# Coterra Energy Inc. (CTRA) FY 2022 MD&A

Verbatim Item 7 Management's Discussion and Analysis from Coterra Energy Inc.'s 10-K for fiscal year 2022.

SEC filing source: https://www.sec.gov/Archives/edgar/data/858470/000085847023000011/cog-20221231.htm
Accession: 0000858470-23-000011
Filing date: 2023-02-27
Report date: 2022-12-31
Extracted structurally from real Item 7 body heading to real Item 7A/8 boundary.
Confidence: high

Company profile: /company/CTRA/
All MD&A years: /company/CTRA/mda/
Previous year: /company/CTRA/mda/fy2021/ (FY 2021)
Next year: /company/CTRA/mda/fy2023/ (FY 2023)

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

The following discussion and analysis is based on management’s perspective and is intended to assist you in understanding our results of operations and our present financial condition and outlook. Our Consolidated Financial Statements and the accompanying Notes to the Consolidated Financial Statements included elsewhere in this Annual Report on Form 10-K contain additional information that should be referenced when reviewing this material. This discussion and analysis also includes forward-looking statements. Readers are cautioned that such forward-looking statements are based on current expectations and assumptions that involve a number of risks and uncertainties, including those described under “Forward-Looking Statements” in Part I of this report and “Risk Factors” in Part I, Item 1A of this report, which could cause actual results to differ materially from those included in this report.

OVERVIEW

Cimarex Merger

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

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

Financial and Operating Overview

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

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

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

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

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

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

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

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

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

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

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

39

Table of Contents

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

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

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

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

Market Conditions and Commodity Prices

Our financial results depend on many factors, particularly commodity prices and our ability to find, develop and market our production on economically attractive terms. Commodity prices are affected by many factors outside of our control, including changes in market supply and demand, which are impacted by pipeline capacity constraints, inventory storage levels, basis differentials, weather conditions, geopolitical, economic and other factors.

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

Although the current outlook on oil and natural gas prices is generally favorable and our operations have not been significantly impacted in the short-term, in the event further disruptions occur and continue for an extended period of time, our operations could be adversely impacted, commodity prices could decline and our costs may continue to increase further. While oil and natural gas prices have fallen since their peak in 2022, further geopolitical disruptions in 2023, such as those experienced in 2022, may cause such prices to rapidly rise once again. Although we are unable to predict future commodity prices, at current oil, natural gas and NGL price levels, we do not believe that an impairment of our oil and gas properties is reasonably likely to occur in the near future; however, in the event that commodity prices significantly decline or costs increase significantly from current levels, our management would evaluate the recoverability of the carrying value of our oil and gas properties.

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

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

Inflation

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

40

Climate

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

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

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

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

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

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

FINANCIAL CONDITION

Liquidity and Capital Resources

We strive to maintain an adequate liquidity level to address commodity price volatility and risk. Our liquidity requirements consist primarily of our planned capital expenditures, payment of contractual obligations (including debt maturity and interest payments), working capital requirements, dividend payments and share repurchases. Although we have no obligation to do so, we may also from time-to-time refinance or retire our outstanding debt through privately negotiated transactions, open market repurchases, redemptions, exchanges, tender offers or otherwise.

Our primary sources of liquidity are cash on hand, net cash provided by operating activities and available borrowing capacity under our revolving credit facility. Our liquidity requirements are generally funded with cash flows provided by operating activities, together with cash on hand. However, from time to time, our investments may be funded by bank borrowings (including draws on our revolving credit facility), sales of non-strategic assets, and private or public financing based on our monitoring of capital markets and our balance sheet. Our debt is currently rated as investment grade by the three leading rating agencies, and there are no “rating triggers” in any of our debt agreements that would accelerate the scheduled maturities should our debt rating fall below a certain level. In determining our debt ratings, the agencies consider a number of qualitative and quantitative items including, but not limited to, current commodity prices, our liquidity position, our asset quality and reserve mix, debt levels, cost structure and growth plans. Credit ratings are not recommendations to buy, sell, or hold securities and may be subject to revision or withdrawal at any time by the assigning rating agency. A change in our debt rating could impact our interest rate on any borrowings under our revolving credit facility and our ability to economically access debt markets in the future and could trigger the requirement to post credit support under various agreements, which could reduce the borrowing capacity under our revolving credit facility. We believe that, with operating cash flow, cash on hand and availability under our revolving credit facility, we have the ability to finance our spending plans over the next twelve months and, based on current expectations, for the longer term.

