Coterra Energy Inc. (CTRA)

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, 2024 compared to the year ended December 31, 2023 reflect the following:

•Net income decreased $504 million from $1.6 billion, or $2.14 per share, in 2023 to $1.1 billion, or $1.51 per share, in 2024.

•Net cash provided by operating activities decreased $863 million, from $3.7 billion, in 2023 to $2.8 billion in 2024.

•Equivalent production increased 4.1 MMBoe from 243.5 MMBoe, or 667.1 MBoe per day, in 2023 to 247.6 MMBoe, or 676.5 MBoe per day, in 2024.

◦Oil production increased 4.7 MMBbl from 35.1 MMBbl, or 96 MBbl per day, in 2023 to 39.8 MMBbl, or 109 MBbl per day, in 2024.

◦Natural gas production decreased 28.0 Bcf from 1,052.7 Bcf, or 2,884 MMcf per day, in 2023 to 1,024.7 Bcf, or 2,800 MMcf per day, in 2024.

◦NGL volumes increased 4.1 MMBbl from 32.9 MMBbl, or 90 MBbl per day, in 2023 to 37.0 MMBbl, or 101 MBbl per day, in 2024.

•Average realized prices (including impact of derivatives):

◦Oil was $74.22 per Bbl in 2024, 2 percent lower than the $76.07 per Bbl price realized in 2023.

◦Natural gas was $1.75 per Mcf in 2024, 28 percent lower than the $2.44 per Mcf price realized in 2023.

◦NGL price for 2024 was $19.95 per Bbl, 2 percent higher than the $19.56 per Bbl price realized in 2023.

•Total capital expenditures for drilling, completion and other fixed assets were $1.8 billion in 2024 compared to $2.1 billion in 2023.

Other financial highlights for the year ended December 31, 2024 and subsequent periods include the following:

•Issued $500 million aggregate principal amount of 5.60% senior notes due March 15, 2034. We used the net proceeds, and cash on hand, to repay the $575 million of 3.65% weighted-average private placement senior notes that matured in September 2024.

•Amended our revolving credit agreement to increase our aggregate commitments from $1.5 billion to $2.0 billion and extend the maturity date from March 2028 to September 2029.

•Entered into a $1.0 billion delayed draw term loan agreement consisting of two tranches of $500 million each, which was fully drawn in January 2025 to partially fund the FME and Avant acquisitions that both closed in January 2025.

•Issued $750 million aggregate principal amount of 5.40% senior notes due February 15, 2035 and $750 million aggregate principal amount of 5.90% senior notes due February 15, 2055. The net proceeds were used to partially fund the FME and Avant acquisitions which both closed in January 2025.

•Completed our previously announced acquisitions of FME and Avant in January 2025 for an aggregate consideration of approximately $4.0 billion, subject to certain post-closing adjustments.

•Increased our quarterly base dividend from $0.20 per share to $0.21 per share in February 2024, and in February 2025 our Board of Directors approved an additional increase of our quarterly base dividend from $0.21 per share to $0.22 per share.

•Repurchased 17 million shares of our common stock during 2024 for $464 million.

Market Conditions and Commodity Prices

Our financial results depend on many factors, particularly commodity prices and our ability to find, develop and market our production on economically attractive terms. Commodity prices are affected by many factors outside of our control,

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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.

Oil prices were relatively steady in 2024 compared to 2023 as demand has continued for oil supply. Following global conflict and supply chain disruptions that drove high oil prices in 2022, OPEC+ reacted with supply reductions which helped to stabilize oil price levels in 2023. U.S. oil production was relatively flat from 2023 to 2024, which, when combined with OPEC+’s reductions, contributed to relatively steadier oil prices in 2023 and 2024. Additionally, while OPEC+ previously announced gradually increasing oil production over the course of 2025, several key members of OPEC+ have indicated their intent to delay such increases until the second half of 2025 and into 2026.

Natural gas prices trended down in 2024 compared to 2023 as strong production and relatively weak demand drove inventory levels above the five-year average. While natural gas prices have recovered from their lows in early 2024, natural gas prices in 2024 still trended lower overall compared to 2023. In response to the weakness of natural gas prices, we reduced our capital expenditures in the Marcellus Shale and also strategically curtailed our natural gas production in the basin from August 2024 through November 2024, resulting in an estimated curtailment of 232 MMcf per day of net production during that period. Natural gas prices increased slightly during the last quarter of 2024 and so far have continued to increase into early 2025 due to, among other factors, colder temperatures resulting in increased seasonal demand. Meanwhile, basis differentials became more divergent in 2024, in part due to constrained pipeline capacity and oversupply in certain geographic areas, and at times have resulted in negative spot market pricing for natural gas during 2024, such as the Waha Hub in the Permian Basin. While such issues have abated so far in 2025 in part due to the opening of the Matterhorn Express Pipeline in the fourth quarter of 2024, basis differentials may increase in magnitude again in 2025 due to a variety of factors we cannot predict. Looking to 2025, forward pricing indicates the recent increase in natural gas prices overall is expected to continue through the remainder of 2025, partially as a result of, among other factors, an expected increase in demand driven by LNG exports. However, LNG exports may be impacted by retaliatory tariffs (including China’s recently announced LNG tariffs), which could reduce the expected demand for LNG in 2025. Nevertheless, we expect natural gas prices overall to be stronger in 2025 compared to 2024.

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 and continue 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 conflicts in the Middle East, 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. 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.

In addition, the issue of, and increasing political and social attention on, climate change has resulted in both existing and pending national, regional and local legislation and regulatory measures, such as mandates for renewable energy and emissions reductions. Changes in these laws or regulations may result in delays or restrictions in permitting and the development of projects, may result in increased costs and may impair our ability to move forward with our construction, completions, drilling, water management, waste handling, storage, transport and remediation activities, or may result in renewable energy alternatives that become more competitive with traditional oil and natural gas-derived products (including government subsidies and incentives for electric vehicles), any of which could have an adverse effect on our financial results.

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 funding our planned acquisitions and 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. However, from time-to-time, our investments may be funded by bank borrowings (including draws under our revolving credit agreement), 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

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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 and term loan, 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. At December 31, 2024 and 2023, we had a working capital surplus of $2.2 billion and $355 million, respectively. The increase in our working capital surplus is primarily due to an increase in cash and cash equivalents related to our issuance of $1.5 billion of senior notes in December 2024 to partially fund our FME and Avant acquisitions which both closed in January 2025. We believe we have adequate liquidity and availability under our revolving credit agreement as outlined above to meet our working capital requirements over the next 12 months.

