cog-20230630

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549



FORM			10-Q

☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934.

For the quarterly period ended June 30, 2023

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934.

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

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 is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒

As of August 4, 2023, there were 755,045,540 shares of Common Stock, Par Value $0.10 Per Share, outstanding.

Table of Contents

COTERRA ENERGY INC.

TABLE OF CONTENTS


		Page
Part I. Financial Information

Item 1.	Financial Statements

Condensed Consolidated Balance Sheet (Unaudited) at June 30, 2023 and December 31, 2022		3

Condensed Consolidated Statement of Operations (Unaudited) for the Three and Six Months Ended June 30, 2023 and 2022		4



Condensed Consolidated Statement of Cash Flows (Unaudited) for the Six Months Ended June 30, 2023 and 2022		5

Condensed Consolidated Statement of Stockholders' Equity (Unaudited) for the Three and Six Months Ended June 30, 2023 and 2022		6

Notes to the Condensed Consolidated Financial Statements (Unaudited)		7



Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	20

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	34

Item 4.	Controls and Procedures	36

Part II. Other Information

Item 1.	Legal Proceedings	37

Item 1A.	Risk Factors	37

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	37

Item 5.	Other Information	37

Item 6.	Exhibits	40

Signatures		42

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PART I. FINANCIAL INFORMATION

ITEM 1. Financial Statements

COTERRA ENERGY INC.

CONDENSED CONSOLIDATED BALANCE SHEET (Unaudited)


(In millions, except per share amounts)	June 30, 2023		December 31, 2022
ASSETS
Current assets
Cash and cash equivalents	$	841	$	673
Restricted cash	9		10
Accounts receivable, net	604		1,221
Income taxes receivable	18		89
Inventories	65		63
Derivative instruments	88		146
Other current assets	15		9
Total current assets	1,640		2,211
Properties and equipment, net (Successful efforts method)	17,801		17,479



Other assets	438		464
	$	19,879	$	20,154

LIABILITIES, REDEEMABLE PREFERRED STOCK AND STOCKHOLDERS' EQUITY
Current liabilities
Accounts payable	$	626	$	844

Accrued liabilities	294		328

Interest payable	21		21

Total current liabilities	941		1,193
Long-term debt, net	2,171		2,181

Deferred income taxes	3,367		3,339
Asset retirement obligations	277		271


Other liabilities	456		500
Total liabilities	7,212		7,484

Commitments and contingencies

Cimarex redeemable preferred stock	8		11

Stockholders' equity
Common stock:
Authorized — 1,800 shares of $0.10 par value in 2023 and 2022
Issued — 755 shares and 768 shares in 2023 and 2022, respectively	76		77
Additional paid-in capital	7,639		7,933
Retained earnings	4,931		4,636
Accumulated other comprehensive income	13		13


Total stockholders' equity	12,659		12,659
	$	19,879	$	20,154

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

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COTERRA ENERGY INC.

CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS (Unaudited)


	Three Months Ended June 30,				Six Months Ended June 30,
(In millions, except per share amounts)	2023		2022		2023		2022
OPERATING REVENUES
Natural gas	$	436	$	1,468	$	1,258	$	2,579
Oil	626		876		1,241		1,575
NGL	129		280		306		525
Gain (loss) on derivative instruments	(12)		(66)		126		(457)
Other	6		14		31		29
	1,185		2,572		2,962		4,251
OPERATING EXPENSES
Direct operations	130		116		264		216
Transportation, processing and gathering	258		238		494		471
Taxes other than income	63		98		149		174
Exploration	5		7		9		13
Depreciation, depletion and amortization	395		414		764		774

General and administrative	58		87		134		194
	909		960		1,814		1,842

Gain (loss) on sale of assets	—		(3)		5		(1)
INCOME FROM OPERATIONS	276		1,609		1,153		2,408

Interest expense	16		22		33		43
Interest income	(10)		(1)		(22)		(1)

Income before income taxes	270		1,588		1,142		2,366
Income tax expense	61		359		256		529
NET INCOME	$	209	$	1,229	$	886	$	1,837





Earnings per share
Basic	$	0.28	$	1.53	$	1.16	$	2.28
Diluted	$	0.27	$	1.52	$	1.16	$	2.27

Weighted-average common shares outstanding
Basic	755		803		760		806
Diluted	760		808		764		809

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

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COTERRA ENERGY INC.

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS (Unaudited)


	Six Months Ended June 30,
(In millions)	2023		2022
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	886	$	1,837
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation, depletion and amortization	764		774

Deferred income tax expense	27		101
(Gain) loss on sale of assets	(5)		1

(Gain) loss on derivative instruments	(126)		457
Net cash received (paid) in settlement of derivative instruments	184		(464)


Amortization of debt premium and debt issuance costs	(10)		(19)

Stock-based compensation and other	24		38
Changes in assets and liabilities:
Accounts receivable, net	617		(489)
Income taxes	71		(200)
Inventories	(2)		(9)
Other current assets	(6)		(6)
Accounts payable and accrued liabilities	(336)		147
Interest payable	—		1
Other assets and liabilities	52		32

Net cash provided by operating activities	2,140		2,201

CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures for drilling, completion and other fixed asset additions	(1,075)		(741)
Capital expenditures for leasehold and property acquisitions	(6)		(4)

Proceeds from sale of assets	33		4



Net cash used in investing activities	(1,048)		(741)

CASH FLOWS FROM FINANCING ACTIVITIES


Repayments of finance leases	(3)		(3)
Common stock repurchases	(325)		(487)

Dividends paid	(588)		(940)

Cash received for stock option exercises	—		10
Cash paid for conversion of redeemable preferred stock	(1)		(10)
Tax withholding on vesting of stock awards	(1)		(7)
Capitalized debt issuance costs	(7)		—

Net cash used in financing activities	(925)		(1,437)

Net increase in cash, cash equivalents and restricted cash	167		23
Cash, cash equivalents and restricted cash, beginning of period	683		1,046
Cash, cash equivalents and restricted cash, end of period	$	850	$	1,069

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

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COTERRA ENERGY INC.

CONDENSED CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY (Unaudited)


(In millions, except per share amounts)	Common Shares	Common Stock Par		Treasury Shares	Treasury Stock		Paid-In Capital		Accumulated Other Comprehensive Income		Retained Earnings		Total
Balance at December 31, 2022	768	$	77	—	$	—	$	7,933	$	13	$	4,636	$	12,659
Net income	—	—		—	—		—		—		677		677


Stock amortization and vesting	—	—		—	—		13		—		—		13


Conversion of Cimarex redeemable preferred stock	—	—		—	—		3		—		—		3
Common stock repurchases	—	—		11	(271)		—		—		—		(271)
Common stock retirements	(11)	(1)		(11)	271		(270)		—		—		—

Cash dividends on common stock at $0.57 per share	—	—		—	—		—		—		(438)		(438)


Balance at March 31, 2023	757	$	76	—	$	—	$	7,679	$	13	$	4,875	$	12,643
Net income	—	—		—	—		—		—		209		209


Stock amortization and vesting	—	—		—	—		17		—		—		17



Common stock repurchases	—	—		2	(57)		—		—		—		(57)
Common stock retirements	(2)	—		(2)	57		(57)		—		—		—
Cash dividends on common stock at $0.20 per share	—	—		—	—		—		—		(153)		(153)


Balance at June 30, 2023	755	$	76	—	$	—	$	7,639	$	13	$	4,931	$	12,659


(In millions, except per share amounts)	Common Shares	Common Stock Par		Treasury Shares	Treasury Stock		Paid-In Capital		Accumulated Other Comprehensive Income		Retained Earnings		Total
Balance at December 31, 2021	893	$	89	79	$	(1,826)	$	10,911	$	1	$	2,563	$	11,738
Net income	—	—		—	—		—		—		608		608
Exercise of stock options	—	—		—	—		6		—		—		6
Stock amortization and vesting	—	—		—	—		10		—		—		10


Common stock repurchases	—	—		8	(192)		—		—		—		(192)
Cash dividends:
Common stock at $0.56 per share	—	—		—	—		—		—		(455)		(455)
Preferred stock at $20.3125 per share	—	—		—	—		—		—		(1)		(1)
Other comprehensive income	—	—		—	—		—		4		—		4
Balance at March 31, 2022	893	$	89	87	$	(2,018)	$	10,927	$	5	$	2,715	$	11,718
Net income	—	—		—	—		—		—		1,229		1,229
Exercise of stock options	—	—		—	—		3		—		—		3
Stock amortization and vesting	—	—		—	—		18		—		—		18
Conversion of Cimarex redeemable preferred stock	1	—		—	—		28		—		—		28
Common stock repurchases	—	—		12	(321)		—		—		—		(321)
Cash dividends on common stock at $0.60 per share	—	—		—	—		—		—		(484)		(484)

Balance at June 30, 2022	894	$	89	99	$	(2,339)	$	10,976	$	5	$	3,460	$	12,191

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

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COTERRA ENERGY INC.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

1. Financial Statement Presentation

During interim periods, Coterra Energy Inc. (the “Company”) follows the same accounting policies disclosed in its Annual Report on Form 10-K for the year ended December 31, 2022 (the “Form 10-K”) filed with the Securities and Exchange Commission (“SEC”), except for any new accounting pronouncements adopted during the period. The interim condensed consolidated financial statements are unaudited and should be read in conjunction with the notes to the consolidated financial statements and information presented in the Form 10-K. In management’s opinion, the accompanying interim condensed consolidated financial statements contain all material adjustments, consisting only of normal recurring adjustments, necessary for a fair statement. The results for any interim period are not necessarily indicative of the results that may be expected for the entire year.

From time to time, we make certain reclassifications to prior year statements to conform with the current year presentation. These reclassifications have no impact on previously reported stockholders’ equity, net income or cash flows.

2. Properties and Equipment, Net

Properties and equipment, net are comprised of the following:


(In millions)	June 30, 2023		December 31, 2022
Proved oil and gas properties	$	18,353	$	17,085
Unproved oil and gas properties	4,881		5,150
Gathering and pipeline systems	507		450
Land, buildings and other equipment	194		183
Finance lease right-of-use asset	25		24
	23,960		22,892
Accumulated depreciation, depletion and amortization	(6,159)		(5,413)
	$	17,801	$	17,479

Capitalized Exploratory Well Costs

As of June 30, 2023, the Company did not have any projects with exploratory well costs capitalized for a period of greater than one year after drilling.

