# Coterra Energy Inc. (CTRA) FY 2024 MD&A Verbatim Item 7 Management's Discussion and Analysis from Coterra Energy Inc.'s 10-K for fiscal year 2024. SEC filing source: https://www.sec.gov/Archives/edgar/data/858470/000085847025000075/cog-20241231.htm Accession: 0000858470-25-000075 Filing date: 2025-02-25 Report date: 2024-12-31 Extracted structurally from real Item 7 body heading to real Item 7A/8 boundary. Published MD&A gate trimmed front/tail over-capture. Confidence: high Company profile: /company/CTRA/ All MD&A years: /company/CTRA/mda/ Previous year: /company/CTRA/mda/fy2023/ (FY 2023) Next year: /company/CTRA/mda/fy2025/ (FY 2025) 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. 36 Table of Contents 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, 37 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 38 Table of Contents 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 $1.0 billion undrawn term loan. Subsequently, the term loan was fully drawn in January 2025, as discussed herein. Our revolving credit agreement and term loan include a covenant potentially limiting our borrowing capacity as determined by our leverage ratio. As of December 31, 2024, we were in compliance with all financial covenants applicable to our revolving credit agreement, term loan and private placement senior notes. Refer to Note 4 of the Notes to the Consolidated Financial Statements, “Long-Term Debt and Credit Agreements,” for further details (including our restrictive covenants and required financial ratio). Cash Flows Our cash flows from operating activities, investing activities and financing activities are as follows: [[GREPCENT_TABLE]] [["","Year Ended December 31,"],["(In millions)","2024","","2023","","2022"],["Cash flows provided by operating activities","$","2,795","","","$","3,658","","","$","5,456"],["Cash flows used in investing activities","(1,762)","","","(2,059)","","","(1,674)"],["Cash flows provided by (used in) financing activities","279","","","(1,317)","","","(4,145)"]] [[/GREPCENT_TABLE]] 39 Table of Contents 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. 40 Table of Contents 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 $75 million outstanding that has a financial maintenance covenant based on a leverage ratio, at which time the Term Loan requires maintenance of a ratio of total net debt to capitalization of no more than 65 percent (with all calculations based on definitions contained in the Term Loan). Certain Restrictive Covenants Our ability to incur debt, incur liens, enter into mergers, sell assets, enter into transactions with affiliates, and engage in certain other activities are subject to certain restrictive covenants in our various debt instruments. In addition, the senior note agreement governing various series of senior notes that were issued in a private placement (the “private placement senior notes”) requires us to maintain a minimum annual coverage ratio of consolidated cash flow to interest expense for the trailing four quarters of not less than 2.8 to 1.0 and requires us to maintain, as of the last day of any fiscal quarter, a maximum ratio of total debt to consolidated EBITDAX for the trailing four quarters of not more than 3.0 to 1.0. At December 31, 2024, we were in compliance with all financial covenants in our private placement senior notes. Refer to Note 4 of the Notes to the Consolidated Financial Statements, “Long-Term Debt and Credit Agreements,” for further details regarding the interest rate on future borrowings under our Credit Agreement and Term Loan, as well as information regarding our restrictive covenants, including our leverage ratio. Capitalization Information about our capitalization is as follows: [[GREPCENT_TABLE]] [["","December 31,"],["(Dollars in millions)","2024","","2023"],["Total debt (1)","$","3,535","","$","2,161"],["Stockholders' equity","13,122","","13,039"],["Total capitalization","$","16,657","","$","15,200"],["Debt to total capitalization","21%","","14%"],["Cash and cash equivalents","$","2,038","","$","956"]] [[/GREPCENT_TABLE]] _______________________________________________________________________________ (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. 