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, 2025

OR

☐       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 July 31, 2025, there were 763,139,972 shares of common stock, par value $0.10 per share, outstanding.

COTERRA ENERGY INC.

TABLE OF CONTENTS

		Page
Part I. Financial Information
Item 1.	Financial Statements
Condensed Consolidated Balance Sheet (Unaudited) as of June 30, 2025 and December 31, 2024		3
Condensed Consolidated Statement of Operations (Unaudited) for the Three and Six Months Ended June 30, 2025 and 2024		4
Condensed Consolidated Statement of Cash Flows (Unaudited) for the Six Months Ended June 30, 2025 and 2024		5
Condensed Consolidated Statement of Stockholders’ Equity (Unaudited) for the Three and Six Months Ended June 30, 2025 and 2024		6
Notes to the Condensed Consolidated Financial Statements (Unaudited)		7
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	22
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	39
Item 4.	Controls and Procedures	41
Part II. Other Information
Item 1.	Legal Proceedings	43
Item 1A.	Risk Factors	43
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	43
Item 5.	Other Information	43
Item 6.	Exhibits	45
Signatures		46

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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, 2025		December 31, 2024
ASSETS
Current assets
Cash and cash equivalents	$	192	$	2,038
Restricted cash	24		239
Accounts receivable, net	1,051		951
Income taxes receivable	85		20
Inventories	57		46
Other current assets	113		27
Total current assets	1,522		3,321
Properties and equipment, net (Successful efforts method)	22,097		17,890
Other assets	363		414
	$	23,982	$	21,625
LIABILITIES, REDEEMABLE PREFERRED STOCK AND STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	1,081	$	833
Accrued liabilities	201		276
Interest payable	70		27
Total current liabilities	1,352		1,136
Long-term debt	4,175		3,535
Deferred income taxes	3,331		3,274
Asset retirement obligations	316		291
Other liabilities	244		259
Total liabilities	9,418		8,495
Commitments and contingencies (Note 8)
Redeemable preferred stock	8		8
Stockholders’ equity
Common stock:
Authorized — 1,800 shares of $0.10 par value in 2025 and 2024
Issued — 763 shares and 735 shares in 2025 and 2024, respectively	76		74
Additional paid-in capital	7,920		7,179
Retained earnings	6,544		5,857
Accumulated other comprehensive income	16		12
Total stockholders' equity	14,556		13,122
	$	23,982	$	21,625

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)	2025		2024		2025		2024
OPERATING REVENUES
Oil	$	888	$	774	$	1,774	$	1,475
Natural gas	601		319		1,499		857
NGL	219		176		425		349
Gain (loss) on derivative instruments	232		(16)		120		(16)
Other	25		18		51		39
	1,965		1,271		3,869		2,704
OPERATING EXPENSES
Direct operations	236		160		452		316
Gathering, processing and transportation	271		242		553		492
Taxes other than income	87		54		183		128
Exploration	4		5		14		10
Depreciation, depletion and amortization	579		447		1,085		879
General and administrative	84		68		176		143
	1,261		976		2,463		1,968
Gain on sale of assets	4		1		4		—
INCOME FROM OPERATIONS	708		296		1,410		736
Interest expense	53		34		106		53
Interest income	(2)		(19)		(10)		(35)
Other income	(1)		—		(1)		—
Income before income taxes	658		281		1,315		718
Income tax expense	147		61		288		146
NET INCOME	$	511	$	220	$	1,027	$	572
Earnings per share
Basic	$	0.67	$	0.30	$	1.35	$	0.77
Diluted	$	0.67	$	0.29	$	1.35	$	0.76
Weighted-average common shares outstanding
Basic	763		742		759		746
Diluted	767		748		762		752

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)	2025		2024
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	1,027	$	572
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	1,085		879
Deferred income tax expense (benefit)	61		(23)
Gain on sale of assets	(4)		—
(Gain) loss on derivatives	(120)		16
Net cash received on settlement of derivative instruments	13		62
Amortization of debt premium, discount and debt issuance costs, net	(9)		(9)
Stock-based compensation and other	30		25
Changes in assets and liabilities:
Accounts receivable, net	91		(14)
Income taxes	(65)		(18)
Inventories	(8)		14
Other current assets	12		(8)
Accounts payable and accrued liabilities	(97)		(17)
Interest payable	43		9
Other assets and liabilities	21		(74)
Net cash provided by operating activities	2,080		1,414
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures for drilling, completion and other fixed asset additions	(1,092)		(936)
Capital expenditures for leasehold and property acquisitions	(57)		(3)
Cash consideration paid for business combinations, net of cash received	(3,222)		—
Purchases of short-term investments	—		(250)
Proceeds from sale of assets	4		1
Other	(3)		—
Net cash used in investing activities	(4,370)		(1,188)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from issuance of debt	1,350		499
Repayments of debt	(700)		—
Common stock repurchases	(47)		(290)
Dividends paid	(346)		(314)
Tax withholding on vesting of stock awards	(24)		—
Other	(4)		(7)
Net cash provided by (used in) financing activities	229		(112)
Net (decrease) increase in cash, cash equivalents and restricted cash	(2,061)		114
Cash, cash equivalents and restricted cash, beginning of period	2,277		965
Cash, cash equivalents and restricted cash, end of period	$	216	$	1,079

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		Additional Paid-In Capital		Accumulated Other Comprehensive Income		Retained Earnings		Total
Balance at December 31, 2024	735	$	74	—	$	—	$	7,179	$	12	$	5,857	$	13,122
Net income	—	—		—	—		—		—		516		516
Issuance of common stock for acquisition	28	2		—	—		783		—		—		785
Stock amortization and vesting	2	—		—	—		(9)		—		—		(9)
Common stock repurchases	—	—		1	(24)		—		—		—		(24)
Common stock retirements	(1)	—		(1)	24		(24)		—		—		—
Cash dividends on common stock at $0.22 per share	—	—		—	—		—		—		(170)		(170)
Other comprehensive income	—	—		—	—		—		4		—		4
Balance at March 31, 2025	764	$	76	—	$	—	$	7,929	$	16	$	6,203	$	14,224
Net income	—	—		—	—		—		—		511		511
Stock amortization and vesting	—	—		—	—		14		—		—		14
Common stock repurchases	—	—		1	(23)		—		—		—		(23)
Common stock retirements	(1)	—		(1)	23		(23)		—		—		—
Cash dividends on common stock at $0.22 per share	—	—		—	—		—		—		(170)		(170)
Balance at June 30, 2025	763	$	76	—	$	—	$	7,920	$	16	$	6,544	$	14,556

(In millions, except per share amounts)	Common Shares	Common Stock Par		Treasury Shares	Treasury Stock		Additional Paid-In Capital		Accumulated Other Comprehensive Income		Retained Earnings		Total
Balance at December 31, 2023	751	$	75	—	$	—	$	7,587	$	11	$	5,366	$	13,039
Net income	—	—		—	—		—		—		352		352
Stock amortization and vesting	—	—		—	—		15		—		—		15
Common stock repurchases	—	—		6	(157)		—		—		—		(157)
Common stock retirements	(6)	—		(6)	157		(157)		—		—		—
Cash dividends on common stock at $0.21 per share	—	—		—	—		—		—		(160)		(160)
Balance at March 31, 2024	745	$	75	—	$	—	$	7,445	$	11	$	5,558	$	13,089
Net income	—	—		—	—		—		—		220		220
Exercise of stock options	—	—		—	—		1		—		—		1
Stock amortization and vesting	—	—		—	—		16		—		—		16
Common stock repurchases	—	—		5	(139)		—		—		—		(139)
Common stock retirements	(5)	(1)		(5)	139		(138)		—		—		—
Cash dividends on common stock at $0.21 per share	—	—		—	—		—		—		(158)		(158)
Balance at June 30, 2024	740	$	74	—	$	—	$	7,324	$	11	$	5,620	$	13,029

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

6

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, 2024 (the “Form 10-K”) filed with the SEC. 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, management makes 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.

Significant Accounting Policies

Segment Reporting

The Company operates in one reportable operating segment, oil and natural gas development, exploration and production. Refer to Note 1 of the Notes to the Consolidated Financial Statements in the Form 10-K for further information.

2. Acquisitions

Franklin Mountain Energy (“FME”) Acquisition

On January 27, 2025, the Company closed on its acquisition of all of the issued and outstanding equity ownership interests of a group of privately owned oil and gas exploration and production companies with assets and operations in the Delaware Basin of New Mexico (the “FME Interests”) for total consideration of $2.5 billion, which included $1.7 billion in cash and the issuance of 28,190,682 shares of the Company’s common stock valued at $785 million based on the closing price of the Company’s common stock on the closing date.

Preliminary Purchase Price Allocation

The transaction was accounted for using the acquisition method of accounting. Under the acquisition method of accounting, the assets and liabilities of the FME Interests were recorded at their respective fair values as of the effective closing date of the acquisition. The purchase price allocation is substantially complete; however, management continues to refine the preliminary valuation of certain assets acquired and liabilities assumed, and may adjust the allocation in subsequent periods. Determining the fair value of the assets and liabilities of the FME Interests requires judgment and certain assumptions to be made. The most significant fair value estimates relate to the valuation of the oil and gas properties and gathering and pipeline systems. Oil and gas properties and gathering and pipeline systems were valued using an income and market approach utilizing Level 3 inputs including internally generated production and development data and estimated price and cost estimates.

7

The following table represents the preliminary allocation of the total purchase price of the FME Interests to the identifiable assets acquired and liabilities assumed based on the fair values as of the closing date of the acquisition:

(In millions, except shares and share price)	Preliminary Purchase Price Allocation
Consideration:
Coterra common stock issued in exchange for FME equity interests	28,190,682
Coterra common stock closing price on January 27, 2025	$	27.83
Total value of Coterra common stock issued	$	785
Cash consideration (1) (2)	1,733
Total consideration	$	2,518
Assets acquired:
Current assets	$	178
Proved oil and gas properties	1,833
Unproved oil and gas properties	590
Gathering and pipeline systems	172
Other assets	6
Total assets acquired	$	2,779
Liabilities assumed:
Current liabilities	$	239
Asset retirement obligations	13
Other liabilities	9
Total liabilities assumed	$	261
Net assets acquired	$	2,518

________________________________________________________

(1)Cash consideration included the release of escrow funds in the amount of $107 million. These funds were included in restricted cash in the Condensed Consolidated Balance Sheet as of December 31, 2024.

