Annual report
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UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-K ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2025 Commission file number 1-10447 COTERRA ENERGY INC. (Exact name of registrant as specified in its charter) Delaware 04-3072771 (State or other jurisdiction ofincorporation or organization) (I.R.S. EmployerIdentification Number) Three Memorial City Plaza, 840 Gessner Road, Suite 1400, Houston, Texas 77024 (Address of principal executive offices including ZIP code) (281) 589-4600 (Registrant’s telephone number, including area code) Securities registered pursuant to Section 12(b) of the Act: Title of each class Trading Symbol(s) Name of each exchange on which registered Common Stock, par value $0.10 per share CTRA New York Stock Exchange Securities registered pursuant to Section 12(g) of the Act: None Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☒ No ☐ Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒ Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐ Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐ Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. Large acceleratedfiler☒ Accelerated filer☐ Non-accelerated filer☐ Smaller reporting company☐ Emerging growthcompany☐ If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐ Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒ If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐ Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐ Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No ☒ The aggregate market value of Common Stock, par value $0.10 per share (“Common Stock”), held by non-affiliates as of the last business day of registrant’s most recently completed second fiscal quarter (based upon the closing sales price on the New York Stock Exchange on June 30, 2025) was approximately $19.2 billion. As of February 13, 2026, there were 759,272,715 shares of Common Stock outstanding. DOCUMENTS INCORPORATED BY REFERENCE Portions of the Proxy Statement for the 2026 Annual Meeting of Stockholders are incorporated by reference into Part III of this report. Such Proxy Statement or an amendment to this Annual Report on Form 10-K will be filed no later than 120 days after December 31, 2025.
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Table of Contents TABLE OF CONTENTS PAGE PART I ITEMS 1 and 2 Business and Properties 6 ITEM 1A Risk Factors 21 ITEM 1B Unresolved Staff Comments 34 ITEM 1C Cybersecurity 34 ITEM 3 Legal Proceedings 36 ITEM 4 Mine Safety Disclosures 36 Information About Our Executive Officers 36 PART II ITEM 5 Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of EquitySecurities 38 ITEM 6 [Reserved] 38 ITEM 7 Management's Discussion and Analysis of Financial Condition and Results of Operations 38 ITEM 7A Quantitative and Qualitative Disclosures about Market Risk 52 ITEM 8 Financial Statements and Supplementary Data 56 ITEM 9 Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 105 ITEM 9A Controls and Procedures 105 ITEM 9B Other Information 105 ITEM 9C Disclosure Regarding Foreign Jurisdictions that Prevent Inspections 105 PART III ITEM 10 Directors, Executive Officers and Corporate Governance 106 ITEM 11 Executive Compensation 106 ITEM 12 Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 106 ITEM 13 Certain Relationships and Related Transactions, and Director Independence 106 ITEM 14 Principal Accounting Fees and Services 106 PART IV ITEM 15 Exhibits and Financial Statement Schedules 107 ITEM 16 Form 10-K Summary 112 SIGNATURES Signatures 113 2
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Table of Contents FORWARD-LOOKING INFORMATION This report includes forward-looking statements within the meaning of federal securities laws. All statements, other than statements of historical fact, included in this report are forward-looking statements. Such forward-looking statements include, but are not limited to, statements regarding future financial and operating performance and results, strategic pursuits and goals, market prices, future hedging and risk management activities, timing and amount of capital expenditures, the anticipated benefits of the Merger (as defined below) involving us and Devon Energy Corporation (“Devon”), the anticipated impact of the Merger on the combined business and future financial and operating results, the expected amount and timing of synergies from the Merger, the anticipated timing of the closing of the Merger transaction and other statements that are not historical facts contained in this report. The words “expect,” “project,” “estimate,” “believe,” “anticipate,” “intend,” “budget,” “plan,” “forecast,” “target,” “predict,” “potential,” “possible,” “may,” “should,” “could,” “would,” “will,” “strategy,” “outlook” and similar expressions are also intended to identify forward-looking statements. We can provide no assurance that the forward-looking statements contained in this report will occur as expected, and actual results may differ materially from those included in this report. Forward-looking statements are based on current expectations and assumptions that involve a number of risks and uncertainties that could cause actual results to differ materially from those included in this report. These risks and uncertainties include, without limitation, the availability of cash on hand and other sources of liquidity to fund our capital expenditures, actions by, or disputes among or between, members of OPEC+, market factors, market prices (including geographic basis differentials) of oil and natural gas and the impacts thereof (including downward adjustments to our estimated proved reserves and potential impairment charges), impacts of inflation and tariff policies, labor shortages and economic disruption, geopolitical disruptions such as the war in Ukraine or the conflict in the Middle East or Venezuela, or further escalation thereof, results of future drilling and marketing activities, future production and costs, the ability to obtain the requisite Coterra and Devon stockholder approvals, the risk that an event, change or other circumstances could give rise to the termination of the Merger Agreement (as defined below), the risk that a condition to closing of the Merger (including obtaining required regulatory approvals) may not be satisfied on a timely basis or at all, the length of time necessary to close the Merger, the risk that the businesses will not be integrated as described in the Merger Agreement, the risk that cost savings and any other synergies from the transaction may not be fully realized or may take longer to realize than expected, the risk that disruptions from the Merger will harm our business, including current plans and operations that management’s time and attention will be diverted on Merger-related issues, potential adverse reactions or changes to business relationships resulting from the announcement, pendency or completion of the Merger, potential litigation relating to the Merger that could be instituted against us or our directors or officers, legislative and regulatory initiatives, electronic, cyber or physical security breaches, the impact of public health crises, including pandemics and epidemics and any related company or governmental policies or actions, and other factors detailed herein and in our other SEC filings. Additional important risks, uncertainties and other factors are described in “Risk Factors” in Part I. Item 1A of this report. Forward-looking statements are based on the estimates and opinions of management at the time the statements are made. Except to the extent required by applicable law, we undertake no obligation to update or revise any forward-looking statement, whether as a result of new information, future events or otherwise. You are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date hereof. Investors should note that we announce material financial information in SEC filings, press releases and public conference calls. Based on guidance from the SEC, we may use the Investors section of our website (www.coterra.com) to communicate with investors. It is possible that the financial and other information posted there could be deemed to be material information. The information on our website is not part of, and is not incorporated into, this report. GLOSSARY OF CERTAIN OIL AND GAS TERMS The following are abbreviations and definitions of certain terms commonly used in the oil and gas industry and included within this Annual Report on Form 10-K: Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons. Bcf. One billion cubic feet of natural gas. Boe. Barrels of oil equivalent. Btu. British thermal units, a measure of heating value. DD&A. Depletion, depreciation and amortization. Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive. EHS. Environmental, health and safety. 3
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Table of Contents ESG. Environmental, social and governance. Exploratory well. A well drilled to find and produce oil or gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir, or to extend a known reservoir. Generally, a well that is not a development well, a service well, or a stratigraphic test well. G&A. General and administrative. GAAP. Accounting principles generally accepted in the U.S. GHG. Greenhouse gas. Hydraulic fracturing. A technology involving the injection of fluids, which typically include small amounts of several chemical additives and sand, into a wellbore under high pressure in order to create fractures in the formation that allow oil or natural gas to flow more freely to the wellbore. MBbl. One thousand barrels of oil or other liquid hydrocarbons. MBoe. One thousand barrels of oil equivalent. Mcf. One thousand cubic feet of natural gas. MMBbl. One million barrels of oil or other liquid hydrocarbons. MMBoe. One million barrels of oil equivalent. MMBtu. One million British thermal units. MMcf. One million cubic feet of natural gas. Net Acres or Net Wells. The sum of the fractional working interest owned in gross acres or gross wells expressed in whole numbers and fractions of whole numbers. Net Production. Gross production multiplied by net revenue interest. NGLs. Natural gas liquids. NYMEX. New York Mercantile Exchange. NYSE. New York Stock Exchange. OPEC+. Organization of Petroleum Exporting Countries and other oil exporting nations. Primary term. The initial time period of an oil and gas lease during which the lessee has the option, but not the obligation, to drill an oil or gas well. Proved developed reserves. Reserves that can be expected to be recovered: (1) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (2) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. Proved reserves. Those quantities, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions and operating methods prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based on future conditions. 4
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Table of Contents Proved undeveloped reserves. Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Under no circumstances shall estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty. PUD. Proved undeveloped. SEC. Securities and Exchange Commission. Tcf. One trillion cubic feet of natural gas. Transco Leidy. Transco-Leidy Line Receipts index price as published by S&P Global Platts in their Inside FERC’s Gas Market Report. Transco Zone 6 Non-NY. Transco Zone 6 Non-NY index price as published by S&P Global Platts in their Inside FERC’s Gas Market Report. U.S. United States. Waha. Waha West Texas Natural Gas Index price as quoted in Platt’s Inside FERC. WTI. West Texas Intermediate, a light sweet blend of oil produced from fields in western Texas and is a grade of oil used as a benchmark in oil pricing. WTI Midland. WTI Midland Index price as quoted by Argus Americas Crude. Energy equivalent is determined using the ratio of one barrel of crude oil, condensate or NGL to six Mcf of natural gas. 5
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Table of Contents PART I ITEMS 1 and 2. BUSINESS AND PROPERTIES Coterra Energy Inc. (“Coterra,” the “Company,” “our,” “we” and “us”) is an independent oil and gas company engaged in the development, exploration and production of oil, natural gas and NGLs. Our assets are concentrated in areas with known hydrocarbon resources, which are conducive to multi-well, repeatable development programs. We operate in one segment, oil and natural gas development, exploration and production, in the continental U.S. Our headquarters are located in Houston, Texas. We also maintain regional offices in Midland, Texas, Pittsburgh, Pennsylvania, and Tulsa, Oklahoma, as well as field offices near our operations. On January 17, 2025, we completed the acquisition of certain interests in oil and gas properties located in the Delaware Basin in New Mexico from certain privately owned sellers for total cash consideration of $1.5 billion (the “Avant assets”). On January 27, 2025, we completed the acquisition of all of the issued and outstanding equity ownership interests of a group of privately owned oil and gas exploration and production companies with assets and operations in the Delaware Basin of New Mexico (the “FME Interests”) for total consideration of $2.5 billion, which included $1.7 billion in cash and the issuance of 28,190,682 shares of our common stock valued at $785 million based on the closing price of our common stock on the closing date. As a result of the acquisitions, we added substantial assets and operations in the Permian Basin in New Mexico. STRATEGY Coterra is a premier U.S.-focused exploration and production company. We embrace innovation, technology and data, as we work to create value for our investors and the communities where we operate. We believe the following strategic priorities will help drive value creation and long-term success. Generate Sustainable Returns. Our premier assets across multiple basins provide commodity diversification and defensive positioning through the commodity price cycles that, combined with our disciplined capital investment, give us confidence in our ability to provide returns to our stockholders that we believe to be sustainable. Over the past three years, we have increased our annual dividend $0.08 per share, or 10 percent, on our common stock to $0.88 per share and have returned over $2.2 billion to stockholders through dividends. During 2025, we also repurchased 6 million shares of our common stock for $140 million, at a weighted average share price of $24.92 per share. Disciplined Capital Allocation Across Top-Tier Position. Our asset portfolio offers scale, duration, commodity optionality and resilient investment returns. With operations in the Permian Basin, Marcellus Shale and Anadarko Basin, our asset portfolio is both commodity and geographically diversified, allowing for capital allocation flexibility that may prove opportunistic in navigating commodity price cycles. During 2025 and 2024, we invested 59 percent and 63 percent, respectively, of our cash flow from operations in our capital programs, and in 2026 we expect to invest approximately 50 percent of our cash flow from operations, based on recent strip prices. We are committed to maintaining a disciplined capital investment strategy to maximize capital efficiency and create value for stockholders. Maintain Financial Strength. Maintaining a top-tier balance sheet with significant financial flexibility is imperative in a cyclical industry exposed to commodity price volatility. Our asset base, revenue diversity, low-cost structure and strong balance sheet provide us with the flexibility to thrive across various commodity price environments. At year-end 2025, we had a $114 million cash balance and $2.0 billion of unused commitments under our revolving credit agreement, well positioned to maintain our balance sheet strength. In January 2025, we borrowed $1.0 billion under our term loan to partially fund the closing of the FME and Avant acquisitions, which consisted of a $500 million Tranche A Term Loan and a $500 million Tranche B Term Loan. During 2025, we repaid the full $500 million Tranche A Term Loan and $200 million of the Tranche B Term Loan. In February 2026, we repaid the remaining $300 million of the Tranche B Term Loan. For additional information, refer to “Mergers and Acquisitions” below, “Liquidity and Capital Resources” in Item 7, and Note 2 and Note 4 of the Notes to the Consolidated Financial Statements “Mergers and Acquisitions” and “Long-Term Debt and Credit Agreements”. Focus on Safe, Responsible and Sustainable Operations. The safety of our employees and contractors is the cornerstone of our focus on operational excellence. We empower all employees and contractors to utilize our Stop Work Authority program, which allows them to stop any work at any time if they are uncomfortable, discover a dangerous condition, or suspect any other EHS hazard. We are also focused on making our operations more environmentally sustainable by actively implementing technology across our operations from the design phase to equipment improvements to limit our methane emissions and flaring activity. We focus on practical and sustainable environmental initiatives that promote efficient use of 6
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Table of Contents fresh and produced water, eliminate or mitigate releases, and minimize land surface impact. We are committed to being responsible stewards of our resources and implementing sustainable practices. We have published our 2025 Sustainability Report, which includes more information related to our sustainability practices, on our website at www.coterra.com. The information on our website is not part of, and is not incorporated into, this Annual Report on Form 10-K or any other report we may file with or furnish to the SEC (and is not deemed filed herewith), whether before or after the date of this Annual Report on Form 10-K and irrespective of any general incorporation language therein. 2026 OUTLOOK Our 2026 full year capital program is expected to be in the range of approximately $2.175 billion to $2.325 billion, a decrease of 3 percent (at the mid-point) from $2.318 billion in 2025. Our lower budgeted capital program reflects a return to normalized Permian investment levels after elevated first-half 2025 spending, tied to acquisition-related rig activity, was fully phased out in the back half of the year. We expect to fund our 2026 capital expenditures with our operating cash flow. We turned in line 199.7 net wells in 2025 and expect to turn-in-line 174 to 208 total net wells in 2026 across our three operating regions. Approximately 68 percent of our capital expenditures will be invested in the Permian Basin, 16 percent in the Marcellus Shale, eight percent in the Anadarko Basin and remaining eight percent for gathering systems infrastructure, saltwater disposal and other spend. In the normal course of our business, we will continue to assess the oil and natural gas price macroeconomic environments and may adjust our capital allocation accordingly. MERGERS AND ACQUISITIONS Announced Merger Involving Devon On February 1, 2026, we entered into an Agreement and Plan of Merger (the “Merger Agreement”) with Devon to combine via an all- stock merger transaction (“Merger”). Devon is a leading oil and gas producer in the U.S. with a diversified multi-basin portfolio headlined by a world-class acreage position in the Delaware Basin. Under terms of the Merger Agreement, at closing Coterra stockholders will receive a fixed exchange ratio of 0.70 shares of Devon common stock for each share of Coterra common stock. Upon completion, Devon stockholders will own approximately 54 percent of the combined company and Coterra stockholders will own approximately 46 percent on a fully diluted basis. The respective Boards of Directors of Coterra and Devon unanimously approved the Merger, which is still subject to the approval of the stockholders of each of Coterra and Devon and the receipt of regulatory approvals, among other conditions. The Merger Agreement contains customary pre-closing covenants, including the obligations of each of Coterra and Devon to conduct their respective businesses in the ordinary course consistent with past practice and to refrain from taking certain specified actions without the consent of the other party. Until the approval by stockholders and subsequent closing, we must continue to operate as a stand-alone company. The Merger is expected to close in the second quarter of 2026, subject to stockholder approvals and other customary closing conditions. Franklin Mountain Energy (“FME”) Acquisition In January 2025, we closed on our acquisition of all of the issued and outstanding equity ownership interests of a group of privately owned oil and gas exploration and production companies with assets and operations in the Delaware Basin of New Mexico (the “FME Interests”) for total consideration of $2.5 billion, which included $1.7 billion of cash and the issuance of 28,190,682 shares of our common stock. Avant Acquisition In January 2025, we closed on the acquisition of certain interests in oil and gas properties located in the Delaware Basin in New Mexico from certain privately owned sellers for total cash consideration of $1.5 billion. DESCRIPTION OF PROPERTIES Our operations are primarily concentrated in three core operating areas—the Permian Basin in west Texas and southeast New Mexico, the Marcellus Shale in northeast Pennsylvania and the Anadarko Basin in the Mid-Continent region in Oklahoma. Permian Basin Our properties are principally located in the western half of the Permian Basin where we currently hold approximately 345,000 net acres in our core operating area in the Delaware Basin. Our development activities are primarily focused on the Wolfcamp Shale and the Bone Spring formation in Culberson and Reeves Counties in Texas and Lea and Eddy Counties in 7
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Table of Contents New Mexico. Our 2025 net production from the Permian Basin was 357 MBoe per day, representing 46 percent of our total oil equivalent production for the year. Net oil production in 2025 averaged 152 MBbl per day, representing 95 percent of our total company oil production. As of December 31, 2025, we had a total of 1,615.3 producing net wells in the Permian Basin, of which approximately 91 percent are operated by us. During 2025, we invested $1.6 billion of capital and had nine drilling rigs and three completion crews operating in the Permian Basin at year end. In January 2025, we completed the FME and Avant acquisitions. With the completion of these acquisitions, we added approximately 49,000 net acres in the Delaware Basin in Lea County, New Mexico and 290.7 producing net wells to our portfolio. Marcellus Shale Our properties are principally located in Susquehanna County, Pennsylvania, where we currently hold approximately 186,000 net acres in the dry gas window of the Marcellus Shale. Our 2025 net production in the Marcellus Shale was 342 MBoe per day, representing 44 percent of our total oil equivalent production for the year. Net natural gas production in 2025 averaged 2,053 MMcf per day, representing 69 percent of our total natural gas production. As of December 31, 2025, we had a total of 1,122.6 producing net wells in the Marcellus Shale, of which over 99 percent are operated by us. During 2025, we invested $313 million of capital and had one drilling rig and one completion crew operating in the Marcellus Shale at year end. Anadarko Basin Our properties are located in the Mid-Continent region in Oklahoma where we currently hold approximately 208,000 net acres. Our development activities are primarily focused on both the Woodford Shale and the Meramec formations. Our 2025 net production in the Anadarko Basin was 82 MBoe per day, representing 10 percent of our total oil equivalent production for the year. As of December 31, 2025, we had a total of 527.0 producing net wells in the Anadarko Basin, of which approximately 63 percent are operated by us. During 2025, we invested $243 million of capital and had one drilling rig and no completion crews operating in the Anadarko Basin at year end. Other Properties Ancillary to our exploration, development and production operations, we operate a number of natural gas gathering and saltwater gathering and disposal systems. The majority of this infrastructure is located in Texas and directly supports our Permian Basin operations. Our gathering systems enable us to connect new wells quickly and to transport natural gas from the wellhead directly to interstate and intrastate pipelines and natural gas processing facilities and to transport produced water to new wells for re-use in completions activities and to disposal facilities. In addition, we can engage in development drilling without relying on third parties to transport our natural gas or produced water and while incurring only the incremental costs of pipeline and compressor additions to our system. During 2025, we invested $137 million in our gathering systems infrastructure, saltwater disposal and other items not directly related to drilling and completion activities. MARKETING Substantially all of our oil and natural gas production is sold under both long-term and short-term sales contracts at market-sensitive prices. We sell oil, natural gas and NGLs to a broad portfolio of domestic and international customers, including industrial customers, local distribution companies, oil and gas marketers, major energy companies, pipeline companies and power generation facilities. We also incur gathering and transportation expenses when we move our oil and natural gas production from wellhead markets to other downstream markets. To date, we have not experienced significant difficulty in transporting or marketing our production as it becomes available; however, there is no assurance that we will always be able to transport and market all of our production. 8
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Table of Contents Delivery Commitments We have entered into various firm sales contracts to deliver and sell natural gas. We believe we will have sufficient production quantities to meet our commitments, but we may be required to purchase natural gas from third parties to satisfy shortfalls, should they occur. A summary of our firm sales commitments as of December 31, 2025 are set forth in the table below: Year Ending December 31, Natural Gas (in Bcf) 2026 644 2027 605 2028 599 2029 525 2030 457 We utilize part of our firm transportation capacity to deliver natural gas under the majority of these firm sales contracts and have entered into numerous agreements for transportation of our production. Some of these contracts have volumetric requirements that could result in monetary shortfall penalties if our production is inadequate to meet such requirements. However, we do not anticipate incurring any penalties based on our current proved reserves and production levels from which we can fulfill these obligations. RISK MANAGEMENT We use derivative financial instruments to manage price risk associated with our production. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Quantitative and Qualitative Disclosures about Market Risk” and Note 5 of the Notes to the Consolidated Financial Statements, “Derivative Instruments” for further discussion related to our use of derivatives. PROVED OIL AND GAS RESERVES The following table presents our estimated proved reserves by commodity as of the dates indicated: December 31, 2025 2024 2023 Oil (MBbl) Proved developed reserves 283,671 189,275 173,392 Proved undeveloped reserves 101,812 80,720 75,821 385,483 269,995 249,213 Natural Gas (Bcf) Proved developed reserves 9,051 8,420 8,590 Proved undeveloped reserves 1,460 1,414 1,935 10,511 9,834 10,525 NGL (MBbl) Proved developed reserves 335,012 271,030 234,306 Proved undeveloped reserves 93,016 90,747 83,150 428,028 361,777 317,456 Oil equivalent (MBoe) 2,565,282 2,270,721 2,320,757 At December 31, 2025, our interests in the Dimock field, which is primarily located in Susquehanna County, Pennsylvania in the Marcellus Shale account for approximately 49 percent of our total proved reserves, on a volumetric basis. There are no other fields which represent 15 percent or more of our total proved reserves. For additional information regarding estimates of our net proved and proved undeveloped reserves, the qualifications of the preparers of our reserves estimates, the evaluation of such estimates by our independent petroleum consultants, our 9
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Table of Contents processes and controls with respect to our reserves estimates and other information about our reserves, including the risks inherent in our estimates of proved reserves, refer to the Supplemental Oil and Gas Information included in Item 8 and “Risk Factors—Business and Operational Risks—Our proved reserves are estimates. Any material inaccuracies in our reserves estimates or underlying assumptions could cause the quantities and net present value of our reserves to be overstated or understated” in Item 1A. PRODUCTION, SALES PRICE AND PRODUCTION COSTS The following table presents historical information about our total and average daily production volumes for oil, natural gas and NGLs; average oil, natural gas and NGL sales prices; and average production costs per oil equivalent: Year Ended December 31, 2025 2024 2023 Production Volumes Oil (MBbl) 58,370 39,808 35,110 Natural gas (Bcf) 1,086 1,025 1,053 NGL (MBbl) 46,247 36,993 32,932 Oil equivalent (MBoe) 285,576 247,589 243,497 Average Daily Production Volumes Oil (MBbl) 160 109 96 Natural gas (MMcf) 2,975 2,800 2,884 NGL (MBbl) 127 101 90 Oil equivalent (MBoe) 782 677 667 Average Sales Price Excluding Derivative Settlements Oil ($/Bbl) $ 63.36 $ 74.18 $ 75.97 Natural gas ($/Mcf) $ 2.43 $ 1.65 $ 2.18 NGL ($/Bbl) $ 18.24 $ 19.95 $ 19.56 Including Derivative Settlements Oil ($/Bbl) $ 64.35 $ 74.22 $ 76.07 Natural gas ($/Mcf) $ 2.47 $ 1.75 $ 2.44 NGL ($/Bbl) $ 18.24 $ 19.95 $ 19.56 Average Production Costs ($/Boe) $ 3.28 $ 2.39 $ 2.01 10
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Table of Contents The following table presents historical information about our total and average daily natural gas production volumes associated with our interests in the Dimock field. There was no oil or NGL production associated with our interests in the Dimock field. Year Ended December 31, 2025 2024 2023 Production Volumes Natural gas (Bcf) 749 768 826 Oil equivalent (MBoe) 124,914 128,008 137,647 Average Daily Production Volumes Natural gas (MMcf) 2,053 2,098 2,263 Oil equivalent (MBoe) 342 350 377 ACREAGE Our interest in both developed and undeveloped properties is primarily in the form of leasehold interests held under oil and gas mineral leases. These leases provide us the right to develop oil and natural gas on the properties. Their primary terms generally range in length from approximately three to 10 years, and, once a successful well is drilled, they typically then continue for the economic life of the well holding such lease. The following table summarizes our gross and net developed and undeveloped leasehold acreage at December 31, 2025: Acreage Developed Undeveloped Total Gross Net Gross Net Gross Net Core Acreage Permian Basin New Mexico 196,553 129,647 75,359 56,053 271,912 185,700 Texas 204,970 136,719 30,469 22,599 235,439 159,318 401,523 266,366 105,828 78,652 507,351 345,018 Marcellus Shale Pennsylvania 176,288 175,765 10,850 10,707 187,138 186,472 Anadarko Basin Oklahoma 319,920 146,664 124,150 61,302 444,070 207,966 Noncore Acreage 159,824 69,621 6,123,920 5,914,876 6,283,744 5,984,497 1,057,555 658,416 6,364,748 6,065,537 7,422,303 6,723,953 (1) Includes acreage outside of our three core operating areas. This acreage is located in the states of Arizona, California, Nevada, New Mexico, Pennsylvania, West Virginia, and various other states. As of December 31, 2025, there is no value ascribed to this acreage, and there are no plans to develop this acreage in the near term. (1) 11
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Table of Contents Total Net Undeveloped Acreage Expiration The table below summarizes by year and operating area our undeveloped acreage expirations in the next three years as of December 31, 2025. In most cases, the drilling of a commercial well will hold the acreage beyond the expiration. Acreage 2026 2027 2028 Gross Net Gross Net Gross Net Core Acreage Permian Basin 2,451 1,888 4,125 2,215 1,316 1,237 Marcellus Shale 530 530 4,815 4,815 1,905 1,834 Anadarko Basin 120 41 19,147 6,202 27,665 18,351 Noncore Acreage — — — — — — 3,101 2,459 28,087 13,232 30,886 21,422 Expiring acreage in our core operating areas in 2026, 2027 and 2028 represents less than one percent of our total undeveloped acreage. At December 31, 2025, we had no PUD reserves recorded on undeveloped acreage that were scheduled for development beyond the expiration dates of the undeveloped acreage or outside of our core operating area. WELL SUMMARY The following table presents our ownership in productive oil and natural gas wells at December 31, 2025. This summary includes oil and natural gas wells in which we have a working interest: Gross Net Natural Gas 3,502 1,892.9 Oil 3,649 1,373.6 Total 7,151 3,266.5 _______________________________________________________________________________ (1) Total percentage of gross and net operated wells is 51 percent and 89 percent, respectively. DRILLING ACTIVITY The table below presents wells that we drilled and completed or in which we participated in the drilling and completion. This information should not be considered indicative of future performance, nor should a correlation be assumed as a result of the number of productive wells drilled, the quantities of reserves found or the economic value. Year Ended December 31, 2025 2024 2023 Gross Net Gross Net Gross Net Development Wells Productive 399 198.3 290 143.8 288 183.3 Dry — — — — — — Exploratory Wells Productive — — — — — — Dry — — 1 0.5 — — Total 399 198.3 291 144.3 288 183.3 Acquired Wells 612 294.4 — — — — During the year ended December 31, 2025, we completed 90 gross wells (57.6 net) that were drilled in prior years. (1) 12
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Table of Contents The following table sets forth information about wells for which drilling was in progress or which were drilled but uncompleted at December 31, 2025, which are not included in the above table: Drilling In Progress Drilled But Uncompleted Gross Net Gross Net Development wells 45 31.0 107 85.3 Exploratory wells — — 1 1.0 Total 45 31.0 108 86.3 OTHER BUSINESS MATTERS Title to Properties We believe that we have satisfactory title to all of our producing properties and leases in accordance with generally accepted industry standards. Individual properties may be subject to burdens such as royalty, overriding royalty, carried, net profits, working and other outstanding interests customary in the industry. In addition, interests may be subject to obligations or duties under applicable laws or burdens such as production payments, ordinary course liens incidental to operating agreements and for current taxes or development obligations under oil and gas leases. As is customary in the industry in the case of undeveloped properties, we conduct preliminary investigations of record title at the time of lease acquisition. We conduct more complete investigations prior to the consummation of an acquisition of producing properties and before commencement of drilling operations on undeveloped properties. Competition The oil and gas industry is highly competitive, and we experience strong competition in the areas in which we operate. We primarily compete with integrated, independent and other energy companies for the sale and transportation of our oil and natural gas production to pipelines, marketing companies and end users. Many of these competitors have greater financial, technical and personnel resources and exploration and development budgets than we have. The effect of these competitive factors cannot be predicted. Price, contract terms, availability of rigs and completion crews and related equipment and quality of service, including pipeline connection times, distribution efficiencies and reliable delivery record affect competition. For example, constrained pipeline capacity and oversupply in certain geographic areas in 2024, 2025, and early 2026 resulted in negative spot market pricing at times for natural gas, such as in the Permian Basin at the Waha Hub. We believe that our concentrated acreage positions and our access to both third-party and Company- owned gathering and pipeline infrastructure in our core operating areas, along with our expected activity level and the related services and equipment that we have secured for the upcoming years, enhance our competitive position. Major Customers During the year ended December 31, 2025, two customers accounted for approximately 22 percent and 14 percent of our total sales. During the year ended December 31, 2024, two customers accounted for approximately 21 percent and 19 percent of our total sales. If any one of our major customers were to stop purchasing our production, we believe there are other purchasers to whom we could sell our production. If multiple significant customers were to stop purchasing our production, we expect to have sufficient alternative markets to handle any sales disruptions despite any initial disruptions that may occur. We regularly monitor the creditworthiness of our customers and may require parent company guarantees, letters of credit or prepayments when necessary. Historically, losses associated with uncollectible receivables have not been significant. Regulation of Oil and Natural Gas Exploration and Production Exploration and production operations are subject to various types of regulation at the federal, state and local levels. These regulations include requiring permits to drill wells, maintaining bonding requirements to drill or operate wells, regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties on which wells are drilled and the plugging and abandoning of wells. Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, the density of wells that may be drilled and the unitization or pooling of oil and gas properties. Some states allow the forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In addition, state conservation laws establish 13
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Table of Contents maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability of production. The laws and regulations limit the amounts of oil and natural gas we can produce from our wells as well as the number of wells, and the locations where, we can drill. Because these laws and regulations are often amended, expanded and reinterpreted, we are unable to predict the future cost or impact of regulatory compliance. The regulatory burden on the oil and gas industry often increases the cost of doing business and, consequently, affects our profitability. These laws and regulations, however, do not affect us differently than others in the industry. Regulation of Natural Gas Marketing, Gathering and Transportation Federal legislation and regulatory controls have historically affected the price of the natural gas we produce and the manner in which our production is transported and marketed. Under the U.S. Natural Gas Act of 1938 (the “NGA”), the U.S. Natural Gas Policy Act of 1978 (the “NGPA”) and the regulations promulgated under those statutes, the U.S. Federal Energy Regulatory Commission (the “FERC”) regulates the interstate sale for resale of natural gas and the transportation of natural gas in interstate commerce, although facilities used in the production or gathering of natural gas in interstate commerce are generally exempted from FERC jurisdiction. However, natural gas prices for all “first sales” of natural gas, which definition covers all sales of our own production, are not subject to price regulation. In addition, the FERC granted to all producers such as us a “blanket certificate of public convenience and necessity” authorizing the sale of natural gas for resale without further FERC approvals. As a result of this policy, all of our produced natural gas is sold at market prices, subject to the terms of any private contracts that may be in effect. Under the provisions of the Energy Policy Act of 2005 (“2005 Act”), the NGA was amended to prohibit any forms of market manipulation in connection with the purchase or sale of natural gas. Pursuant to the 2005 Act, the FERC established regulations intended to increase natural gas pricing transparency by, among other things, requiring market participants to report their gas sales transactions annually to the FERC. The 2005 Act also significantly increased the penalties for violations of the NGA and NGPA and the FERC’s regulations. The current maximum penalty is approximately $1.6 million per day per violation. Under the NGPA, natural gas gathering facilities are expressly exempt from FERC jurisdiction. What constitutes “gathering” under the NGPA has evolved through FERC decisions and judicial review of such decisions. We believe that our gathering and production facilities meet the test for non-jurisdictional “gathering” systems under the NGPA and that our facilities are not subject to federal regulations. Although exempt from FERC oversight, our natural gas gathering systems and services may receive regulatory scrutiny by state and federal agencies regarding the safety and operating aspects of the transportation and storage activities of these facilities. Our natural gas sales prices continue to be affected by intrastate and interstate gas transportation regulation because the cost of transporting the natural gas once sold to the consuming market is a factor in the prices we receive. The rates and terms for access to natural gas pipeline transportation services are subject to extensive regulation. The FERC’s regulations require, among other things, that interstate natural gas pipelines provide firm and interruptible transportation service on an unbundled, open access, and non-discriminatory basis, provide internet access to current information about available pipeline capacity and other relevant information, and permit pipeline shippers under certain circumstances to release contracted transportation and storage capacity to other shippers, thereby creating secondary markets for such services. The rates for such transportation and storage services are subject to the FERC’s ratemaking authority, and the FERC exercises its authority by applying cost-of-service principles to limit the maximum and minimum levels of tariff-based recourse rates. However, it also allows for the negotiated rates as an alternative to cost-based rates and may grant market-based rates in certain circumstances, typically with respect to storage services. The FERC regulations also restrict interstate natural gas pipelines from sharing transportation or customer information with marketing affiliates and require that the transmission function personnel of interstate natural gas pipelines operate independently of the marketing function personnel of the pipeline or its affiliates. We cannot predict what new or different regulations the FERC and other regulatory agencies may adopt, or what effect subsequent regulations may have on our activities. Similarly, we cannot predict what proposals, if any, that affect the oil and natural gas industry might actually be enacted by the U.S. Congress or the various state legislatures and what effect, if any, such proposals might have on us. Further, we cannot predict whether the recent trend toward federal deregulation of the natural gas industry will continue or what effect future policies will have on our sale of gas. Federal Regulation of Swap Transactions We use derivative financial instruments such as collar, swap and basis swap agreements to attempt to manage price risk due to the impact of changes in commodity prices on our operating results and cash flows. The Commodity Exchange Act provides the U.S. Commodity Futures Trading Commission (the “CFTC”) with jurisdiction to regulate the over-the-counter (“OTC”) derivatives market (which includes the sorts of financial instruments we use) and participants in that market. We endeavor to ensure that our OTC derivatives transactions comply with applicable CFTC regulations. We believe that our use of swaps to hedge against changes in commodity prices qualifies us as a commercial end ‑ user, which would exempt us from a future requirements to centrally clear our commodity swaps. Any future changes in CFTC regulations could increase the cost of 14
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Table of Contents entering into derivative contracts, limit the availability of derivatives to protect against risks that we encounter, reduce our ability to monetize or restructure our existing derivative contracts and increase our exposure to less creditworthy counterparties. If we reduce our use of swaps, our results of operations may become more volatile and our cash flows may be less predictable. Federal Regulation of Petroleum Sales of crude oil and NGLs are not regulated and are made at market prices. However, the price received from the sale of these products is affected by the cost of transporting the products to market. Much of that transportation is through interstate common carrier pipelines, which are regulated by the FERC under the Interstate Commerce Act (“ICA”). The FERC requires that pipelines regulated under the ICA file tariffs setting forth the rates and terms and conditions of service and that such service not be unduly discriminatory or preferential. The FERC’s regulations provide for an indexing system for ICA-regulated rates by which the carrier makes annual adjustments based on the rate of inflation, subject to maximum ceiling and other conditions and limitations. These adjustments may increase or decrease the cost of transporting crude oil and NGLs by interstate pipeline. In 2020, the FERC established the new adder for calculating the ceiling for crude oil and liquids pipeline rates subject to indexing, establishing an index level of Producer Price Index for Finished Goods plus 0.78 percent for the five-year period commencing July 1, 2021. On rehearing, the FERC subsequently reduced the adder to minus 0.21 percent, but this action was vacated on appeal to the U.S. Court of Appeals for the D.C. Circuit in 2024. In response to the court’s ruling, the FERC reinstated the plus 0.78 percent adder but issued a supplemental notice of proposed rulemaking proposing to re-adopt the minus 0.21 percent adder for the remainder of the five-year period. This proposal is pending before the FERC. Cost-of-service based rates, market-based rates and settlement rates are alternatives to the indexing system and may be used in certain specified circumstances to change rates. Rates and terms and conditions of service are subject to challenge by protest or complaint and also may be investigated by the FERC on its own motion. We are unable to predict with certainty the effect upon us of these periodic reviews by the FERC of the pipeline index or any potential future challenges to pipelines’ rates. Environmental and Safety Regulations General. Our operations are subject to extensive and stringent federal, state and local laws and regulations governing the protection of the environment. These laws and regulations can change, restrict or otherwise impact our business in many ways, including the handling or disposal of waste material, planning for future activities to avoid or mitigate harm to threatened or endangered species, and requiring the installation and operation of emissions or pollution control equipment. Existing environmental laws and regulations could be revised or reinterpreted, which introduces further uncertainty as to our compliance obligations. Failure to comply with these laws and regulations could result in the assessment of administrative, civil and criminal penalties, the imposition of remedial requirements and the issuance of orders enjoining future operations. Permits are required for the operation of our various facilities. These permits can be revoked, modified or renewed by issuing authorities. Governmental authorities enforce compliance with their regulations through fines, injunctions or both. Regulations can increase the cost of planning, designing, installing and operating, and can affect the timing of installing and operating, oil and natural gas facilities. Although we believe that compliance with environmental regulations will not have a material adverse effect on us, risks of substantial costs and liabilities and potential suspension or cessation of operations under certain conditions related to environmental considerations or compliance issues are part of oil and natural gas production operations. We can provide no assurance that we will not incur significant costs and liabilities. Also, it is possible that other developments, such as stricter environmental laws and regulations and claims for damages to property or persons resulting from oil and natural gas production could result in substantial costs and liabilities to us. Solid and Hazardous Waste. We currently own or lease, and have in the past owned or leased, numerous properties that were used for the production of oil and natural gas for many years. Although operating and disposal practices that were standard in the industry at the time may have been utilized, it is possible that hydrocarbons or other wastes may have been disposed of or released on or under the properties currently owned or leased by us. State and federal laws applicable to oil and gas wastes and properties have become stricter over time. Under these increasingly stringent requirements, we could be required to remove or remediate previously disposed wastes (including wastes disposed or released by prior owners and operators), clean up contamination (including groundwater contamination by prior owners or operators) or perform plugging operations to prevent future contamination. We generate some wastes that are hazardous wastes subject to the Resource Conservation and Recovery Act (the “RCRA”) and comparable state statutes, as well as wastes that are exempt from such regulation. The U.S. Environmental Protection Agency (the “EPA”) limits the disposal options for certain hazardous wastes. It is possible that certain wastes currently exempt from regulation as hazardous wastes may in the future be designated as hazardous wastes under RCRA or other applicable statutes. In the future, we could be subject to more rigorous and costly disposal requirements than we encounter today. 15
