#1UNIT R UNIT CORPORATION Investor Presentation March 2024#2Forward 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 Unit Corporation (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 and other risks disclosed under "Risk Factors" in the Company's most recent Annual Report and Quarterly Reports filed thereafter. 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 may contain financial measures that have not been prepared in accordance with U.S. Generally Accepted Accounting Principles ("non-GAAP financial measures") including PV-10 reserve values and certain operating measures such as Adjusted EBITDA. 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 appendices. UNIT CORPORATION 2#3• . Investment Highlights Established track record of returning value to shareholders . . $37.50 per share of dividends paid in 2023 2.47 million shares repurchased since 2020 bankruptcy emergence 2024 Quarterly Dividends of $1.25 per share Strong balance sheet as of December 31, 2023 • $61 million of net cash & cash equivalents No long-term debt Reserves as of December 31, 2023¹ • $237 million based on the SEC standardized measure PDP PV-10: • $249 million based on SEC pricing $248 million based on forward strip pricing All 14 BOSS rigs contracted and operating in the Permian Basin Substantial remaining tax shield of $244 million of NOL's as of December 31, 2023 Final payment of $8 million from sale of Superior to be received in April 2024 1 See Appendix 2 for reconciliation of reserve values to standardized measure UNIT CORPORATION 3#42023 Consolidated Financial Highlights 1Q231 2Q23 3Q23 4Q23 FY2023 (in thousands, except per share amounts) Revenues: Oil and natural gas $ 48,026 $ 31,176 $ 35,205 $ 31,830 $ 146,237 Contract drilling $ 45,903 $ 47,405 $ 44,951 $ 42,797 $ 181,056 Gas gathering and processing $ $ $ $ $ Total revenues $ 93,929 $ 78,581 $ 80,156 $ 74,627 $ 327,293 Net income attributable to Unit Corporation $ 134,650 $ 28,017 $ 28,835 $ 57,437 $ 248,939 Basic earnings per share $ 13.93 $ 2.90 $ 2.98 $ 5.89 $ 25.68 Diluted earnings per share $ 13.75 $ 2.86 $ 2.94 $ 5.79 $ 25.32 Adjusted EBITDA Capital expenditures 1 $ 51,143 $ 32,782 $ 30,629 $ 25,161 $ 139,715 $ 1,606 $ 3,774 $ 6,195 $ 6,484 $ 18,059 1 See Appendix 1 for a description of Adjusted EBITDA and reconciliation to net income attributable to Unit Corporation UNIT CORPORATION#5Unit Petroleum Company (UPC) Summary • Efficient, low-cost production and modest decline in PDP reserves Substantial position of ~147,500 net acres in the Anadarko Basin Development strategies: . • Converting non-producing reserves to producing reserves Evaluating acquisitions of producing properties in core areas High-grading producing properties by selling interests in non-core areas Legacy bankruptcy hedges now gone, will hedge opportunistically as deemed appropriate going forward Reducing G&A run rate to reflect current smaller footprint and plans UNIT CORPORATION S#6Unit Petroleum Company Operations Footprint E&P Operations Office Location Anadarko Basin UNIT CORPORATION Tulsa Headquarters 9#7Unit Petroleum Company 2023 Operating and Financial Highlights 1Q23 2Q23 3Q23 4Q23 YTD (In thousands unless otherwise specified) Oil and Natural Gas: Revenue, before inter-segment eliminations Operating costs, before inter-segment eliminations $ es es $ 48,026 $ 31,176 $ 35,205 $ 31,830 $ 146,237 17,164 $ 15,224 $ 16,823 $ 16,528 $ 65,739 Average oil price ($/Bbl) $ Average oil price excluding derivatives ($/Bbl) Average NGLS price ($/Boe) Average NGLs price excluding derivatives ($/Boe) $ Average natural gas price ($/Mcf) Average natural gas price excluding derivatives ($/Mcf) ssssss 65.96 $ 57.34 $ 60.33 $ 57.12 $ 60.61 $ 73.94 $ 71.62 $ 80.83 $ 76.98 $ 75.57 $ 21.37 $ 14.77 $ 17.79 $ 18.25 $ 18.02 21.37 $ 14.77 $ 17.79 $ 18.25 $ 18.02 $ 4.04 $ 1.46 $ 1.75 $ 1.72 $ 2.28 $ 3.11 $ 1.32 $ 1.78 $ 2.04 $ 2.07 Oil production (MBbls) 300 250 225 209 984 NGL production (MBbls) 419 428 429 360 1,636 Natural gas production (MMcf) 5,369 5,188 5,185 4,453 20,195 BOE production (MBbls) 1,615 