Coterra Energy Inc. - Annual Report: 2022 (Form 10-K)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D. C. 20549

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2022

Commission file number 1-10447

COTERRA ENERGY INC.

(Exact name of registrant as specified in its charter)


Delaware						04-3072771
(State or other jurisdiction of incorporation or organization)						(I.R.S. Employer Identification Number)

Three Memorial City Plaza,

840 Gessner Road, Suite 1400, Houston, Texas 77024

(Address of principal executive offices including ZIP code)

(281) 589-4600

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:


Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common Stock, par value $0.10 per share	CTRA	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☒ No ☐

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer

☒

Accelerated filer

☐

Non-accelerated filer

☐

Smaller reporting company

☐

Emerging growth company

☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No ☒

The aggregate market value of Common Stock, par value $0.10 per share (“Common Stock”), held by non-affiliates as of the last business day of registrant’s most recently completed second fiscal quarter (based upon the closing sales price on the New York Stock Exchange on June 30, 2022) was approximately $20.2 billion.

As of February 24, 2023, there were 768,258,911 shares of Common Stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Proxy Statement for the Annual Meeting of Stockholders to be held May 4, 2023 are incorporated by reference into Part III of this report.

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TABLE OF CONTENTS


		PAGE
PART I
ITEMS 1 and 2	Business and Properties	6
ITEM 1A	Risk Factors	24
ITEM 1B	Unresolved Staff Comments	35
ITEM 3	Legal Proceedings	35
ITEM 4	Mine Safety Disclosures	35
	Information About Our Executive Officers	35
PART II
ITEM 5	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	36
ITEM 6	[Reserved]	39
ITEM 7	Management's Discussion and Analysis of Financial Condition and Results of Operations	39
ITEM 7A	Quantitative and Qualitative Disclosures about Market Risk	53
ITEM 8	Financial Statements and Supplementary Data	56
ITEM 9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	105
ITEM 9A	Controls and Procedures	105
ITEM 9B	Other Information	105
ITEM 9C	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	105
PART III
ITEM 10	Directors, Executive Officers and Corporate Governance	106
ITEM 11	Executive Compensation	106
ITEM 12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	106
ITEM 13	Certain Relationships and Related Transactions, and Director Independence	106
ITEM 14	Principal Accounting Fees and Services	106
PART IV
ITEM 15	Exhibits and Financial Statement Schedules	107
ITEM 16	Form 10-K Summary	110

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FORWARD-LOOKING INFORMATION

This report includes forward-looking statements within the meaning of federal securities laws. All statements, other than statements of historical fact, included in this report are forward-looking statements. Such forward-looking statements include, but are not limited to, statements regarding future financial and operating performance and results, the anticipated effects of, and certain other matters related to, the merger involving Cimarex Energy Co. (“Cimarex”), strategic pursuits and goals, market prices, future hedging and risk management activities, and other statements that are not historical facts contained in this report. The words “expect,” “project,” “estimate,” “believe,” “anticipate,” “intend,” “budget,” “plan,” “forecast,” “target,” “predict,” “potential,” “possible,” “may,” “should,” “could,” “would,” “will,” “strategy,” “outlook” and similar expressions are also intended to identify forward-looking statements. We can provide no assurance that the forward-looking statements contained in this report will occur as expected, and actual results may differ materially from those included in this report. 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. These risks and uncertainties include, without limitation, the impact of public health crises, including pandemics (such as the coronavirus (“COVID-19”) pandemic) and epidemics and any related company or governmental policies or actions, the risk that our and Cimarex’s businesses will not be integrated successfully, the risk that the cost savings and any other synergies from the merger involving Cimarex may not be fully realized or may take longer to realize than expected, the availability of cash on hand and other sources of liquidity to fund our capital expenditures, actions by, or disputes among or between, members of OPEC+, market factors, market prices (including geographic basis differentials) of oil and natural gas, impacts of inflation, labor shortages and economic disruption, including as a result of pandemics and geopolitical disruptions such as the war in Ukraine, results of future drilling and marketing activities, future production and costs, legislative and regulatory initiatives, electronic, cyber or physical security breaches and other factors detailed herein and in our other Securities and Exchange Commission (“SEC”) filings. Additional important risks, uncertainties and other factors are described in “Risk Factors” in Part I. Item 1A of this report. Forward-looking statements are based on the estimates and opinions of management at the time the statements are made. Except to the extent required by applicable law, we undertake no obligation to update or revise any forward-looking statement, whether as a result of new information, future events or otherwise. You are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date hereof.

Investors should note that we announce material financial information in SEC filings, press releases and public conference calls. Based on guidance from the SEC, we may use the Investors section of our website (www.coterra.com) to communicate with investors. It is possible that the financial and other information posted there could be deemed to be material information. The information on our website is not part of, and is not incorporated into, this report.

GLOSSARY OF CERTAIN OIL AND GAS TERMS

The following are abbreviations and definitions of certain terms commonly used in the oil and gas industry and included within this Annual Report on Form 10-K:

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.

Bcf. One billion cubic feet of natural gas.

Boe. Barrels of oil equivalent.

Btu. British thermal units, a measure of heating value.

DD&A. Depletion, depreciation and amortization.

EHS. Environmental, health and safety.

ESG. Environmental, social and governance.

GAAP. Accounting principles generally accepted in the U.S.

GHG. Greenhouse gases.

Hydraulic fracturing. A technology involving the injection of fluids typically including small amounts of several chemical additives as well as sand into a well under high pressure in order to create fractures in the formation that allow oil or natural gas to flow more freely to the wellbore.

MBbl. One thousand barrels of oil or other liquid hydrocarbons.

MBblpd. One thousand barrels of oil or other liquid hydrocarbons per day.

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MBoe. One thousand barrels of oil equivalent.

MBoepd. One thousand barrels of oil equivalent per day.

Mcf. One thousand cubic feet of natural gas.

MMBbl. One million barrels of oil or other liquid hydrocarbons.

MMBoe. One million barrels of oil equivalent.

MMBtu. One million British thermal units.

MMcf. One million cubic feet of natural gas.

MMcfpd. One million cubic feet of natural gas per day.

Net Acres or Net Wells. The sum of the fractional working interest owned in gross acres or gross wells expressed in whole numbers and fractions of whole numbers.

Net Production. Gross production multiplied by net revenue interest.

NGLs. Natural gas liquids.

NYMEX. New York Mercantile Exchange.

NYSE. New York Stock Exchange.

OPEC+. Organization of Petroleum Exporting Countries and other oil exporting nations.

Proved developed reserves. Developed reserves are reserves that can be expected to be recovered: (1) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (2) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Proved reserves. Proved reserves are those quantities, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions and operating methods prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based on future conditions.

Proved undeveloped reserves. Undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

PUD. Proved undeveloped.

SEC. Securities and Exchange Commission.

Tcf. One trillion cubic feet of natural gas.

U.S. United States.

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Waha. Waha West Texas Natural Gas Index price as quoted in Platt’s Inside FERC.

WTI. West Texas Intermediate, a light sweet blend of oil produced from fields in western Texas and is a grade of oil used as a benchmark in oil pricing.

WTI Midland. WTI Midland Index price as quoted by Argus Americas Crude.

Energy equivalent is determined using the ratio of one barrel of crude oil, condensate or NGL to six Mcf of natural gas.

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PART I

ITEMS 1 and 2. BUSINESS AND PROPERTIES

Coterra Energy Inc. (“Coterra,” “our,” “we” and “us”) is an independent oil and gas company engaged in the development, exploration and production of oil, natural gas and NGLs. Our assets are concentrated in areas with known hydrocarbon resources, which are conducive to multi-well, repeatable development programs. We operate in one segment, oil and natural gas development, exploration and production, in the continental U.S.

Our headquarters is located in Houston, Texas. We also maintain regional offices in Pittsburgh, Pennsylvania, Midland, Texas, and Tulsa, Oklahoma, as well as field offices near our operations.

On October 1, 2021, we completed a merger transaction (the “Merger”) with Cimarex. 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 relating to the Merger (the “Merger Agreement”), and subject to certain exceptions specified in the Merger Agreement, each eligible share of Cimarex common stock was converted into the right to receive 4.0146 shares of our common stock at closing. 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 certain previously outstanding Cimarex restricted share awards). Additionally, on October 1, 2021, we changed our name to Coterra Energy Inc.

Operational information set forth in this Annual Report on Form 10-K does not include the activity of Cimarex for periods prior to the completion of the Merger.

STRATEGY

Coterra is a premier U.S.-focused exploration and production company. We embrace innovation, technology and data, as we work to create value for our investors and the communities where we operate. We believe the following strategic priorities will help drive value creation and long-term success.

Generate Sustainable Returns. Our premier assets across multiple basins provide commodity diversification and strong cash flow generation through the commodity price cycles that, combined with our disciplined capital investment, give us the confidence in our ability to provide returns to our stockholders that we believe to be sustainable. Demonstrating our confidence in our business model, we increased our annual base dividend on our common stock to $0.50 per share following the consummation of the Merger, followed by an increase in February 2022 to $0.60 per share and an additional increase in February 2023 to $0.80 per share. From October 1, 2021 through our recent February 2023 dividend announcement, we will have returned approximately $3.2 billion to stockholders through our base, variable and special dividends. Furthermore, consistent with our returns-focused strategy, in February 2022, our Board of Directors approved a $1.25 billion share repurchase program, which was used to repurchase 48 million shares of our common stock, and was fully utilized by December 31, 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. During 2022, we returned $4.06 per share to stockholders via dividend payments and share repurchases. Coterra remains committed to returning 50 percent or more of our free cash flow to our stockholders through our base dividend, share repurchase program, and/or a variable dividend.

Disciplined Capital Allocation Across Top-Tier Position. We believe our asset portfolio offers scale, capital optionality and low break-even investment options. We anticipate our drilling inventory will be developed over the coming decades at the current run-rate. We are committed to maintaining a disciplined capital investment strategy and using technology and innovation to maximize capital efficiency and operational execution. We believe that having three operating areas of scale, the Permian Basin, Marcellus Shale and Anadarko Basin, offers diversity of geography, commodity and revenue streams to allocate our capital, which should support strong and stable cash flow generation through commodity price cycles. During 2022, we invested 31 percent of our cash flow from operations in our drilling program and in 2023 expect to invest approximately 50 percent of our estimated cash flow from operations, based on current strip prices.

Maintain Financial Strength. We believe that maintaining an industry-leading balance sheet with significant financial flexibility is imperative in a cyclical industry exposed to commodity price volatility. We believe our asset base, revenue diversity, low-cost structure and strong balance sheet provide us the flexibility we need to thrive across various commodity price environments. During 2022, we retired $874 million of outstanding debt. With no significant debt maturities until 2024, a year-end 2022 cash balance of $673 million and $1.5 billion of unused commitments under our revolving credit facility, we believe we are well positioned to maintain our balance sheet strength.

Focus on Safe, Responsible and Sustainable Operations. We believe responsible development of oil and natural gas resources provides opportunity for a bright future, one built through technology and innovation that offers prosperity for

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communities around the world. Our operational focus is based on making our operations more environmentally and socially sustainable by actively implementing technology across our operations from design phase to equipment improvements to limit and reduce our methane emissions and flaring activity. Our safety programs are built on a foundation that emphasizes personal safety and includes a Stop Work Authority program that empowers employees and contractors to stop work if they discover a dangerous condition or other serious EHS hazard. In addition, we focus on practical and sustainable environmental initiatives that promote efficient use of water and help to protect water quality, eliminate or mitigate releases, and minimize land surface impact. We are committed to being responsible stewards of our resources and implementing sustainable practices under the guidance of our management team and our diverse and experienced Board of Directors. We have published our 2022 Sustainability Report, which includes more information related to our sustainability practices, on our website at www.coterra.com. The information on our website is not part of, and is not incorporated into, this report on Form 10-K or any other report we may file with or furnish to the SEC (and is not deemed filed herewith), whether before or after the date of this report on Form 10-K and irrespective of any general incorporation language therein.

2023 OUTLOOK

DESCRIPTION OF PROPERTIES

Our operations are primarily concentrated in three operating areas—the Permian Basin in west Texas and southern New Mexico, the Marcellus Shale in northeast Pennsylvania and the Anadarko Basin in the Mid-Continent region in Oklahoma.

Permian Basin

Our Permian Basin properties are principally located in the western half of the Permian Basin known as the Delaware Basin where we currently hold approximately 307,000 net acres in the play. Our development activities are primarily focused on the Wolfcamp Shale and the Bone Spring formation in Culberson and Reeves Counties in Texas and Lea and Eddy Counties in New Mexico. Our 2022 net production in the Permian Basin was 211 MBoepd, representing 33 percent of our total equivalent production for the year. As of December 31, 2022, we had a total of 1,056.3 net wells in the Permian Basin, of which approximately 88 percent are operated by us.

During 2022, we invested $791 million in the Permian Basin, where we exited 2022 with six drilling rigs operating in the play and plan to exit 2023 with six rigs operating.

Marcellus Shale

Our Marcellus Shale properties are principally located in Susquehanna County, Pennsylvania, where we currently hold approximately 183,000 net acres in the dry gas window in the Marcellus Shale. Our 2022 net production in the Marcellus was 367 MBoepd, representing 58 percent of our total equivalent production for the year. As of December 31, 2022, we had a total of 1,024.2 net wells in the Marcellus Shale, of which approximately 99 percent are operated by us.

During 2022, we invested $813 million in the Marcellus Shale, where we exited 2022 with two drilling rigs operating in the play and plan to exit 2023 with two rigs operating.

Anadarko Basin

Our Anadarko Basin properties are principally located in Oklahoma where we currently hold approximately 182,000 net acres in the play. Our development activities are primarily focused on the Woodford Shale and the Meramec formation, both in Oklahoma. Our 2022 net production in the Anadarko Basin was 55 MBoepd, representing nine percent of our total equivalent production for the year. As of December 31, 2022, we had a total of 511.4 net wells in the Anadarko Basin, of which approximately 60 percent are operated by us.

During 2022, we invested $121 million in the Anadarko Basin. At the end of 2022, we had one rig operating in the play for a multi-well program expected to run through mid-2023.

Other Properties

Ancillary to our exploration, development and production operations, we operate a number of natural gas gathering and saltwater gathering and disposal systems. The majority of our gathering infrastructure is located in Texas and directly supports our Permian Basin operations. Our gathering systems enable us to connect new wells quickly and to transport natural gas from

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the wellhead directly to interstate pipelines and natural gas processing facilities and to transport water produced along with oil and gas (“produced water”) for re-use in completions activities and to disposal facilities. Control of our gathering pipeline systems also enables us to transport natural gas produced by third parties. In addition, we can engage in development drilling without relying on third parties to transport our natural gas or produced water and incur only the incremental costs of pipeline and compressor additions to our system.

MARKETING

Substantially all of our oil and natural gas production is sold at market sensitive prices under both long-term and short-term sales contracts. We sell oil, natural gas and NGLs to a broad portfolio of customers, including industrial customers, local distribution companies, oil and gas marketers, major energy companies, pipeline companies and power generation facilities.

Demand for natural gas has historically been seasonal, with peak demand and typically higher prices occurring during the winter months.

We also incur transportation and gathering expenses to move our oil and natural gas production from the wellhead to our principal markets in the U.S. The majority of our Marcellus Shale and Anadarko Basin natural gas production is gathered on third-party gathering systems, while the majority of our Permian Basin natural gas production is gathered on company-owned and operated gathering systems. Most of our natural gas is transported on interstate pipelines where we have long-term contractual capacity arrangements or use purchaser-owned capacity under both long-term and short-term sales contracts.

To date, we have not experienced significant difficulty in transporting or marketing our production as it becomes available; however, there is no assurance that we will always be able to transport and market all of our production.

Delivery Commitments

We have entered into various firm sales contracts to deliver and sell natural gas. We believe we will have sufficient production quantities to meet substantially all of our commitments, but may be required to purchase natural gas from third parties to satisfy shortfalls should they occur.

A summary of our firm sales commitments as of December 31, 2022 are set forth in the table below:


						Natural Gas (in Bcf)
2023						644
2024						601
2025						577
2026						572
2027						549

We utilize a part of our firm transportation capacity to deliver natural gas under the majority of these firm sales contracts and have entered into numerous agreements for transportation of our production. Some of these contracts have volumetric requirements which could require monetary shortfall penalties if our production is inadequate to meet the terms. However, we do not believe we will have any financial commitment due based on our current proved reserves and production levels from which we can fulfill these obligations.

RISK MANAGEMENT

From time to time, we use derivative financial instruments to manage price risk associated with our oil and natural gas production. Although there are many different types of derivatives available, we generally utilize collar, swap and basis swap agreements designed to assist us in managing price risk. The collar arrangements are a combination of put and call options used to establish floor and ceiling prices for a fixed volume of production during a certain time period. They provide for payments to counterparties if the index price exceeds the ceiling and payments from the counterparties if the index price falls below the floor. The swap agreements call for payments to, or receipts from, counterparties based on whether the index price for the period is greater or less than the fixed price established for the particular period under the swap agreement.

During 2022, natural gas collars with floor prices ranging from $1.70 to $8.50 per MMBtu and ceiling prices ranging from $2.10 to $13.08 per MMBtu covered 245.8 Bcf, or 24 percent, of natural gas production at a weighted-average price of $4.94 per MMBtu. Natural gas swaps covered 14.9 Bcf, or one percent, of natural gas production at a weighted-average price of $2.26 per MMBtu.

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During 2022, oil collars with floor prices ranging from $35.00 to $90.00 per Bbl and ceiling prices ranging from $45.15 to $145.25 per Bbl covered 9.7 MMBbls, or 31 percent, of oil production at a weighted-average price of $55.00 per Bbl. Oil basis swaps covered 8.7 MMBbls, or 27 percent, of oil production at a weighted-average price of $0.30 per Bbl. Oil roll differential swaps covered 2.7 MMBbls, or 9 percent, of oil production at a weighted-average price of $(0.02) per Bbl.

As of December 31, 2022, we had the following outstanding financial commodity derivatives:



	2023
Natural Gas	First Quarter		Second Quarter		Third Quarter		Fourth Quarter




Waha gas collars
Volume (MMBtu)	8,100,000		8,190,000		8,280,000		8,280,000
Weighted average floor ($/MMBtu)	$	3.03	$	3.03	$	3.03	$	3.03
Weighted average ceiling ($/MMBtu)	$	5.39	$	5.39	$	5.39	$	5.39

NYMEX collars
Volume (MMBtu)	54,000,000		31,850,000		32,200,000		29,150,000
Weighted average floor ($/MMBtu)	$	5.12	$	4.07	$	4.07	$	4.03
Weighted average ceiling ($/MMBtu)	$	9.34	$	6.78	$	6.78	$	6.61



	2023
Oil	First Quarter		Second Quarter
WTI oil collars
Volume (MBbl)	1,350		1,365
Weighted average floor ($/Bbl)	$	70.00	$	70.00
Weighted average ceiling ($/Bbl)	$	116.03	$	116.03

WTI Midland oil basis swaps
Volume (MBbl)	1,350		1,365
Weighted average differential ($/Bbl)	$	0.63	$	0.63

A significant portion of our expected oil and natural gas production for 2023 and beyond is currently unhedged and directly exposed to the volatility in oil and natural gas prices, whether favorable or unfavorable. We will continue to evaluate the benefit of using derivatives in the future. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Quantitative and Qualitative Disclosures about Market Risk” for further discussion related to our use of derivatives.

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PROVED OIL AND GAS RESERVES

The following table presents our estimated proved reserves by commodity as of the dates indicated:


	December 31,
	2022	2021	2020
Oil (MBbl)
Proved developed reserves	168,649	153,010	—
Proved undeveloped reserves	71,107	36,419	—
	239,756	189,429	—
Natural Gas (Bcf)
Proved developed reserves	8,543	10,691	8,608
Proved undeveloped reserves	2,630	4,204	5,064
	11,173	14,895	13,672
NGLs (MBbl)
Proved developed reserves	224,706	193,598	—
Proved undeveloped reserves	72,059	27,017	—
	296,765	220,615,000	—

Oil equivalent (MBoe)	2,398,666	2,892,582	2,278,636

At December 31, 2022, our Dimock field, which is located in the Marcellus Shale in Susquehanna County, Pennsylvania, contained approximately 62 percent of our total proved reserves.

For additional information regarding estimates of our net proved and proved undeveloped reserves, the qualifications of the preparers of our reserves estimates, the evaluation of such estimates by our independent petroleum consultants, our processes and controls with respect to our reserves estimates and other information about our reserves, including the risks inherent in our estimates of proved reserves, refer to the Supplemental Oil and Gas Information included in Item 8 and “Risk Factors—Business and Operational Risks—Our proved reserves are estimates. Any material inaccuracies in our reserves estimates or underlying assumptions could cause the quantities and net present value of our reserves to be overstated or understated” in Item 1A.

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PRODUCTION, SALES PRICE AND PRODUCTION COSTS

The following table presents historical information about our total and average daily production volumes for oil, natural gas and NGLs; average oil, natural gas and NGL sales prices; and average production costs per equivalent:


	Year Ended December 31,
	2022		2021 (1)		2020
Production Volumes
Oil (MBbl)	31,926		8,150		—
Natural gas (Bcf)	1,024		911		858
NGL (MBbl)	28,697		7,104		—
Equivalents (MBoe)	231,342		167,113		142,954

Average Daily Production Volumes
Oil (MBbl)	87		89		—
Natural gas (MMcf)	2,806		2,492		2,344
NGL (MBbl)	79		77		—
Equivalents (MBoe)	634		660		391

Average Sales Price
Excluding Derivative Settlements
Oil ($/Bbl)	$	94.47	$	75.61	$	—
Natural gas ($/Mcf)	$	5.34	$	3.07	$	1.64
NGL ($/Bbl)	$	33.58	$	34.18	$	—
Including Derivative Settlements
Oil ($/Bbl)	$	84.33	$	60.35	$	—
Natural gas ($/Mcf)	$	4.91	$	2.73	$	1.68
NGL ($/Bbl)	$	33.58	$	34.18	$	—

Average Production Costs ($/Boe)	$	1.84	$	0.77	$	0.36

_______________________________________________________________________________

(1)On October 1, 2021, we completed the Merger. The production information presented in this table includes Cimarex production for the period subsequent to that date.

The following table presents historical information about our total and average daily natural gas production volumes associated with our interests in the Dimock field in the Marcellus Shale, which contains 15 percent or more of our total proved reserves. There was no oil or NGL production associated with our interests in the Dimock field:


	Year Ended December 31,
	2022	2021	2020
Production Volumes

Natural gas (Bcf)	805	853	858

Equivalents (MBoe)	134,097	142,223	142,954

Average Daily Production Volumes

Natural gas (MMcf)	2,204	2,338	2,344

Equivalents (MBoe)	367	390	391

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ACREAGE

Our interest in both developed and undeveloped properties is primarily in the form of leasehold interests held under customary mineral leases. These leases provide us the right to develop oil and/or natural gas on the properties. Their primary terms generally range in length from approximately three to 10 years. These properties are held for longer periods if production is established.

The following table summarizes our gross and net developed and undeveloped leasehold acreage at December 31, 2022:


	Acreage
	Developed		Undeveloped		Total
	Gross	Net	Gross	Net	Gross	Net
Permian Basin
New Mexico	155,066	111,768	55,419	38,813	210,485	150,581
Texas	204,971	136,845	23,999	19,354	228,970	156,199
	360,037	248,613	79,418	58,167	439,455	306,780
Marcellus Shale
Pennsylvania	165,999	165,180	19,334	17,790	185,333	182,970


Anadarko Basin

Oklahoma	320,080	146,987	72,740	35,428	392,820	182,415



Other
Arizona	17,207	17,207	2,097,841	2,097,841	2,115,048	2,115,048
California	—	—	383,487	383,487	383,487	383,487
Colorado	4,208	1,363	25,352	18,767	29,560	20,130
Kentucky	122	92	22,436	19,222	22,558	19,314
Montana	7,397	1,606	27,137	8,180	34,534	9,786
Nevada	440	1	1,007,167	1,007,167	1,007,607	1,007,168
New Mexico	10,655	2,436	1,640,195	1,634,459	1,650,850	1,636,895
Offshore Gulf of Mexico	18,853	7,005	15,000	9,000	33,853	16,005
Pennsylvania	—	—	111,422	62,884	111,422	62,884
Texas	45,091	12,361	22,520	17,009	67,611	29,370
Utah	4,803	1,442	61,320	57,177	66,123	58,619
West Virginia	—	—	623,295	591,426	623,295	591,426
Wyoming	22,071	2,345	79,522	23,751	101,593	26,096
Other	8,435	1,714	57,097	30,275	65,532	31,989
	139,282	47,572	6,173,791	5,960,645	6,313,073	6,008,217
	985,398	608,352	6,345,283	6,072,030	7,330,681	6,680,382

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Total Net Undeveloped Acreage Expiration

The table below summarizes by year and operating area our undeveloped acreage expirations in the next three years. In most cases, the drilling of a commercial well will hold the acreage beyond the expiration.


	Acreage
	2023				2024				2025
	Gross		Net		Gross		Net		Gross		Net
Permian Basin	960		960		3		3		—		—
Marcellus Shale	1,970		1,968		1,670		1,566		2,084		2,080
Anadarko Basin	4,097		934		700		134		520		125
Other	7,725		6,697		1,302		1,241		—		—
	14,752		10,559		3,675		2,944		2,604		2,205

Percentage of total undeveloped acreage	—	%	—	%	—	%	—	%	—	%	—	%

At December 31, 2022, we had no PUD reserves recorded on undeveloped acreage that were scheduled for development beyond the expiration dates of the undeveloped acreage or outside of our primary operating area.

WELL SUMMARY

The following table presents our ownership in productive oil and natural gas wells at December 31, 2022. This summary includes oil and natural gas wells in which we have a working interest:


	Gross	Net
Natural Gas	3,268	1,800.2
Oil	2,421	793.1
Total(1)	5,689	2,593.3

_______________________________________________________________________________

(1)Total percentage of gross and net operated wells is 49 percent and 87 percent, respectively.

DRILLING ACTIVITY

We drilled and completed wells or participated in the drilling and completion of wells as indicated in the table below. During the years presented below, we did not drill and complete any exploration wells. The information below should not be considered indicative of future performance, nor should a correlation be assumed between the number of productive wells drilled, quantities of reserves found or economic value.


	Year Ended December 31,
	2022		2021		2020
	Gross	Net	Gross	Net	Gross	Net
Development Wells
Productive	284	173.9	114	99.9	74	64.3
Dry	1	0.7	—	—	—	—



Total	285	174.6	114	99.9	74	64.3

Acquired Wells	—	—	7,266	1,715.3	—	—

During the year ended December 31, 2022, we completed 58 gross wells (37.2 net) that were drilled in prior years.

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The following table sets forth information about wells for which drilling was in progress or which were drilled but uncompleted at December 31, 2022, which are not included in the above table:

Drilling In Progress

Drilled But Uncompleted

Gross

Net

Gross

Net

Development wells

28.0

63.1

OTHER BUSINESS MATTERS

Title to Properties

We believe that we have satisfactory title to all of our producing properties in accordance with generally accepted industry standards. Individual properties may be subject to burdens such as royalty, overriding royalty, carried, net profits, working and other outstanding interests customary in the industry. In addition, interests may be subject to obligations or duties under applicable laws or burdens such as production payments, ordinary course liens incidental to operating agreements and for current taxes or development obligations under oil and gas leases. As is customary in the industry in the case of undeveloped properties, we conduct preliminary investigations of record title at the time of lease acquisition. We conduct more complete investigations prior to the consummation of an acquisition of producing properties and before commencement of drilling operations on undeveloped properties.

Competition

The oil and gas industry is highly competitive, and we experience strong competition in our primary producing areas. We primarily compete with integrated, independent and other energy companies for the sale and transportation of our oil and natural gas production to pipelines, marketing companies and end users. Furthermore, the oil and gas industry competes with other energy industries that supply fuel and power to industrial, commercial and residential consumers. Many of these competitors have greater financial, technical and personnel resources than we have. The effect of these competitive factors cannot be predicted.

Price, contract terms, availability of rigs and related equipment and quality of service, including pipeline connection times and distribution efficiencies affect competition. We believe that our concentrated acreage positions and our access to both third-party and company-owned gathering and pipeline infrastructure in our primary operating areas, along with our expected activity level and the related services and equipment that we have secured for the upcoming years, enhance our competitive position compared to other producers who do not have similar systems or services in place.

Major Customers

During the year ended December 31, 2022, two customers accounted for approximately 13 percent and 11 percent of our total sales. During the year ended December 31, 2021, no customer accounted for more than 10 percent of our total sales. If any one of our major customers were to stop purchasing our production, we believe there are a number of other purchasers to whom we could sell our production. If multiple significant customers were to stop purchasing our production, we believe there could be some initial challenges, but we have sufficient alternative markets to handle any sales disruptions.

We regularly monitor the creditworthiness of our customers and may require parent company guarantees, letters of credit or prepayments when necessary. Historically, losses associated with uncollectible receivables have not been significant.

Regulation of Oil and Natural Gas Exploration and Production

Exploration and production operations are subject to various types of regulation at the federal, state and local levels. This regulation includes requiring permits to drill wells, maintaining bonding requirements to drill or operate wells, regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties on which wells are drilled and the plugging and abandoning of wells. Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, the density of wells that may be drilled in a given field and the unitization or pooling of oil and gas properties. Some states allow the forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibiting the venting or flaring of natural gas and imposing certain requirements regarding the ratability of production. The effect of these regulations is to limit the amounts of oil and natural gas we can produce from our wells, and to limit the number of wells or the locations where we can drill. Because these statutes, rules and regulations undergo frequent review and often are amended, expanded and reinterpreted, we are unable to predict the future cost or impact of regulatory compliance. The regulatory burden on the oil and

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gas industry increases our cost of doing business and, consequently, affects our profitability. We do not believe, however, we are affected differently by these regulations than others in the industry.

Regulation of Natural Gas Marketing, Gathering and Transportation

Federal legislation and regulatory controls have historically affected the price of the natural gas we produce and the manner in which our production is transported and marketed. Under the U.S. Natural Gas Act of 1938 (the “NGA”), the U.S. Natural Gas Policy Act of 1978 (the “NGPA”) and the regulations promulgated under those statutes, the U.S. Federal Energy Regulatory Commission (the “FERC”) regulates the interstate sale for resale of natural gas and the transportation of natural gas in interstate commerce, although facilities used in the production or gathering of natural gas in interstate commerce are generally exempted from FERC jurisdiction. Effective beginning in January 1993, the Natural Gas Wellhead Decontrol Act deregulated natural gas prices for all “first sales” of natural gas, which definition covers all sales of our own production. In addition, as part of the broad industry restructuring initiatives described below, the FERC granted to all producers such as us a “blanket certificate of public convenience and necessity” authorizing the sale of natural gas for resale without further FERC approvals. As a result of this policy, all of our produced natural gas is sold at market prices, subject to the terms of any private contracts that may be in effect. In addition, under the provisions of the Energy Policy Act of 2005 (“2005 Act”), the NGA was amended to prohibit any forms of market manipulation in connection with the purchase or sale of natural gas. Pursuant to the 2005 Act, the FERC established regulations intended to increase natural gas pricing transparency by, among other things, requiring market participants to report their gas sales transactions annually to the FERC. The 2005 Act also significantly increased the penalties for violations of the NGA and NGPA and the FERC’s regulations thereunder up to $1 million per day per violation. This maximum penalty authority established by statute has been and will continue to be adjusted periodically for inflation. The current maximum penalty is over $1 million per day per violation. In 2010, the FERC issued Penalty Guidelines for the determination of civil penalties and procedure under its enforcement program.