In March 2024, we issued $500 million of 5.60% senior notes, and used these net proceeds, along with cash on hand, to fund the repayment of the $575 million of 3.65% weighted-average senior notes that matured in September 2024.

In September 2024, we entered into an amendment relating to our revolving credit agreement, which increased our aggregate commitments from $1.5 billion to $2.0 billion and extended the maturity date to September 2029, among other things.

In December 2024, we issued $750 million of 5.40% senior notes which will mature in February 2035 and $750 million of 5.90% senior notes which will mature in February 2055. We used the net proceeds to partially fund the FME and Avant acquisitions which both closed in January 2025.

In December 2024, we entered into a $1.0 billion delayed draw term loan agreement which consists of two tranches, 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. In January 2025, we borrowed the full $1.0 billion available under the term loan and used the proceeds to partially fund the FME and Avant acquisitions which both closed in January 2025.

As of December 31, 2024, we had unrestricted cash on hand of $2.0 billion, unused commitments of $2.0 billion under our revolving credit agreement, and a $1.0 billion undrawn term loan. Subsequently, the term loan was fully drawn in January 2025, as discussed herein.

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, 2024, 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:

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2024 and 2023 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 decreased by $863 million in 2024 compared to 2023. This decrease was primarily due to a decrease in natural gas revenue, caused by lower natural gas prices and production, an increase in operating costs, a decrease in cash received on derivative settlements and a net reduction in working capital during 2024. These decreases were partially offset by higher oil and NGL revenues primarily driven by higher production.

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 decreased by $297 million in 2024 compared to 2023. This decrease was primarily due to $335 million of lower cash paid for capital expenditures, partially offset by $31 million lower proceeds from asset sales.

Financing Activities. Cash flows provided by financing activities increased by $1.6 billion in 2024 compared to 2023. The increase was due to the issuance of the $500 million of 5.60% senior notes in March 2024, $750 million of 5.40% senior notes and $750 million of 5.90% senior notes in December 2024, and $265 million of lower dividend payments. These increases were partially offset by the repayment of $575 million of 3.65% weighted-average senior notes at their maturity in September 2024 and $50 million of higher common stock repurchases during 2024. The lower dividend payments were a result of a decrease in our dividend from $1.17 per common share for 2023 to $0.84 per common share for 2024 due to a special variable-rate dividend of $0.37 that was paid in 2023, and a decrease in outstanding shares of stock due to our active share repurchase program during 2023 and 2024.

2023 and 2022 Compared. For information on the comparison of operating, investing, and financing cash flows for the year ended December 31, 2023 compared to the year ended December 31, 2022, refer to Financial Condition (Cash Flows) included in the Coterra Energy Inc. Annual Report on Form 10-K for the year ended December 31, 2023, which information in incorporated by reference herein.

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 (the “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, 2024, we were in compliance with all financial covenants and had $2.0 billion of borrowing capacity under our Credit Agreement.

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Term Loan

In December 2024, we entered into a $1.0 billion 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. As of December 31, 2024, we had no borrowings outstanding under the Term Loan and $1.0 billion of available commitments.

In January 2025, we borrowed $500 million under the Tranche A Term Loan to partially fund the closing of the FME acquisition and $500 million under the Tranche B Term Loan to partially fund the closing of the Avant acquisition.

Borrowings under the Term Loan bear interest at a rate per annum equal to, at our option, either (i) a term SOFR plus a 0.10 percent credit spread adjustment for all tenors or (ii) 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 ticking fee on the average daily amount of the Tranche A commitments and Tranche B commitments is calculated at annual rates ranging from 10 basis points to 25 basis points based on our credit rating.

The Term Loan 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 until such time as we have no other debt (other than our Credit Agreement) 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 capitalization of no more than 65 percent (with all calculations based on definitions contained in the Term Loan).

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, 2024, 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.

Capitalization

Information about our capitalization is as follows:

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(1)Included $575 million of current portion of long-term debt as of December 31, 2023 that was repaid at maturity in September 2024. There were no borrowings outstanding under our Credit Agreement or Term Loan as of December 31, 2024 or December 31, 2023.

Share repurchases. In February 2023, our Board of Directors approved a new 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.

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During the year ended December 31, 2024, we repurchased and retired 17 million shares of our common stock for $464 million. We repurchased and retired 17 million shares of common stock for $418 million during the year ended December 31, 2023.

During the years ended December 31, 2024 and 2023, 351,791 and 332,634 shares of common stock, respectively, 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 2023 and 2024, our Board of Directors approved an increase in the base quarterly dividend from $0.15 per share to $0.20 per share beginning in the first quarter of 2023 and from $0.20 per share to $0.21 per share beginning in the first quarter of 2024, respectively.

In February 2025, our Board of Directors approved an additional increase in our base quarterly dividend from $0.21 per share to $0.22 per share beginning in the first quarter of 2025.

The following table presents our dividends paid on our common stock for the year ended December 31, 2024 and 2023.

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.

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 2023 and 2022.

In 2024, our capital program focused on the Permian Basin, Anadarko Basin, and Marcellus Shale, where we drilled 313 gross wells (159.4 net) and completed 290 gross wells (143.8 net), of which 92 gross wells (62.8 net) were drilled but uncompleted in prior years.

Our 2025 full year capital program is expected to be in the range of approximately $2.1 billion to $2.4 billion. We expect to turn-in-line 175 to 205 total net wells in 2025 across our three operating regions. Approximately 70 percent of capital expenditures will be invested in the Permian Basin, 11 percent in the Marcellus Shale, 10 percent in the Anadarko Basin and remaining percent for gathering systems infrastructure, saltwater disposal and other spend. The increase in our year-over-year budgeted capital program was primarily driven by incremental capital expenditures associated with our recently completed FME and Avant acquisitions in January 2025, which increased our anticipated expenditures in the Permian Basin. We will continue to assess the commodity price environment and may increase or decrease our capital expenditures accordingly.

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Contractual Obligations

We have various contractual obligations in the normal course of our operations. As of December 31, 2024, 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, 2024, 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.

RESULTS OF OPERATIONS

2024 and 2023 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 $286 million primarily due to higher production in the Permian Basin partially offset by lower oil prices.

Natural Gas Revenues

Natural gas revenues decreased $599 million primarily due to significantly lower natural gas prices and lower production. The decrease in production was primarily due to lower production in the Marcellus Shale, where we strategically curtailed production from August 2024 through November 2024 due to weaker natural gas prices. This decrease was partially offset by higher production in the Permian and Anadarko Basins.

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NGL Revenues

NGL revenues increased $94 million primarily due to higher NGL volumes in the Permian Basin and Anadarko Basin and slightly higher NGL prices.

