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Table of Contents
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 September 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 October 30, 2025, there were 761,377,552 shares of common stock, par value $0.10 per share, outstanding.

Table of Contents
COTERRA ENERGY INC.
TABLE OF CONTENTS

|  | Page
Part I. Financial Information |
Item 1. | Financial Statements |
Condensed Consolidated Balance Sheet (Unaudited) as of September 30, 2025 and December 31, 2024 | 3
Condensed Consolidated Statement of Operations (Unaudited) for the Three and Nine Months Ended September 30, 2025 and 2024 | 4
Condensed Consolidated Statement of Cash Flows (Unaudited) for the Nine Months Ended Sept ember 30, 2025 and 2024 | 5
Condensed Consolidated Statement of Stockholders’ Equity (Unaudited) for the Three and Nine Months Ended September 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 | 44
Signatures | 45

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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) |  | September 30, 2025 |  | December 31, 2024
ASSETS |  |  |  |
Current assets |  |  |  |
Cash and cash equivalents |  | $ | 98 |  |  | $ | 2,038 |
Restricted cash |  | 5 |  |  | 239 |
Accounts receivable, net |  | 1,012 |  |  | 951 |
Income taxes receivable |  | 210 |  |  | 20 |
Inventories |  | 61 |  |  | 46 |
Other current assets |  | 140 |  |  | 27 |
Total current assets |  | 1,526 |  |  | 3,321 |
Properties and equipment, net (Successful efforts method) |  | 22,167 |  |  | 17,890 |
Other assets |  | 314 |  |  | 414 |
|  | $ | 24,007 |  |  | $ | 21,625 |
LIABILITIES, REDEEMABLE PREFERRED STOCK AND STOCKHOLDERS’ EQUITY |  |  |  |
Current liabilities |  |  |  |
Accounts payable |  | $ | 1,027 |  |  | $ | 833 |
Current portion of long-term debt |  | 250 |  |  | — |
Accrued liabilities |  | 187 |  |  | 276 |
Interest payable |  | 25 |  |  | 27 |
Total current liabilities |  | 1,489 |  |  | 1,136 |
Long-term debt |  | 3,672 |  |  | 3,535 |
Deferred income taxes |  | 3,555 |  |  | 3,274 |
Asset retirement obligations |  | 326 |  |  | 291 |
Other liabilities |  | 239 |  |  | 259 |
Total liabilities |  | 9,281 |  |  | 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 — 764 shares and 735 shares in 2025 and 2024, respectively |  | 76 |  |  | 74 |
