Bank of America Merrill Lynch - Unit Corporation · Bank of America Merrill Lynch Leveraged Finance...

Bank of America Merrill LynchLeveraged Finance Conference

December 3, 2015

Forward Looking Statement

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.

2

Unit Corporation: A Diversified Energy Company

3

12

10Casper Casper

6

Arkoma Basin

Marcellus

North La/ East Texas Basin

Gulf Coast Basin

Houston Houston

Oklahoma City

Oklahoma City

Tulsa HeadquartersTulsa Headquarters

Anadarko Basin

Permian Basin

54

94 Unit Rigs

E&P Operations

Mid‐Stream Operations

Office Location

12

PittsburghPittsburgh

• Tulsa based, incorporated in 1963

• We have consistently grown throughout many commodity cycles

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

Lower for Longer?

Unit Petroleum has asset packages that can earn strong returns in the current commodity price environment Unit Drilling’s new BOSS rigs have been very well received by customers Superior Pipeline cash flow has improved in stability and reliability with increased emphasis on fee based revenue Asset and financial flexibility Our Balance Sheet provides capability

4

Key Growth Points

5

Exploration & Production– 203% average production replacement since 2005– Liquids production has grown 258% since the fourth quarter of 2009– Proved reserves: 179 MMBoe (1) – 76% Proved Developed

Drilling– Seven BOSS rigs operating under contract; eighth to return to original operator– 94 drilling rig fleet

Mid‐Stream– 145% increase in daily natural gas processing volumes since 2010– 170% increase in daily liquids sold volumes since 2010– Approximately 1,450 miles of pipeline

Strong Balance Sheet– Remains conservatively financed as the company has grown

(1) As of 12/31/2014.

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

12/31/2005 12/31/2006 12/31/2007 12/31/2008 12/31/2009 12/31/2010 12/31/2011 12/31/2012 12/31/2013 12/31/2014 TTM

Oil and Gas Contract Drilling Midstream

6

Segment EBITDA Margins (1) in Line with Pure Play Peers EB

ITDA

Margins

E&P Company Peer Average

Land Drilling Peer Average

Midstream Peer Average

Source: E&P: CRK, EGN, LINE, NBL, NFX, QEP, SD, SGY, SM, XEC; Contract Drilling: HP, ICD, NBR, PES, PKD, PTEN; Midstream: BPL, DPM, ENLK, EPD, ETE, ETP, MMLP, PAA, PAGP, RRMS, SXL

(1) See Segment EBITDA Margins in Appendix (also available at www.unitcorp.com/investor/reports.html).

Conservative Debt Structure – No Near‐Term Maturities

7

Senior Subordinated Notes

$650 million, 6.625%

10‐year, NC5; maturity 2021

Key Covenants Coverage ratio ≥ 2.25x (1) Actual ratio 9.27x (1,2)

Unsecured Bank Facility

Current Borrowing Base $550 million

Elected Commitment $500 million

Outstanding (2) $261.7 million

Maturity April 2020

Key Covenants Current ratio ≥ 1.0 to 1.0 (1) Actual ratio 2.06x (1,2)

Leverage ratio ≤ 4.0 (1) Actual ratio 1.97x (1,2)(1) As defined in Indenture/Credit Agreement(2) As of September 30, 2015

Ratings S&P Moody’s FitchCorporate BB‐ Ba3 BBSenior Subordinated Notes BB‐ B1 BB‐

Strong Capital Discipline

Total debt / LTM’s adjusted EBITDA of 1.97x (1)

Strong access to capital

No near‐term maturities

Oil and natural gas segment core plays largely HBP ‐exploration program not driven by lease expirations

8

(1) As of September 30, 2015

Track Record of Reserve Growth

9

0%

100%

200%

300%

400%

2005 2006 2007 2008 2009 2010 2011 2012 2013 2014

0

30

60

90

120

150

180

2005 2006 2007 2008 2009 2010 2011 2012 2013 2014

(1) The Company uses the reserve replacement ratio as an indicator of the Company's ability to replenish annual production volumes and grow its proved reserves, including by acquisition, thereby providing some information on the sources of future production. It should be noted that the reserve replacement ratio is a statistical indicator that has limitations. The ratio is limited because it typically varies widely based on the extent and timing of discoveries and property acquisitions. Its predictive and comparative value is also limited for the same reasons. In addition, since the ratio does not imbed the cost or timing of future production of new reserves, it cannot be used as a measure of value creation.

