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, 2021

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. ☒

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 $.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, 2021) was approximately $6.9 billion.

As of February 24, 2022, there were 813,757,948 shares of Common Stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Proxy Statement for the Annual Meeting of Stockholders to be held April 29, 2022 are incorporated by reference into Part III of this report.

Table of Contents

TABLE OF CONTENTS

		PAGE
PART I
ITEMS 1 and 2	Business and Properties	7
ITEM 1A	Risk Factors	28
ITEM 1B	Unresolved Staff Comments	44
ITEM 3	Legal Proceedings	44
ITEM 4	Mine Safety Disclosures	44
	Information About our Executive Officers	45
PART II
ITEM 5	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	46
ITEM 6	[Reserved]	48
ITEM 7	Management's Discussion and Analysis of Financial Condition and Results of Operations	48
ITEM 7A	Quantitative and Qualitative Disclosures about Market Risk	62
ITEM 8	Financial Statements and Supplementary Data	66
ITEM 9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	117
ITEM 9A	Controls and Procedures	117
ITEM 9B	Other Information	117
ITEM 9C	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	117
PART III
ITEM 10	Directors, Executive Officers and Corporate Governance	118
ITEM 11	Executive Compensation	118
ITEM 12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	118
ITEM 13	Certain Relationships and Related Transactions, and Director Independence	118
ITEM 14	Principal Accounting Fees and Services	118
PART IV
ITEM 15	Exhibits and Financial Statement Schedules	119
ITEM 16	Form 10-K Summary	123

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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 continuing effects of the coronavirus (“COVID-19”) pandemic and the impact thereof on our business, financial condition and results of operations and the economy as a whole, 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 the Organization of Petroleum Exporting Countries and other exporting nations, market factors, market prices (including geographic basis differentials) of oil and natural gas, results of future drilling and marketing activity, 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.

RISK FACTORS SUMMARY

The following is a summary of the principal risks that could adversely affect our business, financial condition, results of operations and/or cash flows:

Business and Operational Risks

•the effects of commodity price fluctuations and potential write-downs on our business as a result of commodity price declines;

•the drilling of oil and natural gas wells, as such activities are high-risk and may result in additional hazards and risks that could cause substantial financial losses;

•the effects of disruptions from unexpected events, including pandemics, health crises and natural disasters;

•our proved reserves estimates and any material inaccuracies which could cause our reserves to be overstated or understated;

•uncertainties in evaluating the expected benefits and potential liabilities of recoverable reserves;

•our ability to find or acquire additional oil and natural gas reserves that are economically recoverable, including development of our proved undeveloped reserves and associated capital expenditures;

•strategic determinations and our potential failure to appropriately allocate capital and resources among our strategic opportunities;

•our ability to sell our oil, natural gas and NGL production, including associated transportation and processing risks;

•the value of our properties after we acquire them due to uncertainties in evaluating recoverable reserves and other expected benefits as well as potential liabilities;

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•the integration of businesses and properties we have or may acquire;

•our limited control over the activities on properties we do not operate;

•wells that may have been partially depleted or drained by offset wells or may be adversely affected by actions other operators may take when drilling, completing or operating wells that they own;

•the potential loss of leases if production is not established within the time periods specified in the leases or if we do not maintain production in paying quantities;

•cyber-attacks targeting our systems, the oil and gas industry systems and infrastructure, or the systems of our third-party service providers;

Risks Related to our Indebtedness, Hedging Activities and Financial Position

•our substantial capital requirements, and our ability to obtain needed financing on satisfactory terms or at all;

•risks associated with our debt and the provisions of our debt agreements, as well as hedging arrangements that expose us to risk of financial loss and limit the potential benefit to us of increases in prices for oil and natural gas;

Legal, Regulatory and Governmental Risks

•ESG concerns or negative public perception regarding us and/or our industry, and federal and state legislation, judicial actions and regulatory initiatives related to oil and gas development and the use of hydraulic fracturing;

•our ability to acquire adequate supplies of water for our oil and gas production operations and the ability to dispose of or recycle the water we use economically and in an environmentally safe manner;

•the adoption of climate change legislation or regulations restricting emission of greenhouse gases, investor pressure concerning climate-related disclosures, and lawsuits;

•various climate-related risks, including various transitional, policy and legal, technological, market, reputational and physical risks;

•privacy and data protection laws, rules and directives relating to the processing of personal data;

•potential tax law changes;

Additional Risks Related to the Merger

•potential loss of customers, distributors, service providers, suppliers, vendors, joint venture participants and other business counterparties and the potential termination of existing contracts;

•the failure to realize all of the anticipated benefits of the Merger;

•the fluctuation of the market price of our common stock and its potential decline if large amounts of our common stock are sold following the Merger;

•potential limitations on our ability to utilize Cimarex’s historic net operating loss carryforwards and other tax attributes;

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;

•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 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;

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General Risk Factors

•the potential loss of key personnel and the potential failure to be insured against all of the operating risks to which we are exposed;

•the substantially greater financial and technological resources that many of our competitors have, which could adversely affect our competitive position; and

•uncertainty regarding the declaration, payment and amounts of future dividends distributed to our stockholders.

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.

DD&A. Depletion, depreciation and amortization.

ESG. Environmental, social and governance.

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

GHG. Greenhouse gases.

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

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

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

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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.

U.S.    United States.

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.

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.

On October 1, 2021, we completed a merger transaction (the “Merger”) with Cimarex Energy Co. (“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.

As a result of the Merger, we added substantial assets and operations in the Permian Basin in Texas and New Mexico and the Anadarko Basin in Oklahoma. As of December 31, 2021, the proved reserves attributable to the Cimarex legacy operations represented 25 percent of our total proved reserves on a BOE basis. The Merger has provided us with geographic, commodity and asset diversification, with exposure to oil, natural gas and NGLs, which we believe will provide us with greater resiliency to market fluctuations and other factors impacting any single commodity, region or basin. We believe we have a multi-decade inventory of high-return development locations in each of our premier oil and natural gas basins in the U.S., with our approximately 177,000 net acres in the Marcellus Shale, approximately 306,000 net acres in the Permian Basin and approximately 182,000 net acres in the Anadarko Basin. We believe the Merger will generate long-term value for our stockholders and positions us to be a premier exploration and production company with the size, scale, inventory and financial strength to deliver sustainable returns through various commodity price cycles.

As of the effective time of the Merger, our Board of Directors was reconstituted to consist of ten members, with five of the directors being persons who previously served on our Board of Directors and five persons who previously served on the Cimarex Board of Directors. Also as of the effective time of the Merger, we made changes to our executive management team, including appointing Mr. Dan O. Dinges (our former President and Chief Executive Officer) as our Executive Chairman of the Board of Directors and appointing Mr. Thomas E. Jorden (Cimarex’s former Chief Executive Officer and President) as our Chief Executive Officer and President.

Certain 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, our team members 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, disciplined capital investment and strong cash flow generation through the commodity price cycles give us the confidence 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 and again in February 2022 to $0.60 per share. Since October 1, 2021, we have returned $652 million to stockholders through base-plus-variable and special dividends. Furthermore and consistent with our returns-focused strategy, in February 2022, our Board of Directors also approved a new $1.25 billion share repurchase program that replaced our previously announced share repurchase program. Together with our base-plus-variable dividend, we remain committed to returning at least 50 percent of our free cash flow to our stockholders, supplementing any of these returns periodically with our share repurchase program, all while staying focused on the 30 percent of cash flow from operations threshold, in all but the lowest commodity environments.

Disciplined Capital Allocation Across Top-Tier Position. We believe that we hold the ability to generate sustainable returns across our asset portfolio, which offers scale, capital optionality and low break-even investment options. We anticipate our drilling inventory will be developed over multiple decades, at the current run-rate. We are committed to maintaining a

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disciplined capital investment strategy and using technology and innovation to maximize capital efficiency and operational execution. We believe that having three operating regions, the Marcellus Shale, Permian Basin and Anadarko Basin, offers diversity of geography and commodity and revenue streams, which should support strong and stable cash flow generation through commodity price cycles. In the fourth quarter of 2021, we invested 44 percent of our cash flow from operations in our drilling program and returned $0.80 per share to stockholders via dividend payments.

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 that our asset base, revenue diversity, low-cost structure and strong balance sheet provides us the flexibility we need to thrive across various commodity price environments. With no significant debt maturities until 2024, a year-end 2021 cash balance of $1.0 billion 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 both today and tomorrow. 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 responsibility and safety leadership. 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.