Additional paid-in capital |  | 7,931 |  |  | 7,179 |
Retained earnings |  | 6,696 |  |  | 5,857 |
Accumulated other comprehensive income |  | 15 |  |  | 12 |
Total stockholders' equity |  | 14,718 |  |  | 13,122 |
|  | $ | 24,007 |  |  | $ | 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 September 30, |  | Nine Months Ended September 30,
(In millions, except per share amounts) |  | 2025 |  | 2024 |  | 2025 |  | 2024
OPERATING REVENUES |  |  |  |  |  |  |  |
Oil |  | $ | 984 |  |  | $ | 765 |  |  | $ | 2,758 |  |  | $ | 2,240 |
Natural gas |  | 519 |  |  | 320 |  |  | 2,018 |  |  | 1,177 |
NGL |  | 213 |  |  | 186 |  |  | 638 |  |  | 535 |
Gain (loss) on derivative instruments, net |  | 62 |  |  | 64 |  |  | 182 |  |  | 48 |
Other |  | 39 |  |  | 24 |  |  | 90 |  |  | 63 |
|  | 1,817 |  |  | 1,359 |  |  | 5,686 |  |  | 4,063 |
OPERATING EXPENSES |  |  |  |  |  |  |  |
Direct operations |  | 275 |  |  | 165 |  |  | 727 |  |  | 481 |
Gathering, processing and transportation |  | 270 |  |  | 245 |  |  | 823 |  |  | 737 |
Taxes other than income |  | 93 |  |  | 66 |  |  | 276 |  |  | 194 |
Exploration |  | 7 |  |  | 9 |  |  | 21 |  |  | 19 |
Depreciation, depletion and amortization |  | 619 |  |  | 475 |  |  | 1,704 |  |  | 1,354 |
General and administrative |  | 83 |  |  | 75 |  |  | 259 |  |  | 218 |
|  | 1,347 |  |  | 1,035 |  |  | 3,810 |  |  | 3,003 |
Gain on sale of assets |  | 1 |  |  | 3 |  |  | 5 |  |  | 3 |
INCOME FROM OPERATIONS |  | 471 |  |  | 327 |  |  | 1,881 |  |  | 1,063 |
Interest expense |  | 50 |  |  | 24 |  |  | 156 |  |  | 77 |
Interest income |  | (2) |  |  | (16) |  |  | (12) |  |  | (51) |
Other income |  | — |  |  | — |  |  | (1) |  |  | — |
Income before income taxes |  | 423 |  |  | 319 |  |  | 1,738 |  |  | 1,037 |
Income tax expense |  | 101 |  |  | 67 |  |  | 389 |  |  | 213 |
NET INCOME |  | $ | 322 |  |  | $ | 252 |  |  | $ | 1,349 |  |  | $ | 824 |
Earnings per share |  |  |  |  |  |  |  |
Basic |  | $ | 0.42 |  |  | $ | 0.34 |  |  | $ | 1.77 |  |  | $ | 1.11 |
Diluted |  | $ | 0.42 |  |  | $ | 0.34 |  |  | $ | 1.76 |  |  | $ | 1.10 |
Weighted-average common shares outstanding |  |  |  |  |  |  |  |
Basic |  | 763 |  |  | 738 |  |  | 761 |  |  | 743 |
Diluted |  | 767 |  |  | 744 |  |  | 764 |  |  | 749 |

