# Coterra Energy Inc. (CTRA) FY 2023 MD&A

Verbatim Item 7 Management's Discussion and Analysis from Coterra Energy Inc.'s 10-K for fiscal year 2023.

SEC filing source: https://www.sec.gov/Archives/edgar/data/858470/000085847024000019/cog-20231231.htm
Accession: 0000858470-24-000019
Filing date: 2024-02-23
Report date: 2023-12-31
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/fy2022/ (FY 2022)
Next year: /company/CTRA/mda/fy2024/ (FY 2024)

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, 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

37

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.

38

Table of Contents

Cash Flows

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

[[GREPCENT_TABLE]]
[["","Year Ended December 31,"],["(In millions)","2023","","2022","","2021"],["Cash flows provided by operating activities","$","3,658","","","$","5,456","","","$","1,667"],["Cash flows (used in) provided by investing activities","(2,059)","","","(1,674)","","","313"],["Cash flows used in financing activities","(1,317)","","","(4,145)","","","(1,086)"]]
[[/GREPCENT_TABLE]]

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

39

Table of Contents

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:

[[GREPCENT_TABLE]]
[["","December 31,"],["(Dollars in millions)","2023","","2022"],["Total debt","$","2,161","","$","2,181"],["Stockholders' equity","13,039","","12,659"],["Total capitalization","$","15,200","","$","14,840"],["Debt to total capitalization","14%","","15%"],["Cash and cash equivalents","$","956","","$","673"]]
[[/GREPCENT_TABLE]]

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.

[[GREPCENT_TABLE]]
[["","","Rate per share"],["","","Base","","Variable","","Total","","Total Dividends Paid (In millions)"],["2023","","$","0.80","","","$","0.37","","","$","1.17","","","$","895"],["2022","","$","0.60","","","$","1.89","","","$","2.49","","","$","1,991"]]
[[/GREPCENT_TABLE]]

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.

40

Table of Contents

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

[[GREPCENT_TABLE]]
[["","Year Ended December 31,"],["(In millions)","2023","","2022","","2021"],["Acquisitions(1) :"],["Proved","$","\u2014","","","$","\u2014","","","$","7,472"],["Unproved","\u2014","","","\u2014","","","5,381"],["Total","$","\u2014","","","$","\u2014","","","$","12,853"],["Capital expenditures"],["Drilling and completion","$","1,979","","","$","1,617","","","$","688"],["Pipeline and gathering","91","","","56","","","9"],["Other","34","","","54","","","23"],["Capital expenditures for drilling, completion and other fixed asset additions","2,104","","","1,727","","","720"],["Capital expenditures for leasehold and property acquisitions","10","","","10","","","5"],["Exploration expenditures(2)","20","","","29","","","18"],["Total","$","2,134","","","$","1,766","","","$","743"]]
[[/GREPCENT_TABLE]]

_______________________________________________________________________________

(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.

41

Table of Contents

RESULTS OF OPERATIONS

2023 and 2022 Compared

Operating Revenues

[[GREPCENT_TABLE]]
[["","Year Ended December 31,","","Variance"],["(In millions)","2023","","2022","","Amount","","Percent"],["Natural gas","$","2,292","","","$","5,469","","","$","(3,177)","","","(58)","%"],["Oil","2,667","","","3,016","","","(349)","","","(12)","%"],["NGL","644","","","964","","","(320)","","","(33)","%"],["Gain (loss) on derivative instruments","230","","","(463)","","","693","","","(150)","%"],["Other","81","","","65","","","16","","","25","%"],["","$","5,914","","","$","9,051","","","$","(3,137)","","","(35)","%"]]
[[/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 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

[[GREPCENT_TABLE]]
[["","Year Ended December 31,","","Variance","Increase (Decrease) (In millions)"],["","2023","","2022","","Amount","","Percent"],["Volume variance (Bcf)","1,052.7","","","1,024.3","","","28.4","","","3","%","","$","152"],["Price variance ($/Mcf)","$","2.18","","","$","5.34","","","$","(3.16)","","","(59)","%","","(3,329)"],["Total","","","","","","","","","$","(3,177)"]]
[[/GREPCENT_TABLE]]

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

[[GREPCENT_TABLE]]
[["","Year Ended December 31,","","Variance","Increase (Decrease) (In millions)"],["","2023","","2022","","Amount","","Percent"],["Volume variance (MMBbl)","35.1","","31.9","","3.2","","10%","","$","302"],["Price variance ($/Bbl)","$","75.97","","","$","94.47","","","$","(18.50)","","","(20)%","","(651)"],["Total","","","","","","","","","$","(349)"]]
[[/GREPCENT_TABLE]]