2022 OUTLOOK

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

DESCRIPTION OF PROPERTIES

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

Marcellus Shale

Our Marcellus Shale properties are principally located in Susquehanna County, Pennsylvania, where we currently hold approximately 177,000 net acres in the dry gas window in the Marcellus Shale. Our 2021 net production in the Marcellus was 389 MBOEPD, representing 85 percent of our total equivalent production for the year. As of December 31, 2021, we had a total of 954.0 net wells in the Marcellus Shale, of which approximately 99 percent are operated by us.

During 2021, we invested $594 million in the Marcellus where we exited 2021 with two drilling rigs operating in the play and plan to exit 2022 with two rigs operating.

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 306,000 net acres in the play. Our development activities are primarily focused on the Wolfcamp Shale in Culberson and Reeves Counties in Texas and Lea and Eddy Counties in New Mexico. Our 2021 net production in the Permian Basin, which represents the production from this basin subsequent to the completion of the Merger on October 1, 2021, was 211 MBOEPD, representing 12 percent of our total equivalent production for the year. As of December 31, 2021, we had a total of 1,164.4 net wells in the Permian Basin, of which approximately 79 percent are operated by us.

During 2021, we invested $147 million in the Permian Basin, which represents the amount invested in the basin subsequent to the completion of the Merger. We exited 2021 with six drilling rigs operating in the play and plan to exit 2022 with six rigs operating.

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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 2021 net production in the Anadarko Basin, which represents the production from this basin subsequent to the completion of the Merger on October 1, 2021, was 59 MBOEPD, representing three percent of our total equivalent production for the year. As of December 31, 2021, we had a total of 568.0 net wells in the Anadarko Basin, of which approximately 57 percent are operated by us.

During 2021, we invested $2 million in the Anadarko Basin, which represents the amount invested in the basin subsequent to the completion of the Merger. At the end of 2021, we had no rigs operating in the play but in the first half of 2022, subject to market conditions, we plan to have up to two rigs in the play.

Other Properties

Ancillary to our exploration, development and production operations, we operate a number of natural gas and saltwater disposal gathering 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 the wellhead directly to interstate pipelines, natural gas processing facilities and produced water 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 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, 2021 are set forth in the table below:

	Natural Gas (in Bcf)
2022	652
2023	644
2024	601
2025	577
2026	572

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.

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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, roll differential swaps 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 2021, oil collars with floor prices ranging from $29.00 to $40.00 per Bbl and ceiling prices ranging from $34.15 to $51.10 per Bbl covered 3.7 Mmbbls, or 45 percent, of oil production at a weighted-average price of $44.37 per Bbl. Oil basis swaps covered 3.2 Mmbbls, or 40 percent, of oil production at a weighted-average price of $(0.08) per Bbl. Oil roll differential swaps covered 1.6 Mmbbls, or 20 percent, of oil production at a weighted-average price of $(0.10) per Bbl.

During 2021, natural gas collars with floor prices ranging from $1.50 to $2.85 per Mmbtu and ceiling prices ranging from $1.75 to $3.94 per Mmbtu covered 193.2 Bcf, or 21 percent, of natural gas production at a weighted-average price of $2.85 per Mmbtu. Natural gas swaps covered 56.3 Bcf, or six percent, of natural gas production at a weighted-average price of $3.16 per Mmbtu.

As of December 31, 2021, we had the following outstanding financial commodity derivatives:

			Collars							Swaps
			Floor				Ceiling			Basis Swaps		Roll Swaps
Type of Contract	Volume (Mbbl)	Contract Period	Range ($/Bbl)		Weighted- Average ($/Bbl)		Range ($/Bbl)	Weighted- Average ($/Bbl)		Weighted- Average ($/Bbl)		Weighted- Average ($/Bbl)
Crude oil (WTI)	630	Jan. 2022-Mar. 2022	$	—	$	35.00	$45.15-$45.40	$	45.28
Crude oil (WTI)	1,629	Jan. 2022-Jun. 2022	$35.00-$37.50		$	36.11	$48.38-$51.10	$	49.97
Crude oil (WTI)	2,730	Jan. 2022-Sep. 2022	$	—	$	40.00	$47.55-$50.89	$	49.19
Crude oil (WTI)	2,920	Jan. 2022-Dec. 2022	$	—	$	57.00	$72.20-$72.80	$	72.43
Crude oil (WTI Midland)(1)	630	Jan. 2022-Mar. 2022								$	0.11
Crude oil (WTI Midland)(1)	1,448	Jan. 2022-Jun. 2022								$	0.25
Crude oil (WTI Midland)(1)	1,911	Jan. 2022-Sep. 2022								$	0.38
Crude oil (WTI Midland)(1)	2,920	Jan. 2022-Dec. 2022								$	0.05
Crude oil (WTI)	630	Jan. 2022-Mar. 2022										$	(0.24)
Crude oil (WTI)	724	Jan. 2022-Jun. 2022										$	(0.20)
Crude oil (WTI)	1,911	Jan. 2022-Sep. 2022										$	0.10

________________________________________________________

(1)The index price the Company pays under these basis swaps is WTI Midland, as quoted by Argus Americas Crude.

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			Collars
			Floor				Ceiling
Type of Contract	Volume (Mmbtu)	Contract Period	Range ($/Mmbtu)		Weighted- Average ($/Mmbtu)		Range ($/Mmbtu)		Weighted- Average ($/Mmbtu)
Natural gas (NYMEX)	36,000,000	Jan. 2022-Mar. 2022	$4.00 - $4.75		$	4.38	$5.00 - $10.32		$	6.97
Natural gas (NYMEX)	42,800,000	Apr. 2022 - Oct. 2022	$3.00 - $3.50		$	3.19	$4.07 - $4.83		$	4.30
Natural gas (Perm EP)(1)	1,800,000	Jan. 2022-Mar. 2022	$1.80 - $1.90		$	1.85	$2.18 - $2.19		$	2.18
Natural gas (Perm EP)(1)	3,620,000	Jan. 2022-Jun. 2022	$	—	$	2.40	$2.85 - $2.90		$	2.88
Natural gas (Perm EP)(1)	7,300,000	Jan. 2022-Dec. 2022	$	—	$	2.50	$	—	$	3.15
Natural gas (PEPL)(2)	3,600,000	Jan. 2022-Mar. 2022	$1.90 - $2.10		$	2.00	$2.35 - $2.44		$	2.40
Natural gas (PEPL)(2)	3,620,000	Jan. 2022-Jun. 2022	$	—	$	2.40	$2.81 - $2.91		$	2.86
Natural gas (PEPL)(2)	7,300,000	Jan. 2022-Dec. 2022	$	—	$	2.60	$	—	$	3.27
Natural gas (Waha)(3)	3,600,000	Jan. 2022-Mar. 2022	$1.70 - $1.84		$	1.77	$2.10 - $2.20		$	2.15
Natural gas (Waha)(3)	3,620,000	Jan. 2022-Jun. 2022	$	—	$	2.40	$2.82 - $2.89		$	2.86
Natural gas (Waha)(3)	2,730,000	Jan. 2022-Sep. 2022	$	—	$	2.40	$	—	$	2.77
Natural gas (Waha)(3)	7,300,000	Jan. 2022-Dec. 2022	$	—	$	2.50	$	—	$	3.12

________________________________________________________

(1)The index price for these collars is El Paso Natural Gas Company, Permian Basin Index (“Perm EP”), as quoted in Platt’s Inside FERC.

(2)The index price for these collars is Panhandle Eastern Pipe Line, Tex/OK Mid-Continent Index (“PEPL”), as quoted in Platt’s Inside FERC.

(3)The index price for these collars is Waha West Texas Natural Gas Index (“Waha”), as quoted in Platt’s Inside FERC.

