Coterra Energy Inc. (CTRA) FY 2021 MD&A

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 referred to 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 that could cause actual results to differ materially from those included in this report, including those under “Forward-Looking Statements” in Part I of this report and “Risk Factors” in Part I, Item 1A of 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. Under the terms of the Merger Agreement and subject to certain exceptions specified therein, each eligible share of Cimarex common stock was converted into the right to receive 4.0146 shares of our common stock. As a result of the completion of the Merger, we issued approximately 408.2 million shares of common stock to Cimarex stockholders (excluding shares that were awarded in replacement of previously outstanding Cimarex restricted share awards). Additionally on October 1, 2021, we changed our name to Coterra Energy Inc.

Certain 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, 2021 compared to the year ended December 31, 2020 are as follows:

•Natural gas production increased 53.4 Bcf, or six percent, from 857.7 Bcf in 2020 to 911.1 Bcf in 2021. The slight increase was attributable to production during the fourth quarter of 2021 from properties acquired in the Merger, which significantly expanded our operations, partially offset by the timing of our drilling and completion activities in the Marcellus Shale in 2021.

•Oil production increased 8 Mmbbl from prior year. The increase was attributable to production during the fourth quarter of 2021 from properties acquired in the Merger.

•NGL production increased 7 Mmbbl from prior year. The increase was attributable to production during the fourth quarter of 2021 from properties acquired in the Merger.

•Average realized natural gas price for 2021 was $2.73 per Mcf, 63 percent higher than the $1.68 per Mcf price realized in 2020.

•Average realized oil and NGL prices for 2021 were $60.35 and $34.18 per Bbl, respectively.

•Total capital expenditures were $725 million in 2021 compared to $570 million in 2020. The increase in capital expenditures was attributable to expanded drilling and completion activities during the fourth quarter of 2021 as a result of the Merger.

•Drilled 114 gross wells (99.9 net) with a success rate of 100 percent in 2021 compared to 74 gross wells (64.3 net) with a success rate of 100 percent in 2020.

•Completed 132 gross wells (108.3 net) in 2021 compared to 86 gross wells (77.3 net) in 2020.

•Average rig count during 2021 was approximately 2.5 rigs in the Marcellus compared to an average rig count of approximately 2.3 rigs during 2020. Rig count since the Merger averaged 5.3 and zero rigs in the Permian Basin and Anadarko Basin, respectively.

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•Repaid $88 million of our 5.58% weighted-average private placement senior notes, which matured in January 2021, and $100 million of our 3.65% weighted-average private placement senior notes, which matured in September 2021.

•Paid dividends of $1.12 per share, including $0.445 per share for regular quarterly dividends, a special common stock dividend of $0.50 per share in October 2021 after the completion of the Merger and a variable common stock dividend of $0.175 per share in November 2021.

Impact of the COVID-19 Pandemic

The ongoing COVID-19 outbreak has caused widespread illness and significant loss of life, leading governments across the world to impose severely stringent limitations on movement and human interaction. We have implemented preventative measures and developed response plans intended to minimize unnecessary risk of exposure and prevent infection among our employees and the communities in which we operate. Beginning in March 2020, we modified certain business practices (including those related to nonoperational employee work locations and the cancellation of physical participation in a number of meetings, events and conferences) to conform to government restrictions and best practices encouraged by the Centers for Disease Control and Prevention, the WHO and other governmental and regulatory authorities. In addition, we implemented and provided training on a COVID-19 Safety Policy containing personal safety protocols; provided additional personal protective equipment to our workforce; implemented rigorous COVID-19 self-assessment, contact tracing and quarantine protocols; increased cleaning protocols at all of our employee work locations; and provided additional paid leave to employees with actual or presumed COVID-19 cases. We also collaborated, and continue to collaborate, with customers, suppliers and service providers to minimize potential impacts to or disruptions of our operations and to implement longer-term emergency response protocols. Although we returned to full in-person working in our Houston headquarters and other offices in July 2021, we intend to continue to monitor developments affecting our workforce, our customers, our suppliers, our service providers and the communities in which we operate, including any significant resurgence in COVID-19 transmission and infection. Should the need arise, we will take such precautions as we believe are warranted.

