Investor Presentation

Q1 Fiscal 2019 UpdateJanuary 31 2019

2

National Fuel is committed to the safe and environmentally conscious development transportation storage and

distribution of natural gas and oil resources

For additional information please visit our corporate responsibility website at httpsresponsibilitynatfuelcom

2

National Fuel is committed to the safe and environmentally conscious development transportation storage and

distribution of natural gas and oil resources

For additional information please visit our corporate responsibility website at httpsresponsibilitynatfuelcom

3

Developing our large high quality acreage position in Marcellus amp Utica shales(1)

NFG A Diversified Integrated Natural Gas Company

Providing safe reliable and affordable service to customers in WNY and NW Pa

UpstreamExploration amp

Production

MidstreamGathering

Pipeline amp Storage

38 of NFG EBITDA(1)

DownstreamUtility

Energy Marketing

of NFG 20EBITDA(1)

Expanding and modernizing pipeline infrastructure to provide outlets for Appalachian natural gas production

785000Net acres in Appalachia

492 MMcfdayNet Appalachian natural gas production

$16 BillionInvestments

since 2010

42 MMDthDaily interstate pipeline capacity under contract

750000Utility

Customers

$300 MillionInvestments in safety since 2014

California oil production generates significant cash flow

(1) This presentation includes forward-looking statements Please review the safe harbor for forward looking statements on slide 55 of this presentation(2) Twelve months ending December 31 2018 A reconciliation of Adjusted EBITDA to Net Income as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation

42 of NFG EBITDA(2)

36 of NFG EBITDA(2)

22 of NFG EBITDA(2)

4

Why National Fuel

Large Appalachian Footprint Driving Significant Growth

5

Integrated Model Enhances Shareholder Value

Operational scale Lower cost of capital Lower operating costs More efficient capital investment More competitive pipeline

infrastructure projects Ability to adjust to changing

commodity price environments Higher returns on investment Strong balance sheet Growing stable dividend

Geographic and Operational Integration Drives Synergies

Upstream and Midstream Co-Development of Marcellus and Utica Installation of just-in-time gathering facilities Expansion of pipeline transmission

infrastructure to reach demand markets

Midstream and Downstream Rate-regulated entities reduce operating

expenses by sharing common resources Utility and Energy Marketing segments are

significant Pipeline amp Storage customers

1

Benefits of National Fuelrsquos Integrated Structure

Financial Efficiencies Investment grade credit rating Shared borrowing capacity Consolidated income tax return

DownstreamUtility

Energy Marketing

MidstreamGathering

Pipeline amp Storage

UpstreamExploration amp

Production

6

Nearly 50 Years of Consecutive Dividend Increases

Annual Rate at Fiscal Year End

$29 BillionDividend payments since 1970

$170per share

48 YearsConsecutive Dividend Increases

$019per share

116 YearsConsecutive Payments

30yield(1)

(1) As of January 29 2019

2

7

1 Production and Gathering Growth of 15-20 Through 2022

Production Growth Supported by Firm Transportation Portfolio

(1) Production trend line represents 175 net growth on average from fiscal 2018 through fiscal 2022

2355 2709

3115

1781 210-230

0

50

100

150

200

250

300

350

400

2018 2019E 2020 2021 2022

Sene

ca N

et P

rodu

ctio

n (B

cfe)

15 Annual Growth

20 Annual Growth

$1079$130-$140

$0

$50

$100

$150

$200

$250

2018 2019E 2020 2021 2022G

athe

ring

Rev

enue

s ($

MM

)

15 Annual Growth

20 Annual Growth

Production Growth Drives Significant Increase in Gathering Revenues

EampP3

(2) Revenue trend line represents 175 growth on average from fiscal 2018 through fiscal 2022

8

Utilization of Existing Infrastructure for Ongoing Utica Development Amplifies Consolidated Returns

L Leveraging Existing Infrastructure to Enhance Returns

(1) Approximate WDA Marcellus gathering facility costs for 192 wells drilled and completed as of September 30 2018 (2) Estimated WDA Utica gathering facility costs for the assumed 120 well locations in Clermont Rich Valley area of redevelopment (3) Internal Rate of Return for Seneca WDA includes estimated well costs under current cost structure and anticipated LOE and Gathering costs Internal Rate of Return for Seneca WDA and Gathering includes expected gathering capital expenditures

through FY 2022 well costs under current cost structure and non-gathering LOE

Gathering CapExWell

($ thousands)Marcellus (pre-2019) $1489(1)

Utica (2019-2022) $392(2)

Gathering Pipelines

Compression

Water Handling Facilities

Roadways and Pads

Gathering Costs in Western Development Area (CRV) 10+ IRR Uplift

Expected(3)

Requires modest investment in new Gathering facilities to support production growth

Utica development on Marcellus pads allows use of existing

Resulting in significant consolidated return uplift for EampP and Gathering

4

9

$1 Billion+ Backlog in Pipeline amp Storage Projects

Line N to Monaca - $23 MM (July 2019)(1)

Empire North - $145 MM (second half of fiscal 2020)

FM100 - $280 MM (late calendar 2021)

bull Companion project to Seneca-anchored Leidy South project

Northern Access - $500 MM (as early as fiscal 2022)

Supply Corp Modernization - $150 - $250 MM (fiscal 2019-2022)

FUTURE INVESTMENTS = $11 ndash $12 Billion

FUTURE EXPANSION REVENUES = ~$150 Million

Line N toMonaca

Northern Access

FM100

Empire North

5

(1) Parentheticals represent target in-service dates for the respective expansion projects

10

Financial Highlights

First Quarter Fiscal 2019

11

673 572 361458

Net

Oil

and

Gas

Pr

oduc

tion

First Quarter Fiscal 2019 Results and Drivers

Exploration amp Production

$034

Exploration amp Production

$037

Gathering $013

Gathering $016

Pipeline amp Storage

$029

Pipeline amp Storage

$029

Utility $025

Utility $030

$102

$112

Energy Marketing $001 Energy Marketing ($001)CorporateAll Other $001

Q1 FY18 Q1 FY19

Adjusted Operating Results ($share)(1)

(1) Adjusted Operating results of $102 for Q1 Fiscal 2018 and $112 for Q1 Fiscal 2019 include operating results of Energy Marketing and Corporate amp All Other segments See slide 61 for a Reconciliation of Adjusted Operating Results to Earnings Per Share(2) Realized price after hedging

$5979 $6170 $272 $261

Q1 FY 2018 Q1 FY 2019

Oil

and

Gas

Pr

icin

g(2)

Natural Gas ($Mcfe)Crude Oil ($Bbl)

Oil Prices

Natural Gas Prices

$238 $297

Gat

herin

g R

even

ue ($

MM

)Increased Seneca Natural Gas Production

Drivers

Natural Gas Production

Oil Production(sale of Sespe field)

Crude Oil (Mbbl) Natural Gas (Bcf)

12

Earnings Guidance

FY2018 Adjusted Operating Results

Non-regulated Businesses

Exploration amp ProductionGathering

$334 share(1) $345 to $365 shareFY2019 Earnings Guidance

Seneca Net Production 210 to 230 Bcfe Gathering Revenues $130-140 million

Natural Gas ~$245Mcf(2) (vs $252Mcf in FY 2018) Crude Oil ~$59Bbl(3) (vs $5866Bbl in FY 2018)

Key Guidance Drivers

(1) Excludes the $1035 million or $120 per share reduction in tax expense due to the remeasurement of deferred taxes resulting from the 2017 Tax Reform Act See non-GAAP disclosure on slide 61 of this presentation(2) Assumes NYMEX natural gas pricing of $325MMBtu (winter) and $275MMBtu (summer) and basin spot pricing of $275MMBtu (winter) and $225MMBtu (summer) for FY19 and reflects the impact of existing financial hedges firm sales

and firm transportation contracts(3) Assumes NYMEX (WTI) oil pricing of $5500Bbl and California-MWSS pricing differentials of 102 to WTI for FY19 and reflects impact of existing financial hedge contracts

Production amp Gathering Throughput

Realized natural gas prices (after-hedge)

Utility Operating Income

Regulated BusinessesPipeline amp StorageUtility

Guidance assumes normal weather modestly higher gross margin expected to be offset by cost inflation

~$285 million in revenues (expected decrease primarily due to expiration of contract on Empire system)

Pipeline amp Storage Revenues

Tax Reform

Realized oil prices (after-hedge)

Lower effective tax rate Effective tax rate ~24-25 (federal rate 21)

13

Exploration amp Production and Gathering OverviewSeneca Resources Company LLC ~ National Fuel Gas Midstream Company LLC

14

Proved Reserves

385 337 290 302 277

16832142

16751973

2357

1914

2344

1849

2154

2523

0

500

1000

1500

2000

2500

3000

2014 2015 2016 2017 2018At September 30

Natural Gas (Bcf)

Crude Oil (MMbbl)

361 Reserve Replacement Rate

Seneca Drill-bit FampD = $066Mcfe(1)

Appalachia Drill-bit FampD = $065Mcfe(1)

(1) Seneca ldquoDrill-bitrdquo finding and development (ldquoFampDrdquo) costs exclude the impact of reserve revisions

Total Proved Reserves (Bcfe)

Fiscal 2018 Proved Reserves Stats

$138

$112

$132

$098

$074

$050

$100

$150

2014 2015 2016 2017 2018

3-Year Average FampD Cost ($Mcfe)

70

30

PDPs PUDs

EampP and Gathering

15

3 rig development program with second rig in WDA focused on Utica

15-20 net production growth expected through fiscal 2022

New EDA Utica development with production expected in Q2 fiscal 2019

Utilize new Atlantic Sunrise firm transportation capacity

Layer-in firm sales to take advantage of attractive regional pricing

Gross production growth will benefit NFGrsquos Gathering segment

Minimal capital investment in California to generate significant cash flow

Growing Production within Disciplined Capital Program

205 194 176 ~16

1406 1541 1605194-214

1611 1735 1781210-230

0

50

100

150

200

250

2016 2017 2018 2019E

$38 $38 $26 ~$25$61

$208$330

$435-$470

$99

$246

$356

$460-$495

$0

$200

$400

$600

2016 2017 2018 2019E

Appalachia West Coast (California)

Near-Term Growth Strategy EampP Net Capital Expenditures ($ millions)(1)

EampP Net Production (Bcfe)

EampP and Gathering

(1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentationFY16 FY17 and FY18 guidance reflects the netting of $157 million $7 million and $17 million respectively of up-front proceeds received from joint development partner for working interest in joint development wells

16

Significant Appalachian Acreage Position

Average gross production ~311 MMcfd

Mostly leased (16-18 royalty) with no significant near-term lease expirations

~90 remaining Marcellus amp Utica locations economic at ~$184Mcf

Additional Marcellus (Tioga Co) amp Geneseo (Lycoming Co) potential

Eastern Development Area (EDA)

Western Development Area (WDA)

Average gross production(1) ~327 MMcfd Large inventory of Marcellus amp Utica

locations economic at ~$200Mcf Royalty free mineral ownership

enhances well economics Highly contiguous nature drives cost and

operational efficiencies

EampP and Gathering

EDA - 70000 AcresWDA - 715000 Acres

(1) Average EDA and WDA gross production as well as WDA-CRV Utica production (see slide 19) and CovingtonTract 595 Production (see slide 23) is for the quarter ended December 31 2018

17

Western Development AreaMarcellus Core Acreage

vs Utica Appraisal Trend(1)

(1) The Utica Shale lies approximately 5000 feet beneath Senecarsquos WDA Marcellus acreage (2) Appraisal program currently in progress Additional tests are planned Prior Marcellus delineation tests helped define the prospective limits of the Marcellus core acreage planned testing in the Utica expected to do the same

Area of Re-Development ~120 Utica locations on existing Marcellus pads

Key Utica testsPast Marcellus delineation testsUtica Trend (currently evaluating)Marcellus Core Acreage

Large well inventory economic at ~$200 Mcf

Marcellus Shale 600+ well locations remaining 200000 acres

Utica Shale 500+ potential locations across Utica trend evaluating extent of prospective acreage(2)

Fee acreage (no royalty) enhances economics and provides development flexibility

Addition of 2nd WDA drilling rig in Q3 FY18 focused on redevelopment of Clermont-Rich Valley acreage for Utica

Use of existing gathering pad and water infrastructure for Utica drives increased Appalachian program returns

Highly contiguous position drives best in class well costs

Utica test results on trend with other Utica wells in NE Pa

Long-term firm contracts support growth

Boone Mountain Utica Test Well23 Bcf 1000ft

Rich Valley Utica Test Well23 Bcf 1000ft

EampP and Gathering

WDA Highlights

18

WDA Utica Appraisal Results and Initial Type Curve

Tested producing from 17 Utica wells in WDA-CRV Higher pressure significantly enhances well

productivity (Utica ~5000rsquo deeper than Marcellus) Drawdown management is critical restricted

drawdown appears to improve well EURs Early production declines much shallower vs

Marcellus

WDA Utica Appraisal Update

WDA Economics

(1) Internal Rate of Return (IRR) is pre-tax and includes estimated well costs under current cost structure LOEand anticipated gathering tariffs

(2) Initial WDA-CRV Utica type curve based on production results and reservoir expectations from the first 5appraisal wells in the WDA-CRV area

(3) WDA-CRV Utica Average includes all 17 producing wells including 2 wells (pad E09-S) for which drawdownmanagement was not used

EampP and Gathering

EURBcf1000rsquo

Well Cost$M1000rsquo

IRR $225

Break-even15 IRR(1)

Utica - CRV 17 $887 23 $197

Marcellus 10 ndash 11 $643 19 $206

(2)

0

1

2

3

4

5

6

7

8

9

0 12 24 36 48 60 72 84 96 108 120

Cum

ulat

ive

Prod

uctio

n B

CF

Months On

WDA-CRV Utica Wells - Normalized to 9000rsquoUtica Type Curve CRV Utica AverageWDA Marcellus Type Curve Boone Mountain Appraisal WellWDA-CRV Utica Type Curve(2) WDA-CRV Utica Average(3)

0005101520253035

0 2 4 6 8 10 12

19

Transitioning to Utica Development in CRV

WDA-CRV Marcellus(Depth ~7000 feet)

WDA-CRV Utica(Depth ~12000 feet)

Avg CRV Marcellus Production 270 MMcfd

Rem Avg EUR 10-11 Bcf 1000 lat ft

Rem Avg Well Costs = $643lat ft

120+ locations on existing Marcellus pads

Est EURs 17 Bcf 1000 lat ft

Est Development Well Costs = $887lat ft

CRV Utica Transition Plan

1)Finish Marcellus Pads in Development

Drill 24 complete 24 Marcellus wells

2)Continue Optimizing Utica DampC design

Additional optimization wells focusing on

Completion design

Landing zone targets

3)Continue transition to Utica development

Future drilling on multi-well pads

Continue using optimization results to determine development well design

Tailor development plan to use existing pad water and gathering infrastructure

CRV Utica Development Utilizes Existing Pad Water and Gathering Infrastructure to Drive Economics

EampP and Gathering

Rich Valley Utica Test

Existing Line

Leased

Seneca Fee

Producing

FY19 Producer

Development

20

Leveraging Existing Gathering Water and Pad Infrastructure Enhances Returns

Limited New Infrastructure Needed to Support Production Growth

WDA Well Costs(1) WDA Consolidated Economics

Steady activity levels and coordination between upstream and midstream activities

enhance returns provide economies of scale and significant operational flexibility

(1) WDA Marcellus well costs reflect drilling completion amp gathering costs for 192 drilled and completed wells as of 93018 WDA Utica well costs reflect expected drilling completion amp gathering costs for the ~120 well locations in area of redevelopment (2) Internal Rate of Return for Seneca WDA includes estimated well costs under current cost structure and anticipated LOE and Gathering costs Internal Rate of Return for Seneca WDA and Gathering includes expected gathering capital expenditures

through FY 2022 well costs under current cost structure and non-gathering LOE

$685$887

$210

$0

$200

$400

$600

$800

$1000

Marcellus(Historic)

Utica - CRV(Current)

$ la

tera

l foo

t

Drilling amp Completion Gathering

$931$895

10 -11

17

00

03

06

09

12

15

18

Marcellus(Historic)

Utica - CRV(Current)

EUR

10

00 fe

et (B

cf)

60-70 EUR increase expected per well

Total cost per well expected to marginally increase

WDA EURs

At a $225 netback price consolidated Seneca WDA and Gathering IRR is

approximately 33 an uplift of ~12 over standalone Seneca WDA economics(2)

10+ IRR Uplift Expected

21

Integrated Development ndash WDA Gathering System

Current System In-Service

~78 miles of pipe 36220 HP of compression

Current Capacity 470 MMcf per day

Interconnects with TGP 300

Total Investment to Date $301 million

Future Build-Out

FY 2019 CapEx $10 - $15 million

Modest gathering pipeline and compression investment required to support Senecarsquos transition to Utica development

Opportunity for 300 miles of pipelines and five compressor stations (+60000 HP installed) as Senecarsquos drilling activity continues

Deliverability into TGP 300 and NFG Supply

Gathering System Build-Out Tailored to Accommodate Senecarsquos WDA Development

Clermont Gathering System Map

EampP and Gathering

22

WDA Firm Transportation and Sales Capacity

Will continue to layer-in firm sales deals of short and longer duration on TGP 300 to reduce spot exposure

WDA spot realizations track TGP Station 313 pricing typically 10cent - 30cent better than TGP Marcellus Zone 4

Leidy South will provide additional capacity to premium markets (Transco Zone 6)

WDA Exit Capacity Supports Long-term Production Growth and Enhances Consolidated Returns

WDA Contracted Firm Transport and Gross Sales Volumes (MDthd)

Seneca gross production trend

EampP and Gathering

0

100

200

300

400

500

600

700

Niagara Expansion Project (TGP and NFG)FT Capacity 158000 Dthd $067Dth

Firm Sales NYMEX amp DAWN

WDA - TGP 300Firm Sales

Leidy SouthTransco Zone 6

Markets330000 Dthd(1)

Will layer-in firm sales to minimize spot exposure

(1) Portion of Transco Project capacity will likely be utilized by EDA Lycoming County production

WDA Gas Marketing Strategy

23

Eastern Development Area

EDA Acreage ndash 70000 AcresEDA Highlights

1 DCNR Tract 007 (Tioga Co Pa)bull Utica development resumed in third quarter fiscal 2018

bull ~43 remaining Utica locations economic at ~$184 Mcf

bull Gathering Infrastructure NFG Midstream Wellsboro

bull Marcellus Shale expected to provide ~60 additional locations

EampP and Gathering

2

1

3

2 Covington amp DCNR Tract 595 (Tioga Co Pa)bull Marcellus locations fully developed (average daily gross production of ~93 MMcfd)

bull Gathering Infrastructure NFG Midstream Covington

bull Opportunity for future Utica appraisal

3 DCNR Tract 100 amp Gamble (Lycoming Co Pa)bull ~45 remaining Marcellus locations economic at ~$153 Mcfbull Firm Transportation Capacity Atlantic Sunrise (189 MDthd)

bull Gathering Infrastructure NFG Midstream Trout Run

bull Geneseo Shale expected to provide 100-120 additional locations

24

EDA Marcellus Lycoming County Development

Marcellus Development in Lycoming County has Resumed in Connection with Atlantic Sunrise

(1) Includes physical fixed price and NYMEX-based firm sales contracts that do not carry any additional transportation costs

EampP and Gathering

Prolific Marcellus acreage with peer leading well results

~45 remaining Marcellus locations economic at ~$153 Mcf

Near-term development focused on filling Atlantic Sunrise capacity

Existing Line

Leased

Seneca Fee

Producing

FY19 Producer

Development

0

50

100

150

200

250

Gro

ss F

irm V

olum

es (M

Dth

d)

EDA ndash Transco Firm Contracts

Atlantic Sunrise (Transco)FT Capacity 189405 Dthd

Cost $073DthFirm Sales NYMEX+

Transco Firm Sales(1)

25

EDA Utica Tioga County Development

Utica Development in Tioga County ndash Tract 007 Development Resumed in Q3 Fiscal 2018

In-Service November 2016

Lateral Length 4640 ft

30 Day IP 1000 ft 34 MMcfd

Est EUR 1000 ft 24 Bcf

Inventory ~43 locations economic at ~$184 Mcf

Targeting to grow production by 100 to 150 MDthd by fiscal 2020

Expected Development Costs $1045 per lateral ft

Gathering Infrastructure NFG Midstream Wellsboro

Modest build-out required to connect to TGP 300

SalesTakeaway Strategy Layer-in firm sales with shippers holding capacity on TGP 300

(1) Includes physical fixed price and NYMEX-based firm sales contracts that do not carry any additional transportation costs

Tract 007 Utica Appraisal Well Results vs Industry

EampP and Gathering

0

100000

200000

300000

400000

500000

600000

700000

800000

0 100 200 300

Nor

mal

ized

Cum

ulat

ive

(Mcf

10

00rsquo)

Days On ProductionIndustry PotterTioga Wells Seneca DCNR 007 73H

0

25

50

75

100

125

150

Gro

ss F

irm V

olum

es (M

Dth

d)

EDA ndash TGP 300 Firm Contracts

Northeast Supply Diversification ProjectFT Capacity 50000 Dthd $050Dth

Firm Sales NYMEX and DAWN

EDA - TGP 300Firm Sales(1)

26

Integrated Development ndash EDA Gathering Systems

Total Investment (to date) ~$46 million FY 2019 Estimated Capital Expenditures $1 MM - $2 MM Capacity 220000 Dth per day (Interconnect w TGP 300) Production Source Seneca Resources ndash Tioga Co (Covington and DCNR Tract 595)

Total Investment (to date) ~$208 million FY 2019 Estimated Capital Expenditures $25 MM - $35 MM Capacity 466000 to 585000 Dth per day (Interconnect w Transco) Production Source Seneca Resources ndash Lycoming Co (DCNR Tract 100 and Gamble) Future third-party volume opportunities

Covington Gathering System

Trout Run Gathering System

Gathering Segment Supporting Senecarsquos EDA Production amp Future Development

Wellsboro Gathering System Total Investment (to date) ~$14 million FY 2019 Estimated Capital Expenditures $8 MM - $15 MM Capacity up to 200000 Dth per day (Interconnect w TGP 300) Production Source Seneca Resources ndash Tioga Co (DCNR Tract 007)

EampP and Gathering

2

1

3

27

Long-term Contracts Supporting Appalachian Growth

(1) Represents base firm sales contracts not tied to firm transportation capacity Base firm sales are either fixed priced or priced at an index (eg NYMEX ) +- a fixed basis and do not carry any transportation costs

Seneca continues to layer-in firm sales contracts with attractive realizations to lock-in drilling economics and minimize spot exposure ahead of firm transportation in-service dates

EampP and Gathering

-

100

200

300

400

500

600

700

800

900

1000

1100

1200

FY 2019 FY 2020 FY 2021 FY 2022Northeast Supply Diversification 50000 Dthd

Niagara Expansion (TGP amp NFG)Delivery Markets Canada-Dawn amp TETCO

158000 Dthd

Atlantic Sunrise (Transco)Delivery Markets Mid-Atlantic amp Southeast US

189405 Dthd

In-BasinFirm Sales

Contracts(1)

Leidy South (Transco amp NFG)

Transco Zone 6 Markets330000 Dthd

Seneca Appalachia Natural Gas MarketingGross Firm Contract Volumes (Mdthday)

28

297000 ($061)

305200 ($061)

305600 ($063)

337000 ($057)

370800 ($024)

369600 ($060)

367900 ($067)

33400 ($070)74500 ($077) 74900 ($077)

81100 ($078)

85900 ($078)

92000 ($073)

91300 ($073)

178800 $255

196000 $234

195500 $234

149900 $232

129500 $230

105400 $222

104500 $222

~517800 509200 575700 576000 568000 586200 567000 563700

Q1 FY19 Q2 FY19 Q3 FY19 Q4 FY19 Q1 FY20 Q2 FY20 Q3 FY20 Q4 FY20

Fixed Price Dawn NYMEX

Near-term Firm Sales Provide Market amp Price Certainty

Net Contracted Firm Sales Volumes (Dth per day)Contracted Index Price Differentials ($ per Dth)(1)

(1) Values shown represent the weighted average fixed price or contracted fixed differential relative to NYMEX (netback price) less any associated transportation costs

Actual Daily Net

Production

641200 716500 708700 693500 708400 674400 667000Gross Firm Sales Volumes (Dthd)

EampP and Gathering

29

California Oil

Stable Oil Production | Minimal Capital Investment | Steady Free Cash Flow

1

2

3

4

5

Location Formation Production Method

FY18 Daily Production(net Boed)

1 East Coalinga Other Temblor Primary 512

2 North Lost Hills

Tulare amp Etchegoin

PrimarySteam flood 892

3 South Lost Hills

Monterey Shale Primary 1359

4 North Midway Sunset

Tulare amp Potter Steam flood 2786

5 South Midway Sunset Antelope Steam flood 2048

TOTAL WEST DIVISION NET PRODUCTION(1) 7597 Boed

EampP and Gathering

(1) West division net production for FY 2018 excludes production from Sespe field which was divested on May 1 2018

30

California Capital Expenditures vs Production

9341 8863

8033 ~7300

2016 2017 2018 2019

Fiscal Year

West Division Average Net Daily Production (Boe)West Division Annual Capital Expenditures ($ MM)(1)

$38 $38

$26 ~$25

2016 2017 2018 2019

Fiscal YearGuidance Guidance

(1) Seneca West Division capital expenditures includes Seneca corporate and eliminations

EampP and Gathering

Sepse Sale Closed on 5118(reduced production by ~900 boed)

31

Pioneer

South MWSS

Acreage

North MWSS

AcreageSec 17N

4149 51

NMWSS amp 17N SMWSS amp Pioneer East Coalinga

California Development Activities

Modest near-term capital program focused on locations that earn attractive returns in current oil price environment

AampD will focus on low cost bolt-on opportunities

Sec 17 Pioneer and East Coalinga development to provide future growth

North

Project IRRs at $55Bbl(1)

(1) Reflects pre-tax IRRs at a $55Bbl WTI

EampP and Gathering

Seneca West Economics

South

East Coalinga

North

South

32

Fiscal 2019 Production and Price Certainty

~49 Bcfe

210 ndash 230 Bcfe

~114 Bcf

~29 Bcf (2)

16+- Bcf~12 Bcfe

0

40

80

120

160

200

240

YTD FY19Actuals

Fixed Price + FirmSales w Hedge

Firm Sales(Unhedged)

Spot Sales California TotalSeneca

Prod

uctio

n (B

cfe)

(1) Average realized price reflects uplift from financial hedges less fixed differentials under firm sales contracts and any firm transportation costs(2) Indicates firm sales contracts with fixed index differentials but not backed by a matching financial hedge

114 Bcf locked-in realizing net ~$241Mcf (1)

29 Bcf of additional basis protection

Spot production assumed to be sold

at ~$275Mmbtu(winter) and ~$225

(summer)

143 Bcf of Appalachian Production Protected by Firm Sales for Remainder of Year

79 of oil production hedged at $5757 Bbl

EampP and Gathering

33

Strong Hedge Book

Natural Gas Swap amp Fixed Physical Sales Contracts (Millions MMBtu)

(1) Fixed price physical sales exclude joint development partnerrsquos share of fixed price contract WDA volumes as specified under the joint development agreement(2) Reflects percentage of projected production for FY19 hedged at the midpoint of the production guidance range(3) Senecarsquos remainder FY19 Production reflects the total FY19 production guidance of 210-230 Bcfe or 220 Bcfe at the midpoint less Q1 actual production

Crude Oil Swap Contracts (Thousands Bbls)

13591188

732

456

0

500

1000

1500

2000

2500

FY 2019 FY 2020 FY 2021 FY 2022

NYMEX (WTI)

Brent

FY 19 Crude Oil79 Hedged (2)

FY 2019 Remaining Production (3)

EampP and Gathering

1174

709

469 406

0

50

100

150

200

250

FY 2019 FY 2020 FY 2021 FY 2022

NYMEX Swaps

Dawn Swaps

Fixed Price Physical Sales

(1)

FY 2019 Remaining Production (3)

FY 19 Nat Gas71 Hedged (2)

34

$065 $070$070 -$075

FY 2017 FY 2018 FY 2019E

$060 $060 $060

$011 $009 $007$071 $069 ~$067

FY 2017 FY 2018 FY 2019E Gathering amp Transport LOE (non-Gathering) GampA Taxes amp Other

Seneca Operating Costs

Competitive low cost structure in Appalachia and California supports strong cash margins

Gathering fee generates significant revenue stream for affiliated gathering company

Seneca DDampARate

$Mcfe

$054 $054 $056

$042 $038 $031

$034 $034 $030

$017 $014 $015

$147 $140 ~$132

FY 2017 FY 2018 FY 2019E

(1)

$1791$1746~$2050

FY 2017 FY 2018 FY 2019E

Appalachia LOE amp Gathering $Mcfe

California LOE$Boe

Total Seneca Cash OpEx$Mcfe

(1)

(2)

(2)

(1) GampA estimate represents the midpoint of the GampA guidance range of $025 to $035 for fiscal 2019(2) The total of the two LOE components represents the midpoint of the LOE guidance range of $085 to $090 for fiscal 2019

EampP and Gathering

35

Senecarsquos Continuing Commitment to the Environment

Produced Water Recycled in Appalachia

100 70Recycled Water

Used in New Shale Well

Completions

Water and Fluids Management Air Quality and Emissions

Seneca Resources Water OperationsFiscal 2018

Seneca Resources Remains Focused on Minimizing GHG Emissions

The Environmental Partnership

EPA Natural Gas Star Program

Green Completions (all fiscal 2018 wells)

Ultrasonic Leak Detection Technology

Emissions Controls

Rig and Vehicle Fuel Conversion

Integrating Renewable Energy into Operations

EampP and Gathering

36

Pipeline and Storage OverviewNational Fuel Gas Supply Corporation ~ Empire Pipeline Inc

37

Pipeline amp Storage Segment Overview

(1) As of September 30 2018 as disclosed in the Companyrsquos fiscal 2018 form 10-K(2) As of December 31 2017 calculated from National Fuel Gas Supply Corporationrsquos and Empire Pipeline Incrsquos 2017 FERC Form-2 reports respectively

Empire Pipeline Inc

National Fuel Gas Supply Corporation

Empire Pipeline

Supply Corp

Contracted Capacity(1) Firm Transportation 3187 MDth per day Firm Storage 71938 Mdth (fully subscribed)

Rate Base(2) ~$820 million FERC Rate Proceeding Status

Rate case settlement extension approved Nov lsquo15 Rate case filing expected by 73119

Contracted Capacity(1) Firm Transportation 978 MDth per day Firm Storage 3753 Mdth (fully subscribed)

Rate Base(2) ~$249 million FERC Rate Proceeding Status

Rate case settlement in principle reached on 122118 FERC approval pending

New transportation rates went into on 1119

Pipeline amp Storage

38

All Seneca volumes will flow through wholly-owned NFG gathering facilities

FM100 Project - Consolidated Benefit for NFG

330000 Dthd of new transportation capacity from WDA and EDA acreage positions to premium markets

New Transco capacity (Leidy South) 330000 Dthday

Rate(1) competitive with other expansion project rates in Senecarsquos current transportation portfolio

Delivery Point(s) Transco Zone 6 interconnections

Seneca

Lease to Transco of new capacity 330000 Dthday

Estimated annual lease revenues ~$35 million

Target In-Service late calendar year 2021

Supply Corp

Project expected to provide long-term earnings uplift to Seneca Supply Corp and Gathering

Pipeline amp Storage

Gathering

(1) Includes lease of new capacity from Supply Corp to Transco

39

FM100 Project ndash Significant Investment by Supply Corp

Pipeline amp Storage

Estimated Capital Cost $280 million(1)

Facilities (all in Pennsylvania) include Approximately 30 miles of new pipeline 2 new compressor stations (totaling

approximately 37000 HP) New interconnection station and modification

of existing interconnection station Abandonment of approximately 45 miles of

existing pipeline and compressor station Regulatory Process

Pre-filing application submitted to FERC in 2017 for original modernization project

FERC 7(b) 7(c) filing expected summer 2019

(1) Includes expansion and modernization portions of the project

40

Empire North Project

Target In-Service second half of fiscal 2020

Est Capital Cost $145 million

Est Annual Revenues ~$25 million

Receipt Point Jackson (Tioga Co Pa production)

Design Capacity and Delivery Points 175000 Dthd to Chippawa (TCPL interconnect)

30000 Dthd to Hopewell (TGP 200 interconnect)

Customers Fully subscribed (205000 Dthday)

Major Facilities 2 new compressor stations in NY (1) amp Pa (1)

No new pipeline construction

Regulatory Process FERC 7(c) application filed on 21618

FERC Environmental Assessment issued 103018

Pipeline amp Storage

Fully Subscribed Project will Provide 205000 Dthday of Incremental Firm Transportation

41

National Fuel Remains Committed to Northern Access Project

Target In-Service as early as fiscal 2022

Total Cost ~$500MM (~$76MM spent to date)

Estimated Annual Revenues ~$84 million

Delivery Points

350000 Dthd to Chippawa (TCPL interconnect)

140000 Dthd to Hopewell (TGP 200 line)

Regulatory Status

February 3 2017 ndash FERC 7(c) certificate issued

August 6 2018 ndash FERC issued Order finding that NY DEC waived water quality certification

Supply and Empire currently working to finalize remaining federal authorizations

Pipeline amp Storage

To Dawn

42

Continued Expansion of the NFG Supply System

Line N Expansion Opportunities

Line N to Monaca Project Project Firm transportation service to a new ethane

cracker facility being built by Shell Chemical Appalachia LLC

Target In-Service July 2019

Estimated Capital Cost $23 million

Contracted Capacity 133000 Dthday

Additional Line N Expansion Opportunity (Supply OS 221) Project New firm transportation service for on-system

demand

Open Season Capacity Awarded 165000 to foundation shipper Precedent agreement in negotiations

Pipeline amp Storage

43

Pipeline amp Storage Customer Mix

Producer33

LDC42

Marketer10

Outside Pipeline

9

End User6

42 MMDthd

(1) Contracted as of 10312018

Customer Transportation by Shipper Type(1) Affiliated Customer Mix (Contracted Capacity)

66

521

41

34

9579

59

LDCs Producers Marketers FirmStorage

Affiliated Non-Affiliated

Firm Transport

Pipeline amp Storage

44

Utility OverviewNational Fuel Gas Distribution Corporation

45

New York amp Pennsylvania Service Territories

New York

Total Customers(1) 535800ROE 87 (NY PSC Rate Case Order April 2017)Rate Mechanismso Revenue Decouplingo Weather Normalizationo Low Income Rateso Merchant Function Charge (Uncollectibles Adj)o 9010 Sharing (Large Customers)o System Modernization Tracker

Pennsylvania

Total Customers(1) 214400ROE Black Box Settlement (2007)Rate Mechanismso Low Income Rateso Merchant Function Charge

(1) As of September 30 2018

Utility

46

New York Rate Case Outcome

Rate Order Summary

Revenue Requirement $59 million

Rate Base $704 million

Allowed Return on Equity (ROE) 87

Capital Structure 429 equity

Other notable items

New rates became effective 5117

Retains rate mechanisms in place under prior order (revenue decoupling weather normalization merchant function charge 9010 large customer sharing)

No stay-out clause

System modernization tracker for Leak Prone Pipe (LPP)

Earnings sharing started 4118 (5050 sharing starts at earnings in excess of 92)

Article 78 appeal filed on 72817 with oral argument completed in January 2019

On April 20 2017 the New York Public Service Commission issued a Rate Order relating to NFG Distributionrsquos rate case (No 16-G-0257) filed in April 2016

Utility

47

Utility Continues its Significant Investments in Safety

$544$618 $636

$699

$944$980

$809$856

$90-100

$00

$250

$500

$750

$1000

$1250

2015 2016 2017 2018 2019E

Cap

ital E

xpen

ditu

res

($ m

illio

ns)

Fiscal Year

Capital Expenditures for Safety Total Capital Expenditures

Modernization Spending in NY Expected to Grow Gross Margin By $2 MM - $5 MM in FY 2019

(1)

(1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation

Utility

System modernization tracker in NY allows recovery of pipeline replacementcosts which is expected to drive modest gross margin and rate base growth

48

Accelerating Pipeline Replacement amp Modernization

Wrought Iron

Plastic

CoatedBare

120130

146 144159

2014 2015 2016 2017 2018Calendar Year

NY9726 miles

PA4830 miles

No Cast Iron Mains in Pa

Miles of Utility Main Pipeline ReplacedUtility Mains by Material(1)

Wrought Iron

Cast Iron

Plastic

Coated Bare

Utility

(1) All values are reported on a calendar year basis as of December 31 2018

49

A Proven History of Controlling Costs

$200 $189 $195

$166 $166

$31 $31

$197 $197

$0

$50

$100

$150

$200

$250

2015 2016 2017 2018 TTM 123118

Fiscal Year

OampM Expense Non-Service Pension Costs

OampM Expense ($ millions)

Utility

(1)

(1) For purposes of comparability to FY 2015 2016 and 2017 Utility Operation and Maintenance Expense for FY 2018 and the twelve months ended December 31 2018 was adjusted by approximately $314 million and $312 million respectively to include non-service pension costs which were re-classified as Other Income (Deductions) as of October 1 2018 on the Companyrsquos Income Statement See Slide 64 for non-GAAP reconciliation of Adjusted Operation and Maintenance Expense to Operation and Maintenance Expense by segment

50

Consolidated Financial OverviewUpstream I Midstream I Downstream

51

Adjusted Operating Results ($ per share)(1)

Diversified Balanced Earnings and Cash Flows

(1) A reconciliation of Adjusted Operating Results to Earnings per Share by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation(2) Consolidated Adjusted EBITDA includes Energy Marketing and Corporate amp All Other Segments A reconciliation of Adjusted EBITDA to Net Income by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in

the Business is included at the end of this presentation

Adjusted EBITDA ($ millions)(2)

$176 $179

$184 $181

$92 $97

$318 $327

$761 $775

$-

$200

$400

$600

$800

FY 2018 TTM 123118

$059 Utility

$097 Pipeline amp Storage

$057 Gathering

$125 Exploration

amp Production

$334 $345 to $365

$-

$100

$200

$300

$400

FY 2018 FY 2019 Guidance

Rate Regulated

40-45

$728

Rate Regulated

~46

52

$89 $94 $98 $81 $86 $90-$100

$140$230

$114 $95 $93 $120-$150

$138$118

$54$33 $48

$55-$65

$603$557

$99 $246$356

$460-$495

$970 $1001

$366$455

$583

$725-$810

$0

$250

$500

$750

$1000

$1250

2014 2015 2016 2017 2018 2019GuidanceFiscal Year

Exploration amp Production

Gathering

Pipeline amp Storage

Utility

Disciplined Flexible Capital Allocation

(2)

(1) Total Capital Expenditures include Energy Marketing Corporate and All Other A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation (2) FY16 FY17 and FY18 reflects the netting of $157 million $7 million and $17 million respectively of up-front proceeds received from joint development partner for working interest in joint development wells and $21M in intercompany asset transfers in FY18

Capital Expenditures by Segment ($ millions)(1)

53

Maintaining Strong Balance Sheet amp Liquidity

Total Equity49

Total Debt51

$42 Billion Total Capitalizationas of December 31 2018

218 x251 x 245 x 247 x 256 x

2015 2016 2017 2018 TTM 123118Fiscal Year End

Net Debt Adjusted EBITDA(1) Capitalization

Debt Maturity Profile ($MM) Liquidity

Committed Credit FacilitiesShort-term Debt OutstandingAvailable Short-term Credit FacilitiesCash Balance at 123118 Total Liquidity at 123118

$ 750 MM0 MM

750 MM110 MM

$ 860 MM

$500 $549 $500

$300 $300

$0

$200

$400

$600

(1) Net Debt is net of cash and temporary cash investments Reconciliations of Net Debt and Adjusted EBITDA to Net Income are included at the end of this presentation

54

Appendix

55

Safe Harbor For Forward Looking StatementsThis presentation may contain ldquoforward-looking statementsrdquo as defined by the Private Securities Litigation Reform Act of 1995 including statements regarding future prospectsplans objectives goals projections estimates of oil and gas quantities strategies future events or performance and underlying assumptions capital structure anticipatedcapital expenditures completion of construction projects projections for pension and other post-retirement benefit obligations impacts of the adoption of new accounting rulesand possible outcomes of litigation or regulatory proceedings as well as statements that are identified by the use of the words ldquoanticipatesrdquo ldquoestimatesrdquo ldquoexpectsrdquo ldquoforecastsrdquoldquointendsrdquo ldquoplansrdquo ldquopredictsrdquo ldquoprojectsrdquo ldquobelievesrdquo ldquoseeksrdquo ldquowillrdquo ldquomayrdquo and similar expressions Forward-looking statements involve risks and uncertainties which couldcause actual results or outcomes to differ materially from those expressed in the forward-looking statements The Companyrsquos expectations beliefs and projections are expressedin good faith and are believed by the Company to have a reasonable basis but there can be no assurance that managementrsquos expectations beliefs or projections will result or beachieved or accomplished

In addition to other factors the following are important factors that could cause actual results to differ materially from those discussed in the forward-looking statements delaysor changes in costs or plans with respect to Company projects or related projects of other companies including difficulties or delays in obtaining necessary governmentalapprovals permits or orders or in obtaining the cooperation of interconnecting facility operators governmentalregulatory actions initiatives and proceedings including thoseinvolving rate cases (which address among other things target rates of return rate design and retained natural gas) environmentalsafety requirements affiliate relationshipsindustry structure and franchise renewal changes in laws regulations or judicial interpretations to which the Company is subject including those involving derivatives taxessafety employment climate change other environmental matters real property and exploration and production activities such as hydraulic fracturing financial and economicconditions including the availability of credit and occurrences affecting the Companyrsquos ability to obtain financing on acceptable terms for working capital capital expendituresand other investments including any downgrades in the Companyrsquos credit ratings and changes in interest rates and other capital market conditions changes in the price ofnatural gas or oil impairments under the SECrsquos full cost ceiling test for natural gas and oil reserves factors affecting the Companyrsquos ability to successfully identify drill for andproduce economically viable natural gas and oil reserves including among others geology lease availability title disputes weather conditions shortages delays orunavailability of equipment and services required in drilling operations insufficient gathering processing and transportation capacity the need to obtain governmentalapprovals and permits and compliance with environmental laws and regulations increasing health care costs and the resulting effect on health insurance premiums and on theobligation to provide other post-retirement benefits changes in price differentials between similar quantities of natural gas or oil sold at different geographic locations and theeffect of such changes on commodity production revenues and demand for pipeline transportation capacity to or from such locations other changes in price differentialsbetween similar quantities of natural gas or oil having different quality heating value hydrocarbon mix or delivery date the cost and effects of legal and administrative claimsagainst the Company or activist shareholder campaigns to effect changes at the Company uncertainty of oil and gas reserve estimates significant differences between theCompanyrsquos projected and actual production levels for natural gas or oil changes in demographic patterns and weather conditions changes in the availability price oraccounting treatment of derivative financial instruments changes in laws actuarial assumptions the interest rate environment and the return on plantrust assets related to theCompanyrsquos pension and other post-retirement benefits which can affect future funding obligations and costs and plan liabilities changes in economic conditions includingglobal national or regional recessions and their effect on the demand for and customersrsquo ability to pay for the Companyrsquos products and services the creditworthiness orperformance of the Companyrsquos key suppliers customers and counterparties the impact of potential information technology cybersecurity or data security breaches economicdisruptions or uninsured losses resulting from major accidents fires severe weather natural disasters terrorist activities or acts of war significant differences between theCompanyrsquos projected and actual capital expenditures and operating expenses or increasing costs of insurance changes in coverage and the ability to obtain insurance

Forward-looking statements include estimates of oil and gas quantities Proved oil and gas reserves are those quantities of oil and gas which by analysis of geoscience andengineering data can be estimated with reasonable certainty to be economically producible under existing economic conditions operating methods and governmentregulations Other estimates of oil and gas quantities including estimates of probable reserves possible reserves and resource potential are by their nature more speculativethan estimates of proved reserves Accordingly estimates other than proved reserves are subject to substantially greater risk of being actually realized Investors are urged toconsider closely the disclosure in our Form 10-K available at wwwnationalfuelgascom You can also obtain this form on the SECrsquos website at wwwsecgov

For a discussion of the risks set forth above and other factors that could cause actual results to differ materially from results referred to in the forward-looking statements seeldquoRisk Factorsrdquo in the Companyrsquos Form 10-K for the fiscal year ended September 30 2018 and the Forms 10-Q for the quarter ended March 31 2018 June 30 2018 and December31 2018 The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date thereof or to reflect the occurrence ofunanticipated events

Appendix

4

Why National Fuel

Large Appalachian Footprint Driving Significant Growth

5

Integrated Model Enhances Shareholder Value

Operational scale Lower cost of capital Lower operating costs More efficient capital investment More competitive pipeline

infrastructure projects Ability to adjust to changing

commodity price environments Higher returns on investment Strong balance sheet Growing stable dividend

Geographic and Operational Integration Drives Synergies

Upstream and Midstream Co-Development of Marcellus and Utica Installation of just-in-time gathering facilities Expansion of pipeline transmission

infrastructure to reach demand markets

Midstream and Downstream Rate-regulated entities reduce operating

expenses by sharing common resources Utility and Energy Marketing segments are

significant Pipeline amp Storage customers

1

Benefits of National Fuelrsquos Integrated Structure

Financial Efficiencies Investment grade credit rating Shared borrowing capacity Consolidated income tax return

DownstreamUtility

Energy Marketing

MidstreamGathering

Pipeline amp Storage

UpstreamExploration amp

Production

6

Nearly 50 Years of Consecutive Dividend Increases

Annual Rate at Fiscal Year End

$29 BillionDividend payments since 1970

$170per share

48 YearsConsecutive Dividend Increases

$019per share

116 YearsConsecutive Payments

30yield(1)

(1) As of January 29 2019

2

7

1 Production and Gathering Growth of 15-20 Through 2022

Production Growth Supported by Firm Transportation Portfolio

(1) Production trend line represents 175 net growth on average from fiscal 2018 through fiscal 2022

2355 2709

3115

1781 210-230

0

50

100

150

200

250

300

350

400

2018 2019E 2020 2021 2022

Sene

ca N

et P

rodu

ctio

n (B

cfe)

15 Annual Growth

20 Annual Growth

$1079$130-$140

$0

$50

$100

$150

$200

$250

2018 2019E 2020 2021 2022G

athe

ring

Rev

enue

s ($

MM

)

15 Annual Growth

20 Annual Growth

Production Growth Drives Significant Increase in Gathering Revenues

EampP3

(2) Revenue trend line represents 175 growth on average from fiscal 2018 through fiscal 2022

8

Utilization of Existing Infrastructure for Ongoing Utica Development Amplifies Consolidated Returns

L Leveraging Existing Infrastructure to Enhance Returns

(1) Approximate WDA Marcellus gathering facility costs for 192 wells drilled and completed as of September 30 2018 (2) Estimated WDA Utica gathering facility costs for the assumed 120 well locations in Clermont Rich Valley area of redevelopment (3) Internal Rate of Return for Seneca WDA includes estimated well costs under current cost structure and anticipated LOE and Gathering costs Internal Rate of Return for Seneca WDA and Gathering includes expected gathering capital expenditures

through FY 2022 well costs under current cost structure and non-gathering LOE

Gathering CapExWell

($ thousands)Marcellus (pre-2019) $1489(1)

Utica (2019-2022) $392(2)

Gathering Pipelines

Compression

Water Handling Facilities

Roadways and Pads

Gathering Costs in Western Development Area (CRV) 10+ IRR Uplift

Expected(3)

Requires modest investment in new Gathering facilities to support production growth

Utica development on Marcellus pads allows use of existing

Resulting in significant consolidated return uplift for EampP and Gathering

4

9

$1 Billion+ Backlog in Pipeline amp Storage Projects

Line N to Monaca - $23 MM (July 2019)(1)

Empire North - $145 MM (second half of fiscal 2020)

FM100 - $280 MM (late calendar 2021)

bull Companion project to Seneca-anchored Leidy South project

Northern Access - $500 MM (as early as fiscal 2022)

Supply Corp Modernization - $150 - $250 MM (fiscal 2019-2022)

FUTURE INVESTMENTS = $11 ndash $12 Billion

FUTURE EXPANSION REVENUES = ~$150 Million

Line N toMonaca

Northern Access

FM100

Empire North

5

(1) Parentheticals represent target in-service dates for the respective expansion projects

10

Financial Highlights

First Quarter Fiscal 2019

11

673 572 361458

Net

Oil

and

Gas

Pr

oduc

tion

First Quarter Fiscal 2019 Results and Drivers

Exploration amp Production

$034

Exploration amp Production

$037

Gathering $013

Gathering $016

Pipeline amp Storage

$029

Pipeline amp Storage

$029

Utility $025

Utility $030

$102

$112

Energy Marketing $001 Energy Marketing ($001)CorporateAll Other $001

Q1 FY18 Q1 FY19

Adjusted Operating Results ($share)(1)

(1) Adjusted Operating results of $102 for Q1 Fiscal 2018 and $112 for Q1 Fiscal 2019 include operating results of Energy Marketing and Corporate amp All Other segments See slide 61 for a Reconciliation of Adjusted Operating Results to Earnings Per Share(2) Realized price after hedging

$5979 $6170 $272 $261

Q1 FY 2018 Q1 FY 2019

Oil

and

Gas

Pr

icin

g(2)

Natural Gas ($Mcfe)Crude Oil ($Bbl)

Oil Prices

Natural Gas Prices

$238 $297

Gat

herin

g R

even

ue ($

MM

)Increased Seneca Natural Gas Production

Drivers

Natural Gas Production

Oil Production(sale of Sespe field)

Crude Oil (Mbbl) Natural Gas (Bcf)

12

Earnings Guidance

FY2018 Adjusted Operating Results

Non-regulated Businesses

Exploration amp ProductionGathering

$334 share(1) $345 to $365 shareFY2019 Earnings Guidance

Seneca Net Production 210 to 230 Bcfe Gathering Revenues $130-140 million

Natural Gas ~$245Mcf(2) (vs $252Mcf in FY 2018) Crude Oil ~$59Bbl(3) (vs $5866Bbl in FY 2018)

Key Guidance Drivers

(1) Excludes the $1035 million or $120 per share reduction in tax expense due to the remeasurement of deferred taxes resulting from the 2017 Tax Reform Act See non-GAAP disclosure on slide 61 of this presentation(2) Assumes NYMEX natural gas pricing of $325MMBtu (winter) and $275MMBtu (summer) and basin spot pricing of $275MMBtu (winter) and $225MMBtu (summer) for FY19 and reflects the impact of existing financial hedges firm sales

and firm transportation contracts(3) Assumes NYMEX (WTI) oil pricing of $5500Bbl and California-MWSS pricing differentials of 102 to WTI for FY19 and reflects impact of existing financial hedge contracts

Production amp Gathering Throughput

Realized natural gas prices (after-hedge)

Utility Operating Income

Regulated BusinessesPipeline amp StorageUtility

Guidance assumes normal weather modestly higher gross margin expected to be offset by cost inflation

~$285 million in revenues (expected decrease primarily due to expiration of contract on Empire system)

Pipeline amp Storage Revenues

Tax Reform

Realized oil prices (after-hedge)

Lower effective tax rate Effective tax rate ~24-25 (federal rate 21)

13

Exploration amp Production and Gathering OverviewSeneca Resources Company LLC ~ National Fuel Gas Midstream Company LLC

14

Proved Reserves

385 337 290 302 277

16832142

16751973

2357

1914

2344

1849

2154

2523

0

500

1000

1500

2000

2500

3000

2014 2015 2016 2017 2018At September 30

Natural Gas (Bcf)

Crude Oil (MMbbl)

361 Reserve Replacement Rate

Seneca Drill-bit FampD = $066Mcfe(1)

Appalachia Drill-bit FampD = $065Mcfe(1)

(1) Seneca ldquoDrill-bitrdquo finding and development (ldquoFampDrdquo) costs exclude the impact of reserve revisions

Total Proved Reserves (Bcfe)

Fiscal 2018 Proved Reserves Stats

$138

$112

$132

$098

$074

$050

$100

$150

2014 2015 2016 2017 2018

3-Year Average FampD Cost ($Mcfe)

70

30

PDPs PUDs

EampP and Gathering

15

3 rig development program with second rig in WDA focused on Utica

15-20 net production growth expected through fiscal 2022

New EDA Utica development with production expected in Q2 fiscal 2019

Utilize new Atlantic Sunrise firm transportation capacity

Layer-in firm sales to take advantage of attractive regional pricing

Gross production growth will benefit NFGrsquos Gathering segment

Minimal capital investment in California to generate significant cash flow

Growing Production within Disciplined Capital Program

205 194 176 ~16

1406 1541 1605194-214

1611 1735 1781210-230

0

50

100

150

200

250

2016 2017 2018 2019E

$38 $38 $26 ~$25$61

$208$330

$435-$470

$99

$246

$356

$460-$495

$0

$200

$400

$600

2016 2017 2018 2019E

Appalachia West Coast (California)

Near-Term Growth Strategy EampP Net Capital Expenditures ($ millions)(1)

EampP Net Production (Bcfe)

EampP and Gathering

(1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentationFY16 FY17 and FY18 guidance reflects the netting of $157 million $7 million and $17 million respectively of up-front proceeds received from joint development partner for working interest in joint development wells

16

Significant Appalachian Acreage Position

Average gross production ~311 MMcfd

Mostly leased (16-18 royalty) with no significant near-term lease expirations

~90 remaining Marcellus amp Utica locations economic at ~$184Mcf

Additional Marcellus (Tioga Co) amp Geneseo (Lycoming Co) potential

Eastern Development Area (EDA)

Western Development Area (WDA)

Average gross production(1) ~327 MMcfd Large inventory of Marcellus amp Utica

locations economic at ~$200Mcf Royalty free mineral ownership

enhances well economics Highly contiguous nature drives cost and

operational efficiencies

EampP and Gathering

EDA - 70000 AcresWDA - 715000 Acres

(1) Average EDA and WDA gross production as well as WDA-CRV Utica production (see slide 19) and CovingtonTract 595 Production (see slide 23) is for the quarter ended December 31 2018

17

Western Development AreaMarcellus Core Acreage

vs Utica Appraisal Trend(1)

(1) The Utica Shale lies approximately 5000 feet beneath Senecarsquos WDA Marcellus acreage (2) Appraisal program currently in progress Additional tests are planned Prior Marcellus delineation tests helped define the prospective limits of the Marcellus core acreage planned testing in the Utica expected to do the same

Area of Re-Development ~120 Utica locations on existing Marcellus pads

Key Utica testsPast Marcellus delineation testsUtica Trend (currently evaluating)Marcellus Core Acreage

Large well inventory economic at ~$200 Mcf

Marcellus Shale 600+ well locations remaining 200000 acres

Utica Shale 500+ potential locations across Utica trend evaluating extent of prospective acreage(2)

Fee acreage (no royalty) enhances economics and provides development flexibility

Addition of 2nd WDA drilling rig in Q3 FY18 focused on redevelopment of Clermont-Rich Valley acreage for Utica

Use of existing gathering pad and water infrastructure for Utica drives increased Appalachian program returns

Highly contiguous position drives best in class well costs

Utica test results on trend with other Utica wells in NE Pa

Long-term firm contracts support growth

Boone Mountain Utica Test Well23 Bcf 1000ft

Rich Valley Utica Test Well23 Bcf 1000ft

EampP and Gathering

WDA Highlights

18

WDA Utica Appraisal Results and Initial Type Curve

Tested producing from 17 Utica wells in WDA-CRV Higher pressure significantly enhances well

productivity (Utica ~5000rsquo deeper than Marcellus) Drawdown management is critical restricted

drawdown appears to improve well EURs Early production declines much shallower vs

Marcellus

WDA Utica Appraisal Update

WDA Economics

(1) Internal Rate of Return (IRR) is pre-tax and includes estimated well costs under current cost structure LOEand anticipated gathering tariffs

(2) Initial WDA-CRV Utica type curve based on production results and reservoir expectations from the first 5appraisal wells in the WDA-CRV area

(3) WDA-CRV Utica Average includes all 17 producing wells including 2 wells (pad E09-S) for which drawdownmanagement was not used

EampP and Gathering

EURBcf1000rsquo

Well Cost$M1000rsquo

IRR $225

Break-even15 IRR(1)

Utica - CRV 17 $887 23 $197

Marcellus 10 ndash 11 $643 19 $206

(2)

0

1

2

3

4

5

6

7

8

9

0 12 24 36 48 60 72 84 96 108 120

Cum

ulat

ive

Prod

uctio

n B

CF

Months On

WDA-CRV Utica Wells - Normalized to 9000rsquoUtica Type Curve CRV Utica AverageWDA Marcellus Type Curve Boone Mountain Appraisal WellWDA-CRV Utica Type Curve(2) WDA-CRV Utica Average(3)

0005101520253035

0 2 4 6 8 10 12

19

Transitioning to Utica Development in CRV

WDA-CRV Marcellus(Depth ~7000 feet)

WDA-CRV Utica(Depth ~12000 feet)

Avg CRV Marcellus Production 270 MMcfd

Rem Avg EUR 10-11 Bcf 1000 lat ft

Rem Avg Well Costs = $643lat ft

120+ locations on existing Marcellus pads

Est EURs 17 Bcf 1000 lat ft

Est Development Well Costs = $887lat ft

CRV Utica Transition Plan

1)Finish Marcellus Pads in Development

Drill 24 complete 24 Marcellus wells

2)Continue Optimizing Utica DampC design

Additional optimization wells focusing on

Completion design

Landing zone targets

3)Continue transition to Utica development

Future drilling on multi-well pads

Continue using optimization results to determine development well design

Tailor development plan to use existing pad water and gathering infrastructure

CRV Utica Development Utilizes Existing Pad Water and Gathering Infrastructure to Drive Economics

EampP and Gathering

Rich Valley Utica Test

Existing Line

Leased

Seneca Fee

Producing

FY19 Producer

Development

20

Leveraging Existing Gathering Water and Pad Infrastructure Enhances Returns

Limited New Infrastructure Needed to Support Production Growth

WDA Well Costs(1) WDA Consolidated Economics

Steady activity levels and coordination between upstream and midstream activities

enhance returns provide economies of scale and significant operational flexibility

(1) WDA Marcellus well costs reflect drilling completion amp gathering costs for 192 drilled and completed wells as of 93018 WDA Utica well costs reflect expected drilling completion amp gathering costs for the ~120 well locations in area of redevelopment (2) Internal Rate of Return for Seneca WDA includes estimated well costs under current cost structure and anticipated LOE and Gathering costs Internal Rate of Return for Seneca WDA and Gathering includes expected gathering capital expenditures

through FY 2022 well costs under current cost structure and non-gathering LOE

$685$887

$210

$0

$200

$400

$600

$800

$1000

Marcellus(Historic)

Utica - CRV(Current)

$ la

tera

l foo

t

Drilling amp Completion Gathering

$931$895

10 -11

17

00

03

06

09

12

15

18

Marcellus(Historic)

Utica - CRV(Current)

EUR

10

00 fe

et (B

cf)

60-70 EUR increase expected per well

Total cost per well expected to marginally increase

WDA EURs

At a $225 netback price consolidated Seneca WDA and Gathering IRR is

approximately 33 an uplift of ~12 over standalone Seneca WDA economics(2)

10+ IRR Uplift Expected

21

Integrated Development ndash WDA Gathering System

Current System In-Service

~78 miles of pipe 36220 HP of compression

Current Capacity 470 MMcf per day

Interconnects with TGP 300

Total Investment to Date $301 million

Future Build-Out

FY 2019 CapEx $10 - $15 million

Modest gathering pipeline and compression investment required to support Senecarsquos transition to Utica development

Opportunity for 300 miles of pipelines and five compressor stations (+60000 HP installed) as Senecarsquos drilling activity continues

Deliverability into TGP 300 and NFG Supply

Gathering System Build-Out Tailored to Accommodate Senecarsquos WDA Development

Clermont Gathering System Map

EampP and Gathering

22

WDA Firm Transportation and Sales Capacity

Will continue to layer-in firm sales deals of short and longer duration on TGP 300 to reduce spot exposure

WDA spot realizations track TGP Station 313 pricing typically 10cent - 30cent better than TGP Marcellus Zone 4

Leidy South will provide additional capacity to premium markets (Transco Zone 6)

WDA Exit Capacity Supports Long-term Production Growth and Enhances Consolidated Returns

WDA Contracted Firm Transport and Gross Sales Volumes (MDthd)

Seneca gross production trend

EampP and Gathering

0

100

200

300

400

500

600

700

Niagara Expansion Project (TGP and NFG)FT Capacity 158000 Dthd $067Dth

Firm Sales NYMEX amp DAWN

WDA - TGP 300Firm Sales

Leidy SouthTransco Zone 6

Markets330000 Dthd(1)

Will layer-in firm sales to minimize spot exposure

(1) Portion of Transco Project capacity will likely be utilized by EDA Lycoming County production

WDA Gas Marketing Strategy

23

Eastern Development Area

EDA Acreage ndash 70000 AcresEDA Highlights

1 DCNR Tract 007 (Tioga Co Pa)bull Utica development resumed in third quarter fiscal 2018

bull ~43 remaining Utica locations economic at ~$184 Mcf

bull Gathering Infrastructure NFG Midstream Wellsboro

bull Marcellus Shale expected to provide ~60 additional locations

EampP and Gathering

2

1

3

2 Covington amp DCNR Tract 595 (Tioga Co Pa)bull Marcellus locations fully developed (average daily gross production of ~93 MMcfd)

bull Gathering Infrastructure NFG Midstream Covington

bull Opportunity for future Utica appraisal

3 DCNR Tract 100 amp Gamble (Lycoming Co Pa)bull ~45 remaining Marcellus locations economic at ~$153 Mcfbull Firm Transportation Capacity Atlantic Sunrise (189 MDthd)

bull Gathering Infrastructure NFG Midstream Trout Run

bull Geneseo Shale expected to provide 100-120 additional locations

24

EDA Marcellus Lycoming County Development

Marcellus Development in Lycoming County has Resumed in Connection with Atlantic Sunrise

(1) Includes physical fixed price and NYMEX-based firm sales contracts that do not carry any additional transportation costs

EampP and Gathering

Prolific Marcellus acreage with peer leading well results

~45 remaining Marcellus locations economic at ~$153 Mcf

Near-term development focused on filling Atlantic Sunrise capacity

Existing Line

Leased

Seneca Fee

Producing

FY19 Producer

Development

0

50

100

150

200

250

Gro

ss F

irm V

olum

es (M

Dth

d)

EDA ndash Transco Firm Contracts

Atlantic Sunrise (Transco)FT Capacity 189405 Dthd

Cost $073DthFirm Sales NYMEX+

Transco Firm Sales(1)

25

EDA Utica Tioga County Development

Utica Development in Tioga County ndash Tract 007 Development Resumed in Q3 Fiscal 2018

In-Service November 2016

Lateral Length 4640 ft

30 Day IP 1000 ft 34 MMcfd

Est EUR 1000 ft 24 Bcf

Inventory ~43 locations economic at ~$184 Mcf

Targeting to grow production by 100 to 150 MDthd by fiscal 2020

Expected Development Costs $1045 per lateral ft

Gathering Infrastructure NFG Midstream Wellsboro

Modest build-out required to connect to TGP 300

SalesTakeaway Strategy Layer-in firm sales with shippers holding capacity on TGP 300

(1) Includes physical fixed price and NYMEX-based firm sales contracts that do not carry any additional transportation costs

Tract 007 Utica Appraisal Well Results vs Industry

EampP and Gathering

0

100000

200000

300000

400000

500000

600000

700000

800000

0 100 200 300

Nor

mal

ized

Cum

ulat

ive

(Mcf

10

00rsquo)

Days On ProductionIndustry PotterTioga Wells Seneca DCNR 007 73H

0

25

50

75

100

125

150

Gro

ss F

irm V

olum

es (M

Dth

d)

EDA ndash TGP 300 Firm Contracts

Northeast Supply Diversification ProjectFT Capacity 50000 Dthd $050Dth

Firm Sales NYMEX and DAWN

EDA - TGP 300Firm Sales(1)

26

Integrated Development ndash EDA Gathering Systems

Total Investment (to date) ~$46 million FY 2019 Estimated Capital Expenditures $1 MM - $2 MM Capacity 220000 Dth per day (Interconnect w TGP 300) Production Source Seneca Resources ndash Tioga Co (Covington and DCNR Tract 595)

Total Investment (to date) ~$208 million FY 2019 Estimated Capital Expenditures $25 MM - $35 MM Capacity 466000 to 585000 Dth per day (Interconnect w Transco) Production Source Seneca Resources ndash Lycoming Co (DCNR Tract 100 and Gamble) Future third-party volume opportunities

Covington Gathering System

Trout Run Gathering System

Gathering Segment Supporting Senecarsquos EDA Production amp Future Development

Wellsboro Gathering System Total Investment (to date) ~$14 million FY 2019 Estimated Capital Expenditures $8 MM - $15 MM Capacity up to 200000 Dth per day (Interconnect w TGP 300) Production Source Seneca Resources ndash Tioga Co (DCNR Tract 007)

EampP and Gathering

2

1

3

27

Long-term Contracts Supporting Appalachian Growth

(1) Represents base firm sales contracts not tied to firm transportation capacity Base firm sales are either fixed priced or priced at an index (eg NYMEX ) +- a fixed basis and do not carry any transportation costs

Seneca continues to layer-in firm sales contracts with attractive realizations to lock-in drilling economics and minimize spot exposure ahead of firm transportation in-service dates

EampP and Gathering

-

100

200

300

400

500

600

700

800

900

1000

1100

1200

FY 2019 FY 2020 FY 2021 FY 2022Northeast Supply Diversification 50000 Dthd

Niagara Expansion (TGP amp NFG)Delivery Markets Canada-Dawn amp TETCO

158000 Dthd

Atlantic Sunrise (Transco)Delivery Markets Mid-Atlantic amp Southeast US

189405 Dthd

In-BasinFirm Sales

Contracts(1)

Leidy South (Transco amp NFG)

Transco Zone 6 Markets330000 Dthd

Seneca Appalachia Natural Gas MarketingGross Firm Contract Volumes (Mdthday)

28

297000 ($061)

305200 ($061)

305600 ($063)

337000 ($057)

370800 ($024)

369600 ($060)

367900 ($067)

33400 ($070)74500 ($077) 74900 ($077)

81100 ($078)

85900 ($078)

92000 ($073)

91300 ($073)

178800 $255

196000 $234

195500 $234

149900 $232

129500 $230

105400 $222

104500 $222

~517800 509200 575700 576000 568000 586200 567000 563700

Q1 FY19 Q2 FY19 Q3 FY19 Q4 FY19 Q1 FY20 Q2 FY20 Q3 FY20 Q4 FY20

Fixed Price Dawn NYMEX

Near-term Firm Sales Provide Market amp Price Certainty

Net Contracted Firm Sales Volumes (Dth per day)Contracted Index Price Differentials ($ per Dth)(1)

(1) Values shown represent the weighted average fixed price or contracted fixed differential relative to NYMEX (netback price) less any associated transportation costs

Actual Daily Net

Production

641200 716500 708700 693500 708400 674400 667000Gross Firm Sales Volumes (Dthd)

EampP and Gathering

29

California Oil

Stable Oil Production | Minimal Capital Investment | Steady Free Cash Flow

1

2

3

4

5

Location Formation Production Method

FY18 Daily Production(net Boed)

1 East Coalinga Other Temblor Primary 512

2 North Lost Hills

Tulare amp Etchegoin

PrimarySteam flood 892

3 South Lost Hills

Monterey Shale Primary 1359

4 North Midway Sunset

Tulare amp Potter Steam flood 2786

5 South Midway Sunset Antelope Steam flood 2048

TOTAL WEST DIVISION NET PRODUCTION(1) 7597 Boed

EampP and Gathering

(1) West division net production for FY 2018 excludes production from Sespe field which was divested on May 1 2018

30

California Capital Expenditures vs Production

9341 8863

8033 ~7300

2016 2017 2018 2019

Fiscal Year

West Division Average Net Daily Production (Boe)West Division Annual Capital Expenditures ($ MM)(1)

$38 $38

$26 ~$25

2016 2017 2018 2019

Fiscal YearGuidance Guidance

(1) Seneca West Division capital expenditures includes Seneca corporate and eliminations

EampP and Gathering

Sepse Sale Closed on 5118(reduced production by ~900 boed)

31

Pioneer

South MWSS

Acreage

North MWSS

AcreageSec 17N

4149 51

NMWSS amp 17N SMWSS amp Pioneer East Coalinga

California Development Activities

Modest near-term capital program focused on locations that earn attractive returns in current oil price environment

AampD will focus on low cost bolt-on opportunities

Sec 17 Pioneer and East Coalinga development to provide future growth

North

Project IRRs at $55Bbl(1)

(1) Reflects pre-tax IRRs at a $55Bbl WTI

EampP and Gathering

Seneca West Economics

South

East Coalinga

North

South

32

Fiscal 2019 Production and Price Certainty

~49 Bcfe

210 ndash 230 Bcfe

~114 Bcf

~29 Bcf (2)

16+- Bcf~12 Bcfe

0

40

80

120

160

200

240

YTD FY19Actuals

Fixed Price + FirmSales w Hedge

Firm Sales(Unhedged)

Spot Sales California TotalSeneca

Prod

uctio

n (B

cfe)

(1) Average realized price reflects uplift from financial hedges less fixed differentials under firm sales contracts and any firm transportation costs(2) Indicates firm sales contracts with fixed index differentials but not backed by a matching financial hedge

114 Bcf locked-in realizing net ~$241Mcf (1)

29 Bcf of additional basis protection

Spot production assumed to be sold

at ~$275Mmbtu(winter) and ~$225

(summer)

143 Bcf of Appalachian Production Protected by Firm Sales for Remainder of Year

79 of oil production hedged at $5757 Bbl

EampP and Gathering

33

Strong Hedge Book

Natural Gas Swap amp Fixed Physical Sales Contracts (Millions MMBtu)

(1) Fixed price physical sales exclude joint development partnerrsquos share of fixed price contract WDA volumes as specified under the joint development agreement(2) Reflects percentage of projected production for FY19 hedged at the midpoint of the production guidance range(3) Senecarsquos remainder FY19 Production reflects the total FY19 production guidance of 210-230 Bcfe or 220 Bcfe at the midpoint less Q1 actual production

Crude Oil Swap Contracts (Thousands Bbls)

13591188

732

456

0

500

1000

1500

2000

2500

FY 2019 FY 2020 FY 2021 FY 2022

NYMEX (WTI)

Brent

FY 19 Crude Oil79 Hedged (2)

FY 2019 Remaining Production (3)

EampP and Gathering

1174

709

469 406

0

50

100

150

200

250

FY 2019 FY 2020 FY 2021 FY 2022

NYMEX Swaps

Dawn Swaps

Fixed Price Physical Sales

(1)

FY 2019 Remaining Production (3)

FY 19 Nat Gas71 Hedged (2)

34

$065 $070$070 -$075

FY 2017 FY 2018 FY 2019E

$060 $060 $060

$011 $009 $007$071 $069 ~$067

FY 2017 FY 2018 FY 2019E Gathering amp Transport LOE (non-Gathering) GampA Taxes amp Other

Seneca Operating Costs

Competitive low cost structure in Appalachia and California supports strong cash margins

Gathering fee generates significant revenue stream for affiliated gathering company

Seneca DDampARate

$Mcfe

$054 $054 $056

$042 $038 $031

$034 $034 $030

$017 $014 $015

$147 $140 ~$132

FY 2017 FY 2018 FY 2019E

(1)

$1791$1746~$2050

FY 2017 FY 2018 FY 2019E

Appalachia LOE amp Gathering $Mcfe

California LOE$Boe

Total Seneca Cash OpEx$Mcfe

(1)

(2)

(2)

(1) GampA estimate represents the midpoint of the GampA guidance range of $025 to $035 for fiscal 2019(2) The total of the two LOE components represents the midpoint of the LOE guidance range of $085 to $090 for fiscal 2019

EampP and Gathering

35

Senecarsquos Continuing Commitment to the Environment

Produced Water Recycled in Appalachia

100 70Recycled Water

Used in New Shale Well

Completions

Water and Fluids Management Air Quality and Emissions

Seneca Resources Water OperationsFiscal 2018

Seneca Resources Remains Focused on Minimizing GHG Emissions

The Environmental Partnership

EPA Natural Gas Star Program

Green Completions (all fiscal 2018 wells)

Ultrasonic Leak Detection Technology

Emissions Controls

Rig and Vehicle Fuel Conversion

Integrating Renewable Energy into Operations

EampP and Gathering

36

Pipeline and Storage OverviewNational Fuel Gas Supply Corporation ~ Empire Pipeline Inc

37

Pipeline amp Storage Segment Overview

(1) As of September 30 2018 as disclosed in the Companyrsquos fiscal 2018 form 10-K(2) As of December 31 2017 calculated from National Fuel Gas Supply Corporationrsquos and Empire Pipeline Incrsquos 2017 FERC Form-2 reports respectively

Empire Pipeline Inc

National Fuel Gas Supply Corporation

Empire Pipeline

Supply Corp

Contracted Capacity(1) Firm Transportation 3187 MDth per day Firm Storage 71938 Mdth (fully subscribed)

Rate Base(2) ~$820 million FERC Rate Proceeding Status

Rate case settlement extension approved Nov lsquo15 Rate case filing expected by 73119

Contracted Capacity(1) Firm Transportation 978 MDth per day Firm Storage 3753 Mdth (fully subscribed)

Rate Base(2) ~$249 million FERC Rate Proceeding Status

Rate case settlement in principle reached on 122118 FERC approval pending

New transportation rates went into on 1119

Pipeline amp Storage

38

All Seneca volumes will flow through wholly-owned NFG gathering facilities

FM100 Project - Consolidated Benefit for NFG

330000 Dthd of new transportation capacity from WDA and EDA acreage positions to premium markets

New Transco capacity (Leidy South) 330000 Dthday

Rate(1) competitive with other expansion project rates in Senecarsquos current transportation portfolio

Delivery Point(s) Transco Zone 6 interconnections

Seneca

Lease to Transco of new capacity 330000 Dthday

Estimated annual lease revenues ~$35 million

Target In-Service late calendar year 2021

Supply Corp

Project expected to provide long-term earnings uplift to Seneca Supply Corp and Gathering

Pipeline amp Storage

Gathering

(1) Includes lease of new capacity from Supply Corp to Transco

39

FM100 Project ndash Significant Investment by Supply Corp

Pipeline amp Storage

Estimated Capital Cost $280 million(1)

Facilities (all in Pennsylvania) include Approximately 30 miles of new pipeline 2 new compressor stations (totaling

approximately 37000 HP) New interconnection station and modification

of existing interconnection station Abandonment of approximately 45 miles of

existing pipeline and compressor station Regulatory Process

Pre-filing application submitted to FERC in 2017 for original modernization project

FERC 7(b) 7(c) filing expected summer 2019

(1) Includes expansion and modernization portions of the project

40

Empire North Project

Target In-Service second half of fiscal 2020

Est Capital Cost $145 million

Est Annual Revenues ~$25 million

Receipt Point Jackson (Tioga Co Pa production)

Design Capacity and Delivery Points 175000 Dthd to Chippawa (TCPL interconnect)

30000 Dthd to Hopewell (TGP 200 interconnect)

Customers Fully subscribed (205000 Dthday)

Major Facilities 2 new compressor stations in NY (1) amp Pa (1)

No new pipeline construction

Regulatory Process FERC 7(c) application filed on 21618

FERC Environmental Assessment issued 103018

Pipeline amp Storage

Fully Subscribed Project will Provide 205000 Dthday of Incremental Firm Transportation

41

National Fuel Remains Committed to Northern Access Project

Target In-Service as early as fiscal 2022

Total Cost ~$500MM (~$76MM spent to date)

Estimated Annual Revenues ~$84 million

Delivery Points

350000 Dthd to Chippawa (TCPL interconnect)

140000 Dthd to Hopewell (TGP 200 line)

Regulatory Status

February 3 2017 ndash FERC 7(c) certificate issued

August 6 2018 ndash FERC issued Order finding that NY DEC waived water quality certification

Supply and Empire currently working to finalize remaining federal authorizations

Pipeline amp Storage

To Dawn

42

Continued Expansion of the NFG Supply System

Line N Expansion Opportunities

Line N to Monaca Project Project Firm transportation service to a new ethane

cracker facility being built by Shell Chemical Appalachia LLC

Target In-Service July 2019

Estimated Capital Cost $23 million

Contracted Capacity 133000 Dthday

Additional Line N Expansion Opportunity (Supply OS 221) Project New firm transportation service for on-system

demand

Open Season Capacity Awarded 165000 to foundation shipper Precedent agreement in negotiations

Pipeline amp Storage

43

Pipeline amp Storage Customer Mix

Producer33

LDC42

Marketer10

Outside Pipeline

9

End User6

42 MMDthd

(1) Contracted as of 10312018

Customer Transportation by Shipper Type(1) Affiliated Customer Mix (Contracted Capacity)

66

521

41

34

9579

59

LDCs Producers Marketers FirmStorage

Affiliated Non-Affiliated

Firm Transport

Pipeline amp Storage

44

Utility OverviewNational Fuel Gas Distribution Corporation

45

New York amp Pennsylvania Service Territories

New York

Total Customers(1) 535800ROE 87 (NY PSC Rate Case Order April 2017)Rate Mechanismso Revenue Decouplingo Weather Normalizationo Low Income Rateso Merchant Function Charge (Uncollectibles Adj)o 9010 Sharing (Large Customers)o System Modernization Tracker

Pennsylvania

Total Customers(1) 214400ROE Black Box Settlement (2007)Rate Mechanismso Low Income Rateso Merchant Function Charge

(1) As of September 30 2018

Utility

46

New York Rate Case Outcome

Rate Order Summary

Revenue Requirement $59 million

Rate Base $704 million

Allowed Return on Equity (ROE) 87

Capital Structure 429 equity

Other notable items

New rates became effective 5117

Retains rate mechanisms in place under prior order (revenue decoupling weather normalization merchant function charge 9010 large customer sharing)

No stay-out clause

System modernization tracker for Leak Prone Pipe (LPP)

Earnings sharing started 4118 (5050 sharing starts at earnings in excess of 92)

Article 78 appeal filed on 72817 with oral argument completed in January 2019

On April 20 2017 the New York Public Service Commission issued a Rate Order relating to NFG Distributionrsquos rate case (No 16-G-0257) filed in April 2016

Utility

47

Utility Continues its Significant Investments in Safety

$544$618 $636

$699

$944$980

$809$856

$90-100

$00

$250

$500

$750

$1000

$1250

2015 2016 2017 2018 2019E

Cap

ital E

xpen

ditu

res

($ m

illio

ns)

Fiscal Year

Capital Expenditures for Safety Total Capital Expenditures

Modernization Spending in NY Expected to Grow Gross Margin By $2 MM - $5 MM in FY 2019

(1)

(1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation

Utility

System modernization tracker in NY allows recovery of pipeline replacementcosts which is expected to drive modest gross margin and rate base growth

48

Accelerating Pipeline Replacement amp Modernization

Wrought Iron

Plastic

CoatedBare

120130

146 144159

2014 2015 2016 2017 2018Calendar Year

NY9726 miles

PA4830 miles

No Cast Iron Mains in Pa

Miles of Utility Main Pipeline ReplacedUtility Mains by Material(1)

Wrought Iron

Cast Iron

Plastic

Coated Bare

Utility

(1) All values are reported on a calendar year basis as of December 31 2018

49

A Proven History of Controlling Costs

$200 $189 $195

$166 $166

$31 $31

$197 $197

$0

$50

$100

$150

$200

$250

2015 2016 2017 2018 TTM 123118

Fiscal Year

OampM Expense Non-Service Pension Costs

OampM Expense ($ millions)

Utility

(1)

(1) For purposes of comparability to FY 2015 2016 and 2017 Utility Operation and Maintenance Expense for FY 2018 and the twelve months ended December 31 2018 was adjusted by approximately $314 million and $312 million respectively to include non-service pension costs which were re-classified as Other Income (Deductions) as of October 1 2018 on the Companyrsquos Income Statement See Slide 64 for non-GAAP reconciliation of Adjusted Operation and Maintenance Expense to Operation and Maintenance Expense by segment

50

Consolidated Financial OverviewUpstream I Midstream I Downstream

51

Adjusted Operating Results ($ per share)(1)

Diversified Balanced Earnings and Cash Flows

(1) A reconciliation of Adjusted Operating Results to Earnings per Share by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation(2) Consolidated Adjusted EBITDA includes Energy Marketing and Corporate amp All Other Segments A reconciliation of Adjusted EBITDA to Net Income by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in

the Business is included at the end of this presentation

Adjusted EBITDA ($ millions)(2)

$176 $179

$184 $181

$92 $97

$318 $327

$761 $775

$-

$200

$400

$600

$800

FY 2018 TTM 123118

$059 Utility

$097 Pipeline amp Storage

$057 Gathering

$125 Exploration

amp Production

$334 $345 to $365

$-

$100

$200

$300

$400

FY 2018 FY 2019 Guidance

Rate Regulated

40-45

$728

Rate Regulated

~46

52

$89 $94 $98 $81 $86 $90-$100

$140$230

$114 $95 $93 $120-$150

$138$118

$54$33 $48

$55-$65

$603$557

$99 $246$356

$460-$495

$970 $1001

$366$455

$583

$725-$810

$0

$250

$500

$750

$1000

$1250

2014 2015 2016 2017 2018 2019GuidanceFiscal Year

Exploration amp Production

Gathering

Pipeline amp Storage

Utility

Disciplined Flexible Capital Allocation

(2)

(1) Total Capital Expenditures include Energy Marketing Corporate and All Other A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation (2) FY16 FY17 and FY18 reflects the netting of $157 million $7 million and $17 million respectively of up-front proceeds received from joint development partner for working interest in joint development wells and $21M in intercompany asset transfers in FY18

Capital Expenditures by Segment ($ millions)(1)

53

Maintaining Strong Balance Sheet amp Liquidity

Total Equity49

Total Debt51

$42 Billion Total Capitalizationas of December 31 2018

218 x251 x 245 x 247 x 256 x

2015 2016 2017 2018 TTM 123118Fiscal Year End

Net Debt Adjusted EBITDA(1) Capitalization

Debt Maturity Profile ($MM) Liquidity

Committed Credit FacilitiesShort-term Debt OutstandingAvailable Short-term Credit FacilitiesCash Balance at 123118 Total Liquidity at 123118

$ 750 MM0 MM

750 MM110 MM

$ 860 MM

$500 $549 $500

$300 $300

$0

$200

$400

$600

(1) Net Debt is net of cash and temporary cash investments Reconciliations of Net Debt and Adjusted EBITDA to Net Income are included at the end of this presentation

54

Appendix

55

Safe Harbor For Forward Looking StatementsThis presentation may contain ldquoforward-looking statementsrdquo as defined by the Private Securities Litigation Reform Act of 1995 including statements regarding future prospectsplans objectives goals projections estimates of oil and gas quantities strategies future events or performance and underlying assumptions capital structure anticipatedcapital expenditures completion of construction projects projections for pension and other post-retirement benefit obligations impacts of the adoption of new accounting rulesand possible outcomes of litigation or regulatory proceedings as well as statements that are identified by the use of the words ldquoanticipatesrdquo ldquoestimatesrdquo ldquoexpectsrdquo ldquoforecastsrdquoldquointendsrdquo ldquoplansrdquo ldquopredictsrdquo ldquoprojectsrdquo ldquobelievesrdquo ldquoseeksrdquo ldquowillrdquo ldquomayrdquo and similar expressions Forward-looking statements involve risks and uncertainties which couldcause actual results or outcomes to differ materially from those expressed in the forward-looking statements The Companyrsquos expectations beliefs and projections are expressedin good faith and are believed by the Company to have a reasonable basis but there can be no assurance that managementrsquos expectations beliefs or projections will result or beachieved or accomplished

In addition to other factors the following are important factors that could cause actual results to differ materially from those discussed in the forward-looking statements delaysor changes in costs or plans with respect to Company projects or related projects of other companies including difficulties or delays in obtaining necessary governmentalapprovals permits or orders or in obtaining the cooperation of interconnecting facility operators governmentalregulatory actions initiatives and proceedings including thoseinvolving rate cases (which address among other things target rates of return rate design and retained natural gas) environmentalsafety requirements affiliate relationshipsindustry structure and franchise renewal changes in laws regulations or judicial interpretations to which the Company is subject including those involving derivatives taxessafety employment climate change other environmental matters real property and exploration and production activities such as hydraulic fracturing financial and economicconditions including the availability of credit and occurrences affecting the Companyrsquos ability to obtain financing on acceptable terms for working capital capital expendituresand other investments including any downgrades in the Companyrsquos credit ratings and changes in interest rates and other capital market conditions changes in the price ofnatural gas or oil impairments under the SECrsquos full cost ceiling test for natural gas and oil reserves factors affecting the Companyrsquos ability to successfully identify drill for andproduce economically viable natural gas and oil reserves including among others geology lease availability title disputes weather conditions shortages delays orunavailability of equipment and services required in drilling operations insufficient gathering processing and transportation capacity the need to obtain governmentalapprovals and permits and compliance with environmental laws and regulations increasing health care costs and the resulting effect on health insurance premiums and on theobligation to provide other post-retirement benefits changes in price differentials between similar quantities of natural gas or oil sold at different geographic locations and theeffect of such changes on commodity production revenues and demand for pipeline transportation capacity to or from such locations other changes in price differentialsbetween similar quantities of natural gas or oil having different quality heating value hydrocarbon mix or delivery date the cost and effects of legal and administrative claimsagainst the Company or activist shareholder campaigns to effect changes at the Company uncertainty of oil and gas reserve estimates significant differences between theCompanyrsquos projected and actual production levels for natural gas or oil changes in demographic patterns and weather conditions changes in the availability price oraccounting treatment of derivative financial instruments changes in laws actuarial assumptions the interest rate environment and the return on plantrust assets related to theCompanyrsquos pension and other post-retirement benefits which can affect future funding obligations and costs and plan liabilities changes in economic conditions includingglobal national or regional recessions and their effect on the demand for and customersrsquo ability to pay for the Companyrsquos products and services the creditworthiness orperformance of the Companyrsquos key suppliers customers and counterparties the impact of potential information technology cybersecurity or data security breaches economicdisruptions or uninsured losses resulting from major accidents fires severe weather natural disasters terrorist activities or acts of war significant differences between theCompanyrsquos projected and actual capital expenditures and operating expenses or increasing costs of insurance changes in coverage and the ability to obtain insurance

Forward-looking statements include estimates of oil and gas quantities Proved oil and gas reserves are those quantities of oil and gas which by analysis of geoscience andengineering data can be estimated with reasonable certainty to be economically producible under existing economic conditions operating methods and governmentregulations Other estimates of oil and gas quantities including estimates of probable reserves possible reserves and resource potential are by their nature more speculativethan estimates of proved reserves Accordingly estimates other than proved reserves are subject to substantially greater risk of being actually realized Investors are urged toconsider closely the disclosure in our Form 10-K available at wwwnationalfuelgascom You can also obtain this form on the SECrsquos website at wwwsecgov

For a discussion of the risks set forth above and other factors that could cause actual results to differ materially from results referred to in the forward-looking statements seeldquoRisk Factorsrdquo in the Companyrsquos Form 10-K for the fiscal year ended September 30 2018 and the Forms 10-Q for the quarter ended March 31 2018 June 30 2018 and December31 2018 The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date thereof or to reflect the occurrence ofunanticipated events

Appendix

5

Integrated Model Enhances Shareholder Value

Operational scale Lower cost of capital Lower operating costs More efficient capital investment More competitive pipeline

infrastructure projects Ability to adjust to changing

commodity price environments Higher returns on investment Strong balance sheet Growing stable dividend

Geographic and Operational Integration Drives Synergies

Upstream and Midstream Co-Development of Marcellus and Utica Installation of just-in-time gathering facilities Expansion of pipeline transmission

infrastructure to reach demand markets

Midstream and Downstream Rate-regulated entities reduce operating

expenses by sharing common resources Utility and Energy Marketing segments are

significant Pipeline amp Storage customers

1

Benefits of National Fuelrsquos Integrated Structure

Financial Efficiencies Investment grade credit rating Shared borrowing capacity Consolidated income tax return

DownstreamUtility

Energy Marketing

MidstreamGathering

Pipeline amp Storage

UpstreamExploration amp

Production

6

Nearly 50 Years of Consecutive Dividend Increases

Annual Rate at Fiscal Year End

$29 BillionDividend payments since 1970

$170per share

48 YearsConsecutive Dividend Increases

$019per share

116 YearsConsecutive Payments

30yield(1)

(1) As of January 29 2019

2

7

1 Production and Gathering Growth of 15-20 Through 2022

Production Growth Supported by Firm Transportation Portfolio

(1) Production trend line represents 175 net growth on average from fiscal 2018 through fiscal 2022

2355 2709

3115

1781 210-230

0

50

100

150

200

250

300

350

400

2018 2019E 2020 2021 2022

Sene

ca N

et P

rodu

ctio

n (B

cfe)

15 Annual Growth

20 Annual Growth

$1079$130-$140

$0

$50

$100

$150

$200

$250

2018 2019E 2020 2021 2022G

athe

ring

Rev

enue

s ($

MM

)

15 Annual Growth

20 Annual Growth

Production Growth Drives Significant Increase in Gathering Revenues

EampP3

(2) Revenue trend line represents 175 growth on average from fiscal 2018 through fiscal 2022

8

Utilization of Existing Infrastructure for Ongoing Utica Development Amplifies Consolidated Returns

L Leveraging Existing Infrastructure to Enhance Returns

(1) Approximate WDA Marcellus gathering facility costs for 192 wells drilled and completed as of September 30 2018 (2) Estimated WDA Utica gathering facility costs for the assumed 120 well locations in Clermont Rich Valley area of redevelopment (3) Internal Rate of Return for Seneca WDA includes estimated well costs under current cost structure and anticipated LOE and Gathering costs Internal Rate of Return for Seneca WDA and Gathering includes expected gathering capital expenditures

through FY 2022 well costs under current cost structure and non-gathering LOE

Gathering CapExWell

($ thousands)Marcellus (pre-2019) $1489(1)

Utica (2019-2022) $392(2)

Gathering Pipelines

Compression

Water Handling Facilities

Roadways and Pads

Gathering Costs in Western Development Area (CRV) 10+ IRR Uplift

Expected(3)

Requires modest investment in new Gathering facilities to support production growth

Utica development on Marcellus pads allows use of existing

Resulting in significant consolidated return uplift for EampP and Gathering

4

9

$1 Billion+ Backlog in Pipeline amp Storage Projects

Line N to Monaca - $23 MM (July 2019)(1)

Empire North - $145 MM (second half of fiscal 2020)

FM100 - $280 MM (late calendar 2021)

bull Companion project to Seneca-anchored Leidy South project

Northern Access - $500 MM (as early as fiscal 2022)

Supply Corp Modernization - $150 - $250 MM (fiscal 2019-2022)

FUTURE INVESTMENTS = $11 ndash $12 Billion

FUTURE EXPANSION REVENUES = ~$150 Million

Line N toMonaca

Northern Access

FM100

Empire North

5

(1) Parentheticals represent target in-service dates for the respective expansion projects

10

Financial Highlights

First Quarter Fiscal 2019

11

673 572 361458

Net

Oil

and

Gas

Pr

oduc

tion

First Quarter Fiscal 2019 Results and Drivers

Exploration amp Production

$034

Exploration amp Production

$037

Gathering $013

Gathering $016

Pipeline amp Storage

$029

Pipeline amp Storage

$029

Utility $025

Utility $030

$102

$112

Energy Marketing $001 Energy Marketing ($001)CorporateAll Other $001

Q1 FY18 Q1 FY19

Adjusted Operating Results ($share)(1)

(1) Adjusted Operating results of $102 for Q1 Fiscal 2018 and $112 for Q1 Fiscal 2019 include operating results of Energy Marketing and Corporate amp All Other segments See slide 61 for a Reconciliation of Adjusted Operating Results to Earnings Per Share(2) Realized price after hedging

$5979 $6170 $272 $261

Q1 FY 2018 Q1 FY 2019

Oil

and

Gas

Pr

icin

g(2)

Natural Gas ($Mcfe)Crude Oil ($Bbl)

Oil Prices

Natural Gas Prices

$238 $297

Gat

herin

g R

even

ue ($

MM

)Increased Seneca Natural Gas Production

Drivers

Natural Gas Production

Oil Production(sale of Sespe field)

Crude Oil (Mbbl) Natural Gas (Bcf)

12

Earnings Guidance

FY2018 Adjusted Operating Results

Non-regulated Businesses

Exploration amp ProductionGathering

$334 share(1) $345 to $365 shareFY2019 Earnings Guidance

Seneca Net Production 210 to 230 Bcfe Gathering Revenues $130-140 million

Natural Gas ~$245Mcf(2) (vs $252Mcf in FY 2018) Crude Oil ~$59Bbl(3) (vs $5866Bbl in FY 2018)

Key Guidance Drivers

(1) Excludes the $1035 million or $120 per share reduction in tax expense due to the remeasurement of deferred taxes resulting from the 2017 Tax Reform Act See non-GAAP disclosure on slide 61 of this presentation(2) Assumes NYMEX natural gas pricing of $325MMBtu (winter) and $275MMBtu (summer) and basin spot pricing of $275MMBtu (winter) and $225MMBtu (summer) for FY19 and reflects the impact of existing financial hedges firm sales

and firm transportation contracts(3) Assumes NYMEX (WTI) oil pricing of $5500Bbl and California-MWSS pricing differentials of 102 to WTI for FY19 and reflects impact of existing financial hedge contracts

Production amp Gathering Throughput

Realized natural gas prices (after-hedge)

Utility Operating Income

Regulated BusinessesPipeline amp StorageUtility

Guidance assumes normal weather modestly higher gross margin expected to be offset by cost inflation

~$285 million in revenues (expected decrease primarily due to expiration of contract on Empire system)

Pipeline amp Storage Revenues

Tax Reform

Realized oil prices (after-hedge)

Lower effective tax rate Effective tax rate ~24-25 (federal rate 21)

13

Exploration amp Production and Gathering OverviewSeneca Resources Company LLC ~ National Fuel Gas Midstream Company LLC

14

Proved Reserves

385 337 290 302 277

16832142

16751973

2357

1914

2344

1849

2154

2523

0

500

1000

1500

2000

2500

3000

2014 2015 2016 2017 2018At September 30

Natural Gas (Bcf)

Crude Oil (MMbbl)

361 Reserve Replacement Rate

Seneca Drill-bit FampD = $066Mcfe(1)

Appalachia Drill-bit FampD = $065Mcfe(1)

(1) Seneca ldquoDrill-bitrdquo finding and development (ldquoFampDrdquo) costs exclude the impact of reserve revisions

Total Proved Reserves (Bcfe)

Fiscal 2018 Proved Reserves Stats

$138

$112

$132

$098

$074

$050

$100

$150

2014 2015 2016 2017 2018

3-Year Average FampD Cost ($Mcfe)

70

30

PDPs PUDs

EampP and Gathering

15

3 rig development program with second rig in WDA focused on Utica

15-20 net production growth expected through fiscal 2022

New EDA Utica development with production expected in Q2 fiscal 2019

Utilize new Atlantic Sunrise firm transportation capacity

Layer-in firm sales to take advantage of attractive regional pricing

Gross production growth will benefit NFGrsquos Gathering segment

Minimal capital investment in California to generate significant cash flow

Growing Production within Disciplined Capital Program

205 194 176 ~16

1406 1541 1605194-214

1611 1735 1781210-230

0

50

100

150

200

250

2016 2017 2018 2019E

$38 $38 $26 ~$25$61

$208$330

$435-$470

$99

$246

$356

$460-$495

$0

$200

$400

$600

2016 2017 2018 2019E

Appalachia West Coast (California)

Near-Term Growth Strategy EampP Net Capital Expenditures ($ millions)(1)

EampP Net Production (Bcfe)

EampP and Gathering

(1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentationFY16 FY17 and FY18 guidance reflects the netting of $157 million $7 million and $17 million respectively of up-front proceeds received from joint development partner for working interest in joint development wells

16

Significant Appalachian Acreage Position

Average gross production ~311 MMcfd

Mostly leased (16-18 royalty) with no significant near-term lease expirations

~90 remaining Marcellus amp Utica locations economic at ~$184Mcf

Additional Marcellus (Tioga Co) amp Geneseo (Lycoming Co) potential

Eastern Development Area (EDA)

Western Development Area (WDA)

Average gross production(1) ~327 MMcfd Large inventory of Marcellus amp Utica

locations economic at ~$200Mcf Royalty free mineral ownership

enhances well economics Highly contiguous nature drives cost and

operational efficiencies

EampP and Gathering

EDA - 70000 AcresWDA - 715000 Acres

(1) Average EDA and WDA gross production as well as WDA-CRV Utica production (see slide 19) and CovingtonTract 595 Production (see slide 23) is for the quarter ended December 31 2018

17

Western Development AreaMarcellus Core Acreage

vs Utica Appraisal Trend(1)

(1) The Utica Shale lies approximately 5000 feet beneath Senecarsquos WDA Marcellus acreage (2) Appraisal program currently in progress Additional tests are planned Prior Marcellus delineation tests helped define the prospective limits of the Marcellus core acreage planned testing in the Utica expected to do the same

Area of Re-Development ~120 Utica locations on existing Marcellus pads

Key Utica testsPast Marcellus delineation testsUtica Trend (currently evaluating)Marcellus Core Acreage

Large well inventory economic at ~$200 Mcf

Marcellus Shale 600+ well locations remaining 200000 acres

Utica Shale 500+ potential locations across Utica trend evaluating extent of prospective acreage(2)

Fee acreage (no royalty) enhances economics and provides development flexibility

Addition of 2nd WDA drilling rig in Q3 FY18 focused on redevelopment of Clermont-Rich Valley acreage for Utica

Use of existing gathering pad and water infrastructure for Utica drives increased Appalachian program returns

Highly contiguous position drives best in class well costs

Utica test results on trend with other Utica wells in NE Pa

Long-term firm contracts support growth

Boone Mountain Utica Test Well23 Bcf 1000ft

Rich Valley Utica Test Well23 Bcf 1000ft

EampP and Gathering

WDA Highlights

18

WDA Utica Appraisal Results and Initial Type Curve

Tested producing from 17 Utica wells in WDA-CRV Higher pressure significantly enhances well

productivity (Utica ~5000rsquo deeper than Marcellus) Drawdown management is critical restricted

drawdown appears to improve well EURs Early production declines much shallower vs

Marcellus

WDA Utica Appraisal Update

WDA Economics

(1) Internal Rate of Return (IRR) is pre-tax and includes estimated well costs under current cost structure LOEand anticipated gathering tariffs

(2) Initial WDA-CRV Utica type curve based on production results and reservoir expectations from the first 5appraisal wells in the WDA-CRV area

(3) WDA-CRV Utica Average includes all 17 producing wells including 2 wells (pad E09-S) for which drawdownmanagement was not used

EampP and Gathering

EURBcf1000rsquo

Well Cost$M1000rsquo

IRR $225

Break-even15 IRR(1)

Utica - CRV 17 $887 23 $197

Marcellus 10 ndash 11 $643 19 $206

(2)

0

1

2

3

4

5

6

7

8

9

0 12 24 36 48 60 72 84 96 108 120

Cum

ulat

ive

Prod

uctio

n B

CF

Months On

WDA-CRV Utica Wells - Normalized to 9000rsquoUtica Type Curve CRV Utica AverageWDA Marcellus Type Curve Boone Mountain Appraisal WellWDA-CRV Utica Type Curve(2) WDA-CRV Utica Average(3)

0005101520253035

0 2 4 6 8 10 12

19

Transitioning to Utica Development in CRV

WDA-CRV Marcellus(Depth ~7000 feet)

WDA-CRV Utica(Depth ~12000 feet)

Avg CRV Marcellus Production 270 MMcfd

Rem Avg EUR 10-11 Bcf 1000 lat ft

Rem Avg Well Costs = $643lat ft

120+ locations on existing Marcellus pads

Est EURs 17 Bcf 1000 lat ft

Est Development Well Costs = $887lat ft

CRV Utica Transition Plan

1)Finish Marcellus Pads in Development

Drill 24 complete 24 Marcellus wells

2)Continue Optimizing Utica DampC design

Additional optimization wells focusing on

Completion design

Landing zone targets

3)Continue transition to Utica development

Future drilling on multi-well pads

Continue using optimization results to determine development well design

Tailor development plan to use existing pad water and gathering infrastructure

CRV Utica Development Utilizes Existing Pad Water and Gathering Infrastructure to Drive Economics

EampP and Gathering

Rich Valley Utica Test

Existing Line

Leased

Seneca Fee

Producing

FY19 Producer

Development

20

Leveraging Existing Gathering Water and Pad Infrastructure Enhances Returns

Limited New Infrastructure Needed to Support Production Growth

WDA Well Costs(1) WDA Consolidated Economics

Steady activity levels and coordination between upstream and midstream activities

enhance returns provide economies of scale and significant operational flexibility

(1) WDA Marcellus well costs reflect drilling completion amp gathering costs for 192 drilled and completed wells as of 93018 WDA Utica well costs reflect expected drilling completion amp gathering costs for the ~120 well locations in area of redevelopment (2) Internal Rate of Return for Seneca WDA includes estimated well costs under current cost structure and anticipated LOE and Gathering costs Internal Rate of Return for Seneca WDA and Gathering includes expected gathering capital expenditures

through FY 2022 well costs under current cost structure and non-gathering LOE

$685$887

$210

$0

$200

$400

$600

$800

$1000

Marcellus(Historic)

Utica - CRV(Current)

$ la

tera

l foo

t

Drilling amp Completion Gathering

$931$895

10 -11

17

00

03

06

09

12

15

18

Marcellus(Historic)

Utica - CRV(Current)

EUR

10

00 fe

et (B

cf)

60-70 EUR increase expected per well

Total cost per well expected to marginally increase

WDA EURs

At a $225 netback price consolidated Seneca WDA and Gathering IRR is

approximately 33 an uplift of ~12 over standalone Seneca WDA economics(2)

10+ IRR Uplift Expected

21

Integrated Development ndash WDA Gathering System

Current System In-Service

~78 miles of pipe 36220 HP of compression

Current Capacity 470 MMcf per day

Interconnects with TGP 300

Total Investment to Date $301 million

Future Build-Out

FY 2019 CapEx $10 - $15 million

Modest gathering pipeline and compression investment required to support Senecarsquos transition to Utica development

Opportunity for 300 miles of pipelines and five compressor stations (+60000 HP installed) as Senecarsquos drilling activity continues

Deliverability into TGP 300 and NFG Supply

Gathering System Build-Out Tailored to Accommodate Senecarsquos WDA Development

Clermont Gathering System Map

EampP and Gathering

22

WDA Firm Transportation and Sales Capacity

Will continue to layer-in firm sales deals of short and longer duration on TGP 300 to reduce spot exposure

WDA spot realizations track TGP Station 313 pricing typically 10cent - 30cent better than TGP Marcellus Zone 4

Leidy South will provide additional capacity to premium markets (Transco Zone 6)

WDA Exit Capacity Supports Long-term Production Growth and Enhances Consolidated Returns

WDA Contracted Firm Transport and Gross Sales Volumes (MDthd)

Seneca gross production trend

EampP and Gathering

0

100

200

300

400

500

600

700

Niagara Expansion Project (TGP and NFG)FT Capacity 158000 Dthd $067Dth

Firm Sales NYMEX amp DAWN

WDA - TGP 300Firm Sales

Leidy SouthTransco Zone 6

Markets330000 Dthd(1)

Will layer-in firm sales to minimize spot exposure

(1) Portion of Transco Project capacity will likely be utilized by EDA Lycoming County production

WDA Gas Marketing Strategy

23

Eastern Development Area

EDA Acreage ndash 70000 AcresEDA Highlights

1 DCNR Tract 007 (Tioga Co Pa)bull Utica development resumed in third quarter fiscal 2018

bull ~43 remaining Utica locations economic at ~$184 Mcf

bull Gathering Infrastructure NFG Midstream Wellsboro

bull Marcellus Shale expected to provide ~60 additional locations

EampP and Gathering

2

1

3

2 Covington amp DCNR Tract 595 (Tioga Co Pa)bull Marcellus locations fully developed (average daily gross production of ~93 MMcfd)

bull Gathering Infrastructure NFG Midstream Covington

bull Opportunity for future Utica appraisal

3 DCNR Tract 100 amp Gamble (Lycoming Co Pa)bull ~45 remaining Marcellus locations economic at ~$153 Mcfbull Firm Transportation Capacity Atlantic Sunrise (189 MDthd)

bull Gathering Infrastructure NFG Midstream Trout Run

bull Geneseo Shale expected to provide 100-120 additional locations

24

EDA Marcellus Lycoming County Development

Marcellus Development in Lycoming County has Resumed in Connection with Atlantic Sunrise

(1) Includes physical fixed price and NYMEX-based firm sales contracts that do not carry any additional transportation costs

EampP and Gathering

Prolific Marcellus acreage with peer leading well results

~45 remaining Marcellus locations economic at ~$153 Mcf

Near-term development focused on filling Atlantic Sunrise capacity

Existing Line

Leased

Seneca Fee

Producing

FY19 Producer

Development

0

50

100

150

200

250

Gro

ss F

irm V

olum

es (M

Dth

d)

EDA ndash Transco Firm Contracts

Atlantic Sunrise (Transco)FT Capacity 189405 Dthd

Cost $073DthFirm Sales NYMEX+

Transco Firm Sales(1)

25

EDA Utica Tioga County Development

Utica Development in Tioga County ndash Tract 007 Development Resumed in Q3 Fiscal 2018

In-Service November 2016

Lateral Length 4640 ft

30 Day IP 1000 ft 34 MMcfd

Est EUR 1000 ft 24 Bcf

Inventory ~43 locations economic at ~$184 Mcf

Targeting to grow production by 100 to 150 MDthd by fiscal 2020

Expected Development Costs $1045 per lateral ft

Gathering Infrastructure NFG Midstream Wellsboro

Modest build-out required to connect to TGP 300

SalesTakeaway Strategy Layer-in firm sales with shippers holding capacity on TGP 300

(1) Includes physical fixed price and NYMEX-based firm sales contracts that do not carry any additional transportation costs

Tract 007 Utica Appraisal Well Results vs Industry

EampP and Gathering

0

100000

200000

300000

400000

500000

600000

700000

800000

0 100 200 300

Nor

mal

ized

Cum

ulat

ive

(Mcf

10

00rsquo)

Days On ProductionIndustry PotterTioga Wells Seneca DCNR 007 73H

0

25

50

75

100

125

150

Gro

ss F

irm V

olum

es (M

Dth

d)

EDA ndash TGP 300 Firm Contracts

Northeast Supply Diversification ProjectFT Capacity 50000 Dthd $050Dth

Firm Sales NYMEX and DAWN

EDA - TGP 300Firm Sales(1)

26

Integrated Development ndash EDA Gathering Systems

Total Investment (to date) ~$46 million FY 2019 Estimated Capital Expenditures $1 MM - $2 MM Capacity 220000 Dth per day (Interconnect w TGP 300) Production Source Seneca Resources ndash Tioga Co (Covington and DCNR Tract 595)

Total Investment (to date) ~$208 million FY 2019 Estimated Capital Expenditures $25 MM - $35 MM Capacity 466000 to 585000 Dth per day (Interconnect w Transco) Production Source Seneca Resources ndash Lycoming Co (DCNR Tract 100 and Gamble) Future third-party volume opportunities

Covington Gathering System

Trout Run Gathering System

Gathering Segment Supporting Senecarsquos EDA Production amp Future Development

Wellsboro Gathering System Total Investment (to date) ~$14 million FY 2019 Estimated Capital Expenditures $8 MM - $15 MM Capacity up to 200000 Dth per day (Interconnect w TGP 300) Production Source Seneca Resources ndash Tioga Co (DCNR Tract 007)

EampP and Gathering

2

1

3

27

Long-term Contracts Supporting Appalachian Growth

(1) Represents base firm sales contracts not tied to firm transportation capacity Base firm sales are either fixed priced or priced at an index (eg NYMEX ) +- a fixed basis and do not carry any transportation costs

Seneca continues to layer-in firm sales contracts with attractive realizations to lock-in drilling economics and minimize spot exposure ahead of firm transportation in-service dates

EampP and Gathering

-

100

200

300

400

500

600

700

800

900

1000

1100

1200

FY 2019 FY 2020 FY 2021 FY 2022Northeast Supply Diversification 50000 Dthd

Niagara Expansion (TGP amp NFG)Delivery Markets Canada-Dawn amp TETCO

158000 Dthd

Atlantic Sunrise (Transco)Delivery Markets Mid-Atlantic amp Southeast US

189405 Dthd

In-BasinFirm Sales

Contracts(1)

Leidy South (Transco amp NFG)

Transco Zone 6 Markets330000 Dthd

Seneca Appalachia Natural Gas MarketingGross Firm Contract Volumes (Mdthday)

28

297000 ($061)

305200 ($061)

305600 ($063)

337000 ($057)

370800 ($024)

369600 ($060)

367900 ($067)

33400 ($070)74500 ($077) 74900 ($077)

81100 ($078)

85900 ($078)

92000 ($073)

91300 ($073)

178800 $255

196000 $234

195500 $234

149900 $232

129500 $230

105400 $222

104500 $222

~517800 509200 575700 576000 568000 586200 567000 563700

Q1 FY19 Q2 FY19 Q3 FY19 Q4 FY19 Q1 FY20 Q2 FY20 Q3 FY20 Q4 FY20

Fixed Price Dawn NYMEX

Near-term Firm Sales Provide Market amp Price Certainty

Net Contracted Firm Sales Volumes (Dth per day)Contracted Index Price Differentials ($ per Dth)(1)

(1) Values shown represent the weighted average fixed price or contracted fixed differential relative to NYMEX (netback price) less any associated transportation costs

Actual Daily Net

Production

641200 716500 708700 693500 708400 674400 667000Gross Firm Sales Volumes (Dthd)

EampP and Gathering

29

California Oil

Stable Oil Production | Minimal Capital Investment | Steady Free Cash Flow

1

2

3

4

5

Location Formation Production Method

FY18 Daily Production(net Boed)

1 East Coalinga Other Temblor Primary 512

2 North Lost Hills

Tulare amp Etchegoin

PrimarySteam flood 892

3 South Lost Hills

Monterey Shale Primary 1359

4 North Midway Sunset

Tulare amp Potter Steam flood 2786

5 South Midway Sunset Antelope Steam flood 2048

TOTAL WEST DIVISION NET PRODUCTION(1) 7597 Boed

EampP and Gathering

(1) West division net production for FY 2018 excludes production from Sespe field which was divested on May 1 2018

30

California Capital Expenditures vs Production

9341 8863

8033 ~7300

2016 2017 2018 2019

Fiscal Year

West Division Average Net Daily Production (Boe)West Division Annual Capital Expenditures ($ MM)(1)

$38 $38

$26 ~$25

2016 2017 2018 2019

Fiscal YearGuidance Guidance

(1) Seneca West Division capital expenditures includes Seneca corporate and eliminations

EampP and Gathering

Sepse Sale Closed on 5118(reduced production by ~900 boed)

31

Pioneer

South MWSS

Acreage

North MWSS

AcreageSec 17N

4149 51

NMWSS amp 17N SMWSS amp Pioneer East Coalinga

California Development Activities

Modest near-term capital program focused on locations that earn attractive returns in current oil price environment

AampD will focus on low cost bolt-on opportunities

Sec 17 Pioneer and East Coalinga development to provide future growth

North

Project IRRs at $55Bbl(1)

(1) Reflects pre-tax IRRs at a $55Bbl WTI

EampP and Gathering

Seneca West Economics

South

East Coalinga

North

South

32

Fiscal 2019 Production and Price Certainty

~49 Bcfe

210 ndash 230 Bcfe

~114 Bcf

~29 Bcf (2)

16+- Bcf~12 Bcfe

0

40

80

120

160

200

240

YTD FY19Actuals

Fixed Price + FirmSales w Hedge

Firm Sales(Unhedged)

Spot Sales California TotalSeneca

Prod

uctio

n (B

cfe)

(1) Average realized price reflects uplift from financial hedges less fixed differentials under firm sales contracts and any firm transportation costs(2) Indicates firm sales contracts with fixed index differentials but not backed by a matching financial hedge

114 Bcf locked-in realizing net ~$241Mcf (1)

29 Bcf of additional basis protection

Spot production assumed to be sold

at ~$275Mmbtu(winter) and ~$225

(summer)

143 Bcf of Appalachian Production Protected by Firm Sales for Remainder of Year

79 of oil production hedged at $5757 Bbl

EampP and Gathering

33

Strong Hedge Book

Natural Gas Swap amp Fixed Physical Sales Contracts (Millions MMBtu)

(1) Fixed price physical sales exclude joint development partnerrsquos share of fixed price contract WDA volumes as specified under the joint development agreement(2) Reflects percentage of projected production for FY19 hedged at the midpoint of the production guidance range(3) Senecarsquos remainder FY19 Production reflects the total FY19 production guidance of 210-230 Bcfe or 220 Bcfe at the midpoint less Q1 actual production

Crude Oil Swap Contracts (Thousands Bbls)

13591188

732

456

0

500

1000

1500

2000

2500

FY 2019 FY 2020 FY 2021 FY 2022

NYMEX (WTI)

Brent

FY 19 Crude Oil79 Hedged (2)

FY 2019 Remaining Production (3)

EampP and Gathering

1174

709

469 406

0

50

100

150

200

250

FY 2019 FY 2020 FY 2021 FY 2022

NYMEX Swaps

Dawn Swaps

Fixed Price Physical Sales

(1)

FY 2019 Remaining Production (3)

FY 19 Nat Gas71 Hedged (2)

34

$065 $070$070 -$075

FY 2017 FY 2018 FY 2019E

$060 $060 $060

$011 $009 $007$071 $069 ~$067

FY 2017 FY 2018 FY 2019E Gathering amp Transport LOE (non-Gathering) GampA Taxes amp Other

Seneca Operating Costs

Competitive low cost structure in Appalachia and California supports strong cash margins

Gathering fee generates significant revenue stream for affiliated gathering company

Seneca DDampARate

$Mcfe

$054 $054 $056

$042 $038 $031

$034 $034 $030

$017 $014 $015

$147 $140 ~$132

FY 2017 FY 2018 FY 2019E

(1)

$1791$1746~$2050

FY 2017 FY 2018 FY 2019E

Appalachia LOE amp Gathering $Mcfe

California LOE$Boe

Total Seneca Cash OpEx$Mcfe

(1)

(2)

(2)

(1) GampA estimate represents the midpoint of the GampA guidance range of $025 to $035 for fiscal 2019(2) The total of the two LOE components represents the midpoint of the LOE guidance range of $085 to $090 for fiscal 2019

EampP and Gathering

35

Senecarsquos Continuing Commitment to the Environment

Produced Water Recycled in Appalachia

100 70Recycled Water

Used in New Shale Well

Completions

Water and Fluids Management Air Quality and Emissions

Seneca Resources Water OperationsFiscal 2018

Seneca Resources Remains Focused on Minimizing GHG Emissions

The Environmental Partnership

EPA Natural Gas Star Program

Green Completions (all fiscal 2018 wells)

Ultrasonic Leak Detection Technology

Emissions Controls

Rig and Vehicle Fuel Conversion

Integrating Renewable Energy into Operations

EampP and Gathering

36

Pipeline and Storage OverviewNational Fuel Gas Supply Corporation ~ Empire Pipeline Inc

37

Pipeline amp Storage Segment Overview

(1) As of September 30 2018 as disclosed in the Companyrsquos fiscal 2018 form 10-K(2) As of December 31 2017 calculated from National Fuel Gas Supply Corporationrsquos and Empire Pipeline Incrsquos 2017 FERC Form-2 reports respectively

Empire Pipeline Inc

National Fuel Gas Supply Corporation

Empire Pipeline

Supply Corp

Contracted Capacity(1) Firm Transportation 3187 MDth per day Firm Storage 71938 Mdth (fully subscribed)

Rate Base(2) ~$820 million FERC Rate Proceeding Status

Rate case settlement extension approved Nov lsquo15 Rate case filing expected by 73119

Contracted Capacity(1) Firm Transportation 978 MDth per day Firm Storage 3753 Mdth (fully subscribed)

Rate Base(2) ~$249 million FERC Rate Proceeding Status

Rate case settlement in principle reached on 122118 FERC approval pending

New transportation rates went into on 1119

Pipeline amp Storage

38

All Seneca volumes will flow through wholly-owned NFG gathering facilities

FM100 Project - Consolidated Benefit for NFG

330000 Dthd of new transportation capacity from WDA and EDA acreage positions to premium markets

New Transco capacity (Leidy South) 330000 Dthday

Rate(1) competitive with other expansion project rates in Senecarsquos current transportation portfolio

Delivery Point(s) Transco Zone 6 interconnections

Seneca

Lease to Transco of new capacity 330000 Dthday

Estimated annual lease revenues ~$35 million

Target In-Service late calendar year 2021

Supply Corp

Project expected to provide long-term earnings uplift to Seneca Supply Corp and Gathering

Pipeline amp Storage

Gathering

(1) Includes lease of new capacity from Supply Corp to Transco

39

FM100 Project ndash Significant Investment by Supply Corp

Pipeline amp Storage

Estimated Capital Cost $280 million(1)

Facilities (all in Pennsylvania) include Approximately 30 miles of new pipeline 2 new compressor stations (totaling

approximately 37000 HP) New interconnection station and modification

of existing interconnection station Abandonment of approximately 45 miles of

existing pipeline and compressor station Regulatory Process

Pre-filing application submitted to FERC in 2017 for original modernization project

FERC 7(b) 7(c) filing expected summer 2019

(1) Includes expansion and modernization portions of the project

40

Empire North Project

Target In-Service second half of fiscal 2020

Est Capital Cost $145 million

Est Annual Revenues ~$25 million

Receipt Point Jackson (Tioga Co Pa production)

Design Capacity and Delivery Points 175000 Dthd to Chippawa (TCPL interconnect)

30000 Dthd to Hopewell (TGP 200 interconnect)

Customers Fully subscribed (205000 Dthday)

Major Facilities 2 new compressor stations in NY (1) amp Pa (1)

No new pipeline construction

Regulatory Process FERC 7(c) application filed on 21618

FERC Environmental Assessment issued 103018

Pipeline amp Storage

Fully Subscribed Project will Provide 205000 Dthday of Incremental Firm Transportation

41

National Fuel Remains Committed to Northern Access Project

Target In-Service as early as fiscal 2022

Total Cost ~$500MM (~$76MM spent to date)

Estimated Annual Revenues ~$84 million

Delivery Points

350000 Dthd to Chippawa (TCPL interconnect)

140000 Dthd to Hopewell (TGP 200 line)

Regulatory Status

February 3 2017 ndash FERC 7(c) certificate issued

August 6 2018 ndash FERC issued Order finding that NY DEC waived water quality certification

Supply and Empire currently working to finalize remaining federal authorizations

Pipeline amp Storage

To Dawn

42

Continued Expansion of the NFG Supply System

Line N Expansion Opportunities

Line N to Monaca Project Project Firm transportation service to a new ethane

cracker facility being built by Shell Chemical Appalachia LLC

Target In-Service July 2019

Estimated Capital Cost $23 million

Contracted Capacity 133000 Dthday

Additional Line N Expansion Opportunity (Supply OS 221) Project New firm transportation service for on-system

demand

Open Season Capacity Awarded 165000 to foundation shipper Precedent agreement in negotiations

Pipeline amp Storage

43

Pipeline amp Storage Customer Mix

Producer33

LDC42

Marketer10

Outside Pipeline

9

End User6

42 MMDthd

(1) Contracted as of 10312018

Customer Transportation by Shipper Type(1) Affiliated Customer Mix (Contracted Capacity)

66

521

41

34

9579

59

LDCs Producers Marketers FirmStorage

Affiliated Non-Affiliated

Firm Transport

Pipeline amp Storage

44

Utility OverviewNational Fuel Gas Distribution Corporation

45

New York amp Pennsylvania Service Territories

New York

Total Customers(1) 535800ROE 87 (NY PSC Rate Case Order April 2017)Rate Mechanismso Revenue Decouplingo Weather Normalizationo Low Income Rateso Merchant Function Charge (Uncollectibles Adj)o 9010 Sharing (Large Customers)o System Modernization Tracker

Pennsylvania

Total Customers(1) 214400ROE Black Box Settlement (2007)Rate Mechanismso Low Income Rateso Merchant Function Charge

(1) As of September 30 2018

Utility

46

New York Rate Case Outcome

Rate Order Summary

Revenue Requirement $59 million

Rate Base $704 million

Allowed Return on Equity (ROE) 87

Capital Structure 429 equity

Other notable items

New rates became effective 5117

Retains rate mechanisms in place under prior order (revenue decoupling weather normalization merchant function charge 9010 large customer sharing)

No stay-out clause

System modernization tracker for Leak Prone Pipe (LPP)

Earnings sharing started 4118 (5050 sharing starts at earnings in excess of 92)

Article 78 appeal filed on 72817 with oral argument completed in January 2019

On April 20 2017 the New York Public Service Commission issued a Rate Order relating to NFG Distributionrsquos rate case (No 16-G-0257) filed in April 2016

Utility

47

Utility Continues its Significant Investments in Safety

$544$618 $636

$699

$944$980

$809$856

$90-100

$00

$250

$500

$750

$1000

$1250

2015 2016 2017 2018 2019E

Cap

ital E

xpen

ditu

res

($ m

illio

ns)

Fiscal Year

Capital Expenditures for Safety Total Capital Expenditures

Modernization Spending in NY Expected to Grow Gross Margin By $2 MM - $5 MM in FY 2019

(1)

(1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation

Utility

System modernization tracker in NY allows recovery of pipeline replacementcosts which is expected to drive modest gross margin and rate base growth

48

Accelerating Pipeline Replacement amp Modernization

Wrought Iron

Plastic

CoatedBare

120130

146 144159

2014 2015 2016 2017 2018Calendar Year

NY9726 miles

PA4830 miles

No Cast Iron Mains in Pa

Miles of Utility Main Pipeline ReplacedUtility Mains by Material(1)

Wrought Iron

Cast Iron

Plastic

Coated Bare

Utility

(1) All values are reported on a calendar year basis as of December 31 2018

49

A Proven History of Controlling Costs

$200 $189 $195

$166 $166

$31 $31

$197 $197

$0

$50

$100

$150

$200

$250

2015 2016 2017 2018 TTM 123118

Fiscal Year

OampM Expense Non-Service Pension Costs

OampM Expense ($ millions)

Utility

(1)

(1) For purposes of comparability to FY 2015 2016 and 2017 Utility Operation and Maintenance Expense for FY 2018 and the twelve months ended December 31 2018 was adjusted by approximately $314 million and $312 million respectively to include non-service pension costs which were re-classified as Other Income (Deductions) as of October 1 2018 on the Companyrsquos Income Statement See Slide 64 for non-GAAP reconciliation of Adjusted Operation and Maintenance Expense to Operation and Maintenance Expense by segment

50

Consolidated Financial OverviewUpstream I Midstream I Downstream

51

Adjusted Operating Results ($ per share)(1)

Diversified Balanced Earnings and Cash Flows

(1) A reconciliation of Adjusted Operating Results to Earnings per Share by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation(2) Consolidated Adjusted EBITDA includes Energy Marketing and Corporate amp All Other Segments A reconciliation of Adjusted EBITDA to Net Income by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in

the Business is included at the end of this presentation

Adjusted EBITDA ($ millions)(2)

$176 $179

$184 $181

$92 $97

$318 $327

$761 $775

$-

$200

$400

$600

$800

FY 2018 TTM 123118

$059 Utility

$097 Pipeline amp Storage

$057 Gathering

$125 Exploration

amp Production

$334 $345 to $365

$-

$100

$200

$300

$400

FY 2018 FY 2019 Guidance

Rate Regulated

40-45

$728

Rate Regulated

~46

52

$89 $94 $98 $81 $86 $90-$100

$140$230

$114 $95 $93 $120-$150

$138$118

$54$33 $48

$55-$65

$603$557

$99 $246$356

$460-$495

$970 $1001

$366$455

$583

$725-$810

$0

$250

$500

$750

$1000

$1250

2014 2015 2016 2017 2018 2019GuidanceFiscal Year

Exploration amp Production

Gathering

Pipeline amp Storage

Utility

Disciplined Flexible Capital Allocation

(2)

(1) Total Capital Expenditures include Energy Marketing Corporate and All Other A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation (2) FY16 FY17 and FY18 reflects the netting of $157 million $7 million and $17 million respectively of up-front proceeds received from joint development partner for working interest in joint development wells and $21M in intercompany asset transfers in FY18

Capital Expenditures by Segment ($ millions)(1)

53

Maintaining Strong Balance Sheet amp Liquidity

Total Equity49

Total Debt51

$42 Billion Total Capitalizationas of December 31 2018

218 x251 x 245 x 247 x 256 x

2015 2016 2017 2018 TTM 123118Fiscal Year End

Net Debt Adjusted EBITDA(1) Capitalization

Debt Maturity Profile ($MM) Liquidity

Committed Credit FacilitiesShort-term Debt OutstandingAvailable Short-term Credit FacilitiesCash Balance at 123118 Total Liquidity at 123118

$ 750 MM0 MM

750 MM110 MM

$ 860 MM

$500 $549 $500

$300 $300

$0

$200

$400

$600

(1) Net Debt is net of cash and temporary cash investments Reconciliations of Net Debt and Adjusted EBITDA to Net Income are included at the end of this presentation

54

Appendix

55

Safe Harbor For Forward Looking StatementsThis presentation may contain ldquoforward-looking statementsrdquo as defined by the Private Securities Litigation Reform Act of 1995 including statements regarding future prospectsplans objectives goals projections estimates of oil and gas quantities strategies future events or performance and underlying assumptions capital structure anticipatedcapital expenditures completion of construction projects projections for pension and other post-retirement benefit obligations impacts of the adoption of new accounting rulesand possible outcomes of litigation or regulatory proceedings as well as statements that are identified by the use of the words ldquoanticipatesrdquo ldquoestimatesrdquo ldquoexpectsrdquo ldquoforecastsrdquoldquointendsrdquo ldquoplansrdquo ldquopredictsrdquo ldquoprojectsrdquo ldquobelievesrdquo ldquoseeksrdquo ldquowillrdquo ldquomayrdquo and similar expressions Forward-looking statements involve risks and uncertainties which couldcause actual results or outcomes to differ materially from those expressed in the forward-looking statements The Companyrsquos expectations beliefs and projections are expressedin good faith and are believed by the Company to have a reasonable basis but there can be no assurance that managementrsquos expectations beliefs or projections will result or beachieved or accomplished

In addition to other factors the following are important factors that could cause actual results to differ materially from those discussed in the forward-looking statements delaysor changes in costs or plans with respect to Company projects or related projects of other companies including difficulties or delays in obtaining necessary governmentalapprovals permits or orders or in obtaining the cooperation of interconnecting facility operators governmentalregulatory actions initiatives and proceedings including thoseinvolving rate cases (which address among other things target rates of return rate design and retained natural gas) environmentalsafety requirements affiliate relationshipsindustry structure and franchise renewal changes in laws regulations or judicial interpretations to which the Company is subject including those involving derivatives taxessafety employment climate change other environmental matters real property and exploration and production activities such as hydraulic fracturing financial and economicconditions including the availability of credit and occurrences affecting the Companyrsquos ability to obtain financing on acceptable terms for working capital capital expendituresand other investments including any downgrades in the Companyrsquos credit ratings and changes in interest rates and other capital market conditions changes in the price ofnatural gas or oil impairments under the SECrsquos full cost ceiling test for natural gas and oil reserves factors affecting the Companyrsquos ability to successfully identify drill for andproduce economically viable natural gas and oil reserves including among others geology lease availability title disputes weather conditions shortages delays orunavailability of equipment and services required in drilling operations insufficient gathering processing and transportation capacity the need to obtain governmentalapprovals and permits and compliance with environmental laws and regulations increasing health care costs and the resulting effect on health insurance premiums and on theobligation to provide other post-retirement benefits changes in price differentials between similar quantities of natural gas or oil sold at different geographic locations and theeffect of such changes on commodity production revenues and demand for pipeline transportation capacity to or from such locations other changes in price differentialsbetween similar quantities of natural gas or oil having different quality heating value hydrocarbon mix or delivery date the cost and effects of legal and administrative claimsagainst the Company or activist shareholder campaigns to effect changes at the Company uncertainty of oil and gas reserve estimates significant differences between theCompanyrsquos projected and actual production levels for natural gas or oil changes in demographic patterns and weather conditions changes in the availability price oraccounting treatment of derivative financial instruments changes in laws actuarial assumptions the interest rate environment and the return on plantrust assets related to theCompanyrsquos pension and other post-retirement benefits which can affect future funding obligations and costs and plan liabilities changes in economic conditions includingglobal national or regional recessions and their effect on the demand for and customersrsquo ability to pay for the Companyrsquos products and services the creditworthiness orperformance of the Companyrsquos key suppliers customers and counterparties the impact of potential information technology cybersecurity or data security breaches economicdisruptions or uninsured losses resulting from major accidents fires severe weather natural disasters terrorist activities or acts of war significant differences between theCompanyrsquos projected and actual capital expenditures and operating expenses or increasing costs of insurance changes in coverage and the ability to obtain insurance

Forward-looking statements include estimates of oil and gas quantities Proved oil and gas reserves are those quantities of oil and gas which by analysis of geoscience andengineering data can be estimated with reasonable certainty to be economically producible under existing economic conditions operating methods and governmentregulations Other estimates of oil and gas quantities including estimates of probable reserves possible reserves and resource potential are by their nature more speculativethan estimates of proved reserves Accordingly estimates other than proved reserves are subject to substantially greater risk of being actually realized Investors are urged toconsider closely the disclosure in our Form 10-K available at wwwnationalfuelgascom You can also obtain this form on the SECrsquos website at wwwsecgov

For a discussion of the risks set forth above and other factors that could cause actual results to differ materially from results referred to in the forward-looking statements seeldquoRisk Factorsrdquo in the Companyrsquos Form 10-K for the fiscal year ended September 30 2018 and the Forms 10-Q for the quarter ended March 31 2018 June 30 2018 and December31 2018 The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date thereof or to reflect the occurrence ofunanticipated events

Appendix

6

Nearly 50 Years of Consecutive Dividend Increases

Annual Rate at Fiscal Year End

$29 BillionDividend payments since 1970

$170per share

48 YearsConsecutive Dividend Increases

$019per share

116 YearsConsecutive Payments

30yield(1)

(1) As of January 29 2019

2

7

1 Production and Gathering Growth of 15-20 Through 2022

Production Growth Supported by Firm Transportation Portfolio

(1) Production trend line represents 175 net growth on average from fiscal 2018 through fiscal 2022

2355 2709

3115

1781 210-230

0

50

100

150

200

250

300

350

400

2018 2019E 2020 2021 2022

Sene

ca N

et P

rodu

ctio

n (B

cfe)

15 Annual Growth

20 Annual Growth

$1079$130-$140

$0

$50

$100

$150

$200

$250

2018 2019E 2020 2021 2022G

athe

ring

Rev

enue

s ($

MM

)

15 Annual Growth

20 Annual Growth

Production Growth Drives Significant Increase in Gathering Revenues

EampP3

(2) Revenue trend line represents 175 growth on average from fiscal 2018 through fiscal 2022

8

Utilization of Existing Infrastructure for Ongoing Utica Development Amplifies Consolidated Returns

L Leveraging Existing Infrastructure to Enhance Returns

(1) Approximate WDA Marcellus gathering facility costs for 192 wells drilled and completed as of September 30 2018 (2) Estimated WDA Utica gathering facility costs for the assumed 120 well locations in Clermont Rich Valley area of redevelopment (3) Internal Rate of Return for Seneca WDA includes estimated well costs under current cost structure and anticipated LOE and Gathering costs Internal Rate of Return for Seneca WDA and Gathering includes expected gathering capital expenditures

through FY 2022 well costs under current cost structure and non-gathering LOE

Gathering CapExWell

($ thousands)Marcellus (pre-2019) $1489(1)

Utica (2019-2022) $392(2)

Gathering Pipelines

Compression

Water Handling Facilities

Roadways and Pads

Gathering Costs in Western Development Area (CRV) 10+ IRR Uplift

Expected(3)

Requires modest investment in new Gathering facilities to support production growth

Utica development on Marcellus pads allows use of existing

Resulting in significant consolidated return uplift for EampP and Gathering

4

9

$1 Billion+ Backlog in Pipeline amp Storage Projects

Line N to Monaca - $23 MM (July 2019)(1)

Empire North - $145 MM (second half of fiscal 2020)

FM100 - $280 MM (late calendar 2021)

bull Companion project to Seneca-anchored Leidy South project

Northern Access - $500 MM (as early as fiscal 2022)

Supply Corp Modernization - $150 - $250 MM (fiscal 2019-2022)

FUTURE INVESTMENTS = $11 ndash $12 Billion

FUTURE EXPANSION REVENUES = ~$150 Million

Line N toMonaca

Northern Access

FM100

Empire North

5

(1) Parentheticals represent target in-service dates for the respective expansion projects

10

Financial Highlights

First Quarter Fiscal 2019

11

673 572 361458

Net

Oil

and

Gas

Pr

oduc

tion

First Quarter Fiscal 2019 Results and Drivers

Exploration amp Production

$034

Exploration amp Production

$037

Gathering $013

Gathering $016

Pipeline amp Storage

$029

Pipeline amp Storage

$029

Utility $025

Utility $030

$102

$112

Energy Marketing $001 Energy Marketing ($001)CorporateAll Other $001

Q1 FY18 Q1 FY19

Adjusted Operating Results ($share)(1)

(1) Adjusted Operating results of $102 for Q1 Fiscal 2018 and $112 for Q1 Fiscal 2019 include operating results of Energy Marketing and Corporate amp All Other segments See slide 61 for a Reconciliation of Adjusted Operating Results to Earnings Per Share(2) Realized price after hedging

$5979 $6170 $272 $261

Q1 FY 2018 Q1 FY 2019

Oil

and

Gas

Pr

icin

g(2)

Natural Gas ($Mcfe)Crude Oil ($Bbl)

Oil Prices

Natural Gas Prices

$238 $297

Gat

herin

g R

even

ue ($

MM

)Increased Seneca Natural Gas Production

Drivers

Natural Gas Production

Oil Production(sale of Sespe field)

Crude Oil (Mbbl) Natural Gas (Bcf)

12

Earnings Guidance

FY2018 Adjusted Operating Results

Non-regulated Businesses

Exploration amp ProductionGathering

$334 share(1) $345 to $365 shareFY2019 Earnings Guidance

Seneca Net Production 210 to 230 Bcfe Gathering Revenues $130-140 million

Natural Gas ~$245Mcf(2) (vs $252Mcf in FY 2018) Crude Oil ~$59Bbl(3) (vs $5866Bbl in FY 2018)

Key Guidance Drivers

(1) Excludes the $1035 million or $120 per share reduction in tax expense due to the remeasurement of deferred taxes resulting from the 2017 Tax Reform Act See non-GAAP disclosure on slide 61 of this presentation(2) Assumes NYMEX natural gas pricing of $325MMBtu (winter) and $275MMBtu (summer) and basin spot pricing of $275MMBtu (winter) and $225MMBtu (summer) for FY19 and reflects the impact of existing financial hedges firm sales

and firm transportation contracts(3) Assumes NYMEX (WTI) oil pricing of $5500Bbl and California-MWSS pricing differentials of 102 to WTI for FY19 and reflects impact of existing financial hedge contracts

Production amp Gathering Throughput

Realized natural gas prices (after-hedge)

Utility Operating Income

Regulated BusinessesPipeline amp StorageUtility

Guidance assumes normal weather modestly higher gross margin expected to be offset by cost inflation

~$285 million in revenues (expected decrease primarily due to expiration of contract on Empire system)

Pipeline amp Storage Revenues

Tax Reform

Realized oil prices (after-hedge)

Lower effective tax rate Effective tax rate ~24-25 (federal rate 21)

13

Exploration amp Production and Gathering OverviewSeneca Resources Company LLC ~ National Fuel Gas Midstream Company LLC

14

Proved Reserves

385 337 290 302 277

16832142

16751973

2357

1914

2344

1849

2154

2523

0

500

1000

1500

2000

2500

3000

2014 2015 2016 2017 2018At September 30

Natural Gas (Bcf)

Crude Oil (MMbbl)

361 Reserve Replacement Rate

Seneca Drill-bit FampD = $066Mcfe(1)

Appalachia Drill-bit FampD = $065Mcfe(1)

(1) Seneca ldquoDrill-bitrdquo finding and development (ldquoFampDrdquo) costs exclude the impact of reserve revisions

Total Proved Reserves (Bcfe)

Fiscal 2018 Proved Reserves Stats

$138

$112

$132

$098

$074

$050

$100

$150

2014 2015 2016 2017 2018

3-Year Average FampD Cost ($Mcfe)

70

30

PDPs PUDs

EampP and Gathering

15

3 rig development program with second rig in WDA focused on Utica

15-20 net production growth expected through fiscal 2022

New EDA Utica development with production expected in Q2 fiscal 2019

Utilize new Atlantic Sunrise firm transportation capacity

Layer-in firm sales to take advantage of attractive regional pricing

Gross production growth will benefit NFGrsquos Gathering segment

Minimal capital investment in California to generate significant cash flow

Growing Production within Disciplined Capital Program

205 194 176 ~16

1406 1541 1605194-214

1611 1735 1781210-230

0

50

100

150

200

250

2016 2017 2018 2019E

$38 $38 $26 ~$25$61

$208$330

$435-$470

$99

$246

$356

$460-$495

$0

$200

$400

$600

2016 2017 2018 2019E

Appalachia West Coast (California)

Near-Term Growth Strategy EampP Net Capital Expenditures ($ millions)(1)

EampP Net Production (Bcfe)

EampP and Gathering

(1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentationFY16 FY17 and FY18 guidance reflects the netting of $157 million $7 million and $17 million respectively of up-front proceeds received from joint development partner for working interest in joint development wells

16

Significant Appalachian Acreage Position

Average gross production ~311 MMcfd

Mostly leased (16-18 royalty) with no significant near-term lease expirations

~90 remaining Marcellus amp Utica locations economic at ~$184Mcf

Additional Marcellus (Tioga Co) amp Geneseo (Lycoming Co) potential

Eastern Development Area (EDA)

Western Development Area (WDA)

Average gross production(1) ~327 MMcfd Large inventory of Marcellus amp Utica

locations economic at ~$200Mcf Royalty free mineral ownership

enhances well economics Highly contiguous nature drives cost and

operational efficiencies

EampP and Gathering

EDA - 70000 AcresWDA - 715000 Acres

(1) Average EDA and WDA gross production as well as WDA-CRV Utica production (see slide 19) and CovingtonTract 595 Production (see slide 23) is for the quarter ended December 31 2018

17

Western Development AreaMarcellus Core Acreage

vs Utica Appraisal Trend(1)

(1) The Utica Shale lies approximately 5000 feet beneath Senecarsquos WDA Marcellus acreage (2) Appraisal program currently in progress Additional tests are planned Prior Marcellus delineation tests helped define the prospective limits of the Marcellus core acreage planned testing in the Utica expected to do the same

Area of Re-Development ~120 Utica locations on existing Marcellus pads

Key Utica testsPast Marcellus delineation testsUtica Trend (currently evaluating)Marcellus Core Acreage

Large well inventory economic at ~$200 Mcf

Marcellus Shale 600+ well locations remaining 200000 acres

Utica Shale 500+ potential locations across Utica trend evaluating extent of prospective acreage(2)

Fee acreage (no royalty) enhances economics and provides development flexibility

Addition of 2nd WDA drilling rig in Q3 FY18 focused on redevelopment of Clermont-Rich Valley acreage for Utica

Use of existing gathering pad and water infrastructure for Utica drives increased Appalachian program returns

Highly contiguous position drives best in class well costs

Utica test results on trend with other Utica wells in NE Pa

Long-term firm contracts support growth

Boone Mountain Utica Test Well23 Bcf 1000ft

Rich Valley Utica Test Well23 Bcf 1000ft

EampP and Gathering

WDA Highlights

18

WDA Utica Appraisal Results and Initial Type Curve

Tested producing from 17 Utica wells in WDA-CRV Higher pressure significantly enhances well

productivity (Utica ~5000rsquo deeper than Marcellus) Drawdown management is critical restricted

drawdown appears to improve well EURs Early production declines much shallower vs

Marcellus

WDA Utica Appraisal Update

WDA Economics

(1) Internal Rate of Return (IRR) is pre-tax and includes estimated well costs under current cost structure LOEand anticipated gathering tariffs

(2) Initial WDA-CRV Utica type curve based on production results and reservoir expectations from the first 5appraisal wells in the WDA-CRV area

(3) WDA-CRV Utica Average includes all 17 producing wells including 2 wells (pad E09-S) for which drawdownmanagement was not used

EampP and Gathering

EURBcf1000rsquo

Well Cost$M1000rsquo

IRR $225

Break-even15 IRR(1)

Utica - CRV 17 $887 23 $197

Marcellus 10 ndash 11 $643 19 $206

(2)

0

1

2

3

4

5

6

7

8

9

0 12 24 36 48 60 72 84 96 108 120

Cum

ulat

ive

Prod

uctio

n B

CF

Months On

WDA-CRV Utica Wells - Normalized to 9000rsquoUtica Type Curve CRV Utica AverageWDA Marcellus Type Curve Boone Mountain Appraisal WellWDA-CRV Utica Type Curve(2) WDA-CRV Utica Average(3)

0005101520253035

0 2 4 6 8 10 12

19

Transitioning to Utica Development in CRV

WDA-CRV Marcellus(Depth ~7000 feet)

WDA-CRV Utica(Depth ~12000 feet)

Avg CRV Marcellus Production 270 MMcfd

Rem Avg EUR 10-11 Bcf 1000 lat ft

Rem Avg Well Costs = $643lat ft

120+ locations on existing Marcellus pads

Est EURs 17 Bcf 1000 lat ft

Est Development Well Costs = $887lat ft

CRV Utica Transition Plan

1)Finish Marcellus Pads in Development

Drill 24 complete 24 Marcellus wells

2)Continue Optimizing Utica DampC design

Additional optimization wells focusing on

Completion design

Landing zone targets

3)Continue transition to Utica development

Future drilling on multi-well pads

Continue using optimization results to determine development well design

Tailor development plan to use existing pad water and gathering infrastructure

CRV Utica Development Utilizes Existing Pad Water and Gathering Infrastructure to Drive Economics

EampP and Gathering

Rich Valley Utica Test

Existing Line

Leased

Seneca Fee

Producing

FY19 Producer

Development

20

Leveraging Existing Gathering Water and Pad Infrastructure Enhances Returns

Limited New Infrastructure Needed to Support Production Growth

WDA Well Costs(1) WDA Consolidated Economics

Steady activity levels and coordination between upstream and midstream activities

enhance returns provide economies of scale and significant operational flexibility

(1) WDA Marcellus well costs reflect drilling completion amp gathering costs for 192 drilled and completed wells as of 93018 WDA Utica well costs reflect expected drilling completion amp gathering costs for the ~120 well locations in area of redevelopment (2) Internal Rate of Return for Seneca WDA includes estimated well costs under current cost structure and anticipated LOE and Gathering costs Internal Rate of Return for Seneca WDA and Gathering includes expected gathering capital expenditures

through FY 2022 well costs under current cost structure and non-gathering LOE

$685$887

$210

$0

$200

$400

$600

$800

$1000

Marcellus(Historic)

Utica - CRV(Current)

$ la

tera

l foo

t

Drilling amp Completion Gathering

$931$895

10 -11

17

00

03

06

09

12

15

18

Marcellus(Historic)

Utica - CRV(Current)

EUR

10

00 fe

et (B

cf)

60-70 EUR increase expected per well

Total cost per well expected to marginally increase

WDA EURs

At a $225 netback price consolidated Seneca WDA and Gathering IRR is

approximately 33 an uplift of ~12 over standalone Seneca WDA economics(2)

10+ IRR Uplift Expected

21

Integrated Development ndash WDA Gathering System

Current System In-Service

~78 miles of pipe 36220 HP of compression

Current Capacity 470 MMcf per day

Interconnects with TGP 300

Total Investment to Date $301 million

Future Build-Out

FY 2019 CapEx $10 - $15 million

Modest gathering pipeline and compression investment required to support Senecarsquos transition to Utica development

Opportunity for 300 miles of pipelines and five compressor stations (+60000 HP installed) as Senecarsquos drilling activity continues

Deliverability into TGP 300 and NFG Supply

Gathering System Build-Out Tailored to Accommodate Senecarsquos WDA Development

Clermont Gathering System Map

EampP and Gathering

22

WDA Firm Transportation and Sales Capacity

Will continue to layer-in firm sales deals of short and longer duration on TGP 300 to reduce spot exposure

WDA spot realizations track TGP Station 313 pricing typically 10cent - 30cent better than TGP Marcellus Zone 4

Leidy South will provide additional capacity to premium markets (Transco Zone 6)

WDA Exit Capacity Supports Long-term Production Growth and Enhances Consolidated Returns

WDA Contracted Firm Transport and Gross Sales Volumes (MDthd)

Seneca gross production trend

EampP and Gathering

0

100

200

300

400

500

600

700

Niagara Expansion Project (TGP and NFG)FT Capacity 158000 Dthd $067Dth

Firm Sales NYMEX amp DAWN

WDA - TGP 300Firm Sales

Leidy SouthTransco Zone 6

Markets330000 Dthd(1)

Will layer-in firm sales to minimize spot exposure

(1) Portion of Transco Project capacity will likely be utilized by EDA Lycoming County production

WDA Gas Marketing Strategy

23

Eastern Development Area

EDA Acreage ndash 70000 AcresEDA Highlights

1 DCNR Tract 007 (Tioga Co Pa)bull Utica development resumed in third quarter fiscal 2018

bull ~43 remaining Utica locations economic at ~$184 Mcf

bull Gathering Infrastructure NFG Midstream Wellsboro

bull Marcellus Shale expected to provide ~60 additional locations

EampP and Gathering

2

1

3

2 Covington amp DCNR Tract 595 (Tioga Co Pa)bull Marcellus locations fully developed (average daily gross production of ~93 MMcfd)

bull Gathering Infrastructure NFG Midstream Covington

bull Opportunity for future Utica appraisal

3 DCNR Tract 100 amp Gamble (Lycoming Co Pa)bull ~45 remaining Marcellus locations economic at ~$153 Mcfbull Firm Transportation Capacity Atlantic Sunrise (189 MDthd)

bull Gathering Infrastructure NFG Midstream Trout Run

bull Geneseo Shale expected to provide 100-120 additional locations

24

EDA Marcellus Lycoming County Development

Marcellus Development in Lycoming County has Resumed in Connection with Atlantic Sunrise

(1) Includes physical fixed price and NYMEX-based firm sales contracts that do not carry any additional transportation costs

EampP and Gathering

Prolific Marcellus acreage with peer leading well results

~45 remaining Marcellus locations economic at ~$153 Mcf

Near-term development focused on filling Atlantic Sunrise capacity

Existing Line

Leased

Seneca Fee

Producing

FY19 Producer

Development

0

50

100

150

200

250

Gro

ss F

irm V

olum

es (M

Dth

d)

EDA ndash Transco Firm Contracts

Atlantic Sunrise (Transco)FT Capacity 189405 Dthd

Cost $073DthFirm Sales NYMEX+

Transco Firm Sales(1)

25

EDA Utica Tioga County Development

Utica Development in Tioga County ndash Tract 007 Development Resumed in Q3 Fiscal 2018

In-Service November 2016

Lateral Length 4640 ft

30 Day IP 1000 ft 34 MMcfd

Est EUR 1000 ft 24 Bcf

Inventory ~43 locations economic at ~$184 Mcf

Targeting to grow production by 100 to 150 MDthd by fiscal 2020

Expected Development Costs $1045 per lateral ft

Gathering Infrastructure NFG Midstream Wellsboro

Modest build-out required to connect to TGP 300

SalesTakeaway Strategy Layer-in firm sales with shippers holding capacity on TGP 300

(1) Includes physical fixed price and NYMEX-based firm sales contracts that do not carry any additional transportation costs

Tract 007 Utica Appraisal Well Results vs Industry

EampP and Gathering

0

100000

200000

300000

400000

500000

600000

700000

800000

0 100 200 300

Nor

mal

ized

Cum

ulat

ive

(Mcf

10

00rsquo)

Days On ProductionIndustry PotterTioga Wells Seneca DCNR 007 73H

0

25

50

75

100

125

150

Gro

ss F

irm V

olum

es (M

Dth

d)

EDA ndash TGP 300 Firm Contracts

Northeast Supply Diversification ProjectFT Capacity 50000 Dthd $050Dth

Firm Sales NYMEX and DAWN

EDA - TGP 300Firm Sales(1)

26

Integrated Development ndash EDA Gathering Systems

Total Investment (to date) ~$46 million FY 2019 Estimated Capital Expenditures $1 MM - $2 MM Capacity 220000 Dth per day (Interconnect w TGP 300) Production Source Seneca Resources ndash Tioga Co (Covington and DCNR Tract 595)

Total Investment (to date) ~$208 million FY 2019 Estimated Capital Expenditures $25 MM - $35 MM Capacity 466000 to 585000 Dth per day (Interconnect w Transco) Production Source Seneca Resources ndash Lycoming Co (DCNR Tract 100 and Gamble) Future third-party volume opportunities

Covington Gathering System

Trout Run Gathering System

Gathering Segment Supporting Senecarsquos EDA Production amp Future Development

Wellsboro Gathering System Total Investment (to date) ~$14 million FY 2019 Estimated Capital Expenditures $8 MM - $15 MM Capacity up to 200000 Dth per day (Interconnect w TGP 300) Production Source Seneca Resources ndash Tioga Co (DCNR Tract 007)

EampP and Gathering

2

1

3

27

Long-term Contracts Supporting Appalachian Growth

(1) Represents base firm sales contracts not tied to firm transportation capacity Base firm sales are either fixed priced or priced at an index (eg NYMEX ) +- a fixed basis and do not carry any transportation costs

Seneca continues to layer-in firm sales contracts with attractive realizations to lock-in drilling economics and minimize spot exposure ahead of firm transportation in-service dates

EampP and Gathering

-

100

200

300

400

500

600

700

800

900

1000

1100

1200

FY 2019 FY 2020 FY 2021 FY 2022Northeast Supply Diversification 50000 Dthd

Niagara Expansion (TGP amp NFG)Delivery Markets Canada-Dawn amp TETCO

158000 Dthd

Atlantic Sunrise (Transco)Delivery Markets Mid-Atlantic amp Southeast US

189405 Dthd

In-BasinFirm Sales

Contracts(1)

Leidy South (Transco amp NFG)

Transco Zone 6 Markets330000 Dthd

Seneca Appalachia Natural Gas MarketingGross Firm Contract Volumes (Mdthday)

28

297000 ($061)

305200 ($061)

305600 ($063)

337000 ($057)

370800 ($024)

369600 ($060)

367900 ($067)

33400 ($070)74500 ($077) 74900 ($077)

81100 ($078)

85900 ($078)

92000 ($073)

91300 ($073)

178800 $255

196000 $234

195500 $234

149900 $232

129500 $230

105400 $222

104500 $222

~517800 509200 575700 576000 568000 586200 567000 563700

Q1 FY19 Q2 FY19 Q3 FY19 Q4 FY19 Q1 FY20 Q2 FY20 Q3 FY20 Q4 FY20

Fixed Price Dawn NYMEX

Near-term Firm Sales Provide Market amp Price Certainty

Net Contracted Firm Sales Volumes (Dth per day)Contracted Index Price Differentials ($ per Dth)(1)

(1) Values shown represent the weighted average fixed price or contracted fixed differential relative to NYMEX (netback price) less any associated transportation costs

Actual Daily Net

Production

641200 716500 708700 693500 708400 674400 667000Gross Firm Sales Volumes (Dthd)

EampP and Gathering

29

California Oil

Stable Oil Production | Minimal Capital Investment | Steady Free Cash Flow

1

2

3

4

5

Location Formation Production Method

FY18 Daily Production(net Boed)

1 East Coalinga Other Temblor Primary 512

2 North Lost Hills

Tulare amp Etchegoin

PrimarySteam flood 892

3 South Lost Hills

Monterey Shale Primary 1359

4 North Midway Sunset

Tulare amp Potter Steam flood 2786

5 South Midway Sunset Antelope Steam flood 2048

TOTAL WEST DIVISION NET PRODUCTION(1) 7597 Boed

EampP and Gathering

(1) West division net production for FY 2018 excludes production from Sespe field which was divested on May 1 2018

30

California Capital Expenditures vs Production

9341 8863

8033 ~7300

2016 2017 2018 2019

Fiscal Year

West Division Average Net Daily Production (Boe)West Division Annual Capital Expenditures ($ MM)(1)

$38 $38

$26 ~$25

2016 2017 2018 2019

Fiscal YearGuidance Guidance

(1) Seneca West Division capital expenditures includes Seneca corporate and eliminations

EampP and Gathering

Sepse Sale Closed on 5118(reduced production by ~900 boed)

31

Pioneer

South MWSS

Acreage

North MWSS

AcreageSec 17N

4149 51

NMWSS amp 17N SMWSS amp Pioneer East Coalinga

California Development Activities

Modest near-term capital program focused on locations that earn attractive returns in current oil price environment

AampD will focus on low cost bolt-on opportunities

Sec 17 Pioneer and East Coalinga development to provide future growth

North

Project IRRs at $55Bbl(1)

(1) Reflects pre-tax IRRs at a $55Bbl WTI

EampP and Gathering

Seneca West Economics

South

East Coalinga

North

South

32

Fiscal 2019 Production and Price Certainty

~49 Bcfe

210 ndash 230 Bcfe

~114 Bcf

~29 Bcf (2)

16+- Bcf~12 Bcfe

0

40

80

120

160

200

240

YTD FY19Actuals

Fixed Price + FirmSales w Hedge

Firm Sales(Unhedged)

Spot Sales California TotalSeneca

Prod

uctio

n (B

cfe)

(1) Average realized price reflects uplift from financial hedges less fixed differentials under firm sales contracts and any firm transportation costs(2) Indicates firm sales contracts with fixed index differentials but not backed by a matching financial hedge

114 Bcf locked-in realizing net ~$241Mcf (1)

29 Bcf of additional basis protection

Spot production assumed to be sold

at ~$275Mmbtu(winter) and ~$225

(summer)

143 Bcf of Appalachian Production Protected by Firm Sales for Remainder of Year

79 of oil production hedged at $5757 Bbl

EampP and Gathering

33

Strong Hedge Book

Natural Gas Swap amp Fixed Physical Sales Contracts (Millions MMBtu)

(1) Fixed price physical sales exclude joint development partnerrsquos share of fixed price contract WDA volumes as specified under the joint development agreement(2) Reflects percentage of projected production for FY19 hedged at the midpoint of the production guidance range(3) Senecarsquos remainder FY19 Production reflects the total FY19 production guidance of 210-230 Bcfe or 220 Bcfe at the midpoint less Q1 actual production

Crude Oil Swap Contracts (Thousands Bbls)

13591188

732

456

0

500

1000

1500

2000

2500

FY 2019 FY 2020 FY 2021 FY 2022

NYMEX (WTI)

Brent

FY 19 Crude Oil79 Hedged (2)

FY 2019 Remaining Production (3)

EampP and Gathering

1174

709

469 406

0

50

100

150

200

250

FY 2019 FY 2020 FY 2021 FY 2022

NYMEX Swaps

Dawn Swaps

Fixed Price Physical Sales

(1)

FY 2019 Remaining Production (3)

FY 19 Nat Gas71 Hedged (2)

34

$065 $070$070 -$075

FY 2017 FY 2018 FY 2019E

$060 $060 $060

$011 $009 $007$071 $069 ~$067

FY 2017 FY 2018 FY 2019E Gathering amp Transport LOE (non-Gathering) GampA Taxes amp Other

Seneca Operating Costs

Competitive low cost structure in Appalachia and California supports strong cash margins

Gathering fee generates significant revenue stream for affiliated gathering company

Seneca DDampARate

$Mcfe

$054 $054 $056

$042 $038 $031

$034 $034 $030

$017 $014 $015

$147 $140 ~$132

FY 2017 FY 2018 FY 2019E

(1)

$1791$1746~$2050

FY 2017 FY 2018 FY 2019E

Appalachia LOE amp Gathering $Mcfe

California LOE$Boe

Total Seneca Cash OpEx$Mcfe

(1)

(2)

(2)

(1) GampA estimate represents the midpoint of the GampA guidance range of $025 to $035 for fiscal 2019(2) The total of the two LOE components represents the midpoint of the LOE guidance range of $085 to $090 for fiscal 2019

EampP and Gathering

35

Senecarsquos Continuing Commitment to the Environment

Produced Water Recycled in Appalachia

100 70Recycled Water

Used in New Shale Well

Completions

Water and Fluids Management Air Quality and Emissions

Seneca Resources Water OperationsFiscal 2018

Seneca Resources Remains Focused on Minimizing GHG Emissions

The Environmental Partnership

EPA Natural Gas Star Program

Green Completions (all fiscal 2018 wells)

Ultrasonic Leak Detection Technology

Emissions Controls

Rig and Vehicle Fuel Conversion

Integrating Renewable Energy into Operations

EampP and Gathering

36

Pipeline and Storage OverviewNational Fuel Gas Supply Corporation ~ Empire Pipeline Inc

37

Pipeline amp Storage Segment Overview

(1) As of September 30 2018 as disclosed in the Companyrsquos fiscal 2018 form 10-K(2) As of December 31 2017 calculated from National Fuel Gas Supply Corporationrsquos and Empire Pipeline Incrsquos 2017 FERC Form-2 reports respectively

Empire Pipeline Inc

National Fuel Gas Supply Corporation

Empire Pipeline

Supply Corp

Contracted Capacity(1) Firm Transportation 3187 MDth per day Firm Storage 71938 Mdth (fully subscribed)

Rate Base(2) ~$820 million FERC Rate Proceeding Status

Rate case settlement extension approved Nov lsquo15 Rate case filing expected by 73119

Contracted Capacity(1) Firm Transportation 978 MDth per day Firm Storage 3753 Mdth (fully subscribed)

Rate Base(2) ~$249 million FERC Rate Proceeding Status

Rate case settlement in principle reached on 122118 FERC approval pending

New transportation rates went into on 1119

Pipeline amp Storage

38

All Seneca volumes will flow through wholly-owned NFG gathering facilities

FM100 Project - Consolidated Benefit for NFG

330000 Dthd of new transportation capacity from WDA and EDA acreage positions to premium markets

New Transco capacity (Leidy South) 330000 Dthday

Rate(1) competitive with other expansion project rates in Senecarsquos current transportation portfolio

Delivery Point(s) Transco Zone 6 interconnections

Seneca

Lease to Transco of new capacity 330000 Dthday

Estimated annual lease revenues ~$35 million

Target In-Service late calendar year 2021

Supply Corp

Project expected to provide long-term earnings uplift to Seneca Supply Corp and Gathering

Pipeline amp Storage

Gathering

(1) Includes lease of new capacity from Supply Corp to Transco

39

FM100 Project ndash Significant Investment by Supply Corp

Pipeline amp Storage

Estimated Capital Cost $280 million(1)

Facilities (all in Pennsylvania) include Approximately 30 miles of new pipeline 2 new compressor stations (totaling

approximately 37000 HP) New interconnection station and modification

of existing interconnection station Abandonment of approximately 45 miles of

existing pipeline and compressor station Regulatory Process

Pre-filing application submitted to FERC in 2017 for original modernization project

FERC 7(b) 7(c) filing expected summer 2019

(1) Includes expansion and modernization portions of the project

40

Empire North Project

Target In-Service second half of fiscal 2020

Est Capital Cost $145 million

Est Annual Revenues ~$25 million

Receipt Point Jackson (Tioga Co Pa production)

Design Capacity and Delivery Points 175000 Dthd to Chippawa (TCPL interconnect)

30000 Dthd to Hopewell (TGP 200 interconnect)

Customers Fully subscribed (205000 Dthday)

Major Facilities 2 new compressor stations in NY (1) amp Pa (1)

No new pipeline construction

Regulatory Process FERC 7(c) application filed on 21618

FERC Environmental Assessment issued 103018

Pipeline amp Storage

Fully Subscribed Project will Provide 205000 Dthday of Incremental Firm Transportation

41

National Fuel Remains Committed to Northern Access Project

Target In-Service as early as fiscal 2022

Total Cost ~$500MM (~$76MM spent to date)

Estimated Annual Revenues ~$84 million

Delivery Points

350000 Dthd to Chippawa (TCPL interconnect)

140000 Dthd to Hopewell (TGP 200 line)

Regulatory Status

February 3 2017 ndash FERC 7(c) certificate issued

August 6 2018 ndash FERC issued Order finding that NY DEC waived water quality certification

Supply and Empire currently working to finalize remaining federal authorizations

Pipeline amp Storage

To Dawn

42

Continued Expansion of the NFG Supply System

Line N Expansion Opportunities

Line N to Monaca Project Project Firm transportation service to a new ethane

cracker facility being built by Shell Chemical Appalachia LLC

Target In-Service July 2019

Estimated Capital Cost $23 million

Contracted Capacity 133000 Dthday

Additional Line N Expansion Opportunity (Supply OS 221) Project New firm transportation service for on-system

demand

Open Season Capacity Awarded 165000 to foundation shipper Precedent agreement in negotiations

Pipeline amp Storage

43

Pipeline amp Storage Customer Mix

Producer33

LDC42

Marketer10

Outside Pipeline

9

End User6

42 MMDthd

(1) Contracted as of 10312018

Customer Transportation by Shipper Type(1) Affiliated Customer Mix (Contracted Capacity)

66

521

41

34

9579

59

LDCs Producers Marketers FirmStorage

Affiliated Non-Affiliated

Firm Transport

Pipeline amp Storage

44

Utility OverviewNational Fuel Gas Distribution Corporation

45

New York amp Pennsylvania Service Territories

New York

Total Customers(1) 535800ROE 87 (NY PSC Rate Case Order April 2017)Rate Mechanismso Revenue Decouplingo Weather Normalizationo Low Income Rateso Merchant Function Charge (Uncollectibles Adj)o 9010 Sharing (Large Customers)o System Modernization Tracker

Pennsylvania

Total Customers(1) 214400ROE Black Box Settlement (2007)Rate Mechanismso Low Income Rateso Merchant Function Charge

(1) As of September 30 2018

Utility

46

New York Rate Case Outcome

Rate Order Summary

Revenue Requirement $59 million

Rate Base $704 million

Allowed Return on Equity (ROE) 87

Capital Structure 429 equity

Other notable items

New rates became effective 5117

Retains rate mechanisms in place under prior order (revenue decoupling weather normalization merchant function charge 9010 large customer sharing)

No stay-out clause

System modernization tracker for Leak Prone Pipe (LPP)

Earnings sharing started 4118 (5050 sharing starts at earnings in excess of 92)

Article 78 appeal filed on 72817 with oral argument completed in January 2019

On April 20 2017 the New York Public Service Commission issued a Rate Order relating to NFG Distributionrsquos rate case (No 16-G-0257) filed in April 2016

Utility

47

Utility Continues its Significant Investments in Safety

$544$618 $636

$699

$944$980

$809$856

$90-100

$00

$250

$500

$750

$1000

$1250

2015 2016 2017 2018 2019E

Cap

ital E

xpen

ditu

res

($ m

illio

ns)

Fiscal Year

Capital Expenditures for Safety Total Capital Expenditures

Modernization Spending in NY Expected to Grow Gross Margin By $2 MM - $5 MM in FY 2019

(1)

(1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation

Utility

System modernization tracker in NY allows recovery of pipeline replacementcosts which is expected to drive modest gross margin and rate base growth

48

Accelerating Pipeline Replacement amp Modernization

Wrought Iron

Plastic

CoatedBare

120130

146 144159

2014 2015 2016 2017 2018Calendar Year

NY9726 miles

PA4830 miles

No Cast Iron Mains in Pa

Miles of Utility Main Pipeline ReplacedUtility Mains by Material(1)

Wrought Iron

Cast Iron

Plastic

Coated Bare

Utility

(1) All values are reported on a calendar year basis as of December 31 2018

49

A Proven History of Controlling Costs

$200 $189 $195

$166 $166

$31 $31

$197 $197

$0

$50

$100

$150

$200

$250

2015 2016 2017 2018 TTM 123118

Fiscal Year

OampM Expense Non-Service Pension Costs

OampM Expense ($ millions)

Utility

(1)

(1) For purposes of comparability to FY 2015 2016 and 2017 Utility Operation and Maintenance Expense for FY 2018 and the twelve months ended December 31 2018 was adjusted by approximately $314 million and $312 million respectively to include non-service pension costs which were re-classified as Other Income (Deductions) as of October 1 2018 on the Companyrsquos Income Statement See Slide 64 for non-GAAP reconciliation of Adjusted Operation and Maintenance Expense to Operation and Maintenance Expense by segment

50

Consolidated Financial OverviewUpstream I Midstream I Downstream

51

Adjusted Operating Results ($ per share)(1)

Diversified Balanced Earnings and Cash Flows

(1) A reconciliation of Adjusted Operating Results to Earnings per Share by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation(2) Consolidated Adjusted EBITDA includes Energy Marketing and Corporate amp All Other Segments A reconciliation of Adjusted EBITDA to Net Income by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in

the Business is included at the end of this presentation

Adjusted EBITDA ($ millions)(2)

$176 $179

$184 $181

$92 $97

$318 $327

$761 $775

$-

$200

$400

$600

$800

FY 2018 TTM 123118

$059 Utility

$097 Pipeline amp Storage

$057 Gathering

$125 Exploration

amp Production

$334 $345 to $365

$-

$100

$200

$300

$400

FY 2018 FY 2019 Guidance

Rate Regulated

40-45

$728

Rate Regulated

~46

52

$89 $94 $98 $81 $86 $90-$100

$140$230

$114 $95 $93 $120-$150

$138$118

$54$33 $48

$55-$65

$603$557

$99 $246$356

$460-$495

$970 $1001

$366$455

$583

$725-$810

$0

$250

$500

$750

$1000

$1250

2014 2015 2016 2017 2018 2019GuidanceFiscal Year

Exploration amp Production

Gathering

Pipeline amp Storage

Utility

Disciplined Flexible Capital Allocation

(2)

(1) Total Capital Expenditures include Energy Marketing Corporate and All Other A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation (2) FY16 FY17 and FY18 reflects the netting of $157 million $7 million and $17 million respectively of up-front proceeds received from joint development partner for working interest in joint development wells and $21M in intercompany asset transfers in FY18

Capital Expenditures by Segment ($ millions)(1)

53

Maintaining Strong Balance Sheet amp Liquidity

Total Equity49

Total Debt51

$42 Billion Total Capitalizationas of December 31 2018

218 x251 x 245 x 247 x 256 x

2015 2016 2017 2018 TTM 123118Fiscal Year End

Net Debt Adjusted EBITDA(1) Capitalization

Debt Maturity Profile ($MM) Liquidity

Committed Credit FacilitiesShort-term Debt OutstandingAvailable Short-term Credit FacilitiesCash Balance at 123118 Total Liquidity at 123118

$ 750 MM0 MM

750 MM110 MM

$ 860 MM

$500 $549 $500

$300 $300

$0

$200

$400

$600

(1) Net Debt is net of cash and temporary cash investments Reconciliations of Net Debt and Adjusted EBITDA to Net Income are included at the end of this presentation

54

Appendix

55

Safe Harbor For Forward Looking StatementsThis presentation may contain ldquoforward-looking statementsrdquo as defined by the Private Securities Litigation Reform Act of 1995 including statements regarding future prospectsplans objectives goals projections estimates of oil and gas quantities strategies future events or performance and underlying assumptions capital structure anticipatedcapital expenditures completion of construction projects projections for pension and other post-retirement benefit obligations impacts of the adoption of new accounting rulesand possible outcomes of litigation or regulatory proceedings as well as statements that are identified by the use of the words ldquoanticipatesrdquo ldquoestimatesrdquo ldquoexpectsrdquo ldquoforecastsrdquoldquointendsrdquo ldquoplansrdquo ldquopredictsrdquo ldquoprojectsrdquo ldquobelievesrdquo ldquoseeksrdquo ldquowillrdquo ldquomayrdquo and similar expressions Forward-looking statements involve risks and uncertainties which couldcause actual results or outcomes to differ materially from those expressed in the forward-looking statements The Companyrsquos expectations beliefs and projections are expressedin good faith and are believed by the Company to have a reasonable basis but there can be no assurance that managementrsquos expectations beliefs or projections will result or beachieved or accomplished

