unitsmarch2020presentati

Investor Presentation March 2020

Forward Looking Statement The information contained herein may include proprietary, sensitive, and confidential information regarding Unit Corporation (together with its wholly-owned direct and indirect subsidiaries, the “Company”), which has not been publicly disclosed. This information is being provided to you in your capacity as a member of the ad hoc group of holders of the Company’s 6.625% senior subordinated notes due 2021, and is subject to the confidentiality agreement you have executed with the Company. Your receipt of this document evidences your understanding and consent that the information contained herein is not to be reproduced, disclosed to any other person, or used for any purpose other than in your capacity as set forth above or as otherwise may be agreed to in writing by the Company. The distribution of these materials or the divulgence of any of their contents to any person, other than the person to whom they were originally delivered and such person’s advisors, without the prior consent of the Company, is prohibited. You are advised that United States securities laws restrict any person who has material, non-public information about a company from purchasing or selling securities of such company (and options, warrants, and rights relating thereto) and from communicating such information to any other person under circumstances in which it is reasonably foreseeable that such person is likely to purchase or sell such securities. You agree not to purchase or sell such securities in violation of any such laws. 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. 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 the Company’s ability to continue as a going concern, the Company’s substantial indebtedness, the Company’s ability to pay, refinance, restructure or amend its indebtedness or otherwise improve its capital structure and liquidity, the possible early maturity of the Company’s Senior Credit Agreement, the Company’s 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 and other risks disclosed under “Risk Factors” in the Company’s most recent Form 10-K and Form 10-Q. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those indicated. 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. This presentation may contain certain terms, such as locations and estimated ultimate recovery (“EUR”) and other similar terms that describe estimates of potential wells and potentially recoverable hydrocarbons that SEC rules prohibit from being included in filings with the SEC. These estimates are by their nature more speculative than estimates of proved, probable and possible reserves and may not constitute “reserves” within the meaning of SEC rules and, accordingly, are subject to substantially greater risk of being actually realized. These estimates are based on the Company’s existing models and internal estimates. 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 EBITDA, adjusted EBITDA, and certain operating margins and 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. NYSE: UNT

Company Overview NYSE: UNT

A Diversified Energy Company 12 8 Casper Marcellus Pittsburgh Mississippian Basin Anadarko Tulsa Headquarters Basin 23 Oklahoma Arkoma Basin City Permian North LA/ • Basin East Texas Basin Tulsa based, Drilling Rigs (58) 11 4 incorporated in 1963 E&P Operations • Houston Gulf Coast Integrated approach Midstream Operations Basin allows Unit to capture margin from each Office Location business segment NYSE: UNT 1

Business Strategy Increase Exposure to Oil Prone Projects Expand Midstream Objective: Manage Drilling Fleet to Maximize Operations by Enhance Stakeholder Value Through Focusing on High Utilization Rate and Sustainable, Capital-Efficient Growth Growth Areas Day Rate Margins Maintain Financial Flexibility NYSE: UNT 2

Company Highlights Unit is an integrated oil & gas company capturing margin across the value chain 1 Diversified and integrated asset base across upstream, midstream, and drilling services 2 Upstream portfolio in the core of the Mid-Con and Gulf Coast with multiple years of inventory 3 Continuing shift to liquids 4 Midstream assets provide predictable fee-based cash flows with 66% coming from 3rd party producers 5 Top tier drilling services business with 100% utilization on high-spec, proprietary BOSS rigs 6 Experienced management team NYSE: UNT 3

Experienced Management Team Years Position Experience Previous Experience President & Chief Larry D. Pinkston1 38 years Executive Officer David T. Merrill1 Chief Operating Officer 36 years General Counsel & Mark E. Schell 40 years C & S Exploration Corporate Secretary G. Les Austin Chief Financial Officer 31 years Executive Vice President Cromling Drilling Company John Cromling 49 years of Drilling for UDC Big Chief Drilling Company Executive Vice President Frank Young 28 years of Exploration for UPC Founder and President Robert Parks 41 years of SPC Chief Operating Officer Mike Hicks 32 years of SPC CMS Field Services Senior Vice President – David Dunham 20 years Business Development 1. Unit Corporation announced on February 21, 2020, David T. Merrill will succeed Larry D. Pinkston as Chief Executive Officer and President, effective April 1, 2020. Larry Pinkston will remain on Unit’s Board of Directors NYSE: UNT 4