Gain (Loss) on Derivative Instruments

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” 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 began to stabilize at the end of 2023 despite on-going demand and the latent effects of inflation and supply chain disruptions and continued to remain stable throughout 2024.

The following table reflects our operating costs and expenses for the years indicated and a discussion of the operating costs and expenses follows.

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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.

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

Lease operating expense increased primarily due to higher production levels and higher operating costs driven by our production mix related to higher production in fields with higher operating costs, primarily in the Permian Basin, and higher equipment and field service costs.

Workover expense increased primarily due to an increase in workover activity in the Permian 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 $1 million primarily due to higher gathering and transportation costs in the Permian Basin related to higher production and higher transportation rates, partially offset by lower gathering charges in the Marcellus Shale related to lower production.

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 decreased $12 million primarily due to lower ad valorem taxes, which was primarily driven by a combination of lower-than-expected property valuations in 2024 resulting in a lower tax obligation and a reduction of prior period accruals in 2024 due to a change in estimated taxes due for the full-year 2023. Additionally, drilling impact fees decreased primarily due to a decrease in drilling activity in the Marcellus Shale and a decrease in assessed rates as a result of lower natural gas prices. These decreases were partially offset by an increase in our production taxes, which increased primarily due to higher oil and NGL production compared to 2023.

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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 $198 million primarily due to a higher depletion rate and an increase in production. Our depletion rate increased due to lower oil and gas reserve volumes and a shift in our production mix to fields with higher depletion rates. The lower oil and gas reserve volumes were driven by negative price revisions as a result of lower prices in 2023.

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. Also included in our depreciation expense is the depreciation of the right-of-use asset associated with our finance lease gathering system. Depreciation expense remained steady in 2024 compared to 2023.

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. Amortization of unproved properties remained steady in 2024 compared to 2023.

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 higher employee-related costs in 2024 compared to 2023 and the recognition of certain long-term commitments for community outreach and charitable contributions in 2024. These increases were partially offset by lower legal expenses in 2024 compared to 2023.

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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. Stock-based compensation expense increased $3 million primarily due to the impact of the liquidation of our common stock from our deferred compensation plan that resulted in a $7 million gain that decreased stock-based compensation expense in the first half of 2023. This increase was partially offset by a decrease in the valuation of performance share awards in 2024 compared to 2023 due to a weaker common stock price and lower non-recurring stock-based compensation expenses related to replacement awards that were granted in the Cimarex merger that vested in late 2023 and the second half of 2024.

Merger related expense decreased $12 million as the accrual for employee-related severance and termination benefits associated with the Cimarex merger transition employees was completed in 2023.

Gain (Loss) on Sale of Assets

The decrease in gain (loss) on sale of assets is due to the sale of certain non-core oil and gas properties and other equipment in 2023.

Interest Expense

The table below reflects our interest expense, net for the periods indicated:

Interest expense increased $19 million due to higher debt balances primarily related to the issuance of $500 million of 5.60% senior notes in March 2024 partially offset by the repayment of $575 million related to the 3.65% weighted-average private placement senior notes in September 2024.

Debt issuance cost amortization increased $6 million primarily due to fees associated with a bridge commitment to provide the term loan commitments related to the FME and Avant acquisitions. These costs were expensed upon termination of the bridge commitment in December 2024.

Other interest expense increased $8 million related to assessments arising due to the timing of certain regulatory filings.

Interest Income

Interest income increased $15 million primarily due to higher interest earned on our higher cash and short-term investment balances during 2024 compared to 2023.

Income Tax Expense

Income tax expense decreased $279 million primarily due to lower pre-tax income and a lower effective tax rate. The effective tax rate decreased due to differences in the non-recurring discrete items recorded during 2024 compared to 2023.

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2023 and 2022 Compared

For information on the comparison of the results of operations for the year ended December 31, 2023 compared to the year ended December 31, 2022, 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, 2023, 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 judgement of management.

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 2024, 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 reserves would result in a decrease of $0.33 per Boe and an increase of $0.37 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

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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 $12 million or decrease by $8 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 our counterparties. 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 or third-party valuation services, or a combination of the foregoing, for reasonableness. The determination of fair value also incorporates a credit adjustment for non-performance risk. We measure the non-performance risk of our counterparties by reviewing credit default swap spreads for the various financial institutions with which we have derivative transactions, 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.

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.

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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 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, 2023 compared to the year ended December 31, 2022 are as follows:

•Net income decreased $2.4 billion from $4.1 billion, or $5.09 per share, in 2022 to $1.6 billion, or $2.14 per share, in 2023.

•Net cash provided by operating activities decreased $1.8 billion, from $5.5 billion, in 2022 to $3.7 billion in 2023.

•Equivalent production increased 12.2 MMBoe from 231.3 MMBoe, or 633.8 MBoe per day, in 2022 to 243.5 MMBoe, or 667.1 MBoe per day, in 2023.

◦Natural gas production increased 28.4 Bcf from 1,024.3 Bcf, or 2,806 MMcf per day, in 2022 to 1,052.7 Bcf, or 2,884 MMcf per day, in 2023.

◦Oil production increased 3.2 MMBbl from 31.9 MMBbl, or 87 MBbl per day, in 2022 to 35.1 MMBbl, or 96 MBbl per day, in 2023.

◦NGL volumes increased 4.2 MMBbl from 28.7 MMBbl, or 79 MBbl per day, in 2022 to 32.9 MMBbl, or 90 MBbl per day, in 2023.

•Average realized prices:

◦Natural gas was $2.44 per Mcf in 2023, 50 percent lower than the $4.91 per Mcf price realized in 2022.

◦Oil was $76.07 per Bbl in 2023, 10 percent lower than the $84.33 per Bbl price realized in 2022.

◦NGL price for 2023 was $19.56 per Bbl, 42 percent lower than the $33.58 per Bbl price realized in 2022.

•Total capital expenditures for drilling, completion and other fixed assets were $2.1 billion in 2023 compared to $1.7 billion in 2022. The increase was driven by higher planned completion activity levels across our operations and higher costs.

•Increased our quarterly base dividend from $0.15 per share for regular quarterly dividends in 2022 to $0.20 per share in 2023 as part of our returns-focused strategy.

•Increased our quarterly base dividend from $0.20 per share to $0.21 per share in February 2024.

•Implemented our new $2.0 billion share repurchase program and repurchased 17 million shares for $418 million during the year ended December 31, 2023. Under our previous share repurchase program, we repurchased 48 million shares for $1.25 billion during the year ended December 31, 2022.