(2)As of June 30, 2025, cash consideration of $16 million remains in escrow and is included in restricted cash and accounts payable on the Company’s Condensed Consolidated Balance Sheet.

FME Post-Acquisition Operating Results

The FME Interests contributed the following to the Company’s consolidated operating results:

(In millions)	January 28, 2025 through June 30, 2025
Revenue	$	384
Net income	$	145

Avant Acquisition

On January 17, 2025, the Company closed on the acquisition of certain interests in oil and gas properties located in the Delaware Basin in New Mexico from certain privately owned sellers for total cash consideration of $1.5 billion (the “Avant assets”).

Preliminary Purchase Price Allocation

The transaction was accounted for using the acquisition method of accounting. Under the acquisition method of accounting, the assets and liabilities acquired in the Avant assets acquisition were recorded at their respective fair values as of

8

the closing date of the acquisition. The purchase price allocation is substantially complete; however, management continues to refine the preliminary valuation of certain assets acquired and liabilities assumed, and may adjust the allocation in subsequent periods. Determining the fair value of the assets and liabilities of the Avant assets requires judgment and certain assumptions to be made. The most significant fair value estimates relate to the valuation of the oil and gas properties and gathering and pipeline systems. Oil and gas properties and gathering and pipeline systems were valued using an income and market approach utilizing Level 3 inputs including internally generated production and development data and estimated price and cost estimates.

The following table represents the preliminary allocation of the total purchase price of the Avant assets to the identifiable assets acquired and liabilities assumed based on the fair values as of the closing date of the acquisition:

(In millions)	Preliminary Purchase Price Allocation
Consideration:
Cash consideration (1)	$	1,518
Total consideration	$	1,518
Assets acquired:
Current assets	$	34
Proved oil and gas properties	640
Unproved oil and gas properties	696
Gathering and pipeline systems	161
Other assets	1
Total assets acquired	$	1,532
Liabilities assumed:
Current liabilities	$	3
Asset retirement obligations	6
Other liabilities	5
Total liabilities assumed	$	14
Net assets acquired	$	1,518

________________________________________________________

(1)Cash consideration included the release of escrow funds in the amount of $109 million. These funds were included in restricted cash in the Condensed Consolidated Balance Sheet as of December 31, 2024.

Avant Post-Acquisition Operating Results

The Avant assets contributed the following to the Company’s consolidated operating results:

(In millions)	January 18, 2025 through June 30, 2025
Revenue	$	118
Net income	$	30

Combined Unaudited Pro Forma Financial Information

The results of operations of the FME Interests and Avant assets have been included in the Company’s condensed consolidated financial statements since the closing date of the acquisitions. The following supplemental pro forma financial information for the six months ended June 30, 2025 and 2024 have been prepared to give effect to the acquisitions of the FME Interests and the Avant assets as if they had occurred on January 1, 2024. The information below reflects pro forma adjustments based on available information and certain assumptions that the Company believes are factual and supportable. The pro forma results of operations do not include any cost savings or other synergies that may result from the acquisitions or any estimated costs that have been or will be incurred by the Company to integrate the FME Interests and Avant assets.

9

The pro forma financial information is not necessarily indicative of the results that might have occurred had the transactions actually taken place on January 1, 2024 and is not intended to be a projection of future results. Future results may vary significantly from the results reflected in the following pro forma financial information because of normal production declines, changes in commodity prices, future acquisitions and divestitures, future development and exploration activities and other factors.

The following table represents the pro forma effect on the Company of the FME and Avant acquisitions as if they had occurred on January 1, 2024:

	Three Months Ended June 30,		Six Months Ended June 30,
(In millions)	2024		2025		2024
Pro forma revenue	$	1,595	$	3,961	$	3,308
Pro forma net income	$	307	$	1,058	$	738

Other Information

In connection with the FME and Avant acquisitions, the Company recognized $14 million of transaction costs for the six months ended June 30, 2025. These costs are primarily related to integration costs, advisory and legal fees and are included in G&A expense in the condensed consolidated financial statements.

3. Properties and Equipment, Net

Properties and equipment, net are comprised of the following:

(In millions)	June 30, 2025		December 31, 2024
Proved oil and gas properties	$	25,619	$	21,765
Unproved oil and gas properties	5,121		4,105
Gathering and pipeline systems	1,008		620
Land, buildings and other equipment	240		213
Finance lease right-of-use asset	29		26
	32,017		26,729
Accumulated DD&A	(9,920)		(8,839)
	$	22,097	$	17,890

Capitalized Exploratory Well Costs

As of and for the six months ended June 30, 2025, the Company did not have any projects with exploratory well costs capitalized for a period of greater than one year after drilling.

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4. Long-Term Debt and Credit Agreements

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

(In millions)	June 30, 2025		December 31, 2024
Private placement senior notes:
3.77% senior notes due September 18, 2026	$	250	$	250
Senior notes:
3.90% senior notes due May 15, 2027	750		750
4.375% senior notes due March 15, 2029	500		500
5.60% senior notes due March 15, 2034	500		500
5.40% senior notes due February 15, 2035	750		750
5.90% senior notes due February 15, 2055	750		750
Term loan:
Tranche A term loan due January 27, 2027	150		—
Tranche B term loan due January 17, 2028	500		—
	4,150		3,500
Unamortized debt premium	58		69
Unamortized debt discount	(10)		(10)
Unamortized debt issuance costs	(23)		(24)
Long-term debt	$	4,175	$	3,535

As of June 30, 2025, the Company was in compliance with all financial covenants for its term loan, revolving credit agreement and 3.77% private placement senior notes.

Revolving Credit Agreement

During the first half of 2025, the Company borrowed and repaid $350 million under its revolving credit agreement. The Company’s weighted-average interest rate for borrowings under the revolving credit agreement for the three and six months ended June 30, 2025 was 8 percent. There were no borrowings under the revolving credit agreement during the first half of 2024.

As of June 30, 2025, the Company had no borrowings outstanding under its revolving credit agreement and unused commitments of $2.0 billion.

Term Loan

In December 2024, the Company entered into a delayed draw term loan credit agreement with Toronto Dominion (Texas), LLC, as administrative agent, and certain other lenders and issuing banks (the “Term Loan”), which consists of a $500 million Tranche A Term Loan and a $500 million Tranche B Term Loan. In January 2025, the Company borrowed $500 million under the Tranche A Term Loan to partially fund the FME Interests acquisition and $500 million under the Tranche B Term Loan to partially fund the acquisition of the Avant assets. During the first half of 2025, the Company repaid $350 million of the Tranche A Term Loan.

During the three and six months ended June 30, 2025, the weighted-average effective interest rate on the Company’s Term Loan was approximately 6 percent. As of June 30, 2025, the effective interest rate on the Company’s Term Loan was approximately 6 percent.

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5. Derivative Instruments

As of June 30, 2025, the Company had the following outstanding financial commodity derivatives:

	2025				2026
Oil	Third Quarter		Fourth Quarter		First Quarter		Second Quarter		Third Quarter		Fourth Quarter
WTI oil collars
Volume (MBbl)	5,152		5,152		2,700		2,730		2,760		2,760
Weighted average floor ($/Bbl)	$	61.34	$	61.34	$	56.67	$	56.67	$	56.67	$	56.67
Weighted average ceiling ($/Bbl)	$	79.00	$	79.00	$	70.68	$	70.68	$	70.68	$	70.68
WTI-NYMEX oil swaps
Volume (MBbl)	1,748		1,748		900		910		920		920
Weighted average price ($/Bbl)	$	69.18	$	69.18	$	66.14	$	66.14	$	66.14	$	66.14
WTI Midland oil basis swaps
Volume (MBbl)	5,520		5,520		1,800		1,820		1,840		1,840
Weighted average differential ($/Bbl)	$	1.02	$	1.02	$	0.95	$	0.95	$	0.95	$	0.95

	2025				2026
Natural Gas	Third Quarter		Fourth Quarter		First Quarter		Second Quarter		Third Quarter		Fourth Quarter
NYMEX gas collars
Volume (MMBtu)	87,400,000		87,400,000		81,000,000		54,600,000		55,200,000		55,200,000
Weighted average floor ($/MMBtu)	$	3.08	$	3.08	$	3.06	$	3.21	$	3.21	$	3.21
Weighted average ceiling ($/MMBtu)	$	4.88	$	5.66	$	6.39	$	5.76	$	5.76	$	5.76
Transco Leidy gas basis swaps
Volume (MMBtu)	18,400,000		18,400,000		—		—		—		—
Weighted average differential ($/MMBtu)	$	(0.70)	$	(0.70)	—		—		—		—
Transco Zone 6 Non-NY gas basis swaps
Volume (MMBtu)	18,400,000		18,400,000		—		—		—		—
Weighted average differential ($/MMBtu)	$	(0.49)	$	(0.49)	—		—		—		—
Waha gas basis swaps
Volume (MMBtu)	13,800,000		13,800,000		13,500,000		13,650,000		13,800,000		13,800,000
Weighted average differential ($/MMBtu)	$	(2.05)	$	(2.05)	$	(1.86)	$	(1.86)	$	(1.86)	$	(1.86)

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, 2025		December 31, 2024		June 30, 2025		December 31, 2024
Commodity contracts	Other current assets	$	98	$	12	$	—	$	—
Commodity contracts	Accrued liabilities	—		—		—		17
Commodity contracts	Other assets	17		—		—		—
Commodity contracts	Other liabilities	—		—		17		4
		$	115	$	12	$	17	$	21

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

(In millions)	June 30, 2025		December 31, 2024
Derivative assets
Gross amounts of recognized assets	$	139	$	26
Gross amounts offset in the condensed consolidated balance sheet	(24)		(14)
Net amounts of assets presented in the condensed consolidated balance sheet	115		12
Gross amounts of financial instruments not offset in the condensed consolidated balance sheet	2		—
Net amount	$	117	$	12
Derivative liabilities
Gross amounts of recognized liabilities	$	41	$	35
Gross amounts offset in the condensed consolidated balance sheet	(24)		(14)
Net amounts of liabilities presented in the condensed consolidated balance sheet	17		21
Gross amounts of financial instruments not offset in the condensed consolidated balance sheet	—		—
Net amount	$	17	$	21

Effect of Derivative Instruments on the Condensed Consolidated Statement of Operations

	Three Months Ended  June 30,				Six Months Ended  June 30,
(In millions)	2025		2024		2025		2024
Cash received (paid) on settlement of derivative instruments
Oil contracts	$	17	$	—	$	12	$	(1)
Gas contracts	18		36		1		63
Non-cash gain (loss) on derivative instruments
Oil contracts	83		(2)		88		(35)
Gas contracts	114		(50)		19		(43)
	$	232	$	(16)	$	120	$	(16)

6. 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.