Our efforts to respond to the challenges presented by the ongoing pandemic, as well as certain operational decisions we previously implemented, such as our maintenance capital program, have helped to minimize the impact, and any resulting disruptions, of the pandemic to our business and operations.

The long-term impact that the COVID-19 pandemic will have on our business, cash flows, liquidity, financial condition and results of operations will depend on future developments, including, among others, the duration, ultimate geographic spread and severity of the virus and its variants (such as the Delta and Omicron variants), the global availability and efficacy of treatments and vaccines and boosters and the acceptance of such treatments and vaccines by a significant portion of the population, any significant resurgence in virus transmission and infection in regions that have experienced improvements, the extent and duration of governmental and other measures implemented to try to slow the spread of the virus (whether through a continuation of existing measures or the re-imposition of prior measures), and other actions by governmental authorities, customers, suppliers and other third parties.

Market Conditions and Commodity Prices

Our financial results depend on many factors, particularly commodity prices and our ability to 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 other factors. Our realized prices are also further impacted by our hedging activities.

Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prevailing commodity prices, particularly oil and natural gas prices. Material declines in commodity prices could have a material adverse effect on our operating results, financial condition, liquidity and ability to obtain financing. Lower commodity prices also may reduce the amount of oil, natural gas, and NGLs that we can produce economically. In addition, in periods of low commodity prices, we may elect to curtail a portion of our production from time to time. Historically, commodity prices have been volatile, with prices sometimes fluctuating widely, and they may remain volatile. As a result, we cannot accurately predict future commodity prices and, therefore, cannot determine with any degree of certainty what effect increases or decreases in these prices will have on our capital program, production volumes or revenues. In addition to commodity prices and production volumes, finding and developing sufficient amounts of oil and natural gas reserves at economical costs are critical to our long-term success.

We account for our derivative instruments on a mark-to-market basis, with changes in fair value recognized in operating revenues in the Consolidated Statement of Operations. As a result of these mark-to-market adjustments associated with our derivative instruments, we will experience volatility in our earnings due to commodity price volatility. Refer to “Results of

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Operations — Impact of Derivative Instruments on Operating Revenues” below and Note 5 of the Notes to the Consolidated Financial Statements, “Derivative Instruments,” for more information.

One of the impacts of the COVID-19 pandemic was a significant reduction in demand for crude oil, and to a lesser extent, natural gas. The supply/demand imbalance driven by the COVID-19 pandemic and production disagreements in March 2020 among members of OPEC+ led to a significant global economic contraction generally in 2020 and continued to have disruptive impacts on the oil and gas industry in 2021. Although the members of OPEC+ agreed in April 2020 to cut oil production and have subsequently taken actions that generally have supported commodity prices, and U.S. production has declined, oil prices and natural gas prices remained low, relative to pre-pandemic levels, through the first quarter of 2021, as the oversupply and lack of demand in the market persisted. Oil, natural gas and NGL prices increased during the second half of 2021 compared to 2020, in part due to greater demand and slightly decreasing production levels. In addition, our costs for services, labor and supplies increased during 2021 due to increased demand for those items and supply chain disruptions related to the COVID-19 pandemic.

Meanwhile, NYMEX oil and natural gas futures prices have strengthened since the reduction of pandemic-related restrictions and recent 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 and sustained higher U.S. exports, lower associated gas growth from oil drilling and improved U.S. economic activity. Oil price futures have improved 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 increase further. 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 from current levels, our management would evaluate the recoverability of the carrying value of our oil and gas properties.

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

FINANCIAL CONDITION

Liquidity and Capital Resources

We strive to maintain an adequate liquidity level to address commodity price volatility and risk. Our primary sources of liquidity are (1) cash on hand, (2) net cash provided by operating activities and (3) available borrowing capacity under our revolving credit facility.

