Raymond James Boston Spring Investors Conference June 6, 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 Integrated approach to business allows Unit to capture margin from each business segment 94 Unit Rigs E&P Operations Mid Stream Operations Office Location Casper 10 Anadarko Basin Permian Basin 13 54 Oklahoma City Houston Tulsa Headquarters Arkoma Basin 5 Gulf Coast Basin Marcellus North La/ East Texas Basin Pittsburgh 3
Company Highlights Highly economic opportunities for our E&P segment Contract drilling segment growing with industry rebound Midstream segment EBITDA poised for growth Fiscally conservative Capital spending within cash flow 4
Core Upstream Producing Areas Mid Continent Region Hoxbar 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) 2016 year end total proves reserves: 707 Bcfe or 118 MMBoe Q1 2017 Daily Production: 42.0 MBoe/d Oil 17% NGLs 29% Gas 54% 60 50 40 30 20 10 0 Average Production (MBoe/d) 46 50 55 47 44 46 2013 2014 2015 2016 2017 est Natural Gas Oil / NGLs Net Wells Drilled: 91 121 35 10 ~25 5
Buffalo Wallow Field Economic Advantages Geology 11 Granite Wash lenses Sands consistent across field Land ~8,800 net acres Operated and ~90% HBP Average working interest ~ 90% 220 270 potential XL locations Resumed drilling in December 2016 Continue to expand position Infrastructure SWD network lowers disposal costs 80% and allows for water recycling Electricity throughout field Superior Pipeline gathers and processes the gas 6
Buffalo Wallow Extended Lateral Results 2,000 Cumulative Production (MMCFE) 1,800 1,600 1,400 1,200 1,000 800 600 400 200 2 nd C1 ROR assumes well cost of $6.3MM 1 st A2 1 st C1 11 BCFE * UPC ROR: 82% (1) Corp ROR: 130% (1) (2) 8 BCFE * UPC ROR: 36% (1) Corp ROR: 58% (1) (2) 5 BCFE * UPC ROR: 9% (1) Corp ROR: 16% (1) (2) 0 0 20 40 60 80 100 120 140 160 180 200 Days 1 5/25/2017 Strip Price Deck with 1 st Production Starting 1/1/2017; See Q2 2017 Economic Prices in Appendix (also available at www.unitcorp.com/investor/reports/html). 2 ROR calculation includes midstream margin. * Potential EUR Range 7
Hoxbar (Marchand Sand) H O X B A R 3, 0 0 0 Hoxbar Marchand Core Area EUR ~ 550 MBoe Estimated well cost $5.0 MM 83% liquids (68% oil) ~26,000 net acres (64% HBP) 60 65 locations Working interest of 50 60% ROR 1 ~ 100% Resumed drilling in late April 5 6 wells for remainder 2017 Future Growth Extended laterals (XL s) Performing waterflood study Waterflood offers significant upside potential 1 5/25/2017 Strip Price Deck with 1 st Production Starting 6/1/2017; See Q2 2017 Economic Prices in Appendix (also available at www.unitcorp.com/investor/reports/html) 8
Hoxbar Acquisition Paid $56.75MM cash plus contributed 180 acres in McClain County 47 PDP wells 23 operated by seller 20 operated by Unit Proved reserves = 3.2 MMBoe Production = 1,367 boepd (73% liquids) 65 gross potential Hoxbar locations 13 new locations 52 planned wells with working interest increased to 80% 8,335 net acres (71% HBP) 42% increase over existing acreage Now 26,000 net acres in play Excellent overlap with existing acreage Unit Acquired Planned secondary recovery projects will substantially increase oil recoveries Add l Interest Acquired 9
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 Gas Oil NGLs JASPER Overall Wilcox Highlights Drilled 164 operated wells since 2003 (155 vertical, 9 horizontal) Program ROR > 100% Operated with working interest ~ 92% Production: ~ 90 MMcfe/d (42% liquids) Resumed drilling activity in Jan. 2017 Gilly Field World Class Gas Reservoir 500 Bcfe stacked pay gas resource Cumulative production ~ 100 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 Latest horizontal IP 30: 9 MMcf/d, 240 Bopd First of 2 exploratory wells waiting on frack Generating new exploration ideas using 165 square miles of 3 D data 10