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Table of Contents Superfund. The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the “Superfund” law, and comparable state laws and regulations impose liability, without regard to fault or the legality of the original conduct, on certain persons with respect to the release of hazardous substances into the environment. These persons include the current and past owners and operators of a site where the release occurred and any party that treated or disposed of or arranged for the treatment or disposal of hazardous substances found at a site. Under CERCLA, such persons may be subject to joint and several strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the EPA, and in some cases, private parties, to undertake actions to clean up such hazardous substances, or to recover the costs of such actions from the responsible parties. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In the course of business, we have used materials and generated wastes and will continue to use materials and generate wastes that may fall within CERCLA’s hazardous substances definition. We may also be an owner or operator of sites on which hazardous substances have been released. As a result, we may be responsible under CERCLA for all or part of the costs to clean up sites where such substances have been released. Oil Pollution Act. The Oil Pollution Act of 1990 (the “OPA”) and implementing regulations impose a variety of obligations on responsible parties related to the prevention of oil spills and liability for damages resulting from such spills in waters of the U.S., the definition of which has expanded and contracted over time with changes in the federal administration and a series of U.S. Supreme Court decisions. The OPA assigns joint and several strict liability to each responsible party for oil removal costs and a variety of public and private damages. The OPA also imposes ongoing requirements on operators, including the preparation of oil spill response plans and proof of financial responsibility to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill. We believe that we are in substantial compliance with the OPA and related federal regulations to the extent applicable to our operations. Endangered Species Act. The Endangered Species Act (the “ESA”) was established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. The U.S. Fish and Wildlife Service (the “FWS”) may designate critical habitat and suitable habitat areas it believes are necessary for survival of a threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to federal land use and may materially delay or prohibit land access for oil and gas development. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act, to bald and golden eagles under the Bald and Golden Eagle Protection Act, and to certain species under state law. We conduct operations in areas where certain species are currently listed as threatened or endangered, or could be listed as such, under the ESA. Operations in areas where threatened or endangered species or their habitat are known to exist may require us to incur increased costs to implement mitigation or protective measures and also may restrict or preclude our drilling activities in those areas or during certain seasons, such as breeding and nesting seasons. We have entered into various voluntary Candidate Conservation Agreements (“CCAs”), whereby we agreed to take certain actions and limit certain activities, such as limiting drilling on certain portions of our acreage during nesting seasons, in an effort to protect certain threatened or endangered species. Participating in CCAs could result in increased costs to us from species protection measures, time delays or limitations on drilling activities, which costs, delays or limitations may be significant. New listing petitions continue to be filed with the FWS which could impact our operations. Many non-governmental organizations (“NGOs”) work closely with the FWS regarding the listing of many species, including species with broad and even nationwide ranges. The increase in endangered species listings may limit our ability to explore for or produce oil and gas in certain areas or cause us to incur additional costs. Clean Water Act. The Federal Water Pollution Control Act (the “Clean Water Act”) and implementing regulations, which are primarily executed through a system of permits, also govern the discharge of certain pollutants into waters of the U.S. Sanctions for failure to comply strictly with the Clean Water Act are generally resolved by payment of fines and correction of any identified deficiencies. However, regulatory agencies could require us to cease construction or operation of certain facilities or to cease hauling wastewater to facilities owned by others that are the source of water discharges to resolve non-compliance. We believe that we substantially comply with the applicable provisions of the Clean Water Act and related federal and state regulations. Clean Air Act. Our operations are subject to the federal Clean Air Act (the “Clean Air Act”) and comparable local and state laws and regulations to control emissions from sources of air pollution. Federal and state laws require new and modified sources of air pollutants to obtain permits prior to commencing construction. Major sources of air pollutants are subject to more 16
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Table of Contents stringent, federally imposed requirements including additional permitting requirements. Federal and state laws designed to control toxic air pollutants and greenhouse gases might require installation of additional controls. Payment of fines and correction of any identified deficiencies generally resolve any failures to comply strictly with air regulations or permits. However, in the event of non-compliance, regulatory agencies could also require us to cease construction or operation of certain facilities or to install additional controls on certain facilities that are air emission sources. We believe that we substantially comply with applicable emission standards and permitting requirements under local, state and federal laws and regulations. Some of our producing wells and associated facilities are subject to restrictive air emission limitations and permitting requirements, which have added costs and caused delays in operations. For additional information, please read “Risk Factors—Legal, Regulatory and Governmental Risks— Federal, state and local laws and regulations, judicial actions and regulatory initiatives related to oil and gas development and the use of hydraulic fracturing could result in increased costs and operating restrictions or delays and adversely affect our business, financial condition, results of operations and cash flows” in Item 1A. If we are unable to comply with air pollution regulations or to obtain permits for emissions associated with our operations, we could be required to forego or implement modifications to certain operations. These regulations may also increase compliance costs for some facilities we own or operate, and result in administrative, civil or criminal penalties for noncompliance. Obtaining permits may delay the development of our oil and natural gas projects, including the construction and operation of facilities. Safe Drinking Water Act. The Safe Drinking Water Act (“SDWA”) and comparable local and state provisions restrict the disposal, treatment or release of water produced or used during oil and natural gas development. Subsurface placement of fluids (including disposal wells or enhanced oil recovery) is governed by federal or state regulatory authorities that, in some cases, includes the state’s oil and gas regulatory authority or the state’s environmental authority. These regulations may increase the costs of compliance for some facilities. Hydraulic Fracturing. Substantially all of our exploration and production operations depend on the use of hydraulic fracturing to enhance production from oil and natural gas wells. Most of our wells would not be economical without the use of hydraulic fracturing to stimulate production from the well. Due to concerns raised relating to potential impacts of hydraulic fracturing on groundwater quality, legislative and regulatory efforts at the U.S. federal, state and local levels have been initiated to render permitting and compliance requirements more stringent for hydraulic fracturing or to restrict or prohibit the activity altogether. States in which we operate also have adopted, or have stated intentions to adopt, laws or regulations that mandate further restrictions on hydraulic fracturing, such as imposing more stringent permitting, disclosure and well-construction requirements on hydraulic fracturing operations and establishing standards for the capture of air emissions released during hydraulic fracturing. In addition to state measures, local land use restrictions, such as city ordinances, may restrict drilling in general or hydraulic fracturing in particular. Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition to oil and natural gas production activities using hydraulic fracturing techniques, which could have an adverse effect on oil and natural gas production activities, including operational delays or increased operating costs in the production of oil and natural gas, or could make it more difficult to perform hydraulic fracturing. At the federal level, the EPA conducted a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, and concluded that hydraulic fracturing activities can impact drinking water resources under some circumstances, including large volume spills and inadequate mechanical integrity of wells. This study and other studies that may be undertaken by the EPA or other federal agencies could spur initiatives to further regulate hydraulic fracturing under the Safe Drinking Water Act, the Toxic Substances Control Act, or other statutory and regulatory mechanisms. A number of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing practices. Our inability to locate sufficient amounts of water, or to dispose of or recycle water used or produced in our exploration and production operations, could adversely impact our operations. For water sourcing, we first seek to use non-potable water supplies, or recycled produced water for our operational needs. In certain areas, there may be insufficient water available for drilling and completion activities. Water must then be obtained from other sources and transported to the drilling site. Our operations in certain areas could be adversely impacted if we are unable to secure sufficient amounts of water or to dispose of or recycle the water used in our operations. The imposition of new environmental and other regulations, as well as produced water disposal well limits or moratoriums in areas of seismicity, could further restrict our ability to conduct operations such as hydraulic fracturing by restricting the disposal of waste such as produced water and drilling fluids. Compliance with environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells may increase our operating costs and cause delays, interruptions or termination of our operations, the extent of which cannot be predicted, all of which could have an adverse effect on our operations and financial condition. Operators, including us, have begun to rely more on recycling of water that flows back from the wellbore following hydraulic fracturing (“flowback water”) and produced water from well sites as a preferred alternative to disposal. 17
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Table of Contents Greenhouse Gas and Climate Change Laws and Regulations. In response to studies suggesting that emissions of carbon dioxide and certain other greenhouse gas (“GHG”), including methane, may be contributing to global climate change, there is increasing focus by local, state, regional, national and international regulatory bodies as well as by investors and the public on GHG emissions and climate change issues. We closely follow developments in this area, including changes in the regulatory landscape in the U.S. at the federal, state, and local levels. We cannot predict, however, how or when such changes may be implemented or ultimately impact our business. U.S. presidents have the power to issue executive orders that can have the effect of the enactment of new laws. The Trump Administration has issued a series of executive orders that signal a shift in the United States’ energy and climate change policies from the prior administration. Future administrations may, however, pursue executive orders similar to, or more restrictive than, current and prior administrations. At the federal level, the EPA has regulated carbon dioxide, methane and other GHGs under existing provisions of the Clean Air Act. In December 2009, the EPA published its findings that emissions of GHGs present an endangerment to public health and the environment because emissions of such gases are contributing to the warming of the earth’s atmosphere and other climatic changes (“Endangerment Finding”). However, in February 2026, the EPA announced the repeal of the Endangerment Finding, which calls into question EPA’s authority to regulate GHGs, as well as EPA’s prior scientific assessment of climate change risks. Litigation regarding the repeal of the Endangerment Finding is anticipated and it is unclear how the repeal will impact EPA’s regulation of GHG emissions on the oil and gas sector going forward. The EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified sources in the U.S., including, among others, certain oil and gas production facilities on an annual basis, which includes certain of our operations. In 2024, the EPA published final rules imposing new, stricter requirements for methane monitoring, reporting, and emissions control at certain oil and natural gas facilities, as well as a final rule implementing a charge on large emitters of waste methane from the oil and gas sector. However, in March 2025, the waste emissions charge rules were repealed and in July 2025, the imposition of the charge was postponed to 2034. In September 2025, the EPA announced a proposal to end the GHG reporting program for all sectors except petroleum and natural gas systems (excluding reporting for natural gas distribution, which would also be eliminated under the proposal) and deferring reporting for petroleum and natural gas systems until 2034. In December 2025, the EPA issued a final rule extending several compliance deadlines and timeframes associated with its 2024 methane rules. If we are unable to recover or pass through a significant portion of our costs related to complying with current and future regulations relating to climate change and GHGs, it could materially affect our operations and financial condition. Any future laws or regulations that limit emissions of GHGs from our equipment and operations could require us to both develop and implement new practices aimed at reducing GHG emissions, such as emissions control technologies, which could increase our operating costs and could adversely affect demand for the oil and gas that we produce. Future implementation or adoption of legislation or regulations adopted at the local, state, and federal levels to address climate change could also make our products more or less desirable than competing sources of energy. At this time, it is not possible to quantify the impact of any such future developments on our business. Occupational Safety and Health Act and Other Laws and Regulations. We are subject to the requirements of the U.S. federal Occupational Safety and Health Act (the “Occupational Safety and Health Act”) and comparable state laws. The Occupational Safety and Health Act hazard communication standard, the EPA community right ‑ to ‑ know regulations under the Title III of CERCLA and similar state laws require that we organize and disclose information about hazardous materials used or produced in our operations. Also, pursuant to the Occupational Safety and Health Act, the Occupational Safety and Health Administration (the “OSHA”) has established a variety of standards related to workplace exposure to hazardous substances and employee health and safety. Human Capital Resources As of December 31, 2025, we had 1,075 Coterra employees, 327 of whom were located in our headquarters in Houston, Texas and 268 of whom were located in our regional offices in Midland, Texas, Tulsa, Oklahoma and Pittsburgh, Pennsylvania. We had a total of 466 employees in production field locations across our regional offices. Of our total employee population, 660 were salaried and 415 were hourly. We believe that our relations with our employees are favorable. None of our employees are represented pursuant to a collective bargaining agreement. Our ability to attract, retain and develop the highest quality employees is a vital component of our success. In managing our people, we seek to: • promote a safe and healthy workplace; • have a results-focused culture centered on transparency and open communication; 18
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Table of Contents • attract, retain and develop a highly qualified, motivated and diverse workforce; • maintain a conservatively managed headcount to minimize workforce fluctuations; • provide opportunities for career growth, learning and development; and • offer highly competitive compensation and benefits packages. We believe these practices, further described below, are the key drivers in our development of current and future talent and leadership as well as employee engagement and retention. Recruiting, Hiring and Advancement. Due to the cyclical nature of our business and the fluctuations in activity that can occur, we manage our headcount carefully. We provide employees with opportunities to learn new roles and develop the breadth and depth of their skills to ensure a collaborative environment, strong talent and future leadership. This also helps to minimize layoffs and overall staff fluctuations when downturns occur. When a position needs to be filled, we generally seek to promote current top-performing employees before going to outside sources for a new hire. We believe this practice helps to build future leadership and to reduce voluntary turnover among our workforce by providing employees with new challenges and opportunities throughout their careers. When we hire from outside the Company, we identify qualified candidates by promoting the position internally for referrals, engaging in recruiting through our website and online platforms, utilizing recruiting services and attending job fairs. We also have a well-established internship program that feeds top talent into our technical functions. In our recruiting efforts, we foster a culture of mutual respect and compliance with all applicable federal, state and local laws governing nondiscrimination in employment. We treat all applicants with the same high level of respect regardless of their gender, ethnicity, religion, national origin, age, marital status, political affiliation, sexual orientation, gender identity, disability or protected veteran status. This philosophy extends to all employees throughout the lifecycle of employment, including recruiting, hiring, placement, promotion, evaluation, leaves of absence, compensation and training. Compensation and Benefits. Our focus on providing competitive total compensation and benefits to our employees is a core value and a key driver of our retention program. We design our compensation programs to provide compensation that is competitive with our industry peers and rewards superior performance and, for managers and executives, aligns compensation with our performance and incentivizes the achievement of superior operating results. We do this through a total rewards program that provides: • base wages or salaries that are competitive for the position and considered for increases annually based on employee performance, business performance and industry outlook; • incentives that reward individual and Company performance, such as performance bonuses, management discretionary bonuses, field operational bonuses and short-term and long-term incentive programs; • retirement benefits, including dollar-for-dollar matching contributions and discretionary employer retirement contributions to a tax- qualified defined contribution savings plan for all employees and other non-qualified retirement programs; • comprehensive health and welfare benefits, including medical insurance, prescription drug benefits, dental insurance, vision insurance, life insurance, accident insurance, short and long-term disability benefits, employee assistance program and health savings accounts; • tuition reimbursement for eligible employees, scholarship program and matching charitable contributions program; and • time off, sick time, parental leave and holiday time. We believe our compensation and benefits package is a strong retention tool and promotes personal health and financial security within our workforce. Health and Safety. The health and safety of our employees is one of our core values for sustainable operations. This value is reflected in our strong safety culture that emphasizes personal responsibility and safety leadership, both for our employees and our contractors that are on our worksites. Our safety programs are built on a foundation that emphasizes personal safety and includes a Stop Work Authority program that empowers employees and contractors to stop work if they discover, or even suspect, a dangerous condition or other serious EHS hazard. Our comprehensive EHS management system establishes a corporate governance framework for EHS compliance and performance and covers all elements of our operating lifecycle. 19
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Table of Contents Website Access to Company Reports We make available free of charge through our website, www.coterra.com, our annual reports on Form 10 ‑ K, quarterly reports on Form 10 ‑ Q, current reports on Form 8 ‑ K and all amendments to those reports as soon as reasonably practicable after such material is electronically filed with or furnished to the SEC. In addition, the SEC maintains a website at www.sec.gov that contains reports, proxy and information statements and other information filed by us. Information on our website, including our 2025 Sustainability Report, is not a part of, and is not incorporated into, this Annual Report on Form 10-K or any other report we may file with or furnish to the SEC (and is not deemed filed herewith), whether before or after the date of this Annual Report on Form 10-K and irrespective of any general incorporation language therein. Furthermore, references to our website URLs are intended to be inactive textual references only. Corporate Governance Matters Our Corporate Governance Guidelines, Code of Business Conduct and Ethics, Audit Committee Charter, Compensation Committee Charter, Governance and Social Responsibility Committee Charter and Environment, Health & Safety Committee Charter are available on our website at www.coterra.com. Requests for copies of these documents can also be made in writing to our Corporate Secretary at our corporate headquarters at Three Memorial City Plaza, 840 Gessner Road, Suite 1400, Houston, Texas 77024. 20
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Table of Contents ITEM 1A. RISK FACTORS You should carefully consider the following risk factors in addition to the other information included in this report. Each of these risk factors could adversely affect our business, financial condition, results of operations and cash flows, as well as adversely affect the value of an investment in our common stock, debt securities, or preferred stock. Risks Related to the Proposed Merger The Merger may not be completed and the Merger Agreement may be terminated in accordance with its terms. On February 1, 2026, we entered into the Merger Agreement with Devon to combine via an all-stock merger transaction. The Merger is subject to a number of conditions to the closing, as specified in the Merger Agreement. These closing conditions include, among others, (1) the receipt of the required approvals from Coterra stockholders and Devon stockholders, (2) the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 and (3) the absence of any governmental order or law that makes consummation of the Merger illegal or otherwise prohibited. We can provide no assurance that the required stockholder approvals will be obtained or that the required conditions to the closing will be satisfied. These conditions to the completion of the Merger, some of which are beyond our control, may not be satisfied or waived in a timely manner or at all, and, accordingly, the Merger may be delayed or may not be completed at all. Any delay in completing the Merger could cause the combined business not to realize, or to be delayed in realizing, some or all of the benefits that we expect to achieve if the Merger is successfully completed within its expected time frame. The termination of the Merger Agreement could negatively impact our business. If the Merger is not completed for any reason, including as a result of a failure to obtain the required approvals from our stockholders or Devon’s stockholders, our ongoing business may be adversely affected and, without realizing any of the expected benefits or having completed the Merger, we would be subject to a number of risks, including the following: • we may experience negative reactions from the financial markets, including negative impacts on our stock price; • we may experience negative reactions from our customers, distributors, suppliers, vendors, landlords, joint venture participants and other third parties with whom we do business, as well as our employees; • we will be required, in certain terminations, to pay Devon a termination fee of $865 million and up to $40 million as reimbursement for Devon’s reasonable and documented fees and expenses in connection with the Merger; and • we will required to pay our costs relating to the Merger, including financial advisory, legal and accounting fees and expenses, regardless of whether the Merger is completed. The business relationships of Coterra and Devon may be subject to disruption and uncertainty associated with the Merger, which could have a material adverse effect on the business, financial condition, cash flows and results of operations of Coterra or Devon pending and following the Merger. Regardless of whether the Merger is completed, the announcement and pendency of the Merger could cause disruptions to our business and financial results, including as follows: • our and Devon’s current and prospective employees may experience uncertainty about their future roles with the combined business or the operations of the combined business following the Merger, which might adversely affect the two companies’ abilities to retain key management and other personnel; • uncertainty regarding the completion of the Merger may cause parties with which we or Devon do business, including customers, distributors, suppliers, vendors, landlords, joint venture participants and other third parties, to delay or defer certain business decisions or to decide to seek to terminate, change or renegotiate their relationships with us or Devon; and • the Merger Agreement restricts us from pursuing attractive business opportunities or strategic transactions that may arise prior to completion of the Merger. These disruptions could have a material and adverse effect on the business, financial condition, cash flows and results of operations, Coterra or Devon, regardless of whether the Merger is completed, as well as a material and adverse effect on our ability to realize the expected cost savings and other benefits of the Merger. The risk, and adverse effects, of any disruption could be exacerbated by a delay in completion of the Merger or termination of the Merger Agreement. 21
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Table of Contents In addition, we have and will continue to divert significant management resources in an effort to complete the Merger. If the Merger is not completed, we will have incurred significant costs, including the diversion of management resources, for which we will have received little or no benefit. Because the market price of Devon common stock has fluctuated and will continue to fluctuate, our stockholders cannot be sure of the value of the consideration they will receive in the Merger, if completed. If the Merger is completed, each eligible share of the Coterra common stock outstanding immediately prior to the Merger will automatically be converted into the right to receive 0.70 shares of Devon common stock. The value of the Devon common stock will depend on the market price at the time the Merger is completed. Prior to completion of the Merger, the market price of Devon common stock is also expected to impact the market price of Coterra common stock. The value of Devon common stock has fluctuated since the date of the announcement of the Merger agreement and will continue to fluctuate. Accordingly, our stockholders will not know or be able to determine the market value of the merger consideration that they would receive upon completion of the Merger. Stock price changes may result from a variety of factors, including, among others, general market and economic conditions, changes in Devon’s and our respective businesses, operations and prospects, market assessments of the likelihood that the Merger will be completed and the timing of the Merger and regulatory considerations. Many of these factors and beyond Devon’s and our control. The Merger Agreement subjects us to restrictions on our business activities prior to the effective time of the Merger, limits our ability to pursue alternatives to the Merger and may discourage other companies from making a favorable alternative transaction proposal. The Merger Agreement restricts Coterra and Devon from entering into certain corporate transactions and taking other specified actions without the consent of the other party, and generally requires each party to continue its operations in the ordinary course, until completion of the Merger. These restrictions could be in place for an extended period of time if completion of the Merger is delayed and could prevent us from pursuing attractive business opportunities that may arise prior to the completion of the Merger. The Merger Agreement also contains provisions that may discourage a third party from submitting a competing proposal that might result in greater value to our stockholders than the Merger, or may result in a potential acquirer of Devon, or a potential competing acquirer of Coterra, proposing to pay a lower per share price to acquire Devon than it might otherwise have proposed to pay. These provisions include a general prohibition on us from soliciting or, subject to certain exceptions relating to the exercise of fiduciary duties by our Board of Directors, entering into discussions with any third party regarding any competing proposal or offer for a competing transaction. Further, even if our Board of Directors withholds, withdraws, qualifies or modifies its recommendation with respect to the Merger-related proposals to be voted on by our stockholders, unless the Merger Agreement has been terminated in accordance with its terms, we will still be required to submit such proposals to a vote of our stockholders. The Merger may be completed even though material adverse changes subsequent to the announcement of the Merger, such as industry-wide changes or other events, may occur. In general, either party to the Merger can refuse to complete the transaction if there is a material adverse change affecting the other party. However, some types of changes do not permit either party to refuse to complete the transaction, even if such changes would have a material adverse effect on either of the parties. For example, a worsening of a party’s financial condition or results of operations due to a decrease in commodity prices or general economic conditions would not give the other party the right to refuse to complete the transaction. In addition, the parties have the ability, but are under no obligation, to waive any material adverse change that results in the failure of a closing condition and instead proceed with completing the transaction, the share price, business and financial results of the combined company may suffer. The failure to integrate the businesses and operations of Devon and Coterra successfully in the expected time frame may adversely affect the combined business’ future results. The Merger involves the combination of two companies which currently operate, and until the completion of the Merger will continue to operate, as independent public companies. We can provide no assurances that our business and Devon’s business can be integrated successfully. It is possible that the integration process could result in the loss of key Coterra employees or key Devon employees, the loss of customers, service providers, vendors or other business counterparties, the disruption of either company’s or both companies’ ongoing businesses, inconsistencies in standards, controls, procedures and policies, potential unknown liabilities and unforeseen expenses or delays associated with and following completion of the Merger or higher-than-expected integration costs and an overall post-completion integration process that takes longer than originally anticipated. 22
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Table of Contents Furthermore, the Board of Directors and executive leadership of the combined company immediately following the Merger will consist of directors and executive officers from each of Devon and Coterra. Combining the boards of directors and management teams of each company into a single board and a single management team could require the reconciliation of differing priorities and philosophies. The combined business may fail to realize all of the anticipated benefits of the Merger. The success of the Merger will depend, in part, on our ability to realize the anticipated benefits and cost savings from combining our business with Devon’s business and operational synergies. The anticipated benefits and cost savings of the Merger may not be realized fully or at all, may take longer to realize than expected, may not be realized or could have other adverse effects that we do not currently foresee. Some of the assumptions that we have made, such as the achievement of the anticipated benefits related to the combination of assets in certain basins and the expected size, scale, inventory, cash flow generation and financial strength of the combined business, may not be realized. The integration process may result in the loss of key employees, the disruption of ongoing businesses or inconsistencies in standards, controls, procedures and policies. In addition, there could be potential unknown liabilities and unforeseen expenses associated with the Merger that could adversely impact the combined business. The declaration, payment and amounts of dividends, if any, distributed to our stockholders following competition of the Merger will be uncertain. Although each of Devon and Coterra has paid cash dividends on its respective shares of common stock in the past, our Board of Directors and the Board of Directors of the combined company may determine not to declare dividends in the future or may reduce the amount of dividends paid in the future. Decisions on whether, when and in which amounts to declare and pay any future dividends will remain in the discretion of the full Board of Directors of the combined company. Any dividend payment amounts will be determined by the Board of Directors on a quarterly basis, and it is possible that the Board of Directors may increase or decrease the amount of dividends paid in the future, or determine not to declare dividends in the future, at any time and for any reason. We expect that any such decisions will depend on the combined business’s financial condition, results of operations, cash balances, cash requirements, future prospects, the outlook for commodity prices and other considerations that the Board of Directors deems relevant, including, but not limited to: • whether the combined company has enough cash to pay such dividends due to its cash requirements, capital spending plans, cash flows or financial position; • its desire to maintain or improve the credit ratings on its debt; and • applicable restrictions under Delaware law. Stockholders should be aware that they have no contractual or other legal right to dividends that have not been declared. Potential litigation against us or Devon could result in substantial costs, an injunction preventing the completion of the Merger and/or a judgment resulting in the payment of damages. Securities class action lawsuits and derivative lawsuits are often brought against public companies that have entered into merger agreements. Even if such a lawsuit is unsuccessful, defending against these claims an result in substantial costs. Stockholders may file lawsuits against Devon, us and/or the directors and officers of either company in connection with the Merger. These lawsuits could prevent or delay the completion of the Merger and result in significant costs to us or Devon, including any costs associated with the indemnification of directors and officers. There can be no assurance that any of the defendants will be successful in the outcome of any potential lawsuits. We will incur significant transaction and Merger-related costs in connection with the Merger. We expect to incur a number of non-recurring costs associated with the Merger. The significant, non-recurring costs associated with the Merger include, among others, fees and expenses of financial advisors and other advisors and representatives and certain employment-related costs relating to our employees. Some of these costs have already been incurred or may be incurred regardless of whether the Merger is completed. 23
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Table of Contents Business and Operational Risks Commodity prices fluctuate widely, and low prices for an extended period would likely have a material adverse impact on our business. Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prices we receive for the oil, natural gas and NGLs that we sell. Lower commodity prices may reduce the amount of oil, natural gas and NGLs that we can produce economically. Historically, commodity prices have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile. Wide fluctuations in commodity prices may result from relatively minor changes in the supply of and demand for oil, natural gas and NGLs, market uncertainty and a variety of additional factors that are beyond our control, including global events or conditions that affect supply and demand (such as pandemics, the war in Ukraine, conflict in the Middle East and other geopolitical risks and sanctions), the actions of OPEC+ members and climate change and potential legislative and regulatory actions related thereto. In addition, the price for natural gas and NGLs that we sell may be impacted by the demand for liquid natural gas (“LNG”) exports and the impact of such demand on domestic natural gas prices, including if future U.S. regulatory action limits the construction of new LNG facilities or limits the approvals of applications for LNG export authorization. Any substantial or extended decline in future commodity prices would have a material adverse effect on our future business, financial condition, results of operations, cash flows, liquidity or ability to finance planned capital expenditures and commitments. If commodity prices decline significantly for a sustained period of time, the lower prices may cause us to reduce our planned drilling program or adversely affect our ability to make planned expenditures, raise additional capital or meet our financial obligations. Furthermore, substantial, extended decreases in commodity prices may render certain projects uneconomic, which may result in significant downward adjustments to our estimated proved reserves and could negatively impact our ability to borrow, our cost of capital and our ability to access capital markets, increase our costs under our revolving credit agreement and limit our ability to execute aspects of our business plans. Future commodity price declines may result in write-downs of the carrying amount of our oil and gas properties, which could materially and adversely affect our results of operations. The value of our oil and gas properties depends on commodity prices. Declines in these prices as well as increases in development costs, changes in well performance, delays in asset development or deterioration of drilling results may result in our having to make material downward adjustments to our estimated proved reserves and could result in an impairment charge and a corresponding write-down of the carrying amount of our oil and gas properties. We evaluate our oil and gas properties for impairment on a field-by-field basis whenever events or changes in circumstances indicate a property’s carrying amount may not be recoverable. We compare expected undiscounted future cash flows to the net book value of the asset. If the future undiscounted expected cash flows, based on our estimate of future commodity prices, operating costs and anticipated production from proved reserves and risk-adjusted probable and possible reserves, are lower than the net book value of the asset, the capitalized cost is reduced to fair value. Commodity pricing is estimated by using a combination of assumptions management uses in its budgeting and forecasting process as well as historical and current prices adjusted for geographical location and quality differentials, as well as other factors that management believes will impact realizable prices. In the event that commodity prices decline, there could be a significant revision to the carrying amounts of oil and gas properties in the future. Drilling, completing and operating oil and natural gas wells are high-risk activities. Our growth is materially dependent upon the success of our drilling program. Drilling for oil and natural gas involves numerous risks, including the risk that no commercially productive reservoirs will be encountered. The cost of drilling, completing and operating wells is substantial and uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors beyond our control, including the risk of electric grid outages and the potential impacts thereof on our electric fracturing systems. Our future drilling activities may not be successful and, if unsuccessful, such failure will have an adverse effect on our future results of operations and financial condition. Our operations present hazards and risks that require significant oversight and are subject to numerous possible disruptions from unexpected events. The scope and nature of our operations present a variety of significant hazards and risks, including operational hazards and risks such as explosions, fires, product spills, and cybersecurity incidents, such as unauthorized access to data or systems, among other risks. Our operations are also subject to broader global events and conditions, including public health crises, pandemics, epidemics, war or civil unrest, acts of terror, weather events and natural disasters, including those that are related to or exacerbated by climate change. Such hazards and risks could impact our business in the areas in which we operate, and our business and operations may be disrupted if we fail to respond in an appropriate manner to such hazards and risks or if we are 24
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Table of Contents unable to efficiently restore or replace affected operational components and capacity. Furthermore, our insurance may not cover such liabilities, or be adequate to compensate us for all resulting losses. The cost of insurance may increase, and the availability of insurance may decrease, as a result of climate change or other factors. The occurrence of any event not covered or fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows. Our proved reserves are estimates. Any material inaccuracies in our reserves estimates or underlying assumptions could cause the quantities and net present value of our reserves to be overstated or understated. Reserves engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. The process of estimating quantities of proved reserves is complex and inherently imprecise, and the reserves data included in this document are only estimates. The process relies on interpretations of available geologic, geophysical, engineering and production data. The extent, quality and reliability of this technical data can vary. The process also requires certain economic assumptions, some of which are mandated by the SEC, such as assumptions relating to commodity prices. Additional assumptions include drilling and operating expenses, capital expenditures, taxes and availability of funds. Furthermore, different reserve engineers may make different estimates of reserves and cash flows based on the same data. For more information on such revision, refer to the Supplemental Oil and Gas Information included in Item 8. Results of drilling, testing and production subsequent to the date of a reserves estimate may justify revising the original estimate. Accordingly, initial reserves estimates often vary from the quantities of oil and natural gas that are ultimately recovered, and such variances may be material. Any significant variance could reduce the estimated quantities and present value of our reserves. You should not assume that the present value of future net cash flows from our proved reserves is the current market value of our estimated reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flows from our proved reserves on the 12-month average index price for the respective commodity, calculated as the unweighted arithmetic average for the first day of the month price for each month and costs in effect on the date of the estimate, holding the prices and costs constant throughout the life of the properties, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. Actual future prices and costs may differ materially from those used in the net present value estimate, and future net present value estimates using then current prices and costs may be significantly less than the current estimate. In addition, the 10 percent discount factor we use when calculating discounted future net cash flows for reporting requirements in compliance with the applicable accounting standards may not be the most appropriate discount factor based on interest rates in effect from time-to-time and risks associated with us or the oil and gas industry in general. Our future performance depends on our ability to find or acquire additional oil and natural gas reserves that are economically recoverable. Unless we successfully replace the reserves that we produce, our reserves will decline as reserves are depleted, eventually resulting in a decrease in oil and natural gas production and lower revenues and cash flow from operations. Our future production is, therefore, highly dependent on our level of success in finding or acquiring additional reserves. We may not be able to replace reserves through our exploration, development and exploitation activities or by acquiring properties at acceptable costs. Additionally, there is no way to predict in advance of any exploration and development whether any particular location will yield sufficient quantities to recover drilling or completion costs or be economically viable. Low commodity prices may further limit the kinds of reserves that we can develop and produce economically. If we are unable to replace our current and future production, our revenues will decrease and our business, financial condition and results of operations may be adversely affected. The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. As of December 31, 2025, approximately 17 percent of our estimated proved reserves (by volume) were undeveloped. Developing PUD reserves requires significant capital expenditures, the estimated future development costs associated with our PUD reserves may not equal our actual costs, development may not occur as scheduled and results of our development activities may not be as estimated. If we choose not to develop our PUD reserves, or if we are not otherwise able to develop them successfully, we will be required to remove them from our reported proved reserves. In addition, under the SEC’s reserves reporting rules, because PUD reserves generally may be recorded only if they relate to wells scheduled to be drilled within five years of the date of booking, we may be required to remove any PUD reserves that are no longer planned to be developed within this five-year time frame. Delays in the development of our PUD reserves, decreases in commodity prices and increases in costs to drill and develop such reserves may also result in some projects becoming uneconomic. 25