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, 2025
Assets
Deferred compensation plan	$	18	$	—	$	—	$	18
Derivative instruments	—		40		99		139
	$	18	$	40	$	99	$	157
Liabilities
Deferred compensation plan	$	18	$	—	$	—	$	18
Derivative instruments	—		—		41		41
	$	18	$	—	$	41	$	59

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(In millions)	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Balance at   December 31, 2024
Assets
Deferred compensation plan	$	17	$	—	$	—	$	17
Derivative instruments	—		—		26		26
	$	17	$	—	$	26	$	43
Liabilities
Deferred compensation plan	$	17	$	—	$	—	$	17
Derivative instruments	—		—		35		35
	$	17	$	—	$	35	$	52

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

The derivative instruments were measured based on quotes from the Company’s third-party valuation service provider and the Company’s counterparties. Such quotes 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 are compared to multiple quotes obtained from counterparties or third-party valuation services, or a combination of the foregoing. 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 credit default swap spreads for various similarly rated companies in the same sector as the Company. 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, discount rates 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 the models provided by third-party valuation service providers or its counterparties’ valuation models. Consequently, additional disclosures regarding significant Level 3 unobservable inputs were not provided.

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

	Six Months Ended  June 30,
(In millions)	2025		2024
Balance at beginning of period	$	(9)	$	92
Total gain (loss) included in earnings	74		(16)
Settlement gain	(7)		(62)
Balance at end of period	$	58	$	14
Change in unrealized gains (losses) relating to assets and liabilities still held at the end of the period	$	67	$	(26)

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. In January 2025, the Company completed the FME and Avant acquisitions and recorded the assets acquired and liabilities assumed at fair value. The most significant fair value determinations for non-financial assets and liabilities are related to acquired oil and gas properties and gathering and pipeline systems. Refer to Note 2 of the Notes to the Condensed Consolidated Financial Statements in this report for additional information. As none of the Company’s other non-financial assets and liabilities were measured at fair value as of June 30, 2025, additional disclosures were not required.

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

Fair Value of Other Financial Instruments

The estimated fair value of other financial instruments is the amount at which the instruments could be exchanged currently between willing parties. The carrying amounts reported in the 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 fair value of the Company’s private placement senior notes is based on third-party quotes, which are derived from credit spreads for the difference between the issue rate and the period end market rate and other unobservable inputs. The Company’s private placement senior notes are valued using a market approach and are classified as Level 3 in the fair value hierarchy. The fair value of the Company’s Term Loan approximates the carrying value as the interest rates are variable and reflective of market rates. The Company’s Term Loan is classified as Level 1 in the fair value hierarchy.

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

	June 30, 2025				December 31, 2024
(In millions)	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-term debt	$	4,175	$	4,057	$	3,535	$	3,395

7. Asset Retirement Obligations

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

	Six Months Ended  June 30,
(In millions)	2025		2024
Balance at beginning of period	$	302	$	289
Liabilities incurred	5		4
Liabilities settled	—		(1)
Liabilities assumed in acquisitions	19		—
Accretion expense	7		6
Balance at end of period	333		298
Less: current asset retirement obligations	(17)		(12)
Noncurrent asset retirement obligations	$	316	$	286

8. 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 “Gathering, Processing and Transportation 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 stockholder derivative action styled Ezell v. Dinges, et. al. (U.S. District Court, Middle District of Pennsylvania) was filed against Messrs. Dinges and Schroeder and the Board of Directors of the Company serving at that time. Several additional derivative complaints were also filed and have been consolidated with the Ezell lawsuit, which was later transferred to the U.S. District Court for the Southern District of Texas. The most recent consolidated amended derivative complaint asserted claims for alleged securities violations under Section 10(b) and Section 21D of the Securities Exchange Act

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of 1934, as amended, as well as claims based on alleged breaches of fiduciary duty and statutory contribution theories. In January 2024, the district court issued an order and final judgment granting the Company’s and defendants’ motion to dismiss and dismissing the consolidated derivative case in its entirety with prejudice. The derivative plaintiffs filed a notice of appeal regarding the final judgment in February 2024, with oral arguments heard by the Fifth Circuit Court of Appeals on February 3, 2025. On May 13, 2025, the Fifth Circuit Court of Appeals affirmed the district court’s order dismissing these claims with prejudice.

In March 2024, one of the plaintiffs in the above consolidated derivative action served a demand letter on the Company’s Board of Directors. The letter demanded that the Board of Directors pursue legal claims against various current and former officers and directors of the Company based on similar factual allegations as contained in the corresponding securities class action (that was settled in late 2024) and consolidated stockholder derivative action described above. In June 2024, the individual who made the demand filed a stockholder derivative lawsuit styled Fischer v. Dinges et. al. (U.S. District Court, Southern District of Texas). The Board of Directors formed a committee to advise it in addressing each of the demands and the lawsuit. In April 2025, the committee advised counsel for the stockholders, who served the demand letters, that it had concluded its investigation, that it had determined that pursuing the claims asserted in the demands would not serve the Company’s interests, and that the committee was therefore rejecting the demands. On May 23, 2025, upon motion of the parties, the district court dismissed these claims without prejudice.

Other Legal Matters

The Company is a defendant in various other legal proceedings arising in the normal course of business. 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. All known liabilities for legal matters are accrued when management determines they are probable and the potential loss is estimable. The establishment of a reserve is based on an estimation process that includes the advice of legal counsel and subjective judgment of management. 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.

9. 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)	2025		2024		2025		2024
Oil	$	888	$	774	$	1,774	$	1,475
Natural gas	601		319		1,499		857
NGL	219		176		425		349
Other	25		18		51		39
	$	1,733	$	1,287	$	3,749	$	2,720

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, 2025, the Company had $5.8 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 14 years.

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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 $860 million and $820 million as of June 30, 2025 and December 31, 2024, respectively, and are reported in accounts receivable, net in the Condensed Consolidated Balance Sheet. As of June 30, 2025, the Company had no assets or liabilities related to its revenue contracts, including no upfront payments or rights to deficiency payments.

10. Income Tax

On July 4, 2025, the U.S. enacted significant tax legislation under H.R. 1, the One Big Beautiful Bill Act (“OBBB”). The OBBB, among other tax provisions, (i) restores section 168(k) 100 percent bonus depreciation for property acquired and placed in service after January 19, 2025, (ii) restores immediate expensing of domestic research and development expenditures for tax years after December 31, 2024, (iii) restores an EBITDA-based section 163(j) calculation for tax years after December 31, 2024, and (iv) allows for the deduction of intangible drilling costs in computing adjusted financial statement income under the Corporate Alternative Minimum Tax for tax years after December 31, 2025.

As this legislation was enacted after June 30, 2025, its effects are not reflected in the Company’s provision for income taxes as of that date. The Company is currently evaluating the impact of the new legislation. While the enactment of the OBBB is not expected to result in a material change to the Company’s total income tax expense, it is expected to have a material impact on the allocation between current and deferred taxes. Specifically, the reinstatement of 100 percent bonus depreciation and immediate expensing of domestic research and development costs are expected to significantly reduce current tax expense, with a corresponding increase in deferred tax expense, beginning in future reporting periods.

11. Capital Stock

Issuance of Common Stock

Upon the closing of the acquisition of the FME Interests in January 2025, the Company issued 28,190,682 shares of its common stock to the sellers of the FME Interests. The shares were valued at $785 million based on the closing price of the stock on the date of issuance.

Dividends

Common Stock

In February 2025, the Company’s Board of Directors approved an increase in its base quarterly dividend from $0.21 per share to $0.22 per share beginning in the first quarter of 2025.

The following table summarizes the dividends the Company has paid on its common stock during the six months ended June 30, 2025 and 2024:

	Base Rate Per Share (1)		Total Dividends Paid (In millions)
2025
First quarter	$	0.22	$	170
Second quarter	0.22		170
	$	0.44	$	340
2024
First quarter	$	0.21	$	160
Second quarter	0.21		158
	$	0.42	$	318

________________________________________________________

(1)    Increases to the Company’s base dividends were previously approved by the Company’s Board of Directors in the February meeting of the respective year presented.

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Treasury Stock

During the six months ended June 30, 2025 and 2024, the Company repurchased and retired 2 million shares for $47 million and 11 million shares for $296 million, respectively. As of June 30, 2025, the Company had $1.1 billion remaining under its current share repurchase program.

12. 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)	2025		2024		2025		2024
Restricted stock units - employees and non-employee directors	$	13	$	12	$	24	$	21
Restricted stock awards	—		2		—		3
Performance share awards	1		2		6		5
Total stock-based compensation expense	$	14	$	16	$	30	$	29
Income tax benefit	$	3	$	—	$	17	$	—

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.

Restricted Stock Units - Employees

During the six months ended June 30, 2025, the Company granted 671,361 restricted stock units to employees of the Company with a weighted average grant date value of $28.48 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 at the end of a three-year service period. The Company assumed a zero to five percent annual forfeiture rate for purposes of recognizing stock-based compensation expense for awards granted in 2025 based on the Company’s actual forfeiture history and expectations for this type of award.

During the six months ended June 30, 2025, 1,166,142 restricted stock units granted in 2022 vested. The weighted average grant date value was $24.14 per unit.