Our liquidity requirements consist primarily of (1) capital expenditures, (2) payment of contractual obligations, including debt maturity and interest payments, (3) working capital requirements, (4) dividend payments and (5) share repurchases. See below for additional discussion and analysis of our cash flows. 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 long term.

We had $1.5 billion of capacity on our revolving credit facility at December 31, 2021. The revolving credit facility is scheduled to mature in April 2024, subject to extension up to one year if certain conditions are met.

At December 31, 2021, we had no borrowings outstanding under our revolving credit facility. We also had unrestricted cash on hand of $1.0 billion as of December 31, 2021.

Our revolving credit facility includes a covenant limiting our borrowing capacity based on our leverage ratio. Refer to Note 4 of the Notes to the Consolidated Financial Statements, “Debt and Credit Agreements,” for further details regarding our leverage ratio.

Immediately prior to the Merger, Cimarex had outstanding senior notes in the aggregate principal amount of $2.0 billion. On October 7, 2021 and after the completion of the Merger, we completed private offers to eligible holders to exchange $1.8 billion in aggregate principal of Cimarex senior notes (the “Existing Cimarex Notes”) for $1.8 billion in aggregate principal of new notes issued by us (the “New Coterra Notes”) and $2 million of cash consideration. In connection with the debt exchange, Cimarex obtained consents to adopt certain amendments to each of the indentures governing the Existing Cimarex Notes to eliminate certain of the covenants, restrictive provisions and events of default from such indentures. The New Coterra Notes are

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general, unsecured, senior obligations of ours and have substantially identical terms and covenants to the Existing Cimarex Notes (before giving effect to the amendments referred to in the immediately preceding sentence), which we believe are customary for senior, unsecured notes issued by companies of similar size and credit quality as compared to us. The New Coterra Notes consist of $706 million aggregate principal amount of 4.375% Senior Notes due 2024, $687 million aggregate principal amount of 3.90% Senior Notes due 2027 and $433 million aggregate principal amount of 4.375% Senior Notes due 2029.

Our debt is currently rated as investment grade by the three leading rating agencies. 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. 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. However, 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.

At December 31, 2021, we were in compliance with all financial covenants for both our revolving credit facility and senior notes. Refer to Note 4 of the Notes to the Consolidated Financial Statements, “Debt and Credit Agreements,” for further details regarding financial covenants.

As market conditions warrant and subject to our contractual restrictions, liquidity position and other factors, we may from time to time seek to repurchase or retire our outstanding debt through cash purchases and/or exchanges for other debt or equity securities in open market transactions, privately negotiated transactions, by tender offer or otherwise. Any such cash repurchases by us may be funded by cash on hand or incurring new debt. The amounts involved in any such transactions, individually or in the aggregate, may be material.

Cash Flows

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

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

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 incur certain Merger-related restructuring cost cash outflows ranging from $100 million to $110 million. These payments will primarily relate to workforce reductions and the associated employee severance benefits, and the acceleration of employee benefits that were triggered by the Merger.

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, 2021 and 2020, we had a working capital surplus of $916 million and $26 million, respectively. We believe we have adequate liquidity and availability under our revolving credit facility to meet our working capital requirements over the next 12 months.

Net cash provided by operating activities in 2021 increased by $889 million compared to 2020. This increase was primarily due to 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,

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oil and NGL revenue was primarily due to the Merger, an increase in realized natural gas prices and moderately higher natural gas production in the Marcellus Shale. Average realized natural gas prices increased by 87 percent in 2021 compared to 2020.

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

Investing Activities. Cash flows used in investing activities decreased by $897 million from 2020 compared to 2021. The decrease was primarily driven by $1.0 billion of cash acquired as a result of the Merger, partially offset by $152 million of higher capital expenditures which were primarily a result of the Merger.