In addition to other factors the following are important factors that could cause actual results to differ materially from those discussed in the forward-looking statements delaysor changes in costs or plans with respect to Company projects or related projects of other companies including difficulties or delays in obtaining necessary governmentalapprovals permits or orders or in obtaining the cooperation of interconnecting facility operators governmentalregulatory actions initiatives and proceedings including thoseinvolving rate cases (which address among other things target rates of return rate design and retained natural gas) environmentalsafety requirements affiliate relationshipsindustry structure and franchise renewal changes in laws regulations or judicial interpretations to which the Company is subject including those involving derivatives taxessafety employment climate change other environmental matters real property and exploration and production activities such as hydraulic fracturing financial and economicconditions including the availability of credit and occurrences affecting the Companyrsquos ability to obtain financing on acceptable terms for working capital capital expendituresand other investments including any downgrades in the Companyrsquos credit ratings and changes in interest rates and other capital market conditions changes in the price ofnatural gas or oil impairments under the SECrsquos full cost ceiling test for natural gas and oil reserves factors affecting the Companyrsquos ability to successfully identify drill for andproduce economically viable natural gas and oil reserves including among others geology lease availability title disputes weather conditions shortages delays orunavailability of equipment and services required in drilling operations insufficient gathering processing and transportation capacity the need to obtain governmentalapprovals and permits and compliance with environmental laws and regulations increasing health care costs and the resulting effect on health insurance premiums and on theobligation to provide other post-retirement benefits changes in price differentials between similar quantities of natural gas or oil sold at different geographic locations and theeffect of such changes on commodity production revenues and demand for pipeline transportation capacity to or from such locations other changes in price differentialsbetween similar quantities of natural gas or oil having different quality heating value hydrocarbon mix or delivery date the cost and effects of legal and administrative claimsagainst the Company or activist shareholder campaigns to effect changes at the Company uncertainty of oil and gas reserve estimates significant differences between theCompanyrsquos projected and actual production levels for natural gas or oil changes in demographic patterns and weather conditions changes in the availability price oraccounting treatment of derivative financial instruments changes in laws actuarial assumptions the interest rate environment and the return on plantrust assets related to theCompanyrsquos pension and other post-retirement benefits which can affect future funding obligations and costs and plan liabilities changes in economic conditions includingglobal national or regional recessions and their effect on the demand for and customersrsquo ability to pay for the Companyrsquos products and services the creditworthiness orperformance of the Companyrsquos key suppliers customers and counterparties the impact of potential information technology cybersecurity or data security breaches economicdisruptions or uninsured losses resulting from major accidents fires severe weather natural disasters terrorist activities or acts of war significant differences between theCompanyrsquos projected and actual capital expenditures and operating expenses or increasing costs of insurance changes in coverage and the ability to obtain insurance

Forward-looking statements include estimates of oil and gas quantities Proved oil and gas reserves are those quantities of oil and gas which by analysis of geoscience andengineering data can be estimated with reasonable certainty to be economically producible under existing economic conditions operating methods and governmentregulations Other estimates of oil and gas quantities including estimates of probable reserves possible reserves and resource potential are by their nature more speculativethan estimates of proved reserves Accordingly estimates other than proved reserves are subject to substantially greater risk of being actually realized Investors are urged toconsider closely the disclosure in our Form 10-K available at wwwnationalfuelgascom You can also obtain this form on the SECrsquos website at wwwsecgov

For a discussion of the risks set forth above and other factors that could cause actual results to differ materially from results referred to in the forward-looking statements seeldquoRisk Factorsrdquo in the Companyrsquos Form 10-K for the fiscal year ended September 30 2018 and the Forms 10-Q for the quarter ended March 31 2018 June 30 2018 and December31 2018 The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date thereof or to reflect the occurrence ofunanticipated events

Appendix

7

1 Production and Gathering Growth of 15-20 Through 2022

Production Growth Supported by Firm Transportation Portfolio

(1) Production trend line represents 175 net growth on average from fiscal 2018 through fiscal 2022

2355 2709

3115

1781 210-230

0

50

100

150

200

250

300

350

400

2018 2019E 2020 2021 2022

Sene

ca N

et P

rodu

ctio

n (B

cfe)

15 Annual Growth

20 Annual Growth

$1079$130-$140

$0

$50

$100

$150

$200

$250

2018 2019E 2020 2021 2022G

athe

ring

Rev

enue

s ($

MM

)

15 Annual Growth

20 Annual Growth

Production Growth Drives Significant Increase in Gathering Revenues

EampP3

(2) Revenue trend line represents 175 growth on average from fiscal 2018 through fiscal 2022

8

Utilization of Existing Infrastructure for Ongoing Utica Development Amplifies Consolidated Returns

L Leveraging Existing Infrastructure to Enhance Returns

(1) Approximate WDA Marcellus gathering facility costs for 192 wells drilled and completed as of September 30 2018 (2) Estimated WDA Utica gathering facility costs for the assumed 120 well locations in Clermont Rich Valley area of redevelopment (3) Internal Rate of Return for Seneca WDA includes estimated well costs under current cost structure and anticipated LOE and Gathering costs Internal Rate of Return for Seneca WDA and Gathering includes expected gathering capital expenditures

through FY 2022 well costs under current cost structure and non-gathering LOE

Gathering CapExWell

($ thousands)Marcellus (pre-2019) $1489(1)

Utica (2019-2022) $392(2)

Gathering Pipelines

Compression

Water Handling Facilities

Roadways and Pads

Gathering Costs in Western Development Area (CRV) 10+ IRR Uplift

Expected(3)

Requires modest investment in new Gathering facilities to support production growth

Utica development on Marcellus pads allows use of existing

Resulting in significant consolidated return uplift for EampP and Gathering

4

9

$1 Billion+ Backlog in Pipeline amp Storage Projects

Line N to Monaca - $23 MM (July 2019)(1)

Empire North - $145 MM (second half of fiscal 2020)

FM100 - $280 MM (late calendar 2021)

bull Companion project to Seneca-anchored Leidy South project

Northern Access - $500 MM (as early as fiscal 2022)

Supply Corp Modernization - $150 - $250 MM (fiscal 2019-2022)

FUTURE INVESTMENTS = $11 ndash $12 Billion

FUTURE EXPANSION REVENUES = ~$150 Million

Line N toMonaca

Northern Access

FM100

Empire North

5

(1) Parentheticals represent target in-service dates for the respective expansion projects

10

Financial Highlights

First Quarter Fiscal 2019

11

673 572 361458

Net

Oil

and

Gas

Pr

oduc

tion

First Quarter Fiscal 2019 Results and Drivers

Exploration amp Production

$034

Exploration amp Production

$037

Gathering $013

Gathering $016

Pipeline amp Storage

$029

Pipeline amp Storage

$029

Utility $025

Utility $030

$102

$112

Energy Marketing $001 Energy Marketing ($001)CorporateAll Other $001

Q1 FY18 Q1 FY19

Adjusted Operating Results ($share)(1)

(1) Adjusted Operating results of $102 for Q1 Fiscal 2018 and $112 for Q1 Fiscal 2019 include operating results of Energy Marketing and Corporate amp All Other segments See slide 61 for a Reconciliation of Adjusted Operating Results to Earnings Per Share(2) Realized price after hedging

$5979 $6170 $272 $261

Q1 FY 2018 Q1 FY 2019

Oil

and

Gas

Pr

icin

g(2)

Natural Gas ($Mcfe)Crude Oil ($Bbl)

Oil Prices

Natural Gas Prices

$238 $297

Gat

herin

g R

even

ue ($

MM

)Increased Seneca Natural Gas Production

Drivers

Natural Gas Production

Oil Production(sale of Sespe field)

Crude Oil (Mbbl) Natural Gas (Bcf)

12

Earnings Guidance

FY2018 Adjusted Operating Results

Non-regulated Businesses

Exploration amp ProductionGathering

$334 share(1) $345 to $365 shareFY2019 Earnings Guidance

Seneca Net Production 210 to 230 Bcfe Gathering Revenues $130-140 million

Natural Gas ~$245Mcf(2) (vs $252Mcf in FY 2018) Crude Oil ~$59Bbl(3) (vs $5866Bbl in FY 2018)

Key Guidance Drivers

(1) Excludes the $1035 million or $120 per share reduction in tax expense due to the remeasurement of deferred taxes resulting from the 2017 Tax Reform Act See non-GAAP disclosure on slide 61 of this presentation(2) Assumes NYMEX natural gas pricing of $325MMBtu (winter) and $275MMBtu (summer) and basin spot pricing of $275MMBtu (winter) and $225MMBtu (summer) for FY19 and reflects the impact of existing financial hedges firm sales

and firm transportation contracts(3) Assumes NYMEX (WTI) oil pricing of $5500Bbl and California-MWSS pricing differentials of 102 to WTI for FY19 and reflects impact of existing financial hedge contracts

Production amp Gathering Throughput

Realized natural gas prices (after-hedge)

Utility Operating Income

Regulated BusinessesPipeline amp StorageUtility

Guidance assumes normal weather modestly higher gross margin expected to be offset by cost inflation

~$285 million in revenues (expected decrease primarily due to expiration of contract on Empire system)

Pipeline amp Storage Revenues

Tax Reform

Realized oil prices (after-hedge)

Lower effective tax rate Effective tax rate ~24-25 (federal rate 21)

13

Exploration amp Production and Gathering OverviewSeneca Resources Company LLC ~ National Fuel Gas Midstream Company LLC

14

Proved Reserves

385 337 290 302 277

16832142

16751973

2357

1914

2344

1849

2154

2523

0

500

1000

1500

2000

2500

3000

2014 2015 2016 2017 2018At September 30

Natural Gas (Bcf)

Crude Oil (MMbbl)

361 Reserve Replacement Rate

Seneca Drill-bit FampD = $066Mcfe(1)

Appalachia Drill-bit FampD = $065Mcfe(1)

(1) Seneca ldquoDrill-bitrdquo finding and development (ldquoFampDrdquo) costs exclude the impact of reserve revisions

Total Proved Reserves (Bcfe)

Fiscal 2018 Proved Reserves Stats

$138

$112

$132

$098

$074

$050

$100

$150

2014 2015 2016 2017 2018

3-Year Average FampD Cost ($Mcfe)

70

30

PDPs PUDs

EampP and Gathering

15

3 rig development program with second rig in WDA focused on Utica

15-20 net production growth expected through fiscal 2022

New EDA Utica development with production expected in Q2 fiscal 2019

Utilize new Atlantic Sunrise firm transportation capacity

Layer-in firm sales to take advantage of attractive regional pricing

Gross production growth will benefit NFGrsquos Gathering segment

Minimal capital investment in California to generate significant cash flow

Growing Production within Disciplined Capital Program

205 194 176 ~16

1406 1541 1605194-214

1611 1735 1781210-230

0

50

100

150

200

250

2016 2017 2018 2019E

$38 $38 $26 ~$25$61

$208$330

$435-$470

$99

$246

$356

$460-$495

$0

$200

$400

$600

2016 2017 2018 2019E

Appalachia West Coast (California)

Near-Term Growth Strategy EampP Net Capital Expenditures ($ millions)(1)

EampP Net Production (Bcfe)

EampP and Gathering

(1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentationFY16 FY17 and FY18 guidance reflects the netting of $157 million $7 million and $17 million respectively of up-front proceeds received from joint development partner for working interest in joint development wells

16

Significant Appalachian Acreage Position

Average gross production ~311 MMcfd

Mostly leased (16-18 royalty) with no significant near-term lease expirations

~90 remaining Marcellus amp Utica locations economic at ~$184Mcf

Additional Marcellus (Tioga Co) amp Geneseo (Lycoming Co) potential

Eastern Development Area (EDA)

Western Development Area (WDA)

Average gross production(1) ~327 MMcfd Large inventory of Marcellus amp Utica

locations economic at ~$200Mcf Royalty free mineral ownership

enhances well economics Highly contiguous nature drives cost and

operational efficiencies

EampP and Gathering

EDA - 70000 AcresWDA - 715000 Acres

(1) Average EDA and WDA gross production as well as WDA-CRV Utica production (see slide 19) and CovingtonTract 595 Production (see slide 23) is for the quarter ended December 31 2018

17

Western Development AreaMarcellus Core Acreage

vs Utica Appraisal Trend(1)

(1) The Utica Shale lies approximately 5000 feet beneath Senecarsquos WDA Marcellus acreage (2) Appraisal program currently in progress Additional tests are planned Prior Marcellus delineation tests helped define the prospective limits of the Marcellus core acreage planned testing in the Utica expected to do the same

Area of Re-Development ~120 Utica locations on existing Marcellus pads

Key Utica testsPast Marcellus delineation testsUtica Trend (currently evaluating)Marcellus Core Acreage

Large well inventory economic at ~$200 Mcf

Marcellus Shale 600+ well locations remaining 200000 acres

Utica Shale 500+ potential locations across Utica trend evaluating extent of prospective acreage(2)

Fee acreage (no royalty) enhances economics and provides development flexibility

Addition of 2nd WDA drilling rig in Q3 FY18 focused on redevelopment of Clermont-Rich Valley acreage for Utica

Use of existing gathering pad and water infrastructure for Utica drives increased Appalachian program returns

Highly contiguous position drives best in class well costs

Utica test results on trend with other Utica wells in NE Pa

Long-term firm contracts support growth

Boone Mountain Utica Test Well23 Bcf 1000ft

Rich Valley Utica Test Well23 Bcf 1000ft

EampP and Gathering

WDA Highlights

18

WDA Utica Appraisal Results and Initial Type Curve

Tested producing from 17 Utica wells in WDA-CRV Higher pressure significantly enhances well

productivity (Utica ~5000rsquo deeper than Marcellus) Drawdown management is critical restricted

drawdown appears to improve well EURs Early production declines much shallower vs

Marcellus

WDA Utica Appraisal Update

WDA Economics

(1) Internal Rate of Return (IRR) is pre-tax and includes estimated well costs under current cost structure LOEand anticipated gathering tariffs

(2) Initial WDA-CRV Utica type curve based on production results and reservoir expectations from the first 5appraisal wells in the WDA-CRV area

(3) WDA-CRV Utica Average includes all 17 producing wells including 2 wells (pad E09-S) for which drawdownmanagement was not used

EampP and Gathering

EURBcf1000rsquo

Well Cost$M1000rsquo

IRR $225

Break-even15 IRR(1)

Utica - CRV 17 $887 23 $197

Marcellus 10 ndash 11 $643 19 $206

(2)

0

1

2

3

4

5

6

7

8

9

0 12 24 36 48 60 72 84 96 108 120

Cum

ulat

ive

Prod

uctio

n B

CF

Months On

WDA-CRV Utica Wells - Normalized to 9000rsquoUtica Type Curve CRV Utica AverageWDA Marcellus Type Curve Boone Mountain Appraisal WellWDA-CRV Utica Type Curve(2) WDA-CRV Utica Average(3)

0005101520253035

0 2 4 6 8 10 12

19

Transitioning to Utica Development in CRV

WDA-CRV Marcellus(Depth ~7000 feet)

WDA-CRV Utica(Depth ~12000 feet)

Avg CRV Marcellus Production 270 MMcfd

Rem Avg EUR 10-11 Bcf 1000 lat ft

Rem Avg Well Costs = $643lat ft

120+ locations on existing Marcellus pads

Est EURs 17 Bcf 1000 lat ft

Est Development Well Costs = $887lat ft

CRV Utica Transition Plan

1)Finish Marcellus Pads in Development

Drill 24 complete 24 Marcellus wells

2)Continue Optimizing Utica DampC design

Additional optimization wells focusing on

Completion design

Landing zone targets

3)Continue transition to Utica development

Future drilling on multi-well pads

Continue using optimization results to determine development well design

Tailor development plan to use existing pad water and gathering infrastructure

CRV Utica Development Utilizes Existing Pad Water and Gathering Infrastructure to Drive Economics

EampP and Gathering

Rich Valley Utica Test

Existing Line

Leased

Seneca Fee

Producing

FY19 Producer

Development

20

Leveraging Existing Gathering Water and Pad Infrastructure Enhances Returns

Limited New Infrastructure Needed to Support Production Growth

WDA Well Costs(1) WDA Consolidated Economics

Steady activity levels and coordination between upstream and midstream activities

enhance returns provide economies of scale and significant operational flexibility

(1) WDA Marcellus well costs reflect drilling completion amp gathering costs for 192 drilled and completed wells as of 93018 WDA Utica well costs reflect expected drilling completion amp gathering costs for the ~120 well locations in area of redevelopment (2) Internal Rate of Return for Seneca WDA includes estimated well costs under current cost structure and anticipated LOE and Gathering costs Internal Rate of Return for Seneca WDA and Gathering includes expected gathering capital expenditures

through FY 2022 well costs under current cost structure and non-gathering LOE

$685$887

$210

$0

$200

$400

$600

$800

$1000

Marcellus(Historic)

Utica - CRV(Current)

$ la

tera

l foo

t

Drilling amp Completion Gathering

$931$895

10 -11

17

00

03

06

09

12

15

18

Marcellus(Historic)

Utica - CRV(Current)

EUR

10

00 fe

et (B

cf)

60-70 EUR increase expected per well

Total cost per well expected to marginally increase

WDA EURs

At a $225 netback price consolidated Seneca WDA and Gathering IRR is

approximately 33 an uplift of ~12 over standalone Seneca WDA economics(2)

10+ IRR Uplift Expected

21

Integrated Development ndash WDA Gathering System

Current System In-Service

~78 miles of pipe 36220 HP of compression

Current Capacity 470 MMcf per day

Interconnects with TGP 300

Total Investment to Date $301 million

Future Build-Out

FY 2019 CapEx $10 - $15 million

Modest gathering pipeline and compression investment required to support Senecarsquos transition to Utica development

Opportunity for 300 miles of pipelines and five compressor stations (+60000 HP installed) as Senecarsquos drilling activity continues

Deliverability into TGP 300 and NFG Supply

Gathering System Build-Out Tailored to Accommodate Senecarsquos WDA Development

Clermont Gathering System Map

EampP and Gathering

22

WDA Firm Transportation and Sales Capacity

Will continue to layer-in firm sales deals of short and longer duration on TGP 300 to reduce spot exposure

WDA spot realizations track TGP Station 313 pricing typically 10cent - 30cent better than TGP Marcellus Zone 4

Leidy South will provide additional capacity to premium markets (Transco Zone 6)

WDA Exit Capacity Supports Long-term Production Growth and Enhances Consolidated Returns

WDA Contracted Firm Transport and Gross Sales Volumes (MDthd)

Seneca gross production trend

EampP and Gathering

0

100

200

300

400

500

600

700

Niagara Expansion Project (TGP and NFG)FT Capacity 158000 Dthd $067Dth

Firm Sales NYMEX amp DAWN

WDA - TGP 300Firm Sales

Leidy SouthTransco Zone 6

Markets330000 Dthd(1)

Will layer-in firm sales to minimize spot exposure

(1) Portion of Transco Project capacity will likely be utilized by EDA Lycoming County production

WDA Gas Marketing Strategy

23

Eastern Development Area

EDA Acreage ndash 70000 AcresEDA Highlights

1 DCNR Tract 007 (Tioga Co Pa)bull Utica development resumed in third quarter fiscal 2018

bull ~43 remaining Utica locations economic at ~$184 Mcf

bull Gathering Infrastructure NFG Midstream Wellsboro

bull Marcellus Shale expected to provide ~60 additional locations

EampP and Gathering

2

1

3

2 Covington amp DCNR Tract 595 (Tioga Co Pa)bull Marcellus locations fully developed (average daily gross production of ~93 MMcfd)

bull Gathering Infrastructure NFG Midstream Covington

bull Opportunity for future Utica appraisal

3 DCNR Tract 100 amp Gamble (Lycoming Co Pa)bull ~45 remaining Marcellus locations economic at ~$153 Mcfbull Firm Transportation Capacity Atlantic Sunrise (189 MDthd)

bull Gathering Infrastructure NFG Midstream Trout Run

bull Geneseo Shale expected to provide 100-120 additional locations

24

EDA Marcellus Lycoming County Development

Marcellus Development in Lycoming County has Resumed in Connection with Atlantic Sunrise

(1) Includes physical fixed price and NYMEX-based firm sales contracts that do not carry any additional transportation costs

EampP and Gathering

Prolific Marcellus acreage with peer leading well results

~45 remaining Marcellus locations economic at ~$153 Mcf

Near-term development focused on filling Atlantic Sunrise capacity

Existing Line

Leased

Seneca Fee

Producing

FY19 Producer

Development

0

50

100

150

200

250

Gro

ss F

irm V

olum

es (M

Dth

d)

EDA ndash Transco Firm Contracts

Atlantic Sunrise (Transco)FT Capacity 189405 Dthd

Cost $073DthFirm Sales NYMEX+

Transco Firm Sales(1)

25

EDA Utica Tioga County Development

Utica Development in Tioga County ndash Tract 007 Development Resumed in Q3 Fiscal 2018

In-Service November 2016

Lateral Length 4640 ft

30 Day IP 1000 ft 34 MMcfd

Est EUR 1000 ft 24 Bcf

Inventory ~43 locations economic at ~$184 Mcf

Targeting to grow production by 100 to 150 MDthd by fiscal 2020

Expected Development Costs $1045 per lateral ft

Gathering Infrastructure NFG Midstream Wellsboro

Modest build-out required to connect to TGP 300

SalesTakeaway Strategy Layer-in firm sales with shippers holding capacity on TGP 300

(1) Includes physical fixed price and NYMEX-based firm sales contracts that do not carry any additional transportation costs

Tract 007 Utica Appraisal Well Results vs Industry

EampP and Gathering

0

100000

200000

300000

400000

500000

600000

700000

800000

0 100 200 300

Nor

mal

ized

Cum

ulat

ive

(Mcf

10

00rsquo)

Days On ProductionIndustry PotterTioga Wells Seneca DCNR 007 73H

0

25

50

75

100

125

150

Gro

ss F

irm V

olum

es (M

Dth

d)

EDA ndash TGP 300 Firm Contracts

Northeast Supply Diversification ProjectFT Capacity 50000 Dthd $050Dth

Firm Sales NYMEX and DAWN

EDA - TGP 300Firm Sales(1)

26

Integrated Development ndash EDA Gathering Systems

Total Investment (to date) ~$46 million FY 2019 Estimated Capital Expenditures $1 MM - $2 MM Capacity 220000 Dth per day (Interconnect w TGP 300) Production Source Seneca Resources ndash Tioga Co (Covington and DCNR Tract 595)

Total Investment (to date) ~$208 million FY 2019 Estimated Capital Expenditures $25 MM - $35 MM Capacity 466000 to 585000 Dth per day (Interconnect w Transco) Production Source Seneca Resources ndash Lycoming Co (DCNR Tract 100 and Gamble) Future third-party volume opportunities

Covington Gathering System

Trout Run Gathering System

Gathering Segment Supporting Senecarsquos EDA Production amp Future Development

Wellsboro Gathering System Total Investment (to date) ~$14 million FY 2019 Estimated Capital Expenditures $8 MM - $15 MM Capacity up to 200000 Dth per day (Interconnect w TGP 300) Production Source Seneca Resources ndash Tioga Co (DCNR Tract 007)

EampP and Gathering

2

1

3

27

Long-term Contracts Supporting Appalachian Growth

(1) Represents base firm sales contracts not tied to firm transportation capacity Base firm sales are either fixed priced or priced at an index (eg NYMEX ) +- a fixed basis and do not carry any transportation costs

Seneca continues to layer-in firm sales contracts with attractive realizations to lock-in drilling economics and minimize spot exposure ahead of firm transportation in-service dates

EampP and Gathering

-

100

200

300

400

500

600

700

800

900

1000

1100

1200

FY 2019 FY 2020 FY 2021 FY 2022Northeast Supply Diversification 50000 Dthd

Niagara Expansion (TGP amp NFG)Delivery Markets Canada-Dawn amp TETCO

158000 Dthd

Atlantic Sunrise (Transco)Delivery Markets Mid-Atlantic amp Southeast US

189405 Dthd

In-BasinFirm Sales

Contracts(1)

Leidy South (Transco amp NFG)

Transco Zone 6 Markets330000 Dthd

Seneca Appalachia Natural Gas MarketingGross Firm Contract Volumes (Mdthday)

28

297000 ($061)

305200 ($061)

305600 ($063)

337000 ($057)

370800 ($024)

369600 ($060)

367900 ($067)

33400 ($070)74500 ($077) 74900 ($077)

81100 ($078)

85900 ($078)

92000 ($073)

91300 ($073)

178800 $255

196000 $234

195500 $234

149900 $232

129500 $230

105400 $222

104500 $222

~517800 509200 575700 576000 568000 586200 567000 563700

Q1 FY19 Q2 FY19 Q3 FY19 Q4 FY19 Q1 FY20 Q2 FY20 Q3 FY20 Q4 FY20

Fixed Price Dawn NYMEX

Near-term Firm Sales Provide Market amp Price Certainty

Net Contracted Firm Sales Volumes (Dth per day)Contracted Index Price Differentials ($ per Dth)(1)

(1) Values shown represent the weighted average fixed price or contracted fixed differential relative to NYMEX (netback price) less any associated transportation costs

Actual Daily Net

Production

641200 716500 708700 693500 708400 674400 667000Gross Firm Sales Volumes (Dthd)

EampP and Gathering

29

California Oil

Stable Oil Production | Minimal Capital Investment | Steady Free Cash Flow

1

2

3

4

5

Location Formation Production Method

FY18 Daily Production(net Boed)

1 East Coalinga Other Temblor Primary 512

2 North Lost Hills

Tulare amp Etchegoin

PrimarySteam flood 892

3 South Lost Hills

Monterey Shale Primary 1359

4 North Midway Sunset

Tulare amp Potter Steam flood 2786

5 South Midway Sunset Antelope Steam flood 2048

TOTAL WEST DIVISION NET PRODUCTION(1) 7597 Boed

EampP and Gathering

(1) West division net production for FY 2018 excludes production from Sespe field which was divested on May 1 2018

30

California Capital Expenditures vs Production

9341 8863

8033 ~7300

2016 2017 2018 2019

Fiscal Year

West Division Average Net Daily Production (Boe)West Division Annual Capital Expenditures ($ MM)(1)

$38 $38

$26 ~$25

2016 2017 2018 2019

Fiscal YearGuidance Guidance

(1) Seneca West Division capital expenditures includes Seneca corporate and eliminations

EampP and Gathering

Sepse Sale Closed on 5118(reduced production by ~900 boed)

31

Pioneer

South MWSS

Acreage

North MWSS

AcreageSec 17N

4149 51

NMWSS amp 17N SMWSS amp Pioneer East Coalinga

California Development Activities

Modest near-term capital program focused on locations that earn attractive returns in current oil price environment

AampD will focus on low cost bolt-on opportunities

Sec 17 Pioneer and East Coalinga development to provide future growth

North

Project IRRs at $55Bbl(1)

(1) Reflects pre-tax IRRs at a $55Bbl WTI

EampP and Gathering

Seneca West Economics

South

East Coalinga

North

South

32

Fiscal 2019 Production and Price Certainty

~49 Bcfe

210 ndash 230 Bcfe

~114 Bcf

~29 Bcf (2)

16+- Bcf~12 Bcfe

0

40

80

120

160

200

240

YTD FY19Actuals

Fixed Price + FirmSales w Hedge

Firm Sales(Unhedged)

Spot Sales California TotalSeneca

Prod

uctio

n (B

cfe)

(1) Average realized price reflects uplift from financial hedges less fixed differentials under firm sales contracts and any firm transportation costs(2) Indicates firm sales contracts with fixed index differentials but not backed by a matching financial hedge

114 Bcf locked-in realizing net ~$241Mcf (1)

29 Bcf of additional basis protection

Spot production assumed to be sold

at ~$275Mmbtu(winter) and ~$225

(summer)

143 Bcf of Appalachian Production Protected by Firm Sales for Remainder of Year

79 of oil production hedged at $5757 Bbl

EampP and Gathering

33

Strong Hedge Book

Natural Gas Swap amp Fixed Physical Sales Contracts (Millions MMBtu)

(1) Fixed price physical sales exclude joint development partnerrsquos share of fixed price contract WDA volumes as specified under the joint development agreement(2) Reflects percentage of projected production for FY19 hedged at the midpoint of the production guidance range(3) Senecarsquos remainder FY19 Production reflects the total FY19 production guidance of 210-230 Bcfe or 220 Bcfe at the midpoint less Q1 actual production

Crude Oil Swap Contracts (Thousands Bbls)

13591188

732

456

0

500

1000

1500

2000

2500

FY 2019 FY 2020 FY 2021 FY 2022

NYMEX (WTI)

Brent

FY 19 Crude Oil79 Hedged (2)

FY 2019 Remaining Production (3)

EampP and Gathering

1174

709

469 406

0

50

100

150

200

250

FY 2019 FY 2020 FY 2021 FY 2022

NYMEX Swaps

Dawn Swaps

Fixed Price Physical Sales

(1)

FY 2019 Remaining Production (3)

FY 19 Nat Gas71 Hedged (2)

34

$065 $070$070 -$075

FY 2017 FY 2018 FY 2019E

$060 $060 $060

$011 $009 $007$071 $069 ~$067

FY 2017 FY 2018 FY 2019E Gathering amp Transport LOE (non-Gathering) GampA Taxes amp Other

Seneca Operating Costs

Competitive low cost structure in Appalachia and California supports strong cash margins

Gathering fee generates significant revenue stream for affiliated gathering company

Seneca DDampARate

$Mcfe

$054 $054 $056

$042 $038 $031

$034 $034 $030

$017 $014 $015

$147 $140 ~$132

FY 2017 FY 2018 FY 2019E

(1)

$1791$1746~$2050

FY 2017 FY 2018 FY 2019E

Appalachia LOE amp Gathering $Mcfe

California LOE$Boe

Total Seneca Cash OpEx$Mcfe

(1)

(2)

(2)

(1) GampA estimate represents the midpoint of the GampA guidance range of $025 to $035 for fiscal 2019(2) The total of the two LOE components represents the midpoint of the LOE guidance range of $085 to $090 for fiscal 2019

EampP and Gathering

35

Senecarsquos Continuing Commitment to the Environment

Produced Water Recycled in Appalachia

100 70Recycled Water

Used in New Shale Well

Completions

Water and Fluids Management Air Quality and Emissions

Seneca Resources Water OperationsFiscal 2018

Seneca Resources Remains Focused on Minimizing GHG Emissions

The Environmental Partnership

EPA Natural Gas Star Program

Green Completions (all fiscal 2018 wells)

Ultrasonic Leak Detection Technology

Emissions Controls

Rig and Vehicle Fuel Conversion

Integrating Renewable Energy into Operations

EampP and Gathering

36

Pipeline and Storage OverviewNational Fuel Gas Supply Corporation ~ Empire Pipeline Inc

37

Pipeline amp Storage Segment Overview

(1) As of September 30 2018 as disclosed in the Companyrsquos fiscal 2018 form 10-K(2) As of December 31 2017 calculated from National Fuel Gas Supply Corporationrsquos and Empire Pipeline Incrsquos 2017 FERC Form-2 reports respectively

Empire Pipeline Inc

National Fuel Gas Supply Corporation

Empire Pipeline

Supply Corp

Contracted Capacity(1) Firm Transportation 3187 MDth per day Firm Storage 71938 Mdth (fully subscribed)

Rate Base(2) ~$820 million FERC Rate Proceeding Status

Rate case settlement extension approved Nov lsquo15 Rate case filing expected by 73119

Contracted Capacity(1) Firm Transportation 978 MDth per day Firm Storage 3753 Mdth (fully subscribed)

Rate Base(2) ~$249 million FERC Rate Proceeding Status

Rate case settlement in principle reached on 122118 FERC approval pending

New transportation rates went into on 1119

Pipeline amp Storage

38

All Seneca volumes will flow through wholly-owned NFG gathering facilities

FM100 Project - Consolidated Benefit for NFG

330000 Dthd of new transportation capacity from WDA and EDA acreage positions to premium markets

New Transco capacity (Leidy South) 330000 Dthday

Rate(1) competitive with other expansion project rates in Senecarsquos current transportation portfolio

Delivery Point(s) Transco Zone 6 interconnections

Seneca

Lease to Transco of new capacity 330000 Dthday

Estimated annual lease revenues ~$35 million

Target In-Service late calendar year 2021

Supply Corp

Project expected to provide long-term earnings uplift to Seneca Supply Corp and Gathering

Pipeline amp Storage

Gathering

(1) Includes lease of new capacity from Supply Corp to Transco

39

FM100 Project ndash Significant Investment by Supply Corp

Pipeline amp Storage

Estimated Capital Cost $280 million(1)

Facilities (all in Pennsylvania) include Approximately 30 miles of new pipeline 2 new compressor stations (totaling

approximately 37000 HP) New interconnection station and modification

of existing interconnection station Abandonment of approximately 45 miles of

existing pipeline and compressor station Regulatory Process

Pre-filing application submitted to FERC in 2017 for original modernization project

FERC 7(b) 7(c) filing expected summer 2019

(1) Includes expansion and modernization portions of the project

40

Empire North Project

Target In-Service second half of fiscal 2020

Est Capital Cost $145 million

Est Annual Revenues ~$25 million

Receipt Point Jackson (Tioga Co Pa production)

Design Capacity and Delivery Points 175000 Dthd to Chippawa (TCPL interconnect)

30000 Dthd to Hopewell (TGP 200 interconnect)

Customers Fully subscribed (205000 Dthday)

Major Facilities 2 new compressor stations in NY (1) amp Pa (1)

No new pipeline construction

Regulatory Process FERC 7(c) application filed on 21618

FERC Environmental Assessment issued 103018

Pipeline amp Storage

Fully Subscribed Project will Provide 205000 Dthday of Incremental Firm Transportation

41

National Fuel Remains Committed to Northern Access Project

Target In-Service as early as fiscal 2022

Total Cost ~$500MM (~$76MM spent to date)

Estimated Annual Revenues ~$84 million

Delivery Points

350000 Dthd to Chippawa (TCPL interconnect)

140000 Dthd to Hopewell (TGP 200 line)

Regulatory Status

February 3 2017 ndash FERC 7(c) certificate issued

August 6 2018 ndash FERC issued Order finding that NY DEC waived water quality certification

Supply and Empire currently working to finalize remaining federal authorizations

Pipeline amp Storage

To Dawn

42

Continued Expansion of the NFG Supply System

Line N Expansion Opportunities

Line N to Monaca Project Project Firm transportation service to a new ethane

cracker facility being built by Shell Chemical Appalachia LLC

Target In-Service July 2019

Estimated Capital Cost $23 million

Contracted Capacity 133000 Dthday

Additional Line N Expansion Opportunity (Supply OS 221) Project New firm transportation service for on-system

demand

Open Season Capacity Awarded 165000 to foundation shipper Precedent agreement in negotiations

Pipeline amp Storage

43

Pipeline amp Storage Customer Mix

Producer33

LDC42

Marketer10

Outside Pipeline

9

End User6

42 MMDthd

(1) Contracted as of 10312018

Customer Transportation by Shipper Type(1) Affiliated Customer Mix (Contracted Capacity)

66

521

41

34

9579

59

LDCs Producers Marketers FirmStorage

Affiliated Non-Affiliated

Firm Transport

Pipeline amp Storage

44

Utility OverviewNational Fuel Gas Distribution Corporation

45

New York amp Pennsylvania Service Territories

New York

Total Customers(1) 535800ROE 87 (NY PSC Rate Case Order April 2017)Rate Mechanismso Revenue Decouplingo Weather Normalizationo Low Income Rateso Merchant Function Charge (Uncollectibles Adj)o 9010 Sharing (Large Customers)o System Modernization Tracker

Pennsylvania

Total Customers(1) 214400ROE Black Box Settlement (2007)Rate Mechanismso Low Income Rateso Merchant Function Charge

(1) As of September 30 2018

Utility

46

New York Rate Case Outcome

Rate Order Summary

Revenue Requirement $59 million

Rate Base $704 million

Allowed Return on Equity (ROE) 87

Capital Structure 429 equity

Other notable items

New rates became effective 5117

Retains rate mechanisms in place under prior order (revenue decoupling weather normalization merchant function charge 9010 large customer sharing)

No stay-out clause

System modernization tracker for Leak Prone Pipe (LPP)

Earnings sharing started 4118 (5050 sharing starts at earnings in excess of 92)

Article 78 appeal filed on 72817 with oral argument completed in January 2019

On April 20 2017 the New York Public Service Commission issued a Rate Order relating to NFG Distributionrsquos rate case (No 16-G-0257) filed in April 2016

Utility

47

Utility Continues its Significant Investments in Safety

$544$618 $636

$699

$944$980

$809$856

$90-100

$00

$250

$500

$750

$1000

$1250

2015 2016 2017 2018 2019E

Cap

ital E

xpen

ditu

res

($ m

illio

ns)

Fiscal Year

Capital Expenditures for Safety Total Capital Expenditures

Modernization Spending in NY Expected to Grow Gross Margin By $2 MM - $5 MM in FY 2019

(1)

(1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation

Utility

System modernization tracker in NY allows recovery of pipeline replacementcosts which is expected to drive modest gross margin and rate base growth

48

Accelerating Pipeline Replacement amp Modernization

Wrought Iron

Plastic

CoatedBare

120130

146 144159

2014 2015 2016 2017 2018Calendar Year

NY9726 miles

PA4830 miles

No Cast Iron Mains in Pa

Miles of Utility Main Pipeline ReplacedUtility Mains by Material(1)

Wrought Iron

Cast Iron

Plastic

Coated Bare

Utility

(1) All values are reported on a calendar year basis as of December 31 2018

49

A Proven History of Controlling Costs

$200 $189 $195

$166 $166

$31 $31

$197 $197

$0

$50

$100

$150

$200

$250

2015 2016 2017 2018 TTM 123118

Fiscal Year

OampM Expense Non-Service Pension Costs

OampM Expense ($ millions)

Utility

(1)

(1) For purposes of comparability to FY 2015 2016 and 2017 Utility Operation and Maintenance Expense for FY 2018 and the twelve months ended December 31 2018 was adjusted by approximately $314 million and $312 million respectively to include non-service pension costs which were re-classified as Other Income (Deductions) as of October 1 2018 on the Companyrsquos Income Statement See Slide 64 for non-GAAP reconciliation of Adjusted Operation and Maintenance Expense to Operation and Maintenance Expense by segment

50

Consolidated Financial OverviewUpstream I Midstream I Downstream

51

Adjusted Operating Results ($ per share)(1)

Diversified Balanced Earnings and Cash Flows

(1) A reconciliation of Adjusted Operating Results to Earnings per Share by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation(2) Consolidated Adjusted EBITDA includes Energy Marketing and Corporate amp All Other Segments A reconciliation of Adjusted EBITDA to Net Income by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in

the Business is included at the end of this presentation

Adjusted EBITDA ($ millions)(2)

$176 $179

$184 $181

$92 $97

$318 $327

$761 $775

$-

$200

$400

$600

$800

FY 2018 TTM 123118

$059 Utility

$097 Pipeline amp Storage

$057 Gathering

$125 Exploration

amp Production

$334 $345 to $365

$-

$100

$200

$300

$400

FY 2018 FY 2019 Guidance

Rate Regulated

40-45

$728

Rate Regulated

~46

52

$89 $94 $98 $81 $86 $90-$100

$140$230

$114 $95 $93 $120-$150

$138$118

$54$33 $48

$55-$65

$603$557

$99 $246$356

$460-$495

$970 $1001

$366$455

$583

$725-$810

$0

$250

$500

$750

$1000

$1250

2014 2015 2016 2017 2018 2019GuidanceFiscal Year

Exploration amp Production

Gathering

Pipeline amp Storage

Utility

Disciplined Flexible Capital Allocation

(2)

(1) Total Capital Expenditures include Energy Marketing Corporate and All Other A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation (2) FY16 FY17 and FY18 reflects the netting of $157 million $7 million and $17 million respectively of up-front proceeds received from joint development partner for working interest in joint development wells and $21M in intercompany asset transfers in FY18

Capital Expenditures by Segment ($ millions)(1)

53

Maintaining Strong Balance Sheet amp Liquidity

Total Equity49

Total Debt51

$42 Billion Total Capitalizationas of December 31 2018

218 x251 x 245 x 247 x 256 x

2015 2016 2017 2018 TTM 123118Fiscal Year End

Net Debt Adjusted EBITDA(1) Capitalization

Debt Maturity Profile ($MM) Liquidity

Committed Credit FacilitiesShort-term Debt OutstandingAvailable Short-term Credit FacilitiesCash Balance at 123118 Total Liquidity at 123118

$ 750 MM0 MM

750 MM110 MM

$ 860 MM

$500 $549 $500

$300 $300

$0

$200

$400

$600

(1) Net Debt is net of cash and temporary cash investments Reconciliations of Net Debt and Adjusted EBITDA to Net Income are included at the end of this presentation

54

Appendix

55

Safe Harbor For Forward Looking StatementsThis presentation may contain ldquoforward-looking statementsrdquo as defined by the Private Securities Litigation Reform Act of 1995 including statements regarding future prospectsplans objectives goals projections estimates of oil and gas quantities strategies future events or performance and underlying assumptions capital structure anticipatedcapital expenditures completion of construction projects projections for pension and other post-retirement benefit obligations impacts of the adoption of new accounting rulesand possible outcomes of litigation or regulatory proceedings as well as statements that are identified by the use of the words ldquoanticipatesrdquo ldquoestimatesrdquo ldquoexpectsrdquo ldquoforecastsrdquoldquointendsrdquo ldquoplansrdquo ldquopredictsrdquo ldquoprojectsrdquo ldquobelievesrdquo ldquoseeksrdquo ldquowillrdquo ldquomayrdquo and similar expressions Forward-looking statements involve risks and uncertainties which couldcause actual results or outcomes to differ materially from those expressed in the forward-looking statements The Companyrsquos expectations beliefs and projections are expressedin good faith and are believed by the Company to have a reasonable basis but there can be no assurance that managementrsquos expectations beliefs or projections will result or beachieved or accomplished

In addition to other factors the following are important factors that could cause actual results to differ materially from those discussed in the forward-looking statements delaysor changes in costs or plans with respect to Company projects or related projects of other companies including difficulties or delays in obtaining necessary governmentalapprovals permits or orders or in obtaining the cooperation of interconnecting facility operators governmentalregulatory actions initiatives and proceedings including thoseinvolving rate cases (which address among other things target rates of return rate design and retained natural gas) environmentalsafety requirements affiliate relationshipsindustry structure and franchise renewal changes in laws regulations or judicial interpretations to which the Company is subject including those involving derivatives taxessafety employment climate change other environmental matters real property and exploration and production activities such as hydraulic fracturing financial and economicconditions including the availability of credit and occurrences affecting the Companyrsquos ability to obtain financing on acceptable terms for working capital capital expendituresand other investments including any downgrades in the Companyrsquos credit ratings and changes in interest rates and other capital market conditions changes in the price ofnatural gas or oil impairments under the SECrsquos full cost ceiling test for natural gas and oil reserves factors affecting the Companyrsquos ability to successfully identify drill for andproduce economically viable natural gas and oil reserves including among others geology lease availability title disputes weather conditions shortages delays orunavailability of equipment and services required in drilling operations insufficient gathering processing and transportation capacity the need to obtain governmentalapprovals and permits and compliance with environmental laws and regulations increasing health care costs and the resulting effect on health insurance premiums and on theobligation to provide other post-retirement benefits changes in price differentials between similar quantities of natural gas or oil sold at different geographic locations and theeffect of such changes on commodity production revenues and demand for pipeline transportation capacity to or from such locations other changes in price differentialsbetween similar quantities of natural gas or oil having different quality heating value hydrocarbon mix or delivery date the cost and effects of legal and administrative claimsagainst the Company or activist shareholder campaigns to effect changes at the Company uncertainty of oil and gas reserve estimates significant differences between theCompanyrsquos projected and actual production levels for natural gas or oil changes in demographic patterns and weather conditions changes in the availability price oraccounting treatment of derivative financial instruments changes in laws actuarial assumptions the interest rate environment and the return on plantrust assets related to theCompanyrsquos pension and other post-retirement benefits which can affect future funding obligations and costs and plan liabilities changes in economic conditions includingglobal national or regional recessions and their effect on the demand for and customersrsquo ability to pay for the Companyrsquos products and services the creditworthiness orperformance of the Companyrsquos key suppliers customers and counterparties the impact of potential information technology cybersecurity or data security breaches economicdisruptions or uninsured losses resulting from major accidents fires severe weather natural disasters terrorist activities or acts of war significant differences between theCompanyrsquos projected and actual capital expenditures and operating expenses or increasing costs of insurance changes in coverage and the ability to obtain insurance

Forward-looking statements include estimates of oil and gas quantities Proved oil and gas reserves are those quantities of oil and gas which by analysis of geoscience andengineering data can be estimated with reasonable certainty to be economically producible under existing economic conditions operating methods and governmentregulations Other estimates of oil and gas quantities including estimates of probable reserves possible reserves and resource potential are by their nature more speculativethan estimates of proved reserves Accordingly estimates other than proved reserves are subject to substantially greater risk of being actually realized Investors are urged toconsider closely the disclosure in our Form 10-K available at wwwnationalfuelgascom You can also obtain this form on the SECrsquos website at wwwsecgov

For a discussion of the risks set forth above and other factors that could cause actual results to differ materially from results referred to in the forward-looking statements seeldquoRisk Factorsrdquo in the Companyrsquos Form 10-K for the fiscal year ended September 30 2018 and the Forms 10-Q for the quarter ended March 31 2018 June 30 2018 and December31 2018 The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date thereof or to reflect the occurrence ofunanticipated events

Appendix

8

Utilization of Existing Infrastructure for Ongoing Utica Development Amplifies Consolidated Returns

L Leveraging Existing Infrastructure to Enhance Returns

(1) Approximate WDA Marcellus gathering facility costs for 192 wells drilled and completed as of September 30 2018 (2) Estimated WDA Utica gathering facility costs for the assumed 120 well locations in Clermont Rich Valley area of redevelopment (3) Internal Rate of Return for Seneca WDA includes estimated well costs under current cost structure and anticipated LOE and Gathering costs Internal Rate of Return for Seneca WDA and Gathering includes expected gathering capital expenditures

through FY 2022 well costs under current cost structure and non-gathering LOE

Gathering CapExWell

($ thousands)Marcellus (pre-2019) $1489(1)

Utica (2019-2022) $392(2)

Gathering Pipelines

Compression

Water Handling Facilities

Roadways and Pads

Gathering Costs in Western Development Area (CRV) 10+ IRR Uplift

Expected(3)

Requires modest investment in new Gathering facilities to support production growth

Utica development on Marcellus pads allows use of existing

Resulting in significant consolidated return uplift for EampP and Gathering

4

9

$1 Billion+ Backlog in Pipeline amp Storage Projects

Line N to Monaca - $23 MM (July 2019)(1)

Empire North - $145 MM (second half of fiscal 2020)

FM100 - $280 MM (late calendar 2021)

bull Companion project to Seneca-anchored Leidy South project

Northern Access - $500 MM (as early as fiscal 2022)

Supply Corp Modernization - $150 - $250 MM (fiscal 2019-2022)

FUTURE INVESTMENTS = $11 ndash $12 Billion

FUTURE EXPANSION REVENUES = ~$150 Million

Line N toMonaca

Northern Access

FM100

Empire North

5

(1) Parentheticals represent target in-service dates for the respective expansion projects

10

Financial Highlights

First Quarter Fiscal 2019

11

673 572 361458

Net

Oil

and

Gas

Pr

oduc

tion

First Quarter Fiscal 2019 Results and Drivers

Exploration amp Production

$034

Exploration amp Production

$037

Gathering $013

Gathering $016

Pipeline amp Storage

$029

Pipeline amp Storage

$029

Utility $025

Utility $030

$102

$112

Energy Marketing $001 Energy Marketing ($001)CorporateAll Other $001

Q1 FY18 Q1 FY19

Adjusted Operating Results ($share)(1)

(1) Adjusted Operating results of $102 for Q1 Fiscal 2018 and $112 for Q1 Fiscal 2019 include operating results of Energy Marketing and Corporate amp All Other segments See slide 61 for a Reconciliation of Adjusted Operating Results to Earnings Per Share(2) Realized price after hedging

$5979 $6170 $272 $261

Q1 FY 2018 Q1 FY 2019

Oil

and

Gas

Pr

icin

g(2)

Natural Gas ($Mcfe)Crude Oil ($Bbl)

Oil Prices

Natural Gas Prices

$238 $297

Gat

herin

g R

even

ue ($

MM

)Increased Seneca Natural Gas Production

Drivers

Natural Gas Production

Oil Production(sale of Sespe field)

Crude Oil (Mbbl) Natural Gas (Bcf)

12

Earnings Guidance

FY2018 Adjusted Operating Results

Non-regulated Businesses

Exploration amp ProductionGathering

$334 share(1) $345 to $365 shareFY2019 Earnings Guidance

Seneca Net Production 210 to 230 Bcfe Gathering Revenues $130-140 million

Natural Gas ~$245Mcf(2) (vs $252Mcf in FY 2018) Crude Oil ~$59Bbl(3) (vs $5866Bbl in FY 2018)

Key Guidance Drivers

(1) Excludes the $1035 million or $120 per share reduction in tax expense due to the remeasurement of deferred taxes resulting from the 2017 Tax Reform Act See non-GAAP disclosure on slide 61 of this presentation(2) Assumes NYMEX natural gas pricing of $325MMBtu (winter) and $275MMBtu (summer) and basin spot pricing of $275MMBtu (winter) and $225MMBtu (summer) for FY19 and reflects the impact of existing financial hedges firm sales

and firm transportation contracts(3) Assumes NYMEX (WTI) oil pricing of $5500Bbl and California-MWSS pricing differentials of 102 to WTI for FY19 and reflects impact of existing financial hedge contracts

Production amp Gathering Throughput

Realized natural gas prices (after-hedge)

Utility Operating Income

Regulated BusinessesPipeline amp StorageUtility

Guidance assumes normal weather modestly higher gross margin expected to be offset by cost inflation

~$285 million in revenues (expected decrease primarily due to expiration of contract on Empire system)

Pipeline amp Storage Revenues

Tax Reform

Realized oil prices (after-hedge)

Lower effective tax rate Effective tax rate ~24-25 (federal rate 21)

13

Exploration amp Production and Gathering OverviewSeneca Resources Company LLC ~ National Fuel Gas Midstream Company LLC

14

Proved Reserves

385 337 290 302 277

16832142

16751973

2357

1914

2344

1849

2154

2523

0

500

1000

1500

2000

2500

3000

2014 2015 2016 2017 2018At September 30

Natural Gas (Bcf)

Crude Oil (MMbbl)

361 Reserve Replacement Rate

Seneca Drill-bit FampD = $066Mcfe(1)

Appalachia Drill-bit FampD = $065Mcfe(1)

(1) Seneca ldquoDrill-bitrdquo finding and development (ldquoFampDrdquo) costs exclude the impact of reserve revisions

Total Proved Reserves (Bcfe)

Fiscal 2018 Proved Reserves Stats

$138

$112

$132

$098

$074

$050

$100

$150

2014 2015 2016 2017 2018

3-Year Average FampD Cost ($Mcfe)

70

30

PDPs PUDs

EampP and Gathering

15

3 rig development program with second rig in WDA focused on Utica

15-20 net production growth expected through fiscal 2022

New EDA Utica development with production expected in Q2 fiscal 2019

Utilize new Atlantic Sunrise firm transportation capacity

Layer-in firm sales to take advantage of attractive regional pricing

Gross production growth will benefit NFGrsquos Gathering segment

Minimal capital investment in California to generate significant cash flow

Growing Production within Disciplined Capital Program

205 194 176 ~16

1406 1541 1605194-214

1611 1735 1781210-230

0

50

100

150

200

250

2016 2017 2018 2019E

$38 $38 $26 ~$25$61

$208$330

$435-$470

$99

$246

$356

$460-$495

$0

$200

$400

$600

2016 2017 2018 2019E

Appalachia West Coast (California)

Near-Term Growth Strategy EampP Net Capital Expenditures ($ millions)(1)

EampP Net Production (Bcfe)

EampP and Gathering

(1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentationFY16 FY17 and FY18 guidance reflects the netting of $157 million $7 million and $17 million respectively of up-front proceeds received from joint development partner for working interest in joint development wells

16

Significant Appalachian Acreage Position

Average gross production ~311 MMcfd

Mostly leased (16-18 royalty) with no significant near-term lease expirations

~90 remaining Marcellus amp Utica locations economic at ~$184Mcf

Additional Marcellus (Tioga Co) amp Geneseo (Lycoming Co) potential

Eastern Development Area (EDA)

Western Development Area (WDA)

Average gross production(1) ~327 MMcfd Large inventory of Marcellus amp Utica

locations economic at ~$200Mcf Royalty free mineral ownership

enhances well economics Highly contiguous nature drives cost and

operational efficiencies

EampP and Gathering

EDA - 70000 AcresWDA - 715000 Acres

(1) Average EDA and WDA gross production as well as WDA-CRV Utica production (see slide 19) and CovingtonTract 595 Production (see slide 23) is for the quarter ended December 31 2018

17

Western Development AreaMarcellus Core Acreage

vs Utica Appraisal Trend(1)

(1) The Utica Shale lies approximately 5000 feet beneath Senecarsquos WDA Marcellus acreage (2) Appraisal program currently in progress Additional tests are planned Prior Marcellus delineation tests helped define the prospective limits of the Marcellus core acreage planned testing in the Utica expected to do the same

Area of Re-Development ~120 Utica locations on existing Marcellus pads

Key Utica testsPast Marcellus delineation testsUtica Trend (currently evaluating)Marcellus Core Acreage

Large well inventory economic at ~$200 Mcf

Marcellus Shale 600+ well locations remaining 200000 acres

Utica Shale 500+ potential locations across Utica trend evaluating extent of prospective acreage(2)

Fee acreage (no royalty) enhances economics and provides development flexibility

Addition of 2nd WDA drilling rig in Q3 FY18 focused on redevelopment of Clermont-Rich Valley acreage for Utica

Use of existing gathering pad and water infrastructure for Utica drives increased Appalachian program returns

Highly contiguous position drives best in class well costs

Utica test results on trend with other Utica wells in NE Pa

Long-term firm contracts support growth

Boone Mountain Utica Test Well23 Bcf 1000ft

Rich Valley Utica Test Well23 Bcf 1000ft

EampP and Gathering

WDA Highlights

18

WDA Utica Appraisal Results and Initial Type Curve

Tested producing from 17 Utica wells in WDA-CRV Higher pressure significantly enhances well

productivity (Utica ~5000rsquo deeper than Marcellus) Drawdown management is critical restricted

drawdown appears to improve well EURs Early production declines much shallower vs

Marcellus

WDA Utica Appraisal Update

WDA Economics

(1) Internal Rate of Return (IRR) is pre-tax and includes estimated well costs under current cost structure LOEand anticipated gathering tariffs

(2) Initial WDA-CRV Utica type curve based on production results and reservoir expectations from the first 5appraisal wells in the WDA-CRV area

(3) WDA-CRV Utica Average includes all 17 producing wells including 2 wells (pad E09-S) for which drawdownmanagement was not used

EampP and Gathering

EURBcf1000rsquo

Well Cost$M1000rsquo

IRR $225

Break-even15 IRR(1)

Utica - CRV 17 $887 23 $197

Marcellus 10 ndash 11 $643 19 $206

(2)

0

1

2

3

4

5

6

7

8

9

0 12 24 36 48 60 72 84 96 108 120

Cum

ulat

ive

Prod

uctio

n B

CF

Months On

WDA-CRV Utica Wells - Normalized to 9000rsquoUtica Type Curve CRV Utica AverageWDA Marcellus Type Curve Boone Mountain Appraisal WellWDA-CRV Utica Type Curve(2) WDA-CRV Utica Average(3)

0005101520253035

0 2 4 6 8 10 12

19

Transitioning to Utica Development in CRV

WDA-CRV Marcellus(Depth ~7000 feet)

WDA-CRV Utica(Depth ~12000 feet)

Avg CRV Marcellus Production 270 MMcfd

Rem Avg EUR 10-11 Bcf 1000 lat ft

Rem Avg Well Costs = $643lat ft

120+ locations on existing Marcellus pads

Est EURs 17 Bcf 1000 lat ft

Est Development Well Costs = $887lat ft

CRV Utica Transition Plan

1)Finish Marcellus Pads in Development

Drill 24 complete 24 Marcellus wells

2)Continue Optimizing Utica DampC design

Additional optimization wells focusing on

Completion design

Landing zone targets

3)Continue transition to Utica development

Future drilling on multi-well pads

Continue using optimization results to determine development well design

Tailor development plan to use existing pad water and gathering infrastructure

CRV Utica Development Utilizes Existing Pad Water and Gathering Infrastructure to Drive Economics

EampP and Gathering

Rich Valley Utica Test

Existing Line

Leased

Seneca Fee

Producing

FY19 Producer

Development

20

Leveraging Existing Gathering Water and Pad Infrastructure Enhances Returns

Limited New Infrastructure Needed to Support Production Growth

WDA Well Costs(1) WDA Consolidated Economics

Steady activity levels and coordination between upstream and midstream activities

enhance returns provide economies of scale and significant operational flexibility

(1) WDA Marcellus well costs reflect drilling completion amp gathering costs for 192 drilled and completed wells as of 93018 WDA Utica well costs reflect expected drilling completion amp gathering costs for the ~120 well locations in area of redevelopment (2) Internal Rate of Return for Seneca WDA includes estimated well costs under current cost structure and anticipated LOE and Gathering costs Internal Rate of Return for Seneca WDA and Gathering includes expected gathering capital expenditures

through FY 2022 well costs under current cost structure and non-gathering LOE

$685$887

$210

$0

$200

$400

$600

$800

$1000

Marcellus(Historic)

Utica - CRV(Current)

$ la

tera

l foo

t

Drilling amp Completion Gathering

$931$895

10 -11

17

00

03

06

09

12

15

18

Marcellus(Historic)

Utica - CRV(Current)

EUR

10

00 fe

et (B

cf)

60-70 EUR increase expected per well

Total cost per well expected to marginally increase

WDA EURs

At a $225 netback price consolidated Seneca WDA and Gathering IRR is

approximately 33 an uplift of ~12 over standalone Seneca WDA economics(2)

10+ IRR Uplift Expected

21

Integrated Development ndash WDA Gathering System

Current System In-Service

~78 miles of pipe 36220 HP of compression

Current Capacity 470 MMcf per day

Interconnects with TGP 300

Total Investment to Date $301 million

Future Build-Out

FY 2019 CapEx $10 - $15 million

Modest gathering pipeline and compression investment required to support Senecarsquos transition to Utica development

Opportunity for 300 miles of pipelines and five compressor stations (+60000 HP installed) as Senecarsquos drilling activity continues

Deliverability into TGP 300 and NFG Supply

Gathering System Build-Out Tailored to Accommodate Senecarsquos WDA Development

Clermont Gathering System Map

EampP and Gathering

22

WDA Firm Transportation and Sales Capacity

Will continue to layer-in firm sales deals of short and longer duration on TGP 300 to reduce spot exposure

WDA spot realizations track TGP Station 313 pricing typically 10cent - 30cent better than TGP Marcellus Zone 4

Leidy South will provide additional capacity to premium markets (Transco Zone 6)

WDA Exit Capacity Supports Long-term Production Growth and Enhances Consolidated Returns

WDA Contracted Firm Transport and Gross Sales Volumes (MDthd)

Seneca gross production trend

EampP and Gathering

0

100

200

300

400

500

600

700

Niagara Expansion Project (TGP and NFG)FT Capacity 158000 Dthd $067Dth

Firm Sales NYMEX amp DAWN

WDA - TGP 300Firm Sales

Leidy SouthTransco Zone 6

Markets330000 Dthd(1)

Will layer-in firm sales to minimize spot exposure

(1) Portion of Transco Project capacity will likely be utilized by EDA Lycoming County production

WDA Gas Marketing Strategy

23

Eastern Development Area

EDA Acreage ndash 70000 AcresEDA Highlights

1 DCNR Tract 007 (Tioga Co Pa)bull Utica development resumed in third quarter fiscal 2018

bull ~43 remaining Utica locations economic at ~$184 Mcf

bull Gathering Infrastructure NFG Midstream Wellsboro

bull Marcellus Shale expected to provide ~60 additional locations

EampP and Gathering

2

1

3

2 Covington amp DCNR Tract 595 (Tioga Co Pa)bull Marcellus locations fully developed (average daily gross production of ~93 MMcfd)

bull Gathering Infrastructure NFG Midstream Covington

bull Opportunity for future Utica appraisal

3 DCNR Tract 100 amp Gamble (Lycoming Co Pa)bull ~45 remaining Marcellus locations economic at ~$153 Mcfbull Firm Transportation Capacity Atlantic Sunrise (189 MDthd)

bull Gathering Infrastructure NFG Midstream Trout Run

bull Geneseo Shale expected to provide 100-120 additional locations

24

EDA Marcellus Lycoming County Development

Marcellus Development in Lycoming County has Resumed in Connection with Atlantic Sunrise

(1) Includes physical fixed price and NYMEX-based firm sales contracts that do not carry any additional transportation costs

EampP and Gathering

Prolific Marcellus acreage with peer leading well results

~45 remaining Marcellus locations economic at ~$153 Mcf

Near-term development focused on filling Atlantic Sunrise capacity

Existing Line

Leased

Seneca Fee

Producing

FY19 Producer

Development

0

50

100

150

200

250

Gro

ss F

irm V

olum

es (M

Dth

d)

EDA ndash Transco Firm Contracts

Atlantic Sunrise (Transco)FT Capacity 189405 Dthd

Cost $073DthFirm Sales NYMEX+

Transco Firm Sales(1)

25

EDA Utica Tioga County Development

Utica Development in Tioga County ndash Tract 007 Development Resumed in Q3 Fiscal 2018

In-Service November 2016

Lateral Length 4640 ft

30 Day IP 1000 ft 34 MMcfd

Est EUR 1000 ft 24 Bcf

Inventory ~43 locations economic at ~$184 Mcf

Targeting to grow production by 100 to 150 MDthd by fiscal 2020

Expected Development Costs $1045 per lateral ft

Gathering Infrastructure NFG Midstream Wellsboro

Modest build-out required to connect to TGP 300

SalesTakeaway Strategy Layer-in firm sales with shippers holding capacity on TGP 300

(1) Includes physical fixed price and NYMEX-based firm sales contracts that do not carry any additional transportation costs

Tract 007 Utica Appraisal Well Results vs Industry

EampP and Gathering

0

100000

200000

300000

400000

500000

600000

700000

800000

0 100 200 300

Nor

mal

ized

Cum

ulat

ive

(Mcf

10

00rsquo)

Days On ProductionIndustry PotterTioga Wells Seneca DCNR 007 73H

0

25

50

75

100

125

150

Gro

ss F

irm V

olum

es (M

Dth

d)

EDA ndash TGP 300 Firm Contracts

Northeast Supply Diversification ProjectFT Capacity 50000 Dthd $050Dth

Firm Sales NYMEX and DAWN

EDA - TGP 300Firm Sales(1)

26

Integrated Development ndash EDA Gathering Systems

Total Investment (to date) ~$46 million FY 2019 Estimated Capital Expenditures $1 MM - $2 MM Capacity 220000 Dth per day (Interconnect w TGP 300) Production Source Seneca Resources ndash Tioga Co (Covington and DCNR Tract 595)

Total Investment (to date) ~$208 million FY 2019 Estimated Capital Expenditures $25 MM - $35 MM Capacity 466000 to 585000 Dth per day (Interconnect w Transco) Production Source Seneca Resources ndash Lycoming Co (DCNR Tract 100 and Gamble) Future third-party volume opportunities

Covington Gathering System

Trout Run Gathering System

Gathering Segment Supporting Senecarsquos EDA Production amp Future Development

Wellsboro Gathering System Total Investment (to date) ~$14 million FY 2019 Estimated Capital Expenditures $8 MM - $15 MM Capacity up to 200000 Dth per day (Interconnect w TGP 300) Production Source Seneca Resources ndash Tioga Co (DCNR Tract 007)

EampP and Gathering

2

1

3

27

Long-term Contracts Supporting Appalachian Growth

(1) Represents base firm sales contracts not tied to firm transportation capacity Base firm sales are either fixed priced or priced at an index (eg NYMEX ) +- a fixed basis and do not carry any transportation costs

Seneca continues to layer-in firm sales contracts with attractive realizations to lock-in drilling economics and minimize spot exposure ahead of firm transportation in-service dates

EampP and Gathering

-

100

200

300

400

500

600

700

800

900

1000

1100

1200

FY 2019 FY 2020 FY 2021 FY 2022Northeast Supply Diversification 50000 Dthd

Niagara Expansion (TGP amp NFG)Delivery Markets Canada-Dawn amp TETCO

158000 Dthd

Atlantic Sunrise (Transco)Delivery Markets Mid-Atlantic amp Southeast US

189405 Dthd

In-BasinFirm Sales

Contracts(1)

Leidy South (Transco amp NFG)

Transco Zone 6 Markets330000 Dthd

Seneca Appalachia Natural Gas MarketingGross Firm Contract Volumes (Mdthday)

28

297000 ($061)

305200 ($061)

305600 ($063)

337000 ($057)

370800 ($024)

369600 ($060)

367900 ($067)

33400 ($070)74500 ($077) 74900 ($077)

81100 ($078)

85900 ($078)

92000 ($073)

91300 ($073)

178800 $255

196000 $234

195500 $234

149900 $232

129500 $230

105400 $222

104500 $222

~517800 509200 575700 576000 568000 586200 567000 563700

Q1 FY19 Q2 FY19 Q3 FY19 Q4 FY19 Q1 FY20 Q2 FY20 Q3 FY20 Q4 FY20

Fixed Price Dawn NYMEX

Near-term Firm Sales Provide Market amp Price Certainty

Net Contracted Firm Sales Volumes (Dth per day)Contracted Index Price Differentials ($ per Dth)(1)

(1) Values shown represent the weighted average fixed price or contracted fixed differential relative to NYMEX (netback price) less any associated transportation costs

Actual Daily Net

Production

641200 716500 708700 693500 708400 674400 667000Gross Firm Sales Volumes (Dthd)

EampP and Gathering

29

California Oil

Stable Oil Production | Minimal Capital Investment | Steady Free Cash Flow

1

2

3

4

5

Location Formation Production Method

FY18 Daily Production(net Boed)

1 East Coalinga Other Temblor Primary 512

2 North Lost Hills

Tulare amp Etchegoin

PrimarySteam flood 892

3 South Lost Hills

Monterey Shale Primary 1359

4 North Midway Sunset

Tulare amp Potter Steam flood 2786

5 South Midway Sunset Antelope Steam flood 2048

TOTAL WEST DIVISION NET PRODUCTION(1) 7597 Boed

EampP and Gathering

(1) West division net production for FY 2018 excludes production from Sespe field which was divested on May 1 2018

30

California Capital Expenditures vs Production

9341 8863

8033 ~7300

2016 2017 2018 2019

Fiscal Year

West Division Average Net Daily Production (Boe)West Division Annual Capital Expenditures ($ MM)(1)

$38 $38

$26 ~$25

2016 2017 2018 2019

Fiscal YearGuidance Guidance

(1) Seneca West Division capital expenditures includes Seneca corporate and eliminations

EampP and Gathering

Sepse Sale Closed on 5118(reduced production by ~900 boed)

31

Pioneer

South MWSS

Acreage

North MWSS

AcreageSec 17N

4149 51

NMWSS amp 17N SMWSS amp Pioneer East Coalinga

California Development Activities

Modest near-term capital program focused on locations that earn attractive returns in current oil price environment

AampD will focus on low cost bolt-on opportunities

Sec 17 Pioneer and East Coalinga development to provide future growth

North

Project IRRs at $55Bbl(1)

(1) Reflects pre-tax IRRs at a $55Bbl WTI

EampP and Gathering

Seneca West Economics

South

East Coalinga

North

South

32

Fiscal 2019 Production and Price Certainty

~49 Bcfe

210 ndash 230 Bcfe

~114 Bcf

~29 Bcf (2)

16+- Bcf~12 Bcfe

0

40

80

120

160

200

240

YTD FY19Actuals

Fixed Price + FirmSales w Hedge

Firm Sales(Unhedged)

Spot Sales California TotalSeneca

Prod

uctio

n (B

cfe)

(1) Average realized price reflects uplift from financial hedges less fixed differentials under firm sales contracts and any firm transportation costs(2) Indicates firm sales contracts with fixed index differentials but not backed by a matching financial hedge

114 Bcf locked-in realizing net ~$241Mcf (1)

29 Bcf of additional basis protection

Spot production assumed to be sold

at ~$275Mmbtu(winter) and ~$225

(summer)

143 Bcf of Appalachian Production Protected by Firm Sales for Remainder of Year

79 of oil production hedged at $5757 Bbl

EampP and Gathering

33

Strong Hedge Book

Natural Gas Swap amp Fixed Physical Sales Contracts (Millions MMBtu)

(1) Fixed price physical sales exclude joint development partnerrsquos share of fixed price contract WDA volumes as specified under the joint development agreement(2) Reflects percentage of projected production for FY19 hedged at the midpoint of the production guidance range(3) Senecarsquos remainder FY19 Production reflects the total FY19 production guidance of 210-230 Bcfe or 220 Bcfe at the midpoint less Q1 actual production

Crude Oil Swap Contracts (Thousands Bbls)

13591188

732

456

0

500

1000

1500

2000

2500

FY 2019 FY 2020 FY 2021 FY 2022

NYMEX (WTI)

Brent

FY 19 Crude Oil79 Hedged (2)

FY 2019 Remaining Production (3)

EampP and Gathering

1174

709

469 406

0

50

100

150

200

250

FY 2019 FY 2020 FY 2021 FY 2022

NYMEX Swaps

Dawn Swaps

Fixed Price Physical Sales

(1)

FY 2019 Remaining Production (3)

FY 19 Nat Gas71 Hedged (2)

34

$065 $070$070 -$075

FY 2017 FY 2018 FY 2019E

$060 $060 $060

$011 $009 $007$071 $069 ~$067

FY 2017 FY 2018 FY 2019E Gathering amp Transport LOE (non-Gathering) GampA Taxes amp Other

Seneca Operating Costs

Competitive low cost structure in Appalachia and California supports strong cash margins

Gathering fee generates significant revenue stream for affiliated gathering company

Seneca DDampARate

$Mcfe

$054 $054 $056

$042 $038 $031

$034 $034 $030

$017 $014 $015

$147 $140 ~$132

FY 2017 FY 2018 FY 2019E

(1)

$1791$1746~$2050

FY 2017 FY 2018 FY 2019E

Appalachia LOE amp Gathering $Mcfe

California LOE$Boe

Total Seneca Cash OpEx$Mcfe

(1)

(2)

(2)

(1) GampA estimate represents the midpoint of the GampA guidance range of $025 to $035 for fiscal 2019(2) The total of the two LOE components represents the midpoint of the LOE guidance range of $085 to $090 for fiscal 2019

EampP and Gathering

35

Senecarsquos Continuing Commitment to the Environment

Produced Water Recycled in Appalachia

100 70Recycled Water

Used in New Shale Well

Completions

Water and Fluids Management Air Quality and Emissions

Seneca Resources Water OperationsFiscal 2018

Seneca Resources Remains Focused on Minimizing GHG Emissions

The Environmental Partnership

EPA Natural Gas Star Program

Green Completions (all fiscal 2018 wells)

Ultrasonic Leak Detection Technology

Emissions Controls

Rig and Vehicle Fuel Conversion

Integrating Renewable Energy into Operations

EampP and Gathering

36

Pipeline and Storage OverviewNational Fuel Gas Supply Corporation ~ Empire Pipeline Inc

37

Pipeline amp Storage Segment Overview

(1) As of September 30 2018 as disclosed in the Companyrsquos fiscal 2018 form 10-K(2) As of December 31 2017 calculated from National Fuel Gas Supply Corporationrsquos and Empire Pipeline Incrsquos 2017 FERC Form-2 reports respectively

Empire Pipeline Inc

National Fuel Gas Supply Corporation

Empire Pipeline

Supply Corp

Contracted Capacity(1) Firm Transportation 3187 MDth per day Firm Storage 71938 Mdth (fully subscribed)

Rate Base(2) ~$820 million FERC Rate Proceeding Status

Rate case settlement extension approved Nov lsquo15 Rate case filing expected by 73119

Contracted Capacity(1) Firm Transportation 978 MDth per day Firm Storage 3753 Mdth (fully subscribed)

Rate Base(2) ~$249 million FERC Rate Proceeding Status

Rate case settlement in principle reached on 122118 FERC approval pending

New transportation rates went into on 1119

Pipeline amp Storage

38

All Seneca volumes will flow through wholly-owned NFG gathering facilities

FM100 Project - Consolidated Benefit for NFG

330000 Dthd of new transportation capacity from WDA and EDA acreage positions to premium markets

New Transco capacity (Leidy South) 330000 Dthday

Rate(1) competitive with other expansion project rates in Senecarsquos current transportation portfolio

Delivery Point(s) Transco Zone 6 interconnections

Seneca

Lease to Transco of new capacity 330000 Dthday

Estimated annual lease revenues ~$35 million

Target In-Service late calendar year 2021

Supply Corp

Project expected to provide long-term earnings uplift to Seneca Supply Corp and Gathering

Pipeline amp Storage

Gathering

(1) Includes lease of new capacity from Supply Corp to Transco

39

FM100 Project ndash Significant Investment by Supply Corp

Pipeline amp Storage

Estimated Capital Cost $280 million(1)

Facilities (all in Pennsylvania) include Approximately 30 miles of new pipeline 2 new compressor stations (totaling

approximately 37000 HP) New interconnection station and modification

of existing interconnection station Abandonment of approximately 45 miles of

existing pipeline and compressor station Regulatory Process

Pre-filing application submitted to FERC in 2017 for original modernization project

FERC 7(b) 7(c) filing expected summer 2019

(1) Includes expansion and modernization portions of the project

40

Empire North Project

Target In-Service second half of fiscal 2020

Est Capital Cost $145 million

Est Annual Revenues ~$25 million

Receipt Point Jackson (Tioga Co Pa production)

Design Capacity and Delivery Points 175000 Dthd to Chippawa (TCPL interconnect)

30000 Dthd to Hopewell (TGP 200 interconnect)

Customers Fully subscribed (205000 Dthday)

Major Facilities 2 new compressor stations in NY (1) amp Pa (1)

No new pipeline construction

Regulatory Process FERC 7(c) application filed on 21618

FERC Environmental Assessment issued 103018

Pipeline amp Storage

Fully Subscribed Project will Provide 205000 Dthday of Incremental Firm Transportation

41

National Fuel Remains Committed to Northern Access Project

Target In-Service as early as fiscal 2022

Total Cost ~$500MM (~$76MM spent to date)

Estimated Annual Revenues ~$84 million

Delivery Points

350000 Dthd to Chippawa (TCPL interconnect)

140000 Dthd to Hopewell (TGP 200 line)

Regulatory Status

February 3 2017 ndash FERC 7(c) certificate issued

August 6 2018 ndash FERC issued Order finding that NY DEC waived water quality certification

Supply and Empire currently working to finalize remaining federal authorizations

Pipeline amp Storage

To Dawn

42

Continued Expansion of the NFG Supply System

Line N Expansion Opportunities

Line N to Monaca Project Project Firm transportation service to a new ethane

cracker facility being built by Shell Chemical Appalachia LLC

Target In-Service July 2019

Estimated Capital Cost $23 million

Contracted Capacity 133000 Dthday

Additional Line N Expansion Opportunity (Supply OS 221) Project New firm transportation service for on-system

demand

Open Season Capacity Awarded 165000 to foundation shipper Precedent agreement in negotiations

Pipeline amp Storage

43

Pipeline amp Storage Customer Mix

Producer33

LDC42

Marketer10

Outside Pipeline

9

End User6

42 MMDthd

(1) Contracted as of 10312018

Customer Transportation by Shipper Type(1) Affiliated Customer Mix (Contracted Capacity)

66

521

41

34

9579

59

LDCs Producers Marketers FirmStorage

Affiliated Non-Affiliated

Firm Transport

Pipeline amp Storage

44

Utility OverviewNational Fuel Gas Distribution Corporation

45

New York amp Pennsylvania Service Territories

New York

Total Customers(1) 535800ROE 87 (NY PSC Rate Case Order April 2017)Rate Mechanismso Revenue Decouplingo Weather Normalizationo Low Income Rateso Merchant Function Charge (Uncollectibles Adj)o 9010 Sharing (Large Customers)o System Modernization Tracker

Pennsylvania

Total Customers(1) 214400ROE Black Box Settlement (2007)Rate Mechanismso Low Income Rateso Merchant Function Charge

(1) As of September 30 2018

Utility

46

New York Rate Case Outcome

Rate Order Summary

Revenue Requirement $59 million

Rate Base $704 million

Allowed Return on Equity (ROE) 87

Capital Structure 429 equity

Other notable items

New rates became effective 5117

Retains rate mechanisms in place under prior order (revenue decoupling weather normalization merchant function charge 9010 large customer sharing)

No stay-out clause

System modernization tracker for Leak Prone Pipe (LPP)

Earnings sharing started 4118 (5050 sharing starts at earnings in excess of 92)

Article 78 appeal filed on 72817 with oral argument completed in January 2019

On April 20 2017 the New York Public Service Commission issued a Rate Order relating to NFG Distributionrsquos rate case (No 16-G-0257) filed in April 2016

Utility

47

Utility Continues its Significant Investments in Safety

$544$618 $636

$699

$944$980

$809$856

$90-100

$00

$250

$500

$750

$1000

$1250

2015 2016 2017 2018 2019E

Cap

ital E

xpen

ditu

res

($ m

illio

ns)

Fiscal Year

Capital Expenditures for Safety Total Capital Expenditures

Modernization Spending in NY Expected to Grow Gross Margin By $2 MM - $5 MM in FY 2019

(1)

(1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation

Utility

System modernization tracker in NY allows recovery of pipeline replacementcosts which is expected to drive modest gross margin and rate base growth

48

Accelerating Pipeline Replacement amp Modernization

Wrought Iron

Plastic

CoatedBare

120130

146 144159

2014 2015 2016 2017 2018Calendar Year

NY9726 miles

PA4830 miles

No Cast Iron Mains in Pa

Miles of Utility Main Pipeline ReplacedUtility Mains by Material(1)

Wrought Iron

Cast Iron

Plastic

Coated Bare

Utility

(1) All values are reported on a calendar year basis as of December 31 2018

49

A Proven History of Controlling Costs

$200 $189 $195

$166 $166

$31 $31

$197 $197

$0

$50

$100

$150

$200

$250

2015 2016 2017 2018 TTM 123118

Fiscal Year

OampM Expense Non-Service Pension Costs

OampM Expense ($ millions)

Utility

(1)

(1) For purposes of comparability to FY 2015 2016 and 2017 Utility Operation and Maintenance Expense for FY 2018 and the twelve months ended December 31 2018 was adjusted by approximately $314 million and $312 million respectively to include non-service pension costs which were re-classified as Other Income (Deductions) as of October 1 2018 on the Companyrsquos Income Statement See Slide 64 for non-GAAP reconciliation of Adjusted Operation and Maintenance Expense to Operation and Maintenance Expense by segment

50

Consolidated Financial OverviewUpstream I Midstream I Downstream

51

Adjusted Operating Results ($ per share)(1)

Diversified Balanced Earnings and Cash Flows

(1) A reconciliation of Adjusted Operating Results to Earnings per Share by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation(2) Consolidated Adjusted EBITDA includes Energy Marketing and Corporate amp All Other Segments A reconciliation of Adjusted EBITDA to Net Income by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in

the Business is included at the end of this presentation

Adjusted EBITDA ($ millions)(2)

$176 $179

$184 $181

$92 $97

$318 $327

$761 $775

$-

$200

$400

$600

$800

FY 2018 TTM 123118

$059 Utility

$097 Pipeline amp Storage

$057 Gathering

$125 Exploration

amp Production

$334 $345 to $365

$-

$100

$200

$300

$400

FY 2018 FY 2019 Guidance

Rate Regulated

40-45

$728

Rate Regulated

~46

52

$89 $94 $98 $81 $86 $90-$100

$140$230

$114 $95 $93 $120-$150

$138$118

$54$33 $48

$55-$65

$603$557

$99 $246$356

$460-$495

$970 $1001

$366$455

$583

$725-$810

$0

$250

$500

$750

$1000

$1250

2014 2015 2016 2017 2018 2019GuidanceFiscal Year

Exploration amp Production

Gathering

Pipeline amp Storage

Utility

Disciplined Flexible Capital Allocation

(2)

(1) Total Capital Expenditures include Energy Marketing Corporate and All Other A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation (2) FY16 FY17 and FY18 reflects the netting of $157 million $7 million and $17 million respectively of up-front proceeds received from joint development partner for working interest in joint development wells and $21M in intercompany asset transfers in FY18

Capital Expenditures by Segment ($ millions)(1)

53

Maintaining Strong Balance Sheet amp Liquidity

Total Equity49

Total Debt51

$42 Billion Total Capitalizationas of December 31 2018

218 x251 x 245 x 247 x 256 x

2015 2016 2017 2018 TTM 123118Fiscal Year End

Net Debt Adjusted EBITDA(1) Capitalization

Debt Maturity Profile ($MM) Liquidity

Committed Credit FacilitiesShort-term Debt OutstandingAvailable Short-term Credit FacilitiesCash Balance at 123118 Total Liquidity at 123118

$ 750 MM0 MM

750 MM110 MM

$ 860 MM

$500 $549 $500

$300 $300

$0

$200

$400

$600

(1) Net Debt is net of cash and temporary cash investments Reconciliations of Net Debt and Adjusted EBITDA to Net Income are included at the end of this presentation

54

Appendix

55

Safe Harbor For Forward Looking StatementsThis presentation may contain ldquoforward-looking statementsrdquo as defined by the Private Securities Litigation Reform Act of 1995 including statements regarding future prospectsplans objectives goals projections estimates of oil and gas quantities strategies future events or performance and underlying assumptions capital structure anticipatedcapital expenditures completion of construction projects projections for pension and other post-retirement benefit obligations impacts of the adoption of new accounting rulesand possible outcomes of litigation or regulatory proceedings as well as statements that are identified by the use of the words ldquoanticipatesrdquo ldquoestimatesrdquo ldquoexpectsrdquo ldquoforecastsrdquoldquointendsrdquo ldquoplansrdquo ldquopredictsrdquo ldquoprojectsrdquo ldquobelievesrdquo ldquoseeksrdquo ldquowillrdquo ldquomayrdquo and similar expressions Forward-looking statements involve risks and uncertainties which couldcause actual results or outcomes to differ materially from those expressed in the forward-looking statements The Companyrsquos expectations beliefs and projections are expressedin good faith and are believed by the Company to have a reasonable basis but there can be no assurance that managementrsquos expectations beliefs or projections will result or beachieved or accomplished

In addition to other factors the following are important factors that could cause actual results to differ materially from those discussed in the forward-looking statements delaysor changes in costs or plans with respect to Company projects or related projects of other companies including difficulties or delays in obtaining necessary governmentalapprovals permits or orders or in obtaining the cooperation of interconnecting facility operators governmentalregulatory actions initiatives and proceedings including thoseinvolving rate cases (which address among other things target rates of return rate design and retained natural gas) environmentalsafety requirements affiliate relationshipsindustry structure and franchise renewal changes in laws regulations or judicial interpretations to which the Company is subject including those involving derivatives taxessafety employment climate change other environmental matters real property and exploration and production activities such as hydraulic fracturing financial and economicconditions including the availability of credit and occurrences affecting the Companyrsquos ability to obtain financing on acceptable terms for working capital capital expendituresand other investments including any downgrades in the Companyrsquos credit ratings and changes in interest rates and other capital market conditions changes in the price ofnatural gas or oil impairments under the SECrsquos full cost ceiling test for natural gas and oil reserves factors affecting the Companyrsquos ability to successfully identify drill for andproduce economically viable natural gas and oil reserves including among others geology lease availability title disputes weather conditions shortages delays orunavailability of equipment and services required in drilling operations insufficient gathering processing and transportation capacity the need to obtain governmentalapprovals and permits and compliance with environmental laws and regulations increasing health care costs and the resulting effect on health insurance premiums and on theobligation to provide other post-retirement benefits changes in price differentials between similar quantities of natural gas or oil sold at different geographic locations and theeffect of such changes on commodity production revenues and demand for pipeline transportation capacity to or from such locations other changes in price differentialsbetween similar quantities of natural gas or oil having different quality heating value hydrocarbon mix or delivery date the cost and effects of legal and administrative claimsagainst the Company or activist shareholder campaigns to effect changes at the Company uncertainty of oil and gas reserve estimates significant differences between theCompanyrsquos projected and actual production levels for natural gas or oil changes in demographic patterns and weather conditions changes in the availability price oraccounting treatment of derivative financial instruments changes in laws actuarial assumptions the interest rate environment and the return on plantrust assets related to theCompanyrsquos pension and other post-retirement benefits which can affect future funding obligations and costs and plan liabilities changes in economic conditions includingglobal national or regional recessions and their effect on the demand for and customersrsquo ability to pay for the Companyrsquos products and services the creditworthiness orperformance of the Companyrsquos key suppliers customers and counterparties the impact of potential information technology cybersecurity or data security breaches economicdisruptions or uninsured losses resulting from major accidents fires severe weather natural disasters terrorist activities or acts of war significant differences between theCompanyrsquos projected and actual capital expenditures and operating expenses or increasing costs of insurance changes in coverage and the ability to obtain insurance

Forward-looking statements include estimates of oil and gas quantities Proved oil and gas reserves are those quantities of oil and gas which by analysis of geoscience andengineering data can be estimated with reasonable certainty to be economically producible under existing economic conditions operating methods and governmentregulations Other estimates of oil and gas quantities including estimates of probable reserves possible reserves and resource potential are by their nature more speculativethan estimates of proved reserves Accordingly estimates other than proved reserves are subject to substantially greater risk of being actually realized Investors are urged toconsider closely the disclosure in our Form 10-K available at wwwnationalfuelgascom You can also obtain this form on the SECrsquos website at wwwsecgov

For a discussion of the risks set forth above and other factors that could cause actual results to differ materially from results referred to in the forward-looking statements seeldquoRisk Factorsrdquo in the Companyrsquos Form 10-K for the fiscal year ended September 30 2018 and the Forms 10-Q for the quarter ended March 31 2018 June 30 2018 and December31 2018 The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date thereof or to reflect the occurrence ofunanticipated events

Appendix

9

$1 Billion+ Backlog in Pipeline amp Storage Projects

Line N to Monaca - $23 MM (July 2019)(1)

Empire North - $145 MM (second half of fiscal 2020)

FM100 - $280 MM (late calendar 2021)

bull Companion project to Seneca-anchored Leidy South project

Northern Access - $500 MM (as early as fiscal 2022)

Supply Corp Modernization - $150 - $250 MM (fiscal 2019-2022)

FUTURE INVESTMENTS = $11 ndash $12 Billion

FUTURE EXPANSION REVENUES = ~$150 Million

Line N toMonaca

Northern Access

FM100

Empire North

5

(1) Parentheticals represent target in-service dates for the respective expansion projects

10

Financial Highlights

First Quarter Fiscal 2019

11

673 572 361458

Net

Oil

and

Gas

Pr

oduc

tion

First Quarter Fiscal 2019 Results and Drivers

Exploration amp Production

$034

Exploration amp Production

$037

Gathering $013

Gathering $016

Pipeline amp Storage

$029

Pipeline amp Storage

$029

Utility $025

Utility $030

$102

$112

Energy Marketing $001 Energy Marketing ($001)CorporateAll Other $001

Q1 FY18 Q1 FY19

Adjusted Operating Results ($share)(1)

(1) Adjusted Operating results of $102 for Q1 Fiscal 2018 and $112 for Q1 Fiscal 2019 include operating results of Energy Marketing and Corporate amp All Other segments See slide 61 for a Reconciliation of Adjusted Operating Results to Earnings Per Share(2) Realized price after hedging

$5979 $6170 $272 $261

Q1 FY 2018 Q1 FY 2019

Oil

and

Gas

Pr

icin

g(2)

Natural Gas ($Mcfe)Crude Oil ($Bbl)

Oil Prices

Natural Gas Prices

$238 $297

Gat

herin

g R

even

ue ($

MM

)Increased Seneca Natural Gas Production

Drivers

Natural Gas Production

Oil Production(sale of Sespe field)

Crude Oil (Mbbl) Natural Gas (Bcf)

12

Earnings Guidance

FY2018 Adjusted Operating Results

Non-regulated Businesses

Exploration amp ProductionGathering

$334 share(1) $345 to $365 shareFY2019 Earnings Guidance

Seneca Net Production 210 to 230 Bcfe Gathering Revenues $130-140 million

Natural Gas ~$245Mcf(2) (vs $252Mcf in FY 2018) Crude Oil ~$59Bbl(3) (vs $5866Bbl in FY 2018)

Key Guidance Drivers

(1) Excludes the $1035 million or $120 per share reduction in tax expense due to the remeasurement of deferred taxes resulting from the 2017 Tax Reform Act See non-GAAP disclosure on slide 61 of this presentation(2) Assumes NYMEX natural gas pricing of $325MMBtu (winter) and $275MMBtu (summer) and basin spot pricing of $275MMBtu (winter) and $225MMBtu (summer) for FY19 and reflects the impact of existing financial hedges firm sales

and firm transportation contracts(3) Assumes NYMEX (WTI) oil pricing of $5500Bbl and California-MWSS pricing differentials of 102 to WTI for FY19 and reflects impact of existing financial hedge contracts

Production amp Gathering Throughput

Realized natural gas prices (after-hedge)

Utility Operating Income

Regulated BusinessesPipeline amp StorageUtility

Guidance assumes normal weather modestly higher gross margin expected to be offset by cost inflation

~$285 million in revenues (expected decrease primarily due to expiration of contract on Empire system)

Pipeline amp Storage Revenues

Tax Reform

Realized oil prices (after-hedge)

Lower effective tax rate Effective tax rate ~24-25 (federal rate 21)

13

Exploration amp Production and Gathering OverviewSeneca Resources Company LLC ~ National Fuel Gas Midstream Company LLC

14

Proved Reserves

385 337 290 302 277

16832142

16751973

2357

1914

2344

1849

2154

2523

0

500

1000

1500

2000

2500

3000

2014 2015 2016 2017 2018At September 30

Natural Gas (Bcf)

Crude Oil (MMbbl)

361 Reserve Replacement Rate

Seneca Drill-bit FampD = $066Mcfe(1)

Appalachia Drill-bit FampD = $065Mcfe(1)

(1) Seneca ldquoDrill-bitrdquo finding and development (ldquoFampDrdquo) costs exclude the impact of reserve revisions

Total Proved Reserves (Bcfe)

Fiscal 2018 Proved Reserves Stats

$138

$112

$132

$098

$074

$050

$100

$150

2014 2015 2016 2017 2018

3-Year Average FampD Cost ($Mcfe)

70

30

PDPs PUDs

EampP and Gathering

15

3 rig development program with second rig in WDA focused on Utica

15-20 net production growth expected through fiscal 2022

New EDA Utica development with production expected in Q2 fiscal 2019

Utilize new Atlantic Sunrise firm transportation capacity

Layer-in firm sales to take advantage of attractive regional pricing

Gross production growth will benefit NFGrsquos Gathering segment

Minimal capital investment in California to generate significant cash flow

Growing Production within Disciplined Capital Program

205 194 176 ~16

1406 1541 1605194-214

1611 1735 1781210-230

0

50

100

150

200

250

2016 2017 2018 2019E

$38 $38 $26 ~$25$61

$208$330

$435-$470

$99

$246

$356

$460-$495

$0

$200

$400

$600

2016 2017 2018 2019E

Appalachia West Coast (California)

Near-Term Growth Strategy EampP Net Capital Expenditures ($ millions)(1)

EampP Net Production (Bcfe)

EampP and Gathering

(1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentationFY16 FY17 and FY18 guidance reflects the netting of $157 million $7 million and $17 million respectively of up-front proceeds received from joint development partner for working interest in joint development wells

16

Significant Appalachian Acreage Position

Average gross production ~311 MMcfd

Mostly leased (16-18 royalty) with no significant near-term lease expirations

~90 remaining Marcellus amp Utica locations economic at ~$184Mcf

Additional Marcellus (Tioga Co) amp Geneseo (Lycoming Co) potential

Eastern Development Area (EDA)

Western Development Area (WDA)

Average gross production(1) ~327 MMcfd Large inventory of Marcellus amp Utica

locations economic at ~$200Mcf Royalty free mineral ownership

enhances well economics Highly contiguous nature drives cost and

operational efficiencies

EampP and Gathering

EDA - 70000 AcresWDA - 715000 Acres

(1) Average EDA and WDA gross production as well as WDA-CRV Utica production (see slide 19) and CovingtonTract 595 Production (see slide 23) is for the quarter ended December 31 2018

17

Western Development AreaMarcellus Core Acreage

vs Utica Appraisal Trend(1)

(1) The Utica Shale lies approximately 5000 feet beneath Senecarsquos WDA Marcellus acreage (2) Appraisal program currently in progress Additional tests are planned Prior Marcellus delineation tests helped define the prospective limits of the Marcellus core acreage planned testing in the Utica expected to do the same

Area of Re-Development ~120 Utica locations on existing Marcellus pads

Key Utica testsPast Marcellus delineation testsUtica Trend (currently evaluating)Marcellus Core Acreage

Large well inventory economic at ~$200 Mcf

Marcellus Shale 600+ well locations remaining 200000 acres

Utica Shale 500+ potential locations across Utica trend evaluating extent of prospective acreage(2)

Fee acreage (no royalty) enhances economics and provides development flexibility

Addition of 2nd WDA drilling rig in Q3 FY18 focused on redevelopment of Clermont-Rich Valley acreage for Utica

Use of existing gathering pad and water infrastructure for Utica drives increased Appalachian program returns

Highly contiguous position drives best in class well costs

Utica test results on trend with other Utica wells in NE Pa

Long-term firm contracts support growth

Boone Mountain Utica Test Well23 Bcf 1000ft

Rich Valley Utica Test Well23 Bcf 1000ft

EampP and Gathering

WDA Highlights

18

WDA Utica Appraisal Results and Initial Type Curve

Tested producing from 17 Utica wells in WDA-CRV Higher pressure significantly enhances well

productivity (Utica ~5000rsquo deeper than Marcellus) Drawdown management is critical restricted

drawdown appears to improve well EURs Early production declines much shallower vs

Marcellus

WDA Utica Appraisal Update

WDA Economics

(1) Internal Rate of Return (IRR) is pre-tax and includes estimated well costs under current cost structure LOEand anticipated gathering tariffs

(2) Initial WDA-CRV Utica type curve based on production results and reservoir expectations from the first 5appraisal wells in the WDA-CRV area

(3) WDA-CRV Utica Average includes all 17 producing wells including 2 wells (pad E09-S) for which drawdownmanagement was not used

EampP and Gathering

EURBcf1000rsquo

Well Cost$M1000rsquo

IRR $225

Break-even15 IRR(1)

Utica - CRV 17 $887 23 $197

Marcellus 10 ndash 11 $643 19 $206

(2)

0

1

2

3

4

5

6

7

8

9

0 12 24 36 48 60 72 84 96 108 120

Cum

ulat

ive

Prod

uctio

n B

CF

Months On

WDA-CRV Utica Wells - Normalized to 9000rsquoUtica Type Curve CRV Utica AverageWDA Marcellus Type Curve Boone Mountain Appraisal WellWDA-CRV Utica Type Curve(2) WDA-CRV Utica Average(3)

0005101520253035

0 2 4 6 8 10 12

19

Transitioning to Utica Development in CRV

WDA-CRV Marcellus(Depth ~7000 feet)

WDA-CRV Utica(Depth ~12000 feet)

Avg CRV Marcellus Production 270 MMcfd

Rem Avg EUR 10-11 Bcf 1000 lat ft

Rem Avg Well Costs = $643lat ft

120+ locations on existing Marcellus pads

Est EURs 17 Bcf 1000 lat ft

Est Development Well Costs = $887lat ft

CRV Utica Transition Plan

1)Finish Marcellus Pads in Development

Drill 24 complete 24 Marcellus wells

2)Continue Optimizing Utica DampC design

Additional optimization wells focusing on

Completion design

Landing zone targets

3)Continue transition to Utica development

Future drilling on multi-well pads

Continue using optimization results to determine development well design

Tailor development plan to use existing pad water and gathering infrastructure

CRV Utica Development Utilizes Existing Pad Water and Gathering Infrastructure to Drive Economics

EampP and Gathering

Rich Valley Utica Test

Existing Line

Leased

Seneca Fee

Producing

FY19 Producer

Development

20

Leveraging Existing Gathering Water and Pad Infrastructure Enhances Returns

Limited New Infrastructure Needed to Support Production Growth

WDA Well Costs(1) WDA Consolidated Economics

Steady activity levels and coordination between upstream and midstream activities

enhance returns provide economies of scale and significant operational flexibility

(1) WDA Marcellus well costs reflect drilling completion amp gathering costs for 192 drilled and completed wells as of 93018 WDA Utica well costs reflect expected drilling completion amp gathering costs for the ~120 well locations in area of redevelopment (2) Internal Rate of Return for Seneca WDA includes estimated well costs under current cost structure and anticipated LOE and Gathering costs Internal Rate of Return for Seneca WDA and Gathering includes expected gathering capital expenditures

through FY 2022 well costs under current cost structure and non-gathering LOE

$685$887

$210

$0

$200

$400

$600

$800

$1000

Marcellus(Historic)

Utica - CRV(Current)

$ la

tera

l foo

t

Drilling amp Completion Gathering

$931$895

10 -11

17

00

03

06

09

12

15

18

Marcellus(Historic)

Utica - CRV(Current)

EUR

10

00 fe

et (B

cf)

60-70 EUR increase expected per well

Total cost per well expected to marginally increase

WDA EURs

At a $225 netback price consolidated Seneca WDA and Gathering IRR is

approximately 33 an uplift of ~12 over standalone Seneca WDA economics(2)

10+ IRR Uplift Expected

21

Integrated Development ndash WDA Gathering System

Current System In-Service

~78 miles of pipe 36220 HP of compression

Current Capacity 470 MMcf per day

Interconnects with TGP 300

Total Investment to Date $301 million

Future Build-Out

FY 2019 CapEx $10 - $15 million

Modest gathering pipeline and compression investment required to support Senecarsquos transition to Utica development

Opportunity for 300 miles of pipelines and five compressor stations (+60000 HP installed) as Senecarsquos drilling activity continues

Deliverability into TGP 300 and NFG Supply

Gathering System Build-Out Tailored to Accommodate Senecarsquos WDA Development

Clermont Gathering System Map

EampP and Gathering

22

WDA Firm Transportation and Sales Capacity

Will continue to layer-in firm sales deals of short and longer duration on TGP 300 to reduce spot exposure

WDA spot realizations track TGP Station 313 pricing typically 10cent - 30cent better than TGP Marcellus Zone 4

Leidy South will provide additional capacity to premium markets (Transco Zone 6)

WDA Exit Capacity Supports Long-term Production Growth and Enhances Consolidated Returns

WDA Contracted Firm Transport and Gross Sales Volumes (MDthd)

Seneca gross production trend

EampP and Gathering

0

100

200

300

400

500

600

700

Niagara Expansion Project (TGP and NFG)FT Capacity 158000 Dthd $067Dth

Firm Sales NYMEX amp DAWN

WDA - TGP 300Firm Sales

Leidy SouthTransco Zone 6

Markets330000 Dthd(1)

Will layer-in firm sales to minimize spot exposure

(1) Portion of Transco Project capacity will likely be utilized by EDA Lycoming County production

WDA Gas Marketing Strategy

23

Eastern Development Area

EDA Acreage ndash 70000 AcresEDA Highlights

1 DCNR Tract 007 (Tioga Co Pa)bull Utica development resumed in third quarter fiscal 2018

bull ~43 remaining Utica locations economic at ~$184 Mcf

bull Gathering Infrastructure NFG Midstream Wellsboro

bull Marcellus Shale expected to provide ~60 additional locations

EampP and Gathering

2

1

3

2 Covington amp DCNR Tract 595 (Tioga Co Pa)bull Marcellus locations fully developed (average daily gross production of ~93 MMcfd)

bull Gathering Infrastructure NFG Midstream Covington

bull Opportunity for future Utica appraisal

3 DCNR Tract 100 amp Gamble (Lycoming Co Pa)bull ~45 remaining Marcellus locations economic at ~$153 Mcfbull Firm Transportation Capacity Atlantic Sunrise (189 MDthd)

bull Gathering Infrastructure NFG Midstream Trout Run

bull Geneseo Shale expected to provide 100-120 additional locations

24

EDA Marcellus Lycoming County Development

Marcellus Development in Lycoming County has Resumed in Connection with Atlantic Sunrise

(1) Includes physical fixed price and NYMEX-based firm sales contracts that do not carry any additional transportation costs

EampP and Gathering

Prolific Marcellus acreage with peer leading well results

~45 remaining Marcellus locations economic at ~$153 Mcf

Near-term development focused on filling Atlantic Sunrise capacity

Existing Line

Leased

Seneca Fee

Producing

FY19 Producer

Development

0

50

100

150

200

250

Gro

ss F

irm V

olum

es (M

Dth

d)

EDA ndash Transco Firm Contracts

Atlantic Sunrise (Transco)FT Capacity 189405 Dthd

Cost $073DthFirm Sales NYMEX+

Transco Firm Sales(1)

25

EDA Utica Tioga County Development

Utica Development in Tioga County ndash Tract 007 Development Resumed in Q3 Fiscal 2018

In-Service November 2016

Lateral Length 4640 ft

30 Day IP 1000 ft 34 MMcfd

Est EUR 1000 ft 24 Bcf

Inventory ~43 locations economic at ~$184 Mcf

Targeting to grow production by 100 to 150 MDthd by fiscal 2020

Expected Development Costs $1045 per lateral ft

Gathering Infrastructure NFG Midstream Wellsboro

Modest build-out required to connect to TGP 300

SalesTakeaway Strategy Layer-in firm sales with shippers holding capacity on TGP 300

(1) Includes physical fixed price and NYMEX-based firm sales contracts that do not carry any additional transportation costs

Tract 007 Utica Appraisal Well Results vs Industry

EampP and Gathering

0

100000

200000

300000

400000

500000

600000

700000

800000

0 100 200 300

Nor

mal

ized

Cum

ulat

ive

(Mcf

10

00rsquo)

Days On ProductionIndustry PotterTioga Wells Seneca DCNR 007 73H

0

25

50

75

100

125

150

Gro

ss F

irm V

olum

es (M

Dth

d)

EDA ndash TGP 300 Firm Contracts

Northeast Supply Diversification ProjectFT Capacity 50000 Dthd $050Dth

Firm Sales NYMEX and DAWN

EDA - TGP 300Firm Sales(1)

26

Integrated Development ndash EDA Gathering Systems

Total Investment (to date) ~$46 million FY 2019 Estimated Capital Expenditures $1 MM - $2 MM Capacity 220000 Dth per day (Interconnect w TGP 300) Production Source Seneca Resources ndash Tioga Co (Covington and DCNR Tract 595)

Total Investment (to date) ~$208 million FY 2019 Estimated Capital Expenditures $25 MM - $35 MM Capacity 466000 to 585000 Dth per day (Interconnect w Transco) Production Source Seneca Resources ndash Lycoming Co (DCNR Tract 100 and Gamble) Future third-party volume opportunities

Covington Gathering System

Trout Run Gathering System

Gathering Segment Supporting Senecarsquos EDA Production amp Future Development

Wellsboro Gathering System Total Investment (to date) ~$14 million FY 2019 Estimated Capital Expenditures $8 MM - $15 MM Capacity up to 200000 Dth per day (Interconnect w TGP 300) Production Source Seneca Resources ndash Tioga Co (DCNR Tract 007)

EampP and Gathering

2

1

3

27

Long-term Contracts Supporting Appalachian Growth

(1) Represents base firm sales contracts not tied to firm transportation capacity Base firm sales are either fixed priced or priced at an index (eg NYMEX ) +- a fixed basis and do not carry any transportation costs

Seneca continues to layer-in firm sales contracts with attractive realizations to lock-in drilling economics and minimize spot exposure ahead of firm transportation in-service dates

EampP and Gathering

-

100

200

300

400

500

600

700

800

900

1000

1100

1200

FY 2019 FY 2020 FY 2021 FY 2022Northeast Supply Diversification 50000 Dthd

Niagara Expansion (TGP amp NFG)Delivery Markets Canada-Dawn amp TETCO

158000 Dthd

Atlantic Sunrise (Transco)Delivery Markets Mid-Atlantic amp Southeast US

189405 Dthd

In-BasinFirm Sales

Contracts(1)

Leidy South (Transco amp NFG)

Transco Zone 6 Markets330000 Dthd

Seneca Appalachia Natural Gas MarketingGross Firm Contract Volumes (Mdthday)

28

297000 ($061)

305200 ($061)

305600 ($063)

337000 ($057)

370800 ($024)

369600 ($060)

367900 ($067)

33400 ($070)74500 ($077) 74900 ($077)

81100 ($078)

85900 ($078)

92000 ($073)

91300 ($073)

178800 $255

196000 $234

195500 $234

149900 $232

129500 $230

105400 $222

104500 $222

~517800 509200 575700 576000 568000 586200 567000 563700

Q1 FY19 Q2 FY19 Q3 FY19 Q4 FY19 Q1 FY20 Q2 FY20 Q3 FY20 Q4 FY20

Fixed Price Dawn NYMEX

Near-term Firm Sales Provide Market amp Price Certainty

Net Contracted Firm Sales Volumes (Dth per day)Contracted Index Price Differentials ($ per Dth)(1)

(1) Values shown represent the weighted average fixed price or contracted fixed differential relative to NYMEX (netback price) less any associated transportation costs

Actual Daily Net

Production

641200 716500 708700 693500 708400 674400 667000Gross Firm Sales Volumes (Dthd)

EampP and Gathering

29

California Oil

Stable Oil Production | Minimal Capital Investment | Steady Free Cash Flow

1

2

3

4

5

Location Formation Production Method

FY18 Daily Production(net Boed)

1 East Coalinga Other Temblor Primary 512

2 North Lost Hills

Tulare amp Etchegoin

PrimarySteam flood 892

3 South Lost Hills

Monterey Shale Primary 1359

4 North Midway Sunset

Tulare amp Potter Steam flood 2786

5 South Midway Sunset Antelope Steam flood 2048

TOTAL WEST DIVISION NET PRODUCTION(1) 7597 Boed

EampP and Gathering

(1) West division net production for FY 2018 excludes production from Sespe field which was divested on May 1 2018

30

California Capital Expenditures vs Production

9341 8863

8033 ~7300

2016 2017 2018 2019

Fiscal Year

West Division Average Net Daily Production (Boe)West Division Annual Capital Expenditures ($ MM)(1)

$38 $38

$26 ~$25

2016 2017 2018 2019

Fiscal YearGuidance Guidance

(1) Seneca West Division capital expenditures includes Seneca corporate and eliminations

EampP and Gathering

Sepse Sale Closed on 5118(reduced production by ~900 boed)

31

Pioneer

South MWSS

Acreage

North MWSS

AcreageSec 17N

4149 51

NMWSS amp 17N SMWSS amp Pioneer East Coalinga

California Development Activities

Modest near-term capital program focused on locations that earn attractive returns in current oil price environment

AampD will focus on low cost bolt-on opportunities

Sec 17 Pioneer and East Coalinga development to provide future growth

North

Project IRRs at $55Bbl(1)

(1) Reflects pre-tax IRRs at a $55Bbl WTI

EampP and Gathering

Seneca West Economics

South

East Coalinga

North

South

32

Fiscal 2019 Production and Price Certainty

~49 Bcfe

210 ndash 230 Bcfe

~114 Bcf

~29 Bcf (2)

16+- Bcf~12 Bcfe

0

40

80

120

160

200

240

YTD FY19Actuals

Fixed Price + FirmSales w Hedge

Firm Sales(Unhedged)

Spot Sales California TotalSeneca

Prod

uctio

n (B

cfe)

(1) Average realized price reflects uplift from financial hedges less fixed differentials under firm sales contracts and any firm transportation costs(2) Indicates firm sales contracts with fixed index differentials but not backed by a matching financial hedge

114 Bcf locked-in realizing net ~$241Mcf (1)

29 Bcf of additional basis protection

Spot production assumed to be sold

at ~$275Mmbtu(winter) and ~$225

(summer)

143 Bcf of Appalachian Production Protected by Firm Sales for Remainder of Year

79 of oil production hedged at $5757 Bbl

EampP and Gathering

33

Strong Hedge Book

Natural Gas Swap amp Fixed Physical Sales Contracts (Millions MMBtu)

(1) Fixed price physical sales exclude joint development partnerrsquos share of fixed price contract WDA volumes as specified under the joint development agreement(2) Reflects percentage of projected production for FY19 hedged at the midpoint of the production guidance range(3) Senecarsquos remainder FY19 Production reflects the total FY19 production guidance of 210-230 Bcfe or 220 Bcfe at the midpoint less Q1 actual production

Crude Oil Swap Contracts (Thousands Bbls)

13591188

732

456

0

500

1000

1500

2000

2500

FY 2019 FY 2020 FY 2021 FY 2022

NYMEX (WTI)

Brent

FY 19 Crude Oil79 Hedged (2)

FY 2019 Remaining Production (3)

EampP and Gathering

1174

709

469 406

0

50

100

150

200

250

FY 2019 FY 2020 FY 2021 FY 2022

NYMEX Swaps

Dawn Swaps

Fixed Price Physical Sales

(1)

FY 2019 Remaining Production (3)

FY 19 Nat Gas71 Hedged (2)

34

$065 $070$070 -$075

FY 2017 FY 2018 FY 2019E

$060 $060 $060

$011 $009 $007$071 $069 ~$067

FY 2017 FY 2018 FY 2019E Gathering amp Transport LOE (non-Gathering) GampA Taxes amp Other

Seneca Operating Costs

Competitive low cost structure in Appalachia and California supports strong cash margins

Gathering fee generates significant revenue stream for affiliated gathering company

Seneca DDampARate

$Mcfe

$054 $054 $056

$042 $038 $031

$034 $034 $030

$017 $014 $015

$147 $140 ~$132

FY 2017 FY 2018 FY 2019E

(1)

$1791$1746~$2050

FY 2017 FY 2018 FY 2019E

Appalachia LOE amp Gathering $Mcfe

California LOE$Boe

Total Seneca Cash OpEx$Mcfe

(1)

(2)

(2)

(1) GampA estimate represents the midpoint of the GampA guidance range of $025 to $035 for fiscal 2019(2) The total of the two LOE components represents the midpoint of the LOE guidance range of $085 to $090 for fiscal 2019

EampP and Gathering

35

Senecarsquos Continuing Commitment to the Environment

Produced Water Recycled in Appalachia

100 70Recycled Water

Used in New Shale Well

Completions

Water and Fluids Management Air Quality and Emissions

Seneca Resources Water OperationsFiscal 2018

Seneca Resources Remains Focused on Minimizing GHG Emissions

The Environmental Partnership

EPA Natural Gas Star Program

Green Completions (all fiscal 2018 wells)

Ultrasonic Leak Detection Technology

Emissions Controls

Rig and Vehicle Fuel Conversion

Integrating Renewable Energy into Operations

EampP and Gathering

36

Pipeline and Storage OverviewNational Fuel Gas Supply Corporation ~ Empire Pipeline Inc

37

Pipeline amp Storage Segment Overview

(1) As of September 30 2018 as disclosed in the Companyrsquos fiscal 2018 form 10-K(2) As of December 31 2017 calculated from National Fuel Gas Supply Corporationrsquos and Empire Pipeline Incrsquos 2017 FERC Form-2 reports respectively

Empire Pipeline Inc

National Fuel Gas Supply Corporation

Empire Pipeline

Supply Corp

Contracted Capacity(1) Firm Transportation 3187 MDth per day Firm Storage 71938 Mdth (fully subscribed)

Rate Base(2) ~$820 million FERC Rate Proceeding Status

Rate case settlement extension approved Nov lsquo15 Rate case filing expected by 73119

Contracted Capacity(1) Firm Transportation 978 MDth per day Firm Storage 3753 Mdth (fully subscribed)

Rate Base(2) ~$249 million FERC Rate Proceeding Status

Rate case settlement in principle reached on 122118 FERC approval pending

New transportation rates went into on 1119

Pipeline amp Storage

38

All Seneca volumes will flow through wholly-owned NFG gathering facilities

FM100 Project - Consolidated Benefit for NFG

330000 Dthd of new transportation capacity from WDA and EDA acreage positions to premium markets

New Transco capacity (Leidy South) 330000 Dthday

Rate(1) competitive with other expansion project rates in Senecarsquos current transportation portfolio

Delivery Point(s) Transco Zone 6 interconnections

Seneca

Lease to Transco of new capacity 330000 Dthday

Estimated annual lease revenues ~$35 million

Target In-Service late calendar year 2021

Supply Corp

Project expected to provide long-term earnings uplift to Seneca Supply Corp and Gathering

Pipeline amp Storage

Gathering

(1) Includes lease of new capacity from Supply Corp to Transco

39

FM100 Project ndash Significant Investment by Supply Corp

Pipeline amp Storage

Estimated Capital Cost $280 million(1)

Facilities (all in Pennsylvania) include Approximately 30 miles of new pipeline 2 new compressor stations (totaling

approximately 37000 HP) New interconnection station and modification

of existing interconnection station Abandonment of approximately 45 miles of

existing pipeline and compressor station Regulatory Process

Pre-filing application submitted to FERC in 2017 for original modernization project

FERC 7(b) 7(c) filing expected summer 2019

(1) Includes expansion and modernization portions of the project

40

Empire North Project

Target In-Service second half of fiscal 2020

Est Capital Cost $145 million

Est Annual Revenues ~$25 million

Receipt Point Jackson (Tioga Co Pa production)

Design Capacity and Delivery Points 175000 Dthd to Chippawa (TCPL interconnect)

30000 Dthd to Hopewell (TGP 200 interconnect)

Customers Fully subscribed (205000 Dthday)

Major Facilities 2 new compressor stations in NY (1) amp Pa (1)

No new pipeline construction

Regulatory Process FERC 7(c) application filed on 21618

FERC Environmental Assessment issued 103018

Pipeline amp Storage

Fully Subscribed Project will Provide 205000 Dthday of Incremental Firm Transportation

41

National Fuel Remains Committed to Northern Access Project

Target In-Service as early as fiscal 2022

Total Cost ~$500MM (~$76MM spent to date)

Estimated Annual Revenues ~$84 million

Delivery Points

350000 Dthd to Chippawa (TCPL interconnect)

140000 Dthd to Hopewell (TGP 200 line)

Regulatory Status

February 3 2017 ndash FERC 7(c) certificate issued

August 6 2018 ndash FERC issued Order finding that NY DEC waived water quality certification

Supply and Empire currently working to finalize remaining federal authorizations

Pipeline amp Storage

To Dawn

42

Continued Expansion of the NFG Supply System

Line N Expansion Opportunities

Line N to Monaca Project Project Firm transportation service to a new ethane

cracker facility being built by Shell Chemical Appalachia LLC

Target In-Service July 2019

Estimated Capital Cost $23 million

Contracted Capacity 133000 Dthday

Additional Line N Expansion Opportunity (Supply OS 221) Project New firm transportation service for on-system

demand

Open Season Capacity Awarded 165000 to foundation shipper Precedent agreement in negotiations

Pipeline amp Storage

43

Pipeline amp Storage Customer Mix

Producer33

LDC42

Marketer10

Outside Pipeline

9

End User6

42 MMDthd

(1) Contracted as of 10312018

Customer Transportation by Shipper Type(1) Affiliated Customer Mix (Contracted Capacity)

66

521

41

34

9579

59

LDCs Producers Marketers FirmStorage

Affiliated Non-Affiliated

Firm Transport

Pipeline amp Storage

44

Utility OverviewNational Fuel Gas Distribution Corporation

45

New York amp Pennsylvania Service Territories

New York

Total Customers(1) 535800ROE 87 (NY PSC Rate Case Order April 2017)Rate Mechanismso Revenue Decouplingo Weather Normalizationo Low Income Rateso Merchant Function Charge (Uncollectibles Adj)o 9010 Sharing (Large Customers)o System Modernization Tracker

Pennsylvania

Total Customers(1) 214400ROE Black Box Settlement (2007)Rate Mechanismso Low Income Rateso Merchant Function Charge

(1) As of September 30 2018

Utility

46

New York Rate Case Outcome

Rate Order Summary

Revenue Requirement $59 million

Rate Base $704 million

Allowed Return on Equity (ROE) 87

Capital Structure 429 equity

Other notable items

New rates became effective 5117

Retains rate mechanisms in place under prior order (revenue decoupling weather normalization merchant function charge 9010 large customer sharing)

No stay-out clause

System modernization tracker for Leak Prone Pipe (LPP)

Earnings sharing started 4118 (5050 sharing starts at earnings in excess of 92)

Article 78 appeal filed on 72817 with oral argument completed in January 2019

On April 20 2017 the New York Public Service Commission issued a Rate Order relating to NFG Distributionrsquos rate case (No 16-G-0257) filed in April 2016

Utility

47

Utility Continues its Significant Investments in Safety

$544$618 $636

$699

$944$980

$809$856

$90-100

$00

$250

$500

$750

$1000

$1250

2015 2016 2017 2018 2019E

Cap

ital E

xpen

ditu

res

($ m

illio

ns)

Fiscal Year

Capital Expenditures for Safety Total Capital Expenditures

Modernization Spending in NY Expected to Grow Gross Margin By $2 MM - $5 MM in FY 2019

(1)

(1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation

Utility

System modernization tracker in NY allows recovery of pipeline replacementcosts which is expected to drive modest gross margin and rate base growth

48

Accelerating Pipeline Replacement amp Modernization

Wrought Iron

Plastic

CoatedBare

120130

146 144159

2014 2015 2016 2017 2018Calendar Year

NY9726 miles

PA4830 miles

No Cast Iron Mains in Pa

Miles of Utility Main Pipeline ReplacedUtility Mains by Material(1)

Wrought Iron

Cast Iron

Plastic

Coated Bare

Utility

(1) All values are reported on a calendar year basis as of December 31 2018

49

A Proven History of Controlling Costs

$200 $189 $195

$166 $166

$31 $31

$197 $197

$0

$50

$100

$150

$200

$250

2015 2016 2017 2018 TTM 123118

Fiscal Year

OampM Expense Non-Service Pension Costs

OampM Expense ($ millions)

Utility

(1)

(1) For purposes of comparability to FY 2015 2016 and 2017 Utility Operation and Maintenance Expense for FY 2018 and the twelve months ended December 31 2018 was adjusted by approximately $314 million and $312 million respectively to include non-service pension costs which were re-classified as Other Income (Deductions) as of October 1 2018 on the Companyrsquos Income Statement See Slide 64 for non-GAAP reconciliation of Adjusted Operation and Maintenance Expense to Operation and Maintenance Expense by segment

50

Consolidated Financial OverviewUpstream I Midstream I Downstream

51

Adjusted Operating Results ($ per share)(1)

Diversified Balanced Earnings and Cash Flows

(1) A reconciliation of Adjusted Operating Results to Earnings per Share by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation(2) Consolidated Adjusted EBITDA includes Energy Marketing and Corporate amp All Other Segments A reconciliation of Adjusted EBITDA to Net Income by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in

the Business is included at the end of this presentation

Adjusted EBITDA ($ millions)(2)

$176 $179

$184 $181

$92 $97

$318 $327

$761 $775

$-

$200

$400

$600

$800

FY 2018 TTM 123118

$059 Utility

$097 Pipeline amp Storage

$057 Gathering

$125 Exploration

amp Production

$334 $345 to $365

$-

$100

$200

$300

$400

FY 2018 FY 2019 Guidance

Rate Regulated

40-45

$728

Rate Regulated

~46

52

$89 $94 $98 $81 $86 $90-$100

$140$230

$114 $95 $93 $120-$150

$138$118

$54$33 $48

$55-$65

$603$557

$99 $246$356

$460-$495

$970 $1001

$366$455

$583

$725-$810

$0

$250

$500

$750

$1000

$1250

2014 2015 2016 2017 2018 2019GuidanceFiscal Year

Exploration amp Production

Gathering

Pipeline amp Storage

Utility

Disciplined Flexible Capital Allocation

(2)

(1) Total Capital Expenditures include Energy Marketing Corporate and All Other A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation (2) FY16 FY17 and FY18 reflects the netting of $157 million $7 million and $17 million respectively of up-front proceeds received from joint development partner for working interest in joint development wells and $21M in intercompany asset transfers in FY18

Capital Expenditures by Segment ($ millions)(1)

53

Maintaining Strong Balance Sheet amp Liquidity

Total Equity49

Total Debt51

$42 Billion Total Capitalizationas of December 31 2018

218 x251 x 245 x 247 x 256 x

2015 2016 2017 2018 TTM 123118Fiscal Year End

Net Debt Adjusted EBITDA(1) Capitalization

Debt Maturity Profile ($MM) Liquidity

Committed Credit FacilitiesShort-term Debt OutstandingAvailable Short-term Credit FacilitiesCash Balance at 123118 Total Liquidity at 123118

$ 750 MM0 MM

750 MM110 MM

$ 860 MM

$500 $549 $500

$300 $300

$0

$200

$400

$600

(1) Net Debt is net of cash and temporary cash investments Reconciliations of Net Debt and Adjusted EBITDA to Net Income are included at the end of this presentation

54

Appendix

55

Safe Harbor For Forward Looking StatementsThis presentation may contain ldquoforward-looking statementsrdquo as defined by the Private Securities Litigation Reform Act of 1995 including statements regarding future prospectsplans objectives goals projections estimates of oil and gas quantities strategies future events or performance and underlying assumptions capital structure anticipatedcapital expenditures completion of construction projects projections for pension and other post-retirement benefit obligations impacts of the adoption of new accounting rulesand possible outcomes of litigation or regulatory proceedings as well as statements that are identified by the use of the words ldquoanticipatesrdquo ldquoestimatesrdquo ldquoexpectsrdquo ldquoforecastsrdquoldquointendsrdquo ldquoplansrdquo ldquopredictsrdquo ldquoprojectsrdquo ldquobelievesrdquo ldquoseeksrdquo ldquowillrdquo ldquomayrdquo and similar expressions Forward-looking statements involve risks and uncertainties which couldcause actual results or outcomes to differ materially from those expressed in the forward-looking statements The Companyrsquos expectations beliefs and projections are expressedin good faith and are believed by the Company to have a reasonable basis but there can be no assurance that managementrsquos expectations beliefs or projections will result or beachieved or accomplished

In addition to other factors the following are important factors that could cause actual results to differ materially from those discussed in the forward-looking statements delaysor changes in costs or plans with respect to Company projects or related projects of other companies including difficulties or delays in obtaining necessary governmentalapprovals permits or orders or in obtaining the cooperation of interconnecting facility operators governmentalregulatory actions initiatives and proceedings including thoseinvolving rate cases (which address among other things target rates of return rate design and retained natural gas) environmentalsafety requirements affiliate relationshipsindustry structure and franchise renewal changes in laws regulations or judicial interpretations to which the Company is subject including those involving derivatives taxessafety employment climate change other environmental matters real property and exploration and production activities such as hydraulic fracturing financial and economicconditions including the availability of credit and occurrences affecting the Companyrsquos ability to obtain financing on acceptable terms for working capital capital expendituresand other investments including any downgrades in the Companyrsquos credit ratings and changes in interest rates and other capital market conditions changes in the price ofnatural gas or oil impairments under the SECrsquos full cost ceiling test for natural gas and oil reserves factors affecting the Companyrsquos ability to successfully identify drill for andproduce economically viable natural gas and oil reserves including among others geology lease availability title disputes weather conditions shortages delays orunavailability of equipment and services required in drilling operations insufficient gathering processing and transportation capacity the need to obtain governmentalapprovals and permits and compliance with environmental laws and regulations increasing health care costs and the resulting effect on health insurance premiums and on theobligation to provide other post-retirement benefits changes in price differentials between similar quantities of natural gas or oil sold at different geographic locations and theeffect of such changes on commodity production revenues and demand for pipeline transportation capacity to or from such locations other changes in price differentialsbetween similar quantities of natural gas or oil having different quality heating value hydrocarbon mix or delivery date the cost and effects of legal and administrative claimsagainst the Company or activist shareholder campaigns to effect changes at the Company uncertainty of oil and gas reserve estimates significant differences between theCompanyrsquos projected and actual production levels for natural gas or oil changes in demographic patterns and weather conditions changes in the availability price oraccounting treatment of derivative financial instruments changes in laws actuarial assumptions the interest rate environment and the return on plantrust assets related to theCompanyrsquos pension and other post-retirement benefits which can affect future funding obligations and costs and plan liabilities changes in economic conditions includingglobal national or regional recessions and their effect on the demand for and customersrsquo ability to pay for the Companyrsquos products and services the creditworthiness orperformance of the Companyrsquos key suppliers customers and counterparties the impact of potential information technology cybersecurity or data security breaches economicdisruptions or uninsured losses resulting from major accidents fires severe weather natural disasters terrorist activities or acts of war significant differences between theCompanyrsquos projected and actual capital expenditures and operating expenses or increasing costs of insurance changes in coverage and the ability to obtain insurance

Forward-looking statements include estimates of oil and gas quantities Proved oil and gas reserves are those quantities of oil and gas which by analysis of geoscience andengineering data can be estimated with reasonable certainty to be economically producible under existing economic conditions operating methods and governmentregulations Other estimates of oil and gas quantities including estimates of probable reserves possible reserves and resource potential are by their nature more speculativethan estimates of proved reserves Accordingly estimates other than proved reserves are subject to substantially greater risk of being actually realized Investors are urged toconsider closely the disclosure in our Form 10-K available at wwwnationalfuelgascom You can also obtain this form on the SECrsquos website at wwwsecgov

For a discussion of the risks set forth above and other factors that could cause actual results to differ materially from results referred to in the forward-looking statements seeldquoRisk Factorsrdquo in the Companyrsquos Form 10-K for the fiscal year ended September 30 2018 and the Forms 10-Q for the quarter ended March 31 2018 June 30 2018 and December31 2018 The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date thereof or to reflect the occurrence ofunanticipated events

Appendix

10

Financial Highlights

First Quarter Fiscal 2019

11

673 572 361458

Net

Oil

and

Gas

Pr

oduc

tion

First Quarter Fiscal 2019 Results and Drivers

Exploration amp Production

$034

Exploration amp Production

$037

Gathering $013

Gathering $016

Pipeline amp Storage

$029

Pipeline amp Storage

$029

Utility $025

Utility $030

$102

$112

Energy Marketing $001 Energy Marketing ($001)CorporateAll Other $001

Q1 FY18 Q1 FY19

Adjusted Operating Results ($share)(1)

(1) Adjusted Operating results of $102 for Q1 Fiscal 2018 and $112 for Q1 Fiscal 2019 include operating results of Energy Marketing and Corporate amp All Other segments See slide 61 for a Reconciliation of Adjusted Operating Results to Earnings Per Share(2) Realized price after hedging

$5979 $6170 $272 $261

Q1 FY 2018 Q1 FY 2019

Oil

and

Gas

Pr

icin

g(2)

Natural Gas ($Mcfe)Crude Oil ($Bbl)

Oil Prices

Natural Gas Prices

$238 $297

Gat

herin

g R

even

ue ($

MM

)Increased Seneca Natural Gas Production

Drivers

Natural Gas Production

Oil Production(sale of Sespe field)

Crude Oil (Mbbl) Natural Gas (Bcf)

12

Earnings Guidance

FY2018 Adjusted Operating Results

Non-regulated Businesses

Exploration amp ProductionGathering

$334 share(1) $345 to $365 shareFY2019 Earnings Guidance

Seneca Net Production 210 to 230 Bcfe Gathering Revenues $130-140 million

Natural Gas ~$245Mcf(2) (vs $252Mcf in FY 2018) Crude Oil ~$59Bbl(3) (vs $5866Bbl in FY 2018)

Key Guidance Drivers

(1) Excludes the $1035 million or $120 per share reduction in tax expense due to the remeasurement of deferred taxes resulting from the 2017 Tax Reform Act See non-GAAP disclosure on slide 61 of this presentation(2) Assumes NYMEX natural gas pricing of $325MMBtu (winter) and $275MMBtu (summer) and basin spot pricing of $275MMBtu (winter) and $225MMBtu (summer) for FY19 and reflects the impact of existing financial hedges firm sales

and firm transportation contracts(3) Assumes NYMEX (WTI) oil pricing of $5500Bbl and California-MWSS pricing differentials of 102 to WTI for FY19 and reflects impact of existing financial hedge contracts

Production amp Gathering Throughput

Realized natural gas prices (after-hedge)

Utility Operating Income

Regulated BusinessesPipeline amp StorageUtility

Guidance assumes normal weather modestly higher gross margin expected to be offset by cost inflation

~$285 million in revenues (expected decrease primarily due to expiration of contract on Empire system)

Pipeline amp Storage Revenues

Tax Reform

Realized oil prices (after-hedge)

Lower effective tax rate Effective tax rate ~24-25 (federal rate 21)

13

Exploration amp Production and Gathering OverviewSeneca Resources Company LLC ~ National Fuel Gas Midstream Company LLC

14

Proved Reserves

385 337 290 302 277

16832142

16751973

2357

1914

2344

1849

2154

2523

0

500

1000

1500

2000

2500

3000

2014 2015 2016 2017 2018At September 30

Natural Gas (Bcf)

Crude Oil (MMbbl)

361 Reserve Replacement Rate

Seneca Drill-bit FampD = $066Mcfe(1)

Appalachia Drill-bit FampD = $065Mcfe(1)

(1) Seneca ldquoDrill-bitrdquo finding and development (ldquoFampDrdquo) costs exclude the impact of reserve revisions

Total Proved Reserves (Bcfe)

Fiscal 2018 Proved Reserves Stats

$138

$112

$132

$098

$074

$050

$100

$150

2014 2015 2016 2017 2018

3-Year Average FampD Cost ($Mcfe)

70

30

PDPs PUDs

EampP and Gathering

15

3 rig development program with second rig in WDA focused on Utica

15-20 net production growth expected through fiscal 2022

New EDA Utica development with production expected in Q2 fiscal 2019

Utilize new Atlantic Sunrise firm transportation capacity

Layer-in firm sales to take advantage of attractive regional pricing

Gross production growth will benefit NFGrsquos Gathering segment

Minimal capital investment in California to generate significant cash flow

Growing Production within Disciplined Capital Program

205 194 176 ~16

1406 1541 1605194-214

1611 1735 1781210-230

0

50

100

150

200

250

2016 2017 2018 2019E

$38 $38 $26 ~$25$61

$208$330

$435-$470

$99

$246

$356

$460-$495

$0

$200

$400

$600

2016 2017 2018 2019E

Appalachia West Coast (California)

Near-Term Growth Strategy EampP Net Capital Expenditures ($ millions)(1)

EampP Net Production (Bcfe)

EampP and Gathering

(1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentationFY16 FY17 and FY18 guidance reflects the netting of $157 million $7 million and $17 million respectively of up-front proceeds received from joint development partner for working interest in joint development wells

16

Significant Appalachian Acreage Position

Average gross production ~311 MMcfd

Mostly leased (16-18 royalty) with no significant near-term lease expirations

~90 remaining Marcellus amp Utica locations economic at ~$184Mcf

Additional Marcellus (Tioga Co) amp Geneseo (Lycoming Co) potential

Eastern Development Area (EDA)

Western Development Area (WDA)

Average gross production(1) ~327 MMcfd Large inventory of Marcellus amp Utica

locations economic at ~$200Mcf Royalty free mineral ownership

enhances well economics Highly contiguous nature drives cost and

operational efficiencies

EampP and Gathering

EDA - 70000 AcresWDA - 715000 Acres

(1) Average EDA and WDA gross production as well as WDA-CRV Utica production (see slide 19) and CovingtonTract 595 Production (see slide 23) is for the quarter ended December 31 2018

17

Western Development AreaMarcellus Core Acreage

vs Utica Appraisal Trend(1)

(1) The Utica Shale lies approximately 5000 feet beneath Senecarsquos WDA Marcellus acreage (2) Appraisal program currently in progress Additional tests are planned Prior Marcellus delineation tests helped define the prospective limits of the Marcellus core acreage planned testing in the Utica expected to do the same

Area of Re-Development ~120 Utica locations on existing Marcellus pads

Key Utica testsPast Marcellus delineation testsUtica Trend (currently evaluating)Marcellus Core Acreage

Large well inventory economic at ~$200 Mcf

Marcellus Shale 600+ well locations remaining 200000 acres

Utica Shale 500+ potential locations across Utica trend evaluating extent of prospective acreage(2)

Fee acreage (no royalty) enhances economics and provides development flexibility

Addition of 2nd WDA drilling rig in Q3 FY18 focused on redevelopment of Clermont-Rich Valley acreage for Utica

Use of existing gathering pad and water infrastructure for Utica drives increased Appalachian program returns

Highly contiguous position drives best in class well costs

Utica test results on trend with other Utica wells in NE Pa

Long-term firm contracts support growth

Boone Mountain Utica Test Well23 Bcf 1000ft

Rich Valley Utica Test Well23 Bcf 1000ft

EampP and Gathering

WDA Highlights

18

WDA Utica Appraisal Results and Initial Type Curve

Tested producing from 17 Utica wells in WDA-CRV Higher pressure significantly enhances well

productivity (Utica ~5000rsquo deeper than Marcellus) Drawdown management is critical restricted

drawdown appears to improve well EURs Early production declines much shallower vs

Marcellus

WDA Utica Appraisal Update

WDA Economics

(1) Internal Rate of Return (IRR) is pre-tax and includes estimated well costs under current cost structure LOEand anticipated gathering tariffs

(2) Initial WDA-CRV Utica type curve based on production results and reservoir expectations from the first 5appraisal wells in the WDA-CRV area

(3) WDA-CRV Utica Average includes all 17 producing wells including 2 wells (pad E09-S) for which drawdownmanagement was not used

EampP and Gathering

EURBcf1000rsquo

Well Cost$M1000rsquo

IRR $225

Break-even15 IRR(1)

Utica - CRV 17 $887 23 $197

Marcellus 10 ndash 11 $643 19 $206

(2)

0

1

2

3

4

5

6

7

8

9

0 12 24 36 48 60 72 84 96 108 120

Cum

ulat

ive

Prod

uctio

n B

CF

Months On

WDA-CRV Utica Wells - Normalized to 9000rsquoUtica Type Curve CRV Utica AverageWDA Marcellus Type Curve Boone Mountain Appraisal WellWDA-CRV Utica Type Curve(2) WDA-CRV Utica Average(3)

0005101520253035

0 2 4 6 8 10 12

19

Transitioning to Utica Development in CRV

WDA-CRV Marcellus(Depth ~7000 feet)

WDA-CRV Utica(Depth ~12000 feet)

Avg CRV Marcellus Production 270 MMcfd

Rem Avg EUR 10-11 Bcf 1000 lat ft

Rem Avg Well Costs = $643lat ft

120+ locations on existing Marcellus pads

Est EURs 17 Bcf 1000 lat ft

Est Development Well Costs = $887lat ft

CRV Utica Transition Plan

1)Finish Marcellus Pads in Development

Drill 24 complete 24 Marcellus wells

2)Continue Optimizing Utica DampC design

Additional optimization wells focusing on

Completion design

Landing zone targets

3)Continue transition to Utica development

Future drilling on multi-well pads

Continue using optimization results to determine development well design

Tailor development plan to use existing pad water and gathering infrastructure

CRV Utica Development Utilizes Existing Pad Water and Gathering Infrastructure to Drive Economics

EampP and Gathering

Rich Valley Utica Test

Existing Line

Leased

Seneca Fee

Producing

FY19 Producer

Development

20

Leveraging Existing Gathering Water and Pad Infrastructure Enhances Returns

Limited New Infrastructure Needed to Support Production Growth

WDA Well Costs(1) WDA Consolidated Economics

Steady activity levels and coordination between upstream and midstream activities

enhance returns provide economies of scale and significant operational flexibility

(1) WDA Marcellus well costs reflect drilling completion amp gathering costs for 192 drilled and completed wells as of 93018 WDA Utica well costs reflect expected drilling completion amp gathering costs for the ~120 well locations in area of redevelopment (2) Internal Rate of Return for Seneca WDA includes estimated well costs under current cost structure and anticipated LOE and Gathering costs Internal Rate of Return for Seneca WDA and Gathering includes expected gathering capital expenditures

through FY 2022 well costs under current cost structure and non-gathering LOE

$685$887

$210

$0

$200

$400

$600

$800

$1000

Marcellus(Historic)

Utica - CRV(Current)

$ la

tera

l foo

t

Drilling amp Completion Gathering

$931$895

10 -11

17

00

03

06

09

12

15

18

Marcellus(Historic)

Utica - CRV(Current)

EUR

10

00 fe

et (B

cf)

60-70 EUR increase expected per well

Total cost per well expected to marginally increase

WDA EURs

At a $225 netback price consolidated Seneca WDA and Gathering IRR is

approximately 33 an uplift of ~12 over standalone Seneca WDA economics(2)

10+ IRR Uplift Expected

21

Integrated Development ndash WDA Gathering System

Current System In-Service

~78 miles of pipe 36220 HP of compression

Current Capacity 470 MMcf per day

Interconnects with TGP 300

Total Investment to Date $301 million

Future Build-Out

FY 2019 CapEx $10 - $15 million

Modest gathering pipeline and compression investment required to support Senecarsquos transition to Utica development

Opportunity for 300 miles of pipelines and five compressor stations (+60000 HP installed) as Senecarsquos drilling activity continues

Deliverability into TGP 300 and NFG Supply

Gathering System Build-Out Tailored to Accommodate Senecarsquos WDA Development

Clermont Gathering System Map

EampP and Gathering

22

WDA Firm Transportation and Sales Capacity

Will continue to layer-in firm sales deals of short and longer duration on TGP 300 to reduce spot exposure

WDA spot realizations track TGP Station 313 pricing typically 10cent - 30cent better than TGP Marcellus Zone 4

Leidy South will provide additional capacity to premium markets (Transco Zone 6)

WDA Exit Capacity Supports Long-term Production Growth and Enhances Consolidated Returns

WDA Contracted Firm Transport and Gross Sales Volumes (MDthd)

Seneca gross production trend

EampP and Gathering

0

100

200

300

400

500

600

700

Niagara Expansion Project (TGP and NFG)FT Capacity 158000 Dthd $067Dth

Firm Sales NYMEX amp DAWN

WDA - TGP 300Firm Sales

Leidy SouthTransco Zone 6

Markets330000 Dthd(1)

Will layer-in firm sales to minimize spot exposure

(1) Portion of Transco Project capacity will likely be utilized by EDA Lycoming County production

WDA Gas Marketing Strategy

23

Eastern Development Area

EDA Acreage ndash 70000 AcresEDA Highlights

1 DCNR Tract 007 (Tioga Co Pa)bull Utica development resumed in third quarter fiscal 2018

bull ~43 remaining Utica locations economic at ~$184 Mcf

bull Gathering Infrastructure NFG Midstream Wellsboro

bull Marcellus Shale expected to provide ~60 additional locations

EampP and Gathering

2

1

3

2 Covington amp DCNR Tract 595 (Tioga Co Pa)bull Marcellus locations fully developed (average daily gross production of ~93 MMcfd)

bull Gathering Infrastructure NFG Midstream Covington

bull Opportunity for future Utica appraisal

3 DCNR Tract 100 amp Gamble (Lycoming Co Pa)bull ~45 remaining Marcellus locations economic at ~$153 Mcfbull Firm Transportation Capacity Atlantic Sunrise (189 MDthd)

bull Gathering Infrastructure NFG Midstream Trout Run

bull Geneseo Shale expected to provide 100-120 additional locations

24

EDA Marcellus Lycoming County Development

Marcellus Development in Lycoming County has Resumed in Connection with Atlantic Sunrise

(1) Includes physical fixed price and NYMEX-based firm sales contracts that do not carry any additional transportation costs

EampP and Gathering

Prolific Marcellus acreage with peer leading well results

~45 remaining Marcellus locations economic at ~$153 Mcf

Near-term development focused on filling Atlantic Sunrise capacity

Existing Line

Leased

Seneca Fee

Producing

FY19 Producer

Development

0

50

100

150

200

250

Gro

ss F

irm V

olum

es (M

Dth

d)

EDA ndash Transco Firm Contracts

Atlantic Sunrise (Transco)FT Capacity 189405 Dthd

Cost $073DthFirm Sales NYMEX+

Transco Firm Sales(1)

25

EDA Utica Tioga County Development

Utica Development in Tioga County ndash Tract 007 Development Resumed in Q3 Fiscal 2018

In-Service November 2016

Lateral Length 4640 ft

30 Day IP 1000 ft 34 MMcfd

Est EUR 1000 ft 24 Bcf

Inventory ~43 locations economic at ~$184 Mcf

Targeting to grow production by 100 to 150 MDthd by fiscal 2020

Expected Development Costs $1045 per lateral ft

Gathering Infrastructure NFG Midstream Wellsboro

Modest build-out required to connect to TGP 300

SalesTakeaway Strategy Layer-in firm sales with shippers holding capacity on TGP 300

(1) Includes physical fixed price and NYMEX-based firm sales contracts that do not carry any additional transportation costs

Tract 007 Utica Appraisal Well Results vs Industry

EampP and Gathering

0

100000

200000

300000

400000

500000

600000

700000

800000

0 100 200 300

Nor

mal

ized

Cum

ulat

ive

(Mcf

10

00rsquo)

Days On ProductionIndustry PotterTioga Wells Seneca DCNR 007 73H

0

25

50

75

100

125

150

Gro

ss F

irm V

olum

es (M

Dth

d)

EDA ndash TGP 300 Firm Contracts

Northeast Supply Diversification ProjectFT Capacity 50000 Dthd $050Dth

Firm Sales NYMEX and DAWN

EDA - TGP 300Firm Sales(1)

26

Integrated Development ndash EDA Gathering Systems

Total Investment (to date) ~$46 million FY 2019 Estimated Capital Expenditures $1 MM - $2 MM Capacity 220000 Dth per day (Interconnect w TGP 300) Production Source Seneca Resources ndash Tioga Co (Covington and DCNR Tract 595)

Total Investment (to date) ~$208 million FY 2019 Estimated Capital Expenditures $25 MM - $35 MM Capacity 466000 to 585000 Dth per day (Interconnect w Transco) Production Source Seneca Resources ndash Lycoming Co (DCNR Tract 100 and Gamble) Future third-party volume opportunities

Covington Gathering System

Trout Run Gathering System

Gathering Segment Supporting Senecarsquos EDA Production amp Future Development

Wellsboro Gathering System Total Investment (to date) ~$14 million FY 2019 Estimated Capital Expenditures $8 MM - $15 MM Capacity up to 200000 Dth per day (Interconnect w TGP 300) Production Source Seneca Resources ndash Tioga Co (DCNR Tract 007)

EampP and Gathering

2

1

3

27

Long-term Contracts Supporting Appalachian Growth

(1) Represents base firm sales contracts not tied to firm transportation capacity Base firm sales are either fixed priced or priced at an index (eg NYMEX ) +- a fixed basis and do not carry any transportation costs

Seneca continues to layer-in firm sales contracts with attractive realizations to lock-in drilling economics and minimize spot exposure ahead of firm transportation in-service dates

EampP and Gathering

-

100

200

300

400

500

600

700

800

900

1000

1100

1200

FY 2019 FY 2020 FY 2021 FY 2022Northeast Supply Diversification 50000 Dthd

Niagara Expansion (TGP amp NFG)Delivery Markets Canada-Dawn amp TETCO

158000 Dthd

Atlantic Sunrise (Transco)Delivery Markets Mid-Atlantic amp Southeast US

189405 Dthd

In-BasinFirm Sales

Contracts(1)

Leidy South (Transco amp NFG)

Transco Zone 6 Markets330000 Dthd

Seneca Appalachia Natural Gas MarketingGross Firm Contract Volumes (Mdthday)

28

297000 ($061)

305200 ($061)

305600 ($063)

337000 ($057)

370800 ($024)

369600 ($060)

367900 ($067)

33400 ($070)74500 ($077) 74900 ($077)

81100 ($078)

85900 ($078)

92000 ($073)

91300 ($073)

178800 $255

196000 $234

195500 $234

149900 $232

129500 $230

105400 $222

104500 $222

~517800 509200 575700 576000 568000 586200 567000 563700

Q1 FY19 Q2 FY19 Q3 FY19 Q4 FY19 Q1 FY20 Q2 FY20 Q3 FY20 Q4 FY20

Fixed Price Dawn NYMEX

Near-term Firm Sales Provide Market amp Price Certainty

Net Contracted Firm Sales Volumes (Dth per day)Contracted Index Price Differentials ($ per Dth)(1)

(1) Values shown represent the weighted average fixed price or contracted fixed differential relative to NYMEX (netback price) less any associated transportation costs

Actual Daily Net

Production

641200 716500 708700 693500 708400 674400 667000Gross Firm Sales Volumes (Dthd)

EampP and Gathering

29

California Oil

Stable Oil Production | Minimal Capital Investment | Steady Free Cash Flow

1

2

3

4

5

Location Formation Production Method

FY18 Daily Production(net Boed)

1 East Coalinga Other Temblor Primary 512

2 North Lost Hills

Tulare amp Etchegoin

PrimarySteam flood 892

3 South Lost Hills

Monterey Shale Primary 1359

4 North Midway Sunset

Tulare amp Potter Steam flood 2786

5 South Midway Sunset Antelope Steam flood 2048

TOTAL WEST DIVISION NET PRODUCTION(1) 7597 Boed

EampP and Gathering

(1) West division net production for FY 2018 excludes production from Sespe field which was divested on May 1 2018

30

California Capital Expenditures vs Production

9341 8863

8033 ~7300

2016 2017 2018 2019

Fiscal Year

West Division Average Net Daily Production (Boe)West Division Annual Capital Expenditures ($ MM)(1)

$38 $38

$26 ~$25

2016 2017 2018 2019

Fiscal YearGuidance Guidance

(1) Seneca West Division capital expenditures includes Seneca corporate and eliminations

EampP and Gathering

Sepse Sale Closed on 5118(reduced production by ~900 boed)

31

Pioneer

South MWSS

Acreage

North MWSS

AcreageSec 17N

4149 51

NMWSS amp 17N SMWSS amp Pioneer East Coalinga

California Development Activities

Modest near-term capital program focused on locations that earn attractive returns in current oil price environment

AampD will focus on low cost bolt-on opportunities

Sec 17 Pioneer and East Coalinga development to provide future growth

North

Project IRRs at $55Bbl(1)

(1) Reflects pre-tax IRRs at a $55Bbl WTI

EampP and Gathering

Seneca West Economics

South

East Coalinga

North

South

32

Fiscal 2019 Production and Price Certainty

~49 Bcfe

210 ndash 230 Bcfe

~114 Bcf

~29 Bcf (2)

16+- Bcf~12 Bcfe

0

40

80

120

160

200

240

YTD FY19Actuals

Fixed Price + FirmSales w Hedge

Firm Sales(Unhedged)

Spot Sales California TotalSeneca

Prod

uctio

n (B

cfe)

(1) Average realized price reflects uplift from financial hedges less fixed differentials under firm sales contracts and any firm transportation costs(2) Indicates firm sales contracts with fixed index differentials but not backed by a matching financial hedge

114 Bcf locked-in realizing net ~$241Mcf (1)

29 Bcf of additional basis protection

Spot production assumed to be sold

at ~$275Mmbtu(winter) and ~$225

(summer)

143 Bcf of Appalachian Production Protected by Firm Sales for Remainder of Year

79 of oil production hedged at $5757 Bbl

EampP and Gathering

33

Strong Hedge Book

Natural Gas Swap amp Fixed Physical Sales Contracts (Millions MMBtu)

(1) Fixed price physical sales exclude joint development partnerrsquos share of fixed price contract WDA volumes as specified under the joint development agreement(2) Reflects percentage of projected production for FY19 hedged at the midpoint of the production guidance range(3) Senecarsquos remainder FY19 Production reflects the total FY19 production guidance of 210-230 Bcfe or 220 Bcfe at the midpoint less Q1 actual production

Crude Oil Swap Contracts (Thousands Bbls)

13591188

732

456

0

500

1000

1500

2000

2500

FY 2019 FY 2020 FY 2021 FY 2022

NYMEX (WTI)

Brent

FY 19 Crude Oil79 Hedged (2)

FY 2019 Remaining Production (3)

EampP and Gathering

1174

709

469 406

0

50

100

150

200

250

FY 2019 FY 2020 FY 2021 FY 2022

NYMEX Swaps

Dawn Swaps

Fixed Price Physical Sales

(1)

FY 2019 Remaining Production (3)

FY 19 Nat Gas71 Hedged (2)

34

$065 $070$070 -$075

FY 2017 FY 2018 FY 2019E

$060 $060 $060

$011 $009 $007$071 $069 ~$067

FY 2017 FY 2018 FY 2019E Gathering amp Transport LOE (non-Gathering) GampA Taxes amp Other

Seneca Operating Costs

Competitive low cost structure in Appalachia and California supports strong cash margins

Gathering fee generates significant revenue stream for affiliated gathering company

Seneca DDampARate

$Mcfe

$054 $054 $056

$042 $038 $031

$034 $034 $030

$017 $014 $015

$147 $140 ~$132

FY 2017 FY 2018 FY 2019E

(1)

$1791$1746~$2050

FY 2017 FY 2018 FY 2019E

Appalachia LOE amp Gathering $Mcfe

California LOE$Boe

Total Seneca Cash OpEx$Mcfe

(1)

(2)

(2)

(1) GampA estimate represents the midpoint of the GampA guidance range of $025 to $035 for fiscal 2019(2) The total of the two LOE components represents the midpoint of the LOE guidance range of $085 to $090 for fiscal 2019

EampP and Gathering

35

Senecarsquos Continuing Commitment to the Environment

Produced Water Recycled in Appalachia

100 70Recycled Water

Used in New Shale Well

Completions

Water and Fluids Management Air Quality and Emissions

Seneca Resources Water OperationsFiscal 2018

Seneca Resources Remains Focused on Minimizing GHG Emissions

The Environmental Partnership

EPA Natural Gas Star Program

Green Completions (all fiscal 2018 wells)

Ultrasonic Leak Detection Technology

Emissions Controls

Rig and Vehicle Fuel Conversion

Integrating Renewable Energy into Operations

EampP and Gathering

36

Pipeline and Storage OverviewNational Fuel Gas Supply Corporation ~ Empire Pipeline Inc

37

Pipeline amp Storage Segment Overview

(1) As of September 30 2018 as disclosed in the Companyrsquos fiscal 2018 form 10-K(2) As of December 31 2017 calculated from National Fuel Gas Supply Corporationrsquos and Empire Pipeline Incrsquos 2017 FERC Form-2 reports respectively

Empire Pipeline Inc

National Fuel Gas Supply Corporation

Empire Pipeline

Supply Corp

Contracted Capacity(1) Firm Transportation 3187 MDth per day Firm Storage 71938 Mdth (fully subscribed)

Rate Base(2) ~$820 million FERC Rate Proceeding Status

Rate case settlement extension approved Nov lsquo15 Rate case filing expected by 73119

Contracted Capacity(1) Firm Transportation 978 MDth per day Firm Storage 3753 Mdth (fully subscribed)

Rate Base(2) ~$249 million FERC Rate Proceeding Status

Rate case settlement in principle reached on 122118 FERC approval pending

New transportation rates went into on 1119

Pipeline amp Storage

38

All Seneca volumes will flow through wholly-owned NFG gathering facilities

FM100 Project - Consolidated Benefit for NFG

330000 Dthd of new transportation capacity from WDA and EDA acreage positions to premium markets

New Transco capacity (Leidy South) 330000 Dthday

Rate(1) competitive with other expansion project rates in Senecarsquos current transportation portfolio

Delivery Point(s) Transco Zone 6 interconnections

Seneca

Lease to Transco of new capacity 330000 Dthday

Estimated annual lease revenues ~$35 million

Target In-Service late calendar year 2021

Supply Corp

Project expected to provide long-term earnings uplift to Seneca Supply Corp and Gathering

Pipeline amp Storage

Gathering

(1) Includes lease of new capacity from Supply Corp to Transco

39

FM100 Project ndash Significant Investment by Supply Corp

Pipeline amp Storage

Estimated Capital Cost $280 million(1)

Facilities (all in Pennsylvania) include Approximately 30 miles of new pipeline 2 new compressor stations (totaling

approximately 37000 HP) New interconnection station and modification

of existing interconnection station Abandonment of approximately 45 miles of

existing pipeline and compressor station Regulatory Process

Pre-filing application submitted to FERC in 2017 for original modernization project

FERC 7(b) 7(c) filing expected summer 2019

(1) Includes expansion and modernization portions of the project

40

Empire North Project

Target In-Service second half of fiscal 2020

Est Capital Cost $145 million

Est Annual Revenues ~$25 million

Receipt Point Jackson (Tioga Co Pa production)

Design Capacity and Delivery Points 175000 Dthd to Chippawa (TCPL interconnect)

30000 Dthd to Hopewell (TGP 200 interconnect)

Customers Fully subscribed (205000 Dthday)

Major Facilities 2 new compressor stations in NY (1) amp Pa (1)

No new pipeline construction

Regulatory Process FERC 7(c) application filed on 21618

FERC Environmental Assessment issued 103018

Pipeline amp Storage

Fully Subscribed Project will Provide 205000 Dthday of Incremental Firm Transportation

41

National Fuel Remains Committed to Northern Access Project

Target In-Service as early as fiscal 2022

Total Cost ~$500MM (~$76MM spent to date)

Estimated Annual Revenues ~$84 million

Delivery Points

350000 Dthd to Chippawa (TCPL interconnect)

140000 Dthd to Hopewell (TGP 200 line)

Regulatory Status

February 3 2017 ndash FERC 7(c) certificate issued

August 6 2018 ndash FERC issued Order finding that NY DEC waived water quality certification

Supply and Empire currently working to finalize remaining federal authorizations

Pipeline amp Storage

To Dawn

42

Continued Expansion of the NFG Supply System

Line N Expansion Opportunities

Line N to Monaca Project Project Firm transportation service to a new ethane

cracker facility being built by Shell Chemical Appalachia LLC

Target In-Service July 2019

Estimated Capital Cost $23 million

Contracted Capacity 133000 Dthday

Additional Line N Expansion Opportunity (Supply OS 221) Project New firm transportation service for on-system

demand

Open Season Capacity Awarded 165000 to foundation shipper Precedent agreement in negotiations

Pipeline amp Storage

43

Pipeline amp Storage Customer Mix

Producer33

LDC42

Marketer10

Outside Pipeline

9

End User6

42 MMDthd

(1) Contracted as of 10312018

Customer Transportation by Shipper Type(1) Affiliated Customer Mix (Contracted Capacity)

66

521

41

34

9579

59

LDCs Producers Marketers FirmStorage

Affiliated Non-Affiliated

Firm Transport

Pipeline amp Storage

44

Utility OverviewNational Fuel Gas Distribution Corporation

45

New York amp Pennsylvania Service Territories

New York

Total Customers(1) 535800ROE 87 (NY PSC Rate Case Order April 2017)Rate Mechanismso Revenue Decouplingo Weather Normalizationo Low Income Rateso Merchant Function Charge (Uncollectibles Adj)o 9010 Sharing (Large Customers)o System Modernization Tracker

Pennsylvania

Total Customers(1) 214400ROE Black Box Settlement (2007)Rate Mechanismso Low Income Rateso Merchant Function Charge

(1) As of September 30 2018

Utility

46

New York Rate Case Outcome

Rate Order Summary

Revenue Requirement $59 million

Rate Base $704 million

Allowed Return on Equity (ROE) 87

Capital Structure 429 equity

Other notable items

New rates became effective 5117

Retains rate mechanisms in place under prior order (revenue decoupling weather normalization merchant function charge 9010 large customer sharing)

No stay-out clause

System modernization tracker for Leak Prone Pipe (LPP)

Earnings sharing started 4118 (5050 sharing starts at earnings in excess of 92)

Article 78 appeal filed on 72817 with oral argument completed in January 2019

On April 20 2017 the New York Public Service Commission issued a Rate Order relating to NFG Distributionrsquos rate case (No 16-G-0257) filed in April 2016

Utility

47

Utility Continues its Significant Investments in Safety

$544$618 $636

$699

$944$980

$809$856

$90-100

$00

$250

$500

$750

$1000

$1250

2015 2016 2017 2018 2019E

Cap

ital E

xpen

ditu

res

($ m

illio

ns)

Fiscal Year

Capital Expenditures for Safety Total Capital Expenditures

Modernization Spending in NY Expected to Grow Gross Margin By $2 MM - $5 MM in FY 2019

(1)

(1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation

Utility

System modernization tracker in NY allows recovery of pipeline replacementcosts which is expected to drive modest gross margin and rate base growth

48

Accelerating Pipeline Replacement amp Modernization

Wrought Iron

Plastic

CoatedBare

120130

146 144159

2014 2015 2016 2017 2018Calendar Year

NY9726 miles

PA4830 miles

No Cast Iron Mains in Pa

Miles of Utility Main Pipeline ReplacedUtility Mains by Material(1)

Wrought Iron

Cast Iron

Plastic

Coated Bare

Utility

(1) All values are reported on a calendar year basis as of December 31 2018

49

A Proven History of Controlling Costs

$200 $189 $195

$166 $166

$31 $31

$197 $197

$0

$50

$100

$150

$200

$250

2015 2016 2017 2018 TTM 123118

Fiscal Year

OampM Expense Non-Service Pension Costs

OampM Expense ($ millions)

Utility

(1)

(1) For purposes of comparability to FY 2015 2016 and 2017 Utility Operation and Maintenance Expense for FY 2018 and the twelve months ended December 31 2018 was adjusted by approximately $314 million and $312 million respectively to include non-service pension costs which were re-classified as Other Income (Deductions) as of October 1 2018 on the Companyrsquos Income Statement See Slide 64 for non-GAAP reconciliation of Adjusted Operation and Maintenance Expense to Operation and Maintenance Expense by segment

50

Consolidated Financial OverviewUpstream I Midstream I Downstream

51

Adjusted Operating Results ($ per share)(1)

Diversified Balanced Earnings and Cash Flows

(1) A reconciliation of Adjusted Operating Results to Earnings per Share by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation(2) Consolidated Adjusted EBITDA includes Energy Marketing and Corporate amp All Other Segments A reconciliation of Adjusted EBITDA to Net Income by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in

the Business is included at the end of this presentation

Adjusted EBITDA ($ millions)(2)

$176 $179

$184 $181

$92 $97

$318 $327

$761 $775

$-

$200

$400

$600

$800

FY 2018 TTM 123118

$059 Utility

$097 Pipeline amp Storage

$057 Gathering

$125 Exploration

amp Production

$334 $345 to $365

$-

$100

$200

$300

$400

FY 2018 FY 2019 Guidance

Rate Regulated

40-45

$728

Rate Regulated

~46

52

$89 $94 $98 $81 $86 $90-$100

$140$230

$114 $95 $93 $120-$150

$138$118

$54$33 $48

$55-$65

$603$557

$99 $246$356

$460-$495

$970 $1001

$366$455

$583

$725-$810

$0

$250

$500

$750

$1000

$1250

2014 2015 2016 2017 2018 2019GuidanceFiscal Year

Exploration amp Production

Gathering

Pipeline amp Storage

Utility

Disciplined Flexible Capital Allocation

(2)

(1) Total Capital Expenditures include Energy Marketing Corporate and All Other A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation (2) FY16 FY17 and FY18 reflects the netting of $157 million $7 million and $17 million respectively of up-front proceeds received from joint development partner for working interest in joint development wells and $21M in intercompany asset transfers in FY18

Capital Expenditures by Segment ($ millions)(1)

53

Maintaining Strong Balance Sheet amp Liquidity

Total Equity49

Total Debt51

$42 Billion Total Capitalizationas of December 31 2018

218 x251 x 245 x 247 x 256 x

2015 2016 2017 2018 TTM 123118Fiscal Year End

Net Debt Adjusted EBITDA(1) Capitalization

Debt Maturity Profile ($MM) Liquidity

Committed Credit FacilitiesShort-term Debt OutstandingAvailable Short-term Credit FacilitiesCash Balance at 123118 Total Liquidity at 123118

$ 750 MM0 MM

750 MM110 MM

$ 860 MM

$500 $549 $500

$300 $300

$0

$200

$400

$600

(1) Net Debt is net of cash and temporary cash investments Reconciliations of Net Debt and Adjusted EBITDA to Net Income are included at the end of this presentation

54

Appendix

55

Safe Harbor For Forward Looking StatementsThis presentation may contain ldquoforward-looking statementsrdquo as defined by the Private Securities Litigation Reform Act of 1995 including statements regarding future prospectsplans objectives goals projections estimates of oil and gas quantities strategies future events or performance and underlying assumptions capital structure anticipatedcapital expenditures completion of construction projects projections for pension and other post-retirement benefit obligations impacts of the adoption of new accounting rulesand possible outcomes of litigation or regulatory proceedings as well as statements that are identified by the use of the words ldquoanticipatesrdquo ldquoestimatesrdquo ldquoexpectsrdquo ldquoforecastsrdquoldquointendsrdquo ldquoplansrdquo ldquopredictsrdquo ldquoprojectsrdquo ldquobelievesrdquo ldquoseeksrdquo ldquowillrdquo ldquomayrdquo and similar expressions Forward-looking statements involve risks and uncertainties which couldcause actual results or outcomes to differ materially from those expressed in the forward-looking statements The Companyrsquos expectations beliefs and projections are expressedin good faith and are believed by the Company to have a reasonable basis but there can be no assurance that managementrsquos expectations beliefs or projections will result or beachieved or accomplished

In addition to other factors the following are important factors that could cause actual results to differ materially from those discussed in the forward-looking statements delaysor changes in costs or plans with respect to Company projects or related projects of other companies including difficulties or delays in obtaining necessary governmentalapprovals permits or orders or in obtaining the cooperation of interconnecting facility operators governmentalregulatory actions initiatives and proceedings including thoseinvolving rate cases (which address among other things target rates of return rate design and retained natural gas) environmentalsafety requirements affiliate relationshipsindustry structure and franchise renewal changes in laws regulations or judicial interpretations to which the Company is subject including those involving derivatives taxessafety employment climate change other environmental matters real property and exploration and production activities such as hydraulic fracturing financial and economicconditions including the availability of credit and occurrences affecting the Companyrsquos ability to obtain financing on acceptable terms for working capital capital expendituresand other investments including any downgrades in the Companyrsquos credit ratings and changes in interest rates and other capital market conditions changes in the price ofnatural gas or oil impairments under the SECrsquos full cost ceiling test for natural gas and oil reserves factors affecting the Companyrsquos ability to successfully identify drill for andproduce economically viable natural gas and oil reserves including among others geology lease availability title disputes weather conditions shortages delays orunavailability of equipment and services required in drilling operations insufficient gathering processing and transportation capacity the need to obtain governmentalapprovals and permits and compliance with environmental laws and regulations increasing health care costs and the resulting effect on health insurance premiums and on theobligation to provide other post-retirement benefits changes in price differentials between similar quantities of natural gas or oil sold at different geographic locations and theeffect of such changes on commodity production revenues and demand for pipeline transportation capacity to or from such locations other changes in price differentialsbetween similar quantities of natural gas or oil having different quality heating value hydrocarbon mix or delivery date the cost and effects of legal and administrative claimsagainst the Company or activist shareholder campaigns to effect changes at the Company uncertainty of oil and gas reserve estimates significant differences between theCompanyrsquos projected and actual production levels for natural gas or oil changes in demographic patterns and weather conditions changes in the availability price oraccounting treatment of derivative financial instruments changes in laws actuarial assumptions the interest rate environment and the return on plantrust assets related to theCompanyrsquos pension and other post-retirement benefits which can affect future funding obligations and costs and plan liabilities changes in economic conditions includingglobal national or regional recessions and their effect on the demand for and customersrsquo ability to pay for the Companyrsquos products and services the creditworthiness orperformance of the Companyrsquos key suppliers customers and counterparties the impact of potential information technology cybersecurity or data security breaches economicdisruptions or uninsured losses resulting from major accidents fires severe weather natural disasters terrorist activities or acts of war significant differences between theCompanyrsquos projected and actual capital expenditures and operating expenses or increasing costs of insurance changes in coverage and the ability to obtain insurance

Forward-looking statements include estimates of oil and gas quantities Proved oil and gas reserves are those quantities of oil and gas which by analysis of geoscience andengineering data can be estimated with reasonable certainty to be economically producible under existing economic conditions operating methods and governmentregulations Other estimates of oil and gas quantities including estimates of probable reserves possible reserves and resource potential are by their nature more speculativethan estimates of proved reserves Accordingly estimates other than proved reserves are subject to substantially greater risk of being actually realized Investors are urged toconsider closely the disclosure in our Form 10-K available at wwwnationalfuelgascom You can also obtain this form on the SECrsquos website at wwwsecgov

For a discussion of the risks set forth above and other factors that could cause actual results to differ materially from results referred to in the forward-looking statements seeldquoRisk Factorsrdquo in the Companyrsquos Form 10-K for the fiscal year ended September 30 2018 and the Forms 10-Q for the quarter ended March 31 2018 June 30 2018 and December31 2018 The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date thereof or to reflect the occurrence ofunanticipated events

Appendix

11

673 572 361458

Net

Oil

and

Gas

Pr

oduc

tion

First Quarter Fiscal 2019 Results and Drivers

Exploration amp Production

$034

Exploration amp Production

$037

Gathering $013

Gathering $016

Pipeline amp Storage

$029

Pipeline amp Storage

$029

Utility $025

Utility $030

$102

$112

Energy Marketing $001 Energy Marketing ($001)CorporateAll Other $001

Q1 FY18 Q1 FY19

Adjusted Operating Results ($share)(1)

(1) Adjusted Operating results of $102 for Q1 Fiscal 2018 and $112 for Q1 Fiscal 2019 include operating results of Energy Marketing and Corporate amp All Other segments See slide 61 for a Reconciliation of Adjusted Operating Results to Earnings Per Share(2) Realized price after hedging

$5979 $6170 $272 $261

Q1 FY 2018 Q1 FY 2019

Oil

and

Gas

Pr

icin

g(2)

Natural Gas ($Mcfe)Crude Oil ($Bbl)

Oil Prices

Natural Gas Prices

$238 $297

Gat

herin

g R

even

ue ($

MM

)Increased Seneca Natural Gas Production

Drivers

Natural Gas Production

Oil Production(sale of Sespe field)

Crude Oil (Mbbl) Natural Gas (Bcf)

12

Earnings Guidance

FY2018 Adjusted Operating Results

Non-regulated Businesses

Exploration amp ProductionGathering

$334 share(1) $345 to $365 shareFY2019 Earnings Guidance

Seneca Net Production 210 to 230 Bcfe Gathering Revenues $130-140 million

Natural Gas ~$245Mcf(2) (vs $252Mcf in FY 2018) Crude Oil ~$59Bbl(3) (vs $5866Bbl in FY 2018)

Key Guidance Drivers

(1) Excludes the $1035 million or $120 per share reduction in tax expense due to the remeasurement of deferred taxes resulting from the 2017 Tax Reform Act See non-GAAP disclosure on slide 61 of this presentation(2) Assumes NYMEX natural gas pricing of $325MMBtu (winter) and $275MMBtu (summer) and basin spot pricing of $275MMBtu (winter) and $225MMBtu (summer) for FY19 and reflects the impact of existing financial hedges firm sales

and firm transportation contracts(3) Assumes NYMEX (WTI) oil pricing of $5500Bbl and California-MWSS pricing differentials of 102 to WTI for FY19 and reflects impact of existing financial hedge contracts

