EnerCom s The Oil & Gas Conference August 17, 2016
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
We Are Focused on 2016 and Beyond We have weathered many cycles during our 50+ year history Balance sheet preservation is key Spending within cash flow Reduce debt with excess cash flow Manage costs 4
2015 Statistics Lowered capital expenditures to $416 million, down 58% from 2014. Exploration & Production Drilling Attained record annual production of 20 MMBoe, a 9% increase year over year Liquids production grew 7% year over year Proved reserves: 135 MMBoe (1) Eight BOSS rigs placed into service; seven under contract 94 drilling rig fleet Mid Stream 13% increase in daily natural gas processing volumes in 2015 11% increase in daily gathered volumes in 2015 Approximately 1,454 miles of pipeline (2) (1) As of December 31, 2015. (2) As of June 30, 2016. 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) 6/30/2016 5.26x (1,2) Secured Bank Facility (Amended April 2016) * Elected Commitment and Current Borrowing Base $475 million Outstanding (2) $236.0 million Maturity April 2020 Key Covenants Current ratio 1.0 to 1.0 (1) Senior Indebtedness ratio 2.75 (1) 6/30/2016 Actual 2.38x (1,2) 0.82x (1,2) (1) As defined in Indenture/Credit Agreement. (2) As of June 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) 1H 16 Daily Production: 48.8 MBoe/d Oil 18% NGLs 28% Gas 54% 60 50 40 30 20 10 0 Average Production (MBoe/d) 50 55 49 46 39 33 2011 2012 2013 2014 2015 1H 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) 900 800 700 600 500 400 300 200 100 0 Dixon 5554 XL #1H (C1) Projected Case (C1) 7.9 Bcfe 0 10 20 30 40 50 60 70 80 90 100 110 Days 1 Q3 2016 Strip Price Deck with 1 st Production Starting 8/2/2016; See Q3 2016 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 WI ~ 95% 190 240 potential XL locations (11 Granite Wash lenses) Plan to resume drilling activity in Q4 2016 or Q1 2017 Projected Type Curve (C1 Lense) 18 22 locations Gross EUR 7.9 Bcfe Well cost $5.7 MM ROR 1 : 33% ROR 1,2 : 55% Dixon 5554 XL #1H (C1) is 1 st 7,500 lateral in Buffalo Wallow 9
Hoxbar (Marchand Sand) Marchand Core Case: 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 Brown 1 11H IP30: 867 Boe/d 1/15 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 H O X B A R 3, 0 0 0 IP30: 801 Boe/d* Well cost: $4.6 million 83% liquids (68% oil) 30 35 core operated locations 58% average working interest 30 35 core non operated locations 35% average working interest Marchand Activity: Riley 1 34H IP30: 720 Boe/d 4/16 Norris 1 28H IP30: 950 Boe/d 3/16 GB 1 30H IP30: 1,367 Boe/d 3/14 Completed 4 horizontal wells in 1 st half of 2016 Plan to resume drilling activity in Q4 2016 * Based on 24 operated and nonoperated wells. 10
Wilcox (Southeast Texas) POLK TYLER Overall Highlights at end of Q2 2016: Drilled 157 operated wells since 2003 (150 vertical, 7 horizontal) 92% average working interest Q2 16 net avg. production: ~97 MMcfe/d 42% liquids (12% oil) Historical ROR: 108% Gilly Field 3D AREA 494 mi.² JASPER 1 st half 2016 LOE average $0.81/Mcfe Well cost: $6.5 $8.0 million 1 st Half 2016 Activity: HARDIN Completed 4 horizontal Wilcox wells Prior Years Drilling Horizontal Wells Completed 4 behind pipe recompletions Identified 2 new Wilcox project areas Acquired 165 square mile 3 D data Currently leasing 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 1 st Half Behind Pipe Recompletions 2016 2 nd Half Behind Pipe Recompletions 12