1,543 1,518 1,310 5,986 Capital expenditures, before inter-segment eliminations $ 1,020 $ 2,928 $ 2,073 $ 685 $ 6,706 UNIT CORPORATION#8Unit Petroleum Company Producing Properties ~147,500 net developed acres 20,000 NET PRODUCTION (EXCLUDES SOLD WELLS) in Anadarko Basin • Modest production decline rate 4,623 wells (~788 net wells) • Low water production • Optimize production and operating costs BOEPD 15,000 10,000 5,000 0 Sep Nove Jan Mar May July 2021 Sep ΛΟΝ Mar May July 2022 ΛΟΝ Perform workovers, recompletions or return-to-production to increase production Anticipated workover and maintenance spend of $4 million per year Reduce plugging and abandoning liability • Current salvaged equipment pricing creates an opportunity for more economic plugging and abandoning of wells Anticipate plugging and abandoning spend of $1 million per year • Continued focus on environmental impact and safe operations UNIT CORPORATION Mar May July Sep Nov 2023 8#9Unit Petroleum Company Reserves Update The following table presents the components of the standardized measure of discounted future net cash flows: 2023 (In thousands) Future development costs Future cash inflows Future production costs Future income tax expenses Future net cash flows 10% annual discount for estimated timing of cash flows $ 850,979 $ (434,221) $ (991) $ (11,714) $ 404,053 $ (166,872) Standardized measure of discounted future net cash flows relating to proved oil, NGLs, and natural gas reserves $ 237,181 As of December 31, 2023: • SEC pricing PDP PV-10 value of $249 million¹ $78.22/bbl oil and $2.64/mcf gas based on first-of-month prices • 5,046 MBO; 100 BCF; 9,866 MBNGL net reserve volume Future revenue attributed 45% to oil, 27% to NGL and 28% to gas Strip pricing PDP PV-10 value of $248 million¹ • • • $67.75/bbl oil and $3.36/mcf gas based on strip pricing as of 1/2/2024 4,904 MBO; 107 BCF; 10,050 MBNGL net reserve volume using strip pricing Future revenue attributed 36% to oil, 23% to NGL and 41% to gas 1 See Appendix 2 for a reconciliation to the standardized measure UNIT CORPORATION 6#10Unit Petroleum Company Change in PDP Reserves during 2023 The decrease in estimated quantities of proved developed oil, NGLs, and natural gas reserves during 2023 was primarily due to divestitures, changes in prices, and current year production. The table below presents estimated quantities of proved developed oil, NGLs, and natural gas reserves and changes in net quantities of proved developed and undeveloped oil, NGLS and natural gas reserves: 2023 Proved developed and undeveloped reserves: Beginning of year Revision of previous estimates Extensions and discoveries Infill reserves in existing proved fields Purchases of minerals in place Production Sales Net proved developed and undeveloped reserves at December 31, 2023 Oil (MBbls) NGL (Mbbls) Gas (Mcf) Total (MBoe) 7,681 20,132 212,409 63,215 (735) (2,763) (31,052) (8,673) 20 24 1,909 362 60 26 291 135 (984) (1,636) (20,195) (5,986) (996) (5,917) (63,476) (17,493) 5,046 9,866 99,886 31,560 1 Revisions of previous estimates decreased primarily due to changes in the unescalated 12-month average product prices which decreased approximately 16% for oil and 58% for natural gas compared to the December 31, 2022 pricing. UNIT CORPORATION 110#11Unit Petroleum Company Development Potential . • Potential locations in Red Fork, Cherokee Shale, Marchand, Medrano, Meramec, Woodford and Granite Wash • • • • • Drill or farm-out high-graded drilling locations Monetize non-core drilling locations Anticipate drilling or participating in 1 to 2 net wells per year, with development capital expenditures of approximately $10 to $20 million per year consistent with recent historical practice and dependent upon future market conditions Participated in 1.3 net wells during 2023 Participated in 1.3 net wells during 2022 Participated in 4.4 net wells during 2021 UNIT CORPORATION 11#12Unit Petroleum Company Divestitures • Sold interests in 958 wells for $50 million during 2023 . • . Sold wells in Texas panhandle and other non-core assets Sold interests