Production amp Gathering Throughput

Realized natural gas prices (after-hedge)

Utility Operating Income

Regulated BusinessesPipeline amp StorageUtility

Guidance assumes normal weather modestly higher gross margin expected to be offset by cost inflation

~$285 million in revenues (expected decrease primarily due to expiration of contract on Empire system)

Pipeline amp Storage Revenues

Tax Reform

Realized oil prices (after-hedge)

Lower effective tax rate Effective tax rate ~24-25 (federal rate 21)

13

Exploration amp Production and Gathering OverviewSeneca Resources Company LLC ~ National Fuel Gas Midstream Company LLC

14

Proved Reserves

385 337 290 302 277

16832142

16751973

2357

1914

2344

1849

2154

2523

0

500

1000

1500

2000

2500

3000

2014 2015 2016 2017 2018At September 30

Natural Gas (Bcf)

Crude Oil (MMbbl)

361 Reserve Replacement Rate

Seneca Drill-bit FampD = $066Mcfe(1)

Appalachia Drill-bit FampD = $065Mcfe(1)

(1) Seneca ldquoDrill-bitrdquo finding and development (ldquoFampDrdquo) costs exclude the impact of reserve revisions

Total Proved Reserves (Bcfe)

Fiscal 2018 Proved Reserves Stats

$138

$112

$132

$098

$074

$050

$100

$150

2014 2015 2016 2017 2018

3-Year Average FampD Cost ($Mcfe)

70

30

PDPs PUDs

EampP and Gathering

15

3 rig development program with second rig in WDA focused on Utica

15-20 net production growth expected through fiscal 2022

New EDA Utica development with production expected in Q2 fiscal 2019

Utilize new Atlantic Sunrise firm transportation capacity

Layer-in firm sales to take advantage of attractive regional pricing

Gross production growth will benefit NFGrsquos Gathering segment

Minimal capital investment in California to generate significant cash flow

Growing Production within Disciplined Capital Program

205 194 176 ~16

1406 1541 1605194-214

1611 1735 1781210-230

0

50

100

150

200

250

2016 2017 2018 2019E

$38 $38 $26 ~$25$61

$208$330

$435-$470

$99

$246

$356

$460-$495

$0

$200

$400

$600

2016 2017 2018 2019E

Appalachia West Coast (California)

Near-Term Growth Strategy EampP Net Capital Expenditures ($ millions)(1)

EampP Net Production (Bcfe)

EampP and Gathering

(1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentationFY16 FY17 and FY18 guidance reflects the netting of $157 million $7 million and $17 million respectively of up-front proceeds received from joint development partner for working interest in joint development wells

16

Significant Appalachian Acreage Position

Average gross production ~311 MMcfd

Mostly leased (16-18 royalty) with no significant near-term lease expirations

~90 remaining Marcellus amp Utica locations economic at ~$184Mcf

Additional Marcellus (Tioga Co) amp Geneseo (Lycoming Co) potential

Eastern Development Area (EDA)

Western Development Area (WDA)

Average gross production(1) ~327 MMcfd Large inventory of Marcellus amp Utica

locations economic at ~$200Mcf Royalty free mineral ownership

enhances well economics Highly contiguous nature drives cost and

operational efficiencies

EampP and Gathering

EDA - 70000 AcresWDA - 715000 Acres

(1) Average EDA and WDA gross production as well as WDA-CRV Utica production (see slide 19) and CovingtonTract 595 Production (see slide 23) is for the quarter ended December 31 2018

17

Western Development AreaMarcellus Core Acreage

vs Utica Appraisal Trend(1)

(1) The Utica Shale lies approximately 5000 feet beneath Senecarsquos WDA Marcellus acreage (2) Appraisal program currently in progress Additional tests are planned Prior Marcellus delineation tests helped define the prospective limits of the Marcellus core acreage planned testing in the Utica expected to do the same

Area of Re-Development ~120 Utica locations on existing Marcellus pads

Key Utica testsPast Marcellus delineation testsUtica Trend (currently evaluating)Marcellus Core Acreage

Large well inventory economic at ~$200 Mcf

Marcellus Shale 600+ well locations remaining 200000 acres

Utica Shale 500+ potential locations across Utica trend evaluating extent of prospective acreage(2)

Fee acreage (no royalty) enhances economics and provides development flexibility

Addition of 2nd WDA drilling rig in Q3 FY18 focused on redevelopment of Clermont-Rich Valley acreage for Utica

Use of existing gathering pad and water infrastructure for Utica drives increased Appalachian program returns

Highly contiguous position drives best in class well costs

Utica test results on trend with other Utica wells in NE Pa

Long-term firm contracts support growth

Boone Mountain Utica Test Well23 Bcf 1000ft

Rich Valley Utica Test Well23 Bcf 1000ft

EampP and Gathering

WDA Highlights

18

WDA Utica Appraisal Results and Initial Type Curve

Tested producing from 17 Utica wells in WDA-CRV Higher pressure significantly enhances well

productivity (Utica ~5000rsquo deeper than Marcellus) Drawdown management is critical restricted

drawdown appears to improve well EURs Early production declines much shallower vs

Marcellus

WDA Utica Appraisal Update

WDA Economics

(1) Internal Rate of Return (IRR) is pre-tax and includes estimated well costs under current cost structure LOEand anticipated gathering tariffs

(2) Initial WDA-CRV Utica type curve based on production results and reservoir expectations from the first 5appraisal wells in the WDA-CRV area

(3) WDA-CRV Utica Average includes all 17 producing wells including 2 wells (pad E09-S) for which drawdownmanagement was not used

EampP and Gathering

EURBcf1000rsquo

Well Cost$M1000rsquo

IRR $225

Break-even15 IRR(1)

Utica - CRV 17 $887 23 $197

Marcellus 10 ndash 11 $643 19 $206

(2)

0

1

2

3

4

5

6

7

8

9

0 12 24 36 48 60 72 84 96 108 120

Cum

ulat

ive

Prod

uctio

n B

CF

Months On

WDA-CRV Utica Wells - Normalized to 9000rsquoUtica Type Curve CRV Utica AverageWDA Marcellus Type Curve Boone Mountain Appraisal WellWDA-CRV Utica Type Curve(2) WDA-CRV Utica Average(3)

0005101520253035

0 2 4 6 8 10 12

19

Transitioning to Utica Development in CRV

WDA-CRV Marcellus(Depth ~7000 feet)

WDA-CRV Utica(Depth ~12000 feet)

Avg CRV Marcellus Production 270 MMcfd

Rem Avg EUR 10-11 Bcf 1000 lat ft

Rem Avg Well Costs = $643lat ft

120+ locations on existing Marcellus pads

Est EURs 17 Bcf 1000 lat ft

Est Development Well Costs = $887lat ft

CRV Utica Transition Plan

1)Finish Marcellus Pads in Development

Drill 24 complete 24 Marcellus wells

2)Continue Optimizing Utica DampC design

Additional optimization wells focusing on

Completion design

Landing zone targets

3)Continue transition to Utica development

Future drilling on multi-well pads

Continue using optimization results to determine development well design

Tailor development plan to use existing pad water and gathering infrastructure

CRV Utica Development Utilizes Existing Pad Water and Gathering Infrastructure to Drive Economics

EampP and Gathering

Rich Valley Utica Test

Existing Line

Leased

Seneca Fee

Producing

FY19 Producer

Development

20

Leveraging Existing Gathering Water and Pad Infrastructure Enhances Returns

Limited New Infrastructure Needed to Support Production Growth

WDA Well Costs(1) WDA Consolidated Economics

Steady activity levels and coordination between upstream and midstream activities

enhance returns provide economies of scale and significant operational flexibility

(1) WDA Marcellus well costs reflect drilling completion amp gathering costs for 192 drilled and completed wells as of 93018 WDA Utica well costs reflect expected drilling completion amp gathering costs for the ~120 well locations in area of redevelopment (2) Internal Rate of Return for Seneca WDA includes estimated well costs under current cost structure and anticipated LOE and Gathering costs Internal Rate of Return for Seneca WDA and Gathering includes expected gathering capital expenditures

through FY 2022 well costs under current cost structure and non-gathering LOE

$685$887

$210

$0

$200

$400

$600

$800

$1000

Marcellus(Historic)

Utica - CRV(Current)

$ la

tera

l foo

t

Drilling amp Completion Gathering

$931$895

10 -11

17

00

03

06

09

12

15

18

Marcellus(Historic)

Utica - CRV(Current)

EUR

10

00 fe

et (B

cf)

60-70 EUR increase expected per well

Total cost per well expected to marginally increase

WDA EURs

At a $225 netback price consolidated Seneca WDA and Gathering IRR is

approximately 33 an uplift of ~12 over standalone Seneca WDA economics(2)

10+ IRR Uplift Expected

21

Integrated Development ndash WDA Gathering System

Current System In-Service

~78 miles of pipe 36220 HP of compression

Current Capacity 470 MMcf per day

Interconnects with TGP 300

Total Investment to Date $301 million

Future Build-Out

FY 2019 CapEx $10 - $15 million

Modest gathering pipeline and compression investment required to support Senecarsquos transition to Utica development

Opportunity for 300 miles of pipelines and five compressor stations (+60000 HP installed) as Senecarsquos drilling activity continues

Deliverability into TGP 300 and NFG Supply

Gathering System Build-Out Tailored to Accommodate Senecarsquos WDA Development

Clermont Gathering System Map

EampP and Gathering

22

WDA Firm Transportation and Sales Capacity

Will continue to layer-in firm sales deals of short and longer duration on TGP 300 to reduce spot exposure

WDA spot realizations track TGP Station 313 pricing typically 10cent - 30cent better than TGP Marcellus Zone 4

Leidy South will provide additional capacity to premium markets (Transco Zone 6)

WDA Exit Capacity Supports Long-term Production Growth and Enhances Consolidated Returns

WDA Contracted Firm Transport and Gross Sales Volumes (MDthd)

Seneca gross production trend

EampP and Gathering

0

100

200

300

400

500

600

700

Niagara Expansion Project (TGP and NFG)FT Capacity 158000 Dthd $067Dth

Firm Sales NYMEX amp DAWN

WDA - TGP 300Firm Sales

Leidy SouthTransco Zone 6

Markets330000 Dthd(1)

Will layer-in firm sales to minimize spot exposure

(1) Portion of Transco Project capacity will likely be utilized by EDA Lycoming County production

WDA Gas Marketing Strategy

23

Eastern Development Area

EDA Acreage ndash 70000 AcresEDA Highlights

1 DCNR Tract 007 (Tioga Co Pa)bull Utica development resumed in third quarter fiscal 2018

bull ~43 remaining Utica locations economic at ~$184 Mcf

bull Gathering Infrastructure NFG Midstream Wellsboro

bull Marcellus Shale expected to provide ~60 additional locations

EampP and Gathering

2

1

3

2 Covington amp DCNR Tract 595 (Tioga Co Pa)bull Marcellus locations fully developed (average daily gross production of ~93 MMcfd)

bull Gathering Infrastructure NFG Midstream Covington

bull Opportunity for future Utica appraisal

3 DCNR Tract 100 amp Gamble (Lycoming Co Pa)bull ~45 remaining Marcellus locations economic at ~$153 Mcfbull Firm Transportation Capacity Atlantic Sunrise (189 MDthd)

bull Gathering Infrastructure NFG Midstream Trout Run

bull Geneseo Shale expected to provide 100-120 additional locations

24

EDA Marcellus Lycoming County Development

Marcellus Development in Lycoming County has Resumed in Connection with Atlantic Sunrise

(1) Includes physical fixed price and NYMEX-based firm sales contracts that do not carry any additional transportation costs

EampP and Gathering

Prolific Marcellus acreage with peer leading well results

~45 remaining Marcellus locations economic at ~$153 Mcf

Near-term development focused on filling Atlantic Sunrise capacity

Existing Line

Leased

Seneca Fee

Producing

FY19 Producer

Development

0

50

100

150

200

250

Gro

ss F

irm V

olum

es (M

Dth

d)

EDA ndash Transco Firm Contracts

Atlantic Sunrise (Transco)FT Capacity 189405 Dthd

Cost $073DthFirm Sales NYMEX+

Transco Firm Sales(1)

25

EDA Utica Tioga County Development

Utica Development in Tioga County ndash Tract 007 Development Resumed in Q3 Fiscal 2018

In-Service November 2016

Lateral Length 4640 ft

30 Day IP 1000 ft 34 MMcfd

Est EUR 1000 ft 24 Bcf

Inventory ~43 locations economic at ~$184 Mcf

Targeting to grow production by 100 to 150 MDthd by fiscal 2020

Expected Development Costs $1045 per lateral ft

Gathering Infrastructure NFG Midstream Wellsboro

Modest build-out required to connect to TGP 300

SalesTakeaway Strategy Layer-in firm sales with shippers holding capacity on TGP 300

(1) Includes physical fixed price and NYMEX-based firm sales contracts that do not carry any additional transportation costs

Tract 007 Utica Appraisal Well Results vs Industry

EampP and Gathering

0

100000

200000

300000

400000

500000

600000

700000

800000

0 100 200 300

Nor

mal

ized

Cum

ulat

ive

(Mcf

10

00rsquo)

Days On ProductionIndustry PotterTioga Wells Seneca DCNR 007 73H

0

25

50

75

100

125

150

Gro

ss F

irm V

olum

es (M

Dth

d)

EDA ndash TGP 300 Firm Contracts

Northeast Supply Diversification ProjectFT Capacity 50000 Dthd $050Dth

Firm Sales NYMEX and DAWN

EDA - TGP 300Firm Sales(1)

26

Integrated Development ndash EDA Gathering Systems

Total Investment (to date) ~$46 million FY 2019 Estimated Capital Expenditures $1 MM - $2 MM Capacity 220000 Dth per day (Interconnect w TGP 300) Production Source Seneca Resources ndash Tioga Co (Covington and DCNR Tract 595)

Total Investment (to date) ~$208 million FY 2019 Estimated Capital Expenditures $25 MM - $35 MM Capacity 466000 to 585000 Dth per day (Interconnect w Transco) Production Source Seneca Resources ndash Lycoming Co (DCNR Tract 100 and Gamble) Future third-party volume opportunities

Covington Gathering System

Trout Run Gathering System

Gathering Segment Supporting Senecarsquos EDA Production amp Future Development

Wellsboro Gathering System Total Investment (to date) ~$14 million FY 2019 Estimated Capital Expenditures $8 MM - $15 MM Capacity up to 200000 Dth per day (Interconnect w TGP 300) Production Source Seneca Resources ndash Tioga Co (DCNR Tract 007)

EampP and Gathering

2

1

3

27

Long-term Contracts Supporting Appalachian Growth

(1) Represents base firm sales contracts not tied to firm transportation capacity Base firm sales are either fixed priced or priced at an index (eg NYMEX ) +- a fixed basis and do not carry any transportation costs

Seneca continues to layer-in firm sales contracts with attractive realizations to lock-in drilling economics and minimize spot exposure ahead of firm transportation in-service dates

EampP and Gathering

-

100

200

300

400

500

600

700

800

900

1000

1100

1200

FY 2019 FY 2020 FY 2021 FY 2022Northeast Supply Diversification 50000 Dthd

Niagara Expansion (TGP amp NFG)Delivery Markets Canada-Dawn amp TETCO

158000 Dthd

Atlantic Sunrise (Transco)Delivery Markets Mid-Atlantic amp Southeast US

189405 Dthd

In-BasinFirm Sales

Contracts(1)

Leidy South (Transco amp NFG)

Transco Zone 6 Markets330000 Dthd

Seneca Appalachia Natural Gas MarketingGross Firm Contract Volumes (Mdthday)

28

297000 ($061)

305200 ($061)

305600 ($063)

337000 ($057)

370800 ($024)

369600 ($060)

367900 ($067)

33400 ($070)74500 ($077) 74900 ($077)

81100 ($078)

85900 ($078)

92000 ($073)

91300 ($073)

178800 $255

196000 $234

195500 $234

149900 $232

129500 $230

105400 $222

104500 $222

~517800 509200 575700 576000 568000 586200 567000 563700

Q1 FY19 Q2 FY19 Q3 FY19 Q4 FY19 Q1 FY20 Q2 FY20 Q3 FY20 Q4 FY20

Fixed Price Dawn NYMEX

Near-term Firm Sales Provide Market amp Price Certainty

Net Contracted Firm Sales Volumes (Dth per day)Contracted Index Price Differentials ($ per Dth)(1)

(1) Values shown represent the weighted average fixed price or contracted fixed differential relative to NYMEX (netback price) less any associated transportation costs

Actual Daily Net

Production

641200 716500 708700 693500 708400 674400 667000Gross Firm Sales Volumes (Dthd)

EampP and Gathering

29

California Oil

Stable Oil Production | Minimal Capital Investment | Steady Free Cash Flow

1

2

3

4

5

Location Formation Production Method

FY18 Daily Production(net Boed)

1 East Coalinga Other Temblor Primary 512

2 North Lost Hills

Tulare amp Etchegoin

PrimarySteam flood 892

3 South Lost Hills

Monterey Shale Primary 1359

4 North Midway Sunset

Tulare amp Potter Steam flood 2786

5 South Midway Sunset Antelope Steam flood 2048

TOTAL WEST DIVISION NET PRODUCTION(1) 7597 Boed

EampP and Gathering

(1) West division net production for FY 2018 excludes production from Sespe field which was divested on May 1 2018

30

California Capital Expenditures vs Production

9341 8863

8033 ~7300

2016 2017 2018 2019

Fiscal Year

West Division Average Net Daily Production (Boe)West Division Annual Capital Expenditures ($ MM)(1)

$38 $38

$26 ~$25

2016 2017 2018 2019

Fiscal YearGuidance Guidance

(1) Seneca West Division capital expenditures includes Seneca corporate and eliminations

EampP and Gathering

Sepse Sale Closed on 5118(reduced production by ~900 boed)

31

Pioneer

South MWSS

Acreage

North MWSS

AcreageSec 17N

4149 51

NMWSS amp 17N SMWSS amp Pioneer East Coalinga

California Development Activities

Modest near-term capital program focused on locations that earn attractive returns in current oil price environment

AampD will focus on low cost bolt-on opportunities

Sec 17 Pioneer and East Coalinga development to provide future growth

North

Project IRRs at $55Bbl(1)

(1) Reflects pre-tax IRRs at a $55Bbl WTI

EampP and Gathering

Seneca West Economics

South

East Coalinga

North

South

32

Fiscal 2019 Production and Price Certainty

~49 Bcfe

210 ndash 230 Bcfe

~114 Bcf

~29 Bcf (2)

16+- Bcf~12 Bcfe

0

40

80

120

160

200

240

YTD FY19Actuals

Fixed Price + FirmSales w Hedge

Firm Sales(Unhedged)

Spot Sales California TotalSeneca

Prod

uctio

n (B

cfe)

(1) Average realized price reflects uplift from financial hedges less fixed differentials under firm sales contracts and any firm transportation costs(2) Indicates firm sales contracts with fixed index differentials but not backed by a matching financial hedge

114 Bcf locked-in realizing net ~$241Mcf (1)

29 Bcf of additional basis protection

Spot production assumed to be sold

at ~$275Mmbtu(winter) and ~$225

(summer)

143 Bcf of Appalachian Production Protected by Firm Sales for Remainder of Year

79 of oil production hedged at $5757 Bbl

EampP and Gathering

33

Strong Hedge Book

Natural Gas Swap amp Fixed Physical Sales Contracts (Millions MMBtu)

(1) Fixed price physical sales exclude joint development partnerrsquos share of fixed price contract WDA volumes as specified under the joint development agreement(2) Reflects percentage of projected production for FY19 hedged at the midpoint of the production guidance range(3) Senecarsquos remainder FY19 Production reflects the total FY19 production guidance of 210-230 Bcfe or 220 Bcfe at the midpoint less Q1 actual production

Crude Oil Swap Contracts (Thousands Bbls)

13591188

732

456

0

500

1000

1500

2000

2500

FY 2019 FY 2020 FY 2021 FY 2022

NYMEX (WTI)

Brent

FY 19 Crude Oil79 Hedged (2)

FY 2019 Remaining Production (3)

EampP and Gathering

1174

709

469 406

0

50

100

150

200

250

FY 2019 FY 2020 FY 2021 FY 2022

NYMEX Swaps

Dawn Swaps

Fixed Price Physical Sales

(1)

FY 2019 Remaining Production (3)

FY 19 Nat Gas71 Hedged (2)

34

$065 $070$070 -$075

FY 2017 FY 2018 FY 2019E

$060 $060 $060

$011 $009 $007$071 $069 ~$067

FY 2017 FY 2018 FY 2019E Gathering amp Transport LOE (non-Gathering) GampA Taxes amp Other

Seneca Operating Costs

Competitive low cost structure in Appalachia and California supports strong cash margins

Gathering fee generates significant revenue stream for affiliated gathering company

Seneca DDampARate

$Mcfe

$054 $054 $056

$042 $038 $031

$034 $034 $030

$017 $014 $015

$147 $140 ~$132

FY 2017 FY 2018 FY 2019E

(1)

$1791$1746~$2050

FY 2017 FY 2018 FY 2019E

Appalachia LOE amp Gathering $Mcfe

California LOE$Boe

Total Seneca Cash OpEx$Mcfe

(1)

(2)

(2)

(1) GampA estimate represents the midpoint of the GampA guidance range of $025 to $035 for fiscal 2019(2) The total of the two LOE components represents the midpoint of the LOE guidance range of $085 to $090 for fiscal 2019

EampP and Gathering

35

Senecarsquos Continuing Commitment to the Environment

Produced Water Recycled in Appalachia

100 70Recycled Water

Used in New Shale Well

Completions

Water and Fluids Management Air Quality and Emissions

Seneca Resources Water OperationsFiscal 2018

Seneca Resources Remains Focused on Minimizing GHG Emissions

The Environmental Partnership

EPA Natural Gas Star Program

Green Completions (all fiscal 2018 wells)

Ultrasonic Leak Detection Technology

Emissions Controls

Rig and Vehicle Fuel Conversion

Integrating Renewable Energy into Operations

EampP and Gathering

36

Pipeline and Storage OverviewNational Fuel Gas Supply Corporation ~ Empire Pipeline Inc

37

Pipeline amp Storage Segment Overview

(1) As of September 30 2018 as disclosed in the Companyrsquos fiscal 2018 form 10-K(2) As of December 31 2017 calculated from National Fuel Gas Supply Corporationrsquos and Empire Pipeline Incrsquos 2017 FERC Form-2 reports respectively

Empire Pipeline Inc

National Fuel Gas Supply Corporation

Empire Pipeline

Supply Corp

Contracted Capacity(1) Firm Transportation 3187 MDth per day Firm Storage 71938 Mdth (fully subscribed)

Rate Base(2) ~$820 million FERC Rate Proceeding Status

Rate case settlement extension approved Nov lsquo15 Rate case filing expected by 73119

Contracted Capacity(1) Firm Transportation 978 MDth per day Firm Storage 3753 Mdth (fully subscribed)

Rate Base(2) ~$249 million FERC Rate Proceeding Status

Rate case settlement in principle reached on 122118 FERC approval pending

New transportation rates went into on 1119

Pipeline amp Storage

38

All Seneca volumes will flow through wholly-owned NFG gathering facilities

FM100 Project - Consolidated Benefit for NFG

330000 Dthd of new transportation capacity from WDA and EDA acreage positions to premium markets

New Transco capacity (Leidy South) 330000 Dthday

Rate(1) competitive with other expansion project rates in Senecarsquos current transportation portfolio

Delivery Point(s) Transco Zone 6 interconnections

Seneca

Lease to Transco of new capacity 330000 Dthday

Estimated annual lease revenues ~$35 million

Target In-Service late calendar year 2021

Supply Corp

Project expected to provide long-term earnings uplift to Seneca Supply Corp and Gathering

Pipeline amp Storage

Gathering

(1) Includes lease of new capacity from Supply Corp to Transco

39

FM100 Project ndash Significant Investment by Supply Corp

Pipeline amp Storage

Estimated Capital Cost $280 million(1)

Facilities (all in Pennsylvania) include Approximately 30 miles of new pipeline 2 new compressor stations (totaling

approximately 37000 HP) New interconnection station and modification

of existing interconnection station Abandonment of approximately 45 miles of

existing pipeline and compressor station Regulatory Process

Pre-filing application submitted to FERC in 2017 for original modernization project

FERC 7(b) 7(c) filing expected summer 2019

(1) Includes expansion and modernization portions of the project

40

Empire North Project

Target In-Service second half of fiscal 2020

Est Capital Cost $145 million

Est Annual Revenues ~$25 million

Receipt Point Jackson (Tioga Co Pa production)

Design Capacity and Delivery Points 175000 Dthd to Chippawa (TCPL interconnect)

30000 Dthd to Hopewell (TGP 200 interconnect)

Customers Fully subscribed (205000 Dthday)

Major Facilities 2 new compressor stations in NY (1) amp Pa (1)

No new pipeline construction

Regulatory Process FERC 7(c) application filed on 21618

FERC Environmental Assessment issued 103018

Pipeline amp Storage

Fully Subscribed Project will Provide 205000 Dthday of Incremental Firm Transportation

41

National Fuel Remains Committed to Northern Access Project

Target In-Service as early as fiscal 2022

Total Cost ~$500MM (~$76MM spent to date)

Estimated Annual Revenues ~$84 million

Delivery Points

350000 Dthd to Chippawa (TCPL interconnect)

140000 Dthd to Hopewell (TGP 200 line)

Regulatory Status

February 3 2017 ndash FERC 7(c) certificate issued

August 6 2018 ndash FERC issued Order finding that NY DEC waived water quality certification

Supply and Empire currently working to finalize remaining federal authorizations

Pipeline amp Storage

To Dawn

42

Continued Expansion of the NFG Supply System

Line N Expansion Opportunities

Line N to Monaca Project Project Firm transportation service to a new ethane

cracker facility being built by Shell Chemical Appalachia LLC

Target In-Service July 2019

Estimated Capital Cost $23 million

Contracted Capacity 133000 Dthday

Additional Line N Expansion Opportunity (Supply OS 221) Project New firm transportation service for on-system

demand

Open Season Capacity Awarded 165000 to foundation shipper Precedent agreement in negotiations

Pipeline amp Storage

43

Pipeline amp Storage Customer Mix

Producer33

LDC42

Marketer10

Outside Pipeline

9

End User6

42 MMDthd

(1) Contracted as of 10312018

Customer Transportation by Shipper Type(1) Affiliated Customer Mix (Contracted Capacity)

66

521

41

34

9579

59

LDCs Producers Marketers FirmStorage

Affiliated Non-Affiliated

Firm Transport

Pipeline amp Storage

44

Utility OverviewNational Fuel Gas Distribution Corporation

45

New York amp Pennsylvania Service Territories

New York

Total Customers(1) 535800ROE 87 (NY PSC Rate Case Order April 2017)Rate Mechanismso Revenue Decouplingo Weather Normalizationo Low Income Rateso Merchant Function Charge (Uncollectibles Adj)o 9010 Sharing (Large Customers)o System Modernization Tracker

Pennsylvania

Total Customers(1) 214400ROE Black Box Settlement (2007)Rate Mechanismso Low Income Rateso Merchant Function Charge

(1) As of September 30 2018

Utility

46

New York Rate Case Outcome

Rate Order Summary

Revenue Requirement $59 million

Rate Base $704 million

Allowed Return on Equity (ROE) 87

Capital Structure 429 equity

Other notable items

New rates became effective 5117

Retains rate mechanisms in place under prior order (revenue decoupling weather normalization merchant function charge 9010 large customer sharing)

No stay-out clause

System modernization tracker for Leak Prone Pipe (LPP)

Earnings sharing started 4118 (5050 sharing starts at earnings in excess of 92)

Article 78 appeal filed on 72817 with oral argument completed in January 2019

On April 20 2017 the New York Public Service Commission issued a Rate Order relating to NFG Distributionrsquos rate case (No 16-G-0257) filed in April 2016

Utility

47

Utility Continues its Significant Investments in Safety

$544$618 $636

$699

$944$980

$809$856

$90-100

$00

$250

$500

$750

$1000

$1250

2015 2016 2017 2018 2019E

Cap

ital E

xpen

ditu

res

($ m

illio

ns)

Fiscal Year

Capital Expenditures for Safety Total Capital Expenditures

Modernization Spending in NY Expected to Grow Gross Margin By $2 MM - $5 MM in FY 2019

(1)

(1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation

Utility

System modernization tracker in NY allows recovery of pipeline replacementcosts which is expected to drive modest gross margin and rate base growth

48

Accelerating Pipeline Replacement amp Modernization

Wrought Iron

Plastic

CoatedBare

120130

146 144159

2014 2015 2016 2017 2018Calendar Year

NY9726 miles

PA4830 miles

No Cast Iron Mains in Pa

Miles of Utility Main Pipeline ReplacedUtility Mains by Material(1)

Wrought Iron

Cast Iron

Plastic

Coated Bare

Utility

(1) All values are reported on a calendar year basis as of December 31 2018

49

A Proven History of Controlling Costs

$200 $189 $195

$166 $166

$31 $31

$197 $197

$0

$50

$100

$150

$200

$250

2015 2016 2017 2018 TTM 123118

Fiscal Year

OampM Expense Non-Service Pension Costs

OampM Expense ($ millions)

Utility

(1)

(1) For purposes of comparability to FY 2015 2016 and 2017 Utility Operation and Maintenance Expense for FY 2018 and the twelve months ended December 31 2018 was adjusted by approximately $314 million and $312 million respectively to include non-service pension costs which were re-classified as Other Income (Deductions) as of October 1 2018 on the Companyrsquos Income Statement See Slide 64 for non-GAAP reconciliation of Adjusted Operation and Maintenance Expense to Operation and Maintenance Expense by segment

50

Consolidated Financial OverviewUpstream I Midstream I Downstream

51

Adjusted Operating Results ($ per share)(1)

Diversified Balanced Earnings and Cash Flows

(1) A reconciliation of Adjusted Operating Results to Earnings per Share by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation(2) Consolidated Adjusted EBITDA includes Energy Marketing and Corporate amp All Other Segments A reconciliation of Adjusted EBITDA to Net Income by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in

the Business is included at the end of this presentation

Adjusted EBITDA ($ millions)(2)

$176 $179

$184 $181

$92 $97

$318 $327

$761 $775

$-

$200

$400

$600

$800

FY 2018 TTM 123118

$059 Utility

$097 Pipeline amp Storage

$057 Gathering

$125 Exploration

amp Production

$334 $345 to $365

$-

$100

$200

$300

$400

FY 2018 FY 2019 Guidance

Rate Regulated

40-45

$728

Rate Regulated

~46

52

$89 $94 $98 $81 $86 $90-$100

$140$230

$114 $95 $93 $120-$150

$138$118

$54$33 $48

$55-$65

$603$557

$99 $246$356

$460-$495

$970 $1001

$366$455

$583

$725-$810

$0

$250

$500

$750

$1000

$1250

2014 2015 2016 2017 2018 2019GuidanceFiscal Year

Exploration amp Production

Gathering

Pipeline amp Storage

Utility

Disciplined Flexible Capital Allocation

(2)

(1) Total Capital Expenditures include Energy Marketing Corporate and All Other A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation (2) FY16 FY17 and FY18 reflects the netting of $157 million $7 million and $17 million respectively of up-front proceeds received from joint development partner for working interest in joint development wells and $21M in intercompany asset transfers in FY18

Capital Expenditures by Segment ($ millions)(1)

53

Maintaining Strong Balance Sheet amp Liquidity

Total Equity49

Total Debt51

$42 Billion Total Capitalizationas of December 31 2018

218 x251 x 245 x 247 x 256 x

2015 2016 2017 2018 TTM 123118Fiscal Year End

Net Debt Adjusted EBITDA(1) Capitalization

Debt Maturity Profile ($MM) Liquidity

Committed Credit FacilitiesShort-term Debt OutstandingAvailable Short-term Credit FacilitiesCash Balance at 123118 Total Liquidity at 123118

$ 750 MM0 MM

750 MM110 MM

$ 860 MM

$500 $549 $500

$300 $300

$0

$200

$400

$600

(1) Net Debt is net of cash and temporary cash investments Reconciliations of Net Debt and Adjusted EBITDA to Net Income are included at the end of this presentation

54

Appendix

55

Safe Harbor For Forward Looking StatementsThis presentation may contain ldquoforward-looking statementsrdquo as defined by the Private Securities Litigation Reform Act of 1995 including statements regarding future prospectsplans objectives goals projections estimates of oil and gas quantities strategies future events or performance and underlying assumptions capital structure anticipatedcapital expenditures completion of construction projects projections for pension and other post-retirement benefit obligations impacts of the adoption of new accounting rulesand possible outcomes of litigation or regulatory proceedings as well as statements that are identified by the use of the words ldquoanticipatesrdquo ldquoestimatesrdquo ldquoexpectsrdquo ldquoforecastsrdquoldquointendsrdquo ldquoplansrdquo ldquopredictsrdquo ldquoprojectsrdquo ldquobelievesrdquo ldquoseeksrdquo ldquowillrdquo ldquomayrdquo and similar expressions Forward-looking statements involve risks and uncertainties which couldcause actual results or outcomes to differ materially from those expressed in the forward-looking statements The Companyrsquos expectations beliefs and projections are expressedin good faith and are believed by the Company to have a reasonable basis but there can be no assurance that managementrsquos expectations beliefs or projections will result or beachieved or accomplished

In addition to other factors the following are important factors that could cause actual results to differ materially from those discussed in the forward-looking statements delaysor changes in costs or plans with respect to Company projects or related projects of other companies including difficulties or delays in obtaining necessary governmentalapprovals permits or orders or in obtaining the cooperation of interconnecting facility operators governmentalregulatory actions initiatives and proceedings including thoseinvolving rate cases (which address among other things target rates of return rate design and retained natural gas) environmentalsafety requirements affiliate relationshipsindustry structure and franchise renewal changes in laws regulations or judicial interpretations to which the Company is subject including those involving derivatives taxessafety employment climate change other environmental matters real property and exploration and production activities such as hydraulic fracturing financial and economicconditions including the availability of credit and occurrences affecting the Companyrsquos ability to obtain financing on acceptable terms for working capital capital expendituresand other investments including any downgrades in the Companyrsquos credit ratings and changes in interest rates and other capital market conditions changes in the price ofnatural gas or oil impairments under the SECrsquos full cost ceiling test for natural gas and oil reserves factors affecting the Companyrsquos ability to successfully identify drill for andproduce economically viable natural gas and oil reserves including among others geology lease availability title disputes weather conditions shortages delays orunavailability of equipment and services required in drilling operations insufficient gathering processing and transportation capacity the need to obtain governmentalapprovals and permits and compliance with environmental laws and regulations increasing health care costs and the resulting effect on health insurance premiums and on theobligation to provide other post-retirement benefits changes in price differentials between similar quantities of natural gas or oil sold at different geographic locations and theeffect of such changes on commodity production revenues and demand for pipeline transportation capacity to or from such locations other changes in price differentialsbetween similar quantities of natural gas or oil having different quality heating value hydrocarbon mix or delivery date the cost and effects of legal and administrative claimsagainst the Company or activist shareholder campaigns to effect changes at the Company uncertainty of oil and gas reserve estimates significant differences between theCompanyrsquos projected and actual production levels for natural gas or oil changes in demographic patterns and weather conditions changes in the availability price oraccounting treatment of derivative financial instruments changes in laws actuarial assumptions the interest rate environment and the return on plantrust assets related to theCompanyrsquos pension and other post-retirement benefits which can affect future funding obligations and costs and plan liabilities changes in economic conditions includingglobal national or regional recessions and their effect on the demand for and customersrsquo ability to pay for the Companyrsquos products and services the creditworthiness orperformance of the Companyrsquos key suppliers customers and counterparties the impact of potential information technology cybersecurity or data security breaches economicdisruptions or uninsured losses resulting from major accidents fires severe weather natural disasters terrorist activities or acts of war significant differences between theCompanyrsquos projected and actual capital expenditures and operating expenses or increasing costs of insurance changes in coverage and the ability to obtain insurance

Forward-looking statements include estimates of oil and gas quantities Proved oil and gas reserves are those quantities of oil and gas which by analysis of geoscience andengineering data can be estimated with reasonable certainty to be economically producible under existing economic conditions operating methods and governmentregulations Other estimates of oil and gas quantities including estimates of probable reserves possible reserves and resource potential are by their nature more speculativethan estimates of proved reserves Accordingly estimates other than proved reserves are subject to substantially greater risk of being actually realized Investors are urged toconsider closely the disclosure in our Form 10-K available at wwwnationalfuelgascom You can also obtain this form on the SECrsquos website at wwwsecgov

For a discussion of the risks set forth above and other factors that could cause actual results to differ materially from results referred to in the forward-looking statements seeldquoRisk Factorsrdquo in the Companyrsquos Form 10-K for the fiscal year ended September 30 2018 and the Forms 10-Q for the quarter ended March 31 2018 June 30 2018 and December31 2018 The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date thereof or to reflect the occurrence ofunanticipated events

Appendix

12

Earnings Guidance

FY2018 Adjusted Operating Results

Non-regulated Businesses

Exploration amp ProductionGathering

$334 share(1) $345 to $365 shareFY2019 Earnings Guidance

Seneca Net Production 210 to 230 Bcfe Gathering Revenues $130-140 million

Natural Gas ~$245Mcf(2) (vs $252Mcf in FY 2018) Crude Oil ~$59Bbl(3) (vs $5866Bbl in FY 2018)

Key Guidance Drivers

(1) Excludes the $1035 million or $120 per share reduction in tax expense due to the remeasurement of deferred taxes resulting from the 2017 Tax Reform Act See non-GAAP disclosure on slide 61 of this presentation(2) Assumes NYMEX natural gas pricing of $325MMBtu (winter) and $275MMBtu (summer) and basin spot pricing of $275MMBtu (winter) and $225MMBtu (summer) for FY19 and reflects the impact of existing financial hedges firm sales

and firm transportation contracts(3) Assumes NYMEX (WTI) oil pricing of $5500Bbl and California-MWSS pricing differentials of 102 to WTI for FY19 and reflects impact of existing financial hedge contracts

Production amp Gathering Throughput

Realized natural gas prices (after-hedge)

Utility Operating Income

Regulated BusinessesPipeline amp StorageUtility

Guidance assumes normal weather modestly higher gross margin expected to be offset by cost inflation

~$285 million in revenues (expected decrease primarily due to expiration of contract on Empire system)

Pipeline amp Storage Revenues

Tax Reform

Realized oil prices (after-hedge)

Lower effective tax rate Effective tax rate ~24-25 (federal rate 21)

13

Exploration amp Production and Gathering OverviewSeneca Resources Company LLC ~ National Fuel Gas Midstream Company LLC

14

Proved Reserves

385 337 290 302 277

16832142

16751973

2357

1914

2344

1849

2154

2523

0

500

1000

1500

2000

2500

3000

2014 2015 2016 2017 2018At September 30

Natural Gas (Bcf)

Crude Oil (MMbbl)

361 Reserve Replacement Rate

Seneca Drill-bit FampD = $066Mcfe(1)

Appalachia Drill-bit FampD = $065Mcfe(1)

(1) Seneca ldquoDrill-bitrdquo finding and development (ldquoFampDrdquo) costs exclude the impact of reserve revisions

Total Proved Reserves (Bcfe)

Fiscal 2018 Proved Reserves Stats

$138

$112

$132

$098

$074

$050

$100

$150

2014 2015 2016 2017 2018

3-Year Average FampD Cost ($Mcfe)

70

30

PDPs PUDs

EampP and Gathering

15

3 rig development program with second rig in WDA focused on Utica

15-20 net production growth expected through fiscal 2022

New EDA Utica development with production expected in Q2 fiscal 2019

Utilize new Atlantic Sunrise firm transportation capacity

Layer-in firm sales to take advantage of attractive regional pricing

Gross production growth will benefit NFGrsquos Gathering segment

Minimal capital investment in California to generate significant cash flow

Growing Production within Disciplined Capital Program

205 194 176 ~16

1406 1541 1605194-214

1611 1735 1781210-230

0

50

100

150

200

250

2016 2017 2018 2019E

$38 $38 $26 ~$25$61

$208$330

$435-$470

$99

$246

$356

$460-$495

$0

$200

$400

$600

2016 2017 2018 2019E

Appalachia West Coast (California)

Near-Term Growth Strategy EampP Net Capital Expenditures ($ millions)(1)

EampP Net Production (Bcfe)

EampP and Gathering

(1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentationFY16 FY17 and FY18 guidance reflects the netting of $157 million $7 million and $17 million respectively of up-front proceeds received from joint development partner for working interest in joint development wells

16

Significant Appalachian Acreage Position

Average gross production ~311 MMcfd

Mostly leased (16-18 royalty) with no significant near-term lease expirations

~90 remaining Marcellus amp Utica locations economic at ~$184Mcf

Additional Marcellus (Tioga Co) amp Geneseo (Lycoming Co) potential

Eastern Development Area (EDA)

Western Development Area (WDA)

Average gross production(1) ~327 MMcfd Large inventory of Marcellus amp Utica

locations economic at ~$200Mcf Royalty free mineral ownership

enhances well economics Highly contiguous nature drives cost and

operational efficiencies

EampP and Gathering

EDA - 70000 AcresWDA - 715000 Acres

(1) Average EDA and WDA gross production as well as WDA-CRV Utica production (see slide 19) and CovingtonTract 595 Production (see slide 23) is for the quarter ended December 31 2018

17

Western Development AreaMarcellus Core Acreage

vs Utica Appraisal Trend(1)

(1) The Utica Shale lies approximately 5000 feet beneath Senecarsquos WDA Marcellus acreage (2) Appraisal program currently in progress Additional tests are planned Prior Marcellus delineation tests helped define the prospective limits of the Marcellus core acreage planned testing in the Utica expected to do the same

Area of Re-Development ~120 Utica locations on existing Marcellus pads

Key Utica testsPast Marcellus delineation testsUtica Trend (currently evaluating)Marcellus Core Acreage

Large well inventory economic at ~$200 Mcf

Marcellus Shale 600+ well locations remaining 200000 acres

Utica Shale 500+ potential locations across Utica trend evaluating extent of prospective acreage(2)

Fee acreage (no royalty) enhances economics and provides development flexibility

Addition of 2nd WDA drilling rig in Q3 FY18 focused on redevelopment of Clermont-Rich Valley acreage for Utica

Use of existing gathering pad and water infrastructure for Utica drives increased Appalachian program returns

Highly contiguous position drives best in class well costs

Utica test results on trend with other Utica wells in NE Pa

Long-term firm contracts support growth

Boone Mountain Utica Test Well23 Bcf 1000ft

Rich Valley Utica Test Well23 Bcf 1000ft

EampP and Gathering

WDA Highlights

18

WDA Utica Appraisal Results and Initial Type Curve

Tested producing from 17 Utica wells in WDA-CRV Higher pressure significantly enhances well

productivity (Utica ~5000rsquo deeper than Marcellus) Drawdown management is critical restricted

drawdown appears to improve well EURs Early production declines much shallower vs

Marcellus

WDA Utica Appraisal Update

WDA Economics

(1) Internal Rate of Return (IRR) is pre-tax and includes estimated well costs under current cost structure LOEand anticipated gathering tariffs

(2) Initial WDA-CRV Utica type curve based on production results and reservoir expectations from the first 5appraisal wells in the WDA-CRV area

(3) WDA-CRV Utica Average includes all 17 producing wells including 2 wells (pad E09-S) for which drawdownmanagement was not used

EampP and Gathering

EURBcf1000rsquo

Well Cost$M1000rsquo

IRR $225

Break-even15 IRR(1)

Utica - CRV 17 $887 23 $197

Marcellus 10 ndash 11 $643 19 $206

(2)

0

1

2

3

4

5

6

7

8

9

0 12 24 36 48 60 72 84 96 108 120

Cum

ulat

ive

Prod

uctio

n B

CF

Months On

WDA-CRV Utica Wells - Normalized to 9000rsquoUtica Type Curve CRV Utica AverageWDA Marcellus Type Curve Boone Mountain Appraisal WellWDA-CRV Utica Type Curve(2) WDA-CRV Utica Average(3)

0005101520253035

0 2 4 6 8 10 12

19

Transitioning to Utica Development in CRV

WDA-CRV Marcellus(Depth ~7000 feet)

WDA-CRV Utica(Depth ~12000 feet)

Avg CRV Marcellus Production 270 MMcfd

Rem Avg EUR 10-11 Bcf 1000 lat ft

Rem Avg Well Costs = $643lat ft

120+ locations on existing Marcellus pads

Est EURs 17 Bcf 1000 lat ft

Est Development Well Costs = $887lat ft

CRV Utica Transition Plan

1)Finish Marcellus Pads in Development

Drill 24 complete 24 Marcellus wells

2)Continue Optimizing Utica DampC design

Additional optimization wells focusing on

Completion design

Landing zone targets

3)Continue transition to Utica development

Future drilling on multi-well pads

Continue using optimization results to determine development well design

Tailor development plan to use existing pad water and gathering infrastructure

CRV Utica Development Utilizes Existing Pad Water and Gathering Infrastructure to Drive Economics

EampP and Gathering

Rich Valley Utica Test

Existing Line

Leased

Seneca Fee

Producing

FY19 Producer

Development

20

Leveraging Existing Gathering Water and Pad Infrastructure Enhances Returns

Limited New Infrastructure Needed to Support Production Growth

WDA Well Costs(1) WDA Consolidated Economics

Steady activity levels and coordination between upstream and midstream activities

enhance returns provide economies of scale and significant operational flexibility

(1) WDA Marcellus well costs reflect drilling completion amp gathering costs for 192 drilled and completed wells as of 93018 WDA Utica well costs reflect expected drilling completion amp gathering costs for the ~120 well locations in area of redevelopment (2) Internal Rate of Return for Seneca WDA includes estimated well costs under current cost structure and anticipated LOE and Gathering costs Internal Rate of Return for Seneca WDA and Gathering includes expected gathering capital expenditures

through FY 2022 well costs under current cost structure and non-gathering LOE

$685$887

$210

$0

$200

$400

$600

$800

$1000

Marcellus(Historic)

Utica - CRV(Current)

$ la

tera

l foo

t

Drilling amp Completion Gathering

$931$895

10 -11

17

00

03

06

09

12

15

18

Marcellus(Historic)

Utica - CRV(Current)

EUR

10

00 fe

et (B

cf)

60-70 EUR increase expected per well

Total cost per well expected to marginally increase

WDA EURs

At a $225 netback price consolidated Seneca WDA and Gathering IRR is

approximately 33 an uplift of ~12 over standalone Seneca WDA economics(2)

10+ IRR Uplift Expected

21

Integrated Development ndash WDA Gathering System

Current System In-Service

~78 miles of pipe 36220 HP of compression

Current Capacity 470 MMcf per day

Interconnects with TGP 300

Total Investment to Date $301 million

Future Build-Out

FY 2019 CapEx $10 - $15 million

Modest gathering pipeline and compression investment required to support Senecarsquos transition to Utica development

Opportunity for 300 miles of pipelines and five compressor stations (+60000 HP installed) as Senecarsquos drilling activity continues

Deliverability into TGP 300 and NFG Supply

Gathering System Build-Out Tailored to Accommodate Senecarsquos WDA Development

Clermont Gathering System Map

EampP and Gathering

22

WDA Firm Transportation and Sales Capacity

Will continue to layer-in firm sales deals of short and longer duration on TGP 300 to reduce spot exposure

WDA spot realizations track TGP Station 313 pricing typically 10cent - 30cent better than TGP Marcellus Zone 4

Leidy South will provide additional capacity to premium markets (Transco Zone 6)

WDA Exit Capacity Supports Long-term Production Growth and Enhances Consolidated Returns

WDA Contracted Firm Transport and Gross Sales Volumes (MDthd)

Seneca gross production trend

EampP and Gathering

0

100

200

300

400

500

600

700

Niagara Expansion Project (TGP and NFG)FT Capacity 158000 Dthd $067Dth

Firm Sales NYMEX amp DAWN

WDA - TGP 300Firm Sales

Leidy SouthTransco Zone 6

Markets330000 Dthd(1)

Will layer-in firm sales to minimize spot exposure

(1) Portion of Transco Project capacity will likely be utilized by EDA Lycoming County production

WDA Gas Marketing Strategy

23

Eastern Development Area

EDA Acreage ndash 70000 AcresEDA Highlights

1 DCNR Tract 007 (Tioga Co Pa)bull Utica development resumed in third quarter fiscal 2018

bull ~43 remaining Utica locations economic at ~$184 Mcf

bull Gathering Infrastructure NFG Midstream Wellsboro

bull Marcellus Shale expected to provide ~60 additional locations

EampP and Gathering

2

1

3

2 Covington amp DCNR Tract 595 (Tioga Co Pa)bull Marcellus locations fully developed (average daily gross production of ~93 MMcfd)

bull Gathering Infrastructure NFG Midstream Covington

bull Opportunity for future Utica appraisal

3 DCNR Tract 100 amp Gamble (Lycoming Co Pa)bull ~45 remaining Marcellus locations economic at ~$153 Mcfbull Firm Transportation Capacity Atlantic Sunrise (189 MDthd)

bull Gathering Infrastructure NFG Midstream Trout Run

bull Geneseo Shale expected to provide 100-120 additional locations

24

EDA Marcellus Lycoming County Development

Marcellus Development in Lycoming County has Resumed in Connection with Atlantic Sunrise

(1) Includes physical fixed price and NYMEX-based firm sales contracts that do not carry any additional transportation costs

EampP and Gathering

Prolific Marcellus acreage with peer leading well results

~45 remaining Marcellus locations economic at ~$153 Mcf

Near-term development focused on filling Atlantic Sunrise capacity

Existing Line

Leased

Seneca Fee

Producing

FY19 Producer

Development

0

50

100

150

200

250

Gro

ss F

irm V

olum

es (M

Dth

d)

EDA ndash Transco Firm Contracts

Atlantic Sunrise (Transco)FT Capacity 189405 Dthd

Cost $073DthFirm Sales NYMEX+

Transco Firm Sales(1)

25

EDA Utica Tioga County Development

Utica Development in Tioga County ndash Tract 007 Development Resumed in Q3 Fiscal 2018

In-Service November 2016

Lateral Length 4640 ft

30 Day IP 1000 ft 34 MMcfd

Est EUR 1000 ft 24 Bcf

Inventory ~43 locations economic at ~$184 Mcf

Targeting to grow production by 100 to 150 MDthd by fiscal 2020

Expected Development Costs $1045 per lateral ft

Gathering Infrastructure NFG Midstream Wellsboro

Modest build-out required to connect to TGP 300

SalesTakeaway Strategy Layer-in firm sales with shippers holding capacity on TGP 300

(1) Includes physical fixed price and NYMEX-based firm sales contracts that do not carry any additional transportation costs

Tract 007 Utica Appraisal Well Results vs Industry

EampP and Gathering

0

100000

200000

300000

400000

500000

600000

700000

800000

0 100 200 300

Nor

mal

ized

Cum

ulat

ive

(Mcf

10

00rsquo)

Days On ProductionIndustry PotterTioga Wells Seneca DCNR 007 73H

0

25

50

75

100

125

150

Gro

ss F

irm V

olum

es (M

Dth

d)

EDA ndash TGP 300 Firm Contracts

Northeast Supply Diversification ProjectFT Capacity 50000 Dthd $050Dth

Firm Sales NYMEX and DAWN

EDA - TGP 300Firm Sales(1)

26

Integrated Development ndash EDA Gathering Systems

Total Investment (to date) ~$46 million FY 2019 Estimated Capital Expenditures $1 MM - $2 MM Capacity 220000 Dth per day (Interconnect w TGP 300) Production Source Seneca Resources ndash Tioga Co (Covington and DCNR Tract 595)

Total Investment (to date) ~$208 million FY 2019 Estimated Capital Expenditures $25 MM - $35 MM Capacity 466000 to 585000 Dth per day (Interconnect w Transco) Production Source Seneca Resources ndash Lycoming Co (DCNR Tract 100 and Gamble) Future third-party volume opportunities

Covington Gathering System

Trout Run Gathering System

Gathering Segment Supporting Senecarsquos EDA Production amp Future Development

Wellsboro Gathering System Total Investment (to date) ~$14 million FY 2019 Estimated Capital Expenditures $8 MM - $15 MM Capacity up to 200000 Dth per day (Interconnect w TGP 300) Production Source Seneca Resources ndash Tioga Co (DCNR Tract 007)

EampP and Gathering

2

1

3

27

Long-term Contracts Supporting Appalachian Growth

(1) Represents base firm sales contracts not tied to firm transportation capacity Base firm sales are either fixed priced or priced at an index (eg NYMEX ) +- a fixed basis and do not carry any transportation costs

Seneca continues to layer-in firm sales contracts with attractive realizations to lock-in drilling economics and minimize spot exposure ahead of firm transportation in-service dates

EampP and Gathering

-

100

200

300

400

500

600

700

800

900

1000

1100

1200

FY 2019 FY 2020 FY 2021 FY 2022Northeast Supply Diversification 50000 Dthd

Niagara Expansion (TGP amp NFG)Delivery Markets Canada-Dawn amp TETCO

158000 Dthd

Atlantic Sunrise (Transco)Delivery Markets Mid-Atlantic amp Southeast US

189405 Dthd

In-BasinFirm Sales

Contracts(1)

Leidy South (Transco amp NFG)

Transco Zone 6 Markets330000 Dthd

Seneca Appalachia Natural Gas MarketingGross Firm Contract Volumes (Mdthday)

28

297000 ($061)

305200 ($061)

305600 ($063)

337000 ($057)

370800 ($024)

369600 ($060)

367900 ($067)

33400 ($070)74500 ($077) 74900 ($077)

81100 ($078)

85900 ($078)

92000 ($073)

91300 ($073)

178800 $255

196000 $234

195500 $234

149900 $232

129500 $230

105400 $222

104500 $222

~517800 509200 575700 576000 568000 586200 567000 563700

Q1 FY19 Q2 FY19 Q3 FY19 Q4 FY19 Q1 FY20 Q2 FY20 Q3 FY20 Q4 FY20

Fixed Price Dawn NYMEX

Near-term Firm Sales Provide Market amp Price Certainty

Net Contracted Firm Sales Volumes (Dth per day)Contracted Index Price Differentials ($ per Dth)(1)

(1) Values shown represent the weighted average fixed price or contracted fixed differential relative to NYMEX (netback price) less any associated transportation costs

Actual Daily Net

Production

641200 716500 708700 693500 708400 674400 667000Gross Firm Sales Volumes (Dthd)

EampP and Gathering

29

California Oil

Stable Oil Production | Minimal Capital Investment | Steady Free Cash Flow

1

2

3

4

5

Location Formation Production Method

FY18 Daily Production(net Boed)

1 East Coalinga Other Temblor Primary 512

2 North Lost Hills

Tulare amp Etchegoin

PrimarySteam flood 892

3 South Lost Hills

Monterey Shale Primary 1359

4 North Midway Sunset

Tulare amp Potter Steam flood 2786

5 South Midway Sunset Antelope Steam flood 2048

TOTAL WEST DIVISION NET PRODUCTION(1) 7597 Boed

EampP and Gathering

(1) West division net production for FY 2018 excludes production from Sespe field which was divested on May 1 2018

30

California Capital Expenditures vs Production

9341 8863

8033 ~7300

2016 2017 2018 2019

Fiscal Year

West Division Average Net Daily Production (Boe)West Division Annual Capital Expenditures ($ MM)(1)

$38 $38

$26 ~$25

2016 2017 2018 2019

Fiscal YearGuidance Guidance

(1) Seneca West Division capital expenditures includes Seneca corporate and eliminations

EampP and Gathering

Sepse Sale Closed on 5118(reduced production by ~900 boed)

31

Pioneer

South MWSS

Acreage

North MWSS

AcreageSec 17N

4149 51

NMWSS amp 17N SMWSS amp Pioneer East Coalinga

California Development Activities

Modest near-term capital program focused on locations that earn attractive returns in current oil price environment

AampD will focus on low cost bolt-on opportunities

Sec 17 Pioneer and East Coalinga development to provide future growth

North

Project IRRs at $55Bbl(1)

(1) Reflects pre-tax IRRs at a $55Bbl WTI

EampP and Gathering

Seneca West Economics

South

East Coalinga

North

South

32

Fiscal 2019 Production and Price Certainty

~49 Bcfe

210 ndash 230 Bcfe

~114 Bcf

~29 Bcf (2)

16+- Bcf~12 Bcfe

0

40

80

120

160

200

240

YTD FY19Actuals

Fixed Price + FirmSales w Hedge

Firm Sales(Unhedged)

Spot Sales California TotalSeneca

Prod

uctio

n (B

cfe)

(1) Average realized price reflects uplift from financial hedges less fixed differentials under firm sales contracts and any firm transportation costs(2) Indicates firm sales contracts with fixed index differentials but not backed by a matching financial hedge

114 Bcf locked-in realizing net ~$241Mcf (1)

29 Bcf of additional basis protection

Spot production assumed to be sold

at ~$275Mmbtu(winter) and ~$225

(summer)

143 Bcf of Appalachian Production Protected by Firm Sales for Remainder of Year

79 of oil production hedged at $5757 Bbl

EampP and Gathering

33

Strong Hedge Book

Natural Gas Swap amp Fixed Physical Sales Contracts (Millions MMBtu)

(1) Fixed price physical sales exclude joint development partnerrsquos share of fixed price contract WDA volumes as specified under the joint development agreement(2) Reflects percentage of projected production for FY19 hedged at the midpoint of the production guidance range(3) Senecarsquos remainder FY19 Production reflects the total FY19 production guidance of 210-230 Bcfe or 220 Bcfe at the midpoint less Q1 actual production

Crude Oil Swap Contracts (Thousands Bbls)

13591188

732

456

0

500

1000

1500

2000

2500

FY 2019 FY 2020 FY 2021 FY 2022

NYMEX (WTI)

Brent

FY 19 Crude Oil79 Hedged (2)

FY 2019 Remaining Production (3)

EampP and Gathering

1174

709

469 406

0

50

100

150

200

250

FY 2019 FY 2020 FY 2021 FY 2022

NYMEX Swaps

Dawn Swaps

Fixed Price Physical Sales

(1)

FY 2019 Remaining Production (3)

FY 19 Nat Gas71 Hedged (2)

34

$065 $070$070 -$075

FY 2017 FY 2018 FY 2019E

$060 $060 $060

$011 $009 $007$071 $069 ~$067

FY 2017 FY 2018 FY 2019E Gathering amp Transport LOE (non-Gathering) GampA Taxes amp Other

Seneca Operating Costs

Competitive low cost structure in Appalachia and California supports strong cash margins

Gathering fee generates significant revenue stream for affiliated gathering company

Seneca DDampARate

$Mcfe

$054 $054 $056

$042 $038 $031

$034 $034 $030

$017 $014 $015

$147 $140 ~$132

FY 2017 FY 2018 FY 2019E

(1)

$1791$1746~$2050

FY 2017 FY 2018 FY 2019E

Appalachia LOE amp Gathering $Mcfe

California LOE$Boe

Total Seneca Cash OpEx$Mcfe

(1)

(2)

(2)

(1) GampA estimate represents the midpoint of the GampA guidance range of $025 to $035 for fiscal 2019(2) The total of the two LOE components represents the midpoint of the LOE guidance range of $085 to $090 for fiscal 2019

EampP and Gathering

35

Senecarsquos Continuing Commitment to the Environment

Produced Water Recycled in Appalachia

100 70Recycled Water

Used in New Shale Well

Completions

Water and Fluids Management Air Quality and Emissions

Seneca Resources Water OperationsFiscal 2018

Seneca Resources Remains Focused on Minimizing GHG Emissions

The Environmental Partnership

EPA Natural Gas Star Program

Green Completions (all fiscal 2018 wells)

Ultrasonic Leak Detection Technology

Emissions Controls

Rig and Vehicle Fuel Conversion

Integrating Renewable Energy into Operations

EampP and Gathering

36

Pipeline and Storage OverviewNational Fuel Gas Supply Corporation ~ Empire Pipeline Inc

37

Pipeline amp Storage Segment Overview

(1) As of September 30 2018 as disclosed in the Companyrsquos fiscal 2018 form 10-K(2) As of December 31 2017 calculated from National Fuel Gas Supply Corporationrsquos and Empire Pipeline Incrsquos 2017 FERC Form-2 reports respectively

Empire Pipeline Inc

National Fuel Gas Supply Corporation

Empire Pipeline

Supply Corp

Contracted Capacity(1) Firm Transportation 3187 MDth per day Firm Storage 71938 Mdth (fully subscribed)

Rate Base(2) ~$820 million FERC Rate Proceeding Status

Rate case settlement extension approved Nov lsquo15 Rate case filing expected by 73119

Contracted Capacity(1) Firm Transportation 978 MDth per day Firm Storage 3753 Mdth (fully subscribed)

Rate Base(2) ~$249 million FERC Rate Proceeding Status

Rate case settlement in principle reached on 122118 FERC approval pending

New transportation rates went into on 1119

Pipeline amp Storage

38

All Seneca volumes will flow through wholly-owned NFG gathering facilities

FM100 Project - Consolidated Benefit for NFG

330000 Dthd of new transportation capacity from WDA and EDA acreage positions to premium markets

New Transco capacity (Leidy South) 330000 Dthday

Rate(1) competitive with other expansion project rates in Senecarsquos current transportation portfolio

Delivery Point(s) Transco Zone 6 interconnections

Seneca

Lease to Transco of new capacity 330000 Dthday

Estimated annual lease revenues ~$35 million

Target In-Service late calendar year 2021

Supply Corp

Project expected to provide long-term earnings uplift to Seneca Supply Corp and Gathering

Pipeline amp Storage

Gathering

(1) Includes lease of new capacity from Supply Corp to Transco

39

FM100 Project ndash Significant Investment by Supply Corp

Pipeline amp Storage

Estimated Capital Cost $280 million(1)

Facilities (all in Pennsylvania) include Approximately 30 miles of new pipeline 2 new compressor stations (totaling

approximately 37000 HP) New interconnection station and modification

of existing interconnection station Abandonment of approximately 45 miles of

existing pipeline and compressor station Regulatory Process

Pre-filing application submitted to FERC in 2017 for original modernization project

FERC 7(b) 7(c) filing expected summer 2019

(1) Includes expansion and modernization portions of the project

40

Empire North Project

Target In-Service second half of fiscal 2020

Est Capital Cost $145 million

Est Annual Revenues ~$25 million

Receipt Point Jackson (Tioga Co Pa production)

Design Capacity and Delivery Points 175000 Dthd to Chippawa (TCPL interconnect)

30000 Dthd to Hopewell (TGP 200 interconnect)

Customers Fully subscribed (205000 Dthday)

Major Facilities 2 new compressor stations in NY (1) amp Pa (1)

No new pipeline construction

Regulatory Process FERC 7(c) application filed on 21618

FERC Environmental Assessment issued 103018

Pipeline amp Storage

Fully Subscribed Project will Provide 205000 Dthday of Incremental Firm Transportation

41

National Fuel Remains Committed to Northern Access Project

Target In-Service as early as fiscal 2022

Total Cost ~$500MM (~$76MM spent to date)

Estimated Annual Revenues ~$84 million

Delivery Points

350000 Dthd to Chippawa (TCPL interconnect)

140000 Dthd to Hopewell (TGP 200 line)

Regulatory Status

February 3 2017 ndash FERC 7(c) certificate issued

August 6 2018 ndash FERC issued Order finding that NY DEC waived water quality certification

Supply and Empire currently working to finalize remaining federal authorizations

Pipeline amp Storage

To Dawn

42

Continued Expansion of the NFG Supply System

Line N Expansion Opportunities

Line N to Monaca Project Project Firm transportation service to a new ethane

cracker facility being built by Shell Chemical Appalachia LLC

Target In-Service July 2019

Estimated Capital Cost $23 million

Contracted Capacity 133000 Dthday

Additional Line N Expansion Opportunity (Supply OS 221) Project New firm transportation service for on-system

demand

Open Season Capacity Awarded 165000 to foundation shipper Precedent agreement in negotiations

Pipeline amp Storage

43

Pipeline amp Storage Customer Mix

Producer33

LDC42

Marketer10

Outside Pipeline

9

End User6

42 MMDthd

(1) Contracted as of 10312018

Customer Transportation by Shipper Type(1) Affiliated Customer Mix (Contracted Capacity)

66

521

41

34

9579

59

LDCs Producers Marketers FirmStorage

Affiliated Non-Affiliated

Firm Transport

Pipeline amp Storage

44

Utility OverviewNational Fuel Gas Distribution Corporation

45

New York amp Pennsylvania Service Territories

New York

Total Customers(1) 535800ROE 87 (NY PSC Rate Case Order April 2017)Rate Mechanismso Revenue Decouplingo Weather Normalizationo Low Income Rateso Merchant Function Charge (Uncollectibles Adj)o 9010 Sharing (Large Customers)o System Modernization Tracker

Pennsylvania

Total Customers(1) 214400ROE Black Box Settlement (2007)Rate Mechanismso Low Income Rateso Merchant Function Charge

(1) As of September 30 2018

Utility

46

New York Rate Case Outcome

Rate Order Summary

Revenue Requirement $59 million

Rate Base $704 million

Allowed Return on Equity (ROE) 87

Capital Structure 429 equity

Other notable items

New rates became effective 5117

Retains rate mechanisms in place under prior order (revenue decoupling weather normalization merchant function charge 9010 large customer sharing)

No stay-out clause

System modernization tracker for Leak Prone Pipe (LPP)

Earnings sharing started 4118 (5050 sharing starts at earnings in excess of 92)

Article 78 appeal filed on 72817 with oral argument completed in January 2019

On April 20 2017 the New York Public Service Commission issued a Rate Order relating to NFG Distributionrsquos rate case (No 16-G-0257) filed in April 2016

Utility

47

Utility Continues its Significant Investments in Safety

$544$618 $636

$699

$944$980

$809$856

$90-100

$00

$250

$500

$750

$1000

$1250

2015 2016 2017 2018 2019E

Cap

ital E

xpen

ditu

res

($ m

illio

ns)

Fiscal Year

Capital Expenditures for Safety Total Capital Expenditures

Modernization Spending in NY Expected to Grow Gross Margin By $2 MM - $5 MM in FY 2019

(1)

(1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation

Utility

System modernization tracker in NY allows recovery of pipeline replacementcosts which is expected to drive modest gross margin and rate base growth

48

Accelerating Pipeline Replacement amp Modernization

Wrought Iron

Plastic

CoatedBare

120130

146 144159

2014 2015 2016 2017 2018Calendar Year

NY9726 miles

PA4830 miles

No Cast Iron Mains in Pa

Miles of Utility Main Pipeline ReplacedUtility Mains by Material(1)

Wrought Iron

Cast Iron

Plastic

Coated Bare

Utility

(1) All values are reported on a calendar year basis as of December 31 2018

49

A Proven History of Controlling Costs

$200 $189 $195

$166 $166

$31 $31

$197 $197

$0

$50

$100

$150

$200

$250

2015 2016 2017 2018 TTM 123118

Fiscal Year

OampM Expense Non-Service Pension Costs

OampM Expense ($ millions)

Utility

(1)

(1) For purposes of comparability to FY 2015 2016 and 2017 Utility Operation and Maintenance Expense for FY 2018 and the twelve months ended December 31 2018 was adjusted by approximately $314 million and $312 million respectively to include non-service pension costs which were re-classified as Other Income (Deductions) as of October 1 2018 on the Companyrsquos Income Statement See Slide 64 for non-GAAP reconciliation of Adjusted Operation and Maintenance Expense to Operation and Maintenance Expense by segment

50

Consolidated Financial OverviewUpstream I Midstream I Downstream

51

Adjusted Operating Results ($ per share)(1)

Diversified Balanced Earnings and Cash Flows

(1) A reconciliation of Adjusted Operating Results to Earnings per Share by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation(2) Consolidated Adjusted EBITDA includes Energy Marketing and Corporate amp All Other Segments A reconciliation of Adjusted EBITDA to Net Income by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in

the Business is included at the end of this presentation

Adjusted EBITDA ($ millions)(2)

$176 $179

$184 $181

$92 $97

$318 $327

$761 $775

$-

$200

$400

$600

$800

FY 2018 TTM 123118

$059 Utility

$097 Pipeline amp Storage

$057 Gathering

$125 Exploration

amp Production

$334 $345 to $365

$-

$100

$200

$300

$400

FY 2018 FY 2019 Guidance

Rate Regulated

40-45

$728

Rate Regulated

~46

52

$89 $94 $98 $81 $86 $90-$100

$140$230

$114 $95 $93 $120-$150

$138$118

$54$33 $48

$55-$65

$603$557

$99 $246$356

$460-$495

$970 $1001

$366$455

$583

$725-$810

$0

$250

$500

$750

$1000

$1250

2014 2015 2016 2017 2018 2019GuidanceFiscal Year

Exploration amp Production

Gathering

Pipeline amp Storage

Utility

Disciplined Flexible Capital Allocation

(2)

(1) Total Capital Expenditures include Energy Marketing Corporate and All Other A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation (2) FY16 FY17 and FY18 reflects the netting of $157 million $7 million and $17 million respectively of up-front proceeds received from joint development partner for working interest in joint development wells and $21M in intercompany asset transfers in FY18

Capital Expenditures by Segment ($ millions)(1)

53

Maintaining Strong Balance Sheet amp Liquidity

Total Equity49

Total Debt51

$42 Billion Total Capitalizationas of December 31 2018

218 x251 x 245 x 247 x 256 x

2015 2016 2017 2018 TTM 123118Fiscal Year End

Net Debt Adjusted EBITDA(1) Capitalization

Debt Maturity Profile ($MM) Liquidity

Committed Credit FacilitiesShort-term Debt OutstandingAvailable Short-term Credit FacilitiesCash Balance at 123118 Total Liquidity at 123118

$ 750 MM0 MM

750 MM110 MM

$ 860 MM

$500 $549 $500

$300 $300

$0

$200

$400

$600

(1) Net Debt is net of cash and temporary cash investments Reconciliations of Net Debt and Adjusted EBITDA to Net Income are included at the end of this presentation

54

Appendix

55

Safe Harbor For Forward Looking StatementsThis presentation may contain ldquoforward-looking statementsrdquo as defined by the Private Securities Litigation Reform Act of 1995 including statements regarding future prospectsplans objectives goals projections estimates of oil and gas quantities strategies future events or performance and underlying assumptions capital structure anticipatedcapital expenditures completion of construction projects projections for pension and other post-retirement benefit obligations impacts of the adoption of new accounting rulesand possible outcomes of litigation or regulatory proceedings as well as statements that are identified by the use of the words ldquoanticipatesrdquo ldquoestimatesrdquo ldquoexpectsrdquo ldquoforecastsrdquoldquointendsrdquo ldquoplansrdquo ldquopredictsrdquo ldquoprojectsrdquo ldquobelievesrdquo ldquoseeksrdquo ldquowillrdquo ldquomayrdquo and similar expressions Forward-looking statements involve risks and uncertainties which couldcause actual results or outcomes to differ materially from those expressed in the forward-looking statements The Companyrsquos expectations beliefs and projections are expressedin good faith and are believed by the Company to have a reasonable basis but there can be no assurance that managementrsquos expectations beliefs or projections will result or beachieved or accomplished

In addition to other factors the following are important factors that could cause actual results to differ materially from those discussed in the forward-looking statements delaysor changes in costs or plans with respect to Company projects or related projects of other companies including difficulties or delays in obtaining necessary governmentalapprovals permits or orders or in obtaining the cooperation of interconnecting facility operators governmentalregulatory actions initiatives and proceedings including thoseinvolving rate cases (which address among other things target rates of return rate design and retained natural gas) environmentalsafety requirements affiliate relationshipsindustry structure and franchise renewal changes in laws regulations or judicial interpretations to which the Company is subject including those involving derivatives taxessafety employment climate change other environmental matters real property and exploration and production activities such as hydraulic fracturing financial and economicconditions including the availability of credit and occurrences affecting the Companyrsquos ability to obtain financing on acceptable terms for working capital capital expendituresand other investments including any downgrades in the Companyrsquos credit ratings and changes in interest rates and other capital market conditions changes in the price ofnatural gas or oil impairments under the SECrsquos full cost ceiling test for natural gas and oil reserves factors affecting the Companyrsquos ability to successfully identify drill for andproduce economically viable natural gas and oil reserves including among others geology lease availability title disputes weather conditions shortages delays orunavailability of equipment and services required in drilling operations insufficient gathering processing and transportation capacity the need to obtain governmentalapprovals and permits and compliance with environmental laws and regulations increasing health care costs and the resulting effect on health insurance premiums and on theobligation to provide other post-retirement benefits changes in price differentials between similar quantities of natural gas or oil sold at different geographic locations and theeffect of such changes on commodity production revenues and demand for pipeline transportation capacity to or from such locations other changes in price differentialsbetween similar quantities of natural gas or oil having different quality heating value hydrocarbon mix or delivery date the cost and effects of legal and administrative claimsagainst the Company or activist shareholder campaigns to effect changes at the Company uncertainty of oil and gas reserve estimates significant differences between theCompanyrsquos projected and actual production levels for natural gas or oil changes in demographic patterns and weather conditions changes in the availability price oraccounting treatment of derivative financial instruments changes in laws actuarial assumptions the interest rate environment and the return on plantrust assets related to theCompanyrsquos pension and other post-retirement benefits which can affect future funding obligations and costs and plan liabilities changes in economic conditions includingglobal national or regional recessions and their effect on the demand for and customersrsquo ability to pay for the Companyrsquos products and services the creditworthiness orperformance of the Companyrsquos key suppliers customers and counterparties the impact of potential information technology cybersecurity or data security breaches economicdisruptions or uninsured losses resulting from major accidents fires severe weather natural disasters terrorist activities or acts of war significant differences between theCompanyrsquos projected and actual capital expenditures and operating expenses or increasing costs of insurance changes in coverage and the ability to obtain insurance

Forward-looking statements include estimates of oil and gas quantities Proved oil and gas reserves are those quantities of oil and gas which by analysis of geoscience andengineering data can be estimated with reasonable certainty to be economically producible under existing economic conditions operating methods and governmentregulations Other estimates of oil and gas quantities including estimates of probable reserves possible reserves and resource potential are by their nature more speculativethan estimates of proved reserves Accordingly estimates other than proved reserves are subject to substantially greater risk of being actually realized Investors are urged toconsider closely the disclosure in our Form 10-K available at wwwnationalfuelgascom You can also obtain this form on the SECrsquos website at wwwsecgov

For a discussion of the risks set forth above and other factors that could cause actual results to differ materially from results referred to in the forward-looking statements seeldquoRisk Factorsrdquo in the Companyrsquos Form 10-K for the fiscal year ended September 30 2018 and the Forms 10-Q for the quarter ended March 31 2018 June 30 2018 and December31 2018 The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date thereof or to reflect the occurrence ofunanticipated events

Appendix

13

Exploration amp Production and Gathering OverviewSeneca Resources Company LLC ~ National Fuel Gas Midstream Company LLC

14

Proved Reserves

385 337 290 302 277

16832142

16751973

2357

1914

2344

1849

2154

2523

0

500

1000

1500

2000

2500

3000

2014 2015 2016 2017 2018At September 30

Natural Gas (Bcf)

Crude Oil (MMbbl)

361 Reserve Replacement Rate

Seneca Drill-bit FampD = $066Mcfe(1)

Appalachia Drill-bit FampD = $065Mcfe(1)

(1) Seneca ldquoDrill-bitrdquo finding and development (ldquoFampDrdquo) costs exclude the impact of reserve revisions

Total Proved Reserves (Bcfe)

Fiscal 2018 Proved Reserves Stats

$138

$112

$132

$098

$074

$050

$100

$150

2014 2015 2016 2017 2018

3-Year Average FampD Cost ($Mcfe)

70

30

PDPs PUDs

EampP and Gathering

15

3 rig development program with second rig in WDA focused on Utica

15-20 net production growth expected through fiscal 2022

New EDA Utica development with production expected in Q2 fiscal 2019

Utilize new Atlantic Sunrise firm transportation capacity

Layer-in firm sales to take advantage of attractive regional pricing

Gross production growth will benefit NFGrsquos Gathering segment

Minimal capital investment in California to generate significant cash flow

Growing Production within Disciplined Capital Program

205 194 176 ~16

1406 1541 1605194-214

1611 1735 1781210-230

0

50

100

150

200

250

2016 2017 2018 2019E

$38 $38 $26 ~$25$61

$208$330

$435-$470

$99

$246

$356

$460-$495

$0

$200

$400

$600

2016 2017 2018 2019E

Appalachia West Coast (California)

Near-Term Growth Strategy EampP Net Capital Expenditures ($ millions)(1)

EampP Net Production (Bcfe)

EampP and Gathering

(1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentationFY16 FY17 and FY18 guidance reflects the netting of $157 million $7 million and $17 million respectively of up-front proceeds received from joint development partner for working interest in joint development wells

16

Significant Appalachian Acreage Position

Average gross production ~311 MMcfd

Mostly leased (16-18 royalty) with no significant near-term lease expirations

~90 remaining Marcellus amp Utica locations economic at ~$184Mcf

Additional Marcellus (Tioga Co) amp Geneseo (Lycoming Co) potential

Eastern Development Area (EDA)

Western Development Area (WDA)

Average gross production(1) ~327 MMcfd Large inventory of Marcellus amp Utica

locations economic at ~$200Mcf Royalty free mineral ownership

enhances well economics Highly contiguous nature drives cost and

operational efficiencies

EampP and Gathering

EDA - 70000 AcresWDA - 715000 Acres

(1) Average EDA and WDA gross production as well as WDA-CRV Utica production (see slide 19) and CovingtonTract 595 Production (see slide 23) is for the quarter ended December 31 2018

17

Western Development AreaMarcellus Core Acreage

vs Utica Appraisal Trend(1)

(1) The Utica Shale lies approximately 5000 feet beneath Senecarsquos WDA Marcellus acreage (2) Appraisal program currently in progress Additional tests are planned Prior Marcellus delineation tests helped define the prospective limits of the Marcellus core acreage planned testing in the Utica expected to do the same

Area of Re-Development ~120 Utica locations on existing Marcellus pads

Key Utica testsPast Marcellus delineation testsUtica Trend (currently evaluating)Marcellus Core Acreage

Large well inventory economic at ~$200 Mcf

Marcellus Shale 600+ well locations remaining 200000 acres

Utica Shale 500+ potential locations across Utica trend evaluating extent of prospective acreage(2)

Fee acreage (no royalty) enhances economics and provides development flexibility

Addition of 2nd WDA drilling rig in Q3 FY18 focused on redevelopment of Clermont-Rich Valley acreage for Utica

Use of existing gathering pad and water infrastructure for Utica drives increased Appalachian program returns

Highly contiguous position drives best in class well costs

Utica test results on trend with other Utica wells in NE Pa

Long-term firm contracts support growth

Boone Mountain Utica Test Well23 Bcf 1000ft

Rich Valley Utica Test Well23 Bcf 1000ft

EampP and Gathering

WDA Highlights

18

WDA Utica Appraisal Results and Initial Type Curve

Tested producing from 17 Utica wells in WDA-CRV Higher pressure significantly enhances well

productivity (Utica ~5000rsquo deeper than Marcellus) Drawdown management is critical restricted

drawdown appears to improve well EURs Early production declines much shallower vs

Marcellus

WDA Utica Appraisal Update

WDA Economics

(1) Internal Rate of Return (IRR) is pre-tax and includes estimated well costs under current cost structure LOEand anticipated gathering tariffs

(2) Initial WDA-CRV Utica type curve based on production results and reservoir expectations from the first 5appraisal wells in the WDA-CRV area

(3) WDA-CRV Utica Average includes all 17 producing wells including 2 wells (pad E09-S) for which drawdownmanagement was not used

EampP and Gathering

EURBcf1000rsquo

Well Cost$M1000rsquo

IRR $225

Break-even15 IRR(1)

Utica - CRV 17 $887 23 $197

Marcellus 10 ndash 11 $643 19 $206

(2)

0

1

2

3

4

5

6

7

8

9

0 12 24 36 48 60 72 84 96 108 120

Cum

ulat

ive

Prod

uctio

n B

CF

Months On

WDA-CRV Utica Wells - Normalized to 9000rsquoUtica Type Curve CRV Utica AverageWDA Marcellus Type Curve Boone Mountain Appraisal WellWDA-CRV Utica Type Curve(2) WDA-CRV Utica Average(3)

0005101520253035

0 2 4 6 8 10 12

19

Transitioning to Utica Development in CRV

WDA-CRV Marcellus(Depth ~7000 feet)

WDA-CRV Utica(Depth ~12000 feet)

Avg CRV Marcellus Production 270 MMcfd

Rem Avg EUR 10-11 Bcf 1000 lat ft

Rem Avg Well Costs = $643lat ft

120+ locations on existing Marcellus pads

Est EURs 17 Bcf 1000 lat ft

Est Development Well Costs = $887lat ft

CRV Utica Transition Plan

1)Finish Marcellus Pads in Development

Drill 24 complete 24 Marcellus wells

2)Continue Optimizing Utica DampC design

Additional optimization wells focusing on

Completion design

Landing zone targets

3)Continue transition to Utica development

Future drilling on multi-well pads

Continue using optimization results to determine development well design

Tailor development plan to use existing pad water and gathering infrastructure

CRV Utica Development Utilizes Existing Pad Water and Gathering Infrastructure to Drive Economics

EampP and Gathering

Rich Valley Utica Test

Existing Line

Leased

Seneca Fee

Producing

FY19 Producer

Development

20

Leveraging Existing Gathering Water and Pad Infrastructure Enhances Returns

Limited New Infrastructure Needed to Support Production Growth

WDA Well Costs(1) WDA Consolidated Economics

Steady activity levels and coordination between upstream and midstream activities

enhance returns provide economies of scale and significant operational flexibility

(1) WDA Marcellus well costs reflect drilling completion amp gathering costs for 192 drilled and completed wells as of 93018 WDA Utica well costs reflect expected drilling completion amp gathering costs for the ~120 well locations in area of redevelopment (2) Internal Rate of Return for Seneca WDA includes estimated well costs under current cost structure and anticipated LOE and Gathering costs Internal Rate of Return for Seneca WDA and Gathering includes expected gathering capital expenditures

through FY 2022 well costs under current cost structure and non-gathering LOE

$685$887

$210

$0

$200

$400

$600

$800

$1000

Marcellus(Historic)

Utica - CRV(Current)

$ la

tera

l foo

t

Drilling amp Completion Gathering

$931$895

10 -11

17

00

03

06

09

12

15

18

Marcellus(Historic)

Utica - CRV(Current)

EUR

10

00 fe

et (B

cf)

60-70 EUR increase expected per well

Total cost per well expected to marginally increase

WDA EURs

At a $225 netback price consolidated Seneca WDA and Gathering IRR is

approximately 33 an uplift of ~12 over standalone Seneca WDA economics(2)

10+ IRR Uplift Expected

21

Integrated Development ndash WDA Gathering System

Current System In-Service

~78 miles of pipe 36220 HP of compression

Current Capacity 470 MMcf per day

Interconnects with TGP 300

Total Investment to Date $301 million

Future Build-Out

FY 2019 CapEx $10 - $15 million

Modest gathering pipeline and compression investment required to support Senecarsquos transition to Utica development

Opportunity for 300 miles of pipelines and five compressor stations (+60000 HP installed) as Senecarsquos drilling activity continues

Deliverability into TGP 300 and NFG Supply

Gathering System Build-Out Tailored to Accommodate Senecarsquos WDA Development

Clermont Gathering System Map

EampP and Gathering

22

WDA Firm Transportation and Sales Capacity

Will continue to layer-in firm sales deals of short and longer duration on TGP 300 to reduce spot exposure

WDA spot realizations track TGP Station 313 pricing typically 10cent - 30cent better than TGP Marcellus Zone 4

Leidy South will provide additional capacity to premium markets (Transco Zone 6)

WDA Exit Capacity Supports Long-term Production Growth and Enhances Consolidated Returns

WDA Contracted Firm Transport and Gross Sales Volumes (MDthd)

Seneca gross production trend

EampP and Gathering

0

100

200

300

400

500

600

700

Niagara Expansion Project (TGP and NFG)FT Capacity 158000 Dthd $067Dth

Firm Sales NYMEX amp DAWN

WDA - TGP 300Firm Sales

Leidy SouthTransco Zone 6

Markets330000 Dthd(1)

Will layer-in firm sales to minimize spot exposure

(1) Portion of Transco Project capacity will likely be utilized by EDA Lycoming County production

WDA Gas Marketing Strategy

23

Eastern Development Area

EDA Acreage ndash 70000 AcresEDA Highlights

1 DCNR Tract 007 (Tioga Co Pa)bull Utica development resumed in third quarter fiscal 2018

bull ~43 remaining Utica locations economic at ~$184 Mcf

bull Gathering Infrastructure NFG Midstream Wellsboro

bull Marcellus Shale expected to provide ~60 additional locations

EampP and Gathering

2

1

3

2 Covington amp DCNR Tract 595 (Tioga Co Pa)bull Marcellus locations fully developed (average daily gross production of ~93 MMcfd)

bull Gathering Infrastructure NFG Midstream Covington

bull Opportunity for future Utica appraisal

3 DCNR Tract 100 amp Gamble (Lycoming Co Pa)bull ~45 remaining Marcellus locations economic at ~$153 Mcfbull Firm Transportation Capacity Atlantic Sunrise (189 MDthd)

bull Gathering Infrastructure NFG Midstream Trout Run

bull Geneseo Shale expected to provide 100-120 additional locations

24

EDA Marcellus Lycoming County Development

Marcellus Development in Lycoming County has Resumed in Connection with Atlantic Sunrise

(1) Includes physical fixed price and NYMEX-based firm sales contracts that do not carry any additional transportation costs

EampP and Gathering

Prolific Marcellus acreage with peer leading well results

~45 remaining Marcellus locations economic at ~$153 Mcf

Near-term development focused on filling Atlantic Sunrise capacity

Existing Line

Leased

Seneca Fee

Producing

FY19 Producer

Development

0

50

100

150

200

250

Gro

ss F

irm V

olum

es (M

Dth

d)

EDA ndash Transco Firm Contracts

Atlantic Sunrise (Transco)FT Capacity 189405 Dthd

Cost $073DthFirm Sales NYMEX+

Transco Firm Sales(1)

25

EDA Utica Tioga County Development

Utica Development in Tioga County ndash Tract 007 Development Resumed in Q3 Fiscal 2018

In-Service November 2016

Lateral Length 4640 ft

30 Day IP 1000 ft 34 MMcfd

Est EUR 1000 ft 24 Bcf

Inventory ~43 locations economic at ~$184 Mcf

Targeting to grow production by 100 to 150 MDthd by fiscal 2020

Expected Development Costs $1045 per lateral ft

Gathering Infrastructure NFG Midstream Wellsboro

Modest build-out required to connect to TGP 300

SalesTakeaway Strategy Layer-in firm sales with shippers holding capacity on TGP 300

(1) Includes physical fixed price and NYMEX-based firm sales contracts that do not carry any additional transportation costs

Tract 007 Utica Appraisal Well Results vs Industry

EampP and Gathering

0

100000

200000

300000

400000

500000

600000

700000

800000

0 100 200 300

Nor

mal

ized

Cum

ulat

ive

(Mcf

10

00rsquo)

Days On ProductionIndustry PotterTioga Wells Seneca DCNR 007 73H

0

25

50

75

100

125

150

Gro

ss F

irm V

olum

es (M

Dth

d)

EDA ndash TGP 300 Firm Contracts

Northeast Supply Diversification ProjectFT Capacity 50000 Dthd $050Dth

Firm Sales NYMEX and DAWN

EDA - TGP 300Firm Sales(1)

26

Integrated Development ndash EDA Gathering Systems

Total Investment (to date) ~$46 million FY 2019 Estimated Capital Expenditures $1 MM - $2 MM Capacity 220000 Dth per day (Interconnect w TGP 300) Production Source Seneca Resources ndash Tioga Co (Covington and DCNR Tract 595)

Total Investment (to date) ~$208 million FY 2019 Estimated Capital Expenditures $25 MM - $35 MM Capacity 466000 to 585000 Dth per day (Interconnect w Transco) Production Source Seneca Resources ndash Lycoming Co (DCNR Tract 100 and Gamble) Future third-party volume opportunities

Covington Gathering System

Trout Run Gathering System

Gathering Segment Supporting Senecarsquos EDA Production amp Future Development

Wellsboro Gathering System Total Investment (to date) ~$14 million FY 2019 Estimated Capital Expenditures $8 MM - $15 MM Capacity up to 200000 Dth per day (Interconnect w TGP 300) Production Source Seneca Resources ndash Tioga Co (DCNR Tract 007)

EampP and Gathering

2

1

3

27

Long-term Contracts Supporting Appalachian Growth

(1) Represents base firm sales contracts not tied to firm transportation capacity Base firm sales are either fixed priced or priced at an index (eg NYMEX ) +- a fixed basis and do not carry any transportation costs

Seneca continues to layer-in firm sales contracts with attractive realizations to lock-in drilling economics and minimize spot exposure ahead of firm transportation in-service dates

EampP and Gathering

-

100

200

300

400

500

600

700

800

900

1000

1100

1200

FY 2019 FY 2020 FY 2021 FY 2022Northeast Supply Diversification 50000 Dthd

Niagara Expansion (TGP amp NFG)Delivery Markets Canada-Dawn amp TETCO

158000 Dthd

Atlantic Sunrise (Transco)Delivery Markets Mid-Atlantic amp Southeast US

189405 Dthd

In-BasinFirm Sales

Contracts(1)

Leidy South (Transco amp NFG)

Transco Zone 6 Markets330000 Dthd

Seneca Appalachia Natural Gas MarketingGross Firm Contract Volumes (Mdthday)

28

297000 ($061)

305200 ($061)

305600 ($063)

337000 ($057)

370800 ($024)

369600 ($060)

367900 ($067)

33400 ($070)74500 ($077) 74900 ($077)

81100 ($078)

85900 ($078)

92000 ($073)

91300 ($073)

178800 $255

196000 $234

195500 $234

149900 $232

129500 $230

105400 $222

104500 $222

~517800 509200 575700 576000 568000 586200 567000 563700

Q1 FY19 Q2 FY19 Q3 FY19 Q4 FY19 Q1 FY20 Q2 FY20 Q3 FY20 Q4 FY20

Fixed Price Dawn NYMEX

Near-term Firm Sales Provide Market amp Price Certainty

Net Contracted Firm Sales Volumes (Dth per day)Contracted Index Price Differentials ($ per Dth)(1)

(1) Values shown represent the weighted average fixed price or contracted fixed differential relative to NYMEX (netback price) less any associated transportation costs

Actual Daily Net

Production

641200 716500 708700 693500 708400 674400 667000Gross Firm Sales Volumes (Dthd)

EampP and Gathering

29

California Oil

Stable Oil Production | Minimal Capital Investment | Steady Free Cash Flow

1

2

3

4

5

Location Formation Production Method

FY18 Daily Production(net Boed)

1 East Coalinga Other Temblor Primary 512

2 North Lost Hills

Tulare amp Etchegoin

PrimarySteam flood 892

3 South Lost Hills

Monterey Shale Primary 1359

4 North Midway Sunset

Tulare amp Potter Steam flood 2786

5 South Midway Sunset Antelope Steam flood 2048

TOTAL WEST DIVISION NET PRODUCTION(1) 7597 Boed

EampP and Gathering

(1) West division net production for FY 2018 excludes production from Sespe field which was divested on May 1 2018

30

California Capital Expenditures vs Production

9341 8863

8033 ~7300

2016 2017 2018 2019

Fiscal Year

West Division Average Net Daily Production (Boe)West Division Annual Capital Expenditures ($ MM)(1)

$38 $38

$26 ~$25

2016 2017 2018 2019

Fiscal YearGuidance Guidance

(1) Seneca West Division capital expenditures includes Seneca corporate and eliminations

EampP and Gathering

Sepse Sale Closed on 5118(reduced production by ~900 boed)

31

Pioneer

South MWSS

Acreage

North MWSS

AcreageSec 17N

4149 51

NMWSS amp 17N SMWSS amp Pioneer East Coalinga

California Development Activities

Modest near-term capital program focused on locations that earn attractive returns in current oil price environment

AampD will focus on low cost bolt-on opportunities

Sec 17 Pioneer and East Coalinga development to provide future growth

North

Project IRRs at $55Bbl(1)

(1) Reflects pre-tax IRRs at a $55Bbl WTI

EampP and Gathering

Seneca West Economics

South

East Coalinga

North

South

32

Fiscal 2019 Production and Price Certainty

~49 Bcfe

210 ndash 230 Bcfe

~114 Bcf

~29 Bcf (2)

16+- Bcf~12 Bcfe

0

40

80

120

160

200

240

YTD FY19Actuals

Fixed Price + FirmSales w Hedge

Firm Sales(Unhedged)

Spot Sales California TotalSeneca

Prod

uctio

n (B

cfe)

(1) Average realized price reflects uplift from financial hedges less fixed differentials under firm sales contracts and any firm transportation costs(2) Indicates firm sales contracts with fixed index differentials but not backed by a matching financial hedge

114 Bcf locked-in realizing net ~$241Mcf (1)

29 Bcf of additional basis protection

Spot production assumed to be sold

at ~$275Mmbtu(winter) and ~$225

(summer)

143 Bcf of Appalachian Production Protected by Firm Sales for Remainder of Year

79 of oil production hedged at $5757 Bbl

EampP and Gathering

33

Strong Hedge Book

Natural Gas Swap amp Fixed Physical Sales Contracts (Millions MMBtu)

(1) Fixed price physical sales exclude joint development partnerrsquos share of fixed price contract WDA volumes as specified under the joint development agreement(2) Reflects percentage of projected production for FY19 hedged at the midpoint of the production guidance range(3) Senecarsquos remainder FY19 Production reflects the total FY19 production guidance of 210-230 Bcfe or 220 Bcfe at the midpoint less Q1 actual production

Crude Oil Swap Contracts (Thousands Bbls)

13591188

732

456

0

500

1000

1500

2000

2500

FY 2019 FY 2020 FY 2021 FY 2022

NYMEX (WTI)

Brent

FY 19 Crude Oil79 Hedged (2)

FY 2019 Remaining Production (3)

EampP and Gathering

1174

709

469 406

0

50

100

150

200

250

FY 2019 FY 2020 FY 2021 FY 2022

NYMEX Swaps

Dawn Swaps

Fixed Price Physical Sales

(1)

FY 2019 Remaining Production (3)

FY 19 Nat Gas71 Hedged (2)

34

$065 $070$070 -$075

FY 2017 FY 2018 FY 2019E

$060 $060 $060

$011 $009 $007$071 $069 ~$067

FY 2017 FY 2018 FY 2019E Gathering amp Transport LOE (non-Gathering) GampA Taxes amp Other

Seneca Operating Costs

Competitive low cost structure in Appalachia and California supports strong cash margins

Gathering fee generates significant revenue stream for affiliated gathering company

Seneca DDampARate

$Mcfe

$054 $054 $056

$042 $038 $031

$034 $034 $030

$017 $014 $015

$147 $140 ~$132

FY 2017 FY 2018 FY 2019E

(1)

$1791$1746~$2050

FY 2017 FY 2018 FY 2019E

Appalachia LOE amp Gathering $Mcfe

California LOE$Boe

Total Seneca Cash OpEx$Mcfe

(1)

(2)

(2)

(1) GampA estimate represents the midpoint of the GampA guidance range of $025 to $035 for fiscal 2019(2) The total of the two LOE components represents the midpoint of the LOE guidance range of $085 to $090 for fiscal 2019

EampP and Gathering

35

Senecarsquos Continuing Commitment to the Environment

Produced Water Recycled in Appalachia

100 70Recycled Water

Used in New Shale Well

Completions

Water and Fluids Management Air Quality and Emissions

Seneca Resources Water OperationsFiscal 2018

Seneca Resources Remains Focused on Minimizing GHG Emissions

The Environmental Partnership

EPA Natural Gas Star Program

Green Completions (all fiscal 2018 wells)

Ultrasonic Leak Detection Technology

Emissions Controls

Rig and Vehicle Fuel Conversion

Integrating Renewable Energy into Operations

EampP and Gathering

36

Pipeline and Storage OverviewNational Fuel Gas Supply Corporation ~ Empire Pipeline Inc

37

Pipeline amp Storage Segment Overview

(1) As of September 30 2018 as disclosed in the Companyrsquos fiscal 2018 form 10-K(2) As of December 31 2017 calculated from National Fuel Gas Supply Corporationrsquos and Empire Pipeline Incrsquos 2017 FERC Form-2 reports respectively

Empire Pipeline Inc

National Fuel Gas Supply Corporation

Empire Pipeline

Supply Corp

Contracted Capacity(1) Firm Transportation 3187 MDth per day Firm Storage 71938 Mdth (fully subscribed)

Rate Base(2) ~$820 million FERC Rate Proceeding Status

Rate case settlement extension approved Nov lsquo15 Rate case filing expected by 73119

Contracted Capacity(1) Firm Transportation 978 MDth per day Firm Storage 3753 Mdth (fully subscribed)

Rate Base(2) ~$249 million FERC Rate Proceeding Status

Rate case settlement in principle reached on 122118 FERC approval pending

New transportation rates went into on 1119

Pipeline amp Storage

38

All Seneca volumes will flow through wholly-owned NFG gathering facilities

FM100 Project - Consolidated Benefit for NFG

330000 Dthd of new transportation capacity from WDA and EDA acreage positions to premium markets

New Transco capacity (Leidy South) 330000 Dthday

Rate(1) competitive with other expansion project rates in Senecarsquos current transportation portfolio

Delivery Point(s) Transco Zone 6 interconnections

Seneca

Lease to Transco of new capacity 330000 Dthday

Estimated annual lease revenues ~$35 million

Target In-Service late calendar year 2021

Supply Corp

Project expected to provide long-term earnings uplift to Seneca Supply Corp and Gathering

Pipeline amp Storage

Gathering

(1) Includes lease of new capacity from Supply Corp to Transco

39

FM100 Project ndash Significant Investment by Supply Corp

Pipeline amp Storage

Estimated Capital Cost $280 million(1)

Facilities (all in Pennsylvania) include Approximately 30 miles of new pipeline 2 new compressor stations (totaling

approximately 37000 HP) New interconnection station and modification

of existing interconnection station Abandonment of approximately 45 miles of

existing pipeline and compressor station Regulatory Process

Pre-filing application submitted to FERC in 2017 for original modernization project

FERC 7(b) 7(c) filing expected summer 2019

(1) Includes expansion and modernization portions of the project

40

Empire North Project

Target In-Service second half of fiscal 2020

Est Capital Cost $145 million

Est Annual Revenues ~$25 million

Receipt Point Jackson (Tioga Co Pa production)

Design Capacity and Delivery Points 175000 Dthd to Chippawa (TCPL interconnect)

30000 Dthd to Hopewell (TGP 200 interconnect)

Customers Fully subscribed (205000 Dthday)

Major Facilities 2 new compressor stations in NY (1) amp Pa (1)

No new pipeline construction

Regulatory Process FERC 7(c) application filed on 21618

FERC Environmental Assessment issued 103018

Pipeline amp Storage

Fully Subscribed Project will Provide 205000 Dthday of Incremental Firm Transportation

41

National Fuel Remains Committed to Northern Access Project

Target In-Service as early as fiscal 2022

Total Cost ~$500MM (~$76MM spent to date)

Estimated Annual Revenues ~$84 million

Delivery Points

350000 Dthd to Chippawa (TCPL interconnect)

140000 Dthd to Hopewell (TGP 200 line)

Regulatory Status

February 3 2017 ndash FERC 7(c) certificate issued

August 6 2018 ndash FERC issued Order finding that NY DEC waived water quality certification

Supply and Empire currently working to finalize remaining federal authorizations

Pipeline amp Storage

To Dawn

42

Continued Expansion of the NFG Supply System

Line N Expansion Opportunities

Line N to Monaca Project Project Firm transportation service to a new ethane

cracker facility being built by Shell Chemical Appalachia LLC

Target In-Service July 2019

Estimated Capital Cost $23 million

Contracted Capacity 133000 Dthday

Additional Line N Expansion Opportunity (Supply OS 221) Project New firm transportation service for on-system

demand

Open Season Capacity Awarded 165000 to foundation shipper Precedent agreement in negotiations

Pipeline amp Storage

43

Pipeline amp Storage Customer Mix

Producer33

LDC42

Marketer10

Outside Pipeline

9

End User6

42 MMDthd

(1) Contracted as of 10312018

Customer Transportation by Shipper Type(1) Affiliated Customer Mix (Contracted Capacity)

66

521

41

34

9579

59

LDCs Producers Marketers FirmStorage

Affiliated Non-Affiliated

Firm Transport

Pipeline amp Storage

44

Utility OverviewNational Fuel Gas Distribution Corporation

45

New York amp Pennsylvania Service Territories

New York

Total Customers(1) 535800ROE 87 (NY PSC Rate Case Order April 2017)Rate Mechanismso Revenue Decouplingo Weather Normalizationo Low Income Rateso Merchant Function Charge (Uncollectibles Adj)o 9010 Sharing (Large Customers)o System Modernization Tracker

Pennsylvania

Total Customers(1) 214400ROE Black Box Settlement (2007)Rate Mechanismso Low Income Rateso Merchant Function Charge

(1) As of September 30 2018

Utility

46

New York Rate Case Outcome

Rate Order Summary

Revenue Requirement $59 million

Rate Base $704 million

Allowed Return on Equity (ROE) 87

Capital Structure 429 equity

Other notable items

New rates became effective 5117

Retains rate mechanisms in place under prior order (revenue decoupling weather normalization merchant function charge 9010 large customer sharing)

No stay-out clause

System modernization tracker for Leak Prone Pipe (LPP)

Earnings sharing started 4118 (5050 sharing starts at earnings in excess of 92)

Article 78 appeal filed on 72817 with oral argument completed in January 2019

On April 20 2017 the New York Public Service Commission issued a Rate Order relating to NFG Distributionrsquos rate case (No 16-G-0257) filed in April 2016

Utility

47

Utility Continues its Significant Investments in Safety

$544$618 $636

$699

$944$980

$809$856

$90-100

$00

$250

$500

$750

$1000

$1250

2015 2016 2017 2018 2019E

Cap

ital E

xpen

ditu

res

($ m

illio

ns)

Fiscal Year

Capital Expenditures for Safety Total Capital Expenditures

Modernization Spending in NY Expected to Grow Gross Margin By $2 MM - $5 MM in FY 2019

(1)

(1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation

Utility

System modernization tracker in NY allows recovery of pipeline replacementcosts which is expected to drive modest gross margin and rate base growth

48

Accelerating Pipeline Replacement amp Modernization

Wrought Iron

Plastic

CoatedBare

120130

146 144159

2014 2015 2016 2017 2018Calendar Year

NY9726 miles

PA4830 miles

No Cast Iron Mains in Pa

Miles of Utility Main Pipeline ReplacedUtility Mains by Material(1)

Wrought Iron

Cast Iron

Plastic

Coated Bare

Utility

(1) All values are reported on a calendar year basis as of December 31 2018

49

A Proven History of Controlling Costs

$200 $189 $195

$166 $166

$31 $31

$197 $197

$0

$50

$100

$150

$200

$250

2015 2016 2017 2018 TTM 123118

Fiscal Year

OampM Expense Non-Service Pension Costs

OampM Expense ($ millions)

Utility

(1)

(1) For purposes of comparability to FY 2015 2016 and 2017 Utility Operation and Maintenance Expense for FY 2018 and the twelve months ended December 31 2018 was adjusted by approximately $314 million and $312 million respectively to include non-service pension costs which were re-classified as Other Income (Deductions) as of October 1 2018 on the Companyrsquos Income Statement See Slide 64 for non-GAAP reconciliation of Adjusted Operation and Maintenance Expense to Operation and Maintenance Expense by segment

50

Consolidated Financial OverviewUpstream I Midstream I Downstream

51

Adjusted Operating Results ($ per share)(1)

Diversified Balanced Earnings and Cash Flows

(1) A reconciliation of Adjusted Operating Results to Earnings per Share by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation(2) Consolidated Adjusted EBITDA includes Energy Marketing and Corporate amp All Other Segments A reconciliation of Adjusted EBITDA to Net Income by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in

the Business is included at the end of this presentation

Adjusted EBITDA ($ millions)(2)

$176 $179

$184 $181

$92 $97

$318 $327

$761 $775

$-

$200

$400

$600

$800

FY 2018 TTM 123118

$059 Utility

$097 Pipeline amp Storage

$057 Gathering

$125 Exploration

amp Production

$334 $345 to $365

$-

$100

$200

$300

$400

FY 2018 FY 2019 Guidance

Rate Regulated

40-45

$728

Rate Regulated

~46

52

$89 $94 $98 $81 $86 $90-$100

$140$230

$114 $95 $93 $120-$150

$138$118

$54$33 $48

$55-$65

$603$557

$99 $246$356

$460-$495

$970 $1001

$366$455

$583

$725-$810

$0

$250

$500

$750

$1000

$1250

2014 2015 2016 2017 2018 2019GuidanceFiscal Year

Exploration amp Production

Gathering

Pipeline amp Storage

Utility

Disciplined Flexible Capital Allocation

(2)

(1) Total Capital Expenditures include Energy Marketing Corporate and All Other A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation (2) FY16 FY17 and FY18 reflects the netting of $157 million $7 million and $17 million respectively of up-front proceeds received from joint development partner for working interest in joint development wells and $21M in intercompany asset transfers in FY18

Capital Expenditures by Segment ($ millions)(1)

53

Maintaining Strong Balance Sheet amp Liquidity

Total Equity49

Total Debt51

$42 Billion Total Capitalizationas of December 31 2018

218 x251 x 245 x 247 x 256 x

2015 2016 2017 2018 TTM 123118Fiscal Year End

Net Debt Adjusted EBITDA(1) Capitalization

Debt Maturity Profile ($MM) Liquidity

Committed Credit FacilitiesShort-term Debt OutstandingAvailable Short-term Credit FacilitiesCash Balance at 123118 Total Liquidity at 123118

$ 750 MM0 MM

750 MM110 MM

$ 860 MM

$500 $549 $500

$300 $300

$0

$200

$400

$600

(1) Net Debt is net of cash and temporary cash investments Reconciliations of Net Debt and Adjusted EBITDA to Net Income are included at the end of this presentation

54

Appendix

55

Safe Harbor For Forward Looking StatementsThis presentation may contain ldquoforward-looking statementsrdquo as defined by the Private Securities Litigation Reform Act of 1995 including statements regarding future prospectsplans objectives goals projections estimates of oil and gas quantities strategies future events or performance and underlying assumptions capital structure anticipatedcapital expenditures completion of construction projects projections for pension and other post-retirement benefit obligations impacts of the adoption of new accounting rulesand possible outcomes of litigation or regulatory proceedings as well as statements that are identified by the use of the words ldquoanticipatesrdquo ldquoestimatesrdquo ldquoexpectsrdquo ldquoforecastsrdquoldquointendsrdquo ldquoplansrdquo ldquopredictsrdquo ldquoprojectsrdquo ldquobelievesrdquo ldquoseeksrdquo ldquowillrdquo ldquomayrdquo and similar expressions Forward-looking statements involve risks and uncertainties which couldcause actual results or outcomes to differ materially from those expressed in the forward-looking statements The Companyrsquos expectations beliefs and projections are expressedin good faith and are believed by the Company to have a reasonable basis but there can be no assurance that managementrsquos expectations beliefs or projections will result or beachieved or accomplished

In addition to other factors the following are important factors that could cause actual results to differ materially from those discussed in the forward-looking statements delaysor changes in costs or plans with respect to Company projects or related projects of other companies including difficulties or delays in obtaining necessary governmentalapprovals permits or orders or in obtaining the cooperation of interconnecting facility operators governmentalregulatory actions initiatives and proceedings including thoseinvolving rate cases (which address among other things target rates of return rate design and retained natural gas) environmentalsafety requirements affiliate relationshipsindustry structure and franchise renewal changes in laws regulations or judicial interpretations to which the Company is subject including those involving derivatives taxessafety employment climate change other environmental matters real property and exploration and production activities such as hydraulic fracturing financial and economicconditions including the availability of credit and occurrences affecting the Companyrsquos ability to obtain financing on acceptable terms for working capital capital expendituresand other investments including any downgrades in the Companyrsquos credit ratings and changes in interest rates and other capital market conditions changes in the price ofnatural gas or oil impairments under the SECrsquos full cost ceiling test for natural gas and oil reserves factors affecting the Companyrsquos ability to successfully identify drill for andproduce economically viable natural gas and oil reserves including among others geology lease availability title disputes weather conditions shortages delays orunavailability of equipment and services required in drilling operations insufficient gathering processing and transportation capacity the need to obtain governmentalapprovals and permits and compliance with environmental laws and regulations increasing health care costs and the resulting effect on health insurance premiums and on theobligation to provide other post-retirement benefits changes in price differentials between similar quantities of natural gas or oil sold at different geographic locations and theeffect of such changes on commodity production revenues and demand for pipeline transportation capacity to or from such locations other changes in price differentialsbetween similar quantities of natural gas or oil having different quality heating value hydrocarbon mix or delivery date the cost and effects of legal and administrative claimsagainst the Company or activist shareholder campaigns to effect changes at the Company uncertainty of oil and gas reserve estimates significant differences between theCompanyrsquos projected and actual production levels for natural gas or oil changes in demographic patterns and weather conditions changes in the availability price oraccounting treatment of derivative financial instruments changes in laws actuarial assumptions the interest rate environment and the return on plantrust assets related to theCompanyrsquos pension and other post-retirement benefits which can affect future funding obligations and costs and plan liabilities changes in economic conditions includingglobal national or regional recessions and their effect on the demand for and customersrsquo ability to pay for the Companyrsquos products and services the creditworthiness orperformance of the Companyrsquos key suppliers customers and counterparties the impact of potential information technology cybersecurity or data security breaches economicdisruptions or uninsured losses resulting from major accidents fires severe weather natural disasters terrorist activities or acts of war significant differences between theCompanyrsquos projected and actual capital expenditures and operating expenses or increasing costs of insurance changes in coverage and the ability to obtain insurance

Forward-looking statements include estimates of oil and gas quantities Proved oil and gas reserves are those quantities of oil and gas which by analysis of geoscience andengineering data can be estimated with reasonable certainty to be economically producible under existing economic conditions operating methods and governmentregulations Other estimates of oil and gas quantities including estimates of probable reserves possible reserves and resource potential are by their nature more speculativethan estimates of proved reserves Accordingly estimates other than proved reserves are subject to substantially greater risk of being actually realized Investors are urged toconsider closely the disclosure in our Form 10-K available at wwwnationalfuelgascom You can also obtain this form on the SECrsquos website at wwwsecgov

For a discussion of the risks set forth above and other factors that could cause actual results to differ materially from results referred to in the forward-looking statements seeldquoRisk Factorsrdquo in the Companyrsquos Form 10-K for the fiscal year ended September 30 2018 and the Forms 10-Q for the quarter ended March 31 2018 June 30 2018 and December31 2018 The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date thereof or to reflect the occurrence ofunanticipated events

Appendix

14

Proved Reserves

385 337 290 302 277

16832142

16751973

2357

1914

2344

1849

2154

2523

0

500

1000

1500

2000

2500

3000

2014 2015 2016 2017 2018At September 30

Natural Gas (Bcf)

Crude Oil (MMbbl)

361 Reserve Replacement Rate

Seneca Drill-bit FampD = $066Mcfe(1)

Appalachia Drill-bit FampD = $065Mcfe(1)

(1) Seneca ldquoDrill-bitrdquo finding and development (ldquoFampDrdquo) costs exclude the impact of reserve revisions

Total Proved Reserves (Bcfe)

Fiscal 2018 Proved Reserves Stats

$138

$112

$132

$098

$074

$050

$100

$150

2014 2015 2016 2017 2018

3-Year Average FampD Cost ($Mcfe)

70

30

PDPs PUDs

EampP and Gathering

15

3 rig development program with second rig in WDA focused on Utica

15-20 net production growth expected through fiscal 2022

New EDA Utica development with production expected in Q2 fiscal 2019

Utilize new Atlantic Sunrise firm transportation capacity

Layer-in firm sales to take advantage of attractive regional pricing

Gross production growth will benefit NFGrsquos Gathering segment

Minimal capital investment in California to generate significant cash flow

Growing Production within Disciplined Capital Program

205 194 176 ~16

1406 1541 1605194-214

1611 1735 1781210-230

0

50

100

150

200

250

2016 2017 2018 2019E

$38 $38 $26 ~$25$61

$208$330

$435-$470

$99

$246

$356

$460-$495

$0

$200

$400

$600

2016 2017 2018 2019E

Appalachia West Coast (California)

Near-Term Growth Strategy EampP Net Capital Expenditures ($ millions)(1)

EampP Net Production (Bcfe)

EampP and Gathering

(1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentationFY16 FY17 and FY18 guidance reflects the netting of $157 million $7 million and $17 million respectively of up-front proceeds received from joint development partner for working interest in joint development wells

16

Significant Appalachian Acreage Position

Average gross production ~311 MMcfd

Mostly leased (16-18 royalty) with no significant near-term lease expirations

~90 remaining Marcellus amp Utica locations economic at ~$184Mcf

Additional Marcellus (Tioga Co) amp Geneseo (Lycoming Co) potential

Eastern Development Area (EDA)

Western Development Area (WDA)

Average gross production(1) ~327 MMcfd Large inventory of Marcellus amp Utica

locations economic at ~$200Mcf Royalty free mineral ownership

enhances well economics Highly contiguous nature drives cost and

operational efficiencies

EampP and Gathering

EDA - 70000 AcresWDA - 715000 Acres

(1) Average EDA and WDA gross production as well as WDA-CRV Utica production (see slide 19) and CovingtonTract 595 Production (see slide 23) is for the quarter ended December 31 2018

17

Western Development AreaMarcellus Core Acreage

vs Utica Appraisal Trend(1)

(1) The Utica Shale lies approximately 5000 feet beneath Senecarsquos WDA Marcellus acreage (2) Appraisal program currently in progress Additional tests are planned Prior Marcellus delineation tests helped define the prospective limits of the Marcellus core acreage planned testing in the Utica expected to do the same

Area of Re-Development ~120 Utica locations on existing Marcellus pads

Key Utica testsPast Marcellus delineation testsUtica Trend (currently evaluating)Marcellus Core Acreage

Large well inventory economic at ~$200 Mcf

Marcellus Shale 600+ well locations remaining 200000 acres

Utica Shale 500+ potential locations across Utica trend evaluating extent of prospective acreage(2)

Fee acreage (no royalty) enhances economics and provides development flexibility

Addition of 2nd WDA drilling rig in Q3 FY18 focused on redevelopment of Clermont-Rich Valley acreage for Utica

Use of existing gathering pad and water infrastructure for Utica drives increased Appalachian program returns

Highly contiguous position drives best in class well costs

Utica test results on trend with other Utica wells in NE Pa

Long-term firm contracts support growth

Boone Mountain Utica Test Well23 Bcf 1000ft

Rich Valley Utica Test Well23 Bcf 1000ft

EampP and Gathering

WDA Highlights

18

WDA Utica Appraisal Results and Initial Type Curve

Tested producing from 17 Utica wells in WDA-CRV Higher pressure significantly enhances well

productivity (Utica ~5000rsquo deeper than Marcellus) Drawdown management is critical restricted

drawdown appears to improve well EURs Early production declines much shallower vs

Marcellus

WDA Utica Appraisal Update

WDA Economics

(1) Internal Rate of Return (IRR) is pre-tax and includes estimated well costs under current cost structure LOEand anticipated gathering tariffs

(2) Initial WDA-CRV Utica type curve based on production results and reservoir expectations from the first 5appraisal wells in the WDA-CRV area

(3) WDA-CRV Utica Average includes all 17 producing wells including 2 wells (pad E09-S) for which drawdownmanagement was not used

EampP and Gathering

EURBcf1000rsquo

Well Cost$M1000rsquo

IRR $225

Break-even15 IRR(1)

Utica - CRV 17 $887 23 $197

Marcellus 10 ndash 11 $643 19 $206

(2)

0

1

2

3

4

5

6

7

8

9

0 12 24 36 48 60 72 84 96 108 120

Cum

ulat

ive

Prod

uctio

n B

CF

Months On

WDA-CRV Utica Wells - Normalized to 9000rsquoUtica Type Curve CRV Utica AverageWDA Marcellus Type Curve Boone Mountain Appraisal WellWDA-CRV Utica Type Curve(2) WDA-CRV Utica Average(3)

0005101520253035

0 2 4 6 8 10 12

19

Transitioning to Utica Development in CRV

WDA-CRV Marcellus(Depth ~7000 feet)

WDA-CRV Utica(Depth ~12000 feet)

Avg CRV Marcellus Production 270 MMcfd

Rem Avg EUR 10-11 Bcf 1000 lat ft

Rem Avg Well Costs = $643lat ft

120+ locations on existing Marcellus pads

Est EURs 17 Bcf 1000 lat ft

Est Development Well Costs = $887lat ft

CRV Utica Transition Plan

1)Finish Marcellus Pads in Development

Drill 24 complete 24 Marcellus wells

2)Continue Optimizing Utica DampC design

Additional optimization wells focusing on

Completion design

Landing zone targets

3)Continue transition to Utica development

Future drilling on multi-well pads

Continue using optimization results to determine development well design

Tailor development plan to use existing pad water and gathering infrastructure

CRV Utica Development Utilizes Existing Pad Water and Gathering Infrastructure to Drive Economics

EampP and Gathering

Rich Valley Utica Test

Existing Line

Leased

Seneca Fee

Producing

FY19 Producer

Development

20

Leveraging Existing Gathering Water and Pad Infrastructure Enhances Returns

Limited New Infrastructure Needed to Support Production Growth

WDA Well Costs(1) WDA Consolidated Economics

Steady activity levels and coordination between upstream and midstream activities

enhance returns provide economies of scale and significant operational flexibility

(1) WDA Marcellus well costs reflect drilling completion amp gathering costs for 192 drilled and completed wells as of 93018 WDA Utica well costs reflect expected drilling completion amp gathering costs for the ~120 well locations in area of redevelopment (2) Internal Rate of Return for Seneca WDA includes estimated well costs under current cost structure and anticipated LOE and Gathering costs Internal Rate of Return for Seneca WDA and Gathering includes expected gathering capital expenditures

through FY 2022 well costs under current cost structure and non-gathering LOE

$685$887

$210

$0

$200

$400

$600

$800

$1000

Marcellus(Historic)

Utica - CRV(Current)

$ la

tera

l foo

t

Drilling amp Completion Gathering

$931$895

10 -11

17

00

03

06

09

12

15

18

Marcellus(Historic)

Utica - CRV(Current)

EUR

10

00 fe

et (B

cf)

60-70 EUR increase expected per well

Total cost per well expected to marginally increase

WDA EURs

At a $225 netback price consolidated Seneca WDA and Gathering IRR is

approximately 33 an uplift of ~12 over standalone Seneca WDA economics(2)

10+ IRR Uplift Expected

21

Integrated Development ndash WDA Gathering System

Current System In-Service

~78 miles of pipe 36220 HP of compression

Current Capacity 470 MMcf per day

Interconnects with TGP 300

Total Investment to Date $301 million

Future Build-Out

FY 2019 CapEx $10 - $15 million

Modest gathering pipeline and compression investment required to support Senecarsquos transition to Utica development

Opportunity for 300 miles of pipelines and five compressor stations (+60000 HP installed) as Senecarsquos drilling activity continues

Deliverability into TGP 300 and NFG Supply

Gathering System Build-Out Tailored to Accommodate Senecarsquos WDA Development

Clermont Gathering System Map

EampP and Gathering

22

WDA Firm Transportation and Sales Capacity

Will continue to layer-in firm sales deals of short and longer duration on TGP 300 to reduce spot exposure

WDA spot realizations track TGP Station 313 pricing typically 10cent - 30cent better than TGP Marcellus Zone 4

Leidy South will provide additional capacity to premium markets (Transco Zone 6)

WDA Exit Capacity Supports Long-term Production Growth and Enhances Consolidated Returns

WDA Contracted Firm Transport and Gross Sales Volumes (MDthd)

Seneca gross production trend

EampP and Gathering

0

100

200

300

400

500

600

700

Niagara Expansion Project (TGP and NFG)FT Capacity 158000 Dthd $067Dth

Firm Sales NYMEX amp DAWN

WDA - TGP 300Firm Sales

Leidy SouthTransco Zone 6

Markets330000 Dthd(1)

Will layer-in firm sales to minimize spot exposure

(1) Portion of Transco Project capacity will likely be utilized by EDA Lycoming County production

WDA Gas Marketing Strategy

23

Eastern Development Area

EDA Acreage ndash 70000 AcresEDA Highlights

1 DCNR Tract 007 (Tioga Co Pa)bull Utica development resumed in third quarter fiscal 2018

bull ~43 remaining Utica locations economic at ~$184 Mcf

bull Gathering Infrastructure NFG Midstream Wellsboro

bull Marcellus Shale expected to provide ~60 additional locations

EampP and Gathering

2

1

3

2 Covington amp DCNR Tract 595 (Tioga Co Pa)bull Marcellus locations fully developed (average daily gross production of ~93 MMcfd)

bull Gathering Infrastructure NFG Midstream Covington

bull Opportunity for future Utica appraisal

3 DCNR Tract 100 amp Gamble (Lycoming Co Pa)bull ~45 remaining Marcellus locations economic at ~$153 Mcfbull Firm Transportation Capacity Atlantic Sunrise (189 MDthd)

bull Gathering Infrastructure NFG Midstream Trout Run

bull Geneseo Shale expected to provide 100-120 additional locations

24

EDA Marcellus Lycoming County Development

Marcellus Development in Lycoming County has Resumed in Connection with Atlantic Sunrise

(1) Includes physical fixed price and NYMEX-based firm sales contracts that do not carry any additional transportation costs

EampP and Gathering

Prolific Marcellus acreage with peer leading well results

~45 remaining Marcellus locations economic at ~$153 Mcf

Near-term development focused on filling Atlantic Sunrise capacity

Existing Line

Leased

Seneca Fee

Producing

FY19 Producer

Development

0

50

100

150

200

250

Gro

ss F

irm V

olum

es (M

Dth

d)

EDA ndash Transco Firm Contracts

Atlantic Sunrise (Transco)FT Capacity 189405 Dthd

Cost $073DthFirm Sales NYMEX+

Transco Firm Sales(1)

25

EDA Utica Tioga County Development

Utica Development in Tioga County ndash Tract 007 Development Resumed in Q3 Fiscal 2018

In-Service November 2016

Lateral Length 4640 ft

30 Day IP 1000 ft 34 MMcfd

Est EUR 1000 ft 24 Bcf

Inventory ~43 locations economic at ~$184 Mcf

Targeting to grow production by 100 to 150 MDthd by fiscal 2020

Expected Development Costs $1045 per lateral ft

Gathering Infrastructure NFG Midstream Wellsboro

Modest build-out required to connect to TGP 300

SalesTakeaway Strategy Layer-in firm sales with shippers holding capacity on TGP 300

(1) Includes physical fixed price and NYMEX-based firm sales contracts that do not carry any additional transportation costs

Tract 007 Utica Appraisal Well Results vs Industry

EampP and Gathering

0

100000

200000

300000

400000

500000

600000

700000

800000

0 100 200 300

Nor

mal

ized

Cum

ulat

ive

(Mcf

10

00rsquo)

Days On ProductionIndustry PotterTioga Wells Seneca DCNR 007 73H

0

25

50

75

100

125

150

Gro

ss F

irm V

olum

es (M

Dth

d)

EDA ndash TGP 300 Firm Contracts

Northeast Supply Diversification ProjectFT Capacity 50000 Dthd $050Dth

Firm Sales NYMEX and DAWN

EDA - TGP 300Firm Sales(1)

26

Integrated Development ndash EDA Gathering Systems

Total Investment (to date) ~$46 million FY 2019 Estimated Capital Expenditures $1 MM - $2 MM Capacity 220000 Dth per day (Interconnect w TGP 300) Production Source Seneca Resources ndash Tioga Co (Covington and DCNR Tract 595)

Total Investment (to date) ~$208 million FY 2019 Estimated Capital Expenditures $25 MM - $35 MM Capacity 466000 to 585000 Dth per day (Interconnect w Transco) Production Source Seneca Resources ndash Lycoming Co (DCNR Tract 100 and Gamble) Future third-party volume opportunities

Covington Gathering System

Trout Run Gathering System

Gathering Segment Supporting Senecarsquos EDA Production amp Future Development

Wellsboro Gathering System Total Investment (to date) ~$14 million FY 2019 Estimated Capital Expenditures $8 MM - $15 MM Capacity up to 200000 Dth per day (Interconnect w TGP 300) Production Source Seneca Resources ndash Tioga Co (DCNR Tract 007)

EampP and Gathering

2

1

3

27

Long-term Contracts Supporting Appalachian Growth

(1) Represents base firm sales contracts not tied to firm transportation capacity Base firm sales are either fixed priced or priced at an index (eg NYMEX ) +- a fixed basis and do not carry any transportation costs

Seneca continues to layer-in firm sales contracts with attractive realizations to lock-in drilling economics and minimize spot exposure ahead of firm transportation in-service dates

EampP and Gathering

-

100

200

300

400

500

600

700

800

900

1000

1100

1200

FY 2019 FY 2020 FY 2021 FY 2022Northeast Supply Diversification 50000 Dthd

Niagara Expansion (TGP amp NFG)Delivery Markets Canada-Dawn amp TETCO

158000 Dthd

Atlantic Sunrise (Transco)Delivery Markets Mid-Atlantic amp Southeast US

189405 Dthd

In-BasinFirm Sales

Contracts(1)

Leidy South (Transco amp NFG)

Transco Zone 6 Markets330000 Dthd

Seneca Appalachia Natural Gas MarketingGross Firm Contract Volumes (Mdthday)

28

297000 ($061)

305200 ($061)

305600 ($063)

337000 ($057)

370800 ($024)

369600 ($060)

367900 ($067)

33400 ($070)74500 ($077) 74900 ($077)

81100 ($078)

85900 ($078)

92000 ($073)

91300 ($073)

178800 $255

196000 $234

195500 $234

149900 $232

129500 $230

105400 $222

104500 $222

~517800 509200 575700 576000 568000 586200 567000 563700

Q1 FY19 Q2 FY19 Q3 FY19 Q4 FY19 Q1 FY20 Q2 FY20 Q3 FY20 Q4 FY20

Fixed Price Dawn NYMEX

Near-term Firm Sales Provide Market amp Price Certainty

Net Contracted Firm Sales Volumes (Dth per day)Contracted Index Price Differentials ($ per Dth)(1)

(1) Values shown represent the weighted average fixed price or contracted fixed differential relative to NYMEX (netback price) less any associated transportation costs

Actual Daily Net

Production

641200 716500 708700 693500 708400 674400 667000Gross Firm Sales Volumes (Dthd)

EampP and Gathering

29

California Oil

Stable Oil Production | Minimal Capital Investment | Steady Free Cash Flow

1

2

3

4

5

Location Formation Production Method

FY18 Daily Production(net Boed)

1 East Coalinga Other Temblor Primary 512

2 North Lost Hills

Tulare amp Etchegoin

PrimarySteam flood 892

3 South Lost Hills

Monterey Shale Primary 1359

4 North Midway Sunset

Tulare amp Potter Steam flood 2786

5 South Midway Sunset Antelope Steam flood 2048

TOTAL WEST DIVISION NET PRODUCTION(1) 7597 Boed

EampP and Gathering

(1) West division net production for FY 2018 excludes production from Sespe field which was divested on May 1 2018

30

California Capital Expenditures vs Production

9341 8863

8033 ~7300

2016 2017 2018 2019

Fiscal Year

West Division Average Net Daily Production (Boe)West Division Annual Capital Expenditures ($ MM)(1)

$38 $38

$26 ~$25

2016 2017 2018 2019

Fiscal YearGuidance Guidance

(1) Seneca West Division capital expenditures includes Seneca corporate and eliminations

EampP and Gathering

Sepse Sale Closed on 5118(reduced production by ~900 boed)

31

Pioneer

South MWSS

Acreage

North MWSS

AcreageSec 17N

4149 51

NMWSS amp 17N SMWSS amp Pioneer East Coalinga

California Development Activities

Modest near-term capital program focused on locations that earn attractive returns in current oil price environment

AampD will focus on low cost bolt-on opportunities

Sec 17 Pioneer and East Coalinga development to provide future growth

North

Project IRRs at $55Bbl(1)

(1) Reflects pre-tax IRRs at a $55Bbl WTI

EampP and Gathering

Seneca West Economics

South

East Coalinga

North

South

32

Fiscal 2019 Production and Price Certainty

~49 Bcfe

210 ndash 230 Bcfe

~114 Bcf

~29 Bcf (2)

16+- Bcf~12 Bcfe

0

40

80

120

160

200

240

YTD FY19Actuals

Fixed Price + FirmSales w Hedge

Firm Sales(Unhedged)

Spot Sales California TotalSeneca

Prod

uctio

n (B

cfe)

(1) Average realized price reflects uplift from financial hedges less fixed differentials under firm sales contracts and any firm transportation costs(2) Indicates firm sales contracts with fixed index differentials but not backed by a matching financial hedge

114 Bcf locked-in realizing net ~$241Mcf (1)

29 Bcf of additional basis protection

Spot production assumed to be sold

at ~$275Mmbtu(winter) and ~$225

(summer)

143 Bcf of Appalachian Production Protected by Firm Sales for Remainder of Year

79 of oil production hedged at $5757 Bbl

EampP and Gathering

33

Strong Hedge Book

Natural Gas Swap amp Fixed Physical Sales Contracts (Millions MMBtu)

(1) Fixed price physical sales exclude joint development partnerrsquos share of fixed price contract WDA volumes as specified under the joint development agreement(2) Reflects percentage of projected production for FY19 hedged at the midpoint of the production guidance range(3) Senecarsquos remainder FY19 Production reflects the total FY19 production guidance of 210-230 Bcfe or 220 Bcfe at the midpoint less Q1 actual production

Crude Oil Swap Contracts (Thousands Bbls)

13591188

732

456

0

500

1000

1500

2000

2500

FY 2019 FY 2020 FY 2021 FY 2022

NYMEX (WTI)

Brent

FY 19 Crude Oil79 Hedged (2)

FY 2019 Remaining Production (3)

EampP and Gathering

1174

709

469 406

0

50

100

150

200

250

FY 2019 FY 2020 FY 2021 FY 2022

NYMEX Swaps

Dawn Swaps

Fixed Price Physical Sales

(1)

FY 2019 Remaining Production (3)

FY 19 Nat Gas71 Hedged (2)

34

$065 $070$070 -$075

FY 2017 FY 2018 FY 2019E

$060 $060 $060

$011 $009 $007$071 $069 ~$067

FY 2017 FY 2018 FY 2019E Gathering amp Transport LOE (non-Gathering) GampA Taxes amp Other

Seneca Operating Costs

Competitive low cost structure in Appalachia and California supports strong cash margins

Gathering fee generates significant revenue stream for affiliated gathering company

Seneca DDampARate

$Mcfe

$054 $054 $056

$042 $038 $031

$034 $034 $030

$017 $014 $015

$147 $140 ~$132

FY 2017 FY 2018 FY 2019E

(1)

$1791$1746~$2050

FY 2017 FY 2018 FY 2019E

Appalachia LOE amp Gathering $Mcfe

California LOE$Boe

Total Seneca Cash OpEx$Mcfe

(1)

(2)

(2)

(1) GampA estimate represents the midpoint of the GampA guidance range of $025 to $035 for fiscal 2019(2) The total of the two LOE components represents the midpoint of the LOE guidance range of $085 to $090 for fiscal 2019

EampP and Gathering

35

Senecarsquos Continuing Commitment to the Environment

Produced Water Recycled in Appalachia

100 70Recycled Water

Used in New Shale Well

Completions

Water and Fluids Management Air Quality and Emissions

Seneca Resources Water OperationsFiscal 2018

Seneca Resources Remains Focused on Minimizing GHG Emissions

The Environmental Partnership

EPA Natural Gas Star Program

Green Completions (all fiscal 2018 wells)

Ultrasonic Leak Detection Technology

Emissions Controls

Rig and Vehicle Fuel Conversion

Integrating Renewable Energy into Operations

EampP and Gathering

36

Pipeline and Storage OverviewNational Fuel Gas Supply Corporation ~ Empire Pipeline Inc

37

Pipeline amp Storage Segment Overview

(1) As of September 30 2018 as disclosed in the Companyrsquos fiscal 2018 form 10-K(2) As of December 31 2017 calculated from National Fuel Gas Supply Corporationrsquos and Empire Pipeline Incrsquos 2017 FERC Form-2 reports respectively

Empire Pipeline Inc

National Fuel Gas Supply Corporation

Empire Pipeline

Supply Corp

Contracted Capacity(1) Firm Transportation 3187 MDth per day Firm Storage 71938 Mdth (fully subscribed)

Rate Base(2) ~$820 million FERC Rate Proceeding Status

Rate case settlement extension approved Nov lsquo15 Rate case filing expected by 73119

Contracted Capacity(1) Firm Transportation 978 MDth per day Firm Storage 3753 Mdth (fully subscribed)

Rate Base(2) ~$249 million FERC Rate Proceeding Status

Rate case settlement in principle reached on 122118 FERC approval pending

New transportation rates went into on 1119

Pipeline amp Storage

38

All Seneca volumes will flow through wholly-owned NFG gathering facilities

FM100 Project - Consolidated Benefit for NFG

330000 Dthd of new transportation capacity from WDA and EDA acreage positions to premium markets

New Transco capacity (Leidy South) 330000 Dthday

Rate(1) competitive with other expansion project rates in Senecarsquos current transportation portfolio

Delivery Point(s) Transco Zone 6 interconnections

Seneca

Lease to Transco of new capacity 330000 Dthday

Estimated annual lease revenues ~$35 million

Target In-Service late calendar year 2021

Supply Corp

Project expected to provide long-term earnings uplift to Seneca Supply Corp and Gathering

Pipeline amp Storage

Gathering

(1) Includes lease of new capacity from Supply Corp to Transco

39

FM100 Project ndash Significant Investment by Supply Corp

Pipeline amp Storage

Estimated Capital Cost $280 million(1)

Facilities (all in Pennsylvania) include Approximately 30 miles of new pipeline 2 new compressor stations (totaling

approximately 37000 HP) New interconnection station and modification

of existing interconnection station Abandonment of approximately 45 miles of

existing pipeline and compressor station Regulatory Process

Pre-filing application submitted to FERC in 2017 for original modernization project

FERC 7(b) 7(c) filing expected summer 2019

(1) Includes expansion and modernization portions of the project

40

Empire North Project

Target In-Service second half of fiscal 2020

Est Capital Cost $145 million

Est Annual Revenues ~$25 million

Receipt Point Jackson (Tioga Co Pa production)

Design Capacity and Delivery Points 175000 Dthd to Chippawa (TCPL interconnect)

30000 Dthd to Hopewell (TGP 200 interconnect)

Customers Fully subscribed (205000 Dthday)

Major Facilities 2 new compressor stations in NY (1) amp Pa (1)

No new pipeline construction

Regulatory Process FERC 7(c) application filed on 21618

FERC Environmental Assessment issued 103018

Pipeline amp Storage

Fully Subscribed Project will Provide 205000 Dthday of Incremental Firm Transportation

41

National Fuel Remains Committed to Northern Access Project

Target In-Service as early as fiscal 2022

Total Cost ~$500MM (~$76MM spent to date)

Estimated Annual Revenues ~$84 million

Delivery Points

350000 Dthd to Chippawa (TCPL interconnect)

140000 Dthd to Hopewell (TGP 200 line)

Regulatory Status

February 3 2017 ndash FERC 7(c) certificate issued

August 6 2018 ndash FERC issued Order finding that NY DEC waived water quality certification

Supply and Empire currently working to finalize remaining federal authorizations

Pipeline amp Storage

To Dawn

42

Continued Expansion of the NFG Supply System

Line N Expansion Opportunities

Line N to Monaca Project Project Firm transportation service to a new ethane

cracker facility being built by Shell Chemical Appalachia LLC

Target In-Service July 2019

Estimated Capital Cost $23 million

Contracted Capacity 133000 Dthday

Additional Line N Expansion Opportunity (Supply OS 221) Project New firm transportation service for on-system

demand

Open Season Capacity Awarded 165000 to foundation shipper Precedent agreement in negotiations

Pipeline amp Storage

43

Pipeline amp Storage Customer Mix

Producer33

LDC42

Marketer10

Outside Pipeline

9

End User6

42 MMDthd

(1) Contracted as of 10312018

Customer Transportation by Shipper Type(1) Affiliated Customer Mix (Contracted Capacity)

66

521

41

34

9579

59

LDCs Producers Marketers FirmStorage

Affiliated Non-Affiliated

Firm Transport

Pipeline amp Storage

44

Utility OverviewNational Fuel Gas Distribution Corporation

45

New York amp Pennsylvania Service Territories

New York

Total Customers(1) 535800ROE 87 (NY PSC Rate Case Order April 2017)Rate Mechanismso Revenue Decouplingo Weather Normalizationo Low Income Rateso Merchant Function Charge (Uncollectibles Adj)o 9010 Sharing (Large Customers)o System Modernization Tracker

Pennsylvania

Total Customers(1) 214400ROE Black Box Settlement (2007)Rate Mechanismso Low Income Rateso Merchant Function Charge

(1) As of September 30 2018

Utility

46

New York Rate Case Outcome

Rate Order Summary

Revenue Requirement $59 million

Rate Base $704 million

Allowed Return on Equity (ROE) 87

Capital Structure 429 equity

Other notable items

New rates became effective 5117

Retains rate mechanisms in place under prior order (revenue decoupling weather normalization merchant function charge 9010 large customer sharing)

No stay-out clause

System modernization tracker for Leak Prone Pipe (LPP)

Earnings sharing started 4118 (5050 sharing starts at earnings in excess of 92)

Article 78 appeal filed on 72817 with oral argument completed in January 2019

On April 20 2017 the New York Public Service Commission issued a Rate Order relating to NFG Distributionrsquos rate case (No 16-G-0257) filed in April 2016

Utility

47

Utility Continues its Significant Investments in Safety

$544$618 $636

$699

$944$980

$809$856

$90-100

$00

$250

$500

$750

$1000

$1250

2015 2016 2017 2018 2019E

Cap

ital E

xpen

ditu

res

($ m

illio

ns)

Fiscal Year

Capital Expenditures for Safety Total Capital Expenditures

Modernization Spending in NY Expected to Grow Gross Margin By $2 MM - $5 MM in FY 2019

(1)

(1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation

Utility

System modernization tracker in NY allows recovery of pipeline replacementcosts which is expected to drive modest gross margin and rate base growth

48

Accelerating Pipeline Replacement amp Modernization

Wrought Iron

Plastic

CoatedBare

120130

146 144159

2014 2015 2016 2017 2018Calendar Year

NY9726 miles

PA4830 miles

No Cast Iron Mains in Pa

Miles of Utility Main Pipeline ReplacedUtility Mains by Material(1)

Wrought Iron

Cast Iron

Plastic

Coated Bare

Utility

(1) All values are reported on a calendar year basis as of December 31 2018

49

A Proven History of Controlling Costs

$200 $189 $195

$166 $166

$31 $31

$197 $197

$0

$50

$100

$150

$200

$250

2015 2016 2017 2018 TTM 123118

Fiscal Year

OampM Expense Non-Service Pension Costs

OampM Expense ($ millions)

Utility

(1)

(1) For purposes of comparability to FY 2015 2016 and 2017 Utility Operation and Maintenance Expense for FY 2018 and the twelve months ended December 31 2018 was adjusted by approximately $314 million and $312 million respectively to include non-service pension costs which were re-classified as Other Income (Deductions) as of October 1 2018 on the Companyrsquos Income Statement See Slide 64 for non-GAAP reconciliation of Adjusted Operation and Maintenance Expense to Operation and Maintenance Expense by segment

50

Consolidated Financial OverviewUpstream I Midstream I Downstream

51

Adjusted Operating Results ($ per share)(1)

Diversified Balanced Earnings and Cash Flows

(1) A reconciliation of Adjusted Operating Results to Earnings per Share by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation(2) Consolidated Adjusted EBITDA includes Energy Marketing and Corporate amp All Other Segments A reconciliation of Adjusted EBITDA to Net Income by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in

the Business is included at the end of this presentation

Adjusted EBITDA ($ millions)(2)

$176 $179

$184 $181

$92 $97

$318 $327

$761 $775

$-

$200

$400

$600

$800

FY 2018 TTM 123118

$059 Utility

$097 Pipeline amp Storage

$057 Gathering

$125 Exploration

amp Production

$334 $345 to $365

$-

$100

$200

$300

$400

FY 2018 FY 2019 Guidance

Rate Regulated

40-45

$728

Rate Regulated

~46

52

$89 $94 $98 $81 $86 $90-$100

$140$230

$114 $95 $93 $120-$150

$138$118

$54$33 $48

$55-$65

$603$557

$99 $246$356

$460-$495

$970 $1001

$366$455

$583

$725-$810

$0

$250

$500

$750

$1000

$1250

2014 2015 2016 2017 2018 2019GuidanceFiscal Year

Exploration amp Production

Gathering

Pipeline amp Storage

Utility

Disciplined Flexible Capital Allocation

(2)

(1) Total Capital Expenditures include Energy Marketing Corporate and All Other A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation (2) FY16 FY17 and FY18 reflects the netting of $157 million $7 million and $17 million respectively of up-front proceeds received from joint development partner for working interest in joint development wells and $21M in intercompany asset transfers in FY18

Capital Expenditures by Segment ($ millions)(1)

53

Maintaining Strong Balance Sheet amp Liquidity

Total Equity49

Total Debt51

$42 Billion Total Capitalizationas of December 31 2018

218 x251 x 245 x 247 x 256 x

2015 2016 2017 2018 TTM 123118Fiscal Year End

Net Debt Adjusted EBITDA(1) Capitalization

Debt Maturity Profile ($MM) Liquidity

Committed Credit FacilitiesShort-term Debt OutstandingAvailable Short-term Credit FacilitiesCash Balance at 123118 Total Liquidity at 123118

$ 750 MM0 MM

750 MM110 MM

$ 860 MM

$500 $549 $500

$300 $300

$0

$200

$400

$600

(1) Net Debt is net of cash and temporary cash investments Reconciliations of Net Debt and Adjusted EBITDA to Net Income are included at the end of this presentation

54

Appendix

55

Safe Harbor For Forward Looking StatementsThis presentation may contain ldquoforward-looking statementsrdquo as defined by the Private Securities Litigation Reform Act of 1995 including statements regarding future prospectsplans objectives goals projections estimates of oil and gas quantities strategies future events or performance and underlying assumptions capital structure anticipatedcapital expenditures completion of construction projects projections for pension and other post-retirement benefit obligations impacts of the adoption of new accounting rulesand possible outcomes of litigation or regulatory proceedings as well as statements that are identified by the use of the words ldquoanticipatesrdquo ldquoestimatesrdquo ldquoexpectsrdquo ldquoforecastsrdquoldquointendsrdquo ldquoplansrdquo ldquopredictsrdquo ldquoprojectsrdquo ldquobelievesrdquo ldquoseeksrdquo ldquowillrdquo ldquomayrdquo and similar expressions Forward-looking statements involve risks and uncertainties which couldcause actual results or outcomes to differ materially from those expressed in the forward-looking statements The Companyrsquos expectations beliefs and projections are expressedin good faith and are believed by the Company to have a reasonable basis but there can be no assurance that managementrsquos expectations beliefs or projections will result or beachieved or accomplished

In addition to other factors the following are important factors that could cause actual results to differ materially from those discussed in the forward-looking statements delaysor changes in costs or plans with respect to Company projects or related projects of other companies including difficulties or delays in obtaining necessary governmentalapprovals permits or orders or in obtaining the cooperation of interconnecting facility operators governmentalregulatory actions initiatives and proceedings including thoseinvolving rate cases (which address among other things target rates of return rate design and retained natural gas) environmentalsafety requirements affiliate relationshipsindustry structure and franchise renewal changes in laws regulations or judicial interpretations to which the Company is subject including those involving derivatives taxessafety employment climate change other environmental matters real property and exploration and production activities such as hydraulic fracturing financial and economicconditions including the availability of credit and occurrences affecting the Companyrsquos ability to obtain financing on acceptable terms for working capital capital expendituresand other investments including any downgrades in the Companyrsquos credit ratings and changes in interest rates and other capital market conditions changes in the price ofnatural gas or oil impairments under the SECrsquos full cost ceiling test for natural gas and oil reserves factors affecting the Companyrsquos ability to successfully identify drill for andproduce economically viable natural gas and oil reserves including among others geology lease availability title disputes weather conditions shortages delays orunavailability of equipment and services required in drilling operations insufficient gathering processing and transportation capacity the need to obtain governmentalapprovals and permits and compliance with environmental laws and regulations increasing health care costs and the resulting effect on health insurance premiums and on theobligation to provide other post-retirement benefits changes in price differentials between similar quantities of natural gas or oil sold at different geographic locations and theeffect of such changes on commodity production revenues and demand for pipeline transportation capacity to or from such locations other changes in price differentialsbetween similar quantities of natural gas or oil having different quality heating value hydrocarbon mix or delivery date the cost and effects of legal and administrative claimsagainst the Company or activist shareholder campaigns to effect changes at the Company uncertainty of oil and gas reserve estimates significant differences between theCompanyrsquos projected and actual production levels for natural gas or oil changes in demographic patterns and weather conditions changes in the availability price oraccounting treatment of derivative financial instruments changes in laws actuarial assumptions the interest rate environment and the return on plantrust assets related to theCompanyrsquos pension and other post-retirement benefits which can affect future funding obligations and costs and plan liabilities changes in economic conditions includingglobal national or regional recessions and their effect on the demand for and customersrsquo ability to pay for the Companyrsquos products and services the creditworthiness orperformance of the Companyrsquos key suppliers customers and counterparties the impact of potential information technology cybersecurity or data security breaches economicdisruptions or uninsured losses resulting from major accidents fires severe weather natural disasters terrorist activities or acts of war significant differences between theCompanyrsquos projected and actual capital expenditures and operating expenses or increasing costs of insurance changes in coverage and the ability to obtain insurance

Forward-looking statements include estimates of oil and gas quantities Proved oil and gas reserves are those quantities of oil and gas which by analysis of geoscience andengineering data can be estimated with reasonable certainty to be economically producible under existing economic conditions operating methods and governmentregulations Other estimates of oil and gas quantities including estimates of probable reserves possible reserves and resource potential are by their nature more speculativethan estimates of proved reserves Accordingly estimates other than proved reserves are subject to substantially greater risk of being actually realized Investors are urged toconsider closely the disclosure in our Form 10-K available at wwwnationalfuelgascom You can also obtain this form on the SECrsquos website at wwwsecgov

For a discussion of the risks set forth above and other factors that could cause actual results to differ materially from results referred to in the forward-looking statements seeldquoRisk Factorsrdquo in the Companyrsquos Form 10-K for the fiscal year ended September 30 2018 and the Forms 10-Q for the quarter ended March 31 2018 June 30 2018 and December31 2018 The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date thereof or to reflect the occurrence ofunanticipated events

Appendix

15

3 rig development program with second rig in WDA focused on Utica

15-20 net production growth expected through fiscal 2022

New EDA Utica development with production expected in Q2 fiscal 2019

Utilize new Atlantic Sunrise firm transportation capacity

Layer-in firm sales to take advantage of attractive regional pricing

Gross production growth will benefit NFGrsquos Gathering segment

Minimal capital investment in California to generate significant cash flow

Growing Production within Disciplined Capital Program

205 194 176 ~16

1406 1541 1605194-214

1611 1735 1781210-230

0

50

100

150

200

250

2016 2017 2018 2019E

$38 $38 $26 ~$25$61

$208$330

$435-$470

$99

$246

$356

$460-$495

$0

$200

$400

$600

2016 2017 2018 2019E

Appalachia West Coast (California)

Near-Term Growth Strategy EampP Net Capital Expenditures ($ millions)(1)

EampP Net Production (Bcfe)

EampP and Gathering

(1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentationFY16 FY17 and FY18 guidance reflects the netting of $157 million $7 million and $17 million respectively of up-front proceeds received from joint development partner for working interest in joint development wells

16

Significant Appalachian Acreage Position

Average gross production ~311 MMcfd

Mostly leased (16-18 royalty) with no significant near-term lease expirations

~90 remaining Marcellus amp Utica locations economic at ~$184Mcf

Additional Marcellus (Tioga Co) amp Geneseo (Lycoming Co) potential

Eastern Development Area (EDA)

Western Development Area (WDA)

Average gross production(1) ~327 MMcfd Large inventory of Marcellus amp Utica

locations economic at ~$200Mcf Royalty free mineral ownership

enhances well economics Highly contiguous nature drives cost and

operational efficiencies

EampP and Gathering

EDA - 70000 AcresWDA - 715000 Acres

(1) Average EDA and WDA gross production as well as WDA-CRV Utica production (see slide 19) and CovingtonTract 595 Production (see slide 23) is for the quarter ended December 31 2018

17

Western Development AreaMarcellus Core Acreage

vs Utica Appraisal Trend(1)

(1) The Utica Shale lies approximately 5000 feet beneath Senecarsquos WDA Marcellus acreage (2) Appraisal program currently in progress Additional tests are planned Prior Marcellus delineation tests helped define the prospective limits of the Marcellus core acreage planned testing in the Utica expected to do the same

Area of Re-Development ~120 Utica locations on existing Marcellus pads

Key Utica testsPast Marcellus delineation testsUtica Trend (currently evaluating)Marcellus Core Acreage

Large well inventory economic at ~$200 Mcf

Marcellus Shale 600+ well locations remaining 200000 acres

Utica Shale 500+ potential locations across Utica trend evaluating extent of prospective acreage(2)

Fee acreage (no royalty) enhances economics and provides development flexibility

Addition of 2nd WDA drilling rig in Q3 FY18 focused on redevelopment of Clermont-Rich Valley acreage for Utica

Use of existing gathering pad and water infrastructure for Utica drives increased Appalachian program returns

Highly contiguous position drives best in class well costs

Utica test results on trend with other Utica wells in NE Pa

Long-term firm contracts support growth

Boone Mountain Utica Test Well23 Bcf 1000ft

Rich Valley Utica Test Well23 Bcf 1000ft

EampP and Gathering

WDA Highlights

18

WDA Utica Appraisal Results and Initial Type Curve

Tested producing from 17 Utica wells in WDA-CRV Higher pressure significantly enhances well

productivity (Utica ~5000rsquo deeper than Marcellus) Drawdown management is critical restricted

drawdown appears to improve well EURs Early production declines much shallower vs

Marcellus

WDA Utica Appraisal Update

WDA Economics

(1) Internal Rate of Return (IRR) is pre-tax and includes estimated well costs under current cost structure LOEand anticipated gathering tariffs

(2) Initial WDA-CRV Utica type curve based on production results and reservoir expectations from the first 5appraisal wells in the WDA-CRV area

(3) WDA-CRV Utica Average includes all 17 producing wells including 2 wells (pad E09-S) for which drawdownmanagement was not used

EampP and Gathering

EURBcf1000rsquo

Well Cost$M1000rsquo

IRR $225

Break-even15 IRR(1)

Utica - CRV 17 $887 23 $197

Marcellus 10 ndash 11 $643 19 $206

(2)

0

1

2

3

4

5

6

7

8

9

0 12 24 36 48 60 72 84 96 108 120

Cum

ulat

ive

Prod

uctio

n B

CF

Months On

WDA-CRV Utica Wells - Normalized to 9000rsquoUtica Type Curve CRV Utica AverageWDA Marcellus Type Curve Boone Mountain Appraisal WellWDA-CRV Utica Type Curve(2) WDA-CRV Utica Average(3)

0005101520253035

0 2 4 6 8 10 12

19

Transitioning to Utica Development in CRV

WDA-CRV Marcellus(Depth ~7000 feet)

WDA-CRV Utica(Depth ~12000 feet)

Avg CRV Marcellus Production 270 MMcfd

Rem Avg EUR 10-11 Bcf 1000 lat ft

Rem Avg Well Costs = $643lat ft

120+ locations on existing Marcellus pads

Est EURs 17 Bcf 1000 lat ft

Est Development Well Costs = $887lat ft

CRV Utica Transition Plan

1)Finish Marcellus Pads in Development

Drill 24 complete 24 Marcellus wells

2)Continue Optimizing Utica DampC design

Additional optimization wells focusing on

Completion design

Landing zone targets

3)Continue transition to Utica development

Future drilling on multi-well pads

Continue using optimization results to determine development well design

Tailor development plan to use existing pad water and gathering infrastructure

CRV Utica Development Utilizes Existing Pad Water and Gathering Infrastructure to Drive Economics

EampP and Gathering

Rich Valley Utica Test

Existing Line

Leased

Seneca Fee

Producing

FY19 Producer

Development

20

Leveraging Existing Gathering Water and Pad Infrastructure Enhances Returns

Limited New Infrastructure Needed to Support Production Growth

WDA Well Costs(1) WDA Consolidated Economics

Steady activity levels and coordination between upstream and midstream activities

enhance returns provide economies of scale and significant operational flexibility

(1) WDA Marcellus well costs reflect drilling completion amp gathering costs for 192 drilled and completed wells as of 93018 WDA Utica well costs reflect expected drilling completion amp gathering costs for the ~120 well locations in area of redevelopment (2) Internal Rate of Return for Seneca WDA includes estimated well costs under current cost structure and anticipated LOE and Gathering costs Internal Rate of Return for Seneca WDA and Gathering includes expected gathering capital expenditures

through FY 2022 well costs under current cost structure and non-gathering LOE

$685$887

$210

$0

$200

$400

$600

$800

$1000

Marcellus(Historic)

Utica - CRV(Current)

$ la

tera

l foo

t

Drilling amp Completion Gathering

$931$895

10 -11

17

00

03

06

09

12

15

18

Marcellus(Historic)

Utica - CRV(Current)

EUR

10

00 fe

et (B

cf)

60-70 EUR increase expected per well

Total cost per well expected to marginally increase

WDA EURs

At a $225 netback price consolidated Seneca WDA and Gathering IRR is

approximately 33 an uplift of ~12 over standalone Seneca WDA economics(2)

10+ IRR Uplift Expected

21

Integrated Development ndash WDA Gathering System

Current System In-Service

~78 miles of pipe 36220 HP of compression

Current Capacity 470 MMcf per day

Interconnects with TGP 300

Total Investment to Date $301 million

Future Build-Out

FY 2019 CapEx $10 - $15 million

Modest gathering pipeline and compression investment required to support Senecarsquos transition to Utica development

Opportunity for 300 miles of pipelines and five compressor stations (+60000 HP installed) as Senecarsquos drilling activity continues

Deliverability into TGP 300 and NFG Supply

Gathering System Build-Out Tailored to Accommodate Senecarsquos WDA Development

Clermont Gathering System Map

EampP and Gathering

22

WDA Firm Transportation and Sales Capacity

Will continue to layer-in firm sales deals of short and longer duration on TGP 300 to reduce spot exposure

WDA spot realizations track TGP Station 313 pricing typically 10cent - 30cent better than TGP Marcellus Zone 4

Leidy South will provide additional capacity to premium markets (Transco Zone 6)

WDA Exit Capacity Supports Long-term Production Growth and Enhances Consolidated Returns

WDA Contracted Firm Transport and Gross Sales Volumes (MDthd)

Seneca gross production trend

EampP and Gathering

0

100

200

300

400

500

600

700

Niagara Expansion Project (TGP and NFG)FT Capacity 158000 Dthd $067Dth

Firm Sales NYMEX amp DAWN

WDA - TGP 300Firm Sales

Leidy SouthTransco Zone 6

Markets330000 Dthd(1)

Will layer-in firm sales to minimize spot exposure

(1) Portion of Transco Project capacity will likely be utilized by EDA Lycoming County production

WDA Gas Marketing Strategy

23

Eastern Development Area

EDA Acreage ndash 70000 AcresEDA Highlights

1 DCNR Tract 007 (Tioga Co Pa)bull Utica development resumed in third quarter fiscal 2018

bull ~43 remaining Utica locations economic at ~$184 Mcf

bull Gathering Infrastructure NFG Midstream Wellsboro

bull Marcellus Shale expected to provide ~60 additional locations

EampP and Gathering

2

1

3

2 Covington amp DCNR Tract 595 (Tioga Co Pa)bull Marcellus locations fully developed (average daily gross production of ~93 MMcfd)

bull Gathering Infrastructure NFG Midstream Covington

bull Opportunity for future Utica appraisal

3 DCNR Tract 100 amp Gamble (Lycoming Co Pa)bull ~45 remaining Marcellus locations economic at ~$153 Mcfbull Firm Transportation Capacity Atlantic Sunrise (189 MDthd)

bull Gathering Infrastructure NFG Midstream Trout Run

bull Geneseo Shale expected to provide 100-120 additional locations

24

EDA Marcellus Lycoming County Development

Marcellus Development in Lycoming County has Resumed in Connection with Atlantic Sunrise

(1) Includes physical fixed price and NYMEX-based firm sales contracts that do not carry any additional transportation costs

EampP and Gathering

Prolific Marcellus acreage with peer leading well results

~45 remaining Marcellus locations economic at ~$153 Mcf

Near-term development focused on filling Atlantic Sunrise capacity

Existing Line

Leased

Seneca Fee

Producing

FY19 Producer

Development

0

50

100

150

200

250

Gro

ss F

irm V

olum

es (M

Dth

d)

EDA ndash Transco Firm Contracts

Atlantic Sunrise (Transco)FT Capacity 189405 Dthd

Cost $073DthFirm Sales NYMEX+

Transco Firm Sales(1)

25

EDA Utica Tioga County Development

Utica Development in Tioga County ndash Tract 007 Development Resumed in Q3 Fiscal 2018

In-Service November 2016

Lateral Length 4640 ft

30 Day IP 1000 ft 34 MMcfd

Est EUR 1000 ft 24 Bcf

Inventory ~43 locations economic at ~$184 Mcf

Targeting to grow production by 100 to 150 MDthd by fiscal 2020

Expected Development Costs $1045 per lateral ft

Gathering Infrastructure NFG Midstream Wellsboro

Modest build-out required to connect to TGP 300

SalesTakeaway Strategy Layer-in firm sales with shippers holding capacity on TGP 300

(1) Includes physical fixed price and NYMEX-based firm sales contracts that do not carry any additional transportation costs

Tract 007 Utica Appraisal Well Results vs Industry

EampP and Gathering

0

100000

200000

300000

400000

500000

600000

700000

800000

0 100 200 300

Nor

mal

ized

Cum

ulat

ive

(Mcf

10

00rsquo)

Days On ProductionIndustry PotterTioga Wells Seneca DCNR 007 73H

0

25

50

75

100

125

150

Gro

ss F

irm V

olum

es (M

Dth

d)

EDA ndash TGP 300 Firm Contracts

Northeast Supply Diversification ProjectFT Capacity 50000 Dthd $050Dth

Firm Sales NYMEX and DAWN

EDA - TGP 300Firm Sales(1)

26

Integrated Development ndash EDA Gathering Systems

Total Investment (to date) ~$46 million FY 2019 Estimated Capital Expenditures $1 MM - $2 MM Capacity 220000 Dth per day (Interconnect w TGP 300) Production Source Seneca Resources ndash Tioga Co (Covington and DCNR Tract 595)

Total Investment (to date) ~$208 million FY 2019 Estimated Capital Expenditures $25 MM - $35 MM Capacity 466000 to 585000 Dth per day (Interconnect w Transco) Production Source Seneca Resources ndash Lycoming Co (DCNR Tract 100 and Gamble) Future third-party volume opportunities

Covington Gathering System

Trout Run Gathering System

Gathering Segment Supporting Senecarsquos EDA Production amp Future Development

Wellsboro Gathering System Total Investment (to date) ~$14 million FY 2019 Estimated Capital Expenditures $8 MM - $15 MM Capacity up to 200000 Dth per day (Interconnect w TGP 300) Production Source Seneca Resources ndash Tioga Co (DCNR Tract 007)

EampP and Gathering

2

1

3

27

Long-term Contracts Supporting Appalachian Growth

(1) Represents base firm sales contracts not tied to firm transportation capacity Base firm sales are either fixed priced or priced at an index (eg NYMEX ) +- a fixed basis and do not carry any transportation costs

Seneca continues to layer-in firm sales contracts with attractive realizations to lock-in drilling economics and minimize spot exposure ahead of firm transportation in-service dates

EampP and Gathering

-

100

200

300

400

500

600

700

800

900

1000

1100

1200

FY 2019 FY 2020 FY 2021 FY 2022Northeast Supply Diversification 50000 Dthd

Niagara Expansion (TGP amp NFG)Delivery Markets Canada-Dawn amp TETCO

158000 Dthd

Atlantic Sunrise (Transco)Delivery Markets Mid-Atlantic amp Southeast US

189405 Dthd

In-BasinFirm Sales

Contracts(1)

Leidy South (Transco amp NFG)

Transco Zone 6 Markets330000 Dthd

Seneca Appalachia Natural Gas MarketingGross Firm Contract Volumes (Mdthday)

28

297000 ($061)

305200 ($061)

305600 ($063)

337000 ($057)

370800 ($024)

369600 ($060)

367900 ($067)

33400 ($070)74500 ($077) 74900 ($077)

81100 ($078)

85900 ($078)

92000 ($073)

91300 ($073)

178800 $255

196000 $234

195500 $234

149900 $232

129500 $230

105400 $222

104500 $222

~517800 509200 575700 576000 568000 586200 567000 563700

Q1 FY19 Q2 FY19 Q3 FY19 Q4 FY19 Q1 FY20 Q2 FY20 Q3 FY20 Q4 FY20

Fixed Price Dawn NYMEX

Near-term Firm Sales Provide Market amp Price Certainty

Net Contracted Firm Sales Volumes (Dth per day)Contracted Index Price Differentials ($ per Dth)(1)

(1) Values shown represent the weighted average fixed price or contracted fixed differential relative to NYMEX (netback price) less any associated transportation costs

Actual Daily Net

Production

641200 716500 708700 693500 708400 674400 667000Gross Firm Sales Volumes (Dthd)

EampP and Gathering

29

California Oil

Stable Oil Production | Minimal Capital Investment | Steady Free Cash Flow

1

2

3

4

5

Location Formation Production Method

FY18 Daily Production(net Boed)

1 East Coalinga Other Temblor Primary 512

2 North Lost Hills

Tulare amp Etchegoin

PrimarySteam flood 892

3 South Lost Hills

Monterey Shale Primary 1359

4 North Midway Sunset

Tulare amp Potter Steam flood 2786

5 South Midway Sunset Antelope Steam flood 2048

TOTAL WEST DIVISION NET PRODUCTION(1) 7597 Boed

EampP and Gathering

(1) West division net production for FY 2018 excludes production from Sespe field which was divested on May 1 2018

30

California Capital Expenditures vs Production

9341 8863

8033 ~7300

2016 2017 2018 2019

Fiscal Year

West Division Average Net Daily Production (Boe)West Division Annual Capital Expenditures ($ MM)(1)

$38 $38

$26 ~$25

2016 2017 2018 2019

Fiscal YearGuidance Guidance

(1) Seneca West Division capital expenditures includes Seneca corporate and eliminations

EampP and Gathering

Sepse Sale Closed on 5118(reduced production by ~900 boed)

31

Pioneer

South MWSS

Acreage

North MWSS

AcreageSec 17N

4149 51

NMWSS amp 17N SMWSS amp Pioneer East Coalinga

California Development Activities

Modest near-term capital program focused on locations that earn attractive returns in current oil price environment

AampD will focus on low cost bolt-on opportunities

Sec 17 Pioneer and East Coalinga development to provide future growth

North

Project IRRs at $55Bbl(1)

(1) Reflects pre-tax IRRs at a $55Bbl WTI

EampP and Gathering

Seneca West Economics

South

East Coalinga

North

South

32

Fiscal 2019 Production and Price Certainty

~49 Bcfe

210 ndash 230 Bcfe

~114 Bcf

~29 Bcf (2)

16+- Bcf~12 Bcfe

0

40

80

120

160

200

240

YTD FY19Actuals

Fixed Price + FirmSales w Hedge

Firm Sales(Unhedged)

Spot Sales California TotalSeneca

Prod

uctio

n (B

cfe)

(1) Average realized price reflects uplift from financial hedges less fixed differentials under firm sales contracts and any firm transportation costs(2) Indicates firm sales contracts with fixed index differentials but not backed by a matching financial hedge

114 Bcf locked-in realizing net ~$241Mcf (1)

29 Bcf of additional basis protection

Spot production assumed to be sold

at ~$275Mmbtu(winter) and ~$225

(summer)

143 Bcf of Appalachian Production Protected by Firm Sales for Remainder of Year

79 of oil production hedged at $5757 Bbl

EampP and Gathering

33

Strong Hedge Book

Natural Gas Swap amp Fixed Physical Sales Contracts (Millions MMBtu)

(1) Fixed price physical sales exclude joint development partnerrsquos share of fixed price contract WDA volumes as specified under the joint development agreement(2) Reflects percentage of projected production for FY19 hedged at the midpoint of the production guidance range(3) Senecarsquos remainder FY19 Production reflects the total FY19 production guidance of 210-230 Bcfe or 220 Bcfe at the midpoint less Q1 actual production

Crude Oil Swap Contracts (Thousands Bbls)

13591188

732

456

0

500

1000

1500

2000

2500

FY 2019 FY 2020 FY 2021 FY 2022

NYMEX (WTI)

Brent

FY 19 Crude Oil79 Hedged (2)

FY 2019 Remaining Production (3)

EampP and Gathering

1174

709

469 406

0

50

100

150

200

250

FY 2019 FY 2020 FY 2021 FY 2022

NYMEX Swaps

Dawn Swaps

Fixed Price Physical Sales

(1)

FY 2019 Remaining Production (3)

FY 19 Nat Gas71 Hedged (2)

34

$065 $070$070 -$075

FY 2017 FY 2018 FY 2019E

$060 $060 $060

$011 $009 $007$071 $069 ~$067

FY 2017 FY 2018 FY 2019E Gathering amp Transport LOE (non-Gathering) GampA Taxes amp Other

Seneca Operating Costs

Competitive low cost structure in Appalachia and California supports strong cash margins

Gathering fee generates significant revenue stream for affiliated gathering company

Seneca DDampARate

$Mcfe

$054 $054 $056

$042 $038 $031

$034 $034 $030

$017 $014 $015

$147 $140 ~$132

FY 2017 FY 2018 FY 2019E

(1)

$1791$1746~$2050

FY 2017 FY 2018 FY 2019E

Appalachia LOE amp Gathering $Mcfe

California LOE$Boe

Total Seneca Cash OpEx$Mcfe

(1)

(2)

(2)

(1) GampA estimate represents the midpoint of the GampA guidance range of $025 to $035 for fiscal 2019(2) The total of the two LOE components represents the midpoint of the LOE guidance range of $085 to $090 for fiscal 2019

EampP and Gathering

35

Senecarsquos Continuing Commitment to the Environment

Produced Water Recycled in Appalachia

100 70Recycled Water

Used in New Shale Well

Completions

Water and Fluids Management Air Quality and Emissions

Seneca Resources Water OperationsFiscal 2018

Seneca Resources Remains Focused on Minimizing GHG Emissions

The Environmental Partnership

EPA Natural Gas Star Program

Green Completions (all fiscal 2018 wells)

Ultrasonic Leak Detection Technology

Emissions Controls

Rig and Vehicle Fuel Conversion

Integrating Renewable Energy into Operations

EampP and Gathering

36

Pipeline and Storage OverviewNational Fuel Gas Supply Corporation ~ Empire Pipeline Inc

37

Pipeline amp Storage Segment Overview

(1) As of September 30 2018 as disclosed in the Companyrsquos fiscal 2018 form 10-K(2) As of December 31 2017 calculated from National Fuel Gas Supply Corporationrsquos and Empire Pipeline Incrsquos 2017 FERC Form-2 reports respectively

Empire Pipeline Inc

National Fuel Gas Supply Corporation

Empire Pipeline

Supply Corp

Contracted Capacity(1) Firm Transportation 3187 MDth per day Firm Storage 71938 Mdth (fully subscribed)

Rate Base(2) ~$820 million FERC Rate Proceeding Status

Rate case settlement extension approved Nov lsquo15 Rate case filing expected by 73119

