Coterra Energy Inc. (CTRA) FY 2025 MD&A

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.

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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.

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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 an impairment 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.

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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:

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

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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.

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Capitalization

Information about our capitalization is as follows:

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(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.

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.

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The following table presents major components of our capital and exploration expenditures:

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(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.

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RESULTS OF OPERATIONS

2025 and 2024 Compared

Operating Revenues

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

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

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

NGL revenues increased $106 million primarily due to higher NGL volumes in the Permian Basin and Anadarko Basin, partially offset by lower NGL prices.

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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:

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.

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.

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Direct operations consisted of lease operating expense and workover expense as follows:

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:

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.

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Depreciation, Depletion and Amortization

DD&A expense consisted of the following for the periods indicated:

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:

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.

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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:

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

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.

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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

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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.

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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.