in 727 wells for $57 million during 2022 Sold wells in Gulf Coast area, Oklahoma panhandle, and other non-core assets Plugging & Abandonment liability significantly decreased largely due to divestitures • Will continue to look for opportunities to sell minor interests in outlying areas and concentrate remaining properties in core fields and plays UNIT CORPORATION 12#13· • • Unit Drilling Company (UDC) Summary 100% pure-play, high-spec drilling fleet of 14 BOSS rigs, working for top- tier operators Focused on operating efficiencies with central relocation to core operating region (Texas, New Mexico, and Oklahoma) Well balanced contract tenure between term and pad-to-pad contracts · Estimated contract backlog over 1,300 days • . • Average Q4 2023 operating daily rate for BOSS rigs of $31,245 On-going sales of legacy equipment, with approximately $19 million in proceeds received during 2023 Committed to the health and safety of our people, and environmental stewardship UNIT CORPORATION 13#14Seattle WASHINGTON Unit Drilling Company Operational Footprint MONTANA NORTH DAKOTA BAKKEN POWDER RIVER SOUTH DAKOTA OREGON IDAHO WYOMING NIOBRARA NEVADA UTAH CALIFORNIA Los Angeles San Diegoo oLas Vegas ARIZONA Gulf o UNIT CORPORATION MINNESOTA Ottawa WISCONSIN Toronto MICHIGAN NEW Y Chicago IOWA NEBRASKA ILLINOIS ROCKIES United States COLORADO KANSAS MISSOURI MARCELLUS PENN INDIANA OHIO UITCA MD WEST VIRGINIA KENTUCKY VIRGINIA NORTH CAROLINA SOUTH CAROLINA OKLAHOMA TENNESSEE MID-CON UNIT DRILLING ARKANSAS COMPANY MISSISSIPPI ARKLATEX ALABAMA GEORGIA NEW MEXICO PERMIAN Permian Basin: (14) TEXAS UNIT DRILLING GULF COAST COMPANY LOUISIANA OFFICE/YARD: Houston EAGLEFORD STACKED RIG: UNIT DRILLING COMPANY WORKING RIG: 14#15Contract Drilling: Unit Drilling Company 2023 Operating and Financial Highlights 1Q23 2Q23 3Q23 4Q23 YTD (In thousands except rig and day amounts, and as otherwise specified) Revenue, before inter-segment eliminations $ 45,903 $ Operating costs, before inter-segment eliminations $ 26,872 $ 47,405 $ 26,882 $ 44,951 $ 27,629 $ 42,797 $ 181,056 26,652 $ 108,035 Total drilling rigs available for use at the end of the period Average number of drilling rigs in use 18 14 14 14 14 16.8 15.6 14.1 13.9 15.1 Total revenue days 1,513 1,423 1,295 1,280 5,511 Average dayrate on daywork contracts ($/day) $ 29,592 $ 31,764 $ 32,572 $ 31,245 $ 31,225 Average dayrate on daywork contracts - BOSS Rigs ($/day) $ 30,845 $ 33,140 $ 32,642 $ 31,245 $ 31,690 Average dayrate on daywork contracts - SCR Rigs ($/day) $ ՄՌ 24,056 $ 21,087 $ 20,724 $ $ 22,944 Capital expenditures $ 510 $ 820 $ 4,122 $ 5,797 $ 11,249 UNIT CORPORATION 15#16Unit Drilling Company High Specification Drilling Contractor Optimized for Complex Horizontal Wells on Large Drilling Locations • • Multi-direction walking systems designed for large pads Increased racking & setback capacity designed for extended reach horizontal drilling programs High-Torque 500-Ton Top Drives Remote Controlled and Automated Pipe Handling Equipment Fast Moving Between Drilling Locations • Box-On-Box Self-Stacking Substructure (BOSS) • • Increased clear-working height of substructure 32-34 truck loads More Hydraulic Mud Pump Horsepower • • (2) 2,200 horsepower quintuplex mud pumps Fit for purpose, 7500 psi working pressure Environmentally Conscious • Bi-fuel capable engines Grid and Battery Power Capable UNIT CORPORATION 16#17Returning Value to Shareholders • Total cash dividends of $37.50 per share paid in 2023 Dividend policy: . 