3. Debt and Credit Agreements

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


(In millions)	June 30, 2023		December 31, 2022

3.65% weighted-average private placement senior notes	$	825	$	825
3.90% senior notes due May 15, 2027	750		750
4.375% senior notes due March 15, 2029	500		500
Revolving credit agreement	—		—
Total	2,075		2,075
Net premium	101		111
Unamortized debt issuance costs	(5)		(5)
Long-term debt	$	2,171	$	2,181

At June 30, 2023, the Company was in compliance with all financial and other covenants for its revolving credit agreement (as defined below), 3.65% weighted-average private placement senior notes (the “private placement senior notes”) and the 3.90% senior notes due May 15, 2027 and 4.375% senior notes due March 15, 2029 (the “senior notes”).

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Revolving Credit Agreement

On March 10, 2023, the Company entered into a revolving credit agreement (the “Credit Agreement”) with JPMorgan Chase Bank, N.A., as administrative agent (“JPMorgan”), and certain lenders and issuing banks party thereto. The aggregate revolving commitments under the Credit Agreement are $1.5 billion, with a discretionary swingline sub-facility of up to $100 million and a letter of credit sub-facility of up to $500 million. The Company may also increase the revolving commitments under the Credit Agreement by up to an additional $500 million subject to certain conditions and the agreement of the lenders providing commitments with respect to such increase.

Borrowings under the Credit Agreement bear interest at a rate per annum equal to, at the Company’s option, either a term secured overnight financing rate (“SOFR”) plus a 0.10 percent credit spread adjustment for all tenors or a base rate, plus an interest rate margin which ranges from 0 to 75 basis points for base rate loans and 100 to 175 basis points for term SOFR loans based on the Company’s credit rating. The commitment fee on the unused available credit is calculated at annual rates ranging from 10 basis points to 27.5 basis points. The Credit Agreement matures on March 10, 2028. The maturity date can be extended for additional one-year periods on up to two occasions upon the agreement of the Company and lenders holding at least 50 percent of the commitments under the Credit Agreement.

The Credit Agreement contains customary covenants, including the maintenance of a maximum leverage ratio of no more than 3.0 to 1.0 as of the last day of any fiscal quarter until such time as the Company has no other debt in a principal amount in excess of $75 million outstanding that has a financial maintenance covenant based on a leverage ratio, at which time the Credit Agreement requires maintenance of a ratio of total debt to total capitalization of no more than 65 percent (with all calculations based on definitions contained in the Credit Agreement).

Concurrently with the Company’s entry into the Credit Agreement, the Company terminated its existing Second Amended and Restated Credit Agreement, dated as of April 22, 2019, with the lenders party thereto and JPMorgan, as administrative agent thereunder.

At June 30, 2023, the Company had no borrowings outstanding under its revolving credit agreement and unused commitments of $1.5 billion.

4. Derivative Instruments

As of June 30, 2023, the Company had the following outstanding financial commodity derivatives:



	2023
Natural Gas	Third Quarter		Fourth Quarter




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

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


	2023
Oil	Third Quarter		Fourth Quarter
WTI oil collars
Volume (MBbl)	920		920
Weighted average floor ($/Bbl)	$	65.00	$	65.00
Weighted average ceiling ($/Bbl)	$	89.66	$	89.66

WTI Midland oil basis swaps
Volume (MBbl)	920		920
Weighted average differential ($/Bbl)	$	1.01	$	1.01

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Effect of Derivative Instruments on the Condensed Consolidated Balance Sheet


		Fair Values of Derivative Instruments
		Derivative Assets				Derivative Liabilities
(In millions)	Balance Sheet Location	June 30, 2023		December 31, 2022		June 30, 2023		December 31, 2022

Commodity contracts	Derivative instruments (current)	$	88	$	146	$	—	$	—

Offsetting of Derivative Assets and Liabilities in the Condensed Consolidated Balance Sheet


(In millions)	June 30, 2023		December 31, 2022
Derivative assets
Gross amounts of recognized assets	$	89	$	147
Gross amounts offset in the condensed consolidated balance sheet	(1)		(1)
Net amounts of assets presented in the condensed consolidated balance sheet	88		146
Gross amounts of financial instruments not offset in the condensed consolidated balance sheet	1		2
Net amount	$	89	$	148

Derivative liabilities
Gross amounts of recognized liabilities	$	1	$	1
Gross amounts offset in the condensed consolidated balance sheet	(1)		(1)
Net amounts of liabilities presented in the condensed consolidated balance sheet	—		—
Gross amounts of financial instruments not offset in the condensed consolidated balance sheet	—		1
Net amount	$	—	$	1

Effect of Derivative Instruments on the Condensed Consolidated Statement of Operations


	Three Months Ended June 30,				Six Months Ended June 30,
(In millions)	2023		2022		2023		2022
Cash received (paid) on settlement of derivative instruments
Gas contracts	$	82	$	(161)	$	181	$	(203)
Oil contracts	2		(132)		3		(261)
Non-cash gain (loss) on derivative instruments
Gas contracts	(96)		133		(54)		(49)
Oil contracts	—		94		(4)		56
	$	(12)	$	(66)	$	126	$	(457)

5. Fair Value Measurements

The Company follows the authoritative guidance for measuring fair value of assets and liabilities in its financial statements. For further information regarding the fair value hierarchy, refer to Note 1 of the Notes to the Consolidated Financial Statements in the Form 10-K.

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Financial Assets and Liabilities

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


(In millions)	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Balance at June 30, 2023
Assets
Deferred compensation plan	$	47	$	—	$	—	$	47
Derivative instruments	—		—		89		89
	$	47	$	—	$	89	$	136
Liabilities
Deferred compensation plan	$	47	$	—	$	—	$	47
Derivative instruments	—		—		1		1
	$	47	$	—	$	1	$	48


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

The Company’s investments associated with its deferred compensation plans consist of mutual funds and deferred shares of the Company’s common stock that are publicly traded and for which market prices are readily available. During the second quarter of 2023, all shares of the Company’s common stock held in the deferred compensation plan were sold and invested in other investment options.

The derivative instruments were measured based on quotes from the Company’s counterparties or internal models. Such quotes and models have been derived using an income approach that considers various inputs, including current market and contractual prices for the underlying instruments, quoted forward commodity prices, basis differentials, volatility factors and interest rates for a similar length of time as the derivative contract term as applicable. Estimates are derived from, or verified using, relevant NYMEX futures contracts, and/or are compared to multiple quotes obtained from counterparties. The determination of the fair values presented above also incorporates a credit adjustment for non-performance risk. The Company measured the non-performance risk of its counterparties by reviewing credit default swap spreads for the various financial institutions with which it has derivative contracts while non-performance risk of the Company is evaluated using market credit spreads provided by several of the Company’s banks. The Company has not incurred any losses related to non-performance risk of its counterparties and does not anticipate any material impact on its financial results due to non-performance by third parties.

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

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


	Six Months Ended June 30,
(In millions)	2023		2022
Balance at beginning of period	$	146	$	(152)
Total gain (loss) included in earnings	126		(450)
Settlement (gain) loss	(184)		457
Transfers in and/or out of Level 3	—		—
Balance at end of period	$	88	$	(145)

Change in unrealized gains (losses) relating to assets and liabilities still held at the end of the period	$	42	$	(112)

Non-Financial Assets and Liabilities

The Company discloses or recognizes its non-financial assets and liabilities, such as impairments of oil and gas properties or acquisitions, at fair value on a nonrecurring basis. As none of the Company’s other non-financial assets and liabilities were measured at fair value as of June 30, 2023, additional disclosures were not required.

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

Fair Value of Other Financial Instruments

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

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

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


	June 30, 2023				December 31, 2022
(In millions)	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-term debt	$	2,171	$	1,962	$	2,181	$	1,955

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6. Asset Retirement Obligations

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


(In millions)	Six Months Ended June 30, 2023
Balance at beginning of period	$	277
Liabilities incurred	3
Liabilities settled	1

Liabilities divested	(4)

Accretion expense	5
Balance at end of period	282
Less: current asset retirement obligations	(5)
Noncurrent asset retirement obligations	$	277

7. Commitments and Contingencies

Contractual Obligations

The Company has various contractual obligations in the normal course of its operations. There have been no material changes to the Company’s contractual obligations described under “Transportation, Processing and Gathering Agreements” and “Lease Commitments” as disclosed in Note 8 of the Notes to Consolidated Financial Statements in the Form 10-K.

Legal Matters

Securities Litigation

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

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

On February 25, 2021, the Company filed a motion to transfer the class action lawsuit to the U.S. District Court for the Southern District of Texas, in Houston, Texas, where its headquarters are located. On June 11, 2021, the Company filed a motion to dismiss the class action lawsuit on the basis that the plaintiffs’ allegations do not meet the requirements for pleading a claim under Section 10(b) or Section 20 of the Exchange Act. On June 22, 2021, the motion to transfer the class action lawsuit to the Southern District of Texas was granted. Pursuant to the prior agreement of the parties, the consolidated derivative case discussed in the preceding paragraph was also transferred to the Southern District of Texas on July 12, 2021. Subsequently, an additional stockholder derivative action styled Treppel Family Trust U/A 08/18/18 Lawrence A. Treppel and Geri D. Treppel for the benefit of Geri D. Treppel and Larry A. Treppel v. Dinges, et al. (U.S. District Court, Southern District of Texas,

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Houston Division), asserting substantially similar Delaware common law claims as in the existing derivative cases, was filed in the Southern District of Texas and consolidated with the existing consolidated derivative cases. On January 12, 2022, the U.S. District Court for the Southern District of Texas granted the Company’s motion to dismiss the class action lawsuit but allowed the plaintiffs to file an amended complaint. The class action plaintiffs filed their amended complaint on February 11, 2022. The Company filed a motion to dismiss the amended class action complaint on March 10, 2022. On August 10, 2022, the U.S. District Court for the Southern District of Texas granted in part and denied in part the Company’s motion to dismiss the amended class action complaint, dismissing certain claims with prejudice but allowing certain claims to proceed. The Company filed its answer to the amended class action complaint on September 14, 2022. The class action case is presently in the discovery and class certification stage. With respect to the consolidated derivative cases, on April 1, 2022, the U.S. District Court for the Southern District of Texas granted the Company’s motion to dismiss such consolidated derivative cases but allowed the plaintiffs to file an amended complaint. The derivative plaintiffs filed their third amended complaint on May 16, 2022. The Company filed its motion to dismiss such amended complaint on June 24, 2022, and filed its reply in support of such motion to dismiss on September 4, 2022. On March 27, 2023, the U.S. District Court for the Southern District of Texas denied the motion to dismiss the derivative case as moot and ordered the Company to file a renewed motion to dismiss addressing certain issues regarding the impact of the class action litigation on the derivative case. The Company filed its renewed motion to dismiss on April 28, 2023, which is now fully briefed and pending for decision. The Company intends to vigorously defend the class action and derivative lawsuits.

