US Capital Advisors E&P Corporate Access DayMarchand Horizontal Producer Marchand Vertical Producer...

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US Capital Advisors E&P Corporate Access Day January 12, 2017

Transcript of US Capital Advisors E&P Corporate Access DayMarchand Horizontal Producer Marchand Vertical Producer...

Page 1: US Capital Advisors E&P Corporate Access DayMarchand Horizontal Producer Marchand Vertical Producer Riley 1‐34H IP30: 720 Boe/d 4/16 Hoxbar MarchandCore Area EUR ~ 550 MBoe Well

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US Capital AdvisorsE&P Corporate Access Day

January 12, 2017

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Forward Looking Statement

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This presentation contains forward‐looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical facts, included in this presentation that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future are forward‐looking statements. The words “believe,” “expect,” “anticipate,” “plan,” “intend,” “foresee,” “should,” “would,” “could,” or other similar expressions are intended to identify forward‐looking statements, which are generally not historical in nature. However, the absence of these words does not mean that the statements are not forward‐looking. Without limiting the generality of the foregoing, forward‐looking statements contained in this presentation specifically include the expectations of plans, strategies, objectives and anticipated financial and operating results of the Company, including as to the Company’s drilling program, production, hedging activities, capital expenditure levels and other guidance included in this presentation. These statements are based on certain assumptions made by the Company based on management’s expectations and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied or expressed by the forward‐looking statements. These include risks relating to financial performance and results, current economic conditions and resulting capital restraints, prices and demand for oil and natural gas, availability of drilling equipment and personnel, availability of sufficient capital to execute the Company’s business plan, the Company’s ability to replace reserves and efficiently develop and exploit its current reserves and other important factors that could cause actual results to differ materially from those projected.  Any forward‐looking statement speaks only as of the date on which such statement is made and the Company undertakes no obligation to correct or update any forward‐looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law. The SEC generally permits oil and gas companies, in filings made with the SEC, to disclose only proved reserves, which are reserve estimates that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. In this communication, the Company uses the term “unproved reserves” which the SEC guidelines prohibit from being included in filings with the SEC. “Unproved reserves” refers to the Company’s internal estimates of hydrocarbon quantities that may be potentially discovered through exploratory drilling or recovered with additional drilling or recovery techniques. Unproved reserves may not constitute reserves within the meaning of the Society of Petroleum Engineer’s Petroleum Resource Management System or proposed SEC rules and does not include any proved reserves. Actual quantities that may be ultimately recovered from the Company’s interests will differ substantially. Factors affecting ultimate recovery include the scope of the Company’s ongoing drilling program, which will be directly affected by the availability of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory approvals and other factors; and actual drilling results, including geological and mechanical factors affecting recovery rates. Estimates of unproved reserves may change significantly as development of the Company’s core assets provide additional data. In addition, our production forecasts and expectations for future periods are dependent upon many assumptions, including estimates of production decline rates from existing wells and the undertaking and outcome of future drilling activity, which may be affected by significant commodity price declines or drilling cost increases.

This presentation contains financial measures that have not been prepared in accordance with U.S. Generally Accepted Accounting Principles (“non‐GAAP financial measures”) including LTM EBITDA and certain debt ratios.  The non‐GAAP financial measures should not be considered a substitute for financial measures prepared in accordance with U.S. Generally Accepted Accounting Principles (“GAAP”).  We urge you to review the reconciliations of the non‐GAAP financial measures to GAAP financial measures in the appendix.

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Unit Corporation: A Diversified Energy Company

3

12

10

5

54

13

Casper Casper 

Houston Houston 

Oklahoma City

Oklahoma City

PittsburghPittsburgh

Tulsa HeadquartersTulsa HeadquartersArkoma Basin

Marcellus

North La/ East Texas Basin

Gulf Coast Basin

Anadarko Basin

Permian Basin94 Unit Rigs

E&P Operations

Mid‐Stream Operations

Office Location

• Tulsa based, incorporated in 1963

• Integrated approach to business allows Unit to capture margin from each business segment

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Setting the Stage for 2017

We have weathered many cycles during our 50+ year history

Maintain spending within cash flow Resume E&P drilling program Use cash flow to drill new wells Continue to manage costs

4

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2016 Highlights

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$165 million anticipated 2016 capital expenditures – well within budget range of $161 millionto $187 million.