Market Conditions and Commodity Prices

Our financial results depend on many factors, particularly commodity prices and our ability to find, develop 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 are impacted by pipeline capacity constraints, inventory storage levels, basis differentials, weather conditions, and geopolitical, economic and other factors.

Oil prices have recovered in recent years from previous pandemic related market weakness, particularly on the demand side. Global conflict and supply chain disruptions drove high oil prices in 2022, which then moderated throughout 2023. OPEC+ reacted with supply reductions, helping to stabilize oil price levels during 2023. Oil and gas companies in the U.S. have largely refrained from expanding their existing production, which has contributed to steadier oil prices in 2023 as compared to recent years and to improved oil futures prices in early 2024.

Natural gas prices trended down year-over-year but strengthened in fourth quarter due to increased power demand. However, natural gas futures prices have declined in the first part of 2024 as the domestic market appears oversupplied.

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 and continue for an extended period of time, our operations could be adversely impacted, commodity prices could decline and our costs may increase. Oil and natural gas prices

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have fallen significantly since their peak in 2022, and we expect commodity price volatility to continue driven by further geopolitical disruptions, including conflicts in the Middle East and actions of OPEC+, and swift near and medium term fluctuations in supply and demand. Although 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 increase significantly from current levels, our management would evaluate the recoverability of the carrying value of our oil and gas properties.

In addition, the issue of, and increasing political and social attention on, climate change has resulted in both existing and pending national, regional and local legislation and regulatory measures, such as mandates for renewable energy and emissions reductions targeted at limiting or reducing emissions of GHGs. Changes in these laws or regulations may result in delays or restrictions in permitting and the development of projects, may result in increased costs and may impair our ability to move forward with our construction, completions, drilling, water management, waste handling, storage, transport and remediation activities, any of which could have an adverse effect on our financial results.

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. However, from time to time, our investments may be funded by bank borrowings (including draws under our revolving credit agreement), sales of non-strategic assets, and private or public financing based on our monitoring of capital markets and our balance sheet. Our debt is currently rated as investment grade by the three leading rating agencies, and 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. In determining our debt ratings, the agencies consider a number of qualitative and quantitative items including, but not limited to, current commodity prices, our liquidity position, our debt levels and leverage ratios, the size and mix of our production and proved reserves, and our cost structure. Credit ratings are not recommendations to buy, sell, or hold securities and may be subject to revision or withdrawal at any time by the assigning rating agency. A change in our debt rating could impact our interest rate on any borrowings under our revolving credit agreement and our ability to economically access debt markets in the future and could trigger the requirement to post credit support under various agreements, which could reduce the borrowing capacity under our revolving credit agreement. 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, 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. At December 31, 2023 and 2022, we had a working capital surplus of $355 million and $1.0 billion, respectively. The decrease in our working capital surplus is primarily due to the reclassification during 2023 of $575 million of long-term debt scheduled to mature in September 2024 to current liabilities. We believe we have adequate liquidity and availability under our revolving credit agreement as outlined above to meet our working capital requirements over the next 12 months.

As of December 31, 2023, we had no borrowings outstanding under our revolving credit agreement, our unused commitments were $1.5 billion, and we had unrestricted cash on hand of $956 million.

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Cash Flows

Our cash flows from operating activities, investing activities and financing activities are as follows:

Operating Activities. Operating cash flow fluctuations are substantially driven by changes in commodity prices, production volumes and operating expenses. Commodity prices have historically been volatile, primarily as a result of supply and demand for oil and natural gas, pipeline infrastructure constraints, basis differentials, inventory storage levels, seasonal influences and geopolitical, economic and other factors. In addition, fluctuations in cash flow may result in an increase or decrease in our capital expenditures.

Net cash provided by operating activities in 2023 decreased by $1.8 billion compared to 2022. This decrease was primarily due to lower net income as a result of lower natural gas, oil and NGL revenue due to lower commodity prices, partially offset by higher production. This decrease was partially offset by lower operating costs, higher cash received on derivative settlements and a larger contribution from changes in working capital and other assets and liabilities.

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 $385 million from 2022 to 2023. The increase was primarily due to $389 million of higher capital expenditures due to our increased capital budget for 2023 compared to 2022 .

Financing Activities. Cash flows used in financing activities decreased by $2.8 billion from 2022 to 2023. The decrease was primarily due to $1.1 billion of lower dividend payments and $845 million of lower common stock repurchases during 2023, and $874 million net repayments of debt in 2022.

2022 and 2021 Compared. For information on the comparison of operating, investing, and financing cash flows for the year ended December 31, 2022 compared to the year ended December 31, 2021, refer to Financial Condition (Cash Flows) included in the Coterra Energy Inc. Annual Report on Form 10-K for the year ended December 31, 2022, which information in incorporated by reference herein.

Revolving Credit Agreement

We had $1.5 billion of borrowing capacity under our revolving credit agreement at December 31, 2023. The revolving credit agreement is scheduled to mature in March 2028 and 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. Borrowings under our revolving 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, in each case plus 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. Our revolving 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 revolving credit agreement will instead require us to maintain a ratio of total debt to total capitalization of no more than 65 percent. At December 31, 2023, we were in compliance with all financial covenants for our revolving credit agreement. 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 the revolving credit agreement and our leverage ratio.

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

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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, 2023, 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 restrictive covenants contained in our various debt instruments.

Capitalization

Information about our capitalization is as follows:

Share repurchases. In February 2023, our Board of Directors approved a new 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 2023, we repurchased and retired 17 million shares of our common stock for $418 million under our authorized share repurchase program. During 2022, the Company repurchased 48 million shares of common stock for $1.25 billion under the February 2022 share repurchase program. During the years ended December 31, 2023 and 2022, 332,634 and 320,236 shares of common stock, respectively, were recorded as treasury stock and retired related to common shares that were retained from vested restricted stock awards for withholding of taxes.

In December 2022, our Board of Directors authorized the retirement of our common stock held in treasury as of December 31, 2022 and provided that prospectively, share repurchases and shares withheld for the vesting of stock awards will be retired in the period in which they are repurchased or withheld. Accordingly, as of December 31, 2023 and 2022, there were no common shares held in Treasury Stock on the Consolidated Balance Sheet.

Dividends. In February 2023, our Board of Directors approved an increase in the base quarterly dividend from $0.15 per share to $0.20 per share.

The following table presents our dividends paid on our common stock for the year ended December 31, 2023 and 2022.

In February 2024, our Board of Directors approved an increase in our base quarterly dividend from $0.20 per share to $0.21 per share beginning in the first quarter of 2024, and approved a quarterly base dividend of $0.21 per share.

