November 2015 - content.stockpr.comcontent.stockpr.com/.../GPOR_3Q2015_Earnings_vWeb.pdf ·...
Transcript of November 2015 - content.stockpr.comcontent.stockpr.com/.../GPOR_3Q2015_Earnings_vWeb.pdf ·...
Investor PresentationNovember 2015
Forward Looking Statement
This presentation includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the SecuritiesExchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical facts, included in this presentation that address activities, events or developmentsthat Gulfport Energy Corporation (“Gulfport” or “the Company”) expects or anticipates will or may occur in the future, including statements relating to the proposed transactions, future capitalexpenditures (including the amount and nature thereof), business strategy and measures to implement strategy, competitive strength, goals, expansion and growth of Gulfport’s business andoperations, plans, market conditions, references to future success, reference to intentions as to future matters and other such matters are forward-looking statements. These statements arebased on certain assumptions and analyses made by Gulfport in light of its experience and its perception of historical trends, current conditions and expected future developments as well asother factors it believes are appropriate in the circumstances. However, whether actual results and developments will conform with Gulfport’s expectations and predictions is subject to anumber of risks and uncertainties, general economic, market, business or weather conditions; the opportunities (or lack thereof) that may be presented to and pursued by Gulfport; competitiveactions by other oil and gas companies; changes in laws or regulations; and other factors, many of which are beyond the control of Gulfport. Specifically, Gulfport cannot assure you that theproposed transactions described in this presentation will be consummated on the terms Gulfport currently contemplates, if at all. Information concerning these and other factors can be foundin the company’s filings with the Securities and Exchange Commission (“the SEC”), including its Forms 10-K, 10-Q and 8-K. Consequently, all of the forward-looking statements made in thispresentation are qualified by these cautionary statements and there can be no assurances that the actual results or developments anticipated by Gulfport will be realized, or even if realized,that they will have the expected consequences to or effects on Gulfport, its business or operations. We have no intention, and disclaim any obligation, to update or revise any forward-lookingstatements, whether as a result of new information, future results or otherwise.
Prior to 2010, the SEC generally permitted oil and gas companies, in their filings, to disclose only proved reserves that a company has demonstrated by actual production or conclusiveformation tests to be economically and legally producible under existing economic and operating conditions. Beginning with year-end reserves for 2009, the SEC permits the optional disclosureof probable and possible reserves that meet the SEC definitions of such terms. The SEC defines "probable reserves" as those additional reserves that are less certain to be recovered than provedreserves but which, in sum with proved reserves, are as likely as not to be recovered. The SEC defines "possible reserves" as those additional reserves that are less certain to be recovered thanprobable reserves. In this presentation, Gulfport provides disclosure with respect to its probable reserves as of December 31, 2014. However, in its filings with the SEC, Gulfport discloses onlyestimated proved reserves. Gulfport's estimated proved reserves as of December 31, 2014 were prepared by Ryder Scott Company, L.P. ("Ryder Scott") with respect to Gulfport's assets in theUtica Shale in Eastern Ohio (97% of its proved reserves at December 31, 2014), by Netherland, Sewell & Associates, Inc. ("NSAI") with respect to Gulfport's WCBB, Hackberry and Niobrara fields(3% of its proved reserves at December 31, 2014) and by Gulfport's personnel with respect to its overriding royalty and non-operated interests (less than 1% of its proved reserves at December31, 2014), and comply with definitions promulgated by the SEC. Each of Ryder Scott and NSAI is an independent petroleum engineering firm. In this press release, we may use the terms "unriskedresource potential," "unrisked resource," "contingent resource," or "EUR," or other descriptions of volumes of hydrocarbons to describe volumes of resources potentially recoverable throughadditional drilling or recovery techniques that the SEC's guidelines prohibit it from including in filings with the SEC. "Unrisked resource potential," "unrisked resource," "contingent resource," or"EUR," do not reflect volumes that are demonstrated as being commercially or technically recoverable. Even if commercially or technically recoverable, a significant recovery factor would beapplied to these volumes to determine estimates of volumes of proved reserves. Accordingly, these estimates are by their nature more speculative than estimates of proved reserves andaccordingly are subject to substantially greater risk of being actually realized by the Company. The methodology for "unrisked resource potential," "unrisked resource," "contingent resource," or"EUR," may also be different than the methodology and guidelines used by the Society of Petroleum Engineers and is different from the SEC's guidelines for estimating probable and possiblereserves.
EBITDA is a non-GAAP financial measure equal to net income, the most directly comparable GAAP financial measure, plus interest expense, income tax expense, accretion expense anddepreciation, depletion and amortization. We have presented EBITDA because we use EBITDA as an integral part of our internal reporting to measure our performance and to evaluate theperformance of our senior management. EBITDA is considered an important indicator of the operational strength of our business. EBITDA eliminates the uneven effect of considerable amountsof non-cash depletion, depreciation of tangible assets and amortization of certain intangible assets. A limitation of this measure, however, is that it does not reflect the periodic costs of certaincapitalized tangible and intangible assets used in generating revenues in our business. Management evaluates the costs of such tangible and intangible assets and the impact of relatedimpairments through other financial measures, such as capital expenditures, investment spending and return on capital. Therefore, we believe that EBITDA provides useful information to ourinvestors regarding our performance and overall results of operations. EBITDA is not intended to be a performance measure that should be regarded as an alternative to, or more meaningfulthan, either net income as an indicator of operating performance or to cash flows from operating activities as a measure of liquidity. In addition, EBITDA is not intended to represent fundsavailable for dividends, reinvestment or other discretionary uses, and should not be considered in isolation or as a substitute for measures of performance prepared in accordance with GAAP.The EBITDA presented herein may not be comparable to similarly titled measures presented by other companies, and may not be identical to corresponding measures used in our variousagreements, including our debt agreements. For a reconciliation of EBITDA to net income, please refer to the filings we have made with the SEC.
2|WWW.GULFPORTENERGY.COM
Gulfport Today
Key Statistics Primary Areas of Operation (3)
1) Market capitalization calculated as of the close of the market on 11/3/2015 at a price of $30.76 per share using shares outstanding from the Company’s 3Q2015 financial statements.
2) Enterprise value calculated as of the close of the market on 11/3/2015 at a price of $30.76 per share using shares outstanding, short‐term debt, long‐term debt, and cash and cash equivalents from the
Company’s 3Q2015 financial statements.
3) Utica Shale acreage as of 11/4/2015, including Paloma and AEU acquisitions and customary post closing adjustments; all other acreage figures as of 9/30/2015.
4) Reserve and resource estimates based on Gulfport’s 24.9% interest in Grizzly Oil Sands ULC. For important qualifications and limitations relating to these oil sands reserves and resources, please see page
36 of this presentation.