Under the NGPA, natural gas gathering facilities are expressly exempt from FERC jurisdiction. What constitutes “gathering” under the NGPA has evolved through FERC decisions and judicial review of such decisions. We believe that our gathering and production facilities meet the test for non-jurisdictional “gathering” systems under the NGPA and that our facilities are not subject to federal regulations. Although exempt from FERC oversight, our natural gas gathering systems and services may receive regulatory scrutiny by state and federal agencies regarding the safety and operating aspects of the transportation and storage activities of these facilities.

Our natural gas sales prices continue to be affected by intrastate and interstate gas transportation regulation because the cost of transporting the natural gas once sold to the consuming market is a factor in the prices we receive. Beginning with Order No. 436 in 1985 and continuing through Order No. 636 in 1992 and Order No. 637 in 2000, the FERC has adopted a series of rule makings that have significantly altered the transportation and marketing of natural gas. These changes were intended by the FERC to foster competition by, among other things, requiring interstate pipeline companies to separate their wholesale gas marketing business from their gas transportation business and by increasing the transparency of pricing for pipeline services. The FERC has also established regulations governing the relationship of pipelines with their marketing affiliates, which essentially require that designated employees function independently of each other and that certain information not be shared. The FERC has also implemented standards relating to the use of electronic data exchange by the pipelines to make transportation information available on a timely basis and to enable transactions to occur on a purely electronic basis.

In light of these statutory and regulatory changes, most pipelines have divested their natural gas sales functions to marketing affiliates, which operate separately from the transporter and in direct competition with all other merchants. Most pipelines have also implemented the large‑scale divestiture of their natural gas gathering facilities to affiliated or non-affiliated companies. Interstate pipelines are required to provide unbundled, open and nondiscriminatory transportation and transportation‑related services to producers, gas marketing companies, local distribution companies, industrial end users and other customers seeking such services. As a result of the FERC requiring natural gas pipeline companies to separate marketing and transportation services, sellers and buyers of natural gas have gained direct access to pipeline transportation services, and are better able to conduct business with a larger number of counterparties. We believe these changes generally have improved our access to markets while, at the same time, substantially increasing competition in the natural gas marketplace. We cannot predict what new or different regulations the FERC and other regulatory agencies may adopt, or what effect subsequent regulations may have on our activities. Similarly, we cannot predict what proposals, if any, that affect the oil and natural gas industry might actually be enacted by the U.S. Congress or the various state legislatures and what effect, if any, such proposals might have on us. Further, we cannot predict whether the recent trend toward federal deregulation of the natural gas industry will continue or what effect future policies will have on our sale of gas.

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Federal Regulation of Swap Transactions

We use derivative financial instruments such as collar, swap and basis swap agreements to attempt to more effectively manage price risk due to the impact of changes in commodity prices on our operating results and cash flows. The Dodd‑Frank Wall Street Reform and Consumer Protection Act (“Dodd‑Frank Act”) enacted comprehensive financial reform, establishing federal oversight over and regulation of the over-the-counter derivatives market (which includes the sorts of financial instruments we use) and participants in the market. The Commodity Futures Trading Commission (the “CFTC”) has promulgated regulations to implement these reforms. While most of the regulations have been promulgated and are already in effect, the rulemaking and implementation process is still ongoing. We believe that our use of swaps to hedge against commodity exposure qualifies us as an end‑user, exempting us from the requirement to centrally clear our swaps. Nevertheless, the changes to other elements in the derivatives markets as a result of Dodd‑Frank and its current and ongoing implementation could significantly increase the cost of derivative contracts, limit the availability of derivatives to protect against risks that we encounter, reduce our ability to monetize or restructure our existing derivative contracts and increase our exposure to less creditworthy counterparties. If we reduce our use of swaps, our results of operations may become more volatile and our cash flows may be less predictable.

Federal Regulation of Petroleum

Sales of crude oil and NGLs are not regulated and are made at market prices. However, the price received from the sale of these products is affected by the cost of transporting the products to market. Much of that transportation is through interstate common carrier pipelines, which are regulated by the FERC under the Interstate Commerce Act (“ICA”). The FERC requires that pipelines regulated under the ICA file tariffs setting forth the rates and terms and conditions of service and that such service not be unduly discriminatory or preferential.

Effective January 1, 1995, the FERC implemented regulations generally grandfathering all previously approved interstate transportation rates and establishing an indexing system for those rates by which adjustments are made annually based on the rate of inflation, subject to certain conditions and limitations. These regulations may increase or decrease the cost of transporting crude oil and NGLs by interstate pipeline. Every five years, the FERC must examine the relationship between the annual change in the applicable index and the actual cost changes experienced in the oil pipeline industry. In December 2015, to implement this required five‑year redetermination, the FERC established an upward adjustment in the index to track oil pipeline cost changes and determined that the Producer Price Index for Finished Goods plus 1.23 percent should be the oil pricing index for the five‑year period beginning July 1, 2016. In 2020, the FERC concluded its five-year index review to establish the new adder for crude oil and liquids pipeline rates subject to indexing. The FERC issued an order on December 17, 2020 establishing an index level of Producer Price Index for Finished Goods plus 0.78 percent for the five-year period commencing July 1, 2021. The result of indexing is a “ceiling rate” for each rate, which is the maximum at which the pipeline may set its interstate transportation rates. A pipeline may also file cost‑of‑service based rates if rate indexing will be insufficient to allow the pipeline to recover its costs. Rates are subject to challenge by protest when they are filed or changed. For indexed rates, complaints alleging that the rates are unjust and unreasonable may only be pursued if the complainant can show that a substantial change has occurred since the enactment of Energy Policy Act of 1992 in either the economic circumstances of the pipeline or in the nature of the services provided that were a basis for the rate. There is no such limitation on complaints alleging that the pipeline’s rates or terms and conditions of service are unduly discriminatory or preferential. We are unable to predict with certainty the effect upon us of these periodic reviews by the FERC of the pipeline index, or any potential future challenges to pipelines’ rates.

Environmental and Safety Regulations

General. Our operations are subject to extensive and stringent federal, state and local laws and regulations governing the protection of the environment. These laws and regulations can change, restrict or otherwise impact our business in many ways, including the handling or disposal of waste material, planning for future activities to avoid or mitigate harm to threatened or endangered species, and requiring the installation and operation of emissions or pollution control equipment. Failure to comply with these laws and regulations could result in the assessment of administrative, civil and criminal penalties, the imposition of remedial requirements and the issuance of orders enjoining future operations. Permits are required for the operation of our various facilities. These permits can be revoked, modified or renewed by issuing authorities. Governmental authorities enforce compliance with their regulations through fines, injunctions or both. Government regulations can increase the cost of planning, designing, installing and operating, and can affect the timing of installing and operating, oil and natural gas facilities. Although we believe that compliance with environmental regulations will not have a material adverse effect on us, risks of substantial costs and liabilities and potential suspension or cessation of operations under certain conditions related to environmental considerations or compliance issues are part of oil and natural gas production operations. We can provide no assurance that significant costs and liabilities will not be incurred. Also, it is possible that other developments, such as stricter environmental

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laws and regulations, and claims for damages to property or persons resulting from oil and natural gas production could result in substantial costs and liabilities to us.

Solid and Hazardous Waste. We currently own or lease, and have in the past owned or leased, numerous properties that were used for the production of oil and natural gas for many years. Although operating and disposal practices that were standard in the industry at the time may have been utilized, it is possible that hydrocarbons or other wastes may have been disposed of or released on or under the properties currently owned or leased by us. State and federal laws applicable to oil and gas wastes and properties have become stricter over time. Under these increasingly stringent requirements, we could be required to remove or remediate previously disposed wastes (including wastes disposed or released by prior owners and operators) or clean up property contamination (including groundwater contamination by prior owners or operators) or to perform plugging operations to prevent future contamination.

We generate some wastes that are hazardous wastes subject to the Resource Conservation and Recovery Act (the “RCRA”) and comparable state statutes, as well as wastes that are exempt from such regulation. The U.S. Environmental Protection Agency (the “EPA”) limits the disposal options for certain hazardous wastes. It is possible that certain wastes currently exempt from regulation as hazardous wastes may in the future be designated as hazardous wastes under RCRA or other applicable statutes. For example, in December 2016, the EPA and environmental groups entered into a consent decree to address the EPA’s alleged failure to timely assess the need to regulate exploration and production related oil and gas wastes exempt from regulation as hazardous wastes under RCRA under Subtitle D applicable to non-hazardous solid waste. The consent decree required the EPA to propose a rulemaking by March 2019 for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or to sign a determination that revision of the regulations is not necessary. In April 2019, the EPA issued its determination that based on its review, including consideration of state regulatory programs, it was not necessary at the time to revise Subtitle D regulations to address the management of oil and gas wastes. In the future, we could be subject to more rigorous and costly disposal requirements than we encounter today.

Superfund. The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the “Superfund” law, and comparable state laws and regulations impose liability, without regard to fault or the legality of the original conduct, on certain persons with respect to the release of hazardous substances into the environment. These persons include the current and past owners and operators of a site where the release occurred and any party that treated or disposed of or arranged for the treatment or disposal of hazardous substances found at a site. Under CERCLA, such persons may be subject to joint and several strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the EPA, and in some cases, private parties, to undertake actions to clean up such hazardous substances, or to recover the costs of such actions from the responsible parties. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In the course of business, we have used materials and generated wastes and will continue to use materials and generate wastes that may fall within CERCLA’s hazardous substances definition. We may also be an owner or operator of sites on which hazardous substances have been released. As a result, we may be responsible under CERCLA for all or part of the costs to clean up sites where such substances have been released.

Oil Pollution Act. The Oil Pollution Act of 1990 (the “OPA”) and implementing regulations impose a variety of obligations on responsible parties related to the prevention of oil spills and liability for damages resulting from such spills in waters of the U.S. The term “waters of the U.S.” has been broadly defined to include inland water bodies, including wetlands and intermittent streams. The OPA assigns joint and several strict liability to each responsible party for oil removal costs and a variety of public and private damages. The OPA also imposes ongoing requirements on operators, including the preparation of oil spill response plans and proof of financial responsibility to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill. We believe that we are in substantial compliance with the OPA and related federal regulations to the extent applicable to our operations.

Endangered Species Act. The Endangered Species Act (the “ESA”) was established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. The U.S. Fish and Wildlife Service (the “FWS”) may designate critical habitat and suitable habitat areas it believes are necessary for survival of a threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to federal land use and may materially delay or prohibit land access for oil and gas development. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act, to bald and golden eagles under the Bald and Golden Eagle Protection Act, and to certain species under state law. We conduct operations in areas where certain species are currently listed as threatened or endangered, or could be listed as such, under the ESA. Operations in areas where threatened or endangered species or their habitat are known to exist may require us to incur increased costs to implement mitigation or protective measures and also may restrict or preclude our drilling activities in those areas or during certain seasons, such as breeding and nesting seasons.

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On June 1, 2021, the FWS proposed to list two distinct population segments (“DPS”) of the lesser prairie-chicken under the ESA. The Southern DPS, located in eastern New Mexico and the southwest Texas panhandle was proposed to be listed as endangered and the Northern DPS, located in southeastern Colorado, southcentral to southwestern Kansas, western Oklahoma and the northeast Texas panhandle, was proposed to be listed as threatened. On November 25, 2022, the FWS finalized the proposed rule, listing the southern DPS of the lesser prairie-chicken as endangered and the northern DPS of the lesser prairie-chicken as threatened. Listing of the lesser prairie-chicken as a threatened or endangered species will impose restrictions on disturbances to critical habitat by landowners and drilling companies that would harass, harm or otherwise result in a “taking” of this species. Regulatory impacts on landowners and businesses from an ultimate decision to list the lesser prairie-chicken could be limited for those landowners and businesses who have entered into certain range-wide conservation planning agreements, such as those developed by the Western Association of Fish and Wildlife Agencies (“WAFWA”), pursuant to which such parties agreed to take steps to protect the lesser prairie-chicken’s habitat and to pay a mitigation fee if its actions harm the lesser prairie-chicken’s habitat. We have entered into a voluntary Candidate Conservation Agreement (a “CCA”) with the WAFWA, whereby we agreed to take certain actions and limit certain activities, such as limiting drilling on certain portions of our acreage during nesting seasons, in an effort to protect the lesser prairie-chicken.

On February 9, 2018, the FWS announced the listing of the Texas Hornshell, a freshwater mussel species in areas where we operate in the Permian Basin, including New Mexico and Texas, as an endangered species. In March 2018, we entered into a CCA concerning voluntary conservation actions with respect to the Texas Hornshell.

Participating in CCAs could result in increased costs to us from species protection measures, time delays or limitations on drilling activities, which costs, delays or limitations may be significant. Listing petitions continue to be filed with the FWS which could impact our operations. Many non-governmental organizations (“NGOs”) work closely with the FWS regarding the listing of many species, including species with broad and even nationwide ranges. The listing of the Mexican Long Nosed Bat, whose habitat includes the Permian Basin where we operate, and the Dunes Sagebrush Lizard in the Permian Basin, are examples of the NGOs’ influence on ESA listing decisions.

On December 1, 2020, the FWS proposed to list the Peppered Chub as endangered under the ESA. The proposed listing was finalized and published on February 28, 2022. The Peppered Chub is a freshwater fish that historically was found in the South Canadian, Cimarron and Arkansas rivers within New Mexico, Texas, Oklahoma and Kansas. We have operations near the South Canadian river in Oklahoma that may be impacted by the listing of the Peppered Chub as endangered. The increase in endangered species listings, such as the Peppered Chub, may limit our ability to explore for or produce oil and gas in certain areas or cause us to incur additional costs.

Clean Water Act. The Federal Water Pollution Control Act (the “Clean Water Act”) and implementing regulations, which are primarily executed through a system of permits, also govern the discharge of certain pollutants into waters of the U.S. Sanctions for failure to comply strictly with the Clean Water Act are generally resolved by payment of fines and correction of any identified deficiencies. However, regulatory agencies could require us to cease construction or operation of certain facilities or to cease hauling wastewater to facilities owned by others that are the source of water discharges to resolve non-compliance. We believe that we substantially comply with the applicable provisions of the Clean Water Act and related federal and state regulations.

Clean Air Act. Our operations are subject to the federal Clean Air Act (the “Clean Air Act”) and comparable local and state laws and regulations to control emissions from sources of air pollution. Federal and state laws require new and modified sources of air pollutants to obtain permits prior to commencing construction. Major sources of air pollutants are subject to more stringent, federally imposed requirements including additional permitting requirements. Federal and state laws designed to control toxic air pollutants and greenhouse gases might require installation of additional controls. Payment of fines and correction of any identified deficiencies generally resolve any failures to comply strictly with air regulations or permits. However, in the event of non-compliance, regulatory agencies could also require us to cease construction or operation of certain facilities or to install additional controls on certain facilities that are air emission sources. We believe that we substantially comply with applicable emission standards and permitting requirements under local, state and federal laws and regulations.

Some of our producing wells and associated facilities are subject to restrictive air emission limitations and permitting requirements. Two examples are the EPA’s source aggregation rule and the EPA’s New Source Performance Standards (“NSPS”) and National Emission Standards for Hazardous Air Pollutants (“NESHAP”). In June 2016, the EPA published a final rule concerning aggregation of sources that affects source determinations for air permitting in the oil and gas industry, and, as a result, aggregating our oil and gas facilities for permitting may result in increased complexity and cost of, and time required for, air permitting. Particularly with respect to obtaining pre-construction permits, the final aggregation rule has added costs and caused delays in operations.

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In 2012, the EPA published final NSPS and NESHAP that amended the existing NSPS and NESHAP for the oil and natural gas sector. In June 2016, the EPA published a final rule that updated and expanded the NSPS by setting additional emissions limits for volatile organic compounds and regulating methane emissions for new and modified sources in the oil and gas industry. In June 2017, the EPA proposed a two-year stay of certain requirements contained in the June 2016 rule and, in November 2017, issued a notice of data availability in support of the stay proposal and provided a 30-day comment period on the information provided. In March 2018, the EPA published a final rule that amended two narrow provisions of the NSPS, removing the requirement for completion of delayed repair during emergency or unscheduled vent blowdowns. In September 2020, the EPA published a final rule amending the 2012 and 2016 NSPS for the oil and natural gas sector that removed transmission and storage sources from the oil and natural gas industry source category and rescinded the methane requirements applicable to the production and processing sources. On June 30, 2021, President Biden signed into law a joint Congressional resolution under the Congressional Review Act disapproving the September 2020 rule amending the EPA’s 2012 and 2016 NSPS standards for the oil and natural gas sector. On November 15, 2021, the EPA proposed rules to reduce methane emissions from both new and existing oil and natural gas industry sources and published supplemental rules regarding the same on December 6, 2022. For additional information, please read “Risk Factors—Legal, Regulatory and Governmental Risks— Federal, state and local laws and regulations, judicial actions and regulatory initiatives related to oil and gas development and the use of hydraulic fracturing could result in increased costs and operating restrictions or delays and adversely affect our business, financial condition, results of operations and cash flows” in Item 1A.

In October 2015, the EPA adopted a lower national ambient air quality standard for ozone. The revised standard resulted in additional areas being designated as ozone non-attainment, which could lead to requirements for additional emissions control equipment and the imposition of more stringent permit requirements on facilities in those areas. The EPA completed its final area designations under the new ozone standard in July 2018. If we are unable to comply with air pollution regulations or to obtain permits for emissions associated with our operations, we could be required to forego or implement modifications to certain operations. These regulations may also increase compliance costs for some facilities we own or operate, and result in administrative, civil and/or criminal penalties for noncompliance. Obtaining permits may delay the development of our oil and natural gas projects, including the construction and operation of facilities.

Safe Drinking Water Act. The Safe Drinking Water Act (“SDWA”) and comparable local and state provisions restrict the disposal, treatment or release of water produced or used during oil and gas development. Subsurface placement of fluids (including disposal wells or enhanced oil recovery) is governed by federal or state regulatory authorities that, in some cases, includes the state oil and gas regulatory authority or the state’s environmental authority. These regulations may increase the costs of compliance for some facilities.

Hydraulic Fracturing. Substantially all of our exploration and production operations depend on the use of hydraulic fracturing to enhance production from oil and natural gas wells. Most of our wells would not be economical without the use of hydraulic fracturing to stimulate production from the well. Due to concerns raised relating to potential impacts of hydraulic fracturing on groundwater quality, legislative and regulatory efforts at the U.S. federal, state and local levels have been initiated to render permitting and compliance requirements more stringent for hydraulic fracturing or to restrict or prohibit the activity altogether. States in which we operate also have adopted, or have stated intentions to adopt, laws or regulations that mandate further restrictions on hydraulic fracturing, such as imposing more stringent permitting, disclosure and well-construction requirements on hydraulic fracturing operations and establishing standards for the capture of air emissions released during hydraulic fracturing. In addition to state measures, local land use restrictions, such as city ordinances, may restrict drilling in general or hydraulic fracturing in particular. Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition to oil and natural gas production activities using hydraulic fracturing techniques, which could have an adverse effect on oil and natural gas production activities, including operational delays or increased operating costs in the production of oil and natural gas, or could make it more difficult to perform hydraulic fracturing. For example, Pennsylvania’s Act 13 of 2012 amended the state’s Oil and Gas Act to, among other things, increase civil penalties and strengthen the authority of the Pennsylvania Department of Environmental Protection over the issuance of drilling permits. Although the Pennsylvania Supreme Court struck down portions of Act 13 that made statewide rules on oil and gas preempt local zoning rules, this could lead to additional local restrictions on oil and gas activity in the state.

At the federal level, the EPA conducted a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater. The EPA released its final report in December 2016. It concluded that hydraulic fracturing activities can impact drinking water resources under some circumstances, including large volume spills and inadequate mechanical integrity of wells. This study and other studies that may be undertaken by the EPA or other federal agencies could spur initiatives to further regulate hydraulic fracturing under the Safe Drinking Water Act, the Toxic Substances Control Act, or other statutory and/or regulatory mechanisms. A number of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing practices.

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Our inability to locate sufficient amounts of water, or to dispose of or recycle water used or produced in our exploration and production operations, could adversely impact our operations. For water sourcing, we first seek to use non-potable water supplies, or recycled produced water for our operational needs. In certain areas, there may be insufficient water available for drilling and completion activities. Water must then be obtained from other sources and transported to the drilling site. Our operations in certain areas could be adversely impacted if we are unable to secure sufficient amounts of water or to dispose of or recycle the water used in our operations. The imposition of new environmental and other regulations, as well as produced water disposal well limits or moratoriums in areas of seismicity, could further restrict our ability to conduct operations such as hydraulic fracturing by restricting the disposal of waste such as produced water and drilling fluids. Compliance with environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells may increase our operating costs and cause delays, interruptions or termination of our operations, the extent of which cannot be predicted, all of which could have an adverse effect on our operations and financial condition. In June 2016, the EPA published final pretreatment standards for disposal of wastewater produced from shale gas operations to publicly owned treatment works. The regulations were developed under the EPA’s Effluent Guidelines Program under the authority of the Clean Water Act. In response to these actions, operators, including us, have begun to rely more on recycling of water that flows back from the wellbore following hydraulic fracturing (“flowback water”) and produced water from well sites as a preferred alternative to disposal.

Greenhouse Gas and Climate Change Laws and Regulations. In response to studies suggesting that emissions of carbon dioxide and certain other greenhouse gases (“GHGs”), including methane, may be contributing to global climate change, there is increasing focus by local, state, regional, national and international regulatory bodies as well as by investors and the public on GHG emissions and climate change issues. In December 2015, the U.S. joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change (the “UNFCCC”) in Paris, France in creating an agreement (the “Paris Agreement”) that requires member countries to review and “represent a progression” in their intended nationally determined contributions (“NDC”) of GHGs, which set GHG emission reduction goals every five years beginning in 2020. In 2019, the U.S. withdrew from the Paris Agreement. The current Presidential administration has made climate change a central priority. On January 20, 2021, his first day in office, President Biden took action to reverse the withdrawal of the previous administration from the Paris Agreement so that the U.S. could rejoin as a party to the agreement. The U.S. officially rejoined the Paris Agreement on February 19, 2021, and in April 2021 submitted its NDC. The U.S. NDC sets an economy-wide target of net GHG emissions reduction from 2005 levels of 50-52% by 2030. The specific measures to be taken in furtherance of achieving this target have not been established, but the NDC submission indicated that a “whole government approach” will be used to achieve this target, including regulatory, technology and policy initiatives designed to reduce the generation of GHG emissions and to incentivize the capture and geologic sequestration or utilization of carbon dioxide that would otherwise be emitted in the atmosphere. Also on his first day in office, President Biden signed an executive order on climate action and reconvened an interagency working group to establish interim and final social costs of three GHGs: carbon dioxide, nitrous oxide, and methane. Carbon dioxide is released during the combustion of fossil fuels, including oil, natural gas, and NGLs, and methane is a primary component of natural gas. The Biden administration stated it will use updated social cost figures to inform federal regulations and major agency actions and to justify aggressive climate action as the U.S. moves toward a “100% clean energy” economy with net-zero GHG emissions.

Although the U.S. Congress has considered legislation designed to reduce emissions of GHGs in recent years, it has not adopted any significant GHG legislation. However, the 2021 Infrastructure and Investment Jobs Act passed by Congress on November 6, 2021 included measures aimed at decarbonization to address climate change, including funding for replacing transit vehicles, including buses, with zero- and low-emission vehicles and for the deployment of an electric vehicle charging network nationwide. This legislation, and other future laws, that promote a shift toward electric vehicles could adversely affect the demand for our products. Moreover, in the absence of federal GHG legislation, a number of state and regional efforts have emerged. These include measures aimed at tracking and/or reducing GHG emissions through cap-and-trade programs, which typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting GHGs. In addition, a coalition of over 20 governors of U.S. states formed the U.S. Climate Alliance to advance the objectives of the Paris Agreement, and several U.S. cities have committed to advance the objectives of the Paris Agreement at the state or local level as well. To this end, California’s governor issued an executive order on September 23, 2020 ordering actions to pursue GHG emissions reductions, including a direction to the California State Air Resources Board to develop and propose regulations to require increasing volumes of new zero-emission passenger vehicles and trucks sold in California over time, with a targeted ban of the sale of new gasoline vehicles by 2035.

At the federal level, the EPA has begun to regulate carbon dioxide and other GHGs under existing provisions of the Clean Air Act. In December 2009, the EPA published its findings that emissions of GHGs present an endangerment to public health and the environment because emissions of such gases are contributing to the warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA adopted regulations under existing provisions of the federal Clean Air Act that establish Prevention of Significant Deterioration (“PSD”) and Title V permit reviews for GHG emissions from certain large

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stationary sources that are otherwise subject to PSD and Title V permitting requirements. The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified sources in the U.S., including, among others, certain oil and gas production facilities on an annual basis, which includes certain of our operations. The EPA widened the scope of annual GHG reporting to include, not only activities associated with completion and workover of gas wells with hydraulic fracturing and activities associated with oil and gas production operations, but also completions and workovers of oil wells with hydraulic fracturing, gathering and boosting systems, and transmission pipelines. More recently, on November 15, 2021, the EPA proposed rules to reduce methane emissions from new and modified sources in the oil and gas sector and published proposed supplemental rules regarding the same on December 6, 2022. The Inflation Reduction Act of 2022 (“IRA”) established the Methane Emissions Reduction Program, which imposes a charge on methane emissions from certain petroleum and natural gas facilities, which may apply to our operations in the future and may require us to expend material sums.

If we are unable to recover or pass through a significant portion of our costs related to complying with current and future regulations relating to climate change and GHGs, it could materially affect our operations and financial condition. Any future laws or regulations that limit emissions of GHGs from our equipment and operations could require us to both develop and implement new practices aimed at reducing GHG emissions, such as emissions control technologies, which could increase our operating costs and could adversely affect demand for the oil and gas that we produce. To the extent financial markets view climate change and GHG emissions as a financial risk, this could negatively impact our cost of, and access to, capital. Future implementation or adoption of legislation or regulations adopted to address climate change could also make our products more or less desirable than competing sources of energy. At this time, it is not possible to quantify the impact of any such future developments on our business.

Occupational Safety and Health Act and Other Laws and Regulations. We are subject to the requirements of the U.S. federal Occupational Safety and Health Act (the “Occupational Safety and Health Act”) and comparable state laws. The Occupational Safety and Health Act hazard communication standard, the EPA community right‑to‑know regulations under the Title III of CERCLA and similar state laws require that we organize and/or disclose information about hazardous materials used or produced in our operations. Also, pursuant to the Occupational Safety and Health Act, the Occupational Safety and Health Administration (the “OSHA”) has established a variety of standards related to workplace exposure to hazardous substances and employee health and safety.

Human Capital Resources

Our ability to attract, retain and develop the highest quality employees is a vital component of our success. In connection with the Merger, we developed integration plans for every organization and are in the final stages of staff reorganizations, relocations of key employees and hiring of new talent for our corporate headquarters in Houston, Texas. Staff reductions are occurring primarily in our Denver, Colorado office (which will close in 2023) and our Tulsa, Oklahoma office, which will be dedicated to management of our Anadarko Basin operations, with other corporate functions transferred to Houston, Texas. Detailed transition, staffing and knowledge transfer plans have ensured that key aspects of ongoing operations continue uninterrupted through this process. Our staff reorganization plans have eliminated redundancy between the legacy company organizations, and our hiring plans have accelerated our ability to attract and develop a diverse workforce. We believe that the resulting employee levels from our integration plan are appropriate and that we will continue to have the human capital to operate our business and carry out our strategy as determined by management and our Board of Directors.

As of December 31, 2022, we had 981 total employees, 283 of whom were located in our headquarters in Houston, Texas and our corporate office in Denver, Colorado and 330 of whom were located in our regional offices in Midland, Texas, Tulsa Oklahoma and Pittsburgh, Pennsylvania. We had a total of 368 employees in production field locations across our regional offices. We had 132 employees that will exit as a result of our integration and transition plans. Of our total employee population, 606 were salaried and 375 were hourly. We also have 244 employees that are employed by our wholly-owned subsidiary, GasSearch Drilling Services Corporation (“GDS”), which is a service company engaged in water hauling and site preparation exclusively for our Marcellus Shale operations. Of our GDS employees, 16 were salaried and 228 were hourly. We believe that our relations with our employees are favorable. None of our employees are represented pursuant to a collective bargaining agreement.

In managing our people, we seek to:

•have a results-focused culture centered on transparency and open communication;

•attract, retain and develop a highly qualified, motivated and diverse workforce;

•maintain a conservatively managed headcount to minimize workforce fluctuations;

•provide opportunities for career growth, learning and development;

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•offer highly competitive compensation and benefits packages; and

•promote a safe and healthy workplace.

We believe these practices, further described below, are the key drivers in our development of current and future talent and leadership as well as employee engagement and retention.

Recruiting, Hiring and Advancement. Due to the cyclical nature of our business and the fluctuations in activity that can occur, we manage our headcount carefully. We provide employees with opportunities to learn new roles and develop the breadth and depth of their skills to ensure a collaborative environment, strong talent and future leadership. This also helps to minimize layoffs and overall staff fluctuations when downturns occur. When a position needs to be filled, we generally seek to promote current top-performing employees before going to outside sources for a new hire. We believe this practice helps to build future leadership and to reduce voluntary turnover among our workforce by providing employees with new challenges and opportunities throughout their careers.

When we hire from outside the company, we identify qualified candidates by promoting the position internally for referrals, engaging in recruiting through our website and online platforms, utilizing recruiting services and attending job fairs. We also have a well-established internship program that feeds top talent into our technical functions. In our recruiting efforts, we foster a culture of mutual respect and compliance with all applicable federal, state and local laws governing nondiscrimination in employment. We seek to increase the diversity of our workforce in our external hiring practices. We ask our recruiting partners to provide diverse slates of candidates and we treat all applicants with the same high level of respect regardless of their gender, ethnicity, religion, national origin, age, marital status, political affiliation, sexual orientation, gender identity, disability or protected veteran status. This philosophy extends to all employees throughout the lifecycle of employment, including recruiting, hiring, placement, promotion, evaluation, leaves of absence, compensation and training.

Compensation and Benefits. Our focus on providing competitive total compensation and benefits to our employees is a core value and a key driver of our retention program. We design our compensation programs to provide compensation that is competitive with our industry peers and rewards superior performance and, for managers and executives, aligns compensation with our performance and incentivizes the achievement of superior operating results. We do this through a total rewards program that provides:

•base wages or salaries that are competitive for the position and considered for increases annually based on employee performance, business performance and industry outlook;

•incentives that reward individual and company performance, such as performance bonuses, management discretionary bonuses, field operational bonuses and short-term and long-term incentive programs;

•retirement benefits, including dollar-for-dollar matching contributions and discretionary employer retirement contributions to a tax-qualified defined contribution savings plan for all employees and other non-qualified retirement programs;

•comprehensive health and welfare benefits, including medical insurance, prescription drug benefits, dental insurance, vision insurance, life insurance, accident insurance, short and long-term disability benefits, employee assistance program and health savings accounts;

•tuition reimbursement for eligible employees, scholarship program and matching charitable contributions program; and

•time off, sick time, parental leave and holiday time.