(2) 164% based on previous SEC reporting standards.

Proved Reserves (MMBoe)

Annual Reserve Replacement(1)Natural GasOil / NGLs

161%171% 176%202% 204%

261%221%

186%

Minimum Target: 150%

164%(2)

116

160

6979

86 95 96104

150

337%

113%

179

Stable and consistent economic growth of oil and natural gas reserves of at least 150% of each year’s production

221% average annual production replacement over last 30 years

Reserve growth driven by Oklahoma and Texas activity and a shift from vertical to horizontal / liquids‐rich drilling

0

10

20

30

40

50

60

2010 2011 2012 2013 2014 2015 est.

Natural Gas Oil / NGLs Prod. Range

Consistent Production Growth

10

88

Average Production (MBoe/d)

Net Wells Drilled:

27

33

39

82 80 91

6%‐8% growth

121

5046

Core Upstream Producing Areas

11

9% 6%

40%36%

9%

Gas54%Oil

20%

NGL26%

Key focus areas include:

Gulf Coast:

– Wilcox (Southeast Texas)

Mid‐Continent:

− Hoxbar (Western Oklahoma)

− Granite Wash (Texas Panhandle)

− Mississippian (Kansas)

Upside resource potential:

– 1,400 – 1,800 gross wells

– 75% average working interest

– 760 – 960 gross MMBoe

– 47% liquids (16% oil, 31% NGLs)

2015 CapEx Breakdown: $309 Million Original Budget$279 Million Revised Budget 9 Months 2015 Daily Production: 55.8 MBoe/d

Granite WashMississippian

WilcoxHoxbar Play

Other

SOHOT

Granite Wash

Mid Continent Region

Upper Gulf Coast Region

Mississippian

Wilcox

12

JASPER

POLK

3D AREA494 mi.²

Gilly Field

HARDIN

Southeast Texas “Jazz” Wilcox AreaPrior Years Drilling

2015 Drilling Program

Wilcox (Southeast Texas)Overall Highlights:

Drilled 146 operated wells since 2003(143 vertical, 3 horizontal)

92% average working interest

Q3 ‘15 net avg. production:82 MMcfe/d

43% liquids (11% oil)

Historical ROR: 112%

Gilly Field Highlights:

Resource potential of 506 gross Bcfe

Produced only 13% of resource potential

93% average working interest

Field size: 1,740 acres

18 vertical, 2 horizontal wells

Gilly Blackwood zone:

CWC: $4.8 MM; EUR: 9.3 Bcfe

ROR: ≥100%**October 2015 Strip Price Deck with 1st Production Starting 1/1/2016; see Q4 2015 Economic Prices in Appendix (also available at www.unitcorp.com/investor/reports.html).

TYLER

Wilcox (Southeast Texas)

13

2015 Activity:

1 rig

13‐16 gross wells(3 horizontal)

2015 projected 18% growth

Upside Resource Potential:

870 Bcfe

95% average WI

43% Liquids (11% oil, 32% NGLs)

0

30,000

60,000

90,000

2012 2013 2014 2015 est.NGLs Oil Gas

Wilcox Net Production

Mcfe/d

14

H O X B A R 3 , 0 0 0 ’ Medrano Core Case:

EUR: 4.8 Bcfe

IP30: 7.0 Mmcfe/d

Well cost: $4.4 million

ROR: 18%*

28% liquids

50‐60 core locations

50% avg. working interest

2016 Medrano Activity:

No activity currently planned

Hoxbar (Medrano Sand)

*October 2015 Strip Price Deck with 1st Production Starting 1/1/2016; see Q4 2015 Economic Prices in Appendix (also available at www.unitcorp.com/investor/reports.html).