Grizzly Oil Sands (4)
Acreage: ~200,000 Net Acres
Proved Reserves: 16.8 Net MMBbl
Probable Reserves: 48.3 Net MMBbl
Contingent Resource: 697.3 Net MMBbl
Utica ShaleAcreage: ~247,000 Net Acres
Proved Reserves: 907.0 Net Bcfe
Probable Reserves: 300.3 Net Bcfe
Southern LouisianaAcreage: ~11,002 Net Acres
Proved Reserves: 4.1 Net MMBoe
Probable Reserves: 8.1 Net MMBoe
Market Capitalization(1) $3.3 Billion
Enterprise Value (2) $4.1 Billion
2014 Average Daily Production 240.3 MMcfepd
1Q14 162.5 MMcfepd
2Q14 160.3 MMcfepd
3Q14 254.0 MMcfepd
4Q14 381.9 MMcfepd
2015E Average Daily Production 517 – 541 MMcfepd
1Q15 424.4 MMcfepd
2Q15 473.9 MMcfepd
3Q15 647.1 MMcfepd
Net Core Acreage
Utica Shale ~247,000 acres
Southern Louisiana ~11,002 acres
Canadian Oil Sands ~200,000 acres
2014 Proved Reserves 933.6 Bcfe
% Gas 77%
3|WWW.GULFPORTENERGY.COM
4|WWW.GULFPORTENERGY.COM
• Gulfport Energy Corporation (“GPOR”) is an independent E&P company based in Oklahoma City, OK
— Company born from legacy assets in South Louisiana
— Free cash flow from legacy assets facilitated expansion into North America’s premier resource plays
Overview of Gulfport
1997 – 1998 1998 – 2005
Phase 1:Formation/Asset Focus
Phase 2:Low Risk Development
Phase 3:Expansion/Diversification
2005 – 2007
Phase 4:Resource Play Addition
2007 – 2012 2012 – Today
Phase 5:Resource Development
• Gulfport Energy was formed in July 1997
• Initial assets were those of WRT Energy and a 50% working interest in the West Cote Blanche Bay (“WCBB”) field contributed by DLB Oil and Gas
• Gulfport divested a number of assets during this period leaving a cleaner balance sheet and focused asset base
• Focused on production and cash flow growth from low risk development activities principally in WCBB
• Reprocessed 3D seismic in WCBB field
• Created a track record of successful drilling
• Continued successful drilling and growth at the WCBB field
• Conducted a 3-D seismic shoot and drilled first exploratory wells in Hackberry field
• Amassed solid acreage position in Canadian Oil Sands and launched core hole drilling program
• Acquired interest in Phu Horm natural gas field in Thailand
• Acquired initial acreage position in Permian Basin and expanded through acquisitions
• Acquired larger interest in second natural gas field in Thailand
• Secured sizable position in the core of the Utica Shale achieving early entrant advantages
• Initiated aggressive drilling program to begin developing Utica Shale resource and currently running a four rig drilling program
• Contributed Permian Basin interests in Diamondback Energy, Inc. IPO to facilitate accelerated resource development
5|WWW.GULFPORTENERGY.COM
Key Investment and Financial Highlights
1) Excluding $301 million acquisition of Paloma and $407 million acquisition from AEU.2) Acreage as of 11/4/2015, including Paloma and AEU acquisitions and customary post closing adjustments.3) Reserve and resource estimates based on Gulfport’s 24.9% interest in Grizzly Oil Sands ULC.4) Based on the midpoint of 2015 guidance.5) Hedge volume and weighted average price excludes swaptions. Detailed overview on slide 32 of the presentation.
Quality
Assets
Strong
Balance Sheet
Conservative
Financial
Strategy
• High quality, low cost assets allow Gulfport to grow production 115% to 125% over 2014, equating to 517 – 541 Mmcfepd
— Anticipated 2015 E&P capital budget of $667 – $677 million and leasehold budget of $85 – $95 million (1)
• Most levered to the core of the Utica Shale of eastern Ohio with approximately 247,000 (2) net acres under lease
— Actively drilling horizontal wells; produced 624.5 MMcfepd during 3Q2015
— Development expected to provide further catalyst for reserves and production growth
• Canadian oil sands provides net exposure to over 762 million barrels of oil resource (3)
• South Louisiana oil production provides strong base of cash flows for resource play expansion — Produced 3,559 Boepd during 3Q2015; high quality Louisiana Sweet crude priced at a premium to WTI
• Strong balance sheet and cash flow expected to allow Gulfport to continue to drive production growth
— Current undrawn borrowing base of $700 million
— Liquidity of $751 million as of 9/30/2015
• Remain committed to funding 2015 activities through operational cash flow, the Company's credit facility and other available sources of liquidity
— Capital will compete and be deployed into highest return projects
• Gulfport actively hedges a portion of its expected production to lock in prices and returns which provide certainty of cash flows to execute on its capital plans
— Currently ~57% (4) of 2015E natural gas production is hedged attractively at $3.94 per MMBtu
— Strong hedge position in 2016 with ~380 (5) Mmcfepd of natural gas production hedged at $3.46 per MMBtu
— Company targets to have 50% to 70% of expected twelve-month run rate total production hedged
Year Ending
12/31/2015
Forecasted Production
Average Daily Gas Equivalent Midpoint – MMcfepd 517 541
% Gas 75% 85%
% Liquids 25% 15%
Forecasted Realizations (before the effects of hedges)
Natural Gas (Differential to NYMEX) - $ per MMBtu ($0.68) ($0.72)
NGL ($ per gallon) $0.37 $0.32Oil (Differential to NYMEX WTI) - $ per Bbl ($7.00)
Projected Operating Costs
Lease Operating Expense - $/Mcfe $0.38 $0.32
Midstream Processing and Marketing - $/Mcfe $0.73 $0.71
Production Taxes - $/Mcfe $0.09 $0.07
General and Administrative (1) - $MM $46 $48
Depreciation, Depletion, and Amortization - $/Mcfe $1.85 $1.75
Budgeted E&P Capital Expenditures – in Millions:
Utica – Operated $514 $517
Utica – Non- Operated $135 $140
Southern Louisiana $18 $20
Total Budgeted E&P Capital Expenditures $667 $677
Budgeted Leasehold Capital Expenditures (2) – in Millions: $85 $95
Net Wells Drilled
Utica – Operated 39 41
Utica – Non- Operated 4 6
Total 43 47Net Wells Completed
Utica – Operated 52 54
Utica – Non- Operated 7 9
Total 59 63
6|WWW.GULFPORTENERGY.COM
Gulfport 2015 Guidance
Utica - Operated$515.5
Utica
Non-
Operated
$137.5
S. Louisiana
$19.0
Leasehold
$90.0
1) Inclusive of non-cash stock compensation.2) Does not include Paloma acquisition or AEU acquisitions.Note: Guidance for the year ending 12/31/15 is based on multiple assumptions and certain analyses made by the Company in light of its experience and perception of historical trends and current conditions and may change due to future developments. Actual results may not conform to the Company’s expectations and predictions. Please refer to page 2 for more detail of forward looking statements.
3rd Quarter 2015 Highlights
7|WWW.GULFPORTENERGY.COM
Increased 155% Year-over-Year
Total Production Production Mix
Utica Wells Completed Oil and Gas Revenues Per Unit Levered Cash Costs
Increased 19% Year-over-Year
Produced~647.1 MMcfe per day
during 3Q2015 Production mix consisted of 81% gas and 19% liquids
during 3Q2015
Approximately $168.2 million (1) in 3Q2015
$1.49 per Mcfe in 3Q2015, a decrease of 31%
Year-over-Year
At quarter end 3Q2015, 153 gross (119.1 net)
Utica wells producing
Utica Production Growth
Utica production of ~624.5 MMcfepd, an increase of
173% Year-over-Year
1) Third Quarter 2015 oil and gas revenues excluding the impact of the unrealized non-cash hedge gain.
YE 2012 YE 2013 YE 2014 YTD 2015
1
26
73
119
2
38
101
153 Net Wells Online
Gross Wells Online
$0.00
$1.00
$2.00
$3.00
4Q'14 1Q'15 2Q'15 3Q'15
MM
cfe
LOE Production Taxes Midstream SG&A Interest
$1.99
$1.73 $1.73$1.49
81%
19% Gas
Liquids
4Q'14 1Q'15 2Q'15 3Q'15
353.4396.0
457.6
624.5MMcfe per day
-
100
200
300
400
500
600
700
1Q'14 2Q'14 3Q'14 4Q'14 1Q'15 2Q'15 3Q'15 2015E
MM
cfe
/da
y
Liquids Gas
2011 2012 2013 2014 2015
49,000
106,000
157,200
184,000
247,000(1)
Net Acreage
8|WWW.GULFPORTENERGY.COM
Strong Growth Ahead
8
Key Highlights Total Net Production
• Gulfport’s total production during 2014 grew 255% over 2013
― Anticipate 2015 production to increase 115% to 125% over 2014
• Gulfport turned-to-sales 47 net operated and 7 net non-operated wells during 2014 in the Utica Shale
― Anticipate 52 to 54 net wells to be completed during 2015
• During 2014 and YTD 2015, Gulfport continues to add acreage in the core of the Utica Shale and currently holds ~247,000 (1) net acres
• Growth in the Utica Shale added significant proved reserve volumes during 2014, increasing 305% over 2013
Net Utica Wells Turned to Sales
1) Acreage as of 11/4/2015, including Paloma and AEU acquisitions and customary post closing adjustment.2) Based on the midpoint of 2015 Guidance. Guidance for the year ending 12/31/15 is based on multiple assumptions and certain
analyses made by the Company in light of its experience and perception of historical trends and current conditions and may change due to future developments. Actual results may not conform to the Company’s expectations and predictions. Please referto page 2 for more detail of forward looking statements.