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

Our working capital is substantially influenced by the variables discussed above and fluctuates based on the timing and amount of borrowings and repayments under our revolving credit facility, repayments of debt, the timing of cash collections and payments on our trade accounts receivable and payable, respectively, payment of dividends, repurchases of our securities and changes in the fair value of our commodity derivative activity. From time to time, our working capital will reflect a deficit, while at other times it will reflect a surplus. This fluctuation is not unusual. At December 31, 2022 and 2021, we had a working capital surplus of $1.0 billion and $916 million, respectively. We believe we have adequate liquidity and availability as outlined above to meet our working capital requirements over the next 12 months.

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

41

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)","2022","","2021","","2020"],["Cash flows provided by operating activities","$","5,456","","","$","1,667","","","$","778"],["Cash flows (used in) provided by investing activities","(1,674)","","","313","","","(584)"],["Cash flows used in financing activities","(4,145)","","","(1,086)","","","(256)"]]
[[/GREPCENT_TABLE]]

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

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

Refer to “Results of Operations” for additional information relative to commodity price, production and operating expense fluctuations. We are unable to predict future commodity prices and, as a result, cannot provide any assurance about future levels of net cash provided by operating activities.

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

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

Revolving Credit Facility

We had $1.5 billion of capacity on our revolving credit facility at December 31, 2022. The revolving credit facility is scheduled to mature in April 2024, subject to extension up to one year if certain conditions are met. Our revolving credit facility bears interest at a margin above rates offered by certain designated banks in the London interbank market or at a margin above the overnight federal funds rate or prime rates by certain designated banks in the U.S. Additionally, our revolving credit facility includes certain customary covenants, including a covenant limiting our borrowing capacity based on our leverage ratio. Our revolving credit facility also requires us to maintain a leverage ratio of no more than 3.0 to 1.0 until such time as we have no other debt outstanding that has a financial maintenance covenant based on a leverage ratio, and thereafter requires us to maintain a ratio of total debt to total capitalization of no more than 65 percent. At December 31, 2022, we were in compliance with all financial covenants for our revolving credit facility, and had no borrowings outstanding under our revolving credit facility. Refer to Note 4 of the Notes to the Consolidated Financial Statements, “Long-Term Debt and Credit Agreements,” for further details regarding the interest rate on future borrowings under the revolving credit facility and our leverage ratio.

Certain Restrictive Covenants

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

42

Table of Contents

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)","2022","","2021"],["Total debt","$","2,181","","$","3,125"],["Stockholders' equity","12,659","","11,738"],["Total capitalization","$","14,840","","$","14,863"],["Debt to total capitalization","15%","","21%"],["Cash and cash equivalents","$","673","","$","1,036"]]
[[/GREPCENT_TABLE]]

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

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

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

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

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

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

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

[[GREPCENT_TABLE]]
[["","","Rate per share"],["","","Base","","Variable","","Total","","Total Dividends Paid (In millions)"],["2022","","$","0.60","","","$","1.89","","","$","2.49","","","$","1,991"],["2021 (1)","","$","0.45","","","$","0.67","","","$","1.12","","","$","779"]]
[[/GREPCENT_TABLE]]

________________________________________________________

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

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

43

Table of Contents

Capital and Exploration Expenditures

On an annual basis, we generally fund most of our capital expenditures, excluding any significant property acquisitions, with cash generated from operations and, if required, borrowings under our revolving credit facility. We budget these expenditures based on our projected cash flows for the year.