Business Segment Overview Unit Petroleum Corporation (“UPC”) Unit Drilling Corporation (“UDC”) Superior Pipeline Company (“SPC”) • Currently running 0 rigs • 58 rig fleet; 18 rigs contracted • Conducted through Superior Pipeline Company • Q3 2019 Production: 47.8 Mboe/d L.L.C., a JV with SP Investor Holdings • 31% total fleet utilization • 51% gas / 28% NGL / 21% oil • Operations consist of buying, selling, gathering, • 55 rigs pad capable processing, and treating natural gas and NGLs • 355,762 net acres (509,930 gross) • ~88% operated production • 14 patented high-spec BOSS rigs optimized • 21 active gathering systems • ~86% HBP for pad drilling • 12 gas processing plants • 750-950 gross locations • 100% BOSS rig utilization • 3 natural gas treatment plants • 2019E YE Proved Reserves: • ~323 MMcf/d processing capacity • 109.7 Mmboe • ~2,100 miles of pipeline in Texas, Oklahoma, • Proved PV-10: $623mm and Appalachia Adjusted EBITDA by Segment Margin by Business Segment (In Millions) 75.0% $500 60.0% $400 $300 45.0% 30.0% $200 Margin $100 15.0% $0 0.0% 2015 2016 2017 2018 9 mos. '19 2015 2016 2017 2018 9 mos. '19 Oil and Natural Gas Contract Drilling Midstream Upstream Midstream Contract Drilling NYSE: UNT 5

Unit’s Integrated Approach Unit’s contract drilling business’ strong margins and cash flow generation helps fund investment in the upstream segment UPC only uses Unit drillings rigs, thereby integrating the value chain Superior’s 25% commodity based exposure allows for some upside to improving commodity prices but also provides significant fee based cash flows Superior systems near UPC properties creates flexibility and allows Unit to capture the margin from Superior’s economics JV terms with Superior provide potential for value realization during a liquidation event or via distribution NYSE: UNT 6

Upstream Segment Overview NYSE: UNT

Upstream Segment Overview Proved Reserves PDNP Mid Continent Region YE 2019E Proved 15% PDP Reserves (Mboe): PUD 58% Hoxbar/STACK PDP: 73,889 PUD18% PDP 67% Granite Wash PDNP: 15,790 30% PUD: 19,997 PDNP Upper Gulf Coast Region 12% Wilcox Q3 2019 Daily Production Oil Q3 2019 Daily 21% Production: Gas 51% 47.8 MBoe/d NGLs 28% Key focus areas include: Mid-Continent: . Southern Oklahoma Hoxbar Oil Trend PV-10 (SEC Pricing) (“SOHOT”) & Red Fork (Western PDNP Oklahoma) 8% . STACK (Western Oklahoma) PUD PDP Total YE 2019E PV-10: PUD16% . Granite Wash (Texas Panhandle) PDP: $474 16% 75% Upper Gulf Coast: PDNP: $53 PDNP PDP . Wilcox (Southeast Texas) PUD: $97 9% 76% NYSE: UNT 7

2019E YE Reserve Detail Oil (Mbbls) Nat Gas (MMcf) NGL (Mbbls) Total (Mboe) PV-10 ($MM) PDP 12,358 227,003 23,697 73,889 $474 PDNP 2,358 52,484 4,685 15,790 $53 PUD 6,864 44,592 5,701 19,997 $97 Total Proved 21,579 324,079 34,084 109,676 $623 Reserves based on SEC price deck; oil at $55.69/Bbl; natural gas liquids at $23.19/Bbl; and natural gas at $2.58/Mcf. All prices before differentials applied. Net Proved Reserves Proved Reserves Allocation PV-10 PDNP PDNPPDNP OilOil 8% 15% 15% 20%17% PUD PUD16% PUD Gas PDP 18% PDP 49% 67% NGLs PDP 31% 76% NYSE: UNT 8

History of Production Growth with Increased Liquids Content (Mboe/d) 60 60% 55 50 47 47 46 46 45 44 45% 39 33 30 29 30% 28 27 24 25 19 15 15 15% 10 10 11 0 0% 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 9 mos. Gas Oil / NGLs % Liquids 2019 NYSE: UNT 9

Track Record of Reserve Growth 179 180 160 160 150 150 150 135 132 116 118 120 104 95 96 86 90 79 Proved Reserves 69 58 (MMBoe) 48 60 42 45 30 0 1 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 Q3'19 Natural Gas Oil / NGLs 450% Average: 160% 337% 285% 300% 300% 261% Annual Production 221% 186% 202% 204% Replacement with 162% 169% 166% 171% 176% 161% 158% New Reserves 150% 113% 0% (1%) -150% (119%) (115%) 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 Q3'19 1. Represents unaudited reserves NYSE: UNT 10