Restricted Stock Units - Non-Employees Directors

During the six months ended June 30, 2025, the Company granted 83,637 restricted stock units, with a weighted-average grant date value of $22.60 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 on the earlier of April 2026 or upon the director’s separation from the Company. Accordingly, the Company recognized this compensation expense immediately.

During the six months ended June 30, 2025, 49,861 restricted stock units granted in 2024 were issued to the Company’s non-employee directors and 76,478 restricted stock units granted and vested in periods from 2016 through 2021 were issued upon the retirement of certain non-employee directors following the Company’s 2025 annual meeting of stockholders. The weighted average grant date value was $23.50 per unit for all awards issued in 2025.

Performance Share Awards

Total Shareholder Return (“TSR”) Performance Share Awards. During the six months ended June 30, 2025, the Company granted 579,476 TSR Performance Share Awards, which are earned or not earned, based on the comparative performance of the Company’s common stock measured against a predetermined group of companies in the Company’s peer group and certain industry-related indices over a three-year performance period, which commenced on February 1, 2025 and ends on January 31, 2028.

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

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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 assumed a zero percent annual forfeiture rate for purposes of recognizing stock-based compensation expense for these awards based on the Company’s actual forfeiture history and expectations for this type of award.

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

	Grant Date
	February 19, 2025			June 30, 2025
Fair value per performance share award	$	21.49		$5.97 - $6.19
Assumptions:
Stock price volatility	33.8		%	27.4% - 33.9%
Risk-free rate of return	4.25		%	3.66% - 4.19%

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

In January 2025, the performance period ended for the TSR Performance Share Awards that were granted in 2022, and 1,103,157 shares with a grant date fair value of $20 million vested based on the Company’s ranking relative to a predetermined peer group. Cash payments associated with these awards of approximately $1 million were also made in February 2025. The calculation of the award payout was certified by the Compensation Committee of the Board of Directors on February 10, 2025.

13. Earnings per Share

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

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

	Three Months Ended  June 30,				Six Months Ended  June 30,
(In millions, except per share amounts)	2025		2024		2025		2024
Income (Numerator)
Net income	$	511	$	220	$	1,027	$	572
Less: dividends attributable to participating securities	—		(1)		—		(1)
Net income available to common stockholders	$	511	$	219	$	1,027	$	571
Shares (Denominator)
Weighted average shares - Basic	763		742		759		746
Dilution effect of stock awards at end of period	4		6		3		6
Weighted average shares - Diluted	767		748		762		752
Earnings per share
Basic	$	0.67	$	0.30	$	1.35	$	0.77
Diluted	$	0.67	$	0.29	$	1.35	$	0.76

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

	Three Months Ended  June 30,		Six Months Ended  June 30,
(In millions)	2025	2024	2025	2024
Weighted-average stock awards excluded from diluted EPS due to the anti-dilutive effect calculated using the treasury stock method	1	—	1	—

14. Restructuring Costs

Restructuring costs are primarily related to workforce reductions and associated severance benefits that were triggered by the merger with Coterra Energy Operating Co (formerly known as 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)	2025		2024
Balance at beginning of period	$	13	$	47
Reductions related to severance payments	(9)		(19)
Balance at end of period	$	4	$	28

15. Additional Balance Sheet Information

Certain balance sheet amounts are comprised of the following:

(In millions)	June 30, 2025		December 31, 2024
Accounts receivable, net
Trade accounts	$	860	$	820
Joint interest accounts	190		133
Other accounts	3		—
	1,053		953
Allowance for credit losses	(2)		(2)
	$	1,051	$	951
Inventories
Tubular goods and well equipment	$	42	$	33
Commodity inventory	15		13
	$	57	$	46
Other current assets
Prepaid balances	$	8	$	14
Derivative instruments	98		12
Other accounts	7		1
	$	113	$	27
Other assets
Deferred compensation plan	$	18	$	17
Debt issuance costs	9		10
Operating lease right-of-use assets	197		251
Derivative instruments	17		—
Other accounts	122		136
	$	363	$	414

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(In millions)	June 30, 2025		December 31, 2024
Accounts payable
Trade accounts	$	132	$	59
Royalty and other owners	481		402
Accrued gathering, processing and transportation	82		85
Accrued capital costs	208		177
Taxes other than income	54		37
Accrued lease operating costs	86		48
Other accounts	38		25
	$	1,081	$	833
Accrued liabilities
Employee benefits	$	50	$	76
Taxes other than income	23		46
Restructuring liabilities	4		13
Derivative instruments	—		17
Operating lease liabilities	96		115
Financing lease liabilities	7		7
Other accounts	21		2
	$	201	$	276
Other liabilities
Deferred compensation plan	$	18	$	17
Postretirement benefits	10		16
Derivative instruments	17		4
Operating lease liabilities	111		145
Other accounts	88		77
	$	244	$	259

16. Interest Expense

Interest expense is comprised of the following:

	Three Months Ended  June 30,				Six Months Ended  June 30,
(In millions)	2025		2024		2025		2024
Interest Expense
Interest expense	$	54	$	27	$	109	$	49
Debt (premium) discount amortization, net	(6)		(6)		(11)		(11)
Debt issuance cost amortization	1		1		3		2
Other	4		12		5		13
	$	53	$	34	$	106	$	53

17. Supplemental Cash Flow Information

	Six Months Ended  June 30,
(In millions)	2025		2024
Non-cash activity
Issuance of common stock for FME Interests	$	785	$	—

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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,” the “Company,” “our,” “we” and “us”) for the three and six month periods ended June 30, 2025 and 2024 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, 2024 filed on February 25, 2025 (our “Form 10-K”).

For the abbreviations and definitions of certain terms commonly used in the oil and gas industry, please see the “Glossary of Certain Oil and Gas Terms” included within our Form 10-K.

OVERVIEW

Financial and Operating Overview

Financial and operating results for the six months ended June 30, 2025 compared to the six months ended June 30, 2024 reflect the following:

•Net income increased $455 million from $572 million, or $0.77 per share, in 2024 to $1.0 billion, or $1.35 per share, in 2025.

•Net cash provided by operating activities increased $666 million, from $1.4 billion in 2024 to $2.1 billion in 2025.

•Equivalent production increased 15.2 MMBoe from 123.3 MMBoe, or 677.7 MBoe per day, in 2024 to 138.5 MMBoe, or 765.4 MBoe per day, in 2025.

◦Oil production increased 7.8 MMBbl from 19.1 MMBbl, or 104.9 MBbl per day, in 2024 to 26.9 MMBbl, or 148.4 MBbl per day, in 2025.

◦Natural gas production increased 24.5 Bcf from 522.3 Bcf, or 2,869.9 MMcf per day, in 2024 to 546.8 Bcf, or 3,021.1 MMcf per day, in 2025.

◦NGL volumes increased 3.4 MMBbl from 17.2 MMBbl, or 94.5 MBbl per day, in 2024 to 20.6 MMBbl, or 113.6 MBbl per day, in 2025.

•Average realized prices (including impact of derivatives):

◦Oil was $66.52 per Bbl in 2025, 14 percent lower than the $77.25 per Bbl realized in 2024.

◦Natural gas was $2.74 per Mcf in 2025, 56 percent higher than the $1.76 per Mcf realized in 2024.

◦NGL price was $20.66 per Bbl in 2025, two percent higher than the $20.28 per Bbl realized in 2024.

•Total capital expenditures for drilling, completion and other fixed assets were $1.1 billion in 2025 compared to $927 million in the corresponding period of the prior year.

Other financial highlights for the six months ended June 30, 2025 include the following:

•Closed two acquisitions in January 2025 in the Delaware Basin in New Mexico for total consideration of $3.3 billion in cash and the issuance of 28,190,682 shares of our common stock valued at $785 million based on the closing price of our common stock on the closing date of the transactions.

•Increased our quarterly base dividend from $0.21 per share to $0.22 per share in February 2025.

•Repaid $350 million of the Tranche A Term Loan.

•Repurchased 2 million shares for $47 million.

Market Conditions and Commodity Prices

Our financial results depend on many factors, particularly commodity prices and our ability to find and develop oil and gas reserves 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 can be impacted by pipeline capacity constraints, inventory storage levels, basis differentials, weather conditions, and geopolitical, economic and other factors.

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While oil prices were relatively steady throughout 2024, prices have declined in the first half of 2025, with the largest decline occurring in April 2025 in both spot and forward pricing. Global oil demand continues to be projected by some, including the International Energy Agency, to be adversely impacted by escalating trade tensions as a result of U.S. economic policy, including tariffs and retaliatory tariffs. However, these forecasts are subject to volatile market conditions, including ongoing shifts in U.S. and international trade policy, as well as geopolitical risk and uncertainty, including political and military disputes. OPEC+ previously announced both production cuts and increased production quotas. The impacts of these changes remain to be seen.

Natural gas prices, which rose in early 2025, have continued to trend downward through the second quarter, driven in part by warmer-than-expected temperatures and record high domestic production. Additionally, shifting U.S. and international trade policy and related uncertainty, including potential retaliatory tariffs on U.S. exports of LNG, have contributed to ongoing volatility in natural gas pricing. Meanwhile, basis differentials have persisted in the U.S., with prices at the Waha Hub in the Permian Basin particularly depressed due to oversupply. Prices turned negative in March 2025 before rebounding in April 2025, but remained volatile through the second quarter. Despite these headwinds, we continue to expect natural gas prices overall to be stronger in 2025 compared to 2024.

In recent months, the potential for increasing tariffs has remained a contributing factor to increased volatility in commodity markets and uncertainty in the general economic outlook. Higher tariffs could result in increased costs of materials used in our operations, less ready access to capital markets or less favorable general economic conditions. The uncertainty surrounding tariff policies has led to fluctuations in commodity prices which could impact our ability to forecast future results. We are continuing to monitor developments related to tariff policies.

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 or the current market volatility and U.S. and international economic policy uncertainty continues for an extended period of time, our operations could be adversely impacted, commodity prices could decline and our costs may increase. We expect commodity price volatility to continue, including as a result of U.S. and international economic policy (such as tariffs or retaliatory tariffs), actions of OPEC+ (including the ability of OPEC+ to successfully coordinate production quotas) and potentially swift near- and medium-term fluctuations in supply and demand, such as potential changes to drilling and capital programs in the short term by U.S. producers. While 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 significantly increase from current levels, our management would evaluate the recoverability of the carrying value of our oil and gas properties.