Financing Activities. Cash flows used in financing activities increased by $830 million from 2020 compared to 2021. The increase was due to $621 million of higher dividend payments related to special and variable common stock dividends paid in 2021, $101 million higher net repayments of debt primarily related to maturities of certain of our senior notes and $104 million higher tax withholding payments related to share-based awards that vested as a result of the Merger.

2020 and 2019 Compared. For information on the comparison of operating, investing and financing cash flows for the year ended December 31, 2019 compared to the year ended December 31, 2020, refer to Financial Condition (Cash Flows) included in the Coterra Energy Inc. (formerly Cabot Oil & Gas Corporation) Annual Report on Form 10-K for the year ended December 31, 2020.

Capitalization

Information about our capitalization is as follows:

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(1)Includes $188 million of current portion of long-term debt at December 31, 2020. There were no borrowings outstanding under our revolving credit facility as of December 31, 2021 and 2020, respectively.

(2)Includes consideration of $9.1 billion related to the issuance of our common stock in connection with the Merger.

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).

Share repurchases. We did not repurchase any shares of our common stock during 2021 and 2020 under our share repurchase program. As of December 31, 2021, 125,067 shares of common stock went into treasury stock that were retained from restricted stock award vestings for the withholding of taxes.

In February 2022, our Board of Directors terminated our previously authorized share repurchase program and authorized a new share repurchase program. This new share repurchase program authorizes the Company to purchase up to $1.25 billion of our common stock in the open market or in negotiated transactions.

Dividends. During 2021 and 2020, we paid dividends of $780 million ($1.12 per share) and $159 million ($0.40 per share) on our common stock, respectively.

In April 2021, our Board of Directors approved an increase in the quarterly dividend on our common stock from $0.10 per share to $0.11 per share. In November 2021, our Board of Directors also approved an increase in the base component of our quarterly dividend on our common stock from $0.11 per share to $0.125 per share. Also on that date, related to our dividend

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strategy to return at least 50 percent of quarterly free cash flows to stockholders, our Board of Directors approved a variable dividend of $0.175 per share, resulting in a total base-plus-variable dividend of $0.30 per share on our common stock.

On October 4, 2021, and in connection with the completion of the Merger, our Board of Directors approved a special dividend of $0.50 per share payable on our common stock on October 22, 2021.

In February 2022, our Board of approved an additional increase in the quarterly dividend on our common stock from $0.125 per share to $0.15 per share. Also on that date, our Board of Directors approved a variable dividend of $0.41 per share, resulting in a quarterly base-plus-variable dividend of $0.56 per share on our common stock.

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:

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(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)Exploration expenditures include $4 million and $2 million of exploratory dry-hole costs in 2020 and 2019, respectively. There were no exploratory dry-hole costs in 2021.

In 2021, we drilled 114 gross wells (99.9 net) and completed 132 gross wells (108.3 net), of which 14 gross wells (13.0 net) were drilled but uncompleted in prior years.

Our 2022 capital program is expected to be approximately $1,400 million to $1,500 million, of which $1,225 million to $1,325 million is allocated to drilling and completion activities. We expect to turn-in-line 134 to 153 total net wells in 2022 across our three operating regions. Approximately 49 percent of drilling and completion capital will be invested in the Permian Basin, 44 percent in the Marcellus Shale and the balance in the Anadarko Basin. Midstream, saltwater disposal, electrification, infrastructure and other investments are expected to total approximately $175 million in the year. 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, 2021, 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

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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, 2021, 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.

Critical Accounting Estimates

In preparing financial statements, we follow GAAP. These principles require 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, 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 substantially complete; however, it may be subject to change for up to one year after October 1, 2021, the effective date of the Merger.

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 a fair value of $12.9 billion. Since sufficient market data was not available regarding the fair values of the acquired proved and unproved oil and gas properties, we prepared our estimates using discounted cash flows and engaged third party valuation experts. Significant judgments and assumptions are inherent in these estimates and include, among other things, estimates of reserve quantities and production volumes, future commodity prices and price differentials, expected development costs, lease operating costs, reserve risk adjustment factors and an estimate of an applicable market participant discount rate that reflects the risk of the underlying cash flow estimates.