Core Area Cash Margins (Mcfe) $8.00 $7.00 Adjusted Base $6.28 $6.00 $0.33 Adjusted Base Adjusted Base $1.37 $5.03 $5.14 $5.00 $0.38 $0.55 Adjusted Base $4.25 Differential - Adjusted* $4.00 $1.12 $0.40 LOE & Taxes $1.49 Adjusted Base Adjusted Base $3.40 $3.33 Cash Margin $1.06 $0.47 $3.00 Adjusted Base $0.89 $2.62 Gas Base, $2.48 $4.59 $0.98 $0.66 $2.00 $3.52 $1.09 $3.10 *Differentials adjusted for $2.78 $0.91 production stream mix $1.00 $1.95 $1.35 $1.05 $0.00 SOHOT STACK Oil Red Fork STACK Wilcox Granite Wash STACK Dry Gas Condensate % Gas 23% 35% 39% 42% 61% 62% 99% Note: assumes 6:1 gas to oil ratio. Production is based on actual (Jan 2019 through Sept 2019) or average type curves for the respective plays. The adjusted base prices represent the weighted average commodity price per Mcfe for each area’s production (using WTI, Henry Hub and Mont Belvieu propane as a proxy for NGL prices) and are based on the November 1, 2019 strip. Differentials are adjusted to each area’s production mix as of November 5, 2019. Differentials for the STACK Dry Gas and Granite Wash are estimated from basis futures and index pricing as of May 28, 2019 and assume a 75% reduction of marketing fees after the commissioning of the Midship Pipeline. Lease operating expenses are based on area specific operating cost models used in preparation of the 2019 2nd Quarter Proved Reserve Report and include gas transportation costs updated as November 5, 2019. Taxes are calculated using production and pricing described in the reserve report with Texas severance taxes adjusted for high cost tax rates. The adjusted base also includes 50% of the applicable midstream margin for Granite Wash and Wilcox NYSE: UNT 11

SOHOT – Low Cost, High ROR Oil Play Unit Petroleum 11 5D “A” 18/7 1HXL IP30: 497 Boe/d 98% Oil Kaiser Francis 10 Amanda 21-6-8 1H IP30: 540 Boe/d 71% Oil Kaiser Francis 9 Torralba 10-5-8 1H IP30: 578 Boe/d 70% Oil Unit Petroleum Camino Unit Petroleum Echo E&P LLC 8 5D 13/12 1HXL Kaiser- Francis IP30: 520 Boe/d 88% Oil Limerock Resources Unit Petroleum 7 Livingston Land 1HXL IP30: 565 Boe/d 72% Oil Unit Petroleum Denotes Unit Non-Op 6 Schenk Trust 3-17HXL working interest IP30: 1,470 Boe/d 75% Oil Marchand Horizontal Unit Petroleum Unit Petroleum Unit Petroleum Unit Petroleum Unit Petroleum 1 Schmidt 1-10H 2 Nina 1-22H 3 McConnell 1-11H 4 Schenk Trust 1-17HXL 5 Schenk Trust 2-17HXL IP30: 687 Boe/d 80% Oil IP30: 1,124 Boe/d 76% Oil IP30: 1,271 Boe/d 63% Oil IP30: 2,349 Boe/d 79% Oil IP30: 1,463 Boe/d 79% Oil NYSE: UNT 12

SOHOT – Low Cost, High ROR Oil Play Marchand Marchand Type Curve 5,000’ 7,500’ IP - 30 (Boe/d) 720 1,006 ROR (1) 73% 108% EUR (Mboe) 568 812 % Liquids 76% 76% Well Cost ($mm) $4.7 $5.9 Single Well Economics 350% 300% 250% % 200% ROR 150% 100% Marchand Horizontal 50% 0% Unit Petroleum $45 / $2.50 11/1 Nymex $65 / $3.50 $75 / $4.00 Camino Echo E&P LLC 5,000' Lateral 7,500' Lateral Kaiser- Francis Limerock Resources 1. 11/1/2019 Strip Price Deck with 1st Production Starting 1/1/2020. (available at www.unitcorp.com/investor/reports/html) NYSE: UNT 13

SOHOT – Predictable Oil Production and Improving Capital Efficiency Geology SOHOT Daily Net BOE by Type 6,000 • Marchand stacked lenses provide multiple oil drilling targets • Medrano proved gas potential 5,000 Land • 31,500 net acres 4,000 • 84% HBP • Majority operated Oil • Average working interest ~ 89% 3,000 • Potential locations: NGL Gas Marchand Medrano Total Operated 15-20 10-15 25-35 2,000 Non-operated 35-40 15-20 50-60 Operations/Infrastructure/Processing 1,000 • Incremental optimization of drilling and completion process has kept cost low without sacrificing EUR 0 • Extended laterals (XL) improving 2017 2018 Est. 2019 capital efficiency NYSE: UNT 14