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

NGL Revenues

[[GREPCENT_TABLE]]
[["","Year Ended December 31,","","Variance","Increase (Decrease) (In millions)"],["","2023","","2022","","Amount","","Percent"],["Volume variance (MMBbl)","32.9","","28.7","","4.2","","","15","%","","$","141"],["Price variance ($/Bbl)","$","19.56","","","$","33.58","","","$","(14.02)","","","(42)","%","","(461)"],["Total","","","","","","","","","$","(320)"]]
[[/GREPCENT_TABLE]]

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

42

Table of Contents

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)","2023","","2022"],["Cash received (paid) on settlement of derivative instruments"],["Gas contracts","$","280","","","$","(438)"],["Oil contracts","4","","","(324)"],["Non-cash gain (loss) on derivative instruments"],["Gas contracts","(72)","","","149"],["Oil contracts","18","","","150"],["","$","230","","","$","(463)"]]
[[/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, 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.

[[GREPCENT_TABLE]]
[["","Year Ended December 31,","","Variance","","Per Boe"],["(In millions, except per Boe)","2023","","2022","","Amount","","Percent","","2023","","2022"],["Operating Expenses"],["Direct operations","$","562","","","$","460","","","$","102","","","22","%","","$","2.31","","","$","1.99"],["Gathering, processing and transportation","975","","","955","","","20","","","2","%","","4.00","","","4.13"],["Taxes other than income","283","","","366","","","(83)","","","(23)","%","","1.16","","","1.58"],["Exploration","20","","","29","","","(9)","","","(31)","%","","0.08","","","0.13"],["Depreciation, depletion and amortization","1,641","","","1,635","","","6","","","\u2014","%","","6.74","","","7.07"],["General and administrative","291","","","396","","","(105)","","","(27)","%","","1.20","","","1.70"],["","$","3,772","","","$","3,841","","","$","(69)","","","(2)","%"]]
[[/GREPCENT_TABLE]]

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.

43

Table of Contents

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)","2023","","2022","","Variance","","2023","","2022"],["Direct Operations"],["Lease operating expense","$","472","","","$","370","","","$","102","","","$","1.94","","","$","1.60"],["Workover expense","90","","","90","","","\u2014","","","0.37","","","0.39"],["","$","562","","","$","460","","","$","102","","","$","2.31","","","$","1.99"]]
[[/GREPCENT_TABLE]]

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:

[[GREPCENT_TABLE]]
[["","Year Ended December 31,"],["(In millions)","2023","","2022","","Variance"],["Taxes Other than Income"],["Production","$","205","","$","282","","","$","(77)"],["Drilling impact fees","23","","","31","","","(8)"],["Ad valorem","53","","","53","","","\u2014"],["Other","2","","","\u2014","","","2"],["","$","283","","","$","366","","","$","(83)"],["Production taxes as a percentage of revenue (Permian and Anadarko Basins)","5.6","%","","5.5","%"]]
[[/GREPCENT_TABLE]]

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.

44

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)","2023","","2022","","Variance","","2023","","2022"],["DD&A Expense"],["Depletion","$","1,509","","","$","1,474","","","$","35","","","$","6.20","","","$","6.37"],["Depreciation","74","","91","","(17)","","","0.30","","0.40"],["Amortization of unproved properties","48","","61","","(13)","","","0.20","","0.26"],["Accretion of ARO","10","","9","","","1","","","0.04","","0.04"],["","$","1,641","","","$","1,635","","","$","6","","","$","6.74","","","$","7.07"]]
[[/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 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:

[[GREPCENT_TABLE]]
[["","Year Ended December 31,"],["(In millions)","2023","","2022","","Variance"],["G&A Expense"],["General and administrative expense","$","220","","","$","241","","","$","(21)"],["Stock-based compensation expense","59","","","86","","","(27)"],["Merger-related expense","12","","","69","","","(57)"],["","$","291","","","$","396","","","$","(105)"]]
[[/GREPCENT_TABLE]]

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

45

Table of Contents

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:

[[GREPCENT_TABLE]]
[["","Year Ended December 31,"],["(In millions)","2023","","2022","","Variance"],["Interest Expense"],["Interest expense","$","82","","","$","110","","","$","(28)"],["Debt premium amortization","(21)","","","(37)","","","16"],["Debt issuance cost amortization","3","","","4","","","(1)"],["Other","9","","","3","","","6"],["","$","73","","","$","80","","","$","(7)"]]
[[/GREPCENT_TABLE]]

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

[[GREPCENT_TABLE]]
[["","Year Ended December 31,"],["(In millions)","2023","","2022","","Variance"],["Income Tax Expense"],["Current tax expense","$","429","","","$","869","","","$","(440)"],["Deferred tax expense","74","","","235","","","(161)"],["","$","503","","","$","1,104","","","$","(601)"],["Combined federal and state effective income tax rate","24","%","","21","%"]]
[[/GREPCENT_TABLE]]

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.

46

Table of Contents

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

47

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 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.

48

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 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.