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

Other Legal Matters

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

Contingency Reserves

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

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8. Revenue Recognition

Disaggregation of Revenue

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


	Three Months Ended June 30,				Six Months Ended June 30,
(In millions)	2023		2022		2023		2022
Natural gas	$	436	$	1,468	$	1,258	$	2,579
Oil	626		876		1,241		1,575
NGL	129		280		306		525
Other	6		14		31		29
	$	1,197	$	2,638	$	2,836	$	4,708

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

Transaction Price Allocated to Remaining Performance Obligations

As of June 30, 2023, the Company had $6.9 billion of unsatisfied performance obligations related to natural gas sales that have a fixed pricing component and a contract term greater than one year. The Company expects to recognize these obligations over the next 16 years.

Contract Balances

Receivables from contracts with customers are recorded when the right to consideration becomes unconditional, generally when control of the product has been transferred to the customer. Receivables from contracts with customers were $434 million and $1.1 billion as of June 30, 2023 and December 31, 2022, respectively, and are reported in accounts receivable, net in the Condensed Consolidated Balance Sheet. As of June 30, 2023, the Company has no assets or liabilities related to its revenue contracts, including no upfront payments or rights to deficiency payments.

9. Capital Stock

Dividends

Common Stock

In February 2023, the Company’s Board of Directors approved an increase in the base quarterly dividend from $0.15 per share to $0.20 per share.

The following table summarizes the Company’s dividends on its common stock for each quarter in 2023 and 2022:


	Rate per share
	Fixed		Variable		Total		Total Dividends (In millions)
2023:
First quarter	$	0.20	$	0.37	$	0.57	$	438
Second quarter	0.20		—		0.20		153


Total year-to-date	$	0.40	$	0.37	$	0.77	$	591
2022:
First quarter	$	0.15	$	0.41	$	0.56	$	455
Second quarter	0.15		0.45		0.60		484


Total year-to-date	$	0.30	$	0.86	$	1.16	$	939

Treasury Stock

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

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During the six months ended June 30, 2023, the Company repurchased and retired 13 million shares for $328 million under its new repurchase program. As of June 30, 2023, the Company had $1.7 billion remaining under its current share repurchase program. During the six months ended June 30, 2022, the Company repurchased 20 million shares for $513 million under its previous share repurchase program.

10. Stock-Based Compensation

General

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


	Three Months Ended June 30,				Six Months Ended June 30,
(In millions)	2023		2022		2023		2022

Restricted stock units - employees and non-employee directors	$	7	$	11	$	14	$	19
Restricted stock awards	4		5		8		10
Performance share awards	3		4		8		10
Deferred performance shares	(7)		1		(7)		5

Total stock-based compensation expense	$	7	$	21	$	23	$	44
Income tax benefit	$	1	$	—	$	2	$	5

Refer to Note 13 of the Notes to the Consolidated Financial Statements in the Form 10-K for further description of the various types of stock-based compensation awards and the applicable award terms.

On May 4, 2023, the Company’s stockholders approved the Coterra Energy Inc. 2023 Equity Incentive Plan (the “2023 Plan”) which replaced the existing Cabot Oil & Gas Corporation 2014 Incentive Plan (the “Prior Cabot Plan”) and the Cimarex Energy Co. Amended and Restated 2019 Equity Incentive Plan (the “Prior Cimarex Plan). Under the 2023 Plan, permitted awards include, but are not limited to, options, stock appreciation rights, restricted stock, restricted stock units, performance stock units and other cash and stock-based awards. A total of 22.95 million shares of common stock may be issued under the 2023 Plan. The 2023 Plan expires on February 21, 2033. No additional awards may be granted under the Prior Cabot Plan or the Prior Cimarex Plan on or after May 4, 2023. Awards outstanding under any of the Company’s prior plans will remain outstanding and vest in accordance with their original terms and conditions.

Restricted Stock Units - Employees

During the six months ended June 30, 2023, the Company granted 666,303 restricted stock units to employees of the Company with a weighted average grant date value of $23.00 per unit. The fair value of restricted stock unit grants is based on the closing stock price on the grant date. Restricted stock units generally vest either at the end of a three-year service period or on a graded or graduated vesting basis at each anniversary date over a three-year service period. The Company used an annual forfeiture rate assumption of zero to five percent for purposes of recognizing stock-based compensation expense for its restricted stock units. The annual forfeiture rate assumption was based on the Company’s actual forfeiture history or expectations for this type of award.

Restricted Stock Units - Non-Employees Directors

In June 2023, the Company granted 73,593 restricted stock units, with a weighted-average grant date value of $24.46 per unit, to the Company’s non-employee directors. The fair value of these units is measured based on the closing stock price on grant date. These units will vest in May 2024 and the Company will recognize compensation expense ratably over the vesting period.

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

Performance Share Awards

Total Shareholder Return (“TSR”) Performance Share Awards. During the six months ended June 30, 2023, the Company granted 577,172 TSR Performance Share Awards, which are earned, or not earned, based on the comparative

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performance of the Company’s common stock measured against a predetermined group of companies in the Company’s peer group and certain industry-related indices over a three-year performance period, which commenced on February 1, 2023 and ends on January 31, 2026.

These awards have both an equity and liability component, with the right to receive up to the first 100 percent of the award in shares of common stock and the right to receive up to an additional 100 percent of the value of the award in excess of the equity component in cash. These awards also include a feature that will reduce the potential cash component of the award if the actual performance is negative over the three-year period and the base calculation indicates an above-target payout. The equity portion of these awards is valued on the grant date and is not marked to market, while the liability portion of the awards is valued as of the end of each reporting period on a mark-to-market basis. The Company calculates the fair value of the equity and liability portions of the awards using a Monte Carlo simulation model.

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

The following assumptions were used to determine the grant date fair value of the equity component on February 21, 2023 and the period-end fair value of the liability component of the TSR Performance Share Awards:


	Grant Date			June 30, 2023
Fair value per performance share award	$	17.18		$11.36 - $12.63
Assumptions:
Stock price volatility	44.8		%	40.9% - 42.6%
Risk-free rate of return	4.40		%	4.59% - 5.02%

11. Earnings per Common Share

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

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


	Three Months Ended June 30,				Six Months Ended June 30,
(In millions, except per share amounts)	2023		2022		2023		2022

Income (Numerator)
Net income	$	209	$	1,229	$	886	$	1,837
Less: dividends attributable to participating securities	(1)		(1)		(3)		(3)
Less: Cimarex redeemable preferred stock dividends	—		—		—		(1)
Net income available to common stockholders	$	208	$	1,228	$	883	$	1,833

Shares (Denominator)
Weighted average shares - Basic	755		803		760		806
Dilution effect of stock awards at end of period	5		5		4		3
Weighted average shares - Diluted	760		808		764		809

Earnings per share:
Basic	$	0.28	$	1.53	$	1.16	$	2.28
Diluted	$	0.27	$	1.52	$	1.16	$	2.27

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


	Three Months Ended June 30,		Six Months Ended June 30,
(In millions)	2023	2022	2023	2022

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

12. Restructuring Costs

Restructuring costs are primarily related to workforce reductions and associated severance benefits that were triggered by the merger with Cimarex Energy Co. that closed on October 1, 2021. The following table summarizes the Company’s restructuring liabilities:


	Six Months Ended June 30,
(In millions)	2023		2022
Balance at beginning of period	$	77	$	43
Additions related to merger integration	11		33
Payments of merger-related restructuring costs	(18)		(7)
Balance at end of period	$	70	$	69

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13. Additional Balance Sheet Information

Certain balance sheet amounts are comprised of the following:


(In millions)	June 30, 2023		December 31, 2022
Accounts receivable, net
Trade accounts	$	434	$	1,067
Joint interest accounts	169		108
Other accounts	3		48
	606		1,223
Allowance for credit losses	(2)		(2)
	$	604	$	1,221













Other assets
Deferred compensation plan	$	47	$	43
Debt issuance costs	9		3

Operating lease right-of-use assets	357		382


Other accounts	25		36
	$	438	$	464
Accounts payable
Trade accounts	$	75	$	27

Royalty and other owners	208		438
Accrued transportation	77		85
Accrued capital costs	180		148
Taxes other than income	5		73
Accrued lease operating costs	41		32


Other accounts	40		41
	$	626	$	844
Accrued liabilities
Employee benefits	$	37	$	74
Taxes other than income	48		62
Restructuring liability	41		39

Operating lease liabilities	115		114
Financing lease liabilities	6		6

Other accounts	47		33
	$	294	$	328
Other liabilities
Deferred compensation plan	$	47	$	55
Postretirement benefits	16		17

Operating lease liabilities	260		287
Financing lease liabilities	9		11
Restructuring liability	29		38
Other accounts	95		92
	$	456	$	500

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14. Interest Expense

Interest expense is comprised of the following:


	Three Months Ended June 30,				Six Months Ended June 30,
(In millions)	2023		2022		2023		2022
Interest Expense
Interest expense	$	21	$	27	$	41	57
Debt premium amortization	(6)		(8)		(11)		(19)
Debt financing costs	1		1		2		2
Other	—		2		1		3
	$	16	$	22	$	33	$	43

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ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following review of operations of Coterra Energy Inc. (“Coterra,” “our,” “we” and “us”) for the three and six month periods ended June 30, 2023 and 2022 should be read in conjunction with our Condensed Consolidated Financial Statements and the Notes included in this Quarterly Report on Form 10-Q (this “Form 10-Q”) and with the Consolidated Financial Statements, Notes and Management’s Discussion and Analysis included in our Annual Report on Form 10-K for the year ended December 31, 2022 (our “Form 10-K”).