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

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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, reserve estimates are generally different from the quantities ultimately recovered. We cannot predict the amounts or timing of such future revisions.

The reserve quantity estimates of our oil and gas properties have been prepared by our petroleum engineering staff. Miller and Lents has audited 100 percent of the proved reserves estimates related to our Marcellus Shale properties, and DeGolyer and MacNaughton has performed an independent evaluation of estimated net reserves representing greater than 80 percent of the total future net revenue discounted at 10 percent attributable to the proved reserves estimates related to our Permian Basin, Anadarko Basin and other properties (excluding our Marcellus Shale properties). Each of Miller and Lents and DeGolyer and MacNaughton concluded, in their opinions, that our presented estimates are reasonable in the aggregate. For more information regarding reserve estimation, including historical reserve revisions, refer to the Supplemental Oil and Gas Information to the Consolidated Financial Statements 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 $0.29 per BOE and an increase of $0.32 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 reserve estimates may impact the outcome of our impairment test under applicable accounting standards. Due to the inherent imprecision of the reserve 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, 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. 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 range from three to five years. The commodity price environment may impact the capital available for exploration projects as well as development drilling.

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 are recorded as a component of operating revenues in gain (loss) on derivative instruments in the Consolidated Statement of Operations.

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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 using a market credit spread provided by one 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, both 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.

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 laws, 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 remeasured each reporting period for liability-classified awards based on the fair value of an award and is recognized over the service period, which is generally the vesting period. To calculate fair value, we use various models, including both a Black Scholes or a Monte Carlo valuation model, as determined by the specific provisions of the award. The use of these models requires significant judgment with respect to expected life, volatility and other factors.

Recently Issued and Adopted Accounting Pronouncements

Refer to Note 1 of the Notes to the Consolidated Financial Statements, “Summary of Significant Accounting Policies,” for a discussion of recently issued and adopted accounting pronouncements.

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OTHER ISSUES AND CONTINGENCIES

Regulations

Our operations are subject to various types of regulation by federal, state and local authorities. Refer to the “Other Business Matters” section of Item 1 for a discussion of these regulations.

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. Our revolving credit agreement 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, 2021, we were in compliance with all financial covenants in both our senior note agreements and our revolving credit agreement.

Operating Risks and Insurance Coverage

Our business involves a variety of operating risks. Refer to “Risk Factors—Business and Operational Risks—We face a variety of hazards and risks that could cause substantial financial losses” in Part I, Item 1A. In accordance with customary industry practice, we maintain insurance against some, but not all, of these hazards and risks and related losses. The occurrence of any loss events not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows. The costs of these insurance policies are somewhat dependent on our historical claims experience, the areas in which we operate and market conditions.

Commodity Pricing and Risk Management Activities

Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prevailing commodity prices. Significant declines in commodity prices may have a material adverse effect on our financial condition, liquidity, ability to obtain financing and operating results. Lower commodity prices also may reduce the amount of oil and natural gas that we can produce economically. Historically, commodity prices have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile. Depressed prices in the future would have a negative impact on our future financial results. In particular, substantially lower prices would significantly reduce revenue and could potentially trigger an impairment of our oil and gas properties or a violation of certain financial debt covenants.

The majority of our production is sold at market-sensitive prices. Generally, if the related commodity index declines, the price that we receive for our production will also decline. Therefore, the amount of revenue that we realize is determined by certain factors that are beyond our control. However, we may mitigate this price risk on a portion of our anticipated production with the use of financial commodity derivatives, including collars, swaps, roll differential swaps and basis swaps to reduce the impact of sustained lower pricing on our revenue. Under these arrangements, there is also a risk that the movement of index prices may result in our inability to realize the full benefit of an improvement in market conditions.