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:

_______________________________________________________________________________

(1)These amounts represent the fair value of the proved and unproved properties recorded in the purchase price allocation with respect to the Merger. The purchase was funded through the issuance of our common stock.

(2)There were no exploratory dry hole costs in 2023, 2022 and 2021.

In 2023, we drilled 264 gross wells (169.4 net) and completed 288 gross wells (183.3 net), of which 98 gross wells (62.7 net) were drilled but uncompleted in prior years.

Our 2024 capital program is expected to be approximately $1.75 billion to $1.95 billion. We expect to turn-in-line 132 to 158 total net wells in 2024 across our three core operating areas. Approximately 60 percent of our drilling and completion capital will be invested in the Permian Basin, 23 percent in the Marcellus Shale and 17 percent in the Anadarko Basin (at the mid-point). The decrease in our year-over-year capital expenditures is primarily driven by lower planned spending in the Marcellus Shale, partially offset by modest increases in the Permian Basin and Anadarko Basin. 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, 2023, 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, 2023, 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

2023 and 2022 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 we expect to fluctuate due to supply and demand factors, and the availability of transportation, seasonality and geopolitical, economic and other factors.

Natural Gas Revenues

Natural gas revenues decreased $3.2 billion primarily due to significantly lower natural gas prices, partially offset by higher production. The increase in production was related to higher production in the Marcellus Shale, Permian Basin and Anadarko Basin.

Oil Revenues

Oil revenues decreased $349 million primarily due to lower oil prices, offset by higher production mainly in the Permian Basin.

NGL Revenues

NGL revenues decreased $320 million primarily due significantly lower NGL prices, partially offset by higher NGL volumes, particularly in the Permian Basin.

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Gain (Loss) on Derivative Instruments

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” 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 remained high due to on-going demand for those items, and to a lesser extent rising inflation and supply chain disruptions, all of which affected the cost of our operations throughout 2022. During 2023, these costs have begun to stabilize.

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 well 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 higher production levels. Additionally, lease operating expense on a per Boe basis generally increased due to increasing costs of equipment and field services, which began to stabilize in late 2023, and higher contract labor and employee-related costs.

Gathering, Processing and Transportation

Gathering, processing and transportation costs principally consist of expenditures to treat and transport production downstream from the wellhead, including gathering, fuel, and compression and processing costs, the last of 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 $20 million primarily due to higher production levels, partially offset by lower costs in the Permian Basin and Anadarko Basin due to lower gathering and transportation rates which were driven by lower commodity prices during 2023 compared to the same period in 2022.

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 decreased $83 million. Production taxes represented the majority of our taxes other than income, which decreased primarily due to lower oil, natural gas and NGL revenues. Drilling impact fees decreased primarily due to the timing of wells drilled in the Marcellus Shale and lower natural gas prices, which drive the fees assessed on our drilling activities.

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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 depend upon the assumed realized sales price for future production. Therefore, fluctuations in oil and 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 $35 million primarily due to increased production partially offset by a lower depletion rate of $6.20 per Boe for 2023 compared to $6.37 per Boe for 2022.

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. Also included in our depreciation expense is the depreciation of the right-of-use asset associated with our finance lease gathering system. Depreciation expense decreased $17 million primarily due to a non-recurring impairment charge related to certain right-of-use assets (building leases) recorded in late 2022.

Unproved oil and gas 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. Amortization of unproved properties decreased $13 million primarily due to a non-recurring charge related to the release of certain leaseholds that occurred in 2022.

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 and merger-related expenses, decreased $21 million primarily due to lower legal costs incurred in 2023 compared to 2022, and lower compensation and benefit costs due to the reduction in transition personnel throughout 2023.

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. Stock-based compensation

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expense decreased $27 million primarily due to higher stock-based compensation costs during 2022 related to the accelerated vesting of employee performance shares and vesting of certain other awards, and a gain related to our deferred compensation plan associated with the liquidation of the Coterra stock in the plan in 2023. These decreases were partially offset by higher stock-based compensation costs related to new shares granted during 2023.

Merger-related expenses decreased $57 million primarily due to lower employee-related severance and termination benefits associated with the termination of transition employees. We accrued for these costs over the transition period during 2022 and early 2023, with substantially all of our expected severance costs being fully accrued over that time period. Merger-related expenses also decreased due to $7 million of transaction-related costs associated with the merger that were incurred in 2022.

Gain (Loss) on Sale of Assets

The increase in gain (loss) on sale of assets is due to the sale of certain non-core oil and gas properties and other equipment.

Interest Expense

The table below reflects our interest expense, net for the periods indicated:

Interest expense decreased $28 million primarily due to the repayment of our 6.51% and 5.58% weighted-average private placement senior notes in August 2022 and the redemption of $750 million of the 4.375% senior notes in late 2022.

Debt premium amortization decreased $16 million primarily due to the redemption of $750 million of the 4.375% senior notes in late 2022.

Interest Income

Interest income increased $37 million primarily due to higher interest rates on higher cash balances.

Gain on Debt Extinguishment

In 2022, we paid down $874 million of our debt for $880 million and recognized a net gain on debt extinguishment of $28 million primarily due to the write off of related debt premiums and debt issuance costs.

Income Tax Expense

Income tax expense decreased $601 million primarily due to lower pre-tax income in 2023 compared to 2022, partially offset by a higher effective tax rate. The effective tax rate was higher for 2023 compared to 2022 due to differences in the non-recurring discrete items recorded during 2023 versus 2022.

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2022 and 2021 Compared

For information on the comparison of the results of operations for the year ended December 31, 2022 compared to the year ended December 31, 2021, 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, 2022, which information is incorporated by reference herein.

Critical Accounting 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 judgement of management.

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 2023, 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 reserves would result in a decrease of $0.31 per Boe and an increase of $0.35 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

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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 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 $12 million or decrease by $8 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 our counterparties or internal models. Such quotes and models 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 for reasonableness. The determination of fair value also incorporates a credit adjustment for non-performance risk. We measure the non-performance risk of our counterparties by reviewing credit default swap spreads for the various financial institutions with which we have derivative transactions, 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.

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.

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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 Accounting Pronouncements

Refer to Note 1 of the Notes to the Consolidated Financial Statements, “Summary of Significant Accounting Policies,” for a discussion of new accounting pronouncements that affect us.

ITEM 7.    MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis is based on management’s perspective and is 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 includes 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.

OVERVIEW

Cimarex Merger

On October 1, 2021, we and Cimarex completed the Merger. Cimarex is an oil and gas exploration and production company with operations in Texas, New Mexico and Oklahoma.