Contracted Capacity(1) Firm Transportation 978 MDth per day Firm Storage 3753 Mdth (fully subscribed)

Rate Base(2) ~$249 million FERC Rate Proceeding Status

Rate case settlement in principle reached on 122118 FERC approval pending

New transportation rates went into on 1119

Pipeline amp Storage

38

All Seneca volumes will flow through wholly-owned NFG gathering facilities

FM100 Project - Consolidated Benefit for NFG

330000 Dthd of new transportation capacity from WDA and EDA acreage positions to premium markets

New Transco capacity (Leidy South) 330000 Dthday

Rate(1) competitive with other expansion project rates in Senecarsquos current transportation portfolio

Delivery Point(s) Transco Zone 6 interconnections

Seneca

Lease to Transco of new capacity 330000 Dthday

Estimated annual lease revenues ~$35 million

Target In-Service late calendar year 2021

Supply Corp

Project expected to provide long-term earnings uplift to Seneca Supply Corp and Gathering

Pipeline amp Storage

Gathering

(1) Includes lease of new capacity from Supply Corp to Transco

39

FM100 Project ndash Significant Investment by Supply Corp

Pipeline amp Storage

Estimated Capital Cost $280 million(1)

Facilities (all in Pennsylvania) include Approximately 30 miles of new pipeline 2 new compressor stations (totaling

approximately 37000 HP) New interconnection station and modification

of existing interconnection station Abandonment of approximately 45 miles of

existing pipeline and compressor station Regulatory Process

Pre-filing application submitted to FERC in 2017 for original modernization project

FERC 7(b) 7(c) filing expected summer 2019

(1) Includes expansion and modernization portions of the project

40

Empire North Project

Target In-Service second half of fiscal 2020

Est Capital Cost $145 million

Est Annual Revenues ~$25 million

Receipt Point Jackson (Tioga Co Pa production)

Design Capacity and Delivery Points 175000 Dthd to Chippawa (TCPL interconnect)

30000 Dthd to Hopewell (TGP 200 interconnect)

Customers Fully subscribed (205000 Dthday)

Major Facilities 2 new compressor stations in NY (1) amp Pa (1)

No new pipeline construction

Regulatory Process FERC 7(c) application filed on 21618

FERC Environmental Assessment issued 103018

Pipeline amp Storage

Fully Subscribed Project will Provide 205000 Dthday of Incremental Firm Transportation

41

National Fuel Remains Committed to Northern Access Project

Target In-Service as early as fiscal 2022

Total Cost ~$500MM (~$76MM spent to date)

Estimated Annual Revenues ~$84 million

Delivery Points

350000 Dthd to Chippawa (TCPL interconnect)

140000 Dthd to Hopewell (TGP 200 line)

Regulatory Status

February 3 2017 ndash FERC 7(c) certificate issued

August 6 2018 ndash FERC issued Order finding that NY DEC waived water quality certification

Supply and Empire currently working to finalize remaining federal authorizations

Pipeline amp Storage

To Dawn

42

Continued Expansion of the NFG Supply System

Line N Expansion Opportunities

Line N to Monaca Project Project Firm transportation service to a new ethane

cracker facility being built by Shell Chemical Appalachia LLC

Target In-Service July 2019

Estimated Capital Cost $23 million

Contracted Capacity 133000 Dthday

Additional Line N Expansion Opportunity (Supply OS 221) Project New firm transportation service for on-system

demand

Open Season Capacity Awarded 165000 to foundation shipper Precedent agreement in negotiations

Pipeline amp Storage

43

Pipeline amp Storage Customer Mix

Producer33

LDC42

Marketer10

Outside Pipeline

9

End User6

42 MMDthd

(1) Contracted as of 10312018

Customer Transportation by Shipper Type(1) Affiliated Customer Mix (Contracted Capacity)

66

521

41

34

9579

59

LDCs Producers Marketers FirmStorage

Affiliated Non-Affiliated

Firm Transport

Pipeline amp Storage

44

Utility OverviewNational Fuel Gas Distribution Corporation

45

New York amp Pennsylvania Service Territories

New York

Total Customers(1) 535800ROE 87 (NY PSC Rate Case Order April 2017)Rate Mechanismso Revenue Decouplingo Weather Normalizationo Low Income Rateso Merchant Function Charge (Uncollectibles Adj)o 9010 Sharing (Large Customers)o System Modernization Tracker

Pennsylvania

Total Customers(1) 214400ROE Black Box Settlement (2007)Rate Mechanismso Low Income Rateso Merchant Function Charge

(1) As of September 30 2018

Utility

46

New York Rate Case Outcome

Rate Order Summary

Revenue Requirement $59 million

Rate Base $704 million

Allowed Return on Equity (ROE) 87

Capital Structure 429 equity

Other notable items

New rates became effective 5117

Retains rate mechanisms in place under prior order (revenue decoupling weather normalization merchant function charge 9010 large customer sharing)

No stay-out clause

System modernization tracker for Leak Prone Pipe (LPP)

Earnings sharing started 4118 (5050 sharing starts at earnings in excess of 92)

Article 78 appeal filed on 72817 with oral argument completed in January 2019

On April 20 2017 the New York Public Service Commission issued a Rate Order relating to NFG Distributionrsquos rate case (No 16-G-0257) filed in April 2016

Utility

47

Utility Continues its Significant Investments in Safety

$544$618 $636

$699

$944$980

$809$856

$90-100

$00

$250

$500

$750

$1000

$1250

2015 2016 2017 2018 2019E

Cap

ital E

xpen

ditu

res

($ m

illio

ns)

Fiscal Year

Capital Expenditures for Safety Total Capital Expenditures

Modernization Spending in NY Expected to Grow Gross Margin By $2 MM - $5 MM in FY 2019

(1)

(1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation

Utility

System modernization tracker in NY allows recovery of pipeline replacementcosts which is expected to drive modest gross margin and rate base growth

48

Accelerating Pipeline Replacement amp Modernization

Wrought Iron

Plastic

CoatedBare

120130

146 144159

2014 2015 2016 2017 2018Calendar Year

NY9726 miles

PA4830 miles

No Cast Iron Mains in Pa

Miles of Utility Main Pipeline ReplacedUtility Mains by Material(1)

Wrought Iron

Cast Iron

Plastic

Coated Bare

Utility

(1) All values are reported on a calendar year basis as of December 31 2018

49

A Proven History of Controlling Costs

$200 $189 $195

$166 $166

$31 $31

$197 $197

$0

$50

$100

$150

$200

$250

2015 2016 2017 2018 TTM 123118

Fiscal Year

OampM Expense Non-Service Pension Costs

OampM Expense ($ millions)

Utility

(1)

(1) For purposes of comparability to FY 2015 2016 and 2017 Utility Operation and Maintenance Expense for FY 2018 and the twelve months ended December 31 2018 was adjusted by approximately $314 million and $312 million respectively to include non-service pension costs which were re-classified as Other Income (Deductions) as of October 1 2018 on the Companyrsquos Income Statement See Slide 64 for non-GAAP reconciliation of Adjusted Operation and Maintenance Expense to Operation and Maintenance Expense by segment

50

Consolidated Financial OverviewUpstream I Midstream I Downstream

51

Adjusted Operating Results ($ per share)(1)

Diversified Balanced Earnings and Cash Flows

(1) A reconciliation of Adjusted Operating Results to Earnings per Share by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation(2) Consolidated Adjusted EBITDA includes Energy Marketing and Corporate amp All Other Segments A reconciliation of Adjusted EBITDA to Net Income by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in

the Business is included at the end of this presentation

Adjusted EBITDA ($ millions)(2)

$176 $179

$184 $181

$92 $97

$318 $327

$761 $775

$-

$200

$400

$600

$800

FY 2018 TTM 123118

$059 Utility

$097 Pipeline amp Storage

$057 Gathering

$125 Exploration

amp Production

$334 $345 to $365

$-

$100

$200

$300

$400

FY 2018 FY 2019 Guidance

Rate Regulated

40-45

$728

Rate Regulated

~46

52

$89 $94 $98 $81 $86 $90-$100

$140$230

$114 $95 $93 $120-$150

$138$118

$54$33 $48

$55-$65

$603$557

$99 $246$356

$460-$495

$970 $1001

$366$455

$583

$725-$810

$0

$250

$500

$750

$1000

$1250

2014 2015 2016 2017 2018 2019GuidanceFiscal Year

Exploration amp Production

Gathering

Pipeline amp Storage

Utility

Disciplined Flexible Capital Allocation

(2)

(1) Total Capital Expenditures include Energy Marketing Corporate and All Other A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation (2) FY16 FY17 and FY18 reflects the netting of $157 million $7 million and $17 million respectively of up-front proceeds received from joint development partner for working interest in joint development wells and $21M in intercompany asset transfers in FY18

Capital Expenditures by Segment ($ millions)(1)

53

Maintaining Strong Balance Sheet amp Liquidity

Total Equity49

Total Debt51

$42 Billion Total Capitalizationas of December 31 2018

218 x251 x 245 x 247 x 256 x

2015 2016 2017 2018 TTM 123118Fiscal Year End

Net Debt Adjusted EBITDA(1) Capitalization

Debt Maturity Profile ($MM) Liquidity

Committed Credit FacilitiesShort-term Debt OutstandingAvailable Short-term Credit FacilitiesCash Balance at 123118 Total Liquidity at 123118

$ 750 MM0 MM

750 MM110 MM

$ 860 MM

$500 $549 $500

$300 $300

$0

$200

$400

$600

(1) Net Debt is net of cash and temporary cash investments Reconciliations of Net Debt and Adjusted EBITDA to Net Income are included at the end of this presentation

54

Appendix

55

Safe Harbor For Forward Looking StatementsThis presentation may contain ldquoforward-looking statementsrdquo as defined by the Private Securities Litigation Reform Act of 1995 including statements regarding future prospectsplans objectives goals projections estimates of oil and gas quantities strategies future events or performance and underlying assumptions capital structure anticipatedcapital expenditures completion of construction projects projections for pension and other post-retirement benefit obligations impacts of the adoption of new accounting rulesand possible outcomes of litigation or regulatory proceedings as well as statements that are identified by the use of the words ldquoanticipatesrdquo ldquoestimatesrdquo ldquoexpectsrdquo ldquoforecastsrdquoldquointendsrdquo ldquoplansrdquo ldquopredictsrdquo ldquoprojectsrdquo ldquobelievesrdquo ldquoseeksrdquo ldquowillrdquo ldquomayrdquo and similar expressions Forward-looking statements involve risks and uncertainties which couldcause actual results or outcomes to differ materially from those expressed in the forward-looking statements The Companyrsquos expectations beliefs and projections are expressedin good faith and are believed by the Company to have a reasonable basis but there can be no assurance that managementrsquos expectations beliefs or projections will result or beachieved or accomplished

In addition to other factors the following are important factors that could cause actual results to differ materially from those discussed in the forward-looking statements delaysor changes in costs or plans with respect to Company projects or related projects of other companies including difficulties or delays in obtaining necessary governmentalapprovals permits or orders or in obtaining the cooperation of interconnecting facility operators governmentalregulatory actions initiatives and proceedings including thoseinvolving rate cases (which address among other things target rates of return rate design and retained natural gas) environmentalsafety requirements affiliate relationshipsindustry structure and franchise renewal changes in laws regulations or judicial interpretations to which the Company is subject including those involving derivatives taxessafety employment climate change other environmental matters real property and exploration and production activities such as hydraulic fracturing financial and economicconditions including the availability of credit and occurrences affecting the Companyrsquos ability to obtain financing on acceptable terms for working capital capital expendituresand other investments including any downgrades in the Companyrsquos credit ratings and changes in interest rates and other capital market conditions changes in the price ofnatural gas or oil impairments under the SECrsquos full cost ceiling test for natural gas and oil reserves factors affecting the Companyrsquos ability to successfully identify drill for andproduce economically viable natural gas and oil reserves including among others geology lease availability title disputes weather conditions shortages delays orunavailability of equipment and services required in drilling operations insufficient gathering processing and transportation capacity the need to obtain governmentalapprovals and permits and compliance with environmental laws and regulations increasing health care costs and the resulting effect on health insurance premiums and on theobligation to provide other post-retirement benefits changes in price differentials between similar quantities of natural gas or oil sold at different geographic locations and theeffect of such changes on commodity production revenues and demand for pipeline transportation capacity to or from such locations other changes in price differentialsbetween similar quantities of natural gas or oil having different quality heating value hydrocarbon mix or delivery date the cost and effects of legal and administrative claimsagainst the Company or activist shareholder campaigns to effect changes at the Company uncertainty of oil and gas reserve estimates significant differences between theCompanyrsquos projected and actual production levels for natural gas or oil changes in demographic patterns and weather conditions changes in the availability price oraccounting treatment of derivative financial instruments changes in laws actuarial assumptions the interest rate environment and the return on plantrust assets related to theCompanyrsquos pension and other post-retirement benefits which can affect future funding obligations and costs and plan liabilities changes in economic conditions includingglobal national or regional recessions and their effect on the demand for and customersrsquo ability to pay for the Companyrsquos products and services the creditworthiness orperformance of the Companyrsquos key suppliers customers and counterparties the impact of potential information technology cybersecurity or data security breaches economicdisruptions or uninsured losses resulting from major accidents fires severe weather natural disasters terrorist activities or acts of war significant differences between theCompanyrsquos projected and actual capital expenditures and operating expenses or increasing costs of insurance changes in coverage and the ability to obtain insurance

Forward-looking statements include estimates of oil and gas quantities Proved oil and gas reserves are those quantities of oil and gas which by analysis of geoscience andengineering data can be estimated with reasonable certainty to be economically producible under existing economic conditions operating methods and governmentregulations Other estimates of oil and gas quantities including estimates of probable reserves possible reserves and resource potential are by their nature more speculativethan estimates of proved reserves Accordingly estimates other than proved reserves are subject to substantially greater risk of being actually realized Investors are urged toconsider closely the disclosure in our Form 10-K available at wwwnationalfuelgascom You can also obtain this form on the SECrsquos website at wwwsecgov

For a discussion of the risks set forth above and other factors that could cause actual results to differ materially from results referred to in the forward-looking statements seeldquoRisk Factorsrdquo in the Companyrsquos Form 10-K for the fiscal year ended September 30 2018 and the Forms 10-Q for the quarter ended March 31 2018 June 30 2018 and December31 2018 The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date thereof or to reflect the occurrence ofunanticipated events

Appendix

16

Significant Appalachian Acreage Position

Average gross production ~311 MMcfd

Mostly leased (16-18 royalty) with no significant near-term lease expirations

~90 remaining Marcellus amp Utica locations economic at ~$184Mcf

Additional Marcellus (Tioga Co) amp Geneseo (Lycoming Co) potential

Eastern Development Area (EDA)

Western Development Area (WDA)

Average gross production(1) ~327 MMcfd Large inventory of Marcellus amp Utica

locations economic at ~$200Mcf Royalty free mineral ownership

enhances well economics Highly contiguous nature drives cost and

operational efficiencies

EampP and Gathering

EDA - 70000 AcresWDA - 715000 Acres

(1) Average EDA and WDA gross production as well as WDA-CRV Utica production (see slide 19) and CovingtonTract 595 Production (see slide 23) is for the quarter ended December 31 2018

17

Western Development AreaMarcellus Core Acreage

vs Utica Appraisal Trend(1)

(1) The Utica Shale lies approximately 5000 feet beneath Senecarsquos WDA Marcellus acreage (2) Appraisal program currently in progress Additional tests are planned Prior Marcellus delineation tests helped define the prospective limits of the Marcellus core acreage planned testing in the Utica expected to do the same

Area of Re-Development ~120 Utica locations on existing Marcellus pads

Key Utica testsPast Marcellus delineation testsUtica Trend (currently evaluating)Marcellus Core Acreage

Large well inventory economic at ~$200 Mcf

Marcellus Shale 600+ well locations remaining 200000 acres

Utica Shale 500+ potential locations across Utica trend evaluating extent of prospective acreage(2)

Fee acreage (no royalty) enhances economics and provides development flexibility

Addition of 2nd WDA drilling rig in Q3 FY18 focused on redevelopment of Clermont-Rich Valley acreage for Utica

Use of existing gathering pad and water infrastructure for Utica drives increased Appalachian program returns

Highly contiguous position drives best in class well costs

Utica test results on trend with other Utica wells in NE Pa

Long-term firm contracts support growth

Boone Mountain Utica Test Well23 Bcf 1000ft

Rich Valley Utica Test Well23 Bcf 1000ft

EampP and Gathering

WDA Highlights

18

WDA Utica Appraisal Results and Initial Type Curve

Tested producing from 17 Utica wells in WDA-CRV Higher pressure significantly enhances well

productivity (Utica ~5000rsquo deeper than Marcellus) Drawdown management is critical restricted

drawdown appears to improve well EURs Early production declines much shallower vs

Marcellus

WDA Utica Appraisal Update

WDA Economics

(1) Internal Rate of Return (IRR) is pre-tax and includes estimated well costs under current cost structure LOEand anticipated gathering tariffs

(2) Initial WDA-CRV Utica type curve based on production results and reservoir expectations from the first 5appraisal wells in the WDA-CRV area

(3) WDA-CRV Utica Average includes all 17 producing wells including 2 wells (pad E09-S) for which drawdownmanagement was not used

EampP and Gathering

EURBcf1000rsquo

Well Cost$M1000rsquo

IRR $225

Break-even15 IRR(1)

Utica - CRV 17 $887 23 $197

Marcellus 10 ndash 11 $643 19 $206

(2)

0

1

2

3

4

5

6

7

8

9

0 12 24 36 48 60 72 84 96 108 120

Cum

ulat

ive

Prod

uctio

n B

CF

Months On

WDA-CRV Utica Wells - Normalized to 9000rsquoUtica Type Curve CRV Utica AverageWDA Marcellus Type Curve Boone Mountain Appraisal WellWDA-CRV Utica Type Curve(2) WDA-CRV Utica Average(3)

0005101520253035

0 2 4 6 8 10 12

19

Transitioning to Utica Development in CRV

WDA-CRV Marcellus(Depth ~7000 feet)

WDA-CRV Utica(Depth ~12000 feet)

Avg CRV Marcellus Production 270 MMcfd

Rem Avg EUR 10-11 Bcf 1000 lat ft

Rem Avg Well Costs = $643lat ft

120+ locations on existing Marcellus pads

Est EURs 17 Bcf 1000 lat ft

Est Development Well Costs = $887lat ft

CRV Utica Transition Plan

1)Finish Marcellus Pads in Development

Drill 24 complete 24 Marcellus wells

2)Continue Optimizing Utica DampC design

Additional optimization wells focusing on

Completion design

Landing zone targets

3)Continue transition to Utica development

Future drilling on multi-well pads

Continue using optimization results to determine development well design

Tailor development plan to use existing pad water and gathering infrastructure

CRV Utica Development Utilizes Existing Pad Water and Gathering Infrastructure to Drive Economics

EampP and Gathering

Rich Valley Utica Test

Existing Line

Leased

Seneca Fee

Producing

FY19 Producer

Development

20

Leveraging Existing Gathering Water and Pad Infrastructure Enhances Returns

Limited New Infrastructure Needed to Support Production Growth

WDA Well Costs(1) WDA Consolidated Economics

Steady activity levels and coordination between upstream and midstream activities

enhance returns provide economies of scale and significant operational flexibility

(1) WDA Marcellus well costs reflect drilling completion amp gathering costs for 192 drilled and completed wells as of 93018 WDA Utica well costs reflect expected drilling completion amp gathering costs for the ~120 well locations in area of redevelopment (2) Internal Rate of Return for Seneca WDA includes estimated well costs under current cost structure and anticipated LOE and Gathering costs Internal Rate of Return for Seneca WDA and Gathering includes expected gathering capital expenditures

through FY 2022 well costs under current cost structure and non-gathering LOE

$685$887

$210

$0

$200

$400

$600

$800

$1000

Marcellus(Historic)

Utica - CRV(Current)

$ la

tera

l foo

t

Drilling amp Completion Gathering

$931$895

10 -11

17

00

03

06

09

12

15

18

Marcellus(Historic)

Utica - CRV(Current)

EUR

10

00 fe

et (B

cf)

60-70 EUR increase expected per well

Total cost per well expected to marginally increase

WDA EURs

At a $225 netback price consolidated Seneca WDA and Gathering IRR is

approximately 33 an uplift of ~12 over standalone Seneca WDA economics(2)

10+ IRR Uplift Expected

21

Integrated Development ndash WDA Gathering System

Current System In-Service

~78 miles of pipe 36220 HP of compression

Current Capacity 470 MMcf per day

Interconnects with TGP 300

Total Investment to Date $301 million

Future Build-Out

FY 2019 CapEx $10 - $15 million

Modest gathering pipeline and compression investment required to support Senecarsquos transition to Utica development

Opportunity for 300 miles of pipelines and five compressor stations (+60000 HP installed) as Senecarsquos drilling activity continues

Deliverability into TGP 300 and NFG Supply

Gathering System Build-Out Tailored to Accommodate Senecarsquos WDA Development

Clermont Gathering System Map

EampP and Gathering

22

WDA Firm Transportation and Sales Capacity

Will continue to layer-in firm sales deals of short and longer duration on TGP 300 to reduce spot exposure

WDA spot realizations track TGP Station 313 pricing typically 10cent - 30cent better than TGP Marcellus Zone 4

Leidy South will provide additional capacity to premium markets (Transco Zone 6)

WDA Exit Capacity Supports Long-term Production Growth and Enhances Consolidated Returns

WDA Contracted Firm Transport and Gross Sales Volumes (MDthd)

Seneca gross production trend

EampP and Gathering

0

100

200

300

400

500

600

700

Niagara Expansion Project (TGP and NFG)FT Capacity 158000 Dthd $067Dth

Firm Sales NYMEX amp DAWN

WDA - TGP 300Firm Sales

Leidy SouthTransco Zone 6

Markets330000 Dthd(1)

Will layer-in firm sales to minimize spot exposure

(1) Portion of Transco Project capacity will likely be utilized by EDA Lycoming County production

WDA Gas Marketing Strategy

23

Eastern Development Area

EDA Acreage ndash 70000 AcresEDA Highlights

1 DCNR Tract 007 (Tioga Co Pa)bull Utica development resumed in third quarter fiscal 2018

bull ~43 remaining Utica locations economic at ~$184 Mcf

bull Gathering Infrastructure NFG Midstream Wellsboro

bull Marcellus Shale expected to provide ~60 additional locations

EampP and Gathering

2

1

3

2 Covington amp DCNR Tract 595 (Tioga Co Pa)bull Marcellus locations fully developed (average daily gross production of ~93 MMcfd)

bull Gathering Infrastructure NFG Midstream Covington

bull Opportunity for future Utica appraisal

3 DCNR Tract 100 amp Gamble (Lycoming Co Pa)bull ~45 remaining Marcellus locations economic at ~$153 Mcfbull Firm Transportation Capacity Atlantic Sunrise (189 MDthd)

bull Gathering Infrastructure NFG Midstream Trout Run

bull Geneseo Shale expected to provide 100-120 additional locations

24

EDA Marcellus Lycoming County Development

Marcellus Development in Lycoming County has Resumed in Connection with Atlantic Sunrise

(1) Includes physical fixed price and NYMEX-based firm sales contracts that do not carry any additional transportation costs

EampP and Gathering

Prolific Marcellus acreage with peer leading well results

~45 remaining Marcellus locations economic at ~$153 Mcf

Near-term development focused on filling Atlantic Sunrise capacity

Existing Line

Leased

Seneca Fee

Producing

FY19 Producer

Development

0

50

100

150

200

250

Gro

ss F

irm V

olum

es (M

Dth

d)

EDA ndash Transco Firm Contracts

Atlantic Sunrise (Transco)FT Capacity 189405 Dthd

Cost $073DthFirm Sales NYMEX+

Transco Firm Sales(1)

25

EDA Utica Tioga County Development

Utica Development in Tioga County ndash Tract 007 Development Resumed in Q3 Fiscal 2018

In-Service November 2016

Lateral Length 4640 ft

30 Day IP 1000 ft 34 MMcfd

Est EUR 1000 ft 24 Bcf

Inventory ~43 locations economic at ~$184 Mcf

Targeting to grow production by 100 to 150 MDthd by fiscal 2020

Expected Development Costs $1045 per lateral ft

Gathering Infrastructure NFG Midstream Wellsboro

Modest build-out required to connect to TGP 300

SalesTakeaway Strategy Layer-in firm sales with shippers holding capacity on TGP 300

(1) Includes physical fixed price and NYMEX-based firm sales contracts that do not carry any additional transportation costs

Tract 007 Utica Appraisal Well Results vs Industry

EampP and Gathering

0

100000

200000

300000

400000

500000

600000

700000

800000

0 100 200 300

Nor

mal

ized

Cum

ulat

ive

(Mcf

10

00rsquo)

Days On ProductionIndustry PotterTioga Wells Seneca DCNR 007 73H

0

25

50

75

100

125

150

Gro

ss F

irm V

olum

es (M

Dth

d)

EDA ndash TGP 300 Firm Contracts

Northeast Supply Diversification ProjectFT Capacity 50000 Dthd $050Dth

Firm Sales NYMEX and DAWN

EDA - TGP 300Firm Sales(1)

26

Integrated Development ndash EDA Gathering Systems

Total Investment (to date) ~$46 million FY 2019 Estimated Capital Expenditures $1 MM - $2 MM Capacity 220000 Dth per day (Interconnect w TGP 300) Production Source Seneca Resources ndash Tioga Co (Covington and DCNR Tract 595)

Total Investment (to date) ~$208 million FY 2019 Estimated Capital Expenditures $25 MM - $35 MM Capacity 466000 to 585000 Dth per day (Interconnect w Transco) Production Source Seneca Resources ndash Lycoming Co (DCNR Tract 100 and Gamble) Future third-party volume opportunities

Covington Gathering System

Trout Run Gathering System

Gathering Segment Supporting Senecarsquos EDA Production amp Future Development

Wellsboro Gathering System Total Investment (to date) ~$14 million FY 2019 Estimated Capital Expenditures $8 MM - $15 MM Capacity up to 200000 Dth per day (Interconnect w TGP 300) Production Source Seneca Resources ndash Tioga Co (DCNR Tract 007)

EampP and Gathering

2

1

3

27

Long-term Contracts Supporting Appalachian Growth

(1) Represents base firm sales contracts not tied to firm transportation capacity Base firm sales are either fixed priced or priced at an index (eg NYMEX ) +- a fixed basis and do not carry any transportation costs

Seneca continues to layer-in firm sales contracts with attractive realizations to lock-in drilling economics and minimize spot exposure ahead of firm transportation in-service dates

EampP and Gathering

-

100

200

300

400

500

600

700

800

900

1000

1100

1200

FY 2019 FY 2020 FY 2021 FY 2022Northeast Supply Diversification 50000 Dthd

Niagara Expansion (TGP amp NFG)Delivery Markets Canada-Dawn amp TETCO

158000 Dthd

Atlantic Sunrise (Transco)Delivery Markets Mid-Atlantic amp Southeast US

189405 Dthd

In-BasinFirm Sales

Contracts(1)

Leidy South (Transco amp NFG)

Transco Zone 6 Markets330000 Dthd

Seneca Appalachia Natural Gas MarketingGross Firm Contract Volumes (Mdthday)

28

297000 ($061)

305200 ($061)

305600 ($063)

337000 ($057)

370800 ($024)

369600 ($060)

367900 ($067)

33400 ($070)74500 ($077) 74900 ($077)

81100 ($078)

85900 ($078)

92000 ($073)

91300 ($073)

178800 $255

196000 $234

195500 $234

149900 $232

129500 $230

105400 $222

104500 $222

~517800 509200 575700 576000 568000 586200 567000 563700

Q1 FY19 Q2 FY19 Q3 FY19 Q4 FY19 Q1 FY20 Q2 FY20 Q3 FY20 Q4 FY20

Fixed Price Dawn NYMEX

Near-term Firm Sales Provide Market amp Price Certainty

Net Contracted Firm Sales Volumes (Dth per day)Contracted Index Price Differentials ($ per Dth)(1)

(1) Values shown represent the weighted average fixed price or contracted fixed differential relative to NYMEX (netback price) less any associated transportation costs

Actual Daily Net

Production

641200 716500 708700 693500 708400 674400 667000Gross Firm Sales Volumes (Dthd)

EampP and Gathering

29

California Oil

Stable Oil Production | Minimal Capital Investment | Steady Free Cash Flow

1

2

3

4

5

Location Formation Production Method

FY18 Daily Production(net Boed)

1 East Coalinga Other Temblor Primary 512

2 North Lost Hills

Tulare amp Etchegoin

PrimarySteam flood 892

3 South Lost Hills

Monterey Shale Primary 1359

4 North Midway Sunset

Tulare amp Potter Steam flood 2786

5 South Midway Sunset Antelope Steam flood 2048

TOTAL WEST DIVISION NET PRODUCTION(1) 7597 Boed

EampP and Gathering

(1) West division net production for FY 2018 excludes production from Sespe field which was divested on May 1 2018

30

California Capital Expenditures vs Production

9341 8863

8033 ~7300

2016 2017 2018 2019

Fiscal Year

West Division Average Net Daily Production (Boe)West Division Annual Capital Expenditures ($ MM)(1)

$38 $38

$26 ~$25

2016 2017 2018 2019

Fiscal YearGuidance Guidance

(1) Seneca West Division capital expenditures includes Seneca corporate and eliminations

EampP and Gathering

Sepse Sale Closed on 5118(reduced production by ~900 boed)

31

Pioneer

South MWSS

Acreage

North MWSS

AcreageSec 17N

4149 51

NMWSS amp 17N SMWSS amp Pioneer East Coalinga

California Development Activities

Modest near-term capital program focused on locations that earn attractive returns in current oil price environment

AampD will focus on low cost bolt-on opportunities

Sec 17 Pioneer and East Coalinga development to provide future growth

North

Project IRRs at $55Bbl(1)

(1) Reflects pre-tax IRRs at a $55Bbl WTI

EampP and Gathering

Seneca West Economics

South

East Coalinga

North

South

32

Fiscal 2019 Production and Price Certainty

~49 Bcfe

210 ndash 230 Bcfe

~114 Bcf

~29 Bcf (2)

16+- Bcf~12 Bcfe

0

40

80

120

160

200

240

YTD FY19Actuals

Fixed Price + FirmSales w Hedge

Firm Sales(Unhedged)

Spot Sales California TotalSeneca

Prod

uctio

n (B

cfe)

(1) Average realized price reflects uplift from financial hedges less fixed differentials under firm sales contracts and any firm transportation costs(2) Indicates firm sales contracts with fixed index differentials but not backed by a matching financial hedge

114 Bcf locked-in realizing net ~$241Mcf (1)

29 Bcf of additional basis protection

Spot production assumed to be sold

at ~$275Mmbtu(winter) and ~$225

(summer)

143 Bcf of Appalachian Production Protected by Firm Sales for Remainder of Year

79 of oil production hedged at $5757 Bbl

EampP and Gathering

33

Strong Hedge Book

Natural Gas Swap amp Fixed Physical Sales Contracts (Millions MMBtu)

(1) Fixed price physical sales exclude joint development partnerrsquos share of fixed price contract WDA volumes as specified under the joint development agreement(2) Reflects percentage of projected production for FY19 hedged at the midpoint of the production guidance range(3) Senecarsquos remainder FY19 Production reflects the total FY19 production guidance of 210-230 Bcfe or 220 Bcfe at the midpoint less Q1 actual production

Crude Oil Swap Contracts (Thousands Bbls)

13591188

732

456

0

500

1000

1500

2000

2500

FY 2019 FY 2020 FY 2021 FY 2022

NYMEX (WTI)

Brent

FY 19 Crude Oil79 Hedged (2)

FY 2019 Remaining Production (3)

EampP and Gathering

1174

709

469 406

0

50

100

150

200

250

FY 2019 FY 2020 FY 2021 FY 2022

NYMEX Swaps

Dawn Swaps

Fixed Price Physical Sales

(1)

FY 2019 Remaining Production (3)

FY 19 Nat Gas71 Hedged (2)

34

$065 $070$070 -$075

FY 2017 FY 2018 FY 2019E

$060 $060 $060

$011 $009 $007$071 $069 ~$067

FY 2017 FY 2018 FY 2019E Gathering amp Transport LOE (non-Gathering) GampA Taxes amp Other

Seneca Operating Costs

Competitive low cost structure in Appalachia and California supports strong cash margins

Gathering fee generates significant revenue stream for affiliated gathering company

Seneca DDampARate

$Mcfe

$054 $054 $056

$042 $038 $031

$034 $034 $030

$017 $014 $015

$147 $140 ~$132

FY 2017 FY 2018 FY 2019E

(1)

$1791$1746~$2050

FY 2017 FY 2018 FY 2019E

Appalachia LOE amp Gathering $Mcfe

California LOE$Boe

Total Seneca Cash OpEx$Mcfe

(1)

(2)

(2)

(1) GampA estimate represents the midpoint of the GampA guidance range of $025 to $035 for fiscal 2019(2) The total of the two LOE components represents the midpoint of the LOE guidance range of $085 to $090 for fiscal 2019

EampP and Gathering

35

Senecarsquos Continuing Commitment to the Environment

Produced Water Recycled in Appalachia

100 70Recycled Water

Used in New Shale Well

Completions

Water and Fluids Management Air Quality and Emissions

Seneca Resources Water OperationsFiscal 2018

Seneca Resources Remains Focused on Minimizing GHG Emissions

The Environmental Partnership

EPA Natural Gas Star Program

Green Completions (all fiscal 2018 wells)

Ultrasonic Leak Detection Technology

Emissions Controls

Rig and Vehicle Fuel Conversion

Integrating Renewable Energy into Operations

EampP and Gathering

36

Pipeline and Storage OverviewNational Fuel Gas Supply Corporation ~ Empire Pipeline Inc

37

Pipeline amp Storage Segment Overview

(1) As of September 30 2018 as disclosed in the Companyrsquos fiscal 2018 form 10-K(2) As of December 31 2017 calculated from National Fuel Gas Supply Corporationrsquos and Empire Pipeline Incrsquos 2017 FERC Form-2 reports respectively

Empire Pipeline Inc

National Fuel Gas Supply Corporation

Empire Pipeline

Supply Corp

Contracted Capacity(1) Firm Transportation 3187 MDth per day Firm Storage 71938 Mdth (fully subscribed)

Rate Base(2) ~$820 million FERC Rate Proceeding Status

Rate case settlement extension approved Nov lsquo15 Rate case filing expected by 73119

Contracted Capacity(1) Firm Transportation 978 MDth per day Firm Storage 3753 Mdth (fully subscribed)

Rate Base(2) ~$249 million FERC Rate Proceeding Status

Rate case settlement in principle reached on 122118 FERC approval pending

New transportation rates went into on 1119

Pipeline amp Storage

38

All Seneca volumes will flow through wholly-owned NFG gathering facilities

FM100 Project - Consolidated Benefit for NFG

330000 Dthd of new transportation capacity from WDA and EDA acreage positions to premium markets

New Transco capacity (Leidy South) 330000 Dthday

Rate(1) competitive with other expansion project rates in Senecarsquos current transportation portfolio

Delivery Point(s) Transco Zone 6 interconnections

Seneca

Lease to Transco of new capacity 330000 Dthday

Estimated annual lease revenues ~$35 million

Target In-Service late calendar year 2021

Supply Corp

Project expected to provide long-term earnings uplift to Seneca Supply Corp and Gathering

Pipeline amp Storage

Gathering

(1) Includes lease of new capacity from Supply Corp to Transco

39

FM100 Project ndash Significant Investment by Supply Corp

Pipeline amp Storage

Estimated Capital Cost $280 million(1)

Facilities (all in Pennsylvania) include Approximately 30 miles of new pipeline 2 new compressor stations (totaling

approximately 37000 HP) New interconnection station and modification

of existing interconnection station Abandonment of approximately 45 miles of

existing pipeline and compressor station Regulatory Process

Pre-filing application submitted to FERC in 2017 for original modernization project

FERC 7(b) 7(c) filing expected summer 2019

(1) Includes expansion and modernization portions of the project

40

Empire North Project

Target In-Service second half of fiscal 2020

Est Capital Cost $145 million

Est Annual Revenues ~$25 million

Receipt Point Jackson (Tioga Co Pa production)

Design Capacity and Delivery Points 175000 Dthd to Chippawa (TCPL interconnect)

30000 Dthd to Hopewell (TGP 200 interconnect)

Customers Fully subscribed (205000 Dthday)

Major Facilities 2 new compressor stations in NY (1) amp Pa (1)

No new pipeline construction

Regulatory Process FERC 7(c) application filed on 21618

FERC Environmental Assessment issued 103018

Pipeline amp Storage

Fully Subscribed Project will Provide 205000 Dthday of Incremental Firm Transportation

41

National Fuel Remains Committed to Northern Access Project

Target In-Service as early as fiscal 2022

Total Cost ~$500MM (~$76MM spent to date)

Estimated Annual Revenues ~$84 million

Delivery Points

350000 Dthd to Chippawa (TCPL interconnect)

140000 Dthd to Hopewell (TGP 200 line)

Regulatory Status

February 3 2017 ndash FERC 7(c) certificate issued

August 6 2018 ndash FERC issued Order finding that NY DEC waived water quality certification

Supply and Empire currently working to finalize remaining federal authorizations

Pipeline amp Storage

To Dawn

42

Continued Expansion of the NFG Supply System

Line N Expansion Opportunities

Line N to Monaca Project Project Firm transportation service to a new ethane

cracker facility being built by Shell Chemical Appalachia LLC

Target In-Service July 2019

Estimated Capital Cost $23 million

Contracted Capacity 133000 Dthday

Additional Line N Expansion Opportunity (Supply OS 221) Project New firm transportation service for on-system

demand

Open Season Capacity Awarded 165000 to foundation shipper Precedent agreement in negotiations

Pipeline amp Storage

43

Pipeline amp Storage Customer Mix

Producer33

LDC42

Marketer10

Outside Pipeline

9

End User6

42 MMDthd

(1) Contracted as of 10312018

Customer Transportation by Shipper Type(1) Affiliated Customer Mix (Contracted Capacity)

66

521

41

34

9579

59

LDCs Producers Marketers FirmStorage

Affiliated Non-Affiliated

Firm Transport

Pipeline amp Storage

44

Utility OverviewNational Fuel Gas Distribution Corporation

45

New York amp Pennsylvania Service Territories

New York

Total Customers(1) 535800ROE 87 (NY PSC Rate Case Order April 2017)Rate Mechanismso Revenue Decouplingo Weather Normalizationo Low Income Rateso Merchant Function Charge (Uncollectibles Adj)o 9010 Sharing (Large Customers)o System Modernization Tracker

Pennsylvania

Total Customers(1) 214400ROE Black Box Settlement (2007)Rate Mechanismso Low Income Rateso Merchant Function Charge

(1) As of September 30 2018

Utility

46

New York Rate Case Outcome

Rate Order Summary

Revenue Requirement $59 million

Rate Base $704 million

Allowed Return on Equity (ROE) 87

Capital Structure 429 equity

Other notable items

New rates became effective 5117

Retains rate mechanisms in place under prior order (revenue decoupling weather normalization merchant function charge 9010 large customer sharing)

No stay-out clause

System modernization tracker for Leak Prone Pipe (LPP)

Earnings sharing started 4118 (5050 sharing starts at earnings in excess of 92)

Article 78 appeal filed on 72817 with oral argument completed in January 2019

On April 20 2017 the New York Public Service Commission issued a Rate Order relating to NFG Distributionrsquos rate case (No 16-G-0257) filed in April 2016

Utility

47

Utility Continues its Significant Investments in Safety

$544$618 $636

$699

$944$980

$809$856

$90-100

$00

$250

$500

$750

$1000

$1250

2015 2016 2017 2018 2019E

Cap

ital E

xpen

ditu

res

($ m

illio

ns)

Fiscal Year

Capital Expenditures for Safety Total Capital Expenditures

Modernization Spending in NY Expected to Grow Gross Margin By $2 MM - $5 MM in FY 2019

(1)

(1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation

Utility

System modernization tracker in NY allows recovery of pipeline replacementcosts which is expected to drive modest gross margin and rate base growth

48

Accelerating Pipeline Replacement amp Modernization

Wrought Iron

Plastic

CoatedBare

120130

146 144159

2014 2015 2016 2017 2018Calendar Year

NY9726 miles

PA4830 miles

No Cast Iron Mains in Pa

Miles of Utility Main Pipeline ReplacedUtility Mains by Material(1)

Wrought Iron

Cast Iron

Plastic

Coated Bare

Utility

(1) All values are reported on a calendar year basis as of December 31 2018

49

A Proven History of Controlling Costs

$200 $189 $195

$166 $166

$31 $31

$197 $197

$0

$50

$100

$150

$200

$250

2015 2016 2017 2018 TTM 123118

Fiscal Year

OampM Expense Non-Service Pension Costs

OampM Expense ($ millions)

Utility

(1)

(1) For purposes of comparability to FY 2015 2016 and 2017 Utility Operation and Maintenance Expense for FY 2018 and the twelve months ended December 31 2018 was adjusted by approximately $314 million and $312 million respectively to include non-service pension costs which were re-classified as Other Income (Deductions) as of October 1 2018 on the Companyrsquos Income Statement See Slide 64 for non-GAAP reconciliation of Adjusted Operation and Maintenance Expense to Operation and Maintenance Expense by segment

50

Consolidated Financial OverviewUpstream I Midstream I Downstream

51

Adjusted Operating Results ($ per share)(1)

Diversified Balanced Earnings and Cash Flows

(1) A reconciliation of Adjusted Operating Results to Earnings per Share by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation(2) Consolidated Adjusted EBITDA includes Energy Marketing and Corporate amp All Other Segments A reconciliation of Adjusted EBITDA to Net Income by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in

the Business is included at the end of this presentation

Adjusted EBITDA ($ millions)(2)

$176 $179

$184 $181

$92 $97

$318 $327

$761 $775

$-

$200

$400

$600

$800

FY 2018 TTM 123118

$059 Utility

$097 Pipeline amp Storage

$057 Gathering

$125 Exploration

amp Production

$334 $345 to $365

$-

$100

$200

$300

$400

FY 2018 FY 2019 Guidance

Rate Regulated

40-45

$728

Rate Regulated

~46

52

$89 $94 $98 $81 $86 $90-$100

$140$230

$114 $95 $93 $120-$150

$138$118

$54$33 $48

$55-$65

$603$557

$99 $246$356

$460-$495

$970 $1001

$366$455

$583

$725-$810

$0

$250

$500

$750

$1000

$1250

2014 2015 2016 2017 2018 2019GuidanceFiscal Year

Exploration amp Production

Gathering

Pipeline amp Storage

Utility

Disciplined Flexible Capital Allocation

(2)

(1) Total Capital Expenditures include Energy Marketing Corporate and All Other A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation (2) FY16 FY17 and FY18 reflects the netting of $157 million $7 million and $17 million respectively of up-front proceeds received from joint development partner for working interest in joint development wells and $21M in intercompany asset transfers in FY18

Capital Expenditures by Segment ($ millions)(1)

53

Maintaining Strong Balance Sheet amp Liquidity

Total Equity49

Total Debt51

$42 Billion Total Capitalizationas of December 31 2018

218 x251 x 245 x 247 x 256 x

2015 2016 2017 2018 TTM 123118Fiscal Year End

Net Debt Adjusted EBITDA(1) Capitalization

Debt Maturity Profile ($MM) Liquidity

Committed Credit FacilitiesShort-term Debt OutstandingAvailable Short-term Credit FacilitiesCash Balance at 123118 Total Liquidity at 123118

$ 750 MM0 MM

750 MM110 MM

$ 860 MM

$500 $549 $500

$300 $300

$0

$200

$400

$600

(1) Net Debt is net of cash and temporary cash investments Reconciliations of Net Debt and Adjusted EBITDA to Net Income are included at the end of this presentation

54

Appendix

55

Safe Harbor For Forward Looking StatementsThis presentation may contain ldquoforward-looking statementsrdquo as defined by the Private Securities Litigation Reform Act of 1995 including statements regarding future prospectsplans objectives goals projections estimates of oil and gas quantities strategies future events or performance and underlying assumptions capital structure anticipatedcapital expenditures completion of construction projects projections for pension and other post-retirement benefit obligations impacts of the adoption of new accounting rulesand possible outcomes of litigation or regulatory proceedings as well as statements that are identified by the use of the words ldquoanticipatesrdquo ldquoestimatesrdquo ldquoexpectsrdquo ldquoforecastsrdquoldquointendsrdquo ldquoplansrdquo ldquopredictsrdquo ldquoprojectsrdquo ldquobelievesrdquo ldquoseeksrdquo ldquowillrdquo ldquomayrdquo and similar expressions Forward-looking statements involve risks and uncertainties which couldcause actual results or outcomes to differ materially from those expressed in the forward-looking statements The Companyrsquos expectations beliefs and projections are expressedin good faith and are believed by the Company to have a reasonable basis but there can be no assurance that managementrsquos expectations beliefs or projections will result or beachieved or accomplished

In addition to other factors the following are important factors that could cause actual results to differ materially from those discussed in the forward-looking statements delaysor changes in costs or plans with respect to Company projects or related projects of other companies including difficulties or delays in obtaining necessary governmentalapprovals permits or orders or in obtaining the cooperation of interconnecting facility operators governmentalregulatory actions initiatives and proceedings including thoseinvolving rate cases (which address among other things target rates of return rate design and retained natural gas) environmentalsafety requirements affiliate relationshipsindustry structure and franchise renewal changes in laws regulations or judicial interpretations to which the Company is subject including those involving derivatives taxessafety employment climate change other environmental matters real property and exploration and production activities such as hydraulic fracturing financial and economicconditions including the availability of credit and occurrences affecting the Companyrsquos ability to obtain financing on acceptable terms for working capital capital expendituresand other investments including any downgrades in the Companyrsquos credit ratings and changes in interest rates and other capital market conditions changes in the price ofnatural gas or oil impairments under the SECrsquos full cost ceiling test for natural gas and oil reserves factors affecting the Companyrsquos ability to successfully identify drill for andproduce economically viable natural gas and oil reserves including among others geology lease availability title disputes weather conditions shortages delays orunavailability of equipment and services required in drilling operations insufficient gathering processing and transportation capacity the need to obtain governmentalapprovals and permits and compliance with environmental laws and regulations increasing health care costs and the resulting effect on health insurance premiums and on theobligation to provide other post-retirement benefits changes in price differentials between similar quantities of natural gas or oil sold at different geographic locations and theeffect of such changes on commodity production revenues and demand for pipeline transportation capacity to or from such locations other changes in price differentialsbetween similar quantities of natural gas or oil having different quality heating value hydrocarbon mix or delivery date the cost and effects of legal and administrative claimsagainst the Company or activist shareholder campaigns to effect changes at the Company uncertainty of oil and gas reserve estimates significant differences between theCompanyrsquos projected and actual production levels for natural gas or oil changes in demographic patterns and weather conditions changes in the availability price oraccounting treatment of derivative financial instruments changes in laws actuarial assumptions the interest rate environment and the return on plantrust assets related to theCompanyrsquos pension and other post-retirement benefits which can affect future funding obligations and costs and plan liabilities changes in economic conditions includingglobal national or regional recessions and their effect on the demand for and customersrsquo ability to pay for the Companyrsquos products and services the creditworthiness orperformance of the Companyrsquos key suppliers customers and counterparties the impact of potential information technology cybersecurity or data security breaches economicdisruptions or uninsured losses resulting from major accidents fires severe weather natural disasters terrorist activities or acts of war significant differences between theCompanyrsquos projected and actual capital expenditures and operating expenses or increasing costs of insurance changes in coverage and the ability to obtain insurance

Forward-looking statements include estimates of oil and gas quantities Proved oil and gas reserves are those quantities of oil and gas which by analysis of geoscience andengineering data can be estimated with reasonable certainty to be economically producible under existing economic conditions operating methods and governmentregulations Other estimates of oil and gas quantities including estimates of probable reserves possible reserves and resource potential are by their nature more speculativethan estimates of proved reserves Accordingly estimates other than proved reserves are subject to substantially greater risk of being actually realized Investors are urged toconsider closely the disclosure in our Form 10-K available at wwwnationalfuelgascom You can also obtain this form on the SECrsquos website at wwwsecgov

For a discussion of the risks set forth above and other factors that could cause actual results to differ materially from results referred to in the forward-looking statements seeldquoRisk Factorsrdquo in the Companyrsquos Form 10-K for the fiscal year ended September 30 2018 and the Forms 10-Q for the quarter ended March 31 2018 June 30 2018 and December31 2018 The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date thereof or to reflect the occurrence ofunanticipated events

Appendix

17

Western Development AreaMarcellus Core Acreage

vs Utica Appraisal Trend(1)

(1) The Utica Shale lies approximately 5000 feet beneath Senecarsquos WDA Marcellus acreage (2) Appraisal program currently in progress Additional tests are planned Prior Marcellus delineation tests helped define the prospective limits of the Marcellus core acreage planned testing in the Utica expected to do the same

Area of Re-Development ~120 Utica locations on existing Marcellus pads

Key Utica testsPast Marcellus delineation testsUtica Trend (currently evaluating)Marcellus Core Acreage

Large well inventory economic at ~$200 Mcf

Marcellus Shale 600+ well locations remaining 200000 acres

Utica Shale 500+ potential locations across Utica trend evaluating extent of prospective acreage(2)

Fee acreage (no royalty) enhances economics and provides development flexibility

Addition of 2nd WDA drilling rig in Q3 FY18 focused on redevelopment of Clermont-Rich Valley acreage for Utica

Use of existing gathering pad and water infrastructure for Utica drives increased Appalachian program returns

Highly contiguous position drives best in class well costs

Utica test results on trend with other Utica wells in NE Pa

Long-term firm contracts support growth

Boone Mountain Utica Test Well23 Bcf 1000ft

Rich Valley Utica Test Well23 Bcf 1000ft

EampP and Gathering

WDA Highlights

18

WDA Utica Appraisal Results and Initial Type Curve

Tested producing from 17 Utica wells in WDA-CRV Higher pressure significantly enhances well

productivity (Utica ~5000rsquo deeper than Marcellus) Drawdown management is critical restricted

drawdown appears to improve well EURs Early production declines much shallower vs

Marcellus

WDA Utica Appraisal Update

WDA Economics

(1) Internal Rate of Return (IRR) is pre-tax and includes estimated well costs under current cost structure LOEand anticipated gathering tariffs

(2) Initial WDA-CRV Utica type curve based on production results and reservoir expectations from the first 5appraisal wells in the WDA-CRV area

(3) WDA-CRV Utica Average includes all 17 producing wells including 2 wells (pad E09-S) for which drawdownmanagement was not used

EampP and Gathering

EURBcf1000rsquo

Well Cost$M1000rsquo

IRR $225

Break-even15 IRR(1)

Utica - CRV 17 $887 23 $197

Marcellus 10 ndash 11 $643 19 $206

(2)

0

1

2

3

4

5

6

7

8

9

0 12 24 36 48 60 72 84 96 108 120

Cum

ulat

ive

Prod

uctio

n B

CF

Months On

WDA-CRV Utica Wells - Normalized to 9000rsquoUtica Type Curve CRV Utica AverageWDA Marcellus Type Curve Boone Mountain Appraisal WellWDA-CRV Utica Type Curve(2) WDA-CRV Utica Average(3)

0005101520253035

0 2 4 6 8 10 12

19

Transitioning to Utica Development in CRV

WDA-CRV Marcellus(Depth ~7000 feet)

WDA-CRV Utica(Depth ~12000 feet)

Avg CRV Marcellus Production 270 MMcfd

Rem Avg EUR 10-11 Bcf 1000 lat ft

Rem Avg Well Costs = $643lat ft

120+ locations on existing Marcellus pads

Est EURs 17 Bcf 1000 lat ft

Est Development Well Costs = $887lat ft

CRV Utica Transition Plan

1)Finish Marcellus Pads in Development

Drill 24 complete 24 Marcellus wells

2)Continue Optimizing Utica DampC design

Additional optimization wells focusing on

Completion design

Landing zone targets

3)Continue transition to Utica development

Future drilling on multi-well pads

Continue using optimization results to determine development well design

Tailor development plan to use existing pad water and gathering infrastructure

CRV Utica Development Utilizes Existing Pad Water and Gathering Infrastructure to Drive Economics

EampP and Gathering

Rich Valley Utica Test

Existing Line

Leased

Seneca Fee

Producing

FY19 Producer

Development

20

Leveraging Existing Gathering Water and Pad Infrastructure Enhances Returns

Limited New Infrastructure Needed to Support Production Growth

WDA Well Costs(1) WDA Consolidated Economics

Steady activity levels and coordination between upstream and midstream activities

enhance returns provide economies of scale and significant operational flexibility

(1) WDA Marcellus well costs reflect drilling completion amp gathering costs for 192 drilled and completed wells as of 93018 WDA Utica well costs reflect expected drilling completion amp gathering costs for the ~120 well locations in area of redevelopment (2) Internal Rate of Return for Seneca WDA includes estimated well costs under current cost structure and anticipated LOE and Gathering costs Internal Rate of Return for Seneca WDA and Gathering includes expected gathering capital expenditures

through FY 2022 well costs under current cost structure and non-gathering LOE

$685$887

$210

$0

$200

$400

$600

$800

$1000

Marcellus(Historic)

Utica - CRV(Current)

$ la

tera

l foo

t

Drilling amp Completion Gathering

$931$895

10 -11

17

00

03

06

09

12

15

18

Marcellus(Historic)

Utica - CRV(Current)

EUR

10

00 fe

et (B

cf)

60-70 EUR increase expected per well

Total cost per well expected to marginally increase

WDA EURs

At a $225 netback price consolidated Seneca WDA and Gathering IRR is

approximately 33 an uplift of ~12 over standalone Seneca WDA economics(2)

10+ IRR Uplift Expected

21

Integrated Development ndash WDA Gathering System

Current System In-Service

~78 miles of pipe 36220 HP of compression

Current Capacity 470 MMcf per day

Interconnects with TGP 300

Total Investment to Date $301 million

Future Build-Out

FY 2019 CapEx $10 - $15 million

Modest gathering pipeline and compression investment required to support Senecarsquos transition to Utica development

Opportunity for 300 miles of pipelines and five compressor stations (+60000 HP installed) as Senecarsquos drilling activity continues

Deliverability into TGP 300 and NFG Supply

Gathering System Build-Out Tailored to Accommodate Senecarsquos WDA Development

Clermont Gathering System Map

EampP and Gathering

22

WDA Firm Transportation and Sales Capacity

Will continue to layer-in firm sales deals of short and longer duration on TGP 300 to reduce spot exposure

WDA spot realizations track TGP Station 313 pricing typically 10cent - 30cent better than TGP Marcellus Zone 4

Leidy South will provide additional capacity to premium markets (Transco Zone 6)

WDA Exit Capacity Supports Long-term Production Growth and Enhances Consolidated Returns

WDA Contracted Firm Transport and Gross Sales Volumes (MDthd)

Seneca gross production trend

EampP and Gathering

0

100

200

300

400

500

600

700

Niagara Expansion Project (TGP and NFG)FT Capacity 158000 Dthd $067Dth

Firm Sales NYMEX amp DAWN

WDA - TGP 300Firm Sales

Leidy SouthTransco Zone 6

Markets330000 Dthd(1)

Will layer-in firm sales to minimize spot exposure

(1) Portion of Transco Project capacity will likely be utilized by EDA Lycoming County production

WDA Gas Marketing Strategy

23

Eastern Development Area

EDA Acreage ndash 70000 AcresEDA Highlights

1 DCNR Tract 007 (Tioga Co Pa)bull Utica development resumed in third quarter fiscal 2018

bull ~43 remaining Utica locations economic at ~$184 Mcf

bull Gathering Infrastructure NFG Midstream Wellsboro

bull Marcellus Shale expected to provide ~60 additional locations

EampP and Gathering

2

1

3

2 Covington amp DCNR Tract 595 (Tioga Co Pa)bull Marcellus locations fully developed (average daily gross production of ~93 MMcfd)

bull Gathering Infrastructure NFG Midstream Covington

bull Opportunity for future Utica appraisal

3 DCNR Tract 100 amp Gamble (Lycoming Co Pa)bull ~45 remaining Marcellus locations economic at ~$153 Mcfbull Firm Transportation Capacity Atlantic Sunrise (189 MDthd)

bull Gathering Infrastructure NFG Midstream Trout Run

bull Geneseo Shale expected to provide 100-120 additional locations

24

EDA Marcellus Lycoming County Development

Marcellus Development in Lycoming County has Resumed in Connection with Atlantic Sunrise

(1) Includes physical fixed price and NYMEX-based firm sales contracts that do not carry any additional transportation costs

EampP and Gathering

Prolific Marcellus acreage with peer leading well results

~45 remaining Marcellus locations economic at ~$153 Mcf

Near-term development focused on filling Atlantic Sunrise capacity

Existing Line

Leased

Seneca Fee

Producing

FY19 Producer

Development

0

50

100

150

200

250

Gro

ss F

irm V

olum

es (M

Dth

d)

EDA ndash Transco Firm Contracts

Atlantic Sunrise (Transco)FT Capacity 189405 Dthd

Cost $073DthFirm Sales NYMEX+

Transco Firm Sales(1)

25

EDA Utica Tioga County Development

Utica Development in Tioga County ndash Tract 007 Development Resumed in Q3 Fiscal 2018

In-Service November 2016

Lateral Length 4640 ft

30 Day IP 1000 ft 34 MMcfd

Est EUR 1000 ft 24 Bcf

Inventory ~43 locations economic at ~$184 Mcf

Targeting to grow production by 100 to 150 MDthd by fiscal 2020

Expected Development Costs $1045 per lateral ft

Gathering Infrastructure NFG Midstream Wellsboro

Modest build-out required to connect to TGP 300

SalesTakeaway Strategy Layer-in firm sales with shippers holding capacity on TGP 300

(1) Includes physical fixed price and NYMEX-based firm sales contracts that do not carry any additional transportation costs

Tract 007 Utica Appraisal Well Results vs Industry

EampP and Gathering

0

100000

200000

300000

400000

500000

600000

700000

800000

0 100 200 300

Nor

mal

ized

Cum

ulat

ive

(Mcf

10

00rsquo)

Days On ProductionIndustry PotterTioga Wells Seneca DCNR 007 73H

0

25

50

75

100

125

150

Gro

ss F

irm V

olum

es (M

Dth

d)

EDA ndash TGP 300 Firm Contracts

Northeast Supply Diversification ProjectFT Capacity 50000 Dthd $050Dth

Firm Sales NYMEX and DAWN

EDA - TGP 300Firm Sales(1)

26

Integrated Development ndash EDA Gathering Systems

Total Investment (to date) ~$46 million FY 2019 Estimated Capital Expenditures $1 MM - $2 MM Capacity 220000 Dth per day (Interconnect w TGP 300) Production Source Seneca Resources ndash Tioga Co (Covington and DCNR Tract 595)

Total Investment (to date) ~$208 million FY 2019 Estimated Capital Expenditures $25 MM - $35 MM Capacity 466000 to 585000 Dth per day (Interconnect w Transco) Production Source Seneca Resources ndash Lycoming Co (DCNR Tract 100 and Gamble) Future third-party volume opportunities

Covington Gathering System

Trout Run Gathering System

Gathering Segment Supporting Senecarsquos EDA Production amp Future Development

Wellsboro Gathering System Total Investment (to date) ~$14 million FY 2019 Estimated Capital Expenditures $8 MM - $15 MM Capacity up to 200000 Dth per day (Interconnect w TGP 300) Production Source Seneca Resources ndash Tioga Co (DCNR Tract 007)

EampP and Gathering

2

1

3

27

Long-term Contracts Supporting Appalachian Growth

(1) Represents base firm sales contracts not tied to firm transportation capacity Base firm sales are either fixed priced or priced at an index (eg NYMEX ) +- a fixed basis and do not carry any transportation costs

Seneca continues to layer-in firm sales contracts with attractive realizations to lock-in drilling economics and minimize spot exposure ahead of firm transportation in-service dates

EampP and Gathering

-

100

200

300

400

500

600

700

800

900

1000

1100

1200

FY 2019 FY 2020 FY 2021 FY 2022Northeast Supply Diversification 50000 Dthd

Niagara Expansion (TGP amp NFG)Delivery Markets Canada-Dawn amp TETCO

158000 Dthd

Atlantic Sunrise (Transco)Delivery Markets Mid-Atlantic amp Southeast US

189405 Dthd

In-BasinFirm Sales

Contracts(1)

Leidy South (Transco amp NFG)

Transco Zone 6 Markets330000 Dthd

Seneca Appalachia Natural Gas MarketingGross Firm Contract Volumes (Mdthday)

28

297000 ($061)

305200 ($061)

305600 ($063)

337000 ($057)

370800 ($024)

369600 ($060)

367900 ($067)

33400 ($070)74500 ($077) 74900 ($077)

81100 ($078)

85900 ($078)

92000 ($073)

91300 ($073)

178800 $255

196000 $234

195500 $234

149900 $232

129500 $230

105400 $222

104500 $222

~517800 509200 575700 576000 568000 586200 567000 563700

Q1 FY19 Q2 FY19 Q3 FY19 Q4 FY19 Q1 FY20 Q2 FY20 Q3 FY20 Q4 FY20

Fixed Price Dawn NYMEX

Near-term Firm Sales Provide Market amp Price Certainty

Net Contracted Firm Sales Volumes (Dth per day)Contracted Index Price Differentials ($ per Dth)(1)

(1) Values shown represent the weighted average fixed price or contracted fixed differential relative to NYMEX (netback price) less any associated transportation costs

Actual Daily Net

Production

641200 716500 708700 693500 708400 674400 667000Gross Firm Sales Volumes (Dthd)

EampP and Gathering

29

California Oil

Stable Oil Production | Minimal Capital Investment | Steady Free Cash Flow

1

2

3

4

5

Location Formation Production Method

FY18 Daily Production(net Boed)

1 East Coalinga Other Temblor Primary 512

2 North Lost Hills

Tulare amp Etchegoin

PrimarySteam flood 892

3 South Lost Hills

Monterey Shale Primary 1359

4 North Midway Sunset

Tulare amp Potter Steam flood 2786

5 South Midway Sunset Antelope Steam flood 2048

TOTAL WEST DIVISION NET PRODUCTION(1) 7597 Boed

EampP and Gathering

(1) West division net production for FY 2018 excludes production from Sespe field which was divested on May 1 2018

30

California Capital Expenditures vs Production

9341 8863

8033 ~7300

2016 2017 2018 2019

Fiscal Year

West Division Average Net Daily Production (Boe)West Division Annual Capital Expenditures ($ MM)(1)

$38 $38

$26 ~$25

2016 2017 2018 2019

Fiscal YearGuidance Guidance

(1) Seneca West Division capital expenditures includes Seneca corporate and eliminations

EampP and Gathering

Sepse Sale Closed on 5118(reduced production by ~900 boed)

31

Pioneer

South MWSS

Acreage

North MWSS

AcreageSec 17N

4149 51

NMWSS amp 17N SMWSS amp Pioneer East Coalinga

California Development Activities

Modest near-term capital program focused on locations that earn attractive returns in current oil price environment

AampD will focus on low cost bolt-on opportunities

Sec 17 Pioneer and East Coalinga development to provide future growth

North

Project IRRs at $55Bbl(1)

(1) Reflects pre-tax IRRs at a $55Bbl WTI

EampP and Gathering

Seneca West Economics

South

East Coalinga

North

South

32

Fiscal 2019 Production and Price Certainty

~49 Bcfe

210 ndash 230 Bcfe

~114 Bcf

~29 Bcf (2)

16+- Bcf~12 Bcfe

0

40

80

120

160

200

240

YTD FY19Actuals

Fixed Price + FirmSales w Hedge

Firm Sales(Unhedged)

Spot Sales California TotalSeneca

Prod

uctio

n (B

cfe)

(1) Average realized price reflects uplift from financial hedges less fixed differentials under firm sales contracts and any firm transportation costs(2) Indicates firm sales contracts with fixed index differentials but not backed by a matching financial hedge

114 Bcf locked-in realizing net ~$241Mcf (1)

29 Bcf of additional basis protection

Spot production assumed to be sold

at ~$275Mmbtu(winter) and ~$225

(summer)

143 Bcf of Appalachian Production Protected by Firm Sales for Remainder of Year

79 of oil production hedged at $5757 Bbl

EampP and Gathering

33

Strong Hedge Book

Natural Gas Swap amp Fixed Physical Sales Contracts (Millions MMBtu)

(1) Fixed price physical sales exclude joint development partnerrsquos share of fixed price contract WDA volumes as specified under the joint development agreement(2) Reflects percentage of projected production for FY19 hedged at the midpoint of the production guidance range(3) Senecarsquos remainder FY19 Production reflects the total FY19 production guidance of 210-230 Bcfe or 220 Bcfe at the midpoint less Q1 actual production

Crude Oil Swap Contracts (Thousands Bbls)

13591188

732

456

0

500

1000

1500

2000

2500

FY 2019 FY 2020 FY 2021 FY 2022

NYMEX (WTI)

Brent

FY 19 Crude Oil79 Hedged (2)

FY 2019 Remaining Production (3)

EampP and Gathering

1174

709

469 406

0

50

100

150

200

250

FY 2019 FY 2020 FY 2021 FY 2022

NYMEX Swaps

Dawn Swaps

Fixed Price Physical Sales

(1)

FY 2019 Remaining Production (3)

FY 19 Nat Gas71 Hedged (2)

34

$065 $070$070 -$075

FY 2017 FY 2018 FY 2019E

$060 $060 $060

$011 $009 $007$071 $069 ~$067

FY 2017 FY 2018 FY 2019E Gathering amp Transport LOE (non-Gathering) GampA Taxes amp Other

Seneca Operating Costs

Competitive low cost structure in Appalachia and California supports strong cash margins

Gathering fee generates significant revenue stream for affiliated gathering company

Seneca DDampARate

$Mcfe

$054 $054 $056

$042 $038 $031

$034 $034 $030

$017 $014 $015

$147 $140 ~$132

FY 2017 FY 2018 FY 2019E

(1)

$1791$1746~$2050

FY 2017 FY 2018 FY 2019E

Appalachia LOE amp Gathering $Mcfe

California LOE$Boe

Total Seneca Cash OpEx$Mcfe

(1)

(2)

(2)

(1) GampA estimate represents the midpoint of the GampA guidance range of $025 to $035 for fiscal 2019(2) The total of the two LOE components represents the midpoint of the LOE guidance range of $085 to $090 for fiscal 2019

EampP and Gathering

35

Senecarsquos Continuing Commitment to the Environment

Produced Water Recycled in Appalachia

100 70Recycled Water

Used in New Shale Well

Completions

Water and Fluids Management Air Quality and Emissions

Seneca Resources Water OperationsFiscal 2018

Seneca Resources Remains Focused on Minimizing GHG Emissions

The Environmental Partnership

EPA Natural Gas Star Program

Green Completions (all fiscal 2018 wells)

Ultrasonic Leak Detection Technology

Emissions Controls

Rig and Vehicle Fuel Conversion

Integrating Renewable Energy into Operations

EampP and Gathering

36

Pipeline and Storage OverviewNational Fuel Gas Supply Corporation ~ Empire Pipeline Inc

37

Pipeline amp Storage Segment Overview

(1) As of September 30 2018 as disclosed in the Companyrsquos fiscal 2018 form 10-K(2) As of December 31 2017 calculated from National Fuel Gas Supply Corporationrsquos and Empire Pipeline Incrsquos 2017 FERC Form-2 reports respectively

Empire Pipeline Inc

National Fuel Gas Supply Corporation

Empire Pipeline

Supply Corp

Contracted Capacity(1) Firm Transportation 3187 MDth per day Firm Storage 71938 Mdth (fully subscribed)

Rate Base(2) ~$820 million FERC Rate Proceeding Status

Rate case settlement extension approved Nov lsquo15 Rate case filing expected by 73119

Contracted Capacity(1) Firm Transportation 978 MDth per day Firm Storage 3753 Mdth (fully subscribed)

Rate Base(2) ~$249 million FERC Rate Proceeding Status

Rate case settlement in principle reached on 122118 FERC approval pending

New transportation rates went into on 1119

Pipeline amp Storage

38

All Seneca volumes will flow through wholly-owned NFG gathering facilities

FM100 Project - Consolidated Benefit for NFG

330000 Dthd of new transportation capacity from WDA and EDA acreage positions to premium markets

New Transco capacity (Leidy South) 330000 Dthday

Rate(1) competitive with other expansion project rates in Senecarsquos current transportation portfolio

Delivery Point(s) Transco Zone 6 interconnections

Seneca

Lease to Transco of new capacity 330000 Dthday

Estimated annual lease revenues ~$35 million

Target In-Service late calendar year 2021

Supply Corp

Project expected to provide long-term earnings uplift to Seneca Supply Corp and Gathering

Pipeline amp Storage

Gathering

(1) Includes lease of new capacity from Supply Corp to Transco

39

FM100 Project ndash Significant Investment by Supply Corp

Pipeline amp Storage

Estimated Capital Cost $280 million(1)

Facilities (all in Pennsylvania) include Approximately 30 miles of new pipeline 2 new compressor stations (totaling

approximately 37000 HP) New interconnection station and modification

of existing interconnection station Abandonment of approximately 45 miles of

existing pipeline and compressor station Regulatory Process

Pre-filing application submitted to FERC in 2017 for original modernization project

FERC 7(b) 7(c) filing expected summer 2019

(1) Includes expansion and modernization portions of the project

40

Empire North Project

Target In-Service second half of fiscal 2020

Est Capital Cost $145 million

Est Annual Revenues ~$25 million

Receipt Point Jackson (Tioga Co Pa production)

Design Capacity and Delivery Points 175000 Dthd to Chippawa (TCPL interconnect)

30000 Dthd to Hopewell (TGP 200 interconnect)

Customers Fully subscribed (205000 Dthday)

Major Facilities 2 new compressor stations in NY (1) amp Pa (1)

No new pipeline construction

Regulatory Process FERC 7(c) application filed on 21618

FERC Environmental Assessment issued 103018

Pipeline amp Storage

Fully Subscribed Project will Provide 205000 Dthday of Incremental Firm Transportation

41

National Fuel Remains Committed to Northern Access Project

Target In-Service as early as fiscal 2022

Total Cost ~$500MM (~$76MM spent to date)

Estimated Annual Revenues ~$84 million

Delivery Points

350000 Dthd to Chippawa (TCPL interconnect)

140000 Dthd to Hopewell (TGP 200 line)

Regulatory Status

February 3 2017 ndash FERC 7(c) certificate issued

August 6 2018 ndash FERC issued Order finding that NY DEC waived water quality certification

Supply and Empire currently working to finalize remaining federal authorizations

Pipeline amp Storage

To Dawn

42

Continued Expansion of the NFG Supply System

Line N Expansion Opportunities

Line N to Monaca Project Project Firm transportation service to a new ethane

cracker facility being built by Shell Chemical Appalachia LLC

Target In-Service July 2019

Estimated Capital Cost $23 million

Contracted Capacity 133000 Dthday

Additional Line N Expansion Opportunity (Supply OS 221) Project New firm transportation service for on-system

demand

Open Season Capacity Awarded 165000 to foundation shipper Precedent agreement in negotiations

Pipeline amp Storage

43

Pipeline amp Storage Customer Mix

Producer33

LDC42

Marketer10

Outside Pipeline

9

End User6

42 MMDthd

(1) Contracted as of 10312018

Customer Transportation by Shipper Type(1) Affiliated Customer Mix (Contracted Capacity)

66

521

41

34

9579

59

LDCs Producers Marketers FirmStorage

Affiliated Non-Affiliated

Firm Transport

Pipeline amp Storage

44

Utility OverviewNational Fuel Gas Distribution Corporation

45

New York amp Pennsylvania Service Territories

New York

Total Customers(1) 535800ROE 87 (NY PSC Rate Case Order April 2017)Rate Mechanismso Revenue Decouplingo Weather Normalizationo Low Income Rateso Merchant Function Charge (Uncollectibles Adj)o 9010 Sharing (Large Customers)o System Modernization Tracker

Pennsylvania

Total Customers(1) 214400ROE Black Box Settlement (2007)Rate Mechanismso Low Income Rateso Merchant Function Charge

(1) As of September 30 2018

Utility

46

New York Rate Case Outcome

Rate Order Summary

Revenue Requirement $59 million

Rate Base $704 million

Allowed Return on Equity (ROE) 87

Capital Structure 429 equity

Other notable items

New rates became effective 5117

Retains rate mechanisms in place under prior order (revenue decoupling weather normalization merchant function charge 9010 large customer sharing)

No stay-out clause

System modernization tracker for Leak Prone Pipe (LPP)

Earnings sharing started 4118 (5050 sharing starts at earnings in excess of 92)

Article 78 appeal filed on 72817 with oral argument completed in January 2019

On April 20 2017 the New York Public Service Commission issued a Rate Order relating to NFG Distributionrsquos rate case (No 16-G-0257) filed in April 2016

Utility

47

Utility Continues its Significant Investments in Safety

$544$618 $636

$699

$944$980

$809$856

$90-100

$00

$250

$500

$750

$1000

$1250

2015 2016 2017 2018 2019E

Cap

ital E

xpen

ditu

res

($ m

illio

ns)

Fiscal Year

Capital Expenditures for Safety Total Capital Expenditures

Modernization Spending in NY Expected to Grow Gross Margin By $2 MM - $5 MM in FY 2019

(1)

(1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation

Utility

System modernization tracker in NY allows recovery of pipeline replacementcosts which is expected to drive modest gross margin and rate base growth

48

Accelerating Pipeline Replacement amp Modernization

Wrought Iron

Plastic

CoatedBare

120130

146 144159

2014 2015 2016 2017 2018Calendar Year

NY9726 miles

PA4830 miles

No Cast Iron Mains in Pa

Miles of Utility Main Pipeline ReplacedUtility Mains by Material(1)

Wrought Iron

Cast Iron

Plastic

Coated Bare

Utility

(1) All values are reported on a calendar year basis as of December 31 2018

49

A Proven History of Controlling Costs

$200 $189 $195

$166 $166

$31 $31

$197 $197

$0

$50

$100

$150

$200

$250

2015 2016 2017 2018 TTM 123118

Fiscal Year

OampM Expense Non-Service Pension Costs

OampM Expense ($ millions)

Utility

(1)

(1) For purposes of comparability to FY 2015 2016 and 2017 Utility Operation and Maintenance Expense for FY 2018 and the twelve months ended December 31 2018 was adjusted by approximately $314 million and $312 million respectively to include non-service pension costs which were re-classified as Other Income (Deductions) as of October 1 2018 on the Companyrsquos Income Statement See Slide 64 for non-GAAP reconciliation of Adjusted Operation and Maintenance Expense to Operation and Maintenance Expense by segment

50

Consolidated Financial OverviewUpstream I Midstream I Downstream

51

Adjusted Operating Results ($ per share)(1)

Diversified Balanced Earnings and Cash Flows

(1) A reconciliation of Adjusted Operating Results to Earnings per Share by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation(2) Consolidated Adjusted EBITDA includes Energy Marketing and Corporate amp All Other Segments A reconciliation of Adjusted EBITDA to Net Income by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in

the Business is included at the end of this presentation

Adjusted EBITDA ($ millions)(2)

$176 $179

$184 $181

$92 $97

$318 $327

$761 $775

$-

$200

$400

$600

$800

FY 2018 TTM 123118

$059 Utility

$097 Pipeline amp Storage

$057 Gathering

$125 Exploration

amp Production

$334 $345 to $365

$-

$100

$200

$300

$400

FY 2018 FY 2019 Guidance

Rate Regulated

40-45

$728

Rate Regulated

~46

52

$89 $94 $98 $81 $86 $90-$100

$140$230

$114 $95 $93 $120-$150

$138$118

$54$33 $48

$55-$65

$603$557

$99 $246$356

$460-$495

$970 $1001

$366$455

$583

$725-$810

$0

$250

$500

$750

$1000

$1250

2014 2015 2016 2017 2018 2019GuidanceFiscal Year

Exploration amp Production

Gathering

Pipeline amp Storage

Utility

Disciplined Flexible Capital Allocation

(2)

(1) Total Capital Expenditures include Energy Marketing Corporate and All Other A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation (2) FY16 FY17 and FY18 reflects the netting of $157 million $7 million and $17 million respectively of up-front proceeds received from joint development partner for working interest in joint development wells and $21M in intercompany asset transfers in FY18

Capital Expenditures by Segment ($ millions)(1)

53

Maintaining Strong Balance Sheet amp Liquidity

Total Equity49

Total Debt51

$42 Billion Total Capitalizationas of December 31 2018

218 x251 x 245 x 247 x 256 x

2015 2016 2017 2018 TTM 123118Fiscal Year End

Net Debt Adjusted EBITDA(1) Capitalization

Debt Maturity Profile ($MM) Liquidity

Committed Credit FacilitiesShort-term Debt OutstandingAvailable Short-term Credit FacilitiesCash Balance at 123118 Total Liquidity at 123118

$ 750 MM0 MM

750 MM110 MM

$ 860 MM

$500 $549 $500

$300 $300

$0

$200

$400

$600

(1) Net Debt is net of cash and temporary cash investments Reconciliations of Net Debt and Adjusted EBITDA to Net Income are included at the end of this presentation

54

Appendix

55

Safe Harbor For Forward Looking StatementsThis presentation may contain ldquoforward-looking statementsrdquo as defined by the Private Securities Litigation Reform Act of 1995 including statements regarding future prospectsplans objectives goals projections estimates of oil and gas quantities strategies future events or performance and underlying assumptions capital structure anticipatedcapital expenditures completion of construction projects projections for pension and other post-retirement benefit obligations impacts of the adoption of new accounting rulesand possible outcomes of litigation or regulatory proceedings as well as statements that are identified by the use of the words ldquoanticipatesrdquo ldquoestimatesrdquo ldquoexpectsrdquo ldquoforecastsrdquoldquointendsrdquo ldquoplansrdquo ldquopredictsrdquo ldquoprojectsrdquo ldquobelievesrdquo ldquoseeksrdquo ldquowillrdquo ldquomayrdquo and similar expressions Forward-looking statements involve risks and uncertainties which couldcause actual results or outcomes to differ materially from those expressed in the forward-looking statements The Companyrsquos expectations beliefs and projections are expressedin good faith and are believed by the Company to have a reasonable basis but there can be no assurance that managementrsquos expectations beliefs or projections will result or beachieved or accomplished

In addition to other factors the following are important factors that could cause actual results to differ materially from those discussed in the forward-looking statements delaysor changes in costs or plans with respect to Company projects or related projects of other companies including difficulties or delays in obtaining necessary governmentalapprovals permits or orders or in obtaining the cooperation of interconnecting facility operators governmentalregulatory actions initiatives and proceedings including thoseinvolving rate cases (which address among other things target rates of return rate design and retained natural gas) environmentalsafety requirements affiliate relationshipsindustry structure and franchise renewal changes in laws regulations or judicial interpretations to which the Company is subject including those involving derivatives taxessafety employment climate change other environmental matters real property and exploration and production activities such as hydraulic fracturing financial and economicconditions including the availability of credit and occurrences affecting the Companyrsquos ability to obtain financing on acceptable terms for working capital capital expendituresand other investments including any downgrades in the Companyrsquos credit ratings and changes in interest rates and other capital market conditions changes in the price ofnatural gas or oil impairments under the SECrsquos full cost ceiling test for natural gas and oil reserves factors affecting the Companyrsquos ability to successfully identify drill for andproduce economically viable natural gas and oil reserves including among others geology lease availability title disputes weather conditions shortages delays orunavailability of equipment and services required in drilling operations insufficient gathering processing and transportation capacity the need to obtain governmentalapprovals and permits and compliance with environmental laws and regulations increasing health care costs and the resulting effect on health insurance premiums and on theobligation to provide other post-retirement benefits changes in price differentials between similar quantities of natural gas or oil sold at different geographic locations and theeffect of such changes on commodity production revenues and demand for pipeline transportation capacity to or from such locations other changes in price differentialsbetween similar quantities of natural gas or oil having different quality heating value hydrocarbon mix or delivery date the cost and effects of legal and administrative claimsagainst the Company or activist shareholder campaigns to effect changes at the Company uncertainty of oil and gas reserve estimates significant differences between theCompanyrsquos projected and actual production levels for natural gas or oil changes in demographic patterns and weather conditions changes in the availability price oraccounting treatment of derivative financial instruments changes in laws actuarial assumptions the interest rate environment and the return on plantrust assets related to theCompanyrsquos pension and other post-retirement benefits which can affect future funding obligations and costs and plan liabilities changes in economic conditions includingglobal national or regional recessions and their effect on the demand for and customersrsquo ability to pay for the Companyrsquos products and services the creditworthiness orperformance of the Companyrsquos key suppliers customers and counterparties the impact of potential information technology cybersecurity or data security breaches economicdisruptions or uninsured losses resulting from major accidents fires severe weather natural disasters terrorist activities or acts of war significant differences between theCompanyrsquos projected and actual capital expenditures and operating expenses or increasing costs of insurance changes in coverage and the ability to obtain insurance

Forward-looking statements include estimates of oil and gas quantities Proved oil and gas reserves are those quantities of oil and gas which by analysis of geoscience andengineering data can be estimated with reasonable certainty to be economically producible under existing economic conditions operating methods and governmentregulations Other estimates of oil and gas quantities including estimates of probable reserves possible reserves and resource potential are by their nature more speculativethan estimates of proved reserves Accordingly estimates other than proved reserves are subject to substantially greater risk of being actually realized Investors are urged toconsider closely the disclosure in our Form 10-K available at wwwnationalfuelgascom You can also obtain this form on the SECrsquos website at wwwsecgov

For a discussion of the risks set forth above and other factors that could cause actual results to differ materially from results referred to in the forward-looking statements seeldquoRisk Factorsrdquo in the Companyrsquos Form 10-K for the fiscal year ended September 30 2018 and the Forms 10-Q for the quarter ended March 31 2018 June 30 2018 and December31 2018 The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date thereof or to reflect the occurrence ofunanticipated events

Appendix

18

WDA Utica Appraisal Results and Initial Type Curve

Tested producing from 17 Utica wells in WDA-CRV Higher pressure significantly enhances well

productivity (Utica ~5000rsquo deeper than Marcellus) Drawdown management is critical restricted

drawdown appears to improve well EURs Early production declines much shallower vs

Marcellus

WDA Utica Appraisal Update

WDA Economics

(1) Internal Rate of Return (IRR) is pre-tax and includes estimated well costs under current cost structure LOEand anticipated gathering tariffs

(2) Initial WDA-CRV Utica type curve based on production results and reservoir expectations from the first 5appraisal wells in the WDA-CRV area

(3) WDA-CRV Utica Average includes all 17 producing wells including 2 wells (pad E09-S) for which drawdownmanagement was not used

EampP and Gathering

EURBcf1000rsquo

Well Cost$M1000rsquo

IRR $225

Break-even15 IRR(1)

Utica - CRV 17 $887 23 $197

Marcellus 10 ndash 11 $643 19 $206

(2)

0

1

2

3

4

5

6

7

8

9

0 12 24 36 48 60 72 84 96 108 120

Cum

ulat

ive

Prod

uctio

n B

CF

Months On

WDA-CRV Utica Wells - Normalized to 9000rsquoUtica Type Curve CRV Utica AverageWDA Marcellus Type Curve Boone Mountain Appraisal WellWDA-CRV Utica Type Curve(2) WDA-CRV Utica Average(3)

0005101520253035

0 2 4 6 8 10 12

19

Transitioning to Utica Development in CRV

WDA-CRV Marcellus(Depth ~7000 feet)

WDA-CRV Utica(Depth ~12000 feet)

Avg CRV Marcellus Production 270 MMcfd

Rem Avg EUR 10-11 Bcf 1000 lat ft

Rem Avg Well Costs = $643lat ft

120+ locations on existing Marcellus pads

Est EURs 17 Bcf 1000 lat ft

Est Development Well Costs = $887lat ft

CRV Utica Transition Plan

1)Finish Marcellus Pads in Development

Drill 24 complete 24 Marcellus wells

2)Continue Optimizing Utica DampC design

Additional optimization wells focusing on

Completion design

Landing zone targets

3)Continue transition to Utica development

Future drilling on multi-well pads

Continue using optimization results to determine development well design

Tailor development plan to use existing pad water and gathering infrastructure

CRV Utica Development Utilizes Existing Pad Water and Gathering Infrastructure to Drive Economics

EampP and Gathering

Rich Valley Utica Test

Existing Line

Leased

Seneca Fee

Producing

FY19 Producer

Development

20

Leveraging Existing Gathering Water and Pad Infrastructure Enhances Returns

Limited New Infrastructure Needed to Support Production Growth

WDA Well Costs(1) WDA Consolidated Economics

Steady activity levels and coordination between upstream and midstream activities

enhance returns provide economies of scale and significant operational flexibility

(1) WDA Marcellus well costs reflect drilling completion amp gathering costs for 192 drilled and completed wells as of 93018 WDA Utica well costs reflect expected drilling completion amp gathering costs for the ~120 well locations in area of redevelopment (2) Internal Rate of Return for Seneca WDA includes estimated well costs under current cost structure and anticipated LOE and Gathering costs Internal Rate of Return for Seneca WDA and Gathering includes expected gathering capital expenditures

through FY 2022 well costs under current cost structure and non-gathering LOE

$685$887

$210

$0

$200

$400

$600

$800

$1000

Marcellus(Historic)

Utica - CRV(Current)

$ la

tera

l foo

t

Drilling amp Completion Gathering

$931$895

10 -11

17

00

03

06

09

12

15

18

Marcellus(Historic)

Utica - CRV(Current)

EUR

10

00 fe

et (B

cf)

60-70 EUR increase expected per well

Total cost per well expected to marginally increase

WDA EURs

At a $225 netback price consolidated Seneca WDA and Gathering IRR is

approximately 33 an uplift of ~12 over standalone Seneca WDA economics(2)

10+ IRR Uplift Expected

21

Integrated Development ndash WDA Gathering System

Current System In-Service

~78 miles of pipe 36220 HP of compression

Current Capacity 470 MMcf per day

Interconnects with TGP 300

Total Investment to Date $301 million

Future Build-Out

FY 2019 CapEx $10 - $15 million

Modest gathering pipeline and compression investment required to support Senecarsquos transition to Utica development

Opportunity for 300 miles of pipelines and five compressor stations (+60000 HP installed) as Senecarsquos drilling activity continues

Deliverability into TGP 300 and NFG Supply

Gathering System Build-Out Tailored to Accommodate Senecarsquos WDA Development

Clermont Gathering System Map

EampP and Gathering

22

WDA Firm Transportation and Sales Capacity

Will continue to layer-in firm sales deals of short and longer duration on TGP 300 to reduce spot exposure

WDA spot realizations track TGP Station 313 pricing typically 10cent - 30cent better than TGP Marcellus Zone 4

Leidy South will provide additional capacity to premium markets (Transco Zone 6)

WDA Exit Capacity Supports Long-term Production Growth and Enhances Consolidated Returns

WDA Contracted Firm Transport and Gross Sales Volumes (MDthd)

Seneca gross production trend

EampP and Gathering

0

100

200

300

400

500

600

700

Niagara Expansion Project (TGP and NFG)FT Capacity 158000 Dthd $067Dth

Firm Sales NYMEX amp DAWN

WDA - TGP 300Firm Sales

Leidy SouthTransco Zone 6

Markets330000 Dthd(1)

Will layer-in firm sales to minimize spot exposure

(1) Portion of Transco Project capacity will likely be utilized by EDA Lycoming County production

WDA Gas Marketing Strategy

23

Eastern Development Area

EDA Acreage ndash 70000 AcresEDA Highlights

1 DCNR Tract 007 (Tioga Co Pa)bull Utica development resumed in third quarter fiscal 2018

bull ~43 remaining Utica locations economic at ~$184 Mcf

bull Gathering Infrastructure NFG Midstream Wellsboro

bull Marcellus Shale expected to provide ~60 additional locations

EampP and Gathering

2

1

3

2 Covington amp DCNR Tract 595 (Tioga Co Pa)bull Marcellus locations fully developed (average daily gross production of ~93 MMcfd)

bull Gathering Infrastructure NFG Midstream Covington

bull Opportunity for future Utica appraisal

3 DCNR Tract 100 amp Gamble (Lycoming Co Pa)bull ~45 remaining Marcellus locations economic at ~$153 Mcfbull Firm Transportation Capacity Atlantic Sunrise (189 MDthd)

bull Gathering Infrastructure NFG Midstream Trout Run

bull Geneseo Shale expected to provide 100-120 additional locations

24

EDA Marcellus Lycoming County Development

Marcellus Development in Lycoming County has Resumed in Connection with Atlantic Sunrise

(1) Includes physical fixed price and NYMEX-based firm sales contracts that do not carry any additional transportation costs

EampP and Gathering

Prolific Marcellus acreage with peer leading well results

~45 remaining Marcellus locations economic at ~$153 Mcf

Near-term development focused on filling Atlantic Sunrise capacity

Existing Line

Leased

Seneca Fee

Producing

FY19 Producer

Development

0

50

100

150

200

250

Gro

ss F

irm V

olum

es (M

Dth

d)

EDA ndash Transco Firm Contracts

Atlantic Sunrise (Transco)FT Capacity 189405 Dthd

Cost $073DthFirm Sales NYMEX+

Transco Firm Sales(1)

25

EDA Utica Tioga County Development

Utica Development in Tioga County ndash Tract 007 Development Resumed in Q3 Fiscal 2018

In-Service November 2016

Lateral Length 4640 ft

30 Day IP 1000 ft 34 MMcfd

Est EUR 1000 ft 24 Bcf

Inventory ~43 locations economic at ~$184 Mcf

Targeting to grow production by 100 to 150 MDthd by fiscal 2020

Expected Development Costs $1045 per lateral ft

Gathering Infrastructure NFG Midstream Wellsboro

Modest build-out required to connect to TGP 300

SalesTakeaway Strategy Layer-in firm sales with shippers holding capacity on TGP 300

(1) Includes physical fixed price and NYMEX-based firm sales contracts that do not carry any additional transportation costs

Tract 007 Utica Appraisal Well Results vs Industry

EampP and Gathering

0

100000

200000

300000

400000

500000

600000

700000

800000

0 100 200 300

Nor

mal

ized

Cum

ulat

ive

(Mcf

10

00rsquo)

Days On ProductionIndustry PotterTioga Wells Seneca DCNR 007 73H

0

25

50

75

100

125

150

Gro

ss F

irm V

olum

es (M

Dth

d)

EDA ndash TGP 300 Firm Contracts

Northeast Supply Diversification ProjectFT Capacity 50000 Dthd $050Dth

Firm Sales NYMEX and DAWN

EDA - TGP 300Firm Sales(1)

26

Integrated Development ndash EDA Gathering Systems

Total Investment (to date) ~$46 million FY 2019 Estimated Capital Expenditures $1 MM - $2 MM Capacity 220000 Dth per day (Interconnect w TGP 300) Production Source Seneca Resources ndash Tioga Co (Covington and DCNR Tract 595)

Total Investment (to date) ~$208 million FY 2019 Estimated Capital Expenditures $25 MM - $35 MM Capacity 466000 to 585000 Dth per day (Interconnect w Transco) Production Source Seneca Resources ndash Lycoming Co (DCNR Tract 100 and Gamble) Future third-party volume opportunities

Covington Gathering System

Trout Run Gathering System

Gathering Segment Supporting Senecarsquos EDA Production amp Future Development

Wellsboro Gathering System Total Investment (to date) ~$14 million FY 2019 Estimated Capital Expenditures $8 MM - $15 MM Capacity up to 200000 Dth per day (Interconnect w TGP 300) Production Source Seneca Resources ndash Tioga Co (DCNR Tract 007)

EampP and Gathering

2

1

3

27

Long-term Contracts Supporting Appalachian Growth

(1) Represents base firm sales contracts not tied to firm transportation capacity Base firm sales are either fixed priced or priced at an index (eg NYMEX ) +- a fixed basis and do not carry any transportation costs

Seneca continues to layer-in firm sales contracts with attractive realizations to lock-in drilling economics and minimize spot exposure ahead of firm transportation in-service dates

EampP and Gathering

-

100

200

300

400

500

600

700

800

900

1000

1100

1200

FY 2019 FY 2020 FY 2021 FY 2022Northeast Supply Diversification 50000 Dthd

Niagara Expansion (TGP amp NFG)Delivery Markets Canada-Dawn amp TETCO

158000 Dthd

Atlantic Sunrise (Transco)Delivery Markets Mid-Atlantic amp Southeast US

189405 Dthd

In-BasinFirm Sales

Contracts(1)

Leidy South (Transco amp NFG)

Transco Zone 6 Markets330000 Dthd

Seneca Appalachia Natural Gas MarketingGross Firm Contract Volumes (Mdthday)

28

297000 ($061)

305200 ($061)

305600 ($063)

337000 ($057)

370800 ($024)

369600 ($060)

367900 ($067)

33400 ($070)74500 ($077) 74900 ($077)

81100 ($078)

85900 ($078)

92000 ($073)

91300 ($073)

178800 $255

196000 $234

195500 $234

149900 $232

129500 $230

105400 $222

104500 $222

~517800 509200 575700 576000 568000 586200 567000 563700

Q1 FY19 Q2 FY19 Q3 FY19 Q4 FY19 Q1 FY20 Q2 FY20 Q3 FY20 Q4 FY20

Fixed Price Dawn NYMEX

Near-term Firm Sales Provide Market amp Price Certainty

Net Contracted Firm Sales Volumes (Dth per day)Contracted Index Price Differentials ($ per Dth)(1)

(1) Values shown represent the weighted average fixed price or contracted fixed differential relative to NYMEX (netback price) less any associated transportation costs

Actual Daily Net

Production

641200 716500 708700 693500 708400 674400 667000Gross Firm Sales Volumes (Dthd)

EampP and Gathering

29

California Oil

Stable Oil Production | Minimal Capital Investment | Steady Free Cash Flow

1

2

3

4

5

Location Formation Production Method

FY18 Daily Production(net Boed)

1 East Coalinga Other Temblor Primary 512

2 North Lost Hills

Tulare amp Etchegoin

PrimarySteam flood 892

3 South Lost Hills

Monterey Shale Primary 1359

4 North Midway Sunset

Tulare amp Potter Steam flood 2786

5 South Midway Sunset Antelope Steam flood 2048

TOTAL WEST DIVISION NET PRODUCTION(1) 7597 Boed

EampP and Gathering

(1) West division net production for FY 2018 excludes production from Sespe field which was divested on May 1 2018

30

California Capital Expenditures vs Production

9341 8863

8033 ~7300

2016 2017 2018 2019

Fiscal Year

West Division Average Net Daily Production (Boe)West Division Annual Capital Expenditures ($ MM)(1)

$38 $38

$26 ~$25

2016 2017 2018 2019

Fiscal YearGuidance Guidance

(1) Seneca West Division capital expenditures includes Seneca corporate and eliminations

EampP and Gathering

Sepse Sale Closed on 5118(reduced production by ~900 boed)

31

Pioneer

South MWSS

Acreage

North MWSS

AcreageSec 17N

4149 51

NMWSS amp 17N SMWSS amp Pioneer East Coalinga

California Development Activities

Modest near-term capital program focused on locations that earn attractive returns in current oil price environment

AampD will focus on low cost bolt-on opportunities

Sec 17 Pioneer and East Coalinga development to provide future growth

North

Project IRRs at $55Bbl(1)

(1) Reflects pre-tax IRRs at a $55Bbl WTI

EampP and Gathering

Seneca West Economics

South

East Coalinga

North

South

32

Fiscal 2019 Production and Price Certainty

~49 Bcfe

210 ndash 230 Bcfe

~114 Bcf

~29 Bcf (2)

16+- Bcf~12 Bcfe

0

40

80

120

160

200

240

YTD FY19Actuals

Fixed Price + FirmSales w Hedge

Firm Sales(Unhedged)

Spot Sales California TotalSeneca

Prod

uctio

n (B

cfe)

(1) Average realized price reflects uplift from financial hedges less fixed differentials under firm sales contracts and any firm transportation costs(2) Indicates firm sales contracts with fixed index differentials but not backed by a matching financial hedge

114 Bcf locked-in realizing net ~$241Mcf (1)

29 Bcf of additional basis protection

Spot production assumed to be sold

at ~$275Mmbtu(winter) and ~$225

(summer)

143 Bcf of Appalachian Production Protected by Firm Sales for Remainder of Year

79 of oil production hedged at $5757 Bbl

EampP and Gathering

33

Strong Hedge Book

Natural Gas Swap amp Fixed Physical Sales Contracts (Millions MMBtu)

(1) Fixed price physical sales exclude joint development partnerrsquos share of fixed price contract WDA volumes as specified under the joint development agreement(2) Reflects percentage of projected production for FY19 hedged at the midpoint of the production guidance range(3) Senecarsquos remainder FY19 Production reflects the total FY19 production guidance of 210-230 Bcfe or 220 Bcfe at the midpoint less Q1 actual production

Crude Oil Swap Contracts (Thousands Bbls)

13591188

732

456

0

500

1000

1500

2000

2500

FY 2019 FY 2020 FY 2021 FY 2022

NYMEX (WTI)

Brent

FY 19 Crude Oil79 Hedged (2)

FY 2019 Remaining Production (3)

EampP and Gathering

1174

709

469 406

0

50

100

150

200

250

FY 2019 FY 2020 FY 2021 FY 2022

NYMEX Swaps

Dawn Swaps

Fixed Price Physical Sales

(1)

FY 2019 Remaining Production (3)

FY 19 Nat Gas71 Hedged (2)

34

$065 $070$070 -$075

FY 2017 FY 2018 FY 2019E

$060 $060 $060

$011 $009 $007$071 $069 ~$067

FY 2017 FY 2018 FY 2019E Gathering amp Transport LOE (non-Gathering) GampA Taxes amp Other

Seneca Operating Costs

Competitive low cost structure in Appalachia and California supports strong cash margins

Gathering fee generates significant revenue stream for affiliated gathering company

Seneca DDampARate

$Mcfe

$054 $054 $056

$042 $038 $031

$034 $034 $030

$017 $014 $015

$147 $140 ~$132

FY 2017 FY 2018 FY 2019E

(1)

$1791$1746~$2050

FY 2017 FY 2018 FY 2019E

Appalachia LOE amp Gathering $Mcfe

California LOE$Boe

Total Seneca Cash OpEx$Mcfe

(1)

(2)

(2)

(1) GampA estimate represents the midpoint of the GampA guidance range of $025 to $035 for fiscal 2019(2) The total of the two LOE components represents the midpoint of the LOE guidance range of $085 to $090 for fiscal 2019

EampP and Gathering

35

Senecarsquos Continuing Commitment to the Environment

Produced Water Recycled in Appalachia

100 70Recycled Water

Used in New Shale Well

Completions

Water and Fluids Management Air Quality and Emissions

Seneca Resources Water OperationsFiscal 2018

Seneca Resources Remains Focused on Minimizing GHG Emissions

The Environmental Partnership

EPA Natural Gas Star Program

Green Completions (all fiscal 2018 wells)

Ultrasonic Leak Detection Technology

Emissions Controls

Rig and Vehicle Fuel Conversion

Integrating Renewable Energy into Operations

EampP and Gathering

36

Pipeline and Storage OverviewNational Fuel Gas Supply Corporation ~ Empire Pipeline Inc

37

Pipeline amp Storage Segment Overview

(1) As of September 30 2018 as disclosed in the Companyrsquos fiscal 2018 form 10-K(2) As of December 31 2017 calculated from National Fuel Gas Supply Corporationrsquos and Empire Pipeline Incrsquos 2017 FERC Form-2 reports respectively

Empire Pipeline Inc

National Fuel Gas Supply Corporation

Empire Pipeline

Supply Corp

Contracted Capacity(1) Firm Transportation 3187 MDth per day Firm Storage 71938 Mdth (fully subscribed)

Rate Base(2) ~$820 million FERC Rate Proceeding Status

Rate case settlement extension approved Nov lsquo15 Rate case filing expected by 73119

Contracted Capacity(1) Firm Transportation 978 MDth per day Firm Storage 3753 Mdth (fully subscribed)

Rate Base(2) ~$249 million FERC Rate Proceeding Status

Rate case settlement in principle reached on 122118 FERC approval pending

New transportation rates went into on 1119

Pipeline amp Storage

38

All Seneca volumes will flow through wholly-owned NFG gathering facilities

FM100 Project - Consolidated Benefit for NFG

330000 Dthd of new transportation capacity from WDA and EDA acreage positions to premium markets

New Transco capacity (Leidy South) 330000 Dthday

Rate(1) competitive with other expansion project rates in Senecarsquos current transportation portfolio

Delivery Point(s) Transco Zone 6 interconnections

Seneca

Lease to Transco of new capacity 330000 Dthday

Estimated annual lease revenues ~$35 million

Target In-Service late calendar year 2021

Supply Corp

Project expected to provide long-term earnings uplift to Seneca Supply Corp and Gathering

Pipeline amp Storage

Gathering

(1) Includes lease of new capacity from Supply Corp to Transco

39

FM100 Project ndash Significant Investment by Supply Corp

Pipeline amp Storage

Estimated Capital Cost $280 million(1)

Facilities (all in Pennsylvania) include Approximately 30 miles of new pipeline 2 new compressor stations (totaling

approximately 37000 HP) New interconnection station and modification

of existing interconnection station Abandonment of approximately 45 miles of

existing pipeline and compressor station Regulatory Process

Pre-filing application submitted to FERC in 2017 for original modernization project

FERC 7(b) 7(c) filing expected summer 2019

(1) Includes expansion and modernization portions of the project

40

Empire North Project

Target In-Service second half of fiscal 2020

Est Capital Cost $145 million

Est Annual Revenues ~$25 million

Receipt Point Jackson (Tioga Co Pa production)

Design Capacity and Delivery Points 175000 Dthd to Chippawa (TCPL interconnect)

30000 Dthd to Hopewell (TGP 200 interconnect)

Customers Fully subscribed (205000 Dthday)

Major Facilities 2 new compressor stations in NY (1) amp Pa (1)

No new pipeline construction

Regulatory Process FERC 7(c) application filed on 21618

FERC Environmental Assessment issued 103018

Pipeline amp Storage

Fully Subscribed Project will Provide 205000 Dthday of Incremental Firm Transportation

41

National Fuel Remains Committed to Northern Access Project

Target In-Service as early as fiscal 2022

Total Cost ~$500MM (~$76MM spent to date)

Estimated Annual Revenues ~$84 million

Delivery Points

350000 Dthd to Chippawa (TCPL interconnect)

140000 Dthd to Hopewell (TGP 200 line)

Regulatory Status

February 3 2017 ndash FERC 7(c) certificate issued

August 6 2018 ndash FERC issued Order finding that NY DEC waived water quality certification

Supply and Empire currently working to finalize remaining federal authorizations

Pipeline amp Storage

To Dawn

42

Continued Expansion of the NFG Supply System

Line N Expansion Opportunities

Line N to Monaca Project Project Firm transportation service to a new ethane

cracker facility being built by Shell Chemical Appalachia LLC

Target In-Service July 2019

Estimated Capital Cost $23 million

Contracted Capacity 133000 Dthday

Additional Line N Expansion Opportunity (Supply OS 221) Project New firm transportation service for on-system

demand

Open Season Capacity Awarded 165000 to foundation shipper Precedent agreement in negotiations

Pipeline amp Storage

43

Pipeline amp Storage Customer Mix

Producer33

LDC42

Marketer10

Outside Pipeline

9

End User6

42 MMDthd

(1) Contracted as of 10312018

Customer Transportation by Shipper Type(1) Affiliated Customer Mix (Contracted Capacity)

66

521

41

34

9579

59

LDCs Producers Marketers FirmStorage

Affiliated Non-Affiliated

Firm Transport

Pipeline amp Storage

44

Utility OverviewNational Fuel Gas Distribution Corporation

45

New York amp Pennsylvania Service Territories

New York

Total Customers(1) 535800ROE 87 (NY PSC Rate Case Order April 2017)Rate Mechanismso Revenue Decouplingo Weather Normalizationo Low Income Rateso Merchant Function Charge (Uncollectibles Adj)o 9010 Sharing (Large Customers)o System Modernization Tracker

Pennsylvania

Total Customers(1) 214400ROE Black Box Settlement (2007)Rate Mechanismso Low Income Rateso Merchant Function Charge

(1) As of September 30 2018

Utility

46

New York Rate Case Outcome

Rate Order Summary

Revenue Requirement $59 million

Rate Base $704 million

Allowed Return on Equity (ROE) 87

Capital Structure 429 equity

Other notable items

New rates became effective 5117

Retains rate mechanisms in place under prior order (revenue decoupling weather normalization merchant function charge 9010 large customer sharing)

No stay-out clause

System modernization tracker for Leak Prone Pipe (LPP)

Earnings sharing started 4118 (5050 sharing starts at earnings in excess of 92)

Article 78 appeal filed on 72817 with oral argument completed in January 2019

On April 20 2017 the New York Public Service Commission issued a Rate Order relating to NFG Distributionrsquos rate case (No 16-G-0257) filed in April 2016

Utility

47

Utility Continues its Significant Investments in Safety

$544$618 $636

$699

$944$980

$809$856

$90-100

$00

$250

$500

$750

$1000

$1250

2015 2016 2017 2018 2019E

Cap

ital E

xpen

ditu

res

($ m

illio

ns)

Fiscal Year

Capital Expenditures for Safety Total Capital Expenditures

Modernization Spending in NY Expected to Grow Gross Margin By $2 MM - $5 MM in FY 2019

(1)

(1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation

Utility

System modernization tracker in NY allows recovery of pipeline replacementcosts which is expected to drive modest gross margin and rate base growth

48

Accelerating Pipeline Replacement amp Modernization

Wrought Iron

Plastic

CoatedBare

120130

146 144159

2014 2015 2016 2017 2018Calendar Year

NY9726 miles

PA4830 miles

No Cast Iron Mains in Pa

Miles of Utility Main Pipeline ReplacedUtility Mains by Material(1)

Wrought Iron

Cast Iron

Plastic

Coated Bare

Utility

(1) All values are reported on a calendar year basis as of December 31 2018

49

A Proven History of Controlling Costs

$200 $189 $195

$166 $166

$31 $31

$197 $197

$0

$50

$100

$150

$200

$250

2015 2016 2017 2018 TTM 123118

Fiscal Year

OampM Expense Non-Service Pension Costs

OampM Expense ($ millions)

Utility

(1)

(1) For purposes of comparability to FY 2015 2016 and 2017 Utility Operation and Maintenance Expense for FY 2018 and the twelve months ended December 31 2018 was adjusted by approximately $314 million and $312 million respectively to include non-service pension costs which were re-classified as Other Income (Deductions) as of October 1 2018 on the Companyrsquos Income Statement See Slide 64 for non-GAAP reconciliation of Adjusted Operation and Maintenance Expense to Operation and Maintenance Expense by segment

50

Consolidated Financial OverviewUpstream I Midstream I Downstream

51

Adjusted Operating Results ($ per share)(1)

Diversified Balanced Earnings and Cash Flows

(1) A reconciliation of Adjusted Operating Results to Earnings per Share by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation(2) Consolidated Adjusted EBITDA includes Energy Marketing and Corporate amp All Other Segments A reconciliation of Adjusted EBITDA to Net Income by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in

the Business is included at the end of this presentation

Adjusted EBITDA ($ millions)(2)

$176 $179

$184 $181

$92 $97

$318 $327

$761 $775

$-

$200

$400

$600

$800

FY 2018 TTM 123118

$059 Utility

$097 Pipeline amp Storage

$057 Gathering

$125 Exploration

amp Production

$334 $345 to $365

$-

$100

$200

$300

$400

FY 2018 FY 2019 Guidance

Rate Regulated

40-45

$728

Rate Regulated

~46

52

$89 $94 $98 $81 $86 $90-$100

$140$230

$114 $95 $93 $120-$150

$138$118

$54$33 $48

$55-$65

$603$557

$99 $246$356

$460-$495

$970 $1001

$366$455

$583

$725-$810

$0

$250

$500

$750

$1000

$1250

2014 2015 2016 2017 2018 2019GuidanceFiscal Year

Exploration amp Production

Gathering

Pipeline amp Storage

Utility

Disciplined Flexible Capital Allocation

(2)

(1) Total Capital Expenditures include Energy Marketing Corporate and All Other A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation (2) FY16 FY17 and FY18 reflects the netting of $157 million $7 million and $17 million respectively of up-front proceeds received from joint development partner for working interest in joint development wells and $21M in intercompany asset transfers in FY18

Capital Expenditures by Segment ($ millions)(1)

53

Maintaining Strong Balance Sheet amp Liquidity

Total Equity49

Total Debt51

$42 Billion Total Capitalizationas of December 31 2018

218 x251 x 245 x 247 x 256 x

2015 2016 2017 2018 TTM 123118Fiscal Year End

Net Debt Adjusted EBITDA(1) Capitalization

Debt Maturity Profile ($MM) Liquidity

Committed Credit FacilitiesShort-term Debt OutstandingAvailable Short-term Credit FacilitiesCash Balance at 123118 Total Liquidity at 123118

$ 750 MM0 MM

750 MM110 MM

$ 860 MM

$500 $549 $500

$300 $300

$0

$200

$400

$600

(1) Net Debt is net of cash and temporary cash investments Reconciliations of Net Debt and Adjusted EBITDA to Net Income are included at the end of this presentation

54

Appendix

55

Safe Harbor For Forward Looking StatementsThis presentation may contain ldquoforward-looking statementsrdquo as defined by the Private Securities Litigation Reform Act of 1995 including statements regarding future prospectsplans objectives goals projections estimates of oil and gas quantities strategies future events or performance and underlying assumptions capital structure anticipatedcapital expenditures completion of construction projects projections for pension and other post-retirement benefit obligations impacts of the adoption of new accounting rulesand possible outcomes of litigation or regulatory proceedings as well as statements that are identified by the use of the words ldquoanticipatesrdquo ldquoestimatesrdquo ldquoexpectsrdquo ldquoforecastsrdquoldquointendsrdquo ldquoplansrdquo ldquopredictsrdquo ldquoprojectsrdquo ldquobelievesrdquo ldquoseeksrdquo ldquowillrdquo ldquomayrdquo and similar expressions Forward-looking statements involve risks and uncertainties which couldcause actual results or outcomes to differ materially from those expressed in the forward-looking statements The Companyrsquos expectations beliefs and projections are expressedin good faith and are believed by the Company to have a reasonable basis but there can be no assurance that managementrsquos expectations beliefs or projections will result or beachieved or accomplished

In addition to other factors the following are important factors that could cause actual results to differ materially from those discussed in the forward-looking statements delaysor changes in costs or plans with respect to Company projects or related projects of other companies including difficulties or delays in obtaining necessary governmentalapprovals permits or orders or in obtaining the cooperation of interconnecting facility operators governmentalregulatory actions initiatives and proceedings including thoseinvolving rate cases (which address among other things target rates of return rate design and retained natural gas) environmentalsafety requirements affiliate relationshipsindustry structure and franchise renewal changes in laws regulations or judicial interpretations to which the Company is subject including those involving derivatives taxessafety employment climate change other environmental matters real property and exploration and production activities such as hydraulic fracturing financial and economicconditions including the availability of credit and occurrences affecting the Companyrsquos ability to obtain financing on acceptable terms for working capital capital expendituresand other investments including any downgrades in the Companyrsquos credit ratings and changes in interest rates and other capital market conditions changes in the price ofnatural gas or oil impairments under the SECrsquos full cost ceiling test for natural gas and oil reserves factors affecting the Companyrsquos ability to successfully identify drill for andproduce economically viable natural gas and oil reserves including among others geology lease availability title disputes weather conditions shortages delays orunavailability of equipment and services required in drilling operations insufficient gathering processing and transportation capacity the need to obtain governmentalapprovals and permits and compliance with environmental laws and regulations increasing health care costs and the resulting effect on health insurance premiums and on theobligation to provide other post-retirement benefits changes in price differentials between similar quantities of natural gas or oil sold at different geographic locations and theeffect of such changes on commodity production revenues and demand for pipeline transportation capacity to or from such locations other changes in price differentialsbetween similar quantities of natural gas or oil having different quality heating value hydrocarbon mix or delivery date the cost and effects of legal and administrative claimsagainst the Company or activist shareholder campaigns to effect changes at the Company uncertainty of oil and gas reserve estimates significant differences between theCompanyrsquos projected and actual production levels for natural gas or oil changes in demographic patterns and weather conditions changes in the availability price oraccounting treatment of derivative financial instruments changes in laws actuarial assumptions the interest rate environment and the return on plantrust assets related to theCompanyrsquos pension and other post-retirement benefits which can affect future funding obligations and costs and plan liabilities changes in economic conditions includingglobal national or regional recessions and their effect on the demand for and customersrsquo ability to pay for the Companyrsquos products and services the creditworthiness orperformance of the Companyrsquos key suppliers customers and counterparties the impact of potential information technology cybersecurity or data security breaches economicdisruptions or uninsured losses resulting from major accidents fires severe weather natural disasters terrorist activities or acts of war significant differences between theCompanyrsquos projected and actual capital expenditures and operating expenses or increasing costs of insurance changes in coverage and the ability to obtain insurance

Forward-looking statements include estimates of oil and gas quantities Proved oil and gas reserves are those quantities of oil and gas which by analysis of geoscience andengineering data can be estimated with reasonable certainty to be economically producible under existing economic conditions operating methods and governmentregulations Other estimates of oil and gas quantities including estimates of probable reserves possible reserves and resource potential are by their nature more speculativethan estimates of proved reserves Accordingly estimates other than proved reserves are subject to substantially greater risk of being actually realized Investors are urged toconsider closely the disclosure in our Form 10-K available at wwwnationalfuelgascom You can also obtain this form on the SECrsquos website at wwwsecgov

For a discussion of the risks set forth above and other factors that could cause actual results to differ materially from results referred to in the forward-looking statements seeldquoRisk Factorsrdquo in the Companyrsquos Form 10-K for the fiscal year ended September 30 2018 and the Forms 10-Q for the quarter ended March 31 2018 June 30 2018 and December31 2018 The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date thereof or to reflect the occurrence ofunanticipated events

Appendix

19

Transitioning to Utica Development in CRV

WDA-CRV Marcellus(Depth ~7000 feet)

WDA-CRV Utica(Depth ~12000 feet)

Avg CRV Marcellus Production 270 MMcfd

Rem Avg EUR 10-11 Bcf 1000 lat ft

Rem Avg Well Costs = $643lat ft

120+ locations on existing Marcellus pads

Est EURs 17 Bcf 1000 lat ft

Est Development Well Costs = $887lat ft

CRV Utica Transition Plan

1)Finish Marcellus Pads in Development

Drill 24 complete 24 Marcellus wells

2)Continue Optimizing Utica DampC design

Additional optimization wells focusing on

Completion design

Landing zone targets

3)Continue transition to Utica development

Future drilling on multi-well pads

Continue using optimization results to determine development well design

Tailor development plan to use existing pad water and gathering infrastructure

CRV Utica Development Utilizes Existing Pad Water and Gathering Infrastructure to Drive Economics

EampP and Gathering

Rich Valley Utica Test

Existing Line

Leased

Seneca Fee

Producing

FY19 Producer

Development

20

Leveraging Existing Gathering Water and Pad Infrastructure Enhances Returns

Limited New Infrastructure Needed to Support Production Growth

WDA Well Costs(1) WDA Consolidated Economics

Steady activity levels and coordination between upstream and midstream activities

enhance returns provide economies of scale and significant operational flexibility

(1) WDA Marcellus well costs reflect drilling completion amp gathering costs for 192 drilled and completed wells as of 93018 WDA Utica well costs reflect expected drilling completion amp gathering costs for the ~120 well locations in area of redevelopment (2) Internal Rate of Return for Seneca WDA includes estimated well costs under current cost structure and anticipated LOE and Gathering costs Internal Rate of Return for Seneca WDA and Gathering includes expected gathering capital expenditures

through FY 2022 well costs under current cost structure and non-gathering LOE

$685$887

$210

$0

$200

$400

$600

$800

$1000

Marcellus(Historic)

Utica - CRV(Current)

$ la

tera

l foo

t

Drilling amp Completion Gathering

$931$895

10 -11

17

00

03

06

09

12

15

18

Marcellus(Historic)

Utica - CRV(Current)

EUR

10

00 fe

et (B

cf)

60-70 EUR increase expected per well

Total cost per well expected to marginally increase

WDA EURs

At a $225 netback price consolidated Seneca WDA and Gathering IRR is

approximately 33 an uplift of ~12 over standalone Seneca WDA economics(2)

10+ IRR Uplift Expected

21

Integrated Development ndash WDA Gathering System

Current System In-Service

~78 miles of pipe 36220 HP of compression

Current Capacity 470 MMcf per day

Interconnects with TGP 300

Total Investment to Date $301 million

Future Build-Out

FY 2019 CapEx $10 - $15 million

Modest gathering pipeline and compression investment required to support Senecarsquos transition to Utica development

Opportunity for 300 miles of pipelines and five compressor stations (+60000 HP installed) as Senecarsquos drilling activity continues

Deliverability into TGP 300 and NFG Supply

Gathering System Build-Out Tailored to Accommodate Senecarsquos WDA Development

Clermont Gathering System Map

EampP and Gathering

22

WDA Firm Transportation and Sales Capacity

Will continue to layer-in firm sales deals of short and longer duration on TGP 300 to reduce spot exposure

WDA spot realizations track TGP Station 313 pricing typically 10cent - 30cent better than TGP Marcellus Zone 4

Leidy South will provide additional capacity to premium markets (Transco Zone 6)

WDA Exit Capacity Supports Long-term Production Growth and Enhances Consolidated Returns

WDA Contracted Firm Transport and Gross Sales Volumes (MDthd)

Seneca gross production trend

EampP and Gathering

0

100

200

300

400

500

600

700

Niagara Expansion Project (TGP and NFG)FT Capacity 158000 Dthd $067Dth

Firm Sales NYMEX amp DAWN

WDA - TGP 300Firm Sales

Leidy SouthTransco Zone 6

Markets330000 Dthd(1)

Will layer-in firm sales to minimize spot exposure

(1) Portion of Transco Project capacity will likely be utilized by EDA Lycoming County production

WDA Gas Marketing Strategy

23

Eastern Development Area

EDA Acreage ndash 70000 AcresEDA Highlights

1 DCNR Tract 007 (Tioga Co Pa)bull Utica development resumed in third quarter fiscal 2018

bull ~43 remaining Utica locations economic at ~$184 Mcf

bull Gathering Infrastructure NFG Midstream Wellsboro

bull Marcellus Shale expected to provide ~60 additional locations

EampP and Gathering

2

1

3

2 Covington amp DCNR Tract 595 (Tioga Co Pa)bull Marcellus locations fully developed (average daily gross production of ~93 MMcfd)

bull Gathering Infrastructure NFG Midstream Covington

bull Opportunity for future Utica appraisal

3 DCNR Tract 100 amp Gamble (Lycoming Co Pa)bull ~45 remaining Marcellus locations economic at ~$153 Mcfbull Firm Transportation Capacity Atlantic Sunrise (189 MDthd)

bull Gathering Infrastructure NFG Midstream Trout Run

bull Geneseo Shale expected to provide 100-120 additional locations

24

EDA Marcellus Lycoming County Development

Marcellus Development in Lycoming County has Resumed in Connection with Atlantic Sunrise

(1) Includes physical fixed price and NYMEX-based firm sales contracts that do not carry any additional transportation costs

EampP and Gathering

Prolific Marcellus acreage with peer leading well results

~45 remaining Marcellus locations economic at ~$153 Mcf

Near-term development focused on filling Atlantic Sunrise capacity

Existing Line

Leased

Seneca Fee

Producing

FY19 Producer

Development

0

50

100

150

200

250

Gro

ss F

irm V

olum

es (M

Dth

d)

EDA ndash Transco Firm Contracts

Atlantic Sunrise (Transco)FT Capacity 189405 Dthd

Cost $073DthFirm Sales NYMEX+

Transco Firm Sales(1)

25

EDA Utica Tioga County Development

Utica Development in Tioga County ndash Tract 007 Development Resumed in Q3 Fiscal 2018

In-Service November 2016

Lateral Length 4640 ft

30 Day IP 1000 ft 34 MMcfd

Est EUR 1000 ft 24 Bcf

Inventory ~43 locations economic at ~$184 Mcf

Targeting to grow production by 100 to 150 MDthd by fiscal 2020

Expected Development Costs $1045 per lateral ft

Gathering Infrastructure NFG Midstream Wellsboro

Modest build-out required to connect to TGP 300

SalesTakeaway Strategy Layer-in firm sales with shippers holding capacity on TGP 300

(1) Includes physical fixed price and NYMEX-based firm sales contracts that do not carry any additional transportation costs

Tract 007 Utica Appraisal Well Results vs Industry

EampP and Gathering

0

100000

200000

300000

400000

500000

600000

700000

800000

0 100 200 300

Nor

mal

ized

Cum

ulat

ive

(Mcf

10

00rsquo)

Days On ProductionIndustry PotterTioga Wells Seneca DCNR 007 73H

0

25

50

75

100

125

150

Gro

ss F

irm V

olum

es (M

Dth

d)

EDA ndash TGP 300 Firm Contracts

Northeast Supply Diversification ProjectFT Capacity 50000 Dthd $050Dth

Firm Sales NYMEX and DAWN

EDA - TGP 300Firm Sales(1)

26

Integrated Development ndash EDA Gathering Systems

Total Investment (to date) ~$46 million FY 2019 Estimated Capital Expenditures $1 MM - $2 MM Capacity 220000 Dth per day (Interconnect w TGP 300) Production Source Seneca Resources ndash Tioga Co (Covington and DCNR Tract 595)

Total Investment (to date) ~$208 million FY 2019 Estimated Capital Expenditures $25 MM - $35 MM Capacity 466000 to 585000 Dth per day (Interconnect w Transco) Production Source Seneca Resources ndash Lycoming Co (DCNR Tract 100 and Gamble) Future third-party volume opportunities

Covington Gathering System

Trout Run Gathering System

Gathering Segment Supporting Senecarsquos EDA Production amp Future Development

Wellsboro Gathering System Total Investment (to date) ~$14 million FY 2019 Estimated Capital Expenditures $8 MM - $15 MM Capacity up to 200000 Dth per day (Interconnect w TGP 300) Production Source Seneca Resources ndash Tioga Co (DCNR Tract 007)

EampP and Gathering

2

1

3

27

Long-term Contracts Supporting Appalachian Growth

(1) Represents base firm sales contracts not tied to firm transportation capacity Base firm sales are either fixed priced or priced at an index (eg NYMEX ) +- a fixed basis and do not carry any transportation costs

Seneca continues to layer-in firm sales contracts with attractive realizations to lock-in drilling economics and minimize spot exposure ahead of firm transportation in-service dates

EampP and Gathering

-

100

200

300

400

500

600

700

800

900

1000

1100

1200

FY 2019 FY 2020 FY 2021 FY 2022Northeast Supply Diversification 50000 Dthd

Niagara Expansion (TGP amp NFG)Delivery Markets Canada-Dawn amp TETCO

158000 Dthd

Atlantic Sunrise (Transco)Delivery Markets Mid-Atlantic amp Southeast US

189405 Dthd

In-BasinFirm Sales

Contracts(1)

Leidy South (Transco amp NFG)

Transco Zone 6 Markets330000 Dthd

Seneca Appalachia Natural Gas MarketingGross Firm Contract Volumes (Mdthday)

28

297000 ($061)

305200 ($061)

305600 ($063)

337000 ($057)

370800 ($024)

369600 ($060)

367900 ($067)

33400 ($070)74500 ($077) 74900 ($077)

81100 ($078)

85900 ($078)

92000 ($073)

91300 ($073)

178800 $255

196000 $234

195500 $234

149900 $232

129500 $230

105400 $222

104500 $222

~517800 509200 575700 576000 568000 586200 567000 563700

Q1 FY19 Q2 FY19 Q3 FY19 Q4 FY19 Q1 FY20 Q2 FY20 Q3 FY20 Q4 FY20

Fixed Price Dawn NYMEX

Near-term Firm Sales Provide Market amp Price Certainty

Net Contracted Firm Sales Volumes (Dth per day)Contracted Index Price Differentials ($ per Dth)(1)

(1) Values shown represent the weighted average fixed price or contracted fixed differential relative to NYMEX (netback price) less any associated transportation costs

Actual Daily Net

Production

641200 716500 708700 693500 708400 674400 667000Gross Firm Sales Volumes (Dthd)

EampP and Gathering

29

California Oil

Stable Oil Production | Minimal Capital Investment | Steady Free Cash Flow

1

2

3

4

5

Location Formation Production Method

FY18 Daily Production(net Boed)

1 East Coalinga Other Temblor Primary 512

2 North Lost Hills

Tulare amp Etchegoin

PrimarySteam flood 892

3 South Lost Hills

Monterey Shale Primary 1359

4 North Midway Sunset

Tulare amp Potter Steam flood 2786

5 South Midway Sunset Antelope Steam flood 2048

TOTAL WEST DIVISION NET PRODUCTION(1) 7597 Boed

EampP and Gathering

(1) West division net production for FY 2018 excludes production from Sespe field which was divested on May 1 2018

30

California Capital Expenditures vs Production

9341 8863

8033 ~7300

2016 2017 2018 2019

Fiscal Year

West Division Average Net Daily Production (Boe)West Division Annual Capital Expenditures ($ MM)(1)

$38 $38

$26 ~$25

2016 2017 2018 2019

Fiscal YearGuidance Guidance

(1) Seneca West Division capital expenditures includes Seneca corporate and eliminations

EampP and Gathering

Sepse Sale Closed on 5118(reduced production by ~900 boed)

31

Pioneer

South MWSS

Acreage

North MWSS

AcreageSec 17N

4149 51

NMWSS amp 17N SMWSS amp Pioneer East Coalinga

California Development Activities

Modest near-term capital program focused on locations that earn attractive returns in current oil price environment

AampD will focus on low cost bolt-on opportunities

Sec 17 Pioneer and East Coalinga development to provide future growth

North

Project IRRs at $55Bbl(1)

(1) Reflects pre-tax IRRs at a $55Bbl WTI

EampP and Gathering

Seneca West Economics

South

East Coalinga

North

South

32

Fiscal 2019 Production and Price Certainty

~49 Bcfe

210 ndash 230 Bcfe

~114 Bcf

~29 Bcf (2)

16+- Bcf~12 Bcfe

0

40

80

120

160

200

240

YTD FY19Actuals

Fixed Price + FirmSales w Hedge

Firm Sales(Unhedged)

Spot Sales California TotalSeneca

Prod

uctio

n (B

cfe)

(1) Average realized price reflects uplift from financial hedges less fixed differentials under firm sales contracts and any firm transportation costs(2) Indicates firm sales contracts with fixed index differentials but not backed by a matching financial hedge

114 Bcf locked-in realizing net ~$241Mcf (1)

29 Bcf of additional basis protection

Spot production assumed to be sold

at ~$275Mmbtu(winter) and ~$225

(summer)

143 Bcf of Appalachian Production Protected by Firm Sales for Remainder of Year

79 of oil production hedged at $5757 Bbl

EampP and Gathering

33

Strong Hedge Book

Natural Gas Swap amp Fixed Physical Sales Contracts (Millions MMBtu)

(1) Fixed price physical sales exclude joint development partnerrsquos share of fixed price contract WDA volumes as specified under the joint development agreement(2) Reflects percentage of projected production for FY19 hedged at the midpoint of the production guidance range(3) Senecarsquos remainder FY19 Production reflects the total FY19 production guidance of 210-230 Bcfe or 220 Bcfe at the midpoint less Q1 actual production

Crude Oil Swap Contracts (Thousands Bbls)

13591188

732

456

0

500

1000

1500

2000

2500

FY 2019 FY 2020 FY 2021 FY 2022

NYMEX (WTI)

Brent

FY 19 Crude Oil79 Hedged (2)

FY 2019 Remaining Production (3)

EampP and Gathering

1174

709

469 406

0

50

100

150

200

250

FY 2019 FY 2020 FY 2021 FY 2022

NYMEX Swaps

Dawn Swaps

Fixed Price Physical Sales

(1)

FY 2019 Remaining Production (3)

FY 19 Nat Gas71 Hedged (2)

34

$065 $070$070 -$075

FY 2017 FY 2018 FY 2019E

$060 $060 $060

$011 $009 $007$071 $069 ~$067

FY 2017 FY 2018 FY 2019E Gathering amp Transport LOE (non-Gathering) GampA Taxes amp Other

Seneca Operating Costs

Competitive low cost structure in Appalachia and California supports strong cash margins

Gathering fee generates significant revenue stream for affiliated gathering company

Seneca DDampARate

$Mcfe

$054 $054 $056

$042 $038 $031

$034 $034 $030

$017 $014 $015

$147 $140 ~$132

FY 2017 FY 2018 FY 2019E

(1)

$1791$1746~$2050

FY 2017 FY 2018 FY 2019E

Appalachia LOE amp Gathering $Mcfe

California LOE$Boe

Total Seneca Cash OpEx$Mcfe

(1)

(2)

(2)

(1) GampA estimate represents the midpoint of the GampA guidance range of $025 to $035 for fiscal 2019(2) The total of the two LOE components represents the midpoint of the LOE guidance range of $085 to $090 for fiscal 2019

EampP and Gathering

35

Senecarsquos Continuing Commitment to the Environment

Produced Water Recycled in Appalachia

100 70Recycled Water

Used in New Shale Well

Completions

Water and Fluids Management Air Quality and Emissions

Seneca Resources Water OperationsFiscal 2018

Seneca Resources Remains Focused on Minimizing GHG Emissions

The Environmental Partnership

EPA Natural Gas Star Program

Green Completions (all fiscal 2018 wells)

Ultrasonic Leak Detection Technology

Emissions Controls

Rig and Vehicle Fuel Conversion

Integrating Renewable Energy into Operations

EampP and Gathering

36

Pipeline and Storage OverviewNational Fuel Gas Supply Corporation ~ Empire Pipeline Inc

37

Pipeline amp Storage Segment Overview

(1) As of September 30 2018 as disclosed in the Companyrsquos fiscal 2018 form 10-K(2) As of December 31 2017 calculated from National Fuel Gas Supply Corporationrsquos and Empire Pipeline Incrsquos 2017 FERC Form-2 reports respectively

Empire Pipeline Inc

National Fuel Gas Supply Corporation

Empire Pipeline

Supply Corp

Contracted Capacity(1) Firm Transportation 3187 MDth per day Firm Storage 71938 Mdth (fully subscribed)

Rate Base(2) ~$820 million FERC Rate Proceeding Status

Rate case settlement extension approved Nov lsquo15 Rate case filing expected by 73119

Contracted Capacity(1) Firm Transportation 978 MDth per day Firm Storage 3753 Mdth (fully subscribed)

Rate Base(2) ~$249 million FERC Rate Proceeding Status

Rate case settlement in principle reached on 122118 FERC approval pending

New transportation rates went into on 1119

Pipeline amp Storage

38

All Seneca volumes will flow through wholly-owned NFG gathering facilities

FM100 Project - Consolidated Benefit for NFG

330000 Dthd of new transportation capacity from WDA and EDA acreage positions to premium markets

New Transco capacity (Leidy South) 330000 Dthday

Rate(1) competitive with other expansion project rates in Senecarsquos current transportation portfolio

Delivery Point(s) Transco Zone 6 interconnections

Seneca

Lease to Transco of new capacity 330000 Dthday

Estimated annual lease revenues ~$35 million

Target In-Service late calendar year 2021

Supply Corp

Project expected to provide long-term earnings uplift to Seneca Supply Corp and Gathering

Pipeline amp Storage

Gathering

(1) Includes lease of new capacity from Supply Corp to Transco

39

FM100 Project ndash Significant Investment by Supply Corp

Pipeline amp Storage

Estimated Capital Cost $280 million(1)

Facilities (all in Pennsylvania) include Approximately 30 miles of new pipeline 2 new compressor stations (totaling

approximately 37000 HP) New interconnection station and modification

of existing interconnection station Abandonment of approximately 45 miles of

existing pipeline and compressor station Regulatory Process

Pre-filing application submitted to FERC in 2017 for original modernization project

FERC 7(b) 7(c) filing expected summer 2019

(1) Includes expansion and modernization portions of the project

40

Empire North Project

Target In-Service second half of fiscal 2020

Est Capital Cost $145 million

Est Annual Revenues ~$25 million

Receipt Point Jackson (Tioga Co Pa production)

Design Capacity and Delivery Points 175000 Dthd to Chippawa (TCPL interconnect)

30000 Dthd to Hopewell (TGP 200 interconnect)

Customers Fully subscribed (205000 Dthday)

Major Facilities 2 new compressor stations in NY (1) amp Pa (1)

No new pipeline construction

Regulatory Process FERC 7(c) application filed on 21618

FERC Environmental Assessment issued 103018

Pipeline amp Storage

Fully Subscribed Project will Provide 205000 Dthday of Incremental Firm Transportation

41

National Fuel Remains Committed to Northern Access Project

Target In-Service as early as fiscal 2022

Total Cost ~$500MM (~$76MM spent to date)

Estimated Annual Revenues ~$84 million

Delivery Points

350000 Dthd to Chippawa (TCPL interconnect)

140000 Dthd to Hopewell (TGP 200 line)

Regulatory Status

February 3 2017 ndash FERC 7(c) certificate issued

August 6 2018 ndash FERC issued Order finding that NY DEC waived water quality certification

Supply and Empire currently working to finalize remaining federal authorizations

Pipeline amp Storage

To Dawn

42

Continued Expansion of the NFG Supply System

Line N Expansion Opportunities

Line N to Monaca Project Project Firm transportation service to a new ethane

cracker facility being built by Shell Chemical Appalachia LLC

Target In-Service July 2019

Estimated Capital Cost $23 million

Contracted Capacity 133000 Dthday

Additional Line N Expansion Opportunity (Supply OS 221) Project New firm transportation service for on-system

demand

Open Season Capacity Awarded 165000 to foundation shipper Precedent agreement in negotiations

Pipeline amp Storage

43

Pipeline amp Storage Customer Mix

Producer33

LDC42

Marketer10

Outside Pipeline

9

End User6

42 MMDthd

(1) Contracted as of 10312018

Customer Transportation by Shipper Type(1) Affiliated Customer Mix (Contracted Capacity)

66

521

41

34

9579

59

LDCs Producers Marketers FirmStorage

Affiliated Non-Affiliated

Firm Transport

Pipeline amp Storage

44

Utility OverviewNational Fuel Gas Distribution Corporation

45

New York amp Pennsylvania Service Territories

New York

Total Customers(1) 535800ROE 87 (NY PSC Rate Case Order April 2017)Rate Mechanismso Revenue Decouplingo Weather Normalizationo Low Income Rateso Merchant Function Charge (Uncollectibles Adj)o 9010 Sharing (Large Customers)o System Modernization Tracker

Pennsylvania

Total Customers(1) 214400ROE Black Box Settlement (2007)Rate Mechanismso Low Income Rateso Merchant Function Charge

(1) As of September 30 2018

Utility

46

New York Rate Case Outcome

Rate Order Summary

Revenue Requirement $59 million

Rate Base $704 million

Allowed Return on Equity (ROE) 87

Capital Structure 429 equity

Other notable items

New rates became effective 5117

Retains rate mechanisms in place under prior order (revenue decoupling weather normalization merchant function charge 9010 large customer sharing)

No stay-out clause

System modernization tracker for Leak Prone Pipe (LPP)

Earnings sharing started 4118 (5050 sharing starts at earnings in excess of 92)

Article 78 appeal filed on 72817 with oral argument completed in January 2019

On April 20 2017 the New York Public Service Commission issued a Rate Order relating to NFG Distributionrsquos rate case (No 16-G-0257) filed in April 2016

Utility

47

Utility Continues its Significant Investments in Safety

$544$618 $636

$699

$944$980

$809$856

$90-100

$00

$250

$500

$750

$1000

$1250

2015 2016 2017 2018 2019E

Cap

ital E

xpen

ditu

res

($ m

illio

ns)

Fiscal Year

Capital Expenditures for Safety Total Capital Expenditures

Modernization Spending in NY Expected to Grow Gross Margin By $2 MM - $5 MM in FY 2019

(1)

(1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation

Utility

System modernization tracker in NY allows recovery of pipeline replacementcosts which is expected to drive modest gross margin and rate base growth

48

Accelerating Pipeline Replacement amp Modernization

Wrought Iron

Plastic

CoatedBare

120130

146 144159

2014 2015 2016 2017 2018Calendar Year

NY9726 miles

PA4830 miles

No Cast Iron Mains in Pa

Miles of Utility Main Pipeline ReplacedUtility Mains by Material(1)

Wrought Iron

Cast Iron

Plastic

Coated Bare

Utility

(1) All values are reported on a calendar year basis as of December 31 2018

49

A Proven History of Controlling Costs

$200 $189 $195

$166 $166

$31 $31

$197 $197

$0

$50

$100

$150

$200

$250

2015 2016 2017 2018 TTM 123118

Fiscal Year

OampM Expense Non-Service Pension Costs

OampM Expense ($ millions)

Utility

(1)

(1) For purposes of comparability to FY 2015 2016 and 2017 Utility Operation and Maintenance Expense for FY 2018 and the twelve months ended December 31 2018 was adjusted by approximately $314 million and $312 million respectively to include non-service pension costs which were re-classified as Other Income (Deductions) as of October 1 2018 on the Companyrsquos Income Statement See Slide 64 for non-GAAP reconciliation of Adjusted Operation and Maintenance Expense to Operation and Maintenance Expense by segment

50

Consolidated Financial OverviewUpstream I Midstream I Downstream

51

Adjusted Operating Results ($ per share)(1)

Diversified Balanced Earnings and Cash Flows

(1) A reconciliation of Adjusted Operating Results to Earnings per Share by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation(2) Consolidated Adjusted EBITDA includes Energy Marketing and Corporate amp All Other Segments A reconciliation of Adjusted EBITDA to Net Income by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in

the Business is included at the end of this presentation

Adjusted EBITDA ($ millions)(2)

$176 $179

$184 $181

$92 $97

$318 $327

$761 $775

$-

$200

$400

$600

$800

FY 2018 TTM 123118

$059 Utility

$097 Pipeline amp Storage

$057 Gathering

$125 Exploration

amp Production

$334 $345 to $365

$-

$100

$200

$300

$400

FY 2018 FY 2019 Guidance

Rate Regulated

40-45

$728

Rate Regulated

~46

52

$89 $94 $98 $81 $86 $90-$100

$140$230

$114 $95 $93 $120-$150

$138$118

$54$33 $48

$55-$65

$603$557

$99 $246$356

$460-$495

$970 $1001

$366$455

$583

$725-$810

$0

$250

$500

$750

$1000

$1250

2014 2015 2016 2017 2018 2019GuidanceFiscal Year

Exploration amp Production

Gathering

Pipeline amp Storage

Utility

Disciplined Flexible Capital Allocation

(2)

(1) Total Capital Expenditures include Energy Marketing Corporate and All Other A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation (2) FY16 FY17 and FY18 reflects the netting of $157 million $7 million and $17 million respectively of up-front proceeds received from joint development partner for working interest in joint development wells and $21M in intercompany asset transfers in FY18

Capital Expenditures by Segment ($ millions)(1)

53

Maintaining Strong Balance Sheet amp Liquidity

Total Equity49

Total Debt51

$42 Billion Total Capitalizationas of December 31 2018

218 x251 x 245 x 247 x 256 x

2015 2016 2017 2018 TTM 123118Fiscal Year End

Net Debt Adjusted EBITDA(1) Capitalization

Debt Maturity Profile ($MM) Liquidity

Committed Credit FacilitiesShort-term Debt OutstandingAvailable Short-term Credit FacilitiesCash Balance at 123118 Total Liquidity at 123118

$ 750 MM0 MM

750 MM110 MM

$ 860 MM

$500 $549 $500

$300 $300

$0

$200

$400

$600

(1) Net Debt is net of cash and temporary cash investments Reconciliations of Net Debt and Adjusted EBITDA to Net Income are included at the end of this presentation

54

Appendix

55

Safe Harbor For Forward Looking StatementsThis presentation may contain ldquoforward-looking statementsrdquo as defined by the Private Securities Litigation Reform Act of 1995 including statements regarding future prospectsplans objectives goals projections estimates of oil and gas quantities strategies future events or performance and underlying assumptions capital structure anticipatedcapital expenditures completion of construction projects projections for pension and other post-retirement benefit obligations impacts of the adoption of new accounting rulesand possible outcomes of litigation or regulatory proceedings as well as statements that are identified by the use of the words ldquoanticipatesrdquo ldquoestimatesrdquo ldquoexpectsrdquo ldquoforecastsrdquoldquointendsrdquo ldquoplansrdquo ldquopredictsrdquo ldquoprojectsrdquo ldquobelievesrdquo ldquoseeksrdquo ldquowillrdquo ldquomayrdquo and similar expressions Forward-looking statements involve risks and uncertainties which couldcause actual results or outcomes to differ materially from those expressed in the forward-looking statements The Companyrsquos expectations beliefs and projections are expressedin good faith and are believed by the Company to have a reasonable basis but there can be no assurance that managementrsquos expectations beliefs or projections will result or beachieved or accomplished

In addition to other factors the following are important factors that could cause actual results to differ materially from those discussed in the forward-looking statements delaysor changes in costs or plans with respect to Company projects or related projects of other companies including difficulties or delays in obtaining necessary governmentalapprovals permits or orders or in obtaining the cooperation of interconnecting facility operators governmentalregulatory actions initiatives and proceedings including thoseinvolving rate cases (which address among other things target rates of return rate design and retained natural gas) environmentalsafety requirements affiliate relationshipsindustry structure and franchise renewal changes in laws regulations or judicial interpretations to which the Company is subject including those involving derivatives taxessafety employment climate change other environmental matters real property and exploration and production activities such as hydraulic fracturing financial and economicconditions including the availability of credit and occurrences affecting the Companyrsquos ability to obtain financing on acceptable terms for working capital capital expendituresand other investments including any downgrades in the Companyrsquos credit ratings and changes in interest rates and other capital market conditions changes in the price ofnatural gas or oil impairments under the SECrsquos full cost ceiling test for natural gas and oil reserves factors affecting the Companyrsquos ability to successfully identify drill for andproduce economically viable natural gas and oil reserves including among others geology lease availability title disputes weather conditions shortages delays orunavailability of equipment and services required in drilling operations insufficient gathering processing and transportation capacity the need to obtain governmentalapprovals and permits and compliance with environmental laws and regulations increasing health care costs and the resulting effect on health insurance premiums and on theobligation to provide other post-retirement benefits changes in price differentials between similar quantities of natural gas or oil sold at different geographic locations and theeffect of such changes on commodity production revenues and demand for pipeline transportation capacity to or from such locations other changes in price differentialsbetween similar quantities of natural gas or oil having different quality heating value hydrocarbon mix or delivery date the cost and effects of legal and administrative claimsagainst the Company or activist shareholder campaigns to effect changes at the Company uncertainty of oil and gas reserve estimates significant differences between theCompanyrsquos projected and actual production levels for natural gas or oil changes in demographic patterns and weather conditions changes in the availability price oraccounting treatment of derivative financial instruments changes in laws actuarial assumptions the interest rate environment and the return on plantrust assets related to theCompanyrsquos pension and other post-retirement benefits which can affect future funding obligations and costs and plan liabilities changes in economic conditions includingglobal national or regional recessions and their effect on the demand for and customersrsquo ability to pay for the Companyrsquos products and services the creditworthiness orperformance of the Companyrsquos key suppliers customers and counterparties the impact of potential information technology cybersecurity or data security breaches economicdisruptions or uninsured losses resulting from major accidents fires severe weather natural disasters terrorist activities or acts of war significant differences between theCompanyrsquos projected and actual capital expenditures and operating expenses or increasing costs of insurance changes in coverage and the ability to obtain insurance

Forward-looking statements include estimates of oil and gas quantities Proved oil and gas reserves are those quantities of oil and gas which by analysis of geoscience andengineering data can be estimated with reasonable certainty to be economically producible under existing economic conditions operating methods and governmentregulations Other estimates of oil and gas quantities including estimates of probable reserves possible reserves and resource potential are by their nature more speculativethan estimates of proved reserves Accordingly estimates other than proved reserves are subject to substantially greater risk of being actually realized Investors are urged toconsider closely the disclosure in our Form 10-K available at wwwnationalfuelgascom You can also obtain this form on the SECrsquos website at wwwsecgov

For a discussion of the risks set forth above and other factors that could cause actual results to differ materially from results referred to in the forward-looking statements seeldquoRisk Factorsrdquo in the Companyrsquos Form 10-K for the fiscal year ended September 30 2018 and the Forms 10-Q for the quarter ended March 31 2018 June 30 2018 and December31 2018 The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date thereof or to reflect the occurrence ofunanticipated events

Appendix

20

Leveraging Existing Gathering Water and Pad Infrastructure Enhances Returns

Limited New Infrastructure Needed to Support Production Growth

WDA Well Costs(1) WDA Consolidated Economics

Steady activity levels and coordination between upstream and midstream activities

enhance returns provide economies of scale and significant operational flexibility

(1) WDA Marcellus well costs reflect drilling completion amp gathering costs for 192 drilled and completed wells as of 93018 WDA Utica well costs reflect expected drilling completion amp gathering costs for the ~120 well locations in area of redevelopment (2) Internal Rate of Return for Seneca WDA includes estimated well costs under current cost structure and anticipated LOE and Gathering costs Internal Rate of Return for Seneca WDA and Gathering includes expected gathering capital expenditures

through FY 2022 well costs under current cost structure and non-gathering LOE

$685$887

$210

$0

$200

$400

$600

$800

$1000

Marcellus(Historic)

Utica - CRV(Current)

$ la

tera

l foo

t

Drilling amp Completion Gathering

$931$895

10 -11

17

00

03

06

09

12

15

18

Marcellus(Historic)

Utica - CRV(Current)

EUR

10

00 fe

et (B

cf)

60-70 EUR increase expected per well

Total cost per well expected to marginally increase

WDA EURs

At a $225 netback price consolidated Seneca WDA and Gathering IRR is

approximately 33 an uplift of ~12 over standalone Seneca WDA economics(2)

10+ IRR Uplift Expected

21

Integrated Development ndash WDA Gathering System

Current System In-Service

~78 miles of pipe 36220 HP of compression

Current Capacity 470 MMcf per day

Interconnects with TGP 300

Total Investment to Date $301 million

Future Build-Out

FY 2019 CapEx $10 - $15 million

Modest gathering pipeline and compression investment required to support Senecarsquos transition to Utica development

Opportunity for 300 miles of pipelines and five compressor stations (+60000 HP installed) as Senecarsquos drilling activity continues

Deliverability into TGP 300 and NFG Supply

Gathering System Build-Out Tailored to Accommodate Senecarsquos WDA Development

Clermont Gathering System Map

EampP and Gathering

22

WDA Firm Transportation and Sales Capacity

Will continue to layer-in firm sales deals of short and longer duration on TGP 300 to reduce spot exposure

WDA spot realizations track TGP Station 313 pricing typically 10cent - 30cent better than TGP Marcellus Zone 4

Leidy South will provide additional capacity to premium markets (Transco Zone 6)

WDA Exit Capacity Supports Long-term Production Growth and Enhances Consolidated Returns

WDA Contracted Firm Transport and Gross Sales Volumes (MDthd)

Seneca gross production trend

EampP and Gathering

0

100

200

300

400

500

600

700

Niagara Expansion Project (TGP and NFG)FT Capacity 158000 Dthd $067Dth

Firm Sales NYMEX amp DAWN

WDA - TGP 300Firm Sales

Leidy SouthTransco Zone 6

Markets330000 Dthd(1)

Will layer-in firm sales to minimize spot exposure

(1) Portion of Transco Project capacity will likely be utilized by EDA Lycoming County production

WDA Gas Marketing Strategy

23

Eastern Development Area

EDA Acreage ndash 70000 AcresEDA Highlights

1 DCNR Tract 007 (Tioga Co Pa)bull Utica development resumed in third quarter fiscal 2018

bull ~43 remaining Utica locations economic at ~$184 Mcf

bull Gathering Infrastructure NFG Midstream Wellsboro

bull Marcellus Shale expected to provide ~60 additional locations

EampP and Gathering

2

1

3

2 Covington amp DCNR Tract 595 (Tioga Co Pa)bull Marcellus locations fully developed (average daily gross production of ~93 MMcfd)

bull Gathering Infrastructure NFG Midstream Covington

bull Opportunity for future Utica appraisal

3 DCNR Tract 100 amp Gamble (Lycoming Co Pa)bull ~45 remaining Marcellus locations economic at ~$153 Mcfbull Firm Transportation Capacity Atlantic Sunrise (189 MDthd)

bull Gathering Infrastructure NFG Midstream Trout Run

bull Geneseo Shale expected to provide 100-120 additional locations

24

EDA Marcellus Lycoming County Development

Marcellus Development in Lycoming County has Resumed in Connection with Atlantic Sunrise

(1) Includes physical fixed price and NYMEX-based firm sales contracts that do not carry any additional transportation costs

EampP and Gathering

Prolific Marcellus acreage with peer leading well results

~45 remaining Marcellus locations economic at ~$153 Mcf

Near-term development focused on filling Atlantic Sunrise capacity

Existing Line

Leased

Seneca Fee

Producing

FY19 Producer

Development

0

50

100

150

200

250

Gro

ss F

irm V

olum

es (M

Dth

d)

EDA ndash Transco Firm Contracts

Atlantic Sunrise (Transco)FT Capacity 189405 Dthd

Cost $073DthFirm Sales NYMEX+

Transco Firm Sales(1)

25

EDA Utica Tioga County Development

Utica Development in Tioga County ndash Tract 007 Development Resumed in Q3 Fiscal 2018

In-Service November 2016

Lateral Length 4640 ft

30 Day IP 1000 ft 34 MMcfd

Est EUR 1000 ft 24 Bcf

Inventory ~43 locations economic at ~$184 Mcf

Targeting to grow production by 100 to 150 MDthd by fiscal 2020

Expected Development Costs $1045 per lateral ft

Gathering Infrastructure NFG Midstream Wellsboro

Modest build-out required to connect to TGP 300

SalesTakeaway Strategy Layer-in firm sales with shippers holding capacity on TGP 300

(1) Includes physical fixed price and NYMEX-based firm sales contracts that do not carry any additional transportation costs

Tract 007 Utica Appraisal Well Results vs Industry

EampP and Gathering

0

100000

200000

300000

400000

500000

600000

700000

800000

0 100 200 300

Nor

mal

ized

Cum

ulat

ive

(Mcf

10

00rsquo)

Days On ProductionIndustry PotterTioga Wells Seneca DCNR 007 73H

0

25

50

75

100

125

150

Gro

ss F

irm V

olum

es (M

Dth

d)

EDA ndash TGP 300 Firm Contracts

Northeast Supply Diversification ProjectFT Capacity 50000 Dthd $050Dth

Firm Sales NYMEX and DAWN

EDA - TGP 300Firm Sales(1)

26

Integrated Development ndash EDA Gathering Systems

Total Investment (to date) ~$46 million FY 2019 Estimated Capital Expenditures $1 MM - $2 MM Capacity 220000 Dth per day (Interconnect w TGP 300) Production Source Seneca Resources ndash Tioga Co (Covington and DCNR Tract 595)

Total Investment (to date) ~$208 million FY 2019 Estimated Capital Expenditures $25 MM - $35 MM Capacity 466000 to 585000 Dth per day (Interconnect w Transco) Production Source Seneca Resources ndash Lycoming Co (DCNR Tract 100 and Gamble) Future third-party volume opportunities

Covington Gathering System

Trout Run Gathering System

Gathering Segment Supporting Senecarsquos EDA Production amp Future Development

Wellsboro Gathering System Total Investment (to date) ~$14 million FY 2019 Estimated Capital Expenditures $8 MM - $15 MM Capacity up to 200000 Dth per day (Interconnect w TGP 300) Production Source Seneca Resources ndash Tioga Co (DCNR Tract 007)

EampP and Gathering

2

1

3

27

Long-term Contracts Supporting Appalachian Growth

(1) Represents base firm sales contracts not tied to firm transportation capacity Base firm sales are either fixed priced or priced at an index (eg NYMEX ) +- a fixed basis and do not carry any transportation costs

Seneca continues to layer-in firm sales contracts with attractive realizations to lock-in drilling economics and minimize spot exposure ahead of firm transportation in-service dates

EampP and Gathering

-

100

200

300

400

500

600

700

800

900

1000

1100

1200

FY 2019 FY 2020 FY 2021 FY 2022Northeast Supply Diversification 50000 Dthd

Niagara Expansion (TGP amp NFG)Delivery Markets Canada-Dawn amp TETCO

158000 Dthd

Atlantic Sunrise (Transco)Delivery Markets Mid-Atlantic amp Southeast US

189405 Dthd

In-BasinFirm Sales

Contracts(1)

Leidy South (Transco amp NFG)

Transco Zone 6 Markets330000 Dthd

Seneca Appalachia Natural Gas MarketingGross Firm Contract Volumes (Mdthday)

28

297000 ($061)

305200 ($061)

305600 ($063)

337000 ($057)

370800 ($024)

369600 ($060)

367900 ($067)

33400 ($070)74500 ($077) 74900 ($077)

81100 ($078)

85900 ($078)

92000 ($073)

91300 ($073)

178800 $255

196000 $234

195500 $234

149900 $232

129500 $230

105400 $222

104500 $222

~517800 509200 575700 576000 568000 586200 567000 563700

Q1 FY19 Q2 FY19 Q3 FY19 Q4 FY19 Q1 FY20 Q2 FY20 Q3 FY20 Q4 FY20

Fixed Price Dawn NYMEX

Near-term Firm Sales Provide Market amp Price Certainty

Net Contracted Firm Sales Volumes (Dth per day)Contracted Index Price Differentials ($ per Dth)(1)

(1) Values shown represent the weighted average fixed price or contracted fixed differential relative to NYMEX (netback price) less any associated transportation costs

Actual Daily Net

Production

641200 716500 708700 693500 708400 674400 667000Gross Firm Sales Volumes (Dthd)

EampP and Gathering

29

California Oil

Stable Oil Production | Minimal Capital Investment | Steady Free Cash Flow

1

2

3

4

5

Location Formation Production Method

FY18 Daily Production(net Boed)

1 East Coalinga Other Temblor Primary 512

2 North Lost Hills

Tulare amp Etchegoin

PrimarySteam flood 892

3 South Lost Hills

Monterey Shale Primary 1359

4 North Midway Sunset

Tulare amp Potter Steam flood 2786

5 South Midway Sunset Antelope Steam flood 2048

TOTAL WEST DIVISION NET PRODUCTION(1) 7597 Boed

EampP and Gathering

(1) West division net production for FY 2018 excludes production from Sespe field which was divested on May 1 2018

30

California Capital Expenditures vs Production

9341 8863

8033 ~7300

2016 2017 2018 2019

Fiscal Year

West Division Average Net Daily Production (Boe)West Division Annual Capital Expenditures ($ MM)(1)

$38 $38

$26 ~$25

2016 2017 2018 2019

Fiscal YearGuidance Guidance

(1) Seneca West Division capital expenditures includes Seneca corporate and eliminations

EampP and Gathering

Sepse Sale Closed on 5118(reduced production by ~900 boed)

31

Pioneer

South MWSS

Acreage

North MWSS

AcreageSec 17N

4149 51

NMWSS amp 17N SMWSS amp Pioneer East Coalinga

California Development Activities

Modest near-term capital program focused on locations that earn attractive returns in current oil price environment

AampD will focus on low cost bolt-on opportunities

Sec 17 Pioneer and East Coalinga development to provide future growth

North

Project IRRs at $55Bbl(1)

(1) Reflects pre-tax IRRs at a $55Bbl WTI

EampP and Gathering

Seneca West Economics

South

East Coalinga

North

South

32

Fiscal 2019 Production and Price Certainty

~49 Bcfe

210 ndash 230 Bcfe

~114 Bcf

~29 Bcf (2)

16+- Bcf~12 Bcfe

0

40

80

120

160

200

240

YTD FY19Actuals

Fixed Price + FirmSales w Hedge

Firm Sales(Unhedged)

Spot Sales California TotalSeneca

Prod

uctio

n (B

cfe)

(1) Average realized price reflects uplift from financial hedges less fixed differentials under firm sales contracts and any firm transportation costs(2) Indicates firm sales contracts with fixed index differentials but not backed by a matching financial hedge

114 Bcf locked-in realizing net ~$241Mcf (1)

29 Bcf of additional basis protection

Spot production assumed to be sold

at ~$275Mmbtu(winter) and ~$225

(summer)

143 Bcf of Appalachian Production Protected by Firm Sales for Remainder of Year

79 of oil production hedged at $5757 Bbl

EampP and Gathering

33

Strong Hedge Book

Natural Gas Swap amp Fixed Physical Sales Contracts (Millions MMBtu)

(1) Fixed price physical sales exclude joint development partnerrsquos share of fixed price contract WDA volumes as specified under the joint development agreement(2) Reflects percentage of projected production for FY19 hedged at the midpoint of the production guidance range(3) Senecarsquos remainder FY19 Production reflects the total FY19 production guidance of 210-230 Bcfe or 220 Bcfe at the midpoint less Q1 actual production

Crude Oil Swap Contracts (Thousands Bbls)

13591188

732

456

0

500

1000

1500

2000

2500

FY 2019 FY 2020 FY 2021 FY 2022

NYMEX (WTI)

Brent

FY 19 Crude Oil79 Hedged (2)

FY 2019 Remaining Production (3)

EampP and Gathering

1174

709

469 406

0

50

100

150

200

250

FY 2019 FY 2020 FY 2021 FY 2022

NYMEX Swaps

Dawn Swaps

Fixed Price Physical Sales

(1)

FY 2019 Remaining Production (3)

FY 19 Nat Gas71 Hedged (2)

34

$065 $070$070 -$075

FY 2017 FY 2018 FY 2019E

$060 $060 $060

$011 $009 $007$071 $069 ~$067

FY 2017 FY 2018 FY 2019E Gathering amp Transport LOE (non-Gathering) GampA Taxes amp Other

Seneca Operating Costs

Competitive low cost structure in Appalachia and California supports strong cash margins

Gathering fee generates significant revenue stream for affiliated gathering company

Seneca DDampARate

$Mcfe

$054 $054 $056

$042 $038 $031

$034 $034 $030

$017 $014 $015

$147 $140 ~$132

FY 2017 FY 2018 FY 2019E

(1)

$1791$1746~$2050

FY 2017 FY 2018 FY 2019E

Appalachia LOE amp Gathering $Mcfe

California LOE$Boe

Total Seneca Cash OpEx$Mcfe

(1)

(2)

(2)

(1) GampA estimate represents the midpoint of the GampA guidance range of $025 to $035 for fiscal 2019(2) The total of the two LOE components represents the midpoint of the LOE guidance range of $085 to $090 for fiscal 2019

EampP and Gathering

35

Senecarsquos Continuing Commitment to the Environment

Produced Water Recycled in Appalachia

100 70Recycled Water

Used in New Shale Well

Completions

Water and Fluids Management Air Quality and Emissions

Seneca Resources Water OperationsFiscal 2018

Seneca Resources Remains Focused on Minimizing GHG Emissions

The Environmental Partnership

EPA Natural Gas Star Program

Green Completions (all fiscal 2018 wells)

Ultrasonic Leak Detection Technology

Emissions Controls

Rig and Vehicle Fuel Conversion

Integrating Renewable Energy into Operations

EampP and Gathering

36

Pipeline and Storage OverviewNational Fuel Gas Supply Corporation ~ Empire Pipeline Inc

37

Pipeline amp Storage Segment Overview

(1) As of September 30 2018 as disclosed in the Companyrsquos fiscal 2018 form 10-K(2) As of December 31 2017 calculated from National Fuel Gas Supply Corporationrsquos and Empire Pipeline Incrsquos 2017 FERC Form-2 reports respectively

Empire Pipeline Inc

National Fuel Gas Supply Corporation

Empire Pipeline

Supply Corp

Contracted Capacity(1) Firm Transportation 3187 MDth per day Firm Storage 71938 Mdth (fully subscribed)

Rate Base(2) ~$820 million FERC Rate Proceeding Status

Rate case settlement extension approved Nov lsquo15 Rate case filing expected by 73119

Contracted Capacity(1) Firm Transportation 978 MDth per day Firm Storage 3753 Mdth (fully subscribed)

Rate Base(2) ~$249 million FERC Rate Proceeding Status

Rate case settlement in principle reached on 122118 FERC approval pending

New transportation rates went into on 1119

Pipeline amp Storage

38

All Seneca volumes will flow through wholly-owned NFG gathering facilities

FM100 Project - Consolidated Benefit for NFG

330000 Dthd of new transportation capacity from WDA and EDA acreage positions to premium markets

New Transco capacity (Leidy South) 330000 Dthday

Rate(1) competitive with other expansion project rates in Senecarsquos current transportation portfolio

Delivery Point(s) Transco Zone 6 interconnections

Seneca

Lease to Transco of new capacity 330000 Dthday

Estimated annual lease revenues ~$35 million

Target In-Service late calendar year 2021

Supply Corp

Project expected to provide long-term earnings uplift to Seneca Supply Corp and Gathering

Pipeline amp Storage

Gathering

(1) Includes lease of new capacity from Supply Corp to Transco

39

FM100 Project ndash Significant Investment by Supply Corp

Pipeline amp Storage

Estimated Capital Cost $280 million(1)

Facilities (all in Pennsylvania) include Approximately 30 miles of new pipeline 2 new compressor stations (totaling

approximately 37000 HP) New interconnection station and modification

of existing interconnection station Abandonment of approximately 45 miles of

existing pipeline and compressor station Regulatory Process

Pre-filing application submitted to FERC in 2017 for original modernization project

FERC 7(b) 7(c) filing expected summer 2019

(1) Includes expansion and modernization portions of the project

40

Empire North Project

Target In-Service second half of fiscal 2020

Est Capital Cost $145 million

Est Annual Revenues ~$25 million

Receipt Point Jackson (Tioga Co Pa production)

Design Capacity and Delivery Points 175000 Dthd to Chippawa (TCPL interconnect)

30000 Dthd to Hopewell (TGP 200 interconnect)

Customers Fully subscribed (205000 Dthday)

Major Facilities 2 new compressor stations in NY (1) amp Pa (1)

No new pipeline construction

Regulatory Process FERC 7(c) application filed on 21618

FERC Environmental Assessment issued 103018

Pipeline amp Storage

Fully Subscribed Project will Provide 205000 Dthday of Incremental Firm Transportation

41

National Fuel Remains Committed to Northern Access Project

Target In-Service as early as fiscal 2022

Total Cost ~$500MM (~$76MM spent to date)

Estimated Annual Revenues ~$84 million

Delivery Points

350000 Dthd to Chippawa (TCPL interconnect)

140000 Dthd to Hopewell (TGP 200 line)

Regulatory Status

February 3 2017 ndash FERC 7(c) certificate issued

August 6 2018 ndash FERC issued Order finding that NY DEC waived water quality certification

Supply and Empire currently working to finalize remaining federal authorizations

Pipeline amp Storage

To Dawn

42

Continued Expansion of the NFG Supply System

Line N Expansion Opportunities

Line N to Monaca Project Project Firm transportation service to a new ethane

cracker facility being built by Shell Chemical Appalachia LLC

Target In-Service July 2019

Estimated Capital Cost $23 million

Contracted Capacity 133000 Dthday

Additional Line N Expansion Opportunity (Supply OS 221) Project New firm transportation service for on-system

demand

Open Season Capacity Awarded 165000 to foundation shipper Precedent agreement in negotiations

Pipeline amp Storage

43

Pipeline amp Storage Customer Mix

Producer33

LDC42

Marketer10

Outside Pipeline

9

End User6

42 MMDthd

(1) Contracted as of 10312018

Customer Transportation by Shipper Type(1) Affiliated Customer Mix (Contracted Capacity)

66

521

41

34

9579

59

LDCs Producers Marketers FirmStorage

Affiliated Non-Affiliated

Firm Transport

Pipeline amp Storage

44

Utility OverviewNational Fuel Gas Distribution Corporation

45

New York amp Pennsylvania Service Territories

New York

Total Customers(1) 535800ROE 87 (NY PSC Rate Case Order April 2017)Rate Mechanismso Revenue Decouplingo Weather Normalizationo Low Income Rateso Merchant Function Charge (Uncollectibles Adj)o 9010 Sharing (Large Customers)o System Modernization Tracker

Pennsylvania

Total Customers(1) 214400ROE Black Box Settlement (2007)Rate Mechanismso Low Income Rateso Merchant Function Charge

(1) As of September 30 2018

Utility

46

New York Rate Case Outcome

Rate Order Summary

Revenue Requirement $59 million

Rate Base $704 million

Allowed Return on Equity (ROE) 87

Capital Structure 429 equity

Other notable items

New rates became effective 5117

Retains rate mechanisms in place under prior order (revenue decoupling weather normalization merchant function charge 9010 large customer sharing)

No stay-out clause

System modernization tracker for Leak Prone Pipe (LPP)

Earnings sharing started 4118 (5050 sharing starts at earnings in excess of 92)

Article 78 appeal filed on 72817 with oral argument completed in January 2019

On April 20 2017 the New York Public Service Commission issued a Rate Order relating to NFG Distributionrsquos rate case (No 16-G-0257) filed in April 2016

Utility

47

Utility Continues its Significant Investments in Safety

$544$618 $636

$699

$944$980

$809$856

$90-100

$00

$250

$500

$750

$1000

$1250

2015 2016 2017 2018 2019E

Cap

ital E

xpen

ditu

res

($ m

illio

ns)

Fiscal Year

Capital Expenditures for Safety Total Capital Expenditures

Modernization Spending in NY Expected to Grow Gross Margin By $2 MM - $5 MM in FY 2019

(1)

(1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation

Utility

System modernization tracker in NY allows recovery of pipeline replacementcosts which is expected to drive modest gross margin and rate base growth

48

Accelerating Pipeline Replacement amp Modernization

Wrought Iron

Plastic

CoatedBare

120130

146 144159

2014 2015 2016 2017 2018Calendar Year

NY9726 miles

PA4830 miles

No Cast Iron Mains in Pa

Miles of Utility Main Pipeline ReplacedUtility Mains by Material(1)

Wrought Iron

Cast Iron

Plastic

Coated Bare

Utility

(1) All values are reported on a calendar year basis as of December 31 2018

49

A Proven History of Controlling Costs

$200 $189 $195

$166 $166

$31 $31

$197 $197

$0

$50

$100

$150

$200

$250

2015 2016 2017 2018 TTM 123118

Fiscal Year

OampM Expense Non-Service Pension Costs

OampM Expense ($ millions)

Utility

(1)

(1) For purposes of comparability to FY 2015 2016 and 2017 Utility Operation and Maintenance Expense for FY 2018 and the twelve months ended December 31 2018 was adjusted by approximately $314 million and $312 million respectively to include non-service pension costs which were re-classified as Other Income (Deductions) as of October 1 2018 on the Companyrsquos Income Statement See Slide 64 for non-GAAP reconciliation of Adjusted Operation and Maintenance Expense to Operation and Maintenance Expense by segment

50

Consolidated Financial OverviewUpstream I Midstream I Downstream

51

Adjusted Operating Results ($ per share)(1)

Diversified Balanced Earnings and Cash Flows

(1) A reconciliation of Adjusted Operating Results to Earnings per Share by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation(2) Consolidated Adjusted EBITDA includes Energy Marketing and Corporate amp All Other Segments A reconciliation of Adjusted EBITDA to Net Income by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in

the Business is included at the end of this presentation

Adjusted EBITDA ($ millions)(2)

$176 $179

$184 $181

$92 $97

$318 $327

$761 $775

$-

$200

$400

$600

$800

FY 2018 TTM 123118

$059 Utility

$097 Pipeline amp Storage

$057 Gathering

$125 Exploration

amp Production

$334 $345 to $365

$-

$100

$200

$300

$400

FY 2018 FY 2019 Guidance

Rate Regulated

40-45

$728

Rate Regulated

~46

52

$89 $94 $98 $81 $86 $90-$100

$140$230

$114 $95 $93 $120-$150

$138$118

$54$33 $48

$55-$65

$603$557

$99 $246$356

$460-$495

$970 $1001

$366$455

$583

$725-$810

$0

$250

$500

$750

$1000

$1250

2014 2015 2016 2017 2018 2019GuidanceFiscal Year

Exploration amp Production

Gathering

Pipeline amp Storage

Utility

Disciplined Flexible Capital Allocation

(2)