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

[[GREPCENT_TABLE]]
[["","Year Ended December 31,"],["(In millions)","2022","","2021","","2020"],["Acquisitions(1) :"],["Proved","$","\u2014","","","$","7,472","","","$","\u2014"],["Unproved","\u2014","","","5,381","","","\u2014"],["Total","$","\u2014","","","$","12,853","","","$","\u2014"],["Capital expenditures"],["Drilling and facilities","$","1,617","","","$","688","","","$","547"],["Leasehold acquisitions","10","","","5","","","6"],["Pipeline and gathering","56","","","9","","","\u2014"],["Other","54","","","23","","","17"],["","1,737","","","725","","","570"],["Exploration expenditures(2)","29","","","18","","","15"],["Total","$","1,766","","","$","743","","","$","585"]]
[[/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 2022 or 2021. Exploration expenditures include $4 million of exploratory dry-hole costs in 2020.

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

Our 2023 capital program is expected to be approximately $2.0 billion to $2.2 billion. We expect to turn-in-line 150 to 175 total net wells in 2023 across our three operating regions. Approximately 49 percent of our drilling and completion capital will be invested in the Permian Basin, 44 percent in the Marcellus Shale and the balance in the Anadarko Basin. The increase in our year-over-year capital expenditures is primarily driven by our expectations around the impact of inflation on our 2023 capital program and a modest increase in activity. We will continue to assess the commodity price environment and may increase or decrease our capital expenditures accordingly.

Contractual Obligations

We have various contractual obligations in the normal course of our operations. As of December 31, 2022, our material contractual obligations include debt and related interest expense, transportation and gathering agreements, lease obligations, operational agreements, drilling and completion obligations, derivative obligations and asset retirement obligations. Other joint owners in the properties operated by us could incur a portion of these costs. We expect that our sources of capital will be adequate to fund these obligations. Refer to the Notes to the Consolidated Financial Statements included in Item 8 of this Annual Report for further details.

From time to time, we enter into arrangements that can give rise to material off-balance sheet obligations. As of December 31, 2022, the material off-balance sheet arrangements we had entered into included certain firm transportation and processing commitments and operating lease agreements with terms at commencement of less than 12 months for equipment used in our exploration and development activities. We have no other off-balance sheet debt or other similar unrecorded obligations.

44

Table of Contents

Critical Accounting Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities as of the date of the balance sheet, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates, and changes in our estimates are recorded when known. We consider the following to be our most critical estimates that involve judgement of management.

Purchase Accounting

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

We made a number of assumptions in estimating the fair value of assets acquired and liabilities assumed in the Merger. The most significant assumptions related to the fair value estimates of proved and unproved oil and gas properties, which were recorded at fair value of $12.9 billion. Because sufficient market data was not available regarding the fair values of the acquired proved and unproved oil and gas properties, we prepared our estimates using discounted cash flows and engaged third party valuation experts. Significant judgments and assumptions are inherent in these estimates and include, among other things, estimates of reserves quantities and production volumes, future commodity prices and price differentials, expected development costs, lease operating costs, reserves risk adjustment factors and an estimate of an applicable market participant discount rate that reflects the risk of the underlying cash flow estimates.

Estimated fair values assigned to assets acquired can have a significant impact on future results of operations, as presented in our financial statements. Fair values are based on estimates of future commodity prices and price differentials, reserves quantities and production volumes, development costs and lease operating costs. In the event that future commodity prices or reserves quantities or production volumes are significantly lower than those used in the determination of fair value as of the effective date of the Merger, the likelihood increases that certain costs may be determined to be unrecoverable.

In addition to the fair value of proved and unproved oil and gas properties, other significant fair value assessments for the assets acquired and liabilities assumed in the Merger relate to long-term debt, fixed assets and derivative instruments. The fair value of the assumed Cimarex publicly traded debt was based on available third-party quoted prices. We prepared estimates and engaged third-party valuation experts to assist in the valuation of certain fixed assets, which required significant judgments and assumptions inherent in the estimates and included projected cash flows and comparable companies’ cash flow multiples. The fair value of assumed derivative instrument liabilities included significant judgments and assumptions related to estimates of future commodity prices and related differentials and estimates of volatility factors and interest rates.

