Johnson Rice Energy Conference September 25, 2018
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
A Diversified Energy Company 10 10 Casper Anadarko Basin Permian Basin 15 55 Mississippian Basin Oklahoma City 6 Marcellus Tulsa Headquarters Arkoma Basin North La/ East Texas Basin Pittsburgh Tulsa based, incorporated in 1963 Integrated approach to business allows Unit to capture margin from each business segment 96 Unit Rigs Houston Gulf Coast Basin E&P Operations Midstream Operations Office Location 3
Investment Highlights Opportunity-rich upstream portfolio with compelling economics provides optionality Upstream capital allocated to areas generating highest rates of return in the Company s portfolio Contract drilling segment activity level rebounding Sale of 50% equity stake in Superior highlights asset value and provides growth capital to benefit all three Unit Business segments Conservative balance sheet with corporate net debt < 2X EBITDA and philosophy of spending within cash flow 4
Core Upstream Producing Areas 60 50 40 30 20 10 0 Average Production (MBoe/d) Net Wells Drilled: 91 121 35 10 26 ~34 55 46 50 47 47-48 44 2013 2014 2015 2016 2017 2018 est Natural Gas Oil / NGLs NGLs 29% Oil 17% Gas 54% Q2 2018 Daily Production: 46.3 MBoe/d Mid Continent Region Hoxbar/STACK Granite Wash Upper Gulf Coast Region Wilcox Key focus areas include: Gulf Coast: Wilcox (Southeast Texas) Mid-Continent: Granite Wash (Texas Panhandle) Hoxbar (Western Oklahoma) STACK (Western Oklahoma) 5
Track Record of Reserve Growth Natural Gas Oil / NGLs 450% 300% 285% 261% 221% 161% 169% 166% 150% 0% -150% 6 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 180 160 150 150 120 90 79 69 60 58 42 45 48 30 0 (119%) 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 Proved Reserves (MMBoe) 179 116 Annual Reserve Replacement Average: 176% 171% 186% 176% 113% 337% 202% 204% 161% 135 118 (1%) 86 95 96 104 150 300%
Core Area Cash Margins $10.00 $9.00 Adjusted Base $9.05 $0.41 $8.00 $7.00 $6.00 $5.00 $1.56 Adjusted Base $6.85 $0.62 $1.17 Adjusted Base $5.98 $0.71 $1.18 Adjusted Base $4.58 Adjusted Base $4.75 Differential - Adjusted* LOE & Taxes $4.00 $3.00 $7.08 $5.05 $0.74 $1.30 $1.13 $1.13 Adjusted Base $2.98 $0.80 Cash Margin Gas Base, $2.81 $2.00 $1.00 $4.09 $2.71 $2.32 $0.92 $1.27 *Differentials adjusted for production stream mix $0.00 SOHOT STACK Oil STACK Condensate Wilcox Granite Wash STACK Dry Gas % Gas 17% 35% 42% 60% 63% 99% Note: Assumes 6:1 gas to oil ratio. Adjusted base represents the weighted average commodity price per Mcfe of the area s production (using WTI, Henry Hub and Mont Belvieu propane for NGL). Adjusted Base also includes 50% of applicable midstream margin for Granite Wash and Wilcox.