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RESULTS OF OPERATIONS

2021 and 2020 Compared

Operating Revenues

Production Revenues

Our production revenues vary from year to year and are derived from sales of our oil, natural gas and NGL production. Our 2021 production revenues were substantially increased due to the Merger, which significantly expanded our operations 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. Commodity prices are market driven and we expect future prices to be volatile due to supply and demand factors, pipeline capacity, seasonality and geopolitical, economic and other factors.

Below is a discussion of our production revenue, price and volume variances.

Natural Gas Revenues

Natural gas revenues increased $1.4 billion primarily due to significantly higher natural gas prices combined with higher production. The increase in production was primarily driven by an increase in fourth quarter production due to the Merger.

Oil Revenues

Oil revenues increased $616 million primarily due to the Merger.

NGL Revenues

NGL revenues increased $243 million primarily due to the Merger.

(Loss) Gain 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 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 on the instruments 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 statements of cash flows. The following table presents the components of “(Loss) gain on derivative instruments” for the years indicated:

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Included in the table above are settlement losses of $194 million related to the derivative liabilities that we assumed in the Merger. Settlement losses realized in 2021 were primarily driven by significant price increases in the underlying commodity index prices that occurred during the fourth quarter of 2021.

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, 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 2021 were substantially increased 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 and supply chain disruptions related to the COVID-19 pandemic.

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

Direct Operations

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

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

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Transportation, Processing and Gathering

Transportation, processing and gathering costs principally consist of expenditures to prepare and transport production from the wellhead, including gathering, fuel, compression and processing costs. 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 $92 million due to our expanded operations due to the Merger, offset by a decrease in costs due to lower production in the Marcellus Shale.

Taxes Other Than Income

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

Taxes other than income increased $69 million. Production taxes represented the majority of our taxes other than income, which increased primarily due to the Merger and higher commodity prices. Drilling impact fees increased primarily due to higher natural gas prices.

Depreciation, Depletion and Amortization

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

Depletion of our producing properties is computed on a field basis using the units-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 $290 million due to increased production and a higher depletion rate of $3.97 per MBOE for 2021, both of which are attributable to a significant increase in the value of the oil and gas properties acquired on the closing date of the Merger, compared to $2.61 per MBOE for 2020.

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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 2021 as compared to 2020 is primarily due to increased depreciation on our gathering and plant facilities acquired in the Merger.

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. 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:

General and administrative increased $44 million primarily due to the Merger, which significantly expanded our headcount and office-related expenses.

Periodic 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 primarily due to the acceleration of vesting of certain stock-based awards on closing of the Merger of $10 million and an increase in compensation expense of $9 million related to replacement awards granted to Cimarex employees at the closing of the Merger. These increases were partially offset by lower stock-based compensation expense of $4 million related to the awards that vested at the closing of the Merger.

Merger-related expenses increased $106 million primarily due to $42 million of transaction-related costs (legal and financial advisor costs) associated with the Merger, $20 million of deferred compensation expense related to certain change-in-control payments and $44 million associated with the expected termination of certain Cimarex employees, which is being accrued over the expected transition period.

Other Expenses and Income

Interest Expense, net

Interest expense increased $8 million primarily due to the incremental interest expense, net of premium amortization associated with the debt related to the Merger of $2.2 billion, including the New Coterra Notes and Existing Cimarex Notes. This increase was partially offset by lower interest expense due to repayment of $87 million of our 6.51% weighted-average private placement senior notes, which matured in July 2020, the repayment of $88 million of our 5.58% weighted-average private placement senior notes, which matured in January 2021, and the repayment of $100 million of our 3.65% weighted-average private placement senior notes, which matured in September 2021.

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Income Tax Expense

Income tax expense increased $303 million due to higher pretax income attributable to increased commodity prices and the Merger.

2020 and 2019 Compared

For information on the comparison of the results of operations for the year ended December 31, 2020 compared to the year ended December 31, 2019, refer to Management's Discussion and Analysis included in the Coterra Energy Inc., formerly known as Cabot Oil & Gas Corporation, Annual Report on Form 10-K for the year ended December 31, 2020.