-
10
20
30
40
50
60
70
1Q'14 2Q'14 3Q'14 4Q'14 2014 2015E
11 7
14 16
47 53
-
1
3 3
7
8
Num
be
r o
f W
ells
Operated
Non-Operated
61 (2)
55
1917
811
Net Utica Acreage
162.5 160.3
254.0
381.9
424.4
473.9
529.0 (2)
647.1
Total Reserve Growth
-
200
400
600
800
1,000
2011 2012 2013 2014
Bcfe
PDP
PDNP
PUD
11683
231
934
Contribution of Permian Basin
interests to Diamondback
77.4 MMcfe
$-
$200
$400
$600
$800
$1,000
$1,200
Credit Facilty Bank Debt (9/30/15) L/Cs Outstanding (9/30/15) Cash (9/30/15) Pro Forma Liquidity
($ M
illio
ns)
Liquidity, Capitalization and Hedge Position
1) Hedge volume and weighted average price excludes swaptions. Detailed overview on slide 32 of the presentation.2) Price forecast as of 11/3/2015.3) Based on the midpoint of 2015 guidance.
Pro Forma Liquidity Position
Gas Hedges (1) Key Highlights
• Strong liquidity and hedge position fund 2015 capital program and provide certainty of cash flows
— Liquidity at 9/30/2015 of $751.0 million
— Gulfport has locked in approximately 57% (3) of expected natural gas production in 2015 at $3.94 per MMBtu
• Strong hedge position in 2016
— Hedged ~380 MMcfepd of natural gas production in 2016 at $3.46 per MMBtu
• Currently expect to exit 2015 at less than 2.5x debt-to-TTM EBITDA based of 2015 forecast at current commodity prices (2)
9|WWW.GULFPORTENERGY.COM
$700
$0
($177.1) $228.1
$751.0
$3.94
$3.46 $3.47$3.35 $3.37
$2.26
$2.57$2.85 $2.96 $3.04
$0.00
$1.00
$2.00
$3.00
$4.00
-
50
100
150
200
250
300
350
400
2015 2016 2017 2018 2019
Mm
cfp
d
Hedge Volume Average Weighted Hedge Price Nymex Strip (2)
Asset Overview
10|WWW.GULFPORTENERGY.COM
10
Utica Shale Overview
• Net proved reserves of 907.0 Bcfe (1)
• Net probable reserves of 300.3 Bcfe (1)
• ~ 247,000 net acres (2)
— Oil - ~ 5%
— Condensate - ~17%
— Wet Gas - ~ 15%
— Dry Gas - ~ 63%
Asset Overview
2015 Activities Update (3)
• Average net production of 624.5 MMcfepd
• ~97% of Gulfport’s total net production
2015 Planned Activities (4)
• Currently running 4 gross operated rigs
— + 1 non-operated rig running within RICE/GPOR AMI
• Operated CAPEX: $514 – $517 million
— Drill 49 to 53 gross (39 to 41 net) wells
— Complete 64 to 68 gross (52 to 54 net) wells
• Non-Operated CAPEX: $135 – $140 million
— Drill 11 to 16 gross (4 to 6 net) wells
— Complete 50 to 64 gross (7 to 9 net) wells
Note: Please refer to page 2 for detail on forward looking statements.1) As of 12/31/2014.2) Acreage as of 11/4/2015, including Paloma and AEU acquisitions and customary post closing adjustments.3) During the three months ended 9/30/2015.4) As of 11/4/2015.
11|WWW.GULFPORTENERGY.COM
CarrizoRector #1H
AnteroWayne Pad
AnteroMiley Pad
Magnum Hunter
Farley Pad
Eclipse ResourcesTippens Pad
Rice EnergyBig Foot #9H
Rice EnergyBlue Thunder Unit
Chevron Howard Connor
Unit
HessCapstone
#2H-29
Gulfport Energy
Warrick Pad
Gulfport Energy
Donato Pad
Gulfport EnergyThompson South Pad
RICE/GPOR AMI Rig
LEGEND
Gulfport Acreage
GPOR Activity
Magnum Hunter
Stalder #3UH
Magnum Hunter
Ormet Pad
GastarSimms Pad
Gulfport Energy
Jade Pad
ChesapeakeBuell #8H
CONSOL / Hess
Athens A #1H-24
RICE/GPOR AMI Rig
Utica Shale – Drilling and Completion Activity
Net Wells Spud
Net Wells Completed
Forecast 23 to 29 gross drilled uncompleted wells in inventory at YE2015
1Q'14 2Q'14 3Q'14 4Q'14 2014 2015E (1)
3 6 3 12
3
8 5
-
16
12 4
5
17
13
40
28
3
3
4
2
11
5
Nu
mb
er
of
We
lls
Non-Op
Dry Gas
Wet Gas
Condensate
1Q'14 2Q'14 3Q'14 4Q'14 2014 2015E (1)
7 1 4
12 7
3 5
5
10
23
3 1
9
2
12
42
1
3 3
7
8
Nu
mb
er
of
We
lls
Non-Op
Dry Gas
Wet Gas
Condensate
10
19
32
18
79
45
117
17 19
54
61
12|WWW.GULFPORTENERGY.COM
1) Based on midpoint of 2015 guidance.
LEGEND
Gulfport Acreage
Drilled/Planned 2015
Drilled 2014
Drilled 2013
13|WWW.GULFPORTENERGY.COM
Utica Shale – Type Curve Assumptions
Condensate Wet Dry Gas
Type Curve Assumptions (1) West East Gas West Central East
Lateral Length 8,000 8,000 8,000 8,000 8,000 8,000
Well Cost ($MM) $8.7 $8.7 $9.3 $9.5 $9.7 $9.9
Well Cost ($ per foot) $1,083 $1,083 $1,164 $1,187 $1,211 $1,234
Total EUR (Bcfe / 1,000) 0.7 1.0 2.0 2.2 2.4 2.6
Total EUR (Bcfe) 5.7 8.1 16.0 17.2 19.0 20.7
% Gas 42% 56% 77% 100% 100% 100%
Assumed Well Spacing (ft) 600 600 750 750 750 750
Net Undeveloped Location 181 88 191 188 423 251
Utica Single Well Economics (1) (2)
181
88
191 188
423
251
15%12%
37%
65%
69%72%
-
50
100
150
200
250
300
350
400
450
0%
10%
20%
30%
40%
50%
60%
70%
80%
Condensate
West
Condensate East Wet Gas Dry Gas West Dry Gas Central Dry Gas East
Ne
t Un
de
ve
lop
ed
Loc
atio
ns
IRR
Net Undeveloped Locations IRR
Note: See appendix slide 24 for detailed assumptions used to generate single well IRRs and slide 28 for net undeveloped locations. 1) Assumes ethane rejection.2) Well economics are based on flat price case of $3.50 / MMBtu gas, $58.00 / Bbl oil, and $14.00 / Bbl NGLs.
LEGEND
Gulfport Acreage
14|WWW.GULFPORTENERGY.COM
Utica Shale – Single Well Economics
Utica Shale Economics and Inventory (1)
15%
30%
45%
12%
25%
38%
14%
37%
66%
98%
14%
37%
65%
97%
134%
17%
41%
69%
102%
138%
19%
43%
72%
105%
141%
0%
20%
40%
60%
80%
100%
120%
140%
160%
Gas $2.50 / Oil $42.50 /
NGL $10.00
Gas $3.00 / Oil $50.00 /
NGL $12.00
Gas $3.50 / Oil $58.00 /
NGL $14.00
Gas $4.00 / Oil $67.00 /
NGL $16.00
Gas $4.50 / Oil $75.00 /
NGL $18.00
Condensate West Condensate East Wet Gas Dry Gas West Dry Gas Central Dry Gas East
Condensate
West
Condensate
East
Wet
Gas
Dry Gas
West
Dry Gas
Central
Dry Gas
East
Net Undeveloped Locations 181 88 191 188 423 251
Note: See appendix slide 24 for detailed assumptions used to generate single well IRRs and slide 28 for net undeveloped locations.1) Assumes ethane rejection.