SOHOT Low Cost, High ROR Oil Play Lease Operator Spud Date IP-30 Boe/d % Oil Lateral Length 4 5 6 7 9 2 1 8 3 1 2 3 4 5 6 7 8 9 Schmidt #1-10H Unit 9/17 687 80 5,000 Nina #1-22H Unit 8/17 1,124 76 4,855 McConnell #1-11H Unit 10/17 1,091 63 4,943 Schenk Tr. #1-17HXL Unit 11/17 2,343 79 7,825 Schenk Tr. #2-17HXL* Unit 4/18 1,625 80 7,047 Schenk Tr. #3-17HXL* Unit 5/18 1,669 75 7,777 Liv. Land #1HXL Unit 1/18 499 72 7,985 Torralba 10-5-8 #1H Kaiser 1/17 575 70 4,839 Amanda 21-6-8 #1H Kaiser 3/17 540 71 5,050 Denotes Unit non-op working interest. *Denotes Well online less than 30 days Single Well Economics Type Curve Marchand 5,000 Marchand 7,500 IP - 30 (Boe/d) 668 935 ROR 122% 173% EUR (Mboe) 525 737 % Liquids 82% 82% Lateral Length 5,000 7,500 Well Cost ($mm) $5.4 $6.7 IRR % 350% 300% 250% 200% 150% 100% 50% 0% $60 / $2.50 8/1 Nymex $70 / $3.00 $80 / $3.50 1 8/1/2018 Strip Price Deck with 1 st Production Starting 10/1/2018. See Q3 2018 Economic Prices in Appendix (also available at www.unitcorp.com/investor/reports/html) Marchand 5k Marchand 7.5k 8
SOHOT Growing Oil Production and Improving Capital Efficiency 600,000 500,000 400,000 300,000 200,000 100,000 0 Quarterly Net BOE Q1'17 Q2'17 Q3'17 Q4'17 Q1'18 Q2'18 Gas NGL Oil Production Delayed Due to Pipeline Event Geology Marchand stacked lenses provide multiple oil drilling targets Medrano proved gas potential Land 23,000 contiguous net acres 84% HBP Majority operated Average working interest 86% 40 to 50 location inventory steady with continued acquisition of bolt on acreage Waterflood potential Operations Running one Unit Drilling rig Incremental optimization of drilling and completion process has kept cost low without sacrificing EUR Extended laterals (XL) improving capital efficiency 9
STACK Core - Provides High ROR Oil/Wet Gas with Dry Gas Optionality 7 Dry Gas 8 Type Curve Condensate 1 2 Unit s Acreage Meramec Woodford 5 3 13 4 Oil Oil Window Condensate Window Dry Gas* Window IP - 30 (Boe/d, Mcfe/d*) 1,693 1,756 14,023* ROR 111% 71% 4% EUR (Mboe/Bcfe*) 1,925 1,941 15.4* % Liquids/Gas* 63% 55% 99% Lateral Length 10,000 10,000 10,000 Well Cost ($mm) $10.7 $10.7 $10.9 10 3 5 12 9 1 8/1/2018 Strip Price Deck with 1 st Production Starting 10/1/2018. See Q3 2018 Economic Prices in Appendix (also available at www.unitcorp.com/investor/reports/html) 15 14 11 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 Lease Operator Spud Date IP-30 MMcfe/d Gas % Lateral Length Anderson Half Continental 2/2016 17.1 99% 9,676 Edith Mae* Continental 6/2016 23.6 99% 9,743 Mol* Continental 8/2017 25.0 100% 9,469 Hicks BIA Marathon 7/2017 14.8 99% 9,652 Essinger* Marathon 10/2017 6.8 95% 4,618 Wyatt* Continental 8/2016 16.5 100% 8,805 Eagle* Continental 9/2017 18.0 100% 9,679 Gripe FIU* Continental 8/2017 16.0 100% 10,175 Lease Operator Spud Date IP-30 Boe/d Liquids % Lateral Length Jordan Devon 4/2017 1,636 51% 10,050 ML Devon 9/2016 1,766 48% 4,676 Carpenter Cimarex 9/2017 1,734 57% 4,786 Privott Devon 10/2016 4,308 57% 10,112 Lorene Continental 7/2017 5,483 30% 10,186 Geronimo 89 Energy 6/2017 895 58% 4,797 Rafter J* Citizen II 7/2017 1,475 27% 8,423 IRR % Denotes Unit working interest 250% 200% 150% 100% 50% 0% *Denotes IP Per Public Data (>30 days) Single Well Economics $60 / $2.50 8/1 Nymex $70 / $3.00 $80 / $3.50 Stack Condensate Stack Dry Gas Stack Oil 10