We believe our compensation and benefits package is a strong retention tool and promotes personal health and financial security within our workforce.

Health and Safety. The health and safety of our employees is one of our core values for sustainable operations. This value is reflected in our strong safety culture that emphasizes personal responsibility and safety leadership, both for our employees and our contractors that are on our worksites. Our safety programs are built on a foundation that emphasizes personal safety and includes a Stop Work Authority program that empowers employees and contractors to stop work if they discover a dangerous condition or other serious EHS hazard. Our comprehensive EHS management system establishes a corporate governance framework for EHS compliance and performance and covers all elements of our operating lifecycle, including comprehensive safety protocols in response to the COVID-19 pandemic that struck suddenly in early 2020. All of our employees are designated “critical infrastructure workers” under the Cybersecurity & Infrastructure Security Agency guidelines, and as a result, our field operations have continued uninterrupted since the onset of the pandemic. During 2022, we

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have taken, and continue to take, actions in response to the COVID-19 pandemic to help protect the health and safety of our employees and others.

Website Access to Company Reports

We make available free of charge through our website, www.coterra.com, our annual reports on Form 10‑K, quarterly reports on Form 10‑Q, current reports on Form 8‑K and all amendments to those reports as soon as reasonably practicable after such material is electronically filed with or furnished to the SEC. In addition, the SEC maintains an Internet site at www.sec.gov that contains reports, proxy and information statements and other information filed by us. Information on our website, including our 2022 Sustainability Report, is not a part of, and is not incorporated into, this report on Form 10-K or any other report we may file with or furnish to the SEC (and is not deemed filed herewith), whether before or after the date of this report on Form 10-K and irrespective of any general incorporation language therein. Furthermore, references to our website URLs are intended to be inactive textual references only.

Corporate Governance Matters

Our Corporate Governance Guidelines, Code of Business Conduct and Ethics, Audit Committee Charter, Compensation Committee Charter, Governance and Social Responsibility Committee Charter and Environment, Health & Safety Committee Charter are available on our website at www.coterra.com. Requests for copies of these documents can also be made in writing to Investor Relations at our corporate headquarters at Three Memorial City Plaza, 840 Gessner Road, Suite 1400, Houston, Texas 77024.

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ITEM 1A. RISK FACTORS

Business and Operational Risks

You should carefully consider the following risk factors in addition to the other information included in this report. Each of these risk factors could adversely affect our business, financial condition, results of operations and/or cash flows, as well as adversely affect the value of an investment in our common stock, debt securities, or preferred stock.

Commodity prices fluctuate widely, and low prices for an extended period would likely have a material adverse impact on our business.

Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prices we receive for the oil, natural gas and NGLs that we sell. Lower commodity prices may reduce the amount of oil, natural gas and NGLs that we can produce economically, while higher commodity prices could cause us to experience periods of higher costs. Historically, commodity prices have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile. Wide fluctuations in commodity prices may result from relatively minor changes in the supply of and demand for oil, natural gas and NGLs, market uncertainty and a variety of additional factors that are beyond our control, including global events or conditions that affect supply and demand, such as the COVID-19 pandemic, the war in Ukraine and other geopolitical risks and sanctions, the actions of OPEC+ members and climate change. Any substantial or extended decline in future commodity prices would have a material adverse effect on our future business, financial condition, results of operations, cash flows, liquidity or ability to finance planned capital expenditures and commitments. If commodity prices decline significantly for a sustained period of time, the lower prices may cause us to reduce our planned drilling program or adversely affect our ability to make planned expenditures, raise additional capital or meet our financial obligations. Furthermore, substantial, extended decreases in commodity prices may render such projects uneconomic, which may result in significant downward adjustments to our estimated proved reserves and could negatively impact our ability to borrow and cost of capital and our ability to access capital markets, increase our costs under our revolving credit facility and limit our ability to execute aspects of our business plans. Refer to “Future commodity price declines may result in write-downs of the carrying amount of our oil and gas properties, which could materially and adversely affect our results of operations.”

Drilling oil and natural gas wells is a high-risk activity.

Our growth is materially dependent upon the success of our drilling program. Drilling for oil and natural gas involves numerous risks, including the risk that no commercially productive reservoirs will be encountered. The cost of drilling, completing and operating wells is substantial and uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors beyond our control. Our future drilling activities may not be successful and, if unsuccessful, such failure will have an adverse effect on our future results of operations and financial condition.

Our operations present hazards and risks that require significant and continuous oversight, and are subject to numerous possible disruptions from unexpected events.

The scope and nature of our operations present a variety of significant hazards and risks, including operational hazards and risks such as explosions, fires, product spills, and cybersecurity incidents and unauthorized access to data or systems, among other risks. Our operations are also subject to broader global events and conditions, including public health crises, pandemic or epidemic, war or civil unrest, acts of terror, weather events and natural disasters, including weather events or natural disasters that are related to or exacerbated by climate change. Such hazards and risks could impact our business in the areas in which we operate, and our business and operations may be disrupted if we fail to respond in an appropriate manner to such hazards and risks or if we are unable to efficiently restore or replace affected operational components and capacity. Furthermore, our insurance may not be adequate to compensate us for all resulting losses. The cost of insurance may increase and the availability of insurance may decrease, as a result of climate change or other factors. The occurrence of any event not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows.

Our proved reserves are estimates. Any material inaccuracies in our reserves estimates or underlying assumptions could cause the quantities and net present value of our reserves to be overstated or understated.

Reserves engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. The process of estimating quantities of proved reserves is complex and inherently imprecise, and the reserves data included in this document are only estimates. The process relies on interpretations of available geologic, 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 assumptions relating to commodity prices. Additional assumptions include drilling and operating expenses, capital expenditures, taxes and availability

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of funds. Furthermore, different reserve engineers may make different estimates of reserves and cash flows based on the same data. For example, our total company proved reserves decreased by approximately 17 percent year over year at December 31, 2022. For more information on such revision, refer to the Supplemental Oil and Gas Information included in Item 8.

Results of drilling, testing and production subsequent to the date of a reserves estimate may justify revising the original estimate. Accordingly, initial reserves estimates often vary from the quantities of oil and natural gas that are ultimately recovered, and such variances may be material. Any significant variance could reduce the estimated quantities and present value of our reserves.

You should not assume that the present value of future net cash flows from our proved reserves is the current market value of our estimated reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flows from our proved reserves on the 12-month average index price for the respective commodity, calculated as the unweighted arithmetic average for the first day of the month price for each month and costs in effect on the date of the estimate, holding the prices and costs constant throughout the life of the properties, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. Actual future prices and costs may differ materially from those used in the net present value estimate, and future net present value estimates using then current prices and costs may be significantly less than the current estimate. In addition, the 10 percent discount factor we use when calculating discounted future net cash flows for reporting requirements in compliance with the applicable accounting standards may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and gas industry in general.

Future commodity price declines may result in write-downs of the carrying amount of our oil and gas properties, which could materially and adversely affect our results of operations.

The value of our oil and gas properties depends on commodity prices. Declines in these prices as well as increases in development costs, changes in well performance, delays in asset development or deterioration of drilling results may result in our having to make material downward adjustments to our estimated proved reserves, and could result in an impairment charge and a corresponding write-down of the carrying amount of our oil and gas properties.

We evaluate our oil and gas properties for impairment on a field-by-field basis whenever events or changes in circumstances indicate a property’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 as well as historical and current prices adjusted for geographical location and quality differentials, as well as other factors that management believes will impact realizable prices. In the event that commodity prices decline, there could be a significant revision to the carrying amounts of oil and gas properties in the future.

Our future performance depends on our ability to find or acquire additional oil and natural gas reserves that are economically recoverable.

Unless we successfully replace the reserves that we produce, our reserves will decline as reserves are depleted, eventually resulting in a decrease in oil and natural gas production and lower revenues and cash flow from operations. Our future production is, therefore, highly dependent on our level of success in finding or acquiring additional reserves. We may not be able to replace reserves through our exploration, development and exploitation activities or by acquiring properties at acceptable costs. Additionally, there is no way to predict in advance of any exploration and development whether any particular location will yield sufficient quantities to recover drilling or completion costs or be economically viable. Low commodity prices may further limit the kinds of reserves that we can develop and produce economically. If we are unable to replace our current and future production, our revenues will decrease and our business, financial condition and results of operations may be adversely affected.

The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate.

As of December 31, 2022, approximately 24 percent of our estimated proved reserves (by volume) were undeveloped. Developing PUD reserves requires significant capital expenditures, and the estimated future development costs associated with our PUD reserves may not equal our actual costs, development may not occur as scheduled and results of our development activities may not be as estimated. If we choose not to develop our PUD reserves, or if we are not otherwise able to develop them successfully, we will be required to remove them from our reported proved reserves. In addition, under the SEC’s reserves reporting rules, because PUD reserves generally may be recorded only if they relate to wells scheduled to be drilled within five years of the date of booking, we may be required to remove any PUD reserves that are no longer planned to be developed

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within this five-year time frame. Delays in the development of our PUD reserves, decreases in commodity prices and increases in costs to drill and develop such reserves may also result in some projects becoming uneconomic.

Strategic determinations, including the allocation of capital and other resources to strategic opportunities, are challenging, and our failure to appropriately allocate capital and resources among our strategic opportunities may adversely affect our financial condition and reduce our growth rate.

Our future growth prospects depend on our ability to identify optimal strategies for our business. In developing our business plans, we considered allocating capital and other resources to various aspects of our business including well-development (primarily drilling), reserve acquisitions, exploratory activity, corporate items and other alternatives. We also consider our likely sources of capital. Notwithstanding the determinations made in the development of our 2023 plan, business opportunities not previously identified periodically may come to our attention, including possible acquisitions and dispositions. If we fail to identify optimal business strategies, or fail to optimize our capital investment and capital raising opportunities and the use of our other resources in furtherance of our business strategies, our financial condition and growth rate may be adversely affected. Moreover, economic or other circumstances may change from those contemplated by our 2023 plan, and our failure to recognize or respond to those changes may limit our ability to achieve our objectives.

Our ability to sell our oil, natural gas and NGL production and/or the prices we receive for our production could be materially harmed if we fail to obtain adequate services such as transportation and processing.

The sale of our oil, natural gas and NGL production depends on a number of factors beyond our control, including the availability and capacity of transportation and processing facilities. We deliver the majority of our oil, natural gas and NGL production through gathering systems and pipelines that we do not own. The lack of available capacity on these systems and facilities could reduce the price offered for our production or result in the shut-in of producing wells or the delay or discontinuance of development plans for properties. Third-party systems and facilities may be unavailable due to market conditions or mechanical or other reasons, and in some cases the resulting curtailments of production could lead to payment being required where we fail to deliver oil, natural gas and NGLs to meet minimum volume commitments. In addition, construction of new pipelines and building of required infrastructure may be slow. To the extent these services are unavailable, we would be unable to realize revenue from wells served by such facilities until suitable arrangements are made to market our production. Our failure to obtain these services on acceptable terms could materially harm our business.

Moreover, these availability and capacity issues are likely to occur in remote areas with less established infrastructure, such as our Permian Basin properties where we have significant oil and natural gas production. Any of these availability or capacity issues could negatively affect our operations, revenues and expenses. In addition, the Marcellus Shale wells we have drilled to date have generally reported very high initial production rates. The amount of natural gas being produced in the area from these new wells, as well as natural gas produced from other existing wells, may exceed the capacity of the various gathering and intrastate or interstate transportation pipelines currently available. This could result in wells being shut in or awaiting a pipeline connection or capacity and/or natural gas being sold at much lower prices than those quoted on NYMEX or than we currently project, which would adversely affect our results of operations and cash flows.

Acquired properties may not be worth what we pay to acquire them, due to uncertainties in evaluating recoverable reserves and other expected benefits, as well as potential liabilities.

Successful property acquisitions require an assessment of a number of factors beyond our control. These factors include estimates of recoverable reserves, exploration potential, future commodity prices, operating costs, production taxes and potential environmental and other liabilities. These assessments are complex and inherently imprecise. Our review of the properties we acquire may not reveal all existing or potential problems. In addition, our review may not allow us to assess fully the potential deficiencies of the properties. We do not inspect every well, and even when we inspect a well we may not discover structural, subsurface or environmental problems that may exist or arise.

There may be threatened or contemplated claims against the assets or businesses we acquire related to environmental, title, regulatory, tax, contract, litigation or other matters of which we are unaware, which could materially and adversely affect our production, revenues and results of operations. We often assume certain liabilities, and we may not be entitled to contractual indemnification for pre-closing liabilities, including environmental liabilities, and our contractual indemnification may not be effective. At times, we acquire interests in properties on an “as is” basis with limited representations and warranties and limited remedies for breaches of such representations and warranties. In addition, significant acquisitions can change the nature of our operations and business if the acquired properties have substantially different operating and geological characteristics or are in different geographic locations than our existing properties.

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The integration of the businesses and properties we have acquired or may in the future acquire could be difficult, and may divert management’s attention away from our existing operations.

The integration of the businesses and properties we have acquired, including via the Merger, or may in the future acquire could be difficult, and may divert management’s attention and financial resources away from our existing operations. These difficulties include:

•the challenge of integrating the acquired businesses and properties while carrying on the ongoing operations of our business;

•the inability to retain key employees of the acquired business;

•the challenge of inconsistencies in standards, controls, procedures and policies of the acquired business;

•potential unknown liabilities, unforeseen expenses or higher-than-expected integration costs;

•an overall post-completion integration process that takes longer than originally anticipated;

•potential lack of operating experience in a geographic market of the acquired properties; and

•the possibility of faulty assumptions underlying our expectations.

If management is not able to effectively manage the integration process, or if any significant business activities are interrupted as a result of the integration process, our business could suffer. Our future success will depend, in part, on our ability to manage our expanded business, which may pose substantial challenges for management. We may also face increased scrutiny from governmental authorities as a result of the increase in the size of our business. There can be no assurances that we will be successful in our integration efforts.

We have limited control over the activities on properties we do not operate.

Other companies operate some of the properties in which we have an interest. As of December 31, 2022, non-operated wells represented approximately 51 percent of our total owned gross wells, or 13 percent of our owned net wells. We have limited ability to influence or control the operation or future development of these non-operated properties and on properties we operate in joint ventures in which we may share control with third parties, including compliance with environmental, safety and other regulations or the amount of capital expenditures that we are required to fund with respect to them. The failure of an operator of our wells or joint venture participant to adequately perform operations, an operator’s breach of the applicable agreements or an operator’s failure to act in ways that are in our best interest could reduce our production and revenues. Our dependence on the operator and other working interest owners, including a joint venture participant, for these projects and our limited ability to influence or control the operation and future development of these properties could materially adversely affect the realization of our targeted returns on capital in drilling or acquisition activities and lead to unexpected future costs.

Many of our properties are in areas that may have been partially depleted or drained by offset wells and certain of our wells may be adversely affected by actions other operators may take when drilling, completing or operating wells that they own.

Many of our properties are in areas that may have been partially depleted or drained by earlier offset drilling. We have no control over offsetting operators, who could take actions, such as drilling and completing additional wells, which could adversely affect our operations. When a new well is completed and produced, the pressure differential in the vicinity of the wellbore causes the migration of reservoir fluids toward the new wellbore (and potentially away from existing wellbores), which could cause a depletion of our proved reserves and may inhibit our ability to further develop our proved reserves. The possibility for these impacts may increase with respect to wells that are shut in as a response to lower commodity prices or the lack of pipeline and storage capacity. In addition, completion operations and other activities conducted on other nearby wells could cause us, in order to protect our existing wells, to shut in production for indefinite periods of time. Shutting in our wells and damage to our wells from offset completions could result in increased costs and could adversely affect the reserves and re-commenced production from such shut in wells.

We may lose leases if production is not established within the time periods specified in the leases or if we do not maintain production in paying quantities.

We could lose leases under certain circumstances if we do not maintain production in paying quantities or meet other lease requirements, and the amounts we spent for those leases could be lost. If we shut in wells in response to lower commodity prices or a lack of pipeline and storage capacity, we may face claims that we are not complying with lease provisions. In

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addition, the Biden administration also may impose new restrictions and regulations affecting our ability to drill, conduct hydraulic fracturing operations, and obtain necessary rights-of-way on federal lands, which could, in turn, result in the loss of federal leases. The combined net acreage expiring over the next three years represents less than one percent of our total net undeveloped acreage as of December 31, 2022. Our actual drilling activities may materially differ from those presently identified, which could adversely affect our business.

Cyber-attacks targeting our systems, the oil and gas industry systems and infrastructure or the systems of our third-party service providers could adversely affect our business.

Our business and the oil and gas industry in general have become increasingly dependent on digital data, computer networks and connected infrastructure, including technologies that are managed by third-party providers on whom we rely to help us collect, host or process information. We depend on this technology to record and store financial data, estimate quantities of oil and natural gas reserves, analyze and share operating data and communicate internally and externally. Computers control nearly all of the oil and gas distribution systems in the U.S., which are necessary to transport our products to market. Computers also enable communications and provide a host of other support services for our business. In recent years (and, in large part, due to the COVID-19 pandemic), we have increased the use of remote networking and online conferencing services and technologies that enable employees to work outside of our corporate infrastructure, which exposes us to additional cybersecurity risks, including unauthorized access to sensitive information as a result of increased remote access and other cybersecurity related incidents.

Cyber-attacks are becoming more sophisticated and include, but are not limited to, malicious software, phishing, ransomware, attempts to gain unauthorized access to data and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information and corruption of data. Unauthorized access to our seismic data, reserves information, customer or employee data or other proprietary or commercially sensitive information could lead to data corruption, communication interruption or other disruptions in our exploration or production operations or planned business transactions, any of which could have a material adverse impact on our business and operations. If our information technology systems cease to function properly or are breached, we could suffer disruptions to our normal operations, which may include drilling, completion, production and corporate functions. A cyber-attack involving our information systems and related infrastructure, or that of our business associates, could result in supply chain disruptions that delay or prevent the transportation and marketing of our production, equipment damage, fires, explosions or environmental releases, non-compliance leading to regulatory fines or penalties, loss or disclosure of, or damage to, our or any of our customer’s or supplier’s data or confidential information that could harm our business by damaging our reputation, subjecting us to potential financial or legal liability and requiring us to incur significant costs, including costs to repair or restore our systems and data or to take other remedial steps.

In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period, and our systems and insurance coverage for protecting against such cybersecurity risks may be costly and may not be sufficient. As cyber-attackers become more sophisticated, we may be required to expend significant additional resources to continue to protect our business or remediate the damage from cyber-attacks. Furthermore, the continuing and evolving threat of cyber-attacks has resulted in increased regulatory focus on prevention, and we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any information security vulnerabilities. To the extent we face increased regulatory requirements, we may be required to expend significant additional resources to meet such requirements.

Risks Related to our Indebtedness, Hedging Activities and Financial Position

We have substantial capital requirements, and we may not be able to obtain needed financing on satisfactory terms, if at all.

We make and expect to make substantial capital expenditures in connection with our development and production projects. We rely on access to both our revolving credit facility and longer-term capital markets as sources of liquidity for any capital requirements not satisfied by cash flow from operations or other sources. Adverse economic and market conditions, such as actions of the Federal Reserve to raise the target federal funds rate, could adversely affect our ability to access such sources of liquidity. Future challenges in the global financial system may adversely affect the terms on which we are able to obtain financing, which could impact our business, financial condition and access to capital. Our ability to access the capital markets may be restricted at a time when we desire, or need, to raise capital, which could have an impact on our flexibility to react to changing economic and business conditions. Additionally, such adverse economic and market conditions could impact our counterparties, including our receivables and our hedging counterparties, who may as a result of such conditions be unable to perform their obligations.

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Risks associated with our debt and the provisions of our debt agreements could adversely affect our business, financial position and results of operations.

Our indebtedness as a result of the Merger and related transactions could have adverse effects on our business, financial condition, results of operations and cash flows, including by requiring us to use a substantial portion of our cash flow to make debt service payments, which will reduce the funds that would otherwise be available for operations, returning cash flow from operations to stockholders and future business opportunities. As a result, our ability to sell assets, engage in strategic transactions or obtain additional financing for working capital, capital expenditures, general corporate and other purposes may be adversely impacted. Our ability to make payments on and to refinance our indebtedness will depend on our ability to generate cash in the future from operations, financings or asset sales. If we fail to make required payments or otherwise default on our debt, the lenders who hold such debt also could accelerate amounts due, which could potentially trigger a default or acceleration of other debt.

Our debt agreements also require compliance with covenants to maintain specified financial ratios. If commodity prices deteriorate from current levels, it could lead to reduced revenues, cash flow and earnings, which in turn could lead to a default under such agreements due to lack of covenant compliance. Because the calculations of the financial ratios are made as of certain dates, the financial ratios can fluctuate significantly from period to period. A prolonged period of lower commodity prices could further increase the risk of our inability to comply with covenants to maintain specified financial ratios. In order to provide a margin of comfort with regard to these financial covenants, we may seek to reduce our capital expenditures, sell non-strategic assets or opportunistically modify or increase our derivative instruments to the extent permitted under our debt agreements. In addition, we may seek to refinance or restructure all or a portion of our indebtedness. We cannot provide assurance that we will be able to successfully execute any of these strategies, and such strategies may be unavailable on favorable terms or at all. For more information about our debt agreements, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Financial Condition-Liquidity and Capital Resources.”

We may have hedging arrangements that expose us to risk of financial loss and limit the benefit to us of increases in prices for oil and natural gas.

From time to time, when we believe that market conditions are favorable, we use financial derivative instruments to manage price risk associated with our oil and natural gas production. While there are many different types of derivatives available, we generally utilize collar, swap and basis swap agreements to manage price risk more effectively.

While these derivatives reduce the impact of declines in commodity prices, these derivatives conversely limit the benefit to us of increases in prices. In addition, these arrangements expose us to risks of financial loss in a variety of circumstances, including when:

•there is an adverse change in the expected differential between the underlying price in the derivative instrument and actual prices received for our production;

•production is less than expected; or

•a counterparty is unable to satisfy its obligations.

The CFTC has promulgated regulations to implement statutory requirements for derivatives transactions, including swaps. Although we believe that our use of swap transactions exempts us from certain regulatory requirements, the changes to the derivatives market regulation affect us directly and indirectly. These changes, as in effect and as continuing to be implemented, could increase the cost of derivative contracts, limit the availability of derivatives to protect against risks that we encounter, reduce our ability to monetize or restructure our existing derivative contracts and increase our exposure to less creditworthy counterparties. If we reduce our use of swaps, our results of operations may become more volatile and our cash flows may be less predictable.

In addition, the use of financial derivative instruments involves the risk that the counterparties will be unable to meet the financial terms of such transactions. We are unable to predict changes in a counterparty’s creditworthiness or ability to perform, and even if we could predict such changes accurately, our ability to negate such risk may be limited depending on market conditions and the contractual terms of the instruments. If any of our counterparties were to default on its obligations under our financial derivative instruments, such a default could (1) have a material adverse effect on our results of operations, (2) result in a larger percentage of our future production being subject to commodity price changes and (3) increase the likelihood that our financial derivative instruments may not achieve their intended strategic purposes.

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We will continue to evaluate the benefit of utilizing derivatives in the future. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 and “Quantitative and Qualitative Disclosures about Market Risk” in Item 7A for further discussion concerning our use of derivatives.

Legal, Regulatory and Governmental Risks

ESG concerns and negative public perception regarding us and/or our industry could adversely affect our business operations and the price of our common stock, debt securities and preferred stock.

Businesses across all industries are facing increasing scrutiny from investors, governmental authorities, regulatory agencies and the public related to their ESG practices, including practices and disclosures related to climate change, sustainability, diversity, equity and inclusion initiatives, and heightened governance standards. Failure, or a perceived failure, to adequately respond to or meet evolving investor, stockholder or public ESG expectations, concerns and standards may cause a business entity to suffer reputational damage and materially and adversely affect the entity’s business, financial condition, or stock and/or debt prices. In addition, organizations that provide ESG information to investors have developed ratings processes for evaluating a business entity’s approach to ESG matters. Although currently no universal rating standards exist, the importance of sustainability evaluations is becoming more broadly accepted by investors and stockholders, with some using these ratings to inform investment and voting decisions. Additionally, certain investors use these scores to benchmark businesses against their peers and, if a business entity is perceived as lagging, these investors may engage with the entity to require improved ESG disclosure or performance. Moreover, certain members of the broader investment community may consider a business entity’s sustainability score as a reputational or other factor in making an investment decision. Consequently, a low sustainability score could result in exclusion of our securities from consideration by certain investment funds, engagement by investors seeking to improve such scores and a negative perception of our operations by certain investors. In addition, efforts in recent years aimed at the investment community to generally promote the divestment of fossil fuel equities and to limit or curtail activities with companies engaged in the extraction of fossil fuel reserves could limit our ability to access capital markets. These initiatives by activists and banks, including certain banks who are parties to the credit agreement providing for our revolving credit facility, could interfere with our business activities, operations and ability to access capital.

Further, negative public perception regarding us and/or our industry resulting from, among other things, concerns raised by advocacy groups about climate change impacts of methane and other greenhouse gas emissions, hydraulic fracturing, oil spills, and pipeline explosions coupled with increasing societal expectations on businesses to address climate change and potential consumer use of substitutes to carbon-intensive energy commodities may result in increased costs, reduced demand for our oil, natural gas and NGL production, reduced profits, increased regulation, regulatory investigations and litigation, and negative impacts on our stock and debt prices and access to capital markets. These factors could also cause the permits we need to conduct our operations to be challenged, withheld, delayed, or burdened by requirements that restrict our ability to profitably conduct our business.

Federal, state and local laws and regulations, judicial actions and regulatory initiatives related to oil and gas development and the use of hydraulic fracturing could result in increased costs and operating restrictions or delays and adversely affect our business, financial condition, results of operations and cash flows.

Our operations are subject to extensive federal, state and local laws and regulations, including drilling and environmental and safety laws and regulations, which increase the cost of planning, designing, drilling, installing and operating oil and natural gas facilities. New laws and regulations or revisions or reinterpretations of existing laws and regulations could further increase these costs, could increase our liability risks, and could result in increased restrictions on oil and gas exploration and production activities, which could have a material adverse effect on us and the oil and gas industry as a whole. Risk of substantial costs and liabilities related to environmental and safety matters in particular, including compliance issues, environmental contamination and claims for damages to persons or property, are inherent in oil and natural gas operations. Failure to comply with applicable environmental and safety laws and regulations also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties as well as the imposition of corrective action requirements and orders. In addition, applicable laws and regulations require us to obtain many permits for the operation of various facilities. The issuance of required permits is not guaranteed and, once issued, permits are subject to revocation, modification and renewal. Failure to comply with applicable laws and regulations can result in fines and penalties or require us to incur substantial costs to remedy violations.

For additional information, please read “Business and Properties—Other Business Matters—Regulation of Oil and Natural Gas Exploration and Production,” “—Regulation of Natural Gas Marketing, Gathering and Transportation,” and “—Environmental and Safety Regulations” in Items 1 and 2.

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Oil and natural gas production operations, especially those using hydraulic fracturing, are substantially dependent on the availability of water. Our ability to produce oil and natural gas economically and in commercial quantities could be impaired if we are unable to acquire adequate supplies of water for our operations or are unable to dispose of or recycle the water we use economically and in an environmentally safe manner.

Water is an essential component of oil and natural gas production during the drilling process. In particular, we use a significant amount of water in the hydraulic fracturing process. Our inability to locate sufficient amounts of water, or dispose of or recycle water used in our exploration and production operations, could adversely impact our operations. Compliance with environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells may increase our operating costs and cause delays, interruptions or termination of our operations, the extent of which cannot be predicted, all of which could have an adverse effect on our operations and financial condition.

For additional information, please read “Business and Properties—Other Business Matters—Environmental and Safety Regulations—Clean Water Act” in Items 1 and 2.

The adoption of climate change legislation or regulations restricting emission of greenhouse gases could result in increased operating costs and reduced demand for the oil and gas we produce.

Studies have found that emission of certain gases, commonly referred to as greenhouse gases (“GHG”), impact the earth’s climate. The U.S. Congress and various states have been evaluating, and in some cases implementing, climate-related legislation and other regulatory initiatives that restrict emissions of GHGs. These actions as well as any future laws or regulations that regulate or limit emissions of GHGs from our equipment and operations could require us to develop and implement new practices aimed at reducing GHG emissions, such as emissions control technologies, and monitor and report GHG emissions associated with our operations, any of which could increase our operating costs and could adversely affect demand for the oil and gas that we produce. At this time, it is not possible to quantify the impact of such future laws and regulations on our business.

For additional information, please read “Business and Properties—Other Business Matters—Environmental and Safety Regulations—Greenhouse Gas and Climate Change Laws and Regulations” in Items 1 and 2.

We are subject to various climate-related risks.

The following is a summary of potential climate-related risks that could adversely affect us:

Transition Risks. Transition risks are related to the transition to a lower-carbon economy and include policy and legal, technology, and market risks.

Policy and Legal Risks. Policy risks include actions that seek to lessen activities that contribute to adverse effects of climate change or to promote adaptation to climate change. Examples of policy actions that would increase the costs of our operations or lower demand for our oil and gas include implementing carbon-pricing mechanisms, shifting energy use toward lower emission sources, adopting energy-efficiency solutions, encouraging greater water efficiency measures, and promoting more sustainable land-use practices. Policy actions also may include restrictions or bans on oil and gas activities, which could lead to write-downs or impairments of our assets or may incentivize the use of alternative or renewable sources of energy that could reduce the demand for our products. For example, the IRA contains tax inducements and other provisions that incentivize investment, development and deployment of alternative energy sources and technologies. Legal risks include potential lawsuits or regulations regarding the impacts of climate change, failure to adapt to climate change, and the insufficiency of disclosure around material financial risks. For example, the SEC in 2021 proposed rules on climate change disclosure requirements for public companies which, if adopted as proposed, could result in substantial compliance costs.

Furthermore, we could also face an increased risk of climate‐related litigation or “greenwashing” suits with respect to our operations, disclosures, or products. Claims have been made against certain energy companies alleging that GHG emissions from oil, gas and NGL operations constitute a public nuisance under federal and state law. Private individuals or public entities also could attempt to enforce environmental laws and regulations against us and could seek personal injury and property damages or other remedies. Additionally, governments and private parties are also increasingly filing suits, or initiating regulatory action, based on allegations that certain public statements regarding ESG-related matters by companies are false and misleading “greenwashing” campaigns that violate deceptive trade practices and consumer protection statutes or that climate-related disclosures made by companies are inadequate. Similar issues can also arise when aspirational statements such as net-zero or carbon neutrality targets are made without clear plans. Although we are not a party to any such climate-related or “greenwashing” litigation currently, unfavorable rulings against us in any such case brought against us in the future could significantly impact our operations and could have an adverse impact on our financial condition.

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Technology Risks. Technological improvements or innovations that support the transition to a lower-carbon, more energy efficient economic system may have a significant impact on us. The development and use of emerging technologies in renewable energy, battery storage, and energy efficiency may lower demand for oil and gas, resulting in lower prices and revenues, and higher costs. In addition, many automobile manufacturers have announced plans to shift production from internal combustion engine to electric powered vehicles, and states and foreign countries have announced bans on sales of internal combustion engine vehicles beginning as early as 2025, which would reduce demand for oil.