Key Highlights
• Focused acreage position in the core of the play
• Consistency of the reservoir enables us to stay within the target zone, the Point Pleasant
─ Highly uniformed stratigraphy and limited reservoir variation
─ Structural simplicity, low dip and minimal faults
─ Petrophysical properties extremely uniform across the play
• Stratigraphy and structural simplicity allow for highly repeatable results
WestA
East Aʹ
SouthB
North Bʹ
Aʹ
B
Bʹ
116 ft 118 ft
122 ft98 ft
Utica Shale – Consistency of Reservoir
15|WWW.GULFPORTENERGY.COM
A
LEGEND
Gulfport Acreage
Utica Shale – Diversified Portfolio
Overview
SENECA PLANT
CADIZ PLANT
LEBANON
CLARINGTON &SWITZERLAND
DEFIANCE
DAWN
MICHCON
CHICAGO CITY GATE
CONSUMERS
ANR Pipeline (North)Amount: 250,000 Dth/d
Market: MidwestCurrently In-Service
Rover Pipeline (North)Amount: 125,000 Dth/d
Market: Midwest and DawnIn-Service 1H2017
Rover Pipeline (South)Amount: 25,000 Dth/d
Market: GulfIn-Service 1H2017
ANR Pipeline (South)Amount: 50,000 Dth/d
Market: GulfCurrently In-Service
Dominion Transmission Amount: 250,000 Dth/d
Market: LebanonCurrently In-Service
Dominion East OhioAmount: 520,000 Dth/d
Market: DTI, TGP, Rex, TETCOCurrently In-Service
Tennessee Gas Pipeline
Amount: 200,000 Dth/dMarket: Gulf
Currently In-ServiceTexas Gas
TransmissionAmount: 104,000 Dth/d
Market: GulfIn-Service June 2016 and April 2017
Columbia (Leach/Rayne)Amount: 100,000 Dth/d
Market: GulfIn-Service November 2017
TETCO PipelineAmount: 147,000 Dth/d
Market: GulfIn-Service Nov 2015 and Nov 2017
Gas City
Rockies Express Amount: 315,000 Dth/dMarket: Midwest / Gulf
Currently In-Service
NGPL PipelineAmount: 20,000 Dth/d
Market: ChicagoCurrently In-Service
16|WWW.GULFPORTENERGY.COM
0
200,000
400,000
600,000
800,000
1,000,000
1,200,000
1,400,000
MM
Btu
pe
r d
ay
Overview
Utica Shale – Firm Transportation and Sales Outlets
Firm Commitments (MMBtu per day)
YE2014 YE2015 YE2016 YE2017 +
(MMBtu / day)
Midwest Markets
ANR Pipeline 184,000 229,000 244,000 244,000
Dominion Transmission Pipeline 11,000 6,000 6,000
NGPL 20,000 20,000 20,000
Rockies Express Pipeline 63,000 153,000 153,000
Rover Pipeline 15,000 15,000
TETCO 46,000
Canadian Markets
ANR Pipeline 60,000 60,000
Rover Pipeline 110,000 110,000
Gulf Coast Markets
ANR Pipeline 50,000 50,000 50,000
Tennessee Gas Pipeline 200,000 200,000 200,000
Texas Gas Transmission 50,000 104,000
Rover Pipeline 25,000 25,000
Columbia Pipeline 100,000
Firm Sales Agreements
Dominion South Point 5,000 5,000
TETCO M2 50,000 75,000 75,000 75,000
Chicago City Gate 50,000
Fixed Basis 33,000 214,000 274,000 124,000
TOTAL 382,000 927,000 1,222,000 1,272,000
Firm Transportation Costs ($ per MMBtu)
$0.00
$0.20
$0.40
$0.60
$0.80
$1.00
2015 2016 2017
$0.47 $0.50 $0.53
$0.11 $0.10 $0.10
$0.58 $0.60 $0.63
$ p
er
MM
Btu
Demand Variable
ANR (Midwest) – November 2016
ET Rover (Dawn) – November 2016
ET Rover (Midwest) – November 2016
Rex (Midwest) – Current
TGP (Gulf) – Current
ANR (Gulf) – Current
ANR (Dawn/Midwest) – Current
DTI (Midwest) – Current TGT (Gulf) – June 2016
NGPL (Midwest) – Current
ET Rover (Gulf) – November 2016
TETCO (Michcon) – November 2017
Firm Sales
Columbia (Gulf) – November 2017
17|WWW.GULFPORTENERGY.COM
ANR (Midwest) – Current
• Early access to premium Midwest markets and was a first-mover in securing early transport at low costs out of the basin
• For 2015, we estimate ~90% of Gulfport’s expected Utica gas production is being sold at premium pricing points
• Gulfport expects to realize a natural gas price of ($0.68) to ($0.72) below Henry Hub in 2015
• Currently have ~57% of 2015E natural gas production hedged which provides certainty to realizations and cash flows
Overview
Utica Shale – Transportation Improves Pricing
2015 Average Differential Firm Portfolio
2013 1Q 2015 Current
382,000
923,000
1,272,000
MM
Btu
pe
r d
ay
YE 2017 Secured Transport Commitments
2015E
Henry Hub ($/MMBtu) (1) $2.66
Basis Differential ($/MMBtu) (2) ($0.70)
BTU Uplift (MMBtu/Scf) $0.18
Pre-Hedge Realized Price ($/Mcf) $2.14
Hedging Impact $0.73
Post-Hedge Realized Price (S/Mcf) $2.87
1) Price forecast as of 11/3/15.2) Based on midpoint of 2015E guidance.
8%
21%
36%
7%
28%
Remainder 2015
Firm Sales (Index)
Firm Sales (Fixed)
Midwest
Canadian
Gulf Coast
3%7%
40%
11%
39%
2016 and Beyond
18|WWW.GULFPORTENERGY.COM
Utica Shale – NGL Infrastructure
Edmonton Markets
Midwest Markets
Ontario Markets
Northeast Markets
Mid-Atlantic Markets
Gulf Coast Markets
Marcus Hook
Chesapeake
Africa
Asia
South Am.
EuropeRail
PipeTruck
Key Highlights
• Gulfport anticipates to realize $0.32 to $0.37 per gallon for NGLS during 2015
• Mont Belvieu propane at lows not seen since 2002
— Compared to Mont Belvieu, Gulfport has more of the barrel subject to seasonal swings
• Expect NGL weakness to continue near-term but believe overall prices could show some improvement during the fourth quarter due to higher seasonal demand and additional export capacity coming on line.
12%
7%
6%
38%
37%
Mont Belvieu
Barrel Makeup
C2 Purity Ethane
C3 Propane
IC4 IsoButane
NC4 Normal Butane
C5+ Rest
Markets % of 2015 C3+ Bbl
Northeast 43%
Export 15%
Gulf Coast 14%
Edmonton 10%
Midwest 9%
Mid-Atlantic 5%
Ontario 4%
100%
Transport Method % of 2015 C3+ Bbl
By Rail 60-65%
By Pipeline 30-35%
By Truck 5-10%
NGL Barrel Composition
19|WWW.GULFPORTENERGY.COM
13%
11%
11%
42%
22%
YTD NGL
Barrel Makeup
Utica Shale – Midstream Infrastructure
Note: Per MarkWest Energy Partners Third Quarter Conference Call Presentation on November 4, 2015.