(1) Total Capital Expenditures include Energy Marketing Corporate and All Other A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation (2) FY16 FY17 and FY18 reflects the netting of $157 million $7 million and $17 million respectively of up-front proceeds received from joint development partner for working interest in joint development wells and $21M in intercompany asset transfers in FY18

Capital Expenditures by Segment ($ millions)(1)

53

Maintaining Strong Balance Sheet amp Liquidity

Total Equity49

Total Debt51

$42 Billion Total Capitalizationas of December 31 2018

218 x251 x 245 x 247 x 256 x

2015 2016 2017 2018 TTM 123118Fiscal Year End

Net Debt Adjusted EBITDA(1) Capitalization

Debt Maturity Profile ($MM) Liquidity

Committed Credit FacilitiesShort-term Debt OutstandingAvailable Short-term Credit FacilitiesCash Balance at 123118 Total Liquidity at 123118

$ 750 MM0 MM

750 MM110 MM

$ 860 MM

$500 $549 $500

$300 $300

$0

$200

$400

$600

(1) Net Debt is net of cash and temporary cash investments Reconciliations of Net Debt and Adjusted EBITDA to Net Income are included at the end of this presentation

54

Appendix

55

Safe Harbor For Forward Looking StatementsThis presentation may contain ldquoforward-looking statementsrdquo as defined by the Private Securities Litigation Reform Act of 1995 including statements regarding future prospectsplans objectives goals projections estimates of oil and gas quantities strategies future events or performance and underlying assumptions capital structure anticipatedcapital expenditures completion of construction projects projections for pension and other post-retirement benefit obligations impacts of the adoption of new accounting rulesand possible outcomes of litigation or regulatory proceedings as well as statements that are identified by the use of the words ldquoanticipatesrdquo ldquoestimatesrdquo ldquoexpectsrdquo ldquoforecastsrdquoldquointendsrdquo ldquoplansrdquo ldquopredictsrdquo ldquoprojectsrdquo ldquobelievesrdquo ldquoseeksrdquo ldquowillrdquo ldquomayrdquo and similar expressions Forward-looking statements involve risks and uncertainties which couldcause actual results or outcomes to differ materially from those expressed in the forward-looking statements The Companyrsquos expectations beliefs and projections are expressedin good faith and are believed by the Company to have a reasonable basis but there can be no assurance that managementrsquos expectations beliefs or projections will result or beachieved or accomplished

In addition to other factors the following are important factors that could cause actual results to differ materially from those discussed in the forward-looking statements delaysor changes in costs or plans with respect to Company projects or related projects of other companies including difficulties or delays in obtaining necessary governmentalapprovals permits or orders or in obtaining the cooperation of interconnecting facility operators governmentalregulatory actions initiatives and proceedings including thoseinvolving rate cases (which address among other things target rates of return rate design and retained natural gas) environmentalsafety requirements affiliate relationshipsindustry structure and franchise renewal changes in laws regulations or judicial interpretations to which the Company is subject including those involving derivatives taxessafety employment climate change other environmental matters real property and exploration and production activities such as hydraulic fracturing financial and economicconditions including the availability of credit and occurrences affecting the Companyrsquos ability to obtain financing on acceptable terms for working capital capital expendituresand other investments including any downgrades in the Companyrsquos credit ratings and changes in interest rates and other capital market conditions changes in the price ofnatural gas or oil impairments under the SECrsquos full cost ceiling test for natural gas and oil reserves factors affecting the Companyrsquos ability to successfully identify drill for andproduce economically viable natural gas and oil reserves including among others geology lease availability title disputes weather conditions shortages delays orunavailability of equipment and services required in drilling operations insufficient gathering processing and transportation capacity the need to obtain governmentalapprovals and permits and compliance with environmental laws and regulations increasing health care costs and the resulting effect on health insurance premiums and on theobligation to provide other post-retirement benefits changes in price differentials between similar quantities of natural gas or oil sold at different geographic locations and theeffect of such changes on commodity production revenues and demand for pipeline transportation capacity to or from such locations other changes in price differentialsbetween similar quantities of natural gas or oil having different quality heating value hydrocarbon mix or delivery date the cost and effects of legal and administrative claimsagainst the Company or activist shareholder campaigns to effect changes at the Company uncertainty of oil and gas reserve estimates significant differences between theCompanyrsquos projected and actual production levels for natural gas or oil changes in demographic patterns and weather conditions changes in the availability price oraccounting treatment of derivative financial instruments changes in laws actuarial assumptions the interest rate environment and the return on plantrust assets related to theCompanyrsquos pension and other post-retirement benefits which can affect future funding obligations and costs and plan liabilities changes in economic conditions includingglobal national or regional recessions and their effect on the demand for and customersrsquo ability to pay for the Companyrsquos products and services the creditworthiness orperformance of the Companyrsquos key suppliers customers and counterparties the impact of potential information technology cybersecurity or data security breaches economicdisruptions or uninsured losses resulting from major accidents fires severe weather natural disasters terrorist activities or acts of war significant differences between theCompanyrsquos projected and actual capital expenditures and operating expenses or increasing costs of insurance changes in coverage and the ability to obtain insurance

Forward-looking statements include estimates of oil and gas quantities Proved oil and gas reserves are those quantities of oil and gas which by analysis of geoscience andengineering data can be estimated with reasonable certainty to be economically producible under existing economic conditions operating methods and governmentregulations Other estimates of oil and gas quantities including estimates of probable reserves possible reserves and resource potential are by their nature more speculativethan estimates of proved reserves Accordingly estimates other than proved reserves are subject to substantially greater risk of being actually realized Investors are urged toconsider closely the disclosure in our Form 10-K available at wwwnationalfuelgascom You can also obtain this form on the SECrsquos website at wwwsecgov

For a discussion of the risks set forth above and other factors that could cause actual results to differ materially from results referred to in the forward-looking statements seeldquoRisk Factorsrdquo in the Companyrsquos Form 10-K for the fiscal year ended September 30 2018 and the Forms 10-Q for the quarter ended March 31 2018 June 30 2018 and December31 2018 The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date thereof or to reflect the occurrence ofunanticipated events

Appendix

21

Integrated Development ndash WDA Gathering System

Current System In-Service

~78 miles of pipe 36220 HP of compression

Current Capacity 470 MMcf per day

Interconnects with TGP 300

Total Investment to Date $301 million

Future Build-Out

FY 2019 CapEx $10 - $15 million

Modest gathering pipeline and compression investment required to support Senecarsquos transition to Utica development

Opportunity for 300 miles of pipelines and five compressor stations (+60000 HP installed) as Senecarsquos drilling activity continues

Deliverability into TGP 300 and NFG Supply

Gathering System Build-Out Tailored to Accommodate Senecarsquos WDA Development

Clermont Gathering System Map

EampP and Gathering

22

WDA Firm Transportation and Sales Capacity

Will continue to layer-in firm sales deals of short and longer duration on TGP 300 to reduce spot exposure

WDA spot realizations track TGP Station 313 pricing typically 10cent - 30cent better than TGP Marcellus Zone 4

Leidy South will provide additional capacity to premium markets (Transco Zone 6)

WDA Exit Capacity Supports Long-term Production Growth and Enhances Consolidated Returns

WDA Contracted Firm Transport and Gross Sales Volumes (MDthd)

Seneca gross production trend

EampP and Gathering

0

100

200

300

400

500

600

700

Niagara Expansion Project (TGP and NFG)FT Capacity 158000 Dthd $067Dth

Firm Sales NYMEX amp DAWN

WDA - TGP 300Firm Sales

Leidy SouthTransco Zone 6

Markets330000 Dthd(1)

Will layer-in firm sales to minimize spot exposure

(1) Portion of Transco Project capacity will likely be utilized by EDA Lycoming County production

WDA Gas Marketing Strategy

23

Eastern Development Area

EDA Acreage ndash 70000 AcresEDA Highlights

1 DCNR Tract 007 (Tioga Co Pa)bull Utica development resumed in third quarter fiscal 2018

bull ~43 remaining Utica locations economic at ~$184 Mcf

bull Gathering Infrastructure NFG Midstream Wellsboro

bull Marcellus Shale expected to provide ~60 additional locations

EampP and Gathering

2

1

3

2 Covington amp DCNR Tract 595 (Tioga Co Pa)bull Marcellus locations fully developed (average daily gross production of ~93 MMcfd)

bull Gathering Infrastructure NFG Midstream Covington

bull Opportunity for future Utica appraisal

3 DCNR Tract 100 amp Gamble (Lycoming Co Pa)bull ~45 remaining Marcellus locations economic at ~$153 Mcfbull Firm Transportation Capacity Atlantic Sunrise (189 MDthd)

bull Gathering Infrastructure NFG Midstream Trout Run

bull Geneseo Shale expected to provide 100-120 additional locations

24

EDA Marcellus Lycoming County Development

Marcellus Development in Lycoming County has Resumed in Connection with Atlantic Sunrise

(1) Includes physical fixed price and NYMEX-based firm sales contracts that do not carry any additional transportation costs

EampP and Gathering

Prolific Marcellus acreage with peer leading well results

~45 remaining Marcellus locations economic at ~$153 Mcf

Near-term development focused on filling Atlantic Sunrise capacity

Existing Line

Leased

Seneca Fee

Producing

FY19 Producer

Development

0

50

100

150

200

250

Gro

ss F

irm V

olum

es (M

Dth

d)

EDA ndash Transco Firm Contracts

Atlantic Sunrise (Transco)FT Capacity 189405 Dthd

Cost $073DthFirm Sales NYMEX+

Transco Firm Sales(1)

25

EDA Utica Tioga County Development

Utica Development in Tioga County ndash Tract 007 Development Resumed in Q3 Fiscal 2018

In-Service November 2016

Lateral Length 4640 ft

30 Day IP 1000 ft 34 MMcfd

Est EUR 1000 ft 24 Bcf

Inventory ~43 locations economic at ~$184 Mcf

Targeting to grow production by 100 to 150 MDthd by fiscal 2020

Expected Development Costs $1045 per lateral ft

Gathering Infrastructure NFG Midstream Wellsboro

Modest build-out required to connect to TGP 300

SalesTakeaway Strategy Layer-in firm sales with shippers holding capacity on TGP 300

(1) Includes physical fixed price and NYMEX-based firm sales contracts that do not carry any additional transportation costs

Tract 007 Utica Appraisal Well Results vs Industry

EampP and Gathering

0

100000

200000

300000

400000

500000

600000

700000

800000

0 100 200 300

Nor

mal

ized

Cum

ulat

ive

(Mcf

10

00rsquo)

Days On ProductionIndustry PotterTioga Wells Seneca DCNR 007 73H

0

25

50

75

100

125

150

Gro

ss F

irm V

olum

es (M

Dth

d)

EDA ndash TGP 300 Firm Contracts

Northeast Supply Diversification ProjectFT Capacity 50000 Dthd $050Dth

Firm Sales NYMEX and DAWN

EDA - TGP 300Firm Sales(1)

26

Integrated Development ndash EDA Gathering Systems

Total Investment (to date) ~$46 million FY 2019 Estimated Capital Expenditures $1 MM - $2 MM Capacity 220000 Dth per day (Interconnect w TGP 300) Production Source Seneca Resources ndash Tioga Co (Covington and DCNR Tract 595)

Total Investment (to date) ~$208 million FY 2019 Estimated Capital Expenditures $25 MM - $35 MM Capacity 466000 to 585000 Dth per day (Interconnect w Transco) Production Source Seneca Resources ndash Lycoming Co (DCNR Tract 100 and Gamble) Future third-party volume opportunities

Covington Gathering System

Trout Run Gathering System

Gathering Segment Supporting Senecarsquos EDA Production amp Future Development

Wellsboro Gathering System Total Investment (to date) ~$14 million FY 2019 Estimated Capital Expenditures $8 MM - $15 MM Capacity up to 200000 Dth per day (Interconnect w TGP 300) Production Source Seneca Resources ndash Tioga Co (DCNR Tract 007)

EampP and Gathering

2

1

3

27

Long-term Contracts Supporting Appalachian Growth

(1) Represents base firm sales contracts not tied to firm transportation capacity Base firm sales are either fixed priced or priced at an index (eg NYMEX ) +- a fixed basis and do not carry any transportation costs

Seneca continues to layer-in firm sales contracts with attractive realizations to lock-in drilling economics and minimize spot exposure ahead of firm transportation in-service dates

EampP and Gathering

-

100

200

300

400

500

600

700

800

900

1000

1100

1200

FY 2019 FY 2020 FY 2021 FY 2022Northeast Supply Diversification 50000 Dthd

Niagara Expansion (TGP amp NFG)Delivery Markets Canada-Dawn amp TETCO

158000 Dthd

Atlantic Sunrise (Transco)Delivery Markets Mid-Atlantic amp Southeast US

189405 Dthd

In-BasinFirm Sales

Contracts(1)

Leidy South (Transco amp NFG)

Transco Zone 6 Markets330000 Dthd

Seneca Appalachia Natural Gas MarketingGross Firm Contract Volumes (Mdthday)

28

297000 ($061)

305200 ($061)

305600 ($063)

337000 ($057)

370800 ($024)

369600 ($060)

367900 ($067)

33400 ($070)74500 ($077) 74900 ($077)

81100 ($078)

85900 ($078)

92000 ($073)

91300 ($073)

178800 $255

196000 $234

195500 $234

149900 $232

129500 $230

105400 $222

104500 $222

~517800 509200 575700 576000 568000 586200 567000 563700

Q1 FY19 Q2 FY19 Q3 FY19 Q4 FY19 Q1 FY20 Q2 FY20 Q3 FY20 Q4 FY20

Fixed Price Dawn NYMEX

Near-term Firm Sales Provide Market amp Price Certainty

Net Contracted Firm Sales Volumes (Dth per day)Contracted Index Price Differentials ($ per Dth)(1)

(1) Values shown represent the weighted average fixed price or contracted fixed differential relative to NYMEX (netback price) less any associated transportation costs

Actual Daily Net

Production

641200 716500 708700 693500 708400 674400 667000Gross Firm Sales Volumes (Dthd)

EampP and Gathering

29

California Oil

Stable Oil Production | Minimal Capital Investment | Steady Free Cash Flow

1

2

3

4

5

Location Formation Production Method

FY18 Daily Production(net Boed)

1 East Coalinga Other Temblor Primary 512

2 North Lost Hills

Tulare amp Etchegoin

PrimarySteam flood 892

3 South Lost Hills

Monterey Shale Primary 1359

4 North Midway Sunset

Tulare amp Potter Steam flood 2786

5 South Midway Sunset Antelope Steam flood 2048

TOTAL WEST DIVISION NET PRODUCTION(1) 7597 Boed

EampP and Gathering

(1) West division net production for FY 2018 excludes production from Sespe field which was divested on May 1 2018

30

California Capital Expenditures vs Production

9341 8863

8033 ~7300

2016 2017 2018 2019

Fiscal Year

West Division Average Net Daily Production (Boe)West Division Annual Capital Expenditures ($ MM)(1)

$38 $38

$26 ~$25

2016 2017 2018 2019

Fiscal YearGuidance Guidance

(1) Seneca West Division capital expenditures includes Seneca corporate and eliminations

EampP and Gathering

Sepse Sale Closed on 5118(reduced production by ~900 boed)

31

Pioneer

South MWSS

Acreage

North MWSS

AcreageSec 17N

4149 51

NMWSS amp 17N SMWSS amp Pioneer East Coalinga

California Development Activities

Modest near-term capital program focused on locations that earn attractive returns in current oil price environment

AampD will focus on low cost bolt-on opportunities

Sec 17 Pioneer and East Coalinga development to provide future growth

North

Project IRRs at $55Bbl(1)

(1) Reflects pre-tax IRRs at a $55Bbl WTI

EampP and Gathering

Seneca West Economics

South

East Coalinga

North

South

32

Fiscal 2019 Production and Price Certainty

~49 Bcfe

210 ndash 230 Bcfe

~114 Bcf

~29 Bcf (2)

16+- Bcf~12 Bcfe

0

40

80

120

160

200

240

YTD FY19Actuals

Fixed Price + FirmSales w Hedge

Firm Sales(Unhedged)

Spot Sales California TotalSeneca

Prod

uctio

n (B

cfe)

(1) Average realized price reflects uplift from financial hedges less fixed differentials under firm sales contracts and any firm transportation costs(2) Indicates firm sales contracts with fixed index differentials but not backed by a matching financial hedge

114 Bcf locked-in realizing net ~$241Mcf (1)

29 Bcf of additional basis protection

Spot production assumed to be sold

at ~$275Mmbtu(winter) and ~$225

(summer)

143 Bcf of Appalachian Production Protected by Firm Sales for Remainder of Year

79 of oil production hedged at $5757 Bbl

EampP and Gathering

33

Strong Hedge Book

Natural Gas Swap amp Fixed Physical Sales Contracts (Millions MMBtu)

(1) Fixed price physical sales exclude joint development partnerrsquos share of fixed price contract WDA volumes as specified under the joint development agreement(2) Reflects percentage of projected production for FY19 hedged at the midpoint of the production guidance range(3) Senecarsquos remainder FY19 Production reflects the total FY19 production guidance of 210-230 Bcfe or 220 Bcfe at the midpoint less Q1 actual production

Crude Oil Swap Contracts (Thousands Bbls)

13591188

732

456

0

500

1000

1500

2000

2500

FY 2019 FY 2020 FY 2021 FY 2022

NYMEX (WTI)

Brent

FY 19 Crude Oil79 Hedged (2)

FY 2019 Remaining Production (3)

EampP and Gathering

1174

709

469 406

0

50

100

150

200

250

FY 2019 FY 2020 FY 2021 FY 2022

NYMEX Swaps

Dawn Swaps

Fixed Price Physical Sales

(1)

FY 2019 Remaining Production (3)

FY 19 Nat Gas71 Hedged (2)

34

$065 $070$070 -$075

FY 2017 FY 2018 FY 2019E

$060 $060 $060

$011 $009 $007$071 $069 ~$067

FY 2017 FY 2018 FY 2019E Gathering amp Transport LOE (non-Gathering) GampA Taxes amp Other

Seneca Operating Costs

Competitive low cost structure in Appalachia and California supports strong cash margins

Gathering fee generates significant revenue stream for affiliated gathering company

Seneca DDampARate

$Mcfe

$054 $054 $056

$042 $038 $031

$034 $034 $030

$017 $014 $015

$147 $140 ~$132

FY 2017 FY 2018 FY 2019E

(1)

$1791$1746~$2050

FY 2017 FY 2018 FY 2019E

Appalachia LOE amp Gathering $Mcfe

California LOE$Boe

Total Seneca Cash OpEx$Mcfe

(1)

(2)

(2)

(1) GampA estimate represents the midpoint of the GampA guidance range of $025 to $035 for fiscal 2019(2) The total of the two LOE components represents the midpoint of the LOE guidance range of $085 to $090 for fiscal 2019

EampP and Gathering

35

Senecarsquos Continuing Commitment to the Environment

Produced Water Recycled in Appalachia

100 70Recycled Water

Used in New Shale Well

Completions

Water and Fluids Management Air Quality and Emissions

Seneca Resources Water OperationsFiscal 2018

Seneca Resources Remains Focused on Minimizing GHG Emissions

The Environmental Partnership

EPA Natural Gas Star Program

Green Completions (all fiscal 2018 wells)

Ultrasonic Leak Detection Technology

Emissions Controls

Rig and Vehicle Fuel Conversion

Integrating Renewable Energy into Operations

EampP and Gathering

36

Pipeline and Storage OverviewNational Fuel Gas Supply Corporation ~ Empire Pipeline Inc

37

Pipeline amp Storage Segment Overview

(1) As of September 30 2018 as disclosed in the Companyrsquos fiscal 2018 form 10-K(2) As of December 31 2017 calculated from National Fuel Gas Supply Corporationrsquos and Empire Pipeline Incrsquos 2017 FERC Form-2 reports respectively

Empire Pipeline Inc

National Fuel Gas Supply Corporation

Empire Pipeline

Supply Corp

Contracted Capacity(1) Firm Transportation 3187 MDth per day Firm Storage 71938 Mdth (fully subscribed)

Rate Base(2) ~$820 million FERC Rate Proceeding Status

Rate case settlement extension approved Nov lsquo15 Rate case filing expected by 73119

Contracted Capacity(1) Firm Transportation 978 MDth per day Firm Storage 3753 Mdth (fully subscribed)

Rate Base(2) ~$249 million FERC Rate Proceeding Status

Rate case settlement in principle reached on 122118 FERC approval pending

New transportation rates went into on 1119

Pipeline amp Storage

38

All Seneca volumes will flow through wholly-owned NFG gathering facilities

FM100 Project - Consolidated Benefit for NFG

330000 Dthd of new transportation capacity from WDA and EDA acreage positions to premium markets

New Transco capacity (Leidy South) 330000 Dthday

Rate(1) competitive with other expansion project rates in Senecarsquos current transportation portfolio

Delivery Point(s) Transco Zone 6 interconnections

Seneca

Lease to Transco of new capacity 330000 Dthday

Estimated annual lease revenues ~$35 million

Target In-Service late calendar year 2021

Supply Corp

Project expected to provide long-term earnings uplift to Seneca Supply Corp and Gathering

Pipeline amp Storage

Gathering

(1) Includes lease of new capacity from Supply Corp to Transco

39

FM100 Project ndash Significant Investment by Supply Corp

Pipeline amp Storage

Estimated Capital Cost $280 million(1)

Facilities (all in Pennsylvania) include Approximately 30 miles of new pipeline 2 new compressor stations (totaling

approximately 37000 HP) New interconnection station and modification

of existing interconnection station Abandonment of approximately 45 miles of

existing pipeline and compressor station Regulatory Process

Pre-filing application submitted to FERC in 2017 for original modernization project

FERC 7(b) 7(c) filing expected summer 2019

(1) Includes expansion and modernization portions of the project

40

Empire North Project

Target In-Service second half of fiscal 2020

Est Capital Cost $145 million

Est Annual Revenues ~$25 million

Receipt Point Jackson (Tioga Co Pa production)

Design Capacity and Delivery Points 175000 Dthd to Chippawa (TCPL interconnect)

30000 Dthd to Hopewell (TGP 200 interconnect)

Customers Fully subscribed (205000 Dthday)

Major Facilities 2 new compressor stations in NY (1) amp Pa (1)

No new pipeline construction

Regulatory Process FERC 7(c) application filed on 21618

FERC Environmental Assessment issued 103018

Pipeline amp Storage

Fully Subscribed Project will Provide 205000 Dthday of Incremental Firm Transportation

41

National Fuel Remains Committed to Northern Access Project

Target In-Service as early as fiscal 2022

Total Cost ~$500MM (~$76MM spent to date)

Estimated Annual Revenues ~$84 million

Delivery Points

350000 Dthd to Chippawa (TCPL interconnect)

140000 Dthd to Hopewell (TGP 200 line)

Regulatory Status

February 3 2017 ndash FERC 7(c) certificate issued

August 6 2018 ndash FERC issued Order finding that NY DEC waived water quality certification

Supply and Empire currently working to finalize remaining federal authorizations

Pipeline amp Storage

To Dawn

42

Continued Expansion of the NFG Supply System

Line N Expansion Opportunities

Line N to Monaca Project Project Firm transportation service to a new ethane

cracker facility being built by Shell Chemical Appalachia LLC

Target In-Service July 2019

Estimated Capital Cost $23 million

Contracted Capacity 133000 Dthday

Additional Line N Expansion Opportunity (Supply OS 221) Project New firm transportation service for on-system

demand

Open Season Capacity Awarded 165000 to foundation shipper Precedent agreement in negotiations

Pipeline amp Storage

43

Pipeline amp Storage Customer Mix

Producer33

LDC42

Marketer10

Outside Pipeline

9

End User6

42 MMDthd

(1) Contracted as of 10312018

Customer Transportation by Shipper Type(1) Affiliated Customer Mix (Contracted Capacity)

66

521

41

34

9579

59

LDCs Producers Marketers FirmStorage

Affiliated Non-Affiliated

Firm Transport

Pipeline amp Storage

44

Utility OverviewNational Fuel Gas Distribution Corporation

45

New York amp Pennsylvania Service Territories

New York

Total Customers(1) 535800ROE 87 (NY PSC Rate Case Order April 2017)Rate Mechanismso Revenue Decouplingo Weather Normalizationo Low Income Rateso Merchant Function Charge (Uncollectibles Adj)o 9010 Sharing (Large Customers)o System Modernization Tracker

Pennsylvania

Total Customers(1) 214400ROE Black Box Settlement (2007)Rate Mechanismso Low Income Rateso Merchant Function Charge

(1) As of September 30 2018

Utility

46

New York Rate Case Outcome

Rate Order Summary

Revenue Requirement $59 million

Rate Base $704 million

Allowed Return on Equity (ROE) 87

Capital Structure 429 equity

Other notable items

New rates became effective 5117

Retains rate mechanisms in place under prior order (revenue decoupling weather normalization merchant function charge 9010 large customer sharing)

No stay-out clause

System modernization tracker for Leak Prone Pipe (LPP)

Earnings sharing started 4118 (5050 sharing starts at earnings in excess of 92)

Article 78 appeal filed on 72817 with oral argument completed in January 2019

On April 20 2017 the New York Public Service Commission issued a Rate Order relating to NFG Distributionrsquos rate case (No 16-G-0257) filed in April 2016

Utility

47

Utility Continues its Significant Investments in Safety

$544$618 $636

$699

$944$980

$809$856

$90-100

$00

$250

$500

$750

$1000

$1250

2015 2016 2017 2018 2019E

Cap

ital E

xpen

ditu

res

($ m

illio

ns)

Fiscal Year

Capital Expenditures for Safety Total Capital Expenditures

Modernization Spending in NY Expected to Grow Gross Margin By $2 MM - $5 MM in FY 2019

(1)

(1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation

Utility

System modernization tracker in NY allows recovery of pipeline replacementcosts which is expected to drive modest gross margin and rate base growth

48

Accelerating Pipeline Replacement amp Modernization

Wrought Iron

Plastic

CoatedBare

120130

146 144159

2014 2015 2016 2017 2018Calendar Year

NY9726 miles

PA4830 miles

No Cast Iron Mains in Pa

Miles of Utility Main Pipeline ReplacedUtility Mains by Material(1)

Wrought Iron

Cast Iron

Plastic

Coated Bare

Utility

(1) All values are reported on a calendar year basis as of December 31 2018

49

A Proven History of Controlling Costs

$200 $189 $195

$166 $166

$31 $31

$197 $197

$0

$50

$100

$150

$200

$250

2015 2016 2017 2018 TTM 123118

Fiscal Year

OampM Expense Non-Service Pension Costs

OampM Expense ($ millions)

Utility

(1)

(1) For purposes of comparability to FY 2015 2016 and 2017 Utility Operation and Maintenance Expense for FY 2018 and the twelve months ended December 31 2018 was adjusted by approximately $314 million and $312 million respectively to include non-service pension costs which were re-classified as Other Income (Deductions) as of October 1 2018 on the Companyrsquos Income Statement See Slide 64 for non-GAAP reconciliation of Adjusted Operation and Maintenance Expense to Operation and Maintenance Expense by segment

50

Consolidated Financial OverviewUpstream I Midstream I Downstream

51

Adjusted Operating Results ($ per share)(1)

Diversified Balanced Earnings and Cash Flows

(1) A reconciliation of Adjusted Operating Results to Earnings per Share by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation(2) Consolidated Adjusted EBITDA includes Energy Marketing and Corporate amp All Other Segments A reconciliation of Adjusted EBITDA to Net Income by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in

the Business is included at the end of this presentation

Adjusted EBITDA ($ millions)(2)

$176 $179

$184 $181

$92 $97

$318 $327

$761 $775

$-

$200

$400

$600

$800

FY 2018 TTM 123118

$059 Utility

$097 Pipeline amp Storage

$057 Gathering

$125 Exploration

amp Production

$334 $345 to $365

$-

$100

$200

$300

$400

FY 2018 FY 2019 Guidance

Rate Regulated

40-45

$728

Rate Regulated

~46

52

$89 $94 $98 $81 $86 $90-$100

$140$230

$114 $95 $93 $120-$150

$138$118

$54$33 $48

$55-$65

$603$557

$99 $246$356

$460-$495

$970 $1001

$366$455

$583

$725-$810

$0

$250

$500

$750

$1000

$1250

2014 2015 2016 2017 2018 2019GuidanceFiscal Year

Exploration amp Production

Gathering

Pipeline amp Storage

Utility

Disciplined Flexible Capital Allocation

(2)

(1) Total Capital Expenditures include Energy Marketing Corporate and All Other A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation (2) FY16 FY17 and FY18 reflects the netting of $157 million $7 million and $17 million respectively of up-front proceeds received from joint development partner for working interest in joint development wells and $21M in intercompany asset transfers in FY18

Capital Expenditures by Segment ($ millions)(1)

53

Maintaining Strong Balance Sheet amp Liquidity

Total Equity49

Total Debt51

$42 Billion Total Capitalizationas of December 31 2018

218 x251 x 245 x 247 x 256 x

2015 2016 2017 2018 TTM 123118Fiscal Year End

Net Debt Adjusted EBITDA(1) Capitalization

Debt Maturity Profile ($MM) Liquidity

Committed Credit FacilitiesShort-term Debt OutstandingAvailable Short-term Credit FacilitiesCash Balance at 123118 Total Liquidity at 123118

$ 750 MM0 MM

750 MM110 MM

$ 860 MM

$500 $549 $500

$300 $300

$0

$200

$400

$600

(1) Net Debt is net of cash and temporary cash investments Reconciliations of Net Debt and Adjusted EBITDA to Net Income are included at the end of this presentation

54

Appendix

55

Safe Harbor For Forward Looking StatementsThis presentation may contain ldquoforward-looking statementsrdquo as defined by the Private Securities Litigation Reform Act of 1995 including statements regarding future prospectsplans objectives goals projections estimates of oil and gas quantities strategies future events or performance and underlying assumptions capital structure anticipatedcapital expenditures completion of construction projects projections for pension and other post-retirement benefit obligations impacts of the adoption of new accounting rulesand possible outcomes of litigation or regulatory proceedings as well as statements that are identified by the use of the words ldquoanticipatesrdquo ldquoestimatesrdquo ldquoexpectsrdquo ldquoforecastsrdquoldquointendsrdquo ldquoplansrdquo ldquopredictsrdquo ldquoprojectsrdquo ldquobelievesrdquo ldquoseeksrdquo ldquowillrdquo ldquomayrdquo and similar expressions Forward-looking statements involve risks and uncertainties which couldcause actual results or outcomes to differ materially from those expressed in the forward-looking statements The Companyrsquos expectations beliefs and projections are expressedin good faith and are believed by the Company to have a reasonable basis but there can be no assurance that managementrsquos expectations beliefs or projections will result or beachieved or accomplished

In addition to other factors the following are important factors that could cause actual results to differ materially from those discussed in the forward-looking statements delaysor changes in costs or plans with respect to Company projects or related projects of other companies including difficulties or delays in obtaining necessary governmentalapprovals permits or orders or in obtaining the cooperation of interconnecting facility operators governmentalregulatory actions initiatives and proceedings including thoseinvolving rate cases (which address among other things target rates of return rate design and retained natural gas) environmentalsafety requirements affiliate relationshipsindustry structure and franchise renewal changes in laws regulations or judicial interpretations to which the Company is subject including those involving derivatives taxessafety employment climate change other environmental matters real property and exploration and production activities such as hydraulic fracturing financial and economicconditions including the availability of credit and occurrences affecting the Companyrsquos ability to obtain financing on acceptable terms for working capital capital expendituresand other investments including any downgrades in the Companyrsquos credit ratings and changes in interest rates and other capital market conditions changes in the price ofnatural gas or oil impairments under the SECrsquos full cost ceiling test for natural gas and oil reserves factors affecting the Companyrsquos ability to successfully identify drill for andproduce economically viable natural gas and oil reserves including among others geology lease availability title disputes weather conditions shortages delays orunavailability of equipment and services required in drilling operations insufficient gathering processing and transportation capacity the need to obtain governmentalapprovals and permits and compliance with environmental laws and regulations increasing health care costs and the resulting effect on health insurance premiums and on theobligation to provide other post-retirement benefits changes in price differentials between similar quantities of natural gas or oil sold at different geographic locations and theeffect of such changes on commodity production revenues and demand for pipeline transportation capacity to or from such locations other changes in price differentialsbetween similar quantities of natural gas or oil having different quality heating value hydrocarbon mix or delivery date the cost and effects of legal and administrative claimsagainst the Company or activist shareholder campaigns to effect changes at the Company uncertainty of oil and gas reserve estimates significant differences between theCompanyrsquos projected and actual production levels for natural gas or oil changes in demographic patterns and weather conditions changes in the availability price oraccounting treatment of derivative financial instruments changes in laws actuarial assumptions the interest rate environment and the return on plantrust assets related to theCompanyrsquos pension and other post-retirement benefits which can affect future funding obligations and costs and plan liabilities changes in economic conditions includingglobal national or regional recessions and their effect on the demand for and customersrsquo ability to pay for the Companyrsquos products and services the creditworthiness orperformance of the Companyrsquos key suppliers customers and counterparties the impact of potential information technology cybersecurity or data security breaches economicdisruptions or uninsured losses resulting from major accidents fires severe weather natural disasters terrorist activities or acts of war significant differences between theCompanyrsquos projected and actual capital expenditures and operating expenses or increasing costs of insurance changes in coverage and the ability to obtain insurance

Forward-looking statements include estimates of oil and gas quantities Proved oil and gas reserves are those quantities of oil and gas which by analysis of geoscience andengineering data can be estimated with reasonable certainty to be economically producible under existing economic conditions operating methods and governmentregulations Other estimates of oil and gas quantities including estimates of probable reserves possible reserves and resource potential are by their nature more speculativethan estimates of proved reserves Accordingly estimates other than proved reserves are subject to substantially greater risk of being actually realized Investors are urged toconsider closely the disclosure in our Form 10-K available at wwwnationalfuelgascom You can also obtain this form on the SECrsquos website at wwwsecgov

For a discussion of the risks set forth above and other factors that could cause actual results to differ materially from results referred to in the forward-looking statements seeldquoRisk Factorsrdquo in the Companyrsquos Form 10-K for the fiscal year ended September 30 2018 and the Forms 10-Q for the quarter ended March 31 2018 June 30 2018 and December31 2018 The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date thereof or to reflect the occurrence ofunanticipated events

Appendix

22

WDA Firm Transportation and Sales Capacity

Will continue to layer-in firm sales deals of short and longer duration on TGP 300 to reduce spot exposure

WDA spot realizations track TGP Station 313 pricing typically 10cent - 30cent better than TGP Marcellus Zone 4

Leidy South will provide additional capacity to premium markets (Transco Zone 6)

WDA Exit Capacity Supports Long-term Production Growth and Enhances Consolidated Returns

WDA Contracted Firm Transport and Gross Sales Volumes (MDthd)

Seneca gross production trend

EampP and Gathering

0

100

200

300

400

500

600

700

Niagara Expansion Project (TGP and NFG)FT Capacity 158000 Dthd $067Dth

Firm Sales NYMEX amp DAWN

WDA - TGP 300Firm Sales

Leidy SouthTransco Zone 6

Markets330000 Dthd(1)

Will layer-in firm sales to minimize spot exposure

(1) Portion of Transco Project capacity will likely be utilized by EDA Lycoming County production

WDA Gas Marketing Strategy

23

Eastern Development Area

EDA Acreage ndash 70000 AcresEDA Highlights

1 DCNR Tract 007 (Tioga Co Pa)bull Utica development resumed in third quarter fiscal 2018

bull ~43 remaining Utica locations economic at ~$184 Mcf

bull Gathering Infrastructure NFG Midstream Wellsboro

bull Marcellus Shale expected to provide ~60 additional locations

EampP and Gathering

2

1

3

2 Covington amp DCNR Tract 595 (Tioga Co Pa)bull Marcellus locations fully developed (average daily gross production of ~93 MMcfd)

bull Gathering Infrastructure NFG Midstream Covington

bull Opportunity for future Utica appraisal

3 DCNR Tract 100 amp Gamble (Lycoming Co Pa)bull ~45 remaining Marcellus locations economic at ~$153 Mcfbull Firm Transportation Capacity Atlantic Sunrise (189 MDthd)

bull Gathering Infrastructure NFG Midstream Trout Run

bull Geneseo Shale expected to provide 100-120 additional locations

24

EDA Marcellus Lycoming County Development

Marcellus Development in Lycoming County has Resumed in Connection with Atlantic Sunrise

(1) Includes physical fixed price and NYMEX-based firm sales contracts that do not carry any additional transportation costs

EampP and Gathering

Prolific Marcellus acreage with peer leading well results

~45 remaining Marcellus locations economic at ~$153 Mcf

Near-term development focused on filling Atlantic Sunrise capacity

Existing Line

Leased

Seneca Fee

Producing

FY19 Producer

Development

0

50

100

150

200

250

Gro

ss F

irm V

olum

es (M

Dth

d)

EDA ndash Transco Firm Contracts

Atlantic Sunrise (Transco)FT Capacity 189405 Dthd

Cost $073DthFirm Sales NYMEX+

Transco Firm Sales(1)

25

EDA Utica Tioga County Development

Utica Development in Tioga County ndash Tract 007 Development Resumed in Q3 Fiscal 2018

In-Service November 2016

Lateral Length 4640 ft

30 Day IP 1000 ft 34 MMcfd

Est EUR 1000 ft 24 Bcf

Inventory ~43 locations economic at ~$184 Mcf

Targeting to grow production by 100 to 150 MDthd by fiscal 2020

Expected Development Costs $1045 per lateral ft

Gathering Infrastructure NFG Midstream Wellsboro

Modest build-out required to connect to TGP 300

SalesTakeaway Strategy Layer-in firm sales with shippers holding capacity on TGP 300

(1) Includes physical fixed price and NYMEX-based firm sales contracts that do not carry any additional transportation costs

Tract 007 Utica Appraisal Well Results vs Industry

EampP and Gathering

0

100000

200000

300000

400000

500000

600000

700000

800000

0 100 200 300

Nor

mal

ized

Cum

ulat

ive

(Mcf

10

00rsquo)

Days On ProductionIndustry PotterTioga Wells Seneca DCNR 007 73H

0

25

50

75

100

125

150

Gro

ss F

irm V

olum

es (M

Dth

d)

EDA ndash TGP 300 Firm Contracts

Northeast Supply Diversification ProjectFT Capacity 50000 Dthd $050Dth

Firm Sales NYMEX and DAWN

EDA - TGP 300Firm Sales(1)

26

Integrated Development ndash EDA Gathering Systems

Total Investment (to date) ~$46 million FY 2019 Estimated Capital Expenditures $1 MM - $2 MM Capacity 220000 Dth per day (Interconnect w TGP 300) Production Source Seneca Resources ndash Tioga Co (Covington and DCNR Tract 595)

Total Investment (to date) ~$208 million FY 2019 Estimated Capital Expenditures $25 MM - $35 MM Capacity 466000 to 585000 Dth per day (Interconnect w Transco) Production Source Seneca Resources ndash Lycoming Co (DCNR Tract 100 and Gamble) Future third-party volume opportunities

Covington Gathering System

Trout Run Gathering System

Gathering Segment Supporting Senecarsquos EDA Production amp Future Development

Wellsboro Gathering System Total Investment (to date) ~$14 million FY 2019 Estimated Capital Expenditures $8 MM - $15 MM Capacity up to 200000 Dth per day (Interconnect w TGP 300) Production Source Seneca Resources ndash Tioga Co (DCNR Tract 007)

EampP and Gathering

2

1

3

27

Long-term Contracts Supporting Appalachian Growth

(1) Represents base firm sales contracts not tied to firm transportation capacity Base firm sales are either fixed priced or priced at an index (eg NYMEX ) +- a fixed basis and do not carry any transportation costs

Seneca continues to layer-in firm sales contracts with attractive realizations to lock-in drilling economics and minimize spot exposure ahead of firm transportation in-service dates

EampP and Gathering

-

100

200

300

400

500

600

700

800

900

1000

1100

1200

FY 2019 FY 2020 FY 2021 FY 2022Northeast Supply Diversification 50000 Dthd

Niagara Expansion (TGP amp NFG)Delivery Markets Canada-Dawn amp TETCO

158000 Dthd

Atlantic Sunrise (Transco)Delivery Markets Mid-Atlantic amp Southeast US

189405 Dthd

In-BasinFirm Sales

Contracts(1)

Leidy South (Transco amp NFG)

Transco Zone 6 Markets330000 Dthd

Seneca Appalachia Natural Gas MarketingGross Firm Contract Volumes (Mdthday)

28

297000 ($061)

305200 ($061)

305600 ($063)

337000 ($057)

370800 ($024)

369600 ($060)

367900 ($067)

33400 ($070)74500 ($077) 74900 ($077)

81100 ($078)

85900 ($078)

92000 ($073)

91300 ($073)

178800 $255

196000 $234

195500 $234

149900 $232

129500 $230

105400 $222

104500 $222

~517800 509200 575700 576000 568000 586200 567000 563700

Q1 FY19 Q2 FY19 Q3 FY19 Q4 FY19 Q1 FY20 Q2 FY20 Q3 FY20 Q4 FY20

Fixed Price Dawn NYMEX

Near-term Firm Sales Provide Market amp Price Certainty

Net Contracted Firm Sales Volumes (Dth per day)Contracted Index Price Differentials ($ per Dth)(1)

(1) Values shown represent the weighted average fixed price or contracted fixed differential relative to NYMEX (netback price) less any associated transportation costs

Actual Daily Net

Production

641200 716500 708700 693500 708400 674400 667000Gross Firm Sales Volumes (Dthd)

EampP and Gathering

29

California Oil

Stable Oil Production | Minimal Capital Investment | Steady Free Cash Flow

1

2

3

4

5

Location Formation Production Method

FY18 Daily Production(net Boed)

1 East Coalinga Other Temblor Primary 512

2 North Lost Hills

Tulare amp Etchegoin

PrimarySteam flood 892

3 South Lost Hills

Monterey Shale Primary 1359

4 North Midway Sunset

Tulare amp Potter Steam flood 2786

5 South Midway Sunset Antelope Steam flood 2048

TOTAL WEST DIVISION NET PRODUCTION(1) 7597 Boed

EampP and Gathering

(1) West division net production for FY 2018 excludes production from Sespe field which was divested on May 1 2018

30

California Capital Expenditures vs Production

9341 8863

8033 ~7300

2016 2017 2018 2019

Fiscal Year

West Division Average Net Daily Production (Boe)West Division Annual Capital Expenditures ($ MM)(1)

$38 $38

$26 ~$25

2016 2017 2018 2019

Fiscal YearGuidance Guidance

(1) Seneca West Division capital expenditures includes Seneca corporate and eliminations

EampP and Gathering

Sepse Sale Closed on 5118(reduced production by ~900 boed)

31

Pioneer

South MWSS

Acreage

North MWSS

AcreageSec 17N

4149 51

NMWSS amp 17N SMWSS amp Pioneer East Coalinga

California Development Activities

Modest near-term capital program focused on locations that earn attractive returns in current oil price environment

AampD will focus on low cost bolt-on opportunities

Sec 17 Pioneer and East Coalinga development to provide future growth

North

Project IRRs at $55Bbl(1)

(1) Reflects pre-tax IRRs at a $55Bbl WTI

EampP and Gathering

Seneca West Economics

South

East Coalinga

North

South

32

Fiscal 2019 Production and Price Certainty

~49 Bcfe

210 ndash 230 Bcfe

~114 Bcf

~29 Bcf (2)

16+- Bcf~12 Bcfe

0

40

80

120

160

200

240

YTD FY19Actuals

Fixed Price + FirmSales w Hedge

Firm Sales(Unhedged)

Spot Sales California TotalSeneca

Prod

uctio

n (B

cfe)

(1) Average realized price reflects uplift from financial hedges less fixed differentials under firm sales contracts and any firm transportation costs(2) Indicates firm sales contracts with fixed index differentials but not backed by a matching financial hedge

114 Bcf locked-in realizing net ~$241Mcf (1)

29 Bcf of additional basis protection

Spot production assumed to be sold

at ~$275Mmbtu(winter) and ~$225

(summer)

143 Bcf of Appalachian Production Protected by Firm Sales for Remainder of Year

79 of oil production hedged at $5757 Bbl

EampP and Gathering

33

Strong Hedge Book

Natural Gas Swap amp Fixed Physical Sales Contracts (Millions MMBtu)

(1) Fixed price physical sales exclude joint development partnerrsquos share of fixed price contract WDA volumes as specified under the joint development agreement(2) Reflects percentage of projected production for FY19 hedged at the midpoint of the production guidance range(3) Senecarsquos remainder FY19 Production reflects the total FY19 production guidance of 210-230 Bcfe or 220 Bcfe at the midpoint less Q1 actual production

Crude Oil Swap Contracts (Thousands Bbls)

13591188

732

456

0

500

1000

1500

2000

2500

FY 2019 FY 2020 FY 2021 FY 2022

NYMEX (WTI)

Brent

FY 19 Crude Oil79 Hedged (2)

FY 2019 Remaining Production (3)

EampP and Gathering

1174

709

469 406

0

50

100

150

200

250

FY 2019 FY 2020 FY 2021 FY 2022

NYMEX Swaps

Dawn Swaps

Fixed Price Physical Sales

(1)

FY 2019 Remaining Production (3)

FY 19 Nat Gas71 Hedged (2)

34

$065 $070$070 -$075

FY 2017 FY 2018 FY 2019E

$060 $060 $060

$011 $009 $007$071 $069 ~$067

FY 2017 FY 2018 FY 2019E Gathering amp Transport LOE (non-Gathering) GampA Taxes amp Other

Seneca Operating Costs

Competitive low cost structure in Appalachia and California supports strong cash margins

Gathering fee generates significant revenue stream for affiliated gathering company

Seneca DDampARate

$Mcfe

$054 $054 $056

$042 $038 $031

$034 $034 $030

$017 $014 $015

$147 $140 ~$132

FY 2017 FY 2018 FY 2019E

(1)

$1791$1746~$2050

FY 2017 FY 2018 FY 2019E

Appalachia LOE amp Gathering $Mcfe

California LOE$Boe

Total Seneca Cash OpEx$Mcfe

(1)

(2)

(2)

(1) GampA estimate represents the midpoint of the GampA guidance range of $025 to $035 for fiscal 2019(2) The total of the two LOE components represents the midpoint of the LOE guidance range of $085 to $090 for fiscal 2019

EampP and Gathering

35

Senecarsquos Continuing Commitment to the Environment

Produced Water Recycled in Appalachia

100 70Recycled Water

Used in New Shale Well

Completions

Water and Fluids Management Air Quality and Emissions

Seneca Resources Water OperationsFiscal 2018

Seneca Resources Remains Focused on Minimizing GHG Emissions

The Environmental Partnership

EPA Natural Gas Star Program

Green Completions (all fiscal 2018 wells)

Ultrasonic Leak Detection Technology

Emissions Controls

Rig and Vehicle Fuel Conversion

Integrating Renewable Energy into Operations

EampP and Gathering

36

Pipeline and Storage OverviewNational Fuel Gas Supply Corporation ~ Empire Pipeline Inc

37

Pipeline amp Storage Segment Overview

(1) As of September 30 2018 as disclosed in the Companyrsquos fiscal 2018 form 10-K(2) As of December 31 2017 calculated from National Fuel Gas Supply Corporationrsquos and Empire Pipeline Incrsquos 2017 FERC Form-2 reports respectively

Empire Pipeline Inc

National Fuel Gas Supply Corporation

Empire Pipeline

Supply Corp

Contracted Capacity(1) Firm Transportation 3187 MDth per day Firm Storage 71938 Mdth (fully subscribed)

Rate Base(2) ~$820 million FERC Rate Proceeding Status

Rate case settlement extension approved Nov lsquo15 Rate case filing expected by 73119

Contracted Capacity(1) Firm Transportation 978 MDth per day Firm Storage 3753 Mdth (fully subscribed)

Rate Base(2) ~$249 million FERC Rate Proceeding Status

Rate case settlement in principle reached on 122118 FERC approval pending

New transportation rates went into on 1119

Pipeline amp Storage

38

All Seneca volumes will flow through wholly-owned NFG gathering facilities

FM100 Project - Consolidated Benefit for NFG

330000 Dthd of new transportation capacity from WDA and EDA acreage positions to premium markets

New Transco capacity (Leidy South) 330000 Dthday

Rate(1) competitive with other expansion project rates in Senecarsquos current transportation portfolio

Delivery Point(s) Transco Zone 6 interconnections

Seneca

Lease to Transco of new capacity 330000 Dthday

Estimated annual lease revenues ~$35 million

Target In-Service late calendar year 2021

Supply Corp

Project expected to provide long-term earnings uplift to Seneca Supply Corp and Gathering

Pipeline amp Storage

Gathering

(1) Includes lease of new capacity from Supply Corp to Transco

39

FM100 Project ndash Significant Investment by Supply Corp

Pipeline amp Storage

Estimated Capital Cost $280 million(1)

Facilities (all in Pennsylvania) include Approximately 30 miles of new pipeline 2 new compressor stations (totaling

approximately 37000 HP) New interconnection station and modification

of existing interconnection station Abandonment of approximately 45 miles of

existing pipeline and compressor station Regulatory Process

Pre-filing application submitted to FERC in 2017 for original modernization project

FERC 7(b) 7(c) filing expected summer 2019

(1) Includes expansion and modernization portions of the project

40

Empire North Project

Target In-Service second half of fiscal 2020

Est Capital Cost $145 million

Est Annual Revenues ~$25 million

Receipt Point Jackson (Tioga Co Pa production)

Design Capacity and Delivery Points 175000 Dthd to Chippawa (TCPL interconnect)

30000 Dthd to Hopewell (TGP 200 interconnect)

Customers Fully subscribed (205000 Dthday)

Major Facilities 2 new compressor stations in NY (1) amp Pa (1)

No new pipeline construction

Regulatory Process FERC 7(c) application filed on 21618

FERC Environmental Assessment issued 103018

Pipeline amp Storage

Fully Subscribed Project will Provide 205000 Dthday of Incremental Firm Transportation

41

National Fuel Remains Committed to Northern Access Project

Target In-Service as early as fiscal 2022

Total Cost ~$500MM (~$76MM spent to date)

Estimated Annual Revenues ~$84 million

Delivery Points

350000 Dthd to Chippawa (TCPL interconnect)

140000 Dthd to Hopewell (TGP 200 line)

Regulatory Status

February 3 2017 ndash FERC 7(c) certificate issued

August 6 2018 ndash FERC issued Order finding that NY DEC waived water quality certification

Supply and Empire currently working to finalize remaining federal authorizations

Pipeline amp Storage

To Dawn

42

Continued Expansion of the NFG Supply System

Line N Expansion Opportunities

Line N to Monaca Project Project Firm transportation service to a new ethane

cracker facility being built by Shell Chemical Appalachia LLC

Target In-Service July 2019

Estimated Capital Cost $23 million

Contracted Capacity 133000 Dthday

Additional Line N Expansion Opportunity (Supply OS 221) Project New firm transportation service for on-system

demand

Open Season Capacity Awarded 165000 to foundation shipper Precedent agreement in negotiations

Pipeline amp Storage

43

Pipeline amp Storage Customer Mix

Producer33

LDC42

Marketer10

Outside Pipeline

9

End User6

42 MMDthd

(1) Contracted as of 10312018

Customer Transportation by Shipper Type(1) Affiliated Customer Mix (Contracted Capacity)

66

521

41

34

9579

59

LDCs Producers Marketers FirmStorage

Affiliated Non-Affiliated

Firm Transport

Pipeline amp Storage

44

Utility OverviewNational Fuel Gas Distribution Corporation

45

New York amp Pennsylvania Service Territories

New York

Total Customers(1) 535800ROE 87 (NY PSC Rate Case Order April 2017)Rate Mechanismso Revenue Decouplingo Weather Normalizationo Low Income Rateso Merchant Function Charge (Uncollectibles Adj)o 9010 Sharing (Large Customers)o System Modernization Tracker

Pennsylvania

Total Customers(1) 214400ROE Black Box Settlement (2007)Rate Mechanismso Low Income Rateso Merchant Function Charge

(1) As of September 30 2018

Utility

46

New York Rate Case Outcome

Rate Order Summary

Revenue Requirement $59 million

Rate Base $704 million

Allowed Return on Equity (ROE) 87

Capital Structure 429 equity

Other notable items

New rates became effective 5117

Retains rate mechanisms in place under prior order (revenue decoupling weather normalization merchant function charge 9010 large customer sharing)

No stay-out clause

System modernization tracker for Leak Prone Pipe (LPP)

Earnings sharing started 4118 (5050 sharing starts at earnings in excess of 92)

Article 78 appeal filed on 72817 with oral argument completed in January 2019

On April 20 2017 the New York Public Service Commission issued a Rate Order relating to NFG Distributionrsquos rate case (No 16-G-0257) filed in April 2016

Utility

47

Utility Continues its Significant Investments in Safety

$544$618 $636

$699

$944$980

$809$856

$90-100

$00

$250

$500

$750

$1000

$1250

2015 2016 2017 2018 2019E

Cap

ital E

xpen

ditu

res

($ m

illio

ns)

Fiscal Year

Capital Expenditures for Safety Total Capital Expenditures

Modernization Spending in NY Expected to Grow Gross Margin By $2 MM - $5 MM in FY 2019

(1)

(1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation

Utility

System modernization tracker in NY allows recovery of pipeline replacementcosts which is expected to drive modest gross margin and rate base growth

48

Accelerating Pipeline Replacement amp Modernization

Wrought Iron

Plastic

CoatedBare

120130

146 144159

2014 2015 2016 2017 2018Calendar Year

NY9726 miles

PA4830 miles

No Cast Iron Mains in Pa

Miles of Utility Main Pipeline ReplacedUtility Mains by Material(1)

Wrought Iron

Cast Iron

Plastic

Coated Bare

Utility

(1) All values are reported on a calendar year basis as of December 31 2018

49

A Proven History of Controlling Costs

$200 $189 $195

$166 $166

$31 $31

$197 $197

$0

$50

$100

$150

$200

$250

2015 2016 2017 2018 TTM 123118

Fiscal Year

OampM Expense Non-Service Pension Costs

OampM Expense ($ millions)

Utility

(1)

(1) For purposes of comparability to FY 2015 2016 and 2017 Utility Operation and Maintenance Expense for FY 2018 and the twelve months ended December 31 2018 was adjusted by approximately $314 million and $312 million respectively to include non-service pension costs which were re-classified as Other Income (Deductions) as of October 1 2018 on the Companyrsquos Income Statement See Slide 64 for non-GAAP reconciliation of Adjusted Operation and Maintenance Expense to Operation and Maintenance Expense by segment

50

Consolidated Financial OverviewUpstream I Midstream I Downstream

51

Adjusted Operating Results ($ per share)(1)

Diversified Balanced Earnings and Cash Flows

(1) A reconciliation of Adjusted Operating Results to Earnings per Share by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation(2) Consolidated Adjusted EBITDA includes Energy Marketing and Corporate amp All Other Segments A reconciliation of Adjusted EBITDA to Net Income by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in

the Business is included at the end of this presentation

Adjusted EBITDA ($ millions)(2)

$176 $179

$184 $181

$92 $97

$318 $327

$761 $775

$-

$200

$400

$600

$800

FY 2018 TTM 123118

$059 Utility

$097 Pipeline amp Storage

$057 Gathering

$125 Exploration

amp Production

$334 $345 to $365

$-

$100

$200

$300

$400

FY 2018 FY 2019 Guidance

Rate Regulated

40-45

$728

Rate Regulated

~46

52

$89 $94 $98 $81 $86 $90-$100

$140$230

$114 $95 $93 $120-$150

$138$118

$54$33 $48

$55-$65

$603$557

$99 $246$356

$460-$495

$970 $1001

$366$455

$583

$725-$810

$0

$250

$500

$750

$1000

$1250

2014 2015 2016 2017 2018 2019GuidanceFiscal Year

Exploration amp Production

Gathering

Pipeline amp Storage

Utility

Disciplined Flexible Capital Allocation

(2)

(1) Total Capital Expenditures include Energy Marketing Corporate and All Other A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation (2) FY16 FY17 and FY18 reflects the netting of $157 million $7 million and $17 million respectively of up-front proceeds received from joint development partner for working interest in joint development wells and $21M in intercompany asset transfers in FY18

Capital Expenditures by Segment ($ millions)(1)

53

Maintaining Strong Balance Sheet amp Liquidity

Total Equity49

Total Debt51

$42 Billion Total Capitalizationas of December 31 2018

218 x251 x 245 x 247 x 256 x

2015 2016 2017 2018 TTM 123118Fiscal Year End

Net Debt Adjusted EBITDA(1) Capitalization

Debt Maturity Profile ($MM) Liquidity

Committed Credit FacilitiesShort-term Debt OutstandingAvailable Short-term Credit FacilitiesCash Balance at 123118 Total Liquidity at 123118

$ 750 MM0 MM

750 MM110 MM

$ 860 MM

$500 $549 $500

$300 $300

$0

$200

$400

$600

(1) Net Debt is net of cash and temporary cash investments Reconciliations of Net Debt and Adjusted EBITDA to Net Income are included at the end of this presentation

54

Appendix

55

Safe Harbor For Forward Looking StatementsThis presentation may contain ldquoforward-looking statementsrdquo as defined by the Private Securities Litigation Reform Act of 1995 including statements regarding future prospectsplans objectives goals projections estimates of oil and gas quantities strategies future events or performance and underlying assumptions capital structure anticipatedcapital expenditures completion of construction projects projections for pension and other post-retirement benefit obligations impacts of the adoption of new accounting rulesand possible outcomes of litigation or regulatory proceedings as well as statements that are identified by the use of the words ldquoanticipatesrdquo ldquoestimatesrdquo ldquoexpectsrdquo ldquoforecastsrdquoldquointendsrdquo ldquoplansrdquo ldquopredictsrdquo ldquoprojectsrdquo ldquobelievesrdquo ldquoseeksrdquo ldquowillrdquo ldquomayrdquo and similar expressions Forward-looking statements involve risks and uncertainties which couldcause actual results or outcomes to differ materially from those expressed in the forward-looking statements The Companyrsquos expectations beliefs and projections are expressedin good faith and are believed by the Company to have a reasonable basis but there can be no assurance that managementrsquos expectations beliefs or projections will result or beachieved or accomplished

In addition to other factors the following are important factors that could cause actual results to differ materially from those discussed in the forward-looking statements delaysor changes in costs or plans with respect to Company projects or related projects of other companies including difficulties or delays in obtaining necessary governmentalapprovals permits or orders or in obtaining the cooperation of interconnecting facility operators governmentalregulatory actions initiatives and proceedings including thoseinvolving rate cases (which address among other things target rates of return rate design and retained natural gas) environmentalsafety requirements affiliate relationshipsindustry structure and franchise renewal changes in laws regulations or judicial interpretations to which the Company is subject including those involving derivatives taxessafety employment climate change other environmental matters real property and exploration and production activities such as hydraulic fracturing financial and economicconditions including the availability of credit and occurrences affecting the Companyrsquos ability to obtain financing on acceptable terms for working capital capital expendituresand other investments including any downgrades in the Companyrsquos credit ratings and changes in interest rates and other capital market conditions changes in the price ofnatural gas or oil impairments under the SECrsquos full cost ceiling test for natural gas and oil reserves factors affecting the Companyrsquos ability to successfully identify drill for andproduce economically viable natural gas and oil reserves including among others geology lease availability title disputes weather conditions shortages delays orunavailability of equipment and services required in drilling operations insufficient gathering processing and transportation capacity the need to obtain governmentalapprovals and permits and compliance with environmental laws and regulations increasing health care costs and the resulting effect on health insurance premiums and on theobligation to provide other post-retirement benefits changes in price differentials between similar quantities of natural gas or oil sold at different geographic locations and theeffect of such changes on commodity production revenues and demand for pipeline transportation capacity to or from such locations other changes in price differentialsbetween similar quantities of natural gas or oil having different quality heating value hydrocarbon mix or delivery date the cost and effects of legal and administrative claimsagainst the Company or activist shareholder campaigns to effect changes at the Company uncertainty of oil and gas reserve estimates significant differences between theCompanyrsquos projected and actual production levels for natural gas or oil changes in demographic patterns and weather conditions changes in the availability price oraccounting treatment of derivative financial instruments changes in laws actuarial assumptions the interest rate environment and the return on plantrust assets related to theCompanyrsquos pension and other post-retirement benefits which can affect future funding obligations and costs and plan liabilities changes in economic conditions includingglobal national or regional recessions and their effect on the demand for and customersrsquo ability to pay for the Companyrsquos products and services the creditworthiness orperformance of the Companyrsquos key suppliers customers and counterparties the impact of potential information technology cybersecurity or data security breaches economicdisruptions or uninsured losses resulting from major accidents fires severe weather natural disasters terrorist activities or acts of war significant differences between theCompanyrsquos projected and actual capital expenditures and operating expenses or increasing costs of insurance changes in coverage and the ability to obtain insurance

Forward-looking statements include estimates of oil and gas quantities Proved oil and gas reserves are those quantities of oil and gas which by analysis of geoscience andengineering data can be estimated with reasonable certainty to be economically producible under existing economic conditions operating methods and governmentregulations Other estimates of oil and gas quantities including estimates of probable reserves possible reserves and resource potential are by their nature more speculativethan estimates of proved reserves Accordingly estimates other than proved reserves are subject to substantially greater risk of being actually realized Investors are urged toconsider closely the disclosure in our Form 10-K available at wwwnationalfuelgascom You can also obtain this form on the SECrsquos website at wwwsecgov

For a discussion of the risks set forth above and other factors that could cause actual results to differ materially from results referred to in the forward-looking statements seeldquoRisk Factorsrdquo in the Companyrsquos Form 10-K for the fiscal year ended September 30 2018 and the Forms 10-Q for the quarter ended March 31 2018 June 30 2018 and December31 2018 The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date thereof or to reflect the occurrence ofunanticipated events

Appendix

23

Eastern Development Area

EDA Acreage ndash 70000 AcresEDA Highlights

1 DCNR Tract 007 (Tioga Co Pa)bull Utica development resumed in third quarter fiscal 2018

bull ~43 remaining Utica locations economic at ~$184 Mcf

bull Gathering Infrastructure NFG Midstream Wellsboro

bull Marcellus Shale expected to provide ~60 additional locations

EampP and Gathering

2

1

3

2 Covington amp DCNR Tract 595 (Tioga Co Pa)bull Marcellus locations fully developed (average daily gross production of ~93 MMcfd)

bull Gathering Infrastructure NFG Midstream Covington

bull Opportunity for future Utica appraisal

3 DCNR Tract 100 amp Gamble (Lycoming Co Pa)bull ~45 remaining Marcellus locations economic at ~$153 Mcfbull Firm Transportation Capacity Atlantic Sunrise (189 MDthd)

bull Gathering Infrastructure NFG Midstream Trout Run

bull Geneseo Shale expected to provide 100-120 additional locations

24

EDA Marcellus Lycoming County Development

Marcellus Development in Lycoming County has Resumed in Connection with Atlantic Sunrise

(1) Includes physical fixed price and NYMEX-based firm sales contracts that do not carry any additional transportation costs

EampP and Gathering

Prolific Marcellus acreage with peer leading well results

~45 remaining Marcellus locations economic at ~$153 Mcf

Near-term development focused on filling Atlantic Sunrise capacity

Existing Line

Leased

Seneca Fee

Producing

FY19 Producer

Development

0

50

100

150

200

250

Gro

ss F

irm V

olum

es (M

Dth

d)

EDA ndash Transco Firm Contracts

Atlantic Sunrise (Transco)FT Capacity 189405 Dthd

Cost $073DthFirm Sales NYMEX+

Transco Firm Sales(1)

25

EDA Utica Tioga County Development

Utica Development in Tioga County ndash Tract 007 Development Resumed in Q3 Fiscal 2018

In-Service November 2016

Lateral Length 4640 ft

30 Day IP 1000 ft 34 MMcfd

Est EUR 1000 ft 24 Bcf

Inventory ~43 locations economic at ~$184 Mcf

Targeting to grow production by 100 to 150 MDthd by fiscal 2020

Expected Development Costs $1045 per lateral ft

Gathering Infrastructure NFG Midstream Wellsboro

Modest build-out required to connect to TGP 300

SalesTakeaway Strategy Layer-in firm sales with shippers holding capacity on TGP 300

(1) Includes physical fixed price and NYMEX-based firm sales contracts that do not carry any additional transportation costs

Tract 007 Utica Appraisal Well Results vs Industry

EampP and Gathering

0

100000

200000

300000

400000

500000

600000

700000

800000

0 100 200 300

Nor

mal

ized

Cum

ulat

ive

(Mcf

10

00rsquo)

Days On ProductionIndustry PotterTioga Wells Seneca DCNR 007 73H

0

25

50

75

100

125

150

Gro

ss F

irm V

olum

es (M

Dth

d)

EDA ndash TGP 300 Firm Contracts

Northeast Supply Diversification ProjectFT Capacity 50000 Dthd $050Dth

Firm Sales NYMEX and DAWN

EDA - TGP 300Firm Sales(1)

26

Integrated Development ndash EDA Gathering Systems

Total Investment (to date) ~$46 million FY 2019 Estimated Capital Expenditures $1 MM - $2 MM Capacity 220000 Dth per day (Interconnect w TGP 300) Production Source Seneca Resources ndash Tioga Co (Covington and DCNR Tract 595)

Total Investment (to date) ~$208 million FY 2019 Estimated Capital Expenditures $25 MM - $35 MM Capacity 466000 to 585000 Dth per day (Interconnect w Transco) Production Source Seneca Resources ndash Lycoming Co (DCNR Tract 100 and Gamble) Future third-party volume opportunities

Covington Gathering System

Trout Run Gathering System

Gathering Segment Supporting Senecarsquos EDA Production amp Future Development

Wellsboro Gathering System Total Investment (to date) ~$14 million FY 2019 Estimated Capital Expenditures $8 MM - $15 MM Capacity up to 200000 Dth per day (Interconnect w TGP 300) Production Source Seneca Resources ndash Tioga Co (DCNR Tract 007)

EampP and Gathering

2

1

3

27

Long-term Contracts Supporting Appalachian Growth

(1) Represents base firm sales contracts not tied to firm transportation capacity Base firm sales are either fixed priced or priced at an index (eg NYMEX ) +- a fixed basis and do not carry any transportation costs

Seneca continues to layer-in firm sales contracts with attractive realizations to lock-in drilling economics and minimize spot exposure ahead of firm transportation in-service dates

EampP and Gathering

-

100

200

300

400

500

600

700

800

900

1000

1100

1200

FY 2019 FY 2020 FY 2021 FY 2022Northeast Supply Diversification 50000 Dthd

Niagara Expansion (TGP amp NFG)Delivery Markets Canada-Dawn amp TETCO

158000 Dthd

Atlantic Sunrise (Transco)Delivery Markets Mid-Atlantic amp Southeast US

189405 Dthd

In-BasinFirm Sales

Contracts(1)

Leidy South (Transco amp NFG)

Transco Zone 6 Markets330000 Dthd

Seneca Appalachia Natural Gas MarketingGross Firm Contract Volumes (Mdthday)

28

297000 ($061)

305200 ($061)

305600 ($063)

337000 ($057)

370800 ($024)

369600 ($060)

367900 ($067)

33400 ($070)74500 ($077) 74900 ($077)

81100 ($078)

85900 ($078)

92000 ($073)

91300 ($073)

178800 $255

196000 $234

195500 $234

149900 $232

129500 $230

105400 $222

104500 $222

~517800 509200 575700 576000 568000 586200 567000 563700

Q1 FY19 Q2 FY19 Q3 FY19 Q4 FY19 Q1 FY20 Q2 FY20 Q3 FY20 Q4 FY20

Fixed Price Dawn NYMEX

Near-term Firm Sales Provide Market amp Price Certainty

Net Contracted Firm Sales Volumes (Dth per day)Contracted Index Price Differentials ($ per Dth)(1)

(1) Values shown represent the weighted average fixed price or contracted fixed differential relative to NYMEX (netback price) less any associated transportation costs

Actual Daily Net

Production

641200 716500 708700 693500 708400 674400 667000Gross Firm Sales Volumes (Dthd)

EampP and Gathering

29

California Oil

Stable Oil Production | Minimal Capital Investment | Steady Free Cash Flow

1

2

3

4

5

Location Formation Production Method

FY18 Daily Production(net Boed)

1 East Coalinga Other Temblor Primary 512

2 North Lost Hills

Tulare amp Etchegoin

PrimarySteam flood 892

3 South Lost Hills

Monterey Shale Primary 1359

4 North Midway Sunset

Tulare amp Potter Steam flood 2786

5 South Midway Sunset Antelope Steam flood 2048

TOTAL WEST DIVISION NET PRODUCTION(1) 7597 Boed

EampP and Gathering

(1) West division net production for FY 2018 excludes production from Sespe field which was divested on May 1 2018

30

California Capital Expenditures vs Production

9341 8863

8033 ~7300

2016 2017 2018 2019

Fiscal Year

West Division Average Net Daily Production (Boe)West Division Annual Capital Expenditures ($ MM)(1)

$38 $38

$26 ~$25

2016 2017 2018 2019

Fiscal YearGuidance Guidance

(1) Seneca West Division capital expenditures includes Seneca corporate and eliminations

EampP and Gathering

Sepse Sale Closed on 5118(reduced production by ~900 boed)

31

Pioneer

South MWSS

Acreage

North MWSS

AcreageSec 17N

4149 51

NMWSS amp 17N SMWSS amp Pioneer East Coalinga

California Development Activities

Modest near-term capital program focused on locations that earn attractive returns in current oil price environment

AampD will focus on low cost bolt-on opportunities

Sec 17 Pioneer and East Coalinga development to provide future growth

North

Project IRRs at $55Bbl(1)

(1) Reflects pre-tax IRRs at a $55Bbl WTI

EampP and Gathering

Seneca West Economics

South

East Coalinga

North

South

32

Fiscal 2019 Production and Price Certainty

~49 Bcfe

210 ndash 230 Bcfe

~114 Bcf

~29 Bcf (2)

16+- Bcf~12 Bcfe

0

40

80

120

160

200

240

YTD FY19Actuals

Fixed Price + FirmSales w Hedge

Firm Sales(Unhedged)

Spot Sales California TotalSeneca

Prod

uctio

n (B

cfe)

(1) Average realized price reflects uplift from financial hedges less fixed differentials under firm sales contracts and any firm transportation costs(2) Indicates firm sales contracts with fixed index differentials but not backed by a matching financial hedge

114 Bcf locked-in realizing net ~$241Mcf (1)

29 Bcf of additional basis protection

Spot production assumed to be sold

at ~$275Mmbtu(winter) and ~$225

(summer)

143 Bcf of Appalachian Production Protected by Firm Sales for Remainder of Year

79 of oil production hedged at $5757 Bbl

EampP and Gathering

33

Strong Hedge Book

Natural Gas Swap amp Fixed Physical Sales Contracts (Millions MMBtu)

(1) Fixed price physical sales exclude joint development partnerrsquos share of fixed price contract WDA volumes as specified under the joint development agreement(2) Reflects percentage of projected production for FY19 hedged at the midpoint of the production guidance range(3) Senecarsquos remainder FY19 Production reflects the total FY19 production guidance of 210-230 Bcfe or 220 Bcfe at the midpoint less Q1 actual production

Crude Oil Swap Contracts (Thousands Bbls)

13591188

732

456

0

500

1000

1500

2000

2500

FY 2019 FY 2020 FY 2021 FY 2022

NYMEX (WTI)

Brent

FY 19 Crude Oil79 Hedged (2)

FY 2019 Remaining Production (3)

EampP and Gathering

1174

709

469 406

0

50

100

150

200

250

FY 2019 FY 2020 FY 2021 FY 2022

NYMEX Swaps

Dawn Swaps

Fixed Price Physical Sales

(1)

FY 2019 Remaining Production (3)

FY 19 Nat Gas71 Hedged (2)

34

$065 $070$070 -$075

FY 2017 FY 2018 FY 2019E

$060 $060 $060

$011 $009 $007$071 $069 ~$067

FY 2017 FY 2018 FY 2019E Gathering amp Transport LOE (non-Gathering) GampA Taxes amp Other

Seneca Operating Costs

Competitive low cost structure in Appalachia and California supports strong cash margins

Gathering fee generates significant revenue stream for affiliated gathering company

Seneca DDampARate

$Mcfe

$054 $054 $056

$042 $038 $031

$034 $034 $030

$017 $014 $015

$147 $140 ~$132

FY 2017 FY 2018 FY 2019E

(1)

$1791$1746~$2050

FY 2017 FY 2018 FY 2019E

Appalachia LOE amp Gathering $Mcfe

California LOE$Boe

Total Seneca Cash OpEx$Mcfe

(1)

(2)

(2)

(1) GampA estimate represents the midpoint of the GampA guidance range of $025 to $035 for fiscal 2019(2) The total of the two LOE components represents the midpoint of the LOE guidance range of $085 to $090 for fiscal 2019

EampP and Gathering

35

Senecarsquos Continuing Commitment to the Environment

Produced Water Recycled in Appalachia

100 70Recycled Water

Used in New Shale Well

Completions

Water and Fluids Management Air Quality and Emissions

Seneca Resources Water OperationsFiscal 2018

Seneca Resources Remains Focused on Minimizing GHG Emissions

The Environmental Partnership

EPA Natural Gas Star Program

Green Completions (all fiscal 2018 wells)

Ultrasonic Leak Detection Technology

Emissions Controls

Rig and Vehicle Fuel Conversion

Integrating Renewable Energy into Operations

EampP and Gathering

36

Pipeline and Storage OverviewNational Fuel Gas Supply Corporation ~ Empire Pipeline Inc

37

Pipeline amp Storage Segment Overview

(1) As of September 30 2018 as disclosed in the Companyrsquos fiscal 2018 form 10-K(2) As of December 31 2017 calculated from National Fuel Gas Supply Corporationrsquos and Empire Pipeline Incrsquos 2017 FERC Form-2 reports respectively

Empire Pipeline Inc

National Fuel Gas Supply Corporation

Empire Pipeline

Supply Corp

Contracted Capacity(1) Firm Transportation 3187 MDth per day Firm Storage 71938 Mdth (fully subscribed)

Rate Base(2) ~$820 million FERC Rate Proceeding Status

Rate case settlement extension approved Nov lsquo15 Rate case filing expected by 73119

Contracted Capacity(1) Firm Transportation 978 MDth per day Firm Storage 3753 Mdth (fully subscribed)

Rate Base(2) ~$249 million FERC Rate Proceeding Status

Rate case settlement in principle reached on 122118 FERC approval pending

New transportation rates went into on 1119

Pipeline amp Storage

38

All Seneca volumes will flow through wholly-owned NFG gathering facilities

FM100 Project - Consolidated Benefit for NFG

330000 Dthd of new transportation capacity from WDA and EDA acreage positions to premium markets

New Transco capacity (Leidy South) 330000 Dthday

Rate(1) competitive with other expansion project rates in Senecarsquos current transportation portfolio

Delivery Point(s) Transco Zone 6 interconnections

Seneca

Lease to Transco of new capacity 330000 Dthday

Estimated annual lease revenues ~$35 million

Target In-Service late calendar year 2021

Supply Corp

Project expected to provide long-term earnings uplift to Seneca Supply Corp and Gathering

Pipeline amp Storage

Gathering

(1) Includes lease of new capacity from Supply Corp to Transco

39

FM100 Project ndash Significant Investment by Supply Corp

Pipeline amp Storage

Estimated Capital Cost $280 million(1)

Facilities (all in Pennsylvania) include Approximately 30 miles of new pipeline 2 new compressor stations (totaling

approximately 37000 HP) New interconnection station and modification

of existing interconnection station Abandonment of approximately 45 miles of

existing pipeline and compressor station Regulatory Process

Pre-filing application submitted to FERC in 2017 for original modernization project

FERC 7(b) 7(c) filing expected summer 2019

(1) Includes expansion and modernization portions of the project

40

Empire North Project

Target In-Service second half of fiscal 2020

Est Capital Cost $145 million

Est Annual Revenues ~$25 million

Receipt Point Jackson (Tioga Co Pa production)

Design Capacity and Delivery Points 175000 Dthd to Chippawa (TCPL interconnect)

30000 Dthd to Hopewell (TGP 200 interconnect)

Customers Fully subscribed (205000 Dthday)

Major Facilities 2 new compressor stations in NY (1) amp Pa (1)

No new pipeline construction

Regulatory Process FERC 7(c) application filed on 21618

FERC Environmental Assessment issued 103018

Pipeline amp Storage

Fully Subscribed Project will Provide 205000 Dthday of Incremental Firm Transportation

41

National Fuel Remains Committed to Northern Access Project

Target In-Service as early as fiscal 2022

Total Cost ~$500MM (~$76MM spent to date)

Estimated Annual Revenues ~$84 million

Delivery Points

350000 Dthd to Chippawa (TCPL interconnect)

140000 Dthd to Hopewell (TGP 200 line)

Regulatory Status

February 3 2017 ndash FERC 7(c) certificate issued

August 6 2018 ndash FERC issued Order finding that NY DEC waived water quality certification

Supply and Empire currently working to finalize remaining federal authorizations

Pipeline amp Storage

To Dawn

42

Continued Expansion of the NFG Supply System

Line N Expansion Opportunities

Line N to Monaca Project Project Firm transportation service to a new ethane

cracker facility being built by Shell Chemical Appalachia LLC

Target In-Service July 2019

Estimated Capital Cost $23 million

Contracted Capacity 133000 Dthday

Additional Line N Expansion Opportunity (Supply OS 221) Project New firm transportation service for on-system

demand

Open Season Capacity Awarded 165000 to foundation shipper Precedent agreement in negotiations

Pipeline amp Storage

43

Pipeline amp Storage Customer Mix

Producer33

LDC42

Marketer10

Outside Pipeline

9

End User6

42 MMDthd

(1) Contracted as of 10312018

Customer Transportation by Shipper Type(1) Affiliated Customer Mix (Contracted Capacity)

66

521

41

34

9579

59

LDCs Producers Marketers FirmStorage

Affiliated Non-Affiliated

Firm Transport

Pipeline amp Storage

44

Utility OverviewNational Fuel Gas Distribution Corporation

45

New York amp Pennsylvania Service Territories

New York

Total Customers(1) 535800ROE 87 (NY PSC Rate Case Order April 2017)Rate Mechanismso Revenue Decouplingo Weather Normalizationo Low Income Rateso Merchant Function Charge (Uncollectibles Adj)o 9010 Sharing (Large Customers)o System Modernization Tracker

Pennsylvania

Total Customers(1) 214400ROE Black Box Settlement (2007)Rate Mechanismso Low Income Rateso Merchant Function Charge

(1) As of September 30 2018

Utility

46

New York Rate Case Outcome

Rate Order Summary

Revenue Requirement $59 million

Rate Base $704 million

Allowed Return on Equity (ROE) 87

Capital Structure 429 equity

Other notable items

New rates became effective 5117

Retains rate mechanisms in place under prior order (revenue decoupling weather normalization merchant function charge 9010 large customer sharing)

No stay-out clause

System modernization tracker for Leak Prone Pipe (LPP)

Earnings sharing started 4118 (5050 sharing starts at earnings in excess of 92)

Article 78 appeal filed on 72817 with oral argument completed in January 2019

On April 20 2017 the New York Public Service Commission issued a Rate Order relating to NFG Distributionrsquos rate case (No 16-G-0257) filed in April 2016

Utility

47

Utility Continues its Significant Investments in Safety

$544$618 $636

$699

$944$980

$809$856

$90-100

$00

$250

$500

$750

$1000

$1250

2015 2016 2017 2018 2019E

Cap

ital E

xpen

ditu

res

($ m

illio

ns)

Fiscal Year

Capital Expenditures for Safety Total Capital Expenditures

Modernization Spending in NY Expected to Grow Gross Margin By $2 MM - $5 MM in FY 2019

(1)

(1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation

Utility

System modernization tracker in NY allows recovery of pipeline replacementcosts which is expected to drive modest gross margin and rate base growth

48

Accelerating Pipeline Replacement amp Modernization

Wrought Iron

Plastic

CoatedBare

120130

146 144159

2014 2015 2016 2017 2018Calendar Year

NY9726 miles

PA4830 miles

No Cast Iron Mains in Pa

Miles of Utility Main Pipeline ReplacedUtility Mains by Material(1)

Wrought Iron

Cast Iron

Plastic

Coated Bare

Utility

(1) All values are reported on a calendar year basis as of December 31 2018

49

A Proven History of Controlling Costs

$200 $189 $195

$166 $166

$31 $31

$197 $197

$0

$50

$100

$150

$200

$250

2015 2016 2017 2018 TTM 123118

Fiscal Year

OampM Expense Non-Service Pension Costs

OampM Expense ($ millions)

Utility

(1)

(1) For purposes of comparability to FY 2015 2016 and 2017 Utility Operation and Maintenance Expense for FY 2018 and the twelve months ended December 31 2018 was adjusted by approximately $314 million and $312 million respectively to include non-service pension costs which were re-classified as Other Income (Deductions) as of October 1 2018 on the Companyrsquos Income Statement See Slide 64 for non-GAAP reconciliation of Adjusted Operation and Maintenance Expense to Operation and Maintenance Expense by segment

50

Consolidated Financial OverviewUpstream I Midstream I Downstream

51

Adjusted Operating Results ($ per share)(1)

Diversified Balanced Earnings and Cash Flows

(1) A reconciliation of Adjusted Operating Results to Earnings per Share by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation(2) Consolidated Adjusted EBITDA includes Energy Marketing and Corporate amp All Other Segments A reconciliation of Adjusted EBITDA to Net Income by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in

the Business is included at the end of this presentation

Adjusted EBITDA ($ millions)(2)

$176 $179

$184 $181

$92 $97

$318 $327

$761 $775

$-

$200

$400

$600

$800

FY 2018 TTM 123118

$059 Utility

$097 Pipeline amp Storage

$057 Gathering

$125 Exploration

amp Production

$334 $345 to $365

$-

$100

$200

$300

$400

FY 2018 FY 2019 Guidance

Rate Regulated

40-45

$728

Rate Regulated

~46

52

$89 $94 $98 $81 $86 $90-$100

$140$230

$114 $95 $93 $120-$150

$138$118

$54$33 $48

$55-$65

$603$557

$99 $246$356

$460-$495

$970 $1001

$366$455

$583

$725-$810

$0

$250

$500

$750

$1000

$1250

2014 2015 2016 2017 2018 2019GuidanceFiscal Year

Exploration amp Production

Gathering

Pipeline amp Storage

Utility

Disciplined Flexible Capital Allocation

(2)

(1) Total Capital Expenditures include Energy Marketing Corporate and All Other A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation (2) FY16 FY17 and FY18 reflects the netting of $157 million $7 million and $17 million respectively of up-front proceeds received from joint development partner for working interest in joint development wells and $21M in intercompany asset transfers in FY18

Capital Expenditures by Segment ($ millions)(1)

53

Maintaining Strong Balance Sheet amp Liquidity

Total Equity49

Total Debt51

$42 Billion Total Capitalizationas of December 31 2018

218 x251 x 245 x 247 x 256 x

2015 2016 2017 2018 TTM 123118Fiscal Year End

Net Debt Adjusted EBITDA(1) Capitalization

Debt Maturity Profile ($MM) Liquidity

Committed Credit FacilitiesShort-term Debt OutstandingAvailable Short-term Credit FacilitiesCash Balance at 123118 Total Liquidity at 123118

$ 750 MM0 MM

750 MM110 MM

$ 860 MM

$500 $549 $500

$300 $300

$0

$200

$400

$600

(1) Net Debt is net of cash and temporary cash investments Reconciliations of Net Debt and Adjusted EBITDA to Net Income are included at the end of this presentation

54

Appendix

55

Safe Harbor For Forward Looking StatementsThis presentation may contain ldquoforward-looking statementsrdquo as defined by the Private Securities Litigation Reform Act of 1995 including statements regarding future prospectsplans objectives goals projections estimates of oil and gas quantities strategies future events or performance and underlying assumptions capital structure anticipatedcapital expenditures completion of construction projects projections for pension and other post-retirement benefit obligations impacts of the adoption of new accounting rulesand possible outcomes of litigation or regulatory proceedings as well as statements that are identified by the use of the words ldquoanticipatesrdquo ldquoestimatesrdquo ldquoexpectsrdquo ldquoforecastsrdquoldquointendsrdquo ldquoplansrdquo ldquopredictsrdquo ldquoprojectsrdquo ldquobelievesrdquo ldquoseeksrdquo ldquowillrdquo ldquomayrdquo and similar expressions Forward-looking statements involve risks and uncertainties which couldcause actual results or outcomes to differ materially from those expressed in the forward-looking statements The Companyrsquos expectations beliefs and projections are expressedin good faith and are believed by the Company to have a reasonable basis but there can be no assurance that managementrsquos expectations beliefs or projections will result or beachieved or accomplished

In addition to other factors the following are important factors that could cause actual results to differ materially from those discussed in the forward-looking statements delaysor changes in costs or plans with respect to Company projects or related projects of other companies including difficulties or delays in obtaining necessary governmentalapprovals permits or orders or in obtaining the cooperation of interconnecting facility operators governmentalregulatory actions initiatives and proceedings including thoseinvolving rate cases (which address among other things target rates of return rate design and retained natural gas) environmentalsafety requirements affiliate relationshipsindustry structure and franchise renewal changes in laws regulations or judicial interpretations to which the Company is subject including those involving derivatives taxessafety employment climate change other environmental matters real property and exploration and production activities such as hydraulic fracturing financial and economicconditions including the availability of credit and occurrences affecting the Companyrsquos ability to obtain financing on acceptable terms for working capital capital expendituresand other investments including any downgrades in the Companyrsquos credit ratings and changes in interest rates and other capital market conditions changes in the price ofnatural gas or oil impairments under the SECrsquos full cost ceiling test for natural gas and oil reserves factors affecting the Companyrsquos ability to successfully identify drill for andproduce economically viable natural gas and oil reserves including among others geology lease availability title disputes weather conditions shortages delays orunavailability of equipment and services required in drilling operations insufficient gathering processing and transportation capacity the need to obtain governmentalapprovals and permits and compliance with environmental laws and regulations increasing health care costs and the resulting effect on health insurance premiums and on theobligation to provide other post-retirement benefits changes in price differentials between similar quantities of natural gas or oil sold at different geographic locations and theeffect of such changes on commodity production revenues and demand for pipeline transportation capacity to or from such locations other changes in price differentialsbetween similar quantities of natural gas or oil having different quality heating value hydrocarbon mix or delivery date the cost and effects of legal and administrative claimsagainst the Company or activist shareholder campaigns to effect changes at the Company uncertainty of oil and gas reserve estimates significant differences between theCompanyrsquos projected and actual production levels for natural gas or oil changes in demographic patterns and weather conditions changes in the availability price oraccounting treatment of derivative financial instruments changes in laws actuarial assumptions the interest rate environment and the return on plantrust assets related to theCompanyrsquos pension and other post-retirement benefits which can affect future funding obligations and costs and plan liabilities changes in economic conditions includingglobal national or regional recessions and their effect on the demand for and customersrsquo ability to pay for the Companyrsquos products and services the creditworthiness orperformance of the Companyrsquos key suppliers customers and counterparties the impact of potential information technology cybersecurity or data security breaches economicdisruptions or uninsured losses resulting from major accidents fires severe weather natural disasters terrorist activities or acts of war significant differences between theCompanyrsquos projected and actual capital expenditures and operating expenses or increasing costs of insurance changes in coverage and the ability to obtain insurance

Forward-looking statements include estimates of oil and gas quantities Proved oil and gas reserves are those quantities of oil and gas which by analysis of geoscience andengineering data can be estimated with reasonable certainty to be economically producible under existing economic conditions operating methods and governmentregulations Other estimates of oil and gas quantities including estimates of probable reserves possible reserves and resource potential are by their nature more speculativethan estimates of proved reserves Accordingly estimates other than proved reserves are subject to substantially greater risk of being actually realized Investors are urged toconsider closely the disclosure in our Form 10-K available at wwwnationalfuelgascom You can also obtain this form on the SECrsquos website at wwwsecgov

For a discussion of the risks set forth above and other factors that could cause actual results to differ materially from results referred to in the forward-looking statements seeldquoRisk Factorsrdquo in the Companyrsquos Form 10-K for the fiscal year ended September 30 2018 and the Forms 10-Q for the quarter ended March 31 2018 June 30 2018 and December31 2018 The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date thereof or to reflect the occurrence ofunanticipated events

Appendix

24

EDA Marcellus Lycoming County Development

Marcellus Development in Lycoming County has Resumed in Connection with Atlantic Sunrise

(1) Includes physical fixed price and NYMEX-based firm sales contracts that do not carry any additional transportation costs

EampP and Gathering

Prolific Marcellus acreage with peer leading well results

~45 remaining Marcellus locations economic at ~$153 Mcf

Near-term development focused on filling Atlantic Sunrise capacity

Existing Line

Leased

Seneca Fee

Producing

FY19 Producer

Development

0

50

100

150

200

250

Gro

ss F

irm V

olum

es (M

Dth

d)

EDA ndash Transco Firm Contracts

Atlantic Sunrise (Transco)FT Capacity 189405 Dthd

Cost $073DthFirm Sales NYMEX+

Transco Firm Sales(1)

25

EDA Utica Tioga County Development

Utica Development in Tioga County ndash Tract 007 Development Resumed in Q3 Fiscal 2018

In-Service November 2016

Lateral Length 4640 ft

30 Day IP 1000 ft 34 MMcfd

Est EUR 1000 ft 24 Bcf

Inventory ~43 locations economic at ~$184 Mcf

Targeting to grow production by 100 to 150 MDthd by fiscal 2020

Expected Development Costs $1045 per lateral ft

Gathering Infrastructure NFG Midstream Wellsboro

Modest build-out required to connect to TGP 300

SalesTakeaway Strategy Layer-in firm sales with shippers holding capacity on TGP 300

(1) Includes physical fixed price and NYMEX-based firm sales contracts that do not carry any additional transportation costs

Tract 007 Utica Appraisal Well Results vs Industry

EampP and Gathering

0

100000

200000

300000

400000

500000

600000

700000

800000

0 100 200 300

Nor

mal

ized

Cum

ulat

ive

(Mcf

10

00rsquo)

Days On ProductionIndustry PotterTioga Wells Seneca DCNR 007 73H

0

25

50

75

100

125

150

Gro

ss F

irm V

olum

es (M

Dth

d)

EDA ndash TGP 300 Firm Contracts

Northeast Supply Diversification ProjectFT Capacity 50000 Dthd $050Dth

Firm Sales NYMEX and DAWN

EDA - TGP 300Firm Sales(1)

26

Integrated Development ndash EDA Gathering Systems

Total Investment (to date) ~$46 million FY 2019 Estimated Capital Expenditures $1 MM - $2 MM Capacity 220000 Dth per day (Interconnect w TGP 300) Production Source Seneca Resources ndash Tioga Co (Covington and DCNR Tract 595)

Total Investment (to date) ~$208 million FY 2019 Estimated Capital Expenditures $25 MM - $35 MM Capacity 466000 to 585000 Dth per day (Interconnect w Transco) Production Source Seneca Resources ndash Lycoming Co (DCNR Tract 100 and Gamble) Future third-party volume opportunities

Covington Gathering System

Trout Run Gathering System

Gathering Segment Supporting Senecarsquos EDA Production amp Future Development

Wellsboro Gathering System Total Investment (to date) ~$14 million FY 2019 Estimated Capital Expenditures $8 MM - $15 MM Capacity up to 200000 Dth per day (Interconnect w TGP 300) Production Source Seneca Resources ndash Tioga Co (DCNR Tract 007)

EampP and Gathering

2

1

3

27

Long-term Contracts Supporting Appalachian Growth

(1) Represents base firm sales contracts not tied to firm transportation capacity Base firm sales are either fixed priced or priced at an index (eg NYMEX ) +- a fixed basis and do not carry any transportation costs

Seneca continues to layer-in firm sales contracts with attractive realizations to lock-in drilling economics and minimize spot exposure ahead of firm transportation in-service dates

EampP and Gathering

-

100

200

300

400

500

600

700

800

900

1000

1100

1200

FY 2019 FY 2020 FY 2021 FY 2022Northeast Supply Diversification 50000 Dthd

Niagara Expansion (TGP amp NFG)Delivery Markets Canada-Dawn amp TETCO

158000 Dthd

Atlantic Sunrise (Transco)Delivery Markets Mid-Atlantic amp Southeast US

189405 Dthd

In-BasinFirm Sales

Contracts(1)

Leidy South (Transco amp NFG)

Transco Zone 6 Markets330000 Dthd

Seneca Appalachia Natural Gas MarketingGross Firm Contract Volumes (Mdthday)

28

297000 ($061)

305200 ($061)

305600 ($063)

337000 ($057)

370800 ($024)

369600 ($060)

367900 ($067)

33400 ($070)74500 ($077) 74900 ($077)

81100 ($078)

85900 ($078)

92000 ($073)

91300 ($073)

178800 $255

196000 $234

195500 $234

149900 $232

129500 $230

105400 $222

104500 $222

~517800 509200 575700 576000 568000 586200 567000 563700

Q1 FY19 Q2 FY19 Q3 FY19 Q4 FY19 Q1 FY20 Q2 FY20 Q3 FY20 Q4 FY20

Fixed Price Dawn NYMEX

Near-term Firm Sales Provide Market amp Price Certainty

Net Contracted Firm Sales Volumes (Dth per day)Contracted Index Price Differentials ($ per Dth)(1)

(1) Values shown represent the weighted average fixed price or contracted fixed differential relative to NYMEX (netback price) less any associated transportation costs

Actual Daily Net

Production

641200 716500 708700 693500 708400 674400 667000Gross Firm Sales Volumes (Dthd)

EampP and Gathering

29

California Oil

Stable Oil Production | Minimal Capital Investment | Steady Free Cash Flow

1

2

3

4

5

Location Formation Production Method

FY18 Daily Production(net Boed)

1 East Coalinga Other Temblor Primary 512

2 North Lost Hills

Tulare amp Etchegoin

PrimarySteam flood 892

3 South Lost Hills

Monterey Shale Primary 1359

4 North Midway Sunset

Tulare amp Potter Steam flood 2786

5 South Midway Sunset Antelope Steam flood 2048

TOTAL WEST DIVISION NET PRODUCTION(1) 7597 Boed

EampP and Gathering

(1) West division net production for FY 2018 excludes production from Sespe field which was divested on May 1 2018

30

California Capital Expenditures vs Production

9341 8863

8033 ~7300

2016 2017 2018 2019

Fiscal Year

West Division Average Net Daily Production (Boe)West Division Annual Capital Expenditures ($ MM)(1)

$38 $38

$26 ~$25

2016 2017 2018 2019

Fiscal YearGuidance Guidance

(1) Seneca West Division capital expenditures includes Seneca corporate and eliminations

EampP and Gathering

Sepse Sale Closed on 5118(reduced production by ~900 boed)

31

Pioneer

South MWSS

Acreage

North MWSS

AcreageSec 17N

4149 51

NMWSS amp 17N SMWSS amp Pioneer East Coalinga

California Development Activities

Modest near-term capital program focused on locations that earn attractive returns in current oil price environment

AampD will focus on low cost bolt-on opportunities

Sec 17 Pioneer and East Coalinga development to provide future growth

North

Project IRRs at $55Bbl(1)

(1) Reflects pre-tax IRRs at a $55Bbl WTI

EampP and Gathering

Seneca West Economics

South

East Coalinga

North

South

32

Fiscal 2019 Production and Price Certainty

~49 Bcfe

210 ndash 230 Bcfe

~114 Bcf

~29 Bcf (2)

16+- Bcf~12 Bcfe

0

40

80

120

160

200

240

YTD FY19Actuals

Fixed Price + FirmSales w Hedge

Firm Sales(Unhedged)

Spot Sales California TotalSeneca

Prod

uctio

n (B

cfe)

(1) Average realized price reflects uplift from financial hedges less fixed differentials under firm sales contracts and any firm transportation costs(2) Indicates firm sales contracts with fixed index differentials but not backed by a matching financial hedge

114 Bcf locked-in realizing net ~$241Mcf (1)

29 Bcf of additional basis protection

Spot production assumed to be sold

at ~$275Mmbtu(winter) and ~$225

(summer)

143 Bcf of Appalachian Production Protected by Firm Sales for Remainder of Year

79 of oil production hedged at $5757 Bbl

EampP and Gathering

33

Strong Hedge Book

Natural Gas Swap amp Fixed Physical Sales Contracts (Millions MMBtu)

(1) Fixed price physical sales exclude joint development partnerrsquos share of fixed price contract WDA volumes as specified under the joint development agreement(2) Reflects percentage of projected production for FY19 hedged at the midpoint of the production guidance range(3) Senecarsquos remainder FY19 Production reflects the total FY19 production guidance of 210-230 Bcfe or 220 Bcfe at the midpoint less Q1 actual production

Crude Oil Swap Contracts (Thousands Bbls)

13591188

732

456

0

500

1000

1500

2000

2500

FY 2019 FY 2020 FY 2021 FY 2022

NYMEX (WTI)

Brent

FY 19 Crude Oil79 Hedged (2)

FY 2019 Remaining Production (3)

EampP and Gathering

1174

709

469 406

0

50

100

150

200

250

FY 2019 FY 2020 FY 2021 FY 2022

NYMEX Swaps

Dawn Swaps

Fixed Price Physical Sales

(1)

FY 2019 Remaining Production (3)

FY 19 Nat Gas71 Hedged (2)

34

$065 $070$070 -$075

FY 2017 FY 2018 FY 2019E

$060 $060 $060

$011 $009 $007$071 $069 ~$067

FY 2017 FY 2018 FY 2019E Gathering amp Transport LOE (non-Gathering) GampA Taxes amp Other

Seneca Operating Costs

Competitive low cost structure in Appalachia and California supports strong cash margins

Gathering fee generates significant revenue stream for affiliated gathering company

Seneca DDampARate

$Mcfe

$054 $054 $056

$042 $038 $031

$034 $034 $030

$017 $014 $015

$147 $140 ~$132

FY 2017 FY 2018 FY 2019E

(1)

$1791$1746~$2050

FY 2017 FY 2018 FY 2019E

Appalachia LOE amp Gathering $Mcfe

California LOE$Boe

Total Seneca Cash OpEx$Mcfe

(1)

(2)

(2)

(1) GampA estimate represents the midpoint of the GampA guidance range of $025 to $035 for fiscal 2019(2) The total of the two LOE components represents the midpoint of the LOE guidance range of $085 to $090 for fiscal 2019

EampP and Gathering

35

Senecarsquos Continuing Commitment to the Environment

Produced Water Recycled in Appalachia

100 70Recycled Water

Used in New Shale Well

Completions

Water and Fluids Management Air Quality and Emissions

Seneca Resources Water OperationsFiscal 2018

Seneca Resources Remains Focused on Minimizing GHG Emissions

The Environmental Partnership

EPA Natural Gas Star Program

Green Completions (all fiscal 2018 wells)

Ultrasonic Leak Detection Technology

Emissions Controls

Rig and Vehicle Fuel Conversion

Integrating Renewable Energy into Operations

EampP and Gathering

36

Pipeline and Storage OverviewNational Fuel Gas Supply Corporation ~ Empire Pipeline Inc

37

Pipeline amp Storage Segment Overview

(1) As of September 30 2018 as disclosed in the Companyrsquos fiscal 2018 form 10-K(2) As of December 31 2017 calculated from National Fuel Gas Supply Corporationrsquos and Empire Pipeline Incrsquos 2017 FERC Form-2 reports respectively

Empire Pipeline Inc

National Fuel Gas Supply Corporation

Empire Pipeline

Supply Corp

Contracted Capacity(1) Firm Transportation 3187 MDth per day Firm Storage 71938 Mdth (fully subscribed)

Rate Base(2) ~$820 million FERC Rate Proceeding Status

Rate case settlement extension approved Nov lsquo15 Rate case filing expected by 73119

Contracted Capacity(1) Firm Transportation 978 MDth per day Firm Storage 3753 Mdth (fully subscribed)

Rate Base(2) ~$249 million FERC Rate Proceeding Status

Rate case settlement in principle reached on 122118 FERC approval pending

New transportation rates went into on 1119

Pipeline amp Storage

38

All Seneca volumes will flow through wholly-owned NFG gathering facilities

FM100 Project - Consolidated Benefit for NFG

330000 Dthd of new transportation capacity from WDA and EDA acreage positions to premium markets

New Transco capacity (Leidy South) 330000 Dthday

Rate(1) competitive with other expansion project rates in Senecarsquos current transportation portfolio

Delivery Point(s) Transco Zone 6 interconnections

Seneca

Lease to Transco of new capacity 330000 Dthday

Estimated annual lease revenues ~$35 million

Target In-Service late calendar year 2021

Supply Corp

Project expected to provide long-term earnings uplift to Seneca Supply Corp and Gathering

Pipeline amp Storage

Gathering

(1) Includes lease of new capacity from Supply Corp to Transco

39

FM100 Project ndash Significant Investment by Supply Corp

Pipeline amp Storage

Estimated Capital Cost $280 million(1)

Facilities (all in Pennsylvania) include Approximately 30 miles of new pipeline 2 new compressor stations (totaling

approximately 37000 HP) New interconnection station and modification

of existing interconnection station Abandonment of approximately 45 miles of

existing pipeline and compressor station Regulatory Process

Pre-filing application submitted to FERC in 2017 for original modernization project

FERC 7(b) 7(c) filing expected summer 2019

(1) Includes expansion and modernization portions of the project

40

Empire North Project

Target In-Service second half of fiscal 2020

Est Capital Cost $145 million

Est Annual Revenues ~$25 million

Receipt Point Jackson (Tioga Co Pa production)

Design Capacity and Delivery Points 175000 Dthd to Chippawa (TCPL interconnect)

30000 Dthd to Hopewell (TGP 200 interconnect)

Customers Fully subscribed (205000 Dthday)

Major Facilities 2 new compressor stations in NY (1) amp Pa (1)

No new pipeline construction

Regulatory Process FERC 7(c) application filed on 21618

FERC Environmental Assessment issued 103018

Pipeline amp Storage

Fully Subscribed Project will Provide 205000 Dthday of Incremental Firm Transportation

41

National Fuel Remains Committed to Northern Access Project

Target In-Service as early as fiscal 2022

Total Cost ~$500MM (~$76MM spent to date)

Estimated Annual Revenues ~$84 million

Delivery Points

350000 Dthd to Chippawa (TCPL interconnect)

140000 Dthd to Hopewell (TGP 200 line)

Regulatory Status

February 3 2017 ndash FERC 7(c) certificate issued

August 6 2018 ndash FERC issued Order finding that NY DEC waived water quality certification

Supply and Empire currently working to finalize remaining federal authorizations

Pipeline amp Storage

To Dawn

42

Continued Expansion of the NFG Supply System

Line N Expansion Opportunities

Line N to Monaca Project Project Firm transportation service to a new ethane

cracker facility being built by Shell Chemical Appalachia LLC

Target In-Service July 2019

Estimated Capital Cost $23 million

Contracted Capacity 133000 Dthday

Additional Line N Expansion Opportunity (Supply OS 221) Project New firm transportation service for on-system

demand

Open Season Capacity Awarded 165000 to foundation shipper Precedent agreement in negotiations

Pipeline amp Storage

43

Pipeline amp Storage Customer Mix

Producer33

LDC42

Marketer10

Outside Pipeline

9

End User6

42 MMDthd

(1) Contracted as of 10312018

Customer Transportation by Shipper Type(1) Affiliated Customer Mix (Contracted Capacity)

66

521

41

34

9579

59

LDCs Producers Marketers FirmStorage

Affiliated Non-Affiliated

Firm Transport

Pipeline amp Storage

44

Utility OverviewNational Fuel Gas Distribution Corporation

45

New York amp Pennsylvania Service Territories

New York

Total Customers(1) 535800ROE 87 (NY PSC Rate Case Order April 2017)Rate Mechanismso Revenue Decouplingo Weather Normalizationo Low Income Rateso Merchant Function Charge (Uncollectibles Adj)o 9010 Sharing (Large Customers)o System Modernization Tracker

Pennsylvania

Total Customers(1) 214400ROE Black Box Settlement (2007)Rate Mechanismso Low Income Rateso Merchant Function Charge

(1) As of September 30 2018

Utility

46

New York Rate Case Outcome

Rate Order Summary

Revenue Requirement $59 million

Rate Base $704 million

Allowed Return on Equity (ROE) 87

Capital Structure 429 equity

Other notable items

New rates became effective 5117

Retains rate mechanisms in place under prior order (revenue decoupling weather normalization merchant function charge 9010 large customer sharing)

No stay-out clause

System modernization tracker for Leak Prone Pipe (LPP)

Earnings sharing started 4118 (5050 sharing starts at earnings in excess of 92)

Article 78 appeal filed on 72817 with oral argument completed in January 2019

On April 20 2017 the New York Public Service Commission issued a Rate Order relating to NFG Distributionrsquos rate case (No 16-G-0257) filed in April 2016

Utility

47

Utility Continues its Significant Investments in Safety

$544$618 $636

$699

$944$980

$809$856

$90-100

$00

$250

$500

$750

$1000

$1250

2015 2016 2017 2018 2019E

Cap

ital E

xpen

ditu

res

($ m

illio

ns)

Fiscal Year

Capital Expenditures for Safety Total Capital Expenditures

Modernization Spending in NY Expected to Grow Gross Margin By $2 MM - $5 MM in FY 2019

(1)

(1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation

Utility

System modernization tracker in NY allows recovery of pipeline replacementcosts which is expected to drive modest gross margin and rate base growth

48

Accelerating Pipeline Replacement amp Modernization

Wrought Iron

Plastic

CoatedBare

120130

146 144159

2014 2015 2016 2017 2018Calendar Year

NY9726 miles

PA4830 miles

No Cast Iron Mains in Pa

Miles of Utility Main Pipeline ReplacedUtility Mains by Material(1)

Wrought Iron

Cast Iron

Plastic

Coated Bare

Utility

(1) All values are reported on a calendar year basis as of December 31 2018

49

A Proven History of Controlling Costs

$200 $189 $195

$166 $166

$31 $31

$197 $197

$0

$50

$100

$150

$200

$250

2015 2016 2017 2018 TTM 123118

Fiscal Year

OampM Expense Non-Service Pension Costs

OampM Expense ($ millions)

Utility

(1)

(1) For purposes of comparability to FY 2015 2016 and 2017 Utility Operation and Maintenance Expense for FY 2018 and the twelve months ended December 31 2018 was adjusted by approximately $314 million and $312 million respectively to include non-service pension costs which were re-classified as Other Income (Deductions) as of October 1 2018 on the Companyrsquos Income Statement See Slide 64 for non-GAAP reconciliation of Adjusted Operation and Maintenance Expense to Operation and Maintenance Expense by segment

50

Consolidated Financial OverviewUpstream I Midstream I Downstream

51

Adjusted Operating Results ($ per share)(1)

Diversified Balanced Earnings and Cash Flows

(1) A reconciliation of Adjusted Operating Results to Earnings per Share by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation(2) Consolidated Adjusted EBITDA includes Energy Marketing and Corporate amp All Other Segments A reconciliation of Adjusted EBITDA to Net Income by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in

the Business is included at the end of this presentation

Adjusted EBITDA ($ millions)(2)

$176 $179

$184 $181

$92 $97

$318 $327

$761 $775

$-

$200

$400

$600

$800

FY 2018 TTM 123118

$059 Utility

$097 Pipeline amp Storage

$057 Gathering

$125 Exploration

amp Production

$334 $345 to $365

$-

$100

$200

$300

$400

FY 2018 FY 2019 Guidance

Rate Regulated

40-45

$728

Rate Regulated

~46

52

$89 $94 $98 $81 $86 $90-$100

$140$230

$114 $95 $93 $120-$150

$138$118

$54$33 $48

$55-$65

$603$557

$99 $246$356

$460-$495

$970 $1001

$366$455

$583

$725-$810

$0

$250

$500

$750

$1000

$1250

2014 2015 2016 2017 2018 2019GuidanceFiscal Year

Exploration amp Production

Gathering

Pipeline amp Storage

Utility

Disciplined Flexible Capital Allocation

(2)

(1) Total Capital Expenditures include Energy Marketing Corporate and All Other A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation (2) FY16 FY17 and FY18 reflects the netting of $157 million $7 million and $17 million respectively of up-front proceeds received from joint development partner for working interest in joint development wells and $21M in intercompany asset transfers in FY18

Capital Expenditures by Segment ($ millions)(1)

53

Maintaining Strong Balance Sheet amp Liquidity

Total Equity49

Total Debt51

$42 Billion Total Capitalizationas of December 31 2018

218 x251 x 245 x 247 x 256 x

2015 2016 2017 2018 TTM 123118Fiscal Year End

Net Debt Adjusted EBITDA(1) Capitalization

Debt Maturity Profile ($MM) Liquidity

Committed Credit FacilitiesShort-term Debt OutstandingAvailable Short-term Credit FacilitiesCash Balance at 123118 Total Liquidity at 123118

$ 750 MM0 MM

750 MM110 MM

$ 860 MM

$500 $549 $500

$300 $300

$0

$200

$400

$600

(1) Net Debt is net of cash and temporary cash investments Reconciliations of Net Debt and Adjusted EBITDA to Net Income are included at the end of this presentation

54

Appendix

55

Safe Harbor For Forward Looking StatementsThis presentation may contain ldquoforward-looking statementsrdquo as defined by the Private Securities Litigation Reform Act of 1995 including statements regarding future prospectsplans objectives goals projections estimates of oil and gas quantities strategies future events or performance and underlying assumptions capital structure anticipatedcapital expenditures completion of construction projects projections for pension and other post-retirement benefit obligations impacts of the adoption of new accounting rulesand possible outcomes of litigation or regulatory proceedings as well as statements that are identified by the use of the words ldquoanticipatesrdquo ldquoestimatesrdquo ldquoexpectsrdquo ldquoforecastsrdquoldquointendsrdquo ldquoplansrdquo ldquopredictsrdquo ldquoprojectsrdquo ldquobelievesrdquo ldquoseeksrdquo ldquowillrdquo ldquomayrdquo and similar expressions Forward-looking statements involve risks and uncertainties which couldcause actual results or outcomes to differ materially from those expressed in the forward-looking statements The Companyrsquos expectations beliefs and projections are expressedin good faith and are believed by the Company to have a reasonable basis but there can be no assurance that managementrsquos expectations beliefs or projections will result or beachieved or accomplished

In addition to other factors the following are important factors that could cause actual results to differ materially from those discussed in the forward-looking statements delaysor changes in costs or plans with respect to Company projects or related projects of other companies including difficulties or delays in obtaining necessary governmentalapprovals permits or orders or in obtaining the cooperation of interconnecting facility operators governmentalregulatory actions initiatives and proceedings including thoseinvolving rate cases (which address among other things target rates of return rate design and retained natural gas) environmentalsafety requirements affiliate relationshipsindustry structure and franchise renewal changes in laws regulations or judicial interpretations to which the Company is subject including those involving derivatives taxessafety employment climate change other environmental matters real property and exploration and production activities such as hydraulic fracturing financial and economicconditions including the availability of credit and occurrences affecting the Companyrsquos ability to obtain financing on acceptable terms for working capital capital expendituresand other investments including any downgrades in the Companyrsquos credit ratings and changes in interest rates and other capital market conditions changes in the price ofnatural gas or oil impairments under the SECrsquos full cost ceiling test for natural gas and oil reserves factors affecting the Companyrsquos ability to successfully identify drill for andproduce economically viable natural gas and oil reserves including among others geology lease availability title disputes weather conditions shortages delays orunavailability of equipment and services required in drilling operations insufficient gathering processing and transportation capacity the need to obtain governmentalapprovals and permits and compliance with environmental laws and regulations increasing health care costs and the resulting effect on health insurance premiums and on theobligation to provide other post-retirement benefits changes in price differentials between similar quantities of natural gas or oil sold at different geographic locations and theeffect of such changes on commodity production revenues and demand for pipeline transportation capacity to or from such locations other changes in price differentialsbetween similar quantities of natural gas or oil having different quality heating value hydrocarbon mix or delivery date the cost and effects of legal and administrative claimsagainst the Company or activist shareholder campaigns to effect changes at the Company uncertainty of oil and gas reserve estimates significant differences between theCompanyrsquos projected and actual production levels for natural gas or oil changes in demographic patterns and weather conditions changes in the availability price oraccounting treatment of derivative financial instruments changes in laws actuarial assumptions the interest rate environment and the return on plantrust assets related to theCompanyrsquos pension and other post-retirement benefits which can affect future funding obligations and costs and plan liabilities changes in economic conditions includingglobal national or regional recessions and their effect on the demand for and customersrsquo ability to pay for the Companyrsquos products and services the creditworthiness orperformance of the Companyrsquos key suppliers customers and counterparties the impact of potential information technology cybersecurity or data security breaches economicdisruptions or uninsured losses resulting from major accidents fires severe weather natural disasters terrorist activities or acts of war significant differences between theCompanyrsquos projected and actual capital expenditures and operating expenses or increasing costs of insurance changes in coverage and the ability to obtain insurance

Forward-looking statements include estimates of oil and gas quantities Proved oil and gas reserves are those quantities of oil and gas which by analysis of geoscience andengineering data can be estimated with reasonable certainty to be economically producible under existing economic conditions operating methods and governmentregulations Other estimates of oil and gas quantities including estimates of probable reserves possible reserves and resource potential are by their nature more speculativethan estimates of proved reserves Accordingly estimates other than proved reserves are subject to substantially greater risk of being actually realized Investors are urged toconsider closely the disclosure in our Form 10-K available at wwwnationalfuelgascom You can also obtain this form on the SECrsquos website at wwwsecgov

For a discussion of the risks set forth above and other factors that could cause actual results to differ materially from results referred to in the forward-looking statements seeldquoRisk Factorsrdquo in the Companyrsquos Form 10-K for the fiscal year ended September 30 2018 and the Forms 10-Q for the quarter ended March 31 2018 June 30 2018 and December31 2018 The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date thereof or to reflect the occurrence ofunanticipated events

Appendix

25

EDA Utica Tioga County Development

Utica Development in Tioga County ndash Tract 007 Development Resumed in Q3 Fiscal 2018

In-Service November 2016

Lateral Length 4640 ft

30 Day IP 1000 ft 34 MMcfd

Est EUR 1000 ft 24 Bcf

Inventory ~43 locations economic at ~$184 Mcf

Targeting to grow production by 100 to 150 MDthd by fiscal 2020

Expected Development Costs $1045 per lateral ft

Gathering Infrastructure NFG Midstream Wellsboro

Modest build-out required to connect to TGP 300

SalesTakeaway Strategy Layer-in firm sales with shippers holding capacity on TGP 300

(1) Includes physical fixed price and NYMEX-based firm sales contracts that do not carry any additional transportation costs

Tract 007 Utica Appraisal Well Results vs Industry

EampP and Gathering

0

100000

200000

300000

400000

500000

600000

700000

800000

0 100 200 300

Nor

mal

ized

Cum

ulat

ive

(Mcf

10

00rsquo)

Days On ProductionIndustry PotterTioga Wells Seneca DCNR 007 73H

0

25

50

75

100

125

150

Gro

ss F

irm V

olum

es (M

Dth

d)

EDA ndash TGP 300 Firm Contracts

Northeast Supply Diversification ProjectFT Capacity 50000 Dthd $050Dth

Firm Sales NYMEX and DAWN

EDA - TGP 300Firm Sales(1)

26

Integrated Development ndash EDA Gathering Systems

Total Investment (to date) ~$46 million FY 2019 Estimated Capital Expenditures $1 MM - $2 MM Capacity 220000 Dth per day (Interconnect w TGP 300) Production Source Seneca Resources ndash Tioga Co (Covington and DCNR Tract 595)

Total Investment (to date) ~$208 million FY 2019 Estimated Capital Expenditures $25 MM - $35 MM Capacity 466000 to 585000 Dth per day (Interconnect w Transco) Production Source Seneca Resources ndash Lycoming Co (DCNR Tract 100 and Gamble) Future third-party volume opportunities

Covington Gathering System

Trout Run Gathering System

Gathering Segment Supporting Senecarsquos EDA Production amp Future Development

Wellsboro Gathering System Total Investment (to date) ~$14 million FY 2019 Estimated Capital Expenditures $8 MM - $15 MM Capacity up to 200000 Dth per day (Interconnect w TGP 300) Production Source Seneca Resources ndash Tioga Co (DCNR Tract 007)

EampP and Gathering

2

1

3

27

Long-term Contracts Supporting Appalachian Growth

(1) Represents base firm sales contracts not tied to firm transportation capacity Base firm sales are either fixed priced or priced at an index (eg NYMEX ) +- a fixed basis and do not carry any transportation costs

Seneca continues to layer-in firm sales contracts with attractive realizations to lock-in drilling economics and minimize spot exposure ahead of firm transportation in-service dates

EampP and Gathering

-

100

200

300

400

500

600

700

800

900

1000

1100

1200

FY 2019 FY 2020 FY 2021 FY 2022Northeast Supply Diversification 50000 Dthd

Niagara Expansion (TGP amp NFG)Delivery Markets Canada-Dawn amp TETCO

158000 Dthd

Atlantic Sunrise (Transco)Delivery Markets Mid-Atlantic amp Southeast US

189405 Dthd

In-BasinFirm Sales

Contracts(1)

Leidy South (Transco amp NFG)

Transco Zone 6 Markets330000 Dthd

Seneca Appalachia Natural Gas MarketingGross Firm Contract Volumes (Mdthday)

28

297000 ($061)

305200 ($061)

305600 ($063)

337000 ($057)

370800 ($024)

369600 ($060)

367900 ($067)

33400 ($070)74500 ($077) 74900 ($077)

81100 ($078)

85900 ($078)

92000 ($073)

91300 ($073)

178800 $255

196000 $234

195500 $234

149900 $232

129500 $230

105400 $222

104500 $222

~517800 509200 575700 576000 568000 586200 567000 563700

Q1 FY19 Q2 FY19 Q3 FY19 Q4 FY19 Q1 FY20 Q2 FY20 Q3 FY20 Q4 FY20

Fixed Price Dawn NYMEX

Near-term Firm Sales Provide Market amp Price Certainty

Net Contracted Firm Sales Volumes (Dth per day)Contracted Index Price Differentials ($ per Dth)(1)

(1) Values shown represent the weighted average fixed price or contracted fixed differential relative to NYMEX (netback price) less any associated transportation costs

Actual Daily Net

Production

641200 716500 708700 693500 708400 674400 667000Gross Firm Sales Volumes (Dthd)

EampP and Gathering

29

California Oil

Stable Oil Production | Minimal Capital Investment | Steady Free Cash Flow

1

2

3

4

5

Location Formation Production Method

FY18 Daily Production(net Boed)

1 East Coalinga Other Temblor Primary 512

2 North Lost Hills

Tulare amp Etchegoin

PrimarySteam flood 892

3 South Lost Hills

Monterey Shale Primary 1359

4 North Midway Sunset

Tulare amp Potter Steam flood 2786

5 South Midway Sunset Antelope Steam flood 2048

TOTAL WEST DIVISION NET PRODUCTION(1) 7597 Boed

EampP and Gathering

(1) West division net production for FY 2018 excludes production from Sespe field which was divested on May 1 2018

30

California Capital Expenditures vs Production

9341 8863

8033 ~7300

2016 2017 2018 2019

Fiscal Year

West Division Average Net Daily Production (Boe)West Division Annual Capital Expenditures ($ MM)(1)

$38 $38

$26 ~$25

2016 2017 2018 2019

Fiscal YearGuidance Guidance

(1) Seneca West Division capital expenditures includes Seneca corporate and eliminations

EampP and Gathering

Sepse Sale Closed on 5118(reduced production by ~900 boed)

31

Pioneer

South MWSS

Acreage

North MWSS

AcreageSec 17N

4149 51

NMWSS amp 17N SMWSS amp Pioneer East Coalinga

California Development Activities

Modest near-term capital program focused on locations that earn attractive returns in current oil price environment

AampD will focus on low cost bolt-on opportunities

Sec 17 Pioneer and East Coalinga development to provide future growth

North

Project IRRs at $55Bbl(1)

(1) Reflects pre-tax IRRs at a $55Bbl WTI

EampP and Gathering

Seneca West Economics

South

East Coalinga

North

South

32

Fiscal 2019 Production and Price Certainty

~49 Bcfe

210 ndash 230 Bcfe

~114 Bcf

~29 Bcf (2)

16+- Bcf~12 Bcfe

0

40

80

120

160

200

240

YTD FY19Actuals

Fixed Price + FirmSales w Hedge

Firm Sales(Unhedged)

Spot Sales California TotalSeneca

Prod

uctio

n (B

cfe)

(1) Average realized price reflects uplift from financial hedges less fixed differentials under firm sales contracts and any firm transportation costs(2) Indicates firm sales contracts with fixed index differentials but not backed by a matching financial hedge

114 Bcf locked-in realizing net ~$241Mcf (1)

29 Bcf of additional basis protection

Spot production assumed to be sold

at ~$275Mmbtu(winter) and ~$225

(summer)

143 Bcf of Appalachian Production Protected by Firm Sales for Remainder of Year

79 of oil production hedged at $5757 Bbl

EampP and Gathering

33

Strong Hedge Book

Natural Gas Swap amp Fixed Physical Sales Contracts (Millions MMBtu)

(1) Fixed price physical sales exclude joint development partnerrsquos share of fixed price contract WDA volumes as specified under the joint development agreement(2) Reflects percentage of projected production for FY19 hedged at the midpoint of the production guidance range(3) Senecarsquos remainder FY19 Production reflects the total FY19 production guidance of 210-230 Bcfe or 220 Bcfe at the midpoint less Q1 actual production

Crude Oil Swap Contracts (Thousands Bbls)

13591188

732

456

0

500

1000

1500

2000

2500

FY 2019 FY 2020 FY 2021 FY 2022

NYMEX (WTI)

Brent

FY 19 Crude Oil79 Hedged (2)

FY 2019 Remaining Production (3)

EampP and Gathering

1174

709

469 406

0

50

100

150

200

250

FY 2019 FY 2020 FY 2021 FY 2022

NYMEX Swaps

Dawn Swaps

Fixed Price Physical Sales

(1)

FY 2019 Remaining Production (3)

FY 19 Nat Gas71 Hedged (2)

34

$065 $070$070 -$075

FY 2017 FY 2018 FY 2019E

$060 $060 $060

$011 $009 $007$071 $069 ~$067

FY 2017 FY 2018 FY 2019E Gathering amp Transport LOE (non-Gathering) GampA Taxes amp Other

Seneca Operating Costs

Competitive low cost structure in Appalachia and California supports strong cash margins

Gathering fee generates significant revenue stream for affiliated gathering company

Seneca DDampARate

$Mcfe

$054 $054 $056

$042 $038 $031

$034 $034 $030

$017 $014 $015

$147 $140 ~$132

FY 2017 FY 2018 FY 2019E

(1)

$1791$1746~$2050

FY 2017 FY 2018 FY 2019E

Appalachia LOE amp Gathering $Mcfe

California LOE$Boe

Total Seneca Cash OpEx$Mcfe

(1)

(2)

(2)

(1) GampA estimate represents the midpoint of the GampA guidance range of $025 to $035 for fiscal 2019(2) The total of the two LOE components represents the midpoint of the LOE guidance range of $085 to $090 for fiscal 2019

EampP and Gathering

35

Senecarsquos Continuing Commitment to the Environment

Produced Water Recycled in Appalachia

100 70Recycled Water

Used in New Shale Well

Completions

Water and Fluids Management Air Quality and Emissions

Seneca Resources Water OperationsFiscal 2018

Seneca Resources Remains Focused on Minimizing GHG Emissions

The Environmental Partnership

EPA Natural Gas Star Program

Green Completions (all fiscal 2018 wells)

Ultrasonic Leak Detection Technology

Emissions Controls

Rig and Vehicle Fuel Conversion

Integrating Renewable Energy into Operations

EampP and Gathering

36

Pipeline and Storage OverviewNational Fuel Gas Supply Corporation ~ Empire Pipeline Inc

37

Pipeline amp Storage Segment Overview

(1) As of September 30 2018 as disclosed in the Companyrsquos fiscal 2018 form 10-K(2) As of December 31 2017 calculated from National Fuel Gas Supply Corporationrsquos and Empire Pipeline Incrsquos 2017 FERC Form-2 reports respectively

Empire Pipeline Inc

National Fuel Gas Supply Corporation

Empire Pipeline

Supply Corp

Contracted Capacity(1) Firm Transportation 3187 MDth per day Firm Storage 71938 Mdth (fully subscribed)

Rate Base(2) ~$820 million FERC Rate Proceeding Status

Rate case settlement extension approved Nov lsquo15 Rate case filing expected by 73119

Contracted Capacity(1) Firm Transportation 978 MDth per day Firm Storage 3753 Mdth (fully subscribed)

Rate Base(2) ~$249 million FERC Rate Proceeding Status

Rate case settlement in principle reached on 122118 FERC approval pending

New transportation rates went into on 1119

Pipeline amp Storage

38

All Seneca volumes will flow through wholly-owned NFG gathering facilities

FM100 Project - Consolidated Benefit for NFG

330000 Dthd of new transportation capacity from WDA and EDA acreage positions to premium markets

New Transco capacity (Leidy South) 330000 Dthday

Rate(1) competitive with other expansion project rates in Senecarsquos current transportation portfolio

Delivery Point(s) Transco Zone 6 interconnections

Seneca

Lease to Transco of new capacity 330000 Dthday

Estimated annual lease revenues ~$35 million

Target In-Service late calendar year 2021

Supply Corp

Project expected to provide long-term earnings uplift to Seneca Supply Corp and Gathering

Pipeline amp Storage

Gathering

(1) Includes lease of new capacity from Supply Corp to Transco

39

FM100 Project ndash Significant Investment by Supply Corp

Pipeline amp Storage

Estimated Capital Cost $280 million(1)

Facilities (all in Pennsylvania) include Approximately 30 miles of new pipeline 2 new compressor stations (totaling

approximately 37000 HP) New interconnection station and modification

of existing interconnection station Abandonment of approximately 45 miles of

existing pipeline and compressor station Regulatory Process

Pre-filing application submitted to FERC in 2017 for original modernization project

FERC 7(b) 7(c) filing expected summer 2019

(1) Includes expansion and modernization portions of the project

40

Empire North Project

Target In-Service second half of fiscal 2020

Est Capital Cost $145 million

Est Annual Revenues ~$25 million

Receipt Point Jackson (Tioga Co Pa production)

Design Capacity and Delivery Points 175000 Dthd to Chippawa (TCPL interconnect)

30000 Dthd to Hopewell (TGP 200 interconnect)

Customers Fully subscribed (205000 Dthday)

Major Facilities 2 new compressor stations in NY (1) amp Pa (1)

No new pipeline construction

Regulatory Process FERC 7(c) application filed on 21618

FERC Environmental Assessment issued 103018

Pipeline amp Storage

Fully Subscribed Project will Provide 205000 Dthday of Incremental Firm Transportation

41

National Fuel Remains Committed to Northern Access Project

Target In-Service as early as fiscal 2022

Total Cost ~$500MM (~$76MM spent to date)

Estimated Annual Revenues ~$84 million

Delivery Points

350000 Dthd to Chippawa (TCPL interconnect)

140000 Dthd to Hopewell (TGP 200 line)

Regulatory Status

February 3 2017 ndash FERC 7(c) certificate issued

August 6 2018 ndash FERC issued Order finding that NY DEC waived water quality certification

Supply and Empire currently working to finalize remaining federal authorizations

Pipeline amp Storage

To Dawn

42

Continued Expansion of the NFG Supply System

Line N Expansion Opportunities

Line N to Monaca Project Project Firm transportation service to a new ethane

cracker facility being built by Shell Chemical Appalachia LLC

Target In-Service July 2019

Estimated Capital Cost $23 million

Contracted Capacity 133000 Dthday

Additional Line N Expansion Opportunity (Supply OS 221) Project New firm transportation service for on-system

demand

Open Season Capacity Awarded 165000 to foundation shipper Precedent agreement in negotiations

Pipeline amp Storage

43

Pipeline amp Storage Customer Mix

Producer33

LDC42

Marketer10

Outside Pipeline

9

End User6

42 MMDthd

(1) Contracted as of 10312018

Customer Transportation by Shipper Type(1) Affiliated Customer Mix (Contracted Capacity)

66

521

41

34

9579

59

LDCs Producers Marketers FirmStorage

Affiliated Non-Affiliated

Firm Transport

Pipeline amp Storage

44

Utility OverviewNational Fuel Gas Distribution Corporation

45

New York amp Pennsylvania Service Territories

New York

Total Customers(1) 535800ROE 87 (NY PSC Rate Case Order April 2017)Rate Mechanismso Revenue Decouplingo Weather Normalizationo Low Income Rateso Merchant Function Charge (Uncollectibles Adj)o 9010 Sharing (Large Customers)o System Modernization Tracker

Pennsylvania

Total Customers(1) 214400ROE Black Box Settlement (2007)Rate Mechanismso Low Income Rateso Merchant Function Charge

(1) As of September 30 2018

Utility

46

New York Rate Case Outcome

Rate Order Summary

Revenue Requirement $59 million

Rate Base $704 million

Allowed Return on Equity (ROE) 87

Capital Structure 429 equity

Other notable items

New rates became effective 5117

Retains rate mechanisms in place under prior order (revenue decoupling weather normalization merchant function charge 9010 large customer sharing)

No stay-out clause

System modernization tracker for Leak Prone Pipe (LPP)

Earnings sharing started 4118 (5050 sharing starts at earnings in excess of 92)

Article 78 appeal filed on 72817 with oral argument completed in January 2019

On April 20 2017 the New York Public Service Commission issued a Rate Order relating to NFG Distributionrsquos rate case (No 16-G-0257) filed in April 2016

Utility

47

Utility Continues its Significant Investments in Safety

$544$618 $636

$699

$944$980

$809$856

$90-100

$00

$250

$500

$750

$1000

$1250

2015 2016 2017 2018 2019E

Cap

ital E

xpen

ditu

res

($ m

illio

ns)

Fiscal Year

Capital Expenditures for Safety Total Capital Expenditures

Modernization Spending in NY Expected to Grow Gross Margin By $2 MM - $5 MM in FY 2019

(1)

(1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation

Utility

System modernization tracker in NY allows recovery of pipeline replacementcosts which is expected to drive modest gross margin and rate base growth

48

Accelerating Pipeline Replacement amp Modernization

Wrought Iron

Plastic

CoatedBare

120130

146 144159

2014 2015 2016 2017 2018Calendar Year

NY9726 miles

PA4830 miles

No Cast Iron Mains in Pa

Miles of Utility Main Pipeline ReplacedUtility Mains by Material(1)

Wrought Iron

Cast Iron

Plastic

Coated Bare

Utility

(1) All values are reported on a calendar year basis as of December 31 2018

49

A Proven History of Controlling Costs

$200 $189 $195

$166 $166

$31 $31

$197 $197

$0

$50

$100

$150

$200

$250

2015 2016 2017 2018 TTM 123118

Fiscal Year

OampM Expense Non-Service Pension Costs

OampM Expense ($ millions)

Utility

(1)

(1) For purposes of comparability to FY 2015 2016 and 2017 Utility Operation and Maintenance Expense for FY 2018 and the twelve months ended December 31 2018 was adjusted by approximately $314 million and $312 million respectively to include non-service pension costs which were re-classified as Other Income (Deductions) as of October 1 2018 on the Companyrsquos Income Statement See Slide 64 for non-GAAP reconciliation of Adjusted Operation and Maintenance Expense to Operation and Maintenance Expense by segment

50

Consolidated Financial OverviewUpstream I Midstream I Downstream

51

Adjusted Operating Results ($ per share)(1)

Diversified Balanced Earnings and Cash Flows

(1) A reconciliation of Adjusted Operating Results to Earnings per Share by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation(2) Consolidated Adjusted EBITDA includes Energy Marketing and Corporate amp All Other Segments A reconciliation of Adjusted EBITDA to Net Income by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in

the Business is included at the end of this presentation

Adjusted EBITDA ($ millions)(2)

$176 $179

$184 $181

$92 $97

$318 $327

$761 $775

$-

$200

$400

$600

$800

FY 2018 TTM 123118

$059 Utility

$097 Pipeline amp Storage

$057 Gathering

$125 Exploration

amp Production

$334 $345 to $365

$-

$100

$200

$300

$400

FY 2018 FY 2019 Guidance

Rate Regulated

40-45

$728

Rate Regulated

~46

52

$89 $94 $98 $81 $86 $90-$100

$140$230

$114 $95 $93 $120-$150

$138$118

$54$33 $48

$55-$65

$603$557

$99 $246$356

$460-$495

$970 $1001

$366$455

$583

$725-$810

$0

$250

$500

$750

$1000

$1250

2014 2015 2016 2017 2018 2019GuidanceFiscal Year

Exploration amp Production

Gathering

Pipeline amp Storage

Utility

Disciplined Flexible Capital Allocation

(2)

(1) Total Capital Expenditures include Energy Marketing Corporate and All Other A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation (2) FY16 FY17 and FY18 reflects the netting of $157 million $7 million and $17 million respectively of up-front proceeds received from joint development partner for working interest in joint development wells and $21M in intercompany asset transfers in FY18

Capital Expenditures by Segment ($ millions)(1)

53

Maintaining Strong Balance Sheet amp Liquidity

Total Equity49

Total Debt51

$42 Billion Total Capitalizationas of December 31 2018

218 x251 x 245 x 247 x 256 x

2015 2016 2017 2018 TTM 123118Fiscal Year End

Net Debt Adjusted EBITDA(1) Capitalization

Debt Maturity Profile ($MM) Liquidity

Committed Credit FacilitiesShort-term Debt OutstandingAvailable Short-term Credit FacilitiesCash Balance at 123118 Total Liquidity at 123118

$ 750 MM0 MM

750 MM110 MM

$ 860 MM

$500 $549 $500

$300 $300

$0

$200

$400

$600

(1) Net Debt is net of cash and temporary cash investments Reconciliations of Net Debt and Adjusted EBITDA to Net Income are included at the end of this presentation

54

Appendix

55

Safe Harbor For Forward Looking StatementsThis presentation may contain ldquoforward-looking statementsrdquo as defined by the Private Securities Litigation Reform Act of 1995 including statements regarding future prospectsplans objectives goals projections estimates of oil and gas quantities strategies future events or performance and underlying assumptions capital structure anticipatedcapital expenditures completion of construction projects projections for pension and other post-retirement benefit obligations impacts of the adoption of new accounting rulesand possible outcomes of litigation or regulatory proceedings as well as statements that are identified by the use of the words ldquoanticipatesrdquo ldquoestimatesrdquo ldquoexpectsrdquo ldquoforecastsrdquoldquointendsrdquo ldquoplansrdquo ldquopredictsrdquo ldquoprojectsrdquo ldquobelievesrdquo ldquoseeksrdquo ldquowillrdquo ldquomayrdquo and similar expressions Forward-looking statements involve risks and uncertainties which couldcause actual results or outcomes to differ materially from those expressed in the forward-looking statements The Companyrsquos expectations beliefs and projections are expressedin good faith and are believed by the Company to have a reasonable basis but there can be no assurance that managementrsquos expectations beliefs or projections will result or beachieved or accomplished

In addition to other factors the following are important factors that could cause actual results to differ materially from those discussed in the forward-looking statements delaysor changes in costs or plans with respect to Company projects or related projects of other companies including difficulties or delays in obtaining necessary governmentalapprovals permits or orders or in obtaining the cooperation of interconnecting facility operators governmentalregulatory actions initiatives and proceedings including thoseinvolving rate cases (which address among other things target rates of return rate design and retained natural gas) environmentalsafety requirements affiliate relationshipsindustry structure and franchise renewal changes in laws regulations or judicial interpretations to which the Company is subject including those involving derivatives taxessafety employment climate change other environmental matters real property and exploration and production activities such as hydraulic fracturing financial and economicconditions including the availability of credit and occurrences affecting the Companyrsquos ability to obtain financing on acceptable terms for working capital capital expendituresand other investments including any downgrades in the Companyrsquos credit ratings and changes in interest rates and other capital market conditions changes in the price ofnatural gas or oil impairments under the SECrsquos full cost ceiling test for natural gas and oil reserves factors affecting the Companyrsquos ability to successfully identify drill for andproduce economically viable natural gas and oil reserves including among others geology lease availability title disputes weather conditions shortages delays orunavailability of equipment and services required in drilling operations insufficient gathering processing and transportation capacity the need to obtain governmentalapprovals and permits and compliance with environmental laws and regulations increasing health care costs and the resulting effect on health insurance premiums and on theobligation to provide other post-retirement benefits changes in price differentials between similar quantities of natural gas or oil sold at different geographic locations and theeffect of such changes on commodity production revenues and demand for pipeline transportation capacity to or from such locations other changes in price differentialsbetween similar quantities of natural gas or oil having different quality heating value hydrocarbon mix or delivery date the cost and effects of legal and administrative claimsagainst the Company or activist shareholder campaigns to effect changes at the Company uncertainty of oil and gas reserve estimates significant differences between theCompanyrsquos projected and actual production levels for natural gas or oil changes in demographic patterns and weather conditions changes in the availability price oraccounting treatment of derivative financial instruments changes in laws actuarial assumptions the interest rate environment and the return on plantrust assets related to theCompanyrsquos pension and other post-retirement benefits which can affect future funding obligations and costs and plan liabilities changes in economic conditions includingglobal national or regional recessions and their effect on the demand for and customersrsquo ability to pay for the Companyrsquos products and services the creditworthiness orperformance of the Companyrsquos key suppliers customers and counterparties the impact of potential information technology cybersecurity or data security breaches economicdisruptions or uninsured losses resulting from major accidents fires severe weather natural disasters terrorist activities or acts of war significant differences between theCompanyrsquos projected and actual capital expenditures and operating expenses or increasing costs of insurance changes in coverage and the ability to obtain insurance

Forward-looking statements include estimates of oil and gas quantities Proved oil and gas reserves are those quantities of oil and gas which by analysis of geoscience andengineering data can be estimated with reasonable certainty to be economically producible under existing economic conditions operating methods and governmentregulations Other estimates of oil and gas quantities including estimates of probable reserves possible reserves and resource potential are by their nature more speculativethan estimates of proved reserves Accordingly estimates other than proved reserves are subject to substantially greater risk of being actually realized Investors are urged toconsider closely the disclosure in our Form 10-K available at wwwnationalfuelgascom You can also obtain this form on the SECrsquos website at wwwsecgov

For a discussion of the risks set forth above and other factors that could cause actual results to differ materially from results referred to in the forward-looking statements seeldquoRisk Factorsrdquo in the Companyrsquos Form 10-K for the fiscal year ended September 30 2018 and the Forms 10-Q for the quarter ended March 31 2018 June 30 2018 and December31 2018 The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date thereof or to reflect the occurrence ofunanticipated events

Appendix

26

Integrated Development ndash EDA Gathering Systems

Total Investment (to date) ~$46 million FY 2019 Estimated Capital Expenditures $1 MM - $2 MM Capacity 220000 Dth per day (Interconnect w TGP 300) Production Source Seneca Resources ndash Tioga Co (Covington and DCNR Tract 595)

Total Investment (to date) ~$208 million FY 2019 Estimated Capital Expenditures $25 MM - $35 MM Capacity 466000 to 585000 Dth per day (Interconnect w Transco) Production Source Seneca Resources ndash Lycoming Co (DCNR Tract 100 and Gamble) Future third-party volume opportunities

Covington Gathering System

Trout Run Gathering System

Gathering Segment Supporting Senecarsquos EDA Production amp Future Development

Wellsboro Gathering System Total Investment (to date) ~$14 million FY 2019 Estimated Capital Expenditures $8 MM - $15 MM Capacity up to 200000 Dth per day (Interconnect w TGP 300) Production Source Seneca Resources ndash Tioga Co (DCNR Tract 007)

EampP and Gathering

2

1

3

27

Long-term Contracts Supporting Appalachian Growth

(1) Represents base firm sales contracts not tied to firm transportation capacity Base firm sales are either fixed priced or priced at an index (eg NYMEX ) +- a fixed basis and do not carry any transportation costs

Seneca continues to layer-in firm sales contracts with attractive realizations to lock-in drilling economics and minimize spot exposure ahead of firm transportation in-service dates

EampP and Gathering

-

100

200

300

400

500

600

700

800

900

1000

1100

1200

FY 2019 FY 2020 FY 2021 FY 2022Northeast Supply Diversification 50000 Dthd

Niagara Expansion (TGP amp NFG)Delivery Markets Canada-Dawn amp TETCO

158000 Dthd

Atlantic Sunrise (Transco)Delivery Markets Mid-Atlantic amp Southeast US

189405 Dthd

In-BasinFirm Sales

Contracts(1)

Leidy South (Transco amp NFG)

Transco Zone 6 Markets330000 Dthd

Seneca Appalachia Natural Gas MarketingGross Firm Contract Volumes (Mdthday)

28

297000 ($061)

305200 ($061)

305600 ($063)

337000 ($057)

370800 ($024)

369600 ($060)

367900 ($067)

33400 ($070)74500 ($077) 74900 ($077)

81100 ($078)

85900 ($078)

92000 ($073)

91300 ($073)

178800 $255

196000 $234

195500 $234

149900 $232

129500 $230

105400 $222

104500 $222

~517800 509200 575700 576000 568000 586200 567000 563700

Q1 FY19 Q2 FY19 Q3 FY19 Q4 FY19 Q1 FY20 Q2 FY20 Q3 FY20 Q4 FY20

Fixed Price Dawn NYMEX

Near-term Firm Sales Provide Market amp Price Certainty

Net Contracted Firm Sales Volumes (Dth per day)Contracted Index Price Differentials ($ per Dth)(1)

(1) Values shown represent the weighted average fixed price or contracted fixed differential relative to NYMEX (netback price) less any associated transportation costs

Actual Daily Net

Production

641200 716500 708700 693500 708400 674400 667000Gross Firm Sales Volumes (Dthd)

EampP and Gathering

29

California Oil

Stable Oil Production | Minimal Capital Investment | Steady Free Cash Flow

1

2

3

4

5

Location Formation Production Method

FY18 Daily Production(net Boed)

1 East Coalinga Other Temblor Primary 512

2 North Lost Hills

Tulare amp Etchegoin

PrimarySteam flood 892

3 South Lost Hills

Monterey Shale Primary 1359

4 North Midway Sunset

Tulare amp Potter Steam flood 2786

5 South Midway Sunset Antelope Steam flood 2048

TOTAL WEST DIVISION NET PRODUCTION(1) 7597 Boed

EampP and Gathering

(1) West division net production for FY 2018 excludes production from Sespe field which was divested on May 1 2018

30

California Capital Expenditures vs Production

9341 8863

8033 ~7300

2016 2017 2018 2019

Fiscal Year

West Division Average Net Daily Production (Boe)West Division Annual Capital Expenditures ($ MM)(1)

$38 $38

$26 ~$25

2016 2017 2018 2019

Fiscal YearGuidance Guidance

(1) Seneca West Division capital expenditures includes Seneca corporate and eliminations

EampP and Gathering

Sepse Sale Closed on 5118(reduced production by ~900 boed)

31

Pioneer

South MWSS

Acreage

North MWSS

AcreageSec 17N

4149 51

NMWSS amp 17N SMWSS amp Pioneer East Coalinga

California Development Activities

Modest near-term capital program focused on locations that earn attractive returns in current oil price environment

AampD will focus on low cost bolt-on opportunities

Sec 17 Pioneer and East Coalinga development to provide future growth

North

Project IRRs at $55Bbl(1)

(1) Reflects pre-tax IRRs at a $55Bbl WTI

EampP and Gathering

Seneca West Economics

South

East Coalinga

North

South

32

Fiscal 2019 Production and Price Certainty

~49 Bcfe

210 ndash 230 Bcfe

~114 Bcf

~29 Bcf (2)

16+- Bcf~12 Bcfe

0

40

80

120

160

200

240

YTD FY19Actuals

Fixed Price + FirmSales w Hedge

Firm Sales(Unhedged)

Spot Sales California TotalSeneca

Prod

uctio

n (B

cfe)

(1) Average realized price reflects uplift from financial hedges less fixed differentials under firm sales contracts and any firm transportation costs(2) Indicates firm sales contracts with fixed index differentials but not backed by a matching financial hedge

114 Bcf locked-in realizing net ~$241Mcf (1)

29 Bcf of additional basis protection

Spot production assumed to be sold

at ~$275Mmbtu(winter) and ~$225

(summer)

143 Bcf of Appalachian Production Protected by Firm Sales for Remainder of Year

79 of oil production hedged at $5757 Bbl

EampP and Gathering

33

Strong Hedge Book

Natural Gas Swap amp Fixed Physical Sales Contracts (Millions MMBtu)

(1) Fixed price physical sales exclude joint development partnerrsquos share of fixed price contract WDA volumes as specified under the joint development agreement(2) Reflects percentage of projected production for FY19 hedged at the midpoint of the production guidance range(3) Senecarsquos remainder FY19 Production reflects the total FY19 production guidance of 210-230 Bcfe or 220 Bcfe at the midpoint less Q1 actual production

Crude Oil Swap Contracts (Thousands Bbls)

13591188

732

456

0

500

1000

1500

2000

2500

FY 2019 FY 2020 FY 2021 FY 2022

NYMEX (WTI)

Brent

FY 19 Crude Oil79 Hedged (2)

FY 2019 Remaining Production (3)

EampP and Gathering

1174

709

469 406

0

50

100

150

200

250

FY 2019 FY 2020 FY 2021 FY 2022

NYMEX Swaps

Dawn Swaps

Fixed Price Physical Sales

(1)

FY 2019 Remaining Production (3)

FY 19 Nat Gas71 Hedged (2)

34

$065 $070$070 -$075

FY 2017 FY 2018 FY 2019E

$060 $060 $060

$011 $009 $007$071 $069 ~$067

FY 2017 FY 2018 FY 2019E Gathering amp Transport LOE (non-Gathering) GampA Taxes amp Other

Seneca Operating Costs

Competitive low cost structure in Appalachia and California supports strong cash margins

Gathering fee generates significant revenue stream for affiliated gathering company

Seneca DDampARate

$Mcfe

$054 $054 $056

$042 $038 $031

$034 $034 $030

$017 $014 $015

$147 $140 ~$132

FY 2017 FY 2018 FY 2019E

(1)

$1791$1746~$2050

FY 2017 FY 2018 FY 2019E

Appalachia LOE amp Gathering $Mcfe

California LOE$Boe

Total Seneca Cash OpEx$Mcfe

(1)

(2)

(2)

(1) GampA estimate represents the midpoint of the GampA guidance range of $025 to $035 for fiscal 2019(2) The total of the two LOE components represents the midpoint of the LOE guidance range of $085 to $090 for fiscal 2019

EampP and Gathering

35

Senecarsquos Continuing Commitment to the Environment

Produced Water Recycled in Appalachia

100 70Recycled Water

Used in New Shale Well

Completions

Water and Fluids Management Air Quality and Emissions

Seneca Resources Water OperationsFiscal 2018

Seneca Resources Remains Focused on Minimizing GHG Emissions

The Environmental Partnership

EPA Natural Gas Star Program

Green Completions (all fiscal 2018 wells)

Ultrasonic Leak Detection Technology

Emissions Controls

Rig and Vehicle Fuel Conversion

Integrating Renewable Energy into Operations

EampP and Gathering

36

Pipeline and Storage OverviewNational Fuel Gas Supply Corporation ~ Empire Pipeline Inc

37

Pipeline amp Storage Segment Overview

(1) As of September 30 2018 as disclosed in the Companyrsquos fiscal 2018 form 10-K(2) As of December 31 2017 calculated from National Fuel Gas Supply Corporationrsquos and Empire Pipeline Incrsquos 2017 FERC Form-2 reports respectively

Empire Pipeline Inc

National Fuel Gas Supply Corporation

Empire Pipeline

Supply Corp

Contracted Capacity(1) Firm Transportation 3187 MDth per day Firm Storage 71938 Mdth (fully subscribed)

Rate Base(2) ~$820 million FERC Rate Proceeding Status

Rate case settlement extension approved Nov lsquo15 Rate case filing expected by 73119

Contracted Capacity(1) Firm Transportation 978 MDth per day Firm Storage 3753 Mdth (fully subscribed)

Rate Base(2) ~$249 million FERC Rate Proceeding Status

Rate case settlement in principle reached on 122118 FERC approval pending

New transportation rates went into on 1119

Pipeline amp Storage

38

All Seneca volumes will flow through wholly-owned NFG gathering facilities

FM100 Project - Consolidated Benefit for NFG

330000 Dthd of new transportation capacity from WDA and EDA acreage positions to premium markets

New Transco capacity (Leidy South) 330000 Dthday

Rate(1) competitive with other expansion project rates in Senecarsquos current transportation portfolio

Delivery Point(s) Transco Zone 6 interconnections

Seneca

Lease to Transco of new capacity 330000 Dthday

Estimated annual lease revenues ~$35 million

Target In-Service late calendar year 2021

Supply Corp

Project expected to provide long-term earnings uplift to Seneca Supply Corp and Gathering

Pipeline amp Storage

Gathering

(1) Includes lease of new capacity from Supply Corp to Transco

39

FM100 Project ndash Significant Investment by Supply Corp

Pipeline amp Storage

Estimated Capital Cost $280 million(1)

Facilities (all in Pennsylvania) include Approximately 30 miles of new pipeline 2 new compressor stations (totaling

approximately 37000 HP) New interconnection station and modification

of existing interconnection station Abandonment of approximately 45 miles of

existing pipeline and compressor station Regulatory Process

Pre-filing application submitted to FERC in 2017 for original modernization project

FERC 7(b) 7(c) filing expected summer 2019

(1) Includes expansion and modernization portions of the project

40

Empire North Project

Target In-Service second half of fiscal 2020

Est Capital Cost $145 million

Est Annual Revenues ~$25 million

Receipt Point Jackson (Tioga Co Pa production)

Design Capacity and Delivery Points 175000 Dthd to Chippawa (TCPL interconnect)

30000 Dthd to Hopewell (TGP 200 interconnect)

Customers Fully subscribed (205000 Dthday)

Major Facilities 2 new compressor stations in NY (1) amp Pa (1)

No new pipeline construction

Regulatory Process FERC 7(c) application filed on 21618

FERC Environmental Assessment issued 103018

Pipeline amp Storage

Fully Subscribed Project will Provide 205000 Dthday of Incremental Firm Transportation

41

National Fuel Remains Committed to Northern Access Project

Target In-Service as early as fiscal 2022

Total Cost ~$500MM (~$76MM spent to date)

Estimated Annual Revenues ~$84 million

Delivery Points

350000 Dthd to Chippawa (TCPL interconnect)

140000 Dthd to Hopewell (TGP 200 line)

Regulatory Status

February 3 2017 ndash FERC 7(c) certificate issued

August 6 2018 ndash FERC issued Order finding that NY DEC waived water quality certification

Supply and Empire currently working to finalize remaining federal authorizations

Pipeline amp Storage

To Dawn

42

Continued Expansion of the NFG Supply System

Line N Expansion Opportunities

Line N to Monaca Project Project Firm transportation service to a new ethane

cracker facility being built by Shell Chemical Appalachia LLC

Target In-Service July 2019

Estimated Capital Cost $23 million

Contracted Capacity 133000 Dthday

Additional Line N Expansion Opportunity (Supply OS 221) Project New firm transportation service for on-system

demand

Open Season Capacity Awarded 165000 to foundation shipper Precedent agreement in negotiations

Pipeline amp Storage

43

Pipeline amp Storage Customer Mix

Producer33

LDC42

Marketer10

Outside Pipeline

9

End User6

42 MMDthd

(1) Contracted as of 10312018

Customer Transportation by Shipper Type(1) Affiliated Customer Mix (Contracted Capacity)

66

521

41

34

9579

59

LDCs Producers Marketers FirmStorage

Affiliated Non-Affiliated

Firm Transport

Pipeline amp Storage

44

Utility OverviewNational Fuel Gas Distribution Corporation

45

New York amp Pennsylvania Service Territories

New York

Total Customers(1) 535800ROE 87 (NY PSC Rate Case Order April 2017)Rate Mechanismso Revenue Decouplingo Weather Normalizationo Low Income Rateso Merchant Function Charge (Uncollectibles Adj)o 9010 Sharing (Large Customers)o System Modernization Tracker

Pennsylvania

Total Customers(1) 214400ROE Black Box Settlement (2007)Rate Mechanismso Low Income Rateso Merchant Function Charge

(1) As of September 30 2018

Utility

46

New York Rate Case Outcome

Rate Order Summary

Revenue Requirement $59 million

Rate Base $704 million

Allowed Return on Equity (ROE) 87

Capital Structure 429 equity

Other notable items

New rates became effective 5117

Retains rate mechanisms in place under prior order (revenue decoupling weather normalization merchant function charge 9010 large customer sharing)

No stay-out clause

System modernization tracker for Leak Prone Pipe (LPP)

Earnings sharing started 4118 (5050 sharing starts at earnings in excess of 92)

Article 78 appeal filed on 72817 with oral argument completed in January 2019

On April 20 2017 the New York Public Service Commission issued a Rate Order relating to NFG Distributionrsquos rate case (No 16-G-0257) filed in April 2016

Utility

47

Utility Continues its Significant Investments in Safety

$544$618 $636

$699

$944$980

$809$856

$90-100

$00

$250

$500

$750

$1000

$1250

2015 2016 2017 2018 2019E

Cap

ital E

xpen

ditu

res

($ m

illio

ns)

Fiscal Year

Capital Expenditures for Safety Total Capital Expenditures

Modernization Spending in NY Expected to Grow Gross Margin By $2 MM - $5 MM in FY 2019

(1)

(1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation

Utility

System modernization tracker in NY allows recovery of pipeline replacementcosts which is expected to drive modest gross margin and rate base growth

48

Accelerating Pipeline Replacement amp Modernization

Wrought Iron

Plastic

CoatedBare

120130

146 144159

2014 2015 2016 2017 2018Calendar Year

NY9726 miles

PA4830 miles

No Cast Iron Mains in Pa

Miles of Utility Main Pipeline ReplacedUtility Mains by Material(1)

Wrought Iron

Cast Iron

Plastic

Coated Bare

Utility

(1) All values are reported on a calendar year basis as of December 31 2018

49

A Proven History of Controlling Costs

$200 $189 $195

$166 $166

$31 $31

$197 $197

$0

$50

$100

$150

$200

$250

2015 2016 2017 2018 TTM 123118

Fiscal Year

OampM Expense Non-Service Pension Costs

OampM Expense ($ millions)

Utility

(1)

(1) For purposes of comparability to FY 2015 2016 and 2017 Utility Operation and Maintenance Expense for FY 2018 and the twelve months ended December 31 2018 was adjusted by approximately $314 million and $312 million respectively to include non-service pension costs which were re-classified as Other Income (Deductions) as of October 1 2018 on the Companyrsquos Income Statement See Slide 64 for non-GAAP reconciliation of Adjusted Operation and Maintenance Expense to Operation and Maintenance Expense by segment

50

Consolidated Financial OverviewUpstream I Midstream I Downstream

51

Adjusted Operating Results ($ per share)(1)

Diversified Balanced Earnings and Cash Flows

(1) A reconciliation of Adjusted Operating Results to Earnings per Share by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation(2) Consolidated Adjusted EBITDA includes Energy Marketing and Corporate amp All Other Segments A reconciliation of Adjusted EBITDA to Net Income by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in

the Business is included at the end of this presentation

Adjusted EBITDA ($ millions)(2)

$176 $179

$184 $181

$92 $97

$318 $327

$761 $775

$-

$200

$400

$600

$800

FY 2018 TTM 123118

$059 Utility

$097 Pipeline amp Storage

$057 Gathering

$125 Exploration

amp Production

$334 $345 to $365

$-

$100

$200

$300

$400

FY 2018 FY 2019 Guidance

Rate Regulated

40-45

$728

Rate Regulated

~46

52

$89 $94 $98 $81 $86 $90-$100

$140$230

$114 $95 $93 $120-$150

$138$118

$54$33 $48

$55-$65

$603$557

$99 $246$356

$460-$495

$970 $1001

$366$455

$583

$725-$810

$0

$250

$500

$750

$1000

$1250

2014 2015 2016 2017 2018 2019GuidanceFiscal Year

Exploration amp Production

Gathering

Pipeline amp Storage

Utility

Disciplined Flexible Capital Allocation

(2)

(1) Total Capital Expenditures include Energy Marketing Corporate and All Other A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation (2) FY16 FY17 and FY18 reflects the netting of $157 million $7 million and $17 million respectively of up-front proceeds received from joint development partner for working interest in joint development wells and $21M in intercompany asset transfers in FY18

Capital Expenditures by Segment ($ millions)(1)

53

Maintaining Strong Balance Sheet amp Liquidity

Total Equity49

Total Debt51

$42 Billion Total Capitalizationas of December 31 2018

218 x251 x 245 x 247 x 256 x

2015 2016 2017 2018 TTM 123118Fiscal Year End

Net Debt Adjusted EBITDA(1) Capitalization

Debt Maturity Profile ($MM) Liquidity

Committed Credit FacilitiesShort-term Debt OutstandingAvailable Short-term Credit FacilitiesCash Balance at 123118 Total Liquidity at 123118

$ 750 MM0 MM

750 MM110 MM

$ 860 MM

$500 $549 $500

$300 $300

$0

$200

$400

$600

(1) Net Debt is net of cash and temporary cash investments Reconciliations of Net Debt and Adjusted EBITDA to Net Income are included at the end of this presentation

54

Appendix

55

Safe Harbor For Forward Looking StatementsThis presentation may contain ldquoforward-looking statementsrdquo as defined by the Private Securities Litigation Reform Act of 1995 including statements regarding future prospectsplans objectives goals projections estimates of oil and gas quantities strategies future events or performance and underlying assumptions capital structure anticipatedcapital expenditures completion of construction projects projections for pension and other post-retirement benefit obligations impacts of the adoption of new accounting rulesand possible outcomes of litigation or regulatory proceedings as well as statements that are identified by the use of the words ldquoanticipatesrdquo ldquoestimatesrdquo ldquoexpectsrdquo ldquoforecastsrdquoldquointendsrdquo ldquoplansrdquo ldquopredictsrdquo ldquoprojectsrdquo ldquobelievesrdquo ldquoseeksrdquo ldquowillrdquo ldquomayrdquo and similar expressions Forward-looking statements involve risks and uncertainties which couldcause actual results or outcomes to differ materially from those expressed in the forward-looking statements The Companyrsquos expectations beliefs and projections are expressedin good faith and are believed by the Company to have a reasonable basis but there can be no assurance that managementrsquos expectations beliefs or projections will result or beachieved or accomplished

In addition to other factors the following are important factors that could cause actual results to differ materially from those discussed in the forward-looking statements delaysor changes in costs or plans with respect to Company projects or related projects of other companies including difficulties or delays in obtaining necessary governmentalapprovals permits or orders or in obtaining the cooperation of interconnecting facility operators governmentalregulatory actions initiatives and proceedings including thoseinvolving rate cases (which address among other things target rates of return rate design and retained natural gas) environmentalsafety requirements affiliate relationshipsindustry structure and franchise renewal changes in laws regulations or judicial interpretations to which the Company is subject including those involving derivatives taxessafety employment climate change other environmental matters real property and exploration and production activities such as hydraulic fracturing financial and economicconditions including the availability of credit and occurrences affecting the Companyrsquos ability to obtain financing on acceptable terms for working capital capital expendituresand other investments including any downgrades in the Companyrsquos credit ratings and changes in interest rates and other capital market conditions changes in the price ofnatural gas or oil impairments under the SECrsquos full cost ceiling test for natural gas and oil reserves factors affecting the Companyrsquos ability to successfully identify drill for andproduce economically viable natural gas and oil reserves including among others geology lease availability title disputes weather conditions shortages delays orunavailability of equipment and services required in drilling operations insufficient gathering processing and transportation capacity the need to obtain governmentalapprovals and permits and compliance with environmental laws and regulations increasing health care costs and the resulting effect on health insurance premiums and on theobligation to provide other post-retirement benefits changes in price differentials between similar quantities of natural gas or oil sold at different geographic locations and theeffect of such changes on commodity production revenues and demand for pipeline transportation capacity to or from such locations other changes in price differentialsbetween similar quantities of natural gas or oil having different quality heating value hydrocarbon mix or delivery date the cost and effects of legal and administrative claimsagainst the Company or activist shareholder campaigns to effect changes at the Company uncertainty of oil and gas reserve estimates significant differences between theCompanyrsquos projected and actual production levels for natural gas or oil changes in demographic patterns and weather conditions changes in the availability price oraccounting treatment of derivative financial instruments changes in laws actuarial assumptions the interest rate environment and the return on plantrust assets related to theCompanyrsquos pension and other post-retirement benefits which can affect future funding obligations and costs and plan liabilities changes in economic conditions includingglobal national or regional recessions and their effect on the demand for and customersrsquo ability to pay for the Companyrsquos products and services the creditworthiness orperformance of the Companyrsquos key suppliers customers and counterparties the impact of potential information technology cybersecurity or data security breaches economicdisruptions or uninsured losses resulting from major accidents fires severe weather natural disasters terrorist activities or acts of war significant differences between theCompanyrsquos projected and actual capital expenditures and operating expenses or increasing costs of insurance changes in coverage and the ability to obtain insurance

Forward-looking statements include estimates of oil and gas quantities Proved oil and gas reserves are those quantities of oil and gas which by analysis of geoscience andengineering data can be estimated with reasonable certainty to be economically producible under existing economic conditions operating methods and governmentregulations Other estimates of oil and gas quantities including estimates of probable reserves possible reserves and resource potential are by their nature more speculativethan estimates of proved reserves Accordingly estimates other than proved reserves are subject to substantially greater risk of being actually realized Investors are urged toconsider closely the disclosure in our Form 10-K available at wwwnationalfuelgascom You can also obtain this form on the SECrsquos website at wwwsecgov

For a discussion of the risks set forth above and other factors that could cause actual results to differ materially from results referred to in the forward-looking statements seeldquoRisk Factorsrdquo in the Companyrsquos Form 10-K for the fiscal year ended September 30 2018 and the Forms 10-Q for the quarter ended March 31 2018 June 30 2018 and December31 2018 The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date thereof or to reflect the occurrence ofunanticipated events

Appendix

27

Long-term Contracts Supporting Appalachian Growth

(1) Represents base firm sales contracts not tied to firm transportation capacity Base firm sales are either fixed priced or priced at an index (eg NYMEX ) +- a fixed basis and do not carry any transportation costs

Seneca continues to layer-in firm sales contracts with attractive realizations to lock-in drilling economics and minimize spot exposure ahead of firm transportation in-service dates

EampP and Gathering

-

100

200

300

400

500

600

700

800

900

1000

1100

1200

FY 2019 FY 2020 FY 2021 FY 2022Northeast Supply Diversification 50000 Dthd

Niagara Expansion (TGP amp NFG)Delivery Markets Canada-Dawn amp TETCO

158000 Dthd

Atlantic Sunrise (Transco)Delivery Markets Mid-Atlantic amp Southeast US

189405 Dthd

In-BasinFirm Sales

Contracts(1)

Leidy South (Transco amp NFG)

Transco Zone 6 Markets330000 Dthd

Seneca Appalachia Natural Gas MarketingGross Firm Contract Volumes (Mdthday)

28

297000 ($061)

305200 ($061)

305600 ($063)

337000 ($057)

370800 ($024)

369600 ($060)

367900 ($067)

33400 ($070)74500 ($077) 74900 ($077)

81100 ($078)

85900 ($078)

92000 ($073)

91300 ($073)

178800 $255

196000 $234

195500 $234

149900 $232

129500 $230

105400 $222

104500 $222

~517800 509200 575700 576000 568000 586200 567000 563700

Q1 FY19 Q2 FY19 Q3 FY19 Q4 FY19 Q1 FY20 Q2 FY20 Q3 FY20 Q4 FY20

Fixed Price Dawn NYMEX

Near-term Firm Sales Provide Market amp Price Certainty

Net Contracted Firm Sales Volumes (Dth per day)Contracted Index Price Differentials ($ per Dth)(1)

(1) Values shown represent the weighted average fixed price or contracted fixed differential relative to NYMEX (netback price) less any associated transportation costs

Actual Daily Net

Production

641200 716500 708700 693500 708400 674400 667000Gross Firm Sales Volumes (Dthd)

EampP and Gathering

29

California Oil

Stable Oil Production | Minimal Capital Investment | Steady Free Cash Flow

1

2

3

4

5

Location Formation Production Method

FY18 Daily Production(net Boed)

1 East Coalinga Other Temblor Primary 512

2 North Lost Hills

Tulare amp Etchegoin

PrimarySteam flood 892

3 South Lost Hills

Monterey Shale Primary 1359

4 North Midway Sunset

Tulare amp Potter Steam flood 2786

5 South Midway Sunset Antelope Steam flood 2048

TOTAL WEST DIVISION NET PRODUCTION(1) 7597 Boed

EampP and Gathering

(1) West division net production for FY 2018 excludes production from Sespe field which was divested on May 1 2018

30

California Capital Expenditures vs Production

9341 8863

8033 ~7300

2016 2017 2018 2019

Fiscal Year

West Division Average Net Daily Production (Boe)West Division Annual Capital Expenditures ($ MM)(1)

$38 $38

$26 ~$25

2016 2017 2018 2019

Fiscal YearGuidance Guidance

(1) Seneca West Division capital expenditures includes Seneca corporate and eliminations

EampP and Gathering

Sepse Sale Closed on 5118(reduced production by ~900 boed)

31

Pioneer

South MWSS

Acreage

North MWSS

AcreageSec 17N

4149 51

NMWSS amp 17N SMWSS amp Pioneer East Coalinga

California Development Activities

Modest near-term capital program focused on locations that earn attractive returns in current oil price environment

AampD will focus on low cost bolt-on opportunities

Sec 17 Pioneer and East Coalinga development to provide future growth

North

Project IRRs at $55Bbl(1)

(1) Reflects pre-tax IRRs at a $55Bbl WTI

EampP and Gathering

Seneca West Economics

South

East Coalinga

North

South

32

Fiscal 2019 Production and Price Certainty

~49 Bcfe

210 ndash 230 Bcfe

~114 Bcf

~29 Bcf (2)

16+- Bcf~12 Bcfe

0

40

80

120

160

200

240

YTD FY19Actuals

Fixed Price + FirmSales w Hedge

Firm Sales(Unhedged)

Spot Sales California TotalSeneca

Prod

uctio

n (B

cfe)

(1) Average realized price reflects uplift from financial hedges less fixed differentials under firm sales contracts and any firm transportation costs(2) Indicates firm sales contracts with fixed index differentials but not backed by a matching financial hedge

114 Bcf locked-in realizing net ~$241Mcf (1)

29 Bcf of additional basis protection

Spot production assumed to be sold

at ~$275Mmbtu(winter) and ~$225

(summer)

143 Bcf of Appalachian Production Protected by Firm Sales for Remainder of Year

79 of oil production hedged at $5757 Bbl

EampP and Gathering

33

Strong Hedge Book

Natural Gas Swap amp Fixed Physical Sales Contracts (Millions MMBtu)

(1) Fixed price physical sales exclude joint development partnerrsquos share of fixed price contract WDA volumes as specified under the joint development agreement(2) Reflects percentage of projected production for FY19 hedged at the midpoint of the production guidance range(3) Senecarsquos remainder FY19 Production reflects the total FY19 production guidance of 210-230 Bcfe or 220 Bcfe at the midpoint less Q1 actual production

Crude Oil Swap Contracts (Thousands Bbls)

13591188

732

456

0

500

1000

1500

2000

2500

FY 2019 FY 2020 FY 2021 FY 2022

NYMEX (WTI)

Brent

FY 19 Crude Oil79 Hedged (2)

FY 2019 Remaining Production (3)

EampP and Gathering

1174

709

469 406

0

50

100

150

200

250

FY 2019 FY 2020 FY 2021 FY 2022

NYMEX Swaps

Dawn Swaps

Fixed Price Physical Sales

(1)