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Table of Contents Strategic determinations, including the allocation of capital and other resources to strategic opportunities, are challenging, and our failure to appropriately allocate capital and resources among our strategic opportunities may adversely affect our financial condition and reduce our growth rate. Our future growth prospects depend on our ability to identify optimal strategies for our business. In developing our business plans, we considered allocating capital and other resources to various aspects of our business including well-development (primarily drilling and completion), reserve acquisitions, exploratory activity, corporate items and other alternatives. We also consider our likely sources of capital. Notwithstanding the determinations made in the development of our 2026 plan, business opportunities not previously identified periodically may come to our attention, including possible acquisitions and dispositions. If we fail to identify optimal business strategies or fail to optimize our capital investment and capital raising opportunities and the use of our other resources in furtherance of our business strategies, our financial condition and growth rate may be adversely affected. Moreover, economic or other circumstances may change from those contemplated by our 2026 plan, and our failure to recognize or respond to those changes may limit our ability to achieve our objectives. Our ability to sell our oil, natural gas and NGL production and the prices we receive for our production could be materially harmed if we fail to obtain adequate services such as gathering, transportation and processing. The sale of our oil, natural gas and NGL production depends on a number of factors beyond our control, including the availability and capacity of gathering, transportation and processing facilities. We deliver the majority of our oil, natural gas and NGL production through gathering systems and pipelines that we do not own. The lack of available capacity on these systems and facilities could reduce the price offered for our production or result in the shut-in of producing wells or the delay or discontinuance of development plans for properties. Third- party systems and facilities may be unavailable due to market conditions or mechanical or other reasons, and in some cases the resulting curtailments of production could lead to payment being required where we fail to deliver oil, natural gas and NGLs to meet minimum volume commitments. In addition, construction of new pipelines and building of required infrastructure may be slow. To the extent these services are unavailable, we would be unable to realize revenue from wells served by such facilities until suitable arrangements are made to market our production. Our failure to obtain these services on acceptable terms could materially harm our business. Moreover, these availability and capacity issues are likely to occur in remote areas with less established infrastructure, such as our Permian Basin properties where we have significant oil and natural gas production. Such availability and capacity issues may result in increased basis differentials, which became more divergent beginning in 2024 in part due to constrained pipeline capacity and oversupply in certain geographic areas. At times, such basis differentials have been significant enough to result in negative spot market pricing in certain areas, such as the Waha Hub in the Permian Basin during 2024, 2025, and early 2026. Any of these availability or capacity issues could negatively affect our operations, revenues and expenses. This could result in wells being shut in or awaiting a pipeline connection or capacity, which would adversely affect our results of operations and cash flows. Acquired properties may not be worth what we pay to acquire them, due to uncertainties in evaluating recoverable reserves and other expected benefits, as well as potential liabilities. Successful property acquisitions require an assessment of a number of factors beyond our control. These factors include estimates of recoverable reserves, exploration and development potential, future commodity prices, operating costs, production taxes and potential environmental and other liabilities. These assessments are complex and inherently imprecise. Our review of the properties we acquire may not reveal all existing or potential problems. In addition, our review may not allow us to assess fully the potential deficiencies of the properties. We do not inspect every well, and even when we inspect a well, we may not discover structural, subsurface or environmental problems that may exist or arise. There may be threatened or contemplated claims against the assets or businesses we acquire related to environmental, title, regulatory, tax, contract, litigation or other matters of which we are unaware, which could materially and adversely affect our production, revenues and results of operations. We often assume certain liabilities, and we may not be entitled to contractual indemnification for pre-closing liabilities, including environmental liabilities, and our contractual indemnification may not be effective. At times, we acquire interests in properties on an “as is” basis with limited representations and warranties and limited remedies for breaches of such representations and warranties. In addition, significant acquisitions can change the nature of our operations and business if the acquired properties have substantially different operating and geological characteristics or are in different geographic locations than our existing properties. 26
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Table of Contents The integration of the businesses and properties we have acquired or may in the future acquire could be difficult and may divert management’s attention away from our existing operations. The integration of the businesses and properties we have acquired or may in the future acquire could be difficult, and may divert management’s attention and financial resources away from our existing operations. These difficulties include: • the challenge of integrating the acquired businesses and properties while carrying on the ongoing operations of our business; • the inability to retain key employees of the acquired business; • the challenge of inconsistencies in standards, controls, procedures and policies of the acquired business; • potential unknown liabilities, unforeseen expenses or higher-than-expected integration costs; • an overall post-completion integration process that takes longer than originally anticipated; • potential lack of operating experience in a geographic market of the acquired properties; and • the possibility of faulty assumptions underlying our expectations. If management is not able to effectively manage the integration process, or if any significant business activities are interrupted as a result of the integration process, our business could suffer. Our future success will depend, in part, on our ability to manage our expanded business, which may pose substantial challenges for management. We may also face increased scrutiny from governmental authorities as a result of the increase in the size of our business. There can be no assurances that we will be successful in our integration efforts. We have limited control over the activities on properties we do not operate. Other companies operate some of the properties in which we have an interest. As of December 31, 2025, non-operated wells represented approximately 49 percent of our total owned gross wells, or 11 percent of our owned net wells. We have limited ability to influence or control the operation or future development of these non-operated properties and of properties we operate in joint ventures in which we may share control with third parties, including compliance with environmental, safety and other regulations or the amount of capital expenditures that we are required to fund with respect to them. An operator of our wells or a joint venture participant may not adequately perform operations, may breach applicable agreements or may fail to act in ways that are in our best interest, which could reduce our production and revenues and expose us to liabilities. Our dependence on the operator or a joint venture participant could materially adversely affect the realization of our targeted returns on capital in drilling or acquisition activities and lead to unexpected future costs. Many of our properties are in areas that may have been partially depleted or drained by offset (i.e., neighboring) wells and certain of our wells may be adversely affected by actions other operators may take when drilling, completing or operating wells that they own. Many of our properties are in areas that may have been partially depleted or drained by earlier drilled offset wells. We have no control over offsetting operators who could take actions such as drilling and completing nearby wells, that could adversely affect our operations. When a new offset well is completed and produced, the pressure differential in the vicinity of the wellbore causes the migration of reservoir fluids toward the new wellbore (and potentially away from existing wellbores), which could cause a depletion of our proved reserves and may inhibit our ability to further develop our proved reserves. The possibility for these impacts may increase with respect to wells that are shut in as a response to lower commodity prices or the lack of pipeline and storage capacity. In addition, completion operations and other activities conducted on other nearby wells could cause us, in order to protect our existing wells, to shut in production for indefinite periods of time. Shutting in our wells and damage to our wells from offset completions could result in increased costs and could adversely affect the reserves and re-commenced production from such shut-in wells. We may lose leases if production is not established within the time periods specified in the leases or if we do not maintain production in paying quantities. We could lose leases under certain circumstances if we do not maintain production in paying quantities or meet other lease requirements, and the amounts we spent for those leases could be lost. If we shut in wells in response to lower commodity prices or a lack of pipeline and storage capacity, we may face claims that we are not complying with lease provisions. In addition, the government also may impose new restrictions and regulations affecting our ability to drill, conduct hydraulic fracturing operations, and obtain necessary rights-of-way on federal lands, which could, in turn, result in the loss of federal 27
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Table of Contents leases. As of December 31, 2025, less than one percent of our net undeveloped acreage in our core operating areas will expire over the next three years. Our actual drilling activities may materially differ from those presently identified, which could adversely affect our business. Oil and natural gas production operations, especially those using hydraulic fracturing, are substantially dependent upon the availability of water and the ability to dispose of produced water gathered from drilling and production activities. Restrictions on the Company’s ability to obtain water or dispose of produced water may have a material effect on its financial condition, results of operations and cash flows. Water is an essential component of oil and natural gas production during the drilling and hydraulic fracturing processes. In particular, we use a significant amount of water in the hydraulic fracturing process. Limitations or restrictions on the Company’s ability to secure sufficient amounts of water (including limitations resulting from natural causes such as drought) could have a material impact on our operations. Severe drought conditions can result in local water districts taking steps to restrict the use of water in their jurisdiction for drilling and hydraulic fracturing in order to protect the local water supply. If the Company is unable to obtain water to use in its operations from local sources, it may need to be obtained from new sources and transported to drilling sites, resulting in increased costs, which could adversely affect our financial condition, results of operations and cash flows. Our inability to locate sufficient amounts of water, or dispose of or recycle water used in our exploration, development and production activities, could adversely impact our operations. Compliance with environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells may increase our operating costs and cause delays, interruptions or termination of our operations. Such delays, interruptions or termination of our operations could have an adverse effect on our operations and financial condition. In addition, the Company must dispose of the fluids produced from oil and gas production operations, including produced water, which it does directly or through the use of third-party vendors. The legal requirements related to the disposal of produced water into a non-producing geologic formation by means of underground injection wells are subject to change based on concerns of the public or governmental authorities regarding such disposal activities. More stringent regulations or legal directives, as well as potential litigation or other developments, related to such disposal activities could materially impact our ability to dispose of produced water, which could adversely affect the Company’s business, financial condition and results of operations. For additional information, please read “Business and Properties—Other Business Matters—Environmental and Safety Regulations— Clean Water Act” in Items 1 and 2. Cyber-attacks targeting our systems, the oil and gas industry systems and infrastructure or the systems of our third-party service providers could adversely affect our business. Our business, like the oil and gas industry in general, has become increasingly dependent on data, information systems, and digitally connected infrastructure, including technologies managed by third-party providers on whom we rely on to help us collect, host or process information. We depend on this technology to, for example, record and store information like financial data, estimate quantities of oil and natural gas reserves, analyze and share operating data, and communicate internally and externally. Information and operational technology systems control nearly all of the oil and gas distribution systems in the U.S., which are necessary to transport our products to market. These systems also enable communications and provide a host of other support services for our business. In recent years we have increased the use of remote networking and online conferencing services and technologies that enable employees to work outside of our corporate infrastructure, which exposes us to additional cybersecurity risks, including unauthorized access to proprietary, confidential, or other sensitive information. We have experienced cyber incidents in the past and, although none have been material, we may experience cybersecurity incidents and security breaches in the future. Cyber-attacks are becoming more sophisticated and can include, but are not limited to, the use of malicious software, phishing scams, ransomware, attempts to gain unauthorized access to systems or data, or other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information, such as personal information of our employees, and corruption of data. In addition, cybersecurity risk is exacerbated with the advancement of technologies like artificial intelligence, which malicious third parties are using to create new, more sophisticated and more frequent attacks. Unauthorized access to our seismic data, reserves information, customer or employee data or other proprietary or commercially sensitive information could lead to data integrity issues, communication interruption or other disruptions in our exploration or production operations or planned business transactions, any of which could have a material adverse impact on our business and operations. If our information or operational technology systems cease to function properly or are breached, we could suffer disruptions to our normal operations, which may include drilling, completion, production and corporate functions. A successful cyber-attack involving our information or operational technology systems and related infrastructure, or that of our business associates or partners, 28
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Table of Contents could result in supply chain disruptions that delay or prevent the transportation and marketing of our production, equipment damage, fires, explosions or environmental releases, non-compliance leading to regulatory fines or penalties, loss or disclosure of, or damage to, our or any of our customer’s or supplier’s data or confidential information that could harm our business by damaging our reputation, subjecting us to potential financial or legal liability and requiring us to incur significant costs, including costs to repair or restore our systems and data or to take other remedial steps. In addition, certain cyber incidents, such as reconnaissance campaigns, may remain undetected for an extended period, and our systems and insurance coverage for protecting against such cybersecurity risks may be costly and may not be sufficient. As cyber-attackers become more sophisticated, we may be required to expend significant additional resources to continue to protect our business or remediate the damage from cyber-attacks. Furthermore, the continuing and evolving threat of cyber-attacks has resulted in increased regulatory focus on prevention, mitigation, and notification, and we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any information security vulnerabilities. To the extent we face increased regulatory requirements, we may be required to expend significant additional resources to meet such requirements. Risks Related to our Indebtedness, Hedging Activities and Financial Position We have substantial capital expenditure requirements, and we may not be able to obtain needed financing on satisfactory terms, if at all. We make and expect to make substantial capital expenditures in connection with our development and production projects. We intend to fund our capital expenditures through cash flows from our operations and, to the extent that is not sufficient, borrowings under our revolving credit agreement. Our ability to generate operating cash flow is subject to a number of risk and variables, including the production of volumes and prices of natural gas, oil and NGLs. We may need to rely on access to both our revolving credit agreement and longer-term capital markets as sources of liquidity for any capital requirements not satisfied by cash flow from operations or other sources. Our ability to access such sources of liquidity may be restricted at a time when we want or need to raise capital, which could have an impact on our flexibility to react to changing economic and business conditions and may cause us to curtail our exploration and development activity. Additionally, such adverse economic and market conditions could impact our counterparties, including our receivables and our hedging counterparties who may, as a result of such conditions, be unable to perform their obligations. Risks associated with our debt and the provisions of our debt agreements could adversely affect our business, financial position and results of operations. Our indebtedness could have adverse effects on our business, financial condition, results of operations and cash flows, including by requiring us to use a substantial portion of our cash flow to make debt service payments, which would reduce the funds that would otherwise be available for operations, returning capital to stockholders and future business opportunities. As a result, our ability to buy and sell assets, engage in strategic transactions or obtain additional financing for working capital, capital expenditures, general corporate and other purposes may be adversely impacted. Our ability to make payments on and to refinance our indebtedness will depend on our ability to generate cash in the future from operations, financings or asset sales. If we fail to make required payments or otherwise default on our debt, the lenders who hold such debt also could accelerate amounts due, which could potentially trigger a default or acceleration of other debt. Our debt agreements also require compliance with covenants to maintain specified financial ratios. If commodity prices deteriorate from current levels, it could lead to reduced revenues, cash flow and earnings, which in turn could lead to a default under such agreements due to lack of covenant compliance. Because the calculations of the financial ratios are made as of certain dates, the financial ratios can fluctuate significantly from period to period. A prolonged period of lower commodity prices could further increase the risk of our inability to comply with covenants to maintain specified financial ratios. In order to provide a margin of comfort with regard to these financial covenants, we may seek to modify our capital program, sell non-strategic assets or opportunistically modify or increase our derivative instruments. In addition, we may seek to refinance or restructure all or a portion of our indebtedness. We cannot provide assurance that we will be able to successfully execute any of these strategies, and such strategies may be unavailable on favorable terms or at all. For more information about our debt agreements, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Financial Condition— Liquidity and Capital Resources” in Item 7. We may have hedging arrangements that expose us to risk of financial loss and limit the benefit to us of increases in prices for oil and natural gas. We use financial derivative instruments to manage commodity price risk. While there are many different types of derivatives available, we generally utilize collar, swap and basis swap agreements to manage price risk more effectively. 29
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Table of Contents While these derivatives reduce the impact of declines in commodity prices, these derivatives conversely limit the benefit to us of increases in prices. In addition, these arrangements expose us to risks of financial loss in a variety of circumstances, including when: • there is an adverse change in the expected differential between the underlying price in the derivative instrument and actual prices received for our production; • production is less than expected; or • a counterparty is unable to satisfy its obligations. In addition, the CFTC has promulgated regulations to implement statutory requirements for derivatives transactions, including swaps. Reduced liquidity in the oil and gas derivative market could increase the cost of derivative contracts, limit the availability of derivatives to protect against risks that we encounter, reduce our ability to monetize or restructure our existing derivative contracts and increase our exposure to less creditworthy counterparties. If we reduce our use of swaps, our results of operations may become more volatile, and our cash flows may be less predictable. In addition, the use of financial derivative instruments involves the risk that the counterparties will be unable to meet the financial terms of such transactions. We are unable to predict changes in a counterparty’s creditworthiness or ability to perform, and even if we could predict such changes accurately, our ability to negate such risk may be limited depending on market conditions and the contractual terms of the instruments. If any of our counterparties were to default on its obligations under our financial derivative instruments, such a default could (1) have a material adverse effect on our results of operations, (2) result in a larger percentage of our future production being subject to commodity price changes and (3) increase the likelihood that our financial derivative instruments may not achieve their intended strategic purposes. We will continue to evaluate the benefit of utilizing derivatives in the future. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 and “Quantitative and Qualitative Disclosures about Market Risk” in Item 7A for further discussion concerning our use of derivatives. Legal, Regulatory and Governmental Risks ESG concerns and negative public perception regarding us and our industry could adversely affect our business operations and the price of our common stock, debt securities and preferred stock. Businesses across all industries are facing increasing scrutiny from investors, governmental authorities, regulatory agencies and the public related to their ESG practices, including practices and disclosures related to climate change, among others. Failure, or a perceived failure, to adequately respond to or meet evolving investor, stockholder or public expectations, concerns and standards may cause a business entity to suffer reputational damage and materially and adversely affect the entity’s business, financial condition, or stock and debt prices. Further, negative public perception regarding us and our industry resulting from, among other things, concerns raised by advocacy groups about climate change impacts of methane and other greenhouse gas emissions, hydraulic fracturing, oil spills, and pipeline explosions coupled with increasing societal expectations on businesses to address climate change and potential consumer use of substitutes to carbon- intensive energy commodities may result in increased costs, reduced demand for our oil, natural gas and NGL production, reduced profits, increased regulation, regulatory investigations and litigation, and negative impacts on our stock and debt prices and access to capital markets. These factors could also cause the permits we need to conduct our operations to be challenged, withheld, delayed, or burdened by requirements that restrict our ability to profitably conduct our business. Federal, state and local laws and regulations, judicial actions and regulatory initiatives related to oil and gas development and the use of hydraulic fracturing could result in increased costs and operating restrictions or delays and adversely affect our business, financial condition, results of operations and cash flows. Our operations are subject to extensive federal, state and local laws and regulations, including drilling and environmental and safety laws and regulations, which increase the cost of planning, designing, drilling, installing and operating oil and natural gas facilities. New laws and regulations or revisions or reinterpretations of existing laws and regulations could further increase these costs, could increase our liability risks, and could result in increased restrictions on oil and gas exploration and production activities, which could have a material adverse effect on us and the oil and gas industry as a whole. Risk of substantial costs and liabilities related to environmental and safety matters in particular, including compliance issues, environmental contamination and claims for damages to persons or property, are inherent in oil and natural gas operations. Failure to comply with applicable environmental and safety laws and regulations also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties as well as the imposition of corrective action requirements and orders. In addition, 30
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Table of Contents applicable laws and regulations require us to obtain many permits for the operation of various facilities. The issuance of required permits is not guaranteed and, once issued, permits are subject to revocation, modification and renewal. Failure to comply with applicable laws and regulations can result in fines and penalties or require us to incur substantial costs to remedy violations. For additional information, please read “Business and Properties—Other Business Matters—Regulation of Oil and Natural Gas Exploration and Production,” “—Regulation of Natural Gas Marketing, Gathering and Transportation,” and “—Environmental and Safety Regulations” in Items 1 and 2. The adoption of climate change legislation or regulations restricting emission of greenhouse gases could result in increased operating costs and reduced demand for the oil and gas we produce. Studies have found that emission of certain gases, commonly referred to as GHGs impact the earth’s climate. The U.S. Congress and various states have been evaluating, and in some cases implementing, climate-related legislation and other regulatory initiatives that restrict GHG emissions. These actions as well as any future laws or regulations that regulate or limit GHG emissions from our equipment and operations could require us to develop and implement new practices aimed at reducing GHG emissions, such as emissions control technologies, and to monitor and report GHG emissions associated with our operations, any of which could increase our operating costs and could adversely affect demand for the oil and gas that we produce. At this time, it is not possible to quantify the impact of such future laws and regulations on our business. For additional information, please read “Business and Properties—Other Business Matters—Environmental and Safety Regulations— Greenhouse Gas and Climate Change Laws and Regulations” in Items 1 and 2. We are subject to various climate-related risks. The following is a summary of potential climate-related risks that could adversely affect us: Market Transition Risks. Increased transition to renewable or other alternative energy sources could adversely affect our business, results of operations and cash flows. Our long-term success will be impacted in part by the ability of the global energy markets to transition to renewable or other alternative energy sources, since increased transition to such alternative sources could adversely impact the long-term demand for oil, natural gas and NGLs. An increase in the demand for alternative energy sources, including as a result of new and more efficient technologies or increased government subsidies and intervention, could further increase the market share of alternative energy sources as compared to oil and natural gas and thereby adversely affect our business, results of operations and cash flows. Policy and Legal Risks. Policy risks include actions that seek to lessen activities that contribute to adverse effects of climate change or to promote adaptation to climate change. Examples of policy actions that would increase the costs of our operations or lower demand for our oil and gas include shifting energy use toward lower emission sources or subsidizing or encouraging through regulatory shifts energy-efficiency solutions. Policy actions also may include restrictions or bans on oil and gas activities, which could lead to write-downs or impairments of our assets. Legal risks include potential lawsuits or regulations regarding the impacts of climate change, failure to adapt to climate change, and the insufficiency of disclosure around material financial risks. Furthermore, we could also face an increased risk of climate ‐ related litigation or “greenwashing” suits with respect to our operations, disclosures, or products. Claims have been made against certain energy companies alleging that GHG emissions from oil, gas and NGL operations constitute a public nuisance under federal and state law. Private individuals or public entities also could attempt to enforce environmental laws and regulations against us and could seek personal injury and property damages or other remedies. Additionally, governments and private parties are also increasingly filing suits, or initiating regulatory action, based on allegations that certain public statements regarding ESG-related matters by companies are false and misleading “greenwashing” campaigns that violate deceptive trade practices and consumer protection statutes or that climate-related disclosures made by companies are inadequate. Similar issues can also arise when aspirational statements such as net-zero or carbon neutrality targets are made without clear plans. Although we are not a party to any such climate-related or “greenwashing” litigation currently, unfavorable rulings against us in any such case brought against us in the future could significantly impact our operations and could have an adverse impact on our financial condition. Alternatively, we may be accused of “greenhushing” for the failure to communicate certain climate-related initiatives, commitments and goals, whether in our filings with the SEC or in other disclosures. Technology Risks. Technological improvements or innovations that support the transition to a lower-carbon, more energy efficient economic system may have a significant impact on us. The development and use of emerging technologies in renewable energy, battery storage, and energy efficiency may lower demand for oil and gas, resulting in lower prices and revenues, and higher costs. 31
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Table of Contents Reputation Risk. Climate change is a potential source of reputational risk, which is tied to changing customer or community perceptions of an organization’s contribution to, or detraction from, the transition to a lower-carbon economy. For additional information, please read “— ESG concerns and negative public perception regarding us and our industry could adversely affect our business operations and the price of our common stock, debt securities and preferred stock” in this Item 1A. Physical Risks. Potential physical risks resulting from climate change may be event driven (including increased severity of extreme weather events, such as hurricanes, droughts, floods, tornadoes, wildfires or freezes) or may be driven by longer-term shifts in climate patterns that may cause sea level rise or chronic heat waves. Potential physical risks may cause direct damage to assets and indirect impacts, such as supply chain disruption, changes in water availability, sourcing and quality, which could impact drilling and completion operations. These physical risks could cause increased costs, production disruptions, lower revenues and substantially increase the cost or limit the availability of insurance. We are subject to a number of privacy and data protection laws, rules and directives (collectively, “data protection laws”) relating to the processing of personal data. The regulatory environment surrounding data protection laws is uncertain. Complying with varying jurisdictional requirements could increase the costs and complexity of compliance, and violations of applicable data protection laws can result in significant penalties. A determination that there have been violations of applicable data protection laws could expose us to significant damage awards, fines and other penalties that could materially harm our business and reputation. Any failure, or perceived failure, by us to comply with applicable data protection laws could result in proceedings or actions against us by governmental entities or others, subject us to significant fines, penalties, judgments and negative publicity, require us to change our business practices, increase the costs and complexity of compliance and adversely affect our business. As noted above, we are also subject to the possibility of security and privacy breaches, which themselves may result in a violation of these laws. Additionally, the acquisition of a company that is not in compliance with applicable data protection laws may result in a violation of these laws. Tax law changes could have an adverse effect on our financial position, results of operations and cash flows. Periodically U.S. legislators propose substantive changes to existing federal income tax laws that would repeal many tax incentives and deductions that are currently used by U.S. oil and gas companies and would impose new taxes. Past proposals have included repeal of the percentage depletion allowance for oil and gas properties; elimination of the ability to fully deduct intangible drilling costs in the year incurred; and increase in the geological and geophysical amortization period for independent producers. These proposals have also included general tax law changes to raise tax rates on both domestic and foreign income. Should the U.S. or the states pass tax legislation limiting any currently allowed tax incentives and deductions, our taxes would increase, potentially significantly, which would have a negative impact on our net income and cash flows. This could also reduce our drilling activities in the U.S. Since future changes to federal and state tax legislation and regulations are unknown, we cannot predict the ultimate impact such changes may have on our business. Risks Related to our Corporate Structure Provisions of Delaware law and our bylaws and charter could discourage change-in-control transactions and prevent stockholders from receiving a premium on their investment. Our charter authorizes our Board of Directors to set the terms of preferred stock. In addition, Delaware law contains provisions that impose restrictions on business combinations with interested parties. Our bylaws prohibit the calling of a special meeting by our stockholders and place procedural requirements and limitations on stockholder proposals at meetings of stockholders. Because of these provisions of our charter, bylaws and Delaware law, persons considering unsolicited tender offers or other unilateral takeover proposals may be more likely to negotiate with our Board of Directors rather than pursue non-negotiated takeover attempts. As a result, these provisions may make it more difficult for our stockholders to benefit from transactions that are opposed by an incumbent Board of Directors. 32
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Table of Contents The personal liability of our directors and officers for monetary damages for breach of their fiduciary duty of care is limited by the Delaware General Corporation Law and by our charter. The Delaware General Corporation Law allows corporations to limit available relief for the breach of directors’ or officers’ duty of care to equitable remedies such as injunction or rescission. Our charter limits the liability of our directors and officers to the fullest extent permitted by Delaware law. Specifically, our directors and officers will not be personally liable for monetary damages for any breach of their fiduciary duty, except for liability: • for any breach of their duty of loyalty to the Company or our stockholders; • for acts or omissions not in good faith or that involve intentional misconduct or a knowing violation of law; • for any transaction from which the director or officer derived an improper personal benefit; • solely with respect to directors, under provisions relating to unlawful payments of dividends or unlawful stock repurchases or redemptions; and • solely with respect to officers, for any action by or in the right of the Company. This limitation may have the effect of reducing the likelihood of derivative litigation against directors or officers and may discourage or deter stockholders (or, with respect to directors, management) from bringing a lawsuit against directors or officers, as applicable, for breach of their duty of care, even though such an action, if successful, might otherwise have benefited our stockholders. The exclusive-forum provision contained in our bylaws could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers or other employees. Our bylaws provide that, unless we consent in writing to the selection of an alternative forum, the sole and exclusive forum for (1) any derivative action or proceeding brought on behalf of us, (2) any action asserting a claim of breach of a fiduciary duty owed by any current or former director, officer, other employee or agent of Coterra to Coterra or our stockholders, including a claim alleging the aiding and abetting of such a breach of fiduciary duty, (3) any action asserting a claim arising pursuant to any provision of the Delaware General Corporation Law or our bylaws or charter or (4) any action asserting a claim governed by the internal affairs doctrine or asserting an "internal corporate claim" shall, to the fullest extent permitted by law, be the Court of Chancery of the State of Delaware (or, if the Court of Chancery does not have jurisdiction, the U.S. federal district court for the District of Delaware). To the fullest extent permitted by applicable law, this exclusive-forum provision applies to state and federal law claims, including claims under the federal securities laws, including the Securities Act of 1933, as amended (the “Securities Act”), and the Securities Exchange Act of 1934, as amended (the “Exchange Act”), although our stockholders will not be deemed to have waived our compliance with the federal securities laws and the rules and regulations thereunder. This exclusive-forum provision may limit the ability of a stockholder to bring a claim in a judicial forum of its choosing for disputes with us or our directors, officers or other employees, which may discourage lawsuits against us and our directors, officers and other employees. Alternatively, if a court were to find this exclusive-forum provision inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings described above, we may incur additional costs associated with resolving such matters in other jurisdictions, which could negatively affect our business, results of operations and financial condition. In addition, stockholders who do bring a claim in a state or federal court located within the State of Delaware could face additional litigation costs in pursuing any such claim, particularly if they do not reside in or near Delaware. In addition, the court located in the State of Delaware may reach different judgments or results than would other courts, including courts where a stockholder would otherwise choose to bring the action, and such judgments or results may be more favorable to us than to our stockholders. General Risk Factors The loss of key personnel could adversely affect our ability to operate. Our operations depend on a relatively small group of key management and technical personnel, and one or more of these individuals could leave our employment. The unexpected loss of the services of one or more of these individuals could have a detrimental effect on us. In addition, our drilling success and the success of other activities integral to our operations will depend, in part, on our ability to attract and retain experienced geologists, engineers and other professionals. Competition for experienced geologists, engineers and some other professionals is extremely intense and can be exacerbated following a downturn in which talented professionals leave the industry or when potential new entrants to the industry decide not to 33
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Table of Contents undertake the professional training to enter the industry. If we cannot retain our technical personnel or attract additional experienced technical personnel, our ability to compete could be harmed. Competition in our industry is intense, and many of our competitors have substantially greater financial, technical and personnel resources than we do, which could adversely affect our competitive position. Competition in the oil and natural gas industry is intense. We primarily compete with integrated, independent and other energy companies for the sale and transportation of our oil and natural gas production to pipelines, marketing companies and end users. Major and independent oil and natural gas companies actively bid for desirable oil and gas properties, as well as for the capital, equipment, labor and infrastructure required to operate and develop these properties. Our competitive position is affected by price, contract terms, availability of rigs and completion crews and related equipment and quality of service, including pipeline connection times, distribution efficiencies and reliable delivery record. Many of our competitors have financial, technical and personnel resources and exploration and development budgets that are substantially greater than ours. These companies may be able to pay more for exploratory projects and productive oil and gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may be able to expend greater resources on the existing and changing technologies that we believe will be increasingly important to attaining success in the industry. These companies may also have a greater ability to continue drilling activities during periods of low oil and natural gas prices and to absorb the burden of current and future governmental regulations and taxation. Further, certain of our competitors may engage in bankruptcy proceedings, debt refinancing transactions, management changes or other strategic initiatives in an attempt to reduce operating costs to maintain a position in the market. This could result in such competitors emerging with stronger or healthier balance sheets and in turn an improved ability to compete with us in the future. We have seen and may continue to see corporate consolidations among our competitors, which could significantly alter industry conditions and competition within the industry. Because our activity is concentrated in areas of heavy industry competition, there is heightened demand for equipment, power, services, facilities and resources, resulting in higher costs than in other areas. Such intense competition also could result in delays in securing, or the inability to secure, the equipment, power, services, water or other resources or facilities necessary for our development activities, which could negatively impact our production volumes. In remote areas, vendors also can charge higher rates due to the inability to attract employees to those areas and the vendors’ ability to deploy their resources in easier-to-access areas. The effect of these competitive factors cannot be predicted. The declaration, payment and amounts of future dividends distributed to our stockholders and the repurchase of our common stock will be uncertain. Although we have paid cash dividends on shares of our common stock and have conducted repurchases of our common stock in the past, our Board of Directors may determine not to take such actions in the future or may reduce the amount of dividends or repurchases made in the future. Decisions on whether, when and in which amounts to declare and pay any future dividends, or to authorize and make any repurchases of our common stock, will remain in the discretion of our Board of Directors. We expect that any such decisions will depend on our financial condition, results of operations, cash balances, cash requirements, future prospects, the outlook for commodity prices and other considerations that our Board of Directors deems relevant. ITEM 1B. UNRESOLVED STAFF COMMENTS None. ITEM 1C. CYBERSECURITY Governance Our Board of Directors, with assistance from our Audit Committee and Cybersecurity Steering Committee, oversees our risk management program, which includes technology and cybersecurity risks. Our management team, including our Director - IT Security who reports to our Executive Vice President and Chief Financial Officer, provides periodic updates on risk management, including technology and cybersecurity risk management, to the Audit Committee and to the Board of Directors. Such periodic updates include presentations regarding cybersecurity matters, including any new cybersecurity threats, events, incidents, risks, risk management solutions, trainings or education, strategy pivots, or governance changes. The Audit Committee regularly reports its actions, findings and recommendations to the Board of Directors. The Audit Committee relies in large part on such periodic updates and presentations from our management team in developing its reports to the Board of Directors. 34
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Table of Contents Risk Management and Strategy We maintain a cybersecurity Incident Response Plan (“IRP”) designed to identify, assess, manage, mitigate, and respond to cybersecurity risks, threats and incidents. The IRP was developed in consultation with common cybersecurity frameworks, including the Center for Internet Security (CIS) Critical Security Controls Framework, to provide efficiency, familiarity and consistency in design. As part of our IRP, we have established a Cybersecurity Incident Management Team (“CIMT”), comprised of senior-level executives and management, that defines overall policy and strategy when faced with a cybersecurity incident. The CIMT provides cross-functional and geographical visibility, as well as executive leadership oversight, to address and mitigate associated risks. Among our CIMT, our Executive Vice President and Chief Financial Officer holds the highest level of executive responsibility for assessing and managing cybersecurity threats, incidents, and risks. Our Director - IT Security is responsible for developing and implementing all cybersecurity risk management, strategy, and governance recommendations, and reports to our Executive Vice President and Chief Financial Officer. The CIMT is supported by a dedicated Cybersecurity Incident Response Team (“CIRT”), comprised generally of security and networking team members with responsibilities to monitor and assess events, cybersecurity incidents, and technical activities throughout our organization. Our CIRT members possess critical skill sets, experience, and competencies related to the management of cybersecurity risks and matters. In particular, our Director - IT Security has over 29 years of experience in the field of information systems and cybersecurity and leads an experienced security and networking team with 71 years of additional combined experience in developing and executing cybersecurity strategies. Our CIRT members also hold over 31 certifications in risk and information security from organizations such as International Information System Security Certification Consortium (ISC2), The SANS Institute, Global Information Assurance Certification (GIAC), CompTIA and Cisco, including Certified Information Systems Security Professional (CISSP), GIAC, Certified Incident Handler Certification (GCIH), GIAC Critical Controls Certification (GCCC), GIAC Continuous Monitoring Certification (GMON), SANS Security Awareness Professional (SSAP), Certified Information Security Manager (CISM), Certified in Risk and Information Systems Control (CRISC), and Certified Information Systems Auditor (CISA). Our CIRT is supported by dedicated Information Technology (“IT”) and Operational Technology (“OT”) security resources, and further supported by various external parties, including but not limited to, cybersecurity service providers, assessors, consultants, auditors, and other third parties engaged on an as-needed basis. The CIRT determines whether a cybersecurity incident warrants escalation to the CIMT. In the event of a cybersecurity incident, the IRP describes processes to detect, analyze, contain, eradicate and remediate such incident. These processes include, but are not limited to: • Maintaining an updated inventory and management of digital assets; • Conducting risk assessments to validate our cybersecurity policies, practices, and tools; • Employing appropriate next generation firewalls, endpoint detection and response (EDR) software, identity and access management (IAM), multifactor authentication (MFA), virtual private network (VPN), account change monitoring, encryption, patch management, web content filter, spam filter and reporting, and security information and event management (SIEM) software; • Conducting regular vulnerability scans of our IT and OT infrastructure; • Obtaining and applying vulnerability patches appropriately; • Conducting penetration tests and assessing recommended corrective actions; • Requiring employees to complete a security awareness training program; • Conducting regular phishing simulations and tabletop exercises to test familiarity with cybersecurity policies and procedures; and • Reviewing and evaluating developments in the cyber threat landscape. Our IRP also describes processes to identify material risks from cybersecurity incidents associated with our use of third-party service providers. Currently, we are not aware of any material risks from cybersecurity threats that have materially affected or are reasonably likely to materially affect our operations. However, the nature of potential cybersecurity risks and threats are 35
