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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
78% avg. working interest
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
Ellen 1‐20HIP30: 9,800 Mcfe/d
12/14
Mary 1‐18PHIP30: 7,400 Mcfe/d
3/15
Mary 1‐18PHIP30: 7,400 Mcfe/d
3/15
Ellen 2‐20HIP30: 9,800 Mcfe/d
12/14
Ellen 2‐20HIP30: 9,800 Mcfe/d
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%*
91% liquids (77% oil)
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
88% avg. working interest
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
52% liquids (12% oil)
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
33
Bank of America Merrill LynchLeveraged Finance Conference
December 3, 2015