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)

|  | Nine Months Ended September 30, |  |  |  |  |  |  |  |  |  |  |  |  |
(In millions) |  | 2025 |  | 2024 |  |  |  |  |  |  |  |  |  |  |  |  |
CASH FLOWS FROM OPERATING ACTIVITIES |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Net income |  | $ | 1,349 |  |  | $ | 824 |  |  |  |  |  |  |  |  |  |  |  |  |  |
Adjustments to reconcile net income to net cash provided by operating activities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Depreciation, depletion and amortization |  | 1,704 |  |  | 1,354 |  |  |  |  |  |  |  |  |  |  |  |  |  |
Deferred income tax expense (benefit) |  | 285 |  |  | (60) |  |  |  |  |  |  |  |  |  |  |  |  |  |
Gain on sale of assets |  | (5) |  |  | (3) |  |  |  |  |  |  |  |  |  |  |  |  |  |
Exploratory dry hole cost |  | — |  |  | 5 |  |  |  |  |  |  |  |  |  |  |  |  |  |
(Gain) loss on derivative instruments, net |  | (182) |  |  | (48) |  |  |  |  |  |  |  |  |  |  |  |  |  |
Net cash received on settlement of derivative instruments |  | 49 |  |  | 90 |  |  |  |  |  |  |  |  |  |  |  |  |  |
Amortization of debt premium, discount and debt issuance costs, net |  | (12) |  |  | (13) |  |  |  |  |  |  |  |  |  |  |  |  |  |
Stock-based compensation and other |  | 43 |  |  | 43 |  |  |  |  |  |  |  |  |  |  |  |  |  |
Changes in assets and liabilities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Accounts receivable, net |  | 130 |  |  | 79 |  |  |  |  |  |  |  |  |  |  |  |  |  |
Income taxes |  | (189) |  |  | 44 |  |  |  |  |  |  |  |  |  |  |  |  |  |
Inventories |  | (12) |  |  | 13 |  |  |  |  |  |  |  |  |  |  |  |  |  |
Other current assets |  | 11 |  |  | (17) |  |  |  |  |  |  |  |  |  |  |  |  |  |
Accounts payable and accrued liabilities |  | (163) |  |  | (29) |  |  |  |  |  |  |  |  |  |  |  |  |  |
Interest payable |  | (2) |  |  | (5) |  |  |  |  |  |  |  |  |  |  |  |  |  |
Other assets and liabilities |  | 45 |  |  | (108) |  |  |  |  |  |  |  |  |  |  |  |  |  |
Net cash provided by operating activities |  | 3,051 |  |  | 2,169 |  |  |  |  |  |  |  |  |  |  |  |  |  |
CASH FLOWS FROM INVESTING ACTIVITIES |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Capital expenditures for drilling, completion and other fixed asset additions |  | (1,707) |  |  | (1,329) |  |  |  |  |  |  |  |  |  |  |  |  |  |
Capital expenditures for leasehold and property acquisitions |  | (86) |  |  | (6) |  |  |  |  |  |  |  |  |  |  |  |  |  |
Cash consideration paid for business combinations, net of cash received |  | (3,238) |  |  | — |  |  |  |  |  |  |  |  |  |  |  |  |  |
Purchases of short-term investments |  | — |  |  | (250) |  |  |  |  |  |  |  |  |  |  |  |  |  |
Proceeds from sale of short-term investments |  | — |  |  | 250 |  |  |  |  |  |  |  |  |  |  |  |  |  |
Other |  | (2) |  |  | 8 |  |  |  |  |  |  |  |  |  |  |  |  |  |
Net cash used in investing activities |  | (5,033) |  |  | (1,327) |  |  |  |  |  |  |  |  |  |  |  |  |  |
CASH FLOWS FROM FINANCING ACTIVITIES |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Proceeds from issuance of debt |  | 1,446 |  |  | 499 |  |  |  |  |  |  |  |  |  |  |  |  |  |
Repayments of debt |  | (1,046) |  |  | (575) |  |  |  |  |  |  |  |  |  |  |  |  |  |
Common stock repurchases |  | (51) |  |  | (401) |  |  |  |  |  |  |  |  |  |  |  |  |  |
Dividends paid |  | (514) |  |  | (470) |  |  |  |  |  |  |  |  |  |  |  |  |  |
Tax withholding on vesting of stock awards |  | (29) |  |  | — |  |  |  |  |  |  |  |  |  |  |  |  |  |
Other |  | 2 |  |  | (12) |  |  |  |  |  |  |  |  |  |  |  |  |  |
Net cash used in financing activities |  | (192) |  |  | (959) |  |  |  |  |  |  |  |  |  |  |  |  |  |
Net decrease in cash, cash equivalents and restricted cash |  | (2,174) |  |  | (117) |  |  |  |  |  |  |  |  |  |  |  |  |  |
Cash, cash equivalents and restricted cash, beginning of period |  | 2,277 |  |  | 965 |  |  |  |  |  |  |  |  |  |  |  |  |  |
Cash, cash equivalents and restricted cash, end of period |  | $ | 103 |  |  | $ | 848 |  |  |  |  |  |  |  |  |  |  |  |  |  |

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 |
Net income |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 322 |  |  | 322 |
Stock amortization and vesting |  | 1 |  |  | — |  |  | — |  |  | — |  |  | 11 |  |  | — |  |  | — |  |  | 11 |
Cash dividends on common stock at $0.22 per share |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (170) |  |  | (170) |
Other comprehensive loss |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (1) |  |  | — |  |  | (1) |
Balance at September 30, 2025 |  | 764 |  |  | $ | 76 |  |  | — |  |  | $ | — |  |  | $ | 7,931 |  |  | $ | 15 |  |  | $ | 6,696 |  |  | $ | 14,718 |