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Table of Contents uncertain, and any future incidents, outages or breaches could have a material adverse effect on our reputation, business strategy, results of operations or financial condition. ITEM 3. LEGAL PROCEEDINGS Legal Matters We are involved in various legal proceedings incidental to our business. The information set forth under the heading “Legal Matters” in Note 8 of the Notes to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K is incorporated by reference in response to this item. Governmental Proceedings From time-to-time, we receive notices of violation from governmental and regulatory authorities, including notices relating to alleged violations of environmental statutes or the rules and regulations promulgated thereunder. While we cannot predict with certainty whether these notices of violation will result in fines, penalties or both, if fines or penalties are imposed, they may result in monetary sanctions, individually or in the aggregate, in excess of a specified threshold. We have elected to use a $1 million threshold for disclosing governmental proceedings of this nature. We believe proceedings under this threshold are not material to our business and financial condition. In June 2023, we received a Notice of Violation and Opportunity to Confer (“NOVOC”) from the U.S. Environmental Protection Agency (“EPA”) alleging violations of the Clean Air Act, the Texas State Implementation Plan, the New Mexico State Implementation Plan (“NMSIP”) and certain other state and federal regulations pertaining to facilities in Texas and New Mexico. Separately, in July 2023, we received a letter from the U.S. Department of Justice that the EPA has referred this NOVOC for civil enforcement proceedings. In August 2023, we received a second NOVOC from the EPA alleging violations of the Clean Air Act, the NMSIP, and certain other state and federal regulations pertaining to Company facilities in New Mexico. We have exchanged information with the EPA and continue to engage in discussions aimed at resolving the allegations. At this time, we are unable to predict with certainty the financial impact of these NOVOCs or the timing of any resolution. However, any enforcement action related to these NOVOCs will likely result in fines or penalties, or both, and corrective actions, which may increase our development costs or operating costs. We believe that any fines, penalties, or corrective actions that may result from these matters will not have a material effect on our financial position, results of operations, or cash flows. ITEM 4. MINE SAFETY DISCLOSURES Not applicable. INFORMATION ABOUT OUR EXECUTIVE OFFICERS The following table shows certain information as of February 13, 2026 about our executive officers, as such term is defined in Rule 3b-7 of the Securities Exchange Act of 1934. All officers are elected annually by our Board of Directors. Name Age Position Thomas E. Jorden 68 Chairman, Chief Executive Officer and President Shannon E. Young III 54 Executive Vice President and Chief Financial Officer Michael D. DeShazer 40 Executive Vice President — Operations Blake A. Sirgo 43 Executive Vice President — Business Units Andrea M. Alexander 43 Senior Vice President and Chief Human Resources Officer Kevin W. Smith 40 Senior Vice President and Chief Technology Officer Adam M. Vela 52 Senior Vice President and General Counsel Gregory F. Conaway 50 Vice President and Chief Accounting Officer Mr. Jorden was appointed Chief Executive Officer and President of Coterra following the merger with Cimarex Energy Co. (now known as Coterra Energy Operating Co, or “Cimarex”) in October 2021 and Chairman of the Board of Coterra in November 2022. Mr. Jorden previously served as the Chief Executive Officer and President of Cimarex beginning September 2011 and as Chairman of the Board of Directors of Cimarex beginning August 2012. At Cimarex, he began serving as Executive Vice President of Exploration when the company formed in 2002. Prior to the formation of Cimarex, Mr. Jorden held multiple leadership roles at Key Production Company, Inc. (“Key”), which was acquired by Cimarex in 2002. He joined Key in 36
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Table of Contents 1993 as Chief Geophysicist and subsequently became Executive Vice President of Exploration. Before joining Key, Mr. Jorden served at Union Pacific Resources and Superior Oil Company. Mr. Young was appointed Executive Vice President and Chief Financial Officer in July 2023. From 2019 to 2023, Mr. Young served as Executive Vice President and Chief Financial Officer of Talos Energy Inc. Prior to joining Talos Energy Inc., Mr. Young served in similar positions for Sheridan Production Company, LLC, Cobalt International Energy, Inc. and Talos Energy LLC. Mr. Young served as a Managing Director for the Global Energy Group at Goldman, Sachs & Co. from 2010 to 2014 and was an investment banker at Morgan Stanley from 1998 to 2010. Mr. DeShazer was appointed Executive Vice President — Operations in August 2025, having previously served as Executive Vice President — Business Units since April 2025. Mr. DeShazer also served as Senior Vice President of Business Units from May 2024 to April 2025 and Vice President of Business Units from October 2021 to May 2024. Mr. DeShazer joined Cimarex in 2007, serving in various engineering and reservoir manager positions, as well as multiple leadership roles, including Technology Group Manager from 2016 to 2018, Asset Evaluation Team Manager from 2018 to 2019 and Vice President of the Permian Business Unit in 2019. Mr. Sirgo was appointed Executive Vice President — Business Units in August 2025, having previously served as Executive Vice President — Operations since April 2025. Mr. Sirgo also served as Senior Vice President of Operations from October 2022 to April 2025 and as Vice President of Operations from October 2021 to October 2022. Mr. Sirgo joined Cimarex in 2008, serving in a number of technical and leadership roles, including Vice President of Operations from February 2020 to October 2021, Vice President of Operation Resources from November 2018 to February 2020, Permian Division Production Manager from June 2016 to November 2018, and in various engineering and production manager positions. Before joining Cimarex, Mr. Sirgo worked at Occidental Petroleum. Ms. Alexander was appointed Senior Vice President and Chief Human Resources Officer in July 2023. Ms. Alexander served as Chief People Officer at Rent the Runway from June 2021 to July 2023. Ms. Alexander served in various roles of increasing responsibility, including Associate Partner and Professional Development Manager, at McKinsey & Company, a management consulting company, from 2009 to 2021. Mr. Smith was appointed Senior Vice President and Chief Technology Officer in May 2024. Mr. Smith previously served as Vice President and Chief Technology Officer following the merger with Cimarex in October 2021. Mr. Smith began his career with Cimarex in 2007, serving in a number of technical and leadership roles, including Director of Technology and Anadarko Exploration Region Manager. In September 2020, Mr. Smith assumed the role of Chief Engineer for Cimarex. Mr. Vela was appointed Senior Vice President and General Counsel in August 2023. Mr. Vela previously served as Vice President and General Counsel since October 2022. Mr. Vela previously served in various capacities at Coterra and Cimarex beginning in 2005, including Vice President, Assistant General Counsel, Chief Litigation Counsel and Corporate Counsel. Mr. Vela is a member of the Texas, Colorado, American and Houston Hispanic Bar associations, as well as the Foundation for Natural Resources and Energy Law. Mr. Conaway was appointed Vice President and Chief Accounting Officer in September 2025 after joining Coterra in August 2025 as Vice President - Accounting. Prior to joining Coterra in 2025, Mr. Conaway was the Chief Accounting Officer of Acuren Corporation, a global inspection, certification and compliance engineering services firm, from November 2024 to April 2025, and as Vice President and Chief Accounting officer of Callon Petroleum Operating Co., an independent oil and natural gas company from January 2020 to March 2024. Mr. Conaway is a Certified Public Accountant in the state of Texas. 37
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Table of Contents PART II ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES Our $0.10 par value common stock is listed and principally traded on the NYSE under the ticker symbol “CTRA.” Cash dividends were paid to our common stockholders in each quarter of 2025. Future dividend payments will depend on the Company’s level of earnings, financial requirements and other factors considered relevant by our Board of Directors. As of February 13, 2026, there were 834 registered holders of our common stock. ISSUER PURCHASES OF EQUITY SECURITIES In February 2023, our Board of Directors approved a new share repurchase program that authorizes us to purchase up to $2.0 billion of our common stock in the open market or in negotiated transactions. During the quarter ended December 31, 2025, we purchased 4 million shares of common stock for $93 million, bringing our total repurchases in 2025 to 6 million shares of common stock at a total cost of $140 million. As of December 31, 2025, we were authorized to repurchase up to approximately an additional $1.0 billion of our outstanding common stock. The following table sets forth information regarding repurchases of our common stock during the quarter ended December 31, 2025. Period Total Number of Shares Purchased (In thousands) Average Price Paid per Share Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (In thousands) Maximum Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (In millions) October 2025 2,316 $ 23.39 2,316 $ 1,024 November 2025 — — — $ 1,024 December 2025 1,506 $ 25.88 1,506 $ 985 Total 3,822 3,822 _______________________________________________________________________________ (1) All purchases during the covered periods were made under the share repurchase program, which was approved by our Board of Directors in February 2023 and which authorized the repurchase of up to $2.0 billion of our common stock. The share repurchase program does not have an expiration date. Purchases were made under terms intended to qualify for exemption under Rules 10b-18 and 10b5-1. (2) Includes 114,256 shares that were repurchased prior to December 31, 2025 and settled in January 2026. ITEM 6. [RESERVED] ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following discussion and analysis are based on management’s perspective and are intended to assist you in understanding our results of operations and our present financial condition and outlook. Our Consolidated Financial Statements and the accompanying Notes to the Consolidated Financial Statements included elsewhere in this Annual Report on Form 10-K contain additional information that should be referenced when reviewing this material. This discussion and analysis also include forward-looking statements. Readers are cautioned that such forward-looking statements are based on current expectations and assumptions that involve a number of risks and uncertainties, including those described under “Forward-Looking Statements” in Part I of this report and “Risk Factors” in Part I, Item 1A of this report, which could cause actual results to differ materially from those included in this report. (1) (2) 38
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Table of Contents OVERVIEW Financial and Operating Overview Financial and operating results for the year ended December 31, 2025 compared to the year ended December 31, 2024 reflect the following: • Net income increased $596 million from $1.1 billion, or $1.51 per share, in 2024 to $1.7 billion, or $2.25 per share, in 2025. • Net cash provided by operating activities increased $1.2 billion, from $2.8 billion, in 2024 to $4.0 billion in 2025. • Oil equivalent production increased 38.0 MMBoe from 247.6 MMBoe, or 676.5 MBoe per day, in 2024 to 285.6 MMBoe, or 782.4 MBoe per day, in 2025. ◦ Oil production increased 18.6 MMBbl from 39.8 MMBbl, or 109 MBbl per day, in 2024 to 58.4 MMBbl, or 160 MBbl per day, in 2025. ◦ Natural gas production increased 61.1 Bcf from 1,024.7 Bcf, or 2,800 MMcf per day, in 2024 to 1,085.8 Bcf, or 2,975 MMcf per day, in 2025. ◦ NGL volumes increased 9.2 MMBbl from 37.0 MMBbl, or 101 MBbl per day, in 2024 to 46.2 MMBbl, or 127 MBbl per day, in 2025. • Average realized prices (including impact of derivatives): ◦ Oil was $64.35 per Bbl in 2025, 13 percent lower than the $74.22 per Bbl price realized in 2024. ◦ Natural gas was $2.47 per Mcf in 2025, 41 percent higher than the $1.75 per Mcf price realized in 2024. ◦ NGL price for 2025 was $18.24 per Bbl, 9 percent lower than the $19.95 per Bbl price realized in 2024. • Total capital expenditures for drilling, completion and other fixed assets were $2.3 billion in 2025 compared to $1.8 billion in 2024. Other financial highlights for the year ended December 31, 2025 include the following: • Closed two acquisitions in January 2025 in the Delaware Basin for total consideration of $3.3 billion in cash and the issuance of 28,190,682 shares of our common stock valued at $785 million based on the closing price of our common stock on the closing date of the transactions. • Increased our quarterly dividend from $0.21 per share to $0.22 per share in February 2025. • Repaid the full $500 million of the Tranche A Term Loan and repaid $200 million of the Tranche B Term Loan. In February 2026, we repaid the remaining $300 million of the Tranche B Term Loan. • Repurchased 6 million shares of our common stock during 2025 for $140 million. Market Conditions and Commodity Prices Our financial results depend on many factors, particularly commodity prices and our ability to find and develop oil and gas reserves and market our production on economically attractive terms. Commodity prices are affected by many factors outside of our control, including changes in market supply and demand, which can be impacted by pipeline capacity constraints, inventory storage levels, basis differentials, weather conditions, and geopolitical, economic and other factors. While oil prices were relatively steady throughout 2024, prices declined in 2025 overall compared to 2024. Various commentators and agencies (including the International Energy Agency) forecast larger global supply inventories compared to 2025 and growing global production, particularly from non-OPEC producers. Forecasts for growing global oil demand are subject to volatile market conditions, including ongoing shifts in U.S. and international trade policy, as well as geopolitical risk and uncertainty related to the ongoing Russia- Ukraine war, conflict in the Middle East and U.S. intervention in Venezuela. The impacts of these changes remain to be seen. Natural gas prices rose in early 2025, trended downward through early fourth quarter, and recovered somewhat heading into 2026, driven in part by lower natural gas power burns in the first and second quarter and record high domestic production. 39
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Heading into 2026, forward pricing for natural gas prices has increased, in part as a result of anticipated colder temperatures, shifting weather models, and expected growing LNG demand. Additionally, increasing power generation opportunities for natural gas, both from demands from electric grids fueled by natural gas-power generation and off-grid demand related to datacenter growth, is anticipated to buoy natural gas prices. While basis differentials have persisted in the U.S., with prices at the Waha Hub in the Permian Basin reaching negative spot pricing at various times throughout 2025 and early 2026 due to oversupply and maintenance, we expect that additional pipeline capacity coming online beginning in late 2026 will alleviate the spread on basis differentials for natural gas. We continue to expect natural gas prices overall to be stronger in 2026 compared to 2025. Although the current outlook on oil and natural gas prices is generally favorable, and our operations have not been significantly impacted in the short-term, in the event further disruptions occur or the current market volatility and U.S. and international economic policy uncertainty continues for an extended period of time, our operations could be adversely impacted, commodity prices could decline and our costs may increase. We expect commodity price volatility to continue, including as a result of U.S. and international economic policy (such as tariffs or retaliatory tariffs), actions of OPEC+ (including the ability of OPEC+ to successfully coordinate production quotas) and potentially swift near- and medium-term fluctuations in supply and demand, such as potential changes to drilling and capital programs in the short-term by U.S. producers. While we are unable to predict future commodity prices, at current oil, natural gas and NGL price levels, we do not believe that animpairment of our oil and gas properties is reasonably likely to occur in the near future. However, in the event that commodity prices significantly decline or costs significantly increase from current levels, our management would evaluate the recoverability of the carrying value of our oil and gas properties. For information about the impact of realized commodity prices on our revenues, refer to “Results of Operations” below. FINANCIAL CONDITION Liquidity and Capital Resources We strive to maintain an adequate liquidity level to address commodity price volatility and risk. Our liquidity requirements consist primarily of our planned capital expenditures, payment of contractual obligations (including debt maturities and interest payments), working capital requirements, dividend payments and share repurchases. Although we have no obligation to do so, we may also from time-to-time refinance or retire our outstanding debt through privately negotiated transactions, open market repurchases, redemptions, exchanges, tender offers or otherwise. Our primary sources of liquidity are cash on hand, net cash provided by operating activities and available borrowing capacity under our revolving credit agreement. Our liquidity requirements are generally funded with cash flows provided by operating activities, together with cash on hand and draws under our revolving credit agreement. However, from time-to-time, our investments may be funded by sales of assets and private or public financing based on our monitoring of capital markets and our balance sheet. While there are no “rating triggers” in any of our debt agreements that would accelerate the scheduled maturities should our debt rating fall below a certain level, a change in our debt rating could adversely impact our interest rate on any borrowings under our revolving credit agreement and our ability to economically access debt markets and could trigger the requirement to post credit support under various agreements, which could reduce the borrowing capacity under our revolving credit agreement. As of the date hereof, our debt is currently rated as investment grade by the three leading rating agencies. For more on the impact of credit ratings on our interest rates and fees for unused commitments under our revolving credit agreement, see Note 4 of the Notes to the Consolidated Financial Statements, “Long-Term Debt and Credit Agreements.” We believe that, with operating cash flow, cash on hand and availability under our revolving credit agreement, we have the ability to finance our spending plans over the next twelve months and, based on current expectations, for the longer term. Our working capital is substantially influenced by the variables discussed above and fluctuates based on the timing and amount of borrowings and repayments under our revolving credit agreement, borrowings and repayments of debt, the timing of cash collections and payments on our trade accounts receivable and payable, respectively, payment of dividends, repurchases of our securities and changes in the fair value of our commodity derivative activity. From time-to-time, our working capital will reflect a deficit, while at other times it will reflect a surplus. This fluctuation is not unusual. As of December 31, 2025, our working capital surplus of $292 million was lower than prior year, primarily due to a lower cash position as a result of funding the purchase price of the FME and Avant acquisitions that closed in January 2025, the full repayment of the Tranche A Term Loan of $500 million in 2025 and the partial repayment of the Tranche B Term Loan of $200 million in 2025. Additionally, we reclassified our 3.77% private placement senior notes due in September 2026 to current debt during the third quarter of 2025. As of December 31, 2024, we had a working capital surplus of $2.2 billion. We believe we have adequate liquidity and availability under our revolving credit agreement as outlined above to meet our working capital requirements and debt repayments over the next 12 months. 40
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Table of Contents As of December 31, 2025, we had unrestricted cash on hand of $114 million and unused commitments of $2.0 billion under our revolving credit agreement. Our revolving credit agreement and term loan include a covenant potentially limiting our borrowing capacity as determined by our leverage ratio. As of December 31, 2025, we were in compliance with all financial covenants applicable to our revolving credit agreement, term loan and private placement senior notes. Refer to Note 4 of the Notes to the Consolidated Financial Statements, “Long-Term Debt and Credit Agreements,” for further details (including our restrictive covenants and required financial ratio). Cash Flows Our cash flows from operating activities, investing activities and financing activities are as follows: Year Ended December 31, (In millions) 2025 2024 2023 Cash flows provided by operating activities $ 4,021 $ 2,795 $ 3,658 Cash flows used in investing activities (5,628) (1,762) (2,059) Cash flows (used in) provided by financing activities (551) 279 (1,317) 2025 and 2024 Compared Operating Activities. Operating cash flow fluctuations are substantially driven by changes in commodity prices, production volumes and operating expenses. As discussed above, commodity prices have historically been volatile. Fluctuations in cash flow may result in an increase or decrease in our planned capital expenditures. Net cash provided by operating activities increased by $1.2 billion in 2025 compared to 2024. This increase was primarily due to higher oil, natural gas and NGL revenues driven by significantly higher natural gas prices and higher production from our legacy properties in the Permian and Anadarko Basins and our FME and Avant acquisitions that closed in January 2025. These increases were partially offset by an increase in operating costs largely due to our FME and Avant acquisitions in 2025. Refer to “Results of Operations” for additional information relative to commodity price, production and operating expense fluctuations. We are unable to predict future commodity prices and, as a result, cannot provide any assurance about future levels of net cash provided by operating activities. Investing Activities. Cash flows used in investing activities increased by $3.9 billion in 2025 compared to 2024. This increase was primarily due to $3.2 billion of net cash consideration paid for business combinations and $616 million of higher cash paid for capital expenditures in 2025 compared to 2024. Financing Activities. Cash flows used in financing activities increased by $830 million in 2025 compared to 2024. The increase was primarily due to the repayment of the $500 million Tranche A Term Loan in 2025, the partial repayment of $200 million of the Tranche B Term Loan in 2025 and the repayment of $746 million of borrowings under our revolver during 2025, compared to the repayment of $575 million of 3.65% weighted-average senior notes at their maturity in September 2024. Additionally, we had lower proceeds from the issuance of debt due to the funding of our term loan and borrowings under our revolver during 2025, compared to the issuance of $500 million of 5.60% senior notes in March 2024 and $750 million of 5.40% senior notes and $750 million of 5.90% senior notes in December 2024. These increases were partially offset by $314 million lower stock repurchases in 2025 compared to 2024. Subsequent Event. In February 2026, we repaid the remaining $300 million of the Tranche B Term Loan. 2024 and 2023 Compared. For information on the comparison of operating, investing, and financing cash flows for the year ended December 31, 2024 compared to the year ended December 31, 2023, refer to Financial Condition (Cash Flows) included in the Coterra Energy Inc. Annual Report on Form 10-K for the year ended December 31, 2024, which information in incorporated by reference herein. Term Loan In December 2024, we entered into a delayed draw term loan credit agreement with Toronto Dominion (Texas), LLC, as administrative agent, and certain other lenders and issuing banks (the “Term Loan”), which consists of a $500 million Tranche A Term Loan and a $500 million Tranche B Term Loan. The Tranche A Term Loan matures two years after funding, and the Tranche B Term Loan matures three years after funding. Borrowings under the Term Loan can be prepaid without penalty. In January 2025, we borrowed $500 million under the Tranche A Term Loan to partially fund the acquisition of the FME Interests 41
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Table of Contents and $500 million of the Tranche B Term Loan to partially fund the acquisition of the Avant assets. During 2025, we repaid the full $500 million of the Tranche A Term Loan and $200 million of the Tranche B Term Loan. Borrowings under the Term Loan bear interest at a rate per annum equal to, at our option, either a term secured overnight financing rate (“SOFR”) plus a 0.10 percent credit spread adjustment for all tenors or a base rate, plus an interest rate margin which ranges from 0 to 75 basis points for base rate loans, 100 to 175 basis points for Tranche A SOFR Term Loans and 112.5 to 187.5 basis points for Tranche B SOFR Term Loans based on our credit rating. The Term Loan contains customary covenants, including the maintenance of a maximum leverage ratio of no more than 3.0 to 1.0 as of the last day of any fiscal quarter until such time as we have no other debt (other than our Credit Agreement as defined below) in a principal amount in excess of $75 million outstanding that has a financial maintenance covenant based on a leverage ratio, at which time the Term Loan requires maintenance of a ratio of total net debt to total capitalization of no more than 65 percent (with all calculations based on definitions contained in the Term Loan). At December 31, 2025, we were in compliance with all financial covenants and had $300 million of outstanding borrowings under our Term Loan. Revolving Credit Agreement In September 2024, we entered into Amendment No. 1 (the “Amendment”) relating to our revolving credit agreement with JPMorgan Chase Bank, N.A., as administrative agent, and certain lenders and issuing banks party thereto (as amended by the Amendment, and further amended, supplemented or otherwise modified from time-to-time, the “Credit Agreement”). The Amendment increased the aggregate revolving commitments under the Credit Agreement from $1.5 billion to $2.0 billion, extended the Credit Agreement maturity date from March 10, 2028 to September 12, 2029, made certain amendments to the representations and warranties, affirmative and negative covenants and events of default, and made certain other modifications. Borrowings under the Credit Agreement bear interest at a rate per annum equal to, at our option, (i) either a term secured overnight financing rate (“SOFR”) plus a 0.10 percent credit spread adjustment for all tenors or (ii) a base rate, plus, in each case, an interest rate margin which ranges from 0 to 75 basis points for base rate loans and 100 to 175 basis points for term SOFR loans, based on our credit rating. The maturity date of the Credit Agreement can be extended for additional one-year periods on up to two occasions upon the agreement of lenders holding at least 50 percent of the commitments under the Credit Agreement and us. The Credit Agreement includes certain customary covenants, including the maintenance of a maximum leverage ratio of no more than 3.0 to 1.0 as of the last day of any fiscal quarter. At such time as we have no other debt in a principal amount in excess of $75 million outstanding that has a financial maintenance covenant based on a substantially similar leverage ratio, in lieu of such maximum leverage ratio covenant, the Credit Agreement will instead require us to maintain a ratio of total net debt to total capitalization of no more than 65 percent (with all calculations based on definitions contained in the Credit Agreement). At December 31, 2025, we were in compliance with all financial covenants and had $2.0 billion of borrowing capacity under our Credit Agreement. Certain Restrictive Covenants Our ability to incur debt, incur liens, enter into mergers, sell assets, enter into transactions with affiliates, and engage in certain other activities are subject to certain restrictive covenants in our various debt instruments. In addition, the senior note agreement governing various series of senior notes that were issued in a private placement (the “private placement senior notes”) requires us to maintain a minimum annual coverage ratio of consolidated cash flow to interest expense for the trailing four quarters of not less than 2.8 to 1.0 and requires us to maintain, as of the last day of any fiscal quarter, a maximum ratio of total debt to consolidated EBITDAX for the trailing four quarters of not more than 3.0 to 1.0. At December 31, 2025, we were in compliance with all financial covenants in our private placement senior notes. Refer to Note 4 of the Notes to the Consolidated Financial Statements, “Long-Term Debt and Credit Agreements,” for further details regarding the interest rate on future borrowings under our Credit Agreement and Term Loan, as well as information regarding our restrictive covenants, including our leverage ratio. 42
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Table of Contents Capitalization Information about our capitalization is as follows: December 31, (Dollars in millions) 2025 2024 Total debt $ 3,818 $ 3,535 Stockholders' equity 14,838 13,122 Total capitalization $ 18,656 $ 16,657 Debt to total capitalization 20% 21% Cash and cash equivalents $ 114 $ 2,038 _______________________________________________________________________________ (1) Includes $250 million of current portion of long-term debt as of December 31, 2025. There were no borrowings outstanding under our Credit Agreement as of December 31, 2025 or December 31, 2024. Share repurchases. In February 2023, our Board of Directors approved a share repurchase program which authorizes the purchase of up to $2.0 billion of our common stock in the open market or in negotiated transactions. During the year ended December 31, 2025, we repurchased and retired 6 million shares of our common stock for $140 million. We repurchased and retired 17 million shares of common stock for $464 million during the year ended December 31, 2024. During the year ended December 31, 2024, 351,791 shares of common stock were recorded as treasury stock and retired related to common shares that were retained from vested restricted stock awards for withholding of taxes. Dividends. In February 2024 and 2025, our Board of Directors approved an increase in the quarterly dividend from $0.20 per share to $0.21 per share beginning in the first quarter of 2024 and from $0.21 per share to $0.22 per share beginning in the first quarter of 2025, respectively. The following table presents our dividends paid on our common stock for the year ended December 31, 2025 and 2024. Rate per share Total Dividends (In millions) 2025 $ 0.88 $ 680 2024 $ 0.84 $ 630 Capital and Exploration Expenditures On an annual basis, we generally fund most of our capital expenditures, excluding any significant property acquisitions, with cash generated from operations and, if required, borrowings under our revolving credit agreement. We budget these expenditures based on our projected cash flows for the year. (1) 43
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Table of Contents The following table presents major components of our capital and exploration expenditures: Year Ended December 31, (In millions) 2025 2024 2023 Acquisitions (business combinations) Proved oil and gas properties $ 2,473 $ — $ — Unproved oil and gas properties 1,286 — — Gathering and pipeline systems 333 — — Total $ 4,092 $ — $ — Capital expenditures Drilling and facilities $ 2,151 $ 1,645 $ 1,979 Pipeline and gathering 124 103 91 Other 43 14 34 Capital expenditures for drilling, completion and other fixed asset additions 2,318 1,762 2,104 Capital expenditures for leasehold and property acquisitions 99 19 10 Exploration expenditures 27 25 20 Total $ 2,444 $ 1,806 $ 2,134 _______________________________________________________________________________ (1) Exploration expenditures include $5 million of exploratory dry hole costs in 2024. There were no exploratory dry hole costs in 2025 and 2023. In 2025, our capital program focused on the Permian Basin, Marcellus Shale, and Anadarko Basin, where we drilled 384 gross wells (203.3 net) and completed 399 gross wells (198.3 net), of which 90 gross wells (57.6 net) were drilled but uncompleted in prior years. Our 2026 full year capital program is expected to be in the range of approximately $2.175 billion to $2.325 billion. We expect to turn-in- line 174 to 208 total net wells in 2026 across our three operating regions. Approximately 68 percent of capital expenditures will be invested in the Permian Basin, 16 percent in the Marcellus Shale, eight percent in the Anadarko Basin and remaining eight percent for gathering systems infrastructure, saltwater disposal and other spend. We will continue to assess the commodity price environment and may increase or decrease our capital expenditures accordingly. Contractual Obligations We have various contractual obligations in the normal course of our operations. As of December 31, 2025, our material contractual obligations include debt and related interest expense, gathering, processing and transportation agreements, lease obligations, operational agreements, drilling and completion obligations, derivative obligations and asset retirement obligations. Other joint owners in the properties operated by us could incur a portion of these costs. We expect that our sources of capital will be adequate to fund these obligations. Refer to the Notes to the Consolidated Financial Statements included in Item 8 of this Annual Report for further details. We enter into arrangements that can give rise to material off-balance sheet obligations. As of December 31, 2025, the material off- balance sheet arrangements we had entered into included certain firm gathering, processing and transportation commitments and operating lease agreements with terms at commencement of less than 12 months for equipment used in our exploration and development activities. We have no other off-balance sheet debt or other similar unrecorded obligations. (1) 44
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Table of Contents RESULTS OF OPERATIONS 2025 and 2024 Compared Operating Revenues Year Ended December 31, Variance (In millions) 2025 2024 Amount Percent Oil $ 3,699 $ 2,953 $ 746 25 % Natural gas 2,633 1,693 940 56 % NGL 844 738 106 14 % Gain (loss) on derivative instruments 351 (3) 354 11,800 % Other 118 77 41 53 % $ 7,645 $ 5,458 $ 2,187 40 % Production Revenues Our production revenues are derived from sales of our oil, natural gas and NGL production. Increases or decreases in our revenues, profitability and future production growth are highly dependent on the commodity prices we receive, which, as discussed above, fluctuate due to a variety of factors (including supply and demand, the availability of transportation, seasonality and geopolitical, economic and other factors). Oil Revenues Year Ended December 31, Variance Increase (Decrease)(In millions) 2025 2024 Amount Percent Volume (MMBbl) 58.4 39.8 18.6 47% $ 1,377 Price ($/Bbl) $ 63.36 $ 74.18 $ (10.82) (15)% (631) Total $ 746 Oil revenues increased $746 million primarily due to increased production in the Permian Basin, partially offset by lower oil prices. Production increased due to the FME and Avant acquisitions in the Permian Basin that closed in January 2025 and higher production from our legacy properties. Natural Gas Revenues Year Ended December 31, Variance Increase (Decrease)(In millions) 2025 2024 Amount Percent Volume (Bcf) 1,085.8 1,024.7 61.1 6 % $ 101 Price ($/Mcf) $ 2.43 $ 1.65 $ 0.78 47 % 839 Total $ 940 Natural gas revenues increased $940 million primarily due to significantly higher natural gas prices and higher production. Production increased due to the FME and Avant acquisitions in the Permian Basin that closed in January 2025 and higher production from our legacy properties in the Permian and Anadarko Basins. This increase was partially offset by lower production in the Marcellus Shale. NGL Revenues Year Ended December 31, Variance Increase (Decrease)(In millions) 2025 2024 Amount Percent Volume (MMBbl) 46.2 37.0 9.2 25 % $ 185 Price ($/Bbl) $ 18.24 $ 19.95 $ (1.71) (9)% (79) Total $ 106 NGL revenues increased $106 million primarily due to higher NGL volumes in the Permian Basin and Anadarko Basin, partially offset by lower NGL prices. 45
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Table of Contents Gain (Loss) on Derivative Instruments, Net Net gains and losses on our derivative instruments are a function of fluctuations in the underlying commodity index prices as compared to the contracted prices and the monthly cash settlements (if any) of the derivative instruments. We have elected not to designate our derivatives as hedging instruments for accounting purposes and, therefore, we do not apply hedge accounting treatment to our derivative instruments. Consequently, changes in the fair value of our derivative instruments and cash settlements are included as a component of operating revenues as either a net gain or loss on derivative instruments. Cash settlements of our contracts are included in cash flows from operating activities in our statement of cash flows. The following table presents the components of “Gain (loss) on derivative instruments, net” for the years indicated: Year Ended December 31, (In millions) 2025 2024 Cash received on settlement of derivative instruments Oil contracts $ 57 $ 2 Gas contracts 49 96 Non-cash gain (loss) on derivative instruments Oil contracts 82 (21) Gas contracts 163 (80) $ 351 $ (3) Operating Costs and Expenses Costs associated with producing oil and natural gas are substantial. Among other factors, some of these costs vary with commodity prices, some trend with volume and commodity mix, some are a function of the number of wells we own and operate, some depend on the prices charged by service companies, and some fluctuate based on a combination of the foregoing. Our costs for services, labor and supplies have modestly declined driven by lower industry activity levels and current oil prices. These savings are being partially offset by tariff impacts that many vendors have faced. In January 2025 with the completion of the FME and Avant acquisitions, we expanded our operations in the Permian Basin. The following table reflects our operating costs and expenses for the years indicated and a discussion of the operating costs and expenses follows. Year Ended December 31, Variance Per Boe (In millions, except per Boe) 2025 2024 Amount Percent 2025 2024 Operating Expenses Direct operations $ 1,023 $ 658 $ 365 55 % $ 3.58 $ 2.66 Gathering, processing and transportation 1,089 976 113 12 % 3.81 3.94 Taxes other than income 366 271 95 35 % 1.28 1.09 Exploration 27 25 2 8 % 0.09 0.10 Depreciation, depletion and amortization 2,370 1,840 530 29 % 8.30 7.43 General and administrative 323 302 21 7 % 1.13 1.22 $ 5,198 $ 4,072 $ 1,126 28 % Direct Operations Direct operations generally consist of costs for labor, equipment, maintenance, saltwater disposal, compression, power, treating and miscellaneous other costs (collectively, “lease operating expense”). Direct operations also include workover activity necessary to maintain production from existing wells. 46
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Table of Contents Direct operations consisted of lease operating expense and workover expense as follows: Year Ended December 31, Per Boe (In millions, except per Boe) 2025 2024 Variance 2025 2024 Direct Operations Lease operating expense $ 827 $ 554 $ 273 $ 2.89 $ 2.24 Workover expense 196 104 92 0.69 0.42 $ 1,023 $ 658 $ 365 $ 3.58 $ 2.66 Lease operating expense increased primarily due to increased production levels and higher costs in the Permian Basin driven in part by the FME and Avant acquisitions in the Permian Basin that closed in January 2025, which have higher lifting costs than our legacy wells. Workover expense increased $92 million primarily due to increased expenses related to higher workover activity in the Permian Basin, partially offset by lower workover activity in the Marcellus Shale due to reduced activity in the basin. Gathering, Processing and Transportation Gathering, processing and transportation costs principally consist of expenditures to prepare and transport production downstream from the wellhead, including gathering, fuel, and compression, along with processing costs, which are incurred to extract NGLs from the raw natural gas stream. Gathering costs also include costs associated with operating our gas gathering infrastructure, including operating and maintenance expenses. Costs vary by operating area and will fluctuate with increases or decreases in production volumes, contractual fees, and changes in fuel and compression costs. Gathering, processing and transportation increased $113 million primarily due to higher production due to the FME and Avant acquisitions in the Permian Basin that closed in January 2025 and higher production from our legacy properties in the Permian and Anadarko Basins. Taxes Other Than Income Taxes other than income consist of production (or severance) taxes, drilling impact fees, ad valorem taxes and other taxes. State and local taxing authorities assess these taxes, with production taxes being based on the volume or value of production, drilling impact fees being based on drilling activities and prevailing natural gas prices and ad valorem taxes being based on the value of properties. The following table presents taxes other than income for the years indicated: Year Ended December 31, (In millions) 2025 2024 Variance Taxes Other than Income Production $ 303 $ 217 $ 86 Drilling impact fees 23 17 6 Ad valorem 39 35 4 Other 1 2 (1) $ 366 $ 271 $ 95 Production taxes as a percentage of revenue (Permian and Anadarko Basins) 6.1 % 5.6 % Taxes other than income increased $95 million primarily due to an increase in our production taxes related to higher production as a result of the FME and Avant acquisitions in the Permian Basin that closed in January 2025 and higher production from our legacy properties in the Permian and Anadarko Basins. The production tax rate increased as a result of higher production mix from properties in areas with higher production tax rates. Additionally, drilling impact fees increased primarily due to increased drilling activity in the Marcellus Shale and higher natural gas prices during 2025 compared to 2024. 47
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Table of Contents Depreciation, Depletion and Amortization DD&A expense consisted of the following for the periods indicated: Year Ended December 31, Per Boe (In millions, except per Boe) 2025 2024 Variance 2025 2024 DD&A Expense Depletion $ 2,202 $ 1,707 $ 495 $ 7.71 $ 6.89 Depreciation 93 73 20 0.31 0.30 Amortization of unproved properties 62 49 13 0.23 0.20 Accretion of ARO 13 11 2 0.05 0.04 $ 2,370 $ 1,840 $ 530 $ 8.30 $ 7.43 Depletion of our producing properties is computed on a field basis using the unit-of-production method under the successful efforts method of accounting. The economic life of each producing property depends upon the estimated proved reserves for that property, which in turn depends upon the assumed realized sales price for future production. Therefore, fluctuations in oil and natural gas prices will impact the level of proved developed and proved reserves used in the calculation. Higher prices generally have the effect of increasing reserves, which reduces depletion expense. Conversely, lower prices generally have the effect of decreasing reserves, which increases depletion expense. The cost of replacing production also impacts our depletion expense. In addition, changes in estimates of reserve quantities, estimates of operating and future development costs, reclassifications of properties from unproved to proved and impairments of oil and gas properties will also impact depletion expense. Our depletion expense increased $495 million primarily due to a higher depletion rate and an increase in production. Our depletion rate increased primarily due to the increase in value of our oil and gas properties related to assets acquired from FME and Avant, which were recorded at fair value. The depletion rate also increased due to a shift in our production mix to fields with higher depletion rates. Fixed assets consist primarily of gas gathering facilities, water infrastructure, buildings, vehicles, aircraft, furniture and fixtures and computer equipment and software. These items are recorded at cost and are depreciated on the straight-line method based on expected lives of the individual assets, which range from three to 30 years. Depreciation expense increased $20 million primarily due to fixed assets acquired from FME and Avant. This increase was partially offset by a decrease in the depreciation of the right-of-use asset associated with our finance lease gathering system, which ended in the third quarter of 2025. Unproved properties are amortized based on our drilling experience and our expectation of converting our unproved leaseholds to proved properties. The rate of amortization depends on the timing and success of our exploration and development program. If development of unproved properties is deemed unsuccessful, and the properties are abandoned or surrendered, the capitalized costs are expensed in the period the determination is made. Our amortization of unproved properties increased $13 million due to unproved properties acquired from FME and Avant. General and Administrative G&A expense consists primarily of salaries and related benefits, stock-based compensation, office rent, legal and consulting fees, systems costs and other administrative costs incurred. The table below reflects our G&A expense for the periods identified: Year Ended December 31, (In millions) 2025 2024 Variance G&A Expense General and administrative expense $ 260 $ 240 $ 20 Stock-based compensation expense 63 62 1 $ 323 $ 302 $ 21 G&A expense, excluding stock-based compensation, increased $20 million primarily due to an increase in legal and professional expenses and acquisition and transition costs associated with the FME and Avant acquisitions completed in January 2025, partially offset by the recognition of certain long-term commitments for community outreach and charitable contributions in 2024. 48
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Table of Contents Stock-based compensation expense will fluctuate based on the grant date fair value of awards, the number of awards, the requisite service period of the awards, estimated employee forfeitures, and the timing of the awards. Interest Expense The table below reflects our interest expense, net for the periods indicated: Year Ended December 31, (In millions) 2025 2024 Variance Interest Expense Interest expense $ 211 $ 101 $ 110 Debt premium and discount amortization, net (21) (21) — Debt issuance cost amortization 6 9 (3) Other 9 17 (8) $ 205 $ 106 $ 99 Interest expense increased $99 million primarily due to an increase of $110 million related to interest on debt balances. This increase was primarily due to the issuance of $500 million of 5.60% senior notes in March 2024, $750 million of 5.40% senior notes in December 2024, $750 million of 5.90% senior notes in December 2024 and $1.0 billion of term loans issued in January 2025 to partially fund the FME and Avant acquisitions. This increase was partially offset by decreases related to repayments of $575 million related to the 3.65% weighted- average private placement senior notes in September 2024 and repayments of $700 million of our term loans in 2025. Interest Income Interest income decreased $48 million primarily due to lower cash balances during 2025 compared to 2024 and a decrease in interest earned on our higher interest rate short-term investment balances that matured in September 2024. Income Tax Expense Year Ended December 31, (In millions) 2025 2024 Variance Income Tax Expense Current tax expense $ 111 $ 369 $ (258) Deferred tax expense (benefit) 435 (145) 580 $ 546 $ 224 $ 322 Combined federal and state effective income tax rate 24.1 % 16.7 % Income tax expense increased $322 million primarily due to higher pre-tax income and a higher effective tax rate. The effective tax rate increased due to differences in the non-recurring discrete items recorded during 2025 compared to 2024. 2024 and 2023 Compared For information on the comparison of the results of operations for the year ended December 31, 2024 compared to the year ended December 31, 2023, refer to Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the Coterra Energy Inc. Annual Report on Form 10-K for the year ended December 31, 2024, which information is incorporated by reference herein. Critical Accounting Policies and Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities as of the date of the balance sheet, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates, and changes in our estimates are recorded when known. We consider the following to be our most critical estimates that involve judgment of management. 49