Market Risks. Markets could be affected by climate change through shifts in supply and demand for certain commodities, especially carbon-intensive commodities such as oil and gas and other products dependent on oil and gas. Lower demand for our oil and gas production could result in lower prices and lower revenues. Market risk also may take the form of limited access to capital as investors shift investments to less carbon-intensive industries and alternative energy industries. In addition, investment advisers, banks, and certain sovereign wealth, pension, and endowment funds recently have been promoting divestment of investments in fossil fuel companies and pressuring lenders to limit funding to companies engaged in the extraction, production, and sale of oil and gas. For additional information, please read “—Risks Related to our Indebtedness, Hedging Activities and Financial Position—We have substantial capital requirements, and we may not be able to obtain needed financing on satisfactory terms, if at all” in this Item 1A.

Reputation Risk. Climate change is a potential source of reputational risk, which is tied to changing customer or community perceptions of an organization’s contribution to, or detraction from, the transition to a lower-carbon economy. For additional information, please read “—ESG concerns and negative public perception regarding us and/or our industry could adversely affect our business operations and the price of our common stock, debt securities and preferred stock.” in this Item 1A.

Physical Risks. Potential physical risks resulting from climate change may be event driven (including increased severity of extreme weather events, such as hurricanes, droughts, or floods) or may be driven by longer-term shifts in climate patterns that may cause sea level rise or chronic heat waves. Potential physical risks may cause direct damage to assets and indirect impacts, such as supply chain disruption, and also could include changes in water availability, sourcing, and quality, which could impact drilling and completion operations. These physical risks could cause increased costs, production disruptions, lower revenues and substantially increase the cost or limit the availability of insurance.

We are subject to a number of privacy and data protection laws, rules and directives (collectively, data protection laws) relating to the processing of personal data.

The regulatory environment surrounding data protection laws is uncertain. Complying with varying jurisdictional requirements could increase the costs and complexity of compliance, and violations of applicable data protection laws can result in significant penalties. A determination that there have been violations of applicable data protection laws could expose us to significant damage awards, fines and other penalties that could materially harm our business and reputation.

Any failure, or perceived failure, by us to comply with applicable data protection laws could result in proceedings or actions against us by governmental entities or others, subject us to significant fines, penalties, judgments and negative publicity, require us to change our business practices, increase the costs and complexity of compliance and adversely affect our business. As noted above, we are also subject to the possibility of security and privacy breaches, which themselves may result in a violation of these laws. Additionally, the acquisition of a company that is not in compliance with applicable data protection laws may result in a violation of these laws.

Tax law changes could have an adverse effect on our financial position, results of operations and cash flows.

Substantive changes to existing federal income tax laws have been proposed that, if adopted, would repeal many tax incentives and deductions that are currently used by U.S. oil and gas companies and would impose new taxes. The proposals include: repeal of the percentage depletion allowance for oil and gas properties; elimination of the ability to fully deduct intangible drilling costs in the year incurred; and increase in the geological and geophysical amortization period for independent producers. Additional proposed general tax law changes include raising tax rates on both domestic and foreign income.

Should the U.S. or the states pass tax legislation limiting any currently allowed tax incentives and deductions, our taxes would increase, potentially significantly, which would have a negative impact on our net income and cash flows. This could also reduce our drilling activities in the U.S. Since future changes to federal and state tax legislation and regulations are unknown, we cannot predict the ultimate impact such changes may have on our business.

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Additional Risks Related to the Merger

We may fail to realize all of the anticipated benefits of the Merger.

The long-term success of the Merger will depend, in part, on our ability to realize the anticipated benefits and cost savings from combining our two businesses and operational synergies. The anticipated benefits and cost savings of the Merger may not be realized fully or at all, may take longer to realize than expected, may not be realized or could have other adverse effects that we do not currently foresee. Some of the assumptions that we have made, such as the achievement of the anticipated benefits related to the geographic, commodity and asset diversification and the expected size, scale, inventory and financial strength of the combined business, may not be realized. In addition, there could be potential unknown liabilities and unforeseen expenses associated with the Merger that could adversely impact us.

Risks Related to our Corporate Structure

Provisions of Delaware law and our bylaws and charter could discourage change-in-control transactions and prevent stockholders from receiving a premium on their investment.

Our charter authorizes our Board of Directors to set the terms of preferred stock. In addition, Delaware law contains provisions that impose restrictions on business combinations with interested parties. Our bylaws prohibit the calling of a special meeting by our stockholders and place procedural requirements and limitations on stockholder proposals at meetings of stockholders. Because of these provisions of our charter, bylaws and Delaware law, persons considering unsolicited tender offers or other unilateral takeover proposals may be more likely to negotiate with our Board of Directors rather than pursue non-negotiated takeover attempts. As a result, these provisions may make it more difficult for our stockholders to benefit from transactions that are opposed by an incumbent Board of Directors.

The personal liability of our directors for monetary damages for breach of their fiduciary duty of care is limited by the Delaware General Corporation Law and by our charter.

The Delaware General Corporation Law allows corporations to limit available relief for the breach of directors’ duty of care to equitable remedies such as injunction or rescission. Our charter limits the liability of our directors to the fullest extent permitted by Delaware law. Specifically, our directors will not be personally liable for monetary damages for any breach of their fiduciary duty as a director, except for liability:

•for any breach of their duty of loyalty to the Company or our stockholders;

•for acts or omissions not in good faith or that involve intentional misconduct or a knowing violation of law;

•under provisions relating to unlawful payments of dividends or unlawful stock repurchases or redemptions; and

•for any transaction from which the director derived an improper personal benefit.

This limitation may have the effect of reducing the likelihood of derivative litigation against directors, and may discourage or deter stockholders or management from bringing a lawsuit against directors for breach of their duty of care, even though such an action, if successful, might otherwise have benefited our stockholders.

The exclusive-forum provision contained in our bylaws could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers or other employees.

Our bylaws provide that, unless we consent in writing to the selection of an alternative forum, the sole and exclusive forum for (1) any derivative action or proceeding brought on behalf of us, (2) any action asserting a claim of breach of a fiduciary duty owed by any current or former director, officer, other employee or agent of Coterra to Coterra or our stockholders, including a claim alleging the aiding and abetting of such a breach of fiduciary duty, (3) any action asserting a claim arising pursuant to any provision of the Delaware General Corporation Law or our bylaws or charter or (4) any action asserting a claim governed by the internal affairs doctrine or asserting an "internal corporate claim" shall, to the fullest extent permitted by law, be the Court of Chancery of the State of Delaware (or, if the Court of Chancery does not have jurisdiction, the U.S. federal district court for the District of Delaware).

To the fullest extent permitted by applicable law, this exclusive-forum provision applies to state and federal law claims, including claims under the federal securities laws, including the Securities Act of 1933, as amended (the “Securities Act”), and the Securities Exchange Act of 1934, as amended (the “Exchange Act”), although our stockholders will not be deemed to have waived our compliance with the federal securities laws and the rules and regulations thereunder. This exclusive-forum provision may limit the ability of a stockholder to bring a claim in a judicial forum of its choosing for disputes with us or our

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directors, officers or other employees, which may discourage lawsuits against us and our directors, officers and other employees. Alternatively, if a court were to find this exclusive-forum provision inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings described above, we may incur additional costs associated with resolving such matters in other jurisdictions, which could negatively affect our business, results of operations and financial condition. In addition, stockholders who do bring a claim in a state or federal court located within the State of Delaware could face additional litigation costs in pursuing any such claim, particularly if they do not reside in or near Delaware. In addition, the court located in the State of Delaware may reach different judgments or results than would other courts, including courts where a stockholder would otherwise choose to bring the action, and such judgments or results may be more favorable to us than to our stockholders.

General Risk Factors

The loss of key personnel could adversely affect our ability to operate.

Our operations depend on a relatively small group of key management and technical personnel, and one or more of these individuals could leave our employment. The change in control and severance benefits triggered by the Merger may provide incentive for key management and technical personnel to leave our company. The unexpected loss of the services of one or more of these individuals could have a detrimental effect on us. In addition, our drilling success and the success of other activities integral to our operations will depend, in part, on our ability to attract and retain experienced geologists, engineers and other professionals. Competition for experienced geologists, engineers and some other professionals is extremely intense and can be exacerbated following a downturn in which talented professionals leave the industry or when potential new entrants to the industry decide not to undertake the professional training to enter the industry. This has occurred as a result of the downturn in commodity prices in 2020 and previous downturns and as a result of initiatives to move from oil and gas to alternative energy sources. If we cannot retain our technical personnel or attract additional experienced technical personnel, our ability to compete could be harmed.

Competition in our industry is intense, and many of our competitors have substantially greater financial and technological resources than we do, which could adversely affect our competitive position.

Competition in the oil and natural gas industry is intense. Major and independent oil and natural gas companies actively bid for desirable oil and gas properties, as well as for the capital, equipment, labor and infrastructure required to operate and develop these properties. Our competitive position is affected by price, contract terms and quality of service, including pipeline connection times, distribution efficiencies and reliable delivery record. Many of our competitors have financial and technological resources and exploration and development budgets that are substantially greater than ours. These companies may be able to pay more for exploratory projects and productive oil and gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may be able to expend greater resources on the existing and changing technologies that we believe will be increasingly important to attaining success in the industry. These companies may also have a greater ability to continue drilling activities during periods of low oil and natural gas prices and to absorb the burden of current and future governmental regulations and taxation.

Further, certain of our competitors may engage in bankruptcy proceedings, debt refinancing transactions, management changes or other strategic initiatives in an attempt to reduce operating costs to maintain a position in the market. This could result in such competitors emerging with stronger or healthier balance sheets and in turn an improved ability to compete with us in the future. We have seen and may continue to see corporate consolidations among our competitors, which could significantly alter industry conditions and competition within the industry.

Because our activity is concentrated in areas of heavy industry competition, there is heightened demand for equipment, power, services, facilities and resources, resulting in higher costs than in other areas. Such intense competition also could result in delays in securing, or the inability to secure, the equipment, power, services, resources or facilities necessary for our development activities, which could negatively impact our production volumes. In remote areas, vendors also can charge higher rates due to the inability to attract employees to those areas and the vendors’ ability to deploy their resources in easier-to-access areas.

The declaration, payment and amounts of future dividends distributed to our stockholders and the repurchase of our common stock will be uncertain.

Although we have paid cash dividends on shares of our common stock and have conducted repurchases of our common stock in the past, our Board of Directors may determine not to take such actions in the future or may reduce the amount of dividends or repurchases made in the future. Decisions on whether, when and in which amounts to declare and pay any future dividends, or to authorize and make any repurchases of our common stock, will remain in the discretion of our Board of

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Directors. We expect that any such decisions will depend on our financial condition, results of operations, cash balances, cash requirements, future prospects, the outlook for commodity prices and other considerations that our Board of Directors deems relevant.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 3. LEGAL PROCEEDINGS

Legal Matters

We are involved in various legal proceedings incidental to our business. The information set forth under the heading “Legal Matters” in Note 8 of the Notes to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K is incorporated by reference in response to this item.

Governmental Proceedings

From time to time we receive notices of violation from governmental and regulatory authorities, including notices relating to alleged violations of environmental statutes or the rules and regulations promulgated thereunder. While we cannot predict with certainty whether these notices of violation will result in fines, penalties or both, if fines or penalties are imposed, they may result in monetary sanctions, individually or in the aggregate, in excess of $300,000.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

INFORMATION ABOUT OUR EXECUTIVE OFFICERS

The following table shows certain information as of February 27, 2023 about our executive officers, as such term is defined in Rule 3b-7 of the Securities Exchange Act of 1934.


Name	Age	Position	Officer Since
Thomas E. Jorden	65	Chairman, Chief Executive Officer and President	2021
Scott C. Schroeder	60	Executive Vice President and Chief Financial Officer	1997
Stephen P. Bell	68	Executive Vice President, Business Development	2021
Christopher H. Clason	56	Senior Vice President and Chief Human Resources Officer	2021
Blake Sirgo	40	Senior Vice President, Operations	2021
Michael D. DeShazer	37	Vice President of Business Units	2021
Gary Hlavinka	61	Vice President, Marcellus Business Unit	2022
Todd M. Roemer	52	Vice President and Chief Accounting Officer	2010
Kevin W. Smith	37	Vice President and Chief Technology Officer	2021
Adam Vela	49	Vice President and General Counsel	2021

All officers are elected annually by our Board of Directors. All of the executive officers have been employed by Coterra Energy Inc. for at least the last five years, except for the following officers:

Mr. Jorden was appointed Chief Executive Officer and President of Coterra following the Merger with Cimarex in October 2021 and Chairman of the Board of Coterra in November 2022. Mr. Jorden previously served as the Chief Executive Officer and President of Cimarex beginning September 2011 and as Chairman of the Board of Directors of Cimarex beginning August 2012. At Cimarex, he began serving as Executive Vice President of Exploration when the company formed in 2002. Prior to the formation of Cimarex, Mr. Jorden held multiple leadership roles at Key Production Company, Inc. (“Key”), which was acquired by Cimarex in 2002. He joined Key in 1993 as Chief Geophysicist and subsequently became Executive Vice President of Exploration. Before joining Key, Mr. Jorden served at Union Pacific Resources and Superior Oil Company.

Mr. Bell was appointed Executive Vice President of Business Development following the Merger with Cimarex in October 2021. At Cimarex, Mr. Bell was appointed Senior Vice President of Business Development and Land in September 2002 and was named Executive Vice President of Business Development in September 2012. Mr. Bell served at Key prior to its

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acquisition by Cimarex. He joined Key in 1994 as Vice President of Land and was appointed Senior Vice President of Business Development and Land in 1999.

Mr. Clason was appointed Senior Vice President and Chief Human Resources Officer following the Merger with Cimarex in October 2021. Mr. Clason joined Cimarex as Vice President and Chief Human Resources Officer in 2019 and was named Senior Vice President and Chief Human Resources Officer in February 2020. Prior to Cimarex, Mr. Clason was Director of MBA Career Management and Employer Relations at the Marriott School of Business at Brigham Young University from 2016 to 2019. Prior to his work in higher education, he was Senior Vice President and Chief Human Resources Officer at ProBuild LLC, a Devonshire Investors company. From 2001 until 2014, Mr. Clason held various global human resources executive leadership roles at Honeywell International, including Vice President Human Resources and Communications at Honeywell Aerospace. His background includes extensive international experience at Citigroup and early career work at Chevron.

Mr. Sirgo was appointed Senior Vice President of Operations in October 2022. Mr. Sirgo previously served as Vice President of Operations at Coterra from October 1, 2021 to October 1, 2022. Prior to the Merger with Cimarex in October 2021, Mr. Sirgo served in a number of technical and leadership roles since joining Cimarex in 2008, including Vice President of Operation Resources from November 2018 to February 2020, Permian Division Production Manager from 2016 to November 2018, and in various engineering and production manager positions. Before joining Cimarex, Mr. Sirgo worked at Occidental Petroleum.

Mr. DeShazer was appointed Vice President of Business Units following the Merger with Cimarex in October 2021. Mr. DeShazer joined Cimarex in 2007, serving in various engineering and reservoir manager positions, as well as multiple leadership roles, including Technology Group Manager from 2016 to 2018 and Asset Evaluation Team Manager from 2018 to 2019. He was named Vice President of the Permian Business Unit in 2019.

Mr. Hlavinka was appointed Vice President of the Marcellus Business Unit in October 2022. Since joining Cabot Oil & Gas Corporation in 1989 he has served in engineering and management roles across the Company’s operations, in multiple producing basins. Mr. Hlavinka worked initially as a Facility Engineer and District Superintendent in the Company’s West Virginia production operations, and subsequently as a Corporate Reservoir Engineer in Houston, Texas. In 2006 he was named West Region Engineering Manager for the Rocky Mountain and Mid-Continent operating areas, and in 2009 he was promoted to Regional Operations Manager for the North Region, with responsibility for Appalachian Basin operations and engineering.

Mr. Smith was appointed Vice President and Chief Technology Officer following the Merger with Cimarex in October 2021. Mr. Smith began his career with Cimarex in 2007, serving in a number of technical and leadership roles, including Director of Technology and Anadarko Exploration Region Manager. In September 2020, Mr. Smith assumed the role of Chief Engineer for Cimarex.

Mr. Vela was appointed Vice President and General Counsel in October 2022. Mr. Vela previously served in various capacities at Coterra and Cimarex beginning in 2005, including Vice President, Assistant General Counsel, Chief Litigation Counsel and Corporate Counsel. Mr. Vela is a member of the Texas, Colorado, American, and Houston Hispanic Bar associations, as well as the Foundation for Natural Resources and Energy Law.

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Our $0.10 par value common stock is listed and principally traded on the NYSE under the ticker symbol “CTRA.” Cash dividends were paid to our common stockholders in each quarter of 2022. Future dividend payments will depend on the company’s level of earnings, financial requirements and other factors considered relevant by our Board of Directors.

As of February 1, 2023, there were 866 registered holders of our common stock.

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ISSUER PURCHASES OF EQUITY SECURITIES

The following table sets forth information regarding repurchases of our common stock during the quarter ended December 31, 2022.


Period	Total Number of Shares Purchased (In thousands) (1)	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (In thousands) (2)	Maximum Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (In millions)
October 2022	—	$	—	—	$	510
November 2022	4,492	$	27.07	4,492	$	388
December 2022	15,730	$	25.22	15,409	$	—
Total	20,222			19,901

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(1)Includes 320,236 shares of common stock purchased at an average price of $27.43 per share from employees in order for employees to satisfy income tax withholding payments related to share-based awards that vested in the period.

(2)In February 2022, our Board of Directors terminated the previously authorized share repurchase program and authorized a new share repurchase program. This new share repurchase program authorized us to purchase up to $1.25 billion of our common stock in the open market or in negotiated transactions, and was fully executed at December 31, 2022. During the quarter ended December 31, 2022, we purchased 19.9 million common shares for $510 million.

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PERFORMANCE GRAPH

The following graph compares our common stock performance (“CTRA”) with the performance of the Standard & Poor’s 500 Stock Index, the Dow Jones U.S. Exploration & Production Index and the S&P Oil & Gas Exploration & Production Index for the period December 2017 through December 2022. The graph assumes that the value of the investment in our common stock and in each index was $100 on December 31, 2017 and that all dividends were reinvested.


	December 31,
Calculated Values	2017		2018		2019		2020		2021		2022
CTRA	$	100.00	$	78.93	$	62.53	$	59.81	$	73.87	$	104.33
S&P 500	$	100.00	$	95.62	$	125.72	$	148.85	$	191.58	$	156.89
Dow Jones U.S. Exploration & Production	$	100.00	$	82.23	$	91.60	$	60.78	$	103.88	$	165.77
S&P Oil & Gas Exploration & Production	$	100.00	$	80.50	$	90.17	$	58.24	$	108.95	$	172.69

The performance graph above is furnished and shall not be deemed to be filed for purposes of Section 18 of the Exchange Act, or otherwise subject to the liabilities of that section, nor shall it be deemed to be incorporated by reference into any registration statement or other filing under the Securities Act or the Exchange Act unless specifically identified therein as being incorporated therein by reference. The performance graph is not soliciting material subject to Regulation 14A of the Exchange Act.

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PART II

ITEM 6. [RESERVED]

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

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

OVERVIEW

Cimarex Merger

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

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

Financial and Operating Overview

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Market Conditions and Commodity Prices

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

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

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

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

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

Inflation

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

Climate

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

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

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

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

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

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

FINANCIAL CONDITION

Liquidity and Capital Resources

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

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

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

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

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

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Cash Flows

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


	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)

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

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

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

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

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

Revolving Credit Facility

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

Certain Restrictive Covenants

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

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placement senior notes. Refer to Note 4 of the Notes to the Consolidated Financial Statements, “Long-Term Debt and Credit Agreements,” for further details regarding the restrictive covenants contained in our various debt instruments.

Capitalization

Information about our capitalization is as follows:


	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

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.


	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

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

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

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Capital and Exploration Expenditures

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

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


	Year Ended December 31,
(In millions)	2022		2021		2020
Acquisitions(1) :
Proved	$	—	$	7,472	$	—
Unproved	—		5,381		—
Total	$	—	$	12,853	$	—

Capital expenditures
Drilling and facilities	$	1,617	$	688	$	547
Leasehold acquisitions	10		5		6

Pipeline and gathering	56		9		—
Other	54		23		17
	1,737		725		570
Exploration expenditures(2)	29		18		15
Total	$	1,766	$	743	$	585

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

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

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

Contractual Obligations

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

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

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Critical Accounting Estimates

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

Purchase Accounting

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

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

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

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

Successful Efforts Method of Accounting

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

Oil and Gas Reserves

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

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

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

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

Oil and Gas Properties

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

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

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

Derivative Instruments

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

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

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

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

Income Taxes

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

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

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

Contingency Reserves

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

Stock-Based Compensation

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

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RESULTS OF OPERATIONS

2022 and 2021 Compared

Operating Revenues


	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	%

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


	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

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


	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

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

NGL Revenues


	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

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

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Loss on Derivative Instruments

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


	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)

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.


	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	%

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Direct Operations

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


	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

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:


	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	—			1			(1)
	$	366		$	83		$	283
Taxes other than income as a percentage of production revenue	3.9		%	2.3		%

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

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Depreciation, Depletion and Amortization

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


	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

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:


	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

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.

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Stock-based compensation expense will fluctuate based on the grant date fair value of awards, the number of awards, the requisite service period of the awards, estimated employee forfeitures, and the timing of the awards. Stock-based compensation expense increased $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:


	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

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


	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		%

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.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

In the normal course of business, we are subject to a variety of risks, including market risks associated with changes in commodity prices and interest rate movements on outstanding debt. The following quantitative and qualitative information is provided for financial instruments to which we were party to as of December 31, 2022 and from which we may incur future gains or losses from changes in commodity prices or interest rates.

Commodity Price Risk

Our most significant market risk exposure is pricing applicable to our oil, natural gas and NGL production. Realized prices are mainly driven by the worldwide price for oil and spot market prices for North American natural gas and NGL production. These prices have been volatile and unpredictable. To mitigate the volatility in commodity prices, we may enter into derivative instruments to hedge a portion of our production.

Derivative Instruments and Risk Management Activities

Our risk management strategy is designed to reduce the risk of commodity price volatility for our production in the oil and natural gas markets through the use of financial commodity derivatives. A committee that consists of members of senior management oversees our risk management activities. Our financial commodity derivatives generally cover a portion of our production and, while protecting us in the event of price declines, limit the benefit to us in the event of price increases. Further, if any of our counterparties defaulted, this protection might be limited as we might not receive the full benefit of our financial commodity derivatives. Please read the discussion below as well as Note 5 of the Notes to the Consolidated Financial Statements, “Derivative Instruments,” in Item 8, for a more detailed discussion of our derivatives.

Periodically, we enter into financial commodity derivatives, including collar, swap, and basis swap agreements, to protect against exposure to commodity price declines related to our oil and natural gas production. Our credit agreement restricts our ability to enter into financial commodity derivatives other than to hedge or mitigate risks to which we have actual or projected exposure or as permitted under our risk management policies and not subjecting us to material speculative risks. All of our financial derivatives are used for risk management purposes and are not held for trading purposes. Under the collar agreements, if the index price rises above the ceiling price, we pay the counterparty. If the index price falls below the floor price, the counterparty pays us. Under the swap agreements, we receive a fixed price on a notional quantity of natural gas or oil in exchange for paying a variable price based on a market-based index.

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As of December 31, 2022, we had the following outstanding financial commodity derivatives:



	2023								Estimated Fair Value Asset (Liability) (In millions)
Natural Gas	First Quarter		Second Quarter		Third Quarter		Fourth Quarter




Waha gas collars									$	44
Volume (MMBtu)	8,100,000		8,190,000		8,280,000		8,280,000
Weighted average floor ($/MMBtu)	$	3.03	$	3.03	$	3.03	$	3.03
Weighted average ceiling ($/MMBtu)	$	5.39	$	5.39	$	5.39	$	5.39

NYMEX collars									$	95
Volume (MMBtu)	54,000,000		31,850,000		32,200,000		29,150,000
Weighted average floor ($/MMBtu)	$	5.12	$	4.07	$	4.07	$	4.03
Weighted average ceiling ($/MMBtu)	$	9.34	$	6.78	$	6.78	$	6.61
									$	139



	2023				Estimated Fair Value Asset (Liability) (In millions)
Oil	First Quarter		Second Quarter
WTI oil collars					$	8
Volume (MBbl)	1,350		1,365
Weighted average floor ($/Bbl)	$	70.00	$	70.00
Weighted average ceiling ($/Bbl)	$	116.03	$	116.03

WTI Midland oil basis swaps					$	(1)
Volume (MBbl)	1,350		1,365
Weighted average differential ($/Bbl)	$	0.63	$	0.63
					$	7

The amounts set forth in the table above represent our total unrealized derivative position at December 31, 2022 and exclude the impact of non-performance risk. Non-performance risk is considered in the fair value of our derivative instruments that are recorded in our Consolidated Financial Statements and is primarily evaluated by reviewing credit default swap spreads for the various financial institutions with which we have derivative contracts, while our non-performance risk is evaluated using a market credit spread provided by several of our banks.

A significant portion of our expected oil and natural gas production for 2023 and beyond is currently unhedged and directly exposed to the volatility in commodity prices, whether favorable or unfavorable.

During 2022, natural gas collars with floor prices ranging from $1.70 to $8.50 per MMBtu and ceiling prices ranging from $2.10 to $13.08 per MMBtu covered 245.8 Bcf, or 24 percent of natural gas production at a weighted-average price of $4.94 per MMBtu. Natural gas swaps covered 14.9 Bcf, or one percent, of natural gas production at a weighted-average price of $2.26 per MMBtu.

We are exposed to market risk on financial commodity derivative instruments to the extent of changes in market prices of oil and natural gas. However, the market risk exposure on these derivative contracts is generally offset by the gain or loss recognized upon the ultimate sale of the commodity. Although notional contract amounts are used to express the volume of oil and natural gas agreements, the amounts that can be subject to credit risk in the event of non-performance by third parties are substantially smaller. Our counterparties are primarily commercial banks and financial service institutions that management believes present minimal credit risk and our derivative contracts are with multiple counterparties to minimize our exposure to any individual counterparty. We perform both quantitative and qualitative assessments of these counterparties based on their credit ratings and credit default swap rates where applicable. We have not incurred any losses related to non-performance risk

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of our counterparties and we do not anticipate any material impact on our financial results due to non-performance by third parties. However, we cannot be certain that we will not experience such losses in the future.

Interest Rate Risk

At December 31, 2022, we had total debt of $2.2 billion (with a principal amount of $2.1 billion). All of our outstanding debt is based on fixed interest rates and, as a result, we do not have significant exposure to movements in market interest rates with respect to such debt. Our revolving credit facility provides for variable interest rate borrowings; however, we did not have any borrowings outstanding as of December 31, 2022 and, therefore, no related exposure to interest rate risk.

Fair Value of Other Financial Instruments

The estimated fair value of other financial instruments is the amount at which the instrument could be exchanged currently between willing parties. The carrying amounts reported in the Consolidated Balance Sheet for cash, cash equivalents and restricted cash approximate fair value due to the short-term maturities of these instruments.

The fair value of our senior notes is based on quoted market prices. We use available market data and valuation methodologies to estimate the fair value of our private placement senior notes. The fair value of the private placement senior notes is the estimated amount we would have to pay a third party to assume the debt, including a credit spread for the difference between the issue rate and the period end market rate. The credit spread is our default or repayment risk. The credit spread (premium or discount) is determined by comparing our senior notes and revolving credit facility to new issuances (secured and unsecured) and secondary trades of similar size and credit statistics for both public and private debt. The fair value of the private placement senior notes is based on interest rates currently available to us.

The carrying amount and estimated fair value of debt is as follows:


	December 31, 2022				December 31, 2021
(In millions)	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-term debt	$	2,181	$	1,955	$	3,125	$	3,163

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS


			Page
Report of Independent Registered Public Accounting Firm (PCAOB ID: 238)			57
Consolidated Balance Sheet at December 31, 2022 and 2021			59
Consolidated Statement of Operations for the Years Ended December 31, 2022, 2021 and 2020			60
Consolidated Statement of Comprehensive Income for the Years Ended December 31, 2022, 2021 and 2020			61
Consolidated Statement of Cash Flows for the Years Ended December 31, 2022, 2021 and 2020			62
Consolidated Statement of Stockholders' Equity for the Years Ended December 31, 2022, 2021 and 2020			63
Notes to the Consolidated Financial Statements			64
Supplemental Oil and Gas Information (Unaudited)			99

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Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of Coterra Energy Inc.

Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the accompanying consolidated balance sheet of Coterra Energy Inc. and its subsidiaries (the “Company”) as of December 31, 2022 and 2021, and the related consolidated statements of operations, of comprehensive income, of stockholders’ equity and of cash flows for each of the three years in the period ended December 31, 2022, including the related notes (collectively referred to as the “consolidated financial statements”). We also have audited the Company’s internal control over financial reporting as of December 31, 2022, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2022 and 2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2022 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2022, based on criteria established in Internal Control – Integrated Framework (2013) issued by the COSO.

Basis for Opinions

The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.

Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

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Critical Audit Matters

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

The Impact of Proved Oil and Natural Gas Reserves on Proved Oil and Gas Properties

As described in Notes 1 and 3 to the consolidated financial statements, a significant portion of the Company’s properties and equipment, net balance of $17,479 million as of December 31, 2022 and depreciation, depletion and amortization (DD&A) expense of $1,635 million for the year ended December 31, 2022 relate to proved oil and gas properties. The Company uses the successful efforts method of accounting for its oil and gas producing activities. As disclosed by management, the Company’s rate of recording DD&A expense is dependent upon the estimate of proved reserves and proved developed reserves, which are utilized in the unit-of-production calculation. In estimating proved oil and natural gas reserves, management relies on interpretations and judgment of available geological, geophysical, engineering and production data, as well as the use of certain economic assumptions such as commodity prices. Additional assumptions include drilling and operating expenses, capital expenditures, taxes and availability of funds. The estimates of oil and natural gas reserves have been developed by specialists, specifically petroleum engineers.

The principal considerations for our determination that performing procedures relating to the impact of proved oil and natural gas reserves on proved oil and gas properties is a critical audit matter are (i) the significant judgment by management, including the use of specialists, when developing the estimates of proved oil and natural gas reserves, which in turn led to (ii) a high degree of auditor judgment and effort in performing procedures and evaluating the audit evidence related to the data, methods, and assumptions used by management and its specialists in developing the estimates of proved oil and natural gas reserves.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s estimates of proved oil and natural gas reserves. The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of the proved oil and natural gas reserves. As a basis for using this work, the specialist’s qualifications were understood and the Company’s relationship with the specialists was assessed. The procedures performed also included evaluation of the methods and assumptions used by the specialists, tests of the completeness and accuracy of the data used by the specialists, and an evaluation of the specialist’s findings.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

February 27, 2023

We have served as the Company’s auditor since 1989.

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COTERRA ENERGY INC.