Successful Efforts Method of Accounting

We follow the successful efforts method of accounting for our oil and gas producing activities. Acquisition costs for proved and unproved properties are capitalized when incurred. Judgment is required to determine the proper classification of wells designated as developmental or exploratory, which ultimately will determine the proper accounting treatment of costs incurred. Exploration costs, including geological and geophysical costs, the costs of carrying and retaining unproved properties and exploratory dry-hole costs are expensed. Development costs, including costs to drill and equip development wells and successful exploratory drilling costs to locate proved reserves, are capitalized.

Oil and Gas Reserves

The process of estimating quantities of proved reserves is inherently imprecise, and the reserves data included in this document is only an estimate. The process relies on interpretations and judgment of available geological, geophysical, engineering and production data. The extent, quality and reliability of this technical data can vary. The process also requires certain economic assumptions, some of which are mandated by the SEC, such as commodity prices. Additional assumptions include drilling and operating expenses, capital expenditures, taxes and availability of funds. Any significant variance in the interpretations or assumptions could materially affect the estimated quantity and value of our reserves and can change substantially over time. Periodic revisions to the estimated reserves and future cash flows may be necessary as a result of reservoir performance, drilling activity, commodity prices, fluctuations in operating expenses, technological advances, new geological or geophysical data or other economic factors. Accordingly, reserves estimates are generally different from the quantities ultimately recovered.

45

Table of Contents

The reserves estimates of our oil and gas properties have been prepared by our petroleum engineering staff and certain of our reserves are subject to an evaluation performed by an independent third-party petroleum consulting firm. In 2022, greater than 90 percent of the total future net revenue discounted at 10 percent attributable to our proved reserves were subject to this evaluation. For more information regarding reserves estimation, including historical reserves revisions, refer to the Supplemental Oil and Gas Information included in Item 8.

Our rate of recording DD&A expense is dependent upon our estimate of proved and proved developed reserves, which are utilized in our unit-of-production calculation. If the estimates of proved reserves were to be reduced, the rate at which we record DD&A expense would increase, reducing net income. Such a reduction in reserves may result from lower market prices, which may make it uneconomic to drill and produce higher cost fields. A five percent positive or negative revision to proved reserves would result in a decrease of $0.31 per Boe and an increase of $0.34 per Boe, respectively, on our DD&A rate. This estimated impact is based on current data, and actual events could require different adjustments to our DD&A rate.

In addition, a decline in proved reserves estimates may impact the outcome of our impairment test under applicable accounting standards. No impairment resulted from our recent downward reserves revision in the Marcellus Shale. Due to the inherent imprecision of the reserves estimation process, risks associated with the operations of proved producing properties and market sensitive commodity prices utilized in our impairment analysis, we cannot determine if an impairment is reasonably likely to occur in the future.

Oil and Gas Properties

We evaluate our proved oil and gas properties for impairment on a field-by-field basis whenever events or changes in circumstances indicate an asset’s carrying amount may not be recoverable. We compare expected undiscounted future cash flows to the net book value of the asset. If the future undiscounted expected cash flows, based on our estimate of future commodity prices, operating costs and anticipated production from proved reserves and risk-adjusted probable and possible reserves, are lower than the net book value of the asset, then the capitalized cost is reduced to fair value. Commodity pricing is estimated by using a combination of assumptions management uses in its budgeting and forecasting process, historical and current prices adjusted for geographical location and quality differentials, as well as other factors that we believe will impact realizable prices. Given the significant volatility in oil, natural gas and NGLs prices, estimates of such future prices are inherently imprecise. In the event that commodity prices significantly decline, we would test the recoverability of the carrying value of our oil and gas properties and, if necessary, record an impairment charge. Fair value is calculated by discounting the future cash flows. The discount factor used is based on rates utilized by market participants that are commensurate with the risks inherent in the development and production of the underlying oil and natural gas.

