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.

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

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.

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	43	28.0	99	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

_______________________________________________________________________________

(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.

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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

________________________________________________________

(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

_______________________________________________________________________________

(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