OVERVIEW

Financial and Operating Overview

Financial and operating results for the six months ended June 30, 2023 compared to the six months ended June 30, 2022 reflect the following:

•Equivalent production increased 3.5 MMBoe from 114.2 MMBoe, or 630.8 MBoepd, in 2022 to 117.7 MMBoe, or 650.1 MBoepd in 2023. The increase was attributable to higher production in the Permian and Anadarko Basins due to the timing and productivity of our 2023 drilling and completion activities.

•Natural gas production increased 2.1 Bcf from 510.3 Bcf, or 2,819 Mmcf per day, in 2022 to 512.4 Bcf, or 2,831 Mmcf per day, in the 2023 period. The slight increase was primarily attributable to higher production in the Anadarko Basin, partially offset by slightly lower production in the Permian Basin, both of which were due to the timing of our drilling and completion activities.

•Oil production increased 1.5 MMBbl from 15.5 MMBbl, or 85.6 MBblpd, in 2022 to 17.0 MMBbl, or 94.0 MBblpd, in 2023. The increase was attributable to higher production in the Permian Basin due to the timing and productivity of our drilling and completion activities.

•NGL volumes increased 1.6 MMBbl from 13.6 MMBbl, or 75.3 MBblpd, in 2022 to 15.2 MMBbl, or 84.2 MBblpd, in 2023. The increase was attributable to increased volumes in the Permian and Anadarko Basins due to the timing and productivity of our drilling and completion activities.

•Average realized natural gas price was $2.81 per Mcf, $1.85 lower than the $4.66 per Mcf realized in the corresponding period of the prior year.

•Average realized oil price was $73.11 per Bbl, $11.65 lower than the $84.76 per Bbl realized in the corresponding period of the prior year.

•Average realized NGL price was $20.11 per Bbl, $18.44 lower than the $38.55 per Bbl realized in the corresponding period of the prior year.

•Total capital expenditures for drilling, completion and other fixed assets were $1.1 billion compared to $794 million in the corresponding period of the prior year. The increase was driven by higher planned completion activity levels across our operations and higher costs.

•Drilled 125 gross wells (82.3 net) with a success rate of 100 percent compared to 127 gross wells (88.3 net) with a success rate of 100 percent for the corresponding period of the prior year.

•Turned in line 131 gross wells (87.3 net) in 2023 compared to 105 gross wells (57.0 net) in the corresponding period of 2022.

•Average rig count during the first six months of 2023 was approximately 6.0, 3.0 and 1.5 rigs in the Permian Basin, Marcellus Shale and Anadarko Basin, respectively, compared to an average rig count of approximately 6.3, 2.8 and 1.7 rigs in the Permian Basin, Marcellus Shale and Anadarko Basin, respectively, during the corresponding period of 2022.

•Increased our quarterly base dividend from $0.15 per share for regular quarterly dividends in 2022 to $0.20 per share as part of our returns-focused strategy.

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•Implemented our new $2.0 billion share repurchase program and repurchased 13 million shares for $328 million during the six months ended June 30, 2023. We repurchased 20 million shares for $513 million during the six months ended June 30, 2022 under our previous share repurchase program.

Market Conditions and Commodity Prices

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

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

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

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

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

Inflation

Certain of our capital expenditures and expenses are affected by general inflation. We are beginning to see inflation moderating as we move into the second half of 2023; however, costs in 2023 still exceed 2022 costs. While rising inflation is typically offset by the higher prices at which we are able to realize on sales of our commodity production, we nevertheless expect to see inflation impact our cost structure for the remainder of 2023, albeit at a more moderate pace compared to 2022.

Recent U.S. Tax Legislation

On August 16, 2022, the Inflation Reduction Act (“IRA”) was signed into law pursuant to the budget reconciliation process. The IRA introduced a new 15 percent corporate alternative minimum tax (“CAMT”), effective for tax years beginning after December 31, 2022, on the adjusted financial statement income (“AFSI”) of corporations with average AFSI exceeding $1 billion over a three-year testing period. The IRA also introduced an excise tax of one percent on the fair market value of certain public company stock repurchases made after December 31, 2022. Based on the current CAMT guidance available, we will be an “applicable corporation” beginning in 2023, but are not currently expecting to owe any additional tax under the CAMT in 2023.

Outlook

Our 2023 full year capital program is expected to be approximately $2.0 billion to $2.2 billion. We expect to fund these capital expenditures with our operating cash flow. We expect to turn-in-line 152 to 165 total net wells in 2023 across our three

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operating regions. Approximately 48 percent of our drilling and completion capital is expected to be invested in the Permian Basin, 43 percent in the Marcellus Shale and the remaining balance in the Anadarko Basin.

In 2022, we drilled 285 gross wells (174.6 net) and turned in line 251 gross wells (148.1 net). For the six months ended June 30, 2023, our capital program focused on the Permian Basin, Marcellus Shale and Anadarko Basin, where we drilled 82.3 net wells and turned in line 87.3 net wells. Our capital program for the remainder of 2023 will focus on execution of our 2023 plan. We allocate our planned program for capital expenditures based on market conditions, return on capital and free cash flow expectations and availability of services and human resources. We will continue to assess the oil and natural gas price environment and may adjust our capital expenditures accordingly.

FINANCIAL CONDITION

Liquidity and Capital Resources

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

Our primary sources of liquidity are cash on hand, net cash provided by operating activities and available borrowing capacity under our revolving credit agreement. Our liquidity requirements are generally funded with cash flows provided by operating activities, together with cash on hand. However, from time to time, our investments may be funded by bank borrowings (including draws on our revolving credit agreement), sales of non-strategic assets, and private or public financing based on our monitoring of capital markets and our balance sheet. Our debt is currently rated as investment grade by the three leading rating agencies, and there are no “rating triggers” in any of our debt agreements that would accelerate the scheduled maturities should our debt rating fall below a certain level. In determining our debt ratings, the agencies consider a number of qualitative and quantitative items including, but not limited to, current commodity prices, our liquidity position, our asset quality and reserve mix, debt levels, cost structure and growth plans. Credit ratings are not recommendations to buy, sell, or hold securities and may be subject to revision or withdrawal at any time by the assigning rating agency. A change in our debt rating could impact our interest rate on any borrowings under our revolving credit agreement and our ability to economically access debt markets in the future and could trigger the requirement to post credit support under various agreements, which could reduce the borrowing capacity under our revolving credit agreement. We believe that, with operating cash flow, cash on hand and availability under our revolving credit agreement, we have the ability to finance our spending plans over the next 12 months and, based on current expectations, for the longer term.

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

Our working capital is substantially influenced by the variables discussed above and fluctuates based on the timing and amount of borrowings and repayments under our revolving credit agreement, repayments of debt, the timing of cash collections and payments on our trade accounts receivable and payable, respectively, payment of dividends, repurchases of our securities and changes in the fair value of our commodity derivative activity. From time to time, our working capital will reflect a deficit, while at other times it will reflect a surplus. This fluctuation is not unusual. At June 30, 2023 and December 31, 2022, we had a working capital surplus of $699 million and $1.0 billion, respectively. We believe we have adequate liquidity and availability as outlined above to meet our working capital requirements over the next 12 months.

As of June 30, 2023, we had no borrowings outstanding under our revolving credit agreement, our unused commitments were $1.5 billion and we had unrestricted cash on hand of $841 million.

Our revolving credit agreement includes a covenant limiting our borrowing capacity based on our leverage ratio. At June 30, 2023, we were in compliance with all financial and other covenants applicable to our revolving credit facility and senior notes. Refer to Note 3 of the Notes to the Condensed Consolidated Financial Statements, “Debt and Credit Agreements,” for further details regarding our revolving credit agreement.

Our investments are generally funded with cash flow provided by operating activities together with cash on hand, bank borrowings, sales of non-strategic assets, and, from time to time, private or public financing based on our monitoring of capital markets and our balance sheet. We also may use a combination of these sources of funds to refinance or retire our outstanding debt through privately negotiated transactions, open market repurchases, redemptions, exchanges, tender offers or otherwise, but we have no obligation to do so.

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Cash Flows

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


	Six Months Ended June 30,
(In millions)	2023		2022
Cash flows provided by operating activities	$	2,140	$	2,201
Cash flows used in investing activities	(1,048)		(741)
Cash flows used in financing activities	(925)		(1,437)
Net increase in cash, cash equivalents and restricted cash	$	167	$	23

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

Net cash provided by operating activities for the six months ended June 30, 2023 decreased by $61 million compared to the same period in 2022. This decrease was primarily due to the decrease in natural gas, oil and NGL revenue resulting primarily from lower commodity prices. This decrease was partially offset by higher cash received on derivative settlements and a larger contribution from changes in working capital and other assets and liabilities.

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

Investing Activities. Cash flows used in investing activities increased by $307 million for the six months ended June 30, 2023 compared to the six months ended June 30, 2022. The increase was primarily due to $336 million of higher capital expenditures due to our increased capital budget for 2023. This increase was partially offset by higher proceeds from the sale of assets of $29 million.

Financing Activities. Cash flows used in financing activities decreased by $512 million for the six months ended June 30, 2023 compared to the six months ended June 30, 2022. The decrease in cash flows used in financing activities was primarily due to lower dividend payments of $352 million as a result of a decrease in our base-plus-variable dividend rate from $1.16 per common share for the six months ended June 30, 2022 compared to $0.77 per common share for the six months ended June 30, 2023, and a decrease in outstanding shares of common stock due to our share repurchase programs during the last six months of 2022 and the first six months of 2023. The decrease in cash flows used in financing activities was also due to a decrease in common stock repurchases of $162 million during the six months ended June 30, 2023 compared to the six months ended June 30, 2022.

Capitalization

Information about our capitalization is as follows:


(In millions)	June 30, 2023			December 31, 2022
Debt (1)	$	2,171		$	2,181
Stockholders' equity	12,659			12,659
Total capitalization	$	14,830		$	14,840
Debt to total capitalization	15		%	15		%
Cash and cash equivalents	$	841		$	673

________________________________________________________

(1)There were no borrowings outstanding under our revolving credit agreement as of June 30, 2023 and December 31, 2022.

