US Capital Advisors E&P Corporate Access Day January 12, 2017
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 12 Tulsa based, incorporated in 1963 Casper 10 Integrated approach to business allows Unit to capture margin from each business segment 94 Unit Rigs E&P Operations Mid Stream Operations Anadarko Basin Permian Basin 13 54 Oklahoma City Houston Tulsa Headquarters Arkoma Basin 5 Gulf Coast Basin Marcellus North La/ East Texas Basin Pittsburgh Office Location 3
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
2016 Highlights $165 million anticipated 2016 capital expenditures well within budget range of $161 million to $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% 5
Debt Structure No Near Term Maturities Senior Subordinated Notes $650 million, 6.625% 10 year, NC5; maturity 2021 Ratings S&P Moody s Fitch Corporate B+ B2 B+ Senior Subordinated Notes B+ B3 BB Key Covenants Interest coverage ratio 2.25x (1) 9/30/2016 4.60x (1,2) 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) 9/30/2016 Actual 2.70x (1,2) 0.85x (1,2) (1) As defined in Indenture/Credit Agreement. (2) As of September 30, 2016. * Drilling rigs are not included in borrowing base. 6
Core Upstream Producing Areas Mid Continent Region SOHOT Granite Wash Upper Gulf Coast Region Wilcox Key focus areas include: Gulf Coast: Wilcox (Southeast Texas) Mid Continent: Hoxbar (Western Oklahoma) Granite Wash (Texas Panhandle) Average Production (MBoe/d) 9 Mos. 16 Daily Production: 48 MBoe/d Oil 17% NGLs 29% Gas 54% 60 50 40 30 20 10 0 33 39 46 50 55 48 2011 2012 2013 2014 2015 9 mos. 2016 Natural Gas Oil / NGLs Net Wells Drilled: 82 80 91 121 35 8 7
Buffalo Wallow Field Granite Wash Stacked Pay A" A 1 Dixon 5554 XL #1H A 2 B C C 1 D E F F 1 Gross Thickness = 2,273 Feet Vertical well G * Shaded intervals have been tested horizontally 8
Granite Wash Extended Length Laterals (~7,500 ) Cumulative Production (MMCFE) 2,500 2,000 1,500 1,000 500 Dixon 5554 XL #1H (C1) 9 12 Bcfe EUR Projected Type Curve (C1) 7.9 Bcfe EUR 0 50 100 150 200 250 300 Days 1 1/3/2017 Strip Price Deck with 1 st 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. 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 ROR 1 : 64% ROR 1,2 : 94% Dixon 5554 XL #1H (C1) is 1 st 7,500 lateral in Buffalo Wallow 9
Hoxbar (Marchand Sand) Marchand Horizontal Producer Marchand Vertical Producer Schenk 17 2H IP30: 450 Boe/d 2/16 McGuffin 1 19H IP30: 930 Boe/d 1/16 Powers 1 15H IP30: 1,233 Boe/d 12/14 Riley 1 34H IP30: 720 Boe/d 4/16 Brown 1 11H IP30: 867 Boe/d 1/15 Norris 1 28H IP30: 950 Boe/d 3/16 Harper 1 19H IP30: 2,467 Boe/d 1/15 Rosey 1H IP30: 1,483 Boe/d 9/14 Earl 2 30H IP30: 1,817 Boe/d 8/14 GB 1 30H IP30: 1,367 Boe/d 3/14 1 1/3/2017 Strip Price Deck with 1 st Production Starting 1/1/2017; See Q1 2017 Economic Prices in Appendix (also available at www.unitcorp.com/investor/reports/html). H O X B A R 3, 0 0 0 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 ROR 1 > 100% Resumed drilling in Q4 2016 Seven wells planned for 2017 Future Growth Seeking approval from OCC to drill Hoxbar extended laterals Kicked off waterflood feasibility study in Q4 2016 Waterflood offers a significant upside potential 10
Wilcox (Southeast Texas) Bcfe 40 30 20 10 POLK Prior Years Drilling Horizontal Wells 0 Gilly Field TYLER 3D AREA 494 mi.² HARDIN Wilcox Annual Production 2012 2013 2014 2015 2016 est. Gas Oil NGLs JASPER 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. 2017 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 11
Gilly Field Wilcox Cross Section Parker #2 Parker GU #1 Parker #4 Gilly Field BS O #3 Gilly DT BS R #4 Temporarily Abandoned Perforations Current Production Future Behind Pipe Recompletions 2016 YTD Q3 Behind Pipe Recompletions 2017 1 st Half Behind Pipe Recompletions 12
YTD 2016 Wilcox BPR & Workover Results Composite Gross Production from BPRs and Workovers 10 BPRs & 7 Workovers Total Cost: $7.1 MM Start of Year 3,360 mcfd 80 bopd End of Q3 30,920 mcfd 1,280 bopd * BPR: Behind Pipe Recompletion 13
Rig Fleet Presence in Key Regions 94 rig fleet 20 800 HP: 21% 70 1,000 1,700 HP: 75% 4 2,000 HP: 4% 12 69% electric 56% 1,500 HP or greater 94 equipped with top drives 59 equipped with skidding or walking systems 10 17% total fleet utilization rate for Q3 2016 Nine BOSS rigs operating under contract Current Rigs Operating (1) Area # of Rigs Anadarko Basin 10 Bakken 3 Niobrara 1 Permian 5 Pinedale 2 Wilcox 1 Total 22 13 54 5 (1) As of January 10, 2017. 14
Average Dayrates and Margins (1) $20,000 100% Margins and Dayrates $15,000 $10,000 75% 50% Average Rig Utilization $5,000 25% $0 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 9 mos. '16 Margins Dayrates Average Rig Utilization 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). 15
The BOSS Drilling Rig 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 16