In addition, some governments, companies, communities and other stakeholders are supporting efforts to address climate change. As a result, such efforts have resulted in both existing and pending legislation and regulatory measures (including at the state, national and international level). Significant uncertainty remains as to the proposed changes in these laws or regulations, which, if adopted, may result in delays or restrictions in permitting and the development of our projects, increases to our costs, impair our ability to move forward with our construction, completions, drilling, water management, waste handling, storage, transport and remediation activities, or more competitive renewable energy alternatives that are able to more effectively compete with traditional oil and natural gas-derived products (including government subsidies and incentives for electric vehicles), 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.

Recent U.S. Tax Legislation

On July 4, 2025, the U.S. enacted significant tax legislation under H.R. 1, the One Big Beautiful Bill Act (“OBBB”). As this legislation was enacted after June 30, 2025, its effects are not reflected in our provision for income taxes as of that date. We are currently evaluating the impact of the new legislation. While the enactment of the OBBB is not expected to result in a material change to our total income tax expense, it is expected to have a material impact on the allocation between current and deferred taxes. Specifically, the reinstatement of 100 percent bonus depreciation and immediate expensing of domestic research and development costs are expected to significantly reduce current tax expense, with a corresponding increase in deferred tax expense, beginning in future reporting periods.

Outlook

Our 2025 full-year capital program is expected to be near the high end of the $2.1 billion to $2.3 billion range. We expect to fund these capital expenditures with our operating cash flow. We expect to turn-in-line 175 to 205 total net wells in 2025 across our three operating regions. We expect to invest approximately 66 percent of our capital expenditures in the Permian

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Basin, 15 percent in the Marcellus Shale, 10 percent in the Anadarko Basin and the remaining nine percent for gathering systems infrastructure, saltwater disposal and other capital expenditures.

In 2024, we drilled 313 gross wells (159.4 net) and turned-in-line 294 gross wells (153.0 net). For the six months ended June 30, 2025, our capital program focused on the Permian Basin, Marcellus Shale and Anadarko Basin, where we drilled 99.0 net wells and turned in line 98.8 net wells. Our capital program for the remainder of 2025 will focus on execution of our 2025 plan presented in our annual guidance. In the normal course of our business, we will continue to assess the oil and natural gas price macro environments and may adjust our capital allocation 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 (including acquisitions), payment of contractual obligations (including debt maturities 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 assets, and private or public financing based on our monitoring of capital markets and our balance sheet. While there are no “rating triggers” in any of our debt agreements that would accelerate the scheduled maturities should our credit rating fall below a certain level, a change in our credit rating could adversely impact our interest rate on any borrowings under our revolving credit agreement and our ability to economically access debt markets and could trigger the requirement to post credit support under various agreements, which could reduce the borrowing capacity under our revolving credit agreement. As of the date hereof, our debt is currently rated as investment grade by the three leading ratings agencies. For more on the impact of credit ratings on our interest rates and fees for unused commitments under our revolving credit agreement, see Note 4 of the Notes to the Consolidated Financial Statements in our Form 10-K. 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.

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, borrowings and 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. As of June 30, 2025, our working capital surplus of $170 million was lower than prior year, primarily due to a lower cash position as a result of funding the purchase price of the FME and Avant acquisitions that closed in January 2025 and the partial repayment of our term loan in the first half of 2025. As of December 31, 2024, we had a working capital surplus of $2.2 billion. We believe we have adequate liquidity and availability under our revolving credit agreement as outlined above to meet our working capital requirements over the next 12 months.

As of June 30, 2025, we had no borrowings outstanding under our revolving credit agreement, our unused commitments were $2.0 billion, and we had unrestricted cash on hand of $192 million.

Our revolving credit agreement and term loan include a covenant potentially limiting our borrowing capacity as determined by our leverage ratio. As of June 30, 2025, we were in compliance with all financial covenants applicable to our revolving credit agreement, term loan and private placement senior notes. Refer to Note 4 of the Notes to the Condensed Consolidated Financial Statements in this report and Note 4 of the Notes to the Consolidated Financial Statements in our Form 10-K for further details.

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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,				Variance
(In millions)	2025		2024		Amount		Percent
Cash flows provided by operating activities	$	2,080	$	1,414	$	666	47	%
Cash flows used in investing activities	(4,370)		(1,188)		(3,182)		268	%
Cash flows provided by (used in) financing activities	229		(112)		341		304	%
Net (decrease) increase in cash, cash equivalents and restricted cash	$	(2,061)	$	114	$	(2,175)	(1,908)	%

Operating Activities. Operating cash flow fluctuations are substantially driven by changes in commodity prices, production volumes and operating expenses. As discussed above, commodity prices have historically been volatile. Fluctuations in cash flow may result in an increase or decrease in our planned capital expenditures.

Net cash provided by operating activities for the six months ended June 30, 2025 increased by $666 million compared to the same period in 2024. This increase was primarily due to higher oil, natural gas and NGL revenues driven by significantly higher natural gas prices and by higher production from our FME and Avant acquisitions that closed in January 2025 and our legacy properties in the Permian and Anadarko Basins. These increases were partially offset by an increase in operating costs largely due to our FME and Avant acquisitions and a decrease in cash received on derivative settlements during the first six months of 2025 compared to 2024.

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 $3.2 billion for the six months ended June 30, 2025 compared to the six months ended June 30, 2024. This increase was primarily due to $3.2 billion of cash consideration paid for business combinations and $210 million higher cash paid for capital expenditures, partially offset by a decrease of $250 million of purchases of short-term investments in 2025 compared to 2024.

Financing Activities. Cash flows provided by financing activities increased by $341 million for the six months ended June 30, 2025 compared to the six months ended June 30, 2024. The increase was due to $851 million higher proceeds from issuance of debt due to the funding of our term loan in 2025 and borrowings under our revolver, and $243 million lower common stock repurchases. These increases were partially offset by $700 million higher debt repayments related to the $350 million repayment of our term loan and the $350 million repayment of borrowings under our revolver during 2025, $32 million of higher dividend payments, and $24 million of higher tax withholding on vesting of stock awards in 2025 compared to 2024.

Capitalization

Information about our capitalization is as follows:

(Dollars in millions)	June 30, 2025			December 31, 2024
Long-term debt (1)	$	4,175		$	3,535
Stockholders’ equity	14,556			13,122
Total capitalization	$	18,731		$	16,657
Debt to total capitalization	22		%	21		%
Cash and cash equivalents	$	192		$	2,038

________________________________________________________

(1) There were no borrowings outstanding under our revolving credit agreement as of June 30, 2025 and December 31, 2024.

Share repurchases. During the six months ended June 30, 2025, we repurchased and retired 2 million shares of our common stock for $47 million. We repurchased and retired 11 million shares of our common stock for $296 million during the six months ended June 30, 2024.

As of June 30, 2025, we had $1.1 billion remaining under our current share repurchase program.

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Dividends. In February 2025, our Board of Directors approved an increase in the base quarterly dividend from $0.21 per share to $0.22 per share.

The following table summarizes our dividends on our common stock for the six months ended June 30, 2025 and 2024:

	Base Rate Per Share		Total Dividends (In millions)
2025
First quarter	$	0.22	$	170
Second quarter	0.22		170
	$	0.44	$	340
2024
First quarter	$	0.21	$	160
Second quarter	0.21		158
	$	0.42	$	318

Capital and Exploration Expenditures

On an annual basis, we generally fund most of our capital expenditures, excluding any significant property acquisitions, with cash flow provided by operating activities, and, if required, 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)	2025		2024
Acquisitions
Proved oil and gas properties	$	2,473	$	—
Unproved oil and gas properties	1,286		—
Gathering and pipeline systems	333		—
	$	4,092	$	—
Capital expenditures:
Drilling and facilities	$	1,044	$	864
Pipeline and gathering	63		54
Other	14		9
Capital expenditures for drilling, completion and other fixed asset additions	1,121		927
Capital expenditures for leasehold and property acquisitions	57		3
Exploration expenditures (1)	14		10
	$	1,192	$	940

________________________________________________________

(1)There were no exploratory dry hole costs for the six months ended June 30, 2025 and 2024.

For the six months ended June 30, 2025, our capital program focused on the Permian Basin, Marcellus Shale and Anadarko Basin, where we drilled 99.0 net wells and turned-in-line 98.8 net wells. We expect that our full-year 2025 capital program will be near the high end of the $2.1 billion to $2.3 billion range. Refer to “Outlook” above 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 “Gathering, Processing and Transportation Agreements” and “Lease Commitments” as disclosed in Note 8 of the Notes to the Consolidated Financial Statements and the obligations described under “Contractual

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Obligations” in Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in our Form 10-K.

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 GAAP. 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.

Purchase Accounting

From time-to-time, we may acquire assets and assume liabilities in transactions accounted for as business combinations, such as the FME and Avant acquisitions. In connection with the FME and Avant acquisitions, we allocated the purchase price consideration to the assets acquired and liabilities assumed based on estimated fair values as of the closing dates of the respective acquisition.

We made a number of assumptions in estimating the fair value of assets acquired and liabilities assumed in the FME and Avant acquisitions. The most significant assumptions related to the fair value estimates of proved and unproved oil and gas properties, which were recorded at a total fair value of $3.8 billion. Since sufficient market data was not available regarding the fair values of the acquired proved and unproved oil and gas properties, we prepared our estimates using discounted cash flows and engaged third-party valuation experts. Significant judgments and assumptions are inherent in these estimates and include, among other things, estimates of reserve quantities and production volumes, future commodity prices and price differentials, expected development costs, lease operating costs, reserve risk adjustment factors and an estimate of an applicable market participant discount rate that reflects the risk of the underlying cash flow estimates.

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

In addition to the fair value of proved and unproved oil and gas properties, other significant fair value assessments for the assets acquired and liabilities assumed in the FME and Avant acquisitions relate to gathering and pipeline systems. We prepared estimates and engaged third-party valuation experts to assist in the valuation of certain other assets, which required significant judgments and assumptions inherent in the estimates and included projected cash flows and comparable companies’ cash flow multiples.