Share repurchases. In February 2023, our Board of Directors approved a share repurchase program which authorizes the purchase of up to $2.0 billion of our common stock in the open market or in negotiated transactions.

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During the six months ended June 30, 2023 and 2022, we repurchased 13 million shares of our common stock for $328 million under our new share repurchase program and 20 million shares of our common stock for $513 million under our previous share repurchase program, respectively.

Dividends. In February 2023, our Board of Directors approved an increase in the base quarterly dividend from $0.15 per share to $0.20 per share.

The following table summarizes our dividends on our common stock for each quarter in 2023 and 2022.


	Rate Per Share
	Fixed		Variable		Total		Total Dividends (In millions)
2023
First quarter	$	0.20	$	0.37	$	0.57	$	438
Second quarter	$	0.20	—		0.20		$	153


Total year-to-date	$	0.40	$	0.37	$	0.77	$	591
2022
First quarter	$	0.15	$	0.41	$	0.56	$	455
Second quarter	0.15		0.45		0.60		$	484


Total	$	0.30	$	0.86	$	1.16	$	939

Capital and Exploration Expenditures

On an annual basis, we generally fund most of our capital expenditures with cash flow provided by operating activities, and, if required, cash on hand and borrowings under our revolving credit agreement. We budget these expenditures based on our projected cash flows for the year.

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


	Six Months Ended June 30,
(In millions)	2023		2022
Capital expenditures:
Drilling and facilities	$	1,023	$	754

Pipeline and gathering	66		27
Other	16		13

Capital expenditures for drilling, completion and other fixed asset additions	1,105		794
Capital expenditures for leasehold and property acquisitions	6		4
Exploration expenditures(1)	9		13
	$	1,120	$	811

________________________________________________________

(1)There were no exploratory dry hole costs for the six months ended June 30, 2023 and 2022.

For the six months ended June 30, 2023, our capital program was focused on the Permian Basin, Marcellus Shale and Anadarko Basin, where we drilled 82.3 net wells and turned in line 87.3 net wells. We continue to expect that our full-year 2023 capital program will be approximately $2.0 billion to $2.2 billion. Refer to “Outlook” for additional information regarding the current year drilling program. We will continue to assess the commodity price environment and may adjust our capital expenditures accordingly.

Contractual Obligations

We have various contractual obligations in the normal course of our operations. There have been no material changes to our contractual obligations described under “Transportation, Processing and Gathering Agreements” and “Lease Commitments” as disclosed in Note 8 of the Notes to the Consolidated Financial Statements and the obligations described under “Contractual Obligations” in Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in our Form 10-K.

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Critical Accounting Policies and Estimates

Our discussion and analysis of our financial condition and results of operations are based on our Condensed Consolidated Financial Statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. Refer to our Form 10-K for further discussion of our critical accounting policies.

RESULTS OF OPERATIONS

Second Quarters of 2023 and 2022 Compared

Operating Revenues


	Three Months Ended June 30,				Variance
(In millions)	2023		2022		Amount		Percent
Operating Revenues
Natural gas	$	436	$	1,468	$	(1,032)	(70)	%
Oil	626		876		(250)		(29)	%
NGL	129		280		(151)		(54)	%
Gain (loss) on derivative instruments	(12)		(66)		54		82	%
Other	6		14		(8)		(57)	%
	$	1,185	$	2,572	$	(1,387)	(54)	%

Production Revenues

Our production revenues are derived from sales of our oil, natural gas and NGL production. Increases or decreases in our revenues, profitability and future production growth are highly dependent on the commodity prices we receive, which we expect to fluctuate due to supply and demand factors, and the availability of transportation, seasonality and geopolitical, economic and other factors.

Natural Gas Revenues


	Three Months Ended June 30,				Variance				Increase (Decrease) (In millions)
	2023		2022		Amount		Percent
Volume variance (Bcf)	264.3		253.9		10.4		4	%	$	60
Price variance ($/Mcf)	$	1.65	$	5.78	$	(4.13)	(71)	%	(1,092)
									$	(1,032)

Natural gas revenues decreased $1.0 billion primarily due to significantly lower natural gas prices, partially offset by higher production. The increase in production was primarily related to higher production in the Marcellus Shale.

Oil Revenues


	Three Months Ended June 30,				Variance				Increase (Decrease) (In millions)
	2023		2022		Amount		Percent
Volume variance (MMBbl)	8.7		8.0		0.7		9	%	$	76
Price variance ($/Bbl)	$	71.88	$	109.23	$	(37.35)	(34)	%	(326)
									$	(250)

Oil revenues decreased $250 million due to significantly lower oil prices partially offset by higher production. The increase in production was primarily related to higher production in the Permian Basin.

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NGL Revenues


	Three Months Ended June 30,				Variance				Increase (Decrease) (In millions)
	2023		2022		Amount		Percent
Volume variance (MMBbl)	7.7		7.2		0.5		7	%	$	20
Price variance ($/Bbl)	$	16.67	$	39.17	$	(22.50)	(57)	%	(171)
									$	(151)

NGL revenues decreased $151 million primarily due to significantly lower NGL prices partially offset by higher volumes primarily in the Permian Basin.

Gain (Loss) on Derivative Instruments

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


	Three Months Ended June 30,
(In millions)	2023		2022
Cash received (paid) on settlement of derivative instruments
Gas contracts	$	82	$	(161)
Oil contracts	2		(132)
Non-cash gain (loss) on derivative instruments
Gas contracts	(96)		133
Oil contracts	—		94
	$	(12)	$	(66)

Operating Costs and Expenses

Costs associated with producing oil and natural gas are substantial. Among other factors, some of these costs vary with commodity prices, some trend with the volume and commodity mix, some are a function of the number of wells we own and operate, some depend on the prices charged by service companies, and some fluctuate based on a combination of the foregoing. Our costs for services, labor and supplies have remained high due to on-going demand for those items, and to a lesser extent rising inflation and supply chain disruptions, all of which have affected the cost of our operations throughout 2022. We currently expect these costs to level off and stabilize during 2023.

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


	Three Months Ended June 30,				Variance				Per BOE
(In millions, except per BOE)	2023		2022		Amount		Percent		2023		2022
Operating Expenses
Direct operations	$	130	$	116	$	14	12	%	$	2.16	$	2.03
Transportation, processing and gathering	258		238		20		8	%	4.27		4.13
Taxes other than income	63		98		(35)		(36)	%	1.05		1.72
Exploration	5		7		(2)		(29)	%	0.09		0.12
Depreciation, depletion and amortization	395		414		(19)		(5)	%	6.54		7.21

General and administrative	58		87		(29)		(33)	%	0.96		1.52
	$	909	$	960	$	(51)	(5)	%

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Direct Operations

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

Direct operations expense consisted of lease operating expense and workover expense as follows:


	Three Months Ended June 30,						Per BOE
(In millions, except per BOE)	2023		2022		Variance		2023		2022
Direct Operations Expense
Lease operating expense	$	102	$	94	$	8	$	1.70	$	1.65
Workover expense	28		22		6		0.46		0.38
	$	130	$	116	$	14	$	2.16	$	2.03

Lease operating expense increased primarily due to higher production levels. Additionally, lease operating expense on a per BOE basis increased due to generally higher costs of equipment and field services and increased labor costs.

Workover expense increased $6 million primarily due to an increase in workover activities related to maintenance project activities in the Marcellus Shale and Anadarko Basin resulting in an increase of $3 million and $2 million, respectively, compared to 2022 activities. Workover activity in the Permian Basin remained relatively flat period over period.

Transportation, Processing and Gathering

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

Transportation, processing and gathering costs increased $20 million primarily due to increased production and a modest increase in transportation rates in the Marcellus Shale and the Permian Basin.

Taxes Other Than Income

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

The following table presents taxes other than income for the periods indicated:


	Three Months Ended June 30,
(In millions)	2023			2022			Variance
Taxes Other than Income
Production	$	43		$	82		$	(39)
Drilling impact fees	4			8			(4)
Ad valorem	16			8			8

	$	63		$	98		$	(35)
Production taxes as percentage of revenue from Permian and Anadarko Basins	5.3		%	5.4		%

Taxes other than income decreased $35 million. Production taxes represented the majority of our taxes other than income, which decreased primarily due to lower oil, natural gas and NGL revenues. Drilling impact fees decreased primarily due to the timing of wells drilled in the Marcellus Shale and lower natural gas prices, which drive the rates assessed on our drilling activities. Ad valorem taxes increased primarily due to higher anticipated appraisal values on our Texas-based properties based on 2022 results of operations in the Permian Basin, which is expected to result in higher 2023 property assessments.

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Depreciation, Depletion and Amortization

Depreciation, depletion and amortization (“DD&A”) expense consisted of the following for the periods indicated:


	Three Months Ended June 30,						Per BOE
(In millions, except per BOE)	2023		2022		Variance		2023		2022
DD&A Expense
Depletion	$	362	$	356	$	6	$	5.98	$	6.19
Depreciation	19		16		3		0.33		0.29
Amortization of unproved properties	12		39		(27)		0.20		0.68
Accretion of ARO	2		3		(1)		0.03		0.05
	$	395	$	414	$	(19)	$	6.54	$	7.21

Depletion of our producing properties is computed on a field basis using the units-of-production method under the successful efforts method of accounting. The economic life of each producing property depends upon the estimated proved reserves for that property, which in turn depend upon the assumed realized sales price for future production. Therefore, fluctuations in oil and gas prices will impact the level of proved developed and proved reserves used in the calculation. Higher prices generally have the effect of increasing reserves, which reduces depletion expense. Conversely, lower prices generally have the effect of decreasing reserves, which increases depletion expense. The cost of replacing production also impacts our depletion expense. In addition, changes in estimates of reserve quantities, estimates of operating and future development costs, reclassifications of properties from unproved to proved and impairments of oil and gas properties will also impact depletion expense. Our depletion expense increased $6 million due to a five percent increase in equivalent production, partially offset by a lower depletion rate. The lower depletion rate was due to a lower depletion rate in the Permian Basin due to an increase in oil and gas reserves at December 31, 2022 due to favorable price revisions, partially offset by an increase in the depletion rate in the Marcellus Shale due to downward oil and gas reserve performance revisions.