Financial and operational information set forth herein does not include the activity of Cimarex for periods prior to the closing of the Merger.

Financial and Operating Overview

Financial and operating results for the year ended December 31, 2022 compared to the year ended December 31, 2021 are as follows:

•Equivalent production increased 64.2 MMBoe from 167.1 MMBoe, or 660.0 MBoepd, in 2021 to 231.3 MMBoe, or 633.8 MBoepd, in 2022. The increase was attributable to production during the year ended 2022 from properties acquired in the Merger, which significantly expanded our operations, partially offset by lower production in the Marcellus Shale due to the timing of drilling and completion activities.

•Natural gas production increased 113.2 Bcf from 911.1 Bcf, or 2,492 MMcf per day, in 2021 to 1,024.3 Bcf, or 2,806 MMcf per day, in 2022. The increase was attributable to production from properties acquired in the Merger, partially offset by lower production in the Marcellus Shale due to the timing of drilling and completion activities.

•Oil production increased 24 MMBbl from 8 MMBbl in 2021 to 32 MMBbl in 2022. The increase was attributable to production from properties acquired in the Merger.

•NGL production increased 22 MMBbl from 7 MMBbl in 2021 to 29 MMBbl in 2022. The increase was attributable to production from properties acquired in the Merger.

•Average realized natural gas price for 2022 was $4.91 per Mcf, 80 percent higher than the $2.73 per Mcf price realized in 2021.

•Average realized oil price for 2022 was $84.33 per Bbl, 40 percent higher than the $60.35 per Bbl price realized in 2021.

•Average realized NGL price for 2022 was $33.58 per Bbl, two percent lower than the $34.18 per Bbl price realized in 2021.

•Total capital expenditures were $1.7 billion in 2022 compared to $725 million in 2021. The increase in capital expenditures was attributable to our expanded operations after the Merger.

•Drilled 285 gross wells (174.6 net) with a success rate of 99.6 percent in 2022 compared to 114 gross wells (99.9 net) with a success rate of 100 percent in 2021.

•Completed 251 gross wells (151.2 net) in 2022 compared to 132 gross wells (108.3 net) in 2021.

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•Average rig count during 2022 was approximately 6.2, 2.9 and 0.9 rigs in the Permian Basin, the Marcellus Shale and the Anadarko Basin, respectively. Average rig count during 2021 was 5.3, 2.5 and 0.9 rigs in the Permian Basin, the Marcellus Shale and the Anadarko Basin, respectively.

•Increased our base-plus-variable dividends from $1.12 per common share in 2021 to $2.49 per common share in 2022, as part of the Company’s returns-focused strategy.

•Fully executed our share repurchase program and repurchased 48 million shares of common stock for $1.25 billion during 2022. In February 2023, our Board of Directors approved a new share repurchase program which authorizes the purchase of up to $2.0 billion of our common stock.

•Redeemed $750 million principal amount of our and Cimarex’s 4.375% senior notes and repaid $37 million principal amount of our 6.51% weighted-average private placement senior notes and $87 million principal amount of our 5.58% weighted-average private placement senior notes during 2022 as part of our efforts to strengthen our balance sheet. Repaid $188 million of private placement senior notes which matured in 2021.

Market Conditions and Commodity Prices

Our financial results depend on many factors, particularly commodity prices and our ability to find, develop 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 are impacted by pipeline capacity constraints, inventory storage levels, basis differentials, weather conditions, geopolitical, economic and other factors.

NYMEX oil and natural gas futures prices have strengthened since the reduction of pandemic-related restrictions and increased OPEC+ cooperation. Improving oil and natural gas futures prices in part reflect market expectations of limited U.S. supply growth from publicly traded companies as a result of capital investment discipline and a focus on delivering free cash flow returns to stockholders. In addition, natural gas prices have benefited from strong worldwide liquefied natural gas (“LNG”) demand, which is, in part, a result of buyers shifting from Russian gas due to the Ukraine invasion, sustained higher U.S. exports, lower associated gas growth from oil drilling and improved U.S. economic activity. These pricing increases have been partially offset by reduced gas consumption due to warmer winter weather in the U.S. and Europe and concerns over potential economic recession, negatively impacting natural gas and NGL prices. Oil price futures have improved (although such future prices are still lower than current spot prices) coinciding with recovering global economic activity, lower supply from major oil producing countries, OPEC+ cooperation and moderating inventory levels.

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 and continue for an extended period of time, our operations could be adversely impacted, commodity prices could decline and our costs may continue to increase further. While oil and natural gas prices have fallen since their peak in 2022, further geopolitical disruptions in 2023, such as those experienced in 2022, may cause such prices to rapidly rise once again. Although 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 increase significantly from current levels, our management would evaluate the recoverability of the carrying value of our oil and gas properties.

In addition, the issue of, and increasing political and social attention on, climate change has resulted in both existing and pending national, regional and local legislation and regulatory measures, such as mandates for renewable energy and emissions reductions targeted at limiting or reducing emissions of greenhouse gases. Changes in these laws or regulations may result in delays or restrictions in permitting and the development of projects, may result in increased costs and may impair our ability to move forward with our construction, completions, drilling, water management, waste handling, storage, transport and remediation activities, any of which could have an adverse effect on our financial results.

For information about the impact of realized commodity prices on our revenues, refer to “Results of Operations” below.

Inflation

Certain of our capital expenditures and expenses are affected by general inflation, which rose throughout 2022. While rising inflation is typically offset by the higher prices at which we are able to realize on sales of our commodity production, we nevertheless expect to see inflation impact our cost structure into 2023, albeit at a more moderate pace compared to 2022.

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Climate

Climate-related regulations and climate-related business trends may impact our business, financial condition and results of our operations, and we may experience the following:

•decreased demand for goods or services that produce significant greenhouse gas emissions or are related to carbon-based energy sources;

•increased demand for goods that result in lower emissions than competing products;

•increased competition to develop innovative new products that result in lower emissions;

•increased demand for generation and transmission of energy from alternative energy sources; and

•reputational risks resulting from our operations or oil, natural gas and NGLs that we sell as it relates to the production of material greenhouse gas emissions.