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Table of Contents Purchase Accounting From time-to-time, we may acquire assets and assume liabilities in transactions accounted for as business combinations, such as the FME and Avant Acquisitions. In connection with these acquisitions, we allocated $4.0 billion of purchase price consideration to the assets acquired and liabilities assumed based on estimated fair values as of the effective dates of the acquisitions. The purchase price allocations are complete as of December 31, 2025. We made a number of assumptions in estimating the fair value of assets acquired and liabilities assumed in the acquisitions. The most significant assumptions related to the fair value estimates of proved and unproved oil and gas properties, which were recorded at a fair value of $3.8 billion. Since sufficient market data was not available regarding the fair values of the acquired proved and unproved oil and gas properties, we prepared our estimates using discounted cash flows and engaged third party valuation experts. Significant judgments and assumptions are inherent in these estimates and include, among other things, future production volumes, future commodity prices, expected development costs, lease operating costs, reserve risk adjustment factors and an estimate of an applicable market participant discount rate that reflects the risk of the underlying cash flow estimates. Estimated fair values assigned to assets acquired can have a significant impact on future results of operations, as presented in our financial statements. Fair values are based on estimates of future commodity prices and price differentials, reserve quantities and production volumes, development costs and lease operating costs. In the event that future commodity prices or reserve quantities or production volumes are significantly lower than those used in the determination of fair value as of the effective date of the acquisitions, the likelihood increases that certain costs may be determined to be unrecoverable. In addition to the fair value of proved and unproved oil and gas properties, other significant fair value assessments for the assets acquired and liabilities assumed in the acquisitions relate to gathering and pipeline systems. We prepared estimates and engaged third-party valuation experts to assist in the valuation of gathering and pipeline systems, which required significant judgments and assumptions inherent in the estimates and included projected cash flows and comparable companies’ cash flow multiples. Successful Efforts Method of Accounting We follow the successful efforts method of accounting for our oil and gas producing activities. Acquisition costs for proved and unproved properties are capitalized when incurred. Judgment is required to determine the proper classification of wells designated as developmental or exploratory, which ultimately will determine the proper accounting treatment of costs incurred. Exploration costs, including geological and geophysical costs, the costs of carrying and retaining unproved properties and exploratory dry-hole costs are expensed. Development costs, including costs to drill and equip development wells and successful exploratory drilling costs to locate proved reserves, are capitalized. Oil and Gas Reserves The process of estimating quantities of proved reserves is inherently imprecise, and the reserves data included in this document are only an estimate. The process relies on interpretations and judgment of available geological, geophysical, engineering and production data. The extent, quality and reliability of this technical data can vary. The process also requires certain economic assumptions, some of which are mandated by the SEC, such as commodity prices. Additional assumptions include drilling and operating expenses, capital expenditures, taxes and availability of funds. Any significant variance in the interpretations or assumptions could materially affect the estimated quantity and value of our reserves and can change substantially over time. Periodic revisions to the estimated reserves and future cash flows may be necessary as a result of reservoir performance, drilling activity, commodity prices, fluctuations in operating expenses, technological advances, new geological or geophysical data or other economic factors. Accordingly, reserves estimates are generally different from the quantities ultimately recovered. The reserves estimates of our oil and gas properties have been prepared by our reservoir engineering staff and certain of our reserves are subject to an evaluation performed by an independent third-party petroleum consulting firm. In 2025, greater than 90 percent of the total future net revenue discounted at 10 percent attributable to our proved reserves were subject to this evaluation. For more information regarding reserves estimation, including historical reserves revisions, refer to the Supplemental Oil and Gas Information included in Item 8. Our rate of recording DD&A expense is dependent upon our estimate of proved reserves, which are utilized in our unit-of-production calculation. If the estimates of proved and proved developed reserves were to be reduced, the rate at which we record DD&A expense would increase, reducing net income. Such a reduction in reserves may result from lower market prices, which may make it uneconomic to drill and produce higher cost fields. A five percent positive or negative revision to proved 50
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Table of Contents reserves would result in a decrease of $0.40 per Boe and an increase of $0.44 per Boe, respectively, on our DD&A rate. This estimated impact is based on current data, and actual events could require different adjustments to our DD&A rate. In addition, a decline in proved reserves estimates may impact the outcome of our impairment test under applicable accounting standards. Due to the inherent imprecision of the reserves estimation process, risks associated with the operations of proved producing properties and market sensitive commodity prices utilized in our impairment analysis, we cannot determine if an impairment is reasonably likely to occur in the future. Oil and Gas Properties We evaluate our proved oil and gas properties for impairment on a field-by-field basis whenever events or changes in circumstances indicate an asset’s carrying amount may not be recoverable. We compare expected undiscounted future cash flows to the net book value of the asset. If the future undiscounted expected cash flows, based on our estimate of future commodity prices, operating costs and anticipated production from proved reserves and risk-adjusted probable and possible reserves, are lower than the net book value of the asset, then the capitalized cost is reduced to fair value. Commodity pricing is estimated by using a combination of assumptions management uses in its budgeting and forecasting process, historical and current prices adjusted for geographical location and quality differentials, as well as other factors that we believe will impact realizable prices. Given the significant volatility in oil, natural gas and NGLs prices, estimates of such future prices are inherently imprecise. In the event that commodity prices significantly decline, we would assess whether the decline constitutes a triggering event that would require us to test the recoverability of the carrying value of our oil and gas properties and, if necessary, record an impairment charge. Fair value is calculated by discounting the future cash flows. The discount factor used is based on rates utilized by market participants that are commensurate with the risks inherent in the development and production of the underlying oil and natural gas. Unproved oil and gas properties are assessed periodically for impairment on an aggregate basis through periodic updates to our unproved acreage amortization based on past drilling and exploration experience, our expectation of converting leases to held by production and average property lives. Average property lives are determined on a geographical basis and based on the estimated life of unproved property leasehold rights. Historically, the average property life in each of the geographical areas has not significantly changed and generally ranges from three to five years. The commodity price environment may impact the capital available for our drilling activities. We have considered these impacts when determining the amortization of our unproved acreage. If the average unproved property life decreases or increases by one year, the amortization would increase by approximately $15 million or decrease by $10 million, respectively, per year. As these properties are developed and reserves are proved, the remaining capitalized costs are subject to depreciation and depletion. If the development of these properties is deemed unsuccessful and the properties are abandoned or surrendered, the capitalized costs related to the unsuccessful activity are expensed in the year the determination is made. The rate at which the unproved properties are written off depends on the timing and success of our future exploration and development program. Derivative Instruments Under applicable accounting standards, the fair value of each derivative instrument is recorded as either an asset or liability on the balance sheet. At the end of each quarterly period, these instruments are marked-to-market. The change in fair value of derivatives not designated as hedges is recorded as a component of operating revenues in gain (loss) on derivative instruments in the Consolidated Statement of Operations. Our derivative contracts are measured based on quotes from a third-party valuation service provider. Such quotes have been derived using an income approach that considers various inputs, including current market and contractual prices for the underlying instruments, quoted forward commodity prices, basis differentials, volatility factors and interest rates for a similar length of time as the derivative contract term, as applicable. These estimates are derived from or verified using relevant NYMEX futures contracts or are compared to multiple quotes obtained from counterparties. The determination of fair value also incorporates a credit adjustment for non-performance risk. The non-performance risk of our counterparties is measured by reviewing credit default swap spreads for the various financial institutions with which we have derivative contracts, while our non-performance risk is evaluated by using credit default swap spreads for various similarly rated companies in our sector. Our financial condition, results of operations and liquidity can be significantly impacted by changes in the market value of our derivative instruments due to volatility of commodity prices, including changes in both index prices (such as NYMEX) and basis differentials. 51
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Table of Contents Income Taxes We make certain estimates and judgments in determining our income tax expense for financial reporting purposes. These estimates and judgments include the calculation of certain deferred tax assets and liabilities that arise from differences in the timing and recognition of revenue and expenses for tax and financial reporting purposes and estimating reserves for potential adverse outcomes regarding tax positions that we have taken. We account for the uncertainty in income taxes using a recognition and measurement threshold for tax positions taken or expected to be taken in a tax return. The tax benefit from an uncertain tax position is recognized when it is more likely than not that the position will be sustained upon examination by taxing authorities based on technical merits of the position. The amount of the tax benefit recognized is the largest amount of the benefit that has a greater than 50 percent likelihood of being realized upon ultimate settlement. The effective tax rate and the tax basis of assets and liabilities reflect management’s estimates of the ultimate outcome of various tax uncertainties. We believe all of our deferred tax assets, net of any valuation allowances, will ultimately be realized, taking into consideration our forecasted future taxable income, which includes consideration of future operating conditions specifically related to commodity prices. If our estimates and judgments change regarding our ability to realize our deferred tax assets, our tax provision could increase in the period it is determined that it is more likely than not it will not be realized. Our effective tax rate is subject to variability as a result of factors other than changes in federal and state tax rates and changes in tax laws which could affect us. Our effective tax rate is affected by changes in the allocation of property, payroll and revenues among states in which we operate. A small change in our estimated future tax rate could have a material effect on current period earnings. Contingency Reserves A provision for contingencies is charged to expense when the loss is probable and the cost is estimable. The establishment of a reserve is based on an estimation process that includes the advice of legal counsel and subjective judgment of management. In certain cases, our judgment is based on the advice and opinions of legal counsel and other advisors, the interpretation of laws and regulations, which can be interpreted differently by regulators and courts of law, our experience and the experiences of other companies dealing with similar matters, and our decision on how we intend to respond to a particular matter. Actual losses can differ from estimates for various reasons, including those noted above. We monitor known and potential legal, environmental and other contingencies and make our best estimate based on the information we have. Future changes in facts and circumstances not currently foreseeable could result in the actual liability exceeding the estimated ranges of loss and amounts accrued. Stock-Based Compensation We account for stock-based compensation under the fair value method of accounting in accordance with applicable accounting standards. Under the fair value method, compensation cost is measured at the grant date for equity-classified awards and re-measured each reporting period for liability-classified awards based on the fair value of an award and is recognized over the service period, which is generally the vesting period. To calculate fair value, we use various models, including both a Black Scholes or a Monte Carlo valuation model, as determined by the specific provisions of the award. The use of these models requires significant judgment with respect to expected life, volatility and other factors. Recently Issued and Adopted Accounting Pronouncements Refer to Note 1 of the Notes to the Consolidated Financial Statements, “Summary of Significant Accounting Policies,” for a discussion of newly issued and adopted accounting pronouncements. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK In the normal course of business, we are subject to a variety of risks, including market risks associated with changes in commodity prices and interest rate movements on outstanding debt. Except as otherwise indicated, the following quantitative and qualitative information is provided for financial instruments to which we were party to as of December 31, 2025 and from which we may incur future gains or losses from changes in commodity prices or interest rates. Commodity Price Risk Our most significant market risk exposure is pricing applicable to our oil, natural gas and NGL production. Realized prices are mainly driven by the worldwide price for oil and spot market prices for North American natural gas and NGL production. As noted above, these prices have been volatile and unpredictable. To mitigate the volatility in commodity prices, we may enter into derivative instruments to hedge a portion of our production. 52
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Table of Contents Derivative Instruments and Risk Management Activities Our commodity price risk management strategy is designed to reduce the risk of commodity price volatility for our production in the oil and natural gas markets through the use of financial commodity derivatives. A committee that consists of members of senior management oversees our risk management activities. Our financial commodity derivatives generally cover a portion of our production and, while protecting us in the event of price declines, limit the benefit to us in the event of price increases. Further, if any of our counterparties defaulted, this protection might be limited as we might not receive the full benefit of our financial commodity derivatives. Please read the discussion below as well as Note 5 of the Notes to the Consolidated Financial Statements, “Derivative Instruments,” in Item 8 for a more detailed discussion of our derivatives. Periodically, we enter into financial commodity derivatives, including collar, swap, and basis swap agreements, to protect against exposure to commodity price declines. All of our financial derivatives are used for risk management purposes and are not held for trading purposes. Under the collar agreements, if the index price rises above the ceiling price, we pay the counterparty. If the index price falls below the floor price, the counterparty pays us. Under the swap agreements, we receive a fixed price on a notional quantity of natural gas or oil in exchange for paying a variable price based on a market-based index. As of December 31, 2025, we had the following outstanding financial commodity derivatives: 2026 Fair Value Asset (Liability) (In millions)Oil First Quarter Second Quarter Third Quarter Fourth Quarter WTI oil collars $ 49 Volume (MBbl) 3,600 3,640 3,680 3,680 Weighted average floor ($/Bbl) $ 56.25 $ 56.25 $ 56.25 $ 56.25 Weighted average ceiling ($/Bbl) $ 70.81 $ 70.81 $ 70.81 $ 70.81 WTI NYMEX oil swaps $ 33 Volume (MBbl) 900 910 920 920 Weighted average price ($/Bbl) $ 66.14 $ 66.14 $ 66.14 $ 66.14 WTI Midland oil basis swaps $ 4 Volume (MBbl) 4,500 4,550 4,600 4,600 Weighted average differential ($/Bbl) $ 0.97 $ 0.97 $ 0.97 $ 0.97 $ 86 53
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Table of Contents 2026 2027 Fair Value Asset (Liability) (In millions)Natural Gas First Quarter Second Quarter Third Quarter Fourth Quarter First Quarter Second Quarter Third Quarter Fourth Quarter NYMEX gas collars $ 85 Volume (MMBtu) 108,000,00081,900,00082,800,00082,800,0007,200,000 7,280,000 7,360,000 7,360,000 Weighted average floor ($/MMBtu)$ 3.23 $ 3.39 $ 3.39 $ 3.39 $ 3.40 $ 3.40 $ 3.40 $ 3.40 Weighted average ceiling ($/MMBtu)$ 6.12 $ 5.61 $ 5.61 $ 5.61 $ 5.17 $ 5.17 $ 5.17 $ 5.17 Transco Leidy gasbasis swaps $ 1 Volume (MMBtu) 13,500,00013,650,00013,800,00013,800,000 — — — — Weighted averagedifferential ($/MMBtu) $ (0.78)$ (0.78)$ (0.78)$ (0.78)$ — $ — $ — $ — Transco Zone 6 Non-NY gas basis swaps $ (2) Volume (MMBtu) 22,500,00022,750,00023,000,00023,000,000 — — — — Weighted averagedifferential ($/MMBtu) $ (0.16)$ (0.16)$ (0.16)$ (0.16)$ — $ — $ — $ — Waha gas basis swaps $ 66 Volume (MMBtu) 18,000,00018,200,00018,400,00018,400,000 — — — — Weighted average differential ($/ MMBtu) $ (1.92)$ (1.92)$ (1.92)$ (1.92)$ — $ — $ — $ — $ 150 In January 2026, we entered into the following financial commodity derivatives: 2026 Oil First Quarter Second Quarter Third Quarter Fourth Quarter WTI oil collars Volume (MBbl) 590 910 920 920 Weighted average floor ($/Bbl) $ 55.00 $ 55.00 $ 50.00 $ 50.00 Weighted average ceiling ($/Bbl) $ 67.40 $ 67.40 $ 69.25 $ 69.25 2026 Natural Gas First Quarter Second Quarter Third Quarter Fourth Quarter Transco Leidy gas basis swaps Volume (MMBtu) 5,900,000 9,100,000 9,200,000 9,200,000 Weighted average differential ($/MMBtu) $ (0.79) $ (0.79) $ (0.79) $ (0.79) A significant portion of our production for 2026 and beyond is currently unhedged and directly exposed to the volatility in oil and natural gas prices, whether favorable or unfavorable. During 2025, oil collars with floor prices ranging from $55.00 to $65.00 per Bbl and ceiling prices ranging from $69.55 to $86.02 per Bbl covered 20.4 MMBbls, or 35 percent, of oil production at a weighted-average price of $65.12 per Bbl. Oil basis swaps covered 23.7 MMBbls, or 41 percent, of oil production at a weighted-average differential of $1.05 per Bbl. Oil swaps covered 6.9 MMBbls, or 12 percent of oil production at a weighted-average price of $63.30 per Bbl. During 2025, natural gas collars with floor prices ranging from $2.75 to $3.50 per MMBtu and ceiling prices ranging from $3.40 to $8.30 per MMBtu covered 277.2 Bcf, or 26 percent of natural gas production at a weighted-average price of $3.51 per 54
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Table of Contents MMBtu. Gas basis swaps covered 171.8 Bcf, or 16 percent of natural gas production at a weighted-average differential of $(0.89) per MMBtu. We are exposed to market risk on financial commodity derivative instruments to the extent of changes in market prices of the related commodity. However, the market risk exposure on these derivative contracts is generally offset by the gain or loss recognized upon the ultimate sale of the commodity. Although notional contract amounts are used to express the volume of oil and natural gas agreements, the amounts that can be subject to credit risk in the event of non-performance by third parties are substantially smaller. Our counterparties are primarily commercial banks and financial service institutions that our management believes present minimal credit risk and our derivative contracts are with multiple counterparties to minimize our exposure to any individual counterparty. We perform both quantitative and qualitative assessments of these counterparties based on their credit ratings and credit default swap rates where applicable. We have not incurred any losses related to non-performance risk of our counterparties and we do not anticipate any material impact on our financial results due to non-performance by third parties. However, we cannot be certain that we will not experience such losses in the future. Interest Rate Risk At December 31, 2025, we had total debt of $3.8 billion. Our debt portfolio includes floating rate debt and fixed-rate debt instruments. Our revolving credit and term loan borrowings are floating rate debt instruments, which exposes us to the risk of earnings or cash flow losses as a result of potential increases in market interest rate. There are no “rating triggers” in any of our debt agreements that would accelerate the scheduled maturities. Should our credit rating fall below a certain level, a change in our credit rating could adversely impact our interest rate on any borrowings under our revolving credit agreement and term loan. As of the date hereof, our debt is currently rated as investment grade by the three leading ratings agencies. For more on the impact of credit ratings on our interest rates, see Note 4 of the Notes to the Consolidated Financial Statements, “Long-Term Debt and Credit Agreements”. At December 31, 2025, we had no outstanding balance under our revolving credit agreement and $300 million outstanding borrowings under our term loan. Assuming no change in the amount of floating rate debt outstanding, a hypothetical 100 basis point increase in the average interest rate under our term loan borrowings would have increased our annual interest expense by approximately $6 million. Actual results may vary due to changes in the amount of floating rate debt outstanding. At December 31, 2025, we had $3.5 billion outstanding borrowings under fixed-rate debt instruments, which do not carry significant exposure to movements in market interest rates. Fair Value of Other Financial Instruments The estimated fair value of other financial instruments is the amount at which the instrument could be exchanged currently between willing parties. The carrying amounts reported in the Consolidated Balance Sheet for cash, cash equivalents and restricted cash approximate fair value due to the short-term maturities of these instruments. The fair value of our senior notes is based on quoted market prices. The fair value of our private placement senior notes is based on third-party quotes which are derived from credit spreads for the difference between the issue rate and the period end market rate and other unobservable inputs. The fair value of the borrowing under our term loan approximates the carrying value as the interest rates are variable and reflective of market rates. The carrying amount and estimated fair value of debt is as follows: December 31, 2025 December 31, 2024 (In millions) CarryingAmount Estimated FairValue CarryingAmount Estimated FairValue Total debt $ 3,818 $ 3,798 $ 3,535 $ 3,395 Current maturities (250) (249) — — Long-term debt, excluding current maturities $ 3,568 $ 3,549 $ 3,535 $ 3,395 55
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Table of Contents ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA INDEX TO CONSOLIDATED FINANCIAL STATEMENTS Page Report of Independent Registered Public Accounting Firm (PCAOB ID: 238) 57 Consolidated Balance Sheet at December 31, 2025 and 2024 60 Consolidated Statement of Operations for the Years Ended December 31, 2025, 2024 and 2023 61 Consolidated Statement of Comprehensive Income for the Years Ended December 31, 2025, 2024 and 2023 62 Consolidated Statement of Cash Flows for the Years Ended December 31, 2025, 2024 and 2023 63 Consolidated Statement of Stockholders’ Equity for the Years Ended December 31, 2025, 2024 and 2023 64 Notes to the Consolidated Financial Statements 65 Supplemental Oil and Gas Information (Unaudited) 99 56
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Table of Contents Report of Independent Registered Public Accounting Firm To the Board of Directors and Stockholders of Coterra Energy Inc. Opinions on the Financial Statements and Internal Control over Financial Reporting We have audited the accompanying consolidated balance sheet of Coterra Energy Inc. and its subsidiaries (the “Company”) as of December 31, 2025 and 2024, and the related consolidated statements of operations, of comprehensive income, of stockholders’ equity and of cash flows for each of the three years in the period ended December 31, 2025, including the related notes (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO. Basis for Opinions The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions. Definition and Limitations of Internal Control over Financial Reporting A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 57
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Table of Contents Critical Audit Matters The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that (i) relate to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate. The Impact of Proved Developed Oil and Natural Gas Reserves on Proved Oil and Gas Properties, Net As described in Notes 1 and 3 to the consolidated financial statements, a significant portion of the Company’s properties and equipment, net balance of $22,058 million as of December 31, 2025 and depreciation, depletion and amortization (DD&A) expense of $2,370 million for the year ended December 31, 2025 relates to proved oil and gas properties. The Company uses the successful efforts method of accounting for its oil and gas producing activities. As disclosed by management, the Company’s rate of recording DD&A expense is dependent upon the estimate of proved reserves, which are utilized in the unit-of-production calculation. In estimating proved oil and natural gas reserves, management relies on interpretations and judgment of available geological, geophysical, engineering and production data, as well as the use of certain economic assumptions such as commodity prices. Additional assumptions include drilling and operating expenses, capital expenditures, taxes and availability of funds. The estimates of proved oil and natural gas reserves have been prepared by the Company’s internal Corporate Reservoir Engineering group and evaluated by third-party petroleum engineers (collectively referred to as “management’s specialists”). The principal considerations for our determination that performing procedures relating to the impact of proved developed oil and natural gas reserves on proved oil and gas properties, net is a critical audit matter are (i) the significant judgment by management, including the use of management’s specialists, when developing the estimates of proved developed oil and natural gas reserves, which are derived using historical production volumes and (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating audit evidence related to data, specifically historical production volumes, methods, and assumptions used by management and its specialists in developing the estimates of proved developed oil and natural gas reserves. Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s estimates of proved developed oil and natural gas reserves. The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of the proved developed oil and natural gas reserves. As a basis for using this work, the specialists’ qualifications were understood and the Company’s relationship with the specialists was assessed. The procedures performed also included (i) evaluating the methods and assumptions used by management’s specialists; (ii) testing the completeness and accuracy of the underlying data used by management’s specialists related to historical production volumes; and (iii) evaluating the specialists’ findings related to future production volumes by comparing future production volumes to relevant historical and current period production volumes, as applicable. Acquisitions of Franklin Mountain Energy and Avant - Valuations of Proved and Unproved Oil and Gas Properties As described in Note 2 to the consolidated financial statements, on January 27, 2025, the Company closed on the acquisition of all of the issued and outstanding equity ownership interests of Franklin Mountain Energy (FME) for total consideration of $2.5 billion, and the assets acquired included $2.4 billion of proved and unproved oil and gas properties. On January 17, 2025, the Company closed on the acquisition of certain interests in oil and gas properties of Avant for total cash consideration of $1.5 billion, and the assets acquired included $1.3 billion of proved and unproved oil and gas properties. As disclosed by management, a number of assumptions were made in estimating the fair value of assets acquired and liabilities assumed. The most significant assumptions related to the fair value estimates of proved and unproved oil and gas properties, which were prepared using discounted cash flows. Significant judgments and assumptions by management include, among other things, future production volumes, future commodity prices, expected development costs, lease operating costs, reserve risk adjustment factors, and an estimate of an applicable market participant discount rate. The principal considerations for our determination that performing procedures relating to the valuations of proved and unproved oil and gas properties acquired in the acquisitions of FME and Avant is a critical audit matter are (i) the significant judgment by management, including the use of management’s specialists, when developing the fair value estimates of the proved and unproved oil and gas properties acquired, which are derived using historical production volumes; (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating audit evidence related to data, specifically historical production volumes, methods, and management’s significant assumptions related to future production volumes, future 58
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Table of Contents commodity prices, expected development costs, lease operating costs, reserve risk adjustment factors, and discount rate; and (iii) the audit effort involved the use of professionals with specialized skill and knowledge. Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to the acquisition accounting, including controls over management’s valuations of proved and unproved oil and gas properties acquired. These procedures also included, among others (i) reading the acquisition agreements; (ii) testing management’s process for developing the fair value estimates of proved and unproved oil and gas properties acquired; (iii) evaluating the appropriateness of the discounted cash flow models used by management; (iv) testing the completeness and accuracy of the underlying data used in the discounted cash flow models; and (v) evaluating the reasonableness of the significant assumptions used by management related to future production volumes, future commodity prices, expected development costs, lease operating costs, reserve risk adjustment factors, and discount rate. Evaluating the future commodity prices assumption involved comparing the prices to observable market data. Evaluating management’s assumptions related to future production volumes, expected development costs, and lease operating costs involved considering (i) the current and past performance of the FME and Avant businesses and (ii) whether the assumptions were consistent with evidence obtained in other areas of the audit. Professionals with specialized skill and knowledge were used to assist in evaluating (i) the appropriateness of the discounted cash flow models and (ii) the reasonableness of the reserve risk adjustment factors and discount rate assumptions. The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of the future production volumes used in the discounted cash flow models. As a basis for using this work, the specialists’ qualifications were understood and the Company’s relationship with the specialists was assessed. The procedures performed also included (i) evaluating the methods and assumptions used by management’s specialists; (ii) testing the completeness and accuracy of the underlying data used by the specialists related to historical production volumes; and (iii) evaluating the specialists’ findings related to future production volumes by comparing future production volumes to relevant historical and current period production volumes, as applicable. /s/ PricewaterhouseCoopers LLP Houston, Texas February 27, 2026 We have served as the Company’s auditor since 1989. 59
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Table of Contents COTERRA ENERGY INC. CONSOLIDATED BALANCE SHEET December 31, (In millions, except per share amounts) 2025 2024 ASSETS Current assets Cash and cash equivalents $ 114 $ 2,038 Restricted cash 5 239 Accounts receivable, net 1,208 951 Income taxes receivable 201 20 Inventories 48 46 Other current assets 273 27 Total current assets 1,849 3,321 Properties and equipment, net (Successful efforts method) 22,058 17,890 Other assets 334 414 $ 24,241 $ 21,625 LIABILITIES, REDEEMABLE PREFERRED STOCK AND STOCKHOLDERS' EQUITY Current liabilities Accounts payable $ 1,056 $ 833 Current portion of long-term debt 250 — Accrued liabilities 197 276 Interest payable 54 27 Total current liabilities 1,557 1,136 Long-term debt 3,568 3,535 Deferred income taxes 3,703 3,274 Asset retirement obligations 329 291 Other liabilities 238 259 Total liabilities 9,395 8,495 Commitments and contingencies (Note 8) Redeemable preferred stock 8 8 Stockholders' equity Common stock: Authorized — 1,800 shares of $0.10 par value in 2025 and 2024 Issued — 760 shares and 735 shares in 2025 and 2024, respectively 76 74 Additional paid-in capital 7,854 7,179 Retained earnings 6,894 5,857 Accumulated other comprehensive income 14 12 Total stockholders' equity 14,838 13,122 $ 24,241 $ 21,625 The accompanying notes are an integral part of these consolidated financial statements. 60
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Table of Contents COTERRA ENERGY INC. CONSOLIDATED STATEMENT OF OPERATIONS Year Ended December 31, (In millions, except per share amounts) 2025 2024 2023 OPERATING REVENUES Oil $ 3,699 $ 2,953 $ 2,667 Natural gas 2,633 1,693 2,292 NGL 844 738 644 Gain (loss) on derivative instruments, net 351 (3) 230 Other 118 77 81 7,645 5,458 5,914 OPERATING EXPENSES Direct operations 1,023 658 562 Gathering, processing and transportation 1,089 976 975 Taxes other than income 366 271 283 Exploration 27 25 20 Depreciation, depletion and amortization 2,370 1,840 1,641 General and administrative 323 302 291 5,198 4,072 3,772 Gain on sale of assets 5 3 12 INCOME FROM OPERATIONS 2,452 1,389 2,154 Interest expense 205 106 73 Interest income (14) (62) (47) Other income (2) — — Income before income taxes 2,263 1,345 2,128 Income tax expense 546 224 503 NET INCOME $ 1,717 $ 1,121 $ 1,625 Earnings per share Basic $ 2.25 $ 1.51 $ 2.14 Diluted $ 2.24 $ 1.50 $ 2.13 Weighted-average common shares outstanding Basic 761 742 756 Diluted 764 745 760 The accompanying notes are an integral part of these consolidated financial statements. 61
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Table of Contents COTERRA ENERGY INC. CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME Year Ended December 31, (In millions) 2025 2024 2023 Net income $ 1,717 $ 1,121 $ 1,625 Postretirement benefits: Amortization of net actuarial gain (2) (1) (2) Net actuarial gain 4 2 — Total other comprehensive income (loss) 2 1 (2) Comprehensive income $ 1,719 $ 1,122 $ 1,623 _______________________________________________________________________________ (1) Net of income taxes of less than $1 million for the years ended December 31, 2025, 2024 and 2023, respectively. (2) Net of income taxes of $2 million and less than $1 million for the years ended December 31, 2025 and 2024, respectively. The accompanying notes are an integral part of these consolidated financial statements. (1) (2) 62
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Table of Contents COTERRA ENERGY INC. CONSOLIDATED STATEMENT OF CASH FLOWS Year Ended December 31, (In millions) 2025 2024 2023 CASH FLOWS FROM OPERATING ACTIVITIES Net income $ 1,717 $ 1,121 $ 1,625 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion and amortization 2,370 1,840 1,641 Deferred income tax expense (benefit) 435 (145) 74 Gain on sale of assets (5) (3) (12) Exploratory dry hole cost — 5 — (Gain) loss on derivative instruments, net (351) 3 (230) Net cash received on settlement of derivative instruments 106 98 284 Amortization of debt premium, debt discount and debt issuance costs (15) (12) (18) Stock-based compensation and other 62 61 57 Changes in assets and liabilities: Accounts receivable, net (67) (108) 378 Income taxes (181) 31 38 Inventories 1 13 4 Other current assets (10) (3) (3) Accounts payable and accrued liabilities (77) 15 (180) Interest payable 27 6 — Other assets and liabilities 9 (127) — Net cash provided by operating activities 4,021 2,795 3,658 CASH FLOWS FROM INVESTING ACTIVITIES Capital expenditures for drilling, completion and other fixed asset additions (2,288) (1,754) (2,089) Capital expenditures for leasehold and property acquisitions (99) (17) (10) Cash consideration paid for business combinations, net of cash received (3,238) — — Purchase of short-term investments — (250) — Proceeds from sale of short-term investments — 250 — Other (3) 9 40 Net cash used in investing activities (5,628) (1,762) (2,059) CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from issuance of debt 1,746 1,990 — Repayments of debt (1,446) (575) — Common stock repurchases (141) (455) (405) Dividends paid (682) (625) (890) Other (28) (56) (22) Net cash (used in) provided by financing activities (551) 279 (1,317) Net (decrease) increase in cash, cash equivalents and restricted cash (2,158) 1,312 282 Cash, cash equivalents and restricted cash, beginning of period 2,277 965 683 Cash, cash equivalents and restricted cash, end of period $ 119 $ 2,277 $ 965 The accompanying notes are an integral part of these consolidated financial statements. 63
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Table of Contents COTERRA ENERGY INC. CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY (In millions, except pershare amounts) CommonShares CommonStockPar TreasuryShares TreasuryStock AdditionalPaid-InCapital AccumulatedOtherComprehensiveIncome RetainedEarnings Total Balance at December 31, 2022 768 $ 77 — $ — $ 7,933 $ 13 $ 4,636 $ 12,659 Net income — — — — — — 1,625 1,625 Exercise of stock options — — — — 2 — — 2 Stock amortization and vesting — — — (9) 65 — — 56 Common stock repurchases — — 17 (409) — — — (409) Common stock retirements (17) (2) (17) 418 (416) — — — Conversion of redeemable preferredstock — — — — 3 — — 3 Cash dividends on common stock at$1.17 per share — — — — — — (895) (895) Other comprehensive loss — — — — — (2) — (2) Balance at December 31, 2023 751 $ 75 — $ — $ 7,587 $ 11 $ 5,366 $ 13,039 Net income — — — — — — 1,121 1,121 Exercise of stock options — — — — 2 — — 2 Stock amortization and vesting 1 1 — (8) 52 — — 45 Common stock repurchases — — 17 (456) — — — (456) Common stock retirements (17) (2) (17) 464 (462) — — — Cash dividends on common stock at$0.84 per share — — — — — — (630) (630) Other comprehensive income — — — — — 1 — 1 Balance at December 31, 2024 735 $ 74 — $ — $ 7,179 $ 12 $ 5,857 $ 13,122 Net income — — — — — — 1,717 1,717 Issuance of common stock foracquisition 28 2 — — 783 — — 785 Stock amortization and vesting 3 — — — 32 — — 32 Common stock repurchases — — 6 (140) — — — (140) Common stock retirements (6) — (6) 140 (140) — — — Cash dividends on common stock at$0.88 per share — — — — — — (680) (680) Other comprehensive income — — — — — 2 — 2 Balance at December 31, 2025 760 $ 76 — $ — $ 7,854 $ 14 $ 6,894 $ 14,838 The accompanying notes are an integral part of these consolidated financial statements. 64
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Table of Contents NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 1. Summary of Significant Accounting Policies Basis of Presentation and Nature of Operations Coterra Energy Inc. and its subsidiaries (“Coterra” or the “Company”) are engaged in the development, exploration and production of oil, natural gas and NGLs exclusively within the continental U.S. The Company’s exploration and development activities are concentrated in areas with known hydrocarbon resources, which are conducive to multi-well, repeatable drilling programs. The consolidated financial statements include the accounts of the Company and its subsidiaries after eliminating all significant intercompany balances and transactions. Certain reclassifications have been made to prior year statements to conform with the current year presentation. These reclassifications have no impact on previously reported stockholders’ equity, net income or cash flows. Recently Adopted Accounting Pronouncements In December 2023, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosure. This ASU enhances income tax disclosure requirements, including additional disaggregation of income taxes paid by federal, state, and foreign jurisdictions and expanded rate reconciliation disclosures across eight specific categories, presented in both dollar amounts and percentages. The Company adopted ASU No. 2023-09 effective for the year ended December 31, 2025 and applied the guidance retrospectively to all periods presented, updating comparative periods to reflect the additional disclosures. The adoption of ASU No. 2023-09 had no effect on the Company’s financial position, results of operations or cash flows as it modified disclosure requirements only. Refer to Note 10 of the Notes to the Consolidated Financial Statements, “Income Taxes” for the revised disclosures consistent with the new standard. Recently Issued Accounting Pronouncements In November 2024, the FASB issued ASU No. 2024-03, Income Statement - Reporting Comprehensive Income - Expense Disaggregation Disclosures (Subtopic 220-40) Disaggregation of Income Statement Expenses. This ASU requires disaggregated disclosures, in the notes to the financial statements, of certain categories of expenses that are included in expense line items on the face of the income statement. The ASU will be effective for fiscal years beginning after December 15, 2026, and interim periods within fiscal years beginning after December 15, 2027, to be applied prospectively, with early adoption and retrospective application permitted. The adoption of ASU No. 2024-03 is not expected to have any effect on the Company’s financial position, results of operations or cash flows as it modifies disclosure requirements only. The Company plans to adopt ASU No. 2024-03 during the year ending December 31, 2027. Significant Accounting Policies Cash and Cash Equivalents The Company considers all highly liquid short-term investments with a maturity of three months or less and deposits in money market funds and other investments that are readily convertible to cash to be cash equivalents. Cash and cash equivalents were primarily concentrated in three financial institutions at December 31, 2025. The Company periodically assesses the financial condition of its financial institutions and considers any possible credit risk to be minimal. Restricted Cash Restricted cash includes cash that is legally or contractually restricted as to withdrawal or usage. As of December 31, 2025 and 2024, the restricted cash balance of $5 million and $239 million, respectively, includes cash deposited in escrow accounts that are restricted for use. Allowance for Credit Losses The Company records an allowance for credit losses based on the Company’s estimate of future expected credit losses on outstanding receivables. Inventories Inventories are primarily comprised of tubular goods and well equipment and commodity inventory, including pipeline imbalances. 65
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Table of Contents Tubular goods and well equipment are carried at average cost and are assessed periodically for obsolescence. Commodity inventories are recorded at actual purchase prices and are adjusted monthly to market prices. Commodity inventories generally turn monthly. Properties and Equipment Oil and Gas Properties The Company uses the successful efforts method of accounting for oil and gas producing activities. Under this method, acquisition costs for proved and unproved properties are capitalized when incurred. Exploration costs, including geological and geophysical costs, the costs of carrying and retaining unproved properties and exploratory dry hole drilling costs, are expensed. Development costs, including the costs to drill and equip development wells and successful exploratory drilling costs to locate proved reserves are capitalized. Exploratory drilling costs are capitalized when incurred pending the determination of whether a well has found proved reserves. The determination is based on a process which relies on interpretations of available geologic, geophysical and engineering data. If a well is determined to be successful, the capitalized drilling costs will be reclassified as part of the cost of the well. If a well is determined to be unsuccessful, the capitalized drilling costs will be charged to exploration expense in the Consolidated Statement of Operations in the period the determination is made. If an exploratory well requires a major capital expenditure before production can begin, the cost of drilling the exploratory well will continue to be carried as an asset pending determination of whether reserves have been found only as long as: (1) the well has found a sufficient quantity of reserves to justify its completion as a producing well if the required capital expenditure is made and (2) drilling of an additional exploratory well is under way or firmly planned for the near future. If drilling in the area is not under way or firmly planned or if the well has not found a commercially producible quantity of reserves, the exploratory well is assumed to be impaired and its costs are charged to exploration expense. Development costs of proved oil and gas properties, including estimated dismantlement, restoration and abandonment costs and acquisition costs, are depreciated and depleted on a field basis by the unit-of-production method using both proved developed and proved reserves. Costs of sold or abandoned properties that make up a part of an amortization base (partial field) remain in the amortization base if the unit-of-production rate is not significantly affected. If significant, a gain or loss, if any, is recognized and the sold or abandoned properties are retired. A gain or loss, if any, is also recognized when a group of proved properties (entire field) that make up the amortization base has been retired, abandoned or sold. The Company evaluates its proved oil and gas properties for impairment whenever events or changes in circumstances indicate an asset’s carrying amount may not be recoverable. The Company compares expected undiscounted future cash flows to the net book value of the asset. If the future undiscounted expected cash flows, based on estimates of future commodity prices, operating costs and anticipated production from proved reserves and risk-adjusted probable and possible reserves, are lower than the net book value of the asset, the capitalized cost is reduced to fair value. Commodity pricing is estimated by using a combination of assumptions management uses in its budgeting and forecasting process as well as historical and current prices adjusted for geographical location and quality differentials, as well as other factors that management believes will impact realizable prices. Fair value is calculated by discounting the future cash flows. The discount factor used is based on rates utilized by market participants that are commensurate with the risks inherent in the development and production of the underlying oil and natural gas. Unproved oil and gas properties are assessed periodically for impairment on an aggregate basis through periodic updates to the Company’s unproved acreage amortization based on past drilling and exploration experience, the Company’s expectation of converting leases to held by production and average property lives. Average property lives are determined on a geographical basis and based on the estimated life of unproved property leasehold rights. Fixed Assets Fixed assets consist primarily of gas gathering systems, water and electrical infrastructure, buildings, vehicles, aircraft, furniture and fixtures, and computer equipment and software. These items are recorded at cost and are depreciated on the straight-line method based on expected lives of the individual assets, which range from three to 30 years. Asset Retirement Obligations The Company records the fair value of a liability for an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated asset retirement cost is capitalized as part of the carrying amount 66
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Table of Contents of the long-lived asset. Asset retirement costs for oil and gas properties are depreciated using the unit-of-production method, while asset retirement costs for other assets are depreciated using the straight-line method over estimated useful lives. Additional retirement obligations increase the liability associated with new oil and gas wells and other facilities as these obligations are incurred. Accretion expense is included in DD&A expense in the Consolidated Statement of Operations. Derivative Instruments The Company enters into financial derivative contracts, primarily collars, swaps and basis swaps, to manage its exposure to price fluctuations on a portion of its anticipated future production volumes. All of the Company’s derivatives are used for risk management purposes and are not held for trading purposes. The Company has elected not to designate its financial derivative instruments as accounting hedges under the accounting guidance. The Company evaluates all of its physical purchase and sale contracts to determine if they meet the definition of a derivative. For contracts that meet the definition of a derivative, the Company may elect the normal purchase normal sale (“NPNS”) exception provided under the applicable accounting guidance and account for the contract using the accrual method of accounting. Contracts that do not qualify for or for which the Company elects not to apply the NPNS exception are accounted for at fair value. All derivatives, except for derivatives that qualify for the NPNS exception, are recognized on the Consolidated Balance Sheet and are measured at fair value. At the end of each quarterly period, these derivatives are marked to market. As a result, changes in the fair value of derivatives are recognized in operating revenues in gain (loss) on derivative instruments. The resulting cash flows are reported as cash flows from operating activities. Leases The Company determines if an arrangement is, or contains, a lease at inception based on whether that contract conveys the right to control the use of an identified asset in exchange for consideration for a period of time. Operating leases are included in right-of-use assets (“ROU assets”) and lease liabilities (current and non-current) in the Consolidated Balance Sheet. Financing leases are included in properties and equipment, net and lease liabilities (current and non-current) in the Consolidated Balance Sheet. Short-term leases (a lease that, at commencement, has a lease term of one year or less and does not contain a purchase option that the Company is reasonably certain to exercise) are not recognized in ROU assets and lease liabilities. For all operating leases, lease and non-lease components are accounted for as a single lease component. ROU assets represent the Company’s right to use an underlying asset for the lease term and lease liabilities represent the Company’s obligation to make lease payments arising from the leases. ROU assets and lease liabilities are recognized at the lease commencement date based on the present value of minimum lease payments over the lease term. Most leases do not provide an implicit interest rate; therefore, the Company uses its incremental borrowing rate based on the information available at the inception date to determine the present value of the lease payments. Lease terms include options to extend the lease when it is reasonably certain that the Company will exercise that option. Lease cost for lease payments is recognized on a straight-line basis over the lease term. Certain leases have payment terms that vary based on the usage of the underlying assets. Variable lease payments are not included in ROU assets and lease liabilities. Fair Value of Assets and Liabilities The Company follows the authoritative accounting guidance for measuring fair value of assets and liabilities in its financial statements. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Company utilizes market data or assumptions that market participants who are independent, knowledgeable and willing and able to transact would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. The Company is able to classify fair value balances based on the observability of these inputs. The authoritative guidance for fair value measurements establishes three levels of the fair value hierarchy, defined as follows: • Level 1: Unadjusted, quoted prices for identical assets or liabilities in active markets. • Level 2: Quoted prices in markets that are not considered to be active or financial instruments for which all significant inputs are observable, either directly or indirectly for substantially the full term of the asset or liability. • Level 3: Significant, unobservable inputs for use when little or no market data exists, requiring a significant degree of judgment. 67