Historical Medrano Highlights:

Completed 15 operated wells

Avg. IP30: 7.0 MMcfe/d


Hazel 1‐24HIP30: 8,900 Mcfe/d

10/14

Hazel 1‐24HIP30: 8,900 Mcfe/d

10/14

Hiram 1‐13HIP30: 9,500 Mcfe/d

2/15

Hiram 1‐13HIP30: 9,500 Mcfe/d

2/15

Rosey 2HIP30: 7,600 Mcfe/d

5/15

Rosey 2HIP30: 7,600 Mcfe/d

5/15

GB 2‐30HIP30: 7,300 Mcfe/d

4/15

GB 2‐30HIP30: 7,300 Mcfe/d

4/15

Ellen 1‐20HIP30: 9,800 Mcfe/d

12/14


12/14

Mary 1‐18PHIP30: 7,400 Mcfe/d

3/15

Mary 1‐18PHIP30: 7,400 Mcfe/d

3/15


12/14


12/14

Chester 1‐29HIP30: 5,800 Mcfe/d

4/15

Chester 1‐29HIP30: 5,800 Mcfe/d

4/15

Hoxbar (Marchand Sand)

15

Marchand Core Case:

EUR: 480 Mboe

IP30: 1,195 Boe/d

Well cost: $5.2 million

ROR: >100%*


30‐40 core operated locations

• 50% average working interest

30‐35 core non operated locations

• 35% average working interest

2016 Marchand Activity:

1 rig

7‐8 wells

H O X B A R 3 , 0 0 0 ’

*October 2015 Strip Price Deck with 1st Production Starting 1/1/2016; see Q4 2015 Economic Prices in Appendix (also available at www.unitcorp.com/investor/reports.html).

Historical Marchand Highlights:

Completed 7 operated wells

Avg. IP30: 1,426 Boe/d


Extensional Area

Harper 1‐19HIP30: 2,467 Boe/d

1/15

Harper 1‐19HIP30: 2,467 Boe/d

1/15

Earl 2‐30HIP30: 1,817 Boe/d

8/14

Earl 2‐30HIP30: 1,817 Boe/d

8/14

GB 1‐30H IP30: 1,367 Boe/d

3/14

GB 1‐30H IP30: 1,367 Boe/d

3/14

Powers 1‐15HIP30: 1,233 Boe/d

12/14

Powers 1‐15HIP30: 1,233 Boe/d

12/14

Rosey 1H IP30: 1,483 Boe/d

9/14

Rosey 1H IP30: 1,483 Boe/d

9/14

Schenk 18HIP30: 700 Boe/d

6/15

Schenk 18HIP30: 700 Boe/d

6/15

Marchand Horizontal ProducerMarchand Vertical Producer

Brown 1‐11HIP30: 867 Boe/d

1/15

Brown 1‐11HIP30: 867 Boe/d

1/15

Granite Wash (Liquids)

16

2015 Activity:

0‐1 rig total

5 net wells

Historical Highlights:

Completed 115 operatedhorizontal wells since 2008

Average WI: ~80%

Q3 ‘15 avg. production:119 MMcfe/d

Average IP30: 5.2 MMcfe/d


CAGR: 37% (5 years)

Buffalo Wallow Potential:

Contiguous operated HBP acreage position with average WI above 90%

Saltwater gathering system coupled with water recycling facility significantly reduces produced water handling costs and provides cheap frac water

Horizontal well results indicate extended lateral drilling should be economic at current strip prices.

Evaluating options to fund extended lateral program

Buffalo Wallow

40,600 N.A.96% H.B.P.40,600 N.A.96% H.B.P.