Fixed assets consist primarily of gas gathering facilities, water infrastructure, buildings, vehicles, aircraft, furniture and fixtures and computer equipment and software. These items are recorded at cost and are depreciated on the straight-line method based on expected lives of the individual assets, which range from three to 30 years. Also included in our depreciation expense is the depreciation of the right-of-use asset associated with our finance lease gathering system.

Unproved properties are amortized based on our drilling experience and our expectation of converting our unproved leaseholds to proved properties. The rate of amortization depends on the timing and success of our exploration and development program. If development of unproved properties is deemed unsuccessful and the properties are abandoned or surrendered, the capitalized costs are expensed in the period the determination is made. Amortization of unproved properties decreased $27 million primarily due to a non-recurring charge related to the release of certain leaseholds that occurred during the second quarter of 2022.

General and Administrative (“G&A”)

G&A expense consists primarily of salaries and related benefits, stock-based compensation, office rent, legal and consulting fees, systems costs and other administrative costs incurred.

The table below reflects our G&A expense for the periods indicated:


	Three Months Ended June 30,
(In millions)	2023		2022		Variance
G&A Expense
General and administrative expense	$	48	$	52	$	(4)
Stock-based compensation expense	7		21		(14)
Merger-related expense	3		14		(11)
	$	58	$	87	$	(29)

G&A expense, excluding stock-based compensation and merger related expenses, decreased $4 million primarily due to lower compensation and benefits due to the ongoing reduction in transition personnel during the second quarter of 2023.

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Stock-based compensation expense will fluctuate based on the grant date fair value of awards, the number of awards, the requisite service period of the awards, estimated employee forfeitures, and the timing of the awards. Stock-based compensation expense decreased $14 million primarily due to higher stock-based compensation costs related to the accelerated vesting of employee performance shares and vesting of certain other awards during 2022 and a gain related to our deferred compensation plan associated with the liquidation of our common stock in the plan that occurred in the second quarter of 2023. These decreases were partially offset by stock-based compensation related to new shares granted in early 2023 and the second half of 2022.

Merger-related expenses decreased $11 million primarily due to lower employee-related severance and termination benefits associated with the expected termination of certain employees. We accrued for these costs over the transition period during 2022 and early 2023, with substantially all of our expected severance costs being fully accrued over that time period. Additional merger-related costs are not expected to be material for the second half of 2023.

Interest Expense

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


	Three Months Ended June 30,
(In millions)	2023		2022		Variance
Interest Expense
Interest expense	$	21	$	27	$	(6)
Debt premium amortization	(6)		(8)		2
Debt financing costs	1		1		—
Other	—		2		(2)
	$	16	$	22	$	(6)

Interest expense decreased $6 million, primarily due to the repayment of our 6.51% and 5.58% weighted-average private placement senior notes in August 2022 and the redemption of $750 million of the 4.375% senior notes in September and October 2022.

Debt premium amortization decreased $2 million primarily due to the redemption of $750 million of our 4.375% senior notes in September and October 2022.

Interest Income

Interest income increased $9 million due to higher interest rates received on higher cash balances.

Income Tax Expense


	Three Months Ended June 30,
(In millions)	2023			2022			Variance
Income Tax Expense
Current tax expense	$	57		$	294		$	(237)
Deferred tax expense	4			65			(61)
	$	61		$	359		$	(298)
Combined federal and state effective income tax rate	22.5		%	22.6		%

Income tax expense decreased $298 million due to lower pre-tax income and a slightly lower effective tax rate in the second quarter of 2023 compared to the second quarter of 2022. The effective tax rate was lower for the second quarter of 2023 compared to the second quarter of 2022 due to differences in the non-recurring discrete items recorded during the second quarter of 2023 versus the second quarter of 2022.

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First Six Months of 2023 and 2022 Compared

Operating Revenues


	Six Months Ended June 30,				Variance
(In millions)	2023		2022		Amount		Percent
Operating Revenues
Natural gas	$	1,258	$	2,579	$	(1,321)	(51)	%
Oil	1,241		1,575		(334)		(21)	%
NGL	306		525		(219)		(42)	%
Gain (loss) on derivative instruments	126		(457)		583		128	%
Other	31		29		2		7	%
	$	2,962	$	4,251	$	(1,289)	(30)	%

Production Revenues

Natural Gas Revenues


	Six Months Ended June 30,				Variance				Increase (Decrease) (In millions)
	2023		2022		Amount		Percent
Volume variance (Bcf)	512.4		510.3		2.1		—	%	$	11
Price variance ($/Mcf)	$	2.46	$	5.05	$	(2.59)	(51)	%	(1,332)
									$	(1,321)

Natural gas revenues decreased $1.3 billion primarily due to significantly lower natural gas prices, partially offset by slightly higher production. The slightly higher production is primarily due to increased production in the Anadarko Basin, partially offset by marginal decreases in the Permian Basin and Marcellus Shale production, primarily due to the timing of our drilling and completion activities.

Oil Revenues


	Six Months Ended June 30,				Variance				Increase (Decrease) (In millions)
	2023		2022		Amount		Percent
Volume variance (MMBbl)	17.0		15.5		1.5		10	%	$	152
Price variance ($/Bbl)	$	72.93	$	101.62	$	(28.69)	(28)	%	(486)
									$	(334)

Oil revenues decreased $334 million primarily due to considerably lower oil prices, partially offset by higher production. The higher production was driven by higher Permian Basin production.

NGL Revenues


	Six Months Ended June 30,				Variance				Increase (Decrease) (In millions)
	2023		2022		Amount		Percent
Volume variance (MMBbl)	15.2		13.6		1.6		12	%	$	62
Price variance ($/Bbl)	$	20.11	$	38.55	$	(18.44)	(48)	%	(281)
									$	(219)

NGL revenues decreased $219 million primarily due to significantly lower NGL prices, partially offset by higher NGL volumes. The higher volume was driven by higher Permian and Andarko Basin volumes due to the timing of our 2023 drilling and completion program.

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Gain (Loss) on Derivative Instruments

The following table presents the components of “Gain (loss) on derivative instruments” for the periods indicated:


	Six Months Ended June 30,
(In millions)	2023		2022
Cash received (paid) on settlement of derivative instruments
Gas contracts	$	181	$	(203)
Oil contracts	3		(261)
Non-cash gain (loss) on derivative instruments
Gas contracts	(54)		(49)
Oil contracts	(4)		56
	$	126	$	(457)

Operating Costs and Expenses

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


	Six Months Ended June 30,				Variance				Per BOE
(In millions, except per BOE)	2023		2022		Amount		Percent		2023		2022
Operating Expenses
Direct operations	$	264	$	216	$	48	22	%	$	2.24	$	1.90
Transportation, processing and gathering	494		471		23		5	%	4.20		4.12
Taxes other than income	149		174		(25)		(14)	%	1.27		1.53
Exploration	9		13		(4)		(31)	%	0.08		0.11
Depreciation, depletion and amortization	764		774		(10)		(1)	%	6.50		6.78

General and administrative	134		194		(60)		(31)	%	1.14		1.68
	$	1,814	$	1,842	$	(28)	(2)	%

Direct Operations

Direct operations expense consisted of lease operating expense and workover expense as follows:


	Six Months Ended June 30,						Per BOE
(In millions, except per BOE)	2023		2022		Variance		2023		2022
Direct Operations
Lease operating expense	$	208	$	176	$	32	$	1.76	$	1.55
Workover expense	56		40		16		0.48		0.35
	$	264	$	216	$	48	$	2.24	$	1.90

Lease operating expense increased on an absolute basis as a result of the increase in production levels. Additionally, lease operating expense on a per BOE basis increased due to generally higher costs of equipment and field services and increased labor costs.

Workover expense increased $16 million primarily due to an increase in workover activities related to maintenance project activities in the Permian Basin, Marcellus Shale and Anadarko Basin resulting in an increase of $6 million, $6 million and $3 million, respectively, compared to 2022 activities.

Transportation, Processing and Gathering

Transportation, processing and gathering costs increased $23 million largely due to increased production and a modest increase in transportation rates in the Marcellus Shale and the Permian Basin.

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Taxes Other Than Income

The following table presents taxes other than income for the periods indicated:


	Six Months Ended June 30,
(In millions)	2023			2022			Variance
Taxes Other than Income
Production	$	103		$	145		$	(42)
Drilling impact fees	13			15			(2)
Ad valorem	32			14			18
Other	1			—			1
	$	149		$	174		$	(25)
Production taxes as percentage of revenue from Permian and Anadarko Basins	6.0		%	5.4		%

Taxes other than income decreased $25 million. Production taxes represented the majority of our taxes other than income, which decreased primarily due to lower oil, natural gas and NGL revenues. Drilling impact fees decreased primarily due to the timing of wells drilled in the Marcellus Shale and lower natural gas prices, which drive the rates assessed on our drilling activities. Ad valorem taxes increased primarily due to higher anticipated appraisal values on our Texas-based properties based on 2022 results of operations in the Permian Basin, which is expected to result in higher 2023 property assessments.

Depreciation, Depletion and Amortization (“DD&A”)

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


	Six Months Ended June 30,						Per BOE
(In millions, except per BOE)	2023		2022		Variance		2023		2022
DD&A Expense
Depletion	$	699	$	695	$	4	$	5.94	$	6.09
Depreciation	36		35		1		0.32		0.31
Amortization of unproved properties	24		39		(15)		0.20		0.34
Accretion of ARO	5		5		—		0.04		0.04
	$	764	$	774	$	(10)	$	6.50	$	6.78

Depletion expense increased $4 million primarily due to higher production, partially offset by a two percent decrease in the depletion rate. The lower depletion rate was due to a lower depletion rate in the Permian Basin due to an increase in oil and gas reserves at December 31, 2022 due to favorable price revisions, partially offset by an increase in the depletion rate in the Marcellus Shale due to downward oil and gas reserve performance revisions.

Amortization of unproved properties decreased $15 million primarily due to a non-recurring charge related to the release of certain leaseholds that occurred during the second quarter of 2022.

General and Administrative (“G&A”)

The table below reflects our G&A expense for the periods indicated:


	Six Months Ended June 30,
(In millions)	2023		2022		Variance
G&A Expense
General and administrative expense	$	100	$	105	$	(5)
Stock-based compensation expense	23		44		(21)
Merger-related expense	11		45		(34)
	$	134	$	194	$	(60)

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G&A expense, excluding stock-based compensation and merger-related expenses, decreased $5 million primarily due to lower compensation and benefits due to the ongoing reduction in transition personnel during the first half of 2023.