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Table of Contents The hierarchy gives the highest priority to Level 1 measurements and the lowest priority to Level 3 measurements. Depending on the particular asset or liability, input availability can vary depending on factors such as product type, longevity of a product in the market and other particular transaction conditions. In some cases, certain inputs used to measure fair value may be categorized into different levels of the fair value hierarchy. For disclosure purposes under the accounting guidance, the lowest level that contains significant inputs used in the valuation should be chosen. Revenue Recognition The Company’s revenue is typically generated from contracts to sell oil, natural gas and NGLs produced from interests in oil and gas properties owned by the Company. These contracts generally require the Company to deliver a specific amount of a commodity per day for a specified number of days at a price that is either fixed or variable. The contracts specify a delivery point which represents the point at which control of the product is transferred to the customer. The Company has determined that these contracts represent multiple performance obligations which are satisfied when control of the commodity transfers to the customer, typically through the delivery of the specified commodity to a designated delivery point. Revenue is measured based on consideration specified in the contract with the customer, and excludes any amounts collected on behalf of third parties. The Company recognizes revenue in the amount that reflects the consideration it expects to be entitled to in exchange for transferring control of those goods to the customer. The contract consideration in the Company’s variable price contracts are typically allocated to specific performance obligations in the contract according to the price stated in the contract. Amounts allocated in the Company’s fixed price contracts are based on the standalone selling price of those products in the context of long-term, fixed price contracts, which generally approximates the contract price. Payment is generally received one or two months after the sale has occurred. The Company has not adjusted the promised amount of consideration for the effects of a significant financing component if the Company expects, at contract inception, that the period between when the Company transfers a promised good or service to the customer and when the customer pays for that good or service will be one year or less. For contracts with an original expected term of one year or less, the Company has elected not to disclose the transaction price allocated to the unsatisfied performance obligations. For contracts with terms greater than one year, the Company has elected not to disclose the price allocated to the unsatisfied performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Since each unit of the respective commodity typically represents a separate performance obligation, future volumes are considered wholly unsatisfied, and disclosure of the transaction price allocated to the remaining performance obligation is not required. Taxes assessed by a governmental authority that are both imposed on and concurrent with a specific revenue-producing transaction, and that are collected by the Company from a customer, are excluded from revenue. Income Taxes The Company follows the asset and liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are recorded for the estimated future tax consequences attributable to the differences between the financial carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using the tax rate in effect for the year in which those temporary differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the year of the enacted rate change. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized. The Company follows the “equity first” approach when applying the limitation for certain executive compensation in excess of $1 million to future compensation. The limitation is first applied to stock-based compensation that vests in future tax years before considering cash compensation paid in a future period. Accordingly, the Company records a deferred tax asset for stock-based compensation expense recorded in the current period, and reverses the temporary difference in the future period, during which the stock-based compensation becomes deductible for tax purposes. The Company is required to make judgments, including estimating reserves for potential adverse outcomes regarding tax positions that the Company has taken. The Company accounts for uncertainty in income taxes using a recognition and measurement threshold for tax positions taken or expected to be taken in a tax return. The tax benefit from an uncertain tax position is recognized when it is more likely than not that the position will be sustained upon examination by taxing authorities based on technical merits of the position. The amount of the tax benefit recognized is the largest amount of the benefit that has a greater than 50 percent likelihood of being realized upon ultimate settlement. The effective tax rate and the tax basis of assets and liabilities reflect management’s estimates of the ultimate outcome of various tax uncertainties. 68
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Table of Contents The Company recognizes accrued interest related to uncertain tax positions in interest expense and accrued penalties related to such positions in G&A expense in the Consolidated Statement of Operations. Stock-Based Compensation The Company accounts for stock-based compensation under the fair value method of accounting. Under this method, compensation cost is measured at the grant date for equity-classified awards and re-measured each reporting period for liability-classified awards based on the fair value of an award and is recognized over the service period, which is generally the vesting period. To calculate fair value, the Company uses a Black Scholes or Monte Carlo valuation model based on the specific provisions of the award. Stock-based compensation cost for all types of awards is included in G&A expense in the Consolidated Statement of Operations. The Company records excess tax benefits and tax deficiencies on stock-based compensation in the income statement upon vesting of the respective awards. Excess tax benefits and tax deficiencies are included in cash flows from operating activities in the Consolidated Statement of Cash Flow. Cash paid by the Company when directly withholding shares from employee stock-based compensation awards for tax-withholding purposes are classified as financing activities in the Consolidated Statement of Cash Flow. Earnings per Share The Company calculates earnings per share recognizing that unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents are “participating securities” and, therefore, should be included in computing earnings per share using the two-class earnings allocation method. The two-class method is an earnings allocation formula that determines earnings per share for each class of common stock and participating security according to dividends declared (or accumulated) and participation rights in undistributed earnings. Certain of the Company’s unvested share-based payment awards, consisting of restricted stock, qualify as participating securities. The Company’s participating securities do not have a contractual obligation to share in the losses of the entity and, therefore, net losses are not allocated to them. Segment Reporting Operating segments are defined as components of an enterprise for which separate financial information is available and regularly evaluated by the Chief Operating Decision Maker (“CODM”) for the purpose of making key operating decisions, allocating resources, and assessing operating performance. The Company operates in one reportable operating segment, oil and natural gas development, exploration and production. The Company’s oil and gas properties are managed as a whole rather than through discrete operating segments. Financial and operational information is tracked by geographic area; however, financial performance is assessed as a single enterprise and not on a geographic basis. Allocation of resources is made on a project basis across the Company’s entire portfolio without regard to geographic area, and considers among other things, return on investment, current market conditions, including commodity prices and market supply, availability of services and human resources, and contractual commitments. The Company’s Chief Executive Officer is its CODM. The Company’s profitability measure is consolidated net income which is used to assess budgeted versus actual results and drives the Company’s operating cash flow. The CODM reviews significant consolidated forecasts and results of operations, including return on capital, operating expenses, and cash flow when making decisions such as the allocation of capital. The financial position, results of operations and cash flows of the Company’s reportable operating segment are consistent with the Company’s consolidated financial statements included herein. Environmental Matters Environmental expenditures are expensed or capitalized, as appropriate, depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations, and that do not have future economic benefit are expensed. Liabilities related to future costs are recorded on an undiscounted basis when environmental assessments and remediation activities are probable and the costs can be reasonably estimated. Any insurance recoveries are recorded as assets when received. Credit and Concentration Risk Substantially all of the Company’s accounts receivable result from the sale of oil, natural gas and NGLs to third parties in the oil and gas industry and joint interest billings with other participants in joint operations. This concentration of purchasers and joint owners may impact the Company’s overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions. The Company does not anticipate any material impact on its financial results due to non-performance by the third parties. 69
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Table of Contents During the year ended December 31, 2025, two customers accounted for approximately 22 percent and 14 percent of the Company’s total sales. During the year ended December 31, 2024, two customers accounted for approximately 21 percent and 19 percent of the Company’s total sales. During the year ended December 31, 2023, two customers accounted for approximately 19 percent and 17 percent of the Company’s total sales. The Company does not believe that the loss of any of its major customers would have a material adverse effect on it because alternative customers are readily available. If any one of the Company’s major customers were to stop purchasing the Company’s production, the Company believes there are a number of other purchasers to whom it could sell its production. If multiple significant customers were to stop purchasing the Company’s production, the Company believes there could be some initial challenges, but the Company believes it has ample alternative markets to handle any sales disruptions. The Company regularly monitors the creditworthiness of its customers and may require parent company guarantees, letters of credit or prepayments when necessary. Historically, losses associated with uncollectible receivables have been insignificant. Use of Estimates In preparing its financial statements, the Company follows GAAP. These principles require management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved oil and gas reserves and related cash flow estimates which are used to compute DD&A, impairments of proved oil and gas properties and the fair value of oil and gas properties in purchase accounting. Other estimates include oil, natural gas and NGL revenues and expenses, fair value of derivative instruments, estimates of expenses related to legal, environmental and other contingencies, asset retirement obligations, postretirement obligations, stock-based compensation and deferred income taxes. Actual results could differ from those estimates. 2. Mergers and Acquisitions Pending Merger Subsequent Event. On February 1, 2026, the Company entered into an Agreement and Plan of Merger (the “Merger Agreement”) with Devon Energy Corporation (“Devon”) to combine via an all-stock merger transaction (“Merger”). Devon is a leading oil and gas producer in the U.S. with a diversified multi-basin portfolio headlined by a world-class acreage position in the Delaware Basin. Under terms of the Merger Agreement, at closing Coterra stockholders will receive a fixed exchange ratio of 0.70 shares of Devon common stock for each share of Coterra common stock. Upon completion, Devon stockholders will own approximately 54 percent of the combined company and Coterra stockholders will own approximately 46 percent on a fully diluted basis. The respective Boards of Directors of the Company and Devon unanimously approved the Merger, which is still subject to the approval of the stockholders of each of the Company and Devon and the receipt of regulatory approvals, among other conditions. The Merger Agreement contains customary pre-closing covenants, including the obligations of each of Coterra and Devon to conduct their respective businesses in the ordinary course consistent with past practice and to refrain from taking certain specified actions without the consent of the other party. Until the approval by stockholders and subsequent closing, the Company must continue to operate as a stand-alone company. The Merger is expected to close in the second quarter of 2026, subject to stockholder approvals and other customary closing conditions. Franklin Mountain Energy (“FME”) Acquisition On January 27, 2025, the Company closed on its acquisition of all of the issued and outstanding equity ownership interests of a group of privately owned oil and gas exploration and production companies with assets and operations in the Delaware Basin of New Mexico (the “FME Interests”) for total consideration of $2.5 billion, which included $1.7 billion in cash and the issuance of 28,190,682 shares of the Company’s common stock valued at $785 million based on the closing price of the Company’s common stock on the closing date. In connection with and upon execution of the FME purchase agreement in November 2024, the Company deposited $125 million with an escrow agent which was included in restricted cash on the Company’s Consolidated Balance Sheet at December 31, 2024. All escrow account balances were released during 2025. 70
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Table of Contents Purchase Price Allocation The transaction was accounted for using the acquisition method of accounting. Under the acquisition method of accounting, the assets and liabilities of the FME Interests were recorded at their respective fair values as of the effective closing date of the acquisition. As of December 31, 2025, the purchase price allocation has been finalized. Determining the fair value of the assets and liabilities of the FME Interests required judgment and certain assumptions to be made. The most significant fair value estimates related to the valuation of the oil and gas properties and gathering and pipeline systems. Oil and gas properties and gathering and pipeline systems were valued using an income and market approach utilizing Level 3 inputs including internally generated production and development data and estimated price and cost estimates. The following table represents the allocation of the total purchase price of the FME Interests to the identifiable assets acquired and liabilities assumed based on the fair values as of the closing date of the acquisition: (In millions, except shares and share price) Purchase Price Allocation Consideration: Coterra common stock issued in exchange for FME equity interests 28,190,682 Coterra common stock closing price on January 27, 2025 $ 27.83 Total value of Coterra common stock issued $ 785 Cash consideration 1,733 Total consideration $ 2,518 Assets acquired: Current assets $ 178 Proved oil and gas properties 1,833 Unproved oil and gas properties 590 Gathering and pipeline systems 172 Other assets 6 Total assets acquired $ 2,779 Liabilities assumed: Current liabilities $ 239 Asset retirement obligations 13 Other liabilities 9 Total liabilities assumed $ 261 Net assets acquired $ 2,518 (1) Cash consideration included the release of escrow funds in the amount of $123 million in 2025. These funds were included in restricted cash in the Consolidated Balance Sheet as of December 31, 2024. FME Post-Acquisition Operating Results The FME Interests contributed the following to the Company’s consolidated operating results: (In millions) January 28, 2025 through December 31, 2025 Revenue $ 755 Net income $ 254 (1) 71
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Table of Contents Avant Acquisition On January 17, 2025, the Company closed on the acquisition of certain interests in oil and gas properties located in the Delaware Basin in New Mexico from certain privately owned sellers for total cash consideration of $1.5 billion (the “Avant assets”). In connection with and upon execution of the Avant purchase and sale agreement in November 2024, the Company deposited $109 million with an escrow agent which was included in restricted cash on the Company’s Consolidated Balance Sheet at December 31, 2024. All escrow account balances were released during 2025. Purchase Price Allocation The transaction was accounted for using the acquisition method of accounting. Under the acquisition method of accounting, the assets and liabilities acquired in the Avant assets acquisition were recorded at their respective fair values as of the closing date of the acquisition. As of December 31, 2025, the purchase price allocation has been finalized. Determining the fair value of the assets and liabilities of the Avant assets required judgment and certain assumptions to be made. The most significant fair value estimates related to the valuation of the oil and gas properties and gathering and pipeline systems. Oil and gas properties and gathering and pipeline systems were valued using an income and market approach utilizing Level 3 inputs including internally generated production and development data and estimated price and cost estimates. The following table represents the allocation of the total purchase price of the Avant assets to the identifiable assets acquired and liabilities assumed based on the fair values as of the closing date of the acquisition: (In millions) Purchase Price Allocation Consideration: Cash consideration $ 1,518 Total consideration $ 1,518 Assets acquired: Current assets $ 34 Proved oil and gas properties 640 Unproved oil and gas properties 696 Gathering and pipeline systems 161 Other assets 1 Total assets acquired $ 1,532 Liabilities assumed: Current liabilities $ 3 Asset retirement obligations 6 Other liabilities 5 Total liabilities assumed $ 14 Net assets acquired $ 1,518 (1) Cash consideration included the release of escrow funds in the amount of $109 million in 2025. These funds were included in restricted cash in the Consolidated Balance Sheet as of December 31, 2024. (1) 72
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Table of Contents Avant Post-Acquisition Operating Results The Avant assets contributed the following to the Company’s consolidated operating results: (In millions) January 18, 2025 through December 31, 2025 Revenue $ 248 Net income $ 40 Combined Unaudited Pro Forma Financial Information The results of operations of the FME Interests and Avant assets have been included in the Company’s consolidated financial statements since the closing date of the acquisitions. The following supplemental pro forma financial information for the year ended December 31, 2025 and 2024 have been prepared to give effect to the acquisitions of the FME Interests and the Avant assets as if they had occurred on January 1, 2024. The information below reflects pro forma adjustments based on available information and certain assumptions that the Company believes are factual and supportable. The pro forma results of operations do not include any cost savings or other synergies that may have resulted from the acquisitions or any estimated costs that have been incurred by the Company to integrate the FME Interests and Avant assets. The pro forma financial information is not necessarily indicative of the results that might have occurred had the transactions actually taken place on January 1, 2024 and is not intended to be a projection of future results. Future results may vary significantly from the results reflected in the following pro forma financial information because of normal production declines, changes in commodity prices, future acquisitions and divestitures, future development and exploration activities and other factors. The following table represents the unaudited pro forma effect on the Company of the FME and Avant acquisitions as if they had occurred on January 1, 2024: December 31, (In millions) 2025 2024 Pro forma revenue $ 7,737 $ 6,737 Pro forma net income $ 1,748 $ 1,475 Other Information In connection with the FME and Avant acquisitions, the Company recognized $15 million of transaction costs for the year ended December 31, 2025. These costs are primarily related to integration costs, advisory and legal fees and are included in G&A expense in the Consolidated Statement of Operations. 73
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Table of Contents 3. Properties and Equipment, Net Properties and equipment, net are comprised of the following: December 31, (In millions) 2025 2024 Proved oil and gas properties $ 27,058 $ 21,765 Unproved oil and gas properties 4,834 4,105 Gathering and pipeline systems 1,065 620 Land, buildings and other equipment 270 213 Finance lease right-of-use asset — 26 33,227 26,729 Accumulated DD&A (11,169) (8,839) $ 22,058 $ 17,890 Capitalized Exploratory Well Costs As of and for the years ended December 31, 2025, 2024 and 2023, the Company did not have any projects with exploratory well costs capitalized for a period of greater than one year after drilling. 74
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Table of Contents 4. Long-Term Debt and Credit Agreements The following table includes a summary of the Company’s long-term debt. December 31, (In millions) 2025 2024 Private placement senior notes: 3.77% senior notes due September 18, 2026 $ 250 $ 250 Senior notes: 3.90% senior notes due May 15, 2027 750 750 4.375% senior notes due March 15, 2029 500 500 5.60% senior notes due March 15, 2034 500 500 5.40% senior notes due February 15, 2035 750 750 5.90% senior notes due February 15, 2055 750 750 Term loan: Tranche A term loan due January 27, 2027 — — Tranche B term loan due January 17, 2028 300 — 3,800 3,500 Unamortized debt premium 47 69 Unamortized debt discount (9) (10) Unamortized debt issuance costs (20) (24) Total debt, net 3,818 3,535 Less: current portion of long-term debt 250 — Long-term debt $ 3,568 $ 3,535 Long-Term Debt Maturity As of December 31, 2025, maturities of long-term debt over the next five years were as follows: (In millions) Year Ending December 31, 2026 $ 250 2027 750 2028 300 2029 500 2030 — Thereafter 2,000 Total long-term debt $ 3,800 Private Placement Senior Notes The private placement senior notes are general, unsecured obligations of the Company. Interest is payable semi-annually. Under the terms of the note purchase agreement, the Company may prepay all or any portion of the notes on any date at a price equal to the principal amount thereof plus accrued and unpaid interest plus a make-whole premium. The note purchase agreement provides that the Company must maintain a minimum annual coverage ratio of consolidated cash flow to interest expense for the trailing four quarters of not less than 2.8 to 1.0 and requires the Company to maintain, as of the last day of any fiscal quarter, a maximum ratio of total debt to consolidated EBITDAX for the trailing four quarters of not more than 3.0 to 1.0. There are also various other covenants and events of default customarily found in such debt instrument. As of December 31, 2025, the Company was in compliance with its financial covenants under the private placement senior notes. 75
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Table of Contents Senior Notes The senior notes (the “Senior Notes”) are general, unsecured obligations of the Company. Interest on each series of Senior Notes is payable semi-annually. Under the terms of the indenture documents governing the Senior Notes, the Company may redeem all or any portion of the Senior Notes of each series on any date at a price equal to the principal amount thereof plus applicable redemption prices described in the governing indentures. The Company is also subject to various covenants and events of default customarily found in such debt instruments. In March 2024, the Company issued $500 million aggregate principal amount of 5.60% senior notes due 2034 (the “2034 Senior Notes”). The 2034 Senior Notes will mature on March 15, 2034 and were issued at a discount of $1 million. The Company incurred approximately $5 million of debt issuance costs that were capitalized and are being amortized over the term of such notes. In December 2024, the Company issued $750 million aggregate principal amount of 5.40% senior notes due 2035 (the “2035 Senior Notes”) and $750 million aggregate principal amount of 5.90% senior notes due 2055 (the “2055 Senior Notes”). The 2035 Senior Notes and the 2055 Senior Notes will mature on February 15, 2035 and February 15, 2055, respectively, and were issued at a discount of $3 million and $5 million, respectively. The Company incurred approximately $7 million and $8 million of debt issuance costs for the 2035 Senior Notes and 2055 Senior Notes, respectively, that were capitalized and are being amortized over the term of such notes. Term Loan In December 2024, the Company entered into a delayed draw term loan credit agreement with Toronto Dominion (Texas), LLC, as administrative agent, and certain other lenders and issuing banks (the “Term Loan”), which consists of a $500 million Tranche A Term Loan and a $500 million Tranche B Term Loan. The Tranche A Term Loan matures two years after funding, and the Tranche B Term Loan matures three years after funding. Borrowings under the Term Loan can be prepaid without penalty. In January 2025, the Company borrowed $500 million under the Tranche A Term Loan to partially fund the acquisition of the FME Interests and $500 million of the Tranche B Term Loan to partially fund the acquisition of the Avant assets. During 2025, the Company repaid the full $500 million of the Tranche A Term Loan and $200 million of the Tranche B Term Loan. Subsequent Event. In February 2026, the Company repaid the remaining $300 million of the Tranche B Term Loan. Borrowings under the Term Loan bear interest at a rate per annum equal to, at the Company’s option, either a term secured overnight financing rate (“SOFR”) plus a 0.10 percent credit spread adjustment for all tenors or a base rate, plus an interest rate margin which ranges from 0 to 75 basis points for base rate loans, 100 to 175 basis points for Tranche A SOFR Term Loans and 112.5 to 187.5 basis points for Tranche B SOFR Term Loans based on the Company’s credit rating. During the year ended December 31, 2025, the weighted-average effective interest rate on the Company’s Term Loan was approximately 5.8 percent. As of December 31, 2025, the effective interest rate on the Company’s Term Loan was approximately 5.2 percent. The Company incurred $2 million of debt issuance costs which were capitalized and are being amortized over the term of the Term Loan. The Term Loan contains customary covenants, including the maintenance of a maximum leverage ratio of no more than 3.0 to 1.0 as of the last day of any fiscal quarter until such time as the Company has no other debt (other than the Company’s Credit Agreement as defined below) in a principal amount in excess of $75 million outstanding that has a financial maintenance covenant based on a leverage ratio, at which time the Term Loan requires maintenance of a ratio of total net debt to total capitalization of no more than 65 percent (with all calculations based on definitions contained in the Term Loan). As of December 31, 2025, the Company was in compliance with its financial covenants under the Term Loan. Revolving Credit Agreement On September 12, 2024, the Company entered into an Amendment No. 1 (the “Amendment”) relating to its revolving credit agreement with JPMorgan Chase Bank, N.A., as administrative agent, and certain lenders and issuing banks party thereto (as amended by the Amendment, and further amended, supplemented or otherwise modified from time-to-time, the “Credit Agreement”). The Amendment has increased the aggregate revolving commitments under the Credit Agreement from $1.5 billion to $2.0 billion, extended the Credit Agreement maturity date from March 10, 2028 to September 12, 2029, made certain amendments to the representations and warranties, affirmative and negative covenants and events of default, and made certain other modifications. The Company incurred $4 million of debt issuance costs related to the Amendment which were capitalized and will be amortized over the term of the amended Credit Agreement. Borrowings under the Credit Agreement bear interest at a rate per annum equal to, at the Company’s option, either a term SOFR plus a 0.10 percent credit spread adjustment for all tenors or a base rate, plus, in each case, an interest rate margin which 76
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Table of Contents ranges from 0 to 75 basis points for base rate loans and 100 to 175 basis points for term SOFR loans, based on the Company’s credit rating. The commitment fee on the unused available credit is calculated at annual rates ranging from 10 basis points to 25 basis points, based on the Company’s credit rating. The maturity date of the Credit Agreement can be extended for additional one-year periods on up to two occasions upon the agreement of the Company and lenders holding at least 50 percent of the commitments under the Credit Agreement. The Credit Agreement contains customary covenants, including the maintenance of a maximum leverage ratio of no more than 3.0 to 1.0 as of the last day of any fiscal quarter. At such time as the Company has no other debt in a principal amount in excess of $75 million outstanding that has a financial maintenance covenant based on a substantially similar leverage ratio, in lieu of such maximum leverage ratio covenant, the Credit Agreement will instead require the Company to maintain a ratio of total net debt to capitalization of no more than 65 percent (with all calculations based on definitions contained in the Credit Agreement). As of December 31, 2025, the Company was in compliance with its financial covenants under the Credit Agreement. During 2025, the Company borrowed and repaid $746 million under its revolving credit agreement. The Company’s weighted-average interest rate for borrowings under the revolving credit agreement for the year ended December 31, 2025 was 7.5 percent. There were no borrowings under the revolving credit agreement during 2024. As of December 31, 2025, the Company had no borrowings outstanding under its revolving credit agreement and unused commitments of $2.0 billion. 5. Derivative Instruments As of December 31, 2025, the Company had the following outstanding financial commodity derivatives: 2026 Oil First Quarter Second Quarter Third Quarter Fourth Quarter WTI oil collars Volume (MBbl) 3,600 3,640 3,680 3,680 Weighted average floor ($/Bbl) $ 56.25 $ 56.25 $ 56.25 $ 56.25 Weighted average ceiling ($/Bbl) $ 70.81 $ 70.81 $ 70.81 $ 70.81 WTI NYMEX oil swaps Volume (MBbl) 900 910 920 920 Weighted average price ($/Bbl) $ 66.14 $ 66.14 $ 66.14 $ 66.14 WTI Midland oil basis swaps Volume (MBbl) 4,500 4,550 4,600 4,600 Weighted average differential ($/Bbl) $ 0.97 $ 0.97 $ 0.97 $ 0.97 77
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Table of Contents 2026 2027 Natural Gas First Quarter Second Quarter Third Quarter Fourth Quarter First Quarter Second Quarter Third Quarter Fourth Quarter NYMEX gas collars Volume (MMBtu) 108,000,000 81,900,000 82,800,000 82,800,0007,200,000 7,280,000 7,360,000 7,360,000 Weighted average floor ($/MMBtu) $ 3.23 $ 3.39 $ 3.39 $ 3.39 $ 3.40 $ 3.40 $ 3.40 $ 3.40 Weighted average ceiling ($/MMBtu) $ 6.12 $ 5.61 $ 5.61 $ 5.61 $ 5.17 $ 5.17 $ 5.17 $ 5.17 Transco Leidy gas basisswaps Volume (MMBtu) 13,500,000 13,650,000 13,800,000 13,800,000 — — — — Weighted averagedifferential ($/MMBtu)$ (0.78) $ (0.78) $ (0.78) $ (0.78) $ — $ — $ — $ — Transco Zone 6 Non-NY gasbasis swaps Volume (MMBtu) 22,500,000 22,750,000 23,000,000 23,000,000 — — — — Weighted averagedifferential ($/MMBtu)$ (0.16) $ (0.16) $ (0.16) $ (0.16) $ — $ — $ — $ — Waha gas basis swaps Volume (MMBtu) 18,000,000 18,200,000 18,400,000 18,400,000 — — — — Weighted average differential ($/MMBtu)$ (1.92) $ (1.92) $ (1.92) $ (1.92) $ — $ — $ — $ — In January 2026, the Company entered into the following financial commodity derivatives: 2026 Oil First Quarter Second Quarter Third Quarter Fourth Quarter WTI oil collars Volume (MBbl) 590 910 920 920 Weighted average floor ($/Bbl) $ 55.00 $ 55.00 $ 50.00 $ 50.00 Weighted average ceiling ($/Bbl) $ 67.40 $ 67.40 $ 69.25 $ 69.25 2026 Natural Gas First Quarter Second Quarter Third Quarter Fourth Quarter Transco Leidy gas basis swaps Volume (MMBtu) 5,900,000 9,100,000 9,200,000 9,200,000 Weighted average differential ($/MMBtu) $ (0.79) $ (0.79) $ (0.79) $ (0.79) Effect of Derivative Instruments on the Consolidated Balance Sheet Fair Values of Derivative Instruments Derivative Assets Derivative Liabilities December 31, December 31, (In millions) Balance Sheet Location 2025 2024 2025 2024 Commodity contracts Other current assets $ 235 $ 12 $ — $ — Commodity contracts Accrued liabilities — — 2 17 Commodity contracts Other assets 3 — — — Commodity contracts Other liabilities — — — 4 $ 238 $ 12 $ 2 $ 21 78
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Table of Contents Offsetting of Derivative Assets and Liabilities in the Consolidated Balance Sheet December 31, (In millions) 2025 2024 Derivative assets Gross amounts of recognized assets $ 242 $ 26 Gross amounts offset in the consolidated balance sheet (4) (14) Net amounts of assets presented in the consolidated balance sheet 238 12 Gross amounts of financial instruments not offset in the consolidated balance sheet 15 — Net amount $ 253 $ 12 Derivative liabilities Gross amounts of recognized liabilities $ 6 $ 35 Gross amounts offset in the consolidated balance sheet (4) (14) Net amounts of liabilities presented in the consolidated balance sheet 2 21 Gross amounts of financial instruments not offset in the consolidated balance sheet — — Net amount $ 2 $ 21 Effect of Derivative Instruments on the Consolidated Statement of Operations Year Ended December 31, (In millions) 2025 2024 2023 Cash received on settlement of derivative instruments Oil contracts $ 57 $ 2 $ 4 Gas contracts 49 96 280 Non-cash gain (loss) on derivative instruments Oil contracts 82 (21) 18 Gas contracts 163 (80) (72) $ 351 $ (3) $ 230 Additional Disclosures about Derivative Instruments The use of derivative instruments involves the risk that the counterparties will be unable to meet their obligations under the agreements. The Company’s counterparties are primarily commercial banks and financial service institutions that management believes present minimal credit risk and its derivative contracts are with multiple counterparties to minimize its exposure to any individual counterparty. The Company performs both quantitative and qualitative assessments of these counterparties based on their credit ratings and credit default swap rates where applicable. Certain counterparties to the Company’s derivative instruments are also lenders under its revolving credit agreement and term loan. The Company’s revolving credit agreement, term loan and derivative instruments contain certain cross default and acceleration provisions that may require immediate payment of the Company’s liabilities thereunder if the Company defaults on other material indebtedness. The Company also has netting arrangements with each of its counterparties that allow it to offset assets and liabilities from separate derivative contracts with that counterparty. 79
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Table of Contents 6. Fair Value Measurements Financial Assets and Liabilities The following fair value hierarchy table presents information about the Company’s financial assets and liabilities measured at fair value on a recurring basis: (In millions) Quoted Prices inActive Markets forIdentical Assets(Level 1) Significant OtherObservable Inputs(Level 2) SignificantUnobservableInputs(Level 3) Balance atDecember 31,2025 Assets Deferred compensation plan $ 21 $ — $ — $ 21 Derivative instruments — 32 210 242 Total assets $ 21 $ 32 $ 210 $ 263 Liabilities Deferred compensation plan $ 21 $ — $ — $ 21 Derivative instruments — — 6 6 Total liabilities $ 21 $ — $ 6 $ 27 (In millions) Quoted Prices inActive Markets forIdentical Assets(Level 1) Significant OtherObservable Inputs(Level 2) SignificantUnobservableInputs(Level 3) Balance atDecember 31,2024 Assets Deferred compensation plan $ 17 $ — $ — $ 17 Derivative instruments — — 26 26 Total assets $ 17 $ — $ 26 $ 43 Liabilities Deferred compensation plan $ 17 $ — $ — $ 17 Derivative instruments — — 35 35 Total liabilities $ 17 $ — $ 35 $ 52 The Company’s investments associated with its deferred compensation plan consist of mutual funds that are publicly traded and for which market prices are readily available. The derivative instruments were measured based on quotes from the Company’s third-party valuation service provider. Such quotes have been derived using an income approach that considers various inputs, including current market and contractual prices for the underlying instruments, quoted forward commodity prices, basis differentials, volatility factors and interest rates for a similar length of time as the derivative contract term as applicable. Estimates are derived from or verified using relevant NYMEX futures contracts and are compared to multiple quotes obtained from counterparties. The determination of the fair values presented above also incorporates a credit adjustment for non-performance risk. Non-performance risk of the Company’s counterparties is measured by reviewing credit default swap spreads for the various financial institutions with which the Company has derivative contracts while non-performance risk of the Company is evaluated using credit default swap spreads for various similarly rated companies in the same sector as the Company. The Company has not incurred any losses related to non-performance risk of its counterparties and does not anticipate any material impact on its financial results due to non- performance by third parties. The most significant unobservable inputs relative to the Company’s Level 3 derivative contracts are basis differentials, discount rates and volatility factors. An increase (decrease) in these unobservable inputs would result in an increase (decrease) in fair value, respectively. The Company does not have access to the specific assumptions used in the models provided by third-party valuation service providers or its counterparties’ valuation models. Consequently, additional disclosures regarding significant Level 3 unobservable inputs were not provided. 80
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Table of Contents The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy: Year Ended December 31, (In millions) 2025 2024 2023 Balance at beginning of period $ (9) $ 92 $ 146 Total gain (loss) included in earnings 288 (3) 230 Settlement (gain) loss (75) (98) (284) Balance at end of period $ 204 $ (9) $ 92 Change in unrealized gains (losses) relating to assets and liabilities still held at the end of the period $ 208 $ (16) $ 92 Non-Financial Assets and Liabilities The Company discloses or recognizes its non-financial assets and liabilities, such as impairments of oil and gas properties or acquisitions, at fair value on a nonrecurring basis. In January 2025, the Company completed the FME and Avant acquisitions and recorded the assets acquired and liabilities assumed at fair value. The most significant fair value determinations for non-financial assets and liabilities are related to acquired oil and gas properties and gathering and pipeline systems. Refer to Note 2 of the Notes to the Consolidated Financial Statements, “Mergers and Acquisitions”, for additional information. As none of the Company’s other non-financial assets and liabilities were measured at fair value as of December 31, 2025, 2024 and 2023, additional disclosures were not required. The estimated fair value of the Company’s asset retirement obligations at inception is determined by utilizing the income approach by applying a credit-adjusted risk-free rate, which takes into account the Company’s credit risk, the time value of money, and the current economic state to the undiscounted expected abandonment cash flows. Given the unobservable nature of the inputs, the measurement of the asset retirement obligations was classified as Level 3 in the fair value hierarchy. Fair Value of Other Financial Instruments The estimated fair value of other financial instruments is the amount at which the instruments could be exchanged currently between willing parties. The carrying amounts reported in the Consolidated Balance Sheet for cash and cash equivalents and restricted cash approximate fair value, due to the short-term maturities of these instruments. Cash and cash equivalents and restricted cash are classified as Level 1 in the fair value hierarchy and the remaining financial instruments are classified as Level 2. The fair value of the Company’s senior notes is based on quoted market prices, which is classified as Level 1 in the fair value hierarchy. The fair value of the Company’s private placement senior notes is based on third-party quotes, which are derived from credit spreads for the difference between the issue rate and the period end market rate and other unobservable inputs. The Company’s private placement senior notes are valued using a market approach and are classified as Level 3 in the fair value hierarchy. The fair value of the Company’s Term Loan approximates the carrying value as the interest rates are variable and reflective of market rates. The Company’s Term Loan is classified as Level 1 in the fair value hierarchy. The carrying amount and estimated fair value of debt is as follows: December 31, 2025 December 31, 2024 (In millions) CarryingAmount EstimatedFair Value CarryingAmount EstimatedFair Value Total debt $ 3,818 $ 3,798 $ 3,535 $ 3,395 Current maturities (250) (249) — — Long-term debt, excluding current maturities $ 3,568 $ 3,549 $ 3,535 $ 3,395 81
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Table of Contents 7. Asset Retirement Obligations Activity related to the Company’s asset retirement obligations is as follows: Year Ended December 31, (In millions) 2025 2024 2023 Balance at beginning of period $ 302 $ 289 $ 277 Liabilities assumed in acquisition 19 — — Liabilities incurred 11 9 6 Liabilities settled (2) (7) (1) Liabilities divested — — (4) Accretion expense 13 11 11 Balance at end of period $ 343 $ 302 $ 289 Less: current asset retirement obligation (14) (11) (9) Noncurrent asset retirement obligation $ 329 $ 291 $ 280 8. Commitments and Contingencies Gathering, Processing and Transportation Agreements As of December 31, 2025, the Company’s future minimum obligations under gathering, processing and transportation agreements are as follows: (In millions) Gathering and Transportation Gas Processing Volume Delivery Water Delivery Year Ending December 31, 2026 $ 193 $ 84 $ 21 $ 7 2027 231 80 17 7 2028 190 72 13 6 2029 182 26 — 6 2030 169 23 — 5 Thereafter 888 36 — — Total $ 1,853 $ 321 $ 51 $ 31 Gathering, Processing and Transportation Commitments The Company has entered into certain gathering and transportation agreements with various pipeline carriers. Under certain of these agreements, the Company is obligated to ship minimum daily quantities, or pay for any deficiencies at a specified rate. The Company’s forecasted production to be shipped on these pipelines is expected to exceed minimum daily quantities provided in the agreements. The Company is also obligated under certain of these arrangements to pay a demand charge for firm capacity rights on pipeline systems regardless of the amount of pipeline capacity utilized by the Company. If the Company does not utilize the capacity, it can release it to others, thus reducing its potential liability. Gas Processing Commitments The Company has entered into certain gas processing agreements. Under certain of these agreements, the Company is obligated to process minimum daily quantities, or pay for any deficiencies at a specified rate. The Company’s forecasted production to be processed under most of these agreements is expected to exceed minimum daily quantities provided in the agreements. Volume Delivery Commitments The Company also has minimum volume delivery commitments associated with agreements to reimburse connection costs to various pipelines. Under certain of these agreements, the Company is obligated to deliver minimum daily quantities, or pay for any deficiencies at a specified rate. The Company’s forecasted production to be delivered under most of these agreements is expected to exceed minimum daily quantities provided in the agreements. 82
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Table of Contents Water Delivery Commitments The Company has minimum volume water delivery commitments associated with a water services agreement that expires in 2030. The Company is obligated to deliver minimum daily quantities or pay for any deficiencies at a specified rate. As of December 31, 2025, the Company had an accrued liability of $13 million associated with this commitment, representing the present value of estimated amounts payable due to insufficient forecasted delivery volumes. Power Purchase Commitments The Company has entered into certain agreements to purchase electrical power. Under certain of these agreements, the Company is obligated to purchase minimum quantities at a fixed rate, or pay for any deficiencies at a specified rate. As of December 31, 2025, the Company’s future minimum obligations under electric power purchase agreements are as follows: (In millions) Amount Year Ending December 31, 2026 $ 6 2027 23 2028 28 2029 7 Total $ 64 Lease Commitments The Company has operating leases for office space, surface use agreements, compressor services, electric hydraulic fracturing services and other leases. The leases have remaining terms ranging from one month to 20 years, including options to extend leases that the Company is reasonably certain to exercise. During the year ended December 31, 2025, the Company recognized operating lease cost and variable lease cost of $120 million and $561 million, respectively. During the year ended December 31, 2024, the Company recognized operating lease cost and variable lease cost of $131 million and $245 million, respectively. Short-term leases. The Company leases drilling rigs, fracturing and other equipment under lease terms ranging from 30 days to one year. Lease cost of $686 million and $387 million was recognized on short-term leases during the year ended December 31, 2025 and 2024, respectively. Certain lease costs are capitalized and included in properties and equipment, net in the Consolidated Balance Sheet because they relate to drilling and completion activities, while other costs are expensed because they relate to production and administrative activities. 83