20|WWW.GULFPORTENERGY.COM
Cadiz ComplexCadiz I - III – 525 MMcf/d – Operational
Cadiz IV – 200 MMcf/d – 2Q16De-ethanization – 40,000 Bbl/d – Operational
Ohio Gathering & Ohio CondensateStabilization Facility – 23,000 Bbl/d– Operational
Hopedale FractionatorC3+ Fractionation I & II- 120,000 Bbl/d – Operational
C3+ Fractionation III - 60,000 Bbl/d –2Q16
Seneca ComplexSeneca I - IV- 800 MMcf/d – Operational
MarkWest Dry Gas SystemOperational
Rice Energy Dry Gas SystemOperational
Gulfport Dry Gas SystemOperational
LEGEND
GPOR Lease Acreage
MarkWest Wet System
MarkWest Dry System
MarkWest NGL Pipeline
Rice Dry System
GPOR Dry System
RICE/GPOR JV Dry Gas System
Rice Energy/Gulfport Dry Gas SystemMid-2016
Utica Shale – Strategic Midstream Joint Venture
21|WWW.GULFPORTENERGY.COM
Overview
Participating in Extensive Dry Gas System in One of the Most Prolific Natural Gas Plays
• GPOR and RICE to form midstream JV to provide gas gathering, compression and water services to GPOR’s Eastern Belmont and Monroe acreage
— Approximately 165 miles of high and low pressure 12” – 30” dry gas gathering pipeline to be constructed
— Approximately $520MM to develop gathering and compression assets and $120MM for water assets
— Approximately 1.8 MMDth/d of estimated throughput capacity
• Plan to pursue third party opportunities within 340,000 acre AMI
• Ownership: GPOR 25% and RICE 75% with RICE to construct and operate all JV assets
• Creates enhanced alignment with midstream provider, providing certainty to timing of infrastructure buildout and further predictability to Gulfport’s production profile
• Provides Gulfport with complete connectivity of our gathering systems and interchangeability of molecules across our firm portfolio
LEGEND
GPOR Lease Acreage
Acreage AMI
GPOR dedicated to RICE
RICE Ohio gathering pipeline
GPOR 12” Pipeline form AEU
Proposed gathering in JV
Southern Louisiana
Asset Overview (1)
2015 Activities Update (2)
2015 Planned Activities (3)
• Net proved reserves of 4.1 MMBoe
• Net probable reserves of 8.1 MMBoe
• 11,002 net acres
• Gulfport operated
• Average net production of 3,559 Boepd during 3Q2015
• ~3% of Gulfport’s total net production
• ~99% oil weighted production mix
— Priced as high quality LLS crude and sold at a premium to WTI
• Maintenance CAPEX: $18 – $20 million
Note: Please refer to page 2 for detail on forward looking statements.1) As of 12/31/2014.2) During the three-month period ended 9/30/2015.3) As of 11/4/2015. 22|WWW.GULFPORTENERGY.COM
Utica Appendix
23|WWW.GULFPORTENERGY.COM
CondensateWest
Condensate East
Wet Gas
Dry Gas West
Dry Gas Central
Dry Gas East
Identified Net Locations 181 88 191 188 423 251
Type Curve Assumptions
Lateral Length (ft.) 8,000 8,000 8,000 8,000 8,000 8,000
Initial Gas Production (Mcf/d) (1) 2,500 3,300 12,000 14,000 14,000 14,000
Flat Period (days) 90 90 274 243 274 304
Shrink 13% 13% 12% N/A N/A N/A
NGL Yield (Bbls/MMcf) 71 65 44 N/A N/A N/A
Residue BTU 1,140 1,135 1,095 1,070 1,060 1,050
Pre-Processed EUR (Bcfe) 4.9 6.7 14.0 17.2 19.0 20.7
Pre-Processed % Gas 56% 78% 100% 100% 100% 100%
Post-Processed EUR (Bcfe / 1,000') (2) 0.7 1.0 2.0 2.2 2.4 2.6
Post-Processed EUR (Bcfe) (2) 5.7 8.1 16.0 17.2 19.0 20.7
Oil (MBbl) 358 249 7 - - -
NGL (MBbl) 196 338 614 - - -
Residue Gas (MMcf) 2,389 4,527 12,227 17,202 18,952 20,711
Post Processed % Gas 42% 56% 77% 100% 100% 100%
Differentials (3)
Gas ($ / MMBtu off NYMEX) $ (0.65) $ (0.65) $ (0.65) $ (0.65) $ (0.65) $ (0.65)
Condensate ($ / Bbl off WTI) $ (10.00) $ (10.00) $ (10.00) $ (10.00) $ (10.00) $ (10.00)
NGL ($ / gallon) $ 12.60 $ 12.60 $ 12.60 $ 12.60 $ 12.60 $ 12.60
Operating Expenses
OPEX - Year 1
Fixed ($/well/mo) $ 25,000 $ 25,000 $ 25,000 $ 25,000 $ 25,000 $ 25,000
Variable ($/Mcf) $ 0.17 $ 0.15 $ 0.05 $ 0.05 $ 0.05 $ 0.05
OPEX - Year 2
Fixed ($/well/mo) $ 20,000 $ 20,000 $ 20,000 $ 20,000 $ 20,000 $ 20,000
Variable ($/Mcf) $ 0.09 $ 0.07 $ 0.02 $ 0.02 $ 0.02 $ 0.02
OPEX - Year 3+
Fixed ($/well/mo) $ 15,000 $ 15,000 $ 15,000 $ 15,000 $ 15,000 $ 15,000
Variable ($/Mcf) $ 0.09 $ 0.07 $ 0.02 $ 0.02 $ 0.02 $ 0.02
Gathering & Compression ($/Mcf) $ 0.64 $ 0.64 $ 0.56 $ 0.40 $ 0.40 $ 0.40
Processing ($/Mcf) $ 0.65 $ 0.65 $ 0.52 N/A N/A N/A
Severance Tax 2.5% 2.5% 2.5% 2.5% 2.5% 2.5%
Well Cost Assumptions
Well Cost ($MM) $ 8.7 $ 8.7 $ 9.3 $ 9.5 $ 9.7 $ 9.9
Well Cost ($ per foot) $ 1,083 $ 1,083 $ 1,164 $ 1,187 $ 1,211 $ 1,234
Utica Shale – Type Curve Assumptions
24|WWW.GULFPORTENERGY.COM
Note: See appendix slide 28 for detailed assumptions used to net undeveloped locations. 1) Represents 24-hour rate well head gas production.2) Assumes ethane rejection.3) Includes transportation costs and basis differentials.
Utica Shale – Condensate Window Type Curves
Condensate Type Curves (1)
15%
30%
45%
12%
25%
38%
0%
10%
20%
30%
40%
50%
Gas $2.50 / Oil $42.50 /
NGL $10.00
Gas $3.00 / Oil $50.00 /
NGL $12.00
Gas $3.50 / Oil $58.00 /
NGL $14.00
Gas $4.00 / Oil $67.00 /
NGL $16.00
Gas $4.50 / Oil $75.00 /
NGL $18.00
Condensate West Condensate East
Single Well Economics (1)
0.0
0.5
1.0
1.5
2.0
2.5
3.0
3.5
4.0
-
1,000
2,000
3,000
4,000
5,000
6,000
7,000
Bc
feM
cfe
pe
r d
ay
Months0.7 Bcfe / 1,000' Daily Production 1.0 Bcfe / 1,000' Daily Production
0.7 Bcfe / 1,000' Cumulative Production 1.0 Bcfe / 1,000' Cumulative Production
Condensate
Type Curve Assumptions (1) West East
Lateral Length 8,000 8,000
Well Cost ($MM) $8.7 $8.7
Well Cost ($ per foot) $1,083 $1,083
Total EUR (Bcfe / 1,000) 0.7 1.0
Total EUR (Bcfe) 5.7 8.1
% Gas 42% 56%
Assumed Well Spacing (ft) 600 600
Net Undeveloped Locations 181 88
25|WWW.GULFPORTENERGY.COM
Note: See appendix slide 24 for detailed assumptions used to generate single well IRRs and slide 28 for net undeveloped locations. 1) Assumes ethane rejection.
Utica Shale – Wet Gas Window Type Curve
Wet Gas Type Curves (1)
14%
37%
66%
98%
0%
20%
40%
60%
80%
100%
Gas $2.50 / Oil $42.50 /
NGL $10.00
Gas $3.00 / Oil $50.00 /
NGL $12.00
Gas $3.50 / Oil $58.00 /
NGL $14.00
Gas $4.00 / Oil $67.00 /
NGL $16.00
Gas $4.50 / Oil $75.00 /
NGL $18.00
Wet Gas
Single Well Economics (1)
0.0
1.0
2.0
3.0
4.0
5.0
6.0
7.0
8.0
9.0
10.0
-
2,000
4,000
6,000
8,000
10,000
12,000
14,000
16,000
Bc
feM
cfe
pe
r d
ay
Months
2.0 Bcfe / 1,000' Daily Production 2.0 Bcfe / 1,000' Cumulative Production
Wet
Type Curve Assumptions (1) Gas
Lateral Length 8,000
Well Cost ($MM) $9.3
Well Cost ($ per foot) $1,164
Total EUR (Bcfe / 1,000) 2.0
Total EUR (Bcfe) 16.0
% Gas 77%
Assumed Well Spacing (ft) 750
Net Undeveloped Locations 191
26|WWW.GULFPORTENERGY.COM
Note: See appendix slide 24 for detailed assumptions used to generate single well IRRs and slide 28 for net undeveloped locations. 1) Assumes ethane rejection.