Red Fork – Adds Oily Drilling Inventory Red Fork Summary • 19,100 net acres • 86% HBP • 64% average WI • 9 horizontal wells drilled • 20-30 operated locations • 15-25 non-op locations • Well costs: • 4,500’ $5.7 MM • 7,500’ $7.1 MM Unit Petroleum Unit Petroleum Unit Petroleum Unit Petroleum Unit Petroleum 1 Frymire 1-18H 2 Hamar 3H-17 3 Schrock 2215 1HX 4 Schrock 1H-19 IP30: 755 Boe/d (9% Oil) IP30: 1,080 Boe/d (72% Oil) IP30: 1,910 Boe/d (54% Oil) IP30: 300 Boe/d (70% Oil) Unit Petroleum Unit Petroleum Unit Petroleum Unit Petroleum Unit Petroleum 5 Wingard 1522 #2HX 6 Wingard Farms 2128 1 HX 7 Saratoga 1720 1 HX 8 Wingard 1510 #1HX 9 Hayes Trust 1 H-12 IP30: 480 Boe/d (16% Oil) IP30: 2,775 Boe/d (75% Oil) IP30: 3,020 Boe/d (75% Oil) IP30: 1215 Boe/d (53% Oil) IP30: 1,615 Boe/d (81% Oil) NYSE: UNT 15

STACK Core – Provides Good ROR Oil/Wet Gas with Dry Gas Optionality Continental Resources 10 Privott 17_20-16N-9 1HX 10 IP30: 4,308 Boe/d 30% Oil Unit Petroleum Cont’l Resources Devon Energy Devon Energy 9 9 Tiger Swallowtail 1HX Cimarex IP30: 18.4 MMcfe/d 81% Gas Citizen Energy II 8 6 Devon Energy 8 Cheetah 32_29-15N-101XH 2 IP30: 3,730 Boe/d 41% Oil Citizen Energy 1 4 7 Braveheart 1H-21-28 3 IP30: 7.4 MMcfe/d 100% Gas 5 Continental Resources 6 Lorene 1-8-5XH IP30: 5,483 Boe/d 30% Oil Denotes IP Per 7 * Public Data Continental Resources 5 Mol 1-7-8XH * Denotes Unit Non-Op IP30: 25.0 MMcfe/d 100% Gas working interest Meramec Horizontal Continental Resources MEP Operating Continental Resources Marathon 1 Eagle 1R-15-10XH * 2 Spanish Castle Magic 1HX* 3 Heckenberg 2-30-19XH 4 Hicks BIA 1-13-12XH IP30: 18.0 MMcfe/d 100% Gas IP30: 22.2 MMcfe/d 99% Gas IP30: 32.2 MMcfe/d 100% Gas IP30: 14.8 MMcfe/d 99% Gas NYSE: UNT 16

STACK Core – Provides Good ROR Oil/Wet Gas with Dry Gas Optionality Oil Condensate Dry Gas* Type Curve Window Window Window IP - 30 (Boe/d, Mcfe/d*) 1,671 1,727 12,212* ROR (1) 104% 36% 0% EUR (Mboe/Bcfe*) 1,890 1,914 13.2* % Liquids/Gas* 63% 55% 99%* Lateral Length 10,000 10,000 10,000 Well Cost ($mm) $8.0 $10.0 $10.9 *Natural gas/equivalent metrics Single Well Economics 400% 350% 300% 250% % Unit Petroleum 200% Continental Resources ROR 150% Devon Energy 100% Cimarex 50% Citizen Energy II 0% $45 / $2.50 11/1 Nymex $65 / $3.50 $75 / $4.00 Stack Condensate Stack Dry Gas Stack Oil 1. 11/1/2019 Strip Price Deck with 1st Production Starting 1/1/2020. Dry Gas 1st Production Starting 4/1/2020 (available at www.unitcorp.com/investor/reports/html) NYSE: UNT 17

STACK – Growing into Core Production Growth Area for Unit Petroleum STACK Daily BOE by Type Geology 3,000 • Stacked drilling targets in Osage, Meramec, and Woodford • Red Fork Potential in some areas • Sands consistently present across play 2,500 Land • 12,000 net acres in STACK Core 2,000 • 5,000 net acres in STACK Extension • 85% HBP Oil • 100 - 150 potential operated locations 1,500 with working interest of 40 - 60% NGL • 400 - 800 potential non-operated Gas locations with working interest of ~ 5% 1,000 Operations/Infrastructure/Processing • Participating in ~ 60 non-op wells in 2019 500 • Dry gas delayed until gas margins and takeaway capacity improve 0 2017 2018 Est. 2019 NYSE: UNT 18

Granite Wash – Low Risk Wet Gas Condensate Play with NGL Price Upside Francis 5713 EXL #3H 1 IP30: 9.5 MMcfe/d (78% Gas) Carr 1357 WXL #4H Francis 5859 EXL #5H 2 5 IP30: 10.0 MMcfe/d (84% Gas) IP30: 5.5 Mmcfe/d (63% Gas) Meek #6836H Meek 6814 #2H 3 6 IP30: 5.8 MMcfe/d (76% Gas) IP30: 9.3 Mmcfe/d (82% Gas) Meek 5453 CXL #2H Francis 5859 WXL #4H 4 7 IP30: 4.1 MMcfe/d (73% Gas) IP30: 6.5 Mmcfe/d (64% Gas) Single Well Economics1 – Granite Wash 50% 40% 30% % ROR ROR 20% 10% 0% $45 / $2.50 11/01 Nymex $65 / $3.50 $75 / $4.00 Unit Tecolote Jones FourPoint BP LeNorman Granite Wash G Wells Current Pricing Potential After Midship Pipeline 1. 11/1/2019 Strip Price Deck with 1st Production Starting 4/1/2020 (available at www.unitcorp.com/investor/reports/html) NYSE: UNT 19