Exploration & Production 2015 year end total proves reserves: 811 Bcfe or 135 MMBoe

Wilcox Q3 production averaged 90 MMcfe per day – for 2016, completed 4 horizontal wells, 10 behind pipe recompletions, and 7 workovers

Granite Wash (Buffalo Wallow) Dixon 5554 XL #1H well during the first 250 days has cumulative production of approximately 50% greater than the projected type curve. 

Beginning to put rigs back into service in Q4 – one currently in SOHOT and one in Granite Wash before year end 

Drilling All nine BOSS rigs operating under contract

Increased number of rigs in service from a low of 13 to 22, a 69% increase

Continue to upgrade SCR rigs with new technology

Midstream Connected two wells pads to Pittsburgh Mills gathering system in Butler County, Pennsylvania (151 MMcf per day 

average daily Q3  throughput volume)

Completed Snow Shoe gathering system in Centre County, Pennsylvania (11 MMcf per day average Q3 throughput volume)

Q3 year over year gathering volumes increased 20%  

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Senior Subordinated Notes

$650 million, 6.625%

10‐year, NC5; maturity 2021

Key Covenants      Interest coverage ratio ≥ 2.25x(1)

Secured Bank Facility (Amended October 2016) * Elected Commitment 

and Current Borrowing Base  $475 million

Outstanding(2) $215.0 million

Maturity April 2020

Key Covenants              Current ratio ≥ 1.0 to 1.0(1)

Senior Indebtedness ratio ≤ 2.75(1)

Debt Structure – No Near‐Term Maturities

6(1) As defined in Indenture/Credit Agreement.(2) As of September 30, 2016. *  Drilling rigs are not included in borrowing base.

Ratings S&P Moody’s FitchCorporate B+ B2 B+Senior Subordinated Notes B+ B3 BB‐

9/30/20164.60x(1,2)

9/30/2016 Actual2.70x(1,2)

0.85x(1,2)

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Core Upstream Producing Areas

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Gas54%

29%NGLs

9 Mos. ‘16 Daily Production: 48 MBoe/d

Key focus areas include:Gulf Coast: Wilcox (Southeast Texas)

Mid‐Continent: Hoxbar (Western Oklahoma) Granite Wash (Texas Panhandle)

Mid Continent Region

Upper Gulf Coast Region

Wilcox

SOHOTGranite Wash

0102030405060

2011 2012 2013 2014 2015 9 mos.2016

Natural Gas Oil / NGLs

82 80 91 121 8

Average Production (MBoe/d)

3339 46 4850 55

35Net Wells Drilled:

17%Oil

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“D”

“F‐1”

“E”

“A"

“A‐1”

“A‐2”

“B”

“C”

“C‐1”

“F”

“G”

Buffalo Wallow Field – Granite Wash Stacked Pay  

8

Dixon 5554 XL #1H

Gross Thickness   =   2,273 Feet

* Shaded intervals have been tested horizontally

Vertical well

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Granite Wash Extended Length Laterals (~7,500’)  

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 ‐

 500

 1,000

 1,500

 2,000

 2,500

0 50 100 150 200 250 300

Cumulative Prod

uctio

n (M

MCFE)

Days

1 1/3/2017 Strip Price Deck with 1st Production Starting 1/1/2017;See Q1 2017 Economic Prices in Appendix (also available at www.unitcorp.com/investor/reports/html).