In early 2022, we entered into the following outstanding financial commodity derivatives:

			Collars
			Floor				Ceiling
Type of Contract	Volume (Mmbtu)	Contract Period	Range ($/Mmbtu)		Weighted- Average ($/Mmbtu)		Range ($/Mmbtu)	Weighted- Average ($/Mmbtu)
Natural gas (NYMEX)	71,500,000	Apr. 2022-Dec. 2022	$3.50 - $4.25		$	3.84	$4.75 - $6.65	$	5.39
Natural gas (NYMEX)	10,700,000	Apr. 2022-Oct. 2022	$	—	$	4.00	$5.60 - $5.69	$	5.63
Natural gas (NYMEX)	7,550,000	Nov. 2022-Mar. 2023	$	—	$	4.00	$7.06 - $7.10	$	7.08

A significant portion of our expected oil and natural gas production for 2022 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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RESERVES

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

	December 31,
	2021	2020	2019
Oil (Mbbl)
Proved developed reserves	153,010	—	—
Proved undeveloped reserves(1)	36,419	—	—
	189,429	—	—
Natural Gas (Bcf)
Proved developed reserves	10,691	8,608	8,056
Proved undeveloped reserves(1)	4,204	5,064	4,847
	14,895	13,672	12,903
NGLs (Mbbl)
Proved developed reserves	193,598	—	—
Proved undeveloped reserves(1)	27,017	—	—
	220,615	—	—
Oil equivalent (MBOE)	2,892,582	2,278,636	2,150,422

______________________________________________________________________________

(1)Proved undeveloped reserves for 2021, 2020 and 2019 include reserves drilled but uncompleted of 80 MMBOE, 40 MMBOE and 131 MMBOE, respectively.

Our proved reserves at December 31, 2021 increased 614 MMBOE, or 27 percent, from 2,279 MMBOE at December 31, 2020, primarily due to the Merger, which increased our proved reserves by 672 MMBOE. During 2021, we added 171 MMBOE of proved reserves through extensions, discoveries and other additions, primarily due to the results from our drilling and completion program in the Dimock field in northeast Pennsylvania. We had a net downward revision of 62 MMBOE, which was primarily due to a net downward performance revision of 97 MMBOE, partially offset by an upward pricing revision of 34 MMBOE. During 2021, we produced 167 MMBOE.

At December 31, 2021, our Dimock field, which is located in the Marcellus Shale in Susquehanna County, Pennsylvania, contained approximately 75 percent of our total proved reserves.

Our reserves are sensitive to commodity prices and their effect on the economic productive life of producing properties. Our reserves are based 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 during the year. Increases in commodity prices may result in a longer economic productive life of a property or result in more economically viable proved undeveloped reserves to be recognized. Decreases in prices may result in negative impacts of this nature.

For additional information regarding estimates of proved reserves, the audits of such estimates by Miller and Lents, Ltd. (“Miller and Lents”) and DeGolyer and MacNaughton and other information about our reserves, including the risks inherent in our estimates of proved reserves, refer to the Supplemental Oil and Gas Information to the Consolidated Financial Statements included in Item 8 and “Risk Factors—Business and Operational Risks—Our proved reserves are estimates. Any material inaccuracies in our reserve estimates or underlying assumptions could cause the quantities and net present value of our reserves to be overstated or understated” in Item 1A.

Technologies Used In Reserves Estimates

We utilize various traditional methods to estimate our reserves, including decline curve extrapolations, material balance calculations, volumetric calculations, analogies and in some cases a combination of these methods. In addition, at times we may use seismic interpretations to confirm continuity of a formation in combination with traditional technologies; however, seismic interpretations are not used in the volumetric computation.

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Internal Control

Our Senior Vice President, Production and Operations is the technical person responsible for our internal reserves estimation process and provides oversight of our corporate reservoir engineering department, which consists of 10 engineers. He has a Bachelor of Science degree in Chemical Engineering, specializing in petroleum engineering, and over 39 years of industry experience with positions of increasing responsibility in operations, engineering and evaluations. He has worked in the area of reserves and reservoir engineering for 30 years and is a member of the Society of Petroleum Engineers.

Our reserves estimation process is coordinated by our corporate reservoir engineering department. Reserve information, including models and other technical data, are stored on secured databases on our network. Certain non-technical inputs used in the reserves estimation process, including commodity prices, production and development costs and ownership percentages, are obtained by other departments and are subject to testing as part of our annual internal control process. We also engage Miller and Lents and DeGolyer and MacNaughton, independent petroleum engineers, to perform independent audits of our estimated proved reserves. Upon completion of the process, the estimated reserves are presented to senior management and the Board of Directors.

Miller and Lents has audited 100 percent of our proved reserves estimates related to our Marcellus Shale properties, and DeGolyer and MacNaughton has performed an independent evaluation of estimated net reserves representing greater than 80 percent of the total future net revenue discounted at 10 percent attributable to our proved reserves estimates related to our Permian Basin, Anadarko Basin and other properties (excluding our Marcellus Shale properties). Each of Miller and Lents and DeGolyer and MacNaughton concluded, in its judgment, we have an effective system for gathering data and documenting information required to estimate our proved reserves and project our future revenues.

Copies of the audit letters by Miller and Lents dated January 31, 2022 and DeGolyer and MacNaughton dated January 17, 2022 have been filed as exhibits to this Annual Report on Form 10-K.

Qualifications of Third Party Engineers

The technical person primarily responsible for the audit of our reserves estimates at Miller and Lents meets the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Miller and Lents is an independent firm of petroleum engineers, geologists, geophysicists and petro physicists; they do not own an interest in our properties and are not retained on a contingent fee basis.

The technical person primarily responsible for the audit of our reserves estimates at DeGolyer and MacNaughton meets the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. DeGolyer and MacNaughton is an independent firm of petroleum engineers, geologists, geophysicists and petro physicists; they do not own an interest in our properties and are not retained on a contingent fee basis.

Proved Undeveloped Reserves

At December 31, 2021, we had future development costs of $2.1 billion associated with 764 MMBOE of PUD reserves, which represents a decrease of 80 MMBOE compared to December 31, 2020. By the end of 2022, we expect to complete substantially all the work necessary to convert our PUD reserves associated with wells that were drilled but uncompleted at December 31, 2021 to proved developed reserves. Future development plans are reflective of the current commodity price environment and have been established based on expected available cash flows from operations. As of December 31, 2021, all PUD reserves are expected to be drilled and completed within five years of initial disclosure of these reserves.

The following table is a reconciliation of the change in our PUD reserves (MMBOE):

	Year Ended December 31, 2021
Balance at beginning of period	844
Transfers to proved developed	(264)
Additions	131
Purchases of reserves in place	97
Revision of prior estimates	(44)
Balance at end of period	764

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Changes in PUD reserves that occurred during the year were due to:

•transfer of 264 MMBOE from PUD to proved developed reserves based on total capital expenditures of $565 million during 2021;

•new PUD reserve additions of 131 MMBOE in the Dimock field in northeast Pennsylvania;

•purchases of reserves in place of 97 MMBOE, which are primarily related to the Merger and are primarily located in the Permian Basin; and

•downward PUD reserve revisions of 44 MMBOE mainly due to performance revisions in the Marcellus Shale.

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,
	2021(1)		2020		2019
Production Volumes
Oil (Mbbl)	8,150		—		—
Natural gas (Bcf)	911		858		865
NGL (Mbbl)	7,104		—		—
Equivalents (MBOE)	167,113		142,954		144,167
Average Daily Production Volumes
Oil (Mbbl)	89		—		—
Natural gas (Mmcf)	2,966		2,344		2,371
NGL (Mbbl)	77		—		—
Equivalents (MBOE)	660		391		395
Average Sales Price
Excluding Derivative Settlements
Oil ($/Bbl)	$	75.61	$	—	$	—
Natural gas ($/Mcf)	$	3.07	$	1.64	$	2.29
NGL ($/Bbl)	$	34.18	$	—	$	—
Including Derivative Settlements
Oil ($/Bbl)	$	60.35	$	—	$	—
Natural gas ($/Mcf)	$	2.73	$	1.68	$	2.45
NGL ($/Bbl)	$	34.18	$	—	$	—
Average Production Costs ($/BOE)	$	0.77	$	0.36	$	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 and not Cimarex production for the entire year.