Stock-based compensation expense decreased $21 million primarily due to higher stock-based compensation costs related to the accelerated vesting of employee performance shares and vesting of certain other awards during 2022 and a gain related to our deferred compensation plan associated with the liquidation of the Company stock in the plan. This decreases was partially offset by higher stock-based compensation costs related to new shares granted in first half of 2023 and second half of 2022.

Merger-related expenses decreased $34 million primarily due to lower employee-related severance and termination benefits associated with the expected termination of certain employees. We accrued for these costs over the transition period during 2022 and early 2023, with substantially all of our expected severance costs being fully accrued over that time period. Merger-related expenses also decreased due to $6 million of transaction-related costs associated with the Merger that were incurred in 2022. Additional merger-related costs are not expected to be material for the second half of 2023.

Interest Expense

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


	Six Months Ended June 30,
(In millions)	2023		2022		Variance
Interest Expense
Interest expense	$	41	$	57	$	(16)
Debt premium amortization	(11)		(19)		8
Debt financing costs	2		2		—
Other	1		3		(2)
	$	33	$	43	$	(10)

Interest expense decreased $16 million primarily due to the repayment of our 6.51% and 5.58% weighted-average private placement senior notes in August 2022 and the redemption of $750 million of the 4.375% senior notes in September and October 2022.

Debt premium amortization decreased $8 million primarily due to the redemption of $750 million of the 4.375% senior notes in September and October 2022.

Interest Income

Interest income increased $21 million due to higher interest rates received on higher cash balances.

Income Tax Expense


	Six Months Ended June 30,
(In millions)	2023			2022			Variance
Income Tax Expense
Current tax expense	$	229		$	428		$	(199)
Deferred tax expense	27			101			(74)
	$	256		$	529		$	(273)
Combined federal and state effective income tax rate	22.4		%	22.4		%

Income tax expense decreased $273 million due to lower pre-tax income.

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, 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, timing and amount of capital expenditures and other statements that are not historical facts contained in or incorporated by reference into this report, are forward-looking statements. The words

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“expect,” “project,” “estimate,” “believe,” “anticipate,” “intend,” “budget,” “plan,” “forecast,” “target,” “predict,” “potential,” “possible,” “may,” “should,” “could,” “would,” “will,” “strategy,” “outlook” and similar expressions are also intended to identify forward-looking statements. We can provide no assurance that the forward-looking statements contained in this report will occur as expected, and actual results may differ materially from those included in this report. Forward-looking statements are based on current expectations and assumptions that involve a number of risks and uncertainties that could cause actual results to differ materially from those included in this report. These risks and uncertainties include, without limitation, the impact of public health crises, including pandemics (such as the coronavirus pandemic) and epidemics and any related company or governmental policies of actions, the risk that our and Cimarex’s businesses will not be integrated successfully, the risk that the cost savings and any other synergies from the Merger involving Cimarex may not be fully realized or may take longer to realize than expected, the availability of cash on hand and other sources of liquidity to fund our capital expenditures, actions by, or disputes among or between, members of OPEC+, market factors, market prices (including geographic basis differentials) of oil and natural gas, impacts of inflation, labor shortages and economic disruption, including as a result of instability in the banking sector, pandemics and geopolitical disruptions such as the war in Ukraine, results of future drilling and marketing activities, future production and costs, legislative and regulatory initiatives, electronic, cyber or physical security breaches and other factors detailed herein and in our other Securities and Exchange Commission (“SEC”) filings. Refer to “Risk Factors” in Item 1A of Part I of our 10-K for additional information about these risks and uncertainties. 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.

ITEM 3. Quantitative and Qualitative Disclosures about Market Risk

In the normal course of business, we are subject to a variety of risks, including market risks associated with changes in commodity prices and interest rate movements on outstanding debt. The following quantitative and qualitative information is provided about financial instruments to which we were party to as of June 30, 2023 and from which we may incur future gains or losses from changes in commodity prices or interest rates.

Commodity Price Risk

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

Derivative Instruments and Risk Management Activities

Our risk management strategy is designed to reduce the risk of commodity price volatility for our production in the oil and natural gas markets through the use of financial commodity derivatives. A committee that consists of members of senior management oversees our risk management activities. Our financial commodity derivatives generally cover a portion of our production and, while protecting us in the event of price declines, limit the benefit to us in the event of price increases. Further, if any of our counterparties defaulted, this protection might be limited as we might not receive the full benefit of our financial commodity derivatives. Please read the discussion below as well as Note 5 of the Notes to the Consolidated Financial Statements in our Form 10-K for a more detailed discussion of our derivatives.

Periodically, we enter into financial commodity derivatives, including collar, swap and basis swap agreements, to protect against exposure to commodity price declines related to our oil and natural gas production. All of our financial derivatives are used for risk management purposes and are not held for trading purposes. Under the collar agreements, if the index price rises above the ceiling price, we pay the counterparty. If the index price falls below the floor price, the counterparty pays us. Under the swap agreements, we receive a fixed price on a notional quantity of natural gas in exchange for paying a variable price based on a market-based index.

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As of June 30, 2023, we had the following outstanding financial commodity derivatives:


	2023				Estimated Value at June 30, 2023 (in millions)
Natural Gas	Third Quarter		Fourth Quarter




Waha gas collars					13
Volume (MMBtu)	8,280,000		8,280,000
Weighted average floor ($/MMBtu)	$	3.03	$	3.03
Weighted average ceiling ($/MMBtu)	$	5.39	$	5.39

NYMEX collars					73
Volume (MMBtu)	32,200,000		29,150,000
Weighted average floor ($/MMBtu)	$	4.07	$	4.03
Weighted average ceiling ($/MMBtu)	$	6.78	$	6.61










					$	86


	2023					Estimated Value at June 30, 2023 (in millions)
Oil		Third Quarter		Fourth Quarter
WTI oil collars							$	3
Volume (MBbl)		920		920
Weighted average floor ($/Bbl)		$	65.00	$	65.00
Weighted average ceiling ($/Bbl)		$	89.66	$	89.66

WTI Midland oil basis swaps							(1)
Volume (MBbl)		920		920
Weighted average differential ($/Bbl)		$	1.01	$	1.01




							$	2

The amounts set forth in the tables above represent our total unrealized derivative position at June 30, 2023 and exclude the impact of non-performance risk. Non-performance risk is considered in the fair value of our derivative instruments that are recorded in our Condensed Consolidated Financial Statements and is primarily evaluated by reviewing credit default swap spreads for the various financial institutions with which we have derivative contracts, while our non-performance risk is evaluated using a market credit spread provided by several of our banks.

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

During the six months ended June 30, 2023, natural gas collars with floor prices ranging from $3.00 to $7.50 per MMBtu and ceiling prices ranging from $4.55 to $13.08 per MMBtu covered 99.2 Bcf, or 20 percent of natural gas production at a weighted-average price of $4.53 per MMBtu.

During the six months ended June 30, 2023, oil collars with floor prices ranging from $65.00 to $80.00 per Bbl and ceiling prices ranging from $89.00 to $118.30 per Bbl covered 3.6 MMBbls, or 26 percent, of oil production at a weighted-average price of $68.74 per Bbl. Oil basis swaps covered 3.6 MMBbls, or 26 percent, of oil production at a weighted-average price of $0.72 per Bbl.

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

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

Interest Rate Risk

At June 30, 2023, we had total debt of $2.2 billion (with a principal amount of $2.1 billion). All of our outstanding debt is based on fixed interest rates and, as a result, we do not have significant exposure to movements in market interest rates with respect to such debt. Our revolving credit agreement provides for variable interest rate borrowings; however, we did not have any borrowings outstanding as of June 30, 2023 and, therefore, no related exposure to interest rate risk.

Fair Value of Other Financial Instruments

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

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

The carrying amount and fair value of debt is as follow:


	June 30, 2023				December 31, 2022
(In millions)	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-term debt	$	2,171	$	1,962	$	2,181	$	1,955

ITEM 4. Controls and Procedures

As of June 30, 2023, the Company carried out an evaluation, under the supervision and with the participation of the Company’s management, including the Company’s Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures pursuant to Rules 13a-15 and 15d-15 of the Securities Exchange Act of 1934 (the Exchange Act). Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures are effective to provide reasonable assurance with respect to the recording, processing, summarizing and reporting, within the time periods specified in the Commission’s rules and forms, of information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act.

There were no changes in the Company’s internal control over financial reporting that occurred during the second quarter of 2023 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

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PART II. OTHER INFORMATION

ITEM 1. Legal Proceedings

Legal Matters

The information set forth under the heading “Legal Matters” in Note 7 of the Notes to Condensed Consolidated Financial Statements included in this Form 10-Q is incorporated by reference in response to this item.

Environmental Matters

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

In June 2023, we received a Notice of Violation and Opportunity to Confer (“NOVOC”) from the U.S. Environmental Protection Agency (“EPA”) alleging violations of the Clean Air Act, the Texas State Implementation Plan, the New Mexico State Implementation Plan and certain other state and federal regulations pertaining to facilities in Texas and New Mexico. Separately, in July 2023, we received a letter from the U.S. Department of Justice that the EPA has referred the NOVOC for civil enforcement proceedings. We have exchanged information with the EPA and are engaged in discussions aimed at resolving the allegations. At this time we are unable to predict with certainty the financial impact of the NOVOC or the timing of its resolution. However, any enforcement action related to the NOVOC will likely result in fines or penalties, or both, and corrective actions, which may increase our development costs or operating costs. We believe that any fines, penalties, or corrective actions that may result from this matter will not have a material effect on our financial position, results of operations, or cash flows.

ITEM 1A. Risk Factors

For additional information about the risk factors that affect us, see Item 1A of Part I of our Form 10-K.

ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds

Issuer Purchases of Equity Securities

Share repurchase activity during the quarter ended June 30, 2023 was as follows:


Period	Total Number of Shares Purchased (In thousands)	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (In thousands) (1)	Maximum Approximate Dollar Value of Shares That May Yet Be Purchased Under the Plans or Programs (In millions)
April 2023	—	$	—	—	$	—
May 2023	—	$	—	—	$	—
June 2023	2,421	$	23.55	2,421	$	1,675
Total	2,421			2,421

________________________________________________________

(1)In February 2023, our Board of Directors approved a new share repurchase program which authorizes us to purchase up to $2.0 billion of our common stock.