(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 |
Net income |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 252 |  |  | 252 |
Stock amortization and vesting |  | — |  |  | — |  |  | — |  |  | — |  |  | 17 |  |  | — |  |  | — |  |  | 17 |
Common stock repurchases |  | — |  |  | — |  |  | 4 |  |  | (108) |  |  | — |  |  | — |  |  | — |  |  | (108) |
Common stock retirements |  | (4) |  |  | — |  |  | (4) |  |  | 108 |  |  | (108) |  |  | — |  |  | — |  |  | — |
Cash dividends on common stock at $0.21 per share |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (156) |  |  | (156) |
Balance at September 30, 2024 |  | 736 |  |  | $ | 74 |  |  | — |  |  | $ | — |  |  | $ | 7,233 |  |  | $ | 11 |  |  | $ | 5,716 |  |  | $ | 13,034 |

The accompanying notes are an integral part of these condensed consolidated financial statements.
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COTERRA ENERGY INC.
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)
1. Financial Statement Presentation
During interim periods, Coterra Energy Inc. (the “Company”) follows the same accounting policies disclosed in its Annual Report on Form 10-K for the year ended December 31, 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 Company does not anticipate any significant changes to the preliminary purchase price allocation. Management continues to refine the preliminary valuation of certain assets acquired and liabilities assumed and expects to finalize the purchase price allocation in first quarter of 2026.
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.
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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) | 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 releases of escrow funds totaling $123 million. These funds were included in restricted cash in the Condensed Consolidated Balance Sheet as of December 31, 2024.
FME Post-Acquisition Operating Results
The FME Interests contributed the following to the Company’s consolidated operating results:

(In millions) |  | Three Months Ended September 30, 2025 |  | January 28, 2025 through September 30, 2025
Revenue |  | $ | 204 |  |  | $ | 588 |
Net income |  | $ | 118 |  |  | $ | 263 |

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 the closing date of the acquisition. The Company does not anticipate any significant changes to the preliminary purchase price
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allocation. Management continues to refine the preliminary valuation of certain assets acquired and liabilities assumed and expects to finalize the purchase price allocation in first quarter of 2026.
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 releases of escrow funds totaling $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) |  | Three Months Ended September 30, 2025 |  | January 18, 2025 through September 30, 2025
Revenue |  | $ | 77 |  |  | $ | 195 |
Net income |  | $ | 26 |  |  | $ | 56 |

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 nine months ended September 30, 2025 and 2024 and the three months ended September 30, 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
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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.
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 September 30, |  | Nine Months Ended September 30,
(In millions) | 2024 |  | 2025 |  | 2024
Pro forma revenue | $ | 1,713 |  |  | $ | 5,781 |  |  | $ | 5,021 |
Pro forma net income | $ | 355 |  |  | $ | 1,641 |  |  | $ | 1,093 |

Other Information
In connection with the FME and Avant acquisitions, the Company recognized $15 million of transaction costs for the nine months ended September 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) |  | September 30, 2025 |  | December 31, 2024
Proved oil and gas properties |  | $ | 26,401 |  |  | $ | 21,765 |
Unproved oil and gas properties |  | 4,976 |  |  | 4,105 |
Gathering and pipeline systems |  | 1,036 |  |  | 620 |
Land, buildings and other equipment |  | 260 |  |  | 213 |
Finance lease right-of-use asset |  | — |  |  | 26 |
|  | 32,673 |  |  | 26,729 |
Accumulated DD&A |  | (10,506) |  |  | (8,839) |
|  | $ | 22,167 |  |  | $ | 17,890 |

Capitalized Exploratory Well Costs
As of and for the nine months ended September 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) |  | September 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 |  | — |  |  | — |
Tranche B term loan due January 17, 2028 |  | 400 |  |  | — |
|  | 3,900 |  |  | 3,500 |
Unamortized debt premium |  | 53 |  |  | 69 |
Unamortized debt discount |  | (10) |  |  | (10) |
Unamortized debt issuance costs |  | (21) |  |  | (24) |
Total debt, net |  | 3,922 |  |  | 3,535 |
Less: current portion of long-term debt |  | 250 |  | —
Long-term debt |  | $ | 3,672 |  |  | $ | 3,535 |