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The following table presents historical information about our total and average daily natural gas production volumes associated with our interests in the Dimock field, 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,
	2021	2020	2019
Production Volumes
Natural gas (Bcf)	853	858	865
Equivalents (MBOE)	142,223	142,954	144,167
Average Daily Production Volumes
Natural gas (Mmcf)	2,338	2,344	2,371
Equivalents (MBOE)	390	391	395

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

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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, 2021:

	Acreage
	Developed		Undeveloped		Total
	Gross	Net	Gross	Net	Gross	Net
Marcellus Shale
Pennsylvania	161,808	161,333	16,093	16,015	177,901	177,348
	161,808	161,333	16,093	16,015	177,901	177,348
Permian Basin
New Mexico	144,942	104,470	65,533	46,099	210,475	150,569
Texas	196,848	130,070	31,697	25,562	228,545	155,632
	341,790	234,540	97,230	71,661	439,020	306,201
Anadarko Basin
Oklahoma	305,621	140,347	87,100	41,993	392,721	182,340
	305,621	140,347	87,100	41,993	392,721	182,340
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	3,832	1,363	25,743	19,057	29,575	20,420
Kentucky	122	92	53,237	47,303	53,359	47,395
Montana	7,397	1,606	25,020	7,307	32,417	8,913
Nevada	440	1	1,007,167	1,007,167	1,007,607	1,007,168
New Mexico	10,438	2,145	1,640,713	1,634,974	1,651,151	1,637,119
Offshore Gulf of Mexico	18,853	7,005	15,000	9,000	33,853	16,005
Pennsylvania	—	—	113,530	63,849	113,530	63,849
Texas	45,092	12,361	22,521	17,009	67,613	29,370
Utah	4,280	955	61,843	57,664	66,123	58,619
West Virginia	—	—	611,798	579,929	611,798	579,929
Wyoming	22,071	2,345	79,522	23,751	101,593	26,096
Other	5,430	867	65,511	35,005	70,941	35,872
	135,162	45,947	6,202,933	5,983,343	6,338,095	6,029,290
	944,381	582,167	6,403,356	6,113,012	7,347,737	6,695,179

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
	2022				2023				2024
	Gross		Net		Gross		Net		Gross		Net
Marcellus Shale	2,701		2,701		3,020		2,933		2,048		1,888
Permian Basin	938		938		960		960		3		3
Anadarko Basin	—		—		4,097		934		700		134
Other	35,418		32,412		7,725		6,697		1,302		1,241
	39,057		36,051		15,802		11,524		4,053		3,266
Percentage of total undeveloped acreage	1	%	1	%	—	%	—	%	—	%	—	%

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At December 31, 2021, we had no proved undeveloped 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, 2021. This summary includes crude oil and natural gas wells in which we have a working interest:

	Gross	Net
Natural Gas	3,401	1,797.0
Oil	4,960	893.4
Total(1)	8,361	2,690.4

_______________________________________________________________________________

(1)Total percentage of gross operated wells is 32 percent.

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,
	2021		2020		2019
	Gross	Net	Gross	Net	Gross	Net
Development Wells
Productive	114	99.9	74	64.3	96	94.0
Dry	—	—	—	—	—	—
Total	114	99.9	74	64.3	96	94.0
Acquired Wells	7,266	1,715.3	—	—	—	—

During the year ended December 31, 2021, we completed 14 gross wells (13.0 net) that were drilled in prior years.

The following table sets forth information about wells for which drilling was in progress or which were drilled but uncompleted at December 31, 2021, which are not included in the above table:

	Drilling In Progress		Drilled But Uncompleted
	Gross	Net	Gross	Net
Development wells	23	14.7	66	39.7

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

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natural gas production to 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. 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 over other producers who do not have similar systems or services in place.

Major Customers

During the year ended December 31, 2021, no customer accounted for more than 10 percent of our total sales. During the year ended December 31, 2020, three customers accounted for approximately 21 percent, 16 percent and 12 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 ample 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 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

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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.

Federal Regulation of Swap Transactions

We use derivative financial instruments such as collar, swap, roll differential 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. Following enactment of the Dodd‑Frank Wall Street Reform and Consumer Protection Act (“Dodd‑Frank Act”) in July 2010, the Commodity Futures Trading Commission (the “CFTC”) has promulgated regulations to implement statutory requirements for swap transactions, including certain options. The CFTC regulations are intended to implement a regulated market in which most swaps are executed on registered exchanges or swap execution facilities and cleared through central counterparties. In addition, all swap market participants are subject to new reporting and recordkeeping requirements related to their swap transactions. 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, changes to the swap market as a result of Dodd‑Frank implementation could significantly increase the cost of entering into new swaps or maintaining existing swaps, materially alter the terms of new or existing swap transactions and/or reduce the availability of new or existing swaps. If we reduce our use of swaps as a result of the Dodd‑Frank Act and regulations, 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, although the annual adjustments may result in decreased rates in a given year. Every five years, the FERC must examine the relationship between the annual change in the applicable index and the

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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 federal, state and local laws and regulations relating to the protection of the environment, public health, natural resources and wildlife, and relating to safety matters. 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 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.

U.S. laws and regulations applicable to our operations include those regulating emissions into the atmosphere, discharges of pollutants into waters, underground injection of wastewater, the generation, storage, transportation and disposal of waste materials and removal and cleanup of materials that may harm the environment, and those relating to occupational health and safety.

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 U.S. federal 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 U.S. 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

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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 federal 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 Oil Pollution Act and related federal regulations to the extent applicable to our operations.

Endangered Species Act. The U.S. federal 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 U.S. federal Migratory Bird Treaty Act. 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.

On April 10, 2014, the FWS published a rule listing, as a threatened species under the ESA, the lesser prairie chicken, whose habitat is over a five-state region, including Texas, New Mexico and Oklahoma, where we conduct a substantial amount of our operations. Although the 2014 listing rule was vacated in July 2016, 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. 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 Peppered Chub is a freshwater fish that historically was found in the South Canadian, Cimarron and Arkansas rivers within New Mexico, Texas,

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Oklahoma and Kansas. We have operations near the South Canadian river in Oklahoma that could be impacted if the Peppered Chub is listed as endangered under the ESA or if the FWS declares the basins of the South Canadian river to be critical habitat. 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 U.S. 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 wastewaters 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 U.S. 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 could add costs and cause delays in operations.

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. For additional information, please read “Risk Factors—Legal, Regulatory and Governmental Risks— Federal and state legislation, 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 U.S. 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 emplacement of fluids (including disposal wells or enhanced oil recovery) is governed by U.S. federal or state regulatory authorities that, in

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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. This technology involves the injection of fluids, usually consisting mostly of water but 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. 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. For example, New York issued a statewide ban on hydraulic fracturing in June 2015. 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.

Water is an essential component of oil and natural gas production during the drilling process, and, 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 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, including as a result of potential regulatory and legislative changes due to the outcome of the 2020 U.S. congressional and presidential elections 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 flowback and produced water from well sites as a preferred alternative to disposal.

The adoption of U.S. federal, state or local laws or the implementation of regulations affecting our ability to conduct hydraulic fracturing could potentially cause a decrease in the completion of new oil and natural gas wells and increased compliance costs, which could increase costs of our operations and cause considerable delays in acquiring regulatory approvals to drill and complete wells. In addition, if existing laws and regulations with regard to hydraulic fracturing are revised or reinterpreted or if new laws and regulations become applicable to our operations through judicial or administrative actions, our business, financial condition, results of operations and cash flows could be adversely affected. For example, a Pennsylvania state appellate court in 2018 appeared to refuse to apply the established common law rule of capture in a case concerning claims of trespass by hydraulic fracturing. The Pennsylvania Supreme Court heard the appeal of this ruling and on January 22, 2020, in Briggs v. Southwestern Energy Production Co., 224 A.3d 334 (“Pa. 2020”), affirmed the rule of capture and remanded the case

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to the Pennsylvania state appellate court for further proceedings. On December 8, 2020, the appellate court issued a non-precedential decision reversing its previous order vacating the trial court’s summary judgment in favor of Southwestern Energy Production Co. (Southwestern). The appellate court refuted the assumptions made by the Pennsylvania Supreme Court concerning the appellate court’s disregard of the established rule of capture and based its reversal on the failure of plaintiffs to “specifically allege that Southwestern engaged in horizontal drilling that extended onto their property, or that Southwestern propelled fracturing fluids and proppants across the property line,” leaving open the possibility that hydraulic fracturing can constitute a physical invasion, and thereby a trespass. Future developments in case law that expand the ability of adjacent property owners to prevail on trespass claims based on hydraulic fracturing could have a material impact on our operations.

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. 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. 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, the California 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 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.