2 ROR calculation includes midstream margin.

Projected Type Curve (C1)7.9 Bcfe EUR

Dixon 5554 XL #1H (C1)9 – 12 Bcfe EUR

Buffalo Wallow Prospect 7,000 contiguous net acres Operated and ~90% HBP Average working interest ~ 95% 190 ‐ 240 potential XL locations    (11 Granite Wash lenses) Resumed drilling activity in December 2016

Projected Type Curve (C1 Lense) 18‐22 locations  Gross EUR 7.9 Bcfe Well cost $6.0 MM  ROR1: ≈64% ROR1,2:  ≈94% Dixon 5554 XL #1H (C1) is 1st7,500’ lateral in Buffalo Wallow

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Hoxbar (Marchand Sand)

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H O X B A R  3 , 0 0 0 ’

Harper  1‐19HIP30:  2,467 Boe/d

1/15

Rosey 1H IP30:  1,483 Boe/d

9/14

Powers 1‐15HIP30: 1,233 Boe/d

12/14

Norris 1‐28HIP30: 950 Boe/d

3/16

Earl 2‐30HIP30: 1,817 Boe/d

8/14

GB 1‐30H   IP30: 1,367 Boe/d

3/14

Brown  1‐11HIP30:  867  Boe/d

1/15

Schenk 17‐2HIP30:  450  Boe/d

2/16

McGuffin 1‐19HIP30:  930  Boe/d

1/16

Marchand Horizontal ProducerMarchand Vertical Producer

Riley 1‐34HIP30: 720 Boe/d

4/16

Hoxbar Marchand Core Area EUR ~ 550 MBoe Well cost ~ $5.0 MM 83% liquids (68% oil) 55‐65 locations with average 

working interest of 40‐45% Working interest will increase 

through poolings ROR1 > 100% Resumed drilling in Q4 2016 Seven wells planned for 2017

Future Growth Seeking approval from OCC 

to drill Hoxbar extended laterals

Kicked off waterfloodfeasibility study in Q4 2016

Waterflood offers a significant upside potential

1 1/3/2017 Strip Price Deck with 1st Production Starting 1/1/2017;See Q1 2017 Economic Prices in Appendix (also available at www.unitcorp.com/investor/reports/html).

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Wilcox (Southeast Texas)

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Overall Wilcox Highlights  Drilled 157 operated wells since 2003

(150 vertical, 7 horizontal) Program ROR > 100% Operated with working interest ~ 92% Production: ~ 90 MMcfe/d (42% liquids) Resuming drilling activity in Jan. 2017JASPER

POLK

3D AREA494 mi.²

HARDIN

Prior Years DrillingHorizontal Wells

TYLER

Gilly Field

0

10

20

30

40

2012 2013 2014 2015 2016 est.

Gas Oil NGLs

Wilcox Annual ProductionBcfe

Gilly Field – World Class Gas Reservoir 500 Bcfe stacked pay gas resource Cumulative production ~ 94 Bcfe Average EUR of 10‐20 Bcfe per well Typical well cost ~ $6 MM ROR > 100%

Future Growth Over 100 stacked pay recompletions and 

workovers to do in existing wells Two exploration areas to test in 2017 Generating new exploration ideas using 

165 square miles of 3‐D data

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Gilly Field Wilcox Cross Section

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Temporarily Abandoned Perforations Current Production

Future Behind Pipe Recompletions 2016 YTD Q3 Behind Pipe Recompletions 2017 1st Half Behind Pipe Recompletions

ParkerGU #1

Parker#4

Parker#2

Gilly Field Gilly DT

BS R #4BS O #3

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YTD 2016 Wilcox BPR & Workover Results

Composite Gross Production from BPRs and Workovers10 BPRs   &   7 Workovers     Total Cost: $7.1 MM

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Start of Year3,360 mcfd80 bopd

End of Q330,920 mcfd1,280 bopd

* BPR:  Behind Pipe Recompletion

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Rig Fleet Presence in Key Regions

14

10

12

54

135

Area # of RigsAnadarko Basin 10

Bakken 3Niobrara 1Permian 5Pinedale 2Wilcox 1Total 22

Current Rigs Operating(1)

94 rig fleet 

69% electric 56% 1,500 HP or greater 94 equipped with top drives 59 equipped with skidding or walking systems

17% total fleet utilization rate for Q3 2016  Nine BOSS rigs operating under contract

20 ≤800 HP: 21%70 1,000‐1,700 HP: 75%4 ≥2,000 HP: 4%

(1) As of January 10, 2017.