FY 2019 Remaining Production (3)

FY 19 Nat Gas71 Hedged (2)

34

$065 $070$070 -$075

FY 2017 FY 2018 FY 2019E

$060 $060 $060

$011 $009 $007$071 $069 ~$067

FY 2017 FY 2018 FY 2019E Gathering amp Transport LOE (non-Gathering) GampA Taxes amp Other

Seneca Operating Costs

Competitive low cost structure in Appalachia and California supports strong cash margins

Gathering fee generates significant revenue stream for affiliated gathering company

Seneca DDampARate

$Mcfe

$054 $054 $056

$042 $038 $031

$034 $034 $030

$017 $014 $015

$147 $140 ~$132

FY 2017 FY 2018 FY 2019E

(1)

$1791$1746~$2050

FY 2017 FY 2018 FY 2019E

Appalachia LOE amp Gathering $Mcfe

California LOE$Boe

Total Seneca Cash OpEx$Mcfe

(1)

(2)

(2)

(1) GampA estimate represents the midpoint of the GampA guidance range of $025 to $035 for fiscal 2019(2) The total of the two LOE components represents the midpoint of the LOE guidance range of $085 to $090 for fiscal 2019

EampP and Gathering

35

Senecarsquos Continuing Commitment to the Environment

Produced Water Recycled in Appalachia

100 70Recycled Water

Used in New Shale Well

Completions

Water and Fluids Management Air Quality and Emissions

Seneca Resources Water OperationsFiscal 2018

Seneca Resources Remains Focused on Minimizing GHG Emissions

The Environmental Partnership

EPA Natural Gas Star Program

Green Completions (all fiscal 2018 wells)

Ultrasonic Leak Detection Technology

Emissions Controls

Rig and Vehicle Fuel Conversion

Integrating Renewable Energy into Operations

EampP and Gathering

36

Pipeline and Storage OverviewNational Fuel Gas Supply Corporation ~ Empire Pipeline Inc

37

Pipeline amp Storage Segment Overview

(1) As of September 30 2018 as disclosed in the Companyrsquos fiscal 2018 form 10-K(2) As of December 31 2017 calculated from National Fuel Gas Supply Corporationrsquos and Empire Pipeline Incrsquos 2017 FERC Form-2 reports respectively

Empire Pipeline Inc

National Fuel Gas Supply Corporation

Empire Pipeline

Supply Corp

Contracted Capacity(1) Firm Transportation 3187 MDth per day Firm Storage 71938 Mdth (fully subscribed)

Rate Base(2) ~$820 million FERC Rate Proceeding Status

Rate case settlement extension approved Nov lsquo15 Rate case filing expected by 73119

Contracted Capacity(1) Firm Transportation 978 MDth per day Firm Storage 3753 Mdth (fully subscribed)

Rate Base(2) ~$249 million FERC Rate Proceeding Status

Rate case settlement in principle reached on 122118 FERC approval pending

New transportation rates went into on 1119

Pipeline amp Storage

38

All Seneca volumes will flow through wholly-owned NFG gathering facilities

FM100 Project - Consolidated Benefit for NFG

330000 Dthd of new transportation capacity from WDA and EDA acreage positions to premium markets

New Transco capacity (Leidy South) 330000 Dthday

Rate(1) competitive with other expansion project rates in Senecarsquos current transportation portfolio

Delivery Point(s) Transco Zone 6 interconnections

Seneca

Lease to Transco of new capacity 330000 Dthday

Estimated annual lease revenues ~$35 million

Target In-Service late calendar year 2021

Supply Corp

Project expected to provide long-term earnings uplift to Seneca Supply Corp and Gathering

Pipeline amp Storage

Gathering

(1) Includes lease of new capacity from Supply Corp to Transco

39

FM100 Project ndash Significant Investment by Supply Corp

Pipeline amp Storage

Estimated Capital Cost $280 million(1)

Facilities (all in Pennsylvania) include Approximately 30 miles of new pipeline 2 new compressor stations (totaling

approximately 37000 HP) New interconnection station and modification

of existing interconnection station Abandonment of approximately 45 miles of

existing pipeline and compressor station Regulatory Process

Pre-filing application submitted to FERC in 2017 for original modernization project

FERC 7(b) 7(c) filing expected summer 2019

(1) Includes expansion and modernization portions of the project

40

Empire North Project

Target In-Service second half of fiscal 2020

Est Capital Cost $145 million

Est Annual Revenues ~$25 million

Receipt Point Jackson (Tioga Co Pa production)

Design Capacity and Delivery Points 175000 Dthd to Chippawa (TCPL interconnect)

30000 Dthd to Hopewell (TGP 200 interconnect)

Customers Fully subscribed (205000 Dthday)

Major Facilities 2 new compressor stations in NY (1) amp Pa (1)

No new pipeline construction

Regulatory Process FERC 7(c) application filed on 21618

FERC Environmental Assessment issued 103018

Pipeline amp Storage

Fully Subscribed Project will Provide 205000 Dthday of Incremental Firm Transportation

41

National Fuel Remains Committed to Northern Access Project

Target In-Service as early as fiscal 2022

Total Cost ~$500MM (~$76MM spent to date)

Estimated Annual Revenues ~$84 million

Delivery Points

350000 Dthd to Chippawa (TCPL interconnect)

140000 Dthd to Hopewell (TGP 200 line)

Regulatory Status

February 3 2017 ndash FERC 7(c) certificate issued

August 6 2018 ndash FERC issued Order finding that NY DEC waived water quality certification

Supply and Empire currently working to finalize remaining federal authorizations

Pipeline amp Storage

To Dawn

42

Continued Expansion of the NFG Supply System

Line N Expansion Opportunities

Line N to Monaca Project Project Firm transportation service to a new ethane

cracker facility being built by Shell Chemical Appalachia LLC

Target In-Service July 2019

Estimated Capital Cost $23 million

Contracted Capacity 133000 Dthday

Additional Line N Expansion Opportunity (Supply OS 221) Project New firm transportation service for on-system

demand

Open Season Capacity Awarded 165000 to foundation shipper Precedent agreement in negotiations

Pipeline amp Storage

43

Pipeline amp Storage Customer Mix

Producer33

LDC42

Marketer10

Outside Pipeline

9

End User6

42 MMDthd

(1) Contracted as of 10312018

Customer Transportation by Shipper Type(1) Affiliated Customer Mix (Contracted Capacity)

66

521

41

34

9579

59

LDCs Producers Marketers FirmStorage

Affiliated Non-Affiliated

Firm Transport

Pipeline amp Storage

44

Utility OverviewNational Fuel Gas Distribution Corporation

45

New York amp Pennsylvania Service Territories

New York

Total Customers(1) 535800ROE 87 (NY PSC Rate Case Order April 2017)Rate Mechanismso Revenue Decouplingo Weather Normalizationo Low Income Rateso Merchant Function Charge (Uncollectibles Adj)o 9010 Sharing (Large Customers)o System Modernization Tracker

Pennsylvania

Total Customers(1) 214400ROE Black Box Settlement (2007)Rate Mechanismso Low Income Rateso Merchant Function Charge

(1) As of September 30 2018

Utility

46

New York Rate Case Outcome

Rate Order Summary

Revenue Requirement $59 million

Rate Base $704 million

Allowed Return on Equity (ROE) 87

Capital Structure 429 equity

Other notable items

New rates became effective 5117

Retains rate mechanisms in place under prior order (revenue decoupling weather normalization merchant function charge 9010 large customer sharing)

No stay-out clause

System modernization tracker for Leak Prone Pipe (LPP)

Earnings sharing started 4118 (5050 sharing starts at earnings in excess of 92)

Article 78 appeal filed on 72817 with oral argument completed in January 2019

On April 20 2017 the New York Public Service Commission issued a Rate Order relating to NFG Distributionrsquos rate case (No 16-G-0257) filed in April 2016

Utility

47

Utility Continues its Significant Investments in Safety

$544$618 $636

$699

$944$980

$809$856

$90-100

$00

$250

$500

$750

$1000

$1250

2015 2016 2017 2018 2019E

Cap

ital E

xpen

ditu

res

($ m

illio

ns)

Fiscal Year

Capital Expenditures for Safety Total Capital Expenditures

Modernization Spending in NY Expected to Grow Gross Margin By $2 MM - $5 MM in FY 2019

(1)

(1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation

Utility

System modernization tracker in NY allows recovery of pipeline replacementcosts which is expected to drive modest gross margin and rate base growth

48

Accelerating Pipeline Replacement amp Modernization

Wrought Iron

Plastic

CoatedBare

120130

146 144159

2014 2015 2016 2017 2018Calendar Year

NY9726 miles

PA4830 miles

No Cast Iron Mains in Pa

Miles of Utility Main Pipeline ReplacedUtility Mains by Material(1)

Wrought Iron

Cast Iron

Plastic

Coated Bare

Utility

(1) All values are reported on a calendar year basis as of December 31 2018

49

A Proven History of Controlling Costs

$200 $189 $195

$166 $166

$31 $31

$197 $197

$0

$50

$100

$150

$200

$250

2015 2016 2017 2018 TTM 123118

Fiscal Year

OampM Expense Non-Service Pension Costs

OampM Expense ($ millions)

Utility

(1)

(1) For purposes of comparability to FY 2015 2016 and 2017 Utility Operation and Maintenance Expense for FY 2018 and the twelve months ended December 31 2018 was adjusted by approximately $314 million and $312 million respectively to include non-service pension costs which were re-classified as Other Income (Deductions) as of October 1 2018 on the Companyrsquos Income Statement See Slide 64 for non-GAAP reconciliation of Adjusted Operation and Maintenance Expense to Operation and Maintenance Expense by segment

50

Consolidated Financial OverviewUpstream I Midstream I Downstream

51

Adjusted Operating Results ($ per share)(1)

Diversified Balanced Earnings and Cash Flows

(1) A reconciliation of Adjusted Operating Results to Earnings per Share by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation(2) Consolidated Adjusted EBITDA includes Energy Marketing and Corporate amp All Other Segments A reconciliation of Adjusted EBITDA to Net Income by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in

the Business is included at the end of this presentation

Adjusted EBITDA ($ millions)(2)

$176 $179

$184 $181

$92 $97

$318 $327

$761 $775

$-

$200

$400

$600

$800

FY 2018 TTM 123118

$059 Utility

$097 Pipeline amp Storage

$057 Gathering

$125 Exploration

amp Production

$334 $345 to $365

$-

$100

$200

$300

$400

FY 2018 FY 2019 Guidance

Rate Regulated

40-45

$728

Rate Regulated

~46

52

$89 $94 $98 $81 $86 $90-$100

$140$230

$114 $95 $93 $120-$150

$138$118

$54$33 $48

$55-$65

$603$557

$99 $246$356

$460-$495

$970 $1001

$366$455

$583

$725-$810

$0

$250

$500

$750

$1000

$1250

2014 2015 2016 2017 2018 2019GuidanceFiscal Year

Exploration amp Production

Gathering

Pipeline amp Storage

Utility

Disciplined Flexible Capital Allocation

(2)

(1) Total Capital Expenditures include Energy Marketing Corporate and All Other A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation (2) FY16 FY17 and FY18 reflects the netting of $157 million $7 million and $17 million respectively of up-front proceeds received from joint development partner for working interest in joint development wells and $21M in intercompany asset transfers in FY18

Capital Expenditures by Segment ($ millions)(1)

53

Maintaining Strong Balance Sheet amp Liquidity

Total Equity49

Total Debt51

$42 Billion Total Capitalizationas of December 31 2018

218 x251 x 245 x 247 x 256 x

2015 2016 2017 2018 TTM 123118Fiscal Year End

Net Debt Adjusted EBITDA(1) Capitalization

Debt Maturity Profile ($MM) Liquidity

Committed Credit FacilitiesShort-term Debt OutstandingAvailable Short-term Credit FacilitiesCash Balance at 123118 Total Liquidity at 123118

$ 750 MM0 MM

750 MM110 MM

$ 860 MM

$500 $549 $500

$300 $300

$0

$200

$400

$600

(1) Net Debt is net of cash and temporary cash investments Reconciliations of Net Debt and Adjusted EBITDA to Net Income are included at the end of this presentation

54

Appendix

55

Safe Harbor For Forward Looking StatementsThis presentation may contain ldquoforward-looking statementsrdquo as defined by the Private Securities Litigation Reform Act of 1995 including statements regarding future prospectsplans objectives goals projections estimates of oil and gas quantities strategies future events or performance and underlying assumptions capital structure anticipatedcapital expenditures completion of construction projects projections for pension and other post-retirement benefit obligations impacts of the adoption of new accounting rulesand possible outcomes of litigation or regulatory proceedings as well as statements that are identified by the use of the words ldquoanticipatesrdquo ldquoestimatesrdquo ldquoexpectsrdquo ldquoforecastsrdquoldquointendsrdquo ldquoplansrdquo ldquopredictsrdquo ldquoprojectsrdquo ldquobelievesrdquo ldquoseeksrdquo ldquowillrdquo ldquomayrdquo and similar expressions Forward-looking statements involve risks and uncertainties which couldcause actual results or outcomes to differ materially from those expressed in the forward-looking statements The Companyrsquos expectations beliefs and projections are expressedin good faith and are believed by the Company to have a reasonable basis but there can be no assurance that managementrsquos expectations beliefs or projections will result or beachieved or accomplished

In addition to other factors the following are important factors that could cause actual results to differ materially from those discussed in the forward-looking statements delaysor changes in costs or plans with respect to Company projects or related projects of other companies including difficulties or delays in obtaining necessary governmentalapprovals permits or orders or in obtaining the cooperation of interconnecting facility operators governmentalregulatory actions initiatives and proceedings including thoseinvolving rate cases (which address among other things target rates of return rate design and retained natural gas) environmentalsafety requirements affiliate relationshipsindustry structure and franchise renewal changes in laws regulations or judicial interpretations to which the Company is subject including those involving derivatives taxessafety employment climate change other environmental matters real property and exploration and production activities such as hydraulic fracturing financial and economicconditions including the availability of credit and occurrences affecting the Companyrsquos ability to obtain financing on acceptable terms for working capital capital expendituresand other investments including any downgrades in the Companyrsquos credit ratings and changes in interest rates and other capital market conditions changes in the price ofnatural gas or oil impairments under the SECrsquos full cost ceiling test for natural gas and oil reserves factors affecting the Companyrsquos ability to successfully identify drill for andproduce economically viable natural gas and oil reserves including among others geology lease availability title disputes weather conditions shortages delays orunavailability of equipment and services required in drilling operations insufficient gathering processing and transportation capacity the need to obtain governmentalapprovals and permits and compliance with environmental laws and regulations increasing health care costs and the resulting effect on health insurance premiums and on theobligation to provide other post-retirement benefits changes in price differentials between similar quantities of natural gas or oil sold at different geographic locations and theeffect of such changes on commodity production revenues and demand for pipeline transportation capacity to or from such locations other changes in price differentialsbetween similar quantities of natural gas or oil having different quality heating value hydrocarbon mix or delivery date the cost and effects of legal and administrative claimsagainst the Company or activist shareholder campaigns to effect changes at the Company uncertainty of oil and gas reserve estimates significant differences between theCompanyrsquos projected and actual production levels for natural gas or oil changes in demographic patterns and weather conditions changes in the availability price oraccounting treatment of derivative financial instruments changes in laws actuarial assumptions the interest rate environment and the return on plantrust assets related to theCompanyrsquos pension and other post-retirement benefits which can affect future funding obligations and costs and plan liabilities changes in economic conditions includingglobal national or regional recessions and their effect on the demand for and customersrsquo ability to pay for the Companyrsquos products and services the creditworthiness orperformance of the Companyrsquos key suppliers customers and counterparties the impact of potential information technology cybersecurity or data security breaches economicdisruptions or uninsured losses resulting from major accidents fires severe weather natural disasters terrorist activities or acts of war significant differences between theCompanyrsquos projected and actual capital expenditures and operating expenses or increasing costs of insurance changes in coverage and the ability to obtain insurance

Forward-looking statements include estimates of oil and gas quantities Proved oil and gas reserves are those quantities of oil and gas which by analysis of geoscience andengineering data can be estimated with reasonable certainty to be economically producible under existing economic conditions operating methods and governmentregulations Other estimates of oil and gas quantities including estimates of probable reserves possible reserves and resource potential are by their nature more speculativethan estimates of proved reserves Accordingly estimates other than proved reserves are subject to substantially greater risk of being actually realized Investors are urged toconsider closely the disclosure in our Form 10-K available at wwwnationalfuelgascom You can also obtain this form on the SECrsquos website at wwwsecgov

For a discussion of the risks set forth above and other factors that could cause actual results to differ materially from results referred to in the forward-looking statements seeldquoRisk Factorsrdquo in the Companyrsquos Form 10-K for the fiscal year ended September 30 2018 and the Forms 10-Q for the quarter ended March 31 2018 June 30 2018 and December31 2018 The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date thereof or to reflect the occurrence ofunanticipated events

Appendix

28

297000 ($061)

305200 ($061)

305600 ($063)

337000 ($057)

370800 ($024)

369600 ($060)

367900 ($067)

33400 ($070)74500 ($077) 74900 ($077)

81100 ($078)

85900 ($078)

92000 ($073)

91300 ($073)

178800 $255

196000 $234

195500 $234

149900 $232

129500 $230

105400 $222

104500 $222

~517800 509200 575700 576000 568000 586200 567000 563700

Q1 FY19 Q2 FY19 Q3 FY19 Q4 FY19 Q1 FY20 Q2 FY20 Q3 FY20 Q4 FY20

Fixed Price Dawn NYMEX

Near-term Firm Sales Provide Market amp Price Certainty

Net Contracted Firm Sales Volumes (Dth per day)Contracted Index Price Differentials ($ per Dth)(1)

(1) Values shown represent the weighted average fixed price or contracted fixed differential relative to NYMEX (netback price) less any associated transportation costs

Actual Daily Net

Production

641200 716500 708700 693500 708400 674400 667000Gross Firm Sales Volumes (Dthd)

EampP and Gathering

29

California Oil

Stable Oil Production | Minimal Capital Investment | Steady Free Cash Flow

1

2

3

4

5

Location Formation Production Method

FY18 Daily Production(net Boed)

1 East Coalinga Other Temblor Primary 512

2 North Lost Hills

Tulare amp Etchegoin

PrimarySteam flood 892

3 South Lost Hills

Monterey Shale Primary 1359

4 North Midway Sunset

Tulare amp Potter Steam flood 2786

5 South Midway Sunset Antelope Steam flood 2048

TOTAL WEST DIVISION NET PRODUCTION(1) 7597 Boed

EampP and Gathering

(1) West division net production for FY 2018 excludes production from Sespe field which was divested on May 1 2018

30

California Capital Expenditures vs Production

9341 8863

8033 ~7300

2016 2017 2018 2019

Fiscal Year

West Division Average Net Daily Production (Boe)West Division Annual Capital Expenditures ($ MM)(1)

$38 $38

$26 ~$25

2016 2017 2018 2019

Fiscal YearGuidance Guidance

(1) Seneca West Division capital expenditures includes Seneca corporate and eliminations

EampP and Gathering

Sepse Sale Closed on 5118(reduced production by ~900 boed)

31

Pioneer

South MWSS

Acreage

North MWSS

AcreageSec 17N

4149 51

NMWSS amp 17N SMWSS amp Pioneer East Coalinga

California Development Activities

Modest near-term capital program focused on locations that earn attractive returns in current oil price environment

AampD will focus on low cost bolt-on opportunities

Sec 17 Pioneer and East Coalinga development to provide future growth

North

Project IRRs at $55Bbl(1)

(1) Reflects pre-tax IRRs at a $55Bbl WTI

EampP and Gathering

Seneca West Economics

South

East Coalinga

North

South

32

Fiscal 2019 Production and Price Certainty

~49 Bcfe

210 ndash 230 Bcfe

~114 Bcf

~29 Bcf (2)

16+- Bcf~12 Bcfe

0

40

80

120

160

200

240

YTD FY19Actuals

Fixed Price + FirmSales w Hedge

Firm Sales(Unhedged)

Spot Sales California TotalSeneca

Prod

uctio

n (B

cfe)

(1) Average realized price reflects uplift from financial hedges less fixed differentials under firm sales contracts and any firm transportation costs(2) Indicates firm sales contracts with fixed index differentials but not backed by a matching financial hedge

114 Bcf locked-in realizing net ~$241Mcf (1)

29 Bcf of additional basis protection

Spot production assumed to be sold

at ~$275Mmbtu(winter) and ~$225

(summer)

143 Bcf of Appalachian Production Protected by Firm Sales for Remainder of Year

79 of oil production hedged at $5757 Bbl

EampP and Gathering

33

Strong Hedge Book

Natural Gas Swap amp Fixed Physical Sales Contracts (Millions MMBtu)

(1) Fixed price physical sales exclude joint development partnerrsquos share of fixed price contract WDA volumes as specified under the joint development agreement(2) Reflects percentage of projected production for FY19 hedged at the midpoint of the production guidance range(3) Senecarsquos remainder FY19 Production reflects the total FY19 production guidance of 210-230 Bcfe or 220 Bcfe at the midpoint less Q1 actual production

Crude Oil Swap Contracts (Thousands Bbls)

13591188

732

456

0

500

1000

1500

2000

2500

FY 2019 FY 2020 FY 2021 FY 2022

NYMEX (WTI)

Brent

FY 19 Crude Oil79 Hedged (2)

FY 2019 Remaining Production (3)

EampP and Gathering

1174

709

469 406

0

50

100

150

200

250

FY 2019 FY 2020 FY 2021 FY 2022

NYMEX Swaps

Dawn Swaps

Fixed Price Physical Sales

(1)

FY 2019 Remaining Production (3)

FY 19 Nat Gas71 Hedged (2)

34

$065 $070$070 -$075

FY 2017 FY 2018 FY 2019E

$060 $060 $060

$011 $009 $007$071 $069 ~$067

FY 2017 FY 2018 FY 2019E Gathering amp Transport LOE (non-Gathering) GampA Taxes amp Other

Seneca Operating Costs

Competitive low cost structure in Appalachia and California supports strong cash margins

Gathering fee generates significant revenue stream for affiliated gathering company

Seneca DDampARate

$Mcfe

$054 $054 $056

$042 $038 $031

$034 $034 $030

$017 $014 $015

$147 $140 ~$132

FY 2017 FY 2018 FY 2019E

(1)

$1791$1746~$2050

FY 2017 FY 2018 FY 2019E

Appalachia LOE amp Gathering $Mcfe

California LOE$Boe

Total Seneca Cash OpEx$Mcfe

(1)

(2)

(2)

(1) GampA estimate represents the midpoint of the GampA guidance range of $025 to $035 for fiscal 2019(2) The total of the two LOE components represents the midpoint of the LOE guidance range of $085 to $090 for fiscal 2019

EampP and Gathering

35

Senecarsquos Continuing Commitment to the Environment

Produced Water Recycled in Appalachia

100 70Recycled Water

Used in New Shale Well

Completions

Water and Fluids Management Air Quality and Emissions

Seneca Resources Water OperationsFiscal 2018

Seneca Resources Remains Focused on Minimizing GHG Emissions

The Environmental Partnership

EPA Natural Gas Star Program

Green Completions (all fiscal 2018 wells)

Ultrasonic Leak Detection Technology

Emissions Controls

Rig and Vehicle Fuel Conversion

Integrating Renewable Energy into Operations

EampP and Gathering

36

Pipeline and Storage OverviewNational Fuel Gas Supply Corporation ~ Empire Pipeline Inc

37

Pipeline amp Storage Segment Overview

(1) As of September 30 2018 as disclosed in the Companyrsquos fiscal 2018 form 10-K(2) As of December 31 2017 calculated from National Fuel Gas Supply Corporationrsquos and Empire Pipeline Incrsquos 2017 FERC Form-2 reports respectively

Empire Pipeline Inc

National Fuel Gas Supply Corporation

Empire Pipeline

Supply Corp

Contracted Capacity(1) Firm Transportation 3187 MDth per day Firm Storage 71938 Mdth (fully subscribed)

Rate Base(2) ~$820 million FERC Rate Proceeding Status

Rate case settlement extension approved Nov lsquo15 Rate case filing expected by 73119

Contracted Capacity(1) Firm Transportation 978 MDth per day Firm Storage 3753 Mdth (fully subscribed)

Rate Base(2) ~$249 million FERC Rate Proceeding Status

Rate case settlement in principle reached on 122118 FERC approval pending

New transportation rates went into on 1119

Pipeline amp Storage

38

All Seneca volumes will flow through wholly-owned NFG gathering facilities

FM100 Project - Consolidated Benefit for NFG

330000 Dthd of new transportation capacity from WDA and EDA acreage positions to premium markets

New Transco capacity (Leidy South) 330000 Dthday

Rate(1) competitive with other expansion project rates in Senecarsquos current transportation portfolio

Delivery Point(s) Transco Zone 6 interconnections

Seneca

Lease to Transco of new capacity 330000 Dthday

Estimated annual lease revenues ~$35 million

Target In-Service late calendar year 2021

Supply Corp

Project expected to provide long-term earnings uplift to Seneca Supply Corp and Gathering

Pipeline amp Storage

Gathering

(1) Includes lease of new capacity from Supply Corp to Transco

39

FM100 Project ndash Significant Investment by Supply Corp

Pipeline amp Storage

Estimated Capital Cost $280 million(1)

Facilities (all in Pennsylvania) include Approximately 30 miles of new pipeline 2 new compressor stations (totaling

approximately 37000 HP) New interconnection station and modification

of existing interconnection station Abandonment of approximately 45 miles of

existing pipeline and compressor station Regulatory Process

Pre-filing application submitted to FERC in 2017 for original modernization project

FERC 7(b) 7(c) filing expected summer 2019

(1) Includes expansion and modernization portions of the project

40

Empire North Project

Target In-Service second half of fiscal 2020

Est Capital Cost $145 million

Est Annual Revenues ~$25 million

Receipt Point Jackson (Tioga Co Pa production)

Design Capacity and Delivery Points 175000 Dthd to Chippawa (TCPL interconnect)

30000 Dthd to Hopewell (TGP 200 interconnect)

Customers Fully subscribed (205000 Dthday)

Major Facilities 2 new compressor stations in NY (1) amp Pa (1)

No new pipeline construction

Regulatory Process FERC 7(c) application filed on 21618

FERC Environmental Assessment issued 103018

Pipeline amp Storage

Fully Subscribed Project will Provide 205000 Dthday of Incremental Firm Transportation

41

National Fuel Remains Committed to Northern Access Project

Target In-Service as early as fiscal 2022

Total Cost ~$500MM (~$76MM spent to date)

Estimated Annual Revenues ~$84 million

Delivery Points

350000 Dthd to Chippawa (TCPL interconnect)

140000 Dthd to Hopewell (TGP 200 line)

Regulatory Status

February 3 2017 ndash FERC 7(c) certificate issued

August 6 2018 ndash FERC issued Order finding that NY DEC waived water quality certification

Supply and Empire currently working to finalize remaining federal authorizations

Pipeline amp Storage

To Dawn

42

Continued Expansion of the NFG Supply System

Line N Expansion Opportunities

Line N to Monaca Project Project Firm transportation service to a new ethane

cracker facility being built by Shell Chemical Appalachia LLC

Target In-Service July 2019

Estimated Capital Cost $23 million

Contracted Capacity 133000 Dthday

Additional Line N Expansion Opportunity (Supply OS 221) Project New firm transportation service for on-system

demand

Open Season Capacity Awarded 165000 to foundation shipper Precedent agreement in negotiations

Pipeline amp Storage

43

Pipeline amp Storage Customer Mix

Producer33

LDC42

Marketer10

Outside Pipeline

9

End User6

42 MMDthd

(1) Contracted as of 10312018

Customer Transportation by Shipper Type(1) Affiliated Customer Mix (Contracted Capacity)

66

521

41

34

9579

59

LDCs Producers Marketers FirmStorage

Affiliated Non-Affiliated

Firm Transport

Pipeline amp Storage

44

Utility OverviewNational Fuel Gas Distribution Corporation

45

New York amp Pennsylvania Service Territories

New York

Total Customers(1) 535800ROE 87 (NY PSC Rate Case Order April 2017)Rate Mechanismso Revenue Decouplingo Weather Normalizationo Low Income Rateso Merchant Function Charge (Uncollectibles Adj)o 9010 Sharing (Large Customers)o System Modernization Tracker

Pennsylvania

Total Customers(1) 214400ROE Black Box Settlement (2007)Rate Mechanismso Low Income Rateso Merchant Function Charge

(1) As of September 30 2018

Utility

46

New York Rate Case Outcome

Rate Order Summary

Revenue Requirement $59 million

Rate Base $704 million

Allowed Return on Equity (ROE) 87

Capital Structure 429 equity

Other notable items

New rates became effective 5117

Retains rate mechanisms in place under prior order (revenue decoupling weather normalization merchant function charge 9010 large customer sharing)

No stay-out clause

System modernization tracker for Leak Prone Pipe (LPP)

Earnings sharing started 4118 (5050 sharing starts at earnings in excess of 92)

Article 78 appeal filed on 72817 with oral argument completed in January 2019

On April 20 2017 the New York Public Service Commission issued a Rate Order relating to NFG Distributionrsquos rate case (No 16-G-0257) filed in April 2016

Utility

47

Utility Continues its Significant Investments in Safety

$544$618 $636

$699

$944$980

$809$856

$90-100

$00

$250

$500

$750

$1000

$1250

2015 2016 2017 2018 2019E

Cap

ital E

xpen

ditu

res

($ m

illio

ns)

Fiscal Year

Capital Expenditures for Safety Total Capital Expenditures

Modernization Spending in NY Expected to Grow Gross Margin By $2 MM - $5 MM in FY 2019

(1)

(1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation

Utility

System modernization tracker in NY allows recovery of pipeline replacementcosts which is expected to drive modest gross margin and rate base growth

48

Accelerating Pipeline Replacement amp Modernization

Wrought Iron

Plastic

CoatedBare

120130

146 144159

2014 2015 2016 2017 2018Calendar Year

NY9726 miles

PA4830 miles

No Cast Iron Mains in Pa

Miles of Utility Main Pipeline ReplacedUtility Mains by Material(1)

Wrought Iron

Cast Iron

Plastic

Coated Bare

Utility

(1) All values are reported on a calendar year basis as of December 31 2018

49

A Proven History of Controlling Costs

$200 $189 $195

$166 $166

$31 $31

$197 $197

$0

$50

$100

$150

$200

$250

2015 2016 2017 2018 TTM 123118

Fiscal Year

OampM Expense Non-Service Pension Costs

OampM Expense ($ millions)

Utility

(1)

(1) For purposes of comparability to FY 2015 2016 and 2017 Utility Operation and Maintenance Expense for FY 2018 and the twelve months ended December 31 2018 was adjusted by approximately $314 million and $312 million respectively to include non-service pension costs which were re-classified as Other Income (Deductions) as of October 1 2018 on the Companyrsquos Income Statement See Slide 64 for non-GAAP reconciliation of Adjusted Operation and Maintenance Expense to Operation and Maintenance Expense by segment

50

Consolidated Financial OverviewUpstream I Midstream I Downstream

51

Adjusted Operating Results ($ per share)(1)

Diversified Balanced Earnings and Cash Flows

(1) A reconciliation of Adjusted Operating Results to Earnings per Share by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation(2) Consolidated Adjusted EBITDA includes Energy Marketing and Corporate amp All Other Segments A reconciliation of Adjusted EBITDA to Net Income by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in

the Business is included at the end of this presentation

Adjusted EBITDA ($ millions)(2)

$176 $179

$184 $181

$92 $97

$318 $327

$761 $775

$-

$200

$400

$600

$800

FY 2018 TTM 123118

$059 Utility

$097 Pipeline amp Storage

$057 Gathering

$125 Exploration

amp Production

$334 $345 to $365

$-

$100

$200

$300

$400

FY 2018 FY 2019 Guidance

Rate Regulated

40-45

$728

Rate Regulated

~46

52

$89 $94 $98 $81 $86 $90-$100

$140$230

$114 $95 $93 $120-$150

$138$118

$54$33 $48

$55-$65

$603$557

$99 $246$356

$460-$495

$970 $1001

$366$455

$583

$725-$810

$0

$250

$500

$750

$1000

$1250

2014 2015 2016 2017 2018 2019GuidanceFiscal Year

Exploration amp Production

Gathering

Pipeline amp Storage

Utility

Disciplined Flexible Capital Allocation

(2)

(1) Total Capital Expenditures include Energy Marketing Corporate and All Other A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation (2) FY16 FY17 and FY18 reflects the netting of $157 million $7 million and $17 million respectively of up-front proceeds received from joint development partner for working interest in joint development wells and $21M in intercompany asset transfers in FY18

Capital Expenditures by Segment ($ millions)(1)

53

Maintaining Strong Balance Sheet amp Liquidity

Total Equity49

Total Debt51

$42 Billion Total Capitalizationas of December 31 2018

218 x251 x 245 x 247 x 256 x

2015 2016 2017 2018 TTM 123118Fiscal Year End

Net Debt Adjusted EBITDA(1) Capitalization

Debt Maturity Profile ($MM) Liquidity

Committed Credit FacilitiesShort-term Debt OutstandingAvailable Short-term Credit FacilitiesCash Balance at 123118 Total Liquidity at 123118

$ 750 MM0 MM

750 MM110 MM

$ 860 MM

$500 $549 $500

$300 $300

$0

$200

$400

$600

(1) Net Debt is net of cash and temporary cash investments Reconciliations of Net Debt and Adjusted EBITDA to Net Income are included at the end of this presentation

54

Appendix

55

Safe Harbor For Forward Looking StatementsThis presentation may contain ldquoforward-looking statementsrdquo as defined by the Private Securities Litigation Reform Act of 1995 including statements regarding future prospectsplans objectives goals projections estimates of oil and gas quantities strategies future events or performance and underlying assumptions capital structure anticipatedcapital expenditures completion of construction projects projections for pension and other post-retirement benefit obligations impacts of the adoption of new accounting rulesand possible outcomes of litigation or regulatory proceedings as well as statements that are identified by the use of the words ldquoanticipatesrdquo ldquoestimatesrdquo ldquoexpectsrdquo ldquoforecastsrdquoldquointendsrdquo ldquoplansrdquo ldquopredictsrdquo ldquoprojectsrdquo ldquobelievesrdquo ldquoseeksrdquo ldquowillrdquo ldquomayrdquo and similar expressions Forward-looking statements involve risks and uncertainties which couldcause actual results or outcomes to differ materially from those expressed in the forward-looking statements The Companyrsquos expectations beliefs and projections are expressedin good faith and are believed by the Company to have a reasonable basis but there can be no assurance that managementrsquos expectations beliefs or projections will result or beachieved or accomplished

In addition to other factors the following are important factors that could cause actual results to differ materially from those discussed in the forward-looking statements delaysor changes in costs or plans with respect to Company projects or related projects of other companies including difficulties or delays in obtaining necessary governmentalapprovals permits or orders or in obtaining the cooperation of interconnecting facility operators governmentalregulatory actions initiatives and proceedings including thoseinvolving rate cases (which address among other things target rates of return rate design and retained natural gas) environmentalsafety requirements affiliate relationshipsindustry structure and franchise renewal changes in laws regulations or judicial interpretations to which the Company is subject including those involving derivatives taxessafety employment climate change other environmental matters real property and exploration and production activities such as hydraulic fracturing financial and economicconditions including the availability of credit and occurrences affecting the Companyrsquos ability to obtain financing on acceptable terms for working capital capital expendituresand other investments including any downgrades in the Companyrsquos credit ratings and changes in interest rates and other capital market conditions changes in the price ofnatural gas or oil impairments under the SECrsquos full cost ceiling test for natural gas and oil reserves factors affecting the Companyrsquos ability to successfully identify drill for andproduce economically viable natural gas and oil reserves including among others geology lease availability title disputes weather conditions shortages delays orunavailability of equipment and services required in drilling operations insufficient gathering processing and transportation capacity the need to obtain governmentalapprovals and permits and compliance with environmental laws and regulations increasing health care costs and the resulting effect on health insurance premiums and on theobligation to provide other post-retirement benefits changes in price differentials between similar quantities of natural gas or oil sold at different geographic locations and theeffect of such changes on commodity production revenues and demand for pipeline transportation capacity to or from such locations other changes in price differentialsbetween similar quantities of natural gas or oil having different quality heating value hydrocarbon mix or delivery date the cost and effects of legal and administrative claimsagainst the Company or activist shareholder campaigns to effect changes at the Company uncertainty of oil and gas reserve estimates significant differences between theCompanyrsquos projected and actual production levels for natural gas or oil changes in demographic patterns and weather conditions changes in the availability price oraccounting treatment of derivative financial instruments changes in laws actuarial assumptions the interest rate environment and the return on plantrust assets related to theCompanyrsquos pension and other post-retirement benefits which can affect future funding obligations and costs and plan liabilities changes in economic conditions includingglobal national or regional recessions and their effect on the demand for and customersrsquo ability to pay for the Companyrsquos products and services the creditworthiness orperformance of the Companyrsquos key suppliers customers and counterparties the impact of potential information technology cybersecurity or data security breaches economicdisruptions or uninsured losses resulting from major accidents fires severe weather natural disasters terrorist activities or acts of war significant differences between theCompanyrsquos projected and actual capital expenditures and operating expenses or increasing costs of insurance changes in coverage and the ability to obtain insurance

Forward-looking statements include estimates of oil and gas quantities Proved oil and gas reserves are those quantities of oil and gas which by analysis of geoscience andengineering data can be estimated with reasonable certainty to be economically producible under existing economic conditions operating methods and governmentregulations Other estimates of oil and gas quantities including estimates of probable reserves possible reserves and resource potential are by their nature more speculativethan estimates of proved reserves Accordingly estimates other than proved reserves are subject to substantially greater risk of being actually realized Investors are urged toconsider closely the disclosure in our Form 10-K available at wwwnationalfuelgascom You can also obtain this form on the SECrsquos website at wwwsecgov

For a discussion of the risks set forth above and other factors that could cause actual results to differ materially from results referred to in the forward-looking statements seeldquoRisk Factorsrdquo in the Companyrsquos Form 10-K for the fiscal year ended September 30 2018 and the Forms 10-Q for the quarter ended March 31 2018 June 30 2018 and December31 2018 The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date thereof or to reflect the occurrence ofunanticipated events

Appendix

29

California Oil

Stable Oil Production | Minimal Capital Investment | Steady Free Cash Flow

1

2

3

4

5

Location Formation Production Method

FY18 Daily Production(net Boed)

1 East Coalinga Other Temblor Primary 512

2 North Lost Hills

Tulare amp Etchegoin

PrimarySteam flood 892

3 South Lost Hills

Monterey Shale Primary 1359

4 North Midway Sunset

Tulare amp Potter Steam flood 2786

5 South Midway Sunset Antelope Steam flood 2048

TOTAL WEST DIVISION NET PRODUCTION(1) 7597 Boed

EampP and Gathering

(1) West division net production for FY 2018 excludes production from Sespe field which was divested on May 1 2018

30

California Capital Expenditures vs Production

9341 8863

8033 ~7300

2016 2017 2018 2019

Fiscal Year

West Division Average Net Daily Production (Boe)West Division Annual Capital Expenditures ($ MM)(1)

$38 $38

$26 ~$25

2016 2017 2018 2019

Fiscal YearGuidance Guidance

(1) Seneca West Division capital expenditures includes Seneca corporate and eliminations

EampP and Gathering

Sepse Sale Closed on 5118(reduced production by ~900 boed)

31

Pioneer

South MWSS

Acreage

North MWSS

AcreageSec 17N

4149 51

NMWSS amp 17N SMWSS amp Pioneer East Coalinga

California Development Activities

Modest near-term capital program focused on locations that earn attractive returns in current oil price environment

AampD will focus on low cost bolt-on opportunities

Sec 17 Pioneer and East Coalinga development to provide future growth

North

Project IRRs at $55Bbl(1)

(1) Reflects pre-tax IRRs at a $55Bbl WTI

EampP and Gathering

Seneca West Economics

South

East Coalinga

North

South

32

Fiscal 2019 Production and Price Certainty

~49 Bcfe

210 ndash 230 Bcfe

~114 Bcf

~29 Bcf (2)

16+- Bcf~12 Bcfe

0

40

80

120

160

200

240

YTD FY19Actuals

Fixed Price + FirmSales w Hedge

Firm Sales(Unhedged)

Spot Sales California TotalSeneca

Prod

uctio

n (B

cfe)

(1) Average realized price reflects uplift from financial hedges less fixed differentials under firm sales contracts and any firm transportation costs(2) Indicates firm sales contracts with fixed index differentials but not backed by a matching financial hedge

114 Bcf locked-in realizing net ~$241Mcf (1)

29 Bcf of additional basis protection

Spot production assumed to be sold

at ~$275Mmbtu(winter) and ~$225

(summer)

143 Bcf of Appalachian Production Protected by Firm Sales for Remainder of Year

79 of oil production hedged at $5757 Bbl

EampP and Gathering

33

Strong Hedge Book

Natural Gas Swap amp Fixed Physical Sales Contracts (Millions MMBtu)

(1) Fixed price physical sales exclude joint development partnerrsquos share of fixed price contract WDA volumes as specified under the joint development agreement(2) Reflects percentage of projected production for FY19 hedged at the midpoint of the production guidance range(3) Senecarsquos remainder FY19 Production reflects the total FY19 production guidance of 210-230 Bcfe or 220 Bcfe at the midpoint less Q1 actual production

Crude Oil Swap Contracts (Thousands Bbls)

13591188

732

456

0

500

1000

1500

2000

2500

FY 2019 FY 2020 FY 2021 FY 2022

NYMEX (WTI)

Brent

FY 19 Crude Oil79 Hedged (2)

FY 2019 Remaining Production (3)

EampP and Gathering

1174

709

469 406

0

50

100

150

200

250

FY 2019 FY 2020 FY 2021 FY 2022

NYMEX Swaps

Dawn Swaps

Fixed Price Physical Sales

(1)

FY 2019 Remaining Production (3)

FY 19 Nat Gas71 Hedged (2)

34

$065 $070$070 -$075

FY 2017 FY 2018 FY 2019E

$060 $060 $060

$011 $009 $007$071 $069 ~$067

FY 2017 FY 2018 FY 2019E Gathering amp Transport LOE (non-Gathering) GampA Taxes amp Other

Seneca Operating Costs

Competitive low cost structure in Appalachia and California supports strong cash margins

Gathering fee generates significant revenue stream for affiliated gathering company

Seneca DDampARate

$Mcfe

$054 $054 $056

$042 $038 $031

$034 $034 $030

$017 $014 $015

$147 $140 ~$132

FY 2017 FY 2018 FY 2019E

(1)

$1791$1746~$2050

FY 2017 FY 2018 FY 2019E

Appalachia LOE amp Gathering $Mcfe

California LOE$Boe

Total Seneca Cash OpEx$Mcfe

(1)

(2)

(2)

(1) GampA estimate represents the midpoint of the GampA guidance range of $025 to $035 for fiscal 2019(2) The total of the two LOE components represents the midpoint of the LOE guidance range of $085 to $090 for fiscal 2019

EampP and Gathering

35

Senecarsquos Continuing Commitment to the Environment

Produced Water Recycled in Appalachia

100 70Recycled Water

Used in New Shale Well

Completions

Water and Fluids Management Air Quality and Emissions

Seneca Resources Water OperationsFiscal 2018

Seneca Resources Remains Focused on Minimizing GHG Emissions

The Environmental Partnership

EPA Natural Gas Star Program

Green Completions (all fiscal 2018 wells)

Ultrasonic Leak Detection Technology

Emissions Controls

Rig and Vehicle Fuel Conversion

Integrating Renewable Energy into Operations

EampP and Gathering

36

Pipeline and Storage OverviewNational Fuel Gas Supply Corporation ~ Empire Pipeline Inc

37

Pipeline amp Storage Segment Overview

(1) As of September 30 2018 as disclosed in the Companyrsquos fiscal 2018 form 10-K(2) As of December 31 2017 calculated from National Fuel Gas Supply Corporationrsquos and Empire Pipeline Incrsquos 2017 FERC Form-2 reports respectively

Empire Pipeline Inc

National Fuel Gas Supply Corporation

Empire Pipeline

Supply Corp

Contracted Capacity(1) Firm Transportation 3187 MDth per day Firm Storage 71938 Mdth (fully subscribed)

Rate Base(2) ~$820 million FERC Rate Proceeding Status

Rate case settlement extension approved Nov lsquo15 Rate case filing expected by 73119

Contracted Capacity(1) Firm Transportation 978 MDth per day Firm Storage 3753 Mdth (fully subscribed)

Rate Base(2) ~$249 million FERC Rate Proceeding Status

Rate case settlement in principle reached on 122118 FERC approval pending

New transportation rates went into on 1119

Pipeline amp Storage

38

All Seneca volumes will flow through wholly-owned NFG gathering facilities

FM100 Project - Consolidated Benefit for NFG

330000 Dthd of new transportation capacity from WDA and EDA acreage positions to premium markets

New Transco capacity (Leidy South) 330000 Dthday

Rate(1) competitive with other expansion project rates in Senecarsquos current transportation portfolio

Delivery Point(s) Transco Zone 6 interconnections

Seneca

Lease to Transco of new capacity 330000 Dthday

Estimated annual lease revenues ~$35 million

Target In-Service late calendar year 2021

Supply Corp

Project expected to provide long-term earnings uplift to Seneca Supply Corp and Gathering

Pipeline amp Storage

Gathering

(1) Includes lease of new capacity from Supply Corp to Transco

39

FM100 Project ndash Significant Investment by Supply Corp

Pipeline amp Storage

Estimated Capital Cost $280 million(1)

Facilities (all in Pennsylvania) include Approximately 30 miles of new pipeline 2 new compressor stations (totaling

approximately 37000 HP) New interconnection station and modification

of existing interconnection station Abandonment of approximately 45 miles of

existing pipeline and compressor station Regulatory Process

Pre-filing application submitted to FERC in 2017 for original modernization project

FERC 7(b) 7(c) filing expected summer 2019

(1) Includes expansion and modernization portions of the project

40

Empire North Project

Target In-Service second half of fiscal 2020

Est Capital Cost $145 million

Est Annual Revenues ~$25 million

Receipt Point Jackson (Tioga Co Pa production)

Design Capacity and Delivery Points 175000 Dthd to Chippawa (TCPL interconnect)

30000 Dthd to Hopewell (TGP 200 interconnect)

Customers Fully subscribed (205000 Dthday)

Major Facilities 2 new compressor stations in NY (1) amp Pa (1)

No new pipeline construction

Regulatory Process FERC 7(c) application filed on 21618

FERC Environmental Assessment issued 103018

Pipeline amp Storage

Fully Subscribed Project will Provide 205000 Dthday of Incremental Firm Transportation

41

National Fuel Remains Committed to Northern Access Project

Target In-Service as early as fiscal 2022

Total Cost ~$500MM (~$76MM spent to date)

Estimated Annual Revenues ~$84 million

Delivery Points

350000 Dthd to Chippawa (TCPL interconnect)

140000 Dthd to Hopewell (TGP 200 line)

Regulatory Status

February 3 2017 ndash FERC 7(c) certificate issued

August 6 2018 ndash FERC issued Order finding that NY DEC waived water quality certification

Supply and Empire currently working to finalize remaining federal authorizations

Pipeline amp Storage

To Dawn

42

Continued Expansion of the NFG Supply System

Line N Expansion Opportunities

Line N to Monaca Project Project Firm transportation service to a new ethane

cracker facility being built by Shell Chemical Appalachia LLC

Target In-Service July 2019

Estimated Capital Cost $23 million

Contracted Capacity 133000 Dthday

Additional Line N Expansion Opportunity (Supply OS 221) Project New firm transportation service for on-system

demand

Open Season Capacity Awarded 165000 to foundation shipper Precedent agreement in negotiations

Pipeline amp Storage

43

Pipeline amp Storage Customer Mix

Producer33

LDC42

Marketer10

Outside Pipeline

9

End User6

42 MMDthd

(1) Contracted as of 10312018

Customer Transportation by Shipper Type(1) Affiliated Customer Mix (Contracted Capacity)

66

521

41

34

9579

59

LDCs Producers Marketers FirmStorage

Affiliated Non-Affiliated

Firm Transport

Pipeline amp Storage

44

Utility OverviewNational Fuel Gas Distribution Corporation

45

New York amp Pennsylvania Service Territories

New York

Total Customers(1) 535800ROE 87 (NY PSC Rate Case Order April 2017)Rate Mechanismso Revenue Decouplingo Weather Normalizationo Low Income Rateso Merchant Function Charge (Uncollectibles Adj)o 9010 Sharing (Large Customers)o System Modernization Tracker

Pennsylvania

Total Customers(1) 214400ROE Black Box Settlement (2007)Rate Mechanismso Low Income Rateso Merchant Function Charge

(1) As of September 30 2018

Utility

46

New York Rate Case Outcome

Rate Order Summary

Revenue Requirement $59 million

Rate Base $704 million

Allowed Return on Equity (ROE) 87

Capital Structure 429 equity

Other notable items

New rates became effective 5117

Retains rate mechanisms in place under prior order (revenue decoupling weather normalization merchant function charge 9010 large customer sharing)

No stay-out clause

System modernization tracker for Leak Prone Pipe (LPP)

Earnings sharing started 4118 (5050 sharing starts at earnings in excess of 92)

Article 78 appeal filed on 72817 with oral argument completed in January 2019

On April 20 2017 the New York Public Service Commission issued a Rate Order relating to NFG Distributionrsquos rate case (No 16-G-0257) filed in April 2016

Utility

47

Utility Continues its Significant Investments in Safety

$544$618 $636

$699

$944$980

$809$856

$90-100

$00

$250

$500

$750

$1000

$1250

2015 2016 2017 2018 2019E

Cap

ital E

xpen

ditu

res

($ m

illio

ns)

Fiscal Year

Capital Expenditures for Safety Total Capital Expenditures

Modernization Spending in NY Expected to Grow Gross Margin By $2 MM - $5 MM in FY 2019

(1)

(1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation

Utility

System modernization tracker in NY allows recovery of pipeline replacementcosts which is expected to drive modest gross margin and rate base growth

48

Accelerating Pipeline Replacement amp Modernization

Wrought Iron

Plastic

CoatedBare

120130

146 144159

2014 2015 2016 2017 2018Calendar Year

NY9726 miles

PA4830 miles

No Cast Iron Mains in Pa

Miles of Utility Main Pipeline ReplacedUtility Mains by Material(1)

Wrought Iron

Cast Iron

Plastic

Coated Bare

Utility

(1) All values are reported on a calendar year basis as of December 31 2018

49

A Proven History of Controlling Costs

$200 $189 $195

$166 $166

$31 $31

$197 $197

$0

$50

$100

$150

$200

$250

2015 2016 2017 2018 TTM 123118

Fiscal Year

OampM Expense Non-Service Pension Costs

OampM Expense ($ millions)

Utility

(1)

(1) For purposes of comparability to FY 2015 2016 and 2017 Utility Operation and Maintenance Expense for FY 2018 and the twelve months ended December 31 2018 was adjusted by approximately $314 million and $312 million respectively to include non-service pension costs which were re-classified as Other Income (Deductions) as of October 1 2018 on the Companyrsquos Income Statement See Slide 64 for non-GAAP reconciliation of Adjusted Operation and Maintenance Expense to Operation and Maintenance Expense by segment

50

Consolidated Financial OverviewUpstream I Midstream I Downstream

51

Adjusted Operating Results ($ per share)(1)

Diversified Balanced Earnings and Cash Flows

(1) A reconciliation of Adjusted Operating Results to Earnings per Share by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation(2) Consolidated Adjusted EBITDA includes Energy Marketing and Corporate amp All Other Segments A reconciliation of Adjusted EBITDA to Net Income by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in

the Business is included at the end of this presentation

Adjusted EBITDA ($ millions)(2)

$176 $179

$184 $181

$92 $97

$318 $327

$761 $775

$-

$200

$400

$600

$800

FY 2018 TTM 123118

$059 Utility

$097 Pipeline amp Storage

$057 Gathering

$125 Exploration

amp Production

$334 $345 to $365

$-

$100

$200

$300

$400

FY 2018 FY 2019 Guidance

Rate Regulated

40-45

$728

Rate Regulated

~46

52

$89 $94 $98 $81 $86 $90-$100

$140$230

$114 $95 $93 $120-$150

$138$118

$54$33 $48

$55-$65

$603$557

$99 $246$356

$460-$495

$970 $1001

$366$455

$583

$725-$810

$0

$250

$500

$750

$1000

$1250

2014 2015 2016 2017 2018 2019GuidanceFiscal Year

Exploration amp Production

Gathering

Pipeline amp Storage

Utility

Disciplined Flexible Capital Allocation

(2)

(1) Total Capital Expenditures include Energy Marketing Corporate and All Other A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation (2) FY16 FY17 and FY18 reflects the netting of $157 million $7 million and $17 million respectively of up-front proceeds received from joint development partner for working interest in joint development wells and $21M in intercompany asset transfers in FY18

Capital Expenditures by Segment ($ millions)(1)

53

Maintaining Strong Balance Sheet amp Liquidity

Total Equity49

Total Debt51

$42 Billion Total Capitalizationas of December 31 2018

218 x251 x 245 x 247 x 256 x

2015 2016 2017 2018 TTM 123118Fiscal Year End

Net Debt Adjusted EBITDA(1) Capitalization

Debt Maturity Profile ($MM) Liquidity

Committed Credit FacilitiesShort-term Debt OutstandingAvailable Short-term Credit FacilitiesCash Balance at 123118 Total Liquidity at 123118

$ 750 MM0 MM

750 MM110 MM

$ 860 MM

$500 $549 $500

$300 $300

$0

$200

$400

$600

(1) Net Debt is net of cash and temporary cash investments Reconciliations of Net Debt and Adjusted EBITDA to Net Income are included at the end of this presentation

54

Appendix

55

Safe Harbor For Forward Looking StatementsThis presentation may contain ldquoforward-looking statementsrdquo as defined by the Private Securities Litigation Reform Act of 1995 including statements regarding future prospectsplans objectives goals projections estimates of oil and gas quantities strategies future events or performance and underlying assumptions capital structure anticipatedcapital expenditures completion of construction projects projections for pension and other post-retirement benefit obligations impacts of the adoption of new accounting rulesand possible outcomes of litigation or regulatory proceedings as well as statements that are identified by the use of the words ldquoanticipatesrdquo ldquoestimatesrdquo ldquoexpectsrdquo ldquoforecastsrdquoldquointendsrdquo ldquoplansrdquo ldquopredictsrdquo ldquoprojectsrdquo ldquobelievesrdquo ldquoseeksrdquo ldquowillrdquo ldquomayrdquo and similar expressions Forward-looking statements involve risks and uncertainties which couldcause actual results or outcomes to differ materially from those expressed in the forward-looking statements The Companyrsquos expectations beliefs and projections are expressedin good faith and are believed by the Company to have a reasonable basis but there can be no assurance that managementrsquos expectations beliefs or projections will result or beachieved or accomplished

In addition to other factors the following are important factors that could cause actual results to differ materially from those discussed in the forward-looking statements delaysor changes in costs or plans with respect to Company projects or related projects of other companies including difficulties or delays in obtaining necessary governmentalapprovals permits or orders or in obtaining the cooperation of interconnecting facility operators governmentalregulatory actions initiatives and proceedings including thoseinvolving rate cases (which address among other things target rates of return rate design and retained natural gas) environmentalsafety requirements affiliate relationshipsindustry structure and franchise renewal changes in laws regulations or judicial interpretations to which the Company is subject including those involving derivatives taxessafety employment climate change other environmental matters real property and exploration and production activities such as hydraulic fracturing financial and economicconditions including the availability of credit and occurrences affecting the Companyrsquos ability to obtain financing on acceptable terms for working capital capital expendituresand other investments including any downgrades in the Companyrsquos credit ratings and changes in interest rates and other capital market conditions changes in the price ofnatural gas or oil impairments under the SECrsquos full cost ceiling test for natural gas and oil reserves factors affecting the Companyrsquos ability to successfully identify drill for andproduce economically viable natural gas and oil reserves including among others geology lease availability title disputes weather conditions shortages delays orunavailability of equipment and services required in drilling operations insufficient gathering processing and transportation capacity the need to obtain governmentalapprovals and permits and compliance with environmental laws and regulations increasing health care costs and the resulting effect on health insurance premiums and on theobligation to provide other post-retirement benefits changes in price differentials between similar quantities of natural gas or oil sold at different geographic locations and theeffect of such changes on commodity production revenues and demand for pipeline transportation capacity to or from such locations other changes in price differentialsbetween similar quantities of natural gas or oil having different quality heating value hydrocarbon mix or delivery date the cost and effects of legal and administrative claimsagainst the Company or activist shareholder campaigns to effect changes at the Company uncertainty of oil and gas reserve estimates significant differences between theCompanyrsquos projected and actual production levels for natural gas or oil changes in demographic patterns and weather conditions changes in the availability price oraccounting treatment of derivative financial instruments changes in laws actuarial assumptions the interest rate environment and the return on plantrust assets related to theCompanyrsquos pension and other post-retirement benefits which can affect future funding obligations and costs and plan liabilities changes in economic conditions includingglobal national or regional recessions and their effect on the demand for and customersrsquo ability to pay for the Companyrsquos products and services the creditworthiness orperformance of the Companyrsquos key suppliers customers and counterparties the impact of potential information technology cybersecurity or data security breaches economicdisruptions or uninsured losses resulting from major accidents fires severe weather natural disasters terrorist activities or acts of war significant differences between theCompanyrsquos projected and actual capital expenditures and operating expenses or increasing costs of insurance changes in coverage and the ability to obtain insurance

Forward-looking statements include estimates of oil and gas quantities Proved oil and gas reserves are those quantities of oil and gas which by analysis of geoscience andengineering data can be estimated with reasonable certainty to be economically producible under existing economic conditions operating methods and governmentregulations Other estimates of oil and gas quantities including estimates of probable reserves possible reserves and resource potential are by their nature more speculativethan estimates of proved reserves Accordingly estimates other than proved reserves are subject to substantially greater risk of being actually realized Investors are urged toconsider closely the disclosure in our Form 10-K available at wwwnationalfuelgascom You can also obtain this form on the SECrsquos website at wwwsecgov

For a discussion of the risks set forth above and other factors that could cause actual results to differ materially from results referred to in the forward-looking statements seeldquoRisk Factorsrdquo in the Companyrsquos Form 10-K for the fiscal year ended September 30 2018 and the Forms 10-Q for the quarter ended March 31 2018 June 30 2018 and December31 2018 The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date thereof or to reflect the occurrence ofunanticipated events

Appendix

30

California Capital Expenditures vs Production

9341 8863

8033 ~7300

2016 2017 2018 2019

Fiscal Year

West Division Average Net Daily Production (Boe)West Division Annual Capital Expenditures ($ MM)(1)

$38 $38

$26 ~$25

2016 2017 2018 2019

Fiscal YearGuidance Guidance

(1) Seneca West Division capital expenditures includes Seneca corporate and eliminations

EampP and Gathering

Sepse Sale Closed on 5118(reduced production by ~900 boed)

31

Pioneer

South MWSS

Acreage

North MWSS

AcreageSec 17N

4149 51

NMWSS amp 17N SMWSS amp Pioneer East Coalinga

California Development Activities

Modest near-term capital program focused on locations that earn attractive returns in current oil price environment

AampD will focus on low cost bolt-on opportunities

Sec 17 Pioneer and East Coalinga development to provide future growth

North

Project IRRs at $55Bbl(1)

(1) Reflects pre-tax IRRs at a $55Bbl WTI

EampP and Gathering

Seneca West Economics

South

East Coalinga

North

South

32

Fiscal 2019 Production and Price Certainty

~49 Bcfe

210 ndash 230 Bcfe

~114 Bcf

~29 Bcf (2)

16+- Bcf~12 Bcfe

0

40

80

120

160

200

240

YTD FY19Actuals

Fixed Price + FirmSales w Hedge

Firm Sales(Unhedged)

Spot Sales California TotalSeneca

Prod

uctio

n (B

cfe)

(1) Average realized price reflects uplift from financial hedges less fixed differentials under firm sales contracts and any firm transportation costs(2) Indicates firm sales contracts with fixed index differentials but not backed by a matching financial hedge

114 Bcf locked-in realizing net ~$241Mcf (1)

29 Bcf of additional basis protection

Spot production assumed to be sold

at ~$275Mmbtu(winter) and ~$225

(summer)

143 Bcf of Appalachian Production Protected by Firm Sales for Remainder of Year

79 of oil production hedged at $5757 Bbl

EampP and Gathering

33

Strong Hedge Book

Natural Gas Swap amp Fixed Physical Sales Contracts (Millions MMBtu)

(1) Fixed price physical sales exclude joint development partnerrsquos share of fixed price contract WDA volumes as specified under the joint development agreement(2) Reflects percentage of projected production for FY19 hedged at the midpoint of the production guidance range(3) Senecarsquos remainder FY19 Production reflects the total FY19 production guidance of 210-230 Bcfe or 220 Bcfe at the midpoint less Q1 actual production

Crude Oil Swap Contracts (Thousands Bbls)

13591188

732

456

0

500

1000

1500

2000

2500

FY 2019 FY 2020 FY 2021 FY 2022

NYMEX (WTI)

Brent

FY 19 Crude Oil79 Hedged (2)

FY 2019 Remaining Production (3)

EampP and Gathering

1174

709

469 406

0

50

100

150

200

250

FY 2019 FY 2020 FY 2021 FY 2022

NYMEX Swaps

Dawn Swaps

Fixed Price Physical Sales

(1)

FY 2019 Remaining Production (3)

FY 19 Nat Gas71 Hedged (2)

34

$065 $070$070 -$075

FY 2017 FY 2018 FY 2019E

$060 $060 $060

$011 $009 $007$071 $069 ~$067

FY 2017 FY 2018 FY 2019E Gathering amp Transport LOE (non-Gathering) GampA Taxes amp Other

Seneca Operating Costs

Competitive low cost structure in Appalachia and California supports strong cash margins

Gathering fee generates significant revenue stream for affiliated gathering company

Seneca DDampARate

$Mcfe

$054 $054 $056

$042 $038 $031

$034 $034 $030

$017 $014 $015

$147 $140 ~$132

FY 2017 FY 2018 FY 2019E

(1)

$1791$1746~$2050

FY 2017 FY 2018 FY 2019E

Appalachia LOE amp Gathering $Mcfe

California LOE$Boe

Total Seneca Cash OpEx$Mcfe

(1)

(2)

(2)

(1) GampA estimate represents the midpoint of the GampA guidance range of $025 to $035 for fiscal 2019(2) The total of the two LOE components represents the midpoint of the LOE guidance range of $085 to $090 for fiscal 2019

EampP and Gathering

35

Senecarsquos Continuing Commitment to the Environment

Produced Water Recycled in Appalachia

100 70Recycled Water

Used in New Shale Well

Completions

Water and Fluids Management Air Quality and Emissions

Seneca Resources Water OperationsFiscal 2018

Seneca Resources Remains Focused on Minimizing GHG Emissions

The Environmental Partnership

EPA Natural Gas Star Program

Green Completions (all fiscal 2018 wells)

Ultrasonic Leak Detection Technology

Emissions Controls

Rig and Vehicle Fuel Conversion

Integrating Renewable Energy into Operations

EampP and Gathering

36

Pipeline and Storage OverviewNational Fuel Gas Supply Corporation ~ Empire Pipeline Inc

37

Pipeline amp Storage Segment Overview

(1) As of September 30 2018 as disclosed in the Companyrsquos fiscal 2018 form 10-K(2) As of December 31 2017 calculated from National Fuel Gas Supply Corporationrsquos and Empire Pipeline Incrsquos 2017 FERC Form-2 reports respectively

Empire Pipeline Inc

National Fuel Gas Supply Corporation

Empire Pipeline

Supply Corp

Contracted Capacity(1) Firm Transportation 3187 MDth per day Firm Storage 71938 Mdth (fully subscribed)

Rate Base(2) ~$820 million FERC Rate Proceeding Status

Rate case settlement extension approved Nov lsquo15 Rate case filing expected by 73119

Contracted Capacity(1) Firm Transportation 978 MDth per day Firm Storage 3753 Mdth (fully subscribed)

Rate Base(2) ~$249 million FERC Rate Proceeding Status

Rate case settlement in principle reached on 122118 FERC approval pending

New transportation rates went into on 1119

Pipeline amp Storage

38

All Seneca volumes will flow through wholly-owned NFG gathering facilities

FM100 Project - Consolidated Benefit for NFG

330000 Dthd of new transportation capacity from WDA and EDA acreage positions to premium markets

New Transco capacity (Leidy South) 330000 Dthday

Rate(1) competitive with other expansion project rates in Senecarsquos current transportation portfolio

Delivery Point(s) Transco Zone 6 interconnections

Seneca

Lease to Transco of new capacity 330000 Dthday

Estimated annual lease revenues ~$35 million

Target In-Service late calendar year 2021

Supply Corp

Project expected to provide long-term earnings uplift to Seneca Supply Corp and Gathering

Pipeline amp Storage

Gathering

(1) Includes lease of new capacity from Supply Corp to Transco

39

FM100 Project ndash Significant Investment by Supply Corp

Pipeline amp Storage

Estimated Capital Cost $280 million(1)

Facilities (all in Pennsylvania) include Approximately 30 miles of new pipeline 2 new compressor stations (totaling

approximately 37000 HP) New interconnection station and modification

of existing interconnection station Abandonment of approximately 45 miles of

existing pipeline and compressor station Regulatory Process

Pre-filing application submitted to FERC in 2017 for original modernization project

FERC 7(b) 7(c) filing expected summer 2019

(1) Includes expansion and modernization portions of the project

40

Empire North Project

Target In-Service second half of fiscal 2020

Est Capital Cost $145 million

Est Annual Revenues ~$25 million

Receipt Point Jackson (Tioga Co Pa production)

Design Capacity and Delivery Points 175000 Dthd to Chippawa (TCPL interconnect)

30000 Dthd to Hopewell (TGP 200 interconnect)

Customers Fully subscribed (205000 Dthday)

Major Facilities 2 new compressor stations in NY (1) amp Pa (1)

No new pipeline construction

Regulatory Process FERC 7(c) application filed on 21618

FERC Environmental Assessment issued 103018

Pipeline amp Storage

Fully Subscribed Project will Provide 205000 Dthday of Incremental Firm Transportation

41

National Fuel Remains Committed to Northern Access Project

Target In-Service as early as fiscal 2022

Total Cost ~$500MM (~$76MM spent to date)

Estimated Annual Revenues ~$84 million

Delivery Points

350000 Dthd to Chippawa (TCPL interconnect)

140000 Dthd to Hopewell (TGP 200 line)

Regulatory Status

February 3 2017 ndash FERC 7(c) certificate issued

August 6 2018 ndash FERC issued Order finding that NY DEC waived water quality certification

Supply and Empire currently working to finalize remaining federal authorizations

Pipeline amp Storage

To Dawn

42

Continued Expansion of the NFG Supply System

Line N Expansion Opportunities

Line N to Monaca Project Project Firm transportation service to a new ethane

cracker facility being built by Shell Chemical Appalachia LLC

Target In-Service July 2019

Estimated Capital Cost $23 million

Contracted Capacity 133000 Dthday

Additional Line N Expansion Opportunity (Supply OS 221) Project New firm transportation service for on-system

demand

Open Season Capacity Awarded 165000 to foundation shipper Precedent agreement in negotiations

Pipeline amp Storage

43

Pipeline amp Storage Customer Mix

Producer33

LDC42

Marketer10

Outside Pipeline

9

End User6

42 MMDthd

(1) Contracted as of 10312018

Customer Transportation by Shipper Type(1) Affiliated Customer Mix (Contracted Capacity)

66

521

41

34

9579

59

LDCs Producers Marketers FirmStorage

Affiliated Non-Affiliated

Firm Transport

Pipeline amp Storage

44

Utility OverviewNational Fuel Gas Distribution Corporation

45

New York amp Pennsylvania Service Territories

New York

Total Customers(1) 535800ROE 87 (NY PSC Rate Case Order April 2017)Rate Mechanismso Revenue Decouplingo Weather Normalizationo Low Income Rateso Merchant Function Charge (Uncollectibles Adj)o 9010 Sharing (Large Customers)o System Modernization Tracker

Pennsylvania

Total Customers(1) 214400ROE Black Box Settlement (2007)Rate Mechanismso Low Income Rateso Merchant Function Charge

(1) As of September 30 2018

Utility

46

New York Rate Case Outcome

Rate Order Summary

Revenue Requirement $59 million

Rate Base $704 million

Allowed Return on Equity (ROE) 87

Capital Structure 429 equity

Other notable items

New rates became effective 5117

Retains rate mechanisms in place under prior order (revenue decoupling weather normalization merchant function charge 9010 large customer sharing)

No stay-out clause

System modernization tracker for Leak Prone Pipe (LPP)

Earnings sharing started 4118 (5050 sharing starts at earnings in excess of 92)

Article 78 appeal filed on 72817 with oral argument completed in January 2019

On April 20 2017 the New York Public Service Commission issued a Rate Order relating to NFG Distributionrsquos rate case (No 16-G-0257) filed in April 2016

Utility

47

Utility Continues its Significant Investments in Safety

$544$618 $636

$699

$944$980

$809$856

$90-100

$00

$250

$500

$750

$1000

$1250

2015 2016 2017 2018 2019E

Cap

ital E

xpen

ditu

res

($ m

illio

ns)

Fiscal Year

Capital Expenditures for Safety Total Capital Expenditures

Modernization Spending in NY Expected to Grow Gross Margin By $2 MM - $5 MM in FY 2019

(1)

(1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation

Utility

System modernization tracker in NY allows recovery of pipeline replacementcosts which is expected to drive modest gross margin and rate base growth

48

Accelerating Pipeline Replacement amp Modernization

Wrought Iron

Plastic

CoatedBare

120130

146 144159

2014 2015 2016 2017 2018Calendar Year

NY9726 miles

PA4830 miles

No Cast Iron Mains in Pa

Miles of Utility Main Pipeline ReplacedUtility Mains by Material(1)

Wrought Iron

Cast Iron

Plastic

Coated Bare

Utility

(1) All values are reported on a calendar year basis as of December 31 2018

49

A Proven History of Controlling Costs

$200 $189 $195

$166 $166

$31 $31

$197 $197

$0

$50

$100

$150

$200

$250

2015 2016 2017 2018 TTM 123118

Fiscal Year

OampM Expense Non-Service Pension Costs

OampM Expense ($ millions)

Utility

(1)

(1) For purposes of comparability to FY 2015 2016 and 2017 Utility Operation and Maintenance Expense for FY 2018 and the twelve months ended December 31 2018 was adjusted by approximately $314 million and $312 million respectively to include non-service pension costs which were re-classified as Other Income (Deductions) as of October 1 2018 on the Companyrsquos Income Statement See Slide 64 for non-GAAP reconciliation of Adjusted Operation and Maintenance Expense to Operation and Maintenance Expense by segment

50

Consolidated Financial OverviewUpstream I Midstream I Downstream

51

Adjusted Operating Results ($ per share)(1)

Diversified Balanced Earnings and Cash Flows

(1) A reconciliation of Adjusted Operating Results to Earnings per Share by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation(2) Consolidated Adjusted EBITDA includes Energy Marketing and Corporate amp All Other Segments A reconciliation of Adjusted EBITDA to Net Income by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in

the Business is included at the end of this presentation

Adjusted EBITDA ($ millions)(2)

$176 $179

$184 $181

$92 $97

$318 $327

$761 $775

$-

$200

$400

$600

$800

FY 2018 TTM 123118

$059 Utility

$097 Pipeline amp Storage

$057 Gathering

$125 Exploration

amp Production

$334 $345 to $365

$-

$100

$200

$300

$400

FY 2018 FY 2019 Guidance

Rate Regulated

40-45

$728

Rate Regulated

~46

52

$89 $94 $98 $81 $86 $90-$100

$140$230

$114 $95 $93 $120-$150

$138$118

$54$33 $48

$55-$65

$603$557

$99 $246$356

$460-$495

$970 $1001

$366$455

$583

$725-$810

$0

$250

$500

$750

$1000

$1250

2014 2015 2016 2017 2018 2019GuidanceFiscal Year

Exploration amp Production

Gathering

Pipeline amp Storage

Utility

Disciplined Flexible Capital Allocation

(2)

(1) Total Capital Expenditures include Energy Marketing Corporate and All Other A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation (2) FY16 FY17 and FY18 reflects the netting of $157 million $7 million and $17 million respectively of up-front proceeds received from joint development partner for working interest in joint development wells and $21M in intercompany asset transfers in FY18

Capital Expenditures by Segment ($ millions)(1)

53

Maintaining Strong Balance Sheet amp Liquidity

Total Equity49

Total Debt51

$42 Billion Total Capitalizationas of December 31 2018

218 x251 x 245 x 247 x 256 x

2015 2016 2017 2018 TTM 123118Fiscal Year End

Net Debt Adjusted EBITDA(1) Capitalization

Debt Maturity Profile ($MM) Liquidity

Committed Credit FacilitiesShort-term Debt OutstandingAvailable Short-term Credit FacilitiesCash Balance at 123118 Total Liquidity at 123118

$ 750 MM0 MM

750 MM110 MM

$ 860 MM

$500 $549 $500

$300 $300

$0

$200

$400

$600

(1) Net Debt is net of cash and temporary cash investments Reconciliations of Net Debt and Adjusted EBITDA to Net Income are included at the end of this presentation

54

Appendix

55

Safe Harbor For Forward Looking StatementsThis presentation may contain ldquoforward-looking statementsrdquo as defined by the Private Securities Litigation Reform Act of 1995 including statements regarding future prospectsplans objectives goals projections estimates of oil and gas quantities strategies future events or performance and underlying assumptions capital structure anticipatedcapital expenditures completion of construction projects projections for pension and other post-retirement benefit obligations impacts of the adoption of new accounting rulesand possible outcomes of litigation or regulatory proceedings as well as statements that are identified by the use of the words ldquoanticipatesrdquo ldquoestimatesrdquo ldquoexpectsrdquo ldquoforecastsrdquoldquointendsrdquo ldquoplansrdquo ldquopredictsrdquo ldquoprojectsrdquo ldquobelievesrdquo ldquoseeksrdquo ldquowillrdquo ldquomayrdquo and similar expressions Forward-looking statements involve risks and uncertainties which couldcause actual results or outcomes to differ materially from those expressed in the forward-looking statements The Companyrsquos expectations beliefs and projections are expressedin good faith and are believed by the Company to have a reasonable basis but there can be no assurance that managementrsquos expectations beliefs or projections will result or beachieved or accomplished

In addition to other factors the following are important factors that could cause actual results to differ materially from those discussed in the forward-looking statements delaysor changes in costs or plans with respect to Company projects or related projects of other companies including difficulties or delays in obtaining necessary governmentalapprovals permits or orders or in obtaining the cooperation of interconnecting facility operators governmentalregulatory actions initiatives and proceedings including thoseinvolving rate cases (which address among other things target rates of return rate design and retained natural gas) environmentalsafety requirements affiliate relationshipsindustry structure and franchise renewal changes in laws regulations or judicial interpretations to which the Company is subject including those involving derivatives taxessafety employment climate change other environmental matters real property and exploration and production activities such as hydraulic fracturing financial and economicconditions including the availability of credit and occurrences affecting the Companyrsquos ability to obtain financing on acceptable terms for working capital capital expendituresand other investments including any downgrades in the Companyrsquos credit ratings and changes in interest rates and other capital market conditions changes in the price ofnatural gas or oil impairments under the SECrsquos full cost ceiling test for natural gas and oil reserves factors affecting the Companyrsquos ability to successfully identify drill for andproduce economically viable natural gas and oil reserves including among others geology lease availability title disputes weather conditions shortages delays orunavailability of equipment and services required in drilling operations insufficient gathering processing and transportation capacity the need to obtain governmentalapprovals and permits and compliance with environmental laws and regulations increasing health care costs and the resulting effect on health insurance premiums and on theobligation to provide other post-retirement benefits changes in price differentials between similar quantities of natural gas or oil sold at different geographic locations and theeffect of such changes on commodity production revenues and demand for pipeline transportation capacity to or from such locations other changes in price differentialsbetween similar quantities of natural gas or oil having different quality heating value hydrocarbon mix or delivery date the cost and effects of legal and administrative claimsagainst the Company or activist shareholder campaigns to effect changes at the Company uncertainty of oil and gas reserve estimates significant differences between theCompanyrsquos projected and actual production levels for natural gas or oil changes in demographic patterns and weather conditions changes in the availability price oraccounting treatment of derivative financial instruments changes in laws actuarial assumptions the interest rate environment and the return on plantrust assets related to theCompanyrsquos pension and other post-retirement benefits which can affect future funding obligations and costs and plan liabilities changes in economic conditions includingglobal national or regional recessions and their effect on the demand for and customersrsquo ability to pay for the Companyrsquos products and services the creditworthiness orperformance of the Companyrsquos key suppliers customers and counterparties the impact of potential information technology cybersecurity or data security breaches economicdisruptions or uninsured losses resulting from major accidents fires severe weather natural disasters terrorist activities or acts of war significant differences between theCompanyrsquos projected and actual capital expenditures and operating expenses or increasing costs of insurance changes in coverage and the ability to obtain insurance

Forward-looking statements include estimates of oil and gas quantities Proved oil and gas reserves are those quantities of oil and gas which by analysis of geoscience andengineering data can be estimated with reasonable certainty to be economically producible under existing economic conditions operating methods and governmentregulations Other estimates of oil and gas quantities including estimates of probable reserves possible reserves and resource potential are by their nature more speculativethan estimates of proved reserves Accordingly estimates other than proved reserves are subject to substantially greater risk of being actually realized Investors are urged toconsider closely the disclosure in our Form 10-K available at wwwnationalfuelgascom You can also obtain this form on the SECrsquos website at wwwsecgov

For a discussion of the risks set forth above and other factors that could cause actual results to differ materially from results referred to in the forward-looking statements seeldquoRisk Factorsrdquo in the Companyrsquos Form 10-K for the fiscal year ended September 30 2018 and the Forms 10-Q for the quarter ended March 31 2018 June 30 2018 and December31 2018 The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date thereof or to reflect the occurrence ofunanticipated events

Appendix

31

Pioneer

South MWSS

Acreage

North MWSS

AcreageSec 17N

4149 51

NMWSS amp 17N SMWSS amp Pioneer East Coalinga

California Development Activities

Modest near-term capital program focused on locations that earn attractive returns in current oil price environment

AampD will focus on low cost bolt-on opportunities

Sec 17 Pioneer and East Coalinga development to provide future growth

North

Project IRRs at $55Bbl(1)

(1) Reflects pre-tax IRRs at a $55Bbl WTI

EampP and Gathering

Seneca West Economics

South

East Coalinga

North

South

32

Fiscal 2019 Production and Price Certainty

~49 Bcfe

210 ndash 230 Bcfe

~114 Bcf

~29 Bcf (2)

16+- Bcf~12 Bcfe

0

40

80

120

160

200

240

YTD FY19Actuals

Fixed Price + FirmSales w Hedge

Firm Sales(Unhedged)

Spot Sales California TotalSeneca

Prod

uctio

n (B

cfe)

(1) Average realized price reflects uplift from financial hedges less fixed differentials under firm sales contracts and any firm transportation costs(2) Indicates firm sales contracts with fixed index differentials but not backed by a matching financial hedge

114 Bcf locked-in realizing net ~$241Mcf (1)

29 Bcf of additional basis protection

Spot production assumed to be sold

at ~$275Mmbtu(winter) and ~$225

(summer)

143 Bcf of Appalachian Production Protected by Firm Sales for Remainder of Year

79 of oil production hedged at $5757 Bbl

EampP and Gathering

33

Strong Hedge Book

Natural Gas Swap amp Fixed Physical Sales Contracts (Millions MMBtu)

(1) Fixed price physical sales exclude joint development partnerrsquos share of fixed price contract WDA volumes as specified under the joint development agreement(2) Reflects percentage of projected production for FY19 hedged at the midpoint of the production guidance range(3) Senecarsquos remainder FY19 Production reflects the total FY19 production guidance of 210-230 Bcfe or 220 Bcfe at the midpoint less Q1 actual production

Crude Oil Swap Contracts (Thousands Bbls)

13591188

732

456

0

500

1000

1500

2000

2500

FY 2019 FY 2020 FY 2021 FY 2022

NYMEX (WTI)

Brent

FY 19 Crude Oil79 Hedged (2)

FY 2019 Remaining Production (3)

EampP and Gathering

1174

709

469 406

0

50

100

150

200

250

FY 2019 FY 2020 FY 2021 FY 2022

NYMEX Swaps

Dawn Swaps

Fixed Price Physical Sales

(1)

FY 2019 Remaining Production (3)

FY 19 Nat Gas71 Hedged (2)

34

$065 $070$070 -$075

FY 2017 FY 2018 FY 2019E

$060 $060 $060

$011 $009 $007$071 $069 ~$067

FY 2017 FY 2018 FY 2019E Gathering amp Transport LOE (non-Gathering) GampA Taxes amp Other

Seneca Operating Costs

Competitive low cost structure in Appalachia and California supports strong cash margins

Gathering fee generates significant revenue stream for affiliated gathering company

Seneca DDampARate

$Mcfe

$054 $054 $056

$042 $038 $031

$034 $034 $030

$017 $014 $015

$147 $140 ~$132

FY 2017 FY 2018 FY 2019E

(1)

$1791$1746~$2050

FY 2017 FY 2018 FY 2019E

Appalachia LOE amp Gathering $Mcfe

California LOE$Boe

Total Seneca Cash OpEx$Mcfe

(1)

(2)

(2)

(1) GampA estimate represents the midpoint of the GampA guidance range of $025 to $035 for fiscal 2019(2) The total of the two LOE components represents the midpoint of the LOE guidance range of $085 to $090 for fiscal 2019

EampP and Gathering

35

Senecarsquos Continuing Commitment to the Environment

Produced Water Recycled in Appalachia

100 70Recycled Water

Used in New Shale Well

Completions

Water and Fluids Management Air Quality and Emissions

Seneca Resources Water OperationsFiscal 2018

Seneca Resources Remains Focused on Minimizing GHG Emissions

The Environmental Partnership

EPA Natural Gas Star Program

Green Completions (all fiscal 2018 wells)

Ultrasonic Leak Detection Technology

Emissions Controls

Rig and Vehicle Fuel Conversion

Integrating Renewable Energy into Operations

EampP and Gathering

36

Pipeline and Storage OverviewNational Fuel Gas Supply Corporation ~ Empire Pipeline Inc

37

Pipeline amp Storage Segment Overview

(1) As of September 30 2018 as disclosed in the Companyrsquos fiscal 2018 form 10-K(2) As of December 31 2017 calculated from National Fuel Gas Supply Corporationrsquos and Empire Pipeline Incrsquos 2017 FERC Form-2 reports respectively

Empire Pipeline Inc

National Fuel Gas Supply Corporation

Empire Pipeline

Supply Corp

Contracted Capacity(1) Firm Transportation 3187 MDth per day Firm Storage 71938 Mdth (fully subscribed)

Rate Base(2) ~$820 million FERC Rate Proceeding Status

Rate case settlement extension approved Nov lsquo15 Rate case filing expected by 73119

Contracted Capacity(1) Firm Transportation 978 MDth per day Firm Storage 3753 Mdth (fully subscribed)

Rate Base(2) ~$249 million FERC Rate Proceeding Status

Rate case settlement in principle reached on 122118 FERC approval pending

New transportation rates went into on 1119

Pipeline amp Storage

38

All Seneca volumes will flow through wholly-owned NFG gathering facilities

FM100 Project - Consolidated Benefit for NFG

330000 Dthd of new transportation capacity from WDA and EDA acreage positions to premium markets

New Transco capacity (Leidy South) 330000 Dthday

Rate(1) competitive with other expansion project rates in Senecarsquos current transportation portfolio

Delivery Point(s) Transco Zone 6 interconnections

Seneca

Lease to Transco of new capacity 330000 Dthday

Estimated annual lease revenues ~$35 million

Target In-Service late calendar year 2021

Supply Corp

Project expected to provide long-term earnings uplift to Seneca Supply Corp and Gathering

Pipeline amp Storage

Gathering

(1) Includes lease of new capacity from Supply Corp to Transco

39

FM100 Project ndash Significant Investment by Supply Corp

Pipeline amp Storage

Estimated Capital Cost $280 million(1)

Facilities (all in Pennsylvania) include Approximately 30 miles of new pipeline 2 new compressor stations (totaling

approximately 37000 HP) New interconnection station and modification

of existing interconnection station Abandonment of approximately 45 miles of

existing pipeline and compressor station Regulatory Process

Pre-filing application submitted to FERC in 2017 for original modernization project

FERC 7(b) 7(c) filing expected summer 2019

(1) Includes expansion and modernization portions of the project

40

Empire North Project

Target In-Service second half of fiscal 2020

Est Capital Cost $145 million

Est Annual Revenues ~$25 million

Receipt Point Jackson (Tioga Co Pa production)

Design Capacity and Delivery Points 175000 Dthd to Chippawa (TCPL interconnect)

30000 Dthd to Hopewell (TGP 200 interconnect)

Customers Fully subscribed (205000 Dthday)

Major Facilities 2 new compressor stations in NY (1) amp Pa (1)

No new pipeline construction

Regulatory Process FERC 7(c) application filed on 21618

FERC Environmental Assessment issued 103018

Pipeline amp Storage

Fully Subscribed Project will Provide 205000 Dthday of Incremental Firm Transportation

41

National Fuel Remains Committed to Northern Access Project

Target In-Service as early as fiscal 2022

Total Cost ~$500MM (~$76MM spent to date)

Estimated Annual Revenues ~$84 million

Delivery Points

350000 Dthd to Chippawa (TCPL interconnect)

140000 Dthd to Hopewell (TGP 200 line)

Regulatory Status

February 3 2017 ndash FERC 7(c) certificate issued

August 6 2018 ndash FERC issued Order finding that NY DEC waived water quality certification

Supply and Empire currently working to finalize remaining federal authorizations

Pipeline amp Storage

To Dawn

42

Continued Expansion of the NFG Supply System

Line N Expansion Opportunities

Line N to Monaca Project Project Firm transportation service to a new ethane

cracker facility being built by Shell Chemical Appalachia LLC

Target In-Service July 2019

Estimated Capital Cost $23 million

Contracted Capacity 133000 Dthday

Additional Line N Expansion Opportunity (Supply OS 221) Project New firm transportation service for on-system

demand

Open Season Capacity Awarded 165000 to foundation shipper Precedent agreement in negotiations

Pipeline amp Storage

43

Pipeline amp Storage Customer Mix

Producer33

LDC42

Marketer10

Outside Pipeline

9

End User6

42 MMDthd

(1) Contracted as of 10312018

Customer Transportation by Shipper Type(1) Affiliated Customer Mix (Contracted Capacity)

66

521

41

34

9579

59

LDCs Producers Marketers FirmStorage

Affiliated Non-Affiliated

Firm Transport

Pipeline amp Storage

44

Utility OverviewNational Fuel Gas Distribution Corporation

45

New York amp Pennsylvania Service Territories

New York

Total Customers(1) 535800ROE 87 (NY PSC Rate Case Order April 2017)Rate Mechanismso Revenue Decouplingo Weather Normalizationo Low Income Rateso Merchant Function Charge (Uncollectibles Adj)o 9010 Sharing (Large Customers)o System Modernization Tracker

Pennsylvania

Total Customers(1) 214400ROE Black Box Settlement (2007)Rate Mechanismso Low Income Rateso Merchant Function Charge

(1) As of September 30 2018

Utility

46

New York Rate Case Outcome

Rate Order Summary

Revenue Requirement $59 million

Rate Base $704 million

Allowed Return on Equity (ROE) 87

Capital Structure 429 equity

Other notable items

New rates became effective 5117

Retains rate mechanisms in place under prior order (revenue decoupling weather normalization merchant function charge 9010 large customer sharing)

No stay-out clause

System modernization tracker for Leak Prone Pipe (LPP)

Earnings sharing started 4118 (5050 sharing starts at earnings in excess of 92)

Article 78 appeal filed on 72817 with oral argument completed in January 2019

On April 20 2017 the New York Public Service Commission issued a Rate Order relating to NFG Distributionrsquos rate case (No 16-G-0257) filed in April 2016

Utility

47

Utility Continues its Significant Investments in Safety

$544$618 $636

$699

$944$980

$809$856

$90-100

$00

$250

$500

$750

$1000

$1250

2015 2016 2017 2018 2019E

Cap

ital E

xpen

ditu

res

($ m

illio

ns)

Fiscal Year

Capital Expenditures for Safety Total Capital Expenditures

Modernization Spending in NY Expected to Grow Gross Margin By $2 MM - $5 MM in FY 2019

(1)

(1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation

Utility

System modernization tracker in NY allows recovery of pipeline replacementcosts which is expected to drive modest gross margin and rate base growth

48

Accelerating Pipeline Replacement amp Modernization

Wrought Iron

Plastic

CoatedBare

120130

146 144159

2014 2015 2016 2017 2018Calendar Year

NY9726 miles

PA4830 miles

No Cast Iron Mains in Pa

Miles of Utility Main Pipeline ReplacedUtility Mains by Material(1)

Wrought Iron

Cast Iron

Plastic

Coated Bare

Utility

(1) All values are reported on a calendar year basis as of December 31 2018

49

A Proven History of Controlling Costs

$200 $189 $195

$166 $166

$31 $31

$197 $197

$0

$50

$100

$150

$200

$250

2015 2016 2017 2018 TTM 123118

Fiscal Year

OampM Expense Non-Service Pension Costs

OampM Expense ($ millions)

Utility

(1)

(1) For purposes of comparability to FY 2015 2016 and 2017 Utility Operation and Maintenance Expense for FY 2018 and the twelve months ended December 31 2018 was adjusted by approximately $314 million and $312 million respectively to include non-service pension costs which were re-classified as Other Income (Deductions) as of October 1 2018 on the Companyrsquos Income Statement See Slide 64 for non-GAAP reconciliation of Adjusted Operation and Maintenance Expense to Operation and Maintenance Expense by segment

50

Consolidated Financial OverviewUpstream I Midstream I Downstream

51

Adjusted Operating Results ($ per share)(1)

Diversified Balanced Earnings and Cash Flows

(1) A reconciliation of Adjusted Operating Results to Earnings per Share by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation(2) Consolidated Adjusted EBITDA includes Energy Marketing and Corporate amp All Other Segments A reconciliation of Adjusted EBITDA to Net Income by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in

the Business is included at the end of this presentation

Adjusted EBITDA ($ millions)(2)

$176 $179

$184 $181

$92 $97

$318 $327

$761 $775

$-

$200

$400

$600

$800

FY 2018 TTM 123118

$059 Utility

$097 Pipeline amp Storage

$057 Gathering

$125 Exploration

amp Production

$334 $345 to $365

$-

$100

$200

$300

$400

FY 2018 FY 2019 Guidance

Rate Regulated

40-45

$728

Rate Regulated

~46

52

$89 $94 $98 $81 $86 $90-$100

$140$230

$114 $95 $93 $120-$150

$138$118

$54$33 $48

$55-$65

$603$557

$99 $246$356

$460-$495

$970 $1001

$366$455

$583

$725-$810

$0

$250

$500

$750

$1000

$1250

2014 2015 2016 2017 2018 2019GuidanceFiscal Year

Exploration amp Production

Gathering

Pipeline amp Storage

Utility

Disciplined Flexible Capital Allocation

(2)

(1) Total Capital Expenditures include Energy Marketing Corporate and All Other A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation (2) FY16 FY17 and FY18 reflects the netting of $157 million $7 million and $17 million respectively of up-front proceeds received from joint development partner for working interest in joint development wells and $21M in intercompany asset transfers in FY18

Capital Expenditures by Segment ($ millions)(1)

53

Maintaining Strong Balance Sheet amp Liquidity

Total Equity49

Total Debt51

$42 Billion Total Capitalizationas of December 31 2018

218 x251 x 245 x 247 x 256 x

2015 2016 2017 2018 TTM 123118Fiscal Year End

Net Debt Adjusted EBITDA(1) Capitalization

Debt Maturity Profile ($MM) Liquidity

Committed Credit FacilitiesShort-term Debt OutstandingAvailable Short-term Credit FacilitiesCash Balance at 123118 Total Liquidity at 123118

$ 750 MM0 MM

750 MM110 MM

$ 860 MM

$500 $549 $500

$300 $300

$0

$200

$400

$600

(1) Net Debt is net of cash and temporary cash investments Reconciliations of Net Debt and Adjusted EBITDA to Net Income are included at the end of this presentation

54

Appendix

55

Safe Harbor For Forward Looking StatementsThis presentation may contain ldquoforward-looking statementsrdquo as defined by the Private Securities Litigation Reform Act of 1995 including statements regarding future prospectsplans objectives goals projections estimates of oil and gas quantities strategies future events or performance and underlying assumptions capital structure anticipatedcapital expenditures completion of construction projects projections for pension and other post-retirement benefit obligations impacts of the adoption of new accounting rulesand possible outcomes of litigation or regulatory proceedings as well as statements that are identified by the use of the words ldquoanticipatesrdquo ldquoestimatesrdquo ldquoexpectsrdquo ldquoforecastsrdquoldquointendsrdquo ldquoplansrdquo ldquopredictsrdquo ldquoprojectsrdquo ldquobelievesrdquo ldquoseeksrdquo ldquowillrdquo ldquomayrdquo and similar expressions Forward-looking statements involve risks and uncertainties which couldcause actual results or outcomes to differ materially from those expressed in the forward-looking statements The Companyrsquos expectations beliefs and projections are expressedin good faith and are believed by the Company to have a reasonable basis but there can be no assurance that managementrsquos expectations beliefs or projections will result or beachieved or accomplished

In addition to other factors the following are important factors that could cause actual results to differ materially from those discussed in the forward-looking statements delaysor changes in costs or plans with respect to Company projects or related projects of other companies including difficulties or delays in obtaining necessary governmentalapprovals permits or orders or in obtaining the cooperation of interconnecting facility operators governmentalregulatory actions initiatives and proceedings including thoseinvolving rate cases (which address among other things target rates of return rate design and retained natural gas) environmentalsafety requirements affiliate relationshipsindustry structure and franchise renewal changes in laws regulations or judicial interpretations to which the Company is subject including those involving derivatives taxessafety employment climate change other environmental matters real property and exploration and production activities such as hydraulic fracturing financial and economicconditions including the availability of credit and occurrences affecting the Companyrsquos ability to obtain financing on acceptable terms for working capital capital expendituresand other investments including any downgrades in the Companyrsquos credit ratings and changes in interest rates and other capital market conditions changes in the price ofnatural gas or oil impairments under the SECrsquos full cost ceiling test for natural gas and oil reserves factors affecting the Companyrsquos ability to successfully identify drill for andproduce economically viable natural gas and oil reserves including among others geology lease availability title disputes weather conditions shortages delays orunavailability of equipment and services required in drilling operations insufficient gathering processing and transportation capacity the need to obtain governmentalapprovals and permits and compliance with environmental laws and regulations increasing health care costs and the resulting effect on health insurance premiums and on theobligation to provide other post-retirement benefits changes in price differentials between similar quantities of natural gas or oil sold at different geographic locations and theeffect of such changes on commodity production revenues and demand for pipeline transportation capacity to or from such locations other changes in price differentialsbetween similar quantities of natural gas or oil having different quality heating value hydrocarbon mix or delivery date the cost and effects of legal and administrative claimsagainst the Company or activist shareholder campaigns to effect changes at the Company uncertainty of oil and gas reserve estimates significant differences between theCompanyrsquos projected and actual production levels for natural gas or oil changes in demographic patterns and weather conditions changes in the availability price oraccounting treatment of derivative financial instruments changes in laws actuarial assumptions the interest rate environment and the return on plantrust assets related to theCompanyrsquos pension and other post-retirement benefits which can affect future funding obligations and costs and plan liabilities changes in economic conditions includingglobal national or regional recessions and their effect on the demand for and customersrsquo ability to pay for the Companyrsquos products and services the creditworthiness orperformance of the Companyrsquos key suppliers customers and counterparties the impact of potential information technology cybersecurity or data security breaches economicdisruptions or uninsured losses resulting from major accidents fires severe weather natural disasters terrorist activities or acts of war significant differences between theCompanyrsquos projected and actual capital expenditures and operating expenses or increasing costs of insurance changes in coverage and the ability to obtain insurance

Forward-looking statements include estimates of oil and gas quantities Proved oil and gas reserves are those quantities of oil and gas which by analysis of geoscience andengineering data can be estimated with reasonable certainty to be economically producible under existing economic conditions operating methods and governmentregulations Other estimates of oil and gas quantities including estimates of probable reserves possible reserves and resource potential are by their nature more speculativethan estimates of proved reserves Accordingly estimates other than proved reserves are subject to substantially greater risk of being actually realized Investors are urged toconsider closely the disclosure in our Form 10-K available at wwwnationalfuelgascom You can also obtain this form on the SECrsquos website at wwwsecgov

For a discussion of the risks set forth above and other factors that could cause actual results to differ materially from results referred to in the forward-looking statements seeldquoRisk Factorsrdquo in the Companyrsquos Form 10-K for the fiscal year ended September 30 2018 and the Forms 10-Q for the quarter ended March 31 2018 June 30 2018 and December31 2018 The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date thereof or to reflect the occurrence ofunanticipated events

Appendix

32

Fiscal 2019 Production and Price Certainty

~49 Bcfe

210 ndash 230 Bcfe

~114 Bcf

~29 Bcf (2)

16+- Bcf~12 Bcfe

0

40

80

120

160

200

240

YTD FY19Actuals

Fixed Price + FirmSales w Hedge

Firm Sales(Unhedged)

Spot Sales California TotalSeneca

Prod

uctio

n (B

cfe)

(1) Average realized price reflects uplift from financial hedges less fixed differentials under firm sales contracts and any firm transportation costs(2) Indicates firm sales contracts with fixed index differentials but not backed by a matching financial hedge

114 Bcf locked-in realizing net ~$241Mcf (1)

29 Bcf of additional basis protection

Spot production assumed to be sold

at ~$275Mmbtu(winter) and ~$225

(summer)

143 Bcf of Appalachian Production Protected by Firm Sales for Remainder of Year

79 of oil production hedged at $5757 Bbl

EampP and Gathering

33

Strong Hedge Book

Natural Gas Swap amp Fixed Physical Sales Contracts (Millions MMBtu)

(1) Fixed price physical sales exclude joint development partnerrsquos share of fixed price contract WDA volumes as specified under the joint development agreement(2) Reflects percentage of projected production for FY19 hedged at the midpoint of the production guidance range(3) Senecarsquos remainder FY19 Production reflects the total FY19 production guidance of 210-230 Bcfe or 220 Bcfe at the midpoint less Q1 actual production

Crude Oil Swap Contracts (Thousands Bbls)

13591188

732

456

0

500

1000

1500

2000

2500

FY 2019 FY 2020 FY 2021 FY 2022

NYMEX (WTI)

Brent

FY 19 Crude Oil79 Hedged (2)

FY 2019 Remaining Production (3)

EampP and Gathering

1174

709

469 406

0

50

100

150

200

250

FY 2019 FY 2020 FY 2021 FY 2022

NYMEX Swaps

Dawn Swaps

Fixed Price Physical Sales

(1)

FY 2019 Remaining Production (3)

FY 19 Nat Gas71 Hedged (2)

34

$065 $070$070 -$075

FY 2017 FY 2018 FY 2019E

$060 $060 $060

$011 $009 $007$071 $069 ~$067

FY 2017 FY 2018 FY 2019E Gathering amp Transport LOE (non-Gathering) GampA Taxes amp Other

Seneca Operating Costs

Competitive low cost structure in Appalachia and California supports strong cash margins

Gathering fee generates significant revenue stream for affiliated gathering company

Seneca DDampARate

$Mcfe

$054 $054 $056

$042 $038 $031

$034 $034 $030

$017 $014 $015

$147 $140 ~$132

FY 2017 FY 2018 FY 2019E

(1)

$1791$1746~$2050

FY 2017 FY 2018 FY 2019E

Appalachia LOE amp Gathering $Mcfe

California LOE$Boe

Total Seneca Cash OpEx$Mcfe

(1)

(2)

(2)

(1) GampA estimate represents the midpoint of the GampA guidance range of $025 to $035 for fiscal 2019(2) The total of the two LOE components represents the midpoint of the LOE guidance range of $085 to $090 for fiscal 2019

EampP and Gathering

35

Senecarsquos Continuing Commitment to the Environment

Produced Water Recycled in Appalachia

100 70Recycled Water

Used in New Shale Well

Completions

Water and Fluids Management Air Quality and Emissions

Seneca Resources Water OperationsFiscal 2018

Seneca Resources Remains Focused on Minimizing GHG Emissions

The Environmental Partnership

EPA Natural Gas Star Program

Green Completions (all fiscal 2018 wells)

Ultrasonic Leak Detection Technology

Emissions Controls

Rig and Vehicle Fuel Conversion

Integrating Renewable Energy into Operations

EampP and Gathering

36

Pipeline and Storage OverviewNational Fuel Gas Supply Corporation ~ Empire Pipeline Inc

37

Pipeline amp Storage Segment Overview

(1) As of September 30 2018 as disclosed in the Companyrsquos fiscal 2018 form 10-K(2) As of December 31 2017 calculated from National Fuel Gas Supply Corporationrsquos and Empire Pipeline Incrsquos 2017 FERC Form-2 reports respectively

Empire Pipeline Inc

National Fuel Gas Supply Corporation

Empire Pipeline

Supply Corp

Contracted Capacity(1) Firm Transportation 3187 MDth per day Firm Storage 71938 Mdth (fully subscribed)

Rate Base(2) ~$820 million FERC Rate Proceeding Status

Rate case settlement extension approved Nov lsquo15 Rate case filing expected by 73119

Contracted Capacity(1) Firm Transportation 978 MDth per day Firm Storage 3753 Mdth (fully subscribed)

Rate Base(2) ~$249 million FERC Rate Proceeding Status

Rate case settlement in principle reached on 122118 FERC approval pending

New transportation rates went into on 1119

Pipeline amp Storage

38

All Seneca volumes will flow through wholly-owned NFG gathering facilities

FM100 Project - Consolidated Benefit for NFG

330000 Dthd of new transportation capacity from WDA and EDA acreage positions to premium markets

New Transco capacity (Leidy South) 330000 Dthday

Rate(1) competitive with other expansion project rates in Senecarsquos current transportation portfolio

Delivery Point(s) Transco Zone 6 interconnections

Seneca

Lease to Transco of new capacity 330000 Dthday

Estimated annual lease revenues ~$35 million

Target In-Service late calendar year 2021

Supply Corp

Project expected to provide long-term earnings uplift to Seneca Supply Corp and Gathering

Pipeline amp Storage

Gathering

(1) Includes lease of new capacity from Supply Corp to Transco

39

FM100 Project ndash Significant Investment by Supply Corp

Pipeline amp Storage

Estimated Capital Cost $280 million(1)

Facilities (all in Pennsylvania) include Approximately 30 miles of new pipeline 2 new compressor stations (totaling

approximately 37000 HP) New interconnection station and modification

of existing interconnection station Abandonment of approximately 45 miles of

existing pipeline and compressor station Regulatory Process

Pre-filing application submitted to FERC in 2017 for original modernization project

FERC 7(b) 7(c) filing expected summer 2019

(1) Includes expansion and modernization portions of the project

40

Empire North Project

Target In-Service second half of fiscal 2020

Est Capital Cost $145 million

Est Annual Revenues ~$25 million

Receipt Point Jackson (Tioga Co Pa production)

Design Capacity and Delivery Points 175000 Dthd to Chippawa (TCPL interconnect)

30000 Dthd to Hopewell (TGP 200 interconnect)

Customers Fully subscribed (205000 Dthday)

Major Facilities 2 new compressor stations in NY (1) amp Pa (1)

No new pipeline construction

Regulatory Process FERC 7(c) application filed on 21618

FERC Environmental Assessment issued 103018

Pipeline amp Storage

Fully Subscribed Project will Provide 205000 Dthday of Incremental Firm Transportation

41

National Fuel Remains Committed to Northern Access Project

Target In-Service as early as fiscal 2022

Total Cost ~$500MM (~$76MM spent to date)

Estimated Annual Revenues ~$84 million

Delivery Points

350000 Dthd to Chippawa (TCPL interconnect)

140000 Dthd to Hopewell (TGP 200 line)

Regulatory Status

February 3 2017 ndash FERC 7(c) certificate issued

August 6 2018 ndash FERC issued Order finding that NY DEC waived water quality certification

Supply and Empire currently working to finalize remaining federal authorizations

Pipeline amp Storage

To Dawn

42

Continued Expansion of the NFG Supply System

Line N Expansion Opportunities

Line N to Monaca Project Project Firm transportation service to a new ethane

cracker facility being built by Shell Chemical Appalachia LLC

Target In-Service July 2019

Estimated Capital Cost $23 million

Contracted Capacity 133000 Dthday

Additional Line N Expansion Opportunity (Supply OS 221) Project New firm transportation service for on-system

demand

Open Season Capacity Awarded 165000 to foundation shipper Precedent agreement in negotiations

Pipeline amp Storage

43

Pipeline amp Storage Customer Mix

Producer33

LDC42

Marketer10

Outside Pipeline

9

End User6

42 MMDthd

(1) Contracted as of 10312018

Customer Transportation by Shipper Type(1) Affiliated Customer Mix (Contracted Capacity)

66

521

41

34

9579

59

LDCs Producers Marketers FirmStorage

Affiliated Non-Affiliated

Firm Transport

Pipeline amp Storage

44

Utility OverviewNational Fuel Gas Distribution Corporation

45

New York amp Pennsylvania Service Territories

New York

Total Customers(1) 535800ROE 87 (NY PSC Rate Case Order April 2017)Rate Mechanismso Revenue Decouplingo Weather Normalizationo Low Income Rateso Merchant Function Charge (Uncollectibles Adj)o 9010 Sharing (Large Customers)o System Modernization Tracker

Pennsylvania

Total Customers(1) 214400ROE Black Box Settlement (2007)Rate Mechanismso Low Income Rateso Merchant Function Charge

(1) As of September 30 2018

Utility

46

New York Rate Case Outcome

Rate Order Summary

Revenue Requirement $59 million

Rate Base $704 million

Allowed Return on Equity (ROE) 87

Capital Structure 429 equity

Other notable items

New rates became effective 5117

Retains rate mechanisms in place under prior order (revenue decoupling weather normalization merchant function charge 9010 large customer sharing)

No stay-out clause

System modernization tracker for Leak Prone Pipe (LPP)

Earnings sharing started 4118 (5050 sharing starts at earnings in excess of 92)

Article 78 appeal filed on 72817 with oral argument completed in January 2019

On April 20 2017 the New York Public Service Commission issued a Rate Order relating to NFG Distributionrsquos rate case (No 16-G-0257) filed in April 2016

Utility

47

Utility Continues its Significant Investments in Safety

$544$618 $636

$699

$944$980

$809$856

$90-100

$00

$250

$500

$750

$1000

$1250

2015 2016 2017 2018 2019E

Cap

ital E

xpen

ditu

res

($ m

illio

ns)

Fiscal Year

Capital Expenditures for Safety Total Capital Expenditures

Modernization Spending in NY Expected to Grow Gross Margin By $2 MM - $5 MM in FY 2019

(1)

(1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation

Utility

System modernization tracker in NY allows recovery of pipeline replacementcosts which is expected to drive modest gross margin and rate base growth

48

Accelerating Pipeline Replacement amp Modernization

Wrought Iron

Plastic

CoatedBare

120130

146 144159

2014 2015 2016 2017 2018Calendar Year

NY9726 miles

PA4830 miles

No Cast Iron Mains in Pa

Miles of Utility Main Pipeline ReplacedUtility Mains by Material(1)

Wrought Iron

Cast Iron

Plastic

Coated Bare

Utility

(1) All values are reported on a calendar year basis as of December 31 2018

49

A Proven History of Controlling Costs

$200 $189 $195

$166 $166

$31 $31

$197 $197

$0

$50

$100

$150

$200

$250

2015 2016 2017 2018 TTM 123118

Fiscal Year

OampM Expense Non-Service Pension Costs

OampM Expense ($ millions)

Utility

(1)

(1) For purposes of comparability to FY 2015 2016 and 2017 Utility Operation and Maintenance Expense for FY 2018 and the twelve months ended December 31 2018 was adjusted by approximately $314 million and $312 million respectively to include non-service pension costs which were re-classified as Other Income (Deductions) as of October 1 2018 on the Companyrsquos Income Statement See Slide 64 for non-GAAP reconciliation of Adjusted Operation and Maintenance Expense to Operation and Maintenance Expense by segment

50

Consolidated Financial OverviewUpstream I Midstream I Downstream

51

Adjusted Operating Results ($ per share)(1)

Diversified Balanced Earnings and Cash Flows

(1) A reconciliation of Adjusted Operating Results to Earnings per Share by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation(2) Consolidated Adjusted EBITDA includes Energy Marketing and Corporate amp All Other Segments A reconciliation of Adjusted EBITDA to Net Income by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in

the Business is included at the end of this presentation

Adjusted EBITDA ($ millions)(2)

$176 $179

$184 $181

$92 $97

$318 $327

$761 $775

$-

$200

$400

$600

$800

FY 2018 TTM 123118

$059 Utility

$097 Pipeline amp Storage

$057 Gathering

$125 Exploration

amp Production

$334 $345 to $365

$-

$100

$200

$300

$400

FY 2018 FY 2019 Guidance

Rate Regulated

40-45

$728

Rate Regulated

~46

52

$89 $94 $98 $81 $86 $90-$100

$140$230

$114 $95 $93 $120-$150

$138$118

$54$33 $48

$55-$65

$603$557

$99 $246$356

$460-$495

$970 $1001

$366$455

$583

$725-$810

$0

$250

$500

$750

$1000

$1250

2014 2015 2016 2017 2018 2019GuidanceFiscal Year

Exploration amp Production

Gathering

Pipeline amp Storage

Utility

Disciplined Flexible Capital Allocation

(2)

(1) Total Capital Expenditures include Energy Marketing Corporate and All Other A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation (2) FY16 FY17 and FY18 reflects the netting of $157 million $7 million and $17 million respectively of up-front proceeds received from joint development partner for working interest in joint development wells and $21M in intercompany asset transfers in FY18

Capital Expenditures by Segment ($ millions)(1)

53

Maintaining Strong Balance Sheet amp Liquidity

Total Equity49

Total Debt51

$42 Billion Total Capitalizationas of December 31 2018

218 x251 x 245 x 247 x 256 x

2015 2016 2017 2018 TTM 123118Fiscal Year End

Net Debt Adjusted EBITDA(1) Capitalization

Debt Maturity Profile ($MM) Liquidity

Committed Credit FacilitiesShort-term Debt OutstandingAvailable Short-term Credit FacilitiesCash Balance at 123118 Total Liquidity at 123118

$ 750 MM0 MM

750 MM110 MM

$ 860 MM

$500 $549 $500

$300 $300

$0

$200

$400

$600

(1) Net Debt is net of cash and temporary cash investments Reconciliations of Net Debt and Adjusted EBITDA to Net Income are included at the end of this presentation

54

Appendix

55

Safe Harbor For Forward Looking StatementsThis presentation may contain ldquoforward-looking statementsrdquo as defined by the Private Securities Litigation Reform Act of 1995 including statements regarding future prospectsplans objectives goals projections estimates of oil and gas quantities strategies future events or performance and underlying assumptions capital structure anticipatedcapital expenditures completion of construction projects projections for pension and other post-retirement benefit obligations impacts of the adoption of new accounting rulesand possible outcomes of litigation or regulatory proceedings as well as statements that are identified by the use of the words ldquoanticipatesrdquo ldquoestimatesrdquo ldquoexpectsrdquo ldquoforecastsrdquoldquointendsrdquo ldquoplansrdquo ldquopredictsrdquo ldquoprojectsrdquo ldquobelievesrdquo ldquoseeksrdquo ldquowillrdquo ldquomayrdquo and similar expressions Forward-looking statements involve risks and uncertainties which couldcause actual results or outcomes to differ materially from those expressed in the forward-looking statements The Companyrsquos expectations beliefs and projections are expressedin good faith and are believed by the Company to have a reasonable basis but there can be no assurance that managementrsquos expectations beliefs or projections will result or beachieved or accomplished

In addition to other factors the following are important factors that could cause actual results to differ materially from those discussed in the forward-looking statements delaysor changes in costs or plans with respect to Company projects or related projects of other companies including difficulties or delays in obtaining necessary governmentalapprovals permits or orders or in obtaining the cooperation of interconnecting facility operators governmentalregulatory actions initiatives and proceedings including thoseinvolving rate cases (which address among other things target rates of return rate design and retained natural gas) environmentalsafety requirements affiliate relationshipsindustry structure and franchise renewal changes in laws regulations or judicial interpretations to which the Company is subject including those involving derivatives taxessafety employment climate change other environmental matters real property and exploration and production activities such as hydraulic fracturing financial and economicconditions including the availability of credit and occurrences affecting the Companyrsquos ability to obtain financing on acceptable terms for working capital capital expendituresand other investments including any downgrades in the Companyrsquos credit ratings and changes in interest rates and other capital market conditions changes in the price ofnatural gas or oil impairments under the SECrsquos full cost ceiling test for natural gas and oil reserves factors affecting the Companyrsquos ability to successfully identify drill for andproduce economically viable natural gas and oil reserves including among others geology lease availability title disputes weather conditions shortages delays orunavailability of equipment and services required in drilling operations insufficient gathering processing and transportation capacity the need to obtain governmentalapprovals and permits and compliance with environmental laws and regulations increasing health care costs and the resulting effect on health insurance premiums and on theobligation to provide other post-retirement benefits changes in price differentials between similar quantities of natural gas or oil sold at different geographic locations and theeffect of such changes on commodity production revenues and demand for pipeline transportation capacity to or from such locations other changes in price differentialsbetween similar quantities of natural gas or oil having different quality heating value hydrocarbon mix or delivery date the cost and effects of legal and administrative claimsagainst the Company or activist shareholder campaigns to effect changes at the Company uncertainty of oil and gas reserve estimates significant differences between theCompanyrsquos projected and actual production levels for natural gas or oil changes in demographic patterns and weather conditions changes in the availability price oraccounting treatment of derivative financial instruments changes in laws actuarial assumptions the interest rate environment and the return on plantrust assets related to theCompanyrsquos pension and other post-retirement benefits which can affect future funding obligations and costs and plan liabilities changes in economic conditions includingglobal national or regional recessions and their effect on the demand for and customersrsquo ability to pay for the Companyrsquos products and services the creditworthiness orperformance of the Companyrsquos key suppliers customers and counterparties the impact of potential information technology cybersecurity or data security breaches economicdisruptions or uninsured losses resulting from major accidents fires severe weather natural disasters terrorist activities or acts of war significant differences between theCompanyrsquos projected and actual capital expenditures and operating expenses or increasing costs of insurance changes in coverage and the ability to obtain insurance

Forward-looking statements include estimates of oil and gas quantities Proved oil and gas reserves are those quantities of oil and gas which by analysis of geoscience andengineering data can be estimated with reasonable certainty to be economically producible under existing economic conditions operating methods and governmentregulations Other estimates of oil and gas quantities including estimates of probable reserves possible reserves and resource potential are by their nature more speculativethan estimates of proved reserves Accordingly estimates other than proved reserves are subject to substantially greater risk of being actually realized Investors are urged toconsider closely the disclosure in our Form 10-K available at wwwnationalfuelgascom You can also obtain this form on the SECrsquos website at wwwsecgov

For a discussion of the risks set forth above and other factors that could cause actual results to differ materially from results referred to in the forward-looking statements seeldquoRisk Factorsrdquo in the Companyrsquos Form 10-K for the fiscal year ended September 30 2018 and the Forms 10-Q for the quarter ended March 31 2018 June 30 2018 and December31 2018 The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date thereof or to reflect the occurrence ofunanticipated events

Appendix

33

Strong Hedge Book

Natural Gas Swap amp Fixed Physical Sales Contracts (Millions MMBtu)

(1) Fixed price physical sales exclude joint development partnerrsquos share of fixed price contract WDA volumes as specified under the joint development agreement(2) Reflects percentage of projected production for FY19 hedged at the midpoint of the production guidance range(3) Senecarsquos remainder FY19 Production reflects the total FY19 production guidance of 210-230 Bcfe or 220 Bcfe at the midpoint less Q1 actual production

Crude Oil Swap Contracts (Thousands Bbls)

13591188

732

456

0

500

1000

1500

2000

2500

FY 2019 FY 2020 FY 2021 FY 2022

NYMEX (WTI)

Brent

FY 19 Crude Oil79 Hedged (2)

FY 2019 Remaining Production (3)

EampP and Gathering

1174

709

469 406

0

50

100

150

200

250

FY 2019 FY 2020 FY 2021 FY 2022

NYMEX Swaps

Dawn Swaps

Fixed Price Physical Sales

(1)

FY 2019 Remaining Production (3)

FY 19 Nat Gas71 Hedged (2)

34

$065 $070$070 -$075

FY 2017 FY 2018 FY 2019E

$060 $060 $060

$011 $009 $007$071 $069 ~$067

FY 2017 FY 2018 FY 2019E Gathering amp Transport LOE (non-Gathering) GampA Taxes amp Other

Seneca Operating Costs

Competitive low cost structure in Appalachia and California supports strong cash margins

Gathering fee generates significant revenue stream for affiliated gathering company

Seneca DDampARate

$Mcfe

$054 $054 $056

$042 $038 $031

$034 $034 $030

$017 $014 $015

$147 $140 ~$132

FY 2017 FY 2018 FY 2019E

(1)

$1791$1746~$2050

FY 2017 FY 2018 FY 2019E

Appalachia LOE amp Gathering $Mcfe

California LOE$Boe

Total Seneca Cash OpEx$Mcfe

(1)

(2)

(2)

(1) GampA estimate represents the midpoint of the GampA guidance range of $025 to $035 for fiscal 2019(2) The total of the two LOE components represents the midpoint of the LOE guidance range of $085 to $090 for fiscal 2019

EampP and Gathering

35

Senecarsquos Continuing Commitment to the Environment

Produced Water Recycled in Appalachia

100 70Recycled Water

Used in New Shale Well

Completions

Water and Fluids Management Air Quality and Emissions

Seneca Resources Water OperationsFiscal 2018

Seneca Resources Remains Focused on Minimizing GHG Emissions

The Environmental Partnership

EPA Natural Gas Star Program

Green Completions (all fiscal 2018 wells)

Ultrasonic Leak Detection Technology

Emissions Controls

Rig and Vehicle Fuel Conversion

Integrating Renewable Energy into Operations

EampP and Gathering

36

Pipeline and Storage OverviewNational Fuel Gas Supply Corporation ~ Empire Pipeline Inc

37

Pipeline amp Storage Segment Overview

(1) As of September 30 2018 as disclosed in the Companyrsquos fiscal 2018 form 10-K(2) As of December 31 2017 calculated from National Fuel Gas Supply Corporationrsquos and Empire Pipeline Incrsquos 2017 FERC Form-2 reports respectively

Empire Pipeline Inc

National Fuel Gas Supply Corporation

Empire Pipeline

Supply Corp

Contracted Capacity(1) Firm Transportation 3187 MDth per day Firm Storage 71938 Mdth (fully subscribed)

Rate Base(2) ~$820 million FERC Rate Proceeding Status

Rate case settlement extension approved Nov lsquo15 Rate case filing expected by 73119

Contracted Capacity(1) Firm Transportation 978 MDth per day Firm Storage 3753 Mdth (fully subscribed)

Rate Base(2) ~$249 million FERC Rate Proceeding Status

Rate case settlement in principle reached on 122118 FERC approval pending

New transportation rates went into on 1119

Pipeline amp Storage

38

All Seneca volumes will flow through wholly-owned NFG gathering facilities

FM100 Project - Consolidated Benefit for NFG

330000 Dthd of new transportation capacity from WDA and EDA acreage positions to premium markets

New Transco capacity (Leidy South) 330000 Dthday

Rate(1) competitive with other expansion project rates in Senecarsquos current transportation portfolio

Delivery Point(s) Transco Zone 6 interconnections

Seneca

Lease to Transco of new capacity 330000 Dthday

Estimated annual lease revenues ~$35 million

Target In-Service late calendar year 2021

Supply Corp

Project expected to provide long-term earnings uplift to Seneca Supply Corp and Gathering

Pipeline amp Storage

Gathering

(1) Includes lease of new capacity from Supply Corp to Transco

39

FM100 Project ndash Significant Investment by Supply Corp

Pipeline amp Storage

Estimated Capital Cost $280 million(1)

Facilities (all in Pennsylvania) include Approximately 30 miles of new pipeline 2 new compressor stations (totaling

approximately 37000 HP) New interconnection station and modification

of existing interconnection station Abandonment of approximately 45 miles of

existing pipeline and compressor station Regulatory Process

Pre-filing application submitted to FERC in 2017 for original modernization project

FERC 7(b) 7(c) filing expected summer 2019

(1) Includes expansion and modernization portions of the project

40

Empire North Project

Target In-Service second half of fiscal 2020

Est Capital Cost $145 million

Est Annual Revenues ~$25 million

Receipt Point Jackson (Tioga Co Pa production)

Design Capacity and Delivery Points 175000 Dthd to Chippawa (TCPL interconnect)

30000 Dthd to Hopewell (TGP 200 interconnect)

Customers Fully subscribed (205000 Dthday)

Major Facilities 2 new compressor stations in NY (1) amp Pa (1)

No new pipeline construction

Regulatory Process FERC 7(c) application filed on 21618

FERC Environmental Assessment issued 103018

Pipeline amp Storage

Fully Subscribed Project will Provide 205000 Dthday of Incremental Firm Transportation

41

National Fuel Remains Committed to Northern Access Project

Target In-Service as early as fiscal 2022

Total Cost ~$500MM (~$76MM spent to date)

Estimated Annual Revenues ~$84 million

Delivery Points

350000 Dthd to Chippawa (TCPL interconnect)

140000 Dthd to Hopewell (TGP 200 line)

Regulatory Status

February 3 2017 ndash FERC 7(c) certificate issued

August 6 2018 ndash FERC issued Order finding that NY DEC waived water quality certification

Supply and Empire currently working to finalize remaining federal authorizations

Pipeline amp Storage

To Dawn

42

Continued Expansion of the NFG Supply System

Line N Expansion Opportunities

Line N to Monaca Project Project Firm transportation service to a new ethane

cracker facility being built by Shell Chemical Appalachia LLC

Target In-Service July 2019

Estimated Capital Cost $23 million

Contracted Capacity 133000 Dthday

Additional Line N Expansion Opportunity (Supply OS 221) Project New firm transportation service for on-system

demand

Open Season Capacity Awarded 165000 to foundation shipper Precedent agreement in negotiations

Pipeline amp Storage

43

Pipeline amp Storage Customer Mix

Producer33

LDC42

Marketer10

Outside Pipeline

9

End User6

42 MMDthd

(1) Contracted as of 10312018

Customer Transportation by Shipper Type(1) Affiliated Customer Mix (Contracted Capacity)

66

521

41

34

9579

59

LDCs Producers Marketers FirmStorage

Affiliated Non-Affiliated

Firm Transport

Pipeline amp Storage

44

Utility OverviewNational Fuel Gas Distribution Corporation

45

New York amp Pennsylvania Service Territories

New York

Total Customers(1) 535800ROE 87 (NY PSC Rate Case Order April 2017)Rate Mechanismso Revenue Decouplingo Weather Normalizationo Low Income Rateso Merchant Function Charge (Uncollectibles Adj)o 9010 Sharing (Large Customers)o System Modernization Tracker

Pennsylvania

Total Customers(1) 214400ROE Black Box Settlement (2007)Rate Mechanismso Low Income Rateso Merchant Function Charge

(1) As of September 30 2018

Utility

46

New York Rate Case Outcome

Rate Order Summary

Revenue Requirement $59 million

Rate Base $704 million

Allowed Return on Equity (ROE) 87

Capital Structure 429 equity

Other notable items

New rates became effective 5117

Retains rate mechanisms in place under prior order (revenue decoupling weather normalization merchant function charge 9010 large customer sharing)

No stay-out clause

System modernization tracker for Leak Prone Pipe (LPP)

Earnings sharing started 4118 (5050 sharing starts at earnings in excess of 92)

Article 78 appeal filed on 72817 with oral argument completed in January 2019

On April 20 2017 the New York Public Service Commission issued a Rate Order relating to NFG Distributionrsquos rate case (No 16-G-0257) filed in April 2016

Utility

47

Utility Continues its Significant Investments in Safety

$544$618 $636

$699

$944$980

$809$856

$90-100

$00

$250

$500

$750

$1000

$1250

2015 2016 2017 2018 2019E

Cap

ital E

xpen

ditu

res

($ m

illio

ns)

Fiscal Year

Capital Expenditures for Safety Total Capital Expenditures

Modernization Spending in NY Expected to Grow Gross Margin By $2 MM - $5 MM in FY 2019

(1)

(1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation

Utility

System modernization tracker in NY allows recovery of pipeline replacementcosts which is expected to drive modest gross margin and rate base growth

48

Accelerating Pipeline Replacement amp Modernization

Wrought Iron

Plastic

CoatedBare

120130

146 144159

2014 2015 2016 2017 2018Calendar Year

NY9726 miles

PA4830 miles

No Cast Iron Mains in Pa

Miles of Utility Main Pipeline ReplacedUtility Mains by Material(1)

Wrought Iron

Cast Iron

Plastic

Coated Bare

Utility

(1) All values are reported on a calendar year basis as of December 31 2018

49

A Proven History of Controlling Costs

$200 $189 $195

$166 $166

$31 $31

$197 $197

$0

$50

$100

$150

$200

$250

2015 2016 2017 2018 TTM 123118

Fiscal Year

OampM Expense Non-Service Pension Costs

OampM Expense ($ millions)

Utility

(1)

(1) For purposes of comparability to FY 2015 2016 and 2017 Utility Operation and Maintenance Expense for FY 2018 and the twelve months ended December 31 2018 was adjusted by approximately $314 million and $312 million respectively to include non-service pension costs which were re-classified as Other Income (Deductions) as of October 1 2018 on the Companyrsquos Income Statement See Slide 64 for non-GAAP reconciliation of Adjusted Operation and Maintenance Expense to Operation and Maintenance Expense by segment

50

Consolidated Financial OverviewUpstream I Midstream I Downstream

51

Adjusted Operating Results ($ per share)(1)

Diversified Balanced Earnings and Cash Flows

(1) A reconciliation of Adjusted Operating Results to Earnings per Share by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation(2) Consolidated Adjusted EBITDA includes Energy Marketing and Corporate amp All Other Segments A reconciliation of Adjusted EBITDA to Net Income by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in

the Business is included at the end of this presentation

Adjusted EBITDA ($ millions)(2)

$176 $179

$184 $181

$92 $97

$318 $327

$761 $775

$-

$200

$400

$600

$800

FY 2018 TTM 123118

$059 Utility

$097 Pipeline amp Storage

$057 Gathering

$125 Exploration

amp Production

$334 $345 to $365

$-

$100

$200

$300

$400

FY 2018 FY 2019 Guidance

Rate Regulated

40-45

$728

Rate Regulated

~46

52

$89 $94 $98 $81 $86 $90-$100

$140$230

$114 $95 $93 $120-$150

$138$118

$54$33 $48

$55-$65

$603$557

$99 $246$356

$460-$495

$970 $1001

$366$455

$583

$725-$810

$0

$250

$500

$750

$1000

$1250

2014 2015 2016 2017 2018 2019GuidanceFiscal Year

Exploration amp Production

Gathering

Pipeline amp Storage

Utility

Disciplined Flexible Capital Allocation

(2)

(1) Total Capital Expenditures include Energy Marketing Corporate and All Other A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation (2) FY16 FY17 and FY18 reflects the netting of $157 million $7 million and $17 million respectively of up-front proceeds received from joint development partner for working interest in joint development wells and $21M in intercompany asset transfers in FY18

Capital Expenditures by Segment ($ millions)(1)

53

Maintaining Strong Balance Sheet amp Liquidity

Total Equity49

Total Debt51

$42 Billion Total Capitalizationas of December 31 2018

218 x251 x 245 x 247 x 256 x

2015 2016 2017 2018 TTM 123118Fiscal Year End

Net Debt Adjusted EBITDA(1) Capitalization

Debt Maturity Profile ($MM) Liquidity

Committed Credit FacilitiesShort-term Debt OutstandingAvailable Short-term Credit FacilitiesCash Balance at 123118 Total Liquidity at 123118

$ 750 MM0 MM

750 MM110 MM

$ 860 MM

$500 $549 $500

$300 $300

$0

$200

$400

$600

(1) Net Debt is net of cash and temporary cash investments Reconciliations of Net Debt and Adjusted EBITDA to Net Income are included at the end of this presentation

54

Appendix

55

Safe Harbor For Forward Looking StatementsThis presentation may contain ldquoforward-looking statementsrdquo as defined by the Private Securities Litigation Reform Act of 1995 including statements regarding future prospectsplans objectives goals projections estimates of oil and gas quantities strategies future events or performance and underlying assumptions capital structure anticipatedcapital expenditures completion of construction projects projections for pension and other post-retirement benefit obligations impacts of the adoption of new accounting rulesand possible outcomes of litigation or regulatory proceedings as well as statements that are identified by the use of the words ldquoanticipatesrdquo ldquoestimatesrdquo ldquoexpectsrdquo ldquoforecastsrdquoldquointendsrdquo ldquoplansrdquo ldquopredictsrdquo ldquoprojectsrdquo ldquobelievesrdquo ldquoseeksrdquo ldquowillrdquo ldquomayrdquo and similar expressions Forward-looking statements involve risks and uncertainties which couldcause actual results or outcomes to differ materially from those expressed in the forward-looking statements The Companyrsquos expectations beliefs and projections are expressedin good faith and are believed by the Company to have a reasonable basis but there can be no assurance that managementrsquos expectations beliefs or projections will result or beachieved or accomplished

In addition to other factors the following are important factors that could cause actual results to differ materially from those discussed in the forward-looking statements delaysor changes in costs or plans with respect to Company projects or related projects of other companies including difficulties or delays in obtaining necessary governmentalapprovals permits or orders or in obtaining the cooperation of interconnecting facility operators governmentalregulatory actions initiatives and proceedings including thoseinvolving rate cases (which address among other things target rates of return rate design and retained natural gas) environmentalsafety requirements affiliate relationshipsindustry structure and franchise renewal changes in laws regulations or judicial interpretations to which the Company is subject including those involving derivatives taxessafety employment climate change other environmental matters real property and exploration and production activities such as hydraulic fracturing financial and economicconditions including the availability of credit and occurrences affecting the Companyrsquos ability to obtain financing on acceptable terms for working capital capital expendituresand other investments including any downgrades in the Companyrsquos credit ratings and changes in interest rates and other capital market conditions changes in the price ofnatural gas or oil impairments under the SECrsquos full cost ceiling test for natural gas and oil reserves factors affecting the Companyrsquos ability to successfully identify drill for andproduce economically viable natural gas and oil reserves including among others geology lease availability title disputes weather conditions shortages delays orunavailability of equipment and services required in drilling operations insufficient gathering processing and transportation capacity the need to obtain governmentalapprovals and permits and compliance with environmental laws and regulations increasing health care costs and the resulting effect on health insurance premiums and on theobligation to provide other post-retirement benefits changes in price differentials between similar quantities of natural gas or oil sold at different geographic locations and theeffect of such changes on commodity production revenues and demand for pipeline transportation capacity to or from such locations other changes in price differentialsbetween similar quantities of natural gas or oil having different quality heating value hydrocarbon mix or delivery date the cost and effects of legal and administrative claimsagainst the Company or activist shareholder campaigns to effect changes at the Company uncertainty of oil and gas reserve estimates significant differences between theCompanyrsquos projected and actual production levels for natural gas or oil changes in demographic patterns and weather conditions changes in the availability price oraccounting treatment of derivative financial instruments changes in laws actuarial assumptions the interest rate environment and the return on plantrust assets related to theCompanyrsquos pension and other post-retirement benefits which can affect future funding obligations and costs and plan liabilities changes in economic conditions includingglobal national or regional recessions and their effect on the demand for and customersrsquo ability to pay for the Companyrsquos products and services the creditworthiness orperformance of the Companyrsquos key suppliers customers and counterparties the impact of potential information technology cybersecurity or data security breaches economicdisruptions or uninsured losses resulting from major accidents fires severe weather natural disasters terrorist activities or acts of war significant differences between theCompanyrsquos projected and actual capital expenditures and operating expenses or increasing costs of insurance changes in coverage and the ability to obtain insurance

Forward-looking statements include estimates of oil and gas quantities Proved oil and gas reserves are those quantities of oil and gas which by analysis of geoscience andengineering data can be estimated with reasonable certainty to be economically producible under existing economic conditions operating methods and governmentregulations Other estimates of oil and gas quantities including estimates of probable reserves possible reserves and resource potential are by their nature more speculativethan estimates of proved reserves Accordingly estimates other than proved reserves are subject to substantially greater risk of being actually realized Investors are urged toconsider closely the disclosure in our Form 10-K available at wwwnationalfuelgascom You can also obtain this form on the SECrsquos website at wwwsecgov

For a discussion of the risks set forth above and other factors that could cause actual results to differ materially from results referred to in the forward-looking statements seeldquoRisk Factorsrdquo in the Companyrsquos Form 10-K for the fiscal year ended September 30 2018 and the Forms 10-Q for the quarter ended March 31 2018 June 30 2018 and December31 2018 The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date thereof or to reflect the occurrence ofunanticipated events

Appendix

34

$065 $070$070 -$075

FY 2017 FY 2018 FY 2019E

$060 $060 $060

$011 $009 $007$071 $069 ~$067

FY 2017 FY 2018 FY 2019E Gathering amp Transport LOE (non-Gathering) GampA Taxes amp Other

Seneca Operating Costs

Competitive low cost structure in Appalachia and California supports strong cash margins

Gathering fee generates significant revenue stream for affiliated gathering company

Seneca DDampARate

$Mcfe

$054 $054 $056

$042 $038 $031

$034 $034 $030

$017 $014 $015

$147 $140 ~$132

FY 2017 FY 2018 FY 2019E

(1)

$1791$1746~$2050

FY 2017 FY 2018 FY 2019E

Appalachia LOE amp Gathering $Mcfe

California LOE$Boe

Total Seneca Cash OpEx$Mcfe

(1)

(2)

(2)

(1) GampA estimate represents the midpoint of the GampA guidance range of $025 to $035 for fiscal 2019(2) The total of the two LOE components represents the midpoint of the LOE guidance range of $085 to $090 for fiscal 2019

EampP and Gathering

35

Senecarsquos Continuing Commitment to the Environment

Produced Water Recycled in Appalachia

100 70Recycled Water

Used in New Shale Well

Completions

Water and Fluids Management Air Quality and Emissions

Seneca Resources Water OperationsFiscal 2018

Seneca Resources Remains Focused on Minimizing GHG Emissions

The Environmental Partnership

EPA Natural Gas Star Program

Green Completions (all fiscal 2018 wells)

Ultrasonic Leak Detection Technology

Emissions Controls

Rig and Vehicle Fuel Conversion

Integrating Renewable Energy into Operations

EampP and Gathering

36

Pipeline and Storage OverviewNational Fuel Gas Supply Corporation ~ Empire Pipeline Inc

37

Pipeline amp Storage Segment Overview

(1) As of September 30 2018 as disclosed in the Companyrsquos fiscal 2018 form 10-K(2) As of December 31 2017 calculated from National Fuel Gas Supply Corporationrsquos and Empire Pipeline Incrsquos 2017 FERC Form-2 reports respectively

Empire Pipeline Inc

National Fuel Gas Supply Corporation

Empire Pipeline

Supply Corp

Contracted Capacity(1) Firm Transportation 3187 MDth per day Firm Storage 71938 Mdth (fully subscribed)

Rate Base(2) ~$820 million FERC Rate Proceeding Status

Rate case settlement extension approved Nov lsquo15 Rate case filing expected by 73119

Contracted Capacity(1) Firm Transportation 978 MDth per day Firm Storage 3753 Mdth (fully subscribed)

Rate Base(2) ~$249 million FERC Rate Proceeding Status

Rate case settlement in principle reached on 122118 FERC approval pending

New transportation rates went into on 1119

Pipeline amp Storage

38

All Seneca volumes will flow through wholly-owned NFG gathering facilities

FM100 Project - Consolidated Benefit for NFG

330000 Dthd of new transportation capacity from WDA and EDA acreage positions to premium markets

New Transco capacity (Leidy South) 330000 Dthday

Rate(1) competitive with other expansion project rates in Senecarsquos current transportation portfolio

Delivery Point(s) Transco Zone 6 interconnections

Seneca

Lease to Transco of new capacity 330000 Dthday

Estimated annual lease revenues ~$35 million

Target In-Service late calendar year 2021

Supply Corp

Project expected to provide long-term earnings uplift to Seneca Supply Corp and Gathering

Pipeline amp Storage

Gathering

(1) Includes lease of new capacity from Supply Corp to Transco

39

FM100 Project ndash Significant Investment by Supply Corp

Pipeline amp Storage

Estimated Capital Cost $280 million(1)

Facilities (all in Pennsylvania) include Approximately 30 miles of new pipeline 2 new compressor stations (totaling

approximately 37000 HP) New interconnection station and modification

of existing interconnection station Abandonment of approximately 45 miles of

existing pipeline and compressor station Regulatory Process

Pre-filing application submitted to FERC in 2017 for original modernization project

FERC 7(b) 7(c) filing expected summer 2019

(1) Includes expansion and modernization portions of the project

40

Empire North Project

Target In-Service second half of fiscal 2020

Est Capital Cost $145 million

Est Annual Revenues ~$25 million

Receipt Point Jackson (Tioga Co Pa production)

Design Capacity and Delivery Points 175000 Dthd to Chippawa (TCPL interconnect)

30000 Dthd to Hopewell (TGP 200 interconnect)

Customers Fully subscribed (205000 Dthday)

Major Facilities 2 new compressor stations in NY (1) amp Pa (1)

No new pipeline construction

Regulatory Process FERC 7(c) application filed on 21618

FERC Environmental Assessment issued 103018

Pipeline amp Storage

Fully Subscribed Project will Provide 205000 Dthday of Incremental Firm Transportation

41

National Fuel Remains Committed to Northern Access Project

Target In-Service as early as fiscal 2022

Total Cost ~$500MM (~$76MM spent to date)

Estimated Annual Revenues ~$84 million

Delivery Points

350000 Dthd to Chippawa (TCPL interconnect)

140000 Dthd to Hopewell (TGP 200 line)

Regulatory Status

February 3 2017 ndash FERC 7(c) certificate issued

August 6 2018 ndash FERC issued Order finding that NY DEC waived water quality certification

Supply and Empire currently working to finalize remaining federal authorizations

Pipeline amp Storage

To Dawn

42

Continued Expansion of the NFG Supply System

Line N Expansion Opportunities

Line N to Monaca Project Project Firm transportation service to a new ethane

cracker facility being built by Shell Chemical Appalachia LLC

Target In-Service July 2019

Estimated Capital Cost $23 million

Contracted Capacity 133000 Dthday

Additional Line N Expansion Opportunity (Supply OS 221) Project New firm transportation service for on-system

demand

Open Season Capacity Awarded 165000 to foundation shipper Precedent agreement in negotiations

Pipeline amp Storage

43

Pipeline amp Storage Customer Mix

Producer33

LDC42

Marketer10

Outside Pipeline

9

End User6

42 MMDthd

(1) Contracted as of 10312018

Customer Transportation by Shipper Type(1) Affiliated Customer Mix (Contracted Capacity)

66

521

41

34

9579

59

LDCs Producers Marketers FirmStorage

Affiliated Non-Affiliated

Firm Transport

Pipeline amp Storage

44

Utility OverviewNational Fuel Gas Distribution Corporation

45

New York amp Pennsylvania Service Territories

New York

Total Customers(1) 535800ROE 87 (NY PSC Rate Case Order April 2017)Rate Mechanismso Revenue Decouplingo Weather Normalizationo Low Income Rateso Merchant Function Charge (Uncollectibles Adj)o 9010 Sharing (Large Customers)o System Modernization Tracker

Pennsylvania

Total Customers(1) 214400ROE Black Box Settlement (2007)Rate Mechanismso Low Income Rateso Merchant Function Charge

(1) As of September 30 2018

Utility

46

New York Rate Case Outcome

Rate Order Summary

Revenue Requirement $59 million

Rate Base $704 million

Allowed Return on Equity (ROE) 87

Capital Structure 429 equity

Other notable items

New rates became effective 5117

Retains rate mechanisms in place under prior order (revenue decoupling weather normalization merchant function charge 9010 large customer sharing)

No stay-out clause

System modernization tracker for Leak Prone Pipe (LPP)

Earnings sharing started 4118 (5050 sharing starts at earnings in excess of 92)

Article 78 appeal filed on 72817 with oral argument completed in January 2019

On April 20 2017 the New York Public Service Commission issued a Rate Order relating to NFG Distributionrsquos rate case (No 16-G-0257) filed in April 2016

Utility

47

Utility Continues its Significant Investments in Safety

$544$618 $636

$699

$944$980

$809$856

$90-100

$00

$250

$500

$750

$1000

$1250

2015 2016 2017 2018 2019E

Cap

ital E

xpen

ditu

res

($ m

illio

ns)

Fiscal Year

Capital Expenditures for Safety Total Capital Expenditures

Modernization Spending in NY Expected to Grow Gross Margin By $2 MM - $5 MM in FY 2019

(1)

(1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation

Utility

System modernization tracker in NY allows recovery of pipeline replacementcosts which is expected to drive modest gross margin and rate base growth

48

Accelerating Pipeline Replacement amp Modernization

Wrought Iron

Plastic

CoatedBare

120130

146 144159

2014 2015 2016 2017 2018Calendar Year

NY9726 miles

PA4830 miles

No Cast Iron Mains in Pa

Miles of Utility Main Pipeline ReplacedUtility Mains by Material(1)

Wrought Iron

Cast Iron

Plastic

Coated Bare

Utility

(1) All values are reported on a calendar year basis as of December 31 2018

49

A Proven History of Controlling Costs

$200 $189 $195

$166 $166

$31 $31

$197 $197

$0

$50

$100

$150

$200

$250

2015 2016 2017 2018 TTM 123118

Fiscal Year

OampM Expense Non-Service Pension Costs

OampM Expense ($ millions)

Utility

(1)

(1) For purposes of comparability to FY 2015 2016 and 2017 Utility Operation and Maintenance Expense for FY 2018 and the twelve months ended December 31 2018 was adjusted by approximately $314 million and $312 million respectively to include non-service pension costs which were re-classified as Other Income (Deductions) as of October 1 2018 on the Companyrsquos Income Statement See Slide 64 for non-GAAP reconciliation of Adjusted Operation and Maintenance Expense to Operation and Maintenance Expense by segment

50

Consolidated Financial OverviewUpstream I Midstream I Downstream

51

Adjusted Operating Results ($ per share)(1)

Diversified Balanced Earnings and Cash Flows

(1) A reconciliation of Adjusted Operating Results to Earnings per Share by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation(2) Consolidated Adjusted EBITDA includes Energy Marketing and Corporate amp All Other Segments A reconciliation of Adjusted EBITDA to Net Income by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in

the Business is included at the end of this presentation

Adjusted EBITDA ($ millions)(2)

$176 $179

$184 $181

$92 $97

$318 $327

$761 $775

$-

$200

$400

$600

$800

FY 2018 TTM 123118

$059 Utility

$097 Pipeline amp Storage

$057 Gathering

$125 Exploration

amp Production

$334 $345 to $365

$-

$100

$200

$300

$400

FY 2018 FY 2019 Guidance

Rate Regulated

40-45

$728

Rate Regulated

~46

52

$89 $94 $98 $81 $86 $90-$100

$140$230

$114 $95 $93 $120-$150

$138$118

$54$33 $48

$55-$65

$603$557

$99 $246$356

$460-$495

$970 $1001

$366$455

$583

$725-$810

$0

$250

$500

$750

$1000

$1250

2014 2015 2016 2017 2018 2019GuidanceFiscal Year

Exploration amp Production

Gathering

Pipeline amp Storage

Utility

Disciplined Flexible Capital Allocation

(2)

(1) Total Capital Expenditures include Energy Marketing Corporate and All Other A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation (2) FY16 FY17 and FY18 reflects the netting of $157 million $7 million and $17 million respectively of up-front proceeds received from joint development partner for working interest in joint development wells and $21M in intercompany asset transfers in FY18

Capital Expenditures by Segment ($ millions)(1)

53

Maintaining Strong Balance Sheet amp Liquidity

Total Equity49

Total Debt51

$42 Billion Total Capitalizationas of December 31 2018

218 x251 x 245 x 247 x 256 x

2015 2016 2017 2018 TTM 123118Fiscal Year End

Net Debt Adjusted EBITDA(1) Capitalization

Debt Maturity Profile ($MM) Liquidity

Committed Credit FacilitiesShort-term Debt OutstandingAvailable Short-term Credit FacilitiesCash Balance at 123118 Total Liquidity at 123118

$ 750 MM0 MM

750 MM110 MM

$ 860 MM

$500 $549 $500

$300 $300

$0

$200

$400

$600

(1) Net Debt is net of cash and temporary cash investments Reconciliations of Net Debt and Adjusted EBITDA to Net Income are included at the end of this presentation

54

Appendix

55

Safe Harbor For Forward Looking StatementsThis presentation may contain ldquoforward-looking statementsrdquo as defined by the Private Securities Litigation Reform Act of 1995 including statements regarding future prospectsplans objectives goals projections estimates of oil and gas quantities strategies future events or performance and underlying assumptions capital structure anticipatedcapital expenditures completion of construction projects projections for pension and other post-retirement benefit obligations impacts of the adoption of new accounting rulesand possible outcomes of litigation or regulatory proceedings as well as statements that are identified by the use of the words ldquoanticipatesrdquo ldquoestimatesrdquo ldquoexpectsrdquo ldquoforecastsrdquoldquointendsrdquo ldquoplansrdquo ldquopredictsrdquo ldquoprojectsrdquo ldquobelievesrdquo ldquoseeksrdquo ldquowillrdquo ldquomayrdquo and similar expressions Forward-looking statements involve risks and uncertainties which couldcause actual results or outcomes to differ materially from those expressed in the forward-looking statements The Companyrsquos expectations beliefs and projections are expressedin good faith and are believed by the Company to have a reasonable basis but there can be no assurance that managementrsquos expectations beliefs or projections will result or beachieved or accomplished

In addition to other factors the following are important factors that could cause actual results to differ materially from those discussed in the forward-looking statements delaysor changes in costs or plans with respect to Company projects or related projects of other companies including difficulties or delays in obtaining necessary governmentalapprovals permits or orders or in obtaining the cooperation of interconnecting facility operators governmentalregulatory actions initiatives and proceedings including thoseinvolving rate cases (which address among other things target rates of return rate design and retained natural gas) environmentalsafety requirements affiliate relationshipsindustry structure and franchise renewal changes in laws regulations or judicial interpretations to which the Company is subject including those involving derivatives taxessafety employment climate change other environmental matters real property and exploration and production activities such as hydraulic fracturing financial and economicconditions including the availability of credit and occurrences affecting the Companyrsquos ability to obtain financing on acceptable terms for working capital capital expendituresand other investments including any downgrades in the Companyrsquos credit ratings and changes in interest rates and other capital market conditions changes in the price ofnatural gas or oil impairments under the SECrsquos full cost ceiling test for natural gas and oil reserves factors affecting the Companyrsquos ability to successfully identify drill for andproduce economically viable natural gas and oil reserves including among others geology lease availability title disputes weather conditions shortages delays orunavailability of equipment and services required in drilling operations insufficient gathering processing and transportation capacity the need to obtain governmentalapprovals and permits and compliance with environmental laws and regulations increasing health care costs and the resulting effect on health insurance premiums and on theobligation to provide other post-retirement benefits changes in price differentials between similar quantities of natural gas or oil sold at different geographic locations and theeffect of such changes on commodity production revenues and demand for pipeline transportation capacity to or from such locations other changes in price differentialsbetween similar quantities of natural gas or oil having different quality heating value hydrocarbon mix or delivery date the cost and effects of legal and administrative claimsagainst the Company or activist shareholder campaigns to effect changes at the Company uncertainty of oil and gas reserve estimates significant differences between theCompanyrsquos projected and actual production levels for natural gas or oil changes in demographic patterns and weather conditions changes in the availability price oraccounting treatment of derivative financial instruments changes in laws actuarial assumptions the interest rate environment and the return on plantrust assets related to theCompanyrsquos pension and other post-retirement benefits which can affect future funding obligations and costs and plan liabilities changes in economic conditions includingglobal national or regional recessions and their effect on the demand for and customersrsquo ability to pay for the Companyrsquos products and services the creditworthiness orperformance of the Companyrsquos key suppliers customers and counterparties the impact of potential information technology cybersecurity or data security breaches economicdisruptions or uninsured losses resulting from major accidents fires severe weather natural disasters terrorist activities or acts of war significant differences between theCompanyrsquos projected and actual capital expenditures and operating expenses or increasing costs of insurance changes in coverage and the ability to obtain insurance

Forward-looking statements include estimates of oil and gas quantities Proved oil and gas reserves are those quantities of oil and gas which by analysis of geoscience andengineering data can be estimated with reasonable certainty to be economically producible under existing economic conditions operating methods and governmentregulations Other estimates of oil and gas quantities including estimates of probable reserves possible reserves and resource potential are by their nature more speculativethan estimates of proved reserves Accordingly estimates other than proved reserves are subject to substantially greater risk of being actually realized Investors are urged toconsider closely the disclosure in our Form 10-K available at wwwnationalfuelgascom You can also obtain this form on the SECrsquos website at wwwsecgov

For a discussion of the risks set forth above and other factors that could cause actual results to differ materially from results referred to in the forward-looking statements seeldquoRisk Factorsrdquo in the Companyrsquos Form 10-K for the fiscal year ended September 30 2018 and the Forms 10-Q for the quarter ended March 31 2018 June 30 2018 and December31 2018 The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date thereof or to reflect the occurrence ofunanticipated events

Appendix

35

Senecarsquos Continuing Commitment to the Environment

Produced Water Recycled in Appalachia

100 70Recycled Water

Used in New Shale Well

Completions

Water and Fluids Management Air Quality and Emissions

Seneca Resources Water OperationsFiscal 2018

Seneca Resources Remains Focused on Minimizing GHG Emissions

The Environmental Partnership

EPA Natural Gas Star Program

Green Completions (all fiscal 2018 wells)

Ultrasonic Leak Detection Technology

Emissions Controls

Rig and Vehicle Fuel Conversion

Integrating Renewable Energy into Operations

EampP and Gathering

36

Pipeline and Storage OverviewNational Fuel Gas Supply Corporation ~ Empire Pipeline Inc

37

Pipeline amp Storage Segment Overview

(1) As of September 30 2018 as disclosed in the Companyrsquos fiscal 2018 form 10-K(2) As of December 31 2017 calculated from National Fuel Gas Supply Corporationrsquos and Empire Pipeline Incrsquos 2017 FERC Form-2 reports respectively

Empire Pipeline Inc

National Fuel Gas Supply Corporation

Empire Pipeline

Supply Corp

Contracted Capacity(1) Firm Transportation 3187 MDth per day Firm Storage 71938 Mdth (fully subscribed)

Rate Base(2) ~$820 million FERC Rate Proceeding Status

Rate case settlement extension approved Nov lsquo15 Rate case filing expected by 73119

Contracted Capacity(1) Firm Transportation 978 MDth per day Firm Storage 3753 Mdth (fully subscribed)

Rate Base(2) ~$249 million FERC Rate Proceeding Status

Rate case settlement in principle reached on 122118 FERC approval pending

New transportation rates went into on 1119

Pipeline amp Storage

38

All Seneca volumes will flow through wholly-owned NFG gathering facilities

FM100 Project - Consolidated Benefit for NFG

330000 Dthd of new transportation capacity from WDA and EDA acreage positions to premium markets

New Transco capacity (Leidy South) 330000 Dthday

Rate(1) competitive with other expansion project rates in Senecarsquos current transportation portfolio

Delivery Point(s) Transco Zone 6 interconnections

Seneca

Lease to Transco of new capacity 330000 Dthday

Estimated annual lease revenues ~$35 million

Target In-Service late calendar year 2021

Supply Corp

Project expected to provide long-term earnings uplift to Seneca Supply Corp and Gathering

Pipeline amp Storage

Gathering

(1) Includes lease of new capacity from Supply Corp to Transco

39

FM100 Project ndash Significant Investment by Supply Corp

Pipeline amp Storage

Estimated Capital Cost $280 million(1)

Facilities (all in Pennsylvania) include Approximately 30 miles of new pipeline 2 new compressor stations (totaling

approximately 37000 HP) New interconnection station and modification

of existing interconnection station Abandonment of approximately 45 miles of

existing pipeline and compressor station Regulatory Process

Pre-filing application submitted to FERC in 2017 for original modernization project

FERC 7(b) 7(c) filing expected summer 2019

(1) Includes expansion and modernization portions of the project

40

Empire North Project

Target In-Service second half of fiscal 2020

Est Capital Cost $145 million

Est Annual Revenues ~$25 million

Receipt Point Jackson (Tioga Co Pa production)

Design Capacity and Delivery Points 175000 Dthd to Chippawa (TCPL interconnect)

30000 Dthd to Hopewell (TGP 200 interconnect)

Customers Fully subscribed (205000 Dthday)

Major Facilities 2 new compressor stations in NY (1) amp Pa (1)

No new pipeline construction

Regulatory Process FERC 7(c) application filed on 21618

FERC Environmental Assessment issued 103018

Pipeline amp Storage

Fully Subscribed Project will Provide 205000 Dthday of Incremental Firm Transportation

41

National Fuel Remains Committed to Northern Access Project

Target In-Service as early as fiscal 2022

Total Cost ~$500MM (~$76MM spent to date)

Estimated Annual Revenues ~$84 million

Delivery Points

350000 Dthd to Chippawa (TCPL interconnect)

140000 Dthd to Hopewell (TGP 200 line)

Regulatory Status

February 3 2017 ndash FERC 7(c) certificate issued

August 6 2018 ndash FERC issued Order finding that NY DEC waived water quality certification

Supply and Empire currently working to finalize remaining federal authorizations

Pipeline amp Storage

To Dawn

42

Continued Expansion of the NFG Supply System

Line N Expansion Opportunities

Line N to Monaca Project Project Firm transportation service to a new ethane

cracker facility being built by Shell Chemical Appalachia LLC

Target In-Service July 2019

Estimated Capital Cost $23 million

Contracted Capacity 133000 Dthday

Additional Line N Expansion Opportunity (Supply OS 221) Project New firm transportation service for on-system

demand

Open Season Capacity Awarded 165000 to foundation shipper Precedent agreement in negotiations

Pipeline amp Storage

43

Pipeline amp Storage Customer Mix

Producer33

LDC42

Marketer10

Outside Pipeline

9

End User6

42 MMDthd

(1) Contracted as of 10312018

Customer Transportation by Shipper Type(1) Affiliated Customer Mix (Contracted Capacity)

66

521

41

34

9579

59

LDCs Producers Marketers FirmStorage

Affiliated Non-Affiliated

Firm Transport

Pipeline amp Storage

44

Utility OverviewNational Fuel Gas Distribution Corporation

45

New York amp Pennsylvania Service Territories

New York

Total Customers(1) 535800ROE 87 (NY PSC Rate Case Order April 2017)Rate Mechanismso Revenue Decouplingo Weather Normalizationo Low Income Rateso Merchant Function Charge (Uncollectibles Adj)o 9010 Sharing (Large Customers)o System Modernization Tracker

Pennsylvania

Total Customers(1) 214400ROE Black Box Settlement (2007)Rate Mechanismso Low Income Rateso Merchant Function Charge

(1) As of September 30 2018

Utility

46

New York Rate Case Outcome

Rate Order Summary

Revenue Requirement $59 million

Rate Base $704 million

Allowed Return on Equity (ROE) 87

Capital Structure 429 equity

Other notable items

New rates became effective 5117

Retains rate mechanisms in place under prior order (revenue decoupling weather normalization merchant function charge 9010 large customer sharing)

No stay-out clause

System modernization tracker for Leak Prone Pipe (LPP)

Earnings sharing started 4118 (5050 sharing starts at earnings in excess of 92)

Article 78 appeal filed on 72817 with oral argument completed in January 2019

On April 20 2017 the New York Public Service Commission issued a Rate Order relating to NFG Distributionrsquos rate case (No 16-G-0257) filed in April 2016

Utility

47

Utility Continues its Significant Investments in Safety

$544$618 $636

$699

$944$980

$809$856

$90-100

$00

$250

$500

$750

$1000

$1250

2015 2016 2017 2018 2019E

Cap

ital E

xpen

ditu

res

($ m

illio

ns)

Fiscal Year

Capital Expenditures for Safety Total Capital Expenditures

Modernization Spending in NY Expected to Grow Gross Margin By $2 MM - $5 MM in FY 2019

(1)

(1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation

Utility

System modernization tracker in NY allows recovery of pipeline replacementcosts which is expected to drive modest gross margin and rate base growth

48

Accelerating Pipeline Replacement amp Modernization

Wrought Iron

Plastic

CoatedBare

120130

146 144159

2014 2015 2016 2017 2018Calendar Year

NY9726 miles

PA4830 miles

No Cast Iron Mains in Pa

Miles of Utility Main Pipeline ReplacedUtility Mains by Material(1)

Wrought Iron

Cast Iron

Plastic

Coated Bare

Utility

(1) All values are reported on a calendar year basis as of December 31 2018

49

A Proven History of Controlling Costs

$200 $189 $195

$166 $166

$31 $31

$197 $197

$0

$50

$100

$150

$200

$250

2015 2016 2017 2018 TTM 123118

Fiscal Year

OampM Expense Non-Service Pension Costs

OampM Expense ($ millions)

Utility

(1)

(1) For purposes of comparability to FY 2015 2016 and 2017 Utility Operation and Maintenance Expense for FY 2018 and the twelve months ended December 31 2018 was adjusted by approximately $314 million and $312 million respectively to include non-service pension costs which were re-classified as Other Income (Deductions) as of October 1 2018 on the Companyrsquos Income Statement See Slide 64 for non-GAAP reconciliation of Adjusted Operation and Maintenance Expense to Operation and Maintenance Expense by segment

50

Consolidated Financial OverviewUpstream I Midstream I Downstream

51

Adjusted Operating Results ($ per share)(1)

Diversified Balanced Earnings and Cash Flows

(1) A reconciliation of Adjusted Operating Results to Earnings per Share by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation(2) Consolidated Adjusted EBITDA includes Energy Marketing and Corporate amp All Other Segments A reconciliation of Adjusted EBITDA to Net Income by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in

the Business is included at the end of this presentation

Adjusted EBITDA ($ millions)(2)

$176 $179

$184 $181

$92 $97

$318 $327

$761 $775

$-

$200

$400

$600

$800

FY 2018 TTM 123118

$059 Utility

$097 Pipeline amp Storage

$057 Gathering

$125 Exploration

amp Production

$334 $345 to $365

$-

$100

$200

$300

$400

FY 2018 FY 2019 Guidance

Rate Regulated

40-45

$728

Rate Regulated

~46

52

$89 $94 $98 $81 $86 $90-$100

$140$230

$114 $95 $93 $120-$150

$138$118

$54$33 $48

$55-$65

$603$557

$99 $246$356

$460-$495

$970 $1001

$366$455

$583

$725-$810

$0

$250

$500

$750

$1000

$1250

2014 2015 2016 2017 2018 2019GuidanceFiscal Year

Exploration amp Production

Gathering

Pipeline amp Storage

Utility

Disciplined Flexible Capital Allocation

(2)

(1) Total Capital Expenditures include Energy Marketing Corporate and All Other A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation (2) FY16 FY17 and FY18 reflects the netting of $157 million $7 million and $17 million respectively of up-front proceeds received from joint development partner for working interest in joint development wells and $21M in intercompany asset transfers in FY18

Capital Expenditures by Segment ($ millions)(1)

53

Maintaining Strong Balance Sheet amp Liquidity

Total Equity49

Total Debt51

$42 Billion Total Capitalizationas of December 31 2018

218 x251 x 245 x 247 x 256 x

2015 2016 2017 2018 TTM 123118Fiscal Year End

Net Debt Adjusted EBITDA(1) Capitalization

Debt Maturity Profile ($MM) Liquidity

Committed Credit FacilitiesShort-term Debt OutstandingAvailable Short-term Credit FacilitiesCash Balance at 123118 Total Liquidity at 123118

$ 750 MM0 MM

750 MM110 MM

$ 860 MM

$500 $549 $500

$300 $300

$0

$200

$400

$600

(1) Net Debt is net of cash and temporary cash investments Reconciliations of Net Debt and Adjusted EBITDA to Net Income are included at the end of this presentation

54

Appendix

55

Safe Harbor For Forward Looking StatementsThis presentation may contain ldquoforward-looking statementsrdquo as defined by the Private Securities Litigation Reform Act of 1995 including statements regarding future prospectsplans objectives goals projections estimates of oil and gas quantities strategies future events or performance and underlying assumptions capital structure anticipatedcapital expenditures completion of construction projects projections for pension and other post-retirement benefit obligations impacts of the adoption of new accounting rulesand possible outcomes of litigation or regulatory proceedings as well as statements that are identified by the use of the words ldquoanticipatesrdquo ldquoestimatesrdquo ldquoexpectsrdquo ldquoforecastsrdquoldquointendsrdquo ldquoplansrdquo ldquopredictsrdquo ldquoprojectsrdquo ldquobelievesrdquo ldquoseeksrdquo ldquowillrdquo ldquomayrdquo and similar expressions Forward-looking statements involve risks and uncertainties which couldcause actual results or outcomes to differ materially from those expressed in the forward-looking statements The Companyrsquos expectations beliefs and projections are expressedin good faith and are believed by the Company to have a reasonable basis but there can be no assurance that managementrsquos expectations beliefs or projections will result or beachieved or accomplished

In addition to other factors the following are important factors that could cause actual results to differ materially from those discussed in the forward-looking statements delaysor changes in costs or plans with respect to Company projects or related projects of other companies including difficulties or delays in obtaining necessary governmentalapprovals permits or orders or in obtaining the cooperation of interconnecting facility operators governmentalregulatory actions initiatives and proceedings including thoseinvolving rate cases (which address among other things target rates of return rate design and retained natural gas) environmentalsafety requirements affiliate relationshipsindustry structure and franchise renewal changes in laws regulations or judicial interpretations to which the Company is subject including those involving derivatives taxessafety employment climate change other environmental matters real property and exploration and production activities such as hydraulic fracturing financial and economicconditions including the availability of credit and occurrences affecting the Companyrsquos ability to obtain financing on acceptable terms for working capital capital expendituresand other investments including any downgrades in the Companyrsquos credit ratings and changes in interest rates and other capital market conditions changes in the price ofnatural gas or oil impairments under the SECrsquos full cost ceiling test for natural gas and oil reserves factors affecting the Companyrsquos ability to successfully identify drill for andproduce economically viable natural gas and oil reserves including among others geology lease availability title disputes weather conditions shortages delays orunavailability of equipment and services required in drilling operations insufficient gathering processing and transportation capacity the need to obtain governmentalapprovals and permits and compliance with environmental laws and regulations increasing health care costs and the resulting effect on health insurance premiums and on theobligation to provide other post-retirement benefits changes in price differentials between similar quantities of natural gas or oil sold at different geographic locations and theeffect of such changes on commodity production revenues and demand for pipeline transportation capacity to or from such locations other changes in price differentialsbetween similar quantities of natural gas or oil having different quality heating value hydrocarbon mix or delivery date the cost and effects of legal and administrative claimsagainst the Company or activist shareholder campaigns to effect changes at the Company uncertainty of oil and gas reserve estimates significant differences between theCompanyrsquos projected and actual production levels for natural gas or oil changes in demographic patterns and weather conditions changes in the availability price oraccounting treatment of derivative financial instruments changes in laws actuarial assumptions the interest rate environment and the return on plantrust assets related to theCompanyrsquos pension and other post-retirement benefits which can affect future funding obligations and costs and plan liabilities changes in economic conditions includingglobal national or regional recessions and their effect on the demand for and customersrsquo ability to pay for the Companyrsquos products and services the creditworthiness orperformance of the Companyrsquos key suppliers customers and counterparties the impact of potential information technology cybersecurity or data security breaches economicdisruptions or uninsured losses resulting from major accidents fires severe weather natural disasters terrorist activities or acts of war significant differences between theCompanyrsquos projected and actual capital expenditures and operating expenses or increasing costs of insurance changes in coverage and the ability to obtain insurance

Forward-looking statements include estimates of oil and gas quantities Proved oil and gas reserves are those quantities of oil and gas which by analysis of geoscience andengineering data can be estimated with reasonable certainty to be economically producible under existing economic conditions operating methods and governmentregulations Other estimates of oil and gas quantities including estimates of probable reserves possible reserves and resource potential are by their nature more speculativethan estimates of proved reserves Accordingly estimates other than proved reserves are subject to substantially greater risk of being actually realized Investors are urged toconsider closely the disclosure in our Form 10-K available at wwwnationalfuelgascom You can also obtain this form on the SECrsquos website at wwwsecgov

For a discussion of the risks set forth above and other factors that could cause actual results to differ materially from results referred to in the forward-looking statements seeldquoRisk Factorsrdquo in the Companyrsquos Form 10-K for the fiscal year ended September 30 2018 and the Forms 10-Q for the quarter ended March 31 2018 June 30 2018 and December31 2018 The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date thereof or to reflect the occurrence ofunanticipated events

Appendix

36

Pipeline and Storage OverviewNational Fuel Gas Supply Corporation ~ Empire Pipeline Inc

37

Pipeline amp Storage Segment Overview

(1) As of September 30 2018 as disclosed in the Companyrsquos fiscal 2018 form 10-K(2) As of December 31 2017 calculated from National Fuel Gas Supply Corporationrsquos and Empire Pipeline Incrsquos 2017 FERC Form-2 reports respectively

Empire Pipeline Inc

National Fuel Gas Supply Corporation

Empire Pipeline

Supply Corp

Contracted Capacity(1) Firm Transportation 3187 MDth per day Firm Storage 71938 Mdth (fully subscribed)

Rate Base(2) ~$820 million FERC Rate Proceeding Status

Rate case settlement extension approved Nov lsquo15 Rate case filing expected by 73119

Contracted Capacity(1) Firm Transportation 978 MDth per day Firm Storage 3753 Mdth (fully subscribed)

Rate Base(2) ~$249 million FERC Rate Proceeding Status

Rate case settlement in principle reached on 122118 FERC approval pending

New transportation rates went into on 1119

Pipeline amp Storage

38

All Seneca volumes will flow through wholly-owned NFG gathering facilities

FM100 Project - Consolidated Benefit for NFG

330000 Dthd of new transportation capacity from WDA and EDA acreage positions to premium markets

New Transco capacity (Leidy South) 330000 Dthday

Rate(1) competitive with other expansion project rates in Senecarsquos current transportation portfolio

Delivery Point(s) Transco Zone 6 interconnections

Seneca

Lease to Transco of new capacity 330000 Dthday

Estimated annual lease revenues ~$35 million

Target In-Service late calendar year 2021

Supply Corp

Project expected to provide long-term earnings uplift to Seneca Supply Corp and Gathering

Pipeline amp Storage

Gathering

(1) Includes lease of new capacity from Supply Corp to Transco

39

FM100 Project ndash Significant Investment by Supply Corp

Pipeline amp Storage

Estimated Capital Cost $280 million(1)

Facilities (all in Pennsylvania) include Approximately 30 miles of new pipeline 2 new compressor stations (totaling

approximately 37000 HP) New interconnection station and modification

of existing interconnection station Abandonment of approximately 45 miles of

existing pipeline and compressor station Regulatory Process

Pre-filing application submitted to FERC in 2017 for original modernization project

FERC 7(b) 7(c) filing expected summer 2019

(1) Includes expansion and modernization portions of the project

40

Empire North Project

Target In-Service second half of fiscal 2020

Est Capital Cost $145 million

Est Annual Revenues ~$25 million

Receipt Point Jackson (Tioga Co Pa production)