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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

We believe that 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 an integration plan for every corporate functional organization and are in the process of completing staff reorganizations, relocations of key employees and hiring of new talent for our corporate headquarters in Houston, Texas. Staff reductions will occur primarily in our Denver, Colorado office (which will eventually be closed) and our Tulsa, Oklahoma office, which will be dedicated to management of our Anadarko Basin operations, with other corporate functions transferred to Houston. Detailed transition and knowledge transfer plans are intended to ensure that key aspects of ongoing operations are uninterrupted through this process. Our staff reorganization plans are intended to eliminate redundancy between the legacy company organizations, and our hiring plans aim to accelerate 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, 2021, with the addition of employees as a result of the Merger, we had 936 total employees, 165 of whom were located in our headquarters in Houston, Texas and our corporate office in Denver, Colorado and 417 of whom were located in our regional offices in Midland, Texas, Tulsa Oklahoma and Pittsburgh, Pennsylvania. We had a total of 354 employees in production field locations across our regional offices. Of our total employee population, 611 were salaried and 325 were hourly. We also have 211 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, 15 were salaried and 196 were hourly. As a result of consistent communication and transparent management, 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 human capital resources, we seek to:

•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;

•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 low voluntary turnover rates, which averaged less than five percent over the five-year period ended December 31, 2021.

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 in an effort to ensure 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 expand the role or

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promote current 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 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 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 that 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 comprehensive environmental, health and safety (“EHS”) management system establishes a corporate governance framework for EHS compliance and performance and covers all elements of our operating lifecycle.

Our EHS management system provided the framework to implement immediate and 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 continued throughout 2020 and 2021. The actions taken to prevent the spread of infection on our worksites and promote the health and safety of our workforce include:

•implementing and providing training on a COVID-19 Safety Policy containing personal safety protocols, such as face coverings, social distancing requirements and personal hygiene measures;

•providing additional personal protective equipment;

•implementing rigorous COVID-19 self-assessment, contact tracing and quarantining protocols;

•increasing cleaning protocols at all locations;

•limiting business travel;

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•providing additional paid leave to employees with actual or presumed COVID-19 cases; and

•encouraging our employees to obtain COVID-19 vaccinations and providing incentives to do so.

Due to these measures, all of our operations continued safely and uninterrupted through the onset of the pandemic in 2020 and throughout 2021. We also implemented appreciation award programs for many of our employees who have continued to work onsite during the pandemic.

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 is not a part of, and is not incorporated into, this report or any other report we may file with or furnish to the SEC, whether before or after the date of this report 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, Corporate Bylaws, Audit Committee Charter, Compensation Committee Charter, Governance and Social Responsibility Committee Charter, Code of Business Conduct and Environment, Health & Safety Committee Charter are available on our website at www.coterra.com, under the “Corporate Governance” section of “Investors.” 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 or debt securities.

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. Historically, commodity prices have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile. For example, the WTI oil prices in 2021 ranged from a high of $84.65 to a low of $47.62 per Bbl and NYMEX natural gas prices in 2021 ranged from a high of $23.86 (during Winter Storm Uri) to a low of $2.43 per Mmbtu. 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. Furthermore, substantial, extended decreases in commodity prices may cause us to delay or postpone a significant portion of our exploration and development projects or 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.”

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. These factors include but are not limited to the following:

•the levels and location of oil, natural gas and NGLs supply and demand and expectations regarding supply and demand, including the potential long-term impact of an abundance of natural gas from shale (such as that produced from our Marcellus Shale properties) on the global natural gas supply;

•the level of consumer demand for oil, natural gas and NGLs, which has been significantly impacted by the COVID-19 pandemic, particularly during 2020;

•weather conditions and seasonal trends;

•political, economic or health conditions in oil, natural gas and NGL producing regions, including the Middle East, Africa, South America and the U.S., including for example, the impacts of local or international pandemics and disasters or events such as the global COVID-19 pandemic;

•the ability and willingness of the members of OPEC+ to agree to and maintain oil price and production controls;

•the price level and quantities of foreign imports;

•actions of governmental authorities;

•the availability, proximity and capacity of gathering, transportation, processing and/or refining facilities in regional or local areas;

•inventory storage levels and the cost and availability of storage and transportation of oil, natural gas and NGLs;

•the nature and extent of domestic and foreign governmental regulations and taxation, including environmental and climate change regulation;

•the price, availability and acceptance of alternative fuels;

•technological advances affecting energy consumption;

•speculation by investors in oil, natural gas and NGLs;

•variations between product prices at sales points and applicable index prices; and

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•overall economic conditions, including the value of the U.S. dollar relative to other major currencies.

These factors and the volatile nature of the energy markets make it impossible to predict future commodity prices. 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.

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, including:

•decreases in commodity prices;

•unexpected drilling conditions, pressure or irregularities in formations;

•equipment failures or accidents, including blowouts, explosions and fires;

•adverse weather conditions;

•surface access restrictions;

•loss of title or other title related issues;

•lack of available gathering or processing facilities or delays in the construction thereof;

•compliance with, or changes in, governmental requirements and regulation, including with respect to wastewater disposal, discharge of greenhouse gases and fracturing;

•unusual or unexpected geological formations or pressure or irregularities in formations; and

•costs of shortages or delays in the availability of drilling rigs or crews and the delivery of equipment and materials.

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 overall drilling success rate or our drilling success rate within a particular geographic area may decline. We may be unable to lease or drill identified or budgeted prospects within our expected time frame, or at all. We may be unable to lease or drill a particular prospect because, in some cases, we identify a prospect or drilling location before seeking an option or lease rights in the prospect or location. Similarly, our drilling schedule may vary from our capital budget. The final determination with respect to the drilling of any scheduled or budgeted wells will depend on a number of factors, including:

•the results of exploration efforts and the acquisition, review and analysis of seismic data;

•the availability of sufficient capital resources to us and the other participants for the drilling of the prospects;

•the approval of the prospects by other participants after additional data has been compiled;

•economic and industry conditions at the time of drilling, including prevailing and anticipated prices for oil and natural gas and the availability of drilling rigs and crews;

•our financial resources and results; and

•the availability of leases and permits on reasonable terms for the prospects and any delays in obtaining such permits.

These projects may not be successfully developed and the wells, if drilled, may not encounter reservoirs of commercially productive oil or natural gas.

Business disruptions from unexpected events, including pandemics, health crises and natural disasters, may disrupt our operations and adversely affect our business, financial condition and results of operations.

The occurrence of one or more unexpected events, including a public health crisis, pandemic and epidemic, war or civil unrest, a terrorist act, a cybersecurity incident resulting in unauthorized access to sensitive information or causing data or

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systems to be unusable, a weather event, an earthquake or other catastrophe could cause instability in world financial markets and lead to increased volatility in prices for oil and natural gas, all of which could adversely affect our business, financial condition and results of operations. For example, the ongoing COVID-19 outbreak has resulted in widespread adverse impacts on the global economy. There is considerable uncertainty regarding the extent to which COVID-19 will continue to spread, including new strains of COVID-19 such as the Delta and Omicron variants, the global availability and efficacy of treatments and vaccines and boosters and the acceptance of such treatments and vaccines by a significant portion of the population, and the extent and duration of governmental and other measures implemented to try to slow the spread of the virus, such as quarantines, shelter-in-place orders and business and government shutdowns (whether through a continuation of existing measures or the re-imposition of prior measures). The worldwide vaccine rollouts in 2021 have allowed governments to ease COVID-19 restrictions and lockdown protocols; however, the recent increase in COVID-19 cases resulting from the Delta and Omicron variants has created questions about whether lockdown protocols must be adjusted and the ultimate impact of those variants is unknown. We have implemented preventative measures and developed response plans intended to minimize unnecessary risk of exposure to infection among our employees at our work sites, and we continue to assess and plan for various operational contingencies related to COVID-19. However, if a significant portion of our employees or contractors or the employees or contractors of the operators of pipelines, processing and other facilities we utilize or of our vendors or suppliers were unable to work due to illness or if our field operations were suspended or temporarily restricted due to control measures designed to contain the outbreak, that could adversely affect our business, financial condition and results of operations, and we cannot guarantee that any precautionary actions taken by us will be effective in preventing disruptions to our business. In the event of any significant resurgence in COVID-19 transmission and infection in the areas in which we operate, our non-operational employees may return to working remotely, which could increase the risk of security breaches or other cyber-incidents or attacks, loss of data, fraud and other disruptions as a consequence of more employees accessing sensitive and critical information from remote locations via network infrastructure and internet services not arranged, established or secured by us.

Additionally, vaccination and testing requirements related to COVID-19 could impact our business in the future. In September 2021, the OSHA was directed to implement an emergency temporary standard requiring employers with 100 or more employees to ensure their workforce is fully vaccinated or to require unvaccinated workers to produce a negative COVID-19 test result on at least a weekly basis. Although the U.S. Supreme Court recently blocked the implementation of the standard, the future implementation of similar mandatory vaccination and testing requirements could have a material adverse effect on our business, financial condition or results of operations in the event that, among other things, a significant portion of our workforce does not choose to become vaccinated, the costs related to mandatory testing for unvaccinated employees are significant or the time away from work for testing is disruptive to our operations.