2024 quarterly cash dividends of $1.25 per share Subsequent variable or special dividends to be determined based on future operating cash flows, available cash, working capital, and capital expenditure requirements or opportunities, among other factors Repurchased 2,472,392 shares since emergence in September 2020 for $79.3 million at an average cost of $32.09 per share Unit's total shareholder return since March 31, 2021 was 584%, compared to 80% for the XOP and 25% for the S&P 500 over the same time frame (Source: CaplQ) 600% 500% 400% 300% 200% 100% 0% -100% Mar-21 Jun-21 Sep-21 Dec-21 Mar-22 Jun-22 Sep-22 Dec-22 Mar-23 Jun-23 Sep-23 Dec-23 • ХОР UNTC S&P 500 UNIT CORPORATION 17#18Contact UNIT CORPORATION Investor Relations, Unit Corporation https://unitcorp.com/investor-relations [email protected] 918-493-7700 Rene Punch - 918-477-4404 [email protected] 18#19Appendix 1 Reconciliation of Net Income to Adjusted EBITDA 1Q23 2Q23 3Q23 4Q23 FY2023 (in thousands) Net income attributable to Unit Corporation $ 134,650 $ 28,017 $ 28,835 $ 57,437 $ 248,939 Add: (Gain)/loss on derivatives $ (13,595) $ (1,500) $ 3,239 $ (1,119) $ (12,975) Less: Cash payments on derivatives settled $ 2,601 $ (2,848) $ (4,806) $ (5,538) $ (10,591) Add: Depreciation, depletion, and amortization $ 3,891 $ 3,824 $ 4,778 $ 5,231 $ 17,724 Less: Gain on sale of Superior $ $ (17,812) $ $ $ (17,812) Less: Gain on disposition of assets $ (3,753) $ (5,676) $ (4,149) $ (36,372) $ (49,950) Add: Stock-based compensation expense $ 1,408 $ 1,008 $ 1,479 $ 3,652 $ 7,547 Add: ARO accretion expense $ 467 $ 478 $ 478 $ 457 $ 1,880 Add: Interest expense $ 39 $ 41 $ 41 $ 43 $ 164 Add: Income tax expense Add: Reorganization expense $ Adjusted EBITDA $ (74,646) $ 81 $ 51,143 $ 27,180 $ 722 $ 1,234 $ (45,510) 70 $ 12 $ 136 $ 299 32,782 $ 30,629 $ 25,161 $ 139,715 Unit believes Adjusted EBITDA provides information useful in assessing operating and financial performance across periods. Unit computes Adjusted EBITDA as net income attributable to Unit Corporation before non-cash valuation changes for commodity derivatives; depreciation, depletion and amortization; interest expense; income tax expense; reorganization expense; asset impairments, if any; asset disposition gains and losses; non-cash share-based compensation; accretion on asset retirement obligations; and other items not related to normal operations. Adjusted EBITDA as defined by Unit may not be comparable to similarly titled measures used by other companies. UNIT CORPORATION 19#20Appendix 2 Description Amount Standardized Measure 1 $237 million Discounted effect of future income tax expenses $12 million Pre-tax PV-10 value under SEC pricing 2 $249 million ($1) million 3 $248 million Impact of adjusting SEC pricing to forward strip pricing Pre-tax PV-10 value under forward strip pricing 1The standardized measure of discounted future net cash flows relating to proved oil, NGLs, and natural gas reserves (Standardized Measure) is calculated in accordance with US GAAP as the after-tax estimated future cash flows from proved reserves discounted at an annual rate of 10 percent. The benchmark price used for all future reserves was $78.22 per barrel of oil, $23.72 per barrel of NGLS, and $2.64 per Mcf of natural gas, then adjusted for price differentials, based on the 12-month historical average of the beginning-of- month prices in accordance with SEC rules. 2 Pre-tax PV-10 value under SEC pricing is consistent with the Standardized Measure calculation, but excludes the effects of future income taxes. We view pre-tax PV-10 under SEC pricing as a useful measure of the value of our proved reserves relative to the values of proved reserves held by other companies as it excludes future income tax expenses which may vary based on the characteristics of the owner of the reserves rather than on the nature, location, and quality of the reserves themselves. We also believe that securities analysts and rating agencies use pre-tax PV-10 under SEC pricing in a similar manner. 3 Pre-tax PV-10 value under forward strip pricing is consistent with the calculation of pre-tax PV-10 value under SEC pricing, but uses forward strip product pricing instead of average historical pricing as required by SEC rules. We view pre-tax PV-10 value under forward strip pricing as a useful measure of the value of our proved reserves both because it excludes future income tax expenses (as discussed above) and because forward strip pricing provides a more current, forward-looking indicator of value. The pricing used is $67.75/bbl oil and $3.36/mcf gas based on strip pricing as of 1/2/2024. UNIT CORPORATION 20