Utica Shale – Dry Gas Window Type Curves
Dry Gas Type Curves (1)
14%
37%
65%
97%
134%
17%
41%
69%
102%
138%
19%
43%
72%
105%
141%
0%
20%
40%
60%
80%
100%
120%
140%
Gas $2.50 / Oil $42.50 /
NGL $10.00
Gas $3.00 / Oil $50.00 /
NGL $12.00
Gas $3.50 / Oil $58.00 /
NGL $14.00
Gas $4.00 / Oil $67.00 /
NGL $16.00
Gas $4.50 / Oil $75.00 /
NGL $18.00
Dry Gas West Dry Gas Central Dry Gas East
Single Well Economics (1)
0.0
2.0
4.0
6.0
8.0
10.0
12.0
-
2,000
4,000
6,000
8,000
10,000
12,000
14,000
16,000
Bc
feM
cfe
pe
r d
ay
Months
2.2 Bcfe / 1,000' Daily Production 2.4 Bcfe / 1,000' Daily Production 2.6 Bcfe / 1,000' Daily Production
2.2 Bcfe / 1,000' Cumulative Production 2.4 Bcfe / 1,000' Cumulative Production 2.6 Bcfe / 1,000' Cumulative Production
Dry Gas
Type Curve Assumptions (1) West Central East
Lateral Length 8,000 8,000 8,000
Well Cost ($MM) $9.5 $9.7 $9.9
Well Cost ($ per foot) $1,187 $1,211 $1,234
Total EUR (Bcfe / 1,000) 2.2 2.4 2.6
Total EUR (Bcfe) 17.2 19.0 20.7
% Gas 100% 100% 100%
Assumed Well Spacing (ft) 750 750 750
Net Undeveloped Locations 188 423 251
27|WWW.GULFPORTENERGY.COM
Note: See appendix slide 24 for detailed assumptions used to generate single well IRRs and slide 28 for net undeveloped locations. 1) Assumes ethane rejection.
Determination of Identified Drilling Locations as of September 30, 2015
Net Undeveloped Locations: Calculated by taking Gulfport’s total net acreage and multiplying such amount by a risking factor which is then divided by Gulfport’s expected well spacing. Gulfport then subtracts net producing wells to arrive at undeveloped net drilling locations.
Net Undeveloped Utica Condensate West Locations: Gulfport assumes these locations have 8,000 foot laterals and 600 foot spacing between wells which yields approximately 110 acre spacing. We apply a 20% risking factor to the net acreage to account for inefficient unitization and the risk associated with the inability to force pool in Ohio.
Net Undeveloped Utica Condensate East Locations: Gulfport assumes these locations have 8,000 foot laterals and 600 foot spacing between wells which yields approximately 110 acre spacing. We apply a 20% risking factor to the net acreage to account for inefficient unitization and the risk associated with the inability to force pool in Ohio.
Net Undeveloped Utica Wet Gas Locations: Gulfport assumes these locations have 8,000 foot laterals and 750 foot spacing between wells which yields approximately 138 acre spacing. We apply a 20% risking factor to the net acreage to account for inefficient unitization and the risk associated with the inability to force pool in Ohio.
Net Undeveloped Utica Dry Gas West Locations: Gulfport assumes these locations have 8,000 foot laterals and 750 foot spacing between wells which yields approximately 138 acre spacing. We apply a 20% risking factor to the net acreage to account for inefficient unitization and the risk associated with the inability to force pool in Ohio.
Net Undeveloped Utica Dry Gas Central Locations: Gulfport assumes these locations have 8,000 foot laterals and 750 foot spacing between wells which yields approximately 138 acre spacing. We apply a 20% risking factor to the net acreage to account for inefficient unitization and the risk associated with the inability to force pool in Ohio.
Net Undeveloped Utica Dry Gas East Locations: Gulfport assumes these locations have 8,000 foot laterals and 750 foot spacing between wells which yields approximately 138 acre spacing. We apply a 20% risking factor to the net acreage to account for inefficient unitization and the risk associated with the inability to force pool in Ohio.
Additional Disclosures
Net Undeveloped Locations (1)
Condensate
West
Condensate
East
Wet
Gas
Dry Gas
West
Dry Gas
Central
Dry Gas
East
Net Undeveloped Location Summary
Net Acres 26,491 14,264 38,064 34,123 77,552 43,429
Lateral Length 8,000 8,000 8,000 8,000 8,000 8,000
Location Spacing 600 600 750 750 750 750
Net Potential Locations 240 129 276 248 563 315
Less approximate wells turned to sales (2) 14 19 37 13 34 1
Unrisked Net Undeveloped Locations 226 110 239 235 529 314
Risking Factor 20% 20% 20% 20% 20% 20%
Risked Net Undeveloped Locations 181 88 191 188 423 251
28|WWW.GULFPORTENERGY.COM
1) All acreage as of 11/4/2015 pro forma for Paloma and AEU acquisitions and customary post closing adjustments.2) Wells turned to sales as of 9/30/2015.
Overview
Utica and SW Marcellus Proposed Pipeline Projects
Source: Wood Mackenzie, “North America gas markets short-term outlook October 2015”.
29|WWW.GULFPORTENERGY.COM
Pipeline/Project Name From Area Direction Total Capacity (MMBtu/day) Start-Up Date
Millennium Express Hancock Northeast Pennsylvania East 205 Apr-14
Tennessee SWLA - Phase 1 Southwest Marcellus & Utica South 400 Apr-14
Rockies Express Seneca Lateral Phase 1 Utica West 225 Apr-14
Dominion Leidy receipts Northeast Pennsylvania West 150 Jun-14
Millennium to Dominion Northeast Pennsylvania South 200 Jun-14
Dominion Lebanon West - Phase 1 Southwest Marcellus & Utica West 250 Jun-14
Tennessee SWLA - Phase 2 Southwest Marcellus & Utica South 200 Jun-14
Texas Eastern Team South Southwest Marcellus & Utica South 300 Sep-14
Texas Eastern Team 2014 - M2 to M3 Existing Market East 300 Nov-14
Tennessee - Uniondale Northeast Pennsylvania East 34 Nov-14
Tennessee Rose Lake Project Northeast Pennsylvania West 230 Nov-14
Columbia Gas Westside/Smithfield III to Leach Southwest Marcellus & Utica South 444 Nov-14
Texas Eastern Team 2014 - M2 to Lebanon Southwest Marcellus & Utica West 50 Nov-14
Texas Eastern Team 2014 - M2 to M1 East Southwest Marcellus & Utica South 250 Nov-14
Rockies Express Seneca Lateral Phase 2 Utica West 375 Nov-14
Transco Northeast Connector to Rockaway Lateral Existing Market East 100 Dec-14
Equitrans Jefferson Compressor Southwest Marcellus & Utica Supply 600 Dec-14
Rockies Express East-to-West* Southwest Marcellus & Utica West 900 Apr-15
Transco Rockaway Delivery Lateral Existing Market New York 647 Jun-15
Rockies Express East-to-West* Southwest Marcellus & Utica West 300 Aug-15
Texas Eastern Uniontown to Gas City Southwest Marcellus & Utica West 425 Aug-15
Transco Virginia Southside Existing Market Southeast 270 Sep-15
Ohio Pipeline Energy Network (OPEN) Southwest Marcellus & Utica South 550 Sep-15
Sulphur Springs Expansion Southwest Marcellus & Utica West 133 Oct-15
Columbia Gas Eastside Expansion Project Northeast Pennsylvania Southeast 312 Nov-15
Northern Access 2015/Niagara Expansion Project Northeast Pennsylvania North 158 Nov-15
Tennessee Broad Run Lateral Southwest Marcellus & Utica South 590 Nov-15
National Fuel Line N Expansion Utica Supply 175 Nov-15
Transco Leidy Southeast Northeast Pennsylvania Southeast 525 Dec-15
Rockies Express Zone 3 Capacity Enhancement Southwest Marcellus & Utica West 800 Apr-16
Equitrans Ohio Valley Connector Southwest Marcellus & Utica Supply 400 Jul-16
Transco Rocksprings Lateral Existing Market New Jersey 192 Aug-16
Constitution Pipeline Northeast Pennsylvania North 650 Sep-16
Rockies Express East-to-West* Southwest Marcellus & Utica West 300 Sep-16
Iroquois South to North Existing Market Canada 300 Nov-16
New Market Project Northeast Pennsylvania North 112 Nov-16
Dominion Lebanon West - Phase 2 Southwest Marcellus & Utica West 130 Nov-16
Dominion West Virginia West Project Southwest Marcellus & Utica Supply 250 Nov-16
Texas Eastern Gulf Markets Expansion - Phase 1 Southwest Marcellus & Utica South 350 Nov-16
Algonquin Incremental Market Existing Market New England 340 Nov-16
Northern Access 2016 Northeast Pennsylvania North 350 Nov-16
ET Rover Southwest Marcellus & Utica West 3,200 Dec-16
Dalton Expansion Project Existing Market Southeast 448 May-17
Atlantic Sunrise Northeast Pennsylvania Southeast 1,700 Sep-17
Penn East Northeast Pennsylvania East 1,000 Nov-17
Susquehanna West Northeast Pennsylvania West 145 Nov-17
Adair Southwest Southwest Marcellus & Utica South 200 Nov-17
Broad Run Expansion Zone 3 to Zone 1 500L Southwest Marcellus & Utica South 200 Nov-17
Gulf Markets Expansion Phase 2 Southwest Marcellus & Utica South 100 Nov-17
Leach Express Southwest Marcellus & Utica South 1,500 Nov-17
NEXUS Pipeline Southwest Marcellus & Utica West 1,500 Nov-17
WB Express Broad Run Part 2 Southwest Marcellus & Utica South 200 Nov-17
23,665
Overview
LNG Exports – Proposed Gulf Coast Projects
Project Name Sponsor Nominal Capacity
(MMtpa)
Nominal Capacity
(Bcf/d)FERC Status Development Status
Sabine Pass Cheniere 18 2.40 Approved Under construction
Cameron Sempra 12 1.60 Approved Under construction
Freeport Export Train 1-2 Freeport LNG 10 1.33 Approved Under construction
Freeport Export Train 3 Freeport LNG 5 0.67 Approved Under construction
Corpus Christi Train 1-2 Cheniere 9 1.20 Approved Under construction
Sabine Pass Train 5 Cheniere 4.5 0.60 Approved Under construction
Corpus Christi Train 3 Cheniere 4.5 0.60 Approved
Sabine Pass Train 6 Cheniere 4.5 0.60 Approved
Lake Charles Export Energy Transfer Equity 15 2.00 H2 15
Magnolia LNG LNG Ltd 8 1.07 2016
Golden Pass Export Golden Pass Products 15.6 2.08 2016
Elba Island Shell 2.5 0.33 2016
Source: Wood Mackenzie, “US FERC tracker – Q3 2015 ,” October 2015.