Furthermore, the COVID-19 pandemic caused a significant reduction in demand for crude oil, and to a lesser extent, natural gas and NGLs during much of 2020. The supply/demand imbalance driven by the COVID-19 pandemic and production disagreements in March 2020 among members of OPEC+ led to a significant global economic contraction generally in 2020 and continued to have disruptive impacts on our industry in 2021. Although an agreement to cut production was subsequently announced by OPEC+, the situation, coupled with the impact of COVID-19 and storage and transportation capacity constraints, resulted in a significant downturn in the oil and gas industry. We cannot predict the full impact that COVID-19 and its variants or the significant disruption and volatility currently being experienced in the oil and natural gas markets will have on our business, financial condition and results of operations at this time due to numerous uncertainties. For example, the operations of our midstream service providers, on whom we rely for the transmission, gathering and processing of a significant portion of our produced oil, natural gas and NGLs, may be disrupted or suspended in response to containing outbreaks, and/or the economic challenges may lead to a reduction in capacity or closing of the facilities and infrastructure of our midstream service providers, which may result in substantial discounts in the prices we receive for our produced oil, natural gas or NGLs or result in the shut-in of producing wells or the delay or discontinuance of development plans for our properties. Although we have not received notices from our customers or counterparties regarding non-performance issues or delays resulting from the COVID-19 pandemic, to the extent we or any of our material suppliers or customers are unable to operate due to government restrictions or otherwise, we may have to temporarily shut down or reduce production, which could result in significant downtime and have significant adverse consequences for our business, financial condition and results of operations.

In addition, the COVID-19 pandemic has impacted supply chains, delaying deliveries of supplies and equipment and increasing costs. Our costs for services, labor and supplies increased during 2021 due to increased demand for those items and supply chain disruptions related to the COVID-19 pandemic. The ultimate impacts of the COVID-19 pandemic will depend on future developments, including, among others, the ultimate severity of the virus, any resurgence in COVID-19 transmission and infection in affected regions after they have begun to experience improvements, the consequences of governmental and other measures, the efficacy of treatments and vaccines and boosters and the success of vaccination programs, the duration of the outbreak, further actions taken by members of OPEC+, actions taken by governmental authorities, customers, suppliers and other third parties, workforce availability and the timing and extent to which normal economic and operating conditions resume.

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

Reserve 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 reserve 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 of funds. Furthermore, different reserve engineers may make different estimates of reserves and cash flows based on the same data.

Results of drilling, testing and production subsequent to the date of an estimate may justify revising the original estimate. Accordingly, initial reserve 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. 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.

In general, the production rate of oil and gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Unless we successfully replace the reserves that we produce, our reserves will decline, 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. Low commodity prices may further limit the kinds of reserves that we can develop and produce economically.

We estimate that production from our proved developed reserves as of December 31, 2021 will decrease at a rate of 24 percent, 17 percent and 13 percent during 2023, 2024 and 2025, respectively (although production from our proved developed reserves is expected to increase during 2022 due to the effects of the Merger, partially offset by natural decline rates). Future development of proved undeveloped and other reserves that we have not currently classified as proved developed producing will impact these rates of decline.

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Exploration, development and exploitation activities involve numerous risks that may result in, among other things, dry holes, the failure to produce oil, natural gas and NGLs in commercial quantities and the inability to fully produce discovered reserves.

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, 2021, approximately 26 percent of our estimated proved reserves (by volume) were undeveloped. These reserve estimates reflect our plans to make capital expenditures for estimated future development costs of $2.1 billion to convert our PUD reserves into proved developed reserves. 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 reserve 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 within this five-year time frame.

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 2022 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 2022 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 build out. 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 more likely to occur in remote areas with less established infrastructure, such as our Delaware Basin properties where we have significant oil and natural gas production. Any of these availability or capacity issues, whether resulting from the COVID-19 pandemic, construction delays, government restrictions, adverse weather conditions (such as the severe winter storm that impacted Texas and Oklahoma in February 2021), fire or other reasons, 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. In such an event, 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

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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.

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 face a variety of hazards and risks that could cause substantial financial losses.

Our business involves a variety of operating risks, including:

•well site blowouts, cratering and explosions;

•equipment failures;

•pipe or cement failures and casing collapses, which can release oil, natural gas, drilling fluids or hydraulic fracturing fluids;

•uncontrolled flows of oil, natural gas or well fluids;

•pipeline ruptures;

•fires;

•formations with abnormal pressures;

•handling and disposal of materials, including drilling fluids and hydraulic fracturing fluids;

•release of toxic gas;

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•buildup of naturally occurring radioactive materials;

•pollution and other environmental risks, including conditions caused by previous owners or operators of our properties; and

•natural disasters.

Any of these events could result in injury or loss of human life, loss of hydrocarbons, significant damage to or destruction of property, environmental pollution, natural resource damages, regulatory investigations and penalties, suspension or impairment of our operations and substantial losses to us.

Our utilization of oil and natural gas gathering and pipeline systems also involves various risks, including the risk of explosions and environmental hazards caused by pipeline leaks and ruptures. The location of pipelines near populated areas, including residential areas, commercial business centers and industrial sites, could increase these risks.

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, 2021, non-operated wells represented approximately 68 percent of our total owned gross wells, or 18 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 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 approximately one percent of our total net undeveloped acreage as of December 31, 2021. 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

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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, 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. Future challenges in the global financial system, including the capital markets, may adversely affect 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. Adverse economic and market conditions could adversely affect the collectability of our trade receivables and cause our commodity hedging counterparties to be unable to perform their obligations or to seek bankruptcy protection. In addition, there have been efforts in recent years aimed at the investment community, including investment advisors, sovereign wealth funds, public pension funds, universities and other groups, promoting the divestment of fossil fuel equities as well as to pressure lenders and other financial services companies to limit or curtail activities with companies engaged in the extraction of fossil fuel reserves, which, if successful, could limit our ability to access capital markets. For example, in October 2020, JP Morgan Chase & Co. announced that it was adopting a financing commitment that is aligned to the goals of the Paris climate accord of 2015 (the “Paris Agreement”). Other banks have made climate-related pledges for various causes, such as stopping the financing of Arctic drilling and coal companies. 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. Future challenges in the economy could also lead to reduced demand for oil and natural gas, which could have a negative impact on our revenues.

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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.

As of December 31, 2021, we had approximately $3.1 billion of debt outstanding (with a principal amount of $2.9 billion) and we may incur additional indebtedness in the future. Following the Merger, our legacy revolving credit facility and private placement senior notes remained outstanding. In addition, on October 7, 2021, we completed an exchange offer, whereby we issued $1.8 billion in aggregate principal amount of new senior notes in exchange for $1.8 billion in aggregate principal amount of previously outstanding Cimarex senior notes. Following completion of that exchange offer, approximately $200 million in aggregate principal amount of Cimarex senior notes remained outstanding. The increase in 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 free cash flow to stockholders and future business opportunities;

•increasing the risk of default on debt obligations;

•limiting our ability to sell assets, engage in strategic transactions or obtain additional financing for working capital, capital expenditures, general corporate and other purposes;

•limiting our flexibility in planning for or reacting to changes in our business and the industry in which we operate, which could place us at a competitive disadvantage compared to our competitors with lower debt-service obligations;

•increasing our exposure to a rise in interest rates, which would generate greater interest expense to the extent we do not have applicable interest rate fluctuation hedges;

•depending on the levels of our outstanding debt, limit our ability to obtain additional financing for working capital, capital expenditures, general corporate and other purposes; and

•increasing our vulnerability to adverse changes in general economic and industry conditions, including declines in commodity prices, economic downturns and adverse developments in our business.

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. Our ability to generate cash is subject to general economic, financial, competitive, legislative, regulatory and other factors that are beyond our control. In addition, our ability to withstand competitive pressures and to react to changes in the oil and gas industries could be impaired. 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.

In addition, the margins we pay under our revolving credit facility depend on (1) the credit rating of our debt, at times when our debt has an investment grade credit rating and (2) our leverage ratio, at times when our debt does not have an investment grade rating. Accordingly, adverse changes in our leverage ratio or the credit rating of our debt may result in an increase in our interest expense.