41 Table of Contents 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 $0.22 per share beginning in the first quarter of 2025. The following table presents our dividends paid on our common stock for the year ended December 31, 2024 and 2023. [[GREPCENT_TABLE]] [["","","Rate per share"],["","","Base","","Variable","","Total","","Total Dividends Paid (In millions)"],["2024","","$","0.84","","","$","\u2014","","","$","0.84","","","$","630"],["2023","","$","0.80","","","$","0.37","","","$","1.17","","","$","895"]] [[/GREPCENT_TABLE]] Capital and Exploration Expenditures On an annual basis, we generally fund most of our capital expenditures, excluding any significant property acquisitions, with cash generated from operations and, if required, borrowings under our revolving credit agreement. We budget these expenditures based on our projected cash flows for the year. The following table presents major components of our capital and exploration expenditures: [[GREPCENT_TABLE]] [["","Year Ended December 31,"],["(In millions)","2024","","2023","","2022"],["Capital expenditures"],["Drilling and completion","$","1,645","","","$","1,979","","","$","1,617"],["Pipeline and gathering","103","","","91","","","56"],["Other","14","","","34","","","54"],["Capital expenditures for drilling, completion and other fixed asset additions","1,762","","","2,104","","","1,727"],["Capital expenditures for leasehold and property acquisitions","19","","","10","","","10"],["Exploration expenditures(1)","25","","","20","","","29"],["Total","$","1,806","","","$","2,134","","","$","1,766"]] [[/GREPCENT_TABLE]] _______________________________________________________________________________ (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. 42 Table of Contents 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 [[GREPCENT_TABLE]] [["","Year Ended December 31,","","Variance"],["(In millions)","2024","","2023","","Amount","","Percent"],["Oil","$","2,953","","","$","2,667","","","$","286","","","11","%"],["Natural gas","1,693","","","2,292","","","(599)","","","(26)","%"],["NGL","738","","","644","","","94","","","15","%"],["Gain (loss) on derivative instruments","(3)","","","230","","","(233)","","","(101)","%"],["Other","77","","","81","","","(4)","","","(5)","%"],["","$","5,458","","","$","5,914","","","$","(456)","","","(8)","%"]] [[/GREPCENT_TABLE]] Production Revenues Our production revenues are derived from sales of our oil, natural gas and NGL production. Increases or decreases in our revenues, profitability and future production growth are highly dependent on the commodity prices we receive, which, as discussed above, fluctuate due to a variety of factors (including supply and demand, the availability of transportation, seasonality and geopolitical, economic and other factors). Oil Revenues [[GREPCENT_TABLE]] [["","Year Ended December 31,","","Variance","Increase (Decrease) (In millions)"],["","2024","","2023","","Amount","","Percent"],["Volume (MMBbl)","39.8","","35.1","","4.7","","13%","","$","357"],["Price ($/Bbl)","$","74.18","","","$","75.97","","","$","(1.79)","","","(2)%","","(71)"],["Total","","","","","","","","","$","286"]] [[/GREPCENT_TABLE]] Oil revenues increased $286 million primarily due to higher production in the Permian Basin partially offset by lower oil prices. Natural Gas Revenues [[GREPCENT_TABLE]] [["","Year Ended December 31,","","Variance","Increase (Decrease) (In millions)"],["","2024","","2023","","Amount","","Percent"],["Volume (Bcf)","1,024.7","","","1,052.7","","","(28.0)","","","(3)","%","","$","(61)"],["Price ($/Mcf)","$","1.65","","","$","2.18","","","$","(0.53)","","","(24)","%","","(538)"],["Total","","","","","","","","","$","(599)"]] [[/GREPCENT_TABLE]] Natural gas revenues decreased $599 million primarily due to significantly lower natural gas prices and lower production. The decrease in production was primarily due to lower production in the Marcellus Shale, where we strategically curtailed production from August 2024 through November 2024 due to weaker natural gas prices. This decrease was partially offset by higher production in the Permian and Anadarko Basins. 43 Table of Contents NGL Revenues [[GREPCENT_TABLE]] [["","Year Ended December 31,","","Variance","Increase (Decrease) (In millions)"],["","2024","","2023","","Amount","","Percent"],["Volume (MMBbl)","37.0","","32.9","","4.1","","","12","%","","$","80"],["Price ($/Bbl)","$","19.95","","","$","19.56","","","$","0.39","","","2","%","","14"],["Total","","","","","","","","","$","94"]] [[/GREPCENT_TABLE]] NGL revenues increased $94 million primarily due to higher NGL volumes in the Permian Basin and Anadarko Basin and slightly higher NGL prices. Gain (Loss) on Derivative Instruments Net gains and losses on our derivative instruments are a function of fluctuations in the underlying commodity index prices as compared to the contracted prices and the monthly cash settlements (if any) of the derivative instruments. We have elected not to designate our derivatives as hedging instruments for accounting purposes and, therefore, we do not apply hedge accounting treatment to our derivative instruments. Consequently, changes in the fair value of our derivative instruments and cash settlements are included as a component of operating revenues as either a net gain or loss on derivative instruments. Cash settlements of our contracts are included in cash flows from operating activities in our statement of cash flows. The following table presents the components of “Gain (loss) on derivative instruments” for the years indicated: [[GREPCENT_TABLE]] [["","Year Ended December 31,"],["(In millions)","2024","","2023"],["Cash received on settlement of derivative instruments"],["Gas contracts","$","96","","","$","280"],["Oil contracts","2","","","4"],["Non-cash gain (loss) on derivative instruments"],["Gas contracts","(80)","","","(72)"],["Oil contracts","(21)","","","18"],["","$","(3)","","","$","230"]] [[/GREPCENT_TABLE]] Operating Costs and Expenses Costs associated with producing oil and natural gas are substantial. Among other factors, some of these costs vary with commodity prices, some trend with volume and commodity mix, some are a function of the number of wells we own and operate, some depend on the prices charged by service companies, and some fluctuate based on a combination of the foregoing. Our costs for services began to stabilize at the end of 2023 despite on-going demand and the latent effects of inflation and supply chain disruptions and continued to remain stable throughout 2024. The following table reflects our operating costs and expenses for the years indicated and a discussion of the operating costs and expenses follows. [[GREPCENT_TABLE]] [["","Year Ended December 31,","","Variance","","Per Boe"],["(In millions, except per Boe)","2024","","2023","","Amount","","Percent","","2024","","2023"],["Operating Expenses"],["Direct operations","$","658","","","$","562","","","$","96","","","17","%","","$","2.66","","","$","2.31"],["Gathering, processing and transportation","976","","","975","","","1","","","\u2014","%","","3.94","","","4.00"],["Taxes other than income","271","","","283","","","(12)","","","(4)","%","","1.09","","","1.16"],["Exploration","25","","","20","","","5","","","25","%","","0.10","","","0.08"],["Depreciation, depletion and amortization","1,840","","","1,641","","","199","","","12","%","","7.43","","","6.74"],["General and administrative","302","","","291","","","11","","","4","%","","1.22","","","1.20"],["","$","4,072","","","$","3,772","","","$","300","","","8","%"]] [[/GREPCENT_TABLE]] 44 Table of Contents Direct Operations Direct operations generally consist of costs for labor, equipment, maintenance, saltwater disposal, compression, power, treating and miscellaneous other costs (collectively, “lease operating expense”). Direct operations also include workover activity necessary to maintain production from existing wells. Direct operations consisted of lease operating expense and workover expense as follows: [[GREPCENT_TABLE]] [["","Year Ended December 31,","","","","Per Boe"],["(In millions, except per Boe)","2024","","2023","","Variance","","2024","","2023"],["Direct Operations"],["Lease operating expense","$","554","","","$","472","","","$","82","","","$","2.24","","","$","1.94"],["Workover expense","104","","","90","","","14","","","0.42","","","0.37"],["","$","658","","","$","562","","","$","96","","","$","2.66","","","$","2.31"]] [[/GREPCENT_TABLE]] 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 $1 million primarily due to higher gathering and transportation costs in the Permian Basin related to higher production and higher transportation rates, partially offset by lower gathering charges in the Marcellus Shale related to lower production. Taxes Other Than Income Taxes other than income consist of production (or severance) taxes, drilling impact fees, ad valorem taxes and other taxes. State and local taxing authorities assess these taxes, with production taxes being based on the volume or value of production, drilling impact fees being based on drilling activities and prevailing natural gas prices and ad valorem taxes being based on the value of properties. The following table presents taxes other than income for the years indicated: [[GREPCENT_TABLE]] [["","Year Ended December 31,"],["(In millions)","2024","","2023","","Variance"],["Taxes Other than Income"],["Production","$","217","","$","205","","","$","12"],["Drilling impact fees","17","","","23","","","(6)"],["Ad valorem","35","","","53","","","(18)"],["Other","2","","","2","","","\u2014"],["","$","271","","","$","283","","","$","(12)"],["Production taxes as a percentage of revenue (Permian and Anadarko Basins)","5.6","%","","5.6","%"]] [[/GREPCENT_TABLE]] Taxes other than income decreased $12 million primarily due to lower ad valorem taxes, which was primarily driven by a combination of lower-than-expected property valuations in 2024 resulting in a lower tax obligation and a reduction of prior period accruals in 2024 due to a change in estimated taxes due for the full-year 2023. Additionally, drilling impact fees decreased primarily due to a decrease in drilling activity in the Marcellus Shale and a decrease in assessed rates as a result of lower natural gas prices. These decreases were partially offset by an increase in our production taxes, which increased primarily due to higher oil and NGL production compared to 2023. 