RESULTS OF OPERATIONS

Second Quarters of 2025 and 2024 Compared

Operating Revenues

	Three Months Ended  June 30,				Variance
(In millions)	2025		2024		Amount		Percent
Operating Revenues
Oil	$	888	$	774	$	114	15	%
Natural gas	601		319		282		88	%
NGL	219		176		43		24	%
Gain (loss) on derivative instruments	232		(16)		248		1,550	%
Other	25		18		7		39	%
	$	1,965	$	1,271	$	694	55	%

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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, as discussed above, fluctuate due to a variety of factors, including supply and demand, the availability of transportation, seasonality and geopolitical, economic and other factors.

Production and Sales Price

The following table presents our total and average daily production volumes for oil, natural gas and NGLs, and our average oil, natural gas and NGL sales prices for the periods indicated.

	Three Months Ended June 30,				Variance
	2025		2024		Amount		Percent
Production Volumes
Oil (MMBbl)	14.1		9.8		4.3		44	%
Natural gas (Bcf)	272.9		253.0		19.9		8	%
NGL (MMBbl)	11.7		9.0		2.7		30	%
Equivalents (MMBoe)	71.3		60.9		10.4		17	%
Average Daily Production Volumes
Oil (MBbl)	155.4		107.2		48.2		45	%
Natural gas (MMcf)	2,998.6		2,779.8		218.8		8	%
NGL (MBbl)	128.7		98.8		29.9		30	%
Equivalents (MBoe)	783.9		669.2		114.7		17	%
Average Sales Price
Excluding Derivative Settlements
Oil ($/Bbl)	$	62.80	$	79.37	$	(16.57)	(21)	%
Natural gas ($/Mcf)	$	2.20	$	1.26	$	0.94	75	%
NGL ($/Bbl)	$	18.72	$	19.53	$	(0.81)	(4)	%
Including Derivative Settlements
Oil ($/Bbl)	$	64.01	$	79.39	$	(15.38)	(19)	%
Natural gas ($/Mcf)	$	2.27	$	1.40	$	0.87	62	%
NGL ($/Bbl)	$	18.72	$	19.53	$	(0.81)	(4)	%

Oil Revenues

	Three Months Ended  June 30,				Variance				Increase (Decrease) (In millions)
	2025		2024		Amount		Percent
Volume (MMBbl)	14.1		9.8		4.3		44	%	$	348
Price ($/Bbl)	$	62.80	$	79.37	$	(16.57)	(21)	%	(234)
									$	114

Oil revenues increased $114 million due to higher production in the Permian Basin, partially offset by lower oil prices. Production increased due to the FME and Avant acquisitions in the Permian Basin that closed in January 2025 and higher production from our legacy properties.

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Natural Gas Revenues

	Three Months Ended  June 30,				Variance				Increase (Decrease) (In millions)
	2025		2024		Amount		Percent
Volume (Bcf)	272.9		253.0		19.9		8	%	$	25
Price ($/Mcf)	$	2.20	$	1.26	$	0.94	75	%	257
									$	282

Natural gas revenues increased $282 million primarily due to significantly higher natural gas prices and higher production in the Permian and Anadarko Basins, partially offset by lower production in the Marcellus Shale. Production increased due to the FME and Avant acquisitions in the Permian Basin that closed in January 2025 and higher production from our legacy properties in the Permian and Anadarko Basins. The decrease in production in the Marcellus Shale was due to a decrease in drilling and completion activity in 2024, which resulted in a decline in production.

NGL Revenues

	Three Months Ended  June 30,				Variance				Increase (Decrease) (In millions)
	2025		2024		Amount		Percent
Volume (MMBbl)	11.7		9.0		2.7		30	%	$	53
Price ($/Bbl)	$	18.72	$	19.53	$	(0.81)	(4)	%	(10)
									$	43

NGL revenues increased $43 million primarily due to higher NGL volumes in the Permian and Anadarko Basins, partially offset by lower prices.

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.

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

	Three Months Ended  June 30,
(In millions)	2025		2024
Cash received on settlement of derivative instruments
Oil contracts	$	17	$	—
Gas contracts	18		36
Non-cash gain (loss) on derivative instruments
Oil contracts	83		(2)
Gas contracts	114		(50)
	$	232	$	(16)

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 had stabilized in 2024 despite on-going demand and latent effects of inflation and supply chain disruptions. In January 2025 with the completion of the FME and Avant acquisitions, we expanded our operations in the Permian Basin.

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The table below 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)	2025		2024		Amount		Percent		2025		2024
Operating Expenses
Direct operations	$	236	$	160	$	76	48	%	$	3.32	$	2.62
Gathering, processing and transportation	271		242		29		12	%	3.81		3.99
Taxes other than income	87		54		33		61	%	1.21		0.89
Exploration	4		5		(1)		(20)	%	0.07		0.09
Depreciation, depletion and amortization	579		447		132		30	%	8.11		7.34
General and administrative	84		68		16		24	%	1.18		1.12
	$	1,261	$	976	$	285	29	%	$	17.70	$	16.05

Direct Operations

Direct operations generally consist of costs for labor, equipment, maintenance, saltwater disposal, compression, power, treating and miscellaneous other costs (collectively, “lease operating expense”). Direct operations also include 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)	2025		2024		Variance		2025		2024
Direct Operations Expense
Lease operating expense	$	194	$	134	$	60	$	2.73	$	2.19
Workover expense	42		26		16		0.59		0.43
	$	236	$	160	$	76	$	3.32	$	2.62

Lease operating expense increased primarily due to higher production levels and higher costs in the Permian Basin driven in part by the FME and Avant acquisitions, which have higher lifting costs than our legacy wells.

Workover expense increased $16 million primarily due to increased expenses related to the FME and Avant acquisitions and higher workover activity in the Permian Basin, partially offset by a decrease in workover activity in the Marcellus Shale due to reduced activity in the basin.

Gathering, Processing and Transportation

Gathering, processing and transportation costs principally consist of expenditures to prepare and transport production downstream from the wellhead, including gathering, fuel, and compression, along with 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.

Gathering, processing and transportation costs increased $29 million primarily due to higher production due to the FME and Avant acquisitions in the Permian Basin that closed in January 2025 and higher production from our legacy properties in the Permian and Anadarko Basins.

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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)	2025			2024			Variance
Taxes Other than Income
Production	$	68		$	52		$	16
Drilling impact fees	6			2			4
Ad valorem	12			(1)			13
Other	1			1			—
	$	87		$	54		$	33
Production taxes as percentage of revenue (Permian and Anadarko Basins)	5.6		%	5.6		%

Taxes other than income increased primarily due to an increase in our production and ad valorem taxes. Production taxes increased primarily due to higher production due to the FME and Avant acquisitions in the Permian Basin that closed in January 2025 and higher production from our legacy properties in the Permian and Anadarko Basins. Ad valorem taxes increased due to a reduction in 2024 ad valorem tax expense related to an adjustment for estimated tax accruals that related to the full-year 2023.

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

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

	Three Months Ended  June 30,						Per BOE
(In millions, except per BOE)	2025		2024		Variance		2025		2024
DD&A Expense
Depletion	$	536	$	414	$	122	$	7.52	$	6.80
Depreciation	24		18		6		0.32		0.29
Amortization of unproved properties	15		12		3		0.22		0.20
Accretion of ARO	4		3		1		0.05		0.05
	$	579	$	447	$	132	$	8.11	$	7.34

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 natural 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 impact depletion expense. Our depletion expense increased $122 million primarily due to a higher depletion rate and an increase in production. Our depletion rate increased primarily due to the increase in value of our oil and gas properties related to assets acquired from FME and Avant, which were recorded at fair value. The depletion rate also increased due to a shift in our production mix to fields with higher depletion rates and changes in our year-end reserves estimates

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.

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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.

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)	2025		2024		Variance
G&A Expense
General and administrative expense	$	70	$	52	$	18
Stock-based compensation expense	14		16		(2)
	$	84	$	68	$	16

G&A expense, excluding stock-based compensation expense, increased $18 million primarily due to higher employee-related costs, legal and professional fees and community outreach and charitable contributions.

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.

Interest Expense

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

	Three Months Ended  June 30,
(In millions)	2025		2024		Variance
Interest Expense
Interest expense	$	54	$	27	$	27
Debt premium and discount amortization, net	(6)		(6)		—
Debt issuance cost amortization	1		1		—
Other	4		12		(8)
	$	53	$	34	$	19

Interest expense increased primarily due to an increase of $27 million related to interest on debt balances. This increase was primarily due to the issuance of $500 million of 5.60% senior notes in early March 2024, $750 million of 5.40% senior notes in December 2024, $750 million of 5.90% senior notes in December 2024 and $1.0 billion of term loans issued in January 2025 to fund the FME and Avant acquisitions. These increases were partially offset by decreases related to repayments of $575 million related to the 3.65% weighted-average private placement senior notes in September 2024 and $350 million of our term loan in the first half of 2025.

Interest Income

Interest income decreased $17 million due to lower cash balances during 2025 compared to 2024 and a decrease in interest earned on our higher interest rate short-term investment balances that matured in September 2024.

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Income Tax Expense

	Three Months Ended  June 30,
(In millions)	2025			2024			Variance
Income Tax Expense
Current tax expense	$	97		$	62		$	35
Deferred tax expense (benefit)	50			(1)			51
	$	147		$	61		$	86
Combined federal and state effective income tax rate	22.3		%	21.6		%

Income tax expense increased $86 million for the three months ended June 30, 2025 compared to the three months ended June 30, 2024 primarily due to higher pre-tax income and a higher effective tax rate. The effective tax rate increased due to differences in permanent book-to-tax adjustments and non-recurring discrete items recorded during the three months ended June 30, 2025 and 2024.

First Six Months of 2025 and 2024 Compared

Operating Revenues

	Six Months Ended  June 30,				Variance
(In millions)	2025		2024		Amount		Percent
Oil	$	1,774	$	1,475	$	299	20	%
Natural gas	1,499		857		642		75	%
NGL	425		349		76		22	%
Gain (loss) on derivative instruments	120		(16)		136		850	%
Other	51		39		12		31	%
	$	3,869	$	2,704	$	1,165	43	%

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Production Revenues

Production and Sales Price

The following table presents our total and average daily production volumes for oil, natural gas and NGLs, and our average oil, natural gas and NGL sales prices for the periods indicated.