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Table of Contents As of December 31, 2025, the Company’s future undiscounted minimum cash payment obligations for its operating lease liabilities are as follows: (In millions) Amount Year Ending December 31, 2026 $ 75 2027 39 2028 30 2029 17 2030 14 Thereafter 38 Total undiscounted future lease payments 213 Present value adjustment (25) Net operating lease liabilities $ 188 Supplemental cash flow information related to leases was as follows: Year Ended December 31, (In millions) 2025 2024 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 128 $ 137 The Company’s financing lease matured in August 2025. For the year ended December 31, 2024, financing cash flows from financing leases was $5 million. Information regarding the weighted-average remaining lease term and the weighted-average discount rate for operating leases is summarized below: December 31, 2025 2024 Weighted-average remaining lease term (in years) 5.0 4.1 Weighted-average discount rate 4.8 % 4.2 % The Company’s financing lease matured in August 2025. For the year ended December 31, 2024, the weighted-average remaining lease term for financing leases was 0.7 years and the weighted-average discount rate for financing leases was 3.2 percent. Legal Matters The Company is a defendant in various legal proceedings arising in the normal course of business. While the outcome and impact of these legal proceedings on the Company cannot be predicted with certainty, management believes that the resolution of these proceedings will not have a material effect on the Company’s financial position, results of operations or cash flows. Contingency Reserves When deemed necessary, the Company establishes reserves for certain legal proceedings. All known liabilities for legal matters are accrued when management determines they are probable and the potential loss is estimable. The establishment of a reserve is based on an estimation process that includes the advice of legal counsel and subjective judgment of management. While management believes these reserves to be adequate, it is reasonably possible that the Company could incur additional losses with respect to those matters for which reserves have been established. The Company believes that any such amount above the amounts accrued would not be material to the Consolidated Financial Statements. Future changes in facts and circumstances not currently known or foreseeable could result in the actual liability exceeding the estimated ranges of loss and amounts accrued. 84
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Table of Contents 9. Revenue Recognition Disaggregation of Revenue The following table presents revenues from contracts with customers disaggregated by product: Year Ended December 31, (In millions) 2025 2024 2023 Oil $ 3,699 $ 2,953 $ 2,667 Natural gas 2,633 1,693 2,292 NGL 844 738 644 Other 118 77 81 $ 7,294 $ 5,461 $ 5,684 All of the Company’s revenues from contracts with customers represent products transferred at a point in time as control is transferred to the customer and generated in the U.S. Transaction Price Allocated to Remaining Performance Obligations A significant number of the Company’s product sales contracts are short-term in nature with a contract term of one year or less. For those contracts, the Company has utilized the practical expedient exempting the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. As of December 31, 2025, the Company has $5.5 billion of unsatisfied performance obligations related to natural gas sales that have a fixed pricing component and a contract term greater than one year. The Company expects to recognize these obligations over the next 13 years. Contract Balances Receivables from contracts with customers are recorded when the right to consideration becomes unconditional, generally when control of the product has been transferred to the customer. Receivables from contracts with customers were $968 million and $820 million as of December 31, 2025 and 2024, respectively, and are reported in accounts receivable, net in the Consolidated Balance Sheet. As of December 31, 2025 and 2024, the Company had no assets or liabilities related to its revenue contracts, including no upfront payments or rights to deficiency payments. 85
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Table of Contents 10. Income Taxes Income tax expense is summarized as follows: Year Ended December 31, (In millions) 2025 2024 2023 Current Federal $ 99 $ 343 $ 387 State 12 26 42 111 369 429 Deferred Federal 372 (72) 52 State 63 (73) 22 435 (145) 74 Income tax expense $ 546 $ 224 $ 503 Income tax expense was different than the amounts computed by applying the statutory federal income tax rate as follows: Year Ended December 31, 2025 2024 2023 (In millions, except rates) Amount Rate Amount Rate Amount Rate U.S. federal statutory tax rate $ 475 21.00 % $ 283 21.00 % $ 447 21.00 % State and local income taxes, net of federalincome tax effect Statutory state income tax, net of federalbenefit 45 1.99 % 9 0.71 % 29 1.35 % Blended deferred rate adjustment 33 1.48 % (26) (1.96)% 16 0.73 % Changes in state valuation allowances (11) (0.51)% (27) (2.00)% 3 0.13 % Other — — % (1) (0.08)% — — % Tax credits (13) (0.57)% (14) (1.06)% (14) (0.65)% Changes in valuation allowances — — % (15) (1.09)% — — % Nontaxable or nondeductible items 10 0.44 % 9 0.67 % 10 0.47 % Changes in unrecognized tax benefits 7 0.33 % (4) (0.29)% 6 0.31 % Other adjustments — (0.02)% 10 0.76 % 6 0.30 % Effective tax rate $ 546 24.14 % $ 224 16.66 % $ 503 23.64 % (1) State taxes in New Mexico, Oklahoma, and Pennsylvania make up the majority (greater than 50 percent) of the tax effect in this category. The Company's overall effective tax rate increased in 2025 compared to 2024, primarily due to deferred tax adjustments related to changes in the overall state tax rate and lower benefits from valuation allowance releases in 2025. The Company’s overall effective tax rate decreased in 2024 compared to 2023, primarily due to benefits from valuation allowance releases and deferred tax adjustments related to changes in the overall state tax rate. (1) 86
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Table of Contents Cash paid for income taxes, net of refunds, is summarized as follows: Year Ended December 31, (In millions) 2025 2024 2023 Federal $ 266 $ 309 $ 348 State New Mexico 15 20 17 Other states 10 10 19 Total State 25 30 36 Cash paid for income taxes, net of refunds $ 291 $ 339 $ 384 The composition of net deferred tax liabilities is as follows: December 31, (In millions) 2025 2024 Deferred Tax Assets Net operating losses $ 157 $ 166 Incentive compensation 38 44 Deferred compensation 1 1 Leases 36 19 Derivative instruments — 2 Other 48 45 Less: valuation allowance (61) (72) Total 219 205 Deferred Tax Liabilities Properties and equipment 3,828 3,456 Leases 40 22 Derivative instruments 53 — Other 1 1 Total 3,922 3,479 Net deferred tax liabilities $ 3,703 $ 3,274 At December 31, 2025, the Company had federal net operating loss carryforwards of approximately $338 million, of which $273 million is subject to expiration in years 2035 through 2037, and of which $65 million does not expire. The Company had a valuation allowance on $38 million of the federal net operating loss carryforwards, but believes the remaining $300 million will be fully utilized prior to expiration. The Company had gross state net operating loss carryforwards of $2.5 billion at December 31, 2025, primarily expiring between 2026 and 2043, with all but $1.2 billion covered by a valuation allowance. The Company also had other credit carryforwards of $15 million at December 31, 2025 that are offset by $4 million of valuation allowances. As of December 31, 2025, the Company had $8 million of valuation allowances on the deferred tax benefits related to federal net operating loss carryforwards, $49 million of valuation allowances on the deferred tax benefits related to state net operating loss carryforwards, and $4 million of valuation allowances on the deferred tax benefits related to other credit carryforwards. The Company believes it is more likely than not that the remainder of its deferred tax benefits will be utilized prior to their expiration. 87
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Table of Contents Unrecognized Tax Benefits A reconciliation of unrecognized tax benefits is as follows: Year Ended December 31, (In millions) 2025 2024 2023 Balance at beginning of period $ 16 $ 20 $ 13 Additions for tax positions of current period 8 3 4 Additions for tax positions of prior periods — — 3 Reductions for tax positions of prior periods — (7) — Balance at end of period $ 24 $ 16 $ 20 During 2025, the Company recorded an $8 million reserve for unrecognized tax benefits related to estimated current year research and development tax credits and Pennsylvania state apportionment matters. As of December 31, 2025, the Company’s overall net reserve for unrecognized tax benefits was $24 million, with a $6 million liability for accrued interest on the uncertain tax benefits. If recognized, the net tax benefit of $24 million would not have a material effect on the Company’s effective tax rate. The Company files income tax returns in the U.S. federal, various states and other jurisdictions. The Company is no longer subject to examinations by state authorities before 2012 or by federal authorities before 2018. The Company believes that appropriate provisions have been made for all jurisdictions and all open years, and that any assessment on these filings will not have a material impact on the Company’s financial position, results of operations or cash flows. Recent U.S. Tax Legislation On July 4, 2025, the U.S. enacted significant tax legislation under H.R. 1, the One Big Beautiful Bill Act (“OBBBA”). The effects of the provisions of the OBBBA have been reflected in the Company’s financial statements for the year ended December 31, 2025. While the enactment of the OBBBA did not result in a material change to the Company’s total income tax expense, it had a material impact on the allocation between current and deferred taxes. Specifically, the reinstatement of 100 percent bonus depreciation and immediate expensing of domestic research and development costs resulted in a significant reduction to current tax expense, with a corresponding increase in deferred tax expense. 11. Employee Benefit Plans Postretirement Benefits The Company provides health care benefits to certain former employees, including their spouses, eligible dependents and surviving spouses (retirees). These benefits are commonly called postretirement benefits. The health care plans are contributory, with participants’ contributions adjusted annually. Most employees that participate in the plan become eligible for these benefits when they meet certain age and service requirements at retirement. Eligibility to receive postretirement benefits was frozen in 2022 to include only former employees already receiving benefits at that time and certain grandfathered employees. During 2022, the Company amended its postretirement plans to phase out all postretirement benefits and freeze future participation in the plan. Certain employees were grandfathered under the plan amendment and remain eligible for future participation in the pre-65 plan upon their retirement based on certain age and years of service criteria, while the post-65 benefit for all plan participants that reach the age of 65 after December 31, 2022, including current retirees participating in the pre-65 plan, was eliminated. Existing retirees participating in both the pre-65 and post-65 plans prior to December 31, 2022 will continue to receive benefits under the plan until the age of 65 in the case of the pre- 65 participants, or voluntary termination of benefits or by death in the case of post-65 participants. As of December 31, 2025 and 2024, the Company provided postretirement benefits to 241 and 267 retirees and their dependents, respectively. Retirement Savings Plan The Company has a Retirement Savings Plan (“RSP”), which is a defined contribution plan. The Company matches a portion of employees’ contributions in cash. Participation in the RSP is voluntary and all employees of the Company are eligible to participate. The Company matches employee contributions dollar-for-dollar, up to the maximum Internal Revenue Service (“IRS”) limit, on the first six percent of an employee’s pre-tax earnings. The RSP also provides for discretionary contributions in an amount equal to 10 percent of an eligible plan participant’s salary and bonus. 88
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Table of Contents During the years ended December 31, 2025, 2024 and 2023, the Company made aggregate contributions to the RSP of $27 million, $19 million and $19 million, respectively, which are included in operating expense based on the classification of the corresponding salaries in the Consolidated Statement of Operations. Deferred Compensation Plans The Company has deferred compensation plans which are available to officers and select employees and act as a supplement to the RSP. The Internal Revenue Code does not cap the amount of compensation that may be taken into account for purposes of determining contributions to the deferred compensation plans and does not impose limitations on the amount of contributions to the deferred compensation plans. At the present time, the Company anticipates making a contribution to the deferred compensation plans on behalf of a participant in the event that Internal Revenue Code limitations cause a participant to receive less than the Company contribution under the RSP. The assets of the deferred compensation plans are held in a rabbi trust and are subject to additional risk of loss in the event of bankruptcy or insolvency of the Company. Under the deferred compensation plans, the participants direct the deemed investment of amounts credited to their accounts. The trust assets are invested in mutual funds that cover the investment spectrum from equity to money market. The mutual funds are publicly traded and have market prices that are readily available. Settlement payments are made to participants in cash, either in a lump sum or in periodic installments. The market value of the trust assets was $21 million and $17 million at December 31, 2025 and 2024, respectively, and is included in other assets in the Consolidated Balance Sheet. Related liabilities totaled $21 million and $17 million at December 31, 2025 and 2024, respectively, and are included in other liabilities in the Consolidated Balance Sheet. There is no impact on earnings or earnings per share from the changes in market value of the other deferred compensation plan assets because the changes in market value of the trust assets are offset completely by changes in the value of the liability, which represents trust assets belonging to plan participants. The Company made contributions to the deferred compensation plans of $4 million, $3 million and $3 million in 2025, 2024 and 2023, respectively, which are included in operating expense based on the classification of the corresponding salaries in the Consolidated Statement of Operations. 12. Capital Stock Issuance of Common Stock Upon the closing of the FME acquisition in January 2025, the Company issued 28,190,682 shares of its common stock to the sellers of the FME Interests. The shares were valued at $785 million based on the closing price of the stock on the date of issuance. 89
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Table of Contents Dividends Common Stock The following table summarizes the dividends the Company has paid on its common stock during 2025, 2024 and 2023: Rate per share Base Variable Total Total Dividends Paid (In millions) 2025: First quarter $ 0.22 $ — $ 0.22 $ 170 Second quarter 0.22 — 0.22 170 Third quarter 0.22 — 0.22 170 Fourth quarter 0.22 — 0.22 170 Total year-to-date $ 0.88 $ — $ 0.88 $ 680 2024: First quarter $ 0.21 $ — $ 0.21 $ 160 Second quarter 0.21 — 0.21 158 Third quarter 0.21 — 0.21 156 Fourth quarter 0.21 — 0.21 156 Total year-to-date $ 0.84 $ — $ 0.84 $ 630 2023: First quarter $ 0.20 $ 0.37 $ 0.57 $ 438 Second quarter 0.20 — 0.20 153 Third quarter 0.20 — 0.20 153 Fourth quarter 0.20 — 0.20 151 Total year-to-date $ 0.80 $ 0.37 $ 1.17 $ 895 (1) Increases to the Company’s dividends were previously approved by the Company’s Board of Directors in the February meeting of the respective year presented. Treasury Stock In February 2023, the Company’s Board of Directors approved a share repurchase program which authorizes the purchase of up to $2.0 billion of the Company’s common stock. During 2025, the Company repurchased and retired 6 million shares of common stock for $140 million under its repurchase program. During 2024, the Company repurchased and retired 17 million shares of common stock for $464 million under its repurchase program. As of December 31, 2025, the Company’s had $1.0 billion remaining under its current share repurchase program. There were no restricted stock vestings related to the Company’s repurchase program during 2025. During 2024 and 2023, the Company withheld and retired 351,791 and 332,634 shares of common stock, respectively, valued at $8 million and $9 million, respectively, related to shares withheld for taxes upon the vesting of certain restricted stock awards. Dividend Restrictions The Board of Directors of the Company determines the amount of future cash dividends, if any, to be declared and paid on the common stock depending on, among other things, the Company’s financial condition, funds from operations, the level of its capital and exploration expenditures and its future business prospects. None of the senior note or credit agreements in place have restricted payment provisions or other provisions which currently limit the Company’s ability to pay dividends. (1) 90
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Table of Contents Redeemable Preferred Stock In October 2021, in connection with the merger with Cimarex Energy Co. (now known as Coterra Energy Operating Co, or “Cimarex”), the Company assumed the obligations associated with Cimarex’s preferred stock, par value $0.01 per share, designated as 8 1/8% Series A Cumulative Perpetual Convertible Preferred Stock (the “Preferred Stock”). The Preferred Stock was originally issued by Cimarex and remains on the Cimarex balance sheet after the merger. The Company accounts for the Preferred Stock as a non-controlling interest, which is immaterial for reporting purposes. During the year ended December 31, 2023, holders of a portion of the Preferred Stock elected to convert their Preferred Stock into Coterra common stock and cash as follows: 2023 Preferred stock converted into Coterra common stock 2,000 Coterra common stock issued 79,285 Cash paid for conversion (in millions) $ 1 Book value of preferred shares at conversion (in millions) $ 3 Upon conversion of the Preferred Stock, the excess of carrying value over cash paid was credited to additional paid-in capital in the Consolidated Balance Sheet. There was no gain or loss recognized on the transactions as the shares were converted in accordance with the original terms of the Certificate of Designations for the Preferred Stock. At December 31, 2025, there were 4,265 shares of Preferred Stock outstanding with a carrying value of $8 million. There were no Preferred Stock conversions during the years ended December 31, 2025 and 2024. 13. Stock-Based Compensation Incentive Plan On May 4, 2023, the Company’s stockholders approved the Coterra Energy Inc. 2023 Equity Incentive Plan (the “2023 Plan”) which replaced the then-existing Cabot Oil & Gas Corporation 2014 Incentive Plan (the “2014 Plan”) and Cimarex Energy Co. Amended and Restated 2019 Equity Incentive Plan (the “2019 Plan”). Under the 2023 Plan, permitted awards include, but are not limited to, options, stock appreciation rights, restricted stock, restricted stock units, performance stock units and other cash and stock-based awards. A total of 22.95 million shares of common stock may be issued under the 2023 Plan. The 2023 Plan expires on February 21, 2033. No additional awards may be granted under the 2014 Plan or the 2019 Plan on or after May 4, 2023. Awards outstanding under any of the Company’s prior plans will remain outstanding and vest in accordance with their original terms and conditions. At December 31, 2025, approximately 15.5 million shares are available for issuance under the 2023 Plan. Stock-based compensation expense of awards issued under the Company’s incentive plans, and the income tax benefit of awards vested and exercised, are as follows: Year Ended December 31, (In millions) 2025 2024 2023 Restricted stock units - employees and non-employee directors $ 51 $ 47 $ 37 Restricted stock awards — 6 14 Performance share awards 12 9 15 Deferred performance shares — — (7) Total stock-based compensation expense $ 63 $ 62 $ 59 Income tax benefit $ 21 $ 12 $ 7 _______________________________________________________________________________ (1) During 2023, 495,774 shares of the Company’s common stock representing vested performance share awards previously deferred into the deferred compensation plan were sold and invested in other investment options. The sale of the Company’s common stock resulted in a $7 million decrease to the deferred compensation liability and a corresponding decrease in stock-based compensation expense. Refer to Note 11 for further discussion of the Company’s deferred compensation plan. (1) 91
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Table of Contents Restricted Stock Units - Employees Restricted stock units are granted to employees of the Company. The fair value of restricted stock unit grants is based on the closing stock price on the grant date. Restricted stock units generally vest at the end of a three-year service period or five-year service period. The restricted stock units are settled in shares of the Company’s common stock on the vesting date. For awards that vest at the end of the service period, expense is recognized ratably using a straight-line approach over the service period. For most restricted stock units, vesting is dependent upon the employees’ continued service with the Company, with the exception of employment termination due to death, disability or, if applicable, retirement. If retirement protection is included in the grant award, the Company accelerates the vesting period for retirement-eligible employees for purposes of recognizing compensation expense in accordance with the vesting provisions of the Company’s stock-based compensation programs. The Company used an annual forfeiture rate assumption ranging from zero to five percent for purposes of recognizing stock-based compensation expense for these restricted stock units. The annual forfeiture rates were based on the Company’s actual forfeiture history and expectations for this type of award. The following table is a summary of restricted stock unit award activity: Year Ended December 31, 2025 Shares Weighted-Average GrantDate Fair Valueper Unit Outstanding at beginning of period 6,165,974 $ 25.71 Granted 2,506,429 25.47 Vested (1,811,642) 24.96 Forfeited (253,201) 26.41 Outstanding at end of period 6,607,560 $ 25.79 The weighted-average grant date fair value per unit granted during 2025, 2024 and 2023 was $25.47, $25.87 and $26.12, respectively. Restricted Stock Units - Non-Employee Directors Restricted stock units are granted to non-employee directors of the Company. The fair value of the restricted stock units is based on the closing stock price on the grant date. Awards that were granted prior to 2022 vested on the grant date, compensation expense was recorded immediately, and the shares of the Company’s common stock will be issued when the director ceases to be a director of the Company. The 2022 grants vested in 2023 and compensation expense was recognized ratably over the service period and Company stock was issued on the vesting date. Grants awarded after 2022 vest one year from the grant date or upon the director’s separation from the Company, as applicable, and accordingly the Company recognizes compensation expense immediately. The Company assumed a zero percent annual forfeiture rate for purposes of recognizing stock-based compensation expense for these restricted stock units, based on the Company’s actual forfeiture history and expectations for this type of award. The following table is a summary of restricted stock unit award activity: Year Ended December 31, 2025 Shares Weighted-Average GrantDate Fair Valueper Unit Outstanding at beginning of period 326,359 $ 22.12 Granted 83,637 22.60 Vested (126,339) 23.50 Outstanding at end of period 283,657 $ 21.65 The weighted-average grant date fair value per unit granted during 2025, 2024 and 2023 was $22.60, $28.08 and $24.46, respectively. 92
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Table of Contents During 2025, 76,478 restricted stock units previously granted and vested in periods from 2016 through 2021 were issued upon the retirement of certain non-employee directors. The weighted-average grant date value was $23.50 per unit for all awards issued in 2025. Performance Share Awards Based on Market Conditions The Company grants performance share awards based on the Company’s performance relative to a predetermined peer group and industry-related indices (“TSR Performance Share Awards”). The performance period for these awards generally commences on February 1 of the respective year in which the award was granted and extends over a three-year performance period. For most performance share awards, vesting is dependent upon the employees’ continued service with the Company, with the exception of employment termination due to death, disability or, if applicable, retirement. For all outstanding performance share awards, the Company used an annual forfeiture rate of zero for purposes of recognizing stock-based compensation expense. The annual forfeiture rate assumption was based on the Company’s actual forfeiture history and expectations for this type of award. The Company assumed a zero percent annual forfeiture rate for purposes of recognizing stock-based compensation for these awards based on the Company’s actual forfeiture history and expectations for this type of award. These awards have both an equity and liability component, with the right to receive up to the first 100 percent of the award in shares of common stock and the right to receive up to an additional 100 percent of the value of the award in excess of the equity component in cash. The equity portion of these awards is valued on the grant date and is not marked to market, while the liability portion of the awards is valued as of the end of each reporting period on a mark-to-market basis. The Company calculates the fair value of the equity and liability portions of the awards using a Monte Carlo simulation model. The TSR Performance Share Awards granted are earned, or not earned, based on the comparative performance of the Company’s common stock measured against a predetermined group of companies in the Company’s peer group and certain industry-related indices over a three-year performance period. The Company’s TSR Performance Share Awards also include a feature that will reduce the potential cash component of the award if the actual performance is negative over the three-year period and the base calculation indicates an above-target payout. The following table is a summary of activity for the TSR Performance Share Awards: Year Ended December 31, 2025 Shares Weighted-Average GrantDate Fair Valueper Unit Outstanding at beginning of period 2,202,494 $ 18.19 Granted 579,476 21.49 Vested (1,103,157) 17.89 Outstanding at end of period 1,678,813 $ 19.52 _______________________________________________________________________________ (1) The grant date fair value figures in this table represent the fair value of the equity component of the performance share awards. The following table reflects certain balance sheet information of outstanding TSR Awards: December 31, (In millions) 2025 2024 Other current liabilities $ 3 $ 1 Other liabilities 4 4 The following table reflects certain cash payments related to the vesting of TSR Awards: Year Ended December 31, (In millions) 2025 2024 2023 Cash payments for TSR awards $ 1 $ — $ — (1) 93
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Table of Contents The following assumptions were used to determine the grant date fair value of the equity component of the TSR Performance Share Awards for the respective periods: Year Ended December 31, 2025 2024 2023 Fair value per performance share award granted during the period $21.49 $19.38 $17.18 - $20.20 Assumptions Stock price volatility 33.8% 38.0% 40.6% - 44.8% Risk free rate of return 4.3% 4.4% 4.4% - 4.8% The following assumptions were used to determine the fair value of the liability component of the TSR Performance Share Awards for the respective periods: December 31, 2025 2024 2023 Fair value per performance share award at the end of the period $5.54 - $7.58 $0.89 - $7.48 $7.57 - 10.67 Assumptions Stock price volatility 27.3% - 30.7% 23.5% - 28.2% 29.1% - 38.8% Risk free rate of return 3.5% - 3.7% 4.1% - 4.4% 4.2% - 4.7% The stock price volatility was calculated using historical closing stock price data for the Company for the period associated with the expected term through the grant date of each award. The risk free rate of return percentages are based on the continuously compounded equivalent of the U.S. Treasury within the expected term as measured on the grant date. Subsequent Event. On January 31, 2026, the performance period ended for the TSR Performance Share Awards that were granted in 2023, and 557,399 shares with a grant date fair value of $10 million vested based on the Company’s ranking relative to a predetermined peer group. Cash payments associated with these awards of approximately $2 million were also made in February 2026. The calculation of the award payout was certified by the Compensation Committee on February 5, 2026. Other Information The following table reflects the aggregate fair value of awards and units that vested during the respective period: December 31, (In millions) 2025 2024 2023 Restricted stock units - employees and non-employee directors $ 51 $ 25 $ 9 Restricted stock awards — 26 22 Performance share awards 31 2 — $ 82 $ 53 $ 31 The following table reflects the unrecognized stock-based compensation and the related weighted-average recognition period associated with the unvested awards and units as of December 31, 2025: Unrecognized Stock-Based Compensation (In Millions) Weighted-Average Period For Recognition (Years) Restricted stock units - employees and non-employee directors $ 85 1.6 Performance share awards 12 1.1 $ 97 Stock Option Awards On October 1, 2021, the Company granted stock option awards to purchase 1,577,554 shares of the Company’s common stock with exercise prices ranging from $8.47 to $28.72 per share. These awards were replacement awards granted to Cimarex employees in connection with the merger with Cimarex and were fully vested on the grant date. 94
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Table of Contents The following table is a summary of activity for the Stock Option Awards: Year Ended December 31, 2025 Shares Weighted-Average Strike Price Outstanding at beginning of period 193,580 $ 12.59 Exercised (89,001) 16.74 Outstanding at end of period 104,579 9.06 Exercisable at end of period 104,579 $ 9.06 _______________________________________________________________________________ (1) The intrinsic value of a stock option is the amount by which the current market value of the underlying stock exceeds the exercise price of the stock option. The aggregate intrinsic value of stock options outstanding and exercisable at December 31, 2025 was $2 million and $2 million, respectively. The weighted-average remaining contractual term is 1.3 years. 14. Earnings per Common Share Basic earnings per share (“EPS”) is computed by dividing net income available to common stockholders by the weighted-average number of common shares outstanding for the period. Diluted EPS is similarly calculated except that the common shares outstanding for the period is increased using the treasury stock and as-if-converted methods to reflect the potential dilution that could occur if outstanding stock awards were vested or exercised at the end of the applicable period. Anti-dilutive shares represent potentially dilutive securities that are excluded from the computation of diluted income or loss per share as their impact would be anti-dilutive. The following is a calculation of basic and diluted net earnings per common share under the two-class method: Year Ended December 31, (In millions except per share amounts) 2025 2024 2023 Income (Numerator) Net income $ 1,717 $ 1,121 $ 1,625 Less: dividends attributable to participating securities (1) (1) (5) Net income available to common stockholders $ 1,716 $ 1,120 $ 1,620 Shares (Denominator) Weighted average shares - Basic 761 742 756 Dilution effect of stock awards at end of period 3 3 4 Weighted average shares - Diluted 764 745 760 Earnings per share: Basic $ 2.25 $ 1.51 $ 2.14 Diluted $ 2.24 $ 1.50 $ 2.13 The following is a calculation of weighted-average shares excluded from diluted EPS due to the anti-dilutive effect: Year Ended December 31, (In millions) 2025 2024 2023 Weighted-average stock awards excluded from diluted EPS due to the anti- dilutive effect calculated using the treasury stock method 1 1 1 (1) (1) 95
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Table of Contents 15. Restructuring Costs Restructuring costs were primarily related to workforce reductions and associated severance benefits that were triggered by the merger with Cimarex. The following table summarizes the Company’s restructuring liabilities: Year Ended December 31, (In millions) 2025 2024 2023 Balance at beginning of period $ 13 $ 47 $ 77 Additions related to merger integration — — 12 Reductions related to severance payments (13) (34) (42) Balance at end of period $ — $ 13 $ 47 16. Additional Balance Sheet Information Certain balance sheet amounts are comprised of the following: December 31, (In millions) 2025 2024 Accounts receivable, net Trade accounts $ 968 $ 820 Joint interest accounts 214 133 Other accounts 29 — 1,211 953 Allowance for credit losses (3) (2) $ 1,208 $ 951 Inventories Tubular goods and well equipment $ 43 $ 33 Commodity inventory 5 13 $ 48 $ 46 Other current assets Prepaid balances $ 10 $ 14 Derivative instruments 235 12 Other accounts 28 1 $ 273 $ 27 Other assets Deferred compensation plan $ 21 $ 17 Debt issuance costs 8 10 Derivative instruments 3 — Operating lease right-of-use assets 182 251 Other accounts 120 136 $ 334 $ 414 96
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Table of Contents December 31, (In millions) 2025 2024 Accounts payable Trade accounts $ 90 $ 59 Royalty and other owners 479 402 Accrued gathering, processing and transportation 101 85 Accrued capital costs 207 177 Accrued lease operating costs 86 48 Taxes other than income 70 37 Other accounts 23 25 $ 1,056 $ 833 Accrued liabilities Employee benefits $ 82 $ 76 Taxes other than income 34 46 Restructuring liability — 13 Derivative instruments 2 17 Operating lease liabilities 68 115 Financing lease liabilities — 7 Other accounts 11 2 $ 197 $ 276 Other liabilities Deferred compensation plan $ 21 $ 17 Postretirement benefits 10 16 Derivative instruments — 4 Operating lease liabilities 120 145 Other accounts 87 77 $ 238 $ 259 17. Interest Expense Interest expense is comprised of the following: Year Ended December 31, (In millions) 2025 2024 2023 Interest Expense Interest expense $ 211 $ 101 $ 82 Debt (premium) discount amortization, net (21) (21) (21) Debt issuance cost amortization 6 9 3 Other 9 17 9 $ 205 $ 106 $ 73 97
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Table of Contents 18. Supplemental Cash Flow Information Year Ended December 31, (In millions) 2025 2024 2023 Cash paid for interest and income taxes Interest $ 183 $ 99 $ 84 Income taxes 293 341 388 Non-cash activity Retirement of treasury shares $ 140 $ 464 $ 418 Issuance of common stock for FME Interests 785 — — 98
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Table of Contents COTERRA ENERGY INC. SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) Oil and Gas Reserves Proved reserves are based on estimates prepared by the Company in accordance with guidelines established by the SEC. Reserves definitions comply with definitions of Rule 4-10(a) of Regulation S-X promulgated by the SEC under the Securities Act. Users of this information should be aware that the process of estimating quantities of “proved,” “proved developed” and “proved undeveloped” oil, natural gas and NGL reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserves estimates may occur from time-to- time. Although every reasonable effort is made to ensure that reserves estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimatesincluded in the financial statement disclosures. Preparation of Reserves Estimates All of the Company’s reserves estimates are maintained by the Company’s internal Corporate Reservoir Engineering group, which is comprised of engineers and engineering analysts. The objectives and management of this group are separate from and independent of the exploration and production functions of the Company. The primary objective of the Company’s Corporate Reservoir Engineering group is to maintain accurate forecasts on all properties of the Company through ongoing monitoring and timely updates of operating and economic parameters (production forecasts, prices and regional differentials, operating expenses, ownership, etc.). In addition, the Corporate Reservoir Engineering group maintains a set of basic guidelines and procedures to ensure that critical checks and reviews of the reserves database are performed on a regular basis. The Corporate Reservoir Engineering group is responsible for estimates of proved reserves. Corporate engineers interact with the exploration and production departments to ensure all appropriate available engineering and geologic data is taken into account prior to establishing or revising an estimate. The recommended revisions of the corporate engineers are reviewed with the Vice President - Corporate Reservoir Engineering and, after approval, entered into the reserves database by an engineering analyst. During the course of the year, the Corporate Reservoir Engineering group reviews their recommendations and updates with the Senior Vice President and Chief Technology Officer for additional oversight and approval. From time-to-time, the Senior Vice President and Chief Technology Officer also will confer with senior management, including the Chief Executive Officer, regarding reserves-related issues. Upon completion of the process, the estimated reserves are presented to senior management and the Board of Directors. The Company’s Senior Vice President and Chief Technology Officer is the technical person primarily responsible for overseeing the Company’s internal reserves estimation process and the Company’s Corporate Reservoir Engineering group. This individual graduated from the University of Tulsa with a Bachelor of Science degree in Petroleum Engineering. He has held numerous engineering and management roles and has over 18 years of experience in oil and gas reservoir evaluation and is a member of the Society of Petroleum Engineers. The Company utilizes various methods and technologies to estimate its proved reserves, including analysis of production performance, analogy, decline curve analysis, rate and pressure transient analysis, reservoir simulation, material balance calculations, volumetric calculations, and in some cases a combination of these methods. Review of Estimates by Third-Party Engineers The Company also engages independent petroleum engineering consulting firms as an additional confirmation of the reasonableness of its internal estimates. During 2025, 2024 and 2023, estimates of net proved reserves representing greater than 90 percent of the total future net revenue discounted at 10 percent attributable to the Company’s proved reserves were subject to an independent evaluation performed by DeGolyer and MacNaughton. In each of the respective periods, DeGolyer and MacNaughton indicated that, based on its investigations and subject to the limitations described in its reserves letters, they believe the Company’s estimates were, in the aggregate, reasonable. A copy of DeGolyer and MacNaughton’s letter regarding the 2025, 2024, and 2023 reserves estimates has been filed as an exhibit to this Annual Report on Form 10-K. 99
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Table of Contents Qualifications of Third-Party Engineers DeGolyer and MacNaughton’s Executive Vice President is the technical person primarily responsible for the evaluation of the Company’s proved reserves. He is a Registered Professional Engineer in the State of Texas with over 15 years of experience in oil and gas reservoir studies and reserves evaluations and meets the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. DeGolyer and MacNaughton is an independent firm of petroleum engineers, geologists, geophysicists and petro- physicists; they do not own an interest in the Company’s properties and are not retained on a contingent fee basis. Estimated Quantities of Proved Oil and Gas Reserves Estimates of total proved reserves at December 31, 2025, 2024 and 2023 were computed using the trailing 12-month average index price for the respective commodity, calculated as the unweighted arithmetic average for the first day of the month price for each month during the respective year. No major discovery or other favorable or unfavorable event after December 31, 2025, is believed to have caused a material change in the estimates of proved or proved developed reserves as of that date. 100
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Table of Contents The following tables illustrate the Company’s net proved reserves, including changes, and proved developed and proved undeveloped reserves for the periods indicated, as estimated by the Company’s engineering staff. All reserves are located within the continental U.S. Oil (MBbl) Natural Gas(Bcf) NGLs(MBbl) Total(MBoe) December 31, 2022 239,755 11,173 296,765 2,398,666 Revision of prior estimates 1,084 (414) 8,067 (59,970) Extensions, discoveries and other additions 44,386 823 46,148 227,660 Production (35,110) (1,053) (32,932) (243,497) Sales of reserves in place (902) (4) (592) (2,102) December 31, 2023 249,213 10,525 317,456 2,320,757 Revision of prior estimates 11,636 (181) 27,686 9,039 Extensions, discoveries and other additions 48,956 516 53,628 188,516 Production (39,808) (1,025) (36,993) (247,589) Sales of reserves in place (2) (1) — (2) December 31, 2024 269,995 9,834 361,777 2,270,721 Revision of prior estimates 5,114 816 21,253 162,258 Extensions, discoveries and other additions 61,439 759 62,841 250,774 Production (58,370) (1,086) (46,247) (285,576) Purchases of reserves in place 107,310 188 28,416 167,143 Sales of reserves in place (5) — (12) (38) December 31, 2025 385,483 10,511 428,028 2,565,282 Proved Developed Reserves December 31, 2022 168,649 8,543 224,706 1,817,140 December 31, 2023 173,392 8,590 234,306 1,839,219 December 31, 2024 189,275 8,420 271,030 1,863,583 December 31, 2025 283,671 9,051 335,012 2,127,175 Proved Undeveloped Reserves December 31, 2022 71,107 2,630 72,059 581,526 December 31, 2023 75,821 1,935 83,150 481,538 December 31, 2024 80,720 1,414 90,747 407,138 December 31, 2025 101,812 1,460 93,016 438,107 Year-end 2025 proved reserves increased approximately 13 percent from year-end 2024 proved reserves to 2,565 MMBoe. Proved natural gas reserves were 10.5 Tcf, proved oil reserves were 385 MMBbls, and proved NGL reserves were 428 MMBbls. The Company’s reserves in the Marcellus Shale accounted for 49 percent of total proved reserves, the Permian Basin accounted for 41 percent, and the remaining 10 percent were in the Anadarko Basin. During 2025, the company completed two acquisitions in the Delaware Basin of New Mexico and added 167 MMBoe of proved reserves through these acquisitions. In addition, the Company added 251 MMBoe of proved reserves through extensions, discoveries, and other additions, which included 172 MMBoe in the Permian Basin, 53 MMBoe in the Marcellus Shale and 25 MMBoe in the Anadarko Basin. The Company had net positive revisions of prior estimates of 162 MMBoe, which included a 66 MMBoe positive revision due to price, and a positive 96 MMBoe performance revision. During 2024, the Company added 189 MMBoe of proved reserves through extensions, discoveries, and other additions, which included 115 MMBoe in the Permian Basin, 28 MMBoe in the Marcellus Shale and 45 MMBoe in the Anadarko Basin. The Company had net positive revisions of prior estimates of 9 MMBoe, which included 59 MMBoe negative revision due to price, offset by a 4 MMBoe positive revision in operating expenses and a positive 64 MMBoe performance revision. During 2023, the Company added 228 MMBoe of proved reserves through extensions, discoveries, and other additions, which included 102 MMBoe in the Permian Basin, 87 MMBoe in the Marcellus Shale and 39 MMBoe in the Anadarko Basin. The Company had net negative revisions of prior estimates of 60 MMBoe, which included 83 MMBoe negative revision due to 101
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Table of Contents price, a 10 MMBOE negative revision due to increases in operating expenses, partially offset by a positive 33 MMBoe performance revision. Proved Undeveloped Reserves At December 31, 2025, the Company had PUD reserves of 438 MMBoe, up 31 MMBoe, or eight percent, from 407 MMBoe of PUD reserves at December 31, 2024. Future development plans are reflective of current commodity price environment and have been established based on expected available cash flows from operations. By the end of 2026, the Company expects to complete substantially all the work necessary to convert its PUD reserves associated with wells that were drilled but uncompleted at December 31, 2025 to proved developed reserves. As of December 31, 2025 all PUD reserves are expected to be drilled and completed within five years of initial disclosure of these reserves. The following table is a reconciliation of the change in the Company’s PUD reserves (MMBoe): Year EndedDecember 31, 2025 Balance at beginning of period 407 Transfers to proved developed (186) Additions 189 Revision of prior estimates 1 Purchase of reserves in place 27 Balance at end of period 438 During 2025, the Company invested $1.3 billion to develop and convert 46 percent of its 2024 PUD reserves to proved developed reserves. During 2024, the Company invested $1.3 billion to develop and convert 42 percent of its 2023 PUD reserves to proved developed reserves. During 2023, the Company invested $1.3 billion to develop and convert 33 percent of its 2022 PUD reserves to proved developed reserves. During 2025, the Company’s 189 MMBoe of PUD reserves additions consisted of 114 MMBoe added in the Permian Basin, 23 MMBoe added in the Anadarko Basin and 52 MMBoe added in the Marcellus Shale. At December 31, 2025, 59 percent were in the Permian Basin, 31 percent were in the Marcellus Shale, and the remaining 10 percent were in the Anadarko Basin. During 2025, the Company had a net upward PUD reserves revision of 1 MMBoe, of which a positive 10 MMBoe in the Permian Basin is due to better than expected well performance compared to previous proved reserve estimates and a negative 9 MMBOE in the Marcellus Shale due to expected delays in development beyond five years. Capitalized Costs Relating to Oil and Gas Producing Activities Capitalized costs relating to oil and gas producing activities and related accumulated DD&A were as follows: December 31, (In millions) 2025 2024 2023 Aggregate capitalized costs relating to oil and gas producing activities $ 31,892 $ 25,870 $ 24,199 Aggregate accumulated DD&A (10,853) (8,590) (6,836) Net capitalized costs $ 21,039 $ 17,280 $ 17,363 102
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Table of Contents Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities Costs incurred in property acquisition, exploration and development activities were as follows: Year Ended December 31, (In millions) 2025 2024 2023 Property acquisition costs, proved $ 4,092 $ — $ — Property acquisition costs, unproved 99 19 10 Exploration costs 27 25 20 Development costs 2,151 1,645 1,979 Total costs $ 6,369 $ 1,689 $ 2,009 Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves The following information has been developed based on oil and natural gas reserves and production volumes estimated by the Company’s engineering staff. It can be used for some comparisons, but should not be the only method used to evaluate the Company or its performance. Further, the information in the following table may not represent realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flows (“Standardized Measure”) be viewed as representative of the current value of the Company. The Company believes that the following factors should be taken into account when reviewing the following information: • Future costs and selling prices will differ from those required to be used in these calculations. • Due to future market conditions and governmental regulations, actual rates of production in future years may vary significantly from the rate of production assumed in the calculations. • Selection of a 10 percent discount rate is arbitrary and may not be a reasonable measure of the relative risk that is part of realizing future net oil and gas revenues. • Future net revenues may be subject to different rates of income taxation. Under the Standardized Measure, future cash inflows were estimated by using the trailing 12-month average index price for the respective commodity, calculated as the unweighted arithmetic average for the first day of the month price for each month during the year. The average prices related to proved reserves are as follows: Year Ended December 31, 2025 2024 2023 Oil ($/Bbl) $ 64.37 $ 72.84 $ 75.05 Natural gas ($/Mcf) $ 2.37 $ 1.23 $ 2.04 NGL ($/Bbl) $ 16.88 $ 18.16 $ 18.39 Future cash inflows were reduced by estimated future development and production costs based on year-end costs to arrive at net cash flow before tax. Future income tax expense was computed by applying year end statutory tax rates to future pretax net cash flows, less the tax basis of the properties involved and utilization of available tax carryforwards related to oil and gas operations. The applicable accounting standards require the use of a 10 percent discount rate. Management does not solely use the following information when making investment and operating decisions. These decisions are based on a number of factors, including estimates of proved reserves and varying price and cost assumptions considered more representative of a range of anticipated economic conditions. 103
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Table of Contents Standardized Measure is as follows: December 31, (In millions) 2025 2024 2023 Future cash inflows $ 56,872 $ 39,268 $ 45,749 Future production costs (22,326) (17,468) (18,414) Future development costs (3,365) (3,098) (3,239) Future income tax expenses (5,992) (3,894) (4,551) Future net cash flows 25,189 14,808 19,545 10% annual discount for estimated timing of cash flows (11,592) (6,355) (8,879) Standardized measure of discounted future net cash flows $ 13,597 $ 8,453 $ 10,666 ______________________________________________________________________________ (1) Includes $703 million, $613 million and $562 million in plugging and abandonment costs as of December 31, 2025, 2024 and 2023, respectively. Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves The following is an analysis of the changes in the Standardized Measure: Year Ended December 31, (In millions) 2025 2024 2023 Beginning of year $ 8,453 $ 10,666 $ 26,072 Discoveries and extensions, net of related future costs 2,109 1,152 1,578 Net changes in prices and production costs 3,877 (3,021) (22,713) Accretion of discount 1,077 1,333 3,348 Revisions of previous quantity estimates 1,191 243 (890) Timing and other (897) 61 979 Changes in estimated future development costs 145 191 220 Development costs incurred 982 897 1,232 Sales and transfers, net of production costs (4,727) (3,454) (3,871) Sales of reserves in place — — (40) Purchases of reserves in place 2,439 — — Net change in income taxes (1,052) 385 4,751 End of year $ 13,597 $ 8,453 $ 10,666 (1) 104