CONSOLIDATED BALANCE SHEET


	December 31,
(In millions, except share and per share amounts)	2022		2021
ASSETS
Current assets
Cash and cash equivalents	$	673	$	1,036
Restricted cash	10		10
Accounts receivable, net	1,221		1,037
Income taxes receivable	89		—
Inventories	63		39
Derivative instruments	146		7

Other current assets	9		7
Total current assets	2,211		2,136
Properties and equipment, net (Successful efforts method)	17,479		17,375



Other assets	464		389
	$	20,154	$	19,900
LIABILITIES, REDEEMABLE PREFERRED STOCK AND STOCKHOLDERS' EQUITY
Current liabilities
Accounts payable	$	844	$	747

Accrued liabilities	328		260
Interest payable	21		25
Income taxes payable	—		29

Derivative instruments	—		159

Total current liabilities	1,193		1,220
Long-term debt, net	2,181		3,125
Deferred income taxes	3,339		3,101
Asset retirement obligations	271		259


Other liabilities	500		407
Total liabilities	7,484		8,112



Commitments and contingencies

Cimarex redeemable preferred stock	11		50

Stockholders' equity
Common stock:
Authorized — 1,800,000,000 shares of $0.10 par value in 2022 and 2021
Issued — 768,244,610 shares and 892,612,010 shares in 2022 and 2021, respectively	77		89
Additional paid-in capital	7,933		10,911
Retained earnings	4,636		2,563
Accumulated other comprehensive income	13		1
Less treasury stock, at cost:
79,082,385 shares in 2021	—		(1,826)
Total stockholders' equity	12,659		11,738
	$	20,154	$	19,900

The accompanying notes are an integral part of these consolidated financial statements.

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COTERRA ENERGY INC.

CONSOLIDATED STATEMENT OF OPERATIONS


	Year Ended December 31,
(In millions, except per share amounts)	2022		2021		2020
OPERATING REVENUES
Natural gas	$	5,469	$	2,798	$	1,405
Oil	3,016		616		—
NGL	964		243		—
(Loss) gain on derivative instruments	(463)		(221)		61
Other	65		13		—
	9,051		3,449		1,466
OPERATING EXPENSES
Direct operations	460		156		73
Transportation, processing and gathering	955		663		571
Taxes other than income	366		83		14
Exploration	29		18		15
Depreciation, depletion and amortization	1,635		693		391


General and administrative	396		270		106
	3,841		1,883		1,170

Loss on sale of assets	(1)		(2)		—
INCOME FROM OPERATIONS	5,209		1,564		296
Interest expense, net	70		62		54
Gain on debt extinguishment	(28)		—		—
Other (income) expense	(2)		—		—
Income before income taxes	5,169		1,502		242
Income tax expense	1,104		344		41
NET INCOME	$	4,065	$	1,158	$	201





Earnings per share
Basic	$	5.09	$	2.30	$	0.50
Diluted	$	5.08	$	2.29	$	0.50

Weighted-average common shares outstanding
Basic	796		503		399
Diluted	799		504		401

The accompanying notes are an integral part of these consolidated financial statements.

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COTERRA ENERGY INC.

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME


	Year Ended December 31,
(In millions)	2022		2021		2020
Net income	$	4,065	$	1,158	$	201
Postretirement benefits:
Net actuarial gain(1)	12		—		1

Amortization of prior service credit(2)	(1)		(1)		(1)

Plan amendment (3)	1		—		—


Total other comprehensive income	12		(1)		—
Comprehensive income	$	4,077	$	1,157	$	201

_______________________________________________________________________________

(1)Net of income taxes of $3 million for the year ended December 31, 2022 and less than $1 million for the years ended December 31, 2021 and 2020.

(2)Net of income taxes of less than $1 million for each of the years ended December 31, 2022, 2021 and 2020.

(3)Net of income taxes of less than $1 million for the year ended December 31, 2022.

The accompanying notes are an integral part of these consolidated financial statements.

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COTERRA ENERGY INC.

CONSOLIDATED STATEMENT OF CASH FLOWS


	Year Ended December 31,
(In millions)	2022		2021		2020
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	4,065	$	1,158	$	201
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	1,635		693		391


Deferred income tax expense	235		126		72
Loss on sale of assets	1		2		—
Exploratory dry hole cost	—		—		4
Loss (gain) on derivative instruments	463		221		(61)
Net cash (paid) received in settlement of derivative instruments	(762)		(431)		35


Amortization of debt premium and debt issuance costs	(40)		(10)		3
Gain on debt extinguishment	(28)		—		—
Stock-based compensation and other	73		52		40
Changes in assets and liabilities:
Accounts receivable, net	(184)		(229)		(6)
Income taxes	(118)		34		124
Inventories	(24)		5		(2)
Other current assets	(4)		(4)		—
Accounts payable and accrued liabilities	96		47		(30)
Interest payable	(5)		6		(2)
Other assets and liabilities	53		(3)		9

Net cash provided by operating activities	5,456		1,667		778
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures for drilling, completion and other fixed asset additions	(1,700)		(723)		(570)

Capital expenditures for leasehold and property acquisitions	(10)		(5)		(6)
Proceeds from sale of assets	36		8		1


Cash received from Merger	—		1,033		—
Proceeds from sale of equity method investments	—		—		(9)
Net cash (used in) provided by investing activities	(1,674)		313		(584)
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings from debt	—		100		196
Repayments of debt	(874)		(288)		(283)
Repayment of finance leases	(6)		(2)		—
Common stock repurchases	(1,250)		—		—

Dividends paid	(1,992)		(780)		(159)

Tax withholding on vesting of stock awards	(25)		(114)		(10)
Capitalized debt issuance costs	—		(4)		—
Cash received for stock option exercises	12		2		—

Cash paid for conversion of redeemable preferred stock	(10)		—		—
Net cash used in financing activities	(4,145)		(1,086)		(256)
Net (decrease) increase in cash, cash equivalents and restricted cash	(363)		894		(62)
Cash, cash equivalents and restricted cash, beginning of period	1,046		152		214
Cash, cash equivalents and restricted cash, end of period	$	683	$	1,046	$	152

The accompanying notes are an integral part of these consolidated financial statements.

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COTERRA ENERGY INC.

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY


(In millions, except per share amounts)	Common Shares	Common Stock Par		Treasury Shares	Treasury Stock		Paid-In Capital		Accumulated Other Comprehensive Income (Loss)		Retained Earnings		Total
Balance at December 31, 2019	477	$	48	79	$	(1,823)	$	1,782	$	1	$	2,143	$	2,151
Net income	—	—		—	—		—		—		201		201


Stock amortization and vesting	1	—		—	—		22		—		—		22



Cash dividends at $0.40 per share	—	—		—	—		—		—		(159)		(159)
Other comprehensive income	—	—		—	—		—		1		—		1

Balance at December 31, 2020	478	$	48	79	$	(1,823)	$	1,804	$	2	$	2,185	$	2,216
Net income	—	—		—	—		—		—		1,158		1,158
Issuance of common stock for merger	408	41		—	—		9,042		—		—		9,083
Issuance of replacement awards and options for merger consideration	4	—		—	—		37		—		—		37
Exercise of stock options	—	—		—	—		2		—		—		2
Stock amortization and vesting	3	—		—	(3)		26		—		—		23



Cash dividends:
Common stock at $1.12 per share	—	—		—	—		—		—		(779)		(779)
Preferred stock at $20.3125 per share	—	—		—	—		—		—		(1)		(1)
Other comprehensive loss	—	—		—	—		—		(1)		—		(1)

Balance at December 31, 2021	893	$	89	79	$	(1,826)	$	10,911	$	1	$	2,563	$	11,738
Net income	—	—		—	—		—		—		4,065		4,065
Exercise of stock options	1	—		—	—		12		—		—		12
Stock amortization and vesting	1	1		1	(9)		54		—		—		46
Common stock repurchases	—	—		48	(1,250)		—		—		—		(1,250)
Common stock retirements	(128)	(13)		(128)	3,085		(3,072)		—		—		—
Conversion of Cimarex redeemable preferred stock	1	—		—	—		28		—		—		28
Cash dividends:
Common stock at $2.49 per share	—	—		—	—		—		—		(1,991)		(1,991)
Preferred stock at $20.3125 per share	—	—		—	—		—		—		(1)		(1)
Other comprehensive income	—	—		—	—		—		12		—		12

Balance at December 31, 2022	768	$	77	—	$	—	$	7,933	$	13	$	4,636	$	12,659

The accompanying notes are an integral part of these consolidated financial statements.

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

1. Summary of Significant Accounting Policies

Basis of Presentation and Nature of Operations

Coterra Energy Inc. and its subsidiaries (“Coterra” or the “Company”) are engaged in the development, exploration and production of oil, natural gas and NGLs exclusively within the continental U.S. The Company’s exploration and development activities are concentrated in areas with known hydrocarbon resources, which are conducive to multi-well, repeatable drilling programs.

The Company operates in one segment, oil and natural gas development, exploration and production. The Company’s oil and gas properties are managed as a whole rather than through discrete operating segments. Operational information is tracked by geographic area; however, financial performance is assessed as a single enterprise and not on a geographic basis. Allocation of resources is made on a project basis across the Company’s entire portfolio without regard to geographic areas.

The consolidated financial statements include the accounts of the Company and its subsidiaries after eliminating all significant intercompany balances and transactions. Certain reclassifications have been made to prior year statements to conform with the current year presentation. These reclassifications have no impact on previously reported stockholders’ equity, net income or cash flows.

The Company and Cimarex Energy Co. (“Cimarex”) completed a merger transaction on October 1, 2021 (the “Merger”), pursuant to an agreement entered into by the Company and Cimarex (the “Merger Agreement”). Refer to Note 2, “Acquisitions,” for further information. Additionally, on October 1, 2021, Cabot Oil & Gas Corporation changed its name to Coterra Energy Inc.

Significant Accounting Policies

Cash and Cash Equivalents

The Company considers all highly liquid short-term investments with a maturity of three months or less and deposits in money market funds that are readily convertible to cash to be cash equivalents. Cash and cash equivalents were primarily concentrated in three financial institutions at December 31, 2022. The Company periodically assesses the financial condition of its financial institutions and considers any possible credit risk to be minimal.

Restricted Cash

Restricted cash includes cash that is legally or contractually restricted as to withdrawal or usage. As of December 31, 2022 and 2021, the restricted cash balance of $10 million and $10 million, respectively, includes cash deposited in escrow accounts that are restricted for use.

Allowance for Doubtful Accounts

The Company records an allowance for doubtful accounts based on the Company’s estimate of future expected credit losses on outstanding receivables.

Inventories

Inventories are comprised of tubular goods and well equipment and are carried at average cost. Inventories are assessed periodically for obsolescence.

Properties and Equipment

Oil and Gas Properties

The Company uses the successful efforts method of accounting for oil and gas producing activities. Under this method, acquisition costs for proved and unproved properties are capitalized when incurred. Exploration costs, including geological and geophysical costs, the costs of carrying and retaining unproved properties and exploratory dry hole drilling costs, are expensed. Development costs, including the costs to drill and equip development wells and successful exploratory drilling costs to locate proved reserves are capitalized.

Exploratory drilling costs are capitalized when incurred pending the determination of whether a well has found proved reserves. The determination is based on a process which relies on interpretations of available geologic, geophysical and

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engineering data. If a well is determined to be successful, the capitalized drilling costs will be reclassified as part of the cost of the well. If a well is determined to be unsuccessful, the capitalized drilling costs will be charged to exploration expense in the Consolidated Statement of Operations in the period the determination is made. If an exploratory well requires a major capital expenditure before production can begin, the cost of drilling the exploratory well will continue to be carried as an asset pending determination of whether reserves have been found only as long as: (1) the well has found a sufficient quantity of reserves to justify its completion as a producing well if the required capital expenditure is made and (2) drilling of an additional exploratory well is under way or firmly planned for the near future. If drilling in the area is not under way or firmly planned or if the well has not found a commercially producible quantity of reserves, the exploratory well is assumed to be impaired and its costs are charged to exploration expense.

Development costs of proved oil and gas properties, including estimated dismantlement, restoration and abandonment costs and acquisition costs, are depreciated and depleted on a field basis by the unit-of-production method using proved developed and proved reserves, respectively.

Costs of sold or abandoned properties that make up a part of an amortization base (partial field) remain in the amortization base if the unit-of-production rate is not significantly affected. If significant, a gain or loss, if any, is recognized and the sold or abandoned properties are retired. A gain or loss, if any, is also recognized when a group of proved properties (entire field) that make up the amortization base has been retired, abandoned or sold.

The Company evaluates its proved oil and gas properties for impairment whenever events or changes in circumstances indicate an asset’s carrying amount may not be recoverable. The Company compares expected undiscounted future cash flows to the net book value of the asset. If the future undiscounted expected cash flows, based on estimates 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 as well as historical and current prices adjusted for geographical location and quality differentials, as well as other factors that management believes will impact realizable prices. 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 the Company’s undeveloped acreage amortization based on past drilling and exploration experience, the Company’s 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.

Fixed Assets

Fixed assets consist primarily of gas gathering systems, 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.

Asset Retirement Obligations

The Company records the fair value of a liability for an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated asset retirement cost is capitalized as part of the carrying amount of the long-lived asset. Asset retirement costs for oil and gas properties are depreciated using the unit-of-production method, while asset retirement costs for other assets are depreciated using the straight-line method over estimated useful lives.

Additional retirement obligations increase the liability associated with new oil and gas wells and other facilities as these obligations are incurred. Accretion expense is included in depreciation, depletion and amortization expense in the Consolidated Statement of Operations.

Derivative Instruments

The Company enters into financial derivative contracts, primarily collars, swaps and basis swaps, to manage its exposure to price fluctuations on a portion of its anticipated future production volumes. The Company’s credit agreement restricts the ability of the Company to enter into financial commodity derivatives other than to hedge or mitigate risks to which the Company has actual or projected exposure or as permitted under the Company’s risk management policies and where such derivatives do not subject the Company to material speculative risks. All of the Company’s derivatives are used for risk management purposes and are not held for trading purposes. The Company has elected not to designate its financial derivative instruments as accounting hedges under the accounting guidance.

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The Company evaluates all of its physical purchase and sale contracts to determine if they meet the definition of a derivative. For contracts that meet the definition of a derivative, the Company may elect the normal purchase normal sale (“NPNS”) exception provided under the applicable accounting guidance and account for the contract using the accrual method of accounting. Contracts that do not qualify for or for which the Company elects not to apply the NPNS exception are accounted for at fair value.

All derivatives, except for derivatives that qualify for the NPNS exception, are recognized on the balance sheet and are measured at fair value. At the end of each quarterly period, these derivatives are marked to market. As a result, changes in the fair value of derivatives are recognized in operating revenues in gain (loss) on derivative instruments. The resulting cash flows are reported as cash flows from operating activities.

Leases

The Company determines if an arrangement is, or contains, a lease at inception based on whether that contract conveys the right to control the use of an identified asset in exchange for consideration for a period of time. Operating leases are included in right-of-use assets (“ROU assets”) and lease liabilities (current and non-current) in the Consolidated Balance Sheet. Financing leases are included in properties and equipment, net and lease liabilities (current and non-current) in the Consolidated Balance Sheet. Short-term leases (a lease that, at commencement, has a lease term of one year or less and does not contain a purchase option that the Company is reasonably certain to exercise) are not recognized in ROU assets and lease liabilities. For all operating leases, lease and non-lease components are accounted for as a single lease component.

ROU assets represent the Company’s right to use an underlying asset for the lease term and lease liabilities represent the Company’s obligation to make lease payments arising from the leases. ROU assets and lease liabilities are recognized at the lease commencement date based on the present value of minimum lease payments over the lease term. Most leases do not provide an implicit interest rate; therefore, the Company uses its incremental borrowing rate based on the information available at the inception date to determine the present value of the lease payments. Lease terms include options to extend the lease when it is reasonably certain that the Company will exercise that option. Lease cost for lease payments is recognized on a straight-line basis over the lease term. Certain leases have payment terms that vary based on the usage of the underlying assets. Variable lease payments are not included in ROU assets and lease liabilities.

Fair Value of Assets and Liabilities

The Company follows the authoritative accounting guidance for measuring fair value of assets and liabilities in its financial statements. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Company utilizes market data or assumptions that market participants who are independent, knowledgeable and willing and able to transact would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. The Company is able to classify fair value balances based on the observability of these inputs. The authoritative guidance for fair value measurements establishes three levels of the fair value hierarchy, defined as follows:

•Level 1: Unadjusted, quoted prices for identical assets or liabilities in active markets.

•Level 2: Quoted prices in markets that are not considered to be active or financial instruments for which all significant inputs are observable, either directly or indirectly for substantially the full term of the asset or liability.

•Level 3: Significant, unobservable inputs for use when little or no market data exists, requiring a significant degree of judgment.

The hierarchy gives the highest priority to Level 1 measurements and the lowest priority to Level 3 measurements. Depending on the particular asset or liability, input availability can vary depending on factors such as product type, longevity of a product in the market and other particular transaction conditions. In some cases, certain inputs used to measure fair value may be categorized into different levels of the fair value hierarchy. For disclosure purposes under the accounting guidance, the lowest level that contains significant inputs used in the valuation should be chosen.

Revenue Recognition

The Company’s revenue is typically generated from contracts to sell oil, natural gas and NGLs produced from interests in oil and gas properties owned by the Company. These contracts generally require the Company to deliver a specific amount of a commodity per day for a specified number of days at a price that is either fixed or variable. The contracts specify a delivery point which represents the point at which control of the product is transferred to the customer. The Company has determined

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that these contracts represent multiple performance obligations which are satisfied when control of the commodity transfers to the customer, typically through the delivery of the specified commodity to a designated delivery point.

Revenue is measured based on consideration specified in the contract with the customer, and excludes any amounts collected on behalf of third parties. The Company recognizes revenue in the amount that reflects the consideration it expects to be entitled to in exchange for transferring control of those goods to the customer. The contract consideration in the Company’s variable price contracts are typically allocated to specific performance obligations in the contract according to the price stated in the contract. Amounts allocated in the Company’s fixed price contracts are based on the standalone selling price of those products in the context of long-term, fixed price contracts, which generally approximates the contract price. Payment is generally received one or two months after the sale has occurred.

The Company has not adjusted the promised amount of consideration for the effects of a significant financing component if the Company expects, at contract inception, that the period between when the Company transfers a promised good or service to the customer and when the customer pays for that good or service will be one year or less.

For contracts with an original expected term of one year or less, the Company has elected not to disclose the transaction price allocated to the unsatisfied performance obligations. For contracts with terms greater than one year, the Company has elected not to disclose the price allocated to the unsatisfied performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Since each unit of the respective commodity typically represents a separate performance obligation, future volumes are considered wholly unsatisfied, and disclosure of the transaction price allocated to the remaining performance obligation is not required.

Taxes assessed by a governmental authority that are both imposed on and concurrent with a specific revenue-producing transaction, and that are collected by the Company from a customer, are excluded from revenue.

Income Taxes

The Company follows the asset and liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are recorded for the estimated future tax consequences attributable to the differences between the financial carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using the tax rate in effect for the year in which those temporary differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the year of the enacted rate change. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.

The Company follows the “equity first” approach when applying the limitation for certain executive compensation in excess of $1 million to future compensation. The limitation is first applied to stock-based compensation that vests in future tax years before considering cash compensation paid in a future period. Accordingly, the Company records a deferred tax asset for stock-based compensation expense recorded in the current period, and reverses the temporary difference in the future period, during which the stock-based compensation becomes deductible for tax purposes.

The Company is required to make judgments, including estimating reserves for potential adverse outcomes regarding tax positions that the Company has taken. The Company accounts for 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.

The Company recognizes accrued interest related to uncertain tax positions in interest expense and accrued penalties related to such positions in general and administrative expense in the Consolidated Statement of Operations.

Stock-Based Compensation

The Company accounts for stock-based compensation under the fair value method of accounting. Under this 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, the Company uses a Black Scholes or Monte Carlo valuation model based on the specific provisions of the award. Stock-based compensation cost for all types of awards is included in general and administrative expense in the Consolidated Statement of Operations.

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The Company records excess tax benefits and tax deficiencies on stock-based compensation in the income statement upon vesting of the respective awards. Excess tax benefits and tax deficiencies are included in cash flows from operating activities in the Consolidated Statement of Cash Flow.

Cash paid by the Company when directly withholding shares from employee stock-based compensation awards for tax-withholding purposes are classified as financing activities in the Consolidated Statement of Cash Flow.

Earnings per Share

The Company calculates earnings per share recognizing that unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents are “participating securities” and, therefore, should be included in computing earnings per share using the two-class earnings allocation method. The two-class method is an earnings allocation formula that determines earnings per share for each class of common stock and participating security according to dividends declared (or accumulated) and participation rights in undistributed earnings. Certain of the Company’s unvested share-based payment awards, consisting of restricted stock, qualify as participating securities. The Company’s participating securities do not have a contractual obligation to share in the losses of the entity and, therefore, net losses are not allocated to them.

Environmental Matters

Environmental expenditures are expensed or capitalized, as appropriate, depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations, and that do not have future economic benefit are expensed. Liabilities related to future costs are recorded on an undiscounted basis when environmental assessments and/or remediation activities are probable and the costs can be reasonably estimated. Any insurance recoveries are recorded as assets when received.

Credit and Concentration Risk

Substantially all of the Company’s accounts receivable result from the sale of oil, natural gas and NGLs to third parties in the oil and gas industry and joint interest billings with other participants in joint operations. This concentration of purchasers and joint owners may impact the Company’s overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions. The Company does not anticipate any material impact on its financial results due to non-performance by the third parties.

During the year ended December 31, 2022, two customers accounted for approximately 13 percent and 11 percent of the Company’s total sales. During the year ended December 31, 2021, no customer accounted for more than 10 percent of the Company’s total sales. During the year ended December 31, 2020, three customers accounted for approximately 21 percent, 16 percent and 12 percent of the Company’s total sales. The Company does not believe that the loss of any of its major customers would have a material adverse effect on it because alternative customers are readily available. If any one of the Company’s major customers were to stop purchasing the Company’s production, the Company believes there are a number of other purchasers to whom it could sell its production. If multiple significant customers were to stop purchasing the Company’s production, the Company believes there could be some initial challenges, but the Company believes it has ample alternative markets to handle any sales disruptions.

The Company regularly monitors the creditworthiness of its customers and may require parent company guarantees, letters of credit or prepayments when necessary. Historically, losses associated with uncollectible receivables have been insignificant.

Use of Estimates

In preparing financial statements, the Company follows 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 at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved oil and gas reserves and related cash flow estimates which are used to compute depreciation, depletion and amortization, impairments of proved oil and gas properties and the fair value of oil and gas properties in purchase accounting. Other estimates include oil, natural gas and NGL revenues and expenses, fair value of derivative instruments, estimates of expenses related to legal, environmental and other contingencies, asset retirement obligations, postretirement obligations, stock-based compensation and deferred income taxes. Actual results could differ from those estimates.

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2. Acquisitions

Cimarex Energy Co.

On October 1, 2021, the Company and Cimarex completed the Merger. Cimarex is an oil and gas exploration and production company with operations in Texas, New Mexico and Oklahoma. Upon the effectiveness of the Merger, each eligible share of Cimarex common stock was converted into the right to receive 4.0146 shares of common stock of the Company. Based on the closing price of Coterra’s common stock on October 1, 2021, the total value of such shares of Coterra common stock was approximately $9.1 billion. The Company and Cimarex intended for the Merger to qualify as a tax-free reorganization for U.S. federal income tax purposes.

Also in accordance with the Merger Agreement with Cimarex and included as merger consideration, the Company issued 3.4 million shares of restricted stock to replace Cimarex restricted stock awards granted to certain employees. Because these restricted shares have non-forfeitable rights to dividends or dividend equivalents, the Company considers these shares as issued and outstanding shares of common stock.

Purchase Price Allocation

The transaction was accounted for using the acquisition method of accounting, with the Company being treated as the accounting acquirer. Under the acquisition method of accounting, the assets, liabilities and mezzanine equity of Cimarex and its subsidiaries were recorded at their respective 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 disclosed herein. Determining the fair value of the assets and liabilities of Cimarex required judgment and certain assumptions to be made. The most significant fair value estimates related to the valuation of Cimarex’s oil and gas properties and certain other fixed assets, long-term debt and derivative instruments. Oil and gas properties and certain fixed assets were valued using an income and market approach utilizing Level 3 inputs including internally generated production and development data and estimated price and cost estimates. Long-term debt was valued using a market approach utilizing Level 1 inputs including observable market prices on the underlying debt instruments. Derivative liabilities were based on Level 3 inputs consistent with the Company’s other commodity derivative instruments. Refer to Note 6, “Fair Value Measurements,” for additional information.

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The following table represents the final allocation of the total purchase price of Cimarex to the identifiable assets acquired and the liabilities assumed based on the fair values as of the effective date of the Merger.


(In millions, except share price and exchange ratio)	Final Purchase Price Allocation
Consideration:
Cimarex common stock issued as of October 1, 2021	103
Less unvested common stock	(3)
Total Cimarex common stock to be converted	100
Exchange ratio	4.0146
Coterra common stock issued in exchange for Cimarex common stock	403
Coterra common stock issued for Cimarex share awards vested on October 1, 2021	5
Total shares of Coterra common stock issued	408
Coterra common stock closing price on October 1, 2021	$	22.25
Total value of Coterra common stock issued	$	9,083
Total value of Coterra stock options issued	15
Total value of Coterra restricted stock awards issued	22
Total consideration	$	9,120

Assets acquired:
Cash and cash equivalents	$	1,033
Accounts receivable	598
Other current assets	31
Properties and equipment	13,300
Other assets	324
Total assets acquired	$	15,286
Liabilities and Mezzanine Equity assumed:
Accounts payable	$	528
Accrued liabilities	258
Derivative instruments, current	382
Other current liabilities	83
Long-term debt	2,196
Deferred income taxes	2,201
Asset retirement obligations	162
Derivative instruments, noncurrent	7
Other liabilities	299
Cimarex redeemable preferred stock	50
Total liabilities and mezzanine equity assumed	$	6,166

Net assets acquired	$	9,120

Post-Acquisition Operating Results

Cimarex contributed the following to the Company’s 2021 consolidated operating results.


(in millions)	October 1, 2021 through December 31, 2021
Revenue	$	1,129
Net income	394

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Unaudited Pro Forma Financial Information

The results of Cimarex’s operations have been included in the Company’s consolidated financial statements since October 1, 2021, the effective date of the Merger. The following supplemental pro forma information for the years ended December 31, 2021 and 2020 has been prepared to give effect to the Cimarex acquisition as if it had occurred on January 1, 2020. The information below reflects pro forma adjustments based on available information and certain assumptions that Coterra believes are factual and supportable. The pro forma results of operations do not include any cost savings or other synergies that may result from the acquisition or any estimated costs that have been or will be incurred by Coterra to integrate the Cimarex assets.

The pro forma information is not necessarily indicative of the results that might have occurred had the transaction actually taken place on January 1, 2020 and is not intended to be a projection of future results. Future results may vary significantly from the results reflected in the following pro forma information because of normal production declines, changes in commodity prices, future acquisitions and divestitures, future development and exploration activities and other factors.


	Year Ended December 31,
(In millions, except per share information)	2021		2020
Pro forma revenue	$	5,236	$	2,990
Pro forma net income (loss)	1,205		(2,189)




Pro forma basic earnings (loss) per share	$	1.49	$	(2.71)
Pro forma diluted earnings (loss) per share	$	1.48	$	(2.71)

Other Information

In connection with the Merger, the Company recognized $42 million of transaction costs for the year ended December 31, 2021. These fees primarily related to bank, legal and accounting fees and are included in general and administrative expenses in the Consolidated Statement of Operations.

3. Properties and Equipment, Net

Properties and equipment, net are comprised of the following:


	December 31,
(In millions)	2022		2021
Proved oil and gas properties	$	17,085	$	15,340
Unproved oil and gas properties	5,150		5,316
Gathering and pipeline systems	450		395
Land, buildings and other equipment	183		140
Finance lease right-of-use asset	16		20
	22,884		21,211
Accumulated depreciation, depletion and amortization	(5,405)		(3,836)
	$	17,479	$	17,375

Capitalized Exploratory Well Costs

As of and for the years ended December 31, 2022, 2021 and 2020, the Company did not have any projects with exploratory well costs capitalized for a period of greater than one year after drilling.

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4. Long-Term Debt and Credit Agreements

The following table includes a summary of the Company’s long-term debt.


	December 31,
(In millions)	2022		2021
Total debt
6.51% weighted-average private placement senior notes	$	—	$	37
5.58% weighted-average private placement senior notes	—		87
3.65% weighted-average private placement senior notes(1)	825		825
4.375% senior notes due June 1, 2024 (2)	—		750
3.90% senior notes due May 15, 2027 (2)	750		750
4.375% senior notes due March 15, 2029 (2)	500		500
Revolving credit facility	—		—
Total	2,075		2,949
Net premium	111		185
Unamortized debt issuance costs	(5)		(9)
Long-term debt	$	2,181	$	3,125

_______________________________________________________________________________

(1)The 3.65% weighted-average senior notes have bullet maturities of $575 million and $250 million due in September 2024 and 2026, respectively.

(2)These notes were assumed by the Company in October 2021 in connection with the Merger. Subsequent to an exchange transaction completed in October 2021, approximately $130 million of these notes remain the unsecured and unsubordinated obligation of Cimarex, a subsidiary of the Company, at December 31, 2022.

The following table includes a summary of Cimarex debt that was outstanding as of the consummation of the Merger on October 1, 2021:


(In millions)	Face Value		Fair Value
4.375% senior notes due June 1, 2024	$	750	$	809
3.90% senior notes due May 15, 2027	750		823
4.375% senior notes due March 15, 2029	500		564
	$	2,000	$	2,196

Private Placement Senior Notes

The Company has various issuances of senior unsecured notes that were issued in separate private placements (the “private placement senior notes”). Interest on each of such series of private placement senior notes is payable semi-annually. Under the terms of the various note purchase agreements, the Company may prepay all or any portion of the notes of each series on any date at a price equal to the principal amount thereof plus accrued and unpaid interest plus a make-whole premium.

During 2022, the Company repaid $37.0 million of its 6.51% weighted-average senior notes for $38 million and $87 million of its 5.58% weighted-average senior notes for $92 million prior to their original maturity dates, and recognized a net loss on debt extinguishment of $7 million.

The note purchase agreements provide that the Company must 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. There are also various other covenants and events of default customarily found in such debt instruments. As of December 31, 2022, the Company was in compliance with its financial covenants under the private placement senior notes.

Senior Notes

In connection with the Merger in 2021, the Company assumed $2.0 billion of Cimarex debt (“Existing Cimarex Notes”) and completed a private exchange offer of $1.8 billion of the Existing Cimarex Notes for new Company notes (“Coterra Notes”

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and, together with the Existing Cimarex Notes, the “Senior Notes”). The Coterra Notes have the same interest rate and payment and maturity dates as the Existing Cimarex Notes for which they were exchanged.

The Senior Notes are general, unsecured obligations of the Company. Interest on each series of Senior Notes is payable semi-annually. Under the terms of the indenture documents governing the Senior Notes, the Company may redeem all or any portion of the Senior Notes of each series on any date at a price equal to the principal amount thereof plus applicable redemption prices described in the governing indentures. The Company is also subject to various covenants and events of default customarily found in such debt instruments.

In 2022, the Company redeemed the $750 million principal amount of its 4.375% Senior Notes for approximately $750 million and recognized a net gain on debt extinguishment of $35 million primarily due to the write off of the associated debt premiums and debt issuance costs.