ITEM 5. Other Information

Amended and Restated Bylaws

On August 4, 2023, the Board of Directors of the Company amended and restated the Company’s Amended and Restated Bylaws (as so amended and restated, the “Amended and Restated Bylaws”), which became effective immediately. The Amended and Restated Bylaws consolidate prior amendments, enhance clarity and effect technical and administrative changes to reflect recent amendments to the Delaware General Corporation Law (the “DGCL”) and Rule 14a-19 promulgated under the

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Exchange Act (the “Universal Proxy Rules”). The amendments effected by the Amended and Restated Bylaws, among other things:

•provide that business transacted at a special meeting of stockholders is limited to the matters set forth in the notice of meeting;

•require that any stockholder submitting a director nomination notice make a representation as to whether such stockholder intends to comply with the Universal Proxy Rules and provide that, if any such stockholder does not comply with the requirements thereof, such nomination shall be disregarded;

•modify the procedures and disclosure requirements set forth in the advance notice bylaw provisions, including (i) to limit the number of nominees a stockholder may nominate for election at a meeting to the number of directors to be elected at such meeting and (ii) to require additional information, representations and disclosures from proposing stockholders, proposed nominees and other persons related to a stockholder’s solicitation of proxies;

•require that a stockholder directly or indirectly soliciting proxies from other stockholders use a proxy card color other than white;

•modify certain provisions, including, without limitation, those relating to adjournment procedures and the availability of lists of stockholders entitled to vote at stockholder meetings, in each case to conform to recent amendments to the DGCL;

•provide for mandatory indemnification and advancement of expenses for the Company’s directors, officers and employees; and

•incorporate certain ministerial and conforming changes to provide clarification and consistency.

The foregoing summary of the Amended and Restated Bylaws does not purport to be a complete description and is qualified in its entirety by reference to the full text of the Amended and Restated Bylaws, a copy of which is filed as Exhibit 3.2 to this filing and incorporated herein by reference.

Certain Equity Awards to Mr Stephen P. Bell

On August 4, 2023, the Company and Stephen P. Bell entered into a letter agreement to memorialize the parties’ agreement regarding the terms of Mr. Bell’s annual long-term incentive awards for each of calendar years 2024 and 2025 and certain of his rights, benefits and entitlements under that certain Severance Compensation Agreement dated as of March 9, 2020 between Mr. Bell and Cimarex (the obligations of which were assumed by the Company on October 1, 2021 in connection with the Merger) (as amended from time to time, the “SPB Severance Agreement”).

In consideration for Mr. Bell’s waiver of the right to assert good reason under the SPB Severance Agreement, the Company agreed to grant to Mr. Bell annual long-term incentive awards with a target annual grant date fair value of $4.5 million during each of calendar years 2024 and 2025 (collectively, the “Annual LTI Awards”), subject to his continued employment with the Company through the applicable grant date. The Annual LTI Awards will be granted in the ordinary course and on the same terms as the annual long-term incentive awards granted to similarly situated executive officers at the applicable grant date. In the unfortunate event of Mr. Bell’s death prior to the date the 2024 Annual LTI Award is granted, the Company will pay to Mr. Bell’s estate a lump sum cash payment of $4.5 million (less applicable taxes) and the right to receive the Annual LTI Awards will be forfeited.

The foregoing description of the letter agreement and the actions contemplated thereby is not complete and is subject to and qualified in its entirety by reference to the full text of the letter agreement, a copy of which is filed as Exhibit 10.4 to this Quarterly Report on Form 10-Q and the terms of which are incorporated herein by reference.

The terms of the SPB Severance Agreement are further described on pages 42 and 58 of the Company’s Definitive Proxy Statement filed with the SEC on March 20, 2023, which description is incorporated herein by reference.

Certain Equity Awards of Mr. Christopher H. Clason

On June 15, 2023 the Company announced that Christopher H. Clason, the Company’s former Senior Vice President and Chief Human Resources Officer, was separating from the Company for good reason under that certain Severance Compensation Agreement dated as of March 9, 2020 between Mr. Clason and Cimarex (the obligations of which were assumed by the Company on October 1, 2021 in connection with the Merger) (as amended from time to time, the “CHC Severance Agreement”) and retiring effective September 30, 2023.

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Following a review of compensation received by similarly situated executive officers who separated from the Company following the Merger and in recognition of the continuity provided by Mr. Clason’s service since the Merger, in addition to Mr. Clason’s rights, benefits and entitlements under the CHC Severance Agreement, on August 3, 2023 the Company approved certain enhanced vesting rights with respect to each of Mr. Clason’s outstanding equity awards. In exchange for such enhanced vesting, Mr. Clason has agreed to complete certain transition services prior to his separation from the Company and to enter into and to comply with a satisfactory separation agreement and release containing non-competition, non-solicitation and confidentiality provisions.

In addition to the pro-rata vesting that will occur in connection with Mr. Clason’s retirement following his resignation for good reason, the equity awards granted to Mr. Clason prior to February 21, 2023 that would have otherwise been forfeited will remain outstanding and be eligible to vest, if at all, in accordance with the original vesting schedule and subject to the satisfaction of any performance criteria, as if Mr. Clason had remained in continuous employment with the Company through the original vesting date of such awards.

Further, 70 percent of Mr. Clason’s equity awards granted on February 21, 2023 will remain outstanding and be eligible to vest, if at all, in accordance with the original vesting schedule and subject to satisfaction of any performance criteria as if Mr. Clason had remained in continuous employment with the Company through the original vesting date of such awards, with only 30 percent being forfeited in connection with Mr. Clason’s retirement.

The terms of the CHC Severance Agreement are further described on pages 42 and 58 of the Company’s Definitive Proxy Statement filed with the SEC on March 20, 2023, which description is incorporated herein by reference.

Trading Plan Arrangements

During the three months ended June 30, 2023, no director or officer of the Company adopted or terminated a “Rule10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408 of Regulation S-K.

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ITEM 6. Exhibits

Index to Exhibits


Exhibit Number						Description

3.1						Restated Certificate of Incorporation of Coterra Energy Inc. (incorporated herein by reference to Exhibit 3.3 of Coterra's Current Report on Form 8-K filed with the SEC on October 1, 2021).

3.2						Amended and Restated Bylaws of Coterra Energy Inc.

4.1						Certificate of Designations to 8 1⁄8% Series A Cumulative Perpetual Convertible Preferred Stock of Cimarex Energy Co. (incorporated herein by reference to Exhibit 4.3 of Coterra’s Annual Report on Form 10-K filed with the SEC on March 1, 2022).

4.2						Amendment to Certificate of Designations to 8 1/8% Series A Cumulative Perpetual Convertible Preferred Stock of Cimarex Energy Co. (incorporated herein by reference to Exhibit 4.4 of Coterra’s Annual Report on Form 10-K filed with the SEC on March 1, 2022).

4.3						Amendment to Certificate of Designations to 8 1/8% Series A Cumulative Perpetual Convertible Preferred Stock of Cimarex Energy Co. (incorporated herein by reference to Exhibit 4.3 of Coterra’s Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2022).

10.1*						Coterra Energy Inc. 2023 Equity Incentive Plan (incorporated herein by reference to Exhibit 10.1 of Coterra’s Current Report on Form 8-K filed with the SEC on May 4, 2023).
						(a) Form of Non-Employee Director Restricted Stock Unit Award Agreement (incorporated herein by reference to Exhibit 10.2(a) of Coterra ’s Current Report on Form 8-K filed with the SEC on May 4, 2023);
						(b) Form of Restricted Stock Unit Award Agreement (incorporated herein by reference to Exhibit 10.2(b ) of Coterra’s Current Report on Form 8-K filed with the SEC on May 4, 2023);
						(c) Form of Performance Stock Unit Award Agreement (incorporated herein by reference to Exhibit 10.2(c ) of Coterra’s Current Report on Form 8-K filed with the SEC on May 4, 2023);

10.2*						Non-Employee Director Deferred Compensation Plan effective May 4, 2023 (incorporated herein by reference to Exhibit 10.3 of Coterra's Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2023).
						(a) Form of Non-Employee Director Deferred Restricted Stock Unit Award Agreement (Annual Fees) (incorporated herein by reference to Exhibit 10.3 (a) of Coterra's Quarterly Report on 10-Q for the fiscal quarter ended March 31, 2023);
						(b) Form of Non-Employee Director Deferred Restricted Stock Unit Award Agreement (Annual RSU Grant) (incorporated herein by reference to Exhibit 10.3 (b) of Coterra's Quarterly Report on 10-Q for the fiscal quarter ended March 31, 2023).

10.3*						Form of Executive Severance Compensation Agreement between Coterra Energy Inc. and certain officers (incorporated herein by reference to Exhibit 10.4 of Coterra's Current Report on Form 10-Q for the fiscal quarter ended March 31, 2023).

10.4*						Letter Agreement with Stephen P. Bell

31.1						302 Certification — Chairman, President and Chief Executive Officer.

31.2						302 Certification — Executive Vice President and Chief Financial Officer.

32.1						906 Certification.

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Exhibit Number						Description
101.INS						Inline XBRL Instance Document. The instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.

101.SCH						Inline XBRL Taxonomy Extension Schema Document.

101.CAL						Inline XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF						Inline XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB						Inline XBRL Taxonomy Extension Label Linkbase Document.

101.PRE						Inline XBRL Taxonomy Extension Presentation Linkbase Document.

104						Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).

_______________________________________________________________________________.

*Compensatory plan, contract or arrangement.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


	COTERRA ENERGY INC.
	(Registrant)

August 8, 2023	By:	/s/ THOMAS E. JORDEN
		Thomas E. Jorden
		Chairman, Chief Executive Officer and President
		(Principal Executive Officer)

August 8, 2023	By:	/s/ SHANNON E. YOUNG III
		Shannon E. Young III
		Executive Vice President and Chief Financial Officer
		(Principal Financial Officer)

August 8, 2023	By:	/s/ TODD M. ROEMER
		Todd M. Roemer
		Vice President and Chief Accounting Officer
		(Principal Accounting Officer)