Unproved oil and gas properties are assessed periodically for impairment on an aggregate basis through periodic updates to our undeveloped acreage amortization based on past drilling and exploration experience, our expectation of converting leases to held by production and average property lives. Average property lives are determined on a geographical basis and based on the estimated life of unproved property leasehold rights. Historically, the average property life in each of the geographical areas has not significantly changed and generally ranges from three to five years. The commodity price environment may impact the capital available for exploration projects as well as development drilling. We have considered these impacts when determining the amortization of our undeveloped acreage. If the average unproved property life decreases or increases by one year, the amortization would increase by approximately $12 million or decrease by $8 million, respectively, per year.

As these properties are developed and reserves are proved, the remaining capitalized costs are subject to depreciation and depletion. If the development of these properties is deemed unsuccessful and the properties are abandoned or surrendered, the capitalized costs related to the unsuccessful activity are expensed in the year the determination is made. The rate at which the unproved properties are written off depends on the timing and success of our future exploration and development program.

Derivative Instruments

Under applicable accounting standards, the fair value of each derivative instrument is recorded as either an asset or liability on the balance sheet. At the end of each quarterly period, these instruments are marked-to-market. The change in fair value of derivatives not designated as hedges is recorded as a component of operating revenues in gain (loss) on derivative instruments in the Consolidated Statement of Operations.

Our derivative contracts are measured based on quotes from our counterparties or internal models. Such quotes and models have been derived using an income approach that considers various inputs including current market and contractual prices for the underlying instruments, quoted forward commodity prices, basis differentials, volatility factors and interest rates for a similar length of time as the derivative contract term, as applicable. These estimates are derived from or verified using relevant NYMEX futures contracts or are compared to multiple quotes obtained from counterparties for reasonableness. The determination of fair value also incorporates a credit adjustment for non-performance risk. We measure the non-performance

46

Table of Contents

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

Our financial condition, results of operations and liquidity can be significantly impacted by changes in the market value of our derivative instruments due to volatility of commodity prices, including changes in both index prices (such as NYMEX and Waha) and basis differentials.

Income Taxes

We make certain estimates and judgments in determining our income tax expense for financial reporting purposes. These estimates and judgments include the calculation of certain deferred tax assets and liabilities that arise from differences in the timing and recognition of revenue and expenses for tax and financial reporting purposes and estimating reserves for potential adverse outcomes regarding tax positions that we have taken. We account for the uncertainty in income taxes using a recognition and measurement threshold for tax positions taken or expected to be taken in a tax return. The tax benefit from an uncertain tax position is recognized when it is more likely than not that the position will be sustained upon examination by taxing authorities based on technical merits of the position. The amount of the tax benefit recognized is the largest amount of the benefit that has a greater than 50 percent likelihood of being realized upon ultimate settlement. The effective tax rate and the tax basis of assets and liabilities reflect management’s estimates of the ultimate outcome of various tax uncertainties.

We believe all of our deferred tax assets, net of any valuation allowances, will ultimately be realized, taking into consideration our forecasted future taxable income, which includes consideration of future operating conditions specifically related to commodity prices. If our estimates and judgments change regarding our ability to realize our deferred tax assets, our tax provision could increase in the period it is determined that it is more likely than not it will not be realized.

Our effective tax rate is subject to variability as a result of factors other than changes in federal and state tax rates and/or changes in tax laws which could affect us. Our effective tax rate is affected by changes in the allocation of property, payroll and revenues among states in which we operate. A small change in our estimated future tax rate could have a material effect on current period earnings.