Revolving Credit Agreement

On April 22, 2019, the Company entered into a second amended and restated credit agreement (the “revolving credit agreement”). The revolving credit agreement is unsecured. The revolving credit agreement was subsequently amended on July 17, 2021 to address certain matters precedent to the Merger with Cimarex and on September 16, 2021 to among other things: (1) remove the provisions which limited borrowings thereunder to an amount not to exceed the borrowing base and certain related provisions; (2) replace the then-existing financial maintenance covenants with a covenant requiring maintenance of a leverage ratio not more than 3.0 to 1.0; (3) provide that if, in the future, the Company no longer has any other indebtedness subject to a leverage-based financial maintenance covenant, then the leverage covenant shall be replaced by a covenant requiring maintenance of a ratio of total debt to total capitalization not to exceed 65 percent at any time; and (4) provide for changes to certain exceptions to the negative covenants to reflect the completion of the Merger. This amendment became effective upon completion of the Merger and closing of the debt exchange described above. The Company’s revolving credit facility matures in April 2024 and can be extended by one year upon the agreement of the Company and lenders holding at least 50 percent of the commitments under the revolving credit facility. As of December 31, 2022, the Company was in compliance with its financial covenants under the revolving credit agreement.

Interest rates under the revolving credit facility are based on LIBOR or ABR indications, plus a margin which ranges from 112.5 to 175 basis points for LIBOR loans and from 12.5 to 75 basis points for ABR loans. The revolving credit facility also provides for a commitment fee on the unused available balance and is calculated at annual rates ranging from 12.5 to 27.5 basis points.

From time to time, the Company uses the LIBOR benchmark rate for borrowings under its revolving credit facility. In July 2017, the U.K. Financial Conduct Authority (“FCA”) announced that it will no longer compel banks to submit rates that are currently used to calculate LIBOR after 2021. Subsequently in March 2021, the FCA announced some U.S. Dollar LIBOR tenors (overnight, 1 month, 3 month, 6 month and 12 month) will continue to be published until June 30, 2023. Regulators in the U.S. and other jurisdictions have been working to replace these rates with alternative reference interest rates that are supported by transactions in liquid and observable markets, such as the Secured Overnight Financing Rate (“SOFR”) for U.S. Dollar LIBOR. The Company’s revolving credit facility has a term that extends beyond June 30, 2023. The Company’s revolving credit facility also provides that in the event that the LIBOR benchmark rate is no longer available, the Company and its lenders will endeavor to establish an alternative interest rate based on the then prevailing market convention for purposes of LIBOR borrowings. The Company currently has no borrowings outstanding under its revolving credit facility and does not expect the transition to an alternative rate to have a material impact on its results of operations or cash flows.

At December 31, 2022, there were no borrowings outstanding under the Company’s revolving credit facility and unused commitments were $1.5 billion.

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5. Derivative Instruments

As of December 31, 2022, the Company had the following outstanding financial commodity derivatives:



	2023
Natural Gas	First Quarter		Second Quarter		Third Quarter		Fourth Quarter




Waha gas collars
Volume (MMBtu)	8,100,000		8,190,000		8,280,000		8,280,000
Weighted average floor ($/MMBtu)	$	3.03	$	3.03	$	3.03	$	3.03
Weighted average ceiling ($/MMBtu)	$	5.39	$	5.39	$	5.39	$	5.39

NYMEX collars
Volume (MMBtu)	54,000,000		31,850,000		32,200,000		29,150,000
Weighted average floor ($/MMBtu)	$	5.12	$	4.07	$	4.07	$	4.03
Weighted average ceiling ($/MMBtu)	$	9.34	$	6.78	$	6.78	$	6.61



	2023
Oil	First Quarter		Second Quarter
WTI oil collars
Volume (MBbl)	1,350		1,365
Weighted average floor ($/Bbl)	$	70.00	$	70.00
Weighted average ceiling ($/Bbl)	$	116.03	$	116.03

WTI Midland oil basis swaps
Volume (MBbl)	1,350		1,365
Weighted average differential ($/Bbl)	$	0.63	$	0.63

Effect of Derivative Instruments on the Consolidated Balance Sheet


		Fair Values of Derivative Instruments
		Derivative Assets				Derivative Liabilities
		December 31,				December 31,
(In millions)	Balance Sheet Location	2022		2021		2022		2021
Commodity contracts	Derivative instruments (current)	$	146	$	7	$	—	$	159

Offsetting of Derivative Assets and Liabilities in the Consolidated Balance Sheet


	December 31,
(In millions)	2022		2021
Derivative assets
Gross amounts of recognized assets	$	147	$	27
Gross amounts offset in the consolidated balance sheet	(1)		(20)
Net amounts of assets presented in the consolidated balance sheet	146		7
Gross amounts of financial instruments not offset in the consolidated balance sheet	2		—
Net amount	$	148	$	7

Derivative liabilities
Gross amounts of recognized liabilities	$	1	$	179
Gross amounts offset in the consolidated balance sheet	(1)		(20)
Net amounts of liabilities presented in the consolidated balance sheet	—		159
Gross amounts of financial instruments not offset in the consolidated balance sheet	1		35
Net amount	$	1	$	194

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Effect of Derivative Instruments on the Consolidated Statement of Operations


	Year Ended December 31,
(In millions)	2022		2021		2020
Cash (paid) received on settlement of derivative instruments
Gas contracts	$	(438)	$	(307)	$	35
Oil contracts	(324)		(124)		—
Non-cash gain on derivative instruments
Gas contracts	149		99		26
Oil contracts	150		111		—
	$	(463)	$	(221)	$	61

Additional Disclosures about Derivative Instruments

The use of derivative instruments involves the risk that the counterparties will be unable to meet their obligations under the agreements. The Company’s counterparties are primarily commercial banks and financial service institutions that management believes present minimal credit risk and its derivative contracts are with multiple counterparties to minimize its exposure to any individual counterparty. The Company performs both quantitative and qualitative assessments of these counterparties based on their credit ratings and credit default swap rates where applicable.

Certain counterparties to the Company’s derivative instruments are also lenders under its revolving credit facility. The Company’s revolving credit facility and derivative instruments contain certain cross default and acceleration provisions that may require immediate payment of the Company’s liabilities thereunder if the Company defaults on other material indebtedness. The Company also has netting arrangements with each of its counterparties that allow it to offset assets and liabilities from separate derivative contracts with that counterparty.

6. Fair Value Measurements

Financial Assets and Liabilities

The following fair value hierarchy table presents information about the Company’s financial assets and liabilities measured at fair value on a recurring basis:


(In millions)	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Balance at December 31, 2022
Assets
Deferred compensation plan	$	43	$	—	$	—	$	43
Derivative instruments	—		—		147		147
Total assets	$	43	$	—	$	147	$	190
Liabilities
Deferred compensation plan	$	55	$	—	$	—	$	55
Derivative instruments	—		—		1		1
Total liabilities	$	55	$	—	$	1	$	56

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(In millions)	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Balance at December 31, 2021
Assets
Deferred compensation plan	$	47	$	—	$	—	$	47
Derivative instruments	—		—		27		27
Total assets	$	47	$	—	$	27	$	74
Liabilities
Deferred compensation plan	$	56	$	—	$	—	$	56
Derivative instruments	—		—		179		179
Total liabilities	$	56	$	—	$	179	$	235

The Company’s investments associated with its deferred compensation plan consist of mutual funds and deferred shares of the Company’s common stock that are publicly traded and for which market prices are readily available.

The derivative instruments were measured based on quotes from the Company’s 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. Estimates are derived from or verified using relevant NYMEX futures contracts and/or are compared to multiple quotes obtained from counterparties. The determination of the fair values presented above also incorporates a credit adjustment for non-performance risk. The Company measured the non-performance risk of its counterparties by reviewing credit default swap spreads for the various financial institutions with which it has derivative contracts while non-performance risk of the Company is evaluated using a market credit spread provided by several of the Company’s banks. The Company has not incurred any losses related to non-performance risk of its counterparties and does not anticipate any material impact on its financial results due to non-performance by third parties.

The most significant unobservable inputs relative to the Company’s Level 3 derivative contracts are basis differentials and volatility factors. An increase (decrease) in these unobservable inputs would result in an increase (decrease) in fair value, respectively. The Company does not have access to the specific assumptions used in its counterparties’ valuation models. Consequently, additional disclosures regarding significant Level 3 unobservable inputs were not provided.

The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy:


	Year Ended December 31,
(In millions)	2022		2021		2020
Balance at beginning of period	$	(152)	$	24	$	—
Total gain (loss) included in earnings	(446)		(532)		41

Settlement (gain) loss	744		356		(17)
Transfers in and/or out of Level 3	—		—		—
Balance at end of period	$	146	$	(152)	$	24

Change in unrealized gains (losses) relating to assets and liabilities still held at the end of the period	$	179	$	(154)	$	24

Non-Financial Assets and Liabilities

The Company discloses or recognizes its non-financial assets and liabilities, such as impairments of oil and gas properties or acquisitions, at fair value on a nonrecurring basis. On October 1, 2021, the Company and Cimarex completed the Merger. In connection with the Merger, the assets acquired and liabilities assumed were recorded at fair value. The most significant fair value determinations for non-financial assets and liabilities related to oil and gas properties acquired. Refer to Note 2, “Acquisitions,” for additional information. As none of the Company’s other non-financial assets and liabilities were measured at fair value as of December 31, 2022, 2021 and 2020, additional disclosures were not required.

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The estimated fair value of the Company’s asset retirement obligations at inception is determined by utilizing the income approach by applying a credit-adjusted risk-free rate, which takes into account the Company’s credit risk, the time value of money, and the current economic state to the undiscounted expected abandonment cash flows. Given the unobservable nature of the inputs, the measurement of the asset retirement obligations was classified as Level 3 in the fair value hierarchy.

Fair Value of Other Financial Instruments

The estimated fair value of other financial instruments is the amount at which the instruments could be exchanged currently between willing parties. The carrying amounts reported in the Consolidated Balance Sheet for cash and cash equivalents and restricted cash approximate fair value, due to the short-term maturities of these instruments. Cash and cash equivalents and restricted cash are classified as Level 1 in the fair value hierarchy and the remaining financial instruments are classified as Level 2.

The fair value of the Company’s Senior Notes is based on quoted market prices, which is classified as Level 1 in the fair value hierarchy. The Company uses available market data and valuation methodologies to estimate the fair value of its private placement senior notes. The fair value of the private placement senior notes is the estimated amount the Company would have to pay a third party to assume the debt, including a credit spread for the difference between the issue rate and the period end market rate. The credit spread is the Company’s default or repayment risk. The credit spread (premium or discount) is determined by comparing the Company’s senior notes and revolving credit facility to new issuances (secured and unsecured) and secondary trades of similar size and credit statistics for both public and private debt. The fair value of the private placement senior notes is based on interest rates currently available to the Company. The Company’s private placement senior notes are valued using an income approach and are classified as Level 3 in the fair value hierarchy.

The carrying amount and estimated fair value of debt is as follows:


	December 31, 2022				December 31, 2021
(In millions)	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-term debt	$	2,181	$	1,955	$	3,125	$	3,163

7. Asset Retirement Obligations

Activity related to the Company’s asset retirement obligations is as follows:


	Year Ended December 31,
(In millions)	2022		2021		2020
Balance at beginning of period	$	263	$	86	$	72
Liabilities assumed in Merger	—		175		—
Liabilities incurred	10		6		10
Liabilities settled	(3)		(10)		—
Liabilities divested	(2)		—		—
Accretion expense	9		6		4

Balance at end of period	277		263		$	86
Less: current asset retirement obligation	(6)		(4)		(1)
Noncurrent asset retirement obligation	$	271	$	259	$	85

8. Commitments and Contingencies

Transportation, Processing and Gathering Agreements

Transportation, Processing and Gathering Commitments

The Company has entered into certain transportation and gathering agreements with various pipeline carriers. Under certain of these agreements, the Company is obligated to ship minimum daily quantities, or pay for any deficiencies at a specified rate. The Company’s forecasted production to be shipped on these pipelines is expected to exceed minimum daily quantities provided in the agreements. The Company is also obligated under certain of these arrangements to pay a demand charge for firm capacity rights on pipeline systems regardless of the amount of pipeline capacity utilized by the Company. If the Company does not utilize the capacity, it can release it to others, thus reducing its potential liability.

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As of December 31, 2022, the Company’s future minimum obligations under transportation and gathering agreements are as follows:


(In millions)
2023	$	108
2024	159
2025	169
2026	153
2027	159
Thereafter	901
	$	1,649

Other Gathering and Processing Volume Commitments

The Company has entered into certain gas processing agreements. Under certain of these agreements, the Company is obligated to process minimum daily quantities, or pay for any deficiencies at a specified rate. The Company’s forecasted production to be processed under most of these agreements is expected to exceed minimum daily quantities provided in the agreements.

As of December 31, 2022, the Company’s future minimum obligations under gas processing agreements are as follows:


(In millions)
2023	$	93
2024	96
2025	96
2026	84
2027	80
Thereafter	157
	$	606

The Company also has minimum volume delivery commitments associated with agreements to reimburse connection costs to various pipelines. Under certain of these agreements, the Company is obligated to deliver minimum daily quantities, or pay for any deficiencies at a specified rate. The Company’s forecasted production to be delivered under most of these agreements is expected to exceed minimum daily quantities provided in the agreements.

As of December 31, 2022, the Company’s future minimum obligations under these delivery commitments are as follows:


(In millions)
2023	$	16
2024	19
2025	13
2026	13
2027	16
Thereafter	13
	$	90

As of December 31, 2022, the Company had accrued $14 million in other non-current liabilities associated with these commitments, representing the present value of estimated amounts payable due to insufficient forecasted delivery volumes.

Water Delivery Commitments

The Company has minimum volume water delivery commitments associated with a water services agreement that expires in 2030. The Company is obligated to deliver minimum daily quantities, or pay for any deficiencies at a specified rate.

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As of December 31, 2022, the Company’s future minimum obligations under this water delivery commitment are as follows:


(In millions)
2023	$	7
2024	7
2025	7
2026	7
2027	7
Thereafter	18
	$	53

As of December 31, 2022, the Company had accrued $20 million in other non-current liabilities associated with this commitment, representing the present value of estimated amounts payable due to insufficient forecasted delivery volumes.

Lease Commitments

The Company has operating leases for office space, surface use agreements, compressor services, electric hydraulic fracturing services, and other leases. The leases have remaining terms ranging from one month to 23 years, including options to extend leases that the Company is reasonably certain to exercise. During the year ended December 31, 2022, the Company recognized operating lease cost and variable lease cost of $104 million and $9 million, respectively. During the year ended December 31, 2021, the Company recognized operating lease cost and variable lease cost of $23 million and $6 million, respectively.

Short-term leases. The Company leases drilling rigs, fracturing and other equipment under lease terms ranging from 30 days to one year. Lease cost of $265 million and $113 million was recognized on short-term leases during the year ended December 31, 2022 and 2021, respectively. Certain lease costs are capitalized and included in Properties and equipment, net in the Consolidated Balance Sheet because they relate to drilling and completion activities, while other costs are expensed because they relate to production and administrative activities.

As of December 31, 2022, the Company’s future undiscounted minimum cash payment obligations for its operating lease liabilities are as follows:


(In millions)	Year Ending December 31,
2023	$	126
2024	115
2025	101
2026	38
2027	9
Thereafter	47
Total undiscounted future lease payments	436
Present value adjustment	(35)
Net operating lease liabilities	$	401

As of December 31, 2022, the Company’s future undiscounted minimum cash payment obligations for its financing lease liabilities are as follows:


(In millions)	Year Ending December 31,
2023	$	7
2024	7
2025	4



Total undiscounted future lease payments	18
Present value adjustment	(1)
Net financing lease liabilities	$	17

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Supplemental cash flow information related to leases was as follows:


	Year Ended December 31,
(In millions)	2022		2021
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	104	$	23
Financing cash flows from financing leases	$	6	$	2

Information regarding the weighted-average remaining lease term and the weighted-average discount rate for operating and financing leases is summarized below:


	December 31,
	2022		2021
Weighted-average remaining lease term (in years)
Operating leases	4.6		5.7
Financing leases	2.7		3.7
Weighted-average discount rate
Operating leases	3.3	%	2.4	%
Financing leases	2.4	%	2.1	%

Legal Matters

Pennsylvania Office of Attorney General Matter

On June 16, 2020, the Office of Attorney General of the Commonwealth of Pennsylvania (“OAG”) informed the Company that it would pursue certain misdemeanor and felony charges in a Susquehanna County Magisterial District Court against the Company related to alleged violations of the Pennsylvania Clean Streams Law. On November 29, 2022, the Company and the OAG resolved these charges, with the Company pleading no contest to one misdemeanor and the OAG dismissing the remaining charges. In addition, the Company agreed to (i) make a one-time payment of $16 million to fund a public water line (or fund permanent water treatment systems if the water line is not constructed), (ii) provide temporary water treatment pending construction of the water line (which is reimbursable from the $16 million payment), and (iii) make a donation of $2,500 to the Clean Water Fund.

Concurrently, the Company and the Pennsylvania Department of Environmental Protection entered into a new Consent Order & Agreement dated November 29, 2022 (“COA”) concerning the nine-square mile area in Dimock, Pennsylvania. This COA replaced the December 15, 2010 Consent Order & Settlement Agreement and provides a framework for potential future development by utilizing horizontal drilling under the nine-square mile area, provided the Company satisfies certain conditions. The Company further agreed to (i) pay a fine of $444,000, (ii) investigate the feasibility of alleviating potential gas pressures near a specific pad, and (iii) plug and abandon various legacy wells no later than December 31, 2032. This COA also incorporates the requirements of the plea agreement regarding the $16 million payment and the provision regarding temporary water treatment.

Securities Litigation

In October 2020, a class action lawsuit styled Delaware County Emp. Ret. Sys. v. Cabot Oil and Gas Corp., et. al. (U.S. District Court, Middle District of Pennsylvania), was filed against the Company, Dan O. Dinges, its then Chief Executive Officer, and Scott C. Schroeder, its Chief Financial Officer, alleging that the Company made misleading statements in its periodic filings with the SEC in violation of Section 10(b) and Section 20 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). The plaintiffs allege misstatements in the Company’s public filings and disclosures over a number of years relating to its potential liability for alleged environmental violations in Pennsylvania. The plaintiffs allege that such misstatements caused a decline in the price of the Company’s common stock when it disclosed in its Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2019 two notices of violations from the Pennsylvania Department of Environmental Protection and an additional decline when it disclosed on June 15, 2020 the criminal charges brought by the Office of the Attorney General of the Commonwealth of Pennsylvania related to alleged violations of the Pennsylvania Clean Streams Law, which prohibits discharge of industrial wastes. The court appointed Delaware County Employees Retirement System to represent the purported class on February 3, 2021. In April 2021, the complaint was amended to include Phillip L. Stalnaker, the Company’s then Senior Vice President of Operations, as a defendant. The plaintiffs seek monetary damages, interest and attorney’s fees.

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Also in October 2020, a stockholder derivative action styled Ezell v. Dinges, et. al. (U.S. District Court, Middle District of Pennsylvania) was filed against the Company, Messrs. Dinges and Schroeder and the Board of Directors of the Company serving at that time, for alleged securities violations under Section 10(b) and Section 21D of the Exchange Act arising from the same alleged misleading statements that form the basis of the class action lawsuit described above. In addition to the Exchange Act claims, the derivative actions also allege claims based on breaches of fiduciary duty and statutory contribution theories. In December 2020, the Ezell case was consolidated with a second derivative case filed in the U.S. District Court, Middle District of Pennsylvania with similar allegations. In January 2021, a third derivative case was filed in the U.S. District Court, Middle District of Pennsylvania with substantially similar allegations and it too was consolidated with the Ezell case in February 2021.

On February 25, 2021, the Company filed a motion to transfer the class action lawsuit to the U.S. District Court for the Southern District of Texas, in Houston, Texas, where its headquarters are located. On June 11, 2021, the Company filed a motion to dismiss the class action lawsuit on the basis that the plaintiffs’ allegations do not meet the requirements for pleading a claim under Section 10(b) or Section 20 of the Exchange Act. On June 22, 2021, the motion to transfer the class action lawsuit to the Southern District of Texas was granted. Pursuant to the prior agreement of the parties, the consolidated derivative case discussed in the preceding paragraph was also transferred to the Southern District of Texas on July 12, 2021. Subsequently, an additional stockholder derivative action styled Treppel Family Trust U/A 08/18/18 Lawrence A. Treppel and Geri D. Treppel for the benefit of Geri D. Treppel and Larry A. Treppel v. Dinges, et al. (U.S. District Court, Southern District of Texas, Houston Division), asserting substantially similar Delaware common law claims as in the existing derivative cases, was filed in the Southern District of Texas and consolidated with the existing consolidated derivative cases. On January 12, 2022, the U.S. District Court for the Southern District of Texas granted the Company’s motion to dismiss the class action lawsuit but allowed the plaintiffs to file an amended complaint. The class action plaintiffs filed their amended complaint on February 11, 2022. The Company filed a motion to dismiss the amended class action complaint on March 10, 2022. On August 10, 2022, the U.S. District Court for the Southern District of Texas granted in part and denied in part the Company’s motion to dismiss the amended class action complaint, dismissing certain claims with prejudice but allowing certain claims to proceed. The Company filed its answer to the amended class action complaint on September 14, 2022. With respect to the consolidated derivative cases, on April 1, 2022, the U.S. District Court for the Southern District of Texas granted the Company’s motion to dismiss such consolidated derivative cases but allowed the plaintiffs to file an amended complaint. The derivative plaintiffs filed their third amended complaint on May 16, 2022. The Company filed its motion to dismiss such amended complaint on June 24, 2022, and filed its reply in support of such motion to dismiss on September 4, 2022. The Company’s motion to dismiss the consolidated derivative cases is fully briefed and is pending for decision. The Company intends to vigorously defend the class action and derivative lawsuits.

In November 2020, the Company received a stockholder demand for inspection of books and records under Section 220 of the General Corporation Law of the State of Delaware (“Section 220 Demand”). The Section 220 Demand seeks broad categories of documents reviewed by the Board of Directors and minutes of meetings of the Board of Directors pertaining to alleged environmental violations in Pennsylvania, as well as documents relating to any board of directors conflicts of interest, dating from January 1, 2015 to the present. The Company also received three other similar requests from other stockholders in February and June 2021. On May 17, 2021, the Company was served with a complaint filed in the Court of Chancery of the State of Delaware by the stockholder making the February 2021 Section 220 Demand to compel the production of books and records requested. After making an agreed books and records production, the Section 220 complaint was voluntarily dismissed effective September 21, 2021. The Company also provided substantially the same books and records production in response to the other three Section 220 requests described above. It is possible that one or more additional stockholder suits could be filed pertaining to the subject matter of the Section 220 Demands and the class and derivative actions described above.

Other Legal Matters

The Company is a defendant in various other legal proceedings arising in the normal course of business. All known liabilities are accrued when management determines they are probable based on its estimate of the potential loss. While the outcome and impact of these legal proceedings on the Company cannot be predicted with certainty, management believes that the resolution of these proceedings will not have a material effect on the Company’s financial position, results of operations or cash flows.

Contingency Reserves

When deemed necessary, the Company establishes reserves for certain legal proceedings. The establishment of a reserve is based on an estimation process that includes the advice of legal counsel and subjective judgment of management. While management believes these reserves to be adequate, it is reasonably possible that the Company could incur additional losses with respect to those matters for which reserves have been established. The Company believes that any such amount above the amounts accrued would not be material to the Consolidated Financial Statements. Future changes in facts and circumstances not currently known or foreseeable could result in the actual liability exceeding the estimated ranges of loss and amounts accrued.

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9. Revenue Recognition

Disaggregation of Revenue

The following table presents revenues from contracts with customers disaggregated by product:


	Year Ended December 31,
(In millions)	2022		2021		2020
OPERATING REVENUES
Natural gas	$	5,469	$	2,798	$	1,405
Oil	3,016		616		—

NGL	964		243		—
Other	65		13		—
	$	9,514	$	3,670	$	1,405

All of the Company’s revenues from contracts with customers represent products transferred at a point in time as control is transferred to the customer and generated in the U.S.

Transaction Price Allocated to Remaining Performance Obligations

A significant number of the Company’s product sales contracts are short-term in nature with a contract term of one year or less. For those contracts, the Company has utilized the practical expedient exempting the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.

As of December 31, 2022, the Company has $7.2 billion of unsatisfied performance obligations related to natural gas sales that have a fixed pricing component and a contract term greater than one year. The Company expects to recognize these obligations over the next 16 years.

Contract Balances

Receivables from contracts with customers are recorded when the right to consideration becomes unconditional, generally when control of the product has been transferred to the customer. Receivables from contracts with customers were $1.1 billion and $922 million as of December 31, 2022 and 2021, respectively, and are reported in accounts receivable, net in the Consolidated Balance Sheet. As of December 31, 2022 and 2021, the Company had no assets or liabilities related to its revenue contracts, including no upfront payments or rights to deficiency payments.

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10. Income Taxes

Income tax expense is summarized as follows:


	Year Ended December 31,
(In millions)	2022		2021		2020
Current
Federal	$	791	$	207	$	(32)
State	78		11		1
	869		218		(31)
Deferred
Federal	217		119		68
State	18		7		4
	235		126		72
Income tax expense	$	1,104	$	344	$	41

Income tax expense was different than the amounts computed by applying the statutory federal income tax rate as follows:


	Year Ended December 31,
	2022				2021				2020
(In millions, except rates)	Amount		Rate		Amount		Rate		Amount		Rate
Computed “expected” federal income tax	$	1,085	21.00	%	$	315	21.00	%	$	51	21.00	%
State income tax, net of federal income tax benefit	93		1.80	%	24		1.59	%	5		1.86	%
Deferred tax adjustment related to change in overall state tax rate	(23)		(0.45)	%	(7)		(0.46)	%	1		0.50	%
Valuation allowance	(66)		(1.28)	%	3		0.22	%	(4)		(1.58)	%
Excess executive compensation	10		0.20	%	15		1.03	%	5		2.18	%
Reserve on uncertain tax positions	6		0.12	%	1		0.05	%	6		2.47	%
Tax credits generated	(34)		(0.66)	%	(6)		(0.39)	%	(23)		(9.63)	%



Other, net	33		0.62	%	(1)		(0.14)	%	—		0.04	%
Income tax expense	$	1,104	21.35	%	$	344	22.90	%	$	41	16.84	%

In 2022, the Company's overall effective tax rate decreased compared to 2021, primarily due to a decrease in the non-deductible excess executive compensation paid in 2022 compared to 2021, tax benefits recorded in 2022 compared to 2021 from the release of valuation allowances primarily associated with state net operating loss carryforwards, and greater research and development tax credit benefits recorded in 2022 compared to 2021 related to amended prior-year returns. The overall effective tax rate increased in 2021 compared to 2020, primarily due to lower research and development tax credit benefits recorded in 2021 compared to 2020.

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The composition of net deferred tax liabilities is as follows:


	December 31,
(In millions)	2022		2021
Deferred Tax Assets
Net operating losses	$	196	$	388



Incentive compensation	24		23
Deferred compensation	30		22
Post-retirement benefits	4		8

Capital loss carryforward	16		30
Other credit carryforwards	4		10
Leases	13		11
Derivative instruments	—		35
Other	30		18
Less: valuation allowance	(110)		(177)
Total	207		368
Deferred Tax Liabilities
Properties and equipment	3,498		3,459
Equity method investments	1		1
Leases	14		9
Derivative instruments	33		—
Total	3,546		3,469
Net deferred tax liabilities	$	3,339	$	3,101

At December 31, 2022, the Company had federal net operating loss carryforwards of approximately $442 million, of which $378 million is subject to expiration in years 2035 through 2037, and of which $64 million does not expire. The Company has a valuation allowance on $37 million of the federal net operating losses, but believes the remaining $405 million will be fully utilized prior to expiration. The Company had gross state net operating losses of $2.6 billion at December 31, 2022, primarily expiring between 2022 and 2040, with all but $198 million covered by a valuation allowance. The Company had capital loss carryforwards of $71 million, which can only be used to offset future capital gains, and expires in 2024. Accordingly, all but $6 million has been offset with a valuation allowance. The Company also had enhanced oil recovery credits of $4 million at December 31, 2022 that are fully offset by valuation allowances.

As of December 31, 2022, the Company had $8 million of valuation allowances on the deferred tax benefits related to federal net operating losses, $83 million of valuation allowances on the deferred tax benefits related to state net operating losses, $15 million of valuation allowances on the deferred tax benefits related to capital loss carryforwards, and $4 million of valuation allowances on the deferred tax benefits related to enhanced oil recovery credits. The Company believes it is more likely than not that the remainder of its deferred tax benefits will be utilized prior to their expiration.

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Unrecognized Tax Benefits

A reconciliation of unrecognized tax benefits is as follows:


	Year Ended December 31,
(In millions)	2022		2021		2020
Balance at beginning of period	$	7	$	6	$	1
Additions for tax positions of current period	1		1		—
Additions for tax positions of prior periods	5		—		5

Balance at end of period	$	13	$	7	$	6

During 2022, the Company recorded a $1 million reserve for unrecognized tax benefits related to estimated current year research and development tax credits. In addition, the Company also recorded a $5 million reserve for unrecognized tax benefits related to research and development credits attributable to Cimarex for prior years. As of December 31, 2022, the Company’s overall net reserve for unrecognized tax positions was $13 million, with a $1 million liability for accrued interest on the uncertain tax positions. If recognized, the net tax benefit of $13 million would not have a material effect on the Company’s effective tax rate.

The Company files income tax returns in the U.S. federal, various states and other jurisdictions. The Company is no longer subject to examinations by state authorities before 2012 or by federal authorities before 2017. The Company believes that appropriate provisions have been made for all jurisdictions and all open years, and that any assessment on these filings will not have a material impact on the Company’s financial position, results of operations or cash flows.

Recent U.S. Tax Legislation

On August 16, 2022, the Inflation Reduction Act (“IRA”) was signed into law pursuant to the budget reconciliation process. The IRA introduced a new 15 percent corporate alternative minimum tax, effective for tax years beginning after December 31, 2022, on the adjusted financial statement income (“AFSI”) of corporations with average AFSI exceeding $1 billion over a three-year testing period. The IRA also introduced an excise tax of one percent on the fair market value of certain public company stock repurchases made after December 31, 2022. The Company is continuing to evaluate the IRA and its requirements, as well as the impact to the Company’s business.

11. Employee Benefit Plans

Postretirement Benefits

The Company provides certain health care benefits for legacy retired employees of Cabot Oil & Gas Corporation, including their spouses, eligible dependents and surviving spouses (retirees). These benefits are commonly called postretirement benefits. The health care plans are contributory, with participants’ contributions adjusted annually. Most legacy employees of Cabot Oil & Gas Corporation become eligible for these benefits if they meet certain age and service requirements at retirement.

The Company provided postretirement benefits to 320 retirees and their dependents at the end of 2022 and 364 retirees and their dependents at the end of 2021.

During 2022, the Company amended its postretirement plans to phase out all postretirement benefits and freeze future participation in the plan. The plan amendment provides that certain employees will be grandfathered and remain eligible for future participation in the pre-65 plan upon their retirement based on certain age and years of service criteria, while the post-65 benefit for all plan participants that reach the age of 65 after December 31, 2022, including current retirees participating the pre-65 plan, will be eliminated. Existing retirees participating in both the pre-65 and post-65 plans prior to December 31, 2022 will continue to receive benefits under the plan until the age of 65 in the case of the pre-65 participants, or voluntary termination of benefits or by death in the case of post-65 participants.

Obligations and Funded Status

The funded status represents the difference between the accumulated benefit obligation of the Company’s postretirement plan and the fair value of plan assets at December 31. The postretirement plan does not have any plan assets; therefore, the unfunded status is equal to the amount of the December 31 accumulated benefit obligation.