Midstream Core Operations Brook Field 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 Pittsburgh Regional office Pittsburgh Mills Bruceton Mills Snow Shoe Hemphill Reno Bellmon Tulsa Headquarters Central & Eastern OK 57,000+ dedicated acres 15 MMcf/d processing capacity 428 miles of gathering pipeline Appalachia 66,000+ dedicated acres 53 miles of gathering pipeline Connected 24 new wells in 2016 Panola East Texas 62 Miles of gathering pipeline 120 MMcf/d gathering capacity Segno Key Metrics 26 active systems Three natural gas treatment plants 343 MMcf/d processing capacity Processing facilities Gathering systems Q3 16 processing volume 153 MMcf/d Approx. 1,460 miles of pipeline 17
Midstream Segment Contract Mix 2010 Q3 2016 Contract Mix Based on Volume 49% 51% Fee Based Commodity Based 23% 77% 85% 15% Contract Mix Based on Margin Fee Based Commodity Based 30% 70% Unit vs. 3 rd Party Margin Contribution 41% 37% 59% 3 rd Party Unit 63% 18
Appalachian Growth Projects A P PA L A C H I A N P R O J E C T S 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 19
Segment Contribution Revenues ($ millions) Adjusted EBITDA ($ millions) (1) $1,600 $1,573 $800 $787 $1,400 $1,315 $1,352 $679 $667 $1,200 $600 $1,000 $800 $854 $400 $410 $600 $400 $428 $200 $170 $200 $0 2012 2013 2014 2015 9 mos. 2016 $0 2012 2013 2014 2015 9 mos. 2016 Oil and Natural Gas Contract Drilling Midstream (1) See Non GAAP Financial Measures in Appendix (also available at www.unitcorp.com/investor/reports.html). 20
Operating Segment Capital Expenditures (In Millions) $1,500 $1,000 $500 $0 2011 2012 2013 2014 2015 2016 Low End Budget Oil and Natural Gas Contract Drilling Midstream Acquisitions 2016 High End Budget 21
APPENDIX 22
Non GAAP Financial Measures Corporate Adjusted EBITDA Nine months ended September 30, Years ended December 31, ($ In Millions) 2015 2016 2012 2013 2014 2015 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 $254 23
Non GAAP Financial Measures Segments Adjusted EBITDA Nine months ended September 30, Years ended December 31, ($ In Millions) 2015 2016 2012 2013 2014 2015 Unit Petroleum Income (Loss) Before Income Taxes (1) $ (1,163) $ (137) $ (77) $ 239 $ 199 $ (1,631) Depreciation, Depletion and Amortization 202 89 211 226 276 252 Impairment of Oil and Natural Gas Properties 1,141 162 284 77 1,599 Adjusted EBITDA $ 180 $ 114 $ 418 $ 465 $ 552 $ 220 Unit Drilling Income (Loss) Before Income Taxes (1) $ 41 $ (12) $ 159 $ 96 $ 42 $ 45 Depreciation and Impairment 51 34 81 71 160 64 Adjusted EBITDA $ 92 $ 22 $ 240 $ 167 $ 202 $ 109 Superior Pipeline Income (Loss) Before Income Taxes (1) $ (1) $ (1) $ 6 $ 11 $ 2 $ (30) Depreciation, Amortization and Impairment 33 34 24 33 48 71 Adjusted EBITDA $ 32 $ 33 $ 30 $ 44 $ 50 $ 41 (1) Does not include allocation of G&A expense. 24
Non GAAP Financial Measures Reconciliation of Average Daily Operating Margin Before Elimination of Intercompany Rig Profit and Bad Debt Expense (In thousands except for operating days and operating margins) Nine months ended September 30, Years ended December 31, 2015 2016 2012 2013 2014 2015 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 Operating profit from contract drilling before elimination of intercompany rig profit and bad debt expense 3,666 235 15,583 17,416 29,343 3,991 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 25
Non GAAP Financial Measures Reconciliation of Average Daily Operating Margin Before Elimination of Intercompany Rig Profit and Bad Debt Expense (In thousands except for operating days and operating margins) Years ended December 31, 2006 2007 2008 2009 2010 2011 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 contract drilling $385,514 $322,862 $309,820 $96,235 $129,571 $214,752 Add: Elimination of intercompany rig profit and bad debt expense Operating profit from contract drilling before elimination of intercompany rig profit and bad debt expense 22,239 24,449 29,381 1,549 9,158 19,900 407,753 347,311 339,201 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 26
Derivative Summary Crude 2017 2018 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Collars Volume (Bbl) Weighted Avg Floor Weighted Avg Ceiling 3 Way Collars Volume (Bbl) 337,500 341,250 345,000 345,000 Weighted 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 Swaps Volume (Bbl) Weighted Avg Swap Natural Gas 2017 2018 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Collars Volume (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 Collars Volume (MMBtu) 1,350,000 1,365,000 1,380,000 1,380,000 900,000 Weighted Avg Floor $2.50 $2.50 $2.50 $2.50 $3.25 Weighted Avg Subfloor $2.00 $2.00 $2.00 $2.00 $2.50 Weighted Avg Ceiling $3.32 $3.32 $3.32 $3.32 $4.43 Swaps Volume (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 27
Q1 2017 Economic Prices 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 28
US Capital Advisors E&P Corporate Access Day January 12, 2017