Contingency Reserves

A provision for contingencies is charged to expense when the loss is probable and the cost is estimable. The establishment of a reserve is based on an estimation process that includes the advice of legal counsel and subjective judgment of management. In certain cases, our judgment is based on the advice and opinions of legal counsel and other advisors, the interpretation of laws and regulations, which can be interpreted differently by regulators and courts of law, our experience and the experiences of other companies dealing with similar matters, and our decision on how we intend to respond to a particular matter. Actual losses can differ from estimates for various reasons, including those noted above. We monitor known and potential legal, environmental and other contingencies and make our best estimate based on the information we have. Future changes in facts and circumstances not currently foreseeable could result in the actual liability exceeding the estimated ranges of loss and amounts accrued.

Stock-Based Compensation

We account for stock-based compensation under the fair value method of accounting in accordance with applicable accounting standards. Under the fair value method, compensation cost is measured at the grant date for equity-classified awards and re-measured each reporting period for liability-classified awards based on the fair value of an award and is recognized over the service period, which is generally the vesting period. To calculate fair value, we use various models, including both a Black Scholes or a Monte Carlo valuation model, as determined by the specific provisions of the award. The use of these models requires significant judgment with respect to expected life, volatility and other factors.

47

Table of Contents

RESULTS OF OPERATIONS

2022 and 2021 Compared

Operating Revenues

[[GREPCENT_TABLE]]
[["","Year Ended December 31,","","Variance"],["(In millions)","2022","","2021","","Amount","","Percent"],["Natural gas","$","5,469","","","$","2,798","","","$","2,671","","","95","%"],["Oil","3,016","","","616","","","2,400","","","390","%"],["NGL","964","","","243","","","721","","","297","%"],["Loss on derivative instruments","(463)","","","(221)","","","(242)","","","110","%"],["Other","65","","","13","","","52","","","400","%"],["","$","9,051","","","$","3,449","","","$","5,602","","","162","%"]]
[[/GREPCENT_TABLE]]

Production Revenues

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

Natural Gas Revenues

[[GREPCENT_TABLE]]
[["","Year Ended December 31,","","Variance","Increase (Decrease) (In millions)"],["","2022","","2021","","Amount","","Percent"],["Volume variance (Bcf)","1,024.3","","","911.1","","113.2","","","12","%","","$","348"],["Price variance ($/Mcf)","$","5.34","","","$","3.07","","","$","2.27","","","74","%","","2,323"],["Total","","","","","","","","","$","2,671"]]
[[/GREPCENT_TABLE]]

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

Oil Revenues

[[GREPCENT_TABLE]]
[["","Year Ended December 31,","","Variance","Increase (Decrease) (In millions)"],["","2022","","2021","","Amount","","Percent"],["Volume variance (MMBbl)","31.9","","8.1","","23.8","","294%","","$","1,799"],["Price variance ($/Bbl)","$","94.47","","","$","75.61","","","$","18.86","","","25%","","601"],["Total","","","","","","","","","$","2,400"]]
[[/GREPCENT_TABLE]]

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

NGL Revenues

[[GREPCENT_TABLE]]
[["","Year Ended December 31,","","Variance","Increase (Decrease) (In millions)"],["","2022","","2021","","Amount","","Percent"],["Volume variance (MMBbl)","28.7","","7.1","","21.6","","304","%","","$","738"],["Price variance ($/Bbl)","$","33.58","","","$","34.18","","","$","(0.60)","","","(2)","%","","(17)"],["Total","","","","","","","","","$","721"]]
[[/GREPCENT_TABLE]]

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

48

Table of Contents

Loss on Derivative Instruments

Net gains and losses on our derivative instruments are a function of fluctuations in the underlying commodity index prices as compared to the contracted prices and the monthly cash settlements (if any) of the derivative instruments. We have elected not to designate our derivatives as hedging instruments for accounting purposes and, therefore, we do not apply hedge accounting treatment to our derivative instruments. Consequently, changes in the fair value of our derivative instruments and cash settlements are included as a component of operating revenues as either a net gain or loss on derivative instruments. Cash settlements of our contracts are included in cash flows from operating activities in our statement of cash flows. The following table presents the components of “Loss on derivative instruments” for the years indicated:

[[GREPCENT_TABLE]]
[["","Year Ended December 31,"],["(In millions)","2022","","2021"],["Cash paid on settlement of derivative instruments"],["Gas contracts","$","(438)","","","$","(307)"],["Oil contracts","(324)","","","(124)"],["Non-cash gain on derivative instruments"],["Gas contracts","149","","","99"],["Oil contracts","150","","","111"],["","$","(463)","","","$","(221)"]]
[[/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 the volume and commodity mix of production, some are a function of the number of wells we own and operate, some depend on the prices charged by service companies, and some fluctuate based on a combination of the foregoing. Our operating costs and expenses in 2022 were substantially higher due to the Merger, which significantly expanded our operations to include the Permian and Anadarko Basins. In addition, our costs for services, labor and supplies have recently increased due to increased demand for those items, inflation and supply chain disruptions.

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

[[GREPCENT_TABLE]]
[["","Year Ended December 31,","","Variance","","Per Boe"],["(In millions, except per Boe)","2022","","2021","","Amount","","Percent","","2022","","2021"],["Operating Expenses"],["Direct operations","$","460","","","$","156","","","$","304","","","195","%","","$","1.99","","","$","0.93"],["Transportation, processing and gathering","955","","","663","","","292","","","44","%","","4.13","","","3.97"],["Taxes other than income","366","","","83","","","283","","","341","%","","1.58","","","0.50"],["Exploration","29","","","18","","","11","","","61","%","","0.13","","","0.11"],["Depreciation, depletion and amortization","1,635","","","693","","","942","","","136","%","","7.07","","","4.15"],["General and administrative","396","","","270","","","126","","","47","%","","1.70","","","1.62"],["","$","3,841","","","$","1,883","","","$","1,958","","","104","%"]]
[[/GREPCENT_TABLE]]

49

Table of Contents

Direct Operations

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

[[GREPCENT_TABLE]]
[["","Year Ended December 31,","","","","Per Boe"],["(In millions, except per Boe)","2022","","2021","","Variance","","2022","","2021"],["Direct Operations"],["Lease operating expense","$","370","","","$","127","","","$","243","","","$","1.60","","","$","0.76"],["Workover expense","90","","29","","61","","0.39","","0.17"],["","$","460","","","$","156","","","$","304","","","$","1.99","","","$","0.93"]]
[[/GREPCENT_TABLE]]

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

Transportation, Processing and Gathering

Transportation, processing and gathering costs principally consist of expenditures to prepare and transport production downstream from the wellhead, including gathering, fuel, and compression and processing costs, which are incurred to extract NGLs from the raw natural gas stream. Gathering costs also include costs associated with operating our gas gathering infrastructure, including operating and maintenance expenses. Costs vary by operating area and will fluctuate with increases or decreases in production volumes, contractual fees, and changes in fuel and compression costs.

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

Taxes Other Than Income

Taxes other than income consist of production (or severance) taxes, drilling impact fees, ad valorem taxes and other taxes. State and local taxing authorities assess these taxes, with production taxes being based on the volume or value of production, drilling impact fees being based on drilling activities and prevailing natural gas prices and ad valorem taxes being based on the value of properties. The following table presents taxes other than income for the years indicated:

[[GREPCENT_TABLE]]
[["","Year Ended December 31,"],["(In millions)","2022","","2021","","Variance"],["Taxes Other than Income"],["Production","$","282","","","$","57","","","$","225"],["Drilling impact fees","31","","","22","","","9"],["Ad valorem","53","","","3","","","50"],["Other","\u2014","","","1","","","(1)"],["","$","366","","","$","83","","","$","283"],["Taxes other than income as a percentage of production revenue","3.9","%","","2.3","%"]]
[[/GREPCENT_TABLE]]

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

50

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)","2022","","2021","","Variance","","2022","","2021"],["DD&A Expense"],["Depletion","$","1,474","","","$","663","","","$","811","","","$","6.37","","","$","3.97"],["Depreciation","91","","23","","68","","","0.40","","0.13"],["Amortization of undeveloped properties","61","","1","","","60","","","0.26","","0.01"],["Accretion of ARO","9","","6","","3","","","0.04","","0.04"],["","$","1,635","","","$","693","","","$","942","","","$","7.07","","","$","4.15"]]
[[/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 $811 million due to increased production and a higher depletion rate of $6.37 per Boe for 2022, both of which are attributable to the value of the oil and gas properties acquired in the Merger, compared to $3.97 per Boe for 2021.