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The change in the Company’s postretirement benefit obligation is as follows:


	Year Ended December 31,
(In millions)	2022		2021		2020
Change in Benefit Obligation
Benefit obligation at beginning of period	$	35	$	33	$	34
Service cost	2		2		2
Interest cost	1		1		1
Actuarial (gain) loss	(15)		1		(2)
Benefits paid	(2)		(2)		(2)

Plan amendments	(3)		—		—
Benefit obligation at end of period	$	18	$	35	$	33
Change in Plan Assets
Fair value of plan assets at end of period	—		—		—
Funded status at end of period	$	(18)	$	(35)	$	(33)
Amounts recognized in balance sheet
Current liabilities	$	1	$	2	$	2
Non-current liabilities	17		33		31
Net amount	$	18	$	35	$	33
Amounts recognized in accumulated other comprehensive income (loss)
Net actuarial (gain) loss	$	(15)	$	—	$	—
Prior service credit	(3)		(2)		(3)
Total	$	(18)	$	(2)	$	(3)

Components of Net Periodic Benefit Cost and Other Amounts Recognized in Other Comprehensive Income (Loss)


	Year Ended December 31,
(In millions)	2022		2021		2020
Components of Net Periodic Postretirement Benefit Cost
Service cost	$	2	$	2	$	2
Interest cost	1		1		1
Amortization of prior service credit	(1)		(1)		(1)

Net periodic postretirement cost	$	2	$	2	$	2
Recognized curtailment gain	(1)		—		—
Total post retirement cost	$	1	$	2	$	2
Other Changes in Benefit Obligations Recognized in Other Comprehensive Income
Net gain	$	(15)	$	—	$	(2)
Prior service credit	(1)		—		—
Amortization of prior service credit	1		1		1

Total recognized in other comprehensive income	(15)		1		(1)
Total recognized in net periodic benefit cost (income) and other comprehensive income	$	(14)	$	3	$	1

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Assumptions

Assumptions used to determine projected postretirement benefit obligations and postretirement costs are as follows:


	December 31,
	2022		2021		2020
Discount rate(1)	5.55	%	2.85	%	2.65	%
Health care cost trend rate for medical benefits assumed for next year (pre-65)	8.00	%	6.50	%	6.75	%
Health care cost trend rate for medical benefits assumed for next year (post-65)	4.50	%	4.75	%	5.00	%
Ultimate trend rate (pre-65)	4.50	%	4.50	%	4.50	%
Ultimate trend rate (post-65)	4.50	%	4.50	%	4.50	%
Year that the rate reaches the ultimate trend rate (pre-65)	2030		2030		2030
Year that the rate reaches the ultimate trend rate (post-65)	2023		2023		2023

_______________________________________________________________________________

(1)Represents the year end rates used to determine the projected benefit obligation. To compute postretirement cost in 2022, 2021 and 2020, the beginning of year discount rates of 2.85 percent, 2.65 percent and 3.50 percent, respectively, were used.

Coverage provided to participants age 65 and older is under a fully-insured arrangement. The Company subsidy is limited to 60 percent of the expected annual fully-insured premium for participants age 65 and older. For all participants under age 65, the Company subsidy for all retiree medical and prescription drug benefits, beginning January 1, 2006, was limited to an aggregate annual amount not to exceed $648,000. This limit increases by three percent annually thereafter.

Cash Flows

Contributions. The Company expects to contribute approximately $1 million to the postretirement benefit plan in 2023.

Estimated Future Benefit Payments. The following estimated benefit payments under the Company’s postretirement plans, which reflect expected future service, are expected to be paid as follows:


(In millions)
2023	$	1
2024	1
2025	1
2026	1
2027	1
Years 2028 - 2032	6

Retirement Savings Plan

The Company has a Retirement Savings Plan (“RSP”), which is a defined contribution plan. The Company matches a portion of employees’ contributions in cash. Participation in the RSP is voluntary and all employees of the Company are eligible to participate. The Company matches employee contributions dollar-for-dollar, up to the maximum Internal Revenue Service (“IRS”) limit, on the first six percent of an employee’s pretax earnings. The RSP also provides for discretionary contributions in an amount equal to 10 percent of an eligible plan participant’s salary and bonus.

In connection with the Merger, the Company assumed the Cimarex Energy Co. 401(k) Plan (the “401(k) Plan”) with respect to Cimarex employees. The Company maintained this plan throughout the integration process and terminated this plan effective December 31, 2022, with all legacy Cimarex employees becoming eligible for the Company’s RSP effective January 1, 2023.

During the years ended December 31, 2022, 2021 and 2020, the Company made aggregate contributions to the RSP and 401(k) Plan of $12 million, $7 million and $6 million, respectively, which are included in general and administrative expense in the Consolidated Statement of Operations. The Company’s common stock was an investment option within the RSP and the 401(k) Plan. Effective December 31, 2022, investment in the Company’s common stock is no longer an option.

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Deferred Compensation Plans

The Company has deferred compensation plans which are available to officers and select employees and act as a supplement to the RSP. The Internal Revenue Code does not cap the amount of compensation that may be taken into account for purposes of determining contributions to the deferred compensation plans and does not impose limitations on the amount of contributions to the deferred compensation plans. At the present time, the Company anticipates making a contribution to the deferred compensation plans on behalf of a participant in the event that Internal Revenue Code limitations cause a participant to receive less than the Company contribution under the RSP.

The assets of the deferred compensation plans are held in a rabbi trust and are subject to additional risk of loss in the event of bankruptcy or insolvency of the Company.

Under the deferred compensation plans, the participants direct the deemed investment of amounts credited to their accounts. The trust assets are invested in either mutual funds that cover the investment spectrum from equity to money market, or may include holdings of the Company’s common stock, which is funded by the issuance of shares to the trust. The mutual funds are publicly traded and have market prices that are readily available. The Company’s common stock is no longer an investment option in the deferred compensation plan effective December 31, 2022. All outstanding Coterra shares previously held in the trust will be liquidated in March 2023. Shares of the Company’s stock currently held in the deferred compensation plan represent vested performance share awards that were previously deferred into the rabbi trust. Settlement payments are made to participants in cash, either in a lump sum or in periodic installments. The market value of the trust assets, excluding the Company’s common stock, was $43 million and $47 million at December 31, 2022 and 2021, respectively, and is included in other assets in the Consolidated Balance Sheet. Related liabilities, including the Company’s common stock, totaled $55 million and $56 million at December 31, 2022 and 2021, respectively, and are included in other liabilities in the Consolidated Balance Sheet. Increases (decreases) in the fair value of the Company’s common stock are recognized as compensation expense (benefit) in general and administrative expense in the Consolidated Statement of Operations. There is no impact on earnings or earnings per share from the changes in market value of the other deferred compensation plan assets because the changes in market value of the trust assets are offset completely by changes in the value of the liability, which represents trust assets belonging to plan participants.

As of December 31, 2022 and 2021, 495,774 shares of the Company’s common stock were held in the rabbi trust, respectively. These shares were recorded at the market value on the date of deferral, which totaled $5 million and is included in additional paid-in capital in stockholders’ equity in the Consolidated Balance Sheet.

On September 30, 2021, certain executives of the Company entered into letter agreements whereby, in exchange for the cancellation of their rights under their change-in-control agreements and the non-competition and non-solicitation provisions contained in the letter agreements, each such executive would receive a contribution into his or her deferred compensation account at the effective time of the Merger. On October 1, 2021, the Company made deferred contribution payments totaling approximately $19 million into such executives’ deferred compensation accounts. All of such contributions are fully vested.

In connection with the Merger, the Company assumed the Cimarex deferred compensation plan. The market value of the trust assets and related liabilities was $27 million at the effective date of the Merger, October 1, 2021. Subsequent to the completion of the Merger, in October 2021, the Company distributed $27 million to the plan participants as a result of the change-in-control provision under the plan.

The Company made contributions to the deferred compensation plans of $1 million, $20 million and $1 million in 2022, 2021 and 2020, respectively, which are included in general and administrative expense in the Consolidated Statement of Operations.

12. Capital Stock

Issuance of Common Stock

Following the effectiveness of the Merger, on October 1, 2021, the Company issued approximately 408.2 million shares of its common stock to Cimarex stockholders under the terms of the Merger Agreement.

In October 2021, in accordance with the Merger Agreement, the Company issued 3.4 million shares of restricted stock to replace Cimarex restricted stock awards granted to certain employees. Because these awards have non-forfeitable rights to dividends or dividend equivalents, the Company considers these shares as issued common stock.

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Increase in Number of Authorized Shares

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

Dividends

Common Stock

The following table summarizes the dividends the Company has paid on its common stock during 2022, 2021 and 2020:


	Rate per share
	Base		Variable		Total		Total Dividends Paid (In millions)
2022:
First quarter	$	0.15	$	0.41	$	0.56	$	455
Second quarter	0.15		0.45		0.60		484
Third quarter	0.15		0.50		0.65		519
Fourth quarter	0.15		0.53		0.68		533
Total year-to-date	$	0.60	$	1.89	$	2.49	$	1,991
2021:
First quarter	$	0.10	$	—	$	0.10	$	40
Second quarter	0.11		—		0.11		44
Third quarter	0.11		—		0.11		44
Fourth quarter (1)	0.13		0.67		0.80		651
Total year-to-date	$	0.45	$	0.67	$	1.12	$	779
2020:
First quarter	$	0.10	$	—	$	0.10	$	40
Second quarter	0.10		—		0.10		40
Third quarter	0.10		—		0.10		40
Fourth quarter	0.10		—		0.10		39
Total year-to-date	$	0.40	$	—	$	0.40	$	159

_______________________________________________________________________________

(1)Includes a special dividend of $0.50 per share on the Company’s common stock that was paid in connection with the completion of the Merger.

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

Cimarex Redeemable Preferred Stock

During 2022 and 2021, the Company paid dividends of $1 million each year, or $20.3125 per share on the outstanding shares of Preferred Stock (as defined below) issued by Cimarex.

Treasury Stock

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

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During 2022, the Company repurchased 48 million shares of common stock for $1.25 billion under the February 2022 share repurchase program. During 2021 and 2020, there were no share repurchases under the prior share repurchase program. As of December 31, 2022, the Company’s February 2022 repurchase program was fully executed.

During 2022 and 2021, the Company withheld 320,236 and 125,067 shares of common stock, respectively, valued at $9 million and $3 million, respectively, related to shares withheld for taxes upon the vesting of certain restricted stock awards.

In December 2022, the Company’s Board of Directors authorized the retirement of the Company’s 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.

Subsequent Event. In February 2023, the Company’s Board of Directors approved a new share repurchase program which authorizes the purchase of up to $2.0 billion of the Company’s common stock.

Dividend Restrictions

The Board of Directors of the Company determines the amount of future cash dividends, if any, to be declared and paid on the common stock depending on, among other things, the Company’s financial condition, funds from operations, the level of its capital and exploration expenditures and its future business prospects. None of the senior note or credit agreements in place have restricted payment provisions or other provisions which currently limit the Company’s ability to pay dividends.

Cimarex Redeemable Preferred Stock

In October 2021, in connection with the Merger, the Company effectively assumed the obligations associated with Cimarex’s preferred stock, par value $0.01 per share, designated as 8 1/8% Series A Cumulative Perpetual Convertible Preferred Stock (the “Preferred Stock”). The Preferred Stock was originally issued by Cimarex and remains on the Cimarex balance sheet after the Merger. The fair value of the Preferred Stock as of the effective date of the Merger was $50 million. The Company accounts for the Preferred Stock as a non-controlling interest, which is immaterial for reporting purposes.

In May 2022, the holders of 21,900 shares of Preferred Stock elected to convert their Preferred Stock into Coterra common stock and cash. As a result of the conversion, the holders received 809,846 shares of Coterra common stock and $10 million in cash according to the terms of the Certificate of Designations for the Preferred Stock. The book value of the converted shares was $39 million, and upon conversion the excess of carrying value over cash paid was credited to additional paid-in capital. There was no gain or loss recognized on the transaction because it was completed in accordance with the original terms of the Certificate of Designations for the Preferred Stock. At December 31, 2022, there were 6,125 shares of Preferred Stock outstanding with a carrying value of $11 million.

13. Stock-Based Compensation

Incentive Plans

Cabot Oil & Gas Corporation 2014 Incentive Plan

On May 1, 2014, the Company’s stockholders approved the Cabot Oil & Gas Corporation 2014 Incentive Plan (the “2014 Plan”). Under the 2014 Plan, incentive and non-statutory stock options, stock appreciation rights (“SARs”), stock awards, cash awards and performance share awards may be granted to key employees, consultants and officers of the Company. Non-employee directors of the Company may be granted discretionary awards under the 2014 Plan consisting of stock options or stock awards. A total of 18.0 million shares of common stock may be issued under the 2014 Plan. Under the 2014 Plan, no more than 10.0 million shares may be issued pursuant to incentive stock options. No additional awards may be granted under the 2014 Plan on or after May 1, 2024. At December 31, 2022, approximately 9.5 million shares are available for issuance under the 2014 Plan.

Cimarex Energy Co. Amended and Restated 2019 Equity Incentive Plan

In connection with the Merger, the Company assumed all rights and obligations under the Cimarex Energy Co. Amended and Restated 2019 Equity Incentive Plan (the “2019 Plan”) and the Company will be entitled to grant equity or equity-based awards with respect to Coterra common stock under the 2019 Plan to current or former employees of Cimarex, to the extent permissible under applicable law and NYSE listing rules. The 2019 Plan provides for grants of stock options, SARs, restricted stock, restricted stock units, performance stock units, cash awards and other stock-based awards. As of December 31, 2022, approximately 35.2 million shares of Coterra common stock are available for issuance under the 2019 Plan, subject to certain limitations.

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General

Stock-based compensation expense of awards issued under the Company’s incentive plans, and the income tax benefit of awards vested and exercised, are as follows:


	Year Ended December 31,
(In millions)	2022		2021		2020

Restricted stock units - employees and non-employee directors	$	31	$	6	$	2
Restricted stock awards	20		6		—
Performance share awards (1)	22		41		40
Deferred performance shares	2		1		(1)
Dividend equivalents	11		3		2
Total stock-based compensation expense	$	86	$	57	$	43
Income tax benefit	$	20	$	24	$	10

_______________________________________________________________________________

(1) In accordance with the Merger Agreement, the Company recognized approximately $18 million of stock-based compensation expense in the fourth quarter of 2021 associated with the acceleration of vesting of certain performance share awards. In the third quarter of 2022, the Company recognized approximately $7 million of stock-based compensation expense associated with the acceleration of vesting of certain employee performance awards.

Restricted Stock Units - Employees

Restricted stock units are granted from time to time to employees of the Company. The fair value of restricted stock unit grants is based on the closing stock price on the grant date. Restricted stock units generally vest either at the end of a three year service period or on a graded or graduated vesting basis at each anniversary date over a three or four year service period. The restricted stock units are settled in shares of the Company’s common stock on the vesting date.

For awards that vest at the end of the service period, expense is recognized ratably using a straight-line approach over the service period. Under the graded or graduated approach, the Company recognizes compensation cost ratably over the requisite service period, as applicable, for each separately vesting tranche as though the awards are, in substance, multiple awards. For most restricted stock units, vesting is dependent upon the employees’ continued service with the Company, with the exception of employment termination due to death, disability or, if applicable, retirement. If retirement protection is included in the grant award, the Company accelerates the vesting period for retirement-eligible employees for purposes of recognizing compensation expense in accordance with the vesting provisions of the Company’s stock-based compensation programs.

The Company used an annual forfeiture rate assumption ranging from zero to five percent for purposes of recognizing stock-based compensation expense for these restricted stock units. The annual forfeiture rates were based on the Company’s actual forfeiture history or expectations for this type of award to various employee groups.

The following table is a summary of restricted stock unit award activity:


	Year Ended December 31, 2022

	Shares	Weighted- Average Grant Date Fair Value per Unit
Outstanding at beginning of period	1,286,471	$	21.00
Granted	2,249,405	24.81
Vested	(316,322)	22.75
Forfeited	(31,410)	25.25
Outstanding at end of period	3,188,144	$	23.47

The weighted-average grant date fair value per unit granted during 2022 and 2021 was $24.81 and $20.83, respectively. There were no units granted in 2020.

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Restricted Stock Units - Non-Employee Directors

Restricted stock units are granted from time to time to non-employee directors of the Company. The fair value of the restricted stock units is based on the closing stock price on the grant date. Prior to 2022, these units vested on the grant date, compensation was recorded immediately and the shares of the Company’s common stock are issued when the director ceases to be a director of the Company. Beginning in 2022, these units will generally vest the earlier of a one-year service period or termination from the Board of Directors with compensation expense recognized ratably over the vesting period and the units will be settled in shares of the Company’s common stock on the vesting date.

The Company did not use an annual forfeiture rate for purposes of recognizing stock-based compensation expense for these restricted stock units. The annual forfeiture rate assumption was based on the Company’s actual forfeiture history or expectations for this type of award.

The following table is a summary of restricted stock unit award activity:


	Year Ended December 31, 2022

	Shares	Weighted- Average Grant Date Fair Value per Unit
Outstanding at beginning of period	245,898	$	20.41

Granted	45,472	35.19
Vested	—	—
Forfeited	—	—
Outstanding at end of period	291,370	$	22.72

The weighted-average grant date fair value per unit granted during 2022, 2021 and 2020 was $35.19, $18.51 and $15.88, respectively.

Restricted Stock Awards

Restricted stock awards are granted from time to time to employees of the Company. The fair value of restricted stock grants is based on the closing stock price on the grant date. Restricted stock awards generally vest either at the end of a three year service period or on a graded or graduated vesting basis at each anniversary date over a three year service period.

For awards that vest at the end of the service period, expense is recognized ratably using a straight-line approach over the service period. Under the graded or graduated approach, the Company recognizes compensation cost ratably over the requisite service period, as applicable, for each separately vesting tranche as though the awards are, in substance, multiple awards. For most restricted stock awards, vesting is dependent upon the employees’ continued service with the Company, with the exception of employment termination due to death, disability or, if applicable, retirement. If retirement protection is included in the grant award, the Company accelerates the vesting period for retirement-eligible employees for purposes of recognizing compensation expense in accordance with the vesting provisions of the Company’s stock-based compensation programs.

The Company used an annual forfeiture rate assumption of ranging from zero to 15 percent for purposes of recognizing stock-based compensation expense for restricted stock awards. The annual forfeiture rates were based on the Company’s actual forfeiture history for this type of award to various employee groups.

The following table is a summary of restricted stock award activity:


	Year Ended December 31, 2022

	Shares	Weighted- Average Grant Date Fair Value per Share
Outstanding at beginning of period	3,019,183	$	22.25
Granted	—	—
Vested	(813,812)	22.25
Forfeited	(136,397)	22.25
Outstanding at end of period	2,068,974	$	22.25

On October 1, 2021, the Company granted 3,364,354 shares of restricted stock, with a grant date value of $22.25 per share. These awards were replacement awards granted to Cimarex employees as provided under the Merger Agreement. The

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fair value of these awards was measured based on the closing stock price on the closing date of the Merger (grant date). The remaining outstanding awards will vest over the next two years. Approximately $22 million of the grant date value was recognized as merger consideration and the remaining fair value will be recognized as stock-based compensation expense over the respective vesting periods. There were no restricted stock awards granted in 2022.

Performance Share Awards

From time to time, the Company grants performance share awards that are based on performance conditions measured against the Company’s internal performance metrics or based on the Company’s performance relative to a predetermined peer group and/or industry-related indices (“TSR Performance Share Awards”). The performance period for these awards generally commences on February 1 of the respective year in which the award was granted and extends over a three-year performance period. For most performance share awards, vesting is dependent upon the employees’ continued service with the Company, with the exception of employment termination due to death, disability or, if applicable, retirement. For all outstanding performance share awards, the Company did not use an annual forfeiture rate for purposes of recognizing stock-based compensation expense for its performance share awards. The annual forfeiture rate assumption was based on the Company’s actual forfeiture history or expectations for this type of award.

Performance Share Awards Based on Internal Performance Metrics

The fair value of performance share award grants based on internal performance metrics is based on the closing stock price on the grant date. Each performance share award represents the right to receive up to 100 percent of the award in shares of common stock.

Employee Performance Share Awards. The Employee Performance Share Awards vest at the end of the three-year performance period and the performance metric are set by the Company’s Compensation Committee. An employee will earn 100 percent of the award on the third anniversary, provided that the Company averages $100 million or more of operating cash flow during the three-year performance period. Based on the Company’s probability assessment at December 31, 2022, it is considered probable that all of the criteria for these awards will be met.

The following table is a summary of activity for Employee Performance Share Awards:


	Year Ended December 31, 2022

	Shares	Weighted- Average Grant Date Fair Value per Share
Outstanding at beginning of period	1,858,104	$	18.93
Granted	—	—
Vested	(1,775,790)	18.88
Forfeited	(9,000)	17.20
Outstanding at end of period	73,314	$	20.46

During 2022, the compensation committee of the Board of Directors of the Company certified that the performance conditions for certain of the Employee Performance Share Awards that were granted in 2020 and 2021 had been met. In July 2022, 1,775,790 shares with a grant date fair value of $22 million were issued and fully vested.

Performance Share Awards Based on Market Conditions

These awards have both an equity and liability component, with the right to receive up to the first 100 percent of the award in shares of common stock and the right to receive up to an additional 100 percent of the value of the award in excess of the equity component in cash. The equity portion of these awards is valued on the grant date and is not marked to market, while the liability portion of the awards is valued as of the end of each reporting period on a mark-to-market basis. The Company calculates the fair value of the equity and liability portions of the awards using a Monte Carlo simulation model.

TSR Performance Share Awards. The TSR Performance Share Awards granted are earned, or not earned, based on the comparative performance of the Company’s common stock measured against a predetermined group of companies in the Company’s peer group and certain industry-related indices over a three-year performance period. The Company’s TSR Performance Share Awards also include a feature that will reduce the potential cash component of the award if the actual performance is negative over the three-year period and the base calculation indicates an above-target payout.

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The following table is a summary of activity for the TSR Performance Share Awards:


	Year Ended December 31, 2022

	Shares	Weighted- Average Grant Date Fair Value per Unit (1)
Outstanding at beginning of period	—	$	—
Granted	1,161,599	17.89
Vested	—	—
Forfeited	—	—
Outstanding at end of period	1,161,599	$	17.89

_______________________________________________________________________________

(1)The grant date fair value figures in this table represent the fair value of the equity component of the performance share awards.

The following table reflects certain balance sheet information of outstanding TSR Awards:


	December 31,
(In millions)	2022		2021

Other non-current liabilities	$	3	$	—

The following table reflects certain cash payments related to the vesting of TSR Awards:


	Year Ended December 31,
(In millions)	2022		2021		2020
Cash payments for TSR awards	$	—	$	—	$	14

The following assumptions were used to determine the grant date fair value of the equity component of the TSR Performance Share Awards for the respective periods:


	Year Ended December 31,
	2022			2021			2020
Fair value per performance share award granted during the period	$	9.01		$	16.07		$	13.79
Assumptions
Stock price volatility	42.6		%	39.8		%	29.5		%
Risk free rate of return	4.4		%	0.2		%	1.4		%

The following assumptions were used to determine the fair value of the liability component of the TSR Performance Share Awards for the respective periods:


	December 31,
	2022		2021				2020
Fair value per performance share award at the end of the period	$14.92		$	—			$10.37 - $10.81
Assumptions
Stock price volatility	42.6	%	—			%	42.4% - 52.4%
Risk free rate of return	4.4	%	—		%		0.1%

The stock price volatility was calculated using historical closing stock price data for the Company for the period associated with the expected term through the grant date of each award. The risk free rate of return percentages are based on the continuously compounded equivalent of the U.S. Treasury within the expected term as measured on the grant date.

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Other Information

The following table reflects the aggregate fair value of awards and units that vested during the respective period:


	December 31,
(In millions)	2022		2021		2020
Restricted stock units - employees and non-employee directors	$	9	$	11	$	—
Restricted stock awards	22		7		—
Performance share awards	45		84		25
	$	76	$	102	$	25

The following table reflects the unrecognized stock-based compensation and the related weighted-average recognition period associated with the unvested awards and units as of December 31, 2022:


	Unrecognized Stock-Based Compensation (In Millions)		Weighted-Average Period For Recognition (Years)
Restricted stock units - employees and non-employee directors	$	48	2.2
Restricted stock awards	21		1.4
Performance share awards	15		1.9
	$	84

Stock Option Awards

On October 1, 2021, the Company granted stock option awards to purchase 1,577,554 shares of the Company’s common stock with exercise prices ranging from $8.47 to $28.72 per share. These awards were replacement awards granted to Cimarex employees as provided under the Merger Agreement and were fully vested on the closing date of the Merger. The grant date fair value of approximately $14 million was recognized as merger consideration and, accordingly, no compensation expense will be recognized by the Company related to these awards, as there is no future service requirement for the holders of these awards.

The following table is a summary of activity for the Stock Option Awards:


	Year Ended December 31, 2022
	Shares	Weighted- Average Strike Price
Outstanding at beginning of period	1,355,352	$	17.35
Granted	—	—
Exercised	(780,606)	16.29
Forfeited or Expired	(38,137)	28.67
Outstanding at end of period(1)	536,609	$	18.08
Exercisable at end of period(1)	536,609	$	18.08

_______________________________________________________________________________

(1)The intrinsic value of a stock option is the amount by which the current market value of the underlying stock exceeds the exercise price of the stock option. The aggregate intrinsic value of stock options outstanding and exercisable at December 31, 2022 was $4 million and $4 million, respectively. The weighted-average remaining contractual term is 2.6 years.

Deferred Performance Shares

As of December 31, 2022, 495,774 shares of the Company’s common stock representing vested performance share awards were deferred into the deferred compensation plan. During 2022, no shares were sold out of the plan. During 2022, an increase to the deferred compensation liability of $2 million was recognized, which represents the increase in the closing price of the Company’s shares held in the trust during the period. The increase in compensation expense was included in general and administrative expense in the Consolidated Statement of Operations.

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14. Earnings per Common Share

Basic earnings per share (“EPS”) is computed by dividing net income available to common stockholders by the weighted-average number of common shares outstanding for the period. Diluted EPS is similarly calculated except that the common shares outstanding for the period is increased using the treasury stock and as-if-converted methods to reflect the potential dilution that could occur if outstanding stock awards were vested or exercised at the end of the applicable period. Anti-dilutive shares represent potentially dilutive securities that are excluded from the computation of diluted income or loss per share as their impact would be anti-dilutive.

The following is a calculation of basic and diluted net earnings per common share under the two-class method:


	Year Ended December 31,
(In millions except per share amounts)	2022		2021		2020

Income (Numerator)
Net income	$	4,065	$	1,158	$	201
Less: dividends attributable to participating securities	(7)		(2)		—
Less: Cimarex redeemable preferred stock dividends	(1)		(1)		—
Net income available to common stockholders	$	4,057	$	1,155	$	201

Shares (Denominator)
Weighted average shares - Basic	796		503		399
Dilution effect of stock awards at end of period	3		1		2
Weighted average shares - Diluted	799		504		401

Earnings per share:
Basic	$	5.09	$	2.30	$	0.50
Diluted	$	5.08	$	2.29	$	0.50

The following is a calculation of weighted-average shares excluded from diluted EPS due to the anti-dilutive effect:


	Year Ended December 31,
(In millions)	2022	2021	2020

Weighted-average stock awards excluded from diluted EPS due to the anti-dilutive effect calculated using the treasury stock method	1	1	—

15. Restructuring Costs

During 2022 and 2021, the Company recognized $52 million and $44 million, respectively, of restructuring costs that are primarily related to workforce reductions and associated severance benefits that were triggered by the Merger. The following table summarizes the Company’s restructuring liabilities:


	Year Ended December 31,
(In millions)	2022		2021
Balance at beginning of period	$	43	$	—
Additions related to merger integration	52		44
Reductions related to merger integration payments	(18)		(1)
Balance at end of period	$	77	$	43

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16. Additional Balance Sheet Information

Certain balance sheet amounts are comprised of the following:


	December 31,
(In millions)	2022		2021
Accounts receivable, net
Trade accounts	$	1,067	$	922
Joint interest accounts	108		83
Other accounts	48		34
	1,223		1,039
Allowance for doubtful accounts	(2)		(2)
	$	1,221	$	1,037








Other assets
Deferred compensation plan	$	43	$	47
Debt issuance cost	3		5


Operating lease right-of-use assets	382		317

Other accounts	36		20
	$	464	$	389
Accounts payable
Trade accounts	$	27	$	94

Royalty and other owners	438		315
Accrued transportation	85		96
Accrued capital costs	148		88
Accrued lease operating costs	32		29
Taxes other than income	73		60


Other accounts	41		65
	$	844	$	747
Accrued liabilities
Employee benefits	$	74	$	81
Taxes other than income	62		13


Restructuring liability	39		43
Operating lease liabilities	114		69
Financing lease liabilities	6		14

Other accounts	33		40
	$	328	$	260
Other liabilities
Deferred compensation plan	$	55	$	56
Postretirement benefits	17		33

Operating lease liabilities	287		248
Financing lease liabilities	11		7
Restructuring liability	38		—
Other accounts	92		63
	$	500	$	407

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17. Interest Expense, net

Interest expense is comprised of the following:


	Year Ended December 31,
(In millions)	2022		2021		2020
Interest Expense, net
Interest expense	$	110	$	62	$	49
Debt premium amortization	(37)		(10)		—
Debt issuance cost amortization	4		3		3
Other	(7)		7		2
	$	70	$	62	$	54

18. Supplemental Cash Flow Information


	Year Ended December 31,
(In millions)	2022		2021		2020
Cash paid for interest and income taxes
Interest	$	119	$	81	$	57
Income taxes	983		184		11

Non-cash activity
Retirement of treasury shares	$	3,085	$	—	$	—
Equity and replacement stock awards issued as consideration in the Merger	$	—	$	9,120	$	—

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COTERRA ENERGY INC.

SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)

Oil and Gas Reserves

Proved reserves are based on estimates prepared by the Company in accordance with guidelines established by the SEC. Reserves definitions comply with definitions of Rule 4-10(a) of Regulation S-X promulgated by the SEC under the Securities Act.

Users of this information should be aware that the process of estimating quantities of “proved,” “proved developed” and “proved undeveloped” oil, natural gas and NGL reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserves estimates may occur from time to time. Although every reasonable effort is made to ensure that reserves estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures.

Preparation of Reserves Estimates

All of the Company’s reserves estimates are maintained by the Company’s internal Corporate Reservoir Engineering group, which is comprised of engineers and engineering analysts. The objectives and management of this group are separate from and independent of the exploration and production functions of the Company. The primary objective of the Company’s Corporate Reservoir Engineering group is to maintain accurate forecasts on all properties of the Company through ongoing monitoring and timely updates of operating and economic parameters (production forecasts, prices and regional differentials, operating expenses, ownership, etc.). In addition, the Corporate Reservoir Engineering group maintains a set of basic guidelines and procedures to ensure that critical checks and reviews of the reserves database are performed on a regular basis.