Granite Wash – Competitive Advantages Drive Differentiated Value Geology Daily Net MMcfe • 11 stacked Granite Wash sands 60 significantly improves capital efficiency • Sands present across acreage 50 Land • 9,000 net largely contiguous acres allow for extended lateral (XL) drilling 40 • 90% HBP and operated • Average working interest ~ 90% 30 • 100-150 potential XL locations Operations/Infrastructure/Processing 20 • Incremental process improvements continue to decrease drilling days 10 • SWD network lowers disposal costs 80% • Water recycling pits lower frack costs 0 • Electricity across field lowers lifting 2016 2017 2018 Est. 2019 costs • Superior processes the gas improving Gas NGL Oil cash margin NYSE: UNT 20

Wilcox – Conventional Stacked Over-Pressured Intervals Provide Low Cost High Potential Overall Wilcox Drilling Program Results • Drilled 177 operated wells since 2003 (166 vertical, 11 horizontal) • Program ROR > 81% • Operated with working interest ~ 91% • Production: ~ 80 MMcfe/d (36% liquids) Gilly Field – Wet Gas Reservoir 2020 Exploration Hightower • 400 Bcfe stacked pay gas resource Enterprise • Cumulative production ~ 135 Bcfe Bivens • Average EUR of 10-20 Bcfe per well Shoal Creek • Typical well ~ $5 MM cost, ROR > 100% Unit’s Wilcox Competitive Advantages • Premium Gulf Coast pricing for oil and gas • Wet Gas/Condensate provides margin uplift 40 BCFE Wilcox Annual Production • Large 3D seismic database provides consistent 30 BCFE stream of exploratory prospect ideas NGLs • Conventional over-pressured reservoirs 20 BCFE Oil provide high potential at low acreage costs 10 BCFE Gas • Proven stacked play concept yielding 0 BCFE significant return (ROR 81%) 2014 2015 2016 2017 2018 2019 • Low cost play (.85/Mcfe) Projected NYSE: UNT 21

Drilling Segment Overview NYSE: UNT

Rig Fleet Presence in Key Regions 12 • 58 rig fleet • 31% total fleet utilization • 55 rigs pad capable 8 • SCR rigs modified to meet customer requirements • All 14 BOSS rigs operating 23 Current Rigs Operating(1) Area # of Rigs Mid-Continent 2 11 Bakken 6 4 Niobrara 2 Permian 8 Total 18 1. As of March 2, 2020 NYSE: UNT 22

Average Dayrates and Margins (1) Dayrates $20,000 40 • Average dayrates increased 4% quarter-over-quarter during 3Q’19 $15,000 30 Average Core Customers UtilizedRigs Dayrates $10,000 20 Margins Margins and $5,000 10 $0 0 2015 2016 2017 2018 Q3'19 Margins Dayrates Average Rigs Utilized 1. See Reconciliation of Average Daily Operating Margin Before Elimination of Intercompany Rig Profit and Bad Debt Expense in Appendix. NYSE: UNT 23

The BOSS Drilling Rig Optimized for Pad Drilling • Multi-direction walking system • Racking & setback capacity for additional tubulars Faster Between Locations • Quick assembly substructure • 32-34 truck loads More Hydraulic Horsepower • (2) 2,200 horsepower mud pumps All 14 BOSS rigs • 1,500 gpm available currently operating with one pump Environmentally Conscious • Dual-fuel capable engines • Compact location footprint NYSE: UNT 24

SCR Rigs Continue to Make an Important Contribution 40 Average Annual Prices1 Crude Natural Gas 35 2015 $48.78 $2.63 2016 $43.41 $2.55 30 21 2017 $50.91 $3.02 21 2018 $64.81 $3.07 25 2019 $57.03 $2.53 18 20 12 • Currently, 18 drilling rigs 4 15 operating 14 • All BOSS rigs operating 10 11 or under contract 9 10 5 7 • 4 SCR rigs operating 0 Dec. 31, 2015 Dec. 31, 2016 Dec. 31, 2017 Dec. 31, 2018 Mar. 2, 2020 A/C SCR 1. Prices are pre-differentials NYSE: UNT 25