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. The increase in depreciation expense during 2022 as compared to 2021 is primarily due to increased depreciation on our gathering and plant facilities acquired in the Merger.

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. Amortization of unproved properties increased $60 million due to the release of certain leaseholds during the period and the amortization of our unproved properties acquired in the Merger. 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.

General and Administrative

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. A portion of our G&A expense is reported net of amounts reimbursed to us by working interest owners of the oil and gas properties we operate. The table below reflects our G&A expense for the periods identified:

[[GREPCENT_TABLE]]
[["","Year Ended December 31,"],["(In millions)","2022","","2021","","Variance"],["G&A Expense"],["General and administrative expense","$","241","","","$","107","","","$","134"],["Stock-based compensation expense","86","","","57","","","29"],["Merger-related expense","69","","106","","(37)"],["","$","396","","","$","270","","","$","126"]]
[[/GREPCENT_TABLE]]

G&A expense, excluding stock-based compensation and merger-related expenses, increased $134 million primarily due to the Merger, which significantly expanded our headcount and office-related expenses.

51

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 $29 million primarily due to the issuance of additional share awards as consideration in the Merger, increased headcount, and the accelerated vesting of employee performance shares as described under “Stock-Based Compensation” in Note 13 of the Notes to the Consolidated Financial Statements included in this Form 10-K.

Merger-related expenses decreased $37 million primarily due to $42 million of lower transaction-related costs associated with the Merger, partially offset by an increase of $8 million of employee-related severance and termination benefits associated with the expected termination of certain employees, which is being accrued over the expected transition period.

Interest Expense, net

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

[[GREPCENT_TABLE]]
[["","Year Ended December 31,"],["(In millions)","2022","","2021","","Variance"],["Interest Expense, net"],["Interest expense","$","110","","","$","62","","","$","48"],["Debt premium amortization","(37)","","","(10)","","","(27)"],["Debt issuance cost amortization","4","","","3","","","1"],["Other","(7)","","","7","","","(14)"],["","$","70","","","$","62","","","$","8"]]
[[/GREPCENT_TABLE]]

Interest expense, net increased $8 million due to (i) an increase of $48 million in interest expense primarily related to incremental interest expense associated with the debt assumed in the Merger of $2.2 billion, which was partially offset by lower interest due to the repayment of $100 million of our 3.65% weighted-average private placement senior notes, which matured in September 2021, the repayment of $37 million of our 6.51% weighted-average private placement senior notes and $87 million of our 5.58% weighted-average private placement senior notes in August 2022 and the redemption of $750 million of the 4.375% senior notes in September and October 2022; (ii) an increase of $27 million of debt premium amortization associated with the previously mentioned debt related to the Merger and (iii) a decrease of $14 million of other interest expense primarily due to interest income earned from higher interest rates and higher cash balances subject to interest income during 2022.

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)","2022","","2021","","Variance"],["Income Tax Expense"],["Current tax expense","$","869","","","$","218","","","$","651"],["Deferred tax expense","235","","","126","","","109"],["","$","1,104","","","$","344","","","$","760"],["Combined federal and state effective income tax rate","21","%","","23","%"]]
[[/GREPCENT_TABLE]]

Income tax expense increased $760 million due to higher pre-tax income in 2022 compared to 2021, partially offset by a lower effective tax rate. The effective tax rate was lower for 2022 compared to 2021 due to differences in the non-recurring discrete items recorded during 2022 versus 2021.

2021 and 2020 Compared

For information on the comparison of the results of operations for the year ended December 31, 2021 compared to the year ended December 31, 2020, 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, 2021.

52

Table of Contents