Wilcox Activity Map for 2017 TYLER SEGNO NE POLK GILLY VILLAGE MILLS CHERRY CREEK WING LIBERTY HARDIN 11
2016 Wilcox Recompletions & Workover Results Composite Gross Production from Recompletions and Workovers 20 Recompletions & 7 Workovers Total Cost: $10MM Start of Year 3,360 mcfd 80 bopd End of Year 40,000 mcfd 1,100 bopd 12
Wilcox Horizontal Test Village Mills Field West Univ. #1H 5,800 Lateral IP30: 9 MMCF/D, 240 BO/D 3,000# Flowing Pressure 22 Stage, 5,300,000# Frac 1.03 BCFG 2.6 MMCF/D IP 214,000# Frac 1.45 BCFG 1.8 MMCF/D IP 72,000# Frac 0.23 BCFG 2.3 MMCF/D IP 48,000# Frac Depth Map on Dempsey Sd 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 31% total fleet utilization at present Nine BOSS rigs operating Current Rigs Operating (1) Area # of Rigs Mid Continent 17 Bakken 3 Niobrara 1 Permian 6 Pinedale 2 Total 29 13 54 5 (1) As of June 5, 2017. 14
SCR Rigs Continue to Make an Important Contribution 30 25 20 15 10 5 0 20 12 9 7 9 9 6 7 May 5, 2016 Aug. 4, 2016 Dec. 31, 2016 Jun. 5, 2017 A/C SCR At industry trough 13 drilling rigs operating Currently, 29 drilling rigs operating Four additional SCR rigs under contract All BOSS rigs operating 20 SCR rigs operating 13 SCR rigs required no modifications 7 SCR rigs required some upgrade 15
Average Dayrates and Margins (1) $20,000 100% Margins and Dayrates $15,000 $10,000 75% 50% Average Rig Utilization $5,000 25% $0 2008 2009 2010 2011 2012 2013 2014 2015 2016 Q1 '17 0% Margins Dayrates Average Rig Utilization (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). 16
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 All nine BOSS rigs currently operating; tenth under construction 17
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 1,975,000+ dedicated acres 193 MMcf/d processing capacity 579 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 12 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 66 Miles of gathering pipeline 120 MMcf/d gathering capacity Segno Key Metrics 25 active systems Three natural gas treatment plants 340 MMcf/d processing capacity Q1 17 processing volume 127 MMcf/d Processing facilities Approx. 1,470 miles of pipeline Gathering systems 18
Midstream Segment Contract Mix 2010 Q1 2017 Contract Mix Based on Volume 49% 51% Fee Based Commodity Based 28% 72% 85% 15% Contract Mix Based on Margin Fee Based Commodity Based 35% 65% Unit vs. 3 rd Party Margin Contribution 41% 35% 59% 3 rd Party Unit 65% 19
Midstream Historical Volumes 200,000,000 180,000,000 160,000,000 MMBtu Gathered & Processed 140,000,000 120,000,000 100,000,000 80,000,000 60,000,000 40,000,000 20,000,000 2009 2010 2011 2012 2013 2014 2015 2016 Gas Gathered (MMbtu) Gas Processed (MMbtu) 20
Midstream Segment Commodity Price Sensitivity (1) $70,000,000 $60,000,000 $50,000,000 $40,000,000 $30,000,000 $20,000,000 $10,000,000 $0 Realized Price* NGL/Barrel: Condensate/Bbl: Segment EBITDA Before Intercompany Eliminations 2009 2010 2011 2012 2013 2014 2015 2016 2016 Adjusted Realized Price Adjusted Price $29.40 $38.64 $43.26 $31.50 $35.70 $30.24 $15.96 $15.96 $21.07 $54.89 $75.07 $88.47 $89.93 $87.46 $81.25 $37.03 $32.56 $47.33 *Net realized prices prices received after transportation, fuel, and fees paid. (1) See Superior Pipeline Company Reconciliation of EBITDA in Appendix (also available at www.unitcorp.com/investor/reports.html). 2016 Adjustments Utilized 2016 volumes Assumed $55.00/Bbl oil price Adjusted for average NGL price of $21.07/Bbl Adjusted average condensate price of $47.33/Bbl Prices are after transportation, fuel, and fees paid. 21