STACK West Successful Extension of Meramec and Potential for Osage Development Type Curve Oil Condensate Dry Gas Unit s Acreage Meramec Osage 2 5 12 12 3 10 4 13 1 146 3 9 11 610 7 STACK Ext Meramec STACK Osage IP - 30 (Boe/d) 1,199 1,160 ROR 96% 33% Total EUR (Mboe) 1,064 996 % Liquids 57% 53% Lateral Length 5,000 5,000 Well Cost ($mm) $6.2 $7.3 58 911 1 8/1/2018 Strip Price Deck with 1 st Production Starting 10/1/2018. See Q3 2018 Economic Prices in Appendix (also available at www.unitcorp.com/investor/reports/html) 47 813 1 2 3 4 5 6 7 8 9 10 11 12 13 14 Lease Operator Spud Date IP-30 Boe/d Liquids % Lateral Length Cox Tapstone 9/2017 1,583 20% 10,009 Rebecca Tapstone 11/2017 788 50% 10,130 GTO Judge Devon 12/2017 1,117 35% 9,431 Bond Comanche 6/2017 1,305 40% 4,300 Walters Newfield 7/2017 1,598 77% 10,179 Ward Comanche 106/2015 627 75% 4,162 Medrill Sandridge 10/2016 1,164 85% 4,681 Schoeppel Chesapeake 7/2016 865 54% 4,764 McConnell Comanche 6/2016 532 46% 4,493 Drinnon Tapstone 5/2016 793 22% 4,111 Olive Lee Devon 3/2014 1,755 19% 4,594 Bivens Tapstone 11/2017 1,363 48% 4,436 Lease Operator Spud Date IP-30 Mmcfe/d Gas % Lateral Length Irwin* Unit 5/2018 5.7 90% 4,567 Tucker Council Oak 6/2017 8.1 99% 4,378 IRR % Denotes Unit working interest 250% 200% 150% 100% 50% 0% *Denotes Well online less than 30 days Single Well Economics $60 / $2.50 8/1 Nymex $70 / $3.00 $80 / $3.50 Stack Ext Meramec Stack Osage 11
STACK Growing into Core Area for Unit Petroleum 140,000 120,000 100,000 80,000 60,000 40,000 20,000 0 Quarterly Net BOE Q1'17 Q2'17 Q3'17 Q4'17 Q1'18 Gas NGL Oil Geology Stacked drilling targets in Osage, Meramec and Woodford Red Fork Potential in some areas Sands consistently present across play Land 17,000 net acres in STACK/STACK West 85% HBP 100-150 potential operated locations with working interest of 40-60% 500-900 potential non-operated locations with working interest of ~5% Operations Running one Unit Drilling rig Participating ~50 non-op wells in 2018 Focused on oil and wet gas window Dry gas delayed until gas margins and takeaway capacity improves 12
Granite Wash Low Risk Wet Gas Condensate Play with NGL Price Upside Well Operator Spud Date IP-30 MMcfe/d Gas % Lateral Length 7 8 5 3 4 1 2 6 1 2 3 4 5 6 7 8 Dixon 5554 XL #1H Unit 2/16 12.5 47% 7,503 Dixon 5554 EXL #4H Unit 2/17 7.5 47% 7,474 Carr 1357 EXL #1H Unit 3/17 14.9 45% 7,891 Carr 1357 EXL #2H Unit 5/17 9.2 45% 7,663 Francis 5859 EXL #2H Unit 9/17 8.1 49% 9,442 Dixon 5554 EXL #5H Unit 6/17 2.1 64% 7,802 Meek 6836H Unit 5/14 5.7 61% 4,375 Meek 6814 XL #1H Unit 3/18 5.5 49% 9,410 Single Well Economics Unit Tecolote Jones FourPoint Le Norman BP GW C1 GW B GW G 120% 100% Type Curve Granite Granite Granite Wash C1 Wash G Wash B IP - 30 (Mcfe/d) 9,960 9,000 7,900 ROR 47% 49% 29% EUR (Bcfe) 7.6 14.2 7.1 % Gas 48% 77% 52% Lateral Length 7,500 7,500 7,500 Well Cost ($mm) $6.2 $6.2 $6.2 Granite Wash C1 Granite Wash G Granite Wash B 1 8/2/2018 Strip Price Deck with 1 st Production Starting 10/1/2018. See Q3 2018 Economic Prices in Appendix (also available at www.unitcorp.com/investor/reports/html) IRR % 80% 60% 40% 20% 0% $60 / $2.50 8/2 Nymex $70 / $3.00 $80 / $3.50 13
Granite Wash Competitive Advantages Drive Differentiated Value 5,000 4,500 4,000 3,500 3,000 2,500 2,000 1,500 1,000 500 0 Buffalo Wallow Quarterly Net MMcfe Q1'17 Q2'17 Q3'17 Q4'17 Q1'18 Q2'18 Gas NGL Oil Geology 11 Stacked Granite Wash lenses significantly improves capital efficiency Sands present across acreage Land 9,000 net largely contiguous acres allow for extended lateral (XL) drilling 90% HBP and Operated Average working interest 90% 100-150 potential XL locations Operations/Infrastructure/Processing Running two Unit Drilling rigs Incremental process improvements continue to decrease drilling days SWD network lowers disposal costs 80% Water recycling pits lower frack costs Electricity across field lowers lifting costs Superior processes the gas improving cash margin 14