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Average Dayrates and Margins (1)

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Average Rig Utilization

Margins and

 Dayrates

$0

$5,000

$10,000

$15,000

$20,000

2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 9 mos.'16

Margins Dayrates Average Rig Utilization

100%

75%

50%

25%

0%

(1) See Reconciliation of Average Daily Operating Margin Before Elimination of Intercompany Rig Profit and Bad Debt Expense in Appendix(also available at www.unitcorp.com/investor/reports.html).

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The BOSS Drilling Rig

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Optimized for Pad Drilling Multi‐direction walking system

Faster Between Locations Quick assembly substructure 32‐34 truck loads

More Hydraulic Horsepower (2) 2,200 horsepower 

mud pumps 1,500 gpm available

with one pump

Environmentally Conscious Dual‐fuel capable 

engines Compact location 

footprint

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Appalachia 66,000+ dedicated acres 53 miles of gathering pipeline Connected 24 new wells in2016

Midstream Core Operations

17

TulsaHeadquarters

PittsburghRegional office

Hemphill

Reno

Bellmon

Segno

Pittsburgh Mills

Processing facilities

Gathering systems

Panola

Key Metrics

• 26 active systems

• Three natural gas treatment plants

• 343 MMcf/d processing capacity

• Q3’16 processing volume 153 MMcf/d 

• Approx. 1,460 miles of pipeline

East Texas 62 Miles of gathering pipeline 120 MMcf/d gathering capacity

Texas Panhandle 52,000 dedicated acres 135 MMcf/d processing capacity 343 miles of gathering pipeline

Northern Oklahoma and Kansas 1,972,000+ dedicated acres 193 MMcf/d processing capacity 572 miles of gathering pipeline

Central & Eastern OK 57,000+ dedicated acres 15 MMcf/d processing capacity 428 miles of gathering pipeline

Brook Field

Snow Shoe

Bruceton Mills

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Midstream Segment Contract Mix

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Contract Mix Based on Margin

Fee BasedCommodity Based

85%30%

70%

15%

Contract Mix Based on Volume

Fee BasedCommodity Based

49%23%

77%51%

2010 Q3 2016

Unit vs. 3rd Party Margin Contribution

3rd PartyUnit

41% 37%63%59%

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Appalachian Growth Projects

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Snow Shoe Gathering System in Centre County, PA

– First flow in January 2016– Six wells currently connected to 

this system– Average gathering volumes were

11 MMcf/d in Q3 2016

Pittsburgh Mills gathering system in Butler County, PA 

– Connected 6 new wells in Q3 2016– Total of 18 wells connected to this 

system in 2016– Received notice to connect a new 

well pad mid‐2017– Average gathered volumes were 

151 MMcf/d in Q3 2016

A P P A L A C H I A N    P R O J E C T S

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Segment Contribution

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Oil and Natural Gas Contract Drilling Midstream

Revenues ($ millions)            Adjusted EBITDA ($ millions)(1)

$0

$200

$400

$600

$800

$1,000

$1,200

$1,400

$1,600

2012 2013 2014 2015 9 mos. 2016

$0

$200

$400

$600

$800

2012 2013 2014 2015 9 mos. 2016

$1,352

$1,573

$854

$428

$1,315

$787

$410

$170

$679 $667

(1) See Non‐GAAP Financial Measures in Appendix (also available at www.unitcorp.com/investor/reports.html).