Design Capacity and Delivery Points 175000 Dthd to Chippawa (TCPL interconnect)

30000 Dthd to Hopewell (TGP 200 interconnect)

Customers Fully subscribed (205000 Dthday)

Major Facilities 2 new compressor stations in NY (1) amp Pa (1)

No new pipeline construction

Regulatory Process FERC 7(c) application filed on 21618

FERC Environmental Assessment issued 103018

Pipeline amp Storage

Fully Subscribed Project will Provide 205000 Dthday of Incremental Firm Transportation

41

National Fuel Remains Committed to Northern Access Project

Target In-Service as early as fiscal 2022

Total Cost ~$500MM (~$76MM spent to date)

Estimated Annual Revenues ~$84 million

Delivery Points

350000 Dthd to Chippawa (TCPL interconnect)

140000 Dthd to Hopewell (TGP 200 line)

Regulatory Status

February 3 2017 ndash FERC 7(c) certificate issued

August 6 2018 ndash FERC issued Order finding that NY DEC waived water quality certification

Supply and Empire currently working to finalize remaining federal authorizations

Pipeline amp Storage

To Dawn

42

Continued Expansion of the NFG Supply System

Line N Expansion Opportunities

Line N to Monaca Project Project Firm transportation service to a new ethane

cracker facility being built by Shell Chemical Appalachia LLC

Target In-Service July 2019

Estimated Capital Cost $23 million

Contracted Capacity 133000 Dthday

Additional Line N Expansion Opportunity (Supply OS 221) Project New firm transportation service for on-system

demand

Open Season Capacity Awarded 165000 to foundation shipper Precedent agreement in negotiations

Pipeline amp Storage

43

Pipeline amp Storage Customer Mix

Producer33

LDC42

Marketer10

Outside Pipeline

9

End User6

42 MMDthd

(1) Contracted as of 10312018

Customer Transportation by Shipper Type(1) Affiliated Customer Mix (Contracted Capacity)

66

521

41

34

9579

59

LDCs Producers Marketers FirmStorage

Affiliated Non-Affiliated

Firm Transport

Pipeline amp Storage

44

Utility OverviewNational Fuel Gas Distribution Corporation

45

New York amp Pennsylvania Service Territories

New York

Total Customers(1) 535800ROE 87 (NY PSC Rate Case Order April 2017)Rate Mechanismso Revenue Decouplingo Weather Normalizationo Low Income Rateso Merchant Function Charge (Uncollectibles Adj)o 9010 Sharing (Large Customers)o System Modernization Tracker

Pennsylvania

Total Customers(1) 214400ROE Black Box Settlement (2007)Rate Mechanismso Low Income Rateso Merchant Function Charge

(1) As of September 30 2018

Utility

46

New York Rate Case Outcome

Rate Order Summary

Revenue Requirement $59 million

Rate Base $704 million

Allowed Return on Equity (ROE) 87

Capital Structure 429 equity

Other notable items

New rates became effective 5117

Retains rate mechanisms in place under prior order (revenue decoupling weather normalization merchant function charge 9010 large customer sharing)

No stay-out clause

System modernization tracker for Leak Prone Pipe (LPP)

Earnings sharing started 4118 (5050 sharing starts at earnings in excess of 92)

Article 78 appeal filed on 72817 with oral argument completed in January 2019

On April 20 2017 the New York Public Service Commission issued a Rate Order relating to NFG Distributionrsquos rate case (No 16-G-0257) filed in April 2016

Utility

47

Utility Continues its Significant Investments in Safety

$544$618 $636

$699

$944$980

$809$856

$90-100

$00

$250

$500

$750

$1000

$1250

2015 2016 2017 2018 2019E

Cap

ital E

xpen

ditu

res

($ m

illio

ns)

Fiscal Year

Capital Expenditures for Safety Total Capital Expenditures

Modernization Spending in NY Expected to Grow Gross Margin By $2 MM - $5 MM in FY 2019

(1)

(1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation

Utility

System modernization tracker in NY allows recovery of pipeline replacementcosts which is expected to drive modest gross margin and rate base growth

48

Accelerating Pipeline Replacement amp Modernization

Wrought Iron

Plastic

CoatedBare

120130

146 144159

2014 2015 2016 2017 2018Calendar Year

NY9726 miles

PA4830 miles

No Cast Iron Mains in Pa

Miles of Utility Main Pipeline ReplacedUtility Mains by Material(1)

Wrought Iron

Cast Iron

Plastic

Coated Bare

Utility

(1) All values are reported on a calendar year basis as of December 31 2018

49

A Proven History of Controlling Costs

$200 $189 $195

$166 $166

$31 $31

$197 $197

$0

$50

$100

$150

$200

$250

2015 2016 2017 2018 TTM 123118

Fiscal Year

OampM Expense Non-Service Pension Costs

OampM Expense ($ millions)

Utility

(1)

(1) For purposes of comparability to FY 2015 2016 and 2017 Utility Operation and Maintenance Expense for FY 2018 and the twelve months ended December 31 2018 was adjusted by approximately $314 million and $312 million respectively to include non-service pension costs which were re-classified as Other Income (Deductions) as of October 1 2018 on the Companyrsquos Income Statement See Slide 64 for non-GAAP reconciliation of Adjusted Operation and Maintenance Expense to Operation and Maintenance Expense by segment

50

Consolidated Financial OverviewUpstream I Midstream I Downstream

51

Adjusted Operating Results ($ per share)(1)

Diversified Balanced Earnings and Cash Flows

(1) A reconciliation of Adjusted Operating Results to Earnings per Share by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation(2) Consolidated Adjusted EBITDA includes Energy Marketing and Corporate amp All Other Segments A reconciliation of Adjusted EBITDA to Net Income by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in

the Business is included at the end of this presentation

Adjusted EBITDA ($ millions)(2)

$176 $179

$184 $181

$92 $97

$318 $327

$761 $775

$-

$200

$400

$600

$800

FY 2018 TTM 123118

$059 Utility

$097 Pipeline amp Storage

$057 Gathering

$125 Exploration

amp Production

$334 $345 to $365

$-

$100

$200

$300

$400

FY 2018 FY 2019 Guidance

Rate Regulated

40-45

$728

Rate Regulated

~46

52

$89 $94 $98 $81 $86 $90-$100

$140$230

$114 $95 $93 $120-$150

$138$118

$54$33 $48

$55-$65

$603$557

$99 $246$356

$460-$495

$970 $1001

$366$455

$583

$725-$810

$0

$250

$500

$750

$1000

$1250

2014 2015 2016 2017 2018 2019GuidanceFiscal Year

Exploration amp Production

Gathering

Pipeline amp Storage

Utility

Disciplined Flexible Capital Allocation

(2)

(1) Total Capital Expenditures include Energy Marketing Corporate and All Other A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation (2) FY16 FY17 and FY18 reflects the netting of $157 million $7 million and $17 million respectively of up-front proceeds received from joint development partner for working interest in joint development wells and $21M in intercompany asset transfers in FY18

Capital Expenditures by Segment ($ millions)(1)

53

Maintaining Strong Balance Sheet amp Liquidity

Total Equity49

Total Debt51

$42 Billion Total Capitalizationas of December 31 2018

218 x251 x 245 x 247 x 256 x

2015 2016 2017 2018 TTM 123118Fiscal Year End

Net Debt Adjusted EBITDA(1) Capitalization

Debt Maturity Profile ($MM) Liquidity

Committed Credit FacilitiesShort-term Debt OutstandingAvailable Short-term Credit FacilitiesCash Balance at 123118 Total Liquidity at 123118

$ 750 MM0 MM

750 MM110 MM

$ 860 MM

$500 $549 $500

$300 $300

$0

$200

$400

$600

(1) Net Debt is net of cash and temporary cash investments Reconciliations of Net Debt and Adjusted EBITDA to Net Income are included at the end of this presentation

54

Appendix

55

Safe Harbor For Forward Looking StatementsThis presentation may contain ldquoforward-looking statementsrdquo as defined by the Private Securities Litigation Reform Act of 1995 including statements regarding future prospectsplans objectives goals projections estimates of oil and gas quantities strategies future events or performance and underlying assumptions capital structure anticipatedcapital expenditures completion of construction projects projections for pension and other post-retirement benefit obligations impacts of the adoption of new accounting rulesand possible outcomes of litigation or regulatory proceedings as well as statements that are identified by the use of the words ldquoanticipatesrdquo ldquoestimatesrdquo ldquoexpectsrdquo ldquoforecastsrdquoldquointendsrdquo ldquoplansrdquo ldquopredictsrdquo ldquoprojectsrdquo ldquobelievesrdquo ldquoseeksrdquo ldquowillrdquo ldquomayrdquo and similar expressions Forward-looking statements involve risks and uncertainties which couldcause actual results or outcomes to differ materially from those expressed in the forward-looking statements The Companyrsquos expectations beliefs and projections are expressedin good faith and are believed by the Company to have a reasonable basis but there can be no assurance that managementrsquos expectations beliefs or projections will result or beachieved or accomplished

In addition to other factors the following are important factors that could cause actual results to differ materially from those discussed in the forward-looking statements delaysor changes in costs or plans with respect to Company projects or related projects of other companies including difficulties or delays in obtaining necessary governmentalapprovals permits or orders or in obtaining the cooperation of interconnecting facility operators governmentalregulatory actions initiatives and proceedings including thoseinvolving rate cases (which address among other things target rates of return rate design and retained natural gas) environmentalsafety requirements affiliate relationshipsindustry structure and franchise renewal changes in laws regulations or judicial interpretations to which the Company is subject including those involving derivatives taxessafety employment climate change other environmental matters real property and exploration and production activities such as hydraulic fracturing financial and economicconditions including the availability of credit and occurrences affecting the Companyrsquos ability to obtain financing on acceptable terms for working capital capital expendituresand other investments including any downgrades in the Companyrsquos credit ratings and changes in interest rates and other capital market conditions changes in the price ofnatural gas or oil impairments under the SECrsquos full cost ceiling test for natural gas and oil reserves factors affecting the Companyrsquos ability to successfully identify drill for andproduce economically viable natural gas and oil reserves including among others geology lease availability title disputes weather conditions shortages delays orunavailability of equipment and services required in drilling operations insufficient gathering processing and transportation capacity the need to obtain governmentalapprovals and permits and compliance with environmental laws and regulations increasing health care costs and the resulting effect on health insurance premiums and on theobligation to provide other post-retirement benefits changes in price differentials between similar quantities of natural gas or oil sold at different geographic locations and theeffect of such changes on commodity production revenues and demand for pipeline transportation capacity to or from such locations other changes in price differentialsbetween similar quantities of natural gas or oil having different quality heating value hydrocarbon mix or delivery date the cost and effects of legal and administrative claimsagainst the Company or activist shareholder campaigns to effect changes at the Company uncertainty of oil and gas reserve estimates significant differences between theCompanyrsquos projected and actual production levels for natural gas or oil changes in demographic patterns and weather conditions changes in the availability price oraccounting treatment of derivative financial instruments changes in laws actuarial assumptions the interest rate environment and the return on plantrust assets related to theCompanyrsquos pension and other post-retirement benefits which can affect future funding obligations and costs and plan liabilities changes in economic conditions includingglobal national or regional recessions and their effect on the demand for and customersrsquo ability to pay for the Companyrsquos products and services the creditworthiness orperformance of the Companyrsquos key suppliers customers and counterparties the impact of potential information technology cybersecurity or data security breaches economicdisruptions or uninsured losses resulting from major accidents fires severe weather natural disasters terrorist activities or acts of war significant differences between theCompanyrsquos projected and actual capital expenditures and operating expenses or increasing costs of insurance changes in coverage and the ability to obtain insurance

Forward-looking statements include estimates of oil and gas quantities Proved oil and gas reserves are those quantities of oil and gas which by analysis of geoscience andengineering data can be estimated with reasonable certainty to be economically producible under existing economic conditions operating methods and governmentregulations Other estimates of oil and gas quantities including estimates of probable reserves possible reserves and resource potential are by their nature more speculativethan estimates of proved reserves Accordingly estimates other than proved reserves are subject to substantially greater risk of being actually realized Investors are urged toconsider closely the disclosure in our Form 10-K available at wwwnationalfuelgascom You can also obtain this form on the SECrsquos website at wwwsecgov

For a discussion of the risks set forth above and other factors that could cause actual results to differ materially from results referred to in the forward-looking statements seeldquoRisk Factorsrdquo in the Companyrsquos Form 10-K for the fiscal year ended September 30 2018 and the Forms 10-Q for the quarter ended March 31 2018 June 30 2018 and December31 2018 The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date thereof or to reflect the occurrence ofunanticipated events

Appendix

37

Pipeline amp Storage Segment Overview

(1) As of September 30 2018 as disclosed in the Companyrsquos fiscal 2018 form 10-K(2) As of December 31 2017 calculated from National Fuel Gas Supply Corporationrsquos and Empire Pipeline Incrsquos 2017 FERC Form-2 reports respectively

Empire Pipeline Inc

National Fuel Gas Supply Corporation

Empire Pipeline

Supply Corp

Contracted Capacity(1) Firm Transportation 3187 MDth per day Firm Storage 71938 Mdth (fully subscribed)

Rate Base(2) ~$820 million FERC Rate Proceeding Status

Rate case settlement extension approved Nov lsquo15 Rate case filing expected by 73119

Contracted Capacity(1) Firm Transportation 978 MDth per day Firm Storage 3753 Mdth (fully subscribed)

Rate Base(2) ~$249 million FERC Rate Proceeding Status

Rate case settlement in principle reached on 122118 FERC approval pending

New transportation rates went into on 1119

Pipeline amp Storage

38

All Seneca volumes will flow through wholly-owned NFG gathering facilities

FM100 Project - Consolidated Benefit for NFG

330000 Dthd of new transportation capacity from WDA and EDA acreage positions to premium markets

New Transco capacity (Leidy South) 330000 Dthday

Rate(1) competitive with other expansion project rates in Senecarsquos current transportation portfolio

Delivery Point(s) Transco Zone 6 interconnections

Seneca

Lease to Transco of new capacity 330000 Dthday

Estimated annual lease revenues ~$35 million

Target In-Service late calendar year 2021

Supply Corp

Project expected to provide long-term earnings uplift to Seneca Supply Corp and Gathering

Pipeline amp Storage

Gathering

(1) Includes lease of new capacity from Supply Corp to Transco

39

FM100 Project ndash Significant Investment by Supply Corp

Pipeline amp Storage

Estimated Capital Cost $280 million(1)

Facilities (all in Pennsylvania) include Approximately 30 miles of new pipeline 2 new compressor stations (totaling

approximately 37000 HP) New interconnection station and modification

of existing interconnection station Abandonment of approximately 45 miles of

existing pipeline and compressor station Regulatory Process

Pre-filing application submitted to FERC in 2017 for original modernization project

FERC 7(b) 7(c) filing expected summer 2019

(1) Includes expansion and modernization portions of the project

40

Empire North Project

Target In-Service second half of fiscal 2020

Est Capital Cost $145 million

Est Annual Revenues ~$25 million

Receipt Point Jackson (Tioga Co Pa production)

Design Capacity and Delivery Points 175000 Dthd to Chippawa (TCPL interconnect)

30000 Dthd to Hopewell (TGP 200 interconnect)

Customers Fully subscribed (205000 Dthday)

Major Facilities 2 new compressor stations in NY (1) amp Pa (1)

No new pipeline construction

Regulatory Process FERC 7(c) application filed on 21618

FERC Environmental Assessment issued 103018

Pipeline amp Storage

Fully Subscribed Project will Provide 205000 Dthday of Incremental Firm Transportation

41

National Fuel Remains Committed to Northern Access Project

Target In-Service as early as fiscal 2022

Total Cost ~$500MM (~$76MM spent to date)

Estimated Annual Revenues ~$84 million

Delivery Points

350000 Dthd to Chippawa (TCPL interconnect)

140000 Dthd to Hopewell (TGP 200 line)

Regulatory Status

February 3 2017 ndash FERC 7(c) certificate issued

August 6 2018 ndash FERC issued Order finding that NY DEC waived water quality certification

Supply and Empire currently working to finalize remaining federal authorizations

Pipeline amp Storage

To Dawn

42

Continued Expansion of the NFG Supply System

Line N Expansion Opportunities

Line N to Monaca Project Project Firm transportation service to a new ethane

cracker facility being built by Shell Chemical Appalachia LLC

Target In-Service July 2019

Estimated Capital Cost $23 million

Contracted Capacity 133000 Dthday

Additional Line N Expansion Opportunity (Supply OS 221) Project New firm transportation service for on-system

demand

Open Season Capacity Awarded 165000 to foundation shipper Precedent agreement in negotiations

Pipeline amp Storage

43

Pipeline amp Storage Customer Mix

Producer33

LDC42

Marketer10

Outside Pipeline

9

End User6

42 MMDthd

(1) Contracted as of 10312018

Customer Transportation by Shipper Type(1) Affiliated Customer Mix (Contracted Capacity)

66

521

41

34

9579

59

LDCs Producers Marketers FirmStorage

Affiliated Non-Affiliated

Firm Transport

Pipeline amp Storage

44

Utility OverviewNational Fuel Gas Distribution Corporation

45

New York amp Pennsylvania Service Territories

New York

Total Customers(1) 535800ROE 87 (NY PSC Rate Case Order April 2017)Rate Mechanismso Revenue Decouplingo Weather Normalizationo Low Income Rateso Merchant Function Charge (Uncollectibles Adj)o 9010 Sharing (Large Customers)o System Modernization Tracker

Pennsylvania

Total Customers(1) 214400ROE Black Box Settlement (2007)Rate Mechanismso Low Income Rateso Merchant Function Charge

(1) As of September 30 2018

Utility

46

New York Rate Case Outcome

Rate Order Summary

Revenue Requirement $59 million

Rate Base $704 million

Allowed Return on Equity (ROE) 87

Capital Structure 429 equity

Other notable items

New rates became effective 5117

Retains rate mechanisms in place under prior order (revenue decoupling weather normalization merchant function charge 9010 large customer sharing)

No stay-out clause

System modernization tracker for Leak Prone Pipe (LPP)

Earnings sharing started 4118 (5050 sharing starts at earnings in excess of 92)

Article 78 appeal filed on 72817 with oral argument completed in January 2019

On April 20 2017 the New York Public Service Commission issued a Rate Order relating to NFG Distributionrsquos rate case (No 16-G-0257) filed in April 2016

Utility

47

Utility Continues its Significant Investments in Safety

$544$618 $636

$699

$944$980

$809$856

$90-100

$00

$250

$500

$750

$1000

$1250

2015 2016 2017 2018 2019E

Cap

ital E

xpen

ditu

res

($ m

illio

ns)

Fiscal Year

Capital Expenditures for Safety Total Capital Expenditures

Modernization Spending in NY Expected to Grow Gross Margin By $2 MM - $5 MM in FY 2019

(1)

(1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation

Utility

System modernization tracker in NY allows recovery of pipeline replacementcosts which is expected to drive modest gross margin and rate base growth

48

Accelerating Pipeline Replacement amp Modernization

Wrought Iron

Plastic

CoatedBare

120130

146 144159

2014 2015 2016 2017 2018Calendar Year

NY9726 miles

PA4830 miles

No Cast Iron Mains in Pa

Miles of Utility Main Pipeline ReplacedUtility Mains by Material(1)

Wrought Iron

Cast Iron

Plastic

Coated Bare

Utility

(1) All values are reported on a calendar year basis as of December 31 2018

49

A Proven History of Controlling Costs

$200 $189 $195

$166 $166

$31 $31

$197 $197

$0

$50

$100

$150

$200

$250

2015 2016 2017 2018 TTM 123118

Fiscal Year

OampM Expense Non-Service Pension Costs

OampM Expense ($ millions)

Utility

(1)

(1) For purposes of comparability to FY 2015 2016 and 2017 Utility Operation and Maintenance Expense for FY 2018 and the twelve months ended December 31 2018 was adjusted by approximately $314 million and $312 million respectively to include non-service pension costs which were re-classified as Other Income (Deductions) as of October 1 2018 on the Companyrsquos Income Statement See Slide 64 for non-GAAP reconciliation of Adjusted Operation and Maintenance Expense to Operation and Maintenance Expense by segment

50

Consolidated Financial OverviewUpstream I Midstream I Downstream

51

Adjusted Operating Results ($ per share)(1)

Diversified Balanced Earnings and Cash Flows

(1) A reconciliation of Adjusted Operating Results to Earnings per Share by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation(2) Consolidated Adjusted EBITDA includes Energy Marketing and Corporate amp All Other Segments A reconciliation of Adjusted EBITDA to Net Income by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in

the Business is included at the end of this presentation

Adjusted EBITDA ($ millions)(2)

$176 $179

$184 $181

$92 $97

$318 $327

$761 $775

$-

$200

$400

$600

$800

FY 2018 TTM 123118

$059 Utility

$097 Pipeline amp Storage

$057 Gathering

$125 Exploration

amp Production

$334 $345 to $365

$-

$100

$200

$300

$400

FY 2018 FY 2019 Guidance

Rate Regulated

40-45

$728

Rate Regulated

~46

52

$89 $94 $98 $81 $86 $90-$100

$140$230

$114 $95 $93 $120-$150

$138$118

$54$33 $48

$55-$65

$603$557

$99 $246$356

$460-$495

$970 $1001

$366$455

$583

$725-$810

$0

$250

$500

$750

$1000

$1250

2014 2015 2016 2017 2018 2019GuidanceFiscal Year

Exploration amp Production

Gathering

Pipeline amp Storage

Utility

Disciplined Flexible Capital Allocation

(2)

(1) Total Capital Expenditures include Energy Marketing Corporate and All Other A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation (2) FY16 FY17 and FY18 reflects the netting of $157 million $7 million and $17 million respectively of up-front proceeds received from joint development partner for working interest in joint development wells and $21M in intercompany asset transfers in FY18

Capital Expenditures by Segment ($ millions)(1)

53

Maintaining Strong Balance Sheet amp Liquidity

Total Equity49

Total Debt51

$42 Billion Total Capitalizationas of December 31 2018

218 x251 x 245 x 247 x 256 x

2015 2016 2017 2018 TTM 123118Fiscal Year End

Net Debt Adjusted EBITDA(1) Capitalization

Debt Maturity Profile ($MM) Liquidity

Committed Credit FacilitiesShort-term Debt OutstandingAvailable Short-term Credit FacilitiesCash Balance at 123118 Total Liquidity at 123118

$ 750 MM0 MM

750 MM110 MM

$ 860 MM

$500 $549 $500

$300 $300

$0

$200

$400

$600

(1) Net Debt is net of cash and temporary cash investments Reconciliations of Net Debt and Adjusted EBITDA to Net Income are included at the end of this presentation

54

Appendix

55

Safe Harbor For Forward Looking StatementsThis presentation may contain ldquoforward-looking statementsrdquo as defined by the Private Securities Litigation Reform Act of 1995 including statements regarding future prospectsplans objectives goals projections estimates of oil and gas quantities strategies future events or performance and underlying assumptions capital structure anticipatedcapital expenditures completion of construction projects projections for pension and other post-retirement benefit obligations impacts of the adoption of new accounting rulesand possible outcomes of litigation or regulatory proceedings as well as statements that are identified by the use of the words ldquoanticipatesrdquo ldquoestimatesrdquo ldquoexpectsrdquo ldquoforecastsrdquoldquointendsrdquo ldquoplansrdquo ldquopredictsrdquo ldquoprojectsrdquo ldquobelievesrdquo ldquoseeksrdquo ldquowillrdquo ldquomayrdquo and similar expressions Forward-looking statements involve risks and uncertainties which couldcause actual results or outcomes to differ materially from those expressed in the forward-looking statements The Companyrsquos expectations beliefs and projections are expressedin good faith and are believed by the Company to have a reasonable basis but there can be no assurance that managementrsquos expectations beliefs or projections will result or beachieved or accomplished

In addition to other factors the following are important factors that could cause actual results to differ materially from those discussed in the forward-looking statements delaysor changes in costs or plans with respect to Company projects or related projects of other companies including difficulties or delays in obtaining necessary governmentalapprovals permits or orders or in obtaining the cooperation of interconnecting facility operators governmentalregulatory actions initiatives and proceedings including thoseinvolving rate cases (which address among other things target rates of return rate design and retained natural gas) environmentalsafety requirements affiliate relationshipsindustry structure and franchise renewal changes in laws regulations or judicial interpretations to which the Company is subject including those involving derivatives taxessafety employment climate change other environmental matters real property and exploration and production activities such as hydraulic fracturing financial and economicconditions including the availability of credit and occurrences affecting the Companyrsquos ability to obtain financing on acceptable terms for working capital capital expendituresand other investments including any downgrades in the Companyrsquos credit ratings and changes in interest rates and other capital market conditions changes in the price ofnatural gas or oil impairments under the SECrsquos full cost ceiling test for natural gas and oil reserves factors affecting the Companyrsquos ability to successfully identify drill for andproduce economically viable natural gas and oil reserves including among others geology lease availability title disputes weather conditions shortages delays orunavailability of equipment and services required in drilling operations insufficient gathering processing and transportation capacity the need to obtain governmentalapprovals and permits and compliance with environmental laws and regulations increasing health care costs and the resulting effect on health insurance premiums and on theobligation to provide other post-retirement benefits changes in price differentials between similar quantities of natural gas or oil sold at different geographic locations and theeffect of such changes on commodity production revenues and demand for pipeline transportation capacity to or from such locations other changes in price differentialsbetween similar quantities of natural gas or oil having different quality heating value hydrocarbon mix or delivery date the cost and effects of legal and administrative claimsagainst the Company or activist shareholder campaigns to effect changes at the Company uncertainty of oil and gas reserve estimates significant differences between theCompanyrsquos projected and actual production levels for natural gas or oil changes in demographic patterns and weather conditions changes in the availability price oraccounting treatment of derivative financial instruments changes in laws actuarial assumptions the interest rate environment and the return on plantrust assets related to theCompanyrsquos pension and other post-retirement benefits which can affect future funding obligations and costs and plan liabilities changes in economic conditions includingglobal national or regional recessions and their effect on the demand for and customersrsquo ability to pay for the Companyrsquos products and services the creditworthiness orperformance of the Companyrsquos key suppliers customers and counterparties the impact of potential information technology cybersecurity or data security breaches economicdisruptions or uninsured losses resulting from major accidents fires severe weather natural disasters terrorist activities or acts of war significant differences between theCompanyrsquos projected and actual capital expenditures and operating expenses or increasing costs of insurance changes in coverage and the ability to obtain insurance

Forward-looking statements include estimates of oil and gas quantities Proved oil and gas reserves are those quantities of oil and gas which by analysis of geoscience andengineering data can be estimated with reasonable certainty to be economically producible under existing economic conditions operating methods and governmentregulations Other estimates of oil and gas quantities including estimates of probable reserves possible reserves and resource potential are by their nature more speculativethan estimates of proved reserves Accordingly estimates other than proved reserves are subject to substantially greater risk of being actually realized Investors are urged toconsider closely the disclosure in our Form 10-K available at wwwnationalfuelgascom You can also obtain this form on the SECrsquos website at wwwsecgov

For a discussion of the risks set forth above and other factors that could cause actual results to differ materially from results referred to in the forward-looking statements seeldquoRisk Factorsrdquo in the Companyrsquos Form 10-K for the fiscal year ended September 30 2018 and the Forms 10-Q for the quarter ended March 31 2018 June 30 2018 and December31 2018 The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date thereof or to reflect the occurrence ofunanticipated events

Appendix

38

All Seneca volumes will flow through wholly-owned NFG gathering facilities

FM100 Project - Consolidated Benefit for NFG

330000 Dthd of new transportation capacity from WDA and EDA acreage positions to premium markets

New Transco capacity (Leidy South) 330000 Dthday

Rate(1) competitive with other expansion project rates in Senecarsquos current transportation portfolio

Delivery Point(s) Transco Zone 6 interconnections

Seneca

Lease to Transco of new capacity 330000 Dthday

Estimated annual lease revenues ~$35 million

Target In-Service late calendar year 2021

Supply Corp

Project expected to provide long-term earnings uplift to Seneca Supply Corp and Gathering

Pipeline amp Storage

Gathering

(1) Includes lease of new capacity from Supply Corp to Transco

39

FM100 Project ndash Significant Investment by Supply Corp

Pipeline amp Storage

Estimated Capital Cost $280 million(1)

Facilities (all in Pennsylvania) include Approximately 30 miles of new pipeline 2 new compressor stations (totaling

approximately 37000 HP) New interconnection station and modification

of existing interconnection station Abandonment of approximately 45 miles of

existing pipeline and compressor station Regulatory Process

Pre-filing application submitted to FERC in 2017 for original modernization project

FERC 7(b) 7(c) filing expected summer 2019

(1) Includes expansion and modernization portions of the project

40

Empire North Project

Target In-Service second half of fiscal 2020

Est Capital Cost $145 million

Est Annual Revenues ~$25 million

Receipt Point Jackson (Tioga Co Pa production)

Design Capacity and Delivery Points 175000 Dthd to Chippawa (TCPL interconnect)

30000 Dthd to Hopewell (TGP 200 interconnect)

Customers Fully subscribed (205000 Dthday)

Major Facilities 2 new compressor stations in NY (1) amp Pa (1)

No new pipeline construction

Regulatory Process FERC 7(c) application filed on 21618

FERC Environmental Assessment issued 103018

Pipeline amp Storage

Fully Subscribed Project will Provide 205000 Dthday of Incremental Firm Transportation

41

National Fuel Remains Committed to Northern Access Project

Target In-Service as early as fiscal 2022

Total Cost ~$500MM (~$76MM spent to date)

Estimated Annual Revenues ~$84 million

Delivery Points

350000 Dthd to Chippawa (TCPL interconnect)

140000 Dthd to Hopewell (TGP 200 line)

Regulatory Status

February 3 2017 ndash FERC 7(c) certificate issued

August 6 2018 ndash FERC issued Order finding that NY DEC waived water quality certification

Supply and Empire currently working to finalize remaining federal authorizations

Pipeline amp Storage

To Dawn

42

Continued Expansion of the NFG Supply System

Line N Expansion Opportunities

Line N to Monaca Project Project Firm transportation service to a new ethane

cracker facility being built by Shell Chemical Appalachia LLC

Target In-Service July 2019

Estimated Capital Cost $23 million

Contracted Capacity 133000 Dthday

Additional Line N Expansion Opportunity (Supply OS 221) Project New firm transportation service for on-system

demand

Open Season Capacity Awarded 165000 to foundation shipper Precedent agreement in negotiations

Pipeline amp Storage

43

Pipeline amp Storage Customer Mix

Producer33

LDC42

Marketer10

Outside Pipeline

9

End User6

42 MMDthd

(1) Contracted as of 10312018

Customer Transportation by Shipper Type(1) Affiliated Customer Mix (Contracted Capacity)

66

521

41

34

9579

59

LDCs Producers Marketers FirmStorage

Affiliated Non-Affiliated

Firm Transport

Pipeline amp Storage

44

Utility OverviewNational Fuel Gas Distribution Corporation

45

New York amp Pennsylvania Service Territories

New York

Total Customers(1) 535800ROE 87 (NY PSC Rate Case Order April 2017)Rate Mechanismso Revenue Decouplingo Weather Normalizationo Low Income Rateso Merchant Function Charge (Uncollectibles Adj)o 9010 Sharing (Large Customers)o System Modernization Tracker

Pennsylvania

Total Customers(1) 214400ROE Black Box Settlement (2007)Rate Mechanismso Low Income Rateso Merchant Function Charge

(1) As of September 30 2018

Utility

46

New York Rate Case Outcome

Rate Order Summary

Revenue Requirement $59 million

Rate Base $704 million

Allowed Return on Equity (ROE) 87

Capital Structure 429 equity

Other notable items

New rates became effective 5117

Retains rate mechanisms in place under prior order (revenue decoupling weather normalization merchant function charge 9010 large customer sharing)

No stay-out clause

System modernization tracker for Leak Prone Pipe (LPP)

Earnings sharing started 4118 (5050 sharing starts at earnings in excess of 92)

Article 78 appeal filed on 72817 with oral argument completed in January 2019

On April 20 2017 the New York Public Service Commission issued a Rate Order relating to NFG Distributionrsquos rate case (No 16-G-0257) filed in April 2016

Utility

47

Utility Continues its Significant Investments in Safety

$544$618 $636

$699

$944$980

$809$856

$90-100

$00

$250

$500

$750

$1000

$1250

2015 2016 2017 2018 2019E

Cap

ital E

xpen

ditu

res

($ m

illio

ns)

Fiscal Year

Capital Expenditures for Safety Total Capital Expenditures

Modernization Spending in NY Expected to Grow Gross Margin By $2 MM - $5 MM in FY 2019

(1)

(1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation

Utility

System modernization tracker in NY allows recovery of pipeline replacementcosts which is expected to drive modest gross margin and rate base growth

48

Accelerating Pipeline Replacement amp Modernization

Wrought Iron

Plastic

CoatedBare

120130

146 144159

2014 2015 2016 2017 2018Calendar Year

NY9726 miles

PA4830 miles

No Cast Iron Mains in Pa

Miles of Utility Main Pipeline ReplacedUtility Mains by Material(1)

Wrought Iron

Cast Iron

Plastic

Coated Bare

Utility

(1) All values are reported on a calendar year basis as of December 31 2018

49

A Proven History of Controlling Costs

$200 $189 $195

$166 $166

$31 $31

$197 $197

$0

$50

$100

$150

$200

$250

2015 2016 2017 2018 TTM 123118

Fiscal Year

OampM Expense Non-Service Pension Costs

OampM Expense ($ millions)

Utility

(1)

(1) For purposes of comparability to FY 2015 2016 and 2017 Utility Operation and Maintenance Expense for FY 2018 and the twelve months ended December 31 2018 was adjusted by approximately $314 million and $312 million respectively to include non-service pension costs which were re-classified as Other Income (Deductions) as of October 1 2018 on the Companyrsquos Income Statement See Slide 64 for non-GAAP reconciliation of Adjusted Operation and Maintenance Expense to Operation and Maintenance Expense by segment

50

Consolidated Financial OverviewUpstream I Midstream I Downstream

51

Adjusted Operating Results ($ per share)(1)

Diversified Balanced Earnings and Cash Flows

(1) A reconciliation of Adjusted Operating Results to Earnings per Share by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation(2) Consolidated Adjusted EBITDA includes Energy Marketing and Corporate amp All Other Segments A reconciliation of Adjusted EBITDA to Net Income by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in

the Business is included at the end of this presentation

Adjusted EBITDA ($ millions)(2)

$176 $179

$184 $181

$92 $97

$318 $327

$761 $775

$-

$200

$400

$600

$800

FY 2018 TTM 123118

$059 Utility

$097 Pipeline amp Storage

$057 Gathering

$125 Exploration

amp Production

$334 $345 to $365

$-

$100

$200

$300

$400

FY 2018 FY 2019 Guidance

Rate Regulated

40-45

$728

Rate Regulated

~46

52

$89 $94 $98 $81 $86 $90-$100

$140$230

$114 $95 $93 $120-$150

$138$118

$54$33 $48

$55-$65

$603$557

$99 $246$356

$460-$495

$970 $1001

$366$455

$583

$725-$810

$0

$250

$500

$750

$1000

$1250

2014 2015 2016 2017 2018 2019GuidanceFiscal Year

Exploration amp Production

Gathering

Pipeline amp Storage

Utility

Disciplined Flexible Capital Allocation

(2)

(1) Total Capital Expenditures include Energy Marketing Corporate and All Other A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation (2) FY16 FY17 and FY18 reflects the netting of $157 million $7 million and $17 million respectively of up-front proceeds received from joint development partner for working interest in joint development wells and $21M in intercompany asset transfers in FY18

Capital Expenditures by Segment ($ millions)(1)

53

Maintaining Strong Balance Sheet amp Liquidity

Total Equity49

Total Debt51

$42 Billion Total Capitalizationas of December 31 2018

218 x251 x 245 x 247 x 256 x

2015 2016 2017 2018 TTM 123118Fiscal Year End

Net Debt Adjusted EBITDA(1) Capitalization

Debt Maturity Profile ($MM) Liquidity

Committed Credit FacilitiesShort-term Debt OutstandingAvailable Short-term Credit FacilitiesCash Balance at 123118 Total Liquidity at 123118

$ 750 MM0 MM

750 MM110 MM

$ 860 MM

$500 $549 $500

$300 $300

$0

$200

$400

$600

(1) Net Debt is net of cash and temporary cash investments Reconciliations of Net Debt and Adjusted EBITDA to Net Income are included at the end of this presentation

54

Appendix

55

Safe Harbor For Forward Looking StatementsThis presentation may contain ldquoforward-looking statementsrdquo as defined by the Private Securities Litigation Reform Act of 1995 including statements regarding future prospectsplans objectives goals projections estimates of oil and gas quantities strategies future events or performance and underlying assumptions capital structure anticipatedcapital expenditures completion of construction projects projections for pension and other post-retirement benefit obligations impacts of the adoption of new accounting rulesand possible outcomes of litigation or regulatory proceedings as well as statements that are identified by the use of the words ldquoanticipatesrdquo ldquoestimatesrdquo ldquoexpectsrdquo ldquoforecastsrdquoldquointendsrdquo ldquoplansrdquo ldquopredictsrdquo ldquoprojectsrdquo ldquobelievesrdquo ldquoseeksrdquo ldquowillrdquo ldquomayrdquo and similar expressions Forward-looking statements involve risks and uncertainties which couldcause actual results or outcomes to differ materially from those expressed in the forward-looking statements The Companyrsquos expectations beliefs and projections are expressedin good faith and are believed by the Company to have a reasonable basis but there can be no assurance that managementrsquos expectations beliefs or projections will result or beachieved or accomplished

In addition to other factors the following are important factors that could cause actual results to differ materially from those discussed in the forward-looking statements delaysor changes in costs or plans with respect to Company projects or related projects of other companies including difficulties or delays in obtaining necessary governmentalapprovals permits or orders or in obtaining the cooperation of interconnecting facility operators governmentalregulatory actions initiatives and proceedings including thoseinvolving rate cases (which address among other things target rates of return rate design and retained natural gas) environmentalsafety requirements affiliate relationshipsindustry structure and franchise renewal changes in laws regulations or judicial interpretations to which the Company is subject including those involving derivatives taxessafety employment climate change other environmental matters real property and exploration and production activities such as hydraulic fracturing financial and economicconditions including the availability of credit and occurrences affecting the Companyrsquos ability to obtain financing on acceptable terms for working capital capital expendituresand other investments including any downgrades in the Companyrsquos credit ratings and changes in interest rates and other capital market conditions changes in the price ofnatural gas or oil impairments under the SECrsquos full cost ceiling test for natural gas and oil reserves factors affecting the Companyrsquos ability to successfully identify drill for andproduce economically viable natural gas and oil reserves including among others geology lease availability title disputes weather conditions shortages delays orunavailability of equipment and services required in drilling operations insufficient gathering processing and transportation capacity the need to obtain governmentalapprovals and permits and compliance with environmental laws and regulations increasing health care costs and the resulting effect on health insurance premiums and on theobligation to provide other post-retirement benefits changes in price differentials between similar quantities of natural gas or oil sold at different geographic locations and theeffect of such changes on commodity production revenues and demand for pipeline transportation capacity to or from such locations other changes in price differentialsbetween similar quantities of natural gas or oil having different quality heating value hydrocarbon mix or delivery date the cost and effects of legal and administrative claimsagainst the Company or activist shareholder campaigns to effect changes at the Company uncertainty of oil and gas reserve estimates significant differences between theCompanyrsquos projected and actual production levels for natural gas or oil changes in demographic patterns and weather conditions changes in the availability price oraccounting treatment of derivative financial instruments changes in laws actuarial assumptions the interest rate environment and the return on plantrust assets related to theCompanyrsquos pension and other post-retirement benefits which can affect future funding obligations and costs and plan liabilities changes in economic conditions includingglobal national or regional recessions and their effect on the demand for and customersrsquo ability to pay for the Companyrsquos products and services the creditworthiness orperformance of the Companyrsquos key suppliers customers and counterparties the impact of potential information technology cybersecurity or data security breaches economicdisruptions or uninsured losses resulting from major accidents fires severe weather natural disasters terrorist activities or acts of war significant differences between theCompanyrsquos projected and actual capital expenditures and operating expenses or increasing costs of insurance changes in coverage and the ability to obtain insurance

Forward-looking statements include estimates of oil and gas quantities Proved oil and gas reserves are those quantities of oil and gas which by analysis of geoscience andengineering data can be estimated with reasonable certainty to be economically producible under existing economic conditions operating methods and governmentregulations Other estimates of oil and gas quantities including estimates of probable reserves possible reserves and resource potential are by their nature more speculativethan estimates of proved reserves Accordingly estimates other than proved reserves are subject to substantially greater risk of being actually realized Investors are urged toconsider closely the disclosure in our Form 10-K available at wwwnationalfuelgascom You can also obtain this form on the SECrsquos website at wwwsecgov

For a discussion of the risks set forth above and other factors that could cause actual results to differ materially from results referred to in the forward-looking statements seeldquoRisk Factorsrdquo in the Companyrsquos Form 10-K for the fiscal year ended September 30 2018 and the Forms 10-Q for the quarter ended March 31 2018 June 30 2018 and December31 2018 The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date thereof or to reflect the occurrence ofunanticipated events

Appendix

39

FM100 Project ndash Significant Investment by Supply Corp

Pipeline amp Storage

Estimated Capital Cost $280 million(1)

Facilities (all in Pennsylvania) include Approximately 30 miles of new pipeline 2 new compressor stations (totaling

approximately 37000 HP) New interconnection station and modification

of existing interconnection station Abandonment of approximately 45 miles of

existing pipeline and compressor station Regulatory Process

Pre-filing application submitted to FERC in 2017 for original modernization project

FERC 7(b) 7(c) filing expected summer 2019

(1) Includes expansion and modernization portions of the project

40

Empire North Project

Target In-Service second half of fiscal 2020

Est Capital Cost $145 million

Est Annual Revenues ~$25 million

Receipt Point Jackson (Tioga Co Pa production)

Design Capacity and Delivery Points 175000 Dthd to Chippawa (TCPL interconnect)

30000 Dthd to Hopewell (TGP 200 interconnect)

Customers Fully subscribed (205000 Dthday)

Major Facilities 2 new compressor stations in NY (1) amp Pa (1)

No new pipeline construction

Regulatory Process FERC 7(c) application filed on 21618

FERC Environmental Assessment issued 103018

Pipeline amp Storage

Fully Subscribed Project will Provide 205000 Dthday of Incremental Firm Transportation

41

National Fuel Remains Committed to Northern Access Project

Target In-Service as early as fiscal 2022

Total Cost ~$500MM (~$76MM spent to date)

Estimated Annual Revenues ~$84 million

Delivery Points

350000 Dthd to Chippawa (TCPL interconnect)

140000 Dthd to Hopewell (TGP 200 line)

Regulatory Status

February 3 2017 ndash FERC 7(c) certificate issued

August 6 2018 ndash FERC issued Order finding that NY DEC waived water quality certification

Supply and Empire currently working to finalize remaining federal authorizations

Pipeline amp Storage

To Dawn

42

Continued Expansion of the NFG Supply System

Line N Expansion Opportunities

Line N to Monaca Project Project Firm transportation service to a new ethane

cracker facility being built by Shell Chemical Appalachia LLC

Target In-Service July 2019

Estimated Capital Cost $23 million

Contracted Capacity 133000 Dthday

Additional Line N Expansion Opportunity (Supply OS 221) Project New firm transportation service for on-system

demand

Open Season Capacity Awarded 165000 to foundation shipper Precedent agreement in negotiations

Pipeline amp Storage

43

Pipeline amp Storage Customer Mix

Producer33

LDC42

Marketer10

Outside Pipeline

9

End User6

42 MMDthd

(1) Contracted as of 10312018

Customer Transportation by Shipper Type(1) Affiliated Customer Mix (Contracted Capacity)

66

521

41

34

9579

59

LDCs Producers Marketers FirmStorage

Affiliated Non-Affiliated

Firm Transport

Pipeline amp Storage

44

Utility OverviewNational Fuel Gas Distribution Corporation

45

New York amp Pennsylvania Service Territories

New York

Total Customers(1) 535800ROE 87 (NY PSC Rate Case Order April 2017)Rate Mechanismso Revenue Decouplingo Weather Normalizationo Low Income Rateso Merchant Function Charge (Uncollectibles Adj)o 9010 Sharing (Large Customers)o System Modernization Tracker

Pennsylvania

Total Customers(1) 214400ROE Black Box Settlement (2007)Rate Mechanismso Low Income Rateso Merchant Function Charge

(1) As of September 30 2018

Utility

46

New York Rate Case Outcome

Rate Order Summary

Revenue Requirement $59 million

Rate Base $704 million

Allowed Return on Equity (ROE) 87

Capital Structure 429 equity

Other notable items

New rates became effective 5117

Retains rate mechanisms in place under prior order (revenue decoupling weather normalization merchant function charge 9010 large customer sharing)

No stay-out clause

System modernization tracker for Leak Prone Pipe (LPP)

Earnings sharing started 4118 (5050 sharing starts at earnings in excess of 92)

Article 78 appeal filed on 72817 with oral argument completed in January 2019

On April 20 2017 the New York Public Service Commission issued a Rate Order relating to NFG Distributionrsquos rate case (No 16-G-0257) filed in April 2016

Utility

47

Utility Continues its Significant Investments in Safety

$544$618 $636

$699

$944$980

$809$856

$90-100

$00

$250

$500

$750

$1000

$1250

2015 2016 2017 2018 2019E

Cap

ital E

xpen

ditu

res

($ m

illio

ns)

Fiscal Year

Capital Expenditures for Safety Total Capital Expenditures

Modernization Spending in NY Expected to Grow Gross Margin By $2 MM - $5 MM in FY 2019

(1)

(1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation

Utility

System modernization tracker in NY allows recovery of pipeline replacementcosts which is expected to drive modest gross margin and rate base growth

48

Accelerating Pipeline Replacement amp Modernization

Wrought Iron

Plastic

CoatedBare

120130

146 144159

2014 2015 2016 2017 2018Calendar Year

NY9726 miles

PA4830 miles

No Cast Iron Mains in Pa

Miles of Utility Main Pipeline ReplacedUtility Mains by Material(1)

Wrought Iron

Cast Iron

Plastic

Coated Bare

Utility

(1) All values are reported on a calendar year basis as of December 31 2018

49

A Proven History of Controlling Costs

$200 $189 $195

$166 $166

$31 $31

$197 $197

$0

$50

$100

$150

$200

$250

2015 2016 2017 2018 TTM 123118

Fiscal Year

OampM Expense Non-Service Pension Costs

OampM Expense ($ millions)

Utility

(1)

(1) For purposes of comparability to FY 2015 2016 and 2017 Utility Operation and Maintenance Expense for FY 2018 and the twelve months ended December 31 2018 was adjusted by approximately $314 million and $312 million respectively to include non-service pension costs which were re-classified as Other Income (Deductions) as of October 1 2018 on the Companyrsquos Income Statement See Slide 64 for non-GAAP reconciliation of Adjusted Operation and Maintenance Expense to Operation and Maintenance Expense by segment

50

Consolidated Financial OverviewUpstream I Midstream I Downstream

51

Adjusted Operating Results ($ per share)(1)

Diversified Balanced Earnings and Cash Flows

(1) A reconciliation of Adjusted Operating Results to Earnings per Share by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation(2) Consolidated Adjusted EBITDA includes Energy Marketing and Corporate amp All Other Segments A reconciliation of Adjusted EBITDA to Net Income by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in

the Business is included at the end of this presentation

Adjusted EBITDA ($ millions)(2)

$176 $179

$184 $181

$92 $97

$318 $327

$761 $775

$-

$200

$400

$600

$800

FY 2018 TTM 123118

$059 Utility

$097 Pipeline amp Storage

$057 Gathering

$125 Exploration

amp Production

$334 $345 to $365

$-

$100

$200

$300

$400

FY 2018 FY 2019 Guidance

Rate Regulated

40-45

$728

Rate Regulated

~46

52

$89 $94 $98 $81 $86 $90-$100

$140$230

$114 $95 $93 $120-$150

$138$118

$54$33 $48

$55-$65

$603$557

$99 $246$356

$460-$495

$970 $1001

$366$455

$583

$725-$810

$0

$250

$500

$750

$1000

$1250

2014 2015 2016 2017 2018 2019GuidanceFiscal Year

Exploration amp Production

Gathering

Pipeline amp Storage

Utility

Disciplined Flexible Capital Allocation

(2)

(1) Total Capital Expenditures include Energy Marketing Corporate and All Other A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation (2) FY16 FY17 and FY18 reflects the netting of $157 million $7 million and $17 million respectively of up-front proceeds received from joint development partner for working interest in joint development wells and $21M in intercompany asset transfers in FY18

Capital Expenditures by Segment ($ millions)(1)

53

Maintaining Strong Balance Sheet amp Liquidity

Total Equity49

Total Debt51

$42 Billion Total Capitalizationas of December 31 2018

218 x251 x 245 x 247 x 256 x

2015 2016 2017 2018 TTM 123118Fiscal Year End

Net Debt Adjusted EBITDA(1) Capitalization

Debt Maturity Profile ($MM) Liquidity

Committed Credit FacilitiesShort-term Debt OutstandingAvailable Short-term Credit FacilitiesCash Balance at 123118 Total Liquidity at 123118

$ 750 MM0 MM

750 MM110 MM

$ 860 MM

$500 $549 $500

$300 $300

$0

$200

$400

$600

(1) Net Debt is net of cash and temporary cash investments Reconciliations of Net Debt and Adjusted EBITDA to Net Income are included at the end of this presentation

54

Appendix

55

Safe Harbor For Forward Looking StatementsThis presentation may contain ldquoforward-looking statementsrdquo as defined by the Private Securities Litigation Reform Act of 1995 including statements regarding future prospectsplans objectives goals projections estimates of oil and gas quantities strategies future events or performance and underlying assumptions capital structure anticipatedcapital expenditures completion of construction projects projections for pension and other post-retirement benefit obligations impacts of the adoption of new accounting rulesand possible outcomes of litigation or regulatory proceedings as well as statements that are identified by the use of the words ldquoanticipatesrdquo ldquoestimatesrdquo ldquoexpectsrdquo ldquoforecastsrdquoldquointendsrdquo ldquoplansrdquo ldquopredictsrdquo ldquoprojectsrdquo ldquobelievesrdquo ldquoseeksrdquo ldquowillrdquo ldquomayrdquo and similar expressions Forward-looking statements involve risks and uncertainties which couldcause actual results or outcomes to differ materially from those expressed in the forward-looking statements The Companyrsquos expectations beliefs and projections are expressedin good faith and are believed by the Company to have a reasonable basis but there can be no assurance that managementrsquos expectations beliefs or projections will result or beachieved or accomplished

In addition to other factors the following are important factors that could cause actual results to differ materially from those discussed in the forward-looking statements delaysor changes in costs or plans with respect to Company projects or related projects of other companies including difficulties or delays in obtaining necessary governmentalapprovals permits or orders or in obtaining the cooperation of interconnecting facility operators governmentalregulatory actions initiatives and proceedings including thoseinvolving rate cases (which address among other things target rates of return rate design and retained natural gas) environmentalsafety requirements affiliate relationshipsindustry structure and franchise renewal changes in laws regulations or judicial interpretations to which the Company is subject including those involving derivatives taxessafety employment climate change other environmental matters real property and exploration and production activities such as hydraulic fracturing financial and economicconditions including the availability of credit and occurrences affecting the Companyrsquos ability to obtain financing on acceptable terms for working capital capital expendituresand other investments including any downgrades in the Companyrsquos credit ratings and changes in interest rates and other capital market conditions changes in the price ofnatural gas or oil impairments under the SECrsquos full cost ceiling test for natural gas and oil reserves factors affecting the Companyrsquos ability to successfully identify drill for andproduce economically viable natural gas and oil reserves including among others geology lease availability title disputes weather conditions shortages delays orunavailability of equipment and services required in drilling operations insufficient gathering processing and transportation capacity the need to obtain governmentalapprovals and permits and compliance with environmental laws and regulations increasing health care costs and the resulting effect on health insurance premiums and on theobligation to provide other post-retirement benefits changes in price differentials between similar quantities of natural gas or oil sold at different geographic locations and theeffect of such changes on commodity production revenues and demand for pipeline transportation capacity to or from such locations other changes in price differentialsbetween similar quantities of natural gas or oil having different quality heating value hydrocarbon mix or delivery date the cost and effects of legal and administrative claimsagainst the Company or activist shareholder campaigns to effect changes at the Company uncertainty of oil and gas reserve estimates significant differences between theCompanyrsquos projected and actual production levels for natural gas or oil changes in demographic patterns and weather conditions changes in the availability price oraccounting treatment of derivative financial instruments changes in laws actuarial assumptions the interest rate environment and the return on plantrust assets related to theCompanyrsquos pension and other post-retirement benefits which can affect future funding obligations and costs and plan liabilities changes in economic conditions includingglobal national or regional recessions and their effect on the demand for and customersrsquo ability to pay for the Companyrsquos products and services the creditworthiness orperformance of the Companyrsquos key suppliers customers and counterparties the impact of potential information technology cybersecurity or data security breaches economicdisruptions or uninsured losses resulting from major accidents fires severe weather natural disasters terrorist activities or acts of war significant differences between theCompanyrsquos projected and actual capital expenditures and operating expenses or increasing costs of insurance changes in coverage and the ability to obtain insurance

Forward-looking statements include estimates of oil and gas quantities Proved oil and gas reserves are those quantities of oil and gas which by analysis of geoscience andengineering data can be estimated with reasonable certainty to be economically producible under existing economic conditions operating methods and governmentregulations Other estimates of oil and gas quantities including estimates of probable reserves possible reserves and resource potential are by their nature more speculativethan estimates of proved reserves Accordingly estimates other than proved reserves are subject to substantially greater risk of being actually realized Investors are urged toconsider closely the disclosure in our Form 10-K available at wwwnationalfuelgascom You can also obtain this form on the SECrsquos website at wwwsecgov

For a discussion of the risks set forth above and other factors that could cause actual results to differ materially from results referred to in the forward-looking statements seeldquoRisk Factorsrdquo in the Companyrsquos Form 10-K for the fiscal year ended September 30 2018 and the Forms 10-Q for the quarter ended March 31 2018 June 30 2018 and December31 2018 The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date thereof or to reflect the occurrence ofunanticipated events

Appendix

40

Empire North Project

Target In-Service second half of fiscal 2020

Est Capital Cost $145 million

Est Annual Revenues ~$25 million

Receipt Point Jackson (Tioga Co Pa production)

Design Capacity and Delivery Points 175000 Dthd to Chippawa (TCPL interconnect)

30000 Dthd to Hopewell (TGP 200 interconnect)

Customers Fully subscribed (205000 Dthday)

Major Facilities 2 new compressor stations in NY (1) amp Pa (1)

No new pipeline construction

Regulatory Process FERC 7(c) application filed on 21618

FERC Environmental Assessment issued 103018

Pipeline amp Storage

Fully Subscribed Project will Provide 205000 Dthday of Incremental Firm Transportation

41

National Fuel Remains Committed to Northern Access Project

Target In-Service as early as fiscal 2022

Total Cost ~$500MM (~$76MM spent to date)

Estimated Annual Revenues ~$84 million

Delivery Points

350000 Dthd to Chippawa (TCPL interconnect)

140000 Dthd to Hopewell (TGP 200 line)

Regulatory Status

February 3 2017 ndash FERC 7(c) certificate issued

August 6 2018 ndash FERC issued Order finding that NY DEC waived water quality certification

Supply and Empire currently working to finalize remaining federal authorizations

Pipeline amp Storage

To Dawn

42

Continued Expansion of the NFG Supply System

Line N Expansion Opportunities

Line N to Monaca Project Project Firm transportation service to a new ethane

cracker facility being built by Shell Chemical Appalachia LLC

Target In-Service July 2019

Estimated Capital Cost $23 million

Contracted Capacity 133000 Dthday

Additional Line N Expansion Opportunity (Supply OS 221) Project New firm transportation service for on-system

demand

Open Season Capacity Awarded 165000 to foundation shipper Precedent agreement in negotiations

Pipeline amp Storage

43

Pipeline amp Storage Customer Mix

Producer33

LDC42

Marketer10

Outside Pipeline

9

End User6

42 MMDthd

(1) Contracted as of 10312018

Customer Transportation by Shipper Type(1) Affiliated Customer Mix (Contracted Capacity)

66

521

41

34

9579

59

LDCs Producers Marketers FirmStorage

Affiliated Non-Affiliated

Firm Transport

Pipeline amp Storage

44

Utility OverviewNational Fuel Gas Distribution Corporation

45

New York amp Pennsylvania Service Territories

New York

Total Customers(1) 535800ROE 87 (NY PSC Rate Case Order April 2017)Rate Mechanismso Revenue Decouplingo Weather Normalizationo Low Income Rateso Merchant Function Charge (Uncollectibles Adj)o 9010 Sharing (Large Customers)o System Modernization Tracker

Pennsylvania

Total Customers(1) 214400ROE Black Box Settlement (2007)Rate Mechanismso Low Income Rateso Merchant Function Charge

(1) As of September 30 2018

Utility

46

New York Rate Case Outcome

Rate Order Summary

Revenue Requirement $59 million

Rate Base $704 million

Allowed Return on Equity (ROE) 87

Capital Structure 429 equity

Other notable items

New rates became effective 5117

Retains rate mechanisms in place under prior order (revenue decoupling weather normalization merchant function charge 9010 large customer sharing)

No stay-out clause

System modernization tracker for Leak Prone Pipe (LPP)

Earnings sharing started 4118 (5050 sharing starts at earnings in excess of 92)

Article 78 appeal filed on 72817 with oral argument completed in January 2019

On April 20 2017 the New York Public Service Commission issued a Rate Order relating to NFG Distributionrsquos rate case (No 16-G-0257) filed in April 2016

Utility

47

Utility Continues its Significant Investments in Safety

$544$618 $636

$699

$944$980

$809$856

$90-100

$00

$250

$500

$750

$1000

$1250

2015 2016 2017 2018 2019E

Cap

ital E

xpen

ditu

res

($ m

illio

ns)

Fiscal Year

Capital Expenditures for Safety Total Capital Expenditures

Modernization Spending in NY Expected to Grow Gross Margin By $2 MM - $5 MM in FY 2019

(1)

(1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation

Utility

System modernization tracker in NY allows recovery of pipeline replacementcosts which is expected to drive modest gross margin and rate base growth

48

Accelerating Pipeline Replacement amp Modernization

Wrought Iron

Plastic

CoatedBare

120130

146 144159

2014 2015 2016 2017 2018Calendar Year

NY9726 miles

PA4830 miles

No Cast Iron Mains in Pa

Miles of Utility Main Pipeline ReplacedUtility Mains by Material(1)

Wrought Iron

Cast Iron

Plastic

Coated Bare

Utility

(1) All values are reported on a calendar year basis as of December 31 2018

49

A Proven History of Controlling Costs

$200 $189 $195

$166 $166

$31 $31

$197 $197

$0

$50

$100

$150

$200

$250

2015 2016 2017 2018 TTM 123118

Fiscal Year

OampM Expense Non-Service Pension Costs

OampM Expense ($ millions)

Utility

(1)

(1) For purposes of comparability to FY 2015 2016 and 2017 Utility Operation and Maintenance Expense for FY 2018 and the twelve months ended December 31 2018 was adjusted by approximately $314 million and $312 million respectively to include non-service pension costs which were re-classified as Other Income (Deductions) as of October 1 2018 on the Companyrsquos Income Statement See Slide 64 for non-GAAP reconciliation of Adjusted Operation and Maintenance Expense to Operation and Maintenance Expense by segment

50

Consolidated Financial OverviewUpstream I Midstream I Downstream

51

Adjusted Operating Results ($ per share)(1)

Diversified Balanced Earnings and Cash Flows

(1) A reconciliation of Adjusted Operating Results to Earnings per Share by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation(2) Consolidated Adjusted EBITDA includes Energy Marketing and Corporate amp All Other Segments A reconciliation of Adjusted EBITDA to Net Income by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in

the Business is included at the end of this presentation

Adjusted EBITDA ($ millions)(2)

$176 $179

$184 $181

$92 $97

$318 $327

$761 $775

$-

$200

$400

$600

$800

FY 2018 TTM 123118

$059 Utility

$097 Pipeline amp Storage

$057 Gathering

$125 Exploration

amp Production

$334 $345 to $365

$-

$100

$200

$300

$400

FY 2018 FY 2019 Guidance

Rate Regulated

40-45

$728

Rate Regulated

~46

52

$89 $94 $98 $81 $86 $90-$100

$140$230

$114 $95 $93 $120-$150

$138$118

$54$33 $48

$55-$65

$603$557

$99 $246$356

$460-$495

$970 $1001

$366$455

$583

$725-$810

$0

$250

$500

$750

$1000

$1250

2014 2015 2016 2017 2018 2019GuidanceFiscal Year

Exploration amp Production

Gathering

Pipeline amp Storage

Utility

Disciplined Flexible Capital Allocation

(2)

(1) Total Capital Expenditures include Energy Marketing Corporate and All Other A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation (2) FY16 FY17 and FY18 reflects the netting of $157 million $7 million and $17 million respectively of up-front proceeds received from joint development partner for working interest in joint development wells and $21M in intercompany asset transfers in FY18

Capital Expenditures by Segment ($ millions)(1)

53

Maintaining Strong Balance Sheet amp Liquidity

Total Equity49

Total Debt51

$42 Billion Total Capitalizationas of December 31 2018

218 x251 x 245 x 247 x 256 x

2015 2016 2017 2018 TTM 123118Fiscal Year End

Net Debt Adjusted EBITDA(1) Capitalization

Debt Maturity Profile ($MM) Liquidity

Committed Credit FacilitiesShort-term Debt OutstandingAvailable Short-term Credit FacilitiesCash Balance at 123118 Total Liquidity at 123118

$ 750 MM0 MM

750 MM110 MM

$ 860 MM

$500 $549 $500

$300 $300

$0

$200

$400

$600

(1) Net Debt is net of cash and temporary cash investments Reconciliations of Net Debt and Adjusted EBITDA to Net Income are included at the end of this presentation

54

Appendix

55

Safe Harbor For Forward Looking StatementsThis presentation may contain ldquoforward-looking statementsrdquo as defined by the Private Securities Litigation Reform Act of 1995 including statements regarding future prospectsplans objectives goals projections estimates of oil and gas quantities strategies future events or performance and underlying assumptions capital structure anticipatedcapital expenditures completion of construction projects projections for pension and other post-retirement benefit obligations impacts of the adoption of new accounting rulesand possible outcomes of litigation or regulatory proceedings as well as statements that are identified by the use of the words ldquoanticipatesrdquo ldquoestimatesrdquo ldquoexpectsrdquo ldquoforecastsrdquoldquointendsrdquo ldquoplansrdquo ldquopredictsrdquo ldquoprojectsrdquo ldquobelievesrdquo ldquoseeksrdquo ldquowillrdquo ldquomayrdquo and similar expressions Forward-looking statements involve risks and uncertainties which couldcause actual results or outcomes to differ materially from those expressed in the forward-looking statements The Companyrsquos expectations beliefs and projections are expressedin good faith and are believed by the Company to have a reasonable basis but there can be no assurance that managementrsquos expectations beliefs or projections will result or beachieved or accomplished

In addition to other factors the following are important factors that could cause actual results to differ materially from those discussed in the forward-looking statements delaysor changes in costs or plans with respect to Company projects or related projects of other companies including difficulties or delays in obtaining necessary governmentalapprovals permits or orders or in obtaining the cooperation of interconnecting facility operators governmentalregulatory actions initiatives and proceedings including thoseinvolving rate cases (which address among other things target rates of return rate design and retained natural gas) environmentalsafety requirements affiliate relationshipsindustry structure and franchise renewal changes in laws regulations or judicial interpretations to which the Company is subject including those involving derivatives taxessafety employment climate change other environmental matters real property and exploration and production activities such as hydraulic fracturing financial and economicconditions including the availability of credit and occurrences affecting the Companyrsquos ability to obtain financing on acceptable terms for working capital capital expendituresand other investments including any downgrades in the Companyrsquos credit ratings and changes in interest rates and other capital market conditions changes in the price ofnatural gas or oil impairments under the SECrsquos full cost ceiling test for natural gas and oil reserves factors affecting the Companyrsquos ability to successfully identify drill for andproduce economically viable natural gas and oil reserves including among others geology lease availability title disputes weather conditions shortages delays orunavailability of equipment and services required in drilling operations insufficient gathering processing and transportation capacity the need to obtain governmentalapprovals and permits and compliance with environmental laws and regulations increasing health care costs and the resulting effect on health insurance premiums and on theobligation to provide other post-retirement benefits changes in price differentials between similar quantities of natural gas or oil sold at different geographic locations and theeffect of such changes on commodity production revenues and demand for pipeline transportation capacity to or from such locations other changes in price differentialsbetween similar quantities of natural gas or oil having different quality heating value hydrocarbon mix or delivery date the cost and effects of legal and administrative claimsagainst the Company or activist shareholder campaigns to effect changes at the Company uncertainty of oil and gas reserve estimates significant differences between theCompanyrsquos projected and actual production levels for natural gas or oil changes in demographic patterns and weather conditions changes in the availability price oraccounting treatment of derivative financial instruments changes in laws actuarial assumptions the interest rate environment and the return on plantrust assets related to theCompanyrsquos pension and other post-retirement benefits which can affect future funding obligations and costs and plan liabilities changes in economic conditions includingglobal national or regional recessions and their effect on the demand for and customersrsquo ability to pay for the Companyrsquos products and services the creditworthiness orperformance of the Companyrsquos key suppliers customers and counterparties the impact of potential information technology cybersecurity or data security breaches economicdisruptions or uninsured losses resulting from major accidents fires severe weather natural disasters terrorist activities or acts of war significant differences between theCompanyrsquos projected and actual capital expenditures and operating expenses or increasing costs of insurance changes in coverage and the ability to obtain insurance

Forward-looking statements include estimates of oil and gas quantities Proved oil and gas reserves are those quantities of oil and gas which by analysis of geoscience andengineering data can be estimated with reasonable certainty to be economically producible under existing economic conditions operating methods and governmentregulations Other estimates of oil and gas quantities including estimates of probable reserves possible reserves and resource potential are by their nature more speculativethan estimates of proved reserves Accordingly estimates other than proved reserves are subject to substantially greater risk of being actually realized Investors are urged toconsider closely the disclosure in our Form 10-K available at wwwnationalfuelgascom You can also obtain this form on the SECrsquos website at wwwsecgov

For a discussion of the risks set forth above and other factors that could cause actual results to differ materially from results referred to in the forward-looking statements seeldquoRisk Factorsrdquo in the Companyrsquos Form 10-K for the fiscal year ended September 30 2018 and the Forms 10-Q for the quarter ended March 31 2018 June 30 2018 and December31 2018 The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date thereof or to reflect the occurrence ofunanticipated events

Appendix

41

National Fuel Remains Committed to Northern Access Project

Target In-Service as early as fiscal 2022

Total Cost ~$500MM (~$76MM spent to date)

Estimated Annual Revenues ~$84 million

Delivery Points

350000 Dthd to Chippawa (TCPL interconnect)

140000 Dthd to Hopewell (TGP 200 line)

Regulatory Status

February 3 2017 ndash FERC 7(c) certificate issued

August 6 2018 ndash FERC issued Order finding that NY DEC waived water quality certification

Supply and Empire currently working to finalize remaining federal authorizations

Pipeline amp Storage

To Dawn

42

Continued Expansion of the NFG Supply System

Line N Expansion Opportunities

Line N to Monaca Project Project Firm transportation service to a new ethane

cracker facility being built by Shell Chemical Appalachia LLC

Target In-Service July 2019

Estimated Capital Cost $23 million

Contracted Capacity 133000 Dthday

Additional Line N Expansion Opportunity (Supply OS 221) Project New firm transportation service for on-system

demand

Open Season Capacity Awarded 165000 to foundation shipper Precedent agreement in negotiations

Pipeline amp Storage

43

Pipeline amp Storage Customer Mix

Producer33

LDC42

Marketer10

Outside Pipeline

9

End User6

42 MMDthd

(1) Contracted as of 10312018

Customer Transportation by Shipper Type(1) Affiliated Customer Mix (Contracted Capacity)

66

521

41

34

9579

59

LDCs Producers Marketers FirmStorage

Affiliated Non-Affiliated

Firm Transport

Pipeline amp Storage

44

Utility OverviewNational Fuel Gas Distribution Corporation

45

New York amp Pennsylvania Service Territories

New York

Total Customers(1) 535800ROE 87 (NY PSC Rate Case Order April 2017)Rate Mechanismso Revenue Decouplingo Weather Normalizationo Low Income Rateso Merchant Function Charge (Uncollectibles Adj)o 9010 Sharing (Large Customers)o System Modernization Tracker

Pennsylvania

Total Customers(1) 214400ROE Black Box Settlement (2007)Rate Mechanismso Low Income Rateso Merchant Function Charge

(1) As of September 30 2018

Utility

46

New York Rate Case Outcome

Rate Order Summary

Revenue Requirement $59 million

Rate Base $704 million

Allowed Return on Equity (ROE) 87

Capital Structure 429 equity

Other notable items

New rates became effective 5117

Retains rate mechanisms in place under prior order (revenue decoupling weather normalization merchant function charge 9010 large customer sharing)

No stay-out clause

System modernization tracker for Leak Prone Pipe (LPP)

Earnings sharing started 4118 (5050 sharing starts at earnings in excess of 92)

Article 78 appeal filed on 72817 with oral argument completed in January 2019

On April 20 2017 the New York Public Service Commission issued a Rate Order relating to NFG Distributionrsquos rate case (No 16-G-0257) filed in April 2016

Utility

47

Utility Continues its Significant Investments in Safety

$544$618 $636

$699

$944$980

$809$856

$90-100

$00

$250

$500

$750

$1000

$1250

2015 2016 2017 2018 2019E

Cap

ital E

xpen

ditu

res

($ m

illio

ns)

Fiscal Year

Capital Expenditures for Safety Total Capital Expenditures

Modernization Spending in NY Expected to Grow Gross Margin By $2 MM - $5 MM in FY 2019

(1)

(1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation

Utility

System modernization tracker in NY allows recovery of pipeline replacementcosts which is expected to drive modest gross margin and rate base growth

48

Accelerating Pipeline Replacement amp Modernization

Wrought Iron

Plastic

CoatedBare

120130

146 144159

2014 2015 2016 2017 2018Calendar Year

NY9726 miles

PA4830 miles

No Cast Iron Mains in Pa

Miles of Utility Main Pipeline ReplacedUtility Mains by Material(1)

Wrought Iron

Cast Iron

Plastic

Coated Bare

Utility

(1) All values are reported on a calendar year basis as of December 31 2018

49

A Proven History of Controlling Costs

$200 $189 $195

$166 $166

$31 $31

$197 $197

$0

$50

$100

$150

$200

$250

2015 2016 2017 2018 TTM 123118

Fiscal Year

OampM Expense Non-Service Pension Costs

OampM Expense ($ millions)

Utility

(1)

(1) For purposes of comparability to FY 2015 2016 and 2017 Utility Operation and Maintenance Expense for FY 2018 and the twelve months ended December 31 2018 was adjusted by approximately $314 million and $312 million respectively to include non-service pension costs which were re-classified as Other Income (Deductions) as of October 1 2018 on the Companyrsquos Income Statement See Slide 64 for non-GAAP reconciliation of Adjusted Operation and Maintenance Expense to Operation and Maintenance Expense by segment

50

Consolidated Financial OverviewUpstream I Midstream I Downstream

51

Adjusted Operating Results ($ per share)(1)

Diversified Balanced Earnings and Cash Flows

(1) A reconciliation of Adjusted Operating Results to Earnings per Share by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation(2) Consolidated Adjusted EBITDA includes Energy Marketing and Corporate amp All Other Segments A reconciliation of Adjusted EBITDA to Net Income by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in

the Business is included at the end of this presentation

Adjusted EBITDA ($ millions)(2)

$176 $179

$184 $181

$92 $97

$318 $327

$761 $775

$-

$200

$400

$600

$800

FY 2018 TTM 123118

$059 Utility

$097 Pipeline amp Storage

$057 Gathering

$125 Exploration

amp Production

$334 $345 to $365

$-

$100

$200

$300

$400

FY 2018 FY 2019 Guidance

Rate Regulated

40-45

$728

Rate Regulated

~46

52

$89 $94 $98 $81 $86 $90-$100

$140$230

$114 $95 $93 $120-$150

$138$118

$54$33 $48

$55-$65

$603$557

$99 $246$356

$460-$495

$970 $1001

$366$455

$583

$725-$810

$0

$250

$500

$750

$1000

$1250

2014 2015 2016 2017 2018 2019GuidanceFiscal Year

Exploration amp Production

Gathering

Pipeline amp Storage

Utility

Disciplined Flexible Capital Allocation

(2)

(1) Total Capital Expenditures include Energy Marketing Corporate and All Other A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation (2) FY16 FY17 and FY18 reflects the netting of $157 million $7 million and $17 million respectively of up-front proceeds received from joint development partner for working interest in joint development wells and $21M in intercompany asset transfers in FY18

Capital Expenditures by Segment ($ millions)(1)

53

Maintaining Strong Balance Sheet amp Liquidity

Total Equity49

Total Debt51

$42 Billion Total Capitalizationas of December 31 2018

218 x251 x 245 x 247 x 256 x

2015 2016 2017 2018 TTM 123118Fiscal Year End

Net Debt Adjusted EBITDA(1) Capitalization

Debt Maturity Profile ($MM) Liquidity

Committed Credit FacilitiesShort-term Debt OutstandingAvailable Short-term Credit FacilitiesCash Balance at 123118 Total Liquidity at 123118

$ 750 MM0 MM

750 MM110 MM

$ 860 MM

$500 $549 $500

$300 $300

$0

$200

$400

$600

(1) Net Debt is net of cash and temporary cash investments Reconciliations of Net Debt and Adjusted EBITDA to Net Income are included at the end of this presentation

54

Appendix

55

Safe Harbor For Forward Looking StatementsThis presentation may contain ldquoforward-looking statementsrdquo as defined by the Private Securities Litigation Reform Act of 1995 including statements regarding future prospectsplans objectives goals projections estimates of oil and gas quantities strategies future events or performance and underlying assumptions capital structure anticipatedcapital expenditures completion of construction projects projections for pension and other post-retirement benefit obligations impacts of the adoption of new accounting rulesand possible outcomes of litigation or regulatory proceedings as well as statements that are identified by the use of the words ldquoanticipatesrdquo ldquoestimatesrdquo ldquoexpectsrdquo ldquoforecastsrdquoldquointendsrdquo ldquoplansrdquo ldquopredictsrdquo ldquoprojectsrdquo ldquobelievesrdquo ldquoseeksrdquo ldquowillrdquo ldquomayrdquo and similar expressions Forward-looking statements involve risks and uncertainties which couldcause actual results or outcomes to differ materially from those expressed in the forward-looking statements The Companyrsquos expectations beliefs and projections are expressedin good faith and are believed by the Company to have a reasonable basis but there can be no assurance that managementrsquos expectations beliefs or projections will result or beachieved or accomplished

In addition to other factors the following are important factors that could cause actual results to differ materially from those discussed in the forward-looking statements delaysor changes in costs or plans with respect to Company projects or related projects of other companies including difficulties or delays in obtaining necessary governmentalapprovals permits or orders or in obtaining the cooperation of interconnecting facility operators governmentalregulatory actions initiatives and proceedings including thoseinvolving rate cases (which address among other things target rates of return rate design and retained natural gas) environmentalsafety requirements affiliate relationshipsindustry structure and franchise renewal changes in laws regulations or judicial interpretations to which the Company is subject including those involving derivatives taxessafety employment climate change other environmental matters real property and exploration and production activities such as hydraulic fracturing financial and economicconditions including the availability of credit and occurrences affecting the Companyrsquos ability to obtain financing on acceptable terms for working capital capital expendituresand other investments including any downgrades in the Companyrsquos credit ratings and changes in interest rates and other capital market conditions changes in the price ofnatural gas or oil impairments under the SECrsquos full cost ceiling test for natural gas and oil reserves factors affecting the Companyrsquos ability to successfully identify drill for andproduce economically viable natural gas and oil reserves including among others geology lease availability title disputes weather conditions shortages delays orunavailability of equipment and services required in drilling operations insufficient gathering processing and transportation capacity the need to obtain governmentalapprovals and permits and compliance with environmental laws and regulations increasing health care costs and the resulting effect on health insurance premiums and on theobligation to provide other post-retirement benefits changes in price differentials between similar quantities of natural gas or oil sold at different geographic locations and theeffect of such changes on commodity production revenues and demand for pipeline transportation capacity to or from such locations other changes in price differentialsbetween similar quantities of natural gas or oil having different quality heating value hydrocarbon mix or delivery date the cost and effects of legal and administrative claimsagainst the Company or activist shareholder campaigns to effect changes at the Company uncertainty of oil and gas reserve estimates significant differences between theCompanyrsquos projected and actual production levels for natural gas or oil changes in demographic patterns and weather conditions changes in the availability price oraccounting treatment of derivative financial instruments changes in laws actuarial assumptions the interest rate environment and the return on plantrust assets related to theCompanyrsquos pension and other post-retirement benefits which can affect future funding obligations and costs and plan liabilities changes in economic conditions includingglobal national or regional recessions and their effect on the demand for and customersrsquo ability to pay for the Companyrsquos products and services the creditworthiness orperformance of the Companyrsquos key suppliers customers and counterparties the impact of potential information technology cybersecurity or data security breaches economicdisruptions or uninsured losses resulting from major accidents fires severe weather natural disasters terrorist activities or acts of war significant differences between theCompanyrsquos projected and actual capital expenditures and operating expenses or increasing costs of insurance changes in coverage and the ability to obtain insurance

Forward-looking statements include estimates of oil and gas quantities Proved oil and gas reserves are those quantities of oil and gas which by analysis of geoscience andengineering data can be estimated with reasonable certainty to be economically producible under existing economic conditions operating methods and governmentregulations Other estimates of oil and gas quantities including estimates of probable reserves possible reserves and resource potential are by their nature more speculativethan estimates of proved reserves Accordingly estimates other than proved reserves are subject to substantially greater risk of being actually realized Investors are urged toconsider closely the disclosure in our Form 10-K available at wwwnationalfuelgascom You can also obtain this form on the SECrsquos website at wwwsecgov

For a discussion of the risks set forth above and other factors that could cause actual results to differ materially from results referred to in the forward-looking statements seeldquoRisk Factorsrdquo in the Companyrsquos Form 10-K for the fiscal year ended September 30 2018 and the Forms 10-Q for the quarter ended March 31 2018 June 30 2018 and December31 2018 The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date thereof or to reflect the occurrence ofunanticipated events

Appendix

42

Continued Expansion of the NFG Supply System

Line N Expansion Opportunities

Line N to Monaca Project Project Firm transportation service to a new ethane

cracker facility being built by Shell Chemical Appalachia LLC

Target In-Service July 2019

Estimated Capital Cost $23 million

Contracted Capacity 133000 Dthday

Additional Line N Expansion Opportunity (Supply OS 221) Project New firm transportation service for on-system

demand

Open Season Capacity Awarded 165000 to foundation shipper Precedent agreement in negotiations

Pipeline amp Storage

43

Pipeline amp Storage Customer Mix

Producer33

LDC42

Marketer10

Outside Pipeline

9

End User6

42 MMDthd

(1) Contracted as of 10312018

Customer Transportation by Shipper Type(1) Affiliated Customer Mix (Contracted Capacity)

66

521

41

34

9579

59

LDCs Producers Marketers FirmStorage

Affiliated Non-Affiliated

Firm Transport

Pipeline amp Storage

44

Utility OverviewNational Fuel Gas Distribution Corporation

45

New York amp Pennsylvania Service Territories

New York

Total Customers(1) 535800ROE 87 (NY PSC Rate Case Order April 2017)Rate Mechanismso Revenue Decouplingo Weather Normalizationo Low Income Rateso Merchant Function Charge (Uncollectibles Adj)o 9010 Sharing (Large Customers)o System Modernization Tracker

Pennsylvania

Total Customers(1) 214400ROE Black Box Settlement (2007)Rate Mechanismso Low Income Rateso Merchant Function Charge

(1) As of September 30 2018

Utility

46

New York Rate Case Outcome

Rate Order Summary

Revenue Requirement $59 million

Rate Base $704 million

Allowed Return on Equity (ROE) 87

Capital Structure 429 equity

Other notable items

New rates became effective 5117

Retains rate mechanisms in place under prior order (revenue decoupling weather normalization merchant function charge 9010 large customer sharing)

No stay-out clause

System modernization tracker for Leak Prone Pipe (LPP)

Earnings sharing started 4118 (5050 sharing starts at earnings in excess of 92)

Article 78 appeal filed on 72817 with oral argument completed in January 2019

On April 20 2017 the New York Public Service Commission issued a Rate Order relating to NFG Distributionrsquos rate case (No 16-G-0257) filed in April 2016

Utility

47

Utility Continues its Significant Investments in Safety

$544$618 $636

$699

$944$980

$809$856

$90-100

$00

$250

$500

$750

$1000

$1250

2015 2016 2017 2018 2019E

Cap

ital E

xpen

ditu

res

($ m

illio

ns)

Fiscal Year

Capital Expenditures for Safety Total Capital Expenditures

Modernization Spending in NY Expected to Grow Gross Margin By $2 MM - $5 MM in FY 2019

(1)

(1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation

Utility

System modernization tracker in NY allows recovery of pipeline replacementcosts which is expected to drive modest gross margin and rate base growth

48

Accelerating Pipeline Replacement amp Modernization

Wrought Iron

Plastic

CoatedBare

120130

146 144159

2014 2015 2016 2017 2018Calendar Year

NY9726 miles

PA4830 miles

No Cast Iron Mains in Pa

Miles of Utility Main Pipeline ReplacedUtility Mains by Material(1)

Wrought Iron

Cast Iron

Plastic

Coated Bare

Utility

(1) All values are reported on a calendar year basis as of December 31 2018

49

A Proven History of Controlling Costs

$200 $189 $195

$166 $166

$31 $31

$197 $197

$0

$50

$100

$150

$200

$250

2015 2016 2017 2018 TTM 123118

Fiscal Year

OampM Expense Non-Service Pension Costs

OampM Expense ($ millions)

Utility

(1)

(1) For purposes of comparability to FY 2015 2016 and 2017 Utility Operation and Maintenance Expense for FY 2018 and the twelve months ended December 31 2018 was adjusted by approximately $314 million and $312 million respectively to include non-service pension costs which were re-classified as Other Income (Deductions) as of October 1 2018 on the Companyrsquos Income Statement See Slide 64 for non-GAAP reconciliation of Adjusted Operation and Maintenance Expense to Operation and Maintenance Expense by segment

50

Consolidated Financial OverviewUpstream I Midstream I Downstream

51

Adjusted Operating Results ($ per share)(1)

Diversified Balanced Earnings and Cash Flows

(1) A reconciliation of Adjusted Operating Results to Earnings per Share by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation(2) Consolidated Adjusted EBITDA includes Energy Marketing and Corporate amp All Other Segments A reconciliation of Adjusted EBITDA to Net Income by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in

the Business is included at the end of this presentation

Adjusted EBITDA ($ millions)(2)

$176 $179

$184 $181

$92 $97

$318 $327

$761 $775

$-

$200

$400

$600

$800

FY 2018 TTM 123118

$059 Utility

$097 Pipeline amp Storage

$057 Gathering

$125 Exploration

amp Production

$334 $345 to $365

$-

$100

$200

$300

$400

FY 2018 FY 2019 Guidance

Rate Regulated

40-45

$728

Rate Regulated

~46

52

$89 $94 $98 $81 $86 $90-$100

$140$230

$114 $95 $93 $120-$150

$138$118

$54$33 $48

$55-$65

$603$557

$99 $246$356

$460-$495

$970 $1001

$366$455

$583

$725-$810

$0

$250

$500

$750

$1000

$1250

2014 2015 2016 2017 2018 2019GuidanceFiscal Year

Exploration amp Production

Gathering

Pipeline amp Storage

Utility

Disciplined Flexible Capital Allocation

(2)

(1) Total Capital Expenditures include Energy Marketing Corporate and All Other A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation (2) FY16 FY17 and FY18 reflects the netting of $157 million $7 million and $17 million respectively of up-front proceeds received from joint development partner for working interest in joint development wells and $21M in intercompany asset transfers in FY18

Capital Expenditures by Segment ($ millions)(1)

53

Maintaining Strong Balance Sheet amp Liquidity

Total Equity49

Total Debt51

$42 Billion Total Capitalizationas of December 31 2018

218 x251 x 245 x 247 x 256 x

2015 2016 2017 2018 TTM 123118Fiscal Year End

Net Debt Adjusted EBITDA(1) Capitalization

Debt Maturity Profile ($MM) Liquidity

Committed Credit FacilitiesShort-term Debt OutstandingAvailable Short-term Credit FacilitiesCash Balance at 123118 Total Liquidity at 123118

$ 750 MM0 MM

750 MM110 MM

$ 860 MM

$500 $549 $500

$300 $300

$0

$200

$400

$600

(1) Net Debt is net of cash and temporary cash investments Reconciliations of Net Debt and Adjusted EBITDA to Net Income are included at the end of this presentation

54

Appendix

55

Safe Harbor For Forward Looking StatementsThis presentation may contain ldquoforward-looking statementsrdquo as defined by the Private Securities Litigation Reform Act of 1995 including statements regarding future prospectsplans objectives goals projections estimates of oil and gas quantities strategies future events or performance and underlying assumptions capital structure anticipatedcapital expenditures completion of construction projects projections for pension and other post-retirement benefit obligations impacts of the adoption of new accounting rulesand possible outcomes of litigation or regulatory proceedings as well as statements that are identified by the use of the words ldquoanticipatesrdquo ldquoestimatesrdquo ldquoexpectsrdquo ldquoforecastsrdquoldquointendsrdquo ldquoplansrdquo ldquopredictsrdquo ldquoprojectsrdquo ldquobelievesrdquo ldquoseeksrdquo ldquowillrdquo ldquomayrdquo and similar expressions Forward-looking statements involve risks and uncertainties which couldcause actual results or outcomes to differ materially from those expressed in the forward-looking statements The Companyrsquos expectations beliefs and projections are expressedin good faith and are believed by the Company to have a reasonable basis but there can be no assurance that managementrsquos expectations beliefs or projections will result or beachieved or accomplished

In addition to other factors the following are important factors that could cause actual results to differ materially from those discussed in the forward-looking statements delaysor changes in costs or plans with respect to Company projects or related projects of other companies including difficulties or delays in obtaining necessary governmentalapprovals permits or orders or in obtaining the cooperation of interconnecting facility operators governmentalregulatory actions initiatives and proceedings including thoseinvolving rate cases (which address among other things target rates of return rate design and retained natural gas) environmentalsafety requirements affiliate relationshipsindustry structure and franchise renewal changes in laws regulations or judicial interpretations to which the Company is subject including those involving derivatives taxessafety employment climate change other environmental matters real property and exploration and production activities such as hydraulic fracturing financial and economicconditions including the availability of credit and occurrences affecting the Companyrsquos ability to obtain financing on acceptable terms for working capital capital expendituresand other investments including any downgrades in the Companyrsquos credit ratings and changes in interest rates and other capital market conditions changes in the price ofnatural gas or oil impairments under the SECrsquos full cost ceiling test for natural gas and oil reserves factors affecting the Companyrsquos ability to successfully identify drill for andproduce economically viable natural gas and oil reserves including among others geology lease availability title disputes weather conditions shortages delays orunavailability of equipment and services required in drilling operations insufficient gathering processing and transportation capacity the need to obtain governmentalapprovals and permits and compliance with environmental laws and regulations increasing health care costs and the resulting effect on health insurance premiums and on theobligation to provide other post-retirement benefits changes in price differentials between similar quantities of natural gas or oil sold at different geographic locations and theeffect of such changes on commodity production revenues and demand for pipeline transportation capacity to or from such locations other changes in price differentialsbetween similar quantities of natural gas or oil having different quality heating value hydrocarbon mix or delivery date the cost and effects of legal and administrative claimsagainst the Company or activist shareholder campaigns to effect changes at the Company uncertainty of oil and gas reserve estimates significant differences between theCompanyrsquos projected and actual production levels for natural gas or oil changes in demographic patterns and weather conditions changes in the availability price oraccounting treatment of derivative financial instruments changes in laws actuarial assumptions the interest rate environment and the return on plantrust assets related to theCompanyrsquos pension and other post-retirement benefits which can affect future funding obligations and costs and plan liabilities changes in economic conditions includingglobal national or regional recessions and their effect on the demand for and customersrsquo ability to pay for the Companyrsquos products and services the creditworthiness orperformance of the Companyrsquos key suppliers customers and counterparties the impact of potential information technology cybersecurity or data security breaches economicdisruptions or uninsured losses resulting from major accidents fires severe weather natural disasters terrorist activities or acts of war significant differences between theCompanyrsquos projected and actual capital expenditures and operating expenses or increasing costs of insurance changes in coverage and the ability to obtain insurance

Forward-looking statements include estimates of oil and gas quantities Proved oil and gas reserves are those quantities of oil and gas which by analysis of geoscience andengineering data can be estimated with reasonable certainty to be economically producible under existing economic conditions operating methods and governmentregulations Other estimates of oil and gas quantities including estimates of probable reserves possible reserves and resource potential are by their nature more speculativethan estimates of proved reserves Accordingly estimates other than proved reserves are subject to substantially greater risk of being actually realized Investors are urged toconsider closely the disclosure in our Form 10-K available at wwwnationalfuelgascom You can also obtain this form on the SECrsquos website at wwwsecgov

For a discussion of the risks set forth above and other factors that could cause actual results to differ materially from results referred to in the forward-looking statements seeldquoRisk Factorsrdquo in the Companyrsquos Form 10-K for the fiscal year ended September 30 2018 and the Forms 10-Q for the quarter ended March 31 2018 June 30 2018 and December31 2018 The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date thereof or to reflect the occurrence ofunanticipated events

Appendix

43

Pipeline amp Storage Customer Mix

Producer33

LDC42

Marketer10

Outside Pipeline

9

End User6

42 MMDthd

(1) Contracted as of 10312018

Customer Transportation by Shipper Type(1) Affiliated Customer Mix (Contracted Capacity)

66

521

41

34

9579

59

LDCs Producers Marketers FirmStorage

Affiliated Non-Affiliated

Firm Transport

Pipeline amp Storage

44

Utility OverviewNational Fuel Gas Distribution Corporation

45

New York amp Pennsylvania Service Territories

New York

Total Customers(1) 535800ROE 87 (NY PSC Rate Case Order April 2017)Rate Mechanismso Revenue Decouplingo Weather Normalizationo Low Income Rateso Merchant Function Charge (Uncollectibles Adj)o 9010 Sharing (Large Customers)o System Modernization Tracker

Pennsylvania

Total Customers(1) 214400ROE Black Box Settlement (2007)Rate Mechanismso Low Income Rateso Merchant Function Charge

(1) As of September 30 2018

Utility

46

New York Rate Case Outcome

Rate Order Summary

Revenue Requirement $59 million

Rate Base $704 million

Allowed Return on Equity (ROE) 87

Capital Structure 429 equity

Other notable items

New rates became effective 5117

Retains rate mechanisms in place under prior order (revenue decoupling weather normalization merchant function charge 9010 large customer sharing)

No stay-out clause

System modernization tracker for Leak Prone Pipe (LPP)

Earnings sharing started 4118 (5050 sharing starts at earnings in excess of 92)

Article 78 appeal filed on 72817 with oral argument completed in January 2019

On April 20 2017 the New York Public Service Commission issued a Rate Order relating to NFG Distributionrsquos rate case (No 16-G-0257) filed in April 2016

Utility

47

Utility Continues its Significant Investments in Safety

$544$618 $636

$699

$944$980

$809$856

$90-100

$00

$250

$500

$750

$1000

$1250

2015 2016 2017 2018 2019E

Cap

ital E

xpen

ditu

res

($ m

illio

ns)

Fiscal Year

Capital Expenditures for Safety Total Capital Expenditures

Modernization Spending in NY Expected to Grow Gross Margin By $2 MM - $5 MM in FY 2019

(1)

(1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation

Utility

System modernization tracker in NY allows recovery of pipeline replacementcosts which is expected to drive modest gross margin and rate base growth

48

Accelerating Pipeline Replacement amp Modernization

Wrought Iron

Plastic

CoatedBare

120130

146 144159

2014 2015 2016 2017 2018Calendar Year

NY9726 miles

PA4830 miles

No Cast Iron Mains in Pa

Miles of Utility Main Pipeline ReplacedUtility Mains by Material(1)

Wrought Iron

Cast Iron

Plastic

Coated Bare

Utility

(1) All values are reported on a calendar year basis as of December 31 2018

49

A Proven History of Controlling Costs

$200 $189 $195

$166 $166

$31 $31

$197 $197

$0

$50

$100

$150

$200

$250

2015 2016 2017 2018 TTM 123118

Fiscal Year

OampM Expense Non-Service Pension Costs

OampM Expense ($ millions)

Utility

(1)

(1) For purposes of comparability to FY 2015 2016 and 2017 Utility Operation and Maintenance Expense for FY 2018 and the twelve months ended December 31 2018 was adjusted by approximately $314 million and $312 million respectively to include non-service pension costs which were re-classified as Other Income (Deductions) as of October 1 2018 on the Companyrsquos Income Statement See Slide 64 for non-GAAP reconciliation of Adjusted Operation and Maintenance Expense to Operation and Maintenance Expense by segment

50

Consolidated Financial OverviewUpstream I Midstream I Downstream

51

Adjusted Operating Results ($ per share)(1)

Diversified Balanced Earnings and Cash Flows

(1) A reconciliation of Adjusted Operating Results to Earnings per Share by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation(2) Consolidated Adjusted EBITDA includes Energy Marketing and Corporate amp All Other Segments A reconciliation of Adjusted EBITDA to Net Income by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in

the Business is included at the end of this presentation

Adjusted EBITDA ($ millions)(2)

$176 $179

$184 $181

$92 $97

$318 $327

$761 $775

$-

$200

$400

$600

$800

FY 2018 TTM 123118

$059 Utility

$097 Pipeline amp Storage

$057 Gathering

$125 Exploration

amp Production

$334 $345 to $365

$-

$100

$200

$300

$400

FY 2018 FY 2019 Guidance

Rate Regulated

40-45

$728

Rate Regulated

~46

52

$89 $94 $98 $81 $86 $90-$100

$140$230

$114 $95 $93 $120-$150

$138$118

$54$33 $48

$55-$65

$603$557

$99 $246$356

$460-$495

$970 $1001

$366$455

$583

$725-$810

$0

$250

$500

$750

$1000

$1250

2014 2015 2016 2017 2018 2019GuidanceFiscal Year

Exploration amp Production

Gathering

Pipeline amp Storage

Utility

Disciplined Flexible Capital Allocation

(2)

(1) Total Capital Expenditures include Energy Marketing Corporate and All Other A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation (2) FY16 FY17 and FY18 reflects the netting of $157 million $7 million and $17 million respectively of up-front proceeds received from joint development partner for working interest in joint development wells and $21M in intercompany asset transfers in FY18

Capital Expenditures by Segment ($ millions)(1)

53

Maintaining Strong Balance Sheet amp Liquidity

Total Equity49

Total Debt51

$42 Billion Total Capitalizationas of December 31 2018

218 x251 x 245 x 247 x 256 x

2015 2016 2017 2018 TTM 123118Fiscal Year End

Net Debt Adjusted EBITDA(1) Capitalization

Debt Maturity Profile ($MM) Liquidity

Committed Credit FacilitiesShort-term Debt OutstandingAvailable Short-term Credit FacilitiesCash Balance at 123118 Total Liquidity at 123118

$ 750 MM0 MM

750 MM110 MM

$ 860 MM

$500 $549 $500

$300 $300

$0

$200

$400

$600

(1) Net Debt is net of cash and temporary cash investments Reconciliations of Net Debt and Adjusted EBITDA to Net Income are included at the end of this presentation

54

Appendix

55

Safe Harbor For Forward Looking StatementsThis presentation may contain ldquoforward-looking statementsrdquo as defined by the Private Securities Litigation Reform Act of 1995 including statements regarding future prospectsplans objectives goals projections estimates of oil and gas quantities strategies future events or performance and underlying assumptions capital structure anticipatedcapital expenditures completion of construction projects projections for pension and other post-retirement benefit obligations impacts of the adoption of new accounting rulesand possible outcomes of litigation or regulatory proceedings as well as statements that are identified by the use of the words ldquoanticipatesrdquo ldquoestimatesrdquo ldquoexpectsrdquo ldquoforecastsrdquoldquointendsrdquo ldquoplansrdquo ldquopredictsrdquo ldquoprojectsrdquo ldquobelievesrdquo ldquoseeksrdquo ldquowillrdquo ldquomayrdquo and similar expressions Forward-looking statements involve risks and uncertainties which couldcause actual results or outcomes to differ materially from those expressed in the forward-looking statements The Companyrsquos expectations beliefs and projections are expressedin good faith and are believed by the Company to have a reasonable basis but there can be no assurance that managementrsquos expectations beliefs or projections will result or beachieved or accomplished

In addition to other factors the following are important factors that could cause actual results to differ materially from those discussed in the forward-looking statements delaysor changes in costs or plans with respect to Company projects or related projects of other companies including difficulties or delays in obtaining necessary governmentalapprovals permits or orders or in obtaining the cooperation of interconnecting facility operators governmentalregulatory actions initiatives and proceedings including thoseinvolving rate cases (which address among other things target rates of return rate design and retained natural gas) environmentalsafety requirements affiliate relationshipsindustry structure and franchise renewal changes in laws regulations or judicial interpretations to which the Company is subject including those involving derivatives taxessafety employment climate change other environmental matters real property and exploration and production activities such as hydraulic fracturing financial and economicconditions including the availability of credit and occurrences affecting the Companyrsquos ability to obtain financing on acceptable terms for working capital capital expendituresand other investments including any downgrades in the Companyrsquos credit ratings and changes in interest rates and other capital market conditions changes in the price ofnatural gas or oil impairments under the SECrsquos full cost ceiling test for natural gas and oil reserves factors affecting the Companyrsquos ability to successfully identify drill for andproduce economically viable natural gas and oil reserves including among others geology lease availability title disputes weather conditions shortages delays orunavailability of equipment and services required in drilling operations insufficient gathering processing and transportation capacity the need to obtain governmentalapprovals and permits and compliance with environmental laws and regulations increasing health care costs and the resulting effect on health insurance premiums and on theobligation to provide other post-retirement benefits changes in price differentials between similar quantities of natural gas or oil sold at different geographic locations and theeffect of such changes on commodity production revenues and demand for pipeline transportation capacity to or from such locations other changes in price differentialsbetween similar quantities of natural gas or oil having different quality heating value hydrocarbon mix or delivery date the cost and effects of legal and administrative claimsagainst the Company or activist shareholder campaigns to effect changes at the Company uncertainty of oil and gas reserve estimates significant differences between theCompanyrsquos projected and actual production levels for natural gas or oil changes in demographic patterns and weather conditions changes in the availability price oraccounting treatment of derivative financial instruments changes in laws actuarial assumptions the interest rate environment and the return on plantrust assets related to theCompanyrsquos pension and other post-retirement benefits which can affect future funding obligations and costs and plan liabilities changes in economic conditions includingglobal national or regional recessions and their effect on the demand for and customersrsquo ability to pay for the Companyrsquos products and services the creditworthiness orperformance of the Companyrsquos key suppliers customers and counterparties the impact of potential information technology cybersecurity or data security breaches economicdisruptions or uninsured losses resulting from major accidents fires severe weather natural disasters terrorist activities or acts of war significant differences between theCompanyrsquos projected and actual capital expenditures and operating expenses or increasing costs of insurance changes in coverage and the ability to obtain insurance

Forward-looking statements include estimates of oil and gas quantities Proved oil and gas reserves are those quantities of oil and gas which by analysis of geoscience andengineering data can be estimated with reasonable certainty to be economically producible under existing economic conditions operating methods and governmentregulations Other estimates of oil and gas quantities including estimates of probable reserves possible reserves and resource potential are by their nature more speculativethan estimates of proved reserves Accordingly estimates other than proved reserves are subject to substantially greater risk of being actually realized Investors are urged toconsider closely the disclosure in our Form 10-K available at wwwnationalfuelgascom You can also obtain this form on the SECrsquos website at wwwsecgov

For a discussion of the risks set forth above and other factors that could cause actual results to differ materially from results referred to in the forward-looking statements seeldquoRisk Factorsrdquo in the Companyrsquos Form 10-K for the fiscal year ended September 30 2018 and the Forms 10-Q for the quarter ended March 31 2018 June 30 2018 and December31 2018 The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date thereof or to reflect the occurrence ofunanticipated events

Appendix

44

Utility OverviewNational Fuel Gas Distribution Corporation

45

New York amp Pennsylvania Service Territories

New York

Total Customers(1) 535800ROE 87 (NY PSC Rate Case Order April 2017)Rate Mechanismso Revenue Decouplingo Weather Normalizationo Low Income Rateso Merchant Function Charge (Uncollectibles Adj)o 9010 Sharing (Large Customers)o System Modernization Tracker

Pennsylvania

Total Customers(1) 214400ROE Black Box Settlement (2007)Rate Mechanismso Low Income Rateso Merchant Function Charge

(1) As of September 30 2018

Utility

46

New York Rate Case Outcome

Rate Order Summary

Revenue Requirement $59 million

Rate Base $704 million

Allowed Return on Equity (ROE) 87

Capital Structure 429 equity

Other notable items

New rates became effective 5117

Retains rate mechanisms in place under prior order (revenue decoupling weather normalization merchant function charge 9010 large customer sharing)

No stay-out clause

System modernization tracker for Leak Prone Pipe (LPP)

Earnings sharing started 4118 (5050 sharing starts at earnings in excess of 92)

Article 78 appeal filed on 72817 with oral argument completed in January 2019

On April 20 2017 the New York Public Service Commission issued a Rate Order relating to NFG Distributionrsquos rate case (No 16-G-0257) filed in April 2016

Utility

47

Utility Continues its Significant Investments in Safety

$544$618 $636

$699

$944$980

$809$856

$90-100

$00

$250

$500

$750

$1000

$1250

2015 2016 2017 2018 2019E

Cap

ital E

xpen

ditu

res

($ m

illio

ns)

Fiscal Year

Capital Expenditures for Safety Total Capital Expenditures

Modernization Spending in NY Expected to Grow Gross Margin By $2 MM - $5 MM in FY 2019

(1)

(1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation

Utility

System modernization tracker in NY allows recovery of pipeline replacementcosts which is expected to drive modest gross margin and rate base growth

48

Accelerating Pipeline Replacement amp Modernization

Wrought Iron

Plastic

CoatedBare

120130

146 144159

2014 2015 2016 2017 2018Calendar Year

NY9726 miles

PA4830 miles

No Cast Iron Mains in Pa

Miles of Utility Main Pipeline ReplacedUtility Mains by Material(1)

Wrought Iron

Cast Iron

Plastic

Coated Bare

Utility

(1) All values are reported on a calendar year basis as of December 31 2018

49

A Proven History of Controlling Costs

$200 $189 $195

$166 $166

$31 $31

$197 $197

$0

$50

$100

$150

$200

$250

2015 2016 2017 2018 TTM 123118

Fiscal Year

OampM Expense Non-Service Pension Costs

OampM Expense ($ millions)

Utility

(1)

(1) For purposes of comparability to FY 2015 2016 and 2017 Utility Operation and Maintenance Expense for FY 2018 and the twelve months ended December 31 2018 was adjusted by approximately $314 million and $312 million respectively to include non-service pension costs which were re-classified as Other Income (Deductions) as of October 1 2018 on the Companyrsquos Income Statement See Slide 64 for non-GAAP reconciliation of Adjusted Operation and Maintenance Expense to Operation and Maintenance Expense by segment

50

Consolidated Financial OverviewUpstream I Midstream I Downstream

51

Adjusted Operating Results ($ per share)(1)

Diversified Balanced Earnings and Cash Flows

(1) A reconciliation of Adjusted Operating Results to Earnings per Share by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation(2) Consolidated Adjusted EBITDA includes Energy Marketing and Corporate amp All Other Segments A reconciliation of Adjusted EBITDA to Net Income by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in

the Business is included at the end of this presentation

Adjusted EBITDA ($ millions)(2)

$176 $179

$184 $181

$92 $97

$318 $327

$761 $775

$-

$200

$400

$600

$800

FY 2018 TTM 123118

$059 Utility

$097 Pipeline amp Storage

$057 Gathering

$125 Exploration

amp Production

$334 $345 to $365

$-

$100

$200

$300

$400

FY 2018 FY 2019 Guidance

Rate Regulated

40-45

$728

Rate Regulated

~46

52

$89 $94 $98 $81 $86 $90-$100

$140$230

$114 $95 $93 $120-$150

$138$118

$54$33 $48

$55-$65

$603$557

$99 $246$356

$460-$495

$970 $1001

$366$455

$583

$725-$810

$0

$250

$500

$750

$1000

$1250

2014 2015 2016 2017 2018 2019GuidanceFiscal Year

Exploration amp Production

Gathering

Pipeline amp Storage

Utility

Disciplined Flexible Capital Allocation

(2)

(1) Total Capital Expenditures include Energy Marketing Corporate and All Other A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation (2) FY16 FY17 and FY18 reflects the netting of $157 million $7 million and $17 million respectively of up-front proceeds received from joint development partner for working interest in joint development wells and $21M in intercompany asset transfers in FY18

Capital Expenditures by Segment ($ millions)(1)

53

Maintaining Strong Balance Sheet amp Liquidity

Total Equity49

Total Debt51

$42 Billion Total Capitalizationas of December 31 2018

218 x251 x 245 x 247 x 256 x

2015 2016 2017 2018 TTM 123118Fiscal Year End

Net Debt Adjusted EBITDA(1) Capitalization

Debt Maturity Profile ($MM) Liquidity

Committed Credit FacilitiesShort-term Debt OutstandingAvailable Short-term Credit FacilitiesCash Balance at 123118 Total Liquidity at 123118

$ 750 MM0 MM

750 MM110 MM

$ 860 MM

$500 $549 $500

$300 $300

$0

$200

$400

$600

(1) Net Debt is net of cash and temporary cash investments Reconciliations of Net Debt and Adjusted EBITDA to Net Income are included at the end of this presentation

54

Appendix

55

Safe Harbor For Forward Looking StatementsThis presentation may contain ldquoforward-looking statementsrdquo as defined by the Private Securities Litigation Reform Act of 1995 including statements regarding future prospectsplans objectives goals projections estimates of oil and gas quantities strategies future events or performance and underlying assumptions capital structure anticipatedcapital expenditures completion of construction projects projections for pension and other post-retirement benefit obligations impacts of the adoption of new accounting rulesand possible outcomes of litigation or regulatory proceedings as well as statements that are identified by the use of the words ldquoanticipatesrdquo ldquoestimatesrdquo ldquoexpectsrdquo ldquoforecastsrdquoldquointendsrdquo ldquoplansrdquo ldquopredictsrdquo ldquoprojectsrdquo ldquobelievesrdquo ldquoseeksrdquo ldquowillrdquo ldquomayrdquo and similar expressions Forward-looking statements involve risks and uncertainties which couldcause actual results or outcomes to differ materially from those expressed in the forward-looking statements The Companyrsquos expectations beliefs and projections are expressedin good faith and are believed by the Company to have a reasonable basis but there can be no assurance that managementrsquos expectations beliefs or projections will result or beachieved or accomplished

In addition to other factors the following are important factors that could cause actual results to differ materially from those discussed in the forward-looking statements delaysor changes in costs or plans with respect to Company projects or related projects of other companies including difficulties or delays in obtaining necessary governmentalapprovals permits or orders or in obtaining the cooperation of interconnecting facility operators governmentalregulatory actions initiatives and proceedings including thoseinvolving rate cases (which address among other things target rates of return rate design and retained natural gas) environmentalsafety requirements affiliate relationshipsindustry structure and franchise renewal changes in laws regulations or judicial interpretations to which the Company is subject including those involving derivatives taxessafety employment climate change other environmental matters real property and exploration and production activities such as hydraulic fracturing financial and economicconditions including the availability of credit and occurrences affecting the Companyrsquos ability to obtain financing on acceptable terms for working capital capital expendituresand other investments including any downgrades in the Companyrsquos credit ratings and changes in interest rates and other capital market conditions changes in the price ofnatural gas or oil impairments under the SECrsquos full cost ceiling test for natural gas and oil reserves factors affecting the Companyrsquos ability to successfully identify drill for andproduce economically viable natural gas and oil reserves including among others geology lease availability title disputes weather conditions shortages delays orunavailability of equipment and services required in drilling operations insufficient gathering processing and transportation capacity the need to obtain governmentalapprovals and permits and compliance with environmental laws and regulations increasing health care costs and the resulting effect on health insurance premiums and on theobligation to provide other post-retirement benefits changes in price differentials between similar quantities of natural gas or oil sold at different geographic locations and theeffect of such changes on commodity production revenues and demand for pipeline transportation capacity to or from such locations other changes in price differentialsbetween similar quantities of natural gas or oil having different quality heating value hydrocarbon mix or delivery date the cost and effects of legal and administrative claimsagainst the Company or activist shareholder campaigns to effect changes at the Company uncertainty of oil and gas reserve estimates significant differences between theCompanyrsquos projected and actual production levels for natural gas or oil changes in demographic patterns and weather conditions changes in the availability price oraccounting treatment of derivative financial instruments changes in laws actuarial assumptions the interest rate environment and the return on plantrust assets related to theCompanyrsquos pension and other post-retirement benefits which can affect future funding obligations and costs and plan liabilities changes in economic conditions includingglobal national or regional recessions and their effect on the demand for and customersrsquo ability to pay for the Companyrsquos products and services the creditworthiness orperformance of the Companyrsquos key suppliers customers and counterparties the impact of potential information technology cybersecurity or data security breaches economicdisruptions or uninsured losses resulting from major accidents fires severe weather natural disasters terrorist activities or acts of war significant differences between theCompanyrsquos projected and actual capital expenditures and operating expenses or increasing costs of insurance changes in coverage and the ability to obtain insurance

Forward-looking statements include estimates of oil and gas quantities Proved oil and gas reserves are those quantities of oil and gas which by analysis of geoscience andengineering data can be estimated with reasonable certainty to be economically producible under existing economic conditions operating methods and governmentregulations Other estimates of oil and gas quantities including estimates of probable reserves possible reserves and resource potential are by their nature more speculativethan estimates of proved reserves Accordingly estimates other than proved reserves are subject to substantially greater risk of being actually realized Investors are urged toconsider closely the disclosure in our Form 10-K available at wwwnationalfuelgascom You can also obtain this form on the SECrsquos website at wwwsecgov

For a discussion of the risks set forth above and other factors that could cause actual results to differ materially from results referred to in the forward-looking statements seeldquoRisk Factorsrdquo in the Companyrsquos Form 10-K for the fiscal year ended September 30 2018 and the Forms 10-Q for the quarter ended March 31 2018 June 30 2018 and December31 2018 The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date thereof or to reflect the occurrence ofunanticipated events

Appendix

45

New York amp Pennsylvania Service Territories

New York

Total Customers(1) 535800ROE 87 (NY PSC Rate Case Order April 2017)Rate Mechanismso Revenue Decouplingo Weather Normalizationo Low Income Rateso Merchant Function Charge (Uncollectibles Adj)o 9010 Sharing (Large Customers)o System Modernization Tracker

Pennsylvania

Total Customers(1) 214400ROE Black Box Settlement (2007)Rate Mechanismso Low Income Rateso Merchant Function Charge

(1) As of September 30 2018

Utility

46

New York Rate Case Outcome

Rate Order Summary

Revenue Requirement $59 million

Rate Base $704 million

Allowed Return on Equity (ROE) 87

Capital Structure 429 equity

Other notable items

New rates became effective 5117

Retains rate mechanisms in place under prior order (revenue decoupling weather normalization merchant function charge 9010 large customer sharing)

No stay-out clause

System modernization tracker for Leak Prone Pipe (LPP)

Earnings sharing started 4118 (5050 sharing starts at earnings in excess of 92)

Article 78 appeal filed on 72817 with oral argument completed in January 2019

On April 20 2017 the New York Public Service Commission issued a Rate Order relating to NFG Distributionrsquos rate case (No 16-G-0257) filed in April 2016

Utility

47

Utility Continues its Significant Investments in Safety

$544$618 $636

$699

$944$980

$809$856

$90-100

$00

$250

$500

$750

$1000

$1250

2015 2016 2017 2018 2019E

Cap

ital E

xpen

ditu

res

($ m

illio

ns)

Fiscal Year

Capital Expenditures for Safety Total Capital Expenditures

Modernization Spending in NY Expected to Grow Gross Margin By $2 MM - $5 MM in FY 2019

(1)

(1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation

Utility

System modernization tracker in NY allows recovery of pipeline replacementcosts which is expected to drive modest gross margin and rate base growth

48

Accelerating Pipeline Replacement amp Modernization

Wrought Iron

Plastic

CoatedBare

120130

146 144159

2014 2015 2016 2017 2018Calendar Year

NY9726 miles

PA4830 miles

No Cast Iron Mains in Pa

Miles of Utility Main Pipeline ReplacedUtility Mains by Material(1)

Wrought Iron

Cast Iron

Plastic

Coated Bare

Utility

(1) All values are reported on a calendar year basis as of December 31 2018

49

A Proven History of Controlling Costs

$200 $189 $195

$166 $166

$31 $31

$197 $197

$0

$50

$100

$150

$200

$250

2015 2016 2017 2018 TTM 123118

Fiscal Year

OampM Expense Non-Service Pension Costs

OampM Expense ($ millions)

Utility

(1)

(1) For purposes of comparability to FY 2015 2016 and 2017 Utility Operation and Maintenance Expense for FY 2018 and the twelve months ended December 31 2018 was adjusted by approximately $314 million and $312 million respectively to include non-service pension costs which were re-classified as Other Income (Deductions) as of October 1 2018 on the Companyrsquos Income Statement See Slide 64 for non-GAAP reconciliation of Adjusted Operation and Maintenance Expense to Operation and Maintenance Expense by segment

50

Consolidated Financial OverviewUpstream I Midstream I Downstream

51

Adjusted Operating Results ($ per share)(1)

Diversified Balanced Earnings and Cash Flows

(1) A reconciliation of Adjusted Operating Results to Earnings per Share by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation(2) Consolidated Adjusted EBITDA includes Energy Marketing and Corporate amp All Other Segments A reconciliation of Adjusted EBITDA to Net Income by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in

the Business is included at the end of this presentation

Adjusted EBITDA ($ millions)(2)

$176 $179

$184 $181

$92 $97

$318 $327

$761 $775

$-

$200

$400

$600

$800

FY 2018 TTM 123118

$059 Utility

$097 Pipeline amp Storage

$057 Gathering

$125 Exploration

amp Production

$334 $345 to $365

$-

$100

$200

$300

$400

FY 2018 FY 2019 Guidance

Rate Regulated

40-45

$728

Rate Regulated

~46

52

$89 $94 $98 $81 $86 $90-$100

$140$230

$114 $95 $93 $120-$150

$138$118

$54$33 $48

$55-$65

$603$557

$99 $246$356

$460-$495

$970 $1001

$366$455

$583

$725-$810

$0

$250

$500

$750

$1000

$1250

2014 2015 2016 2017 2018 2019GuidanceFiscal Year

Exploration amp Production

Gathering

Pipeline amp Storage

Utility

Disciplined Flexible Capital Allocation

(2)

(1) Total Capital Expenditures include Energy Marketing Corporate and All Other A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation (2) FY16 FY17 and FY18 reflects the netting of $157 million $7 million and $17 million respectively of up-front proceeds received from joint development partner for working interest in joint development wells and $21M in intercompany asset transfers in FY18

Capital Expenditures by Segment ($ millions)(1)

53

Maintaining Strong Balance Sheet amp Liquidity

Total Equity49

Total Debt51

$42 Billion Total Capitalizationas of December 31 2018

218 x251 x 245 x 247 x 256 x

2015 2016 2017 2018 TTM 123118Fiscal Year End

Net Debt Adjusted EBITDA(1) Capitalization

Debt Maturity Profile ($MM) Liquidity

Committed Credit FacilitiesShort-term Debt OutstandingAvailable Short-term Credit FacilitiesCash Balance at 123118 Total Liquidity at 123118

$ 750 MM0 MM

750 MM110 MM

$ 860 MM

$500 $549 $500

$300 $300

$0

$200

$400

$600

(1) Net Debt is net of cash and temporary cash investments Reconciliations of Net Debt and Adjusted EBITDA to Net Income are included at the end of this presentation

54

Appendix

55

Safe Harbor For Forward Looking StatementsThis presentation may contain ldquoforward-looking statementsrdquo as defined by the Private Securities Litigation Reform Act of 1995 including statements regarding future prospectsplans objectives goals projections estimates of oil and gas quantities strategies future events or performance and underlying assumptions capital structure anticipatedcapital expenditures completion of construction projects projections for pension and other post-retirement benefit obligations impacts of the adoption of new accounting rulesand possible outcomes of litigation or regulatory proceedings as well as statements that are identified by the use of the words ldquoanticipatesrdquo ldquoestimatesrdquo ldquoexpectsrdquo ldquoforecastsrdquoldquointendsrdquo ldquoplansrdquo ldquopredictsrdquo ldquoprojectsrdquo ldquobelievesrdquo ldquoseeksrdquo ldquowillrdquo ldquomayrdquo and similar expressions Forward-looking statements involve risks and uncertainties which couldcause actual results or outcomes to differ materially from those expressed in the forward-looking statements The Companyrsquos expectations beliefs and projections are expressedin good faith and are believed by the Company to have a reasonable basis but there can be no assurance that managementrsquos expectations beliefs or projections will result or beachieved or accomplished

In addition to other factors the following are important factors that could cause actual results to differ materially from those discussed in the forward-looking statements delaysor changes in costs or plans with respect to Company projects or related projects of other companies including difficulties or delays in obtaining necessary governmentalapprovals permits or orders or in obtaining the cooperation of interconnecting facility operators governmentalregulatory actions initiatives and proceedings including thoseinvolving rate cases (which address among other things target rates of return rate design and retained natural gas) environmentalsafety requirements affiliate relationshipsindustry structure and franchise renewal changes in laws regulations or judicial interpretations to which the Company is subject including those involving derivatives taxessafety employment climate change other environmental matters real property and exploration and production activities such as hydraulic fracturing financial and economicconditions including the availability of credit and occurrences affecting the Companyrsquos ability to obtain financing on acceptable terms for working capital capital expendituresand other investments including any downgrades in the Companyrsquos credit ratings and changes in interest rates and other capital market conditions changes in the price ofnatural gas or oil impairments under the SECrsquos full cost ceiling test for natural gas and oil reserves factors affecting the Companyrsquos ability to successfully identify drill for andproduce economically viable natural gas and oil reserves including among others geology lease availability title disputes weather conditions shortages delays orunavailability of equipment and services required in drilling operations insufficient gathering processing and transportation capacity the need to obtain governmentalapprovals and permits and compliance with environmental laws and regulations increasing health care costs and the resulting effect on health insurance premiums and on theobligation to provide other post-retirement benefits changes in price differentials between similar quantities of natural gas or oil sold at different geographic locations and theeffect of such changes on commodity production revenues and demand for pipeline transportation capacity to or from such locations other changes in price differentialsbetween similar quantities of natural gas or oil having different quality heating value hydrocarbon mix or delivery date the cost and effects of legal and administrative claimsagainst the Company or activist shareholder campaigns to effect changes at the Company uncertainty of oil and gas reserve estimates significant differences between theCompanyrsquos projected and actual production levels for natural gas or oil changes in demographic patterns and weather conditions changes in the availability price oraccounting treatment of derivative financial instruments changes in laws actuarial assumptions the interest rate environment and the return on plantrust assets related to theCompanyrsquos pension and other post-retirement benefits which can affect future funding obligations and costs and plan liabilities changes in economic conditions includingglobal national or regional recessions and their effect on the demand for and customersrsquo ability to pay for the Companyrsquos products and services the creditworthiness orperformance of the Companyrsquos key suppliers customers and counterparties the impact of potential information technology cybersecurity or data security breaches economicdisruptions or uninsured losses resulting from major accidents fires severe weather natural disasters terrorist activities or acts of war significant differences between theCompanyrsquos projected and actual capital expenditures and operating expenses or increasing costs of insurance changes in coverage and the ability to obtain insurance

Forward-looking statements include estimates of oil and gas quantities Proved oil and gas reserves are those quantities of oil and gas which by analysis of geoscience andengineering data can be estimated with reasonable certainty to be economically producible under existing economic conditions operating methods and governmentregulations Other estimates of oil and gas quantities including estimates of probable reserves possible reserves and resource potential are by their nature more speculativethan estimates of proved reserves Accordingly estimates other than proved reserves are subject to substantially greater risk of being actually realized Investors are urged toconsider closely the disclosure in our Form 10-K available at wwwnationalfuelgascom You can also obtain this form on the SECrsquos website at wwwsecgov

For a discussion of the risks set forth above and other factors that could cause actual results to differ materially from results referred to in the forward-looking statements seeldquoRisk Factorsrdquo in the Companyrsquos Form 10-K for the fiscal year ended September 30 2018 and the Forms 10-Q for the quarter ended March 31 2018 June 30 2018 and December31 2018 The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date thereof or to reflect the occurrence ofunanticipated events

Appendix

46

New York Rate Case Outcome

Rate Order Summary

Revenue Requirement $59 million

Rate Base $704 million

Allowed Return on Equity (ROE) 87

Capital Structure 429 equity

Other notable items

New rates became effective 5117

Retains rate mechanisms in place under prior order (revenue decoupling weather normalization merchant function charge 9010 large customer sharing)

No stay-out clause

System modernization tracker for Leak Prone Pipe (LPP)

Earnings sharing started 4118 (5050 sharing starts at earnings in excess of 92)

Article 78 appeal filed on 72817 with oral argument completed in January 2019

On April 20 2017 the New York Public Service Commission issued a Rate Order relating to NFG Distributionrsquos rate case (No 16-G-0257) filed in April 2016

Utility

47

Utility Continues its Significant Investments in Safety

$544$618 $636

$699

$944$980

$809$856

$90-100

$00

$250

$500

$750

$1000

$1250

2015 2016 2017 2018 2019E

Cap

ital E

xpen

ditu

res

($ m

illio

ns)

Fiscal Year

Capital Expenditures for Safety Total Capital Expenditures

Modernization Spending in NY Expected to Grow Gross Margin By $2 MM - $5 MM in FY 2019

(1)

(1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation

Utility

System modernization tracker in NY allows recovery of pipeline replacementcosts which is expected to drive modest gross margin and rate base growth

48

Accelerating Pipeline Replacement amp Modernization

Wrought Iron

Plastic

CoatedBare

120130

146 144159

2014 2015 2016 2017 2018Calendar Year

NY9726 miles

PA4830 miles

No Cast Iron Mains in Pa

Miles of Utility Main Pipeline ReplacedUtility Mains by Material(1)

Wrought Iron

Cast Iron

Plastic

Coated Bare

Utility

(1) All values are reported on a calendar year basis as of December 31 2018

49

A Proven History of Controlling Costs

$200 $189 $195

$166 $166

$31 $31

$197 $197

$0

$50

$100

$150

$200

$250

2015 2016 2017 2018 TTM 123118

Fiscal Year

OampM Expense Non-Service Pension Costs

OampM Expense ($ millions)

Utility

(1)

(1) For purposes of comparability to FY 2015 2016 and 2017 Utility Operation and Maintenance Expense for FY 2018 and the twelve months ended December 31 2018 was adjusted by approximately $314 million and $312 million respectively to include non-service pension costs which were re-classified as Other Income (Deductions) as of October 1 2018 on the Companyrsquos Income Statement See Slide 64 for non-GAAP reconciliation of Adjusted Operation and Maintenance Expense to Operation and Maintenance Expense by segment

50

Consolidated Financial OverviewUpstream I Midstream I Downstream

51

Adjusted Operating Results ($ per share)(1)

Diversified Balanced Earnings and Cash Flows

(1) A reconciliation of Adjusted Operating Results to Earnings per Share by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation(2) Consolidated Adjusted EBITDA includes Energy Marketing and Corporate amp All Other Segments A reconciliation of Adjusted EBITDA to Net Income by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in

the Business is included at the end of this presentation

Adjusted EBITDA ($ millions)(2)

$176 $179

$184 $181

$92 $97

$318 $327

$761 $775

$-

$200

$400

$600

$800

FY 2018 TTM 123118

$059 Utility

$097 Pipeline amp Storage

$057 Gathering

$125 Exploration

amp Production

$334 $345 to $365

$-

$100

$200

$300

$400

FY 2018 FY 2019 Guidance

Rate Regulated

40-45

$728

Rate Regulated

~46

52

$89 $94 $98 $81 $86 $90-$100

$140$230

$114 $95 $93 $120-$150

$138$118

$54$33 $48

$55-$65

$603$557

$99 $246$356

$460-$495

$970 $1001

$366$455

$583

$725-$810

$0

$250

$500

$750

$1000

$1250

2014 2015 2016 2017 2018 2019GuidanceFiscal Year

Exploration amp Production

Gathering

Pipeline amp Storage

Utility

Disciplined Flexible Capital Allocation

(2)

(1) Total Capital Expenditures include Energy Marketing Corporate and All Other A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation (2) FY16 FY17 and FY18 reflects the netting of $157 million $7 million and $17 million respectively of up-front proceeds received from joint development partner for working interest in joint development wells and $21M in intercompany asset transfers in FY18

Capital Expenditures by Segment ($ millions)(1)

53

Maintaining Strong Balance Sheet amp Liquidity

Total Equity49

Total Debt51

$42 Billion Total Capitalizationas of December 31 2018

218 x251 x 245 x 247 x 256 x

2015 2016 2017 2018 TTM 123118Fiscal Year End

Net Debt Adjusted EBITDA(1) Capitalization

Debt Maturity Profile ($MM) Liquidity

Committed Credit FacilitiesShort-term Debt OutstandingAvailable Short-term Credit FacilitiesCash Balance at 123118 Total Liquidity at 123118

$ 750 MM0 MM

750 MM110 MM

$ 860 MM

$500 $549 $500

$300 $300

$0

$200

$400

$600

(1) Net Debt is net of cash and temporary cash investments Reconciliations of Net Debt and Adjusted EBITDA to Net Income are included at the end of this presentation

54

Appendix

55

Safe Harbor For Forward Looking StatementsThis presentation may contain ldquoforward-looking statementsrdquo as defined by the Private Securities Litigation Reform Act of 1995 including statements regarding future prospectsplans objectives goals projections estimates of oil and gas quantities strategies future events or performance and underlying assumptions capital structure anticipatedcapital expenditures completion of construction projects projections for pension and other post-retirement benefit obligations impacts of the adoption of new accounting rulesand possible outcomes of litigation or regulatory proceedings as well as statements that are identified by the use of the words ldquoanticipatesrdquo ldquoestimatesrdquo ldquoexpectsrdquo ldquoforecastsrdquoldquointendsrdquo ldquoplansrdquo ldquopredictsrdquo ldquoprojectsrdquo ldquobelievesrdquo ldquoseeksrdquo ldquowillrdquo ldquomayrdquo and similar expressions Forward-looking statements involve risks and uncertainties which couldcause actual results or outcomes to differ materially from those expressed in the forward-looking statements The Companyrsquos expectations beliefs and projections are expressedin good faith and are believed by the Company to have a reasonable basis but there can be no assurance that managementrsquos expectations beliefs or projections will result or beachieved or accomplished

In addition to other factors the following are important factors that could cause actual results to differ materially from those discussed in the forward-looking statements delaysor changes in costs or plans with respect to Company projects or related projects of other companies including difficulties or delays in obtaining necessary governmentalapprovals permits or orders or in obtaining the cooperation of interconnecting facility operators governmentalregulatory actions initiatives and proceedings including thoseinvolving rate cases (which address among other things target rates of return rate design and retained natural gas) environmentalsafety requirements affiliate relationshipsindustry structure and franchise renewal changes in laws regulations or judicial interpretations to which the Company is subject including those involving derivatives taxessafety employment climate change other environmental matters real property and exploration and production activities such as hydraulic fracturing financial and economicconditions including the availability of credit and occurrences affecting the Companyrsquos ability to obtain financing on acceptable terms for working capital capital expendituresand other investments including any downgrades in the Companyrsquos credit ratings and changes in interest rates and other capital market conditions changes in the price ofnatural gas or oil impairments under the SECrsquos full cost ceiling test for natural gas and oil reserves factors affecting the Companyrsquos ability to successfully identify drill for andproduce economically viable natural gas and oil reserves including among others geology lease availability title disputes weather conditions shortages delays orunavailability of equipment and services required in drilling operations insufficient gathering processing and transportation capacity the need to obtain governmentalapprovals and permits and compliance with environmental laws and regulations increasing health care costs and the resulting effect on health insurance premiums and on theobligation to provide other post-retirement benefits changes in price differentials between similar quantities of natural gas or oil sold at different geographic locations and theeffect of such changes on commodity production revenues and demand for pipeline transportation capacity to or from such locations other changes in price differentialsbetween similar quantities of natural gas or oil having different quality heating value hydrocarbon mix or delivery date the cost and effects of legal and administrative claimsagainst the Company or activist shareholder campaigns to effect changes at the Company uncertainty of oil and gas reserve estimates significant differences between theCompanyrsquos projected and actual production levels for natural gas or oil changes in demographic patterns and weather conditions changes in the availability price oraccounting treatment of derivative financial instruments changes in laws actuarial assumptions the interest rate environment and the return on plantrust assets related to theCompanyrsquos pension and other post-retirement benefits which can affect future funding obligations and costs and plan liabilities changes in economic conditions includingglobal national or regional recessions and their effect on the demand for and customersrsquo ability to pay for the Companyrsquos products and services the creditworthiness orperformance of the Companyrsquos key suppliers customers and counterparties the impact of potential information technology cybersecurity or data security breaches economicdisruptions or uninsured losses resulting from major accidents fires severe weather natural disasters terrorist activities or acts of war significant differences between theCompanyrsquos projected and actual capital expenditures and operating expenses or increasing costs of insurance changes in coverage and the ability to obtain insurance

Forward-looking statements include estimates of oil and gas quantities Proved oil and gas reserves are those quantities of oil and gas which by analysis of geoscience andengineering data can be estimated with reasonable certainty to be economically producible under existing economic conditions operating methods and governmentregulations Other estimates of oil and gas quantities including estimates of probable reserves possible reserves and resource potential are by their nature more speculativethan estimates of proved reserves Accordingly estimates other than proved reserves are subject to substantially greater risk of being actually realized Investors are urged toconsider closely the disclosure in our Form 10-K available at wwwnationalfuelgascom You can also obtain this form on the SECrsquos website at wwwsecgov

For a discussion of the risks set forth above and other factors that could cause actual results to differ materially from results referred to in the forward-looking statements seeldquoRisk Factorsrdquo in the Companyrsquos Form 10-K for the fiscal year ended September 30 2018 and the Forms 10-Q for the quarter ended March 31 2018 June 30 2018 and December31 2018 The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date thereof or to reflect the occurrence ofunanticipated events

Appendix

47

Utility Continues its Significant Investments in Safety

$544$618 $636

$699

$944$980

$809$856

$90-100

$00

$250

$500

$750

$1000

$1250

2015 2016 2017 2018 2019E

Cap

ital E

xpen

ditu

res

($ m

illio

ns)

Fiscal Year

Capital Expenditures for Safety Total Capital Expenditures

Modernization Spending in NY Expected to Grow Gross Margin By $2 MM - $5 MM in FY 2019

(1)

(1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation

Utility

System modernization tracker in NY allows recovery of pipeline replacementcosts which is expected to drive modest gross margin and rate base growth

48

Accelerating Pipeline Replacement amp Modernization

Wrought Iron

Plastic

CoatedBare

120130

146 144159

2014 2015 2016 2017 2018Calendar Year

NY9726 miles

PA4830 miles

No Cast Iron Mains in Pa

Miles of Utility Main Pipeline ReplacedUtility Mains by Material(1)

Wrought Iron

Cast Iron

Plastic

Coated Bare

Utility

(1) All values are reported on a calendar year basis as of December 31 2018

49

A Proven History of Controlling Costs

$200 $189 $195

$166 $166

$31 $31

$197 $197

$0

$50

$100

$150

$200

$250

2015 2016 2017 2018 TTM 123118

Fiscal Year

OampM Expense Non-Service Pension Costs

OampM Expense ($ millions)

Utility

(1)

(1) For purposes of comparability to FY 2015 2016 and 2017 Utility Operation and Maintenance Expense for FY 2018 and the twelve months ended December 31 2018 was adjusted by approximately $314 million and $312 million respectively to include non-service pension costs which were re-classified as Other Income (Deductions) as of October 1 2018 on the Companyrsquos Income Statement See Slide 64 for non-GAAP reconciliation of Adjusted Operation and Maintenance Expense to Operation and Maintenance Expense by segment

50

Consolidated Financial OverviewUpstream I Midstream I Downstream

51

Adjusted Operating Results ($ per share)(1)

Diversified Balanced Earnings and Cash Flows

(1) A reconciliation of Adjusted Operating Results to Earnings per Share by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation(2) Consolidated Adjusted EBITDA includes Energy Marketing and Corporate amp All Other Segments A reconciliation of Adjusted EBITDA to Net Income by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in

the Business is included at the end of this presentation

Adjusted EBITDA ($ millions)(2)

$176 $179

$184 $181

$92 $97

$318 $327

$761 $775

$-

$200

$400

$600

$800

FY 2018 TTM 123118

$059 Utility

$097 Pipeline amp Storage

$057 Gathering

$125 Exploration

amp Production

$334 $345 to $365

$-

$100

$200

$300

$400

FY 2018 FY 2019 Guidance

Rate Regulated

40-45

$728

Rate Regulated

~46

52

$89 $94 $98 $81 $86 $90-$100

$140$230

$114 $95 $93 $120-$150

$138$118

$54$33 $48

$55-$65

$603$557

$99 $246$356

$460-$495

$970 $1001

$366$455

$583

$725-$810

$0

$250

$500

$750

$1000

$1250

2014 2015 2016 2017 2018 2019GuidanceFiscal Year

Exploration amp Production

Gathering

Pipeline amp Storage

Utility

Disciplined Flexible Capital Allocation

(2)

(1) Total Capital Expenditures include Energy Marketing Corporate and All Other A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation (2) FY16 FY17 and FY18 reflects the netting of $157 million $7 million and $17 million respectively of up-front proceeds received from joint development partner for working interest in joint development wells and $21M in intercompany asset transfers in FY18

Capital Expenditures by Segment ($ millions)(1)

53

Maintaining Strong Balance Sheet amp Liquidity

Total Equity49

Total Debt51

$42 Billion Total Capitalizationas of December 31 2018

218 x251 x 245 x 247 x 256 x

2015 2016 2017 2018 TTM 123118Fiscal Year End

Net Debt Adjusted EBITDA(1) Capitalization

Debt Maturity Profile ($MM) Liquidity

Committed Credit FacilitiesShort-term Debt OutstandingAvailable Short-term Credit FacilitiesCash Balance at 123118 Total Liquidity at 123118

$ 750 MM0 MM

750 MM110 MM

$ 860 MM

$500 $549 $500

$300 $300

$0

$200

$400

$600

(1) Net Debt is net of cash and temporary cash investments Reconciliations of Net Debt and Adjusted EBITDA to Net Income are included at the end of this presentation

54

Appendix

55

Safe Harbor For Forward Looking StatementsThis presentation may contain ldquoforward-looking statementsrdquo as defined by the Private Securities Litigation Reform Act of 1995 including statements regarding future prospectsplans objectives goals projections estimates of oil and gas quantities strategies future events or performance and underlying assumptions capital structure anticipatedcapital expenditures completion of construction projects projections for pension and other post-retirement benefit obligations impacts of the adoption of new accounting rulesand possible outcomes of litigation or regulatory proceedings as well as statements that are identified by the use of the words ldquoanticipatesrdquo ldquoestimatesrdquo ldquoexpectsrdquo ldquoforecastsrdquoldquointendsrdquo ldquoplansrdquo ldquopredictsrdquo ldquoprojectsrdquo ldquobelievesrdquo ldquoseeksrdquo ldquowillrdquo ldquomayrdquo and similar expressions Forward-looking statements involve risks and uncertainties which couldcause actual results or outcomes to differ materially from those expressed in the forward-looking statements The Companyrsquos expectations beliefs and projections are expressedin good faith and are believed by the Company to have a reasonable basis but there can be no assurance that managementrsquos expectations beliefs or projections will result or beachieved or accomplished

In addition to other factors the following are important factors that could cause actual results to differ materially from those discussed in the forward-looking statements delaysor changes in costs or plans with respect to Company projects or related projects of other companies including difficulties or delays in obtaining necessary governmentalapprovals permits or orders or in obtaining the cooperation of interconnecting facility operators governmentalregulatory actions initiatives and proceedings including thoseinvolving rate cases (which address among other things target rates of return rate design and retained natural gas) environmentalsafety requirements affiliate relationshipsindustry structure and franchise renewal changes in laws regulations or judicial interpretations to which the Company is subject including those involving derivatives taxessafety employment climate change other environmental matters real property and exploration and production activities such as hydraulic fracturing financial and economicconditions including the availability of credit and occurrences affecting the Companyrsquos ability to obtain financing on acceptable terms for working capital capital expendituresand other investments including any downgrades in the Companyrsquos credit ratings and changes in interest rates and other capital market conditions changes in the price ofnatural gas or oil impairments under the SECrsquos full cost ceiling test for natural gas and oil reserves factors affecting the Companyrsquos ability to successfully identify drill for andproduce economically viable natural gas and oil reserves including among others geology lease availability title disputes weather conditions shortages delays orunavailability of equipment and services required in drilling operations insufficient gathering processing and transportation capacity the need to obtain governmentalapprovals and permits and compliance with environmental laws and regulations increasing health care costs and the resulting effect on health insurance premiums and on theobligation to provide other post-retirement benefits changes in price differentials between similar quantities of natural gas or oil sold at different geographic locations and theeffect of such changes on commodity production revenues and demand for pipeline transportation capacity to or from such locations other changes in price differentialsbetween similar quantities of natural gas or oil having different quality heating value hydrocarbon mix or delivery date the cost and effects of legal and administrative claimsagainst the Company or activist shareholder campaigns to effect changes at the Company uncertainty of oil and gas reserve estimates significant differences between theCompanyrsquos projected and actual production levels for natural gas or oil changes in demographic patterns and weather conditions changes in the availability price oraccounting treatment of derivative financial instruments changes in laws actuarial assumptions the interest rate environment and the return on plantrust assets related to theCompanyrsquos pension and other post-retirement benefits which can affect future funding obligations and costs and plan liabilities changes in economic conditions includingglobal national or regional recessions and their effect on the demand for and customersrsquo ability to pay for the Companyrsquos products and services the creditworthiness orperformance of the Companyrsquos key suppliers customers and counterparties the impact of potential information technology cybersecurity or data security breaches economicdisruptions or uninsured losses resulting from major accidents fires severe weather natural disasters terrorist activities or acts of war significant differences between theCompanyrsquos projected and actual capital expenditures and operating expenses or increasing costs of insurance changes in coverage and the ability to obtain insurance

Forward-looking statements include estimates of oil and gas quantities Proved oil and gas reserves are those quantities of oil and gas which by analysis of geoscience andengineering data can be estimated with reasonable certainty to be economically producible under existing economic conditions operating methods and governmentregulations Other estimates of oil and gas quantities including estimates of probable reserves possible reserves and resource potential are by their nature more speculativethan estimates of proved reserves Accordingly estimates other than proved reserves are subject to substantially greater risk of being actually realized Investors are urged toconsider closely the disclosure in our Form 10-K available at wwwnationalfuelgascom You can also obtain this form on the SECrsquos website at wwwsecgov

For a discussion of the risks set forth above and other factors that could cause actual results to differ materially from results referred to in the forward-looking statements seeldquoRisk Factorsrdquo in the Companyrsquos Form 10-K for the fiscal year ended September 30 2018 and the Forms 10-Q for the quarter ended March 31 2018 June 30 2018 and December31 2018 The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date thereof or to reflect the occurrence ofunanticipated events

Appendix

48

Accelerating Pipeline Replacement amp Modernization

Wrought Iron

Plastic

CoatedBare

120130

146 144159

2014 2015 2016 2017 2018Calendar Year

NY9726 miles

PA4830 miles

No Cast Iron Mains in Pa

Miles of Utility Main Pipeline ReplacedUtility Mains by Material(1)

Wrought Iron

Cast Iron

Plastic

Coated Bare

Utility

(1) All values are reported on a calendar year basis as of December 31 2018

49

A Proven History of Controlling Costs

$200 $189 $195

$166 $166

$31 $31

$197 $197

$0

$50

$100

$150

$200

$250

2015 2016 2017 2018 TTM 123118

Fiscal Year

OampM Expense Non-Service Pension Costs

OampM Expense ($ millions)

Utility

(1)

(1) For purposes of comparability to FY 2015 2016 and 2017 Utility Operation and Maintenance Expense for FY 2018 and the twelve months ended December 31 2018 was adjusted by approximately $314 million and $312 million respectively to include non-service pension costs which were re-classified as Other Income (Deductions) as of October 1 2018 on the Companyrsquos Income Statement See Slide 64 for non-GAAP reconciliation of Adjusted Operation and Maintenance Expense to Operation and Maintenance Expense by segment

50

Consolidated Financial OverviewUpstream I Midstream I Downstream

51

Adjusted Operating Results ($ per share)(1)

Diversified Balanced Earnings and Cash Flows

(1) A reconciliation of Adjusted Operating Results to Earnings per Share by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation(2) Consolidated Adjusted EBITDA includes Energy Marketing and Corporate amp All Other Segments A reconciliation of Adjusted EBITDA to Net Income by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in

the Business is included at the end of this presentation

Adjusted EBITDA ($ millions)(2)

$176 $179

$184 $181

$92 $97

$318 $327

$761 $775

$-

$200

$400

$600

$800

FY 2018 TTM 123118

$059 Utility

$097 Pipeline amp Storage

$057 Gathering

$125 Exploration

amp Production

$334 $345 to $365

$-

$100

$200

$300

$400

FY 2018 FY 2019 Guidance

Rate Regulated

40-45

$728

Rate Regulated

~46

52

$89 $94 $98 $81 $86 $90-$100

$140$230

$114 $95 $93 $120-$150

$138$118

$54$33 $48

$55-$65

$603$557

$99 $246$356

$460-$495

$970 $1001

$366$455

$583

$725-$810

$0

$250

$500

$750

$1000

$1250

2014 2015 2016 2017 2018 2019GuidanceFiscal Year

Exploration amp Production

Gathering

Pipeline amp Storage

Utility

Disciplined Flexible Capital Allocation

(2)

(1) Total Capital Expenditures include Energy Marketing Corporate and All Other A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation (2) FY16 FY17 and FY18 reflects the netting of $157 million $7 million and $17 million respectively of up-front proceeds received from joint development partner for working interest in joint development wells and $21M in intercompany asset transfers in FY18

Capital Expenditures by Segment ($ millions)(1)

53

Maintaining Strong Balance Sheet amp Liquidity

Total Equity49

Total Debt51

$42 Billion Total Capitalizationas of December 31 2018

218 x251 x 245 x 247 x 256 x

2015 2016 2017 2018 TTM 123118Fiscal Year End

Net Debt Adjusted EBITDA(1) Capitalization

Debt Maturity Profile ($MM) Liquidity

Committed Credit FacilitiesShort-term Debt OutstandingAvailable Short-term Credit FacilitiesCash Balance at 123118 Total Liquidity at 123118

$ 750 MM0 MM

750 MM110 MM

$ 860 MM

$500 $549 $500

$300 $300

$0

$200

$400

$600

(1) Net Debt is net of cash and temporary cash investments Reconciliations of Net Debt and Adjusted EBITDA to Net Income are included at the end of this presentation

54

Appendix

55

Safe Harbor For Forward Looking StatementsThis presentation may contain ldquoforward-looking statementsrdquo as defined by the Private Securities Litigation Reform Act of 1995 including statements regarding future prospectsplans objectives goals projections estimates of oil and gas quantities strategies future events or performance and underlying assumptions capital structure anticipatedcapital expenditures completion of construction projects projections for pension and other post-retirement benefit obligations impacts of the adoption of new accounting rulesand possible outcomes of litigation or regulatory proceedings as well as statements that are identified by the use of the words ldquoanticipatesrdquo ldquoestimatesrdquo ldquoexpectsrdquo ldquoforecastsrdquoldquointendsrdquo ldquoplansrdquo ldquopredictsrdquo ldquoprojectsrdquo ldquobelievesrdquo ldquoseeksrdquo ldquowillrdquo ldquomayrdquo and similar expressions Forward-looking statements involve risks and uncertainties which couldcause actual results or outcomes to differ materially from those expressed in the forward-looking statements The Companyrsquos expectations beliefs and projections are expressedin good faith and are believed by the Company to have a reasonable basis but there can be no assurance that managementrsquos expectations beliefs or projections will result or beachieved or accomplished

In addition to other factors the following are important factors that could cause actual results to differ materially from those discussed in the forward-looking statements delaysor changes in costs or plans with respect to Company projects or related projects of other companies including difficulties or delays in obtaining necessary governmentalapprovals permits or orders or in obtaining the cooperation of interconnecting facility operators governmentalregulatory actions initiatives and proceedings including thoseinvolving rate cases (which address among other things target rates of return rate design and retained natural gas) environmentalsafety requirements affiliate relationshipsindustry structure and franchise renewal changes in laws regulations or judicial interpretations to which the Company is subject including those involving derivatives taxessafety employment climate change other environmental matters real property and exploration and production activities such as hydraulic fracturing financial and economicconditions including the availability of credit and occurrences affecting the Companyrsquos ability to obtain financing on acceptable terms for working capital capital expendituresand other investments including any downgrades in the Companyrsquos credit ratings and changes in interest rates and other capital market conditions changes in the price ofnatural gas or oil impairments under the SECrsquos full cost ceiling test for natural gas and oil reserves factors affecting the Companyrsquos ability to successfully identify drill for andproduce economically viable natural gas and oil reserves including among others geology lease availability title disputes weather conditions shortages delays orunavailability of equipment and services required in drilling operations insufficient gathering processing and transportation capacity the need to obtain governmentalapprovals and permits and compliance with environmental laws and regulations increasing health care costs and the resulting effect on health insurance premiums and on theobligation to provide other post-retirement benefits changes in price differentials between similar quantities of natural gas or oil sold at different geographic locations and theeffect of such changes on commodity production revenues and demand for pipeline transportation capacity to or from such locations other changes in price differentialsbetween similar quantities of natural gas or oil having different quality heating value hydrocarbon mix or delivery date the cost and effects of legal and administrative claimsagainst the Company or activist shareholder campaigns to effect changes at the Company uncertainty of oil and gas reserve estimates significant differences between theCompanyrsquos projected and actual production levels for natural gas or oil changes in demographic patterns and weather conditions changes in the availability price oraccounting treatment of derivative financial instruments changes in laws actuarial assumptions the interest rate environment and the return on plantrust assets related to theCompanyrsquos pension and other post-retirement benefits which can affect future funding obligations and costs and plan liabilities changes in economic conditions includingglobal national or regional recessions and their effect on the demand for and customersrsquo ability to pay for the Companyrsquos products and services the creditworthiness orperformance of the Companyrsquos key suppliers customers and counterparties the impact of potential information technology cybersecurity or data security breaches economicdisruptions or uninsured losses resulting from major accidents fires severe weather natural disasters terrorist activities or acts of war significant differences between theCompanyrsquos projected and actual capital expenditures and operating expenses or increasing costs of insurance changes in coverage and the ability to obtain insurance

Forward-looking statements include estimates of oil and gas quantities Proved oil and gas reserves are those quantities of oil and gas which by analysis of geoscience andengineering data can be estimated with reasonable certainty to be economically producible under existing economic conditions operating methods and governmentregulations Other estimates of oil and gas quantities including estimates of probable reserves possible reserves and resource potential are by their nature more speculativethan estimates of proved reserves Accordingly estimates other than proved reserves are subject to substantially greater risk of being actually realized Investors are urged toconsider closely the disclosure in our Form 10-K available at wwwnationalfuelgascom You can also obtain this form on the SECrsquos website at wwwsecgov

For a discussion of the risks set forth above and other factors that could cause actual results to differ materially from results referred to in the forward-looking statements seeldquoRisk Factorsrdquo in the Companyrsquos Form 10-K for the fiscal year ended September 30 2018 and the Forms 10-Q for the quarter ended March 31 2018 June 30 2018 and December31 2018 The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date thereof or to reflect the occurrence ofunanticipated events

Appendix

49

A Proven History of Controlling Costs

$200 $189 $195

$166 $166

$31 $31

$197 $197

$0

$50

$100

$150

$200

$250

2015 2016 2017 2018 TTM 123118

Fiscal Year

OampM Expense Non-Service Pension Costs

OampM Expense ($ millions)

Utility

(1)

(1) For purposes of comparability to FY 2015 2016 and 2017 Utility Operation and Maintenance Expense for FY 2018 and the twelve months ended December 31 2018 was adjusted by approximately $314 million and $312 million respectively to include non-service pension costs which were re-classified as Other Income (Deductions) as of October 1 2018 on the Companyrsquos Income Statement See Slide 64 for non-GAAP reconciliation of Adjusted Operation and Maintenance Expense to Operation and Maintenance Expense by segment

50

Consolidated Financial OverviewUpstream I Midstream I Downstream

51

Adjusted Operating Results ($ per share)(1)

Diversified Balanced Earnings and Cash Flows

(1) A reconciliation of Adjusted Operating Results to Earnings per Share by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation(2) Consolidated Adjusted EBITDA includes Energy Marketing and Corporate amp All Other Segments A reconciliation of Adjusted EBITDA to Net Income by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in

the Business is included at the end of this presentation

Adjusted EBITDA ($ millions)(2)

$176 $179

$184 $181

$92 $97

$318 $327

$761 $775

$-

$200

$400

$600

$800

FY 2018 TTM 123118

$059 Utility

$097 Pipeline amp Storage

$057 Gathering

$125 Exploration

amp Production

$334 $345 to $365

$-

$100

$200

$300

$400

FY 2018 FY 2019 Guidance

Rate Regulated

40-45

$728

Rate Regulated

~46

52

$89 $94 $98 $81 $86 $90-$100

$140$230

$114 $95 $93 $120-$150

$138$118

$54$33 $48

$55-$65

$603$557

$99 $246$356

$460-$495

$970 $1001

$366$455

$583

$725-$810

$0

$250

$500

$750

$1000

$1250

2014 2015 2016 2017 2018 2019GuidanceFiscal Year

Exploration amp Production

Gathering

Pipeline amp Storage

Utility

Disciplined Flexible Capital Allocation

(2)

(1) Total Capital Expenditures include Energy Marketing Corporate and All Other A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation (2) FY16 FY17 and FY18 reflects the netting of $157 million $7 million and $17 million respectively of up-front proceeds received from joint development partner for working interest in joint development wells and $21M in intercompany asset transfers in FY18

Capital Expenditures by Segment ($ millions)(1)

53

Maintaining Strong Balance Sheet amp Liquidity

Total Equity49

Total Debt51

$42 Billion Total Capitalizationas of December 31 2018

218 x251 x 245 x 247 x 256 x

2015 2016 2017 2018 TTM 123118Fiscal Year End

Net Debt Adjusted EBITDA(1) Capitalization

Debt Maturity Profile ($MM) Liquidity

Committed Credit FacilitiesShort-term Debt OutstandingAvailable Short-term Credit FacilitiesCash Balance at 123118 Total Liquidity at 123118

$ 750 MM0 MM

750 MM110 MM

$ 860 MM

$500 $549 $500

$300 $300

$0

$200

$400

$600

(1) Net Debt is net of cash and temporary cash investments Reconciliations of Net Debt and Adjusted EBITDA to Net Income are included at the end of this presentation

54

Appendix

55

Safe Harbor For Forward Looking StatementsThis presentation may contain ldquoforward-looking statementsrdquo as defined by the Private Securities Litigation Reform Act of 1995 including statements regarding future prospectsplans objectives goals projections estimates of oil and gas quantities strategies future events or performance and underlying assumptions capital structure anticipatedcapital expenditures completion of construction projects projections for pension and other post-retirement benefit obligations impacts of the adoption of new accounting rulesand possible outcomes of litigation or regulatory proceedings as well as statements that are identified by the use of the words ldquoanticipatesrdquo ldquoestimatesrdquo ldquoexpectsrdquo ldquoforecastsrdquoldquointendsrdquo ldquoplansrdquo ldquopredictsrdquo ldquoprojectsrdquo ldquobelievesrdquo ldquoseeksrdquo ldquowillrdquo ldquomayrdquo and similar expressions Forward-looking statements involve risks and uncertainties which couldcause actual results or outcomes to differ materially from those expressed in the forward-looking statements The Companyrsquos expectations beliefs and projections are expressedin good faith and are believed by the Company to have a reasonable basis but there can be no assurance that managementrsquos expectations beliefs or projections will result or beachieved or accomplished

In addition to other factors the following are important factors that could cause actual results to differ materially from those discussed in the forward-looking statements delaysor changes in costs or plans with respect to Company projects or related projects of other companies including difficulties or delays in obtaining necessary governmentalapprovals permits or orders or in obtaining the cooperation of interconnecting facility operators governmentalregulatory actions initiatives and proceedings including thoseinvolving rate cases (which address among other things target rates of return rate design and retained natural gas) environmentalsafety requirements affiliate relationshipsindustry structure and franchise renewal changes in laws regulations or judicial interpretations to which the Company is subject including those involving derivatives taxessafety employment climate change other environmental matters real property and exploration and production activities such as hydraulic fracturing financial and economicconditions including the availability of credit and occurrences affecting the Companyrsquos ability to obtain financing on acceptable terms for working capital capital expendituresand other investments including any downgrades in the Companyrsquos credit ratings and changes in interest rates and other capital market conditions changes in the price ofnatural gas or oil impairments under the SECrsquos full cost ceiling test for natural gas and oil reserves factors affecting the Companyrsquos ability to successfully identify drill for andproduce economically viable natural gas and oil reserves including among others geology lease availability title disputes weather conditions shortages delays orunavailability of equipment and services required in drilling operations insufficient gathering processing and transportation capacity the need to obtain governmentalapprovals and permits and compliance with environmental laws and regulations increasing health care costs and the resulting effect on health insurance premiums and on theobligation to provide other post-retirement benefits changes in price differentials between similar quantities of natural gas or oil sold at different geographic locations and theeffect of such changes on commodity production revenues and demand for pipeline transportation capacity to or from such locations other changes in price differentialsbetween similar quantities of natural gas or oil having different quality heating value hydrocarbon mix or delivery date the cost and effects of legal and administrative claimsagainst the Company or activist shareholder campaigns to effect changes at the Company uncertainty of oil and gas reserve estimates significant differences between theCompanyrsquos projected and actual production levels for natural gas or oil changes in demographic patterns and weather conditions changes in the availability price oraccounting treatment of derivative financial instruments changes in laws actuarial assumptions the interest rate environment and the return on plantrust assets related to theCompanyrsquos pension and other post-retirement benefits which can affect future funding obligations and costs and plan liabilities changes in economic conditions includingglobal national or regional recessions and their effect on the demand for and customersrsquo ability to pay for the Companyrsquos products and services the creditworthiness orperformance of the Companyrsquos key suppliers customers and counterparties the impact of potential information technology cybersecurity or data security breaches economicdisruptions or uninsured losses resulting from major accidents fires severe weather natural disasters terrorist activities or acts of war significant differences between theCompanyrsquos projected and actual capital expenditures and operating expenses or increasing costs of insurance changes in coverage and the ability to obtain insurance

Forward-looking statements include estimates of oil and gas quantities Proved oil and gas reserves are those quantities of oil and gas which by analysis of geoscience andengineering data can be estimated with reasonable certainty to be economically producible under existing economic conditions operating methods and governmentregulations Other estimates of oil and gas quantities including estimates of probable reserves possible reserves and resource potential are by their nature more speculativethan estimates of proved reserves Accordingly estimates other than proved reserves are subject to substantially greater risk of being actually realized Investors are urged toconsider closely the disclosure in our Form 10-K available at wwwnationalfuelgascom You can also obtain this form on the SECrsquos website at wwwsecgov

For a discussion of the risks set forth above and other factors that could cause actual results to differ materially from results referred to in the forward-looking statements seeldquoRisk Factorsrdquo in the Companyrsquos Form 10-K for the fiscal year ended September 30 2018 and the Forms 10-Q for the quarter ended March 31 2018 June 30 2018 and December31 2018 The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date thereof or to reflect the occurrence ofunanticipated events

Appendix

50

Consolidated Financial OverviewUpstream I Midstream I Downstream

51

Adjusted Operating Results ($ per share)(1)

Diversified Balanced Earnings and Cash Flows

(1) A reconciliation of Adjusted Operating Results to Earnings per Share by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation(2) Consolidated Adjusted EBITDA includes Energy Marketing and Corporate amp All Other Segments A reconciliation of Adjusted EBITDA to Net Income by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in

the Business is included at the end of this presentation

Adjusted EBITDA ($ millions)(2)

$176 $179

$184 $181

$92 $97

$318 $327

$761 $775

$-

$200

$400

$600

$800

FY 2018 TTM 123118

$059 Utility

$097 Pipeline amp Storage

$057 Gathering

$125 Exploration

amp Production

$334 $345 to $365

$-

$100

$200

$300

$400

FY 2018 FY 2019 Guidance

Rate Regulated

40-45

$728

Rate Regulated

~46

52

$89 $94 $98 $81 $86 $90-$100

$140$230

$114 $95 $93 $120-$150

$138$118

$54$33 $48

$55-$65

$603$557

$99 $246$356

$460-$495

$970 $1001

$366$455

$583

$725-$810

$0

$250

$500

$750

$1000

$1250

2014 2015 2016 2017 2018 2019GuidanceFiscal Year

Exploration amp Production

Gathering

Pipeline amp Storage

Utility

Disciplined Flexible Capital Allocation

(2)

(1) Total Capital Expenditures include Energy Marketing Corporate and All Other A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation (2) FY16 FY17 and FY18 reflects the netting of $157 million $7 million and $17 million respectively of up-front proceeds received from joint development partner for working interest in joint development wells and $21M in intercompany asset transfers in FY18

Capital Expenditures by Segment ($ millions)(1)

53

Maintaining Strong Balance Sheet amp Liquidity

Total Equity49

Total Debt51

$42 Billion Total Capitalizationas of December 31 2018

218 x251 x 245 x 247 x 256 x

2015 2016 2017 2018 TTM 123118Fiscal Year End

Net Debt Adjusted EBITDA(1) Capitalization

Debt Maturity Profile ($MM) Liquidity

Committed Credit FacilitiesShort-term Debt OutstandingAvailable Short-term Credit FacilitiesCash Balance at 123118 Total Liquidity at 123118

$ 750 MM0 MM

750 MM110 MM

$ 860 MM

$500 $549 $500

$300 $300

$0

$200

$400

$600

(1) Net Debt is net of cash and temporary cash investments Reconciliations of Net Debt and Adjusted EBITDA to Net Income are included at the end of this presentation

54

Appendix

55

Safe Harbor For Forward Looking StatementsThis presentation may contain ldquoforward-looking statementsrdquo as defined by the Private Securities Litigation Reform Act of 1995 including statements regarding future prospectsplans objectives goals projections estimates of oil and gas quantities strategies future events or performance and underlying assumptions capital structure anticipatedcapital expenditures completion of construction projects projections for pension and other post-retirement benefit obligations impacts of the adoption of new accounting rulesand possible outcomes of litigation or regulatory proceedings as well as statements that are identified by the use of the words ldquoanticipatesrdquo ldquoestimatesrdquo ldquoexpectsrdquo ldquoforecastsrdquoldquointendsrdquo ldquoplansrdquo ldquopredictsrdquo ldquoprojectsrdquo ldquobelievesrdquo ldquoseeksrdquo ldquowillrdquo ldquomayrdquo and similar expressions Forward-looking statements involve risks and uncertainties which couldcause actual results or outcomes to differ materially from those expressed in the forward-looking statements The Companyrsquos expectations beliefs and projections are expressedin good faith and are believed by the Company to have a reasonable basis but there can be no assurance that managementrsquos expectations beliefs or projections will result or beachieved or accomplished

In addition to other factors the following are important factors that could cause actual results to differ materially from those discussed in the forward-looking statements delaysor changes in costs or plans with respect to Company projects or related projects of other companies including difficulties or delays in obtaining necessary governmentalapprovals permits or orders or in obtaining the cooperation of interconnecting facility operators governmentalregulatory actions initiatives and proceedings including thoseinvolving rate cases (which address among other things target rates of return rate design and retained natural gas) environmentalsafety requirements affiliate relationshipsindustry structure and franchise renewal changes in laws regulations or judicial interpretations to which the Company is subject including those involving derivatives taxessafety employment climate change other environmental matters real property and exploration and production activities such as hydraulic fracturing financial and economicconditions including the availability of credit and occurrences affecting the Companyrsquos ability to obtain financing on acceptable terms for working capital capital expendituresand other investments including any downgrades in the Companyrsquos credit ratings and changes in interest rates and other capital market conditions changes in the price ofnatural gas or oil impairments under the SECrsquos full cost ceiling test for natural gas and oil reserves factors affecting the Companyrsquos ability to successfully identify drill for andproduce economically viable natural gas and oil reserves including among others geology lease availability title disputes weather conditions shortages delays orunavailability of equipment and services required in drilling operations insufficient gathering processing and transportation capacity the need to obtain governmentalapprovals and permits and compliance with environmental laws and regulations increasing health care costs and the resulting effect on health insurance premiums and on theobligation to provide other post-retirement benefits changes in price differentials between similar quantities of natural gas or oil sold at different geographic locations and theeffect of such changes on commodity production revenues and demand for pipeline transportation capacity to or from such locations other changes in price differentialsbetween similar quantities of natural gas or oil having different quality heating value hydrocarbon mix or delivery date the cost and effects of legal and administrative claimsagainst the Company or activist shareholder campaigns to effect changes at the Company uncertainty of oil and gas reserve estimates significant differences between theCompanyrsquos projected and actual production levels for natural gas or oil changes in demographic patterns and weather conditions changes in the availability price oraccounting treatment of derivative financial instruments changes in laws actuarial assumptions the interest rate environment and the return on plantrust assets related to theCompanyrsquos pension and other post-retirement benefits which can affect future funding obligations and costs and plan liabilities changes in economic conditions includingglobal national or regional recessions and their effect on the demand for and customersrsquo ability to pay for the Companyrsquos products and services the creditworthiness orperformance of the Companyrsquos key suppliers customers and counterparties the impact of potential information technology cybersecurity or data security breaches economicdisruptions or uninsured losses resulting from major accidents fires severe weather natural disasters terrorist activities or acts of war significant differences between theCompanyrsquos projected and actual capital expenditures and operating expenses or increasing costs of insurance changes in coverage and the ability to obtain insurance

Forward-looking statements include estimates of oil and gas quantities Proved oil and gas reserves are those quantities of oil and gas which by analysis of geoscience andengineering data can be estimated with reasonable certainty to be economically producible under existing economic conditions operating methods and governmentregulations Other estimates of oil and gas quantities including estimates of probable reserves possible reserves and resource potential are by their nature more speculativethan estimates of proved reserves Accordingly estimates other than proved reserves are subject to substantially greater risk of being actually realized Investors are urged toconsider closely the disclosure in our Form 10-K available at wwwnationalfuelgascom You can also obtain this form on the SECrsquos website at wwwsecgov

For a discussion of the risks set forth above and other factors that could cause actual results to differ materially from results referred to in the forward-looking statements seeldquoRisk Factorsrdquo in the Companyrsquos Form 10-K for the fiscal year ended September 30 2018 and the Forms 10-Q for the quarter ended March 31 2018 June 30 2018 and December31 2018 The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date thereof or to reflect the occurrence ofunanticipated events

Appendix

51

Adjusted Operating Results ($ per share)(1)

Diversified Balanced Earnings and Cash Flows

(1) A reconciliation of Adjusted Operating Results to Earnings per Share by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation(2) Consolidated Adjusted EBITDA includes Energy Marketing and Corporate amp All Other Segments A reconciliation of Adjusted EBITDA to Net Income by segment as presented on the Consolidated Statement of Income and Earnings Reinvested in

the Business is included at the end of this presentation

Adjusted EBITDA ($ millions)(2)

$176 $179

$184 $181

$92 $97

$318 $327

$761 $775

$-

$200

$400

$600

$800

FY 2018 TTM 123118

$059 Utility

$097 Pipeline amp Storage

$057 Gathering

$125 Exploration

amp Production

$334 $345 to $365

$-

$100

$200

$300

$400

FY 2018 FY 2019 Guidance

Rate Regulated

40-45

$728

Rate Regulated

~46

52

$89 $94 $98 $81 $86 $90-$100

$140$230

$114 $95 $93 $120-$150

$138$118

$54$33 $48

$55-$65

$603$557

$99 $246$356

$460-$495

$970 $1001

$366$455

$583

$725-$810

$0

$250

$500

$750

$1000

$1250

2014 2015 2016 2017 2018 2019GuidanceFiscal Year

Exploration amp Production

Gathering

Pipeline amp Storage

Utility

Disciplined Flexible Capital Allocation

(2)

(1) Total Capital Expenditures include Energy Marketing Corporate and All Other A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation (2) FY16 FY17 and FY18 reflects the netting of $157 million $7 million and $17 million respectively of up-front proceeds received from joint development partner for working interest in joint development wells and $21M in intercompany asset transfers in FY18

Capital Expenditures by Segment ($ millions)(1)

53

Maintaining Strong Balance Sheet amp Liquidity

Total Equity49

Total Debt51

$42 Billion Total Capitalizationas of December 31 2018

218 x251 x 245 x 247 x 256 x

2015 2016 2017 2018 TTM 123118Fiscal Year End

Net Debt Adjusted EBITDA(1) Capitalization

Debt Maturity Profile ($MM) Liquidity

Committed Credit FacilitiesShort-term Debt OutstandingAvailable Short-term Credit FacilitiesCash Balance at 123118 Total Liquidity at 123118

$ 750 MM0 MM

750 MM110 MM

$ 860 MM

$500 $549 $500

$300 $300

$0

$200

$400

$600

(1) Net Debt is net of cash and temporary cash investments Reconciliations of Net Debt and Adjusted EBITDA to Net Income are included at the end of this presentation

54

Appendix

55

Safe Harbor For Forward Looking StatementsThis presentation may contain ldquoforward-looking statementsrdquo as defined by the Private Securities Litigation Reform Act of 1995 including statements regarding future prospectsplans objectives goals projections estimates of oil and gas quantities strategies future events or performance and underlying assumptions capital structure anticipatedcapital expenditures completion of construction projects projections for pension and other post-retirement benefit obligations impacts of the adoption of new accounting rulesand possible outcomes of litigation or regulatory proceedings as well as statements that are identified by the use of the words ldquoanticipatesrdquo ldquoestimatesrdquo ldquoexpectsrdquo ldquoforecastsrdquoldquointendsrdquo ldquoplansrdquo ldquopredictsrdquo ldquoprojectsrdquo ldquobelievesrdquo ldquoseeksrdquo ldquowillrdquo ldquomayrdquo and similar expressions Forward-looking statements involve risks and uncertainties which couldcause actual results or outcomes to differ materially from those expressed in the forward-looking statements The Companyrsquos expectations beliefs and projections are expressedin good faith and are believed by the Company to have a reasonable basis but there can be no assurance that managementrsquos expectations beliefs or projections will result or beachieved or accomplished