45 Table of Contents Depreciation, Depletion and Amortization DD&A expense consisted of the following for the periods indicated: [[GREPCENT_TABLE]] [["","Year Ended December 31,","","","","Per Boe"],["(In millions, except per Boe)","2024","","2023","","Variance","","2024","","2023"],["DD&A Expense"],["Depletion","$","1,707","","","$","1,509","","","$","198","","","$","6.89","","","$","6.20"],["Depreciation","73","","","74","","","(1)","","","0.30","","0.30"],["Amortization of unproved properties","49","","","48","","","1","","","0.20","","0.20"],["Accretion of ARO","11","","","10","","","1","","","0.04","","0.04"],["","$","1,840","","","$","1,641","","","$","199","","","$","7.43","","","$","6.74"]] [[/GREPCENT_TABLE]] 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 $198 million primarily due to a higher depletion rate and an increase in production. Our depletion rate increased due to lower oil and gas reserve volumes and a shift in our production mix to fields with higher depletion rates. The lower oil and gas reserve volumes were driven by negative price revisions as a result of lower prices in 2023. Fixed assets consist primarily of gas gathering facilities, water infrastructure, buildings, vehicles, aircraft, furniture and fixtures and computer equipment and software. These items are recorded at cost and are depreciated on the straight-line method based on expected lives of the individual assets, which range from three to 30 years. Also included in our depreciation expense is the depreciation of the right-of-use asset associated with our finance lease gathering system. Depreciation expense remained steady in 2024 compared to 2023. Unproved properties are amortized based on our drilling experience and our expectation of converting our unproved leaseholds to proved properties. The rate of amortization depends on the timing and success of our exploration and development program. If development of unproved properties is deemed unsuccessful and the properties are abandoned or surrendered, the capitalized costs are expensed in the period the determination is made. Amortization of unproved properties remained steady in 2024 compared to 2023. General and Administrative G&A expense consists primarily of salaries and related benefits, stock-based compensation, office rent, legal and consulting fees, systems costs and other administrative costs incurred. The table below reflects our G&A expense for the periods identified: [[GREPCENT_TABLE]] [["","Year Ended December 31,"],["(In millions)","2024","","2023","","Variance"],["G&A Expense"],["General and administrative expense","$","240","","","$","220","","","$","20"],["Stock-based compensation expense","62","","","59","","","3"],["Merger-related expense","\u2014","","","12","","","(12)"],["","$","302","","","$","291","","","$","11"]] [[/GREPCENT_TABLE]] 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. 46 Table of Contents Stock-based compensation expense will fluctuate based on the grant date fair value of awards, the number of awards, the requisite service period of the awards, estimated employee forfeitures, and the timing of the awards. 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 $12 million as the accrual for employee-related severance and termination benefits associated with the Cimarex merger transition employees was completed in 2023. Gain (Loss) on Sale of Assets The decrease in gain (loss) on sale of assets is due to the sale of certain non-core oil and gas properties and other equipment in 2023. Interest Expense The table below reflects our interest expense, net for the periods indicated: [[GREPCENT_TABLE]] [["","Year Ended December 31,"],["(In millions)","2024","","2023","","Variance"],["Interest Expense"],["Interest expense","$","101","","","$","82","","","$","19"],["Debt premium and discount amortization, net","(21)","","","(21)","","","\u2014"],["Debt issuance cost amortization","9","","","3","","","6"],["Other","17","","","9","","","8"],["","$","106","","","$","73","","","$","33"]] [[/GREPCENT_TABLE]] 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 $15 million primarily due to higher interest earned on our higher cash and short-term investment balances during 2024 compared to 2023. Income Tax Expense [[GREPCENT_TABLE]] [["","Year Ended December 31,"],["(In millions)","2024","","2023","","Variance"],["Income Tax Expense"],["Current tax expense","$","369","","","$","429","","","$","(60)"],["Deferred tax (benefit) expense","(145)","","","74","","","(219)"],["","$","224","","","$","503","","","$","(279)"],["Combined federal and state effective income tax rate","16.7","%","","23.6","%"]] [[/GREPCENT_TABLE]] 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. 47 Table of Contents 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 48 Table of Contents 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. 49 Table of Contents 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.