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Operating Segment Capital Expenditures

21

$0

$500

$1,000

$1,500

2011 2012 2013 2014 2015 2016 Low EndBudget

2016 High EndBudget

Oil and Natural Gas Contract Drilling Midstream Acquisitions

(In Millions)

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APPENDIX

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Non‐GAAP Financial Measures ‐ Corporate

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Adjusted EBITDA

Years ended December 31,($ In Millions) 2016 2012 2013 2014 20152015

Nine months ended September 30,Q3 LTM

Net Income (Loss) ($728)  ($137) $23  $185  $136  ($1,037) ($446)Income Taxes (439) (73) 16  117  87  (627) (261)Depreciation, Depletion and Amortization 280  160  319  334  405  355  235 

Impairments 1,149  161  284  0  158  1,635  647 Interest Expense 23  30  14  15  17  32  39 (Gain) loss on derivatives (13) 5 1  8  (30) (26) (8)Settlements during the period of matured derivative contracts 32  12  0  (2) (6) 47  27 

Stock compensation plans 13  11  17  22  24  21  19 Other non‐cash items 3  2  5  5  5  3  2 (Gain) loss on disposition of assets 6 (1)  0  (17) (9) 7  0 Adjusted EBITDA $326  $170  $679  $667  $787  $410  $254 

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Unit PetroleumIncome (Loss) Before Income Taxes (1) $ (1,163) $ (137) $ (77) $ 239 $ 199 $ (1,631)

Depreciation, Depletion and Amortization 202 89 211 226 276 252Impairment of Oil and Natural Gas Properties 1,141 162 284 ‐ 77 1,599

Adjusted EBITDA $ 180 $ 114 $ 418 $ 465 $ 552 $ 220

Unit DrillingIncome (Loss) Before Income Taxes (1) $ 41 $ (12) $ 159 $ 96 $ 42 $ 45

Depreciation and Impairment 51 34 81 71 160 64Adjusted EBITDA $ 92 $ 22 $ 240 $ 167 $ 202 $ 109

Superior PipelineIncome (Loss) Before Income Taxes (1) $ (1) $ (1) $ 6 $ 11 $ 2 $ (30)

Depreciation, Amortization and Impairment 33 34 24 33 48 71Adjusted EBITDA $ 32 $ 33 $ 30 $ 44 $ 50 $ 41

(1) Does not include allocation of G&A expense.

Non‐GAAP Financial Measures ‐ Segments

24

Adjusted EBITDAYears ended December 31,

($ In Millions) 2016 2012 2013 2014 20152015Nine months ended September 30,

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Non‐GAAP Financial Measures

25

Reconciliation of Average Daily Operating MarginBefore Elimination of Intercompany Rig Profit and Bad Debt Expense

Years ended December 31,(In thousands except for operating daysand operating margins) 2016 2012 2013 2014 20152015

Nine months ended September 30,

Contract drilling revenue $215,114  $88,786  $529,719  $414,778  $476,517  $265,668 

Contract drilling operating cost 123,717  66,489  289,524  247,280  274,933  156,408 

Operating profit from contract drilling $91,397  $22,297  $240,195  $167,498  $201,584  $109,260 

Add:

Elimination of intercompany rig profit and bad debt expense 3,666  235  15,583  17,416  29,343  3,991 

Operating profit from contract drilling before elimination of intercompany rig profit and bad debt expense

95,063  22,532  255,778  184,914  230,927  113,251 

Contract drilling operating days 10,175  4,578  26,704  23,720  27,516  12,681 

Average daily operating margin before elimination of intercompany rig profit and bad debt expense

$9,343  $4,922  $9,578  $7,796  $8,392  $8,931 

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Non‐GAAP Financial MeasuresReconciliation of Average Daily Operating MarginBefore Elimination of Intercompany Rig Profit and Bad Debt Expense

Years ended December 31,2007 2008 2009 2011

(In thousands except for operating daysand operating margins)