Parker GU #1 Gilly Field Wilcox Recompletion Summary Cumulative Production Since Recompletion: Gas: 0.82 BCF Oil: 44.0 MBO Cost: $588,994 Net PW10: $7.07 MM WI: 75.00% RI: 57.59% Updated: 8/10/2016 13
First Half 2016 Wilcox Recompletion Results Composite Gross Production from Recompleted Wells (1) Hankamer Tram #1 (2) Parker GU #1 (3) Black Stone O #3 (4) Black Stone BP #1 Black Stone O #3 Segno A Sd. Parker GU #1 Lower Gil. B Sd. Black Stone BP #1 Start of Year 650 mcfd 17 bopd Hankamer Tram #1 11,900 ft. Sd. End of Q2 14,200 mcfd 500 bopd 14
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 58 equipped with skidding or walking systems 10 14% total fleet utilization rate for Q2 2016 Eight BOSS rigs in service; seven currently under contract 54 Current Rigs Operating (1) Area # of Rigs Anadarko Basin 8 Bakken 2 Niobrara 2 Permian 3 Pinedale 1 Total 16 (1) As of August 16, 2016. 13 5 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 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 6 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). 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 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 1,972,000+ dedicated acres 193 MMcf/d processing capacity 570 miles of gathering pipeline Pittsburgh Regional office Pittsburgh Mills Bruceton Mills Snow Shoe Hemphill Reno Bellmon Tulsa Headquarters Central & Eastern OK 56,000+ dedicated acres 15 MMcf/d processing capacity 428 miles of gathering pipeline Appalachia 66,000+ dedicated acres 50 miles of gathering pipeline Connected 18 new wells in 1 st half of 2016 Panola East Texas 62 Miles of gathering pipeline Key Metrics 26 active systems Segno Three natural gas treatment plants 343 MMcf/d processing capacity Q2 16 processing volume 162 MMcf/d Processing facilities Approx. 1,450 miles of pipeline Gathering systems 18
Midstream Segment Contract Mix 2010 Q2 2016 Contract Mix Based on Volume 49% 51% Fee Based Commodity Based 22% 78% 85% 15% Contract Mix Based on Margin Fee Based Commodity Based 28% 72% Unit vs. 3 rd Party Margin Contribution 41% 37% 59% 3 rd Party Unit 63% 19
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 Signed contract with new producer and connected a new three well pad in Q2 2016 Pittsburgh Mills gathering system in Butler County, PA Connected 10 new wells in Q1 2016 Connected a new two well pad in Q2 2016 Received notice to connect a new well pad mid 2017 20
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 $200 $274 $200 $103 $0 2012 2013 2014 2015 1H '16 $0 2012 2013 2014 2015 1H '16 Oil and Natural Gas Contract Drilling Midstream (1) See Non GAAP Financial Measures in Appendix (also available at www.unitcorp.com/investor/reports.html). 21
Operating Segment Capital Expenditures (In Millions) $1,500 $1,000 $500 $0 2011 2012 2013 2014 2015 2016 Low End Budget Oil and Natural Gas Contract Drilling Midstream Acquisitions 2016 High End Budget 22
APPENDIX 23