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 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-Capital Resources and Liquidity.”

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

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available, we generally utilize collar, swap, roll differential swap and basis swap agreements to manage price risk more effectively. In addition, to mitigate a portion of its exposure to changes in commodity prices, Cimarex historically hedged oil and natural gas prices from time to time, primarily through the use of certain derivative instruments. Upon completion of the Merger, we assumed Cimarex’s existing hedges, such that we will now bear the economic impact of those hedges.

The collar arrangements are 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 that period when the swap is put in place. These arrangements 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 swap transactions. These regulations are intended to implement a regulated market in which most swaps are executed on registered exchanges or swap execution facilities and cleared through central counterparties. Although we believe that our use of swap transactions exempt us from certain regulatory requirements, the changes to the swap market due to increased regulation could significantly increase the cost of entering into new swaps or maintaining existing swaps, materially alter the terms of new or existing swap transactions and/or reduce the availability of new or existing swaps. If we reduce our use of swaps as a result of the Dodd-Frank Wall Street Reform and Consumer Protection Act and implementing regulations thereunder, 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.

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 or negative public perception regarding us and/or our industry could have an adverse effect on our business operations and the price of our common stock.

Businesses across all industries are facing increasing scrutiny from investors, stockholders and the public related to their ESG practices. 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, and/or stock price. 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 common stock from consideration by certain investment funds, engagement by investors seeking to improve such scores and a negative perception of our operations by certain investors.

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

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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 price 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 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.

Most of our exploration and production operations depend on the use of hydraulic fracturing to enhance production from oil and gas wells. This technology involves the injection of fluids—usually consisting mostly of water but typically including small amounts of several chemical additives—as well as sand or other proppants into a well under high pressure in order to create fractures in the rock that allow oil or gas to flow more freely to the wellbore. Most of our wells would not be economical without the use of hydraulic fracturing to stimulate production from the well. If existing laws and regulations with regard to hydraulic fracturing are revised or reinterpreted or if new laws and regulations become applicable to our operations through judicial or administrative actions, our business, financial condition, results of operations and cash flows could be adversely affected. Further, state and federal regulatory agencies have focused on a possible connection between the operation of injection wells used for oil and gas waste disposal and seismic activity in recent years. Similar concerns have been raised that hydraulic fracturing may also contribute to seismic activity. When caused by human activity, such events are called induced seismicity. In March 2016, the U.S. Geological Survey identified six states with the most significant hazards from induced seismicity, including Oklahoma, Kansas, Texas, Colorado, New Mexico, and Arkansas. These concerns have further increased regulatory scrutiny on hydraulic fracturing as well as oil and gas waste injection wells and led to the adoption of state and local laws regulating such activities. We cannot predict whether additional federal, state or local laws or regulations applicable to hydraulic fracturing or oil and gas waste injection wells will be enacted in the future and, if so, what actions any such laws or regulations would require or prohibit. These concerns also could lead to greater opposition to, and litigation concerning, oil and gas activities utilizing hydraulic fracturing or injection wells for waste disposal, 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 from developing shale plays, or could make it more difficult to perform hydraulic fracturing. In addition, if existing laws and regulations with regard to hydraulic fracturing are revised or reinterpreted or if new laws and regulations become applicable to our operations through judicial or administrative actions, our business, financial condition, results of operations and cash flows could be adversely affected.

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 could result in more complex, costly, and time-consuming air permitting and cause delays in our operations. In August 2012 and June 2016, the EPA published rules establishing new air emission control requirements for the oil and natural gas sector, including NSPS to address emissions of sulfur dioxide and volatile organic compounds and to regulate methane emissions for new and modified sources in the oil and gas industry, and NESHAP to address hazardous air pollutants frequently associated with gas production and processing activities. Although these rules were stayed and ultimately carved back by a September 2020 EPA rule, on June 30, 2021, President Biden signed into law a joint Congressional resolution under the Congressional Review Act disapproving the September 2020 rule. On November 15, 2021, the EPA proposed rules to reduce methane emissions from both new and existing oil and natural gas

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industry sources. Compliance with the 2012 and 2016 NSPS for the oil and gas sector and any additional requirements imposed by new EPA regulations, particularly a new methane regulation, may require modifications to certain of our operations or increase the cost of new or modified facilities, including the installation of new equipment to control emissions at the well site, which could result in significant costs, including increased capital expenditures and operating costs, and adversely impact our business.

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.

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. For water sourcing, we first seek to use non-potable water supplies for our operational needs. In certain areas, there may be insufficient local aquifer capacity to provide a source of water for drilling activities. Water must then be obtained from other sources and transported to the drilling site. An inability to secure sufficient amounts of water or to dispose of or recycle the water used in our operations could adversely impact our operations in certain areas. 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. In the absence of significant federal GHG legislation, a number of state and regional efforts have emerged, 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. On January 20, 2021, his first day in office, President Biden signed an executive order on climate action and reconvened an interagency working group to establish 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. 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 both 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. These policy actions potentially could be accelerated with a

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Democratic party in control of Congress and the Presidency. 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. Legal risks include potential lawsuits claiming failure to mitigate impacts of climate change, failure to adapt to climate change, and the insufficiency of disclosure around material financial risks.

Furthermore, we also 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.

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.

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 or negative public perception regarding us and/or our industry could have an adverse effect on our business operations and the price of our common stock.”

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

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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 and imposing a new alternative minimum tax on book income. Further, many states are currently in deficits, and have been enacting laws eliminating or limiting certain deductions, carryforwards and credits in order to increase tax revenue.

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.

Additional Risks Related to the Merger

The Merger may result in a loss of customers, distributors, service providers, suppliers, vendors, joint venture participants and other business counterparties and may result in the termination of existing contracts.

As a result of the Merger, some of our and Cimarex's legacy customers, distributors, service providers, suppliers, vendors, joint venture participants and other business counterparties may terminate or scale back their current or prospective business relationships with the combined business. If relationships with customers, distributors, service providers, suppliers, vendors, joint venture participants and other business counterparties are adversely affected by the Merger, our business, financial condition, results of operations and cash flows could be materially and adversely affected.

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.

The market price of our common stock may fluctuate for various reasons and may decline if large amounts of our common stock are sold following the Merger.

The market price of our common stock may fluctuate significantly in the future and holders of our common stock could lose some or all of the value of their investment. As a result of the Merger, we issued approximately 408.2 million shares of our common stock to former Cimarex stockholders (excluding shares that were awarded in replacement of previously outstanding Cimarex restricted share awards). The Merger Agreement contained no restrictions on the ability of former Cimarex stockholders or our historic stockholders to sell or otherwise dispose of shares of our common stock. Former Cimarex stockholders may decide not to hold the shares of our common stock that they received in the Merger, and our historic stockholders may decide to reduce their investment in us as a result of the changes to our investment profile as a result of the Merger. These sales of our common stock (or the perception that these sales may occur) could have the effect of depressing the market price for our common stock. In addition, with the completion of the Merger, our financial position is different from our financial position before the completion of the Merger, and our future results of operations and cash flows will be affected by factors different from those that previously affected our results of operations and cash flows, all of which could adversely affect the market price of our common stock. Furthermore, the stock market has experienced significant price and volume fluctuations in recent times which, if they continue to occur, could have a material adverse effect on the market for, or liquidity of, our common stock, regardless of our actual operating performance.

Our ability to utilize Cimarex's historic net operating loss carryforwards and other tax attributes may be limited.

On October 1, 2021, we completed the Merger, and as a result, we acquired Cimarex’s U.S. federal net operating loss carryforwards (“NOLs”) and other tax attributes. Our ability to utilize these NOLs and other tax attributes to reduce future taxable income depends on many factors, including future income, which cannot be assured. Section 382 of the Internal

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Revenue Code of 1986, as amended ("Section 382"), generally imposes an annual limitation on the amount of NOLs and other tax attributes that may be used to offset taxable income when a corporation has undergone an "ownership change" (as determined under Section 382). An ownership change generally occurs if one or more stockholders (or groups of stockholders) who are each deemed to own at least 5 percent of such corporation's stock increase their ownership by more than 50 percentage points over their lowest ownership percentage within a rolling three-year period.