Wilcox Conventional Stacked Over-Pressured Intervals Provide Low Cost Homerun Potential BCFE 40 30 20 10 0 POLK Gilly Field Prior Years Drilling Horizontal Wells TYLER 3D AREA 494 mi.² HARDIN Wilcox Annual Production JASPER 2012 2013 2014 2015 2016 2017 2018 Projected Gas Oil NGLs LOEX ($/MCFE) $/MCFE 2.00 1.60 1.20 0.80 0.40 Overall Wilcox Drilling Program Results Drilled 170 operated wells since 2003 (160 vertical, 10 horizontal) Program ROR > 80% Operated with working interest ~ 92% Production: ~ 110 MMcfe/d (42% liquids) Running one Unit Drilling rig Gilly Field World Class Wet Gas Reservoir 500 Bcfe stacked pay gas resource Cumulative production ~ 125 Bcfe Average EUR of 10-20 Bcfe per well Typical well ~ $6 MM cost, ROR > 100% Unit s Wilcox Competitive Advantages Premium Gulf Coast pricing for oil and gas Wet Gas/Condensate provides margin uplift Large 3D seismic database provides consistent stream of exploratory prospect ideas Conventional over-pressured reservoirs provide homerun potential at low acreage costs 15
Wilcox Trend Provides an Extensive Play Area Wilcox Strategy for Future Growth Continue development of Gilly Field area with vertical and horizontal drilling and over 80 stacked pay recompletion/workover opportunities in existing wells Drill and delineate high inventory of exploratory prospects (34) with homerun potential (e.g. Wing/ Cherry Creek/Brandt prospects) Utilize horizontal drilling to extend field boundaries and accelerate reserve recovery (e.g. Gilly/NE Segno/Village Mills Fields)
Rig Fleet Presence in Key Regions 96 rig fleet 20 800 HP: 21% 72 1,000-1,700 HP: 75% 4 2,000 HP: 4% 10 70% electric 54% 1,500 HP or greater 35 equipped with skidding or walking systems 27 additional can be skidded 35% total fleet utilization at present All eleven BOSS rigs operating Entered into long-term contracts for 12 th and 13 th BOSS rigs Current Rigs Operating (1) Area # of Rigs Mid Continent 19 Bakken 5 Niobrara 1 Permian 7 DJ 1 Gulf Coast 1 Total 34 10 15 55 6 (1) As of September 21, 2018. 17
SCR Rigs Continue to Make an Important Contribution 40 35 30 26 21 23 At industry trough 13 drilling rigs operating 25 20 15 12 Currently, 34 drilling rigs operating All BOSS rigs operating 10 5 7 6 9 10 10 11 23 SCR rigs operating 0 May 5, 2016 Dec. 31, 2016 Sept. 4, 2017 Dec. 31, 2017 Sep. 21, 2018 A/C SCR 18
Average Dayrates and Margins (1) $20,000 100% Margins and Dayrates $15,000 $10,000 $5,000 75% 50% 25% Average Rig Utilization Decline in dayrates lagged utilization decrease due to long-term contract roll-off Utilization increased from low in Q2 2016 Margins improved from Q2 2017 forward $0 2014 2015 2016 2017 Q2'18 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). 19
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 11 BOSS rigs currently under contract 12 th and 13 th BOSS rig s under contract (components being assembled) 20
Superior Joint Venture Overview SP Investor Holdings LLC 50% 50% Retains 50% equity interest Received $300 million Retains operational control of Superior Pipeline Acquired 50% equity interest $300 million consideration Non-managing member Superior Credit Facility: On May 10, 2018, Superior entered into a five year $200 million senior secured revolving credit facility with an option to increase the credit amount up to $250 million, subject to certain conditions. 21