Midstream Segment Overview NYSE: UNT

Midstream Core Operations Key Metrics Northern Oklahoma and Kansas Tulsa . Approx. 1.9 million dedicated acres Bellmon Headquarters . 176 MMcf/d processing capacity • 21 active gathering systems . Approx. 1,2501 miles of gathering Hemphill pipeline Cashion • Panola 12 gas processing plants Texas Panhandle . Approx. 47,000 dedicated acres • Three natural gas treatment . 135 MMcf/d processing capacity plants . 331 miles of gathering pipeline Segno • 323 MMcf/d processing capacity Central & Eastern OK . Approx. 70,000 dedicated acres • Q3’19 average processing . 12 MMcf/d processing capacity volume of 168 MMcf/d . 404 miles of gathering pipeline East Texas Processing facilities • Q3’19 average throughput . 62 miles of gathering pipeline Gathering systems volume of 429 MMcf/d . 120 MMcf/d gathering capacity . Q3’19 average gathered volume • Approx. 2,100 miles of pipeline of 63 MMcf/d Brookfield Pittsburgh MillsSnow Shoe Appalachia . Approx. 71,000 dedicated acres Pittsburgh . 56 miles of gathering pipeline Regional office . Connected 7 new wells in 2019 Bruceton Mills 1. Includes assets acquired per January 7, 2020 SPC Press Release NYSE: UNT 26

Midstream Segment Contract Mix 2010 Contract Mix Based on Volume Q3 2019 25% 49% 51% Fee Based 75% Commodity Based Contract Mix Based on Margin 15% 29% 85% Fee Based 71% Commodity Based Unit vs. 3rd Party Margin Contribution 41% 34% 59% 3rd Party 66% Unit NYSE: UNT 27

Superior Joint Venture Overview SP Investor Holdings, LLC 50% 50% • Retains 50% equity interest • Acquired 50% equity interest • Received $300 million • $300 million consideration • Retains operational control of • Non-managing member Superior NYSE: UNT 28

Superior Joint Venture Key Terms • Unit’s sale of 50% of its interest in Superior Pipeline Company, L.L.C. is governed by the Purchase and Sale Agreement and the Drilling Commitment Agreement • These agreements contain provisions which have implications on any distributions from or a sale of SPC: • Lock-up on any sale of SPC units or in whole until April 1, 2020 • The JV Partners have a right of first offer to match the sales price of another member’s units • A distribution waterfall governs sale proceed distributions among members following sale or dissolution of SPC, including the JV Partners receiving a priority on all distributions until they have received a 7% IRR on their initial $300 million investment before Unit would receive distributions from the sale • Unit has a commitment to spend $150 million towards developing locations which flow into SPC’s Hemphill system by 12/31/2021 • As of 12/31/19 Unit had spent $25mm of the $150mm commitment • If Unit operates 2 rigs during 2021 in the Granite Wash area, the drilling commitment will likely be satisfied • Unit will forego future distributions from SPC until the JV Partner receives distributions equal to 58% of any amount that has not been spent under the drilling agreement by 12/31/2021 NYSE: UNT 29

Financial Summary NYSE: UNT

Unit’s Operational & Financial Policy UPC  History of managing production growth through volatile commodity price environments  Increasing oil and liquids cuts through opportunistic development of the asset base  Focused on driving free cash flow generation UDC  Significant amounts of free cash flow generation from the drilling business  100% utilization of the high-quality BOSS rigs  Minimal capex required to upgrade non-BOSS fleet to meet higher spec preferences SPC  ~75% of volumes committed to fee-based contracts, mitigating commodity price risk  Diversified set of upstream operators with UPC contributing <35% of volumes on the system  Track record of accretive bolt-on acquisitions NYSE: UNT 30

Operating Segment Capital Expenditures ($ in millions) 2019E Activity Oil and Natural Gas $500 • Focused on the high margin Western Oklahoma area • Increasing liquids cut and $400 generate cash flow Contract Drilling $300 • Added a 14th Boss Rig to the fleet • 100% Boss Rig utilization $200 Midstream $100 • Opportunistic acquisitions and pursuit of additional fee based contracts from high quality $0 operators 2015 2016 2017 2018 2019 Preliminary Oil and Natural Gas Contract Drilling Midstream NYSE: UNT 31

Long-Term Forecast Assumptions UPC • Base Case : Solely focused on highest return wells at UPC with 2020E 2021E 2022E 2023E 2024E no Granite Wash development Western Oklahoma 2.0 2.0 2.0 2.0 2.0 • Alternate Case: Assumes a portion of UPC’s development plan is directed to the Granite Wash Granite Wash -- -- -- -- -- • Assumes intercompany cost eliminations of 2.7% throughout Case Base the projection period Total UPC Rigs 2.0 2.0 2.0 2.0 2.0 • Projections assume the pricing assumptions1 below: Western Oklahoma 2.0 -- 2.0 2.0 2.0 2020E 2021E 2022E 2023E 2024E Granite Wash -- 2.0 -- -- -- Oil ($ / Bbl) $52.50 $52.50 $52.50 $52.50 $52.50 Case Pricing Alternate Gas ($ / Mcf) 2.25 2.30 2.35 2.43 2.50 Assumptions Total UPC Rigs 2.0 2.0 2.0 2.0 2.0 NGL ($ / Bbl) 18.38 18.38 18.38 18.38 18.38 UDC SPC • Assumes an average of 58 available rigs from 2020E-2024E, • SPC EBITDA and capital expenditures shown at 50% of value starting with 14 BOSS rigs reflecting Unit’s ownership • Assumes a 20 average rig utilization in 2020E-2024E • SPC free cash flow is not included in the consolidated free cash flow • Assumes average Daywork Revenue / Rig-day of $19.2m in 2020E and $19.1m in 2021E-2024E • Assumes intercompany revenue eliminations of 26.1% and cost eliminations of 28.8% throughout the projection period • Assumes intercompany revenue eliminations of 6.9% and cost eliminations of 6.6% throughout the projection period 1. The oil and gas industry has experienced significant commodity price volatility. The pricing assumptions used herein are for illustrative purposes only and do not necessarily represent the views of the Company’s management or advisors NYSE: UNT 32