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 BB B3 BB Key Covenants Interest coverage ratio 2.25x (1) 3/31/2017 5.07x (1,2) Secured Bank Facility (Redetermined April 2017) * Elected Commitment and Current Borrowing Base $475 million Outstanding (2) $150.0 million Maturity April 2020 Key Covenants Current ratio 1.0 to 1.0 (1) Senior Indebtedness ratio 2.75 (1) 3/31/2017 Actual 3.10x (1,2) 0.54x (1,2) (1) As defined in Indenture/Credit Agreement. (2) As of March 31, 2017. * Drilling rigs are not included in borrowing base. 22
Segment Contribution Revenues ($ millions) Adjusted EBITDA ($ millions) (1) $1,600 $1,573 $800 $787 $1,400 $1,352 $667 $1,200 $600 $1,000 $800 $854 $400 $410 $600 $602 $252 $400 $200 $200 $176 $75 $0 2013 2014 2015 2016 Q1 '17 $0 2013 2014 2015 2016 Q1 '17 Oil and Natural Gas Contract Drilling Midstream (1) See Non GAAP Financial Measures in Appendix (also available at www.unitcorp.com/investor/reports.html). 23
Operating Segment Capital Expenditures (In Millions) $1,500 $1,000 $500 $0 2013 2014 2015 2016 2017 Budget Oil and Natural Gas Contract Drilling Midstream 24
Investment Considerations E&P segment three core areas provide compelling economics Contract drilling segment resuming pattern of growth Midstream segment positioned to benefit from increased activity levels and liquids price improvement We maintain fiscal discipline Solid balance sheet with ample liquidity 25
APPENDIX 26
Non GAAP Financial Measures Corporate Adjusted EBITDA Three months ended March 31, Years ended December 31, ($ In Millions) 2016 2017 2013 2014 2015 2016 Net Income (Loss) ($41) $16 $185 $136 ($1,037) ($136) Income Taxes (16) 14 117 87 (627) (71) Depreciation, Depletion and Amortization 56 47 334 405 355 210 Impairments 38 158 1,635 162 Interest Expense 10 9 15 17 32 40 (Gain) loss on derivatives (11) (15) 8 (30) (26) 23 Settlements during the period of matured derivative contracts 7 (1) (2) (6) 47 10 Stock compensation plans 5 4 22 24 21 14 Other non cash items 1 1 5 5 3 3 (Gain) loss on disposition of assets (1) (17) (9) 7 (3) Adjusted EBITDA $48 $75 $667 $787 $410 $252 27
Non GAAP Financial Measures Segments Adjusted EBITDA Three months ended March 31, Years ended December 31, ($ In Millions) 2016 2017 2013 2014 2015 2016 Unit Petroleum Income (Loss) Before Income Taxes (1) $ (45) $ 36 $ 239 $ 199 $ (1,631) $ (102) Depreciation, Depletion and Amortization 32 22 226 276 252 114 Impairment of Oil and Natural Gas Properties 38 77 1,599 162 Adjusted EBITDA $ 25 $ 58 $ 465 $ 552 $ 220 $ 174 Unit Drilling Income (Loss) Before Income Taxes (1) $ (1) $ (5) $ 96 $ 42 $ 45 $ (13) Depreciation and Impairment 12 13 71 160 64 47 Adjusted EBITDA $ 11 $ 8 $ 167 $ 202 $ 109 $ 34 Superior Pipeline Income (Loss) Before Income Taxes (1) $ (3) $ 2 $ 11 $ 2 $ (30) $ 2 Depreciation, Amortization and Impairment 11 11 33 48 71 46 Adjusted EBITDA $ 8 $ 13 $ 44 $ 50 $ 41 $ 48 (1) After intercompany eliminations and does not include allocation of G&A expense. 28