Midstream Core Operations Hemphill Reno Bellmon Tulsa Headquarters Panola Northern Oklahoma and Kansas 1,752,102 dedicated acres 201 MMcf/d processing capacity 614 miles of gathering pipeline Texas Panhandle 46,900 dedicated acres 135 MMcf/d processing capacity 331 miles of gathering pipeline Central & Eastern OK 62,720 dedicated acres 12 MMcf/d processing capacity 397 miles of gathering pipeline Key Metrics 22 active systems Three natural gas treatment plants 348 MMcf/d processing capacity Q2 18 average processing volume of 161 MMcf/d Approx. 1,457 miles of pipeline Segno East Texas 62 miles of gathering pipeline 120 MMcf/d dehy capacity Q2 18 average gathered volume of 84.1 MMcf/d Pittsburgh Regional office Brook Field Pittsburgh Mills Snow Shoe Processing facilities Gathering systems Appalachia 70,894 dedicated acres 53 miles of gathering pipeline Q2 18 average gathered volume of 123.3 MMcf/d Connected 7 new infill wells in Q2 18 Bruceton Mills 22
Midstream Segment Contract Mix 2010 Q2 2018 Contract Mix Based on Volume 49% 51% Fee Based Commodity Based 34% 66% 85% 15% Contract Mix Based on Margin Fee Based Commodity Based 40% 60% Unit vs. 3 rd Party Margin Contribution 41% 39% 59% 3 rd Party Unit 61% 23
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) 6/30/2018 6.28x (1,2) Secured Bank Facility (Redetermined April 2018) * Borrowing Base and Elected Commitment $425 million Outstanding (2) $0 Maturity April 2020 Key Covenants Current ratio 1.0 to 1.0 (1) Senior Indebtedness ratio 2.75 (1) 6/30/2018 3.67x (1,2) 0x (1,2) (1) As defined in Indenture/Credit Agreement. (2) As of June 30, 2018. * Drilling rigs are not included in borrowing base. 24
Segment Contribution Revenues ($ millions) Adjusted EBITDA ($ millions) (1) $1,600 $1,573 $800 $785 $1,400 $1,200 $600 $1,000 $800 $600 $400 $854 $602 $740 $408 $400 $200 $408 $250 $313 $178 $200 $0 2014 2015 2016 2017 6 mos. '18 $0 2014 2015 2016 2017 6 mos. '18 Oil and Natural Gas Contract Drilling Midstream (1) See Non-GAAP Financial Measures in Appendix (also available at www.unitcorp.com/investor/reports.html). 25
Operating Segment Capital Expenditures (1) (In Millions) $1,500 $1,000 $500 $0 2013 2014 2015 2016 2017 2018 Forecast Oil and Natural Gas Contract Drilling Midstream (1) Net of acquisitions and plugging liability revisions. 26
APPENDIX 27
Non-GAAP Financial Measures - Corporate Adjusted EBITDA Six months ended June 30, Years ended December 31, ($ In Millions) 2017 2018 2014 2015 2016 2017 Net Income (Loss) $25 $16 $136 ($1,037) ($136) $118 Income Taxes 20 6 87 (627) (71) (58) Depreciation, Depletion and Amortization 97 115 403 353 208 209 Impairments --- --- 158 1,635 162 --- Interest Expense 19 18 17 32 40 38 (Gain) loss on derivatives (24) 21 (30) (26) 23 (15) Settlements during the period of matured derivative contracts (2) (9) (6) 47 10 --- Stock compensation plans 8 12 24 21 14 18 Other non-cash items 2 (1) 5 3 3 3 (Gain) loss on disposition of assets (1) --- (9) 7 (3) --- Adjusted EBITDA $144 $178 $785 $408 $250 $313 Adjusted EBITDA attributable to noncontrolling interest --- 7 --- --- --- --- Adjusted EBITDA attributable to Unit $144 $171 $785 $408 $250 $313 28