Non GAAP Financial Measures Adjusted EBITDA Six months ended June 30, Years ended December 31, ($ In Millions) 2015 2016 2012 2013 2014 2015 Q2 LTM Net Income (Loss) ($523) ($113) $23 $185 $136 ($1,037) ($627) Income Taxes (315) (59) 16 117 87 (627) (371) Depreciation, Depletion and Amortization 197 110 319 334 405 355 268 Impairments 819 112 284 0 158 1,635 927 Interest Expense 15 20 14 15 17 32 37 (Gain) loss on derivatives (4) 12 1 8 (30) (26) (10) Settlements during the period of matured derivative contracts 21 12 0 (2) (6) 47 38 Stock compensation plans 12 8 17 22 24 21 17 Other non cash items 2 2 5 5 5 3 3 (Gain) loss on disposition of assets (1) (1) 0 (17) (9) 7 7 Adjusted EBITDA $223 $103 $679 $667 $787 $410 $289 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) Six months ended June 30, Years ended December 31, 2015 2016 2012 2013 2014 2015 Contract drilling revenue $150,092 $62,967 $529,719 $414,778 $476,517 $265,668 Contract drilling operating cost 88,231 47,352 289,524 247,280 274,933 156,408 Operating profit from contract drilling $61,861 $15,615 $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 3,447 235 15,583 17,416 29,343 3,991 65,308 15,850 255,778 184,914 230,927 113,251 Contract drilling operating days 7,305 3,108 26,704 23,720 27,516 12,681 Average daily operating margin before elimination of intercompany rig profit and bad debt expense $8,940 $5,100 $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 2016 2017 2018 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Collars Volume (Bbl) 468,650 225,400 133,400 Weighted Avg Floor $40.71 $44.44 $47.50 Weighted Avg Ceiling $49.88 $52.46 $56.40 3 Way Collars Volume (Bbl) 63,700 128,800 128,800 67,500 68,250 69,000 69,000 Weighted Avg Floor $46.50 $47.00 $47.00 $50.00 $50.00 $50.00 $50.00 Weighted Avg Subfloor $35.00 $35.00 $35.00 $37.50 $37.50 $37.50 $37.50 Weighted Avg Ceiling $57.00 $60.25 $60.25 $63.90 $63.90 $63.90 $63.90 Swaps Volume (Bbl) 92,000 Weighted Avg Swap $48.45 Natural Gas 2016 2017 2018 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Collars Volume (MMBtu) 3,822,000 3,864,000 3,864,000 1,800,000 1,820,000 1,840,000 620,000 Weighted Avg Floor $2.40 $2.40 $2.40 $2.88 $2.88 $2.88 $2.88 Weighted Avg Ceiling $2.88 $2.88 $2.88 $3.10 $3.10 $3.10 $3.10 3 Way Collars Volume (MMBtu) 1,228,500 1,242,000 1,242,000 1,350,000 1,365,000 1,380,000 1,380,000 Weighted Avg Floor $2.70 $2.70 $2.70 $2.50 $2.50 $2.50 $2.50 Weighted Avg Subfloor $2.20 $2.20 $2.20 $2.00 $2.00 $2.00 $2.00 Weighted Avg Ceiling $3.26 $3.26 $3.26 $3.32 $3.32 $3.32 $3.32 Swaps Volume (MMBtu) 4,095,000 4,140,000 4,140,000 5,400,000 5,460,000 5,520,000 5,520,000 900,000 910,000 920,000 920,000 Weighted Avg Swap $2.60 $2.60 $2.60 $2.96 $2.96 $2.96 $2.96 $3.03 $3.03 $3.03 $3.03 27
Q3 2016 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+ 2016 $40.994 $2.916 $0.192 $0.430 $0.601 $0.645 $0.892 $0.158 $0.374 $0.542 $0.655 $0.895 2017 $45.234 $3.144 $0.207 $0.474 $0.663 $0.711 $0.984 $0.170 $0.412 $0.598 $0.723 $0.988 2018 $48.125 $3.005 $0.198 $0.505 $0.706 $0.757 $1.047 $0.163 $0.438 $0.637 $0.769 $1.051 2019 $49.898 $2.980 $0.196 $0.523 $0.732 $0.785 $1.085 $0.161 $0.455 $0.660 $0.797 $1.090 2020 $51.305 $3.038 $0.200 $0.538 $0.752 $0.807 $1.116 $0.164 $0.467 $0.679 $0.820 $1.121 Thereafter $51.305 $3.038 $0.200 $0.538 $0.752 $0.807 $1.116 $0.164 $0.467 $0.679 $0.820 $1.121 28
EnerCom s The Oil & Gas Conference August 17, 2016