Non GAAP Financial Measures Reconciliation of Average Daily Operating Margin Before Elimination of Intercompany Rig Profit and Bad Debt Expense Three months ended Years ended (In thousands except for operating days March 31, December 31, and operating margins) 2016 2017 2013 2014 2015 2016 Contract drilling revenue $38,710 $37,185 $414,778 $476,517 $265,668 $122,086 Contract drilling operating cost 28,098 29,227 247,280 274,933 156,408 88,154 Operating profit from contract drilling $10,612 $7,958 $167,498 $201,584 $109,260 $33,932 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 17,416 29,343 3,991 235 10,612 7,958 184,914 230,927 113,251 34,167 Contract drilling operating days 1,878 2,291 23,720 27,516 12,681 6,374 Average daily operating margin before elimination of intercompany rig profit and bad debt expense $5,651 $3,474 $7,796 $8,392 $8,931 $5,360 29
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, 2008 2009 2010 2011 2012 Contract drilling revenue $622,727 $236,315 $316,384 $484,651 $529,719 Contract drilling operating cost 312,907 140,080 186,813 269,899 289,524 Operating profit from contract drilling $309,820 $96,235 $129,571 $214,752 $240,195 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 29,381 1,549 9,158 19,900 15,583 339,201 97,784 138,729 234,652 255,778 Contract drilling operating days 37,745 14,183 22,367 27,619 26,704 Average daily operating margin before elimination of intercopmany rig profit and bad debt expense $8,987 $6,894 $6,202 $8,496 $9,578 30
Midstream Reconciliation of EBITDA (Before Intercompany Eliminations) Segment EBITDA Before Intercompany Eliminations Years ended December 31, ($ In Millions) 2009 2010 2011 2012 2013 2014 2015 2016 Total Midstream Income (Loss) Before Intercompany Eliminations $ 7,126 $ 19,267 $ 19,555 $ 8,237 $ 15,636 $ 6,626 $ (24,159) $ 8,799 (Gain) Loss on Disposition of Assets 81 313 (97) (465) 302 Depreciation and Amortization 16,104 15,385 16,101 23,110 33,191 40,434 43,676 45,715 Impairments 1,278 7,068 26,966 Segment EBITDA Before Intercompany Eliminations * $ 23,230 $ 34,652 $ 35,737 $ 32,938 $ 48,827 $ 54,031 $ 46,018 $ 54,816 *Excludes depreciation, allocated interest, and corporate G&A 31
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 90,000 91,000 92,000 92,000 Weighted Avg Floor $49.79 $49.79 $49.79 $49.79 $50.00 $50.00 $50.00 $50.00 Weighted Avg Subfloor $39.58 $39.58 $39.58 $39.58 $40.00 $40.00 $40.00 $40.00 Weighted Avg Ceiling $60.98 $60.98 $60.98 $60.98 $56.65 $56.65 $56.65 $56.65 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 1,990,000 5,400,000 1,820,000 1,840,000 1,840,000 Weighted Avg Floor $2.50 $2.50 $2.50 $2.81 $3.29 $3.00 $3.00 $3.00 Weighted Avg Subfloor $2.00 $2.00 $2.00 $2.23 $2.63 $2.50 $2.50 $2.50 Weighted Avg Ceiling $3.32 $3.32 $3.32 $3.53 $4.07 $3.51 $3.51 $3.51 Swaps Volume (MMBtu) 6,300,000 6,370,000 6,440,000 5,830,000 1,800,000 1,820,000 1,840,000 1,840,000 Weighted Avg Swap $3.04 $3.04 $3.04 $2.99 $3.01 $3.01 $3.01 $3.01 32
Q2 2017 Economic Prices Strip Case* Crude Natural Gas MB C2 MB C3 BBL MB C3 MB NC4 MB ic4 MB C5+ CW C2 CW C3 CW NC4 CW ic4 CW C5+ 2017 $51.048 $3.334 $0.261 $0.662 $27.815 $0.783 $0.773 $1.123 $0.210 $0.629 $0.734 $0.842 $1.132 2018 $51.498 $3.092 $0.242 $0.668 $28.060 $0.790 $0.780 $1.133 $0.195 $0.634 $0.741 $0.850 $1.142 2019 $50.838 $2.864 $0.224 $0.660 $27.700 $0.779 $0.770 $1.119 $0.181 $0.626 $0.731 $0.839 $1.127 2020 $50.883 $2.838 $0.222 $0.660 $27.724 $0.780 $0.770 $1.120 $0.179 $0.627 $0.732 $0.840 $1.128 2021 $51.521 $2.887 $0.226 $0.668 $28.072 $0.790 $0.780 $1.134 $0.182 $0.634 $0.741 $0.850 $1.142 Thereafter $51.521 $2.887 $0.226 $0.668 $28.072 $0.790 $0.780 $1.134 $0.182 $0.634 $0.741 $0.850 $1.142 *Strip prices as of 5/25/2017. 33
Raymond James Boston Spring Investors Conference June 6, 2017