5 Year Consolidated Summary Projections – Base Case ($ in millions) Production (No Granite Wash Drilling; Boed) EBITDA $199 $190 $194 $200 % Liquids 50.1% 53.7% 53.9% 54.4% 54.9% $175 $34 $34 $34 $34 $34 $23 $18 $20 $23 $22 38,682 38,406 37,171 36,463 36,231 $172 $174 $149 $168 $169 ($30) ($30) ($30) ($30) ($30) 2020E 2021E 2022E 2023E 2024E 2020E 2021E 2022E 2023E 2024E Capital Expenditures Unlevered Free Cash Flow1 $100 Cumulative 5 Year $400 Cash Flow: $228mm $153 $153 $151 $58 $143 $143 $75 $49 $52 $300 $16 $16 $16 $45 $18 $16 $16 $18 $11 $11 $9 $18 $18 $9 $9 $50 $24 $200 $18 $55 $25 $46 $49 $43 $100 $126 $126 $118 $127 $118 $23 $-- $-- ($17) ($16) ($16) ($16) ($16) ($25) ($100) 2020E 2021E 2022E 2023E 2024E 2020E 2021E 2022E 2023E 2024E UPC SPC UDC Corporate SG&A Cumulative FCF Note: Reflects pricing assumptions and figures net of eliminations 1. Does not include SPC cash flow 33

5 Year Consolidated Summary Projections – Alternate Case ($ in millions) Production (Granite Wash Drilling; Boed) EBITDA $200 $192 $181 $192 % Liquids 50.1% 51.5% 46.7% 50.6% 52.2% $175 $34 $34 $34 $34 $34 $30 $25 $26 $22 $26 38,682 39,664 42,212 39,195 38,075 $149 $158 $150 $163 $170 ($30) ($30) ($30) ($30) ($30) 2020E 2021E 2022E 2023E 2024E 2020E 2021E 2022E 2023E 2024E Capital Expenditures Unlevered Free Cash Flow1 $75 Cumulative 5 Year $300 $209 $48 $48 $16 Cash Flow: $123mm $11 $50 $18 $18 $200 $25 $23 $152 $154 $149 $143 $18 $16 $16 $18 $9 $16 $16 $25 $45 $45 $100 $11 $9 $9 $24 $18 $21 $182 $-- $-- ($17) ($24) ($16) ($16) ($16) $125 $130 $118 $125 ($25) ($100) ($16) ($50) ($21) ($200) 2020E 2021E 2022E 2023E 2024E 2020E 2021E 2022E 2023E 2024E UPC SPC UDC Corporate SG&A Cumulative FCF Note: Reflects pricing assumptions and figures net of eliminations 1. Does not include SPC cash flow 34

Appendix NYSE: UNT

Corporate Structure Overview Unit Corporation Superior SPC Midstream Unit Drilling Unit Petroleum 8200 Unit Pipeline SP Investor Operating, Company Company Drive, L.L.C. Company, Holdings, LLC L.L.C. L.L.C.1 Unit Drilling Superior Superior USA Colombia, Pipeline Texas, Appalachian L.L.C. L.L.C. Pipeline, L.L.C. Preston Unit Drilling County Gas Colombia, Gathering, L.L.C. L.L.C. 1. Superior Pipeline Company L.L.C. is a JV between Unit Corporation (50%) and SP Investor Holdings, LLC (50%) NYSE: UNT 35