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 maturity 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 facility. Our liquidity requirements are generally funded with cash flows provided by operating activities, together with cash on hand. However, from time to time, our investments may be funded by bank borrowings (including draws on our revolving credit facility), sales of non-strategic assets, and private or public financing based on our monitoring of capital markets and our balance sheet. Our debt is currently rated as investment grade by the three leading rating agencies, and 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. In determining our debt ratings, the agencies consider a number of qualitative and quantitative items including, but not limited to, current commodity prices, our liquidity position, our asset quality and reserve mix, debt levels, cost structure and growth plans. Credit ratings are not recommendations to buy, sell, or hold securities and may be subject to revision or withdrawal at any time by the assigning rating agency. A change in our debt rating could impact our interest rate on any borrowings under our revolving credit facility and our ability to economically access debt markets in the future and could trigger the requirement to post credit support under various agreements, which could reduce the borrowing capacity under our revolving credit facility. We believe that, with operating cash flow, cash on hand and availability under our revolving credit facility, we have the ability to finance our spending plans over the next twelve months and, based on current expectations, for the longer term.

We plan to continue our practice of entering into hedging arrangements to reduce the impact of commodity price volatility on our cash flow from operations.

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 facility, 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. At December 31, 2022 and 2021, we had a working capital surplus of $1.0 billion and $916 million, respectively. We believe we have adequate liquidity and availability as outlined above to meet our working capital requirements over the next 12 months.

We had $1.5 billion of capacity on our revolving credit facility at December 31, 2022, and unrestricted cash on hand of $673 million.

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Cash Flows

Our cash flows from operating activities, investing activities and financing activities are as follows:

Operating Activities. Net cash provided by operating activities in 2022 increased by $3.8 billion compared to 2021. This increase was primarily due to higher net income as a result of higher natural gas, oil and NGL revenue, partially offset by higher operating expenses, higher cash paid on derivative settlements and unfavorable changes in working capital and other assets and liabilities. The increase in natural gas, oil and NGL revenue was primarily due to increased production as a result of the Merger and an overall increase in commodity prices. Average oil and natural gas prices increased by $18.86 per Bbl and $2.27 per Mcf, respectively, and average NGL prices decreased $0.60 per Bbl in 2022 compared to 2021.

On October 1, 2021, we and Cimarex completed the Merger. Although we expect to achieve certain general and administrative expense synergies over the long-term through cost savings, in the near-term we will continue to incur certain severance costs related to the Merger, which in total are expected to range from $100 million to $110 million. These payments will primarily relate to workforce reductions and the associated employee severance benefits. As of December 31, 2022, we have incurred approximately $96 million of employee severance benefits.

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 $2.0 billion from 2021 to 2022. The increase was primarily due to $982 million of higher capital expenditures as a result of our expanded operations after the Merger and $1.0 billion of cash held by Cimarex that was subsequently reflected on our balance sheet after consummation of the Merger in 2021.

Financing Activities. Cash flows used in financing activities increased by $3.1 billion from 2021 to 2022. The increase was due to $1.3 billion of higher share repurchases during 2022, $1.2 billion of higher dividend payments in 2022 compared to 2021, and $686 million higher net repayments of debt. These increases were partially offset by $89 million lower tax withholding payments related to share-based awards that vested as a result of the Merger.

Revolving Credit Facility

We had $1.5 billion of capacity on our revolving credit facility at December 31, 2022. The revolving credit facility is scheduled to mature in April 2024, subject to extension up to one year if certain conditions are met. Our revolving credit facility bears interest at a margin above rates offered by certain designated banks in the London interbank market or at a margin above the overnight federal funds rate or prime rates by certain designated banks in the U.S. Additionally, our revolving credit facility includes certain customary covenants, including a covenant limiting our borrowing capacity based on our leverage ratio. Our revolving credit facility also requires us to maintain a leverage ratio of no more than 3.0 to 1.0 until such time as we have no other debt outstanding that has a financial maintenance covenant based on a leverage ratio, and thereafter requires us to maintain a ratio of total debt to total capitalization of no more than 65 percent. At December 31, 2022, we were in compliance with all financial covenants for our revolving credit facility, and had no borrowings outstanding under our revolving credit facility. 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 the revolving credit facility and our leverage ratio.

Certain Restrictive Covenants

Our ability to incur debt, incur liens, pay dividends, repurchase or redeem our equity interests, redeem our senior notes, make certain types of investments, 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 agreements governing various series of senior notes that were issued in separate private placements (the “private placement senior notes”) require us to maintain a minimum annual coverage ratio of consolidated cash flow to interest expense for the trailing four quarters of 2.8 to 1.0 and require a maximum ratio of total debt to consolidated EBITDA for the trailing four quarters of not more than 3.0 to 1.0. At December 31, 2022, we were in compliance with all financial covenants in our private

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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 restrictive covenants contained in our various debt instruments.

Capitalization

Information about our capitalization is as follows:

On September 29, 2021, our stockholders approved an amendment to our certificate of incorporation to increase the number of authorized shares of our common stock from 960,000,000 shares to 1,800,000,000 shares. That amendment became effective on October 1, 2021.

On October 1, 2021 and following the effectiveness of the Merger, we issued approximately 408.2 million shares of common stock to Cimarex stockholders under the terms of the Merger Agreement (excluding shares that were awarded in replacement of previously outstanding Cimarex restricted share awards).

Common stock repurchases. In February 2022, our Board of Directors terminated our previously authorized share repurchase program and approved a share repurchase program which allowed us to purchase up to $1.25 billion of our common stock in the open market or in negotiated transactions. As of December 31, 2022, this repurchase program was fully executed and in February 2023 our Board of Directors approved a new share repurchase program which authorizes the purchase of $2.0 billion of our common stock.

During 2022, we repurchased 48 million shares of our common stock for $1.25 billion under our authorized share repurchase program. We did not repurchase any shares of our common stock during 2021 under our previously authorized share repurchase program. During the years ended December 31, 2022 and 2021, 320,236 and 125,067 shares of common stock, respectively, were recorded as treasury stock related to common shares that were retained from vested restricted stock awards for withholding of taxes.

In December 2022, our Board of Directors authorized the retirement of our common stock held in treasury and as of December 31, 2022, there were no common shares held in Treasury Stock on the Consolidated Balance Sheet. Prospectively, share repurchases and shares withheld for the vesting of stock awards will be retired in the period in which they are repurchased or withheld.

Dividends. In February 2022, our Board of Directors approved an increase in our base quarterly dividend from $0.125 per share to $0.15 per share beginning in the first quarter of 2022. Our Board of Directors previously approved an increase in our base quarterly dividend rate in the fourth quarter of 2021 and second quarter of 2021 from $0.11 per share to $0.125 per share and from $0.10 per share to $0.11 per share, respectively.

The following table presents our dividends paid on our common stock for the full year 2022 and 2021.

________________________________________________________

(1)Includes a special dividend of $0.50 per share on our common stock that was paid following the completion of the Merger.