$0

$4

$8

$12

$16

Peer 1 Unit Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9 Peer 10

Expertise in Areas of Operations

17

Average: $10.21

Unit has experienced management and operating teams and is a leader in minimizing operating expenses

Ope

ratin

g Expe

nse / Bo

e(1)

(1) Data in table is as of Q3 2015.Source: CRK, EGN, LINE, NFX, NBL, QEP, SD, SGY, SM, XEC

Significant Drilling Presence in AttractiveProducing Regions

18

94 rig fleet

– Fleet average ~1,260 HP rating;

– Almost all of contracted rigs drilling horizontal wells

33% utilization rate for Q3 2015

– 43% of the 49 1,200‐1,700 HP rigs under contract

Refurbished 48 rigs since 2009

Seven BOSS rigs operating

One BOSS rig going back tooriginal operator

Bakken

PinedaleAnticline

Mississippian

Niobrara

AnadarkoGranite Wash

Permian Wilcox

Area # of RigsAnadarko Basin 8

Bakken 4Granite Wash 4Mississippi 1Permian 4

Pinedale Anticline 2Niobrara 3Wilcox 1Total 27

19

$0

$5,000

$10,000

$15,000

$20,000

2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 9 mos.2015

Margins Dayrates Average Rig Utilization

Average Dayrates and Margins (1)

(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).

Average R

ig Utilization

Mar

gins

and

Day

rate

s

100%

75%

50%

25%

0%

Rig Fleet Snap Shot

20

43%57%

1,200‐1,700 HP

49

% Utilized % Unutilized

100%

≥ 2,000 HP

4

18%82%

800‐1,000 HP

28

8%

92%

< 800 HP

13

82% of Total Fleet

M: 8SCR: 5A/C: ‐

M: 18SCR: 10A/C: ‐

M: 3SCR: 38A/C: 8

M: ‐SCR: 4A/C: ‐

Utilization by Type:Mechanical: 0SCR: 20A/C: 7

The BOSS Drilling Rig

21

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

Appalachia 43,000+ dedicated acres 36 miles of gathering pipeline 200 MMcf/d pipeline capacity

Midstream Core Operations

22

TulsaHeadquarters

PittsburghRegional office

Hemphill

Reno

Bellmon

Segno

Pittsburgh Mills

Processing facilities

Gathering systems

Panola

Key Metrics

• 25 Active Systems

• Three Natural Gas Treatment Plants

• 340 MMcf/d Processing Capacity

• Approx. 1,450 miles of Pipeline

East Texas 59 Miles of gathering pipeline

Texas Panhandle 50,100 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 565 miles of gathering pipeline

Central & Eastern OK 60,100+ dedicated acres 12 MMcf/d processing capacity 449 miles of gathering pipeline

Brook Field

Snow Shoe

Bruceton Mills

Contract Mix Based on Margin

Fee BasedCommodity Based

85%37%

63%

15%

Contract Mix Based on Volume

Fee BasedCommodity Based

49%33%

67%51%

Midstream Segment Contract Mix

23

2010 Q3 2015

Unit vs. 3rd Party Margin Contribution

3rd PartyUnit

41% 44% 56%59%

Appalachian Growth Projects

24

• Constructing Snowshoe Gathering System in Centre County, PA– Estimated Total Capital: $97 million– Initial 2015 Capital: $30 million

• Expansion of Pittsburgh Mills gathering system into Butler County, PA – Constructing compression station –

estimated completion Q4 2015– Scheduled to connect next well pad

in Q4 2015– Four additional well pads scheduled

for connection in 2016

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

Segment Contribution

25

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

2011 2012 2013 2014 9 mos. 2015$0

$200

$400

$600

$800

2011 2012 2013 2014 9 mos. 2015

$1,352

$1,573

$682

$1,208$1,315

$758

$311

$603$657 $640

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

Capital Expenditures

26

$0

$500

$1,000

$1,500

2011 2012 2013 2014 2015 OriginalForecast

2015 RevisedForecast

Oil and Natural Gas Contract Drilling Midstream Acquisitions

(In Millions)

Investment Considerations

27

In a commodity price challenged world:

Unit Petroleum has asset packages that can earn strong returns in the current commodity price environment Unit Drilling’s new BOSS rigs have been very well received by customers Superior Pipeline cash flow has improved in stability and reliability with increased emphasis on fee based revenue Asset and financial flexibility Our Balance Sheet provides capability