30|WWW.GULFPORTENERGY.COM
Hedge Book (1)
Hedged Production
1) As of November 4, 2015. 2) Counterparty has option to call.
4Q15 1Q16 2Q16 3Q16 4Q16 2015 2016 2017 2018 2018
Natural Gas Contract Summary:
Natural Gas Fixed Price Swaps (NYMEX)
Volume (BBtupd) 296 415 378 355 372 241 380 162 70 5
Weighted Average Price ($/MMBtu) $ 3.87 $ 3.56 $ 3.45 $ 3.42 $ 3.39 $ 3.94 $ 3.46 $ 3.47 $ 3.35 $ 3.37
Natural Gas Fixed Price Swaptions (NYMEX) (2)
Volume (BBtupd) - 75 95 95 95 - 90 65 - -
Weighted Average Price ($/MMBtu) $ - $ 3.25 $ 3.18 $ 3.18 $ 3.18 $ - $ 3.19 $ 3.30 $ - $ -
Total Potential Natural Gas Volumes (BBtupd) 296 490 473 450 467 241 470 227 70 5
Total Weighted Average Price ($/MMBtu) $ 3.87 $ 3.51 $ 3.40 $ 3.37 $ 3.35 $ 3.94 $ 3.41 $ 3.42 $ 3.35 $ 3.37
Oil Contract Summary:
Oil Fixed Price Swaps (LLS)
Volume (Bblpd) 1,500 1,500 1,500 - - 1,132 746 - - -
Weighted Average Price ($/Bbl) $ 63.03 $ 63.03 $ 63.03 $ - $ - $ 62.86 $ 63.03 $ - $ - $ -
Oil Fixed Price Swaps (WTI)
Volume (Bblpd) 1,000 1,000 1,000 $ - $ - 586 497 - - -
Weighted Average Price ($/Bbl) $ 61.40 $ 61.40 $ 61.40 $ - $ - $ 61.40 $ 61.40 $ - $ - $ -
Total Potential Crude Oil (Bblpd) 2,500 2,500 2,500 - - 1,718 1,243 - - -
Total Weighted Average Price ($/Bbl) $ 62.38 $ 62.38 $ 62.38 $ - $ - $ 62.36 $ 62.38 $ - $ - $ -
Propane Contract Summary:
C3 Propane Fixed Price Swaps (TET)
Volume (Bblpd) 1,000 1,000 1,000 1,000 1,000 252 1,000 - - -
Weighted Average Price ($/Gal) $ 0.48 $ 0.48 $ 0.48 $ 0.48 $ 0.48 $ 0.48 $ 0.48 $ - $ - $ -
Basis Contract Summary:
MichCon
Volume (BBtupd) 60 70 40 40 40 39 47 - - -
Differential ($/MMBtu) $ 0.09 $ 0.11 $ 0.02 $ 0.02 $ 0.02 $ 0.05 $ 0.05 $ - $ - $ -
Tetco M2
Volume (BBtupd) - - - - 33 - 8 12 - -
Differential ($/MMBtu) $ - $ - $ - $ - $ (0.59) $ - $ (0.59) $ (0.59) $ - $ -
32|WWW.GULFPORTENERGY.COM
Financial and Operational Summary
33|WWW.GULFPORTENERGY.COM
2014 2015 3Q2015 Results1Q2014 2Q2014 3Q2014 4Q2014 FY2014 1Q2015 2Q2015 3Q2015 YTD 2015 FY2015E Q-o-Q Y-o-Y
Production
Gas - Bcf 7.7 9.0 16.6 26.1 59.3 26.0 33.1 48.1 107.2 45% 191%
Oil - MBbls 726.7 709.5 571.4 676.1 2,683.8 765.6 727.1 732.1 2,224.8 1% 28%
Liquids - MBbls 434.2 227.1 563.6 824.9 2,049.8 1,273.3 941.0 1,168.9 3,383.2 24% 107%
Total Equivalent (Bcfe) 14.6 14.6 23.4 35.1 87.7 38.2 43.1 59.5 140.9 187.6 197.5 38% 155%
Total Daily Equivalent (MMcfepd) 162,523 160,349 253,990 381,886 240,327 424,425 473,935 647,062 515,956 514,000 541,000 37% 155%
Product Mix
Gas 52% 61% 71% 74% 68% 68% 77% 81% 76% 75% 85% 5% 14%
Liquids 48% 39% 29% 26% 32% 32% 23% 19% 24% 25% 15% (17%) (34%)
Realized Prices
Average Realized Prices before the impact of derivatives ($/Mcfe) $9.28 $8.30 $6.04 $4.66 $6.40 $3.30 $2.84 $2.33 $2.75 (18%) (61%)
Average Realized Prices incl. cash-settlement of derivatives ($/Mcfe) $8.65 $7.69 $6.03 $4.84 $6.27 $3.30 $3.41 $2.83 $3.26 (17%) (53%)
Average Realized Prices including derivatives ($/Mcfe) $8.06 $7.85 $7.29 $7.63 $7.65 $4.61 $2.60 $3.87 $3.68 49% (47%)
Average NYMEX Henry Hub ($/MMBtu) $4.92 $4.67 $4.06 $4.00 $4.41 $2.98 $2.64 $2.77 $2.80 5% (32%)
Differential to Henry Hub ($/MMBtu) (0.35) (0.61) (0.71) (0.91) (0.91) (0.44) (0.59) (0.87) (0.70) ($0.68) ($0.72)
Natural Gas Realized Price before the impact of derivatives ($/MMBtu) $4.57 $4.06 $3.35 $3.09 $3.50 $2.54 $2.05 $1.90 $2.10 (7%) (43%)
BTU Upgrade (MMBtu / Scf) 0.41 0.37 0.30 0.28 0.31 0.23 0.18 0.17 0.19
Natural Gas Realized Price before the impact of derivatives ($/Mcf) $4.98 $4.43 $3.65 $3.37 $3.81 $2.77 $2.23 $2.07 $2.29 (7%) (43%)
Impact of cash settled derivatives ($/Mcf) (1.05) (0.83) 0.01 0.11 (0.20) 0.67 0.74 0.55 0.64
Natural Gas Realized Price incl. cash-settlement of derivatives ($/Mcf) $3.93 $3.60 $3.66 $3.48 $3.61 $3.44 $2.97 $2.62 $2.93 (12%) (28%)
Average NYMEX WTI ($/Bbl) $98.61 $102.98 $97.21 $73.12 $92.92 $48.57 $57.96 $46.44 $50.98 (20%) (52%)
Differential to WTI ($/Bbl) (0.35) (3.57) (3.32) (5.63) (3.04) (6.85) (7.81) (5.91) (6.90) ($7.00)
Oil Realized Price before the impact of derivatives ($/Mcf) $98.26 $99.40 $93.89 $67.48 $89.88 $41.72 $50.15 $40.53 $44.08 (19%) (57%)
Impact of cash settled derivatives ($/Mcf) (1.53) (2.11) (0.64) 4.91 0.13 1.88 (0.01) 4.30 2.06
Oil Realized Price incl. cash-settlement of derivatives ($/Mcf) $96.73 $97.29 $93.25 $72.39 $90.01 $43.59 $50.14 $44.84 $46.14 (11%) (52%)
NGL Realized Price before the impact of derivatives ($/Gal) $1.43 $1.14 $1.14 $0.87 $1.09 $0.41 $0.30 $0.19 $0.31 $0.37 $0.32 (37%) (83%)
Impact of cash settled derivatives ($/Gal) - - - - - - - - -
NGL Realized Price incl. cash-settlement of derivatives ($/Gal) $1.43 $1.14 $1.14 $0.87 $1.09 $0.41 $0.30 $0.19 $0.31 (37%) (83%)
Operating Expenses per Mcfe
Lease operating expense $0.80 $0.87 $0.51 $0.46 $0.59 $0.44 $0.39 $0.30 $0.36 $0.38 $0.32 (25%) (42%)
Production taxes $0.48 $0.45 $0.22 $0.15 $0.27 $0.11 $0.08 $0.06 $0.08 $0.09 $0.07 (21%) (73%)
Midstream gathering and processing $0.53 $0.74 $0.80 $0.77 $0.73 $0.66 $0.76 $0.71 $0.71 $0.73 $0.71 (7%) (12%)
Unit Operating Costs $1.80 $2.06 $1.53 $1.38 $1.60 $1.22 $1.23 $1.06 $1.16 $1.20 $1.10 (14%) (31%)
Revenues (in thousands)
Gas sales $18,349 $35,522 $85,168 $190,215 $329,254 $118,570 $65,871 $179,215 $363,656 172% 110%