In February 2023, our Board of Directors approved an increase in our base quarterly dividend from $0.15 per share to $0.20 per share beginning in the first quarter of 2023, and approved a quarterly base dividend of $0.20 per share and a variable dividend of $0.37 per share, resulting in a total base-plus-variable dividend of $0.57 per share on our common stock.

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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 facility. We budget these expenditures based on our projected cash flows for the year.

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

_______________________________________________________________________________

(1)These amounts represent the fair value of the proved and unproved properties recorded in the purchase price allocation with respect to the Merger. The purchase was funded through the issuance of our common stock.

(2)There were no exploratory dry-hole costs in 2022 or 2021. Exploration expenditures include $4 million of exploratory dry-hole costs in 2020.

In 2022, we drilled 285 gross wells (174.6 net) and completed 251 gross wells (151.2 net), of which 58 gross wells (37.2 net) were drilled but uncompleted in prior years.

Our 2023 capital program is expected to be approximately $2.0 billion to $2.2 billion. We expect to turn-in-line 150 to 175 total net wells in 2023 across our three operating regions. Approximately 49 percent of our drilling and completion capital will be invested in the Permian Basin, 44 percent in the Marcellus Shale and the balance in the Anadarko Basin. The increase in our year-over-year capital expenditures is primarily driven by our expectations around the impact of inflation on our 2023 capital program and a modest increase in activity. 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, 2022, our material contractual obligations include debt and related interest expense, transportation and gathering 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.

From time to time, we enter into arrangements that can give rise to material off-balance sheet obligations. As of December 31, 2022, the material off-balance sheet arrangements we had entered into included certain firm transportation and processing 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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Critical Accounting 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 judgement of management.

Purchase Accounting

From time to time we may acquire assets and assume liabilities in transactions accounted for as business combinations, such as the Merger. In connection with the Merger in 2021, we allocated the $9.1 billion of purchase price consideration to the assets acquired and liabilities assumed based on estimated fair values as of the effective date of the Merger. The purchase price allocation is complete and there were no material adjustments to the amounts previously disclosed.

We made a number of assumptions in estimating the fair value of assets acquired and liabilities assumed in the Merger. The most significant assumptions related to the fair value estimates of proved and unproved oil and gas properties, which were recorded at fair value of $12.9 billion. Because 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, estimates of reserves quantities and production volumes, future commodity prices and price differentials, expected development costs, lease operating costs, reserves 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, reserves quantities and production volumes, development costs and lease operating costs. In the event that future commodity prices or reserves quantities or production volumes are significantly lower than those used in the determination of fair value as of the effective date of the Merger, 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 Merger relate to long-term debt, fixed assets and derivative instruments. The fair value of the assumed Cimarex publicly traded debt was based on available third-party quoted prices. We prepared estimates and engaged third-party valuation experts to assist in the valuation of certain fixed assets, which required significant judgments and assumptions inherent in the estimates and included projected cash flows and comparable companies’ cash flow multiples. The fair value of assumed derivative instrument liabilities included significant judgments and assumptions related to estimates of future commodity prices and related differentials and estimates of volatility factors and interest rates.

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 is 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.

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The reserves estimates of our oil and gas properties have been prepared by our petroleum engineering staff and certain of our reserves are subject to an evaluation performed by an independent third-party petroleum consulting firm. In 2022, 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 and proved developed reserves, which are utilized in our unit-of-production calculation. If the estimates of proved 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 reserves would result in a decrease of $0.31 per Boe and an increase of $0.34 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. No impairment resulted from our recent downward reserves revision in the Marcellus Shale. 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 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 undeveloped 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 exploration projects as well as development drilling. We have considered these impacts when determining the amortization of our undeveloped acreage. If the average unproved property life decreases or increases by one year, the amortization would increase by approximately $12 million or decrease by $8 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 our counterparties or internal models. Such quotes and models 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 for reasonableness. The determination of fair value also incorporates a credit adjustment for non-performance risk. We measure the non-performance

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risk of our counterparties by reviewing credit default swap spreads for the various financial institutions with which we have derivative transactions, while our non-performance risk is evaluated using a market credit spread provided by several of our banks.

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 Waha) and basis differentials.

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/or 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.

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RESULTS OF OPERATIONS

2022 and 2021 Compared

Operating Revenues

Production Revenues

Our production revenues are derived from sales of our oil, natural gas and NGL production. Our 2022 production revenues were substantially higher due to the Merger, which significantly expanded our operations and related production to include the Permian and Anadarko Basins. Increases or decreases in our revenues, profitability and future production growth are highly dependent on the commodity prices we receive, which we expect to fluctuate due to supply and demand factors, and the availability of transportation, seasonality and geopolitical, economic and other factors.

Natural Gas Revenues

Natural gas revenues increased $2.7 billion primarily due to significantly higher natural gas prices combined with higher production. The increase in production was primarily related to properties acquired in the Merger, which significantly expanded our operations, partially offset by lower production related to the timing of our drilling and completion activities in the Marcellus Shale.

Oil Revenues

Oil revenues increased $2.4 billion primarily due to our expanded operations and related production after the Merger and higher oil prices.

NGL Revenues

NGL revenues increased $721 million primarily due to our expanded operations and related production after the Merger, partially offset by slightly lower NGL prices.

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Loss on Derivative Instruments

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 “Loss on derivative instruments” 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 the volume and commodity mix of production, 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 operating costs and expenses in 2022 were substantially higher due to the Merger, which significantly expanded our operations to include the Permian and Anadarko Basins. In addition, our costs for services, labor and supplies have recently increased due to increased demand for those items, inflation and supply chain disruptions.

The following table reflects our operating costs and expenses for the years indicated and a discussion of the operating costs and expenses follows.

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Direct Operations

Direct operations generally consists of costs for labor, equipment, maintenance, saltwater disposal, compression, power, treating and miscellaneous other costs (collectively, “lease operating expense”). Direct operations also includes well workover activity necessary to maintain production from existing wells. Direct operations consisted of lease operating expense and workover expense as follows:

Lease operating and workover expense increased due to our expanded operations due to the Merger.

Transportation, Processing and Gathering

Transportation, processing and gathering costs principally consist of expenditures to prepare and transport production downstream from the wellhead, including gathering, fuel, and compression and 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.

Transportation, processing and gathering increased $292 million due to our expanded operations due to the Merger.

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 $283 million. Production taxes represented the majority of our taxes other than income, which increased primarily due to higher production related to properties acquired in the Merger and higher commodity prices. Drilling impact fees increased primarily due to higher natural gas prices. Ad valorem taxes increased primarily due to our expanded operations after the Merger and higher property valuations.

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Depreciation, Depletion and Amortization

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