	Six Months Ended  June 30,				Variance
	2025		2024		Amount		Percent
Production Volumes
Oil (MMBbl)	26.9		19.1		7.8		41	%
Natural gas (Bcf)	546.8		522.3		24.5		5	%
NGL (MMBbl)	20.6		17.2		3.4		20	%
Equivalents (MMBoe)	138.5		123.3		15.2		12	%
Average Daily Production Volumes
Oil (MBbl)	148.4		104.9		43.5		41	%
Natural gas (MMcf)	3,021.1		2,869.9		151.2		5	%
NGL (MBbl)	113.6		94.5		19.1		20	%
Equivalents (MBoe)	765.4		677.7		87.7		13	%
Average Sales Price
Excluding Derivative Settlements
Oil ($/Bbl)	$	66.08	$	77.31	$	(11.23)	(15)	%
Natural gas ($/Mcf)	$	2.74	$	1.64	$	1.10	67	%
NGL ($/Bbl)	$	20.66	$	20.28	$	0.38	2	%
Including Derivative Settlements
Oil ($/Bbl)	$	66.52	$	77.25	$	(10.73)	(14)	%
Natural gas ($/Mcf)	$	2.74	$	1.76	$	0.98	56	%
NGL ($/Bbl)	$	20.66	$	20.28	$	0.38	2	%

Oil Revenues

	Six Months Ended  June 30,				Variance				Increase (Decrease) (In millions)
	2025		2024		Amount		Percent
Volume (MMBbl)	26.9		19.1		7.8		41	%	$	601
Price ($/Bbl)	$	66.08	$	77.31	$	(11.23)	(15)	%	(302)
									$	299

Oil revenues increased $299 million primarily due to higher production in the Permian and Anadarko Basins, partially offset by lower oil prices. Production increased due to the FME and Avant acquisitions in the Permian Basin that closed in January 2025 and higher production from our legacy properties.

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Natural Gas Revenues

	Six Months Ended  June 30,				Variance				Increase (Decrease) (In millions)
	2025		2024		Amount		Percent
Volume (Bcf)	546.8		522.3		24.5		5	%	40
Price ($/Mcf)	$	2.74	$	1.64	$	1.10	67	%	602
									$	642

Natural gas revenues increased $642 million primarily due to significantly higher natural gas prices and higher production in the Permian and Anadarko Basins, partially offset by lower production in the Marcellus Shale. Production increased due to the FME and Avant acquisitions in the Permian Basin that closed in January 2025 and higher production from our legacy properties in the Permian and Anadarko Basins. The decrease in production in the Marcellus Shale was due to a decrease in drilling and completion activity in 2024 which resulted in a decline in production.

NGL Revenues

	Six Months Ended  June 30,				Variance				Increase (Decrease) (In millions)
	2025		2024		Amount		Percent
Volume (MMBbl)	20.6		17.2		3.4		20	%	$	68
Price ($/Bbl)	$	20.66	$	20.28	$	0.38	2	%	8
									$	76

NGL revenues increased $76 million primarily due to higher volumes in the Permian and Anadarko Basins and slightly higher NGL prices.

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)	2025		2024
Cash received (paid) on settlement of derivative instruments
Oil contracts	$	12	$	(1)
Gas contracts	1		63
Non-cash gain (loss) on derivative instruments
Oil contracts	88		(35)
Gas contracts	19		(43)
	$	120	$	(16)

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Operating Costs and Expenses

The table below 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)	2025		2024		Amount		Percent		2025		2024
Operating Expenses
Direct operations	$	452	$	316	$	136	43	%	$	3.26	$	2.56
Gathering, processing and transportation	553		492		61		12	%	4.00		3.99
Taxes other than income	183		128		55		43	%	1.32		1.04
Exploration	14		10		4		40	%	0.10		0.08
Depreciation, depletion and amortization	1,085		879		206		23	%	7.83		7.12
General and administrative	176		143		33		23	%	1.27		1.16
	$	2,463	$	1,968	$	495	25	%	$	17.78	$	15.95

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)	2025		2024		Variance		2025		2024
Direct Operations
Lease operating expense	$	383	$	264	$	119	$	2.76	$	2.14
Workover expense	69		52		17		0.50		0.42
	$	452	$	316	$	136	$	3.26	$	2.56

Lease operating expense increased primarily due to higher production levels and higher costs in the Permian Basin driven in part by the FME and Avant acquisitions, which have higher lifting costs than our legacy wells.

Workover expense increased by $17 million primarily due to higher expense related to the FME and Avant acquisitions and higher workover activity in the Permian Basin, partially offset by lower activity in the Marcellus Shale due to reduced activity in the basin.

Gathering, Processing and Transportation

Gathering, processing and transportation costs increased $61 million, primarily due to higher production due to the FME and Avant acquisitions in the Permian Basin that closed in January 2025 and higher production from our legacy properties in the Permian and Anadarko Basins.

Taxes Other Than Income

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

	Six Months Ended  June 30,
(In millions)	2025			2024			Variance
Taxes Other than Income
Production	$	147		$	106		$	41
Drilling impact fees	11			7			4
Ad valorem	24			16			8
Other	1			(1)			2
	$	183		$	128		$	55
Production taxes as percentage of revenue (Permian and Anadarko Basins)	5.9		%	5.6		%

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Taxes other than income increased $55 million primarily due to an increase in our production and ad valorem taxes. Production taxes increased primarily due to higher production due to the FME and Avant acquisitions in the Permian Basin that closed in January 2025 and higher production from our legacy properties in the Permian and Anadarko Basins. Ad valorem taxes increased due to a reduction in 2024 ad valorem tax expense related to an adjustment for estimated tax accruals related to the full-year 2023.

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)	2025		2024		Variance		2025		2024
DD&A Expense
Depletion	$	1,003	$	813	$	190	$	7.24	$	6.59
Depreciation	47		36		11		0.35		0.29
Amortization of unproved properties	28		24		4		0.20		0.19
Accretion of ARO	7		6		1		0.04		0.05
	$	1,085	$	879	$	206	$	7.83	$	7.12

Our depletion expense increased $190 million primarily due to a higher depletion rate and an increase in production. Our depletion rate increased primarily due to the increase in value of our oil and gas properties related to assets acquired from FME and Avant, which were recorded at fair value. The depletion rate also increased due to a shift in our production mix to fields with higher depletion rates and changes in our year-end reserves estimates.

General and Administrative (“G&A”)

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

	Six Months Ended  June 30,
(In millions)	2025		2024		Variance
G&A Expense
General and administrative expense	$	146	$	114	$	32
Stock-based compensation expense	30		29		1
	$	176	$	143	$	33

G&A expense, excluding stock-based compensation expense, increased $32 million primarily due to acquisition and transition costs associated with the FME and Avant acquisitions completed in January 2025, increased employee-related costs and higher legal and professional fees, partially offset by the recognition of certain long-term commitments for community outreach and charitable contributions that were accrued in 2024.

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.

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Interest Expense

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

	Six Months Ended  June 30,
(In millions)	2025		2024		Variance
Interest Expense
Interest expense	$	109	$	49	$	60
Debt premium and discount amortization, net	(11)		(11)		—
Debt issuance cost amortization	3		2		1
Other	5		13		(8)
	$	106	$	53	$	53

Interest expense increased $53 million primarily due to an increase of $60 million related to interest on debt balances. This increase was primarily due to the issuance of $500 million of 5.60% senior notes in early March 2024, $750 million of 5.40% senior notes in December 2024, $750 million of 5.90% senior notes in December 2024 and $1.0 billion of term loans issued in January 2025 to fund the FME and Avant acquisitions. These increases were partially offset by repayments of $575 million related to the 3.65% weighted-average private placement senior notes in September 2024 and $350 million of our term loan in the first half of 2025.

Interest Income

Interest income decreased $25 million due to lower cash balances during 2025 compared to 2024 and a decrease in interest earned on short-term investment balances that matured in September 2024.

Income Tax Expense

	Six Months Ended  June 30,
(In millions)	2025			2024			Variance
Income Tax Expense
Current tax expense	$	227		$	169		$	58
Deferred tax expense (benefit)	61			(23)			84
	$	288		$	146		$	142
Combined federal and state effective income tax rate	21.9		%	20.3		%

Income tax expense increased $142 million for the six months ended June 30, 2025 compared to the six months ended June 30, 2024 primarily due to higher pre-tax income and a higher effective tax rate. The effective tax rate increased due to differences in permanent book-to-tax adjustments and non-recurring discrete items recorded during the six months ended June 30, 2025 and 2024.