In addition to other factors the following are important factors that could cause actual results to differ materially from those discussed in the forward-looking statements delaysor changes in costs or plans with respect to Company projects or related projects of other companies including difficulties or delays in obtaining necessary governmentalapprovals permits or orders or in obtaining the cooperation of interconnecting facility operators governmentalregulatory actions initiatives and proceedings including thoseinvolving rate cases (which address among other things target rates of return rate design and retained natural gas) environmentalsafety requirements affiliate relationshipsindustry structure and franchise renewal changes in laws regulations or judicial interpretations to which the Company is subject including those involving derivatives taxessafety employment climate change other environmental matters real property and exploration and production activities such as hydraulic fracturing financial and economicconditions including the availability of credit and occurrences affecting the Companyrsquos ability to obtain financing on acceptable terms for working capital capital expendituresand other investments including any downgrades in the Companyrsquos credit ratings and changes in interest rates and other capital market conditions changes in the price ofnatural gas or oil impairments under the SECrsquos full cost ceiling test for natural gas and oil reserves factors affecting the Companyrsquos ability to successfully identify drill for andproduce economically viable natural gas and oil reserves including among others geology lease availability title disputes weather conditions shortages delays orunavailability of equipment and services required in drilling operations insufficient gathering processing and transportation capacity the need to obtain governmentalapprovals and permits and compliance with environmental laws and regulations increasing health care costs and the resulting effect on health insurance premiums and on theobligation to provide other post-retirement benefits changes in price differentials between similar quantities of natural gas or oil sold at different geographic locations and theeffect of such changes on commodity production revenues and demand for pipeline transportation capacity to or from such locations other changes in price differentialsbetween similar quantities of natural gas or oil having different quality heating value hydrocarbon mix or delivery date the cost and effects of legal and administrative claimsagainst the Company or activist shareholder campaigns to effect changes at the Company uncertainty of oil and gas reserve estimates significant differences between theCompanyrsquos projected and actual production levels for natural gas or oil changes in demographic patterns and weather conditions changes in the availability price oraccounting treatment of derivative financial instruments changes in laws actuarial assumptions the interest rate environment and the return on plantrust assets related to theCompanyrsquos pension and other post-retirement benefits which can affect future funding obligations and costs and plan liabilities changes in economic conditions includingglobal national or regional recessions and their effect on the demand for and customersrsquo ability to pay for the Companyrsquos products and services the creditworthiness orperformance of the Companyrsquos key suppliers customers and counterparties the impact of potential information technology cybersecurity or data security breaches economicdisruptions or uninsured losses resulting from major accidents fires severe weather natural disasters terrorist activities or acts of war significant differences between theCompanyrsquos projected and actual capital expenditures and operating expenses or increasing costs of insurance changes in coverage and the ability to obtain insurance

Forward-looking statements include estimates of oil and gas quantities Proved oil and gas reserves are those quantities of oil and gas which by analysis of geoscience andengineering data can be estimated with reasonable certainty to be economically producible under existing economic conditions operating methods and governmentregulations Other estimates of oil and gas quantities including estimates of probable reserves possible reserves and resource potential are by their nature more speculativethan estimates of proved reserves Accordingly estimates other than proved reserves are subject to substantially greater risk of being actually realized Investors are urged toconsider closely the disclosure in our Form 10-K available at wwwnationalfuelgascom You can also obtain this form on the SECrsquos website at wwwsecgov

For a discussion of the risks set forth above and other factors that could cause actual results to differ materially from results referred to in the forward-looking statements seeldquoRisk Factorsrdquo in the Companyrsquos Form 10-K for the fiscal year ended September 30 2018 and the Forms 10-Q for the quarter ended March 31 2018 June 30 2018 and December31 2018 The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date thereof or to reflect the occurrence ofunanticipated events

Appendix

52

$89 $94 $98 $81 $86 $90-$100

$140$230

$114 $95 $93 $120-$150

$138$118

$54$33 $48

$55-$65

$603$557

$99 $246$356

$460-$495

$970 $1001

$366$455

$583

$725-$810

$0

$250

$500

$750

$1000

$1250

2014 2015 2016 2017 2018 2019GuidanceFiscal Year

Exploration amp Production

Gathering

Pipeline amp Storage

Utility

Disciplined Flexible Capital Allocation

(2)

(1) Total Capital Expenditures include Energy Marketing Corporate and All Other A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation (2) FY16 FY17 and FY18 reflects the netting of $157 million $7 million and $17 million respectively of up-front proceeds received from joint development partner for working interest in joint development wells and $21M in intercompany asset transfers in FY18

Capital Expenditures by Segment ($ millions)(1)

53

Maintaining Strong Balance Sheet amp Liquidity

Total Equity49

Total Debt51

$42 Billion Total Capitalizationas of December 31 2018

218 x251 x 245 x 247 x 256 x

2015 2016 2017 2018 TTM 123118Fiscal Year End

Net Debt Adjusted EBITDA(1) Capitalization

Debt Maturity Profile ($MM) Liquidity

Committed Credit FacilitiesShort-term Debt OutstandingAvailable Short-term Credit FacilitiesCash Balance at 123118 Total Liquidity at 123118

$ 750 MM0 MM

750 MM110 MM

$ 860 MM

$500 $549 $500

$300 $300

$0

$200

$400

$600

(1) Net Debt is net of cash and temporary cash investments Reconciliations of Net Debt and Adjusted EBITDA to Net Income are included at the end of this presentation

54

Appendix

55

Safe Harbor For Forward Looking StatementsThis presentation may contain ldquoforward-looking statementsrdquo as defined by the Private Securities Litigation Reform Act of 1995 including statements regarding future prospectsplans objectives goals projections estimates of oil and gas quantities strategies future events or performance and underlying assumptions capital structure anticipatedcapital expenditures completion of construction projects projections for pension and other post-retirement benefit obligations impacts of the adoption of new accounting rulesand possible outcomes of litigation or regulatory proceedings as well as statements that are identified by the use of the words ldquoanticipatesrdquo ldquoestimatesrdquo ldquoexpectsrdquo ldquoforecastsrdquoldquointendsrdquo ldquoplansrdquo ldquopredictsrdquo ldquoprojectsrdquo ldquobelievesrdquo ldquoseeksrdquo ldquowillrdquo ldquomayrdquo and similar expressions Forward-looking statements involve risks and uncertainties which couldcause actual results or outcomes to differ materially from those expressed in the forward-looking statements The Companyrsquos expectations beliefs and projections are expressedin good faith and are believed by the Company to have a reasonable basis but there can be no assurance that managementrsquos expectations beliefs or projections will result or beachieved or accomplished

In addition to other factors the following are important factors that could cause actual results to differ materially from those discussed in the forward-looking statements delaysor changes in costs or plans with respect to Company projects or related projects of other companies including difficulties or delays in obtaining necessary governmentalapprovals permits or orders or in obtaining the cooperation of interconnecting facility operators governmentalregulatory actions initiatives and proceedings including thoseinvolving rate cases (which address among other things target rates of return rate design and retained natural gas) environmentalsafety requirements affiliate relationshipsindustry structure and franchise renewal changes in laws regulations or judicial interpretations to which the Company is subject including those involving derivatives taxessafety employment climate change other environmental matters real property and exploration and production activities such as hydraulic fracturing financial and economicconditions including the availability of credit and occurrences affecting the Companyrsquos ability to obtain financing on acceptable terms for working capital capital expendituresand other investments including any downgrades in the Companyrsquos credit ratings and changes in interest rates and other capital market conditions changes in the price ofnatural gas or oil impairments under the SECrsquos full cost ceiling test for natural gas and oil reserves factors affecting the Companyrsquos ability to successfully identify drill for andproduce economically viable natural gas and oil reserves including among others geology lease availability title disputes weather conditions shortages delays orunavailability of equipment and services required in drilling operations insufficient gathering processing and transportation capacity the need to obtain governmentalapprovals and permits and compliance with environmental laws and regulations increasing health care costs and the resulting effect on health insurance premiums and on theobligation to provide other post-retirement benefits changes in price differentials between similar quantities of natural gas or oil sold at different geographic locations and theeffect of such changes on commodity production revenues and demand for pipeline transportation capacity to or from such locations other changes in price differentialsbetween similar quantities of natural gas or oil having different quality heating value hydrocarbon mix or delivery date the cost and effects of legal and administrative claimsagainst the Company or activist shareholder campaigns to effect changes at the Company uncertainty of oil and gas reserve estimates significant differences between theCompanyrsquos projected and actual production levels for natural gas or oil changes in demographic patterns and weather conditions changes in the availability price oraccounting treatment of derivative financial instruments changes in laws actuarial assumptions the interest rate environment and the return on plantrust assets related to theCompanyrsquos pension and other post-retirement benefits which can affect future funding obligations and costs and plan liabilities changes in economic conditions includingglobal national or regional recessions and their effect on the demand for and customersrsquo ability to pay for the Companyrsquos products and services the creditworthiness orperformance of the Companyrsquos key suppliers customers and counterparties the impact of potential information technology cybersecurity or data security breaches economicdisruptions or uninsured losses resulting from major accidents fires severe weather natural disasters terrorist activities or acts of war significant differences between theCompanyrsquos projected and actual capital expenditures and operating expenses or increasing costs of insurance changes in coverage and the ability to obtain insurance

Forward-looking statements include estimates of oil and gas quantities Proved oil and gas reserves are those quantities of oil and gas which by analysis of geoscience andengineering data can be estimated with reasonable certainty to be economically producible under existing economic conditions operating methods and governmentregulations Other estimates of oil and gas quantities including estimates of probable reserves possible reserves and resource potential are by their nature more speculativethan estimates of proved reserves Accordingly estimates other than proved reserves are subject to substantially greater risk of being actually realized Investors are urged toconsider closely the disclosure in our Form 10-K available at wwwnationalfuelgascom You can also obtain this form on the SECrsquos website at wwwsecgov

For a discussion of the risks set forth above and other factors that could cause actual results to differ materially from results referred to in the forward-looking statements seeldquoRisk Factorsrdquo in the Companyrsquos Form 10-K for the fiscal year ended September 30 2018 and the Forms 10-Q for the quarter ended March 31 2018 June 30 2018 and December31 2018 The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date thereof or to reflect the occurrence ofunanticipated events

Appendix

53

Maintaining Strong Balance Sheet amp Liquidity

Total Equity49

Total Debt51

$42 Billion Total Capitalizationas of December 31 2018

218 x251 x 245 x 247 x 256 x

2015 2016 2017 2018 TTM 123118Fiscal Year End

Net Debt Adjusted EBITDA(1) Capitalization

Debt Maturity Profile ($MM) Liquidity

Committed Credit FacilitiesShort-term Debt OutstandingAvailable Short-term Credit FacilitiesCash Balance at 123118 Total Liquidity at 123118

$ 750 MM0 MM

750 MM110 MM

$ 860 MM

$500 $549 $500

$300 $300

$0

$200

$400

$600

(1) Net Debt is net of cash and temporary cash investments Reconciliations of Net Debt and Adjusted EBITDA to Net Income are included at the end of this presentation

54

Appendix

55

Safe Harbor For Forward Looking StatementsThis presentation may contain ldquoforward-looking statementsrdquo as defined by the Private Securities Litigation Reform Act of 1995 including statements regarding future prospectsplans objectives goals projections estimates of oil and gas quantities strategies future events or performance and underlying assumptions capital structure anticipatedcapital expenditures completion of construction projects projections for pension and other post-retirement benefit obligations impacts of the adoption of new accounting rulesand possible outcomes of litigation or regulatory proceedings as well as statements that are identified by the use of the words ldquoanticipatesrdquo ldquoestimatesrdquo ldquoexpectsrdquo ldquoforecastsrdquoldquointendsrdquo ldquoplansrdquo ldquopredictsrdquo ldquoprojectsrdquo ldquobelievesrdquo ldquoseeksrdquo ldquowillrdquo ldquomayrdquo and similar expressions Forward-looking statements involve risks and uncertainties which couldcause actual results or outcomes to differ materially from those expressed in the forward-looking statements The Companyrsquos expectations beliefs and projections are expressedin good faith and are believed by the Company to have a reasonable basis but there can be no assurance that managementrsquos expectations beliefs or projections will result or beachieved or accomplished

In addition to other factors the following are important factors that could cause actual results to differ materially from those discussed in the forward-looking statements delaysor changes in costs or plans with respect to Company projects or related projects of other companies including difficulties or delays in obtaining necessary governmentalapprovals permits or orders or in obtaining the cooperation of interconnecting facility operators governmentalregulatory actions initiatives and proceedings including thoseinvolving rate cases (which address among other things target rates of return rate design and retained natural gas) environmentalsafety requirements affiliate relationshipsindustry structure and franchise renewal changes in laws regulations or judicial interpretations to which the Company is subject including those involving derivatives taxessafety employment climate change other environmental matters real property and exploration and production activities such as hydraulic fracturing financial and economicconditions including the availability of credit and occurrences affecting the Companyrsquos ability to obtain financing on acceptable terms for working capital capital expendituresand other investments including any downgrades in the Companyrsquos credit ratings and changes in interest rates and other capital market conditions changes in the price ofnatural gas or oil impairments under the SECrsquos full cost ceiling test for natural gas and oil reserves factors affecting the Companyrsquos ability to successfully identify drill for andproduce economically viable natural gas and oil reserves including among others geology lease availability title disputes weather conditions shortages delays orunavailability of equipment and services required in drilling operations insufficient gathering processing and transportation capacity the need to obtain governmentalapprovals and permits and compliance with environmental laws and regulations increasing health care costs and the resulting effect on health insurance premiums and on theobligation to provide other post-retirement benefits changes in price differentials between similar quantities of natural gas or oil sold at different geographic locations and theeffect of such changes on commodity production revenues and demand for pipeline transportation capacity to or from such locations other changes in price differentialsbetween similar quantities of natural gas or oil having different quality heating value hydrocarbon mix or delivery date the cost and effects of legal and administrative claimsagainst the Company or activist shareholder campaigns to effect changes at the Company uncertainty of oil and gas reserve estimates significant differences between theCompanyrsquos projected and actual production levels for natural gas or oil changes in demographic patterns and weather conditions changes in the availability price oraccounting treatment of derivative financial instruments changes in laws actuarial assumptions the interest rate environment and the return on plantrust assets related to theCompanyrsquos pension and other post-retirement benefits which can affect future funding obligations and costs and plan liabilities changes in economic conditions includingglobal national or regional recessions and their effect on the demand for and customersrsquo ability to pay for the Companyrsquos products and services the creditworthiness orperformance of the Companyrsquos key suppliers customers and counterparties the impact of potential information technology cybersecurity or data security breaches economicdisruptions or uninsured losses resulting from major accidents fires severe weather natural disasters terrorist activities or acts of war significant differences between theCompanyrsquos projected and actual capital expenditures and operating expenses or increasing costs of insurance changes in coverage and the ability to obtain insurance

Forward-looking statements include estimates of oil and gas quantities Proved oil and gas reserves are those quantities of oil and gas which by analysis of geoscience andengineering data can be estimated with reasonable certainty to be economically producible under existing economic conditions operating methods and governmentregulations Other estimates of oil and gas quantities including estimates of probable reserves possible reserves and resource potential are by their nature more speculativethan estimates of proved reserves Accordingly estimates other than proved reserves are subject to substantially greater risk of being actually realized Investors are urged toconsider closely the disclosure in our Form 10-K available at wwwnationalfuelgascom You can also obtain this form on the SECrsquos website at wwwsecgov

For a discussion of the risks set forth above and other factors that could cause actual results to differ materially from results referred to in the forward-looking statements seeldquoRisk Factorsrdquo in the Companyrsquos Form 10-K for the fiscal year ended September 30 2018 and the Forms 10-Q for the quarter ended March 31 2018 June 30 2018 and December31 2018 The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date thereof or to reflect the occurrence ofunanticipated events

Appendix

54

Appendix

55

Safe Harbor For Forward Looking StatementsThis presentation may contain ldquoforward-looking statementsrdquo as defined by the Private Securities Litigation Reform Act of 1995 including statements regarding future prospectsplans objectives goals projections estimates of oil and gas quantities strategies future events or performance and underlying assumptions capital structure anticipatedcapital expenditures completion of construction projects projections for pension and other post-retirement benefit obligations impacts of the adoption of new accounting rulesand possible outcomes of litigation or regulatory proceedings as well as statements that are identified by the use of the words ldquoanticipatesrdquo ldquoestimatesrdquo ldquoexpectsrdquo ldquoforecastsrdquoldquointendsrdquo ldquoplansrdquo ldquopredictsrdquo ldquoprojectsrdquo ldquobelievesrdquo ldquoseeksrdquo ldquowillrdquo ldquomayrdquo and similar expressions Forward-looking statements involve risks and uncertainties which couldcause actual results or outcomes to differ materially from those expressed in the forward-looking statements The Companyrsquos expectations beliefs and projections are expressedin good faith and are believed by the Company to have a reasonable basis but there can be no assurance that managementrsquos expectations beliefs or projections will result or beachieved or accomplished

In addition to other factors the following are important factors that could cause actual results to differ materially from those discussed in the forward-looking statements delaysor changes in costs or plans with respect to Company projects or related projects of other companies including difficulties or delays in obtaining necessary governmentalapprovals permits or orders or in obtaining the cooperation of interconnecting facility operators governmentalregulatory actions initiatives and proceedings including thoseinvolving rate cases (which address among other things target rates of return rate design and retained natural gas) environmentalsafety requirements affiliate relationshipsindustry structure and franchise renewal changes in laws regulations or judicial interpretations to which the Company is subject including those involving derivatives taxessafety employment climate change other environmental matters real property and exploration and production activities such as hydraulic fracturing financial and economicconditions including the availability of credit and occurrences affecting the Companyrsquos ability to obtain financing on acceptable terms for working capital capital expendituresand other investments including any downgrades in the Companyrsquos credit ratings and changes in interest rates and other capital market conditions changes in the price ofnatural gas or oil impairments under the SECrsquos full cost ceiling test for natural gas and oil reserves factors affecting the Companyrsquos ability to successfully identify drill for andproduce economically viable natural gas and oil reserves including among others geology lease availability title disputes weather conditions shortages delays orunavailability of equipment and services required in drilling operations insufficient gathering processing and transportation capacity the need to obtain governmentalapprovals and permits and compliance with environmental laws and regulations increasing health care costs and the resulting effect on health insurance premiums and on theobligation to provide other post-retirement benefits changes in price differentials between similar quantities of natural gas or oil sold at different geographic locations and theeffect of such changes on commodity production revenues and demand for pipeline transportation capacity to or from such locations other changes in price differentialsbetween similar quantities of natural gas or oil having different quality heating value hydrocarbon mix or delivery date the cost and effects of legal and administrative claimsagainst the Company or activist shareholder campaigns to effect changes at the Company uncertainty of oil and gas reserve estimates significant differences between theCompanyrsquos projected and actual production levels for natural gas or oil changes in demographic patterns and weather conditions changes in the availability price oraccounting treatment of derivative financial instruments changes in laws actuarial assumptions the interest rate environment and the return on plantrust assets related to theCompanyrsquos pension and other post-retirement benefits which can affect future funding obligations and costs and plan liabilities changes in economic conditions includingglobal national or regional recessions and their effect on the demand for and customersrsquo ability to pay for the Companyrsquos products and services the creditworthiness orperformance of the Companyrsquos key suppliers customers and counterparties the impact of potential information technology cybersecurity or data security breaches economicdisruptions or uninsured losses resulting from major accidents fires severe weather natural disasters terrorist activities or acts of war significant differences between theCompanyrsquos projected and actual capital expenditures and operating expenses or increasing costs of insurance changes in coverage and the ability to obtain insurance

Forward-looking statements include estimates of oil and gas quantities Proved oil and gas reserves are those quantities of oil and gas which by analysis of geoscience andengineering data can be estimated with reasonable certainty to be economically producible under existing economic conditions operating methods and governmentregulations Other estimates of oil and gas quantities including estimates of probable reserves possible reserves and resource potential are by their nature more speculativethan estimates of proved reserves Accordingly estimates other than proved reserves are subject to substantially greater risk of being actually realized Investors are urged toconsider closely the disclosure in our Form 10-K available at wwwnationalfuelgascom You can also obtain this form on the SECrsquos website at wwwsecgov

For a discussion of the risks set forth above and other factors that could cause actual results to differ materially from results referred to in the forward-looking statements seeldquoRisk Factorsrdquo in the Companyrsquos Form 10-K for the fiscal year ended September 30 2018 and the Forms 10-Q for the quarter ended March 31 2018 June 30 2018 and December31 2018 The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date thereof or to reflect the occurrence ofunanticipated events

Appendix

55

Safe Harbor For Forward Looking StatementsThis presentation may contain ldquoforward-looking statementsrdquo as defined by the Private Securities Litigation Reform Act of 1995 including statements regarding future prospectsplans objectives goals projections estimates of oil and gas quantities strategies future events or performance and underlying assumptions capital structure anticipatedcapital expenditures completion of construction projects projections for pension and other post-retirement benefit obligations impacts of the adoption of new accounting rulesand possible outcomes of litigation or regulatory proceedings as well as statements that are identified by the use of the words ldquoanticipatesrdquo ldquoestimatesrdquo ldquoexpectsrdquo ldquoforecastsrdquoldquointendsrdquo ldquoplansrdquo ldquopredictsrdquo ldquoprojectsrdquo ldquobelievesrdquo ldquoseeksrdquo ldquowillrdquo ldquomayrdquo and similar expressions Forward-looking statements involve risks and uncertainties which couldcause actual results or outcomes to differ materially from those expressed in the forward-looking statements The Companyrsquos expectations beliefs and projections are expressedin good faith and are believed by the Company to have a reasonable basis but there can be no assurance that managementrsquos expectations beliefs or projections will result or beachieved or accomplished

In addition to other factors the following are important factors that could cause actual results to differ materially from those discussed in the forward-looking statements delaysor changes in costs or plans with respect to Company projects or related projects of other companies including difficulties or delays in obtaining necessary governmentalapprovals permits or orders or in obtaining the cooperation of interconnecting facility operators governmentalregulatory actions initiatives and proceedings including thoseinvolving rate cases (which address among other things target rates of return rate design and retained natural gas) environmentalsafety requirements affiliate relationshipsindustry structure and franchise renewal changes in laws regulations or judicial interpretations to which the Company is subject including those involving derivatives taxessafety employment climate change other environmental matters real property and exploration and production activities such as hydraulic fracturing financial and economicconditions including the availability of credit and occurrences affecting the Companyrsquos ability to obtain financing on acceptable terms for working capital capital expendituresand other investments including any downgrades in the Companyrsquos credit ratings and changes in interest rates and other capital market conditions changes in the price ofnatural gas or oil impairments under the SECrsquos full cost ceiling test for natural gas and oil reserves factors affecting the Companyrsquos ability to successfully identify drill for andproduce economically viable natural gas and oil reserves including among others geology lease availability title disputes weather conditions shortages delays orunavailability of equipment and services required in drilling operations insufficient gathering processing and transportation capacity the need to obtain governmentalapprovals and permits and compliance with environmental laws and regulations increasing health care costs and the resulting effect on health insurance premiums and on theobligation to provide other post-retirement benefits changes in price differentials between similar quantities of natural gas or oil sold at different geographic locations and theeffect of such changes on commodity production revenues and demand for pipeline transportation capacity to or from such locations other changes in price differentialsbetween similar quantities of natural gas or oil having different quality heating value hydrocarbon mix or delivery date the cost and effects of legal and administrative claimsagainst the Company or activist shareholder campaigns to effect changes at the Company uncertainty of oil and gas reserve estimates significant differences between theCompanyrsquos projected and actual production levels for natural gas or oil changes in demographic patterns and weather conditions changes in the availability price oraccounting treatment of derivative financial instruments changes in laws actuarial assumptions the interest rate environment and the return on plantrust assets related to theCompanyrsquos pension and other post-retirement benefits which can affect future funding obligations and costs and plan liabilities changes in economic conditions includingglobal national or regional recessions and their effect on the demand for and customersrsquo ability to pay for the Companyrsquos products and services the creditworthiness orperformance of the Companyrsquos key suppliers customers and counterparties the impact of potential information technology cybersecurity or data security breaches economicdisruptions or uninsured losses resulting from major accidents fires severe weather natural disasters terrorist activities or acts of war significant differences between theCompanyrsquos projected and actual capital expenditures and operating expenses or increasing costs of insurance changes in coverage and the ability to obtain insurance

Forward-looking statements include estimates of oil and gas quantities Proved oil and gas reserves are those quantities of oil and gas which by analysis of geoscience andengineering data can be estimated with reasonable certainty to be economically producible under existing economic conditions operating methods and governmentregulations Other estimates of oil and gas quantities including estimates of probable reserves possible reserves and resource potential are by their nature more speculativethan estimates of proved reserves Accordingly estimates other than proved reserves are subject to substantially greater risk of being actually realized Investors are urged toconsider closely the disclosure in our Form 10-K available at wwwnationalfuelgascom You can also obtain this form on the SECrsquos website at wwwsecgov

For a discussion of the risks set forth above and other factors that could cause actual results to differ materially from results referred to in the forward-looking statements seeldquoRisk Factorsrdquo in the Companyrsquos Form 10-K for the fiscal year ended September 30 2018 and the Forms 10-Q for the quarter ended March 31 2018 June 30 2018 and December31 2018 The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date thereof or to reflect the occurrence ofunanticipated events

Appendix

56

Hedge Positions and Prices

Natural Gas Volumes in thousand MMBtu Prices in $MMBtu

VolumeAvgPrice Volume

AvgPrice Volume

AvgPrice Volume

AvgPrice

NYMEX Swaps 60120 $293 18640 $304 4840 $301 - -

Dawn Swaps 5400 $300 7200 $300 600 $300 - -

Fixed Price Physical 51915 $268 45046 $234 41488 $222 40580 $223

Total 117435 $282 70886 $259 46928 $231 40580 $223

Crude Oil Volumes amp Prices in Bbl

Avg Avg Avg AvgPrice Price Price Price

Brent Swaps 558000 $6352 864000 $6351 576000 $6468 300000 $6007

NYMEX Swaps 801000 $5342 324000 $5052 156000 $5100 156000 $5100

Total 1359000 $5757 1188000 $5996 732000 $6161 456000 $5697

Fiscal 2022

Volume

Fiscal 2020 Fiscal 2021Fiscal 2019

Fiscal 2019 Fiscal 2020

Volume

Fiscal 2021

Volume

Fiscal 2022

Volume

(1) Fixed price physical sales exclude joint development partnerrsquos share of fixed price contract WDA volumes as specified under the joint development agreement

(1)

Appendix

Sheet1

Sheet3

57

Appalachia Drilling Program Economics

(1) Net realized price reflects either (a) price received at the gathering system interconnect or (b) price received at delivery market net of firm transportation charges(2) Internal Rate of Return (IRR) is pre-tax and includes estimated well costs under current cost structure LOE and Gathering tariffs anticipated for each prospect

Large Marcellus and Utica Inventory Economic at ~$200MMBtu(1)

$250Realized

$225Realized

$200Realized

Tract 100 amp Gamble

Lycoming CoMarcellus 45 4900 25 $1057 76 58 44 $153

Transco Leidy ampAtlantic Sunrise

Southeast US(NYMEX+)

DCNR 007Tioga Co

Utica 43 8300 20 $1045 49 36 22 $184 TGP 300

Clermont Rich Valley

Utica 120+ 9000 17 $887 30 23 16 $197

Core Areas Marcellus 600+ 8500 10 to 11 $643 26 19 14 $206

TGP 300 Niagara

Expansion Canada (Dawn) amp

FM100Leidy South (Transco

Zone 6)

WDA

Realized Price(1)

Required for 15 IRR

Anticipated DeliveryMarkets

EDA

Prospect Reservoir

Locations Remaining

to Be Drilled

Completed Lateral

Length (ft)EUR 1000

(Bcf)

Internal Rate of Return (2)

Well Cost$M1000 ft

Appendix

Sheet1

58

Comparable GAAP Financial Measure Slides amp Reconciliations

This presentation contains certain non-GAAP financial measures For pages that contain non-GAAP financial measures pages containing themost directly comparable GAAP financial measures and reconciliations are provided in the slides that follow

The Company believes that its non-GAAP financial measures are useful to investors because they provide an alternative method for assessing theCompanyrsquos ongoing operating results and for comparing the Companyrsquos financial performance to other companies The Companyrsquos managementuses these non-GAAP financial measures for the same purpose and for planning and forecasting purposes The presentation of non-GAAPfinancial measures is not meant to be a substitute for financial measures prepared in accordance with GAAP

Management defines Adjusted Operating Results as reported GAAP earnings before items impacting comparability

The Companyrsquos earnings guidance range does not include the impact of certain items that impacted the comparability of earnings during the firstquarter including (1) the remeasurement of deferred income taxes resulting from the 2017 Tax Reform Act which reduced the Companyrsquos incometax expense and benefited consolidated earnings in the first quarter by $006 per share (2) the full year impact of the Exploration and Productionsegmentrsquos unrealized gain on hedging ineffectiveness which increased earnings by $006 per share in the first quarter ($32 million or $003 pershare of the unrealized gain relates to hedge contracts that will settle during the remaining nine months ending September 30 2019) and (3) theunrealized loss on other investments due to the change in an accounting rule which lowered earnings by $006 per share While the Companyexpects to record additional adjustments to one or more of these items during the remaining nine months ending September 30 2019 theamounts of these and other potential adjustments are not reasonably determinable at this time As such the Company is unable to provideearnings guidance other than on a non-GAAP basis

Management defines Adjusted EBITDA as reported GAAP earnings before the following items interest expense income taxes depreciationdepletion and amortization interest and other income impairments and other items reflected in operating income that impact comparability

Appendix

59

Non-GAAP Reconciliations ndash Adjusted EBITDA

Appendix

(1) Total Adjusted EBITDA for FY 2018 and the twelve months ended December 31 2018 include the reclassification of non-service pension costs from Operating and Maintenance Expense to Other Income (Deductions) as of October 1 2018 on the Companyrsquos Income Statement which on a consolidated basis were approximately $3264 million in FY 2018 and approximately $3257 million for the twelve months ended December 31 2018 This reclassification is not reflected in Total Adjusted EBITDA for FY 2015 FY 2016 or FY 2017

Reconciliation of Adjusted EBITDA to Consolidated Net Income($ Thousands)

Total Adjusted EBITDAExploration amp Production Adjusted EBITDA 418726$ 363438$ 361079$ 317706$ 327381$ Pipeline amp Storage Adjusted EBITDA 188042 199446 180328 183973 181380 Gathering Adjusted EBITDA 68881 78685 94380 91937 97072 Utility Adjusted EBITDA 164037 148683 151078 175555 178974 Energy Marketing Adjusted EBITDA 12237 6655 2080 1033 (1492) Corporate amp All Other Adjusted EBITDA (11900) (8238) (11805) (8735) (8145) Total Adjusted EBITDA 840023$ 788669$ 777140$ 761469$ 775170$

Total Adjusted EBITDA 840023$ 788669$ 777140$ 761469$ 775170$ Minus Interest Expense (99471) (121044) (119837) (114522) (112445) Plus Other Income (Deductions) 11961 14055 11156 (21177) (27276) Minus Income Tax Expense 319136 232549 (160682) 7494 (96692) Minus Depreciation Depletion amp Amortization (336158) (249417) (224195) (240961) (249386) Minus Impairment of Oil and Gas Properties (EampP) (1126257) (948307) - - - Plus Reversal of Stock-Based Compensation (all segments) 7776 - - - - Minus Unrealized Gain (Loss) on Hedge Ineffectiveness 3563 392 (100) (782) 6156 Minus Joint Development Agreement Professional Fees (EampP) - (7855) - - - Rounding - - - - - Consolidated Net Income (379427)$ (290958)$ 283482$ 391521$ 295527$

Consolidated Debt to Total Adjusted EBITDALong-Term Debt Net of Current Portion (End of Period) 2099000$ 2099000$ 2099000$ 2149000$ 2149000$ Current Portion of Long-Term Debt (End of Period) - - 300000 - - Notes Payable to Banks and Commercial Paper (End of Period) - - - - - Less Cash and Temporary Cash Investments (End of Period) (113596) (129972) (555530) (229606) (109754)

Total Net Debt (End of Period) 1985404$ 1969028$ 1843470$ 1919394$ 2039246$

Long-Term Debt Net of Current Portion (Start of Period) 1649000 2099000 2099000 2099000 2099000 Current Portion of Long-Term Debt (Start of Period) - - - 300000 - Notes Payable to Banks and Commercial Paper (Start of Period) 85600 - - - - Less Cash and Temporary Cash Investments (Start of Period) (36886) (113596) (129972) (555530) (166289)

Total Net Debt (Start of Period) 1697714$ 1985404$ 1969028$ 1843470$ 1932711$

Average Total Net Debt 1841559$ 1977216$ 1906249$ 1881432$ 1985979$

Average Total Net Debt to Total Adjusted EBITDA 219 x 251 x 245 x 247 x 256 x

12-MonthsEnded 123118FY 2015 FY 2016 FY 2017 FY 2018

(1)(1)

60

Non-GAAP Reconciliations ndash Adjusted EBITDA by Segment

Appendix

Reconciliation of Adjusted EBITDA to Net Income by Segment($ Thousands)

Exploration and Production SegmentReported GAAP Earnings $ 180632 $ 38214 $ 106698 $ 112148

Depreciation Depletion and Amortization 124274 34700 27425 131549Interest and Other Income (308) (278) (3) (584)Interest Expense 54288 13163 13374 54077Income Taxes (41962) 10602 (67707) 36347Unrealized (Gain) Loss of Hedge Ineffectiveness 782 (6505) 433 (6156)

Adjusted EBITDA $ 317706 $ 89896 $ 80221 $ 327382

Pipeline and Storage SegmentReported GAAP Earnings $ 97246 $ 25102 $ 38462 $ 83886

Depreciation Depletion and Amortization 43463 11114 10596 43981Interest and Other Income (5925) (1926) (1645) (6206)Interest Expense 31383 7286 7876 30793Income Taxes 17806 6248 (4872) 28926

Adjusted EBITDA $ 183973 $ 47824 $ 50417 $ 181380

Gathering SegmentReported GAAP Earnings $ 83519 $ 14183 $ 45400 $ 52302

Depreciation Depletion and Amortization 17313 4679 4088 17904Interest and Other Income (778) (43) (316) (505)Interest Expense 9560 2377 2340 9597Income Taxes (17677) 4752 (30699) 17774

Adjusted EBITDA $ 91937 $ 25948 $ 20813 $ 97072

FY19 FY18 12-MonthsFY 2018 FYTD FYTD Ended 123118

($ Thousands)

Utility SegmentReported GAAP Earnings $ 51217 $ 25649 $ 20993 $ 55873

Depreciation Depletion and Amortization 53253 13290 13325 53218Interest and Other Income 29074 6216 6691 28599Interest Expense 26753 5893 6837 25809Income Taxes 15258 6521 6304 15475

Adjusted EBITDA $ 175555 $ 57569 $ 54150 $ 178974

Energy Marketing SegmentReported GAAP Earnings $ 373 $ (302) $ 1046 $ (975)

Depreciation Depletion and Amortization 275 70 69 276Interest and Other Income (269) (45) (13) (301)Interest Expense 22 5 11 16Income Taxes 632 (449) 691 (508)

Adjusted EBITDA $ 1033 $ (721) $ 1804 $ (1492)

Corporate and All OtherReported GAAP Earnings $ (21466) $ (186) $ (13945) $ (7707)

Depreciation Depletion and Amortization 2383 402 327 2458Interest and Other Income (616) 5678 (1211) 6273Interest Expense (7484) (2212) (1849) (7847)Income Taxes 18449 (4765) 15005 (1321)

Adjusted EBITDA $ (8735) $ (1083) $ (1673) $ (8145)

FY19 FY18 12-MonthsFY 2018 FYTD FYTD Ended 123118

61

Non-GAAP Reconciliations ndash Adjusted Operating Results

Appendix

(in thousands except per share amounts) 2018 2017Reported GAAP Earnings 102660$ 198654$

Items impacting comparabilityRemeasurement of deferred income taxes under 2017 Tax Reform (5000) (111000) Unrealized (gain) loss on hedge ineffectiveness (EampP) (6505) 433 Tax impact of unrealized (gain) loss on hedge ineffectiveness 1366 (106) Unrealized loss on other investments (Corporate All Other) 6347 - Tax impact of unrealized loss on other investments (1333) -

Adjusted Operating Results 97535$ 87981$

Reported GAAP Earnings per share 118$ 230$ Items impacting comparability

Remeasurement of deferred income taxes under 2017 Tax Reform (006) (129) Unrealized (gain) loss on hedge ineffectiveness (EampP) (008) 001 Tax impact of unrealized (gain) loss on hedge ineffectiveness 002 - Unrealized loss on other investments (Corporate All Other) 007 - Tax impact of unrealized loss on other investments (002) - Rounding 001 -

Adjusted Operating Results per share 112$ 102$

Three Months EndedDecember 31

Fiscal Year Ended September 30 (in thousands except per share amounts) 2018 2017 Reported GAAP Earnings $ 391521 $ 283482

Items impacting comparability Remeasurement of deferred income taxes under 2017 Tax Reform (103484 ) mdash

Premium paid on early redemption of debt (EampP) 962 mdash Tax impact on premium paid on early redemption of debt (235 ) mdash

Adjusted Operating Results $ 288764 $ 283482 Reported GAAP Earnings per share $ 453 $ 330

Items impacting comparability Remeasurement of deferred income taxes under 2017 Tax Reform (120 ) mdash

Premium paid on early redemption of debt net of tax 001 mdash Adjusted Operating Results per share $ 334 $ 330

Adjusted Operating Results

Sheet2

Sheet1

62

Non-GAAP Reconciliations ndash Capital Expenditures

Appendix

Reconciliation of Segment Capital Expenditures to Consolidated Capital Expenditures ($ Thousands) FY 2019

FY 2014 FY 2015 FY 2016 FY 2017 FY 2018 ForecastCapital Expenditures

Exploration amp Production Capital Expenditures 602705$ 557313$ 256104$ 253057$ 380677$ $460000 - $495000Pipeline amp Storage Capital Expenditures 139821$ 230192$ 114250$ 95336$ 92832$ $120000 - $150000Gathering Segment Capital Expenditures 137799$ 118166$ 54293$ 32645$ 61728$ $55000 - $65000Utility Capital Expenditures 88810$ 94371$ 98007$ 80867$ 85648$ $90000 - $100000Energy Marketing Corporate amp All Other Capital Expenditures 772$ 467$ 397$ 212$ 222$ Eliminations - -$ -$ -$ (20505)$ Total Capital Expenditures from Continuing Operations 969907$ 1000509$ 523051$ 462117$ 600602$ $725000 - $810000

Plus (Minus) Accrued Capital Expenditures

Exploration amp Production FY 2018 Accrued Capital Expenditures (51343)$ Exploration amp Production FY 2017 Accrued Capital Expenditures (36465)$ 36465$ Exploration amp Production FY 2016 Accrued Capital Expenditures - - (25215) 25215 Exploration amp Production FY 2015 Accrued Capital Expenditures - (46173) 46173 - Exploration amp Production FY 2014 Accrued Capital Expenditures (80108) 80108 - - Exploration amp Production FY 2013 Accrued Capital Expenditures 58478 - - - Exploration amp Production FY 2012 Accrued Capital Expenditures - - - - Pipeline amp Storage FY 2018 Accrued Capital Expenditures (21861)$ Pipeline amp Storage FY 2017 Accrued Capital Expenditures (25077) 25077$ Pipeline amp Storage FY 2016 Accrued Capital Expenditures - - (18661) 18661 Pipeline amp Storage FY 2015 Accrued Capital Expenditures - (33925) 33925 - Pipeline amp Storage FY 2014 Accrued Capital Expenditures (28122) 28122 - - Pipeline amp Storage FY 2013 Accrued Capital Expenditures 5633 - - - Pipeline amp Storage FY 2012 Accrued Capital Expenditures - - - - Gathering FY 2018 Accrued Capital Expenditures (6084)$ Gathering FY 2017 Accrued Capital Expenditures (3925) 3925$ Gathering FY 2016 Accrued Capital Expenditures - - (5355) 5355 Gathering FY 2015 Accrued Capital Expenditures - (22416) 22416 - Gathering FY 2014 Accrued Capital Expenditures (20084) 20084 - - Gathering FY 2013 Accrued Capital Expenditures 6700 - - - Gathering FY 2012 Accrued Capital Expenditures - - - - Utility FY 2018 Accrued Capital Expenditures (9525)$ Utility FY 2017 Accrued Capital Expenditures (6748) 6748$ Utility FY 2016 Accrued Capital Expenditures - - (11203) 11203 Utility FY 2015 Accrued Capital Expenditures - (16445) 16445 - Utility FY 2014 Accrued Capital Expenditures (8315) 8315 - - Utility FY 2013 Accrued Capital Expenditures 10328 - - - Utility FY 2012 Accrued Capital Expenditures - - - - Total Accrued Capital Expenditures (55490)$ 17670$ 58525$ (11782)$ (16597)$

Total Capital Expenditures per Statement of Cash Flows 914417$ 1018179$ 581576$ 450335$ 584004$ $725000 - $810000

63

Non-GAAP Reconciliations ndash EampP Operating Expenses

Appendix

Reconciliation of Exploration amp Production Segment Operating Expenses by Division($000s unless noted otherwise)

Appalachia West Coast(2) Total EampP Appalachia West Coast(2) Total EampP Appalachia West Coast(2) Total EampP Appalachia West Coast(2) Total EampP$ Mcfe $ Boe $ Mcfe $ Mcfe $ Boe $ Mcfe

Operating ExpensesGathering amp Transportation Expense (1) $95611 $46 $95657 $060 $002 $054 $92874 $502 $93376 $060 $016 $054Other Lease Operating Expense $14604 $52461 $67065 $009 $1789 $038 $16625 $55990 $72615 $011 $1731 $042Lease Operating and Transportation Expense $110215 $52507 $162721 $069 $1791 $091 $109499 $56492 $165991 $071 $1746 $096

General amp Administrative Expense $60596 $034 $58734 $034

All Other Operating and Maintenance Expense $11077 $006 $13469 $008Property Franchise and Other Taxes $14400 $008 $15426 $009Total Taxes amp Other $25477 $014 $28895 $017

Depreciation Depletion amp Amortization $124274 $070 $112565 $065

ProductionGas Production (MMcf) 160499 2407 162906 154093 2995 157088 Oil Production (MBbl) 4 2531 2535 4 2736 2740

Total Production (Mmcfe) 160523 17592 178114 154117 19411 173528 Total Production (Mboe) 26754 2932 29686 25686 3235 28921

(1) Gathering and Transportation expense is net of any payments received from JDA partner for the partners share of gathering cost(2) Seneca West Coast division includes Seneca corporate and eliminations

Twelve Months Ended September 30 2018

Twelve Months Ended September 30 2017

64

Non-GAAP Reconciliations ndash Adjusted Operation amp Maintenance Expense

Appendix

Reconciliation of Adjusted Operation and Maintenance Expense to Operation and Maintenance Expense By Segment ($ Thousands)

Exploration and Production SegmentOperation and Maintenance

General and Administrative Expense $ 59425 $ 15198 $ 13602 $ 61021Lease Operating and Transportation Expense 162721 42562 39647 165636All Other Operation and Maintenance Expense 11077 2353 2535 10895

Operation and Maintenance Expense $ 233223 60113 55784 237552Plus Non-Service Pension Costs 1171 4 293 882

Adjusted Operation and Maintenance Expense $ 234394 $ 60117 $ 56077 $ 238434

Pipeline and Storage SegmentOperation and Maintenance Expense $ 86876 $ 21633 $ 17672 $ 90837

Plus Non-Service Pension Costs (1420) (467) (356) (1531)Adjusted Operation and Maintenance Expense $ 85456 $ 21166 $ 17316 $ 89306

Gathering SegmentOperation and Maintenance Expense $ 15862 $ 3711 $ 2984 $ 16589

Plus Non-Service Pension Cots 328 82 82 328Adjusted Operation and Maintenance Expense $ 16190 $ 3793 $ 3066 $ 16917

Utility SegmentOperation and Maintenance Expense $ 165857 $ 43155 $ 43317 $ 165695

Plus Non-Service Pension Costs 31400 6928 7165 31163Adjusted Operation and Maintenance Expense $ 197257 $ 50083 $ 50482 $ 196858

Energy Marketing SegmentOperation and Maintenance Expense $ 6057 $ 1617 $ 1513 $ 6161

Plus Non-Service Pension Costs 497 123 124 496Adjusted Operation and Maintenance Expense $ 6554 $ 1740 $ 1637 $ 6657

Corporate and All Other Operation and Maintenance Expense $ 17003 $ 3058 $ 3721 $ 16340

Plus Non-Service Pension Costs 664 737 167 1234Adjusted Operation and Maintenance Expense $ 17667 $ 3795 $ 3888 $ 17574

Intersegment Eliminations $ (115112) $ (31643) $ (25517) $ (121238)

ConsolidatedOperation and Maintenance Expense $ 409766 $ 101644 $ 99474 $ 411936

Plus Non-Service Pension Costs 32640 7407 7475 32572Adjusted Operation and Maintenance Expense $ 442406 $ 109051 $ 106949 $ 444508

FY19 FY18 12-MonthsFY 2018 FYTD FYTD Ended 123118

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			Q1			Q1
			FY 2019			FY 2018
	Net Gain (Loss) on Hedge Ineffectiveness			$ 6504854			$ (433000)
	Federal Statutory Tax Rate			210			245
	Tax Benefit (Expense)			$ 1366019			$ (106085)
	After-tax Impact			$ 5138835			$ (326915)
	Net Gain (Loss) on ERP TopHat Investments			$ 6346969			$ - 0
	Federal Statutory Tax Rate			210			245
	Tax Benefit (Expense)			$ 1332863			$ - 0
	After-tax Impact			$ 5014106			$ - 0

Nationl Fuel Gas Company
Q1 - FY 2019
Segment Discussion Earnings Tables
Exploration amp Production
	Three Months EndedDecember 31
(in thousands except per share amounts)		2018		2017		Variance			2018		2017		Variance
Net Income		$ 38214		$ 106698		$ (68484)			$ 044		$ 124		$ (1)
Remeasurement of accumulated deferred taxes under 2017 Tax Reform		$ (990)		$ (77300)		$ 76310			$ (090)		$ (090)		$ - 0
Unrealized (gain) loss on hedge ineffectiveness (EampP)		$ (6505)		$ 433		$ (6938)			$ 001
Tax impact of unrealized (gain) loss on hedge ineffectiveness		$ 1366		$ (106)		$ 1472
Adjusted Operating Results		$ 32085		$ 29725		$ 2360			$ (046)		$ 034		$ (1)
Adjusted EBITDA		$ 89896		$ 80220		$ 9676
Pipeline amp Storage		$ 000s					$ per diluted share
	Three Months EndedDecember 31
(in thousands except per share amounts)		2018		2017		Variance			2017		2017		Variance
Net Income		$ 25102		$ 38462		$ (13360)			$ 045		$ 045		$ - 0
Remeasurement of accumulated deferred taxes under 2017 Tax Reform		$ - 0		$ (14100)		$ 14100			$ (016)		$ (016)		$ - 0
Adjusted Operating Results		$ 25102		$ 24362		$ 740			$ 029		$ 029		$ - 0
Adjusted EBITDA		$ 47824		$ 50417		$ (2593)
Gathering
	Three Months EndedDecember 31					$ per diluted share
(in thousands except per share amounts)		2018		2017		Variance			2017		2017		Variance
Net Income		$ 14183		$ 45400		$ (31217)			$ 053		$ 053		$ - 0
Remeasurement of accumulated deferred taxes under 2017 Tax Reform		$ (500)		$ (34900)		$ 34400			$ (040)		$ (040)		$ - 0
Adjusted Operating Results		$ 13683		$ 10500		$ 3183			$ 013		$ 013		$ - 0
Adjusted EBITDA		$ 25948		$ 20813		$ 5135
Utility
	Three Months EndedDecember 31					$ per diluted share
(in thousands except per share amounts)		2018		2017		Variance			2017		2017		Variance
Net Income		$ 25649		$ 20993		$ 4656			$ 026		$ 026		$ - 0
Remeasurement of accumulated deferred taxes under 2017 Tax Reform		$ - 0		$ - 0		$ - 0			$ (002)		$ (002)		$ - 0
Adjusted Operating Results		$ 25649		$ 20993		$ 4656			$ 024		$ 024		$ - 0
Adjusted EBITDA		$ 57569		$ 54150		$ 3419
Energy Marketing
	Three Months EndedDecember 31					$ per diluted share
(in thousands except per share amounts)		2017		2017		Variance			2017		2017		Variance
Net Income		$ (302)		$ 1046		$ (1348)			$ 001		$ 001		$ - 0
Revaluation of Accumulated Deferred Income Taxes		$ (198)		$ 200		$ (398)			$ - 0		$ - 0		$ - 0
Segment Operating Results		$ (500)		$ 1246		$ (1746)			$ 001		$ 001		$ - 0
Adjusted EBITDA		$ (721)		$ 1804		$ (2525)

ADJUSTED OPERATING RESULTS
		Three Months EndedDecember 31
(in thousands except per share amounts)			2018			2017			Var
Reported GAAP Earnings			$ 102660			$ 198654			$ (95994)
Items impacting comparability
Remeasurement of deferred income taxes under 2017 Tax Reform			(5000)			(111000)			106000
Unrealized (gain) loss on hedge ineffectiveness (EampP)			(6505)			433			(6938)
Tax impact of unrealized (gain) loss on hedge ineffectiveness			1366			(106)			1472
Unrealized loss on other investments (Corporate All Other)			6347			- 0			6347
Tax impact of unrealized loss on other investments			(1333)			- 0			(1333)
Adjusted Operating Results			$ 97535			$ 87981			$ 9554
Reported GAAP Earnings per share			$ 118			$ 230			$ (112)
Items impacting comparability
Remeasurement of deferred income taxes under 2017 Tax Reform			(006)			(129)			123
Unrealized (gain) loss on hedge ineffectiveness (EampP)			(008)			001			(009)
Tax impact of unrealized (gain) loss on hedge ineffectiveness			002			- 0			002
Unrealized loss on other investments (Corporate All Other)			007			- 0			007
Tax impact of unrealized loss on other investments			(002)			- 0			(002)
Rounding			001			- 0			001
Adjusted Operating Results per share			$ 112			$ 102			$ 010
weighted average shares			86708814			86325537
impact of remeasurement			(006)			(129)
unrealized gain hedging pre-tax			(008)			001
unrealized gain hedging - tax impact			002			(000)
unrealized loss ERP investments pre-tax			007			- 0
imrealized loss ERP investments - tax impact			(002)			- 0
adjusted op results			112			102

	Prospect		Reservoir		Locations Remainingto Be Drilled		Completed Lateral Length (ft)		EUR 1000 (Bcf)		Well Cost$M1000 ft		Internal Rate of Return (2)				Realized Price(1) Required for 15 IRR		Anticipated DeliveryMarkets
						EUR 1000 (Bcf)		$250Realized		$225Realized		$200Realized
EDA		Tract 100 amp GambleLycoming Co		Marcellus		45		4900		25		$1057		76		58		44		$153		Transco Leidy ampAtlantic Sunrise Southeast US(NYMEX+)
	DCNR 007Tioga Co		Utica		43		8300		20		$1045		49		36		22		$184		TGP 300
WDA		Clermont Rich Valley		Utica		120+		9000		17		$887		30		23		16		$197		TGP 300 Niagara Expansion Canada (Dawn) amp FM100Leidy South (Transco Zone 6)
	Core Areas		Marcellus		600+		8500		10 to 11		$643		26		19		14		$206
FY15Q3

	Natural Gas Volumes in thousand MMBtu Prices in $MMBtu
		Fiscal 2019			Fiscal 2020			Fiscal 2021			Fiscal 2022			Fiscal 2023
		Volume		AvgPrice		Volume		AvgPrice		Volume		AvgPrice		Volume		AvgPrice		Volume		AvgPrice
	NYMEX Swaps		60120		$293		18640		$304		4840		$301		-		-		-		-
	Dawn Swaps		5400		$300		7200		$300		600		$300		-		-		-		-
	Fixed Price Physical		51915		$268		45046		$234		41488		$222		40580		$223		40589		$223
	Total		117435		$282		70886		$259		46928		$231		40580		$223		40589		$223
	Crude Oil Volumes amp Prices in Bbl
		Fiscal 2019			Fiscal 2020			Fiscal 2021			Fiscal 2022			Fiscal 2023
		Volume		Avg		Volume		Avg		Volume		Avg		Volume		Avg		Volume		Avg
			Price			Price			Price			Price			Price
	Brent Swaps		558000		$6352		864000		$6351		576000		$6468		300000		$6007		-		-
	NYMEX Swaps		801000		$5342		324000		$5052		156000		$5100		156000		$5100		-		-
	Total		1359000		$5757		1188000		$5996		732000		$6161		456000		$5697		-		-

57

Appalachia Drilling Program Economics

(1) Net realized price reflects either (a) price received at the gathering system interconnect or (b) price received at delivery market net of firm transportation charges(2) Internal Rate of Return (IRR) is pre-tax and includes estimated well costs under current cost structure LOE and Gathering tariffs anticipated for each prospect

Large Marcellus and Utica Inventory Economic at ~$200MMBtu(1)

$250Realized

$225Realized

$200Realized

Tract 100 amp Gamble

Lycoming CoMarcellus 45 4900 25 $1057 76 58 44 $153

Transco Leidy ampAtlantic Sunrise

Southeast US(NYMEX+)

DCNR 007Tioga Co

Utica 43 8300 20 $1045 49 36 22 $184 TGP 300

Clermont Rich Valley

Utica 120+ 9000 17 $887 30 23 16 $197

Core Areas Marcellus 600+ 8500 10 to 11 $643 26 19 14 $206

TGP 300 Niagara

Expansion Canada (Dawn) amp

FM100Leidy South (Transco

Zone 6)

WDA

Realized Price(1)

Required for 15 IRR

Anticipated DeliveryMarkets

EDA

Prospect Reservoir

Locations Remaining

to Be Drilled

Completed Lateral

Length (ft)EUR 1000

(Bcf)

Internal Rate of Return (2)

Well Cost$M1000 ft

Appendix

Sheet1

58

Comparable GAAP Financial Measure Slides amp Reconciliations

This presentation contains certain non-GAAP financial measures For pages that contain non-GAAP financial measures pages containing themost directly comparable GAAP financial measures and reconciliations are provided in the slides that follow

The Company believes that its non-GAAP financial measures are useful to investors because they provide an alternative method for assessing theCompanyrsquos ongoing operating results and for comparing the Companyrsquos financial performance to other companies The Companyrsquos managementuses these non-GAAP financial measures for the same purpose and for planning and forecasting purposes The presentation of non-GAAPfinancial measures is not meant to be a substitute for financial measures prepared in accordance with GAAP

Management defines Adjusted Operating Results as reported GAAP earnings before items impacting comparability

The Companyrsquos earnings guidance range does not include the impact of certain items that impacted the comparability of earnings during the firstquarter including (1) the remeasurement of deferred income taxes resulting from the 2017 Tax Reform Act which reduced the Companyrsquos incometax expense and benefited consolidated earnings in the first quarter by $006 per share (2) the full year impact of the Exploration and Productionsegmentrsquos unrealized gain on hedging ineffectiveness which increased earnings by $006 per share in the first quarter ($32 million or $003 pershare of the unrealized gain relates to hedge contracts that will settle during the remaining nine months ending September 30 2019) and (3) theunrealized loss on other investments due to the change in an accounting rule which lowered earnings by $006 per share While the Companyexpects to record additional adjustments to one or more of these items during the remaining nine months ending September 30 2019 theamounts of these and other potential adjustments are not reasonably determinable at this time As such the Company is unable to provideearnings guidance other than on a non-GAAP basis

Management defines Adjusted EBITDA as reported GAAP earnings before the following items interest expense income taxes depreciationdepletion and amortization interest and other income impairments and other items reflected in operating income that impact comparability

Appendix

59

Non-GAAP Reconciliations ndash Adjusted EBITDA

Appendix

(1) Total Adjusted EBITDA for FY 2018 and the twelve months ended December 31 2018 include the reclassification of non-service pension costs from Operating and Maintenance Expense to Other Income (Deductions) as of October 1 2018 on the Companyrsquos Income Statement which on a consolidated basis were approximately $3264 million in FY 2018 and approximately $3257 million for the twelve months ended December 31 2018 This reclassification is not reflected in Total Adjusted EBITDA for FY 2015 FY 2016 or FY 2017

Reconciliation of Adjusted EBITDA to Consolidated Net Income($ Thousands)

Total Adjusted EBITDAExploration amp Production Adjusted EBITDA 418726$ 363438$ 361079$ 317706$ 327381$ Pipeline amp Storage Adjusted EBITDA 188042 199446 180328 183973 181380 Gathering Adjusted EBITDA 68881 78685 94380 91937 97072 Utility Adjusted EBITDA 164037 148683 151078 175555 178974 Energy Marketing Adjusted EBITDA 12237 6655 2080 1033 (1492) Corporate amp All Other Adjusted EBITDA (11900) (8238) (11805) (8735) (8145) Total Adjusted EBITDA 840023$ 788669$ 777140$ 761469$ 775170$

Total Adjusted EBITDA 840023$ 788669$ 777140$ 761469$ 775170$ Minus Interest Expense (99471) (121044) (119837) (114522) (112445) Plus Other Income (Deductions) 11961 14055 11156 (21177) (27276) Minus Income Tax Expense 319136 232549 (160682) 7494 (96692) Minus Depreciation Depletion amp Amortization (336158) (249417) (224195) (240961) (249386) Minus Impairment of Oil and Gas Properties (EampP) (1126257) (948307) - - - Plus Reversal of Stock-Based Compensation (all segments) 7776 - - - - Minus Unrealized Gain (Loss) on Hedge Ineffectiveness 3563 392 (100) (782) 6156 Minus Joint Development Agreement Professional Fees (EampP) - (7855) - - - Rounding - - - - - Consolidated Net Income (379427)$ (290958)$ 283482$ 391521$ 295527$

Consolidated Debt to Total Adjusted EBITDALong-Term Debt Net of Current Portion (End of Period) 2099000$ 2099000$ 2099000$ 2149000$ 2149000$ Current Portion of Long-Term Debt (End of Period) - - 300000 - - Notes Payable to Banks and Commercial Paper (End of Period) - - - - - Less Cash and Temporary Cash Investments (End of Period) (113596) (129972) (555530) (229606) (109754)

Total Net Debt (End of Period) 1985404$ 1969028$ 1843470$ 1919394$ 2039246$

Long-Term Debt Net of Current Portion (Start of Period) 1649000 2099000 2099000 2099000 2099000 Current Portion of Long-Term Debt (Start of Period) - - - 300000 - Notes Payable to Banks and Commercial Paper (Start of Period) 85600 - - - - Less Cash and Temporary Cash Investments (Start of Period) (36886) (113596) (129972) (555530) (166289)

Total Net Debt (Start of Period) 1697714$ 1985404$ 1969028$ 1843470$ 1932711$

Average Total Net Debt 1841559$ 1977216$ 1906249$ 1881432$ 1985979$

Average Total Net Debt to Total Adjusted EBITDA 219 x 251 x 245 x 247 x 256 x

12-MonthsEnded 123118FY 2015 FY 2016 FY 2017 FY 2018

(1)(1)

60

Non-GAAP Reconciliations ndash Adjusted EBITDA by Segment

Appendix

Reconciliation of Adjusted EBITDA to Net Income by Segment($ Thousands)

Exploration and Production SegmentReported GAAP Earnings $ 180632 $ 38214 $ 106698 $ 112148

Depreciation Depletion and Amortization 124274 34700 27425 131549Interest and Other Income (308) (278) (3) (584)Interest Expense 54288 13163 13374 54077Income Taxes (41962) 10602 (67707) 36347Unrealized (Gain) Loss of Hedge Ineffectiveness 782 (6505) 433 (6156)

Adjusted EBITDA $ 317706 $ 89896 $ 80221 $ 327382

Pipeline and Storage SegmentReported GAAP Earnings $ 97246 $ 25102 $ 38462 $ 83886

Depreciation Depletion and Amortization 43463 11114 10596 43981Interest and Other Income (5925) (1926) (1645) (6206)Interest Expense 31383 7286 7876 30793Income Taxes 17806 6248 (4872) 28926

Adjusted EBITDA $ 183973 $ 47824 $ 50417 $ 181380

Gathering SegmentReported GAAP Earnings $ 83519 $ 14183 $ 45400 $ 52302

Depreciation Depletion and Amortization 17313 4679 4088 17904Interest and Other Income (778) (43) (316) (505)Interest Expense 9560 2377 2340 9597Income Taxes (17677) 4752 (30699) 17774

Adjusted EBITDA $ 91937 $ 25948 $ 20813 $ 97072

FY19 FY18 12-MonthsFY 2018 FYTD FYTD Ended 123118

($ Thousands)

Utility SegmentReported GAAP Earnings $ 51217 $ 25649 $ 20993 $ 55873

Depreciation Depletion and Amortization 53253 13290 13325 53218Interest and Other Income 29074 6216 6691 28599Interest Expense 26753 5893 6837 25809Income Taxes 15258 6521 6304 15475

Adjusted EBITDA $ 175555 $ 57569 $ 54150 $ 178974

Energy Marketing SegmentReported GAAP Earnings $ 373 $ (302) $ 1046 $ (975)

Depreciation Depletion and Amortization 275 70 69 276Interest and Other Income (269) (45) (13) (301)Interest Expense 22 5 11 16Income Taxes 632 (449) 691 (508)

Adjusted EBITDA $ 1033 $ (721) $ 1804 $ (1492)

Corporate and All OtherReported GAAP Earnings $ (21466) $ (186) $ (13945) $ (7707)

Depreciation Depletion and Amortization 2383 402 327 2458Interest and Other Income (616) 5678 (1211) 6273Interest Expense (7484) (2212) (1849) (7847)Income Taxes 18449 (4765) 15005 (1321)

Adjusted EBITDA $ (8735) $ (1083) $ (1673) $ (8145)

FY19 FY18 12-MonthsFY 2018 FYTD FYTD Ended 123118

61

Non-GAAP Reconciliations ndash Adjusted Operating Results

Appendix

(in thousands except per share amounts) 2018 2017Reported GAAP Earnings 102660$ 198654$

Items impacting comparabilityRemeasurement of deferred income taxes under 2017 Tax Reform (5000) (111000) Unrealized (gain) loss on hedge ineffectiveness (EampP) (6505) 433 Tax impact of unrealized (gain) loss on hedge ineffectiveness 1366 (106) Unrealized loss on other investments (Corporate All Other) 6347 - Tax impact of unrealized loss on other investments (1333) -

Adjusted Operating Results 97535$ 87981$

Reported GAAP Earnings per share 118$ 230$ Items impacting comparability

Remeasurement of deferred income taxes under 2017 Tax Reform (006) (129) Unrealized (gain) loss on hedge ineffectiveness (EampP) (008) 001 Tax impact of unrealized (gain) loss on hedge ineffectiveness 002 - Unrealized loss on other investments (Corporate All Other) 007 - Tax impact of unrealized loss on other investments (002) - Rounding 001 -

Adjusted Operating Results per share 112$ 102$

Three Months EndedDecember 31

Fiscal Year Ended September 30 (in thousands except per share amounts) 2018 2017 Reported GAAP Earnings $ 391521 $ 283482

Items impacting comparability Remeasurement of deferred income taxes under 2017 Tax Reform (103484 ) mdash

Premium paid on early redemption of debt (EampP) 962 mdash Tax impact on premium paid on early redemption of debt (235 ) mdash

Adjusted Operating Results $ 288764 $ 283482 Reported GAAP Earnings per share $ 453 $ 330

Items impacting comparability Remeasurement of deferred income taxes under 2017 Tax Reform (120 ) mdash

Premium paid on early redemption of debt net of tax 001 mdash Adjusted Operating Results per share $ 334 $ 330

Adjusted Operating Results

Sheet2

Sheet1

62

Non-GAAP Reconciliations ndash Capital Expenditures

Appendix

Reconciliation of Segment Capital Expenditures to Consolidated Capital Expenditures ($ Thousands) FY 2019

FY 2014 FY 2015 FY 2016 FY 2017 FY 2018 ForecastCapital Expenditures

Exploration amp Production Capital Expenditures 602705$ 557313$ 256104$ 253057$ 380677$ $460000 - $495000Pipeline amp Storage Capital Expenditures 139821$ 230192$ 114250$ 95336$ 92832$ $120000 - $150000Gathering Segment Capital Expenditures 137799$ 118166$ 54293$ 32645$ 61728$ $55000 - $65000Utility Capital Expenditures 88810$ 94371$ 98007$ 80867$ 85648$ $90000 - $100000Energy Marketing Corporate amp All Other Capital Expenditures 772$ 467$ 397$ 212$ 222$ Eliminations - -$ -$ -$ (20505)$ Total Capital Expenditures from Continuing Operations 969907$ 1000509$ 523051$ 462117$ 600602$ $725000 - $810000

Plus (Minus) Accrued Capital Expenditures

Exploration amp Production FY 2018 Accrued Capital Expenditures (51343)$ Exploration amp Production FY 2017 Accrued Capital Expenditures (36465)$ 36465$ Exploration amp Production FY 2016 Accrued Capital Expenditures - - (25215) 25215 Exploration amp Production FY 2015 Accrued Capital Expenditures - (46173) 46173 - Exploration amp Production FY 2014 Accrued Capital Expenditures (80108) 80108 - - Exploration amp Production FY 2013 Accrued Capital Expenditures 58478 - - - Exploration amp Production FY 2012 Accrued Capital Expenditures - - - - Pipeline amp Storage FY 2018 Accrued Capital Expenditures (21861)$ Pipeline amp Storage FY 2017 Accrued Capital Expenditures (25077) 25077$ Pipeline amp Storage FY 2016 Accrued Capital Expenditures - - (18661) 18661 Pipeline amp Storage FY 2015 Accrued Capital Expenditures - (33925) 33925 - Pipeline amp Storage FY 2014 Accrued Capital Expenditures (28122) 28122 - - Pipeline amp Storage FY 2013 Accrued Capital Expenditures 5633 - - - Pipeline amp Storage FY 2012 Accrued Capital Expenditures - - - - Gathering FY 2018 Accrued Capital Expenditures (6084)$ Gathering FY 2017 Accrued Capital Expenditures (3925) 3925$ Gathering FY 2016 Accrued Capital Expenditures - - (5355) 5355 Gathering FY 2015 Accrued Capital Expenditures - (22416) 22416 - Gathering FY 2014 Accrued Capital Expenditures (20084) 20084 - - Gathering FY 2013 Accrued Capital Expenditures 6700 - - - Gathering FY 2012 Accrued Capital Expenditures - - - - Utility FY 2018 Accrued Capital Expenditures (9525)$ Utility FY 2017 Accrued Capital Expenditures (6748) 6748$ Utility FY 2016 Accrued Capital Expenditures - - (11203) 11203 Utility FY 2015 Accrued Capital Expenditures - (16445) 16445 - Utility FY 2014 Accrued Capital Expenditures (8315) 8315 - - Utility FY 2013 Accrued Capital Expenditures 10328 - - - Utility FY 2012 Accrued Capital Expenditures - - - - Total Accrued Capital Expenditures (55490)$ 17670$ 58525$ (11782)$ (16597)$

Total Capital Expenditures per Statement of Cash Flows 914417$ 1018179$ 581576$ 450335$ 584004$ $725000 - $810000

63

Non-GAAP Reconciliations ndash EampP Operating Expenses

Appendix

Reconciliation of Exploration amp Production Segment Operating Expenses by Division($000s unless noted otherwise)

Appalachia West Coast(2) Total EampP Appalachia West Coast(2) Total EampP Appalachia West Coast(2) Total EampP Appalachia West Coast(2) Total EampP$ Mcfe $ Boe $ Mcfe $ Mcfe $ Boe $ Mcfe

Operating ExpensesGathering amp Transportation Expense (1) $95611 $46 $95657 $060 $002 $054 $92874 $502 $93376 $060 $016 $054Other Lease Operating Expense $14604 $52461 $67065 $009 $1789 $038 $16625 $55990 $72615 $011 $1731 $042Lease Operating and Transportation Expense $110215 $52507 $162721 $069 $1791 $091 $109499 $56492 $165991 $071 $1746 $096

General amp Administrative Expense $60596 $034 $58734 $034

All Other Operating and Maintenance Expense $11077 $006 $13469 $008Property Franchise and Other Taxes $14400 $008 $15426 $009Total Taxes amp Other $25477 $014 $28895 $017

Depreciation Depletion amp Amortization $124274 $070 $112565 $065

ProductionGas Production (MMcf) 160499 2407 162906 154093 2995 157088 Oil Production (MBbl) 4 2531 2535 4 2736 2740

Total Production (Mmcfe) 160523 17592 178114 154117 19411 173528 Total Production (Mboe) 26754 2932 29686 25686 3235 28921

(1) Gathering and Transportation expense is net of any payments received from JDA partner for the partners share of gathering cost(2) Seneca West Coast division includes Seneca corporate and eliminations

Twelve Months Ended September 30 2018

Twelve Months Ended September 30 2017

64

Non-GAAP Reconciliations ndash Adjusted Operation amp Maintenance Expense

Appendix

Reconciliation of Adjusted Operation and Maintenance Expense to Operation and Maintenance Expense By Segment ($ Thousands)

Exploration and Production SegmentOperation and Maintenance

General and Administrative Expense $ 59425 $ 15198 $ 13602 $ 61021Lease Operating and Transportation Expense 162721 42562 39647 165636All Other Operation and Maintenance Expense 11077 2353 2535 10895

Operation and Maintenance Expense $ 233223 60113 55784 237552Plus Non-Service Pension Costs 1171 4 293 882

Adjusted Operation and Maintenance Expense $ 234394 $ 60117 $ 56077 $ 238434

Pipeline and Storage SegmentOperation and Maintenance Expense $ 86876 $ 21633 $ 17672 $ 90837

Plus Non-Service Pension Costs (1420) (467) (356) (1531)Adjusted Operation and Maintenance Expense $ 85456 $ 21166 $ 17316 $ 89306

Gathering SegmentOperation and Maintenance Expense $ 15862 $ 3711 $ 2984 $ 16589

Plus Non-Service Pension Cots 328 82 82 328Adjusted Operation and Maintenance Expense $ 16190 $ 3793 $ 3066 $ 16917

Utility SegmentOperation and Maintenance Expense $ 165857 $ 43155 $ 43317 $ 165695

Plus Non-Service Pension Costs 31400 6928 7165 31163Adjusted Operation and Maintenance Expense $ 197257 $ 50083 $ 50482 $ 196858

Energy Marketing SegmentOperation and Maintenance Expense $ 6057 $ 1617 $ 1513 $ 6161

Plus Non-Service Pension Costs 497 123 124 496Adjusted Operation and Maintenance Expense $ 6554 $ 1740 $ 1637 $ 6657

Corporate and All Other Operation and Maintenance Expense $ 17003 $ 3058 $ 3721 $ 16340

Plus Non-Service Pension Costs 664 737 167 1234Adjusted Operation and Maintenance Expense $ 17667 $ 3795 $ 3888 $ 17574

Intersegment Eliminations $ (115112) $ (31643) $ (25517) $ (121238)

ConsolidatedOperation and Maintenance Expense $ 409766 $ 101644 $ 99474 $ 411936

Plus Non-Service Pension Costs 32640 7407 7475 32572Adjusted Operation and Maintenance Expense $ 442406 $ 109051 $ 106949 $ 444508

FY19 FY18 12-MonthsFY 2018 FYTD FYTD Ended 123118

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			Q1			Q1
			FY 2019			FY 2018
	Net Gain (Loss) on Hedge Ineffectiveness			$ 6504854			$ (433000)
	Federal Statutory Tax Rate			210			245
	Tax Benefit (Expense)			$ 1366019			$ (106085)
	After-tax Impact			$ 5138835			$ (326915)
	Net Gain (Loss) on ERP TopHat Investments			$ 6346969			$ - 0
	Federal Statutory Tax Rate			210			245
	Tax Benefit (Expense)			$ 1332863			$ - 0
	After-tax Impact			$ 5014106			$ - 0

Nationl Fuel Gas Company
Q1 - FY 2019
Segment Discussion Earnings Tables
Exploration amp Production
	Three Months EndedDecember 31
(in thousands except per share amounts)		2018		2017		Variance			2018		2017		Variance
Net Income		$ 38214		$ 106698		$ (68484)			$ 044		$ 124		$ (1)
Remeasurement of accumulated deferred taxes under 2017 Tax Reform		$ (990)		$ (77300)		$ 76310			$ (090)		$ (090)		$ - 0
Unrealized (gain) loss on hedge ineffectiveness (EampP)		$ (6505)		$ 433		$ (6938)			$ 001
Tax impact of unrealized (gain) loss on hedge ineffectiveness		$ 1366		$ (106)		$ 1472
Adjusted Operating Results		$ 32085		$ 29725		$ 2360			$ (046)		$ 034		$ (1)
Adjusted EBITDA		$ 89896		$ 80220		$ 9676
Pipeline amp Storage		$ 000s					$ per diluted share
	Three Months EndedDecember 31
(in thousands except per share amounts)		2018		2017		Variance			2017		2017		Variance
Net Income		$ 25102		$ 38462		$ (13360)			$ 045		$ 045		$ - 0
Remeasurement of accumulated deferred taxes under 2017 Tax Reform		$ - 0		$ (14100)		$ 14100			$ (016)		$ (016)		$ - 0
Adjusted Operating Results		$ 25102		$ 24362		$ 740			$ 029		$ 029		$ - 0
Adjusted EBITDA		$ 47824		$ 50417		$ (2593)
Gathering
	Three Months EndedDecember 31					$ per diluted share
(in thousands except per share amounts)		2018		2017		Variance			2017		2017		Variance
Net Income		$ 14183		$ 45400		$ (31217)			$ 053		$ 053		$ - 0
Remeasurement of accumulated deferred taxes under 2017 Tax Reform		$ (500)		$ (34900)		$ 34400			$ (040)		$ (040)		$ - 0
Adjusted Operating Results		$ 13683		$ 10500		$ 3183			$ 013		$ 013		$ - 0
Adjusted EBITDA		$ 25948		$ 20813		$ 5135
Utility
	Three Months EndedDecember 31					$ per diluted share
(in thousands except per share amounts)		2018		2017		Variance			2017		2017		Variance
Net Income		$ 25649		$ 20993		$ 4656			$ 026		$ 026		$ - 0
Remeasurement of accumulated deferred taxes under 2017 Tax Reform		$ - 0		$ - 0		$ - 0			$ (002)		$ (002)		$ - 0
Adjusted Operating Results		$ 25649		$ 20993		$ 4656			$ 024		$ 024		$ - 0
Adjusted EBITDA		$ 57569		$ 54150		$ 3419
Energy Marketing
	Three Months EndedDecember 31					$ per diluted share
(in thousands except per share amounts)		2017		2017		Variance			2017		2017		Variance
Net Income		$ (302)		$ 1046		$ (1348)			$ 001		$ 001		$ - 0
Revaluation of Accumulated Deferred Income Taxes		$ (198)		$ 200		$ (398)			$ - 0		$ - 0		$ - 0
Segment Operating Results		$ (500)		$ 1246		$ (1746)			$ 001		$ 001		$ - 0
Adjusted EBITDA		$ (721)		$ 1804		$ (2525)

ADJUSTED OPERATING RESULTS
		Three Months EndedDecember 31
(in thousands except per share amounts)			2018			2017			Var
Reported GAAP Earnings			$ 102660			$ 198654			$ (95994)
Items impacting comparability
Remeasurement of deferred income taxes under 2017 Tax Reform			(5000)			(111000)			106000
Unrealized (gain) loss on hedge ineffectiveness (EampP)			(6505)			433			(6938)
Tax impact of unrealized (gain) loss on hedge ineffectiveness			1366			(106)			1472
Unrealized loss on other investments (Corporate All Other)			6347			- 0			6347
Tax impact of unrealized loss on other investments			(1333)			- 0			(1333)
Adjusted Operating Results			$ 97535			$ 87981			$ 9554
Reported GAAP Earnings per share			$ 118			$ 230			$ (112)
Items impacting comparability
Remeasurement of deferred income taxes under 2017 Tax Reform			(006)			(129)			123
Unrealized (gain) loss on hedge ineffectiveness (EampP)			(008)			001			(009)
Tax impact of unrealized (gain) loss on hedge ineffectiveness			002			- 0			002
Unrealized loss on other investments (Corporate All Other)			007			- 0			007
Tax impact of unrealized loss on other investments			(002)			- 0			(002)
Rounding			001			- 0			001
Adjusted Operating Results per share			$ 112			$ 102			$ 010
weighted average shares			86708814			86325537
impact of remeasurement			(006)			(129)
unrealized gain hedging pre-tax			(008)			001
unrealized gain hedging - tax impact			002			(000)
unrealized loss ERP investments pre-tax			007			- 0
imrealized loss ERP investments - tax impact			(002)			- 0
adjusted op results			112			102

	Prospect		Reservoir		Locations Remainingto Be Drilled		Completed Lateral Length (ft)		EUR 1000 (Bcf)		Well Cost$M1000 ft		Internal Rate of Return (2)				Realized Price(1) Required for 15 IRR		Anticipated DeliveryMarkets
						EUR 1000 (Bcf)		$250Realized		$225Realized		$200Realized
EDA		Tract 100 amp GambleLycoming Co		Marcellus		45		4900		25		$1057		76		58		44		$153		Transco Leidy ampAtlantic Sunrise Southeast US(NYMEX+)
	DCNR 007Tioga Co		Utica		43		8300		20		$1045		49		36		22		$184		TGP 300
WDA		Clermont Rich Valley		Utica		120+		9000		17		$887		30		23		16		$197		TGP 300 Niagara Expansion Canada (Dawn) amp FM100Leidy South (Transco Zone 6)
	Core Areas		Marcellus		600+		8500		10 to 11		$643		26		19		14		$206
FY15Q3

58

Comparable GAAP Financial Measure Slides amp Reconciliations

This presentation contains certain non-GAAP financial measures For pages that contain non-GAAP financial measures pages containing themost directly comparable GAAP financial measures and reconciliations are provided in the slides that follow

The Company believes that its non-GAAP financial measures are useful to investors because they provide an alternative method for assessing theCompanyrsquos ongoing operating results and for comparing the Companyrsquos financial performance to other companies The Companyrsquos managementuses these non-GAAP financial measures for the same purpose and for planning and forecasting purposes The presentation of non-GAAPfinancial measures is not meant to be a substitute for financial measures prepared in accordance with GAAP

Management defines Adjusted Operating Results as reported GAAP earnings before items impacting comparability

The Companyrsquos earnings guidance range does not include the impact of certain items that impacted the comparability of earnings during the firstquarter including (1) the remeasurement of deferred income taxes resulting from the 2017 Tax Reform Act which reduced the Companyrsquos incometax expense and benefited consolidated earnings in the first quarter by $006 per share (2) the full year impact of the Exploration and Productionsegmentrsquos unrealized gain on hedging ineffectiveness which increased earnings by $006 per share in the first quarter ($32 million or $003 pershare of the unrealized gain relates to hedge contracts that will settle during the remaining nine months ending September 30 2019) and (3) theunrealized loss on other investments due to the change in an accounting rule which lowered earnings by $006 per share While the Companyexpects to record additional adjustments to one or more of these items during the remaining nine months ending September 30 2019 theamounts of these and other potential adjustments are not reasonably determinable at this time As such the Company is unable to provideearnings guidance other than on a non-GAAP basis

Management defines Adjusted EBITDA as reported GAAP earnings before the following items interest expense income taxes depreciationdepletion and amortization interest and other income impairments and other items reflected in operating income that impact comparability

Appendix

59

Non-GAAP Reconciliations ndash Adjusted EBITDA

Appendix

(1) Total Adjusted EBITDA for FY 2018 and the twelve months ended December 31 2018 include the reclassification of non-service pension costs from Operating and Maintenance Expense to Other Income (Deductions) as of October 1 2018 on the Companyrsquos Income Statement which on a consolidated basis were approximately $3264 million in FY 2018 and approximately $3257 million for the twelve months ended December 31 2018 This reclassification is not reflected in Total Adjusted EBITDA for FY 2015 FY 2016 or FY 2017

Reconciliation of Adjusted EBITDA to Consolidated Net Income($ Thousands)

Total Adjusted EBITDAExploration amp Production Adjusted EBITDA 418726$ 363438$ 361079$ 317706$ 327381$ Pipeline amp Storage Adjusted EBITDA 188042 199446 180328 183973 181380 Gathering Adjusted EBITDA 68881 78685 94380 91937 97072 Utility Adjusted EBITDA 164037 148683 151078 175555 178974 Energy Marketing Adjusted EBITDA 12237 6655 2080 1033 (1492) Corporate amp All Other Adjusted EBITDA (11900) (8238) (11805) (8735) (8145) Total Adjusted EBITDA 840023$ 788669$ 777140$ 761469$ 775170$

Total Adjusted EBITDA 840023$ 788669$ 777140$ 761469$ 775170$ Minus Interest Expense (99471) (121044) (119837) (114522) (112445) Plus Other Income (Deductions) 11961 14055 11156 (21177) (27276) Minus Income Tax Expense 319136 232549 (160682) 7494 (96692) Minus Depreciation Depletion amp Amortization (336158) (249417) (224195) (240961) (249386) Minus Impairment of Oil and Gas Properties (EampP) (1126257) (948307) - - - Plus Reversal of Stock-Based Compensation (all segments) 7776 - - - - Minus Unrealized Gain (Loss) on Hedge Ineffectiveness 3563 392 (100) (782) 6156 Minus Joint Development Agreement Professional Fees (EampP) - (7855) - - - Rounding - - - - - Consolidated Net Income (379427)$ (290958)$ 283482$ 391521$ 295527$

Consolidated Debt to Total Adjusted EBITDALong-Term Debt Net of Current Portion (End of Period) 2099000$ 2099000$ 2099000$ 2149000$ 2149000$ Current Portion of Long-Term Debt (End of Period) - - 300000 - - Notes Payable to Banks and Commercial Paper (End of Period) - - - - - Less Cash and Temporary Cash Investments (End of Period) (113596) (129972) (555530) (229606) (109754)

Total Net Debt (End of Period) 1985404$ 1969028$ 1843470$ 1919394$ 2039246$

Long-Term Debt Net of Current Portion (Start of Period) 1649000 2099000 2099000 2099000 2099000 Current Portion of Long-Term Debt (Start of Period) - - - 300000 - Notes Payable to Banks and Commercial Paper (Start of Period) 85600 - - - - Less Cash and Temporary Cash Investments (Start of Period) (36886) (113596) (129972) (555530) (166289)

Total Net Debt (Start of Period) 1697714$ 1985404$ 1969028$ 1843470$ 1932711$

Average Total Net Debt 1841559$ 1977216$ 1906249$ 1881432$ 1985979$

Average Total Net Debt to Total Adjusted EBITDA 219 x 251 x 245 x 247 x 256 x

12-MonthsEnded 123118FY 2015 FY 2016 FY 2017 FY 2018

(1)(1)

60

Non-GAAP Reconciliations ndash Adjusted EBITDA by Segment

Appendix

Reconciliation of Adjusted EBITDA to Net Income by Segment($ Thousands)

Exploration and Production SegmentReported GAAP Earnings $ 180632 $ 38214 $ 106698 $ 112148

Depreciation Depletion and Amortization 124274 34700 27425 131549Interest and Other Income (308) (278) (3) (584)Interest Expense 54288 13163 13374 54077Income Taxes (41962) 10602 (67707) 36347Unrealized (Gain) Loss of Hedge Ineffectiveness 782 (6505) 433 (6156)

Adjusted EBITDA $ 317706 $ 89896 $ 80221 $ 327382

Pipeline and Storage SegmentReported GAAP Earnings $ 97246 $ 25102 $ 38462 $ 83886

Depreciation Depletion and Amortization 43463 11114 10596 43981Interest and Other Income (5925) (1926) (1645) (6206)Interest Expense 31383 7286 7876 30793Income Taxes 17806 6248 (4872) 28926

Adjusted EBITDA $ 183973 $ 47824 $ 50417 $ 181380

Gathering SegmentReported GAAP Earnings $ 83519 $ 14183 $ 45400 $ 52302

Depreciation Depletion and Amortization 17313 4679 4088 17904Interest and Other Income (778) (43) (316) (505)Interest Expense 9560 2377 2340 9597Income Taxes (17677) 4752 (30699) 17774

Adjusted EBITDA $ 91937 $ 25948 $ 20813 $ 97072

FY19 FY18 12-MonthsFY 2018 FYTD FYTD Ended 123118

($ Thousands)

Utility SegmentReported GAAP Earnings $ 51217 $ 25649 $ 20993 $ 55873

Depreciation Depletion and Amortization 53253 13290 13325 53218Interest and Other Income 29074 6216 6691 28599Interest Expense 26753 5893 6837 25809Income Taxes 15258 6521 6304 15475

Adjusted EBITDA $ 175555 $ 57569 $ 54150 $ 178974

Energy Marketing SegmentReported GAAP Earnings $ 373 $ (302) $ 1046 $ (975)

Depreciation Depletion and Amortization 275 70 69 276Interest and Other Income (269) (45) (13) (301)Interest Expense 22 5 11 16Income Taxes 632 (449) 691 (508)

Adjusted EBITDA $ 1033 $ (721) $ 1804 $ (1492)

Corporate and All OtherReported GAAP Earnings $ (21466) $ (186) $ (13945) $ (7707)

Depreciation Depletion and Amortization 2383 402 327 2458Interest and Other Income (616) 5678 (1211) 6273Interest Expense (7484) (2212) (1849) (7847)Income Taxes 18449 (4765) 15005 (1321)

Adjusted EBITDA $ (8735) $ (1083) $ (1673) $ (8145)

FY19 FY18 12-MonthsFY 2018 FYTD FYTD Ended 123118

61

Non-GAAP Reconciliations ndash Adjusted Operating Results

Appendix

(in thousands except per share amounts) 2018 2017Reported GAAP Earnings 102660$ 198654$

Items impacting comparabilityRemeasurement of deferred income taxes under 2017 Tax Reform (5000) (111000) Unrealized (gain) loss on hedge ineffectiveness (EampP) (6505) 433 Tax impact of unrealized (gain) loss on hedge ineffectiveness 1366 (106) Unrealized loss on other investments (Corporate All Other) 6347 - Tax impact of unrealized loss on other investments (1333) -

Adjusted Operating Results 97535$ 87981$

Reported GAAP Earnings per share 118$ 230$ Items impacting comparability

Remeasurement of deferred income taxes under 2017 Tax Reform (006) (129) Unrealized (gain) loss on hedge ineffectiveness (EampP) (008) 001 Tax impact of unrealized (gain) loss on hedge ineffectiveness 002 - Unrealized loss on other investments (Corporate All Other) 007 - Tax impact of unrealized loss on other investments (002) - Rounding 001 -

Adjusted Operating Results per share 112$ 102$

Three Months EndedDecember 31

Fiscal Year Ended September 30 (in thousands except per share amounts) 2018 2017 Reported GAAP Earnings $ 391521 $ 283482

Items impacting comparability Remeasurement of deferred income taxes under 2017 Tax Reform (103484 ) mdash

Premium paid on early redemption of debt (EampP) 962 mdash Tax impact on premium paid on early redemption of debt (235 ) mdash

Adjusted Operating Results $ 288764 $ 283482 Reported GAAP Earnings per share $ 453 $ 330

Items impacting comparability Remeasurement of deferred income taxes under 2017 Tax Reform (120 ) mdash

Premium paid on early redemption of debt net of tax 001 mdash Adjusted Operating Results per share $ 334 $ 330

Adjusted Operating Results

Sheet2

Sheet1

62

Non-GAAP Reconciliations ndash Capital Expenditures

Appendix

Reconciliation of Segment Capital Expenditures to Consolidated Capital Expenditures ($ Thousands) FY 2019

FY 2014 FY 2015 FY 2016 FY 2017 FY 2018 ForecastCapital Expenditures

Exploration amp Production Capital Expenditures 602705$ 557313$ 256104$ 253057$ 380677$ $460000 - $495000Pipeline amp Storage Capital Expenditures 139821$ 230192$ 114250$ 95336$ 92832$ $120000 - $150000Gathering Segment Capital Expenditures 137799$ 118166$ 54293$ 32645$ 61728$ $55000 - $65000Utility Capital Expenditures 88810$ 94371$ 98007$ 80867$ 85648$ $90000 - $100000Energy Marketing Corporate amp All Other Capital Expenditures 772$ 467$ 397$ 212$ 222$ Eliminations - -$ -$ -$ (20505)$ Total Capital Expenditures from Continuing Operations 969907$ 1000509$ 523051$ 462117$ 600602$ $725000 - $810000

Plus (Minus) Accrued Capital Expenditures

Exploration amp Production FY 2018 Accrued Capital Expenditures (51343)$ Exploration amp Production FY 2017 Accrued Capital Expenditures (36465)$ 36465$ Exploration amp Production FY 2016 Accrued Capital Expenditures - - (25215) 25215 Exploration amp Production FY 2015 Accrued Capital Expenditures - (46173) 46173 - Exploration amp Production FY 2014 Accrued Capital Expenditures (80108) 80108 - - Exploration amp Production FY 2013 Accrued Capital Expenditures 58478 - - - Exploration amp Production FY 2012 Accrued Capital Expenditures - - - - Pipeline amp Storage FY 2018 Accrued Capital Expenditures (21861)$ Pipeline amp Storage FY 2017 Accrued Capital Expenditures (25077) 25077$ Pipeline amp Storage FY 2016 Accrued Capital Expenditures - - (18661) 18661 Pipeline amp Storage FY 2015 Accrued Capital Expenditures - (33925) 33925 - Pipeline amp Storage FY 2014 Accrued Capital Expenditures (28122) 28122 - - Pipeline amp Storage FY 2013 Accrued Capital Expenditures 5633 - - - Pipeline amp Storage FY 2012 Accrued Capital Expenditures - - - - Gathering FY 2018 Accrued Capital Expenditures (6084)$ Gathering FY 2017 Accrued Capital Expenditures (3925) 3925$ Gathering FY 2016 Accrued Capital Expenditures - - (5355) 5355 Gathering FY 2015 Accrued Capital Expenditures - (22416) 22416 - Gathering FY 2014 Accrued Capital Expenditures (20084) 20084 - - Gathering FY 2013 Accrued Capital Expenditures 6700 - - - Gathering FY 2012 Accrued Capital Expenditures - - - - Utility FY 2018 Accrued Capital Expenditures (9525)$ Utility FY 2017 Accrued Capital Expenditures (6748) 6748$ Utility FY 2016 Accrued Capital Expenditures - - (11203) 11203 Utility FY 2015 Accrued Capital Expenditures - (16445) 16445 - Utility FY 2014 Accrued Capital Expenditures (8315) 8315 - - Utility FY 2013 Accrued Capital Expenditures 10328 - - - Utility FY 2012 Accrued Capital Expenditures - - - - Total Accrued Capital Expenditures (55490)$ 17670$ 58525$ (11782)$ (16597)$

Total Capital Expenditures per Statement of Cash Flows 914417$ 1018179$ 581576$ 450335$ 584004$ $725000 - $810000

63

Non-GAAP Reconciliations ndash EampP Operating Expenses

Appendix

Reconciliation of Exploration amp Production Segment Operating Expenses by Division($000s unless noted otherwise)

Appalachia West Coast(2) Total EampP Appalachia West Coast(2) Total EampP Appalachia West Coast(2) Total EampP Appalachia West Coast(2) Total EampP$ Mcfe $ Boe $ Mcfe $ Mcfe $ Boe $ Mcfe

Operating ExpensesGathering amp Transportation Expense (1) $95611 $46 $95657 $060 $002 $054 $92874 $502 $93376 $060 $016 $054Other Lease Operating Expense $14604 $52461 $67065 $009 $1789 $038 $16625 $55990 $72615 $011 $1731 $042Lease Operating and Transportation Expense $110215 $52507 $162721 $069 $1791 $091 $109499 $56492 $165991 $071 $1746 $096

General amp Administrative Expense $60596 $034 $58734 $034

All Other Operating and Maintenance Expense $11077 $006 $13469 $008Property Franchise and Other Taxes $14400 $008 $15426 $009Total Taxes amp Other $25477 $014 $28895 $017

Depreciation Depletion amp Amortization $124274 $070 $112565 $065

ProductionGas Production (MMcf) 160499 2407 162906 154093 2995 157088 Oil Production (MBbl) 4 2531 2535 4 2736 2740

Total Production (Mmcfe) 160523 17592 178114 154117 19411 173528 Total Production (Mboe) 26754 2932 29686 25686 3235 28921

(1) Gathering and Transportation expense is net of any payments received from JDA partner for the partners share of gathering cost(2) Seneca West Coast division includes Seneca corporate and eliminations

Twelve Months Ended September 30 2018

Twelve Months Ended September 30 2017

64

Non-GAAP Reconciliations ndash Adjusted Operation amp Maintenance Expense

Appendix

Reconciliation of Adjusted Operation and Maintenance Expense to Operation and Maintenance Expense By Segment ($ Thousands)

Exploration and Production SegmentOperation and Maintenance

General and Administrative Expense $ 59425 $ 15198 $ 13602 $ 61021Lease Operating and Transportation Expense 162721 42562 39647 165636All Other Operation and Maintenance Expense 11077 2353 2535 10895

Operation and Maintenance Expense $ 233223 60113 55784 237552Plus Non-Service Pension Costs 1171 4 293 882

Adjusted Operation and Maintenance Expense $ 234394 $ 60117 $ 56077 $ 238434

Pipeline and Storage SegmentOperation and Maintenance Expense $ 86876 $ 21633 $ 17672 $ 90837

Plus Non-Service Pension Costs (1420) (467) (356) (1531)Adjusted Operation and Maintenance Expense $ 85456 $ 21166 $ 17316 $ 89306

Gathering SegmentOperation and Maintenance Expense $ 15862 $ 3711 $ 2984 $ 16589

Plus Non-Service Pension Cots 328 82 82 328Adjusted Operation and Maintenance Expense $ 16190 $ 3793 $ 3066 $ 16917

Utility SegmentOperation and Maintenance Expense $ 165857 $ 43155 $ 43317 $ 165695

Plus Non-Service Pension Costs 31400 6928 7165 31163Adjusted Operation and Maintenance Expense $ 197257 $ 50083 $ 50482 $ 196858

Energy Marketing SegmentOperation and Maintenance Expense $ 6057 $ 1617 $ 1513 $ 6161

Plus Non-Service Pension Costs 497 123 124 496Adjusted Operation and Maintenance Expense $ 6554 $ 1740 $ 1637 $ 6657

Corporate and All Other Operation and Maintenance Expense $ 17003 $ 3058 $ 3721 $ 16340

Plus Non-Service Pension Costs 664 737 167 1234Adjusted Operation and Maintenance Expense $ 17667 $ 3795 $ 3888 $ 17574

Intersegment Eliminations $ (115112) $ (31643) $ (25517) $ (121238)

ConsolidatedOperation and Maintenance Expense $ 409766 $ 101644 $ 99474 $ 411936

Plus Non-Service Pension Costs 32640 7407 7475 32572Adjusted Operation and Maintenance Expense $ 442406 $ 109051 $ 106949 $ 444508

FY19 FY18 12-MonthsFY 2018 FYTD FYTD Ended 123118

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			Q1			Q1
			FY 2019			FY 2018
	Net Gain (Loss) on Hedge Ineffectiveness			$ 6504854			$ (433000)
	Federal Statutory Tax Rate			210			245
	Tax Benefit (Expense)			$ 1366019			$ (106085)
	After-tax Impact			$ 5138835			$ (326915)
	Net Gain (Loss) on ERP TopHat Investments			$ 6346969			$ - 0
	Federal Statutory Tax Rate			210			245
	Tax Benefit (Expense)			$ 1332863			$ - 0
	After-tax Impact			$ 5014106			$ - 0

Nationl Fuel Gas Company
Q1 - FY 2019
Segment Discussion Earnings Tables
Exploration amp Production
	Three Months EndedDecember 31
(in thousands except per share amounts)		2018		2017		Variance			2018		2017		Variance
Net Income		$ 38214		$ 106698		$ (68484)			$ 044		$ 124		$ (1)
Remeasurement of accumulated deferred taxes under 2017 Tax Reform		$ (990)		$ (77300)		$ 76310			$ (090)		$ (090)		$ - 0
Unrealized (gain) loss on hedge ineffectiveness (EampP)		$ (6505)		$ 433		$ (6938)			$ 001
Tax impact of unrealized (gain) loss on hedge ineffectiveness		$ 1366		$ (106)		$ 1472
Adjusted Operating Results		$ 32085		$ 29725		$ 2360			$ (046)		$ 034		$ (1)
Adjusted EBITDA		$ 89896		$ 80220		$ 9676
Pipeline amp Storage		$ 000s					$ per diluted share
	Three Months EndedDecember 31
(in thousands except per share amounts)		2018		2017		Variance			2017		2017		Variance
Net Income		$ 25102		$ 38462		$ (13360)			$ 045		$ 045		$ - 0
Remeasurement of accumulated deferred taxes under 2017 Tax Reform		$ - 0		$ (14100)		$ 14100			$ (016)		$ (016)		$ - 0
Adjusted Operating Results		$ 25102		$ 24362		$ 740			$ 029		$ 029		$ - 0
Adjusted EBITDA		$ 47824		$ 50417		$ (2593)
Gathering
	Three Months EndedDecember 31					$ per diluted share
(in thousands except per share amounts)		2018		2017		Variance			2017		2017		Variance
Net Income		$ 14183		$ 45400		$ (31217)			$ 053		$ 053		$ - 0
Remeasurement of accumulated deferred taxes under 2017 Tax Reform		$ (500)		$ (34900)		$ 34400			$ (040)		$ (040)		$ - 0
Adjusted Operating Results		$ 13683		$ 10500		$ 3183			$ 013		$ 013		$ - 0
Adjusted EBITDA		$ 25948		$ 20813		$ 5135
Utility
	Three Months EndedDecember 31					$ per diluted share
(in thousands except per share amounts)		2018		2017		Variance			2017		2017		Variance
Net Income		$ 25649		$ 20993		$ 4656			$ 026		$ 026		$ - 0
Remeasurement of accumulated deferred taxes under 2017 Tax Reform		$ - 0		$ - 0		$ - 0			$ (002)		$ (002)		$ - 0
Adjusted Operating Results		$ 25649		$ 20993		$ 4656			$ 024		$ 024		$ - 0
Adjusted EBITDA		$ 57569		$ 54150		$ 3419
Energy Marketing
	Three Months EndedDecember 31					$ per diluted share
(in thousands except per share amounts)		2017		2017		Variance			2017		2017		Variance
Net Income		$ (302)		$ 1046		$ (1348)			$ 001		$ 001		$ - 0
Revaluation of Accumulated Deferred Income Taxes		$ (198)		$ 200		$ (398)			$ - 0		$ - 0		$ - 0
Segment Operating Results		$ (500)		$ 1246		$ (1746)			$ 001		$ 001		$ - 0
Adjusted EBITDA		$ (721)		$ 1804		$ (2525)

ADJUSTED OPERATING RESULTS
		Three Months EndedDecember 31
(in thousands except per share amounts)			2018			2017			Var
Reported GAAP Earnings			$ 102660			$ 198654			$ (95994)
Items impacting comparability
Remeasurement of deferred income taxes under 2017 Tax Reform			(5000)			(111000)			106000
Unrealized (gain) loss on hedge ineffectiveness (EampP)			(6505)			433			(6938)
Tax impact of unrealized (gain) loss on hedge ineffectiveness			1366			(106)			1472
Unrealized loss on other investments (Corporate All Other)			6347			- 0			6347
Tax impact of unrealized loss on other investments			(1333)			- 0			(1333)
Adjusted Operating Results			$ 97535			$ 87981			$ 9554
Reported GAAP Earnings per share			$ 118			$ 230			$ (112)
Items impacting comparability
Remeasurement of deferred income taxes under 2017 Tax Reform			(006)			(129)			123
Unrealized (gain) loss on hedge ineffectiveness (EampP)			(008)			001			(009)
Tax impact of unrealized (gain) loss on hedge ineffectiveness			002			- 0			002
Unrealized loss on other investments (Corporate All Other)			007			- 0			007
Tax impact of unrealized loss on other investments			(002)			- 0			(002)
Rounding			001			- 0			001
Adjusted Operating Results per share			$ 112			$ 102			$ 010
weighted average shares			86708814			86325537
impact of remeasurement			(006)			(129)
unrealized gain hedging pre-tax			(008)			001
unrealized gain hedging - tax impact			002			(000)
unrealized loss ERP investments pre-tax			007			- 0
imrealized loss ERP investments - tax impact			(002)			- 0
adjusted op results			112			102

59

Non-GAAP Reconciliations ndash Adjusted EBITDA

Appendix

(1) Total Adjusted EBITDA for FY 2018 and the twelve months ended December 31 2018 include the reclassification of non-service pension costs from Operating and Maintenance Expense to Other Income (Deductions) as of October 1 2018 on the Companyrsquos Income Statement which on a consolidated basis were approximately $3264 million in FY 2018 and approximately $3257 million for the twelve months ended December 31 2018 This reclassification is not reflected in Total Adjusted EBITDA for FY 2015 FY 2016 or FY 2017

Reconciliation of Adjusted EBITDA to Consolidated Net Income($ Thousands)

Total Adjusted EBITDAExploration amp Production Adjusted EBITDA 418726$ 363438$ 361079$ 317706$ 327381$ Pipeline amp Storage Adjusted EBITDA 188042 199446 180328 183973 181380 Gathering Adjusted EBITDA 68881 78685 94380 91937 97072 Utility Adjusted EBITDA 164037 148683 151078 175555 178974 Energy Marketing Adjusted EBITDA 12237 6655 2080 1033 (1492) Corporate amp All Other Adjusted EBITDA (11900) (8238) (11805) (8735) (8145) Total Adjusted EBITDA 840023$ 788669$ 777140$ 761469$ 775170$

Total Adjusted EBITDA 840023$ 788669$ 777140$ 761469$ 775170$ Minus Interest Expense (99471) (121044) (119837) (114522) (112445) Plus Other Income (Deductions) 11961 14055 11156 (21177) (27276) Minus Income Tax Expense 319136 232549 (160682) 7494 (96692) Minus Depreciation Depletion amp Amortization (336158) (249417) (224195) (240961) (249386) Minus Impairment of Oil and Gas Properties (EampP) (1126257) (948307) - - - Plus Reversal of Stock-Based Compensation (all segments) 7776 - - - - Minus Unrealized Gain (Loss) on Hedge Ineffectiveness 3563 392 (100) (782) 6156 Minus Joint Development Agreement Professional Fees (EampP) - (7855) - - - Rounding - - - - - Consolidated Net Income (379427)$ (290958)$ 283482$ 391521$ 295527$

Consolidated Debt to Total Adjusted EBITDALong-Term Debt Net of Current Portion (End of Period) 2099000$ 2099000$ 2099000$ 2149000$ 2149000$ Current Portion of Long-Term Debt (End of Period) - - 300000 - - Notes Payable to Banks and Commercial Paper (End of Period) - - - - - Less Cash and Temporary Cash Investments (End of Period) (113596) (129972) (555530) (229606) (109754)

Total Net Debt (End of Period) 1985404$ 1969028$ 1843470$ 1919394$ 2039246$

Long-Term Debt Net of Current Portion (Start of Period) 1649000 2099000 2099000 2099000 2099000 Current Portion of Long-Term Debt (Start of Period) - - - 300000 - Notes Payable to Banks and Commercial Paper (Start of Period) 85600 - - - - Less Cash and Temporary Cash Investments (Start of Period) (36886) (113596) (129972) (555530) (166289)

Total Net Debt (Start of Period) 1697714$ 1985404$ 1969028$ 1843470$ 1932711$

Average Total Net Debt 1841559$ 1977216$ 1906249$ 1881432$ 1985979$

Average Total Net Debt to Total Adjusted EBITDA 219 x 251 x 245 x 247 x 256 x

12-MonthsEnded 123118FY 2015 FY 2016 FY 2017 FY 2018

(1)(1)

60

Non-GAAP Reconciliations ndash Adjusted EBITDA by Segment

Appendix

Reconciliation of Adjusted EBITDA to Net Income by Segment($ Thousands)

Exploration and Production SegmentReported GAAP Earnings $ 180632 $ 38214 $ 106698 $ 112148

Depreciation Depletion and Amortization 124274 34700 27425 131549Interest and Other Income (308) (278) (3) (584)Interest Expense 54288 13163 13374 54077Income Taxes (41962) 10602 (67707) 36347Unrealized (Gain) Loss of Hedge Ineffectiveness 782 (6505) 433 (6156)

Adjusted EBITDA $ 317706 $ 89896 $ 80221 $ 327382

Pipeline and Storage SegmentReported GAAP Earnings $ 97246 $ 25102 $ 38462 $ 83886

Depreciation Depletion and Amortization 43463 11114 10596 43981Interest and Other Income (5925) (1926) (1645) (6206)Interest Expense 31383 7286 7876 30793Income Taxes 17806 6248 (4872) 28926

Adjusted EBITDA $ 183973 $ 47824 $ 50417 $ 181380

Gathering SegmentReported GAAP Earnings $ 83519 $ 14183 $ 45400 $ 52302

Depreciation Depletion and Amortization 17313 4679 4088 17904Interest and Other Income (778) (43) (316) (505)Interest Expense 9560 2377 2340 9597Income Taxes (17677) 4752 (30699) 17774

Adjusted EBITDA $ 91937 $ 25948 $ 20813 $ 97072

FY19 FY18 12-MonthsFY 2018 FYTD FYTD Ended 123118

($ Thousands)

Utility SegmentReported GAAP Earnings $ 51217 $ 25649 $ 20993 $ 55873

Depreciation Depletion and Amortization 53253 13290 13325 53218Interest and Other Income 29074 6216 6691 28599Interest Expense 26753 5893 6837 25809Income Taxes 15258 6521 6304 15475

Adjusted EBITDA $ 175555 $ 57569 $ 54150 $ 178974

Energy Marketing SegmentReported GAAP Earnings $ 373 $ (302) $ 1046 $ (975)

Depreciation Depletion and Amortization 275 70 69 276Interest and Other Income (269) (45) (13) (301)Interest Expense 22 5 11 16Income Taxes 632 (449) 691 (508)

Adjusted EBITDA $ 1033 $ (721) $ 1804 $ (1492)

Corporate and All OtherReported GAAP Earnings $ (21466) $ (186) $ (13945) $ (7707)

Depreciation Depletion and Amortization 2383 402 327 2458Interest and Other Income (616) 5678 (1211) 6273Interest Expense (7484) (2212) (1849) (7847)Income Taxes 18449 (4765) 15005 (1321)

Adjusted EBITDA $ (8735) $ (1083) $ (1673) $ (8145)

FY19 FY18 12-MonthsFY 2018 FYTD FYTD Ended 123118

61

Non-GAAP Reconciliations ndash Adjusted Operating Results

Appendix

(in thousands except per share amounts) 2018 2017Reported GAAP Earnings 102660$ 198654$

Items impacting comparabilityRemeasurement of deferred income taxes under 2017 Tax Reform (5000) (111000) Unrealized (gain) loss on hedge ineffectiveness (EampP) (6505) 433 Tax impact of unrealized (gain) loss on hedge ineffectiveness 1366 (106) Unrealized loss on other investments (Corporate All Other) 6347 - Tax impact of unrealized loss on other investments (1333) -

Adjusted Operating Results 97535$ 87981$

Reported GAAP Earnings per share 118$ 230$ Items impacting comparability

Remeasurement of deferred income taxes under 2017 Tax Reform (006) (129) Unrealized (gain) loss on hedge ineffectiveness (EampP) (008) 001 Tax impact of unrealized (gain) loss on hedge ineffectiveness 002 - Unrealized loss on other investments (Corporate All Other) 007 - Tax impact of unrealized loss on other investments (002) - Rounding 001 -

Adjusted Operating Results per share 112$ 102$

Three Months EndedDecember 31

Fiscal Year Ended September 30 (in thousands except per share amounts) 2018 2017 Reported GAAP Earnings $ 391521 $ 283482

Items impacting comparability Remeasurement of deferred income taxes under 2017 Tax Reform (103484 ) mdash

Premium paid on early redemption of debt (EampP) 962 mdash Tax impact on premium paid on early redemption of debt (235 ) mdash

Adjusted Operating Results $ 288764 $ 283482 Reported GAAP Earnings per share $ 453 $ 330

Items impacting comparability Remeasurement of deferred income taxes under 2017 Tax Reform (120 ) mdash

Premium paid on early redemption of debt net of tax 001 mdash Adjusted Operating Results per share $ 334 $ 330

Adjusted Operating Results

Sheet2

Sheet1

62

Non-GAAP Reconciliations ndash Capital Expenditures

Appendix

Reconciliation of Segment Capital Expenditures to Consolidated Capital Expenditures ($ Thousands) FY 2019

FY 2014 FY 2015 FY 2016 FY 2017 FY 2018 ForecastCapital Expenditures

Exploration amp Production Capital Expenditures 602705$ 557313$ 256104$ 253057$ 380677$ $460000 - $495000Pipeline amp Storage Capital Expenditures 139821$ 230192$ 114250$ 95336$ 92832$ $120000 - $150000Gathering Segment Capital Expenditures 137799$ 118166$ 54293$ 32645$ 61728$ $55000 - $65000Utility Capital Expenditures 88810$ 94371$ 98007$ 80867$ 85648$ $90000 - $100000Energy Marketing Corporate amp All Other Capital Expenditures 772$ 467$ 397$ 212$ 222$ Eliminations - -$ -$ -$ (20505)$ Total Capital Expenditures from Continuing Operations 969907$ 1000509$ 523051$ 462117$ 600602$ $725000 - $810000

Plus (Minus) Accrued Capital Expenditures

Exploration amp Production FY 2018 Accrued Capital Expenditures (51343)$ Exploration amp Production FY 2017 Accrued Capital Expenditures (36465)$ 36465$ Exploration amp Production FY 2016 Accrued Capital Expenditures - - (25215) 25215 Exploration amp Production FY 2015 Accrued Capital Expenditures - (46173) 46173 - Exploration amp Production FY 2014 Accrued Capital Expenditures (80108) 80108 - - Exploration amp Production FY 2013 Accrued Capital Expenditures 58478 - - - Exploration amp Production FY 2012 Accrued Capital Expenditures - - - - Pipeline amp Storage FY 2018 Accrued Capital Expenditures (21861)$ Pipeline amp Storage FY 2017 Accrued Capital Expenditures (25077) 25077$ Pipeline amp Storage FY 2016 Accrued Capital Expenditures - - (18661) 18661 Pipeline amp Storage FY 2015 Accrued Capital Expenditures - (33925) 33925 - Pipeline amp Storage FY 2014 Accrued Capital Expenditures (28122) 28122 - - Pipeline amp Storage FY 2013 Accrued Capital Expenditures 5633 - - - Pipeline amp Storage FY 2012 Accrued Capital Expenditures - - - - Gathering FY 2018 Accrued Capital Expenditures (6084)$ Gathering FY 2017 Accrued Capital Expenditures (3925) 3925$ Gathering FY 2016 Accrued Capital Expenditures - - (5355) 5355 Gathering FY 2015 Accrued Capital Expenditures - (22416) 22416 - Gathering FY 2014 Accrued Capital Expenditures (20084) 20084 - - Gathering FY 2013 Accrued Capital Expenditures 6700 - - - Gathering FY 2012 Accrued Capital Expenditures - - - - Utility FY 2018 Accrued Capital Expenditures (9525)$ Utility FY 2017 Accrued Capital Expenditures (6748) 6748$ Utility FY 2016 Accrued Capital Expenditures - - (11203) 11203 Utility FY 2015 Accrued Capital Expenditures - (16445) 16445 - Utility FY 2014 Accrued Capital Expenditures (8315) 8315 - - Utility FY 2013 Accrued Capital Expenditures 10328 - - - Utility FY 2012 Accrued Capital Expenditures - - - - Total Accrued Capital Expenditures (55490)$ 17670$ 58525$ (11782)$ (16597)$

Total Capital Expenditures per Statement of Cash Flows 914417$ 1018179$ 581576$ 450335$ 584004$ $725000 - $810000

63

Non-GAAP Reconciliations ndash EampP Operating Expenses

Appendix

Reconciliation of Exploration amp Production Segment Operating Expenses by Division($000s unless noted otherwise)

Appalachia West Coast(2) Total EampP Appalachia West Coast(2) Total EampP Appalachia West Coast(2) Total EampP Appalachia West Coast(2) Total EampP$ Mcfe $ Boe $ Mcfe $ Mcfe $ Boe $ Mcfe

Operating ExpensesGathering amp Transportation Expense (1) $95611 $46 $95657 $060 $002 $054 $92874 $502 $93376 $060 $016 $054Other Lease Operating Expense $14604 $52461 $67065 $009 $1789 $038 $16625 $55990 $72615 $011 $1731 $042Lease Operating and Transportation Expense $110215 $52507 $162721 $069 $1791 $091 $109499 $56492 $165991 $071 $1746 $096

General amp Administrative Expense $60596 $034 $58734 $034

All Other Operating and Maintenance Expense $11077 $006 $13469 $008Property Franchise and Other Taxes $14400 $008 $15426 $009Total Taxes amp Other $25477 $014 $28895 $017

Depreciation Depletion amp Amortization $124274 $070 $112565 $065

ProductionGas Production (MMcf) 160499 2407 162906 154093 2995 157088 Oil Production (MBbl) 4 2531 2535 4 2736 2740

Total Production (Mmcfe) 160523 17592 178114 154117 19411 173528 Total Production (Mboe) 26754 2932 29686 25686 3235 28921

(1) Gathering and Transportation expense is net of any payments received from JDA partner for the partners share of gathering cost(2) Seneca West Coast division includes Seneca corporate and eliminations

Twelve Months Ended September 30 2018

Twelve Months Ended September 30 2017

64

Non-GAAP Reconciliations ndash Adjusted Operation amp Maintenance Expense

Appendix

Reconciliation of Adjusted Operation and Maintenance Expense to Operation and Maintenance Expense By Segment ($ Thousands)

Exploration and Production SegmentOperation and Maintenance

General and Administrative Expense $ 59425 $ 15198 $ 13602 $ 61021Lease Operating and Transportation Expense 162721 42562 39647 165636All Other Operation and Maintenance Expense 11077 2353 2535 10895

Operation and Maintenance Expense $ 233223 60113 55784 237552Plus Non-Service Pension Costs 1171 4 293 882

Adjusted Operation and Maintenance Expense $ 234394 $ 60117 $ 56077 $ 238434

Pipeline and Storage SegmentOperation and Maintenance Expense $ 86876 $ 21633 $ 17672 $ 90837

Plus Non-Service Pension Costs (1420) (467) (356) (1531)Adjusted Operation and Maintenance Expense $ 85456 $ 21166 $ 17316 $ 89306

Gathering SegmentOperation and Maintenance Expense $ 15862 $ 3711 $ 2984 $ 16589

Plus Non-Service Pension Cots 328 82 82 328Adjusted Operation and Maintenance Expense $ 16190 $ 3793 $ 3066 $ 16917

Utility SegmentOperation and Maintenance Expense $ 165857 $ 43155 $ 43317 $ 165695

Plus Non-Service Pension Costs 31400 6928 7165 31163Adjusted Operation and Maintenance Expense $ 197257 $ 50083 $ 50482 $ 196858

Energy Marketing SegmentOperation and Maintenance Expense $ 6057 $ 1617 $ 1513 $ 6161

Plus Non-Service Pension Costs 497 123 124 496Adjusted Operation and Maintenance Expense $ 6554 $ 1740 $ 1637 $ 6657

Corporate and All Other Operation and Maintenance Expense $ 17003 $ 3058 $ 3721 $ 16340

Plus Non-Service Pension Costs 664 737 167 1234Adjusted Operation and Maintenance Expense $ 17667 $ 3795 $ 3888 $ 17574

Intersegment Eliminations $ (115112) $ (31643) $ (25517) $ (121238)

ConsolidatedOperation and Maintenance Expense $ 409766 $ 101644 $ 99474 $ 411936

Plus Non-Service Pension Costs 32640 7407 7475 32572Adjusted Operation and Maintenance Expense $ 442406 $ 109051 $ 106949 $ 444508

FY19 FY18 12-MonthsFY 2018 FYTD FYTD Ended 123118

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			Q1			Q1
			FY 2019			FY 2018
	Net Gain (Loss) on Hedge Ineffectiveness			$ 6504854			$ (433000)
	Federal Statutory Tax Rate			210			245
	Tax Benefit (Expense)			$ 1366019			$ (106085)
	After-tax Impact			$ 5138835			$ (326915)
	Net Gain (Loss) on ERP TopHat Investments			$ 6346969			$ - 0
	Federal Statutory Tax Rate			210			245
	Tax Benefit (Expense)			$ 1332863			$ - 0
	After-tax Impact			$ 5014106			$ - 0

Nationl Fuel Gas Company
Q1 - FY 2019
Segment Discussion Earnings Tables
Exploration amp Production
	Three Months EndedDecember 31
(in thousands except per share amounts)		2018		2017		Variance			2018		2017		Variance
Net Income		$ 38214		$ 106698		$ (68484)			$ 044		$ 124		$ (1)
Remeasurement of accumulated deferred taxes under 2017 Tax Reform		$ (990)		$ (77300)		$ 76310			$ (090)		$ (090)		$ - 0
Unrealized (gain) loss on hedge ineffectiveness (EampP)		$ (6505)		$ 433		$ (6938)			$ 001
Tax impact of unrealized (gain) loss on hedge ineffectiveness		$ 1366		$ (106)		$ 1472
Adjusted Operating Results		$ 32085		$ 29725		$ 2360			$ (046)		$ 034		$ (1)
Adjusted EBITDA		$ 89896		$ 80220		$ 9676
Pipeline amp Storage		$ 000s					$ per diluted share
	Three Months EndedDecember 31
(in thousands except per share amounts)		2018		2017		Variance			2017		2017		Variance
Net Income		$ 25102		$ 38462		$ (13360)			$ 045		$ 045		$ - 0
Remeasurement of accumulated deferred taxes under 2017 Tax Reform		$ - 0		$ (14100)		$ 14100			$ (016)		$ (016)		$ - 0
Adjusted Operating Results		$ 25102		$ 24362		$ 740			$ 029		$ 029		$ - 0
Adjusted EBITDA		$ 47824		$ 50417		$ (2593)
Gathering
	Three Months EndedDecember 31					$ per diluted share
(in thousands except per share amounts)		2018		2017		Variance			2017		2017		Variance
Net Income		$ 14183		$ 45400		$ (31217)			$ 053		$ 053		$ - 0
Remeasurement of accumulated deferred taxes under 2017 Tax Reform		$ (500)		$ (34900)		$ 34400			$ (040)		$ (040)		$ - 0
Adjusted Operating Results		$ 13683		$ 10500		$ 3183			$ 013		$ 013		$ - 0
Adjusted EBITDA		$ 25948		$ 20813		$ 5135
Utility
	Three Months EndedDecember 31					$ per diluted share
(in thousands except per share amounts)		2018		2017		Variance			2017		2017		Variance
Net Income		$ 25649		$ 20993		$ 4656			$ 026		$ 026		$ - 0
Remeasurement of accumulated deferred taxes under 2017 Tax Reform		$ - 0		$ - 0		$ - 0			$ (002)		$ (002)		$ - 0
Adjusted Operating Results		$ 25649		$ 20993		$ 4656			$ 024		$ 024		$ - 0
Adjusted EBITDA		$ 57569		$ 54150		$ 3419
Energy Marketing
	Three Months EndedDecember 31					$ per diluted share
(in thousands except per share amounts)		2017		2017		Variance			2017		2017		Variance
Net Income		$ (302)		$ 1046		$ (1348)			$ 001		$ 001		$ - 0
Revaluation of Accumulated Deferred Income Taxes		$ (198)		$ 200		$ (398)			$ - 0		$ - 0		$ - 0
Segment Operating Results		$ (500)		$ 1246		$ (1746)			$ 001		$ 001		$ - 0
Adjusted EBITDA		$ (721)		$ 1804		$ (2525)

ADJUSTED OPERATING RESULTS
		Three Months EndedDecember 31
(in thousands except per share amounts)			2018			2017			Var
Reported GAAP Earnings			$ 102660			$ 198654			$ (95994)
Items impacting comparability
Remeasurement of deferred income taxes under 2017 Tax Reform			(5000)			(111000)			106000
Unrealized (gain) loss on hedge ineffectiveness (EampP)			(6505)			433			(6938)
Tax impact of unrealized (gain) loss on hedge ineffectiveness			1366			(106)			1472
Unrealized loss on other investments (Corporate All Other)			6347			- 0			6347
Tax impact of unrealized loss on other investments			(1333)			- 0			(1333)
Adjusted Operating Results			$ 97535			$ 87981			$ 9554
Reported GAAP Earnings per share			$ 118			$ 230			$ (112)
Items impacting comparability
Remeasurement of deferred income taxes under 2017 Tax Reform			(006)			(129)			123
Unrealized (gain) loss on hedge ineffectiveness (EampP)			(008)			001			(009)
Tax impact of unrealized (gain) loss on hedge ineffectiveness			002			- 0			002
Unrealized loss on other investments (Corporate All Other)			007			- 0			007
Tax impact of unrealized loss on other investments			(002)			- 0			(002)
Rounding			001			- 0			001
Adjusted Operating Results per share			$ 112			$ 102			$ 010
weighted average shares			86708814			86325537
impact of remeasurement			(006)			(129)
unrealized gain hedging pre-tax			(008)			001
unrealized gain hedging - tax impact			002			(000)
unrealized loss ERP investments pre-tax			007			- 0
imrealized loss ERP investments - tax impact			(002)			- 0
adjusted op results			112			102

60

Non-GAAP Reconciliations ndash Adjusted EBITDA by Segment

Appendix

Reconciliation of Adjusted EBITDA to Net Income by Segment($ Thousands)

Exploration and Production SegmentReported GAAP Earnings $ 180632 $ 38214 $ 106698 $ 112148

Depreciation Depletion and Amortization 124274 34700 27425 131549Interest and Other Income (308) (278) (3) (584)Interest Expense 54288 13163 13374 54077Income Taxes (41962) 10602 (67707) 36347Unrealized (Gain) Loss of Hedge Ineffectiveness 782 (6505) 433 (6156)

Adjusted EBITDA $ 317706 $ 89896 $ 80221 $ 327382

Pipeline and Storage SegmentReported GAAP Earnings $ 97246 $ 25102 $ 38462 $ 83886

Depreciation Depletion and Amortization 43463 11114 10596 43981Interest and Other Income (5925) (1926) (1645) (6206)Interest Expense 31383 7286 7876 30793Income Taxes 17806 6248 (4872) 28926

Adjusted EBITDA $ 183973 $ 47824 $ 50417 $ 181380

Gathering SegmentReported GAAP Earnings $ 83519 $ 14183 $ 45400 $ 52302

Depreciation Depletion and Amortization 17313 4679 4088 17904Interest and Other Income (778) (43) (316) (505)Interest Expense 9560 2377 2340 9597Income Taxes (17677) 4752 (30699) 17774

Adjusted EBITDA $ 91937 $ 25948 $ 20813 $ 97072

FY19 FY18 12-MonthsFY 2018 FYTD FYTD Ended 123118

($ Thousands)

Utility SegmentReported GAAP Earnings $ 51217 $ 25649 $ 20993 $ 55873

Depreciation Depletion and Amortization 53253 13290 13325 53218Interest and Other Income 29074 6216 6691 28599Interest Expense 26753 5893 6837 25809Income Taxes 15258 6521 6304 15475

Adjusted EBITDA $ 175555 $ 57569 $ 54150 $ 178974

Energy Marketing SegmentReported GAAP Earnings $ 373 $ (302) $ 1046 $ (975)

Depreciation Depletion and Amortization 275 70 69 276Interest and Other Income (269) (45) (13) (301)Interest Expense 22 5 11 16Income Taxes 632 (449) 691 (508)

Adjusted EBITDA $ 1033 $ (721) $ 1804 $ (1492)

Corporate and All OtherReported GAAP Earnings $ (21466) $ (186) $ (13945) $ (7707)

Depreciation Depletion and Amortization 2383 402 327 2458Interest and Other Income (616) 5678 (1211) 6273Interest Expense (7484) (2212) (1849) (7847)Income Taxes 18449 (4765) 15005 (1321)

Adjusted EBITDA $ (8735) $ (1083) $ (1673) $ (8145)

FY19 FY18 12-MonthsFY 2018 FYTD FYTD Ended 123118

61

Non-GAAP Reconciliations ndash Adjusted Operating Results

Appendix

(in thousands except per share amounts) 2018 2017Reported GAAP Earnings 102660$ 198654$

Items impacting comparabilityRemeasurement of deferred income taxes under 2017 Tax Reform (5000) (111000) Unrealized (gain) loss on hedge ineffectiveness (EampP) (6505) 433 Tax impact of unrealized (gain) loss on hedge ineffectiveness 1366 (106) Unrealized loss on other investments (Corporate All Other) 6347 - Tax impact of unrealized loss on other investments (1333) -

Adjusted Operating Results 97535$ 87981$

Reported GAAP Earnings per share 118$ 230$ Items impacting comparability

Remeasurement of deferred income taxes under 2017 Tax Reform (006) (129) Unrealized (gain) loss on hedge ineffectiveness (EampP) (008) 001 Tax impact of unrealized (gain) loss on hedge ineffectiveness 002 - Unrealized loss on other investments (Corporate All Other) 007 - Tax impact of unrealized loss on other investments (002) - Rounding 001 -

Adjusted Operating Results per share 112$ 102$

Three Months EndedDecember 31

Fiscal Year Ended September 30 (in thousands except per share amounts) 2018 2017 Reported GAAP Earnings $ 391521 $ 283482

Items impacting comparability Remeasurement of deferred income taxes under 2017 Tax Reform (103484 ) mdash

Premium paid on early redemption of debt (EampP) 962 mdash Tax impact on premium paid on early redemption of debt (235 ) mdash

Adjusted Operating Results $ 288764 $ 283482 Reported GAAP Earnings per share $ 453 $ 330

Items impacting comparability Remeasurement of deferred income taxes under 2017 Tax Reform (120 ) mdash

Premium paid on early redemption of debt net of tax 001 mdash Adjusted Operating Results per share $ 334 $ 330

Adjusted Operating Results

Sheet2

Sheet1

62

Non-GAAP Reconciliations ndash Capital Expenditures

Appendix

Reconciliation of Segment Capital Expenditures to Consolidated Capital Expenditures ($ Thousands) FY 2019

FY 2014 FY 2015 FY 2016 FY 2017 FY 2018 ForecastCapital Expenditures

Exploration amp Production Capital Expenditures 602705$ 557313$ 256104$ 253057$ 380677$ $460000 - $495000Pipeline amp Storage Capital Expenditures 139821$ 230192$ 114250$ 95336$ 92832$ $120000 - $150000Gathering Segment Capital Expenditures 137799$ 118166$ 54293$ 32645$ 61728$ $55000 - $65000Utility Capital Expenditures 88810$ 94371$ 98007$ 80867$ 85648$ $90000 - $100000Energy Marketing Corporate amp All Other Capital Expenditures 772$ 467$ 397$ 212$ 222$ Eliminations - -$ -$ -$ (20505)$ Total Capital Expenditures from Continuing Operations 969907$ 1000509$ 523051$ 462117$ 600602$ $725000 - $810000

Plus (Minus) Accrued Capital Expenditures

Exploration amp Production FY 2018 Accrued Capital Expenditures (51343)$ Exploration amp Production FY 2017 Accrued Capital Expenditures (36465)$ 36465$ Exploration amp Production FY 2016 Accrued Capital Expenditures - - (25215) 25215 Exploration amp Production FY 2015 Accrued Capital Expenditures - (46173) 46173 - Exploration amp Production FY 2014 Accrued Capital Expenditures (80108) 80108 - - Exploration amp Production FY 2013 Accrued Capital Expenditures 58478 - - - Exploration amp Production FY 2012 Accrued Capital Expenditures - - - - Pipeline amp Storage FY 2018 Accrued Capital Expenditures (21861)$ Pipeline amp Storage FY 2017 Accrued Capital Expenditures (25077) 25077$ Pipeline amp Storage FY 2016 Accrued Capital Expenditures - - (18661) 18661 Pipeline amp Storage FY 2015 Accrued Capital Expenditures - (33925) 33925 - Pipeline amp Storage FY 2014 Accrued Capital Expenditures (28122) 28122 - - Pipeline amp Storage FY 2013 Accrued Capital Expenditures 5633 - - - Pipeline amp Storage FY 2012 Accrued Capital Expenditures - - - - Gathering FY 2018 Accrued Capital Expenditures (6084)$ Gathering FY 2017 Accrued Capital Expenditures (3925) 3925$ Gathering FY 2016 Accrued Capital Expenditures - - (5355) 5355 Gathering FY 2015 Accrued Capital Expenditures - (22416) 22416 - Gathering FY 2014 Accrued Capital Expenditures (20084) 20084 - - Gathering FY 2013 Accrued Capital Expenditures 6700 - - - Gathering FY 2012 Accrued Capital Expenditures - - - - Utility FY 2018 Accrued Capital Expenditures (9525)$ Utility FY 2017 Accrued Capital Expenditures (6748) 6748$ Utility FY 2016 Accrued Capital Expenditures - - (11203) 11203 Utility FY 2015 Accrued Capital Expenditures - (16445) 16445 - Utility FY 2014 Accrued Capital Expenditures (8315) 8315 - - Utility FY 2013 Accrued Capital Expenditures 10328 - - - Utility FY 2012 Accrued Capital Expenditures - - - - Total Accrued Capital Expenditures (55490)$ 17670$ 58525$ (11782)$ (16597)$

Total Capital Expenditures per Statement of Cash Flows 914417$ 1018179$ 581576$ 450335$ 584004$ $725000 - $810000

63

Non-GAAP Reconciliations ndash EampP Operating Expenses

Appendix

Reconciliation of Exploration amp Production Segment Operating Expenses by Division($000s unless noted otherwise)

Appalachia West Coast(2) Total EampP Appalachia West Coast(2) Total EampP Appalachia West Coast(2) Total EampP Appalachia West Coast(2) Total EampP$ Mcfe $ Boe $ Mcfe $ Mcfe $ Boe $ Mcfe

Operating ExpensesGathering amp Transportation Expense (1) $95611 $46 $95657 $060 $002 $054 $92874 $502 $93376 $060 $016 $054Other Lease Operating Expense $14604 $52461 $67065 $009 $1789 $038 $16625 $55990 $72615 $011 $1731 $042Lease Operating and Transportation Expense $110215 $52507 $162721 $069 $1791 $091 $109499 $56492 $165991 $071 $1746 $096

General amp Administrative Expense $60596 $034 $58734 $034

All Other Operating and Maintenance Expense $11077 $006 $13469 $008Property Franchise and Other Taxes $14400 $008 $15426 $009Total Taxes amp Other $25477 $014 $28895 $017

Depreciation Depletion amp Amortization $124274 $070 $112565 $065

ProductionGas Production (MMcf) 160499 2407 162906 154093 2995 157088 Oil Production (MBbl) 4 2531 2535 4 2736 2740

Total Production (Mmcfe) 160523 17592 178114 154117 19411 173528 Total Production (Mboe) 26754 2932 29686 25686 3235 28921

(1) Gathering and Transportation expense is net of any payments received from JDA partner for the partners share of gathering cost(2) Seneca West Coast division includes Seneca corporate and eliminations

Twelve Months Ended September 30 2018

Twelve Months Ended September 30 2017

64

Non-GAAP Reconciliations ndash Adjusted Operation amp Maintenance Expense

Appendix

Reconciliation of Adjusted Operation and Maintenance Expense to Operation and Maintenance Expense By Segment ($ Thousands)

Exploration and Production SegmentOperation and Maintenance

General and Administrative Expense $ 59425 $ 15198 $ 13602 $ 61021Lease Operating and Transportation Expense 162721 42562 39647 165636All Other Operation and Maintenance Expense 11077 2353 2535 10895

Operation and Maintenance Expense $ 233223 60113 55784 237552Plus Non-Service Pension Costs 1171 4 293 882

Adjusted Operation and Maintenance Expense $ 234394 $ 60117 $ 56077 $ 238434

Pipeline and Storage SegmentOperation and Maintenance Expense $ 86876 $ 21633 $ 17672 $ 90837

Plus Non-Service Pension Costs (1420) (467) (356) (1531)Adjusted Operation and Maintenance Expense $ 85456 $ 21166 $ 17316 $ 89306

Gathering SegmentOperation and Maintenance Expense $ 15862 $ 3711 $ 2984 $ 16589

Plus Non-Service Pension Cots 328 82 82 328Adjusted Operation and Maintenance Expense $ 16190 $ 3793 $ 3066 $ 16917

Utility SegmentOperation and Maintenance Expense $ 165857 $ 43155 $ 43317 $ 165695

Plus Non-Service Pension Costs 31400 6928 7165 31163Adjusted Operation and Maintenance Expense $ 197257 $ 50083 $ 50482 $ 196858

Energy Marketing SegmentOperation and Maintenance Expense $ 6057 $ 1617 $ 1513 $ 6161

Plus Non-Service Pension Costs 497 123 124 496Adjusted Operation and Maintenance Expense $ 6554 $ 1740 $ 1637 $ 6657

Corporate and All Other Operation and Maintenance Expense $ 17003 $ 3058 $ 3721 $ 16340

Plus Non-Service Pension Costs 664 737 167 1234Adjusted Operation and Maintenance Expense $ 17667 $ 3795 $ 3888 $ 17574

Intersegment Eliminations $ (115112) $ (31643) $ (25517) $ (121238)

ConsolidatedOperation and Maintenance Expense $ 409766 $ 101644 $ 99474 $ 411936

Plus Non-Service Pension Costs 32640 7407 7475 32572Adjusted Operation and Maintenance Expense $ 442406 $ 109051 $ 106949 $ 444508

FY19 FY18 12-MonthsFY 2018 FYTD FYTD Ended 123118

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			Q1			Q1
			FY 2019			FY 2018
	Net Gain (Loss) on Hedge Ineffectiveness			$ 6504854			$ (433000)
	Federal Statutory Tax Rate			210			245
	Tax Benefit (Expense)			$ 1366019			$ (106085)
	After-tax Impact			$ 5138835			$ (326915)
	Net Gain (Loss) on ERP TopHat Investments			$ 6346969			$ - 0
	Federal Statutory Tax Rate			210			245
	Tax Benefit (Expense)			$ 1332863			$ - 0
	After-tax Impact			$ 5014106			$ - 0

Nationl Fuel Gas Company
Q1 - FY 2019
Segment Discussion Earnings Tables
Exploration amp Production
	Three Months EndedDecember 31
(in thousands except per share amounts)		2018		2017		Variance			2018		2017		Variance
Net Income		$ 38214		$ 106698		$ (68484)			$ 044		$ 124		$ (1)
Remeasurement of accumulated deferred taxes under 2017 Tax Reform		$ (990)		$ (77300)		$ 76310			$ (090)		$ (090)		$ - 0
Unrealized (gain) loss on hedge ineffectiveness (EampP)		$ (6505)		$ 433		$ (6938)			$ 001
Tax impact of unrealized (gain) loss on hedge ineffectiveness		$ 1366		$ (106)		$ 1472
Adjusted Operating Results		$ 32085		$ 29725		$ 2360			$ (046)		$ 034		$ (1)
Adjusted EBITDA		$ 89896		$ 80220		$ 9676
Pipeline amp Storage		$ 000s					$ per diluted share
	Three Months EndedDecember 31
(in thousands except per share amounts)		2018		2017		Variance			2017		2017		Variance
Net Income		$ 25102		$ 38462		$ (13360)			$ 045		$ 045		$ - 0
Remeasurement of accumulated deferred taxes under 2017 Tax Reform		$ - 0		$ (14100)		$ 14100			$ (016)		$ (016)		$ - 0
Adjusted Operating Results		$ 25102		$ 24362		$ 740			$ 029		$ 029		$ - 0
Adjusted EBITDA		$ 47824		$ 50417		$ (2593)
Gathering
	Three Months EndedDecember 31					$ per diluted share
(in thousands except per share amounts)		2018		2017		Variance			2017		2017		Variance
Net Income		$ 14183		$ 45400		$ (31217)			$ 053		$ 053		$ - 0
Remeasurement of accumulated deferred taxes under 2017 Tax Reform		$ (500)		$ (34900)		$ 34400			$ (040)		$ (040)		$ - 0
Adjusted Operating Results		$ 13683		$ 10500		$ 3183			$ 013		$ 013		$ - 0
Adjusted EBITDA		$ 25948		$ 20813		$ 5135
Utility
	Three Months EndedDecember 31					$ per diluted share
(in thousands except per share amounts)		2018		2017		Variance			2017		2017		Variance
Net Income		$ 25649		$ 20993		$ 4656			$ 026		$ 026		$ - 0
Remeasurement of accumulated deferred taxes under 2017 Tax Reform		$ - 0		$ - 0		$ - 0			$ (002)		$ (002)		$ - 0
Adjusted Operating Results		$ 25649		$ 20993		$ 4656			$ 024		$ 024		$ - 0
Adjusted EBITDA		$ 57569		$ 54150		$ 3419
Energy Marketing
	Three Months EndedDecember 31					$ per diluted share
(in thousands except per share amounts)		2017		2017		Variance			2017		2017		Variance
Net Income		$ (302)		$ 1046		$ (1348)			$ 001		$ 001		$ - 0
Revaluation of Accumulated Deferred Income Taxes		$ (198)		$ 200		$ (398)			$ - 0		$ - 0		$ - 0
Segment Operating Results		$ (500)		$ 1246		$ (1746)			$ 001		$ 001		$ - 0
Adjusted EBITDA		$ (721)		$ 1804		$ (2525)

ADJUSTED OPERATING RESULTS
		Three Months EndedDecember 31
(in thousands except per share amounts)			2018			2017			Var
Reported GAAP Earnings			$ 102660			$ 198654			$ (95994)
Items impacting comparability
Remeasurement of deferred income taxes under 2017 Tax Reform			(5000)			(111000)			106000
Unrealized (gain) loss on hedge ineffectiveness (EampP)			(6505)			433			(6938)
Tax impact of unrealized (gain) loss on hedge ineffectiveness			1366			(106)			1472
Unrealized loss on other investments (Corporate All Other)			6347			- 0			6347
Tax impact of unrealized loss on other investments			(1333)			- 0			(1333)
Adjusted Operating Results			$ 97535			$ 87981			$ 9554
Reported GAAP Earnings per share			$ 118			$ 230			$ (112)
Items impacting comparability
Remeasurement of deferred income taxes under 2017 Tax Reform			(006)			(129)			123
Unrealized (gain) loss on hedge ineffectiveness (EampP)			(008)			001			(009)
Tax impact of unrealized (gain) loss on hedge ineffectiveness			002			- 0			002
Unrealized loss on other investments (Corporate All Other)			007			- 0			007
Tax impact of unrealized loss on other investments			(002)			- 0			(002)
Rounding			001			- 0			001
Adjusted Operating Results per share			$ 112			$ 102			$ 010
weighted average shares			86708814			86325537
impact of remeasurement			(006)			(129)
unrealized gain hedging pre-tax			(008)			001
unrealized gain hedging - tax impact			002			(000)
unrealized loss ERP investments pre-tax			007			- 0
imrealized loss ERP investments - tax impact			(002)			- 0
adjusted op results			112			102

61

Non-GAAP Reconciliations ndash Adjusted Operating Results

Appendix

(in thousands except per share amounts) 2018 2017Reported GAAP Earnings 102660$ 198654$

Items impacting comparabilityRemeasurement of deferred income taxes under 2017 Tax Reform (5000) (111000) Unrealized (gain) loss on hedge ineffectiveness (EampP) (6505) 433 Tax impact of unrealized (gain) loss on hedge ineffectiveness 1366 (106) Unrealized loss on other investments (Corporate All Other) 6347 - Tax impact of unrealized loss on other investments (1333) -

Adjusted Operating Results 97535$ 87981$

Reported GAAP Earnings per share 118$ 230$ Items impacting comparability

Remeasurement of deferred income taxes under 2017 Tax Reform (006) (129) Unrealized (gain) loss on hedge ineffectiveness (EampP) (008) 001 Tax impact of unrealized (gain) loss on hedge ineffectiveness 002 - Unrealized loss on other investments (Corporate All Other) 007 - Tax impact of unrealized loss on other investments (002) - Rounding 001 -

Adjusted Operating Results per share 112$ 102$

Three Months EndedDecember 31

Fiscal Year Ended September 30 (in thousands except per share amounts) 2018 2017 Reported GAAP Earnings $ 391521 $ 283482

Items impacting comparability Remeasurement of deferred income taxes under 2017 Tax Reform (103484 ) mdash

Premium paid on early redemption of debt (EampP) 962 mdash Tax impact on premium paid on early redemption of debt (235 ) mdash

Adjusted Operating Results $ 288764 $ 283482 Reported GAAP Earnings per share $ 453 $ 330

Items impacting comparability Remeasurement of deferred income taxes under 2017 Tax Reform (120 ) mdash

Premium paid on early redemption of debt net of tax 001 mdash Adjusted Operating Results per share $ 334 $ 330

Adjusted Operating Results

Sheet2

Sheet1

62

Non-GAAP Reconciliations ndash Capital Expenditures

Appendix

Reconciliation of Segment Capital Expenditures to Consolidated Capital Expenditures ($ Thousands) FY 2019

FY 2014 FY 2015 FY 2016 FY 2017 FY 2018 ForecastCapital Expenditures

Exploration amp Production Capital Expenditures 602705$ 557313$ 256104$ 253057$ 380677$ $460000 - $495000Pipeline amp Storage Capital Expenditures 139821$ 230192$ 114250$ 95336$ 92832$ $120000 - $150000Gathering Segment Capital Expenditures 137799$ 118166$ 54293$ 32645$ 61728$ $55000 - $65000Utility Capital Expenditures 88810$ 94371$ 98007$ 80867$ 85648$ $90000 - $100000Energy Marketing Corporate amp All Other Capital Expenditures 772$ 467$ 397$ 212$ 222$ Eliminations - -$ -$ -$ (20505)$ Total Capital Expenditures from Continuing Operations 969907$ 1000509$ 523051$ 462117$ 600602$ $725000 - $810000

Plus (Minus) Accrued Capital Expenditures

Exploration amp Production FY 2018 Accrued Capital Expenditures (51343)$ Exploration amp Production FY 2017 Accrued Capital Expenditures (36465)$ 36465$ Exploration amp Production FY 2016 Accrued Capital Expenditures - - (25215) 25215 Exploration amp Production FY 2015 Accrued Capital Expenditures - (46173) 46173 - Exploration amp Production FY 2014 Accrued Capital Expenditures (80108) 80108 - - Exploration amp Production FY 2013 Accrued Capital Expenditures 58478 - - - Exploration amp Production FY 2012 Accrued Capital Expenditures - - - - Pipeline amp Storage FY 2018 Accrued Capital Expenditures (21861)$ Pipeline amp Storage FY 2017 Accrued Capital Expenditures (25077) 25077$ Pipeline amp Storage FY 2016 Accrued Capital Expenditures - - (18661) 18661 Pipeline amp Storage FY 2015 Accrued Capital Expenditures - (33925) 33925 - Pipeline amp Storage FY 2014 Accrued Capital Expenditures (28122) 28122 - - Pipeline amp Storage FY 2013 Accrued Capital Expenditures 5633 - - - Pipeline amp Storage FY 2012 Accrued Capital Expenditures - - - - Gathering FY 2018 Accrued Capital Expenditures (6084)$ Gathering FY 2017 Accrued Capital Expenditures (3925) 3925$ Gathering FY 2016 Accrued Capital Expenditures - - (5355) 5355 Gathering FY 2015 Accrued Capital Expenditures - (22416) 22416 - Gathering FY 2014 Accrued Capital Expenditures (20084) 20084 - - Gathering FY 2013 Accrued Capital Expenditures 6700 - - - Gathering FY 2012 Accrued Capital Expenditures - - - - Utility FY 2018 Accrued Capital Expenditures (9525)$ Utility FY 2017 Accrued Capital Expenditures (6748) 6748$ Utility FY 2016 Accrued Capital Expenditures - - (11203) 11203 Utility FY 2015 Accrued Capital Expenditures - (16445) 16445 - Utility FY 2014 Accrued Capital Expenditures (8315) 8315 - - Utility FY 2013 Accrued Capital Expenditures 10328 - - - Utility FY 2012 Accrued Capital Expenditures - - - - Total Accrued Capital Expenditures (55490)$ 17670$ 58525$ (11782)$ (16597)$

Total Capital Expenditures per Statement of Cash Flows 914417$ 1018179$ 581576$ 450335$ 584004$ $725000 - $810000

63

Non-GAAP Reconciliations ndash EampP Operating Expenses

Appendix

Reconciliation of Exploration amp Production Segment Operating Expenses by Division($000s unless noted otherwise)

Appalachia West Coast(2) Total EampP Appalachia West Coast(2) Total EampP Appalachia West Coast(2) Total EampP Appalachia West Coast(2) Total EampP$ Mcfe $ Boe $ Mcfe $ Mcfe $ Boe $ Mcfe

Operating ExpensesGathering amp Transportation Expense (1) $95611 $46 $95657 $060 $002 $054 $92874 $502 $93376 $060 $016 $054Other Lease Operating Expense $14604 $52461 $67065 $009 $1789 $038 $16625 $55990 $72615 $011 $1731 $042Lease Operating and Transportation Expense $110215 $52507 $162721 $069 $1791 $091 $109499 $56492 $165991 $071 $1746 $096

General amp Administrative Expense $60596 $034 $58734 $034

All Other Operating and Maintenance Expense $11077 $006 $13469 $008Property Franchise and Other Taxes $14400 $008 $15426 $009Total Taxes amp Other $25477 $014 $28895 $017

Depreciation Depletion amp Amortization $124274 $070 $112565 $065

ProductionGas Production (MMcf) 160499 2407 162906 154093 2995 157088 Oil Production (MBbl) 4 2531 2535 4 2736 2740

Total Production (Mmcfe) 160523 17592 178114 154117 19411 173528 Total Production (Mboe) 26754 2932 29686 25686 3235 28921

(1) Gathering and Transportation expense is net of any payments received from JDA partner for the partners share of gathering cost(2) Seneca West Coast division includes Seneca corporate and eliminations

Twelve Months Ended September 30 2018

Twelve Months Ended September 30 2017

64

Non-GAAP Reconciliations ndash Adjusted Operation amp Maintenance Expense

Appendix

Reconciliation of Adjusted Operation and Maintenance Expense to Operation and Maintenance Expense By Segment ($ Thousands)

Exploration and Production SegmentOperation and Maintenance

General and Administrative Expense $ 59425 $ 15198 $ 13602 $ 61021Lease Operating and Transportation Expense 162721 42562 39647 165636All Other Operation and Maintenance Expense 11077 2353 2535 10895

Operation and Maintenance Expense $ 233223 60113 55784 237552Plus Non-Service Pension Costs 1171 4 293 882

Adjusted Operation and Maintenance Expense $ 234394 $ 60117 $ 56077 $ 238434

Pipeline and Storage SegmentOperation and Maintenance Expense $ 86876 $ 21633 $ 17672 $ 90837

Plus Non-Service Pension Costs (1420) (467) (356) (1531)Adjusted Operation and Maintenance Expense $ 85456 $ 21166 $ 17316 $ 89306

Gathering SegmentOperation and Maintenance Expense $ 15862 $ 3711 $ 2984 $ 16589

Plus Non-Service Pension Cots 328 82 82 328Adjusted Operation and Maintenance Expense $ 16190 $ 3793 $ 3066 $ 16917

Utility SegmentOperation and Maintenance Expense $ 165857 $ 43155 $ 43317 $ 165695

Plus Non-Service Pension Costs 31400 6928 7165 31163Adjusted Operation and Maintenance Expense $ 197257 $ 50083 $ 50482 $ 196858

Energy Marketing SegmentOperation and Maintenance Expense $ 6057 $ 1617 $ 1513 $ 6161

Plus Non-Service Pension Costs 497 123 124 496Adjusted Operation and Maintenance Expense $ 6554 $ 1740 $ 1637 $ 6657

Corporate and All Other Operation and Maintenance Expense $ 17003 $ 3058 $ 3721 $ 16340

Plus Non-Service Pension Costs 664 737 167 1234Adjusted Operation and Maintenance Expense $ 17667 $ 3795 $ 3888 $ 17574

Intersegment Eliminations $ (115112) $ (31643) $ (25517) $ (121238)

ConsolidatedOperation and Maintenance Expense $ 409766 $ 101644 $ 99474 $ 411936

Plus Non-Service Pension Costs 32640 7407 7475 32572Adjusted Operation and Maintenance Expense $ 442406 $ 109051 $ 106949 $ 444508

FY19 FY18 12-MonthsFY 2018 FYTD FYTD Ended 123118

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			Q1			Q1
			FY 2019			FY 2018
	Net Gain (Loss) on Hedge Ineffectiveness			$ 6504854			$ (433000)
	Federal Statutory Tax Rate			210			245
	Tax Benefit (Expense)			$ 1366019			$ (106085)
	After-tax Impact			$ 5138835			$ (326915)
	Net Gain (Loss) on ERP TopHat Investments			$ 6346969			$ - 0
	Federal Statutory Tax Rate			210			245
	Tax Benefit (Expense)			$ 1332863			$ - 0
	After-tax Impact			$ 5014106			$ - 0

Nationl Fuel Gas Company
Q1 - FY 2019
Segment Discussion Earnings Tables
Exploration amp Production
	Three Months EndedDecember 31
(in thousands except per share amounts)		2018		2017		Variance			2018		2017		Variance
Net Income		$ 38214		$ 106698		$ (68484)			$ 044		$ 124		$ (1)
Remeasurement of accumulated deferred taxes under 2017 Tax Reform		$ (990)		$ (77300)		$ 76310			$ (090)		$ (090)		$ - 0
Unrealized (gain) loss on hedge ineffectiveness (EampP)		$ (6505)		$ 433		$ (6938)			$ 001
Tax impact of unrealized (gain) loss on hedge ineffectiveness		$ 1366		$ (106)		$ 1472
Adjusted Operating Results		$ 32085		$ 29725		$ 2360			$ (046)		$ 034		$ (1)
Adjusted EBITDA		$ 89896		$ 80220		$ 9676
Pipeline amp Storage		$ 000s					$ per diluted share
	Three Months EndedDecember 31
(in thousands except per share amounts)		2018		2017		Variance			2017		2017		Variance
Net Income		$ 25102		$ 38462		$ (13360)			$ 045		$ 045		$ - 0
Remeasurement of accumulated deferred taxes under 2017 Tax Reform		$ - 0		$ (14100)		$ 14100			$ (016)		$ (016)		$ - 0
Adjusted Operating Results		$ 25102		$ 24362		$ 740			$ 029		$ 029		$ - 0
Adjusted EBITDA		$ 47824		$ 50417		$ (2593)
Gathering
	Three Months EndedDecember 31					$ per diluted share
(in thousands except per share amounts)		2018		2017		Variance			2017		2017		Variance
Net Income		$ 14183		$ 45400		$ (31217)			$ 053		$ 053		$ - 0
Remeasurement of accumulated deferred taxes under 2017 Tax Reform		$ (500)		$ (34900)		$ 34400			$ (040)		$ (040)		$ - 0
Adjusted Operating Results		$ 13683		$ 10500		$ 3183			$ 013		$ 013		$ - 0
Adjusted EBITDA		$ 25948		$ 20813		$ 5135
Utility
	Three Months EndedDecember 31					$ per diluted share
(in thousands except per share amounts)		2018		2017		Variance			2017		2017		Variance
Net Income		$ 25649		$ 20993		$ 4656			$ 026		$ 026		$ - 0
Remeasurement of accumulated deferred taxes under 2017 Tax Reform		$ - 0		$ - 0		$ - 0			$ (002)		$ (002)		$ - 0
Adjusted Operating Results		$ 25649		$ 20993		$ 4656			$ 024		$ 024		$ - 0
Adjusted EBITDA		$ 57569		$ 54150		$ 3419
Energy Marketing
	Three Months EndedDecember 31					$ per diluted share
(in thousands except per share amounts)		2017		2017		Variance			2017		2017		Variance
Net Income		$ (302)		$ 1046		$ (1348)			$ 001		$ 001		$ - 0
Revaluation of Accumulated Deferred Income Taxes		$ (198)		$ 200		$ (398)			$ - 0		$ - 0		$ - 0
Segment Operating Results		$ (500)		$ 1246		$ (1746)			$ 001		$ 001		$ - 0
Adjusted EBITDA		$ (721)		$ 1804		$ (2525)

ADJUSTED OPERATING RESULTS
		Three Months EndedDecember 31
(in thousands except per share amounts)			2018			2017			Var
Reported GAAP Earnings			$ 102660			$ 198654			$ (95994)
Items impacting comparability
Remeasurement of deferred income taxes under 2017 Tax Reform			(5000)			(111000)			106000
Unrealized (gain) loss on hedge ineffectiveness (EampP)			(6505)			433			(6938)
Tax impact of unrealized (gain) loss on hedge ineffectiveness			1366			(106)			1472
Unrealized loss on other investments (Corporate All Other)			6347			- 0			6347
Tax impact of unrealized loss on other investments			(1333)			- 0			(1333)
Adjusted Operating Results			$ 97535			$ 87981			$ 9554
Reported GAAP Earnings per share			$ 118			$ 230			$ (112)
Items impacting comparability
Remeasurement of deferred income taxes under 2017 Tax Reform			(006)			(129)			123
Unrealized (gain) loss on hedge ineffectiveness (EampP)			(008)			001			(009)
Tax impact of unrealized (gain) loss on hedge ineffectiveness			002			- 0			002
Unrealized loss on other investments (Corporate All Other)			007			- 0			007
Tax impact of unrealized loss on other investments			(002)			- 0			(002)
Rounding			001			- 0			001
Adjusted Operating Results per share			$ 112			$ 102			$ 010
weighted average shares			86708814			86325537
impact of remeasurement			(006)			(129)
unrealized gain hedging pre-tax			(008)			001
unrealized gain hedging - tax impact			002			(000)
unrealized loss ERP investments pre-tax			007			- 0
imrealized loss ERP investments - tax impact			(002)			- 0
adjusted op results			112			102

62

Non-GAAP Reconciliations ndash Capital Expenditures

Appendix

Reconciliation of Segment Capital Expenditures to Consolidated Capital Expenditures ($ Thousands) FY 2019

FY 2014 FY 2015 FY 2016 FY 2017 FY 2018 ForecastCapital Expenditures

Exploration amp Production Capital Expenditures 602705$ 557313$ 256104$ 253057$ 380677$ $460000 - $495000Pipeline amp Storage Capital Expenditures 139821$ 230192$ 114250$ 95336$ 92832$ $120000 - $150000Gathering Segment Capital Expenditures 137799$ 118166$ 54293$ 32645$ 61728$ $55000 - $65000Utility Capital Expenditures 88810$ 94371$ 98007$ 80867$ 85648$ $90000 - $100000Energy Marketing Corporate amp All Other Capital Expenditures 772$ 467$ 397$ 212$ 222$ Eliminations - -$ -$ -$ (20505)$ Total Capital Expenditures from Continuing Operations 969907$ 1000509$ 523051$ 462117$ 600602$ $725000 - $810000

Plus (Minus) Accrued Capital Expenditures

Exploration amp Production FY 2018 Accrued Capital Expenditures (51343)$ Exploration amp Production FY 2017 Accrued Capital Expenditures (36465)$ 36465$ Exploration amp Production FY 2016 Accrued Capital Expenditures - - (25215) 25215 Exploration amp Production FY 2015 Accrued Capital Expenditures - (46173) 46173 - Exploration amp Production FY 2014 Accrued Capital Expenditures (80108) 80108 - - Exploration amp Production FY 2013 Accrued Capital Expenditures 58478 - - - Exploration amp Production FY 2012 Accrued Capital Expenditures - - - - Pipeline amp Storage FY 2018 Accrued Capital Expenditures (21861)$ Pipeline amp Storage FY 2017 Accrued Capital Expenditures (25077) 25077$ Pipeline amp Storage FY 2016 Accrued Capital Expenditures - - (18661) 18661 Pipeline amp Storage FY 2015 Accrued Capital Expenditures - (33925) 33925 - Pipeline amp Storage FY 2014 Accrued Capital Expenditures (28122) 28122 - - Pipeline amp Storage FY 2013 Accrued Capital Expenditures 5633 - - - Pipeline amp Storage FY 2012 Accrued Capital Expenditures - - - - Gathering FY 2018 Accrued Capital Expenditures (6084)$ Gathering FY 2017 Accrued Capital Expenditures (3925) 3925$ Gathering FY 2016 Accrued Capital Expenditures - - (5355) 5355 Gathering FY 2015 Accrued Capital Expenditures - (22416) 22416 - Gathering FY 2014 Accrued Capital Expenditures (20084) 20084 - - Gathering FY 2013 Accrued Capital Expenditures 6700 - - - Gathering FY 2012 Accrued Capital Expenditures - - - - Utility FY 2018 Accrued Capital Expenditures (9525)$ Utility FY 2017 Accrued Capital Expenditures (6748) 6748$ Utility FY 2016 Accrued Capital Expenditures - - (11203) 11203 Utility FY 2015 Accrued Capital Expenditures - (16445) 16445 - Utility FY 2014 Accrued Capital Expenditures (8315) 8315 - - Utility FY 2013 Accrued Capital Expenditures 10328 - - - Utility FY 2012 Accrued Capital Expenditures - - - - Total Accrued Capital Expenditures (55490)$ 17670$ 58525$ (11782)$ (16597)$

Total Capital Expenditures per Statement of Cash Flows 914417$ 1018179$ 581576$ 450335$ 584004$ $725000 - $810000

63

Non-GAAP Reconciliations ndash EampP Operating Expenses

Appendix

Reconciliation of Exploration amp Production Segment Operating Expenses by Division($000s unless noted otherwise)

Appalachia West Coast(2) Total EampP Appalachia West Coast(2) Total EampP Appalachia West Coast(2) Total EampP Appalachia West Coast(2) Total EampP$ Mcfe $ Boe $ Mcfe $ Mcfe $ Boe $ Mcfe

Operating ExpensesGathering amp Transportation Expense (1) $95611 $46 $95657 $060 $002 $054 $92874 $502 $93376 $060 $016 $054Other Lease Operating Expense $14604 $52461 $67065 $009 $1789 $038 $16625 $55990 $72615 $011 $1731 $042Lease Operating and Transportation Expense $110215 $52507 $162721 $069 $1791 $091 $109499 $56492 $165991 $071 $1746 $096

General amp Administrative Expense $60596 $034 $58734 $034

All Other Operating and Maintenance Expense $11077 $006 $13469 $008Property Franchise and Other Taxes $14400 $008 $15426 $009Total Taxes amp Other $25477 $014 $28895 $017

Depreciation Depletion amp Amortization $124274 $070 $112565 $065

ProductionGas Production (MMcf) 160499 2407 162906 154093 2995 157088 Oil Production (MBbl) 4 2531 2535 4 2736 2740

Total Production (Mmcfe) 160523 17592 178114 154117 19411 173528 Total Production (Mboe) 26754 2932 29686 25686 3235 28921

(1) Gathering and Transportation expense is net of any payments received from JDA partner for the partners share of gathering cost(2) Seneca West Coast division includes Seneca corporate and eliminations

Twelve Months Ended September 30 2018

Twelve Months Ended September 30 2017

64

Non-GAAP Reconciliations ndash Adjusted Operation amp Maintenance Expense

Appendix

Reconciliation of Adjusted Operation and Maintenance Expense to Operation and Maintenance Expense By Segment ($ Thousands)

Exploration and Production SegmentOperation and Maintenance

General and Administrative Expense $ 59425 $ 15198 $ 13602 $ 61021Lease Operating and Transportation Expense 162721 42562 39647 165636All Other Operation and Maintenance Expense 11077 2353 2535 10895

Operation and Maintenance Expense $ 233223 60113 55784 237552Plus Non-Service Pension Costs 1171 4 293 882

Adjusted Operation and Maintenance Expense $ 234394 $ 60117 $ 56077 $ 238434

Pipeline and Storage SegmentOperation and Maintenance Expense $ 86876 $ 21633 $ 17672 $ 90837

Plus Non-Service Pension Costs (1420) (467) (356) (1531)Adjusted Operation and Maintenance Expense $ 85456 $ 21166 $ 17316 $ 89306

Gathering SegmentOperation and Maintenance Expense $ 15862 $ 3711 $ 2984 $ 16589

Plus Non-Service Pension Cots 328 82 82 328Adjusted Operation and Maintenance Expense $ 16190 $ 3793 $ 3066 $ 16917

Utility SegmentOperation and Maintenance Expense $ 165857 $ 43155 $ 43317 $ 165695

Plus Non-Service Pension Costs 31400 6928 7165 31163Adjusted Operation and Maintenance Expense $ 197257 $ 50083 $ 50482 $ 196858

Energy Marketing SegmentOperation and Maintenance Expense $ 6057 $ 1617 $ 1513 $ 6161

Plus Non-Service Pension Costs 497 123 124 496Adjusted Operation and Maintenance Expense $ 6554 $ 1740 $ 1637 $ 6657

Corporate and All Other Operation and Maintenance Expense $ 17003 $ 3058 $ 3721 $ 16340

Plus Non-Service Pension Costs 664 737 167 1234Adjusted Operation and Maintenance Expense $ 17667 $ 3795 $ 3888 $ 17574

Intersegment Eliminations $ (115112) $ (31643) $ (25517) $ (121238)

ConsolidatedOperation and Maintenance Expense $ 409766 $ 101644 $ 99474 $ 411936

Plus Non-Service Pension Costs 32640 7407 7475 32572Adjusted Operation and Maintenance Expense $ 442406 $ 109051 $ 106949 $ 444508

FY19 FY18 12-MonthsFY 2018 FYTD FYTD Ended 123118

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63

Non-GAAP Reconciliations ndash EampP Operating Expenses

Appendix

Reconciliation of Exploration amp Production Segment Operating Expenses by Division($000s unless noted otherwise)

Appalachia West Coast(2) Total EampP Appalachia West Coast(2) Total EampP Appalachia West Coast(2) Total EampP Appalachia West Coast(2) Total EampP$ Mcfe $ Boe $ Mcfe $ Mcfe $ Boe $ Mcfe

Operating ExpensesGathering amp Transportation Expense (1) $95611 $46 $95657 $060 $002 $054 $92874 $502 $93376 $060 $016 $054Other Lease Operating Expense $14604 $52461 $67065 $009 $1789 $038 $16625 $55990 $72615 $011 $1731 $042Lease Operating and Transportation Expense $110215 $52507 $162721 $069 $1791 $091 $109499 $56492 $165991 $071 $1746 $096

General amp Administrative Expense $60596 $034 $58734 $034

All Other Operating and Maintenance Expense $11077 $006 $13469 $008Property Franchise and Other Taxes $14400 $008 $15426 $009Total Taxes amp Other $25477 $014 $28895 $017

Depreciation Depletion amp Amortization $124274 $070 $112565 $065

ProductionGas Production (MMcf) 160499 2407 162906 154093 2995 157088 Oil Production (MBbl) 4 2531 2535 4 2736 2740

Total Production (Mmcfe) 160523 17592 178114 154117 19411 173528 Total Production (Mboe) 26754 2932 29686 25686 3235 28921

(1) Gathering and Transportation expense is net of any payments received from JDA partner for the partners share of gathering cost(2) Seneca West Coast division includes Seneca corporate and eliminations

Twelve Months Ended September 30 2018

Twelve Months Ended September 30 2017

64

Non-GAAP Reconciliations ndash Adjusted Operation amp Maintenance Expense

Appendix

Reconciliation of Adjusted Operation and Maintenance Expense to Operation and Maintenance Expense By Segment ($ Thousands)

Exploration and Production SegmentOperation and Maintenance

General and Administrative Expense $ 59425 $ 15198 $ 13602 $ 61021Lease Operating and Transportation Expense 162721 42562 39647 165636All Other Operation and Maintenance Expense 11077 2353 2535 10895

Operation and Maintenance Expense $ 233223 60113 55784 237552Plus Non-Service Pension Costs 1171 4 293 882

Adjusted Operation and Maintenance Expense $ 234394 $ 60117 $ 56077 $ 238434

Pipeline and Storage SegmentOperation and Maintenance Expense $ 86876 $ 21633 $ 17672 $ 90837

Plus Non-Service Pension Costs (1420) (467) (356) (1531)Adjusted Operation and Maintenance Expense $ 85456 $ 21166 $ 17316 $ 89306

Gathering SegmentOperation and Maintenance Expense $ 15862 $ 3711 $ 2984 $ 16589

Plus Non-Service Pension Cots 328 82 82 328Adjusted Operation and Maintenance Expense $ 16190 $ 3793 $ 3066 $ 16917

Utility SegmentOperation and Maintenance Expense $ 165857 $ 43155 $ 43317 $ 165695

Plus Non-Service Pension Costs 31400 6928 7165 31163Adjusted Operation and Maintenance Expense $ 197257 $ 50083 $ 50482 $ 196858

Energy Marketing SegmentOperation and Maintenance Expense $ 6057 $ 1617 $ 1513 $ 6161

Plus Non-Service Pension Costs 497 123 124 496Adjusted Operation and Maintenance Expense $ 6554 $ 1740 $ 1637 $ 6657

Corporate and All Other Operation and Maintenance Expense $ 17003 $ 3058 $ 3721 $ 16340

Plus Non-Service Pension Costs 664 737 167 1234Adjusted Operation and Maintenance Expense $ 17667 $ 3795 $ 3888 $ 17574

Intersegment Eliminations $ (115112) $ (31643) $ (25517) $ (121238)

ConsolidatedOperation and Maintenance Expense $ 409766 $ 101644 $ 99474 $ 411936

Plus Non-Service Pension Costs 32640 7407 7475 32572Adjusted Operation and Maintenance Expense $ 442406 $ 109051 $ 106949 $ 444508

FY19 FY18 12-MonthsFY 2018 FYTD FYTD Ended 123118

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64

Non-GAAP Reconciliations ndash Adjusted Operation amp Maintenance Expense

Appendix

Reconciliation of Adjusted Operation and Maintenance Expense to Operation and Maintenance Expense By Segment ($ Thousands)

Exploration and Production SegmentOperation and Maintenance

General and Administrative Expense $ 59425 $ 15198 $ 13602 $ 61021Lease Operating and Transportation Expense 162721 42562 39647 165636All Other Operation and Maintenance Expense 11077 2353 2535 10895

Operation and Maintenance Expense $ 233223 60113 55784 237552Plus Non-Service Pension Costs 1171 4 293 882

Adjusted Operation and Maintenance Expense $ 234394 $ 60117 $ 56077 $ 238434

Pipeline and Storage SegmentOperation and Maintenance Expense $ 86876 $ 21633 $ 17672 $ 90837

Plus Non-Service Pension Costs (1420) (467) (356) (1531)Adjusted Operation and Maintenance Expense $ 85456 $ 21166 $ 17316 $ 89306

Gathering SegmentOperation and Maintenance Expense $ 15862 $ 3711 $ 2984 $ 16589

Plus Non-Service Pension Cots 328 82 82 328Adjusted Operation and Maintenance Expense $ 16190 $ 3793 $ 3066 $ 16917

Utility SegmentOperation and Maintenance Expense $ 165857 $ 43155 $ 43317 $ 165695

Plus Non-Service Pension Costs 31400 6928 7165 31163Adjusted Operation and Maintenance Expense $ 197257 $ 50083 $ 50482 $ 196858

Energy Marketing SegmentOperation and Maintenance Expense $ 6057 $ 1617 $ 1513 $ 6161

Plus Non-Service Pension Costs 497 123 124 496Adjusted Operation and Maintenance Expense $ 6554 $ 1740 $ 1637 $ 6657

Corporate and All Other Operation and Maintenance Expense $ 17003 $ 3058 $ 3721 $ 16340

Plus Non-Service Pension Costs 664 737 167 1234Adjusted Operation and Maintenance Expense $ 17667 $ 3795 $ 3888 $ 17574

Intersegment Eliminations $ (115112) $ (31643) $ (25517) $ (121238)

ConsolidatedOperation and Maintenance Expense $ 409766 $ 101644 $ 99474 $ 411936

Plus Non-Service Pension Costs 32640 7407 7475 32572Adjusted Operation and Maintenance Expense $ 442406 $ 109051 $ 106949 $ 444508

FY19 FY18 12-MonthsFY 2018 FYTD FYTD Ended 123118

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