Oil and condensates sales 73,377 68,078 58,196 47,730 247,381 35,500 34,465 41,747 111,712 21% (28%)
Liquid sales 26,136 10,897 27,021 30,073 94,127 22,007 11,958 9,431 43,396 (21%) (65%)
Other income, net 167 239 419 (321) 504 240 (24) 176 392 (833%) (58%)
Total Revenue $118,029 $114,736 $170,804 $267,697 $671,266 $176,317 $112,270 $230,569 $519,156 105% 35%
Plus unrealized hedge (gain) loss 8,666 (2,232) (29,482) (98,099) (121,147) (31,324) 34,633 (62,182) (58,873) (280%) 111%
Total Revenue excl. non-cash impact from derivatives $126,695 $112,504 $141,322 $169,598 $550,119 $144,993 $146,903 $168,387 $460,283 15% 19%
Expenses (in thousands)
Lease operating expense $11,629 $12,680 $11,883 $15,999 $52,191 $16,980 $16,863 $17,568 $51,411 4% 48%
Production taxes 6,957 6,601 5,213 5,235 24,006 4,285 3,285 3,593 11,163 9% (31%)
Midstream gathering and processing 7,769 10,780 18,714 27,204 64,467 25,381 32,904 42,166 100,451 28% 125%
General and administrative 9,511 10,382 8,939 9,458 38,290 10,799 9,515 11,001 31,315 16% 23%
Other (106) (36) (25) (28) (195) (9) (248) (279) (536) 13% 1,016%
Adjusted EBITDA $90,935 $72,097 $96,598 $111,730 $371,360 $87,557 $84,584 $94,338 $266,479 12% (2%)
Depreciation, depletion and amortization 56,877 55,994 72,409 80,151 265,431 89,909 71,155 90,329 251,393 27% 25%
Adjusted Net Income (Loss) $16,737 $6,114 $11,019 $10,654 $44,524 ($7,187) $250 ($8,694) ($15,631) (3,578%) (179%)
Net Reserves as of December 31, 2014
Oil Gas NGL Total PV-10 ($MM)
(MMBbls) (Bcf) (MMBbls) (Bcfe) SEC (1)
Proved Developed Producing 3.5 344.1 12.4 439.4 $1,154
Proved Developed Non-Producing 2.2 1.1 - 14.4 $82
Proved Undeveloped 3.8 373.8 13.9 479.8 $605
Total Proved Reserves 9.5 719.0 26.3 933.6 $1,841
Probable Reserves 9.1 260.4 5.7 349.6 $578
Total Proved + Probable Reserves 18.6 979.4 32.0 1,283.2 $2,419
SEC 1P Net Present Value – 10%SEC Proved Reserve AllocationSEC Net Proved Reserves
2014 Proved Reserve Summary
1) Per Company reserve report for year ending 12/31/14.
PDP
47%
PDNP
2%
PUD
51%
Oil
6%NGL
17%
Gas
77%
PDP
68%
PDNP
3%
PUD
29%
34|WWW.GULFPORTENERGY.COM
Grizzly Oil Sands
• Gulfport has interest in a substantial position in the Canadian oil sands by way of a 24.9% interest in Grizzly Oil Sands ULC (“Grizzly”)
— Grizzly is effectively the last major private company in the oil sands without a joint venture partner
Note: Gulfport Energy Corporation owns 24.9% of Grizzly Oil Sands ULC. For important qualification and limitations relating to these oil sands reserves and resources, please see page 36 of this presentation1) GLJ Petroleum Consultants Ltd, as December 31, 2014.
• Over 800,000 net acres in Athabasca and Peace River regions (nearly all 100% working interest)
• 67 million bbls of proved reserves, 193 million bbls of probable reserves, and approximately 3.0 billion bbls of 2P+Contingent Resources (1)
• Grizzly’s “ARMS” development model enables repeatable and scalable project development, reducing execution and financing risk
Grizzly Summary Grizzly Acreage
35|WWW.GULFPORTENERGY.COM
— Notes:
— Proved reserves are defined in the Canadian Oil and Gas Evaluation Handbook (the "COGE Handbook") as those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated Proved reserves.
— Probable reserves are defined in the COGE Handbook as those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.
— Contingent Resources are defined in the COGE Handbook as those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies.
— Prospective Resources are defined in the COGE Handbook as those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects.
— Best Estimate as defined in the COGE Handbook is considered to be the best estimate of the quantity that will actually be recovered from the accumulation. If probabilistic methods are used, this term is a measure of central tendency of the uncertainty distribution (P50).
— Discovered Petroleum Initially-In-Place are defined in the COGE Handbook as that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations prior to production.
— Undiscovered Petroleum Initially-In-Place are defined in the COGE Handbook as that quantity of petroleum that is estimated, on a given date, to be contained in accumulations yet to be discovered.
— It should be noted that reserves, Contingent Resources and Prospective Resources involve different risks associated with achieving commerciality. There is no certainty that it will be commercially viable for Grizzly to produce any portion of the Contingent Resources. There is no certainty that any portion of Grizzly’s Prospective Resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the Prospective Resources. Grizzly’s Prospective Resource estimates discussed in this press release have been risked for the chance of discovery but not for the chance of development and hence are considered by Grizzly as partially risked estimates.
Reserves and Resources Notes
Note: Gulfport Energy Corporation owns 24.9% of Grizzly Oil Sands ULC.
36|WWW.GULFPORTENERGY.COM
Gulfport Energy Headquarters14313 North May Avenue, Suite 100
Oklahoma City, OK 73134www.gulfportenergy.com
Investor Relations (405) 242-4888