As of September 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 2025, the Company borrowed and repaid $446 million under its revolving credit agreement. The Company’s weighted-average interest rate for borrowings under the revolving credit agreement for the three and nine months ended September 30, 2025 was 7.7 percent. There were no borrowings under the revolving credit agreement during 2024.
As of September 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 consisted 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 2025, the Company repaid the full $500 million Tranche A Term Loan and $100 million of the Tranche B Term Loan.
During the three and nine months ended September 30, 2025, the weighted-average effective interest rate on the Company’s Term Loan was approximately 5.8 percent. As of September 30, 2025, the effective interest rate on the Company’s Term Loan was approximately 5.6 percent.
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5. Derivative Instruments
As of September 30, 2025, the Company had the following outstanding financial commodity derivatives:

|  |  |  |  |  |  |  |  | 2025 |  | 2026 |  |
Oil |  |  |  |  |  |  |  |  | Fourth Quarter |  | First Quarter |  | Second Quarter |  | Third Quarter |  | Fourth Quarter |  |  |  |  |  |
WTI oil collars |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Volume (MBbl) |  |  |  |  |  |  |  |  | 5,152 |  | 3,600 |  | 3,640 |  | 3,680 |  | 3,680 |  |  |  |  |  |
Weighted average floor ($/Bbl) |  |  |  |  |  |  |  |  | $ | 61.34 |  |  | $ | 56.25 |  |  | $ | 56.25 |  |  | $ | 56.25 |  |  | $ | 56.25 |  |  |  |  |  |  |
Weighted average ceiling ($/Bbl) |  |  |  |  |  |  |  |  | $ | 79.00 |  |  | $ | 70.81 |  |  | $ | 70.81 |  |  | $ | 70.81 |  |  | $ | 70.81 |  |  |  |  |  |  |
WTI-NYMEX oil swaps |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Volume (MBbl) |  |  |  |  |  |  |  |  | 1,748 |  | 900 |  | 910 |  | 920 |  | 920 |  |  |  |  |  |
Weighted average price ($/Bbl) |  |  |  |  |  |  |  |  | $ | 69.18 |  |  | $ | 66.14 |  |  | $ | 66.14 |  |  | $ | 66.14 |  |  | $ | 66.14 |  |  |  |  |  |  |
WTI Midland oil basis swaps |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Volume (MBbl) |  |  |  |  |  |  |  |  | 5,520 |  | 4,500 |  | 4,550 |  | 4,600 |  | 4,600 |  |  |  |  |  |
Weighted average differential ($/Bbl) |  |  |  |  |  |  |  |  | $ | 1.02 |  |  | $ | 0.97 |  |  | $ | 0.97 |  |  | $ | 0.97 |  |  | $ | 0.97 |  |  |  |  |  |  |