28

APPENDIX

29

Segment EBITDA Margin12/31/2005 12/31/2006 12/31/2007 12/31/2008 12/31/2009 12/31/2010 12/31/2011 12/31/2012 12/31/2013 12/31/2014 TTM

RevenuesOil and Gas (Including Cash Flow Derivatives Settled) $318,208 $357,599 $391,480 $552,696 $362,245 $399,771 $514,614 $567,944 $649,718 $740,079 $474,847

Drilling $462,141 $699,396 $627,642 $622,727 $236,315 $316,384 $484,651 $529,719 $414,778 $476,517 $350,101Gas Gathering $100,464 $101,863 $138,595 $181,730 $108,628 $154,516 $208,238 $217,460 $287,354 $356,348 $235,542Derivatives Settled(Non‐designated) $0 $0 $0 $0 ($2,422) $0 ($711) $0 ($1,764) ($6,038) $45,102

ExpensesOil and GasOperating cost $60,779 $81,120 $97,109 $116,239 $87,734 $105,365 $131,271 $150,212 $184,001 $187,916 $183,808DDA $67,282 $108,124 $127,417 $159,550 $114,681 $118,793 $183,350 $211,347 $226,498 $276,088 $277,508Impairment $0 $0 $0 $281,966 $281,241 $0 $0 $283,606 $0 $76,683 $1,217,736

DrillingOperating cost $266,472 $313,882 $304,780 $312,907 $140,080 $186,813 $269,899 $289,524 $247,280 $274,933 $201,625Depreciation and impairment $42,876 $51,959 $56,804 $69,841 $45,326 $69,970 $79,667 $81,007 $71,194 $159,688 $149,341

Gas Gathering and ProcessingOperating Cost $92,467 $88,834 $119,776 $150,466 $87,908 $122,146 $174,859 $187,292 $243,406 $306,831 $193,746Depreciation, amortization,and impairment $3,279 $6,247 $11,059 $14,822 $16,104 $15,385 $16,101 $24,388 $31,191 $47,502 $50,048

G&A $14,343 $18,690 $22,036 $25,419 $24,011 $26,152 $30,055 $33,086 $38,323 $42,023 $38,251

EBITDA MarginOil and Gas 79% 76% 73% 77% 72% 71% 72% 71% 69% 72% 61%Drilling 41% 54% 50% 48% 37% 38% 42% 43% 38% 40% 39%Gas Gathering 6% 11% 12% 15% 16% 18% 14% 11% 12% 11% 14%

G&A AllocationOil and Gas $5,182 $5,767 $7,451 $10,352 $12,259 $12,008 $12,799 $14,288 $18,393 $19,686 $17,127Drilling $7,525 $11,280 $11,947 $11,652 $8,073 $9,492 $12,046 $13,327 $11,758 $12,731 $12,628Gas Gathering $1,636 $1,643 $2,638 $3,400 $3,711 $4,636 $5,176 $5,471 $8,146 $9,520 $8,496

Non‐GAAP Financial Measures

30

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

Years ended December 31,($ in Millions)Net Income (Loss)Income TaxesDepreciation, Depletion and AmortizationImpairmentsInterest Expense

Unit PetroleumIncome (Loss) Before Income Taxes (1)Depreciation, Depletion and AmortizationImpairment of Oil and Natural Gas Properties

EBITDA

Unit DrillingIncome Before Income Taxes (1)Depreciation and Impairment

EBITDA

Superior PipelineIncome Before Income Taxes (1)Depreciation, Amortization and Impairment

EBITDA

2011$196123281‐4

$200183‐

$383

$13580

$215

$1716$33

2012$2316

31928414

($77)211284$418

$15981

$240

$624$30

(Gain) loss on derivatives not designated ashedges and hedge ineffectiveness

Settlements during the period of maturedderivative contracts

(Gain) loss on disposition of assets

(2) 1

Adjusted EBITDA $603 $657

2015

$(728)(439)280

1,14924

$(1,163)202

1,141$180

$4051

$91

$‐32

$32

(13)

$311

32 ‐ ‐

2013$185117334‐15

$239226‐

$465

$9671

$167

$1133

$44

8

$640

(2)