Non-GAAP Financial Measures - Segments Segment Adjusted EBITDA (with G&A allocated) Six months ended June 30, Years ended December 31, ($ In Millions) 2017 2018 2014 2015 2016 2017 Unit Petroleum Income (Loss) Before Income Taxes (1) $ 64 $ 75 $ 199 $ (1,631) $ (102) $ 125 Depreciation, Depletion and Amortization 45 62 276 252 114 102 Impairment of Oil and Natural Gas Properties --- --- 77 1,599 162 --- Other Adjustments (2) (4) (14) (10) 43 6 (5) Adjusted EBITDA $ 105 $ 123 $ 542 $ 263 $ 180 $ 222 Unit Drilling Income (Loss) Before Income Taxes (1) $ (7) $ 2 $ 42 $ 45 $ (13) $ (4) Depreciation and Impairment 27 27 160 64 47 56 Other Adjustments (2) (4) (3) (6) (4) (8) (8) Adjusted EBITDA $ 16 $ 26 $ 196 $ 105 $ 26 $ 44 Superior Pipeline Income (Loss) Before Income Taxes (1) $ 4 $ 7 $ 2 $ (30) $ 2 $ 8 Depreciation, Amortization and Impairment 22 22 48 71 46 44 Other Adjustments (2) (3) --- (3) (2) (4) (5) Adjusted EBITDA $ 23 $ 29 $ 47 $ 39 $ 44 $ 47 (1) After intercompany eliminations. (2) Adjustments per non-gaap financial measures corporate schedule (previous slide). 29
Non-GAAP Financial Measures Reconciliation of Average Contract Drilling Daily Operating Margin Before Elimination of Intercompany Rig Profit and Bad Debt Expense Six months ended Years ended (In thousands except for operating days June 30, December 31, and operating margins) 2017 2018 2014 2015 2016 2017 Contract drilling revenue $76,440 $92,915 $476,517 $265,668 $122,086 $174,720 Contract drilling operating cost 56,466 63,561 274,933 156,408 88,154 122,600 Operating profit from contract drilling $19,974 $29,354 $201,584 $109,260 $33,932 $52,120 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 376 1,248 29,343 3,991 235 1,620 20,350 30,602 230,927 113,251 34,167 53,740 Contract drilling operating days 4,916 5,778 27,516 12,681 6,374 10,964 Average daily operating margin before elimination of intercompany rig profit and bad debt expense $4,139 $5,296 $8,392 $8,931 $5,360 $4,901 30
Derivative Summary 2018 2019 2020 Q3 Q4 CRUDE: Collars Volume (Bbl) -- -- -- -- Weighted Avg Floor -- -- -- -- Weighted Avg Ceiling -- -- -- -- 3-Way Collars Volume (Bbl) 184,000 184,000 1,460,000 -- Weighted Avg Floor $47.50 $47.50 $61.25 -- Weighted Avg Subfloor $37.50 $37.50 $51.25 -- Weighted Avg Ceiling $56.08 $56.08 $72.93 -- Swaps Volume (Bbl) 368,000 368,000 -- -- Weighted Avg Swap $53.52 $53.52 -- -- NATURAL GAS: Collars Volume (MMBtu) 2,760,000 -- -- -- Weighted Avg Floor $2.67 -- -- -- Weighted Avg Ceiling $2.97 -- -- -- 3-Way Collars Volume (MMBtu) 1,840,000 1,840,000 -- -- Weighted Avg Floor $3.00 $3.00 -- -- Weighted Avg Subfloor $2.50 $2.50 -- -- Weighted Avg Ceiling $3.51 $3.51 -- -- Swaps Volume (MMBtu) 3,680,000 2,150,000 3,650,000 -- Weighted Avg Swap $2.99 $3.01 $2.81 -- Basis Swaps Volume (MMBtu) 2,760,000 2,450,000 21,900,000 10,950,000 Weighted Avg Swap ($0.48) ($0.52) ($0.46) ($0.28) PROPANE: Swaps Volume (Bbl) 138,000 -- -- -- Weighted Avg Swap $32.144 -- -- -- 31
Q3 2018 Economic Prices Strip Case* Crude Natural Gas MB C2 MB C3 MB C3 $ per barrel MB NC4 MB ic4 MB C5+ CW C2 CW C3 CW NC4 CW ic4 CW C5+ 2018 $66.525 $2.812 $0.375 $0.924 $38.818 $1.077 $1.091 $1.475 $0.127 $0.693 $0.809 $0.978 $1.228 2019 $63.563 $2.710 $0.361 $0.883 $37.089 $1.029 $1.043 $1.409 $0.123 $0.662 $0.773 $0.935 $1.173 2020 $60.526 $2.600 $0.346 $0.841 $35.317 $0.980 $0.993 $1.342 $0.118 $0.631 $0.736 $0.890 $1.117 2021 $57.988 $2.567 $0.342 $0.806 $33.837 $0.938 $0.951 $1.286 $0.116 $0.604 $0.705 $0.853 $1.070 2022 $56.145 $2.600 $0.346 $0.780 $32.761 $0.909 $0.921 $1.245 $0.118 $0.585 $0.683 $0.826 $1.036 Thereafter $56.145 $2.600 $0.346 $0.780 $32.761 $0.909 $0.921 $1.245 $0.118 $0.585 $0.683 $0.826 $1.036 *Strip prices as of 8/2/2018. 32
JOHNSON RICE ENERGY CONFERENCE September 25, 2018