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, strategic pursuits and goals, market prices, future hedging and risk management activities, the impact of tariffs, timing and amount of capital expenditures and other statements that are not historical facts contained in this report. The words “expect,” “project,” “estimate,” “believe,” “anticipate,” “intend,” “budget,” “plan,” “forecast,” “target,” “predict,” “potential,” “possible,” “may,” “should,” “could,” “would,” “will,” “strategy,” “outlook” and similar expressions are also intended to identify forward-looking statements. We can provide no assurance that the forward-looking statements contained in this report will occur as expected, and actual results may differ materially from those included in this report. Forward-looking statements are based on current expectations and assumptions that involve a number of risks and uncertainties that could cause actual results to differ materially from those included in this report. These risks and uncertainties include, without limitation, the availability of cash on hand and other sources of liquidity to fund our capital expenditures, changes in U.S. and international economic policy (including tariffs and retaliatory tariffs and the impacts thereof), 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

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economic disruption, geopolitical disruptions such as the war in Ukraine or the conflict in the Middle East or further escalation thereof, the potential effects of ongoing political and military disputes, results of future drilling and marketing activities (including seismicity and similar data), future production and costs, legislative and regulatory initiatives, electronic, cyber or physical security breaches, the impact of public health crises, including pandemics and epidemics and any related company or governmental policies or actions, and other factors detailed herein and in our other SEC filings. Refer to “Risk Factors” in Item 1A of Part I of our Form 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. Except as otherwise indicated, the following quantitative and qualitative information is provided about financial instruments to which we were party as of June 30, 2025 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. As noted above, 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 commodity price 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 these 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 in this Form 10-Q and 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. 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, 2025, we had the following outstanding financial commodity derivatives:

	2025				2026								Fair Value Asset (Liability) (In millions)
Oil	Third Quarter		Fourth Quarter		First Quarter		Second Quarter		Third Quarter		Fourth Quarter
WTI oil collars													$	52
Volume (MBbl)	5,152		5,152		2,700		2,730		2,760		2,760
Weighted average floor ($/Bbl)	$	61.34	$	61.34	$	56.67	$	56.67	$	56.67	$	56.67
Weighted average ceiling ($/Bbl)	$	79.00	$	79.00	$	70.68	$	70.68	$	70.68	$	70.68
WTI-NYMEX oil swaps													40
Volume (MBbl)	1,748		1,748		900		910		920		920
Weighted average price ($/Bbl)	$	69.18	$	69.18	$	66.14	$	66.14	$	66.14	$	66.14
WTI Midland oil basis swaps													2
Volume (MBbl)	5,520		5,520		1,800		1,820		1,840		1,840
Weighted average differential ($/Bbl)	$	1.02	$	1.02	$	0.95	$	0.95	$	0.95	$	0.95

	2025				2026								Fair Value Asset (Liability) (In millions)
Natural Gas	Third Quarter		Fourth Quarter		First Quarter		Second Quarter		Third Quarter		Fourth Quarter
NYMEX gas collars													$	(23)
Volume (MMBtu)	87,400,000		87,400,000		81,000,000		54,600,000		55,200,000		55,200,000
Weighted average floor ($/MMBtu)	$	3.08	$	3.08	$	3.06	$	3.21	$	3.21	$	3.21
Weighted average ceiling ($/MMBtu)	$	4.88	$	5.66	$	6.39	$	5.76	$	5.76	$	5.76
Transco Leidy gas basis swaps													16
Volume (MMBtu)	18,400,000		18,400,000		—		—		—		—
Weighted average differential ($/MMBtu)	$	(0.70)	$	(0.70)	—		—		—		—
Transco Zone 6 Non-NY gas basis swaps													14
Volume (MMBtu)	18,400,000		18,400,000		—		—		—		—
Weighted average differential ($/MMBtu)	$	(0.49)	$	(0.49)	—		—		—		—
Waha gas basis swaps
Volume (MMBtu)	13,800,000		13,800,000		13,500,000		13,650,000		13,800,000		13,800,000		(3)
Weighted average differential ($/MMBtu)	$	(2.05)	$	(2.05)	$	(1.86)	$	(1.86)	$	(1.86)	$	(1.86)

A significant portion of our expected oil and natural gas production for the remainder of 2025 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, 2025, oil collars with floor prices ranging from $55.00 to $65.00 per Bbl and ceiling prices ranging from $69.55 to $86.02 per Bbl covered 10.1 MMBbls, or 38 percent, of our oil production at a weighted-average price of $66.95 per Bbl. Oil swaps covered 3.4 MMBbls, or 13 percent, of our oil production at a weighted-average price of $69.18 per Bbl. Oil basis swaps covered 12.7 MMBbls, or 47 percent, of our oil production at a weighted-average differential of $1.07 per Bbl.

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During the six months ended June 30, 2025, natural gas collars with floor prices ranging from $2.75 to $3.50 per MMBtu and ceiling prices ranging from $3.40 to $7.00 per MMBtu covered 135.1 Mcf, or 25 percent of our natural gas production at a weighted-average price of $3.55 per MMBtu. Gas basis swaps covered 73.5 Bcf, or 13 percent of natural gas production at a weighted-average differential of $(0.76) per MMBtu.

We are exposed to market risk on financial commodity derivative instruments to the extent of changes in market prices of the related commodity. 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 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

As of June 30, 2025, we had total long-term debt of $4.2 billion. Our portfolio of long-term debt includes floating rate debt and fixed-rate instruments. Our revolving credit agreement and term loan borrowings are floating rate debt instruments, which exposes us to the risk of earnings or cash flow losses as the result of potential increases in market interest rates.

There are no “rating triggers” in any of our debt agreements that would accelerate the scheduled maturities. Should our credit rating fall below a certain level, a change in our credit rating could adversely impact our interest rate on any borrowings under our revolving credit agreement and term loan. As of the date hereof, our debt is currently rated as investment grade by the three leading ratings agencies. For more on the impact of credit ratings on our interest rates, see Note 4 of the Notes to the Consolidated Financial Statements in our Form 10-K.

As of June 30, 2025, we had no outstanding balance under our revolving credit agreement and $650 million outstanding borrowings under our term loan. Assuming no change in the amount of floating rate debt outstanding, a hypothetical 100 basis point increase in the average interest rate under our term loan borrowings would have increased our annual interest expense by approximately $3 million. Actual results may vary due to changes in the amount of floating rate debt outstanding.

As of June 30, 2025, we had $3.5 billion outstanding borrowings under fixed-rate debt instruments, which do not carry significant exposure to movements in market interest rates.

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. The fair value of our private placement senior notes is based on third-party quotes which are derived from credit spreads for the difference between the issue rate and the period end market rate and other unobservable inputs. The fair value of the borrowing under our term loan approximates the carrying value as the interest rates are variable and reflective of market rates.

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

	June 30, 2025				December 31, 2024
(In millions)	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-term debt	$	4,175	$	4,057	$	3,535	$	3,395

ITEM 4. Controls and Procedures

As of June 30, 2025, 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, as amended (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

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reasonable assurance with respect to the recording, processing, summarizing and reporting, within the time periods specified in the SEC’s rules and forms, of information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act.

During the quarter ended June 30, 2025, the Company integrated the controls and related procedures of the FME and Avant acquisitions into its internal control over financial reporting and they are now included in the Company’s assessment of the effectiveness of the Company’s internal control over financial reporting.

Other than incorporating the controls and related procedures of the acquired businesses, there were no changes in the Company’s internal control over financial reporting that occurred during the second quarter of 2025 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 8 of the Notes to Condensed Consolidated Financial Statements included in this Form 10-Q is incorporated by reference in response to this item.

Governmental Proceedings

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

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 (“NMSIP”) and certain other state and federal regulations pertaining to Company 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 this NOVOC for civil enforcement proceedings. In August 2023, we received a second NOVOC from the EPA alleging violations of the Clean Air Act, the NMSIP, and certain other state and federal regulations pertaining to Company facilities in New Mexico. We have exchanged information with the EPA and continue to engage in discussions aimed at resolving the allegations. At this time we are unable to predict with certainty the financial impact of these NOVOCs or the timing of any resolution. However, any enforcement action related to these NOVOCs will likely result in fines or penalties, or both, and corrective actions, which may increase our development costs and operating costs. We believe that any fines, penalties, or corrective actions that may result from these matters 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, 2025 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 2025	524	$	24.67	524	$	1,088
May 2025	405	$	24.66	405	$	1,078
June 2025	—	$	—	—	$	1,078
	929			929

_______________________________________________________________________________

(1)    All purchases during the covered periods were made under the share repurchase program, which was approved by our Board of Directors in February 2023 and which authorized the repurchase of up to $2.0 billion of our common stock. The share repurchase program does not have an expiration date. Purchases were made under terms intended to qualify for exemption under Rules 10b-18 and 10b5-1.

ITEM 5. Other Information

Amended and Restated Bylaws

On July 30, 2025, 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 enhance clarity and effect technical and administrative changes to conform to decisions by the

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Delaware Supreme Court and Delaware Court of Chancery since the prior amendment and restatement of the Company’s bylaws. The amendments effected by the Amended and Restated Bylaws, among other things:

•modify the disclosure requirements set forth in the advance notice bylaw provisions, including, without limitation, those relating to information, representations and disclosures from proposing stockholders, proposed nominees and other persons related to a stockholder’s solicitation of proxies, in each case to conform to recent decisions by the Delaware Supreme Court and Delaware Court of Chancery;

•modify certain provisions, including, without limitation, those relating to conduct at stockholders’ meetings and the appointment of a chair to preside thereat;

•provide that, at any meeting of the Board of Directors, a quorum shall consist of a majority of the directors then in office;

•provide that, with respect to committees, a majority of the members of each such committee then in office shall constitute a quorum for the transaction of business; 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.

Amendment to Amended and Restated Letter Agreement with Thomas E. Jorden

On July 31, 2025, at the recommendation of the Compensation Committee of the Board of Directors, the Company and Thomas E. Jorden entered into an Amendment to Amended and Restated Letter Agreement to extend the term of Mr. Jorden’s employment from October 1, 2026 to the date of the Company’s 2027 annual meeting of stockholders.

The foregoing summary of the Amendment to Amended and Restated Letter Agreement does not purport to be a complete description and is qualified in its entirety by reference to the full text of the Amendment to Amended and Restated Letter Agreement, a copy of which is filed as Exhibit 10.2 to this filing and incorporated herein by reference.

Trading Plan Arrangements

During the three months ended June 30, 2025, no director or officer of the Company adopted or terminated a “Rule 10b5-1 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	Amended and Restated Certificate of Incorporation of Coterra Energy Inc. (incorporated herein by reference to Exhibit 3.1 of Coterra’s Current Report on Form 8-K filed with the SEC on May 2, 2024).
**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	Amendment to Amended and Restated Letter Agreement dated as of July 31, 2025 between Coterra Energy Inc. and Thomas E. Jorden.*
**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.
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.

**    Filed herewith.

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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 5, 2025	By:	/s/ THOMAS E. JORDEN
		Thomas E. Jorden
		Chairman, Chief Executive Officer and President
		(Principal Executive Officer)
August 5, 2025	By:	/s/ SHANNON E. YOUNG III
		Shannon E. Young III
		Executive Vice President and Chief Financial Officer
		(Principal Financial Officer)
August 5, 2025	By:	/s/ TODD M. ROEMER
		Todd M. Roemer
		Vice President and Chief Accounting Officer
		(Principal Accounting Officer)

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