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Table of Contents ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. ITEM 9A. CONTROLS AND PROCEDURES Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures As of December 31, 2025, the Company carried out an evaluation, under the supervision and with the participation of the Company’s management, including the Company’s Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures pursuant to Rules 13a-15 and 15d-15 of the Exchange Act. Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures are effective to provide reasonable assurance with respect to the recording, processing, summarizing and reporting, within the time periods specified in the SEC’s rules and forms, of information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act. Changes in Internal Control over Financial Reporting There were no changes in internal control over financial reporting that occurred during the fourth quarter of 2025 that have materially affected, or are reasonably likely to have a material effect on, the Company’s internal control over financial reporting. Management’s Report on Internal Control over Financial Reporting The management of Coterra Energy Inc. is responsible for establishing and maintaining adequate internal control over financial reporting. Coterra Energy Inc.’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Coterra Energy Inc.’s management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2025. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in Internal Control—Integrated Framework (2013). Based on this assessment management has concluded that, as of December 31, 2025, the Company’s internal control over financial reporting is effective at a reasonable assurance level based on those criteria. The effectiveness of Coterra Energy Inc.’s internal control over financial reporting as of December 31, 2025, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein. ITEM 9B. OTHER INFORMATION During the three months ended December 31, 2025, no director or officer of Coterra adopted or terminated a “Rule 10b5-1 trading arrangement” or “no-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408 of Regulation S-K. ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS None. 105
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Table of Contents PART III ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE The information set forth in Part 1 under the caption “Information about our Executive Officers” regarding our executive officers and the information set forth under the caption “Business—Other Business Matters—Corporate Governance Matters” in Item 1 regarding our Code of Business Conduct and Ethics is incorporated by reference in response to this item. The information required by this item is incorporated by reference from the Company’s definitive Proxy Statement in connection with the 2026 annual stockholders’ meeting (the “2026 Proxy Statement”). In the event the 2026 Proxy Statement is not filed with the SEC in the 120-day period after December 31, 2025, the information required by this item will be included in an amendment to this Annual Report on Form 10-K that will be filed not later than the end of such 120-day period. ITEM 11. EXECUTIVE COMPENSATION The information required by this item is incorporated by reference from the 2026 Proxy Statement. In the event the 2026 Proxy Statement is not filed with the SEC in the 120-day period after December 31, 2025, the information required by this item will be included in an amendment to this Annual Report on Form 10-K that will be filed not later than the end of such 120-day period. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS The information required by this item is incorporated by reference from the Company’s 2026 Proxy Statement. In the event the 2026 Proxy Statement is not filed with the SEC in the 120-day period after December 31, 2025, the information required by this item will be included in an amendment to this Annual Report on Form 10-K that will be filed not later than the end of such 120-day period. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE The information required by this item is incorporated by reference from the Company’s 2026 Proxy Statement. In the event the 2026 Proxy Statement is not filed with the SEC in the 120-day period after December 31, 2025, the information required by this item will be included in an amendment to this Annual Report on Form 10-K that will be filed not later than the end of such 120-day period. ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES The information required by this item is incorporated by reference from the Company’s 2026 Proxy Statement. In the event the 2026 Proxy Statement is not filed with the SEC in the 120-day period after December 31, 2025, the information required by this item will be included in an amendment to this Annual Report on Form 10-K that will be filed not later than the end of such 120-day period. 106
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Table of Contents PART IV ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES A. INDEX 1. Consolidated Financial Statements See Index on page 56. 2. Financial Statement Schedules Financial statement schedules listed under SEC rules but not included in this report are omitted because they are not applicable or the required information is provided in the notes to our consolidated financial statements. 3. Exhibits The following instruments are included as exhibits to this report. Those exhibits below incorporated herein by reference are indicated as such by the information supplied in the parenthetical thereafter. If no parenthetical appears after an exhibit, copies of the instrument have been included herewith. The Company’s file number with the SEC is 1-10447. ExhibitNumber Description 2.1Agreement and Plan of Merger, dated as of May 23, 2021, by and among Cabot Oil & Gas Corporation,Double C Merger Sub, Inc. and Cimarex Energy Co. (incorporated herein by reference to Exhibit 2.1 ofCoterra’s Current Report on Form 8-K filed with the SEC on May 24, 2021). 2.2Amendment No. 1 to Agreement and Plan of Merger, dated as of June 29, 2021, by and among Cabot Oil &Gas Corporation, Double C Merger Sub, Inc. and Cimarex Energy Co. (incorporated herein by reference toAnnex A to the Joint Proxy Statement/Prospectus included in Coterra’s Registration Statement on Form S-4(Reg. No. 333-257534) filed with the SEC on June 30, 2021). 2.3Agreement and Plan of Merger, dated as of February 1, 2026, by and among Coterra Energy Inc., DevonEnergy Corporation, and Cubs Merger Sub, Inc. (incorporated herein by reference to Exhibit 2.1 of Coterra’sCurrent Report on Form 8-K filed with the SEC on February 2, 2026. 3.1Amended and Restated Certificate of Incorporation of Coterra Energy Inc. (incorporated herein by reference toExhibit 3.1 of the Company’s Current Report on Form 8-K filed with the SEC on May 2, 2024). 3.2Amended and Restated Bylaws of Coterra Energy Inc. (incorporated herein by reference to Exhibit 3.2 ofCoterra’s Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2025). 4.1Description of Securities Registered Pursuant to Section 12 of Securities Exchange Act of 1934 (incorporatedherein by reference to Exhibit 4.1 of Coterra's Annual Report on Form 10-K for the fiscal year endedDecember 31, 2024). 4.2Form of Common Stock Certificate of Coterra Energy Inc. (incorporated herein by reference to Exhibit 4.3 ofCoterra’s Registration Statement on Form S-8 (Reg. No. 333-260035 ) filed with the SEC on October 5, 2021). 4.3Certificate of Designations to 8 1⁄8% Series A Cumulative Perpetual Convertible Preferred Stock of CimarexEnergy Co. (incorporated herein by reference to Exhibit 4.3 of Coterra’s Annual Report on Form 10-K for thefiscal year ended December 31, 2021). 4.4Amendment to Certificate of Designations to 8 1⁄8% Series A Cumulative Perpetual Convertible PreferredStock of Cimarex Energy Co. (incorporated herein by reference to Exhibit 4.4 of Coterra’s Annual Report onForm 10-K for the fiscal year ended December 31, 2021). 4.5Amendment to Certificate of Designations to 8 1/8% Series A Cumulative Perpetual Convertible PreferredStock of Cimarex Energy Co. (incorporated herein by reference to Exhibit 4.3 of Coterra’s Quarterly Report onForm 10-Q for the fiscal quarter ended March 31, 2022). 4.6Note Purchase Agreement, dated as of September 18, 2014, among Cabot Oil & Gas Corporation and thePurchasers named therein (incorporated herein by reference to Exhibit 4.1 of Coterra’s Current Report on Form8-K filed with the SEC on September 24, 2014). (a) Amendment No. 1 to Note Purchase Agreement, dated as of December 31, 2015 (incorporated herein byreference to Exhibit 4.5 of Coterra’s Current Report on Form 8-K filed with the SEC on February 9, 2016). (b) Amendment No. 2 to Note Purchase Agreement, dated as of April 8, 2016 (incorporated herein by referenceto Exhibit 4.4(b) of Coterra’s Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2016). 4.7Indenture, dated as of October 7, 2021, by and between Coterra Energy Inc. and U.S. Bank National Association, as Trustee (incorporated herein by reference to Exhibit 4.1 of Coterra’s Current Report on Form 8- K filed with the SEC on October 7, 2021). 107
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Table of Contents 4.8First Supplemental Indenture, dated as of October 7, 2021, by and between Coterra Energy Inc. and U.S. Bank National Association, as Trustee (incorporated herein by reference to Exhibit 4.2 of Coterra’s Current Report on Form 8-K filed with the SEC on October 7, 2021). 4.9Form of 3.90% Senior Notes due 2027 (incorporated herein by reference to Exhibit A-2 to the First Supplemental Indenture filed as Exhibit 4.2 of Coterra’s Current Report on Form 8-K filed with the SEC on October 7, 2021). 4.10Form of 4.375% Senior Notes due 2029 (incorporated herein by reference to Exhibit A-3 to the First Supplemental Indenture filed as Exhibit 4.2 of Coterra’s Current Report on Form 8-K filed with the SEC on October 7, 2021). 4.11Second Supplemental Indenture, dated as of March 13, 2024, by and between Coterra Energy Inc. and U.S. Bank Trust Company, National Association, as trustee (incorporated herein by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K filed with the SEC on March 13, 2024). 4.12Form of 5.60% Senior Notes due 2034 (incorporated herein by reference to Exhibit A to the Second Supplemental Indenture filed as Exhibit 4.2 of the Company’s Current Report on Form 8-K filed with the SEC on March 13, 2024). 4.13Third Supplemental Indenture, dated as of December 17, 2024, by and between Coterra Energy Inc. and U.S. Bank Trust Company, National Association, as trustee (incorporated herein by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K filed with the SEC on December 17, 2024). 4.14Form of 5.40% Senior Notes due 2035 (incorporated herein by reference to Exhibit A-1 to the Third Supplemental Indenture filed as Exhibit 4.2 of the Company’s Current Report on Form 8-K filed with the SEC on December 17, 2024). 4.15Form of 5.90% Senior Notes due 2055 (incorporated herein by reference to Exhibit A-2 to the Third Supplemental Indenture filed as Exhibit 4.2 of the Company’s Current Report on Form 8-K filed with the SEC on December 17, 2024). Coterra or certain of its consolidated subsidiaries are parties to other debt instruments under which the total amount of securities authorized does not exceed 10 percent of Coterra’s total consolidated assets. Pursuant to paragraph (4)(iii)(A) of Item 601(b) of Regulation S-K, Coterra agrees to furnish a copy of any of those instruments to the SEC upon its request. *10.1Form of Change in Control Agreement between Cabot Oil & Gas Corporation and Certain Officers(incorporated herein by reference to Exhibit 10.1 of Coterra’s Annual Report on Form 10-K for the fiscal yearended December 31, 2008). (a) Form of Change in Control Agreement between Cabot Oil & Gas Corporation and Certain Officers(Confirmation that Certain Benefits no Longer Apply) (incorporated herein by reference to Exhibit 10.1(a) ofCoterra’s Annual Report on Form 10-K for the fiscal year ended December 31, 2010). (b) Form of Amendment to Change in Control Agreement (incorporated herein by reference to Exhibit 10.4 ofCoterra’s Registration Statement on Form S-4 (Reg. No. 333-257534) filed with the SEC on June 30, 2021). (c) Form of Letter Agreement with respect to Change-in-Control Arrangements (incorporated herein by reference to Exhibit 10.1 of Coterra’s Current Report on Form 8-K filed with the SEC on October 1, 2021). (d) Amendment to Change in Control Agreement and Employment Letter Agreement dated December 27, 2022(incorporated herein by reference to Exhibit 10.1 of Coterra’s Current Report on Form 8-K filed with the SECon December 29, 2022). *10.2Form of Indemnification Agreement between Cabot Oil & Gas Corporation and Certain Officers (incorporatedherein by reference to Exhibit 10.2 of Coterra’s Annual Report on Form 10-K for the fiscal year endedDecember 31, 2012). *10.3Form of Indemnification Agreement (incorporated herein by reference to Exhibit 10.3 of Coterra’s CurrentReport on Form 8-K filed with the SEC on October 1, 2021). *10.4Deferred Compensation Plan of Cabot Oil & Gas Corporation, as Amended and Restated, Effective January 1,2011 (incorporated herein by reference to Exhibit 10.1 of Coterra’s Quarterly Report on Form 10-Q for thefiscal quarter ended June 30, 2011). *10.5Employment Letter Agreement, dated as of May 23, 2021, between Cabot Oil & Gas Corporation and Thomas E. Jorden (incorporated herein by reference to Exhibit 10.2 of Coterra’s Registration Statement on Form S-4 (Reg. No. 333-257534) filed with the SEC on June 30, 2021). *10.6Side Letter Agreement, dated as of June 29, 2021, by and between Cabot Oil and Gas Corporation and Thomas E. Jorden (incorporated herein by reference to Exhibit 10.3 of Coterra’s Registration Statement on Form S-4 (Reg. No. 333-257534) filed with the SEC on June 30, 2021). *10.7Amended and Restated Employment Letter Agreement dated as of September 19, 2023 between Coterra Energy Inc. and Thomas E. Jorden (incorporated herein by reference to Exhibit 10.1 of Coterra’s Current Report of Form 8-K filed with the SEC on September 19, 2023). 108
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Table of Contents (a) Amendment to Amended and Restated Letter Agreement dated as of July 31, 2025 between Coterra Energy Inc. and Thomas E. Jorden (incorporated herein by reference to Exhibit 10.1 of Coterra’s Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2025). *10.8Letter Agreement with Stephen P. Bell (incorporated herein by reference to Exhibit 10.4 of Coterra Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2023). *10.9Cabot Oil & Gas Corporation 2014 Incentive Plan, Effective May 1, 2014 (incorporated herein by reference to Exhibit 10.1 of Coterra’s Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2014). (a) Form of Non-Employee Director Restricted Unit Award Agreement (incorporated herein by reference toExhibit 10.2 of Coterra’s Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2014). (b) Form of Restricted Stock Award Agreement (3 year graded) (incorporated herein by reference to Exhibit10.2(a) of Coterra’s Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2015). (c) Form of Restricted Stock Award Agreement (3 year cliff) (incorporated herein by reference to Exhibit10.2(b) of Coterra’s Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2015). (d) Form of Performance Share Award Agreement (Officers) (incorporated herein by reference to Exhibit10.2(c) of Coterra’s Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2015). (e) Form of Hybrid Performance Share Award Agreement (incorporate herein by reference to Exhibit 10.2(d)of Coterra’s Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2015). (f) Form of Performance Share Award Agreement (Employees) (incorporated herein by reference to Exhibit10.2(e) of Coterra’s Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2015). (g) Form of Performance Share Award Agreement (Employees) (incorporated herein by reference to Exhibit10.8(g) of Coterra’s Annual Report on Form 10-K for the fiscal year ended December 31, 2020). (h) Form of Restricted Stock Unit Award Agreement (officers) (incorporated herein by reference to Exhibit10.1(a) of Coterra’s Quarterly Report of Form 10-Q for the fiscal quarter ended March 31, 2023). (i) Form of Performance Share Unit Award Agreement (continuing officers) (incorporated herein by referenceto Exhibit 10.1(b) of Coterra’s Quarterly Report of Form 10-Q for the fiscal quarter ended March 31, 2023). (j) Form of Performance Share Award Agreement (transitioning officers) (incorporated herein by reference toExhibit 10.1(c) of Coterra’s Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2023). *10.10Cimarex Energy Co. Amended and Restated 2019 Equity Incentive Plan, Effective May 12, 2021 (incorporatedherein by reference to Exhibit 4.4 of Coterra’s Registration Statement on Form S-8 (Reg. No. 333-260230)filed with the SEC on October 14, 2021). (a) Form of Restricted Stock Unit Award Agreement (legacy Cimarex continuing officers) (incorporated hereinby reference to Exhibit 10.2 of Coterra’s Quarterly Report on Form 10-Q for the fiscal quarter ended March 31,2022); (b) Form of Restricted Stock Unit Award Agreement (legacy Cimarex transitioning officers) (incorporatedherein by reference to Exhibit 10.2 of Coterra’s Quarterly Report on Form 10-Q for the fiscal quarter endedMarch 31, 2022); (c) Form of Performance Share Award Agreement (legacy Cimarex continuing officers) (incorporated hereinby reference to Exhibit 10.2 of Coterra’s Quarterly Report on Form 10-Q for the fiscal quarter ended March 31,2022); (d) Form of Performance Share Award Agreement (incorporated herein by reference to Exhibit 10.2 ofCoterra’s Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2022). *10.11Coterra Energy Inc. 2023 Equity Incentive Plan (incorporated herein by reference to Exhibit 10.1 of Coterra’sCurrent Report on Form 8-K filed with the SEC on May 5, 2023). (a) Form of Non-Employee Director Restricted Stock Unit Award Agreement (incorporated herein by referenceto Exhibit 10.2(a) of Coterra’s Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2023); (b) Form of Restricted Stock Unit Award Agreement (incorporated herein by reference to Exhibit 10.2(b) ofCoterra’s Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2023); (c) Form of Performance Stock Unit Award Agreement (incorporated herein by reference to Exhibit 10.2(c) ofCoterra’s Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2023); (d) Form of Restricted Stock Unit Award Agreement (incorporated herein by reference to Exhibit 10.11(d) ofCoterra’s Annual Report on Form 10-K for the fiscal year ended December 31, 2023); (e) Form of Performance Stock Unit Award Agreement (incorporated herein by reference to Exhibit 10.11(e) ofCoterra’s Annual Report on Form 10-K for the fiscal year ended December 31, 2023); (f) Form of Restricted Stock Unit Award Agreement (incorporated herein by reference to Exhibit 10.4(a) ofCoterra’s Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2025); (g) Form of Performance Stock Unit Award Agreement (incorporated herein by reference to Exhibit 10.4(b) ofCoterra’s Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2025). 109
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Table of Contents *10.12Form of Severance Compensation Agreement of certain executive officers of Cimarex Energy Co.(incorporated herein by reference to Exhibit 10.1 of Cimarex’s Current Report on Form 8-K filed with the SECon March 13, 2020). (a) Form of Amendment to Severance Compensation Agreements of certain executive officers of CimarexEnergy Co. (incorporated herein by reference to Exhibit 10.11 of Coterra’s Quarterly Report on Form 10-Q forthe fiscal quarter ended September 30, 2021). *10.13Amended and Restated Severance Compensation Agreement, dated as of January 31, 2026, by and between Coterra Energy Inc. and Thomas E. Jorden (incorporated herein by reference to Exhibit 10.1 of Coterra’s Current Report on Form 8-K filed with the SEC on February 2, 2026). *10.14Form of Executive Severance Compensation Agreement between Coterra Energy Inc. and certain officers(incorporated herein by reference to Exhibit 10.4 of Coterra's Quarterly Report on Form 10-Q for the fiscalquarter ended March 31, 2023). *10.15Form of Amended and Restated Severance Compensation Agreement between Coterra Energy Inc. and certainofficers (incorporated herein by reference to Exhibit 10.2 of Coterra’s Current Report on Form 8-K filed withthe SEC on February 2, 2026). *10.16Non-Employee Director Deferred Compensation Plan effective December 21, 2012 (incorporated herein byreference to Exhibit 10.10 of Coterra’s Annual Report on Form 10-K for the fiscal year ended December 31,2012). *10.17Non-Employee Director Deferred Compensation Plan effective May 4, 2023 (incorporated herein by referenceto Exhibit 10.3 of Coterra’s Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2023). (a) Form of Non-Employee Director Deferred Restricted Stock Unit Award Agreement (Annual Fees)(incorporated herein by reference to Exhibit 10.3(a) of Coterra’s Quarterly Report on Form 10-Q for the fiscalquarter ended March 31, 2023); (b) Form of Non-Employee Director Deferred Restricted Stock Unit Award Agreement (Annual RSU Grant)(incorporated herein by reference to Exhibit 10.3(b) of Coterra’s Quarterly Report on Form 10-Q for the fiscalquarter ended March 31, 2023). 10.18Credit Agreement dated as of March 10, 2023, among Coterra Energy, Inc., as Borrower, JPMorgan ChaseBank, N.A., as Administrative Agent, and the Lenders and Issuing Banks party thereto (incorporated herein byreference to Exhibit 10.1 of Coterra’s Current Report on Form 8-K filed with the SEC on March 16, 2023). 10.19First Amendment to Credit Agreement, dated as of September 12, 2024, among the Company, as Borrower,JPMorgan Chase Bank, N.A., as Administrative Agent, and the Lenders and Issuing Banks party thereto(incorporated herein by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed with theSEC on September 12, 2024). 10.20Credit Agreement, dated as of December 10, 2024, Toronto Dominion (Texas) LLC, as Administrative Agent,and the Lenders and Issuing Banks party thereto (incorporated herein by reference to Exhibit 10.1 of theCompany’s Current Report on Form 8-K filed with the SEC on December 16, 2024). 10.21Membership Interest Purchase Agreement, dated as of November 12, 2024, by and among Franklin MountainEnergy Holdings, LP, Franklin Mountain Energy Holdings 2, LP, and Franklin Mountain GP2, LLC, as sellers,solely in its capacity as Seller Representative, Franklin Mountain Energy Holdings, LP, Cimarex Energy Co.,as purchaser, and Coterra Energy Inc., as purchaser parent (incorporated herein by reference to Exhibit 10.1 ofthe Company’s Current Report on Form 8-K filed with the SEC on November 15, 2024). 10.22First Amendment to Membership Interest Purchase Agreement, dated as of December 28, 2024, but effectivefor all purposes as of November 12, 2024, by and among Franklin Mountain Energy Holdings, LP, FranklinMountain Energy Holdings 2, LP, and Franklin Mountain GP2, LLC, as sellers, solely in its capacity as SellerRepresentative, Franklin Mountain Energy Holdings, LP, Cimarex Energy Co., as purchaser, and CoterraEnergy Inc., as purchaser parent (incorporated herein by reference to Exhibit 10.2 of the Company’s CurrentReport on Form 8-K filed with the SEC on December 31, 2024). 10.23Closing Agreement and Second Amendment to Membership Interest Purchase Agreement, dated as of January27, 2025, but effective for all purposes as of November 12, 2024, by and among Franklin Mountain EnergyHoldings, LP, Franklin Mountain Energy Holdings 2, LP, and Franklin Mountain GP2, LLC, as sellers, solelyin its capacity as Seller Representative, Franklin Mountain Energy Holdings, LP, Cimarex Energy Co., aspurchaser, and Coterra Energy Inc., as purchaser parent (incorporated herein by reference to Exhibit 10.21 ofCoterra's Annual Report on Form 10-K for the fiscal year ended December 31, 2024). 10.24Registration Rights Agreement, dated as of January 27, 2025, among Coterra Energy Inc., and the Stockholdersparty thereto (incorporated herein by reference to Exhibit 10.22 of Coterra's Annual Report on Form 10-K forthe fiscal year ended December 31, 2024). 10.25Purchase and Sale Agreement, dated as of November 12, 2024, by and among Avant Natural Resources, LLC,Avant Operating, LLC, Guard Income Fund, LP, Double Cabin Minerals, LLC, Legion Water Services, LLC,and Legion Production Partners, LLC, as sellers, and Cimarex Energy Co., as buyer (incorporated herein byreference to Exhibit 10.2 of the Company’s Current Report on Form 8-K filed with the SEC on November 15,2024). 19Coterra Energy Inc. Insider Trading Policy and Procedures approved October 31, 2024 (incorporated herein byreference to Exhibit 19 of Coterra's Annual Report on Form 10-K for the fiscal year ended December 31,2024). **21.1Subsidiaries of Coterra Energy Inc. 110
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Table of Contents **23.1Consent of PricewaterhouseCoopers LLP. **23.2Consent of DeGolyer and MacNaughton. **31.1302 Certification—Chairman, Chief Executive Officer and President. **31.2302 Certification—Executive Vice President and Chief Financial Officer. **32.1906 Certification - Chief Executive Officer and Chief Financial Officer. 97Policy for the Recovery of Erroneously Awarded Compensation (incorporated herein by reference to Exhibit97 of Coterra's Annual Report on Form 10-K for the fiscal year ended December 31, 2024). **99.1DeGolyer and MacNaughton Report for 2025. 99.2DeGolyer and MacNaughton Report for 2024 (incorporated herein by reference to Exhibit 99.1 of Coterra'sAnnual Report on Form 10-K filed for the fiscal year ended December 31, 2024). 99.3DeGolyer and MacNaughton Report for 2023 (incorporated herein by reference to Exhibit 99.1 of Coterra’sAnnual Report on Form 10-K for the fiscal year ended December 31, 2023). 101.INS Inline XBRL Instance Document. The instance document does not appear in the Interactive Data File becauseits XBRL tags are embedded within the Inline XBRL document. 101.SCH Inline XBRL Taxonomy Extension Schema Document. 101.CAL Inline XBRL Taxonomy Extension Calculation Linkbase Document. 101.LAB Inline XBRL Taxonomy Extension Label Linkbase Document. 101.PRE Inline XBRL Taxonomy Extension Presentation Linkbase Document. 101.DEF Inline XBRL Taxonomy Extension Definition Linkbase Document. 104 Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101). ______________________________________________________________________________ * Compensatory plan, contract or arrangement. ** Filed herewith. 111
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Table of Contents ITEM 16. FORM 10-K SUMMARY Coterra has elected not to include summary information. 112
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Table of Contents SIGNATURES Pursuant to the requirements of Section 13 and 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Houston, State of Texas, on February 27, 2026. COTERRA ENERGY INC. By: /s/ THOMAS E. JORDEN Thomas E. JordenChairman, Chief Executive Officer and President ______________________________________________________________________________________________________________________________ 113
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Table of Contents Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. Signature Title Date /s/ THOMAS E. JORDEN Chairman, Chief Executive Officer and President(Principal Executive Officer) February 27, 2026 Thomas E. Jorden /s/ SHANNON E. YOUNG III Executive Vice President and Chief FinancialOfficer (Principal Financial Officer) February 27, 2026 Shannon E. Young III /s/ GREGORY F. CONAWAY Vice President and Chief Accounting Officer(Principal Accounting Officer) February 27, 2026 Gregory F. Conaway /s/ DOROTHY M. ABLES Director February 27, 2026 Dorothy M. Ables /s/ AMANDA M. BROCK Lead Independent Director February 27, 2026 Amanda M. Brock /s/ PAUL N. ECKLEY Director February 27, 2026 Paul N. Eckley /s/ HANS HELMERICH Director February 27, 2026 Hans Helmerich /s/JACINTO J. HERNANDEZ Director February 27, 2026 Jacinto J. Hernandez /s/ JEFFERY E. SHELLEBARGER Director February 27, 2026 Jeffrey E. Shellebarger /s/ LISA A. STEWART Director February 27, 2026 Lisa A. Stewart /s/ FRANCES M. VALLEJO Director February 27, 2026 Frances M. Vallejo /s/ MARCUS A. WATTS Director February 27, 2026 Marcus A. Watts 114
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Exhibit 21.1 SUBSIDIARIES OF COTERRA ENERGY INC. Coterra Energy Operating Co (formerly Cimarex Energy Co.) Magnum Hunter Production, Inc.
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Exhibit 23.1 CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (File Nos. 333-282949 and 333-282950) and Form S-8 (File Nos. 333-195642, 333-260035, 333-260230 and 333-271681) of Coterra Energy Inc. of our report dated February 27, 2026 relating to the financial statements and the effectiveness of internal control over financial reporting, which appears in this Form 10- K. /s/ PricewaterhouseCoopers LLP Houston, Texas February 27, 2026
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Exhibit 23.2 DeGolyer and MacNaughton 5001 Spring Valley Road Suite 800 East Dallas, Texas 75244 February 27, 2026 Coterra Energy Inc. Three Memorial City Plaza 840 Gessner Road, Suite 1400 Houston, Texas 77024 Ladies and Gentlemen: We hereby consent to the references to DeGolyer and MacNaughton and to our independent evaluation of the proved oil, condensate, natural gas liquids, and gas reserves, as of December 31, 2025, 2024 and 2023, estimated by Coterra Energy Inc. (“Coterra”) that were presented in our reports of third party dated January 29, 2026, February 3, 2025 and January 26, 2024 (“Letter Reports”), under the headings “Reserves,” “Internal Control,” “Qualifications of Third Party Engineers,” “Critical Accounting Estimates,” and “Supplemental Oil and Gas Information (Unaudited) Oil and Gas Reserves” and to the filing of our Letter Reports as exhibits in the Annual Report on Form 10-K of Coterra for the fiscal year ended December 31, 2025. We further consent to the incorporation by reference of our Letter Reports in the Registration Statement on Form S-3 (File Nos. 333-282949 and 333-282950) and Form S-8 (File Nos. 333-195642, 333-260035, 333-260230, and 333-271681) of Coterra (“Registration Statements”) and to the use of the name DeGolyer and MacNaughton under the heading “Experts” in the Registration Statements. Very truly yours, /s/ DeGolyer and MacNaughton DeGOLYER and MacNAUGHTON Texas Registered Engineering Firm F-716
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Exhibit 31.1 I, Thomas E. Jorden, certify that: 1. I have reviewed this annual report on Form 10-K of Coterra Energy Inc.; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; c) evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and d) disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: February 27, 2026 /s/ THOMAS E. JORDEN Thomas E. JordenChairman, Chief Executive Officer and President
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Exhibit 31.2 I, Shannon E. Young III, certify that: 1. I have reviewed this annual report on Form 10-K of Coterra Energy Inc.; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; c) evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and d) disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: February 27, 2026 /s/ SHANNON E. YOUNG III Shannon E. Young III Executive Vice President and Chief Financial Officer
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Exhibit 32.1 Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code) Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code), each of the undersigned, Thomas E. Jorden, Chief Executive Officer of Coterra Energy Inc., a Delaware corporation (the "Company"), and Shannon E. Young III, Chief Financial Officer of the Company, hereby certify that, to his knowledge: (1) the Company's Annual Report on Form 10-K for the year ended December 31, 2025 (the "Report") fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and (2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. Dated:February 27, 2026 /s/ THOMAS E. JORDEN Thomas E. Jorden Chief Executive Officer /s/ SHANNON E. YOUNG III Shannon E. Young III Chief Financial Officer
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EXHIBIT 99.1 DeGolyer and MacNaughton 5001 Spring Valley Road Suite 800 East Dallas, Texas 75244 January 29, 2026 Coterra Energy Inc. Three Memorial City Plaza 840 Gessner Road Suite 1400 Houston, Texas 77024 Ladies and Gentlemen: Pursuant to your request, this report of third party presents an independent evaluation, as of December 31, 2025, of the estimated net proved oil, condensate, natural gas liquids (NGL), and gas reserves of certain properties in which Coterra Energy Inc. (Coterra) has represented it holds an interest. The properties evaluated herein are primarily located in New Mexico, Oklahoma, Pennsylvania, and Texas. This evaluation was completed on January 29, 2026. Coterra has represented that these properties account for greater than 90 percent of the total future net revenue discounted at 10 percent attributable to the total interests held by Coterra, as well as greater than 86 percent on a net equivalent barrel basis of net proved reserves attributable to the interests held by Coterra, as of December 31, 2025, and that the net proved reserves estimates were prepared in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the United States Securities and Exchange Commission (SEC). It is our opinion that the procedures and methodologies employed by Coterra for the preparation of its proved reserves estimates as of December 31, 2025, comply with the current requirements of the SEC. We have reviewed information provided to us by Coterra that it represents to be Coterra’s estimates of the net reserves, as of December 31, 2025, for the same properties as those which we evaluated. This report was prepared in accordance with guidelines specified in Item 1202(a)(8) of Regulation S–K and is to be used for inclusion in certain SEC filings by Coterra. Reserves estimates included herein are expressed as net reserves as represented by Coterra. Gross reserves are defined as the total estimated petroleum remaining to be produced from these properties after December 31, 2025. Net reserves are defined as that portion of the gross reserves attributable to the interests held by Coterra after deducting all interests held by others. Estimates of reserves should be regarded only as estimates that may change as further production history and additional information become available. Not only are such estimates based on that information which is currently available, but such estimates are also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information. Information used in the preparation of this report was obtained from Coterra and from public sources. In the preparation of this report we have relied, without independent verification, upon information furnished by Coterra with respect to the property interests being evaluated, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, and various other information and data that were accepted as represented. A field examination was not considered necessary for the purposes of this report.
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DeGolyer and MacNaughton Definition of Reserves Petroleum reserves included in this report are classified as proved. Only proved reserves have been evaluated for this report. Reserves classifications used in this report are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC. Reserves are judged to be economically producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation of current regulatory practices using conventional production methods and equipment. In the analyses of production-decline curves, reserves were estimated only to the limit of economic rates of production under existing economic and operating conditions using prices and costs consistent with the effective date of this report, including consideration of changes in existing prices provided only by contractual arrangements but not including escalations based upon future conditions. The petroleum reserves are classified as follows: Proved oil and gas reserves – Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. (i) The area of the reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. (ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. (iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. (iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities. (v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12 ‑ month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-
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DeGolyer and MacNaughton month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. Developed oil and gas reserves – Developed oil and gas reserves are reserves of any category that can be expected to be recovered: (i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. Undeveloped oil and gas reserves – Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. (i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. (ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. (iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in [section 210.4–10 (a) Definitions], or by other evidence using reliable technology establishing reasonable certainty. Methodology and Procedures Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principles and techniques that are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC and with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (revised June 2019) Approved by the SPE Board on 25 June 2019” and in Monograph 3 and Monograph 4 published by the Society of Petroleum Evaluation Engineers. The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history. Based on the current stage of field development, production performance, the development plans provided by Coterra, and analyses of areas offsetting existing wells with test or production data, reserves were classified as proved. The proved undeveloped reserves estimates were based on opportunities identified in the plan of development provided by Coterra.
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DeGolyer and MacNaughton Coterra has represented that its senior management is committed to the development plan provided by Coterra and that Coterra has the financial capability to execute the development plan, including the drilling and completion of wells and the installation of equipment and facilities. For the evaluation of unconventional reservoirs, a performance-based methodology integrating the appropriate geology and petroleum engineering data was utilized for this report. Performance-based methodology primarily includes (1) production diagnostics, (2) decline-curve analysis, and (3) model-based analysis (if necessary, based on availability of data). Production diagnostics include data quality control, identification of flow regimes, and characteristic well performance behavior. These analyses were performed for all well groupings (or type-curve areas). Characteristic rate-decline profiles from diagnostic interpretation were translated to modified hyperbolic rate profiles, including one or multiple b-exponent values followed by an exponential decline. Based on the availability of data, model-based analysis may be integrated to evaluate long-term decline behavior, the effect of dynamic reservoir and fracture parameters on well performance, and complex situations sourced by the nature of unconventional reservoirs. In the evaluation of undeveloped reserves, type-well analysis was performed using well data from analogous reservoirs for which more complete historical performance data were available. In certain cases, reserves were estimated by incorporating elements of analogy with similar wells or reservoirs for which more complete data were available. Data provided by Coterra from wells drilled through December 31, 2025, and made available for this evaluation were used to prepare the reserves estimates herein. These reserves estimates were based on consideration of daily and monthly production data available through December 2025. Cumulative production, as of December 31, 2025, was deducted from the estimated gross ultimate recovery to estimate gross reserves. Oil and condensate reserves estimated herein are those to be recovered by normal field separation. NGL reserves estimated herein include pentanes and heavier fractions (C ) and liquefied petroleum gas (LPG), which consists primarily of propane and butane fractions, and are the result of low-temperature plant processing. Oil, condensate, and NGL reserves included in this report are expressed in thousands of barrels (Mbbl). In these estimates, 1 barrel equals 42 United States gallons. For reporting purposes, oil and condensate reserves have been estimated separately and are presented herein as a summed quantity. Gas quantities estimated herein are expressed as sales gas. Sales gas is defined as the total gas to be produced from the reservoirs, measured at the point of delivery, after reduction for fuel usage, flare, and shrinkage resulting from field separation and processing. Gas reserves estimated herein are reported as sales gas. Gas quantities are expressed at a temperature base of 60 degrees Fahrenheit (°F) and at the pressure base of the state in which the quantities are located. Gas quantities included in this report are expressed in millions of cubic feet (MMcf). Gas quantities are identified by the type of reservoir from which the gas will be produced. Nonassociated gas is gas at initial reservoir conditions with no oil present in the reservoir. Associated gas is both gas-cap gas and solution gas. Gas-cap gas is gas at initial reservoir conditions and is in communication with an underlying oil zone. 5+
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DeGolyer and MacNaughton Solution gas is gas dissolved in oil at initial reservoir conditions. Gas quantities estimated herein include both associated and nonassociated gas. At the request of Coterra, sales gas reserves estimated herein were converted to oil equivalent using an energy equivalent factor of 6,000 cubic feet of gas per 1 barrel of oil equivalent. Primary Economic Assumptions This report has been prepared using initial prices, expenses, and costs provided by Coterra. Future prices were estimated using guidelines established by the SEC and the Financial Accounting Standards Board (FASB). The following economic assumptions were used for estimating the reserves reported herein: Oil and Condensate Prices Coterra has represented that the oil and condensate prices were based on a reference price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual agreements. Coterra applied differentials by property to a West Texas Intermediate reference price of $65.34 per barrel and the prices were held constant thereafter. The volume-weighted average price attributable to the estimated proved reserves over the lives of the properties for only those properties evaluated by DeGolyer and MacNaughton was $64.37 per barrel of oil and condensate. NGL Prices Coterra has represented that the NGL prices were based on a reference price of $27.54 per barrel. Coterra supplied differentials by property to the reference price and the prices were held constant thereafter. The volume-weighted average price attributable to the estimated proved reserves over the lives of the properties for only those properties evaluated by DeGolyer and MacNaughton was $16.88 per barrel of NGL. Gas Prices Coterra has represented that the gas prices were based on a reference price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12 ‑ month period prior to the end of the reporting period, unless prices are defined by contractual agreements. Coterra applied differentials by property to a Henry Hub reference price of $3.39 per million Btu and held constant thereafter. Btu factors provided by Coterra were used to convert prices from dollars per million Btu to dollars per thousand cubic feet. The volume ‑ weighted average price attributable to the estimated proved reserves over the lives of the properties for only those properties evaluated by DeGolyer and MacNaughton was $2.372 per thousand cubic feet of gas. Production and Ad Valorem Taxes Production taxes were calculated using the tax rates for the state in which the reserves are located. Ad valorem taxes were calculated using rates provided by Coterra based on recent payments.
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DeGolyer and MacNaughton Operating Expenses, Capital Costs, and Abandonment Costs Estimates of operating expenses and future capital expenditures, provided by Coterra and based on existing economic conditions, were held constant for the lives of the properties and were not adjusted for inflation. In certain cases, future expenditures, either higher or lower than current expenditures, may have been used because of anticipated changes in operating conditions, but no general escalation that might result from inflation was applied. Abandonment costs, which are those costs associated with the removal of equipment, plugging of wells, and reclamation and restoration associated with the abandonment, were provided by Coterra for all properties and were not adjusted for inflation. Operating expenses, capital costs, and abandonment costs were considered, as appropriate, in determining the economic viability of the undeveloped reserves estimated herein. In our opinion, the information relating to estimated proved reserves of oil, condensate, NGL, and gas of the properties evaluated by us contained in this report has been prepared in accordance with Paragraphs 932-235-50-4, 932-235-50-6, 932-235-50-7, and 932-235- 50-9 of the Accounting Standards Update 932-235-50, Extractive Industries – Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures (January 2010) of the FASB and Rules 4–10(a) (1)–(32) of Regulation S–X and Rules 302(b), 1201, 1202(a) (1), (2), (3), (4), (8), and 1203(a) of Regulation S–K of the SEC; provided, however, that estimates of proved developed and proved undeveloped reserves are not presented at the beginning of the year. To the extent the above-enumerated rules, regulations, and statements require determinations of an accounting or legal nature, we, as engineers, are necessarily unable to express an opinion as to whether the above-described information is in accordance therewith or sufficient therefor.
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DeGolyer and MacNaughton Summary of Conclusions DeGolyer and MacNaughton has performed an independent evaluation of the extent of the estimated net proved oil, condensate, NGL, and gas reserves of certain properties in which Coterra has represented it holds an interest. Coterra has represented that its estimated net proved reserves attributable to the evaluated properties were based on the definition of proved reserves of the SEC. Coterra’s estimates of the net proved reserves, as of December 31, 2025, attributable to these properties, which represent greater than 86 percent of the reserves attributable to the interests held by Coterra on a net equivalent basis and greater than 90 percent of the total future net revenue discounted at 10 percent attributable to the interests held by Coterra, are summarized as follows, expressed in thousands of barrels (Mbbl), millions of cubic feet (MMcf), and thousands of barrels of oil equivalent (Mboe): Estimated by Coterra Net Proved Reserves as of December 31, 2025 Oil and Condensate (Mbbl) NGL (Mbbl) Sales Gas (MMcf) Oil Equivalent (Mboe) Evaluated by DeGolyer and MacNaughton 341,978 362,683 9,080,439 2,218,068 Not Evaluated by DeGolyer and MacNaughton 43,505 65,346 1,430,183 347,214 Total Proved Reserves 385,483 428,029 10,510,622 2,565,282 Notes: 1. All reserves estimates shown herein were prepared by Coterra. 2. Sales gas reserves estimated herein were converted to oil equivalent using an energy equivalent factor of 6,000 cubic feet of gas per 1 barrel of oil equivalent. In comparing the detailed net proved reserves estimates prepared by DeGolyer and MacNaughton and by Coterra, differences have been found, both positive and negative, resulting in an aggregate difference of less than 10 percent when compared on the basis of net equivalent barrels. It is DeGolyer and MacNaughton’s opinion that the net proved reserves estimates prepared by Coterra on the properties evaluated by DeGolyer and MacNaughton and referred to above, when compared on the basis of net equivalent barrels, in aggregate, do not differ materially from those prepared by DeGolyer and MacNaughton. While the oil and gas industry may be subject to regulatory changes from time to time that could affect an industry participant’s ability to recover its reserves, we are not aware of any such governmental actions which would restrict the recovery of the December 31, 2025, estimated reserves. DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1936. DeGolyer and MacNaughton does not have any financial interest, including stock ownership, in Coterra. Our fees were not contingent on the results of our evaluation. This report has been prepared at the request of Coterra. DeGolyer and MacNaughton has used all assumptions, procedures, data, and methods that it considers necessary to prepare this report.
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DeGolyer and MacNaughton Submitted, /s/ DeGolyer and MacNaughton DeGOLYER and MacNAUGHTON Texas Registered Engineering Firm F-716
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DeGolyer and MacNaughton CERTIFICATE of QUALIFICATION I, Dilhan Ilk, Petroleum Engineer with DeGolyer and MacNaughton, 5001 Spring Valley Road, Suite 800 East, Dallas, Texas, 75244 U.S.A., hereby certify: 1. That I am an Executive Vice President with DeGolyer and MacNaughton, which firm did prepare this report of third party addressed to Coterra Energy Inc. dated January 29, 2026, and that I, as Executive Vice President, was responsible for the preparation of this report of third party. 1. That I attended Istanbul Technical University, and that I graduated with a Bachelor of Science degree in Petroleum Engineering in the year 2003, a Master of Science degree in Petroleum Engineering from Texas A&M University in 2005, and a Doctor of Philosophy degree in Petroleum Engineering from Texas A&M University in 2010; that I am a Registered Professional Engineer in the State of Texas; that I am a member of the Society of Petroleum Engineers; and that I have in excess of 15 years of experience in oil and gas reservoir studies and reserves evaluations. /s/ Dilhan Ilk Dilhan Ilk, P.E.[SEAL] Executive Vice President DeGolyer and MacNaughton