Contract drilling revenue $699,396  $627,642  $622,727  $236,315  $316,384  $484,651 

Contract drilling operating cost 313,882  304,780  312,907  140,080  186,813  269,899 

Operating profit from contractdrilling $385,514  $322,862  $309,820  $96,235  $129,571  $214,752 

Add:

Elimination of intercompany rig profit and bad debt expense 22,239  24,449  29,381  1,549  9,158  19,900 

Operating profit from contract drilling before elimination of intercompany rig profit and bad debt expense

407,753  347,311  339,201  97,784  138,729  234,652 

Contract drilling operating days 39,798  36,299  37,745  14,183  22,367  27,619 

Average daily operating margin before elimination of intercopmany rig profit and bad debt expense

$10,246  $9,568  $8,987  $6,894  $6,202  $8,496 

2006 2010

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Derivative Summary

27

Crude 2017 2018Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4

CollarsVolume (Bbl) ‐‐ ‐‐ ‐‐ ‐‐Weighted Avg Floor ‐‐ ‐‐ ‐‐ ‐‐Weighted Avg Ceiling ‐‐ ‐‐ ‐‐ ‐‐

3‐Way CollarsVolume (Bbl) 337,500 341,250 345,000 345,000Weighted Avg Floor $49.79  $49.79  $49.79  $49.79 Weighted Avg Subfloor $39.58  $39.58  $39.58  $39.58 Weighted Avg Ceiling $60.98  $60.98  $60.98  $60.98 

SwapsVolume (Bbl) ‐‐ ‐‐ ‐‐ ‐‐Weighted Avg Swap ‐‐ ‐‐ ‐‐ ‐‐

Natural Gas 2017 2018Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4

CollarsVolume (MMBtu) 1,800,000  1,820,000  1,840,000  620,000 Weighted Avg Floor $2.88  $2.88  $2.88  $2.88 Weighted Avg Ceiling $3.10  $3.10  $3.10  $3.10 

3‐Way CollarsVolume (MMBtu) 1,350,000  1,365,000  1,380,000  1,380,000  900,000Weighted Avg Floor $2.50  $2.50  $2.50  $2.50  $3.25Weighted Avg Subfloor $2.00  $2.00  $2.00  $2.00  $2.50Weighted Avg Ceiling $3.32  $3.32  $3.32  $3.32  $4.43

SwapsVolume (MMBtu) 6,300,000  5,460,000  5,520,000  5,520,000  900,000  910,000  920,000  920,000 Weighted Avg Swap $3.04  $2.96  $2.96  $2.96  $3.03  $3.03  $3.03  $3.03 

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Strip Case

Crude Natural Gas MB C2 MB C3 MB NC4 MB iC4 MB C5+ CW C2 CW C3 CW NC4 CW iC4 CW C5+

2017  $57.086  $3.434  $0.242  $0.741 $31.130  $1.239  $1.098  $1.257  $0.226  $0.743  $1.116  $1.200  $1.286 

2018  $56.896  $3.082  $0.217  $0.739 $31.027  $1.235  $1.095  $1.252  $0.203  $0.740  $1.112  $1.196  $1.282 

2019  $56.170  $2.862  $0.202  $0.729 $30.631  $1.219  $1.081  $1.236  $0.188  $0.731  $1.098  $1.180  $1.265 

2020  $56.103  $2.877  $0.203  $0.728 $30.595  $1.218  $1.080  $1.235  $0.189  $0.730  $1.097  $1.179  $1.264 

2021  $56.250  $2.905  $0.205  $0.730 $30.675  $1.221  $1.082  $1.238  $0.191  $0.732  $1.099  $1.182  $1.267 

Thereafter $56.250  $2.905  $0.205  $0.730 $30.675  $1.221  $1.082  $1.238  $0.191  $0.732  $1.099  $1.182  $1.267 

Q1 2017 Economic Prices 

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US Capital AdvisorsE&P Corporate Access Day

January 12, 2017