The Corporate Reservoir Engineering group is responsible for estimates of proved reserves. Corporate engineers interact with the exploration and production departments to ensure all appropriate available engineering and geologic data is taken into account prior to establishing or revising an estimate. The recommended revisions of the corporate engineers are reviewed with the Manager of Corporate Reservoir Engineering and, after approval, entered into the reserves database by an engineering analyst. During the course of the year, the Corporate Reservoir Engineering group reviews their recommendations and updates with the Vice President and Chief Technology Officer for additional oversight and approval. From time to time, the Vice President and Chief Technology Officer also will confer with senior management, including the Chief Executive Officer, regarding reserves-related issues. Upon completion of the process, the estimated reserves are presented to senior management and the Board of Directors.

The Company’s Vice President and Chief Technology Officer is the technical person primarily responsible for overseeing the Company’s internal reserves estimation process and the Company’s Corporate Reservoir Engineering group. This individual graduated from the University of Tulsa with a Bachelor of Science degree in Petroleum Engineering. He has held numerous engineering and management roles and has over 15 years of experience in oil and gas reservoir evaluation and is a member of the Society of Petroleum Engineers.

The Company utilizes various methods and technologies to estimate its proved reserves, including analysis of production performance, analogy, decline curve analysis, rate and pressure transient analysis, reservoir simulation, material balance calculations, volumetric calculations, and in some cases a combination of these methods.

Review of Estimates by Third Party Engineers

The Company also engages independent petroleum engineering consulting firms as an additional confirmation of the reasonableness of its internal estimates.

During 2022, estimates of net proved reserves representing greater than 90 percent of the total future net revenue discounted at 10 percent attributable to the Company’s proved reserves were subject to an independent evaluation performed by DeGolyer and MacNaughton.

During 2021, 100 percent of the Company’s estimates with respect to the Company’s Marcellus Shale reserves were audited by Miller and Lents, Ltd. (“Miller and Lents”), and estimates of the net reserves representing greater than 80 percent of

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the total future net revenue discounted at 10 percent attributable to the Company’s remaining reserves were subject to an independent evaluation performed by DeGolyer and MacNaughton.

During 2020, 100 percent of estimates of proved reserves were audited by Miller and Lents.

In each of the respective periods, DeGolyer and MacNaughton and Miller and Lents each indicated that, based on their investigations and subject to the limitations described in their reserves letters, they believe the Company’s estimates were, in the aggregate, reasonable. A copy of DeGolyer and MacNaughton’s letter regarding the 2022 reserves estimate has been filed as an exhibit to this Annual Report on Form 10-K.

Qualifications of Third Party Engineers

DeGolyer and MacNaughton’s Executive Vice President is the technical person primarily responsible for the evaluation of the Company’s proved reserves. He is a Registered Professional Engineer in the State of Texas with over 12 years of experience in oil and gas reservoir studies and reserves evaluations and meets the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. DeGolyer and MacNaughton is an independent firm of petroleum engineers, geologists, geophysicists and petro physicists; they do not own an interest in the Company’s properties and are not retained on a contingent fee basis.

Estimated Quantities of Proved Oil and Gas Reserves

Estimates of total proved reserves at December 31, 2022, 2021 and 2020 were computed using the trailing 12-month average index price for the respective commodity, calculated as the unweighted arithmetic average for the first day of the month price for each month during the respective year.

No major discovery or other favorable or unfavorable event after December 31, 2022, is believed to have caused a material change in the estimates of proved or proved developed reserves as of that date.

100

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The following tables illustrate the Company’s net proved reserves, including changes, and proved developed and proved undeveloped reserves for the periods indicated, as estimated by the Company’s engineering staff. All reserves are located within the continental U.S.


	Oil (MBbl)	Natural Gas (Bcf)	NGLs (MBbl)	Total (MBoe)
December 31, 2019	22	12,903	—	2,150,422
Revision of prior estimates	(3)	(347)	—	(57,808)
Extensions, discoveries and other additions	—	1,974	—	328,976
Production	(4)	(858)	—	(142,954)


December 31, 2020	15	13,672	—	2,278,636
Revision of prior estimates	10,837	(538)	16,797	(61,967)
Extensions, discoveries and other additions	2,633	973	6,100	170,988
Production	(8,150)	(911)	(7,104)	(167,113)
Purchases of reserves in place	184,094	1,699	204,822	672,038

December 31, 2021	189,429	14,895	220,615	2,892,582
Revision of prior estimates	14,594	(4,299)	35,162	(666,716)
Extensions, discoveries and other additions	69,118	1,602	69,862	405,972
Production	(31,926)	(1,024)	(28,697)	(231,342)

Sales of reserves in place	(1,460)	(1)	(177)	(1,830)
December 31, 2022	239,755	11,173	296,765	2,398,666
Proved Developed Reserves
December 31, 2019	22	8,056	—	1,342,589
December 31, 2020	15	8,608	—	1,434,714
December 31, 2021	153,010	10,691	193,598	2,128,439
December 31, 2022	168,649	8,543	224,706	1,817,140
Proved Undeveloped Reserves
December 31, 2019	—	4,847	—	807,833
December 31, 2020	—	5,064	—	843,922
December 31, 2021	36,419	4,204	27,017	764,143
December 31, 2022	71,107	2,630	72,059	581,526

Year-end 2022 proved reserves decreased approximately 17 percent from year-end 2021 proved reserves to 2,399 MMBoe. Proved natural gas reserves were 11.2 Tcf, proved oil reserves were 240 MMBbls, and proved NGL reserves were 297 MMBbls. The Company’s reserves in the Marcellus Shale accounted for 62 percent of total proved reserves, the Permian Basin accounted for 29 percent, and the remaining nine percent were in the Anadarko Basin.

During 2022, the Company added 406 MMBoe of proved reserves through extensions, discoveries, and other additions, which included 191 MMBoe in the Marcellus Shale, 193 MMBoe in the Permian Basin, and 22 MMBoe in the Anadarko Basin.

The Company had net negative revisions of prior estimates of 667 MMBoe, which included 571 MMBoe in downward performance revisions related to updated forecast parameters in the Marcellus Shale to account for a different decline behavior observed in bounded wells compared to unbounded wells. The net negative revisions also included 168 MMBoe associated with the removal of PUD reserves in the Marcellus Shale whose development is expected to be delayed beyond five years of initial booking. These negative revisions in the Marcellus Shale were partially offset by 32 MMBoe in positive performance revisions in the Permian Basin, 39 MMBoe in positive revisions related to upward price revisions, and 1 MMBoe in positive revisions related to decreases in operating expenses.

During 2021, the Company added 171 MMBoe of proved reserves through extensions, discoveries, and other additions, which were primarily in the Marcellus Shale. Additionally, the Company added 672 MMBoe from purchases of reserves in place related to the acquisition of Cimarex’s oil and gas properties in connection with the Merger. The reserves acquired were primarily related to the Wolfcamp Shale and Bone Spring in the Permian Basin and the Woodford Shale in the Anadarko Basin. The Company also had net negative revisions of 62 MMBoe, which was primarily due to a 97 MMBoe downward performance

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revision and a 6 MMBoe downward revision associated with PUD reclassifications as a result of the five-year limitation. These downward revisions were partially offset by a 42 MMBoe positive pricing and cost revision. The net downward performance revision of 97 MMBoe was primarily due to a 57 MMBoe performance revision related to certain proved developed reserves and a 40 MMBoe downward performance revision associated with PUD reserves.

During 2020, the Company added 329 MMBoe of proved reserves through extensions, discoveries, and other additions in the Marcellus Shale. The Company had net negative revisions of 58 MMBoe, which were primarily due to a net downward performance revision of 41 MMBoe and a downward revision of 11 MMBoe associated with PUD reclassifications as a result of the five-year limitation. The net downward performance revision of 41 MMBoe was primarily due to a downward performance revision of 61 MMBoe related to certain proved developed producing properties, partially offset by an upward revision of 21 MMBoe associated with the Company’s PUD reserves related to positive performance revisions as a result of drilling of longer lateral length wells.

Proved Undeveloped Reserves

At December 31, 2022, the Company had PUD reserves of 582 MMBoe, down 182 MMBoe, or 24 percent, from 764 MMBoe of PUD reserves at December 31, 2021. Future development plans are reflective of the current commodity price environment and have been established based on expected available cash flows from operations. By the end of 2023, the Company expects to complete substantially all the work necessary to convert its PUD reserves associated with wells that were drilled but uncompleted at December 31, 2022 to proved developed reserves. As of December 31, 2022 all PUD reserves are expected to be drilled and completed within five years of initial disclosure of these reserves. The following table is a reconciliation of the change in the Company’s PUD reserves (MMBoe):


			Year Ended December 31, 2022
Balance at beginning of period			764
Transfers to proved developed			(280)
Additions			364
Revision of prior estimates			(266)
Balance at end of period			582

During 2022, the Company invested $945 million to develop and convert 37 percent of its 2021 PUD reserves to proved developed reserves. During 2021, the Company invested $565 million to develop and convert 31 percent of its 2020 PUD reserves to proved developed reserves. During 2020, the Company invested $456 million to develop and convert 37 percent of its 2019 PUD reserves to proved developed reserves.

During 2022, the Company’s 364 MMBoe of PUD reserves additions consisted of 172 MMBoe added in the Marcellus Shale, 171 MMBoe added in the Permian Basin, and 21 MMBoe added in the Anadarko Basin. At December 31, 2022, 62 percent of the Company’s PUD reserves were in the Marcellus Shale, 34 percent were in the Permian Basin and the remaining four percent were in the Anadarko Basin.

During 2022, the Company had a net negative PUD reserves revision of 266 MMBoe. Of this total, 100 MMBoe was related to a downward revision to PUD forecasts as a result of lower than expected well performance in the Marcellus Shale. The net negative revisions also included 168 MMBoe due to the removal of PUD reserves in the Marcellus Shale whose development is expected to be delayed beyond five years of initial date of booking due to the Company’s updated development plans, which resulted in changes to the timing of capital investments and well spacing in the Marcellus Shale. These negative revisions were partially offset by 2 MMBoe related to a positive revision to PUD forecasts in the Permian Basin as a result of better than expected well performance compared to previous proved reserves estimates.

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Capitalized Costs Relating to Oil and Gas Producing Activities

Capitalized costs relating to oil and gas producing activities and related accumulated depreciation, depletion and amortization were as follows:


	December 31,
(In millions)	2022		2021		2020
Aggregate capitalized costs relating to oil and gas producing activities	$	22,235	$	20,655	$	7,154
Aggregate accumulated depreciation, depletion and amortization	(5,285)		(3,775)		(3,149)
Net capitalized costs	$	16,950	$	16,880	$	4,005

Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities

Costs incurred in property acquisition, exploration and development activities were as follows:


	Year Ended December 31,
(In millions)	2022		2021(1)		2020
Property acquisition costs, proved	$	—	$	7,472	$	—
Property acquisition costs, unproved	10		5,386		6
Exploration costs	29		18		15
Development costs	1,617		688		547
Total costs	$	1,656	$	13,564	$	568

_______________________________________________________________________________

(1)These amounts include 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 the Company’s common stock.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

The following information has been developed based on oil and natural gas reserves and production volumes estimated by the Company’s engineering staff. It can be used for some comparisons, but should not be the only method used to evaluate the Company or its performance. Further, the information in the following table may not represent realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flows (“Standardized Measure”) be viewed as representative of the current value of the Company.

The Company believes that the following factors should be taken into account when reviewing the following information:

•Future costs and selling prices will differ from those required to be used in these calculations.

•Due to future market conditions and governmental regulations, actual rates of production in future years may vary significantly from the rate of production assumed in the calculations.

•Selection of a 10 percent discount rate is arbitrary and may not be a reasonable measure of the relative risk that is part of realizing future net oil and gas revenues.

•Future net revenues may be subject to different rates of income taxation.

Under the Standardized Measure, future cash inflows were estimated by using the trailing 12-month average index price for the respective commodity, calculated as the unweighted arithmetic average for the first day of the month price for each month during the year.

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The average prices (adjusted for basis and quality differentials) related to proved reserves are as follows:


	Year Ended December 31,
	2022		2021		2020
Natural gas	$	6.36	$	2.93	$	1.64
Oil	$	93.67	$	65.40	$	32.53
NGLs	$	41.76	$	25.74	$	—

In the above table, natural gas prices are stated per Mcf and oil and NGL prices are stated per barrel.

Future cash inflows were reduced by estimated future development and production costs based on year end costs to arrive at net cash flow before tax. Future income tax expense was computed by applying year end statutory tax rates to future pretax net cash flows, less the tax basis of the properties involved and utilization of available tax carryforwards related to oil and gas operations. The applicable accounting standards require the use of a 10 percent discount rate.

Management does not solely use the following information when making investment and operating decisions. These decisions are based on a number of factors, including estimates of proved reserves and varying price and cost assumptions considered more representative of a range of anticipated economic conditions.

Standardized Measure is as follows:


	December 31,
(In millions)	2022		2021		2020
Future cash inflows	$	90,509	$	60,908	$	22,385
Future production costs	(20,105)		(18,241)		(10,784)
Future development costs(1)	(3,859)		(2,449)		(1,612)
Future income tax expenses	(14,570)		(8,535)		(2,176)
Future net cash flows	51,975		31,683		7,813
10% annual discount for estimated timing of cash flows	(25,903)		(18,399)		(4,751)
Standardized measure of discounted future net cash flows	$	26,072	$	13,284	$	3,062

______________________________________________________________________________

(1)Includes $544 million, $390 million and $224 million in plugging and abandonment costs as of December 31, 2022, 2021 and 2020, respectively.

Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

The following is an analysis of the changes in the Standardized Measure:


	Year Ended December 31,
(In millions)	2022		2021		2020
Beginning of year	$	13,284	$	3,062	$	5,861
Discoveries and extensions, net of related future costs	5,944		800		311
Net changes in prices and production costs	17,462		9,573		(4,326)
Accretion of discount	1,919		551		750
Revisions of previous quantity estimates	(3,825)		467		(108)
Timing and other	55		(161)		6
Changes in estimated future development costs	65		(103)		—
Development costs incurred	604		497		501
Sales and transfers, net of production costs	(7,912)		(2,801)		(746)
Sales of reserves in place	(18)		(1)		—
Purchases of reserves in place	—		6,477		—
Net change in income taxes	(1,506)		(5,077)		813
End of year	$	26,072	$	13,284	$	3,062

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

As of December 31, 2022, the Company carried out an evaluation, under the supervision and with the participation of the Company’s management, including the Company’s Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures pursuant to Rules 13a-15 and 15d-15 of the Exchange Act. Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures are effective to provide reasonable assurance with respect to the recording, processing, summarizing and reporting, within the time periods specified in the SEC’s rules and forms, of information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act.

During the quarter ended December 31, 2022, the Company integrated the controls and related procedures of Cimarex into its internal control over financial reporting and they are now included in the Company’s assessment of the effectiveness of the Company’s internal control over financial reporting.

Changes in Internal Control over Financial Reporting

There were no changes in internal control over financial reporting that occurred during the fourth quarter of 2022 that have materially affected, or are reasonably likely to have a material effect on, the Company’s internal control over financial reporting.

Management’s Report on Internal Control over Financial Reporting

The management of Coterra Energy Inc. is responsible for establishing and maintaining adequate internal control over financial reporting. Coterra Energy Inc.’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Coterra Energy Inc.’s management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2022. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in Internal Control—Integrated Framework (2013). Based on this assessment management has concluded that, as of December 31, 2022, the Company’s internal control over financial reporting is effective at a reasonable assurance level based on those criteria.

The effectiveness of Coterra Energy Inc.’s internal control over financial reporting as of December 31, 2022, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.

ITEM 9B. OTHER INFORMATION

None.

ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

None.

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PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The information set forth in Part 1 under the caption “Information about our Executive Officers” regarding our executive officers and the information set forth under the caption “Business—Other Business Matters—Corporate Governance Matters” in Item 1 regarding our Code of Business Conduct and Ethics is incorporated by reference in response to this item. The information required by this item is incorporated by reference from the Company’s definitive Proxy Statement in connection with the 2023 annual stockholders’ meeting.

ITEM 11. EXECUTIVE COMPENSATION

The information required by this item is incorporated by reference from the Company’s definitive Proxy Statement in connection with the 2023 annual stockholders’ meeting.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The information required by this item is incorporated by reference from the Company’s definitive Proxy Statement in connection with the 2023 annual stockholders’ meeting.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

The information required by this item is incorporated by reference from the Company’s definitive Proxy Statement in connection with the 2023 annual stockholders’ meeting.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

The information required by this item is incorporated by reference from the Company’s definitive Proxy Statement in connection with the 2023 annual stockholders’ meeting.

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PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

A. INDEX

1. Consolidated Financial Statements

See Index on page 56.

2. Financial Statement Schedules

Financial statement schedules listed under SEC rules but not included in this report are omitted because they are not applicable or the required information is provided in the notes to our consolidated financial statements.

3. Exhibits

The following instruments are included as exhibits to this report. Those exhibits below incorporated herein by reference are indicated as such by the information supplied in the parenthetical thereafter. If no parenthetical appears after an exhibit, copies of the instrument have been included herewith. The Company’s file number with the SEC is 1-10447.


Exhibit Number			Description
2.1			Agreement and Plan of Merger, dated as of May 23, 2021, by and among Cabot Oil & Gas Corporation, Double C Merger Sub, Inc. and Cimarex Energy Co. (incorporated herein by reference to Exhibit 2.1 of Coterra’s Current Report on Form 8-K filed with the SEC on May 24, 2021).
2.2			Amendment No. 1 to Agreement and Plan of Merger, dated as of June 29, 2021, by and among Cabot Oil & Gas Corporation, Double C Merger Sub, Inc. and Cimarex Energy Co. (incorporated herein by reference to Annex A to the Joint Proxy Statement/Prospectus included in Coterra’s Registration Statement on Form S-4 (Reg. No. 333-257534) filed with the SEC on June 30, 2021).
3.1			Restated Certificate of Incorporation of Coterra Energy Inc. (incorporated herein by reference to Exhibit 3.3 of Coterra’s Current Report on Form 8-K filed with the SEC on October 1, 2021).
3.2			Amended and Restated Bylaws of Coterra Energy Inc. (incorporated herein by reference to Exhibit 3.4 of Coterra’s Current Report on Form 8-K filed with the SEC on October 1, 2021).
4.1			Description of Securities Registered Pursuant to Section 12 of the Securities Exchange Act or 1934 (incorp o rated her e in by reference to Exhibit 4.1 of Coterra ’s Annu al Report on Form 10-K filed with the SEC on March 1, 2022.)
4.2			Form of Common Stock Certificate of Coterra Energy Inc. (incorporated herein by reference to Exhibit 4.3 of Coterra’s Registration Statement on Form S-8 (Reg. No. 333-260035 ) filed with the SEC on October 5, 2021).
4.3			Certificate of Designations to 8 1⁄8% Series A Cumulative Perpetual Convertible Preferred Stock of Cimarex Energy Co. (incorporated herein by reference to Exhibit 4.3 of Coterra’s Annual Report on Form 10-K filed with the SEC on March 1, 2022).
4.4			Amendment to Certificate of Designations to 8 1⁄8% Series A Cumulative Perpetual Convertible Preferred Stock of Cimarex Energy Co. (incorporated herein by reference to Exhibit 4.4 of Coterra’s Annual Report on Form 10-K filed with the SEC on March 1, 2022).
4.5			A mendment to Certificate of Designations to 8 1/8% Series A Cumulat ive Perpetual Convertible Preferred Sto ck of Cimarex Energy Co. (incorporated herein by reference to Ex hibit 4.3 of Coterra ’s Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2022).
4.6			Note Purchase Agreement dated as of September 18, 2014 among Cabot Oil & Gas Corporation and the Purchasers named therein (incorporated herein by reference to Exhibit 4.1 of Coterra’s Current Report on Form 8-K filed with the SEC on September 24, 2014).
			(a) Amendment No. 1 to Note Purchase Agreement, dated as of December 31, 2015 (incorporated herein by reference to Exhibit 4.5 of Coterra’s Current Report on Form 8-K filed with the SEC on February 9, 2016).
			(b) Amendment No. 2 to Note Purchase Agreement, dated as of April 8, 2016 (incorporated herein by reference to Exhibit 4.4(b) of Coterra’s Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2016).
4.7			Indenture, dated as of October 7, 2021, by and between Coterra Energy Inc. and U.S. Bank National Association, as Trustee (incorporated herein by reference to Exhibit 4.1 of Coterra’s Current Report on Form 8-K filed with the SEC on October 7, 2021).
4.8			First Supplemental Indenture, dated as of October 7, 2021, by and between Coterra Energy Inc. and U.S. Bank National Association, as Trustee (incorporated herein by reference to Exhibit 4.2 of Coterra’s Current Report on Form 8-K filed with the SEC on October 7, 2021).

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4.9			Form of 3.90% Senior Notes due 2027 (incorporated herein by reference to Exhibit A-2 to the First Supplemental Indenture filed as Exhibit 4.2 of Coterra’s Current Report on Form 8-K filed with the SEC on October 7, 2021).
4.10			Form of 4.375% Senior Notes due 2029 (incorporated herein by reference to Exhibit A-3 to the First Supplemental Indenture filed as Exhibit 4.2 of Coterra’s Current Report on Form 8-K filed with the SEC on October 7, 2021).
Coterra or certain of its consolidated subsidiaries are parties to other debt instruments under which the total amount of securities authorized does not exceed 10% of Coterra’s total consolidated assets. Pursuant to paragraph (4)(iii)(A) of Item 601(b) of Regulation S-K, Coterra agrees to furnish a copy of any of those instruments to the SEC upon its request.
*10.1			Form of Change in Control Agreement between Cabot Oil & Gas Corporation and Certain Officers (incorporated herein by reference to Exhibit 10.1 of Coterra’s Annual Report on Form 10-K for the fiscal year ended December 31, 2008).
			(a) Form of Change in Control Agreement between Cabot Oil & Gas Corporation and Certain Officers (Confirmation that Certain Benefits no Longer Apply) (incorporated herein by reference to Exhibit 10.1(a) of Coterra’s Annual Report on Form 10-K for the fiscal year ended December 31, 2010).
			(b) Form of Amendment to Change in Control Agreement (incorporated herein by reference to Exhibit 10.4 of Coterra’s Registration Statement on Form S-4 (Reg. No. 333-257534) filed with the SEC on June 30, 2021).
			(c) Form of Letter Agreement with respect to Change-in-Control Arrangements (incorporated herein by reference to Exhibit 10.1 of Coterra’s Current Report on Form 8-K filed with the SEC on October 1, 2021).
			(d) Amendment to Change in Control Agreement and Employment Letter Agreement dated December 27, 2022 (incorporated herein by reference to Exhibit 10.1 of Coterra ’s Current Report on Form 8-K filed with the S EC on December 2 9 , 2022).
*10.2			Form of Indemni fication Agreement between Cabot Oil & Gas Corporation and Certain Officers (incorporated herein by reference to Exhibit 10.2 of Coterra’s Annual Report on Form 10-K for the fiscal year ended December 31, 2012).
*10.3			Form of Indemnification Agreement (incorporated herein by reference to Exhibit 10.3 of Coterra’s Current Report on Form 8-K filed with the SEC on October 1, 2021).
*10.4			Deferred Compensation Plan of Cabot Oil & Gas Corporation, as Amended and Restated, Effective January 1, 2011 (incorporated herein by reference to Exhibit 10.1 of Coterra’s Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2011).
*10.5			Deferred Compensation Letter Agreement, dated as of September 30, 2021, between Cabot Oil & Gas Corporation and Phillip L. Stalnaker (incorporated herein by reference to Exhibit 10.2 of Coterra’s Current Report on Form 8-K filed with the SEC on October 1, 2021).
*10.6			Employment Letter Agreement, dated as of May 23, 2021, between Cabot Oil & Gas Corporation and Dan O. Dinges (incorporated herein by reference to Exhibit 10.1 of Coterra’s Registration Statement on Form S-4 (Reg. No. 333-257534) filed with the SEC on June 30, 2021).
*10.7			Employment Letter Agreement, dated as of May 23, 2021, between Cabot Oil & Gas Corporation and Thomas E. Jorden (incorporated herein by reference to Exhibit 10.2 of Coterra’s Registration Statement on Form S-4 (Reg. No. 333-257534) filed with the SEC on June 30, 2021).
*10.8			Side Letter Agreement, dated as of June 29, 2021, by and between Cabot Oil and Gas Corporation and Thomas E. Jorden (incorporated herein by reference to Exhibit 10.3 of Coterra’s Registration Statement on Form S-4 (Reg. No. 333-257534) filed with the SEC on June 30, 2021).
*10.9			Cabot Oil & Gas Corporation 2014 Incentive Plan , Effective May 1, 2014 (incorporated herein by reference to Exhibit 10.1 of Coterra’s Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2014).
			(a) Form of Non-Employee Director Restricted Unit Award Agreement (incorporated herein by reference to Exhibit 10.2 of Coterra’s Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2014).
			(b) Form of Restricted Stock Award Agreement (3 year graded) (incorporated herein by reference to Exhibit 10.2(a) of Coterra’s Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2015).
			(c) Form of Restricted Stock Award Agreement (3 year cliff) (incorporated herein by reference to Exhibit 10.2(b) of Coterra’s Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2015).
			(d) Form of Performance Share Award Agreement (Officers) (incorporated herein by reference to Exhibit 10.2(c) of Coterra’s Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2015).
			(e) Form of Hybrid Performance Share Award Agreement (incorporate herein by reference to Exhibit 10.2(d) of Coterra’s Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2015)..
			(f) Form of Performance Share Award Agreement (Employees) (incorporated herein by reference to Exhibit 10.2(e) of Coterra’s Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2015).
			(g) Form of Performance Share Award Agreement (Employees) (incorporated herein by reference to Exhibit 10.8 (g) of Coterra’s Annual Report on Form 10-K for the fiscal year ended December 31, 2020).

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*10.10			Cimarex Energy Co. Amended and Restated 2019 Equity Incentive Plan , Effective Ma y 12, 2021 (incorporated herein by reference to Exhibit 4.4 of Coterra ’s Registration Statement on Form S-8 (Reg. No. 333-260230) filed with the S EC on October 14 , 2021).
			(a) Form of Restricted Stock Unit Award Agreement (legacy Cimarex continuing officers) (incorporated herein by reference to Exhibit 10.2 of Coterra ’s Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 20 22);
			(b) Form of Restricted Stock Unit Award Agre ement (legacy Cimarex transitioning officers) (incorporated herein by reference to Exhibit 10.2 of Coterra ’s Quarterly Report on Form 10-Q f or the fiscal quarte r ended March 31, 2022);
			(c) Form of Performance Share Award Agreement (legacy Ci marex continuing officers) (incorporated herein by re ference to Exhibit 10.2 of Coterra ’s Quarterly Report on Form 10-Q for the fiscal quarter ended March 3 1 , 2022);
			(d) Form of Performanc e Share Award Agreement (incorporated herein by reference to Exhibit 10.2 of Coterra ’s Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2022).
*10.11			Form of Severance Compensation Agreement of certain executive officers of Cimarex Energy Co. (incorporated herein by reference to Exhibit 10.1 of Cimarex’s Current Report on Form 8-K filed with the SEC on March 13, 2020).
			(a) Form of Amendment to Severance Compensation Agreements of certain executive officers of Cimarex Energy Co. (incorporated herein by reference to Exhibit 10.11 of Coterra’s Quarterly Report on Form 10-Q for the fiscal quarter ended September 30, 2021).
*10.12			Nonemployee Director Deferred Compensation Plan effective December 21, 2012 (incorporated herein by reference to Exhibit 10.10 of Coterra’s Annual Report on Form 10-K for the fiscal year ended December 31, 2012).
10.13			Second Amended and Restated Credit Agreement dated as of April 22, 2019, among Cabot Oil & Gas Corporation, as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent and Joint Lead Arranger, Merrill Lynch, Pierce, Fenner & Smith, Incorporated, as Syndication Agent and Joint Lead Arranger, Bank of Montreal, The Bank of Nova Scotia, Houston Branch, Citibank N.A., Compass Bank, Toronto Dominion (New York) LLC, U.S. Bank National Association and Wells Fargo, N.A. as Co-Documentation Agent, and the Lenders party thereto (incorporated herein by reference to Exhibit 10.1 of Coterra’s Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2019).
10.14			First Amendment to Second Amended and Restated Credit Agreement, dated as of June 17, 2021, by and among Cabot Oil & Gas Corporation, the Lenders party thereto and JPMorgan Chase Bank, N.A., as Administrative Agent (incorporated herein by reference to Exhibit 10.1 of Coterra’s Current Report on Form 8-K filed with the SEC on June 17, 2021).
10.15			Second Amendment to Second Amended and Restated Credit Agreement, dated as of September 16, 2021, by and among Cabot Oil & Gas Corporation, the Lenders party thereto and JPMorgan Chase Bank, N.A., as Administrative Agent (incorporated herein by reference to Exhibit 10.1 of Coterra’s Current Report on Form 8-K filed with the SEC on September 17, 2021).
21.1			Subsidiaries of Coterra Energy Inc.
23.1			Consent of PricewaterhouseCoopers LLP.
23.2			Consent of DeGolyer and MacNaughton.
31.1			302 Certification—Chairman, Chief Executive Officer and President.
31.2			302 Certification—Executive Vice President and Chief Financial Officer.
32.1			906 Certification - Chief Executive Officer and Chief Financial Officer
99.1			DeGolyer and MacNaughton Report .
101.INS			Inline XBRL Instance Document. The instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
101.SCH			Inline XBRL Taxonomy Extension Schema Document.
101.CAL			Inline XBRL Taxonomy Extension Calculation Linkbase Document.
101.LAB			Inline XBRL Taxonomy Extension Label Linkbase Document.
101.PRE			Inline XBRL Taxonomy Extension Presentation Linkbase Document.
101.DEF			Inline XBRL Taxonomy Extension Definition Linkbase Document.
104			Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).

______________________________________________________________________________

*Compensatory plan, contract or arrangement.

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ITEM 16. FORM 10-K SUMMARY

Coterra has elected not to include summary information.

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SIGNATURES

Pursuant to the requirements of Section 13 and 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Houston, State of Texas, on the 27th of February 2023.


			COTERRA ENERGY INC.
			By:						/s/ THOMAS E. JORDEN
									Thomas E. Jorden Chairman, Chief Executive Officer and President

______________________________________________________________________________________________________________________________

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

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Signature

Title

Date

/s/ THOMAS E. JORDEN

Chairman, Chief Executive Officer and President (Principal Executive Officer)

February 27, 2023

Thomas E. Jorden

/s/ SCOTT C. SCHROEDER

Executive Vice President and Chief Financial Officer (Principal Financial Officer)

February 27, 2023

Scott C. Schroeder

/s/ TODD M. ROEMER

Vice President and Chief Accounting Officer (Principal Accounting Officer)

February 27, 2023

Todd M. Roemer

/s/ DOROTHY M. ABLES

Director

February 27, 2023

Dorothy M. Ables

/s/ ROBERT S. BOSWELL

Lead Director

February 27, 2023

Robert S. Boswell

/s/ AMANDA M. BROCK

Director

February 27, 2023

Amanda M. Brock

/s/ DAN O. DINGES

Director

February 27, 2023

Dan O. Dinges

/s/ PAUL N. ECKLEY

Director

February 27, 2023

Paul N. Eckley

/s/ HANS HELMERICH

Director

February 27, 2023

Hans Helmerich

/s/ LISA A. STEWART

Director

February 27, 2023

Lisa A. Stewart

/s/ FRANCES M. VALLEJO

Director

February 27, 2023

Frances M. Vallejo

/s/ MARCUS A. WATTS

Director

February 27, 2023

Marcus A. Watts

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