As a result of the Merger, an ownership change occurred with respect to Cimarex under Section 382, which triggered a limitation on our ability to utilize Cimarex's historic NOLs and other tax attributes and could cause some of those NOLs and other tax attributes to expire unutilized. This annual limitation under Section 382 is determined by multiplying (1) the fair market value of Cimarex's stock at the time of the Merger by (2) the long-term tax exempt rate published by the Internal Revenue Service for the month in which the Merger occurred, subject to certain adjustments (provided that any unused annual limitation may be carried over to later years). In addition, the NOLs Cimarex acquired in 2019 as part of its acquisition of Resolute Energy Corporation are already subject to a Section 382 limitation.

See Note 10 of the Notes to Consolidated Financial Statements, “Income Taxes,” included in Item 8 for more information regarding Cimarex’s historic NOL carryforwards and the Section 382 limitation.

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).

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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 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.

We may not be insured against all of the operating risks to which we are exposed.

We maintain insurance against some, but not all, operating risks and losses. We do not carry business interruption insurance. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows. The cost of insurance may increase, and the availability of insurance may decrease, as a result of climate change or other factors.

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, driven in part by reduced commodity prices related to the global COVID-19 pandemic, 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.

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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 will be uncertain.

Although we have paid cash dividends on shares of common stock in the past, our Board of Directors may determine not to declare dividends in the future or may reduce the amount of dividends paid in the future. Decisions on whether, when and in which amounts to declare and pay any future dividends will remain in the discretion of our Board of Directors. Any dividend payment amounts will be determined by our Board of Directors on a quarterly basis, and it is possible that our Board of Directors may increase or decrease the amount of dividends paid in the future, or determine not to declare dividends in the future, at any time and for any reason. 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, including, but not limited to:

•whether we have enough cash to pay such dividends due to our cash requirements, capital spending plans, cash flows or financial position;

•our desire to maintain or improve the credit ratings on our debt; and

•applicable restrictions under Delaware law.

Our common stockholders should be aware that they have no contractual or other legal right to dividends that have not been declared.

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 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 and/or penalties, if fines and/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.

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INFORMATION ABOUT OUR EXECUTIVE OFFICERS

The following table shows certain information as of February 28, 2022 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
Dan O. Dinges	68	Executive Chairman, Board of Directors	2001
Thomas E. Jorden	64	Chief Executive Officer and President	2021
Scott C. Schroeder	59	Executive Vice President and Chief Financial Officer	1997
Stephen P. Bell	67	Executive Vice President, Business Development	2021
Francis B. Barron	59	Senior Vice President and General Counsel, and Assistant Corporate Secretary	2021
Christopher H. Clason	55	Senior Vice President and Chief Human Resources Officer	2021
Steven W. Lindeman	61	Senior Vice President, Production and Operations	2011
Phillip L. Stalnaker	62	Senior Vice President, Marcellus Business Unit	2009
Michael D. DeShazer	36	Vice President of Business Units	2021
Todd M. Roemer	51	Vice President and Chief Accounting Officer	2010
Kevin W. Smith	36	Vice President and Chief Technology Officer	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, each of whom previously served Cimarex as described below and began serving in his current role at the Company as of October 1, 2021, the effective date of the Merger:

Mr. Jorden previously served as the Chief Executive Officer and President of Cimarex since September 2011 and as Chairman of the Board of Directors of Cimarex since 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 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 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. Barron joined Cimarex as Senior Vice President and General Counsel in 2013. Prior to Cimarex, Mr. Barron served in various capacities at Bill Barrett Corporation between 2004 and 2013, including as Executive Vice President and General Counsel, Secretary, and Chief Financial Officer. Prior to Bill Barrett Corporation, Mr. Barron was a partner at the Denver, Colorado office of the law firm of Patton Boggs LLP, as well as a partner at Bearman Talesnick & Clowdus Professional Corporation.

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. 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. 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.

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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 2021. 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, 2022, there were 771 registered holders of our common stock.

EQUITY COMPENSATION PLAN INFORMATION

In connection with the Merger, we assumed all rights and obligations under the Cimarex Energy Co. 2019 Equity Incentive Plan (the “2019 Cimarex Plan”) and will be entitled to grant equity or equity-based awards with respect to Coterra common stock under the plan to current or former employees of Cimarex, to the extent permissible under applicable law and NYSE listing rules. The 2019 Cimarex Plan provides for grants of options, stock appreciation rights, restricted stock, restricted stock units, performance stock units, cash awards and other stock-based awards.

The following table provides information as of December 31, 2021 regarding the number of shares of common stock that may be issued under our incentive plans, including the 2019 Cimarex Plan.

	(a)		(b)	(c)
Plan Category	Number of securities to be issued upon exercise of outstanding options, warrants and rights		Weighted-average exercise price of outstanding options, warrants and rights	Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
Equity compensation plans approved by security holders	4,745,825	(1)	n/a	49,430,179	(2)
Equity compensation plans not approved by security holders	n/a		n/a	n/a
Total	4,745,825		n/a	49,430,179

_______________________________________________________________________________

(1)Includes 1,858,104 employee performance shares, the performance periods of which end on December 31, 2021, 2022, 2023, and September 30, 2024; 1,355,352 non-qualified stock options which expire in periods ranging from 2022 to 2027; 1,286,471 restricted stock units awarded to employees that vest in April 2022, December 2024 and various dates in 2022 and 2023 and 245,898 restricted stock units awarded to the non-employee directors, the restrictions on which would lapse upon a non-employee director's departure from our Board of Directors.

(2)Includes 3,019,183 shares of restricted stock, the restrictions on which lapse in 2022, 2023 and 2024, and 10,461,081 shares that are available for future grants under the Coterra Energy Inc. 2014 Incentive Plan; and 35,949,915 shares that are available for future grants to legacy Cimarex employees only under the 2019 Incentive Plan.

ISSUER PURCHASES OF EQUITY SECURITIES

Our Board of Directors previously authorized a share repurchase program under which we could purchase shares of our common stock in the open market or in negotiated transactions. No expiration date was associated with this prior authorization, and there were no repurchases under this authorized share repurchase program during the quarter ended December 31, 2021.

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 authorizes the Company to purchase up to $1.25 billion of our common stock in the open market or in negotiated transactions.

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The following table sets forth information regarding repurchases of our common stock during the quarter ended December 31, 2021.

Period	Total number of shares purchased (1)	Average price paid per share		Total number of shares purchased as part of publicly announced plans or programs	Maximum number of shares that may yet be purchased under the plans or programs
October 2021	—	—		—	—
November 2021	—	—		—	—
December 2021	125,067	$	19.74	—	—
Total	125,067	$	19.74	—	—

_______________________________________________________________________________

(1)Reflects shares purchased from employees in order for employees to satisfy income tax withholding payments related to share-based awards that vested during the period.

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 2016 through December 2021. The graph assumes that the value of the investment in our common stock and in each index was $100 on December 31, 2016 and that all dividends were reinvested.

	December 31,
Calculated Values	2016		2017		2018		2019		2020		2021
CTRA	$	100.00	$	123.26	$	97.29	$	77.07	$	73.73	$	91.05
S&P 500	$	100.00	$	121.83	$	116.49	$	153.17	$	181.35	$	233.41
Dow Jones U.S. Exploration & Production	$	100.00	$	101.30	$	83.30	$	92.79	$	61.57	$	105.24
S&P Oil & Gas Exploration & Production	$	100.00	$	93.69	$	75.42	$	84.49	$	54.56	$	102.08

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 referred to when reviewing this material. This discussion and analysis also includes forward-looking statements. Readers are cautioned that such forward-looking statements are based on current expectations and assumptions that involve a number of risks and uncertainties that could cause actual results to differ materially from those included in this report, including those under “Forward-Looking Statements” in Part I of this report and “Risk Factors” in Part I, Item 1A of this report.

OVERVIEW

Cimarex Merger

On October 1, 2021, we and Cimarex completed the Merger. Cimarex is an oil and gas exploration and production company with operations in Texas, New Mexico and Oklahoma. Under the terms of the Merger Agreement and subject to certain exceptions specified therein, each eligible share of Cimarex common stock was converted into the right to receive 4.0146 shares of our common stock. As a result of the completion of the Merger, we issued approximately 408.2 million shares of common stock to Cimarex stockholders (excluding shares that were awarded in replacement of previously outstanding Cimarex restricted share awards). Additionally on October 1, 2021, we changed our name to Coterra Energy Inc.

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

Financial and Operating Overview

Financial and operating results for the year ended December 31, 2021 compared to the year ended December 31, 2020 are as follows:

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

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

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

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

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

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

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

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

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

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

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

Impact of the COVID-19 Pandemic

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

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

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

Market Conditions and Commodity Prices

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

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