Derivative Summary Crude Oil 2019 2020 Q4 Q1 Q2 Q3 Q4 Collars Volume (Bbl) -- -- -- -- -- Weighted Avg Floor -- -- -- -- -- Weighted Avg Ceiling -- -- -- -- -- 3-Way Collars Volume (Bbl) 368,000 -- -- -- -- Weighted Avg Floor $61.25 -- -- -- -- Weighted Avg Subfloor 51.25 -- -- -- -- Weighted Avg Ceiling 72.93 -- -- -- -- Swaps Volume (Bbl) 184,000 -- -- -- -- Weighted Avg Swap $59.80 -- -- -- -- Natural Gas 2019 2020 Q4 Q1 Q2 Q3 Q4 Collars Volume (MMBtu) 1,840,000 -- -- -- -- Weighted Avg Floor 2.63 -- -- -- -- Weighted Avg Ceiling 3.03 -- -- -- -- 3-Way Collars Volume (MMBtu) -- 2,730,000 2,730,000 2,760,000 2,760,000 Weighted Avg Floor -- $2.50 $2.50 $2.50 $2.50 Weighted Avg Subfloor -- 2.20 2.20 2.20 2.20 Weighted Avg Ceiling -- 2.80 2.80 2.80 2.80 Swaps Volume (MMBtu) 4,300,000 -- -- -- -- Weighted Avg Swap $2.90 -- -- -- -- Basis Swaps Volume (MMBtu) 5,520,000 4,550,000 4,550,000 4,600,000 4,600,000 Weighted Avg Swap ($0.46) ($0.35) ($0.35) ($0.35) ($0.35) NYSE: UNT 36

Unit 2019 Preliminary Consolidated Financials ($ in millions) 2019E Low 2019E High Production (MBoed) 45.5 - 46.5 Consolidated Revenue $670 - $680 Consolidated Adjusted EBITDA $283 - $288 Consolidated Net Capex1 $340 - $345 1. Includes proceeds from divestures NYSE: UNT 37

Non-GAAP Financial Measures - Segments Reconciliation of Margin by Segment Nine Months Ended Year Ended December 31, September 30, (In thousands) 2015 2016 2017 2018 2019 Oil and natural gas $ 219,728 $ 174,037 $ 226,955 $ 291,384 $ 137,635 Contract drilling 109,260 33,932 52,120 65,107 42,283 Gas gathering and processing 41,233 48,261 51,693 55,894 36,194 Total margin by segment 370,221 256,230 330,768 412,385 216,112 Depreciation, depletion and amortization (352,742) (208,353) (209,257) (243,605) (198,632) Impairments (1,634,628) (161,563) --- (147,884) (234,880) Total operating income (loss) (1,617,149) (113,686) 121,511 20,896 (217,400) General and administrative (34,358) (33,337) (38,087) (38,707) (29,899) Gain (loss) on disposition of assets (7,229) 2,540 327 704 (1,424) Interest, net (31,963) (39,829) (38,334) (33,494) (27,067) Gain (loss) on derivatives 26,345 (22,813) 14,732 (3,184) 5,232 Other 45 307 21 22 (611) (Loss) before income taxes $(1,664,309) $ (206,818) $ 60,170 $ (53,763) $(271,169) The company has included margin by segment because: • It considers margin by segment to be an important supplemental measure of operating performance for presenting trends in its core businesses. • Margin by segment is useful to investors because it provides a means to evaluate the ongoing operating performance of the segments and company using criteria used by management. NYSE: UNT 38

Non-GAAP Financial Measures - Segments Segment Adjusted EBITDA (with G&A allocated) ($ In millions) Nine months ended Sept. 30, Years ended December 31, Unit Petroleum 2018 2019 2015 2016 2017 2018 Income (Loss) Before Income Taxes (1) $ 82 $ (157) $(1,622) $ (138) $ 126 $ 139 Depreciation, Depletion and Amortization 98 118 252 114 102 134 Impairment of Oil & Natural Gas Properties --- 170 1,599 162 --- --- Other Adjustments (2) 13 12 34 42 (5) (13) Adjusted EBITDA $ 193 $ 143 $ 263 $ 180 $ 223 $ 260 Unit Drilling Income (Loss) Before Income Taxes (1) $ (1) $ (68) $ 31 $ (20) $ (15) $ (151) Depreciation and Impairment 42 39 64 47 56 58 Impairment of drilling equipment --- 63 --- --- --- 148 Other Adjustments (2) 3 2 10 (1) 3 4 Adjusted EBITDA $ 44 $ 36 $ 105 $ 26 $ 44 $ 59 Superior Pipeline Income (Loss) Before Income Taxes (1) $ 8 $ (3) $ (33) $ (4) $ 1 $ 8 Depreciation, Amortization and Impairment 33 38 71 46 44 45 Other Adjustments (2) (1) 1 1 2 2 (1) Adjusted EBITDA $ 40 $ 36 $ 39 $ 44 $ 47 $ 52 (1) After intercompany eliminations. (2) Adjustments per non-GAAP financial measures – corporate schedule (previous slide). Note: Corporate G&A is allocated to the segments based on a weighted average percentage of total segment identifiable assets plus budget segment cap-x, segment depreciation, segment revenues and direct segment G&A minus budgeted divestitures. Superior Pipeline was excluded from the allocation starting in April 2018 since they are directly billed for Corporate G&A per the JV contract and the billed amount is reduced from the Corporate G&A amount allocated to the drilling and oil and gas segments. NYSE: UNT 39