2014$13687

40515817

$19927677

$552

$42160$202

$248

$50

(30)

$758

(6)

Adjusted EBITDA

2014

$179112294‐12

$240201

‐$441

$8461

$145

$1030

$40

9

$578

(19)

Nine months ended September 30,

(9) 6 1 ‐ (17) (9)

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

31

Non‐GAAP Financial Measures

Years ended December 31,(In thousands except for operating daysand operating margins) 2015 2011 2012 2013 2014

Contract drilling revenue $ 341,530 $ 215,114 $ 484,651 $ 529,719 $ 414,778 $ 476,517

Contract drilling operating cost 197,025 123,717 269,899 289,524 247,280 274,933

Operating profit from contract drilling 144,505 91,397 214,752 240,195 167,498 201,584

Add:

Elimination of intercompany rig profit andbad debt expense 20,674 3,666 19,900 15,583 17,416 29,343

Operating profit from contract drillingbefore elimination of intercompany rigprofit and bad debt expense 165,179 95,063 234,652 255,778 184,914 230,927

Contract drilling operating days 20,073 10,175 27,619 26,704 23,720 27,516

Average daily operating margin beforeelimination of intercompany rig profitand bad debt expense $ 8,229 $ 9,343 $ 8,496 $ 9,578 $ 7,796 $ 8,392

2014Nine months ended September 30,

32

Period StructureVolumeBbl/Day

WeightedAverage

Fixed Price

WeightedAverage

Floor Price

WeightedAverage

Subfloor Price

WeightedAverage

Ceiling Price

Oct'15 ‐ Dec'15 Swap 1,000 $95.00

Oct'15 ‐ Dec'15 Collar 2,000 $58.00 $64.40

Jan'16 ‐ Jun'16 3‐Way Collar 700 $46.50 $35.00 $57.00

Jan'16 ‐ Jun'16 Collar 2150 $46.36 $55.62

Jul'16 ‐ Dec'16 3‐Way Collar 1,400 $47.00 $35.00 $60.25

Jul'16 ‐ Dec'16 Collar 1,450 $47.50 $56.40

Jan'17‐ Dec'17 3‐Way Collar 750 $50.00 $37.50 $63.90

Period StructureVolume

MMBtu/Day

WeightedAverage

Fixed Price

WeightedAverage

Floor Price

WeightedAverage

Subfloor Price

WeightedAverage

Ceiling Price

Oct'15 ‐ Dec'15 Swap 40,000 $3.98

Nov'15 ‐ Dec'15 3‐Way Collar 13,500 $2.70 $2.20 $3.26

Jan'16 ‐ Dec'16 Swap 10,000 $3.25

Jan'16 ‐ Dec'16 3‐Way Collar 13,500 $2.70 $2.20 $3.26

Jan'16 ‐ Dec'16 Collar 27,000 $2.50 $3.11

Derivative Summary

Natural Gas

Crude

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+

2015 $44.235 $2.293 $0.208 $0.420 $0.583 $0.592 $0.977 $0.178 $0.390 $0.550 $0.613 $0.967

2016 $47.182 $2.604 $0.242 $0.455 $0.627 $0.639 $1.049 $0.185 $0.429 $0.596 $0.658 $1.038

2017 $52.067 $2.884 $0.267 $0.540 $0.716 $0.734 $1.157 $0.207 $0.541 $0.697 $0.772 $1.122

2018 $54.893 $2.961 $0.278 $0.569 $0.754 $0.774 $1.220 $0.218 $0.570 $0.734 $0.814 $1.183

2019 $56.958 $3.039 $0.287 $0.590 $0.783 $0.803 $1.266 $0.227 $0.592 $0.762 $0.844 $1.227

2020 $58.414 $3.237 $0.302 $0.596 $0.791 $0.811 $1.279 $0.242 $0.597 $0.770 $0.853 $1.240

Thereafter $58.414 $3.237 $0.302 $0.596 $0.791 $0.811 $1.279 $0.242 $0.597 $0.770 $0.853 $1.240

Q4 2015 Economic PricesOctober 27, 2015

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