|  |  |  |  |  |  |  |  |  | 2025 |  | 2026 |  |  |  |  |  |  |  |  |  |  |
Natural Gas |  |  |  |  |  |  |  |  |  | Fourth Quarter |  | First Quarter |  | Second Quarter |  | Third Quarter |  | Fourth Quarter |  |  |  |  |  |  |  |  |  |  |
NYMEX gas collars |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Volume (MMBtu) |  |  |  |  |  |  |  |  |  | 87,400,000 |  | 81,000,000 |  | 54,600,000 |  | 55,200,000 |  | 55,200,000 |  |  |  |  |  |  |  |  |  |  |
Weighted average floor ($/MMBtu) |  |  |  |  |  |  |  |  |  | $ | 3.08 |  |  | $ | 3.06 |  |  | $ | 3.21 |  |  | $ | 3.21 |  |  | $ | 3.21 |  |  |  |  |  |  |  |  |  |  |  |
Weighted average ceiling ($/MMBtu) |  |  |  |  |  |  |  |  |  | $ | 5.66 |  |  | $ | 6.39 |  |  | $ | 5.76 |  |  | $ | 5.76 |  |  | $ | 5.76 |  |  |  |  |  |  |  |  |  |  |  |
Transco Leidy gas basis swaps |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Volume (MMBtu) |  |  |  |  |  |  |  |  |  | 18,400,000 |  | — |  | — |  | — |  | — |  |  |  |  |  |  |  |  |  |  |
Weighted average differential ($/MMBtu) |  |  |  |  |  |  |  |  |  | $ | (0.70) |  |  | — |  | — |  | — |  | — |  |  |  |  |  |  |  |  |  |  |
Transco Zone 6 Non-NY gas basis swaps |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Volume (MMBtu) |  |  |  |  |  |  |  |  |  | 18,400,000 |  | 13,500,000 |  | 13,650,000 |  | 13,800,000 |  | 13,800,000 |  |  |  |  |  |  |  |  |  |  |
Weighted average differential ($/MMBtu) |  |  |  |  |  |  |  |  |  | $ | (0.49) |  |  | $ | (0.26) |  |  | $ | (0.26) |  |  | $ | (0.26) |  |  | $ | (0.26) |  |  |  |  |  |  |  |  |  |  |  |
Waha gas basis swaps |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Volume (MMBtu) |  |  |  |  |  |  |  |  |  | 13,800,000 |  | 13,500,000 |  | 13,650,000 |  | 13,800,000 |  | 13,800,000 |  |  |  |  |  |  |  |  |  |  |
Weighted average differential ($/MMBtu) |  |  |  |  |  |  |  |  |  | $ | (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 |  | September 30, 2025 |  | December 31, 2024 |  | September 30, 2025 |  | December 31, 2024
Commodity contracts |  | Other current assets |  | $ | 124 |  |  | $ | 12 |  |  | $ | — |  |  | $ | — |
Commodity contracts |  | Accrued liabilities |  | — |  |  | — |  |  | 3 |  |  | 17 |
Commodity contracts |  | Other assets |  | 12 |  |  | — |  |  | — |  |  | — |
Commodity contracts |  | Other liabilities |  | — |  |  | — |  |  | 9 |  |  | 4 |
|  |  |  | $ | 136 |  |  | $ | 12 |  |  | $ | 12 |  |  | $ | 21 |

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

(In millions) |  | September 30, 2025 |  | December 31, 2024
Derivative assets |  |  |  |
Gross amounts of recognized assets |  | $ | 153 |  |  | $ | 26 |
Gross amounts offset in the condensed consolidated balance sheet |  | (17) |  |  | (14) |
Net amounts of assets presented in the condensed consolidated balance sheet |  | 136 |  |  | 12 |
Gross amounts of financial instruments not offset in the condensed consolidated balance sheet |  | 4 |  |  | — |
Net amount |  | $ | 140 |  |  | $ | 12 |
Derivative liabilities |  |  |  |
Gross amounts of recognized liabilities |  | $ | 29 |  |  | $ | 35 |
Gross amounts offset in the condensed consolidated balance sheet |  | (17) |  |  | (14) |
Net amounts of liabilities presented in the condensed consolidated balance sheet |  | 12 |  |  | 21 |
Gross amounts of financial instruments not offset in the condensed consolidated balance sheet |  | — |  |  | — |
Net amount |  | $ | 12 |  |  | $ | 21 |

Effect of Derivative Instruments on the Condensed Consolidated Statement of Operations

|  | Three Months Ended September 30, |  | Nine Months Ended September 30,
(In millions) |  | 2025 |  | 2024 |  | 2025 |  | 2024
Cash received on settlement of derivative instruments |  |  |  |  |  |  |  |
Oil contracts |  | $ | 10 |  |  | $ | 1 |  |  | $ | 22 |  |  | $ | — |
Gas contracts |  | 26 |  |  | 27 |  |  | 27 |  |  | 90 |
Non-cash gain (loss) on derivative instruments |  |  |  |  |  |  |  |
Oil contracts |  | (25) |  |  | 48 |  |  | 63 |  |  | 14 |
Gas contracts |  | 51 |  |  | (12) |  |  | 70 |  |  | (56) |
|  | $ | 62 |  |  | $ | 64 |  |  | $ | 182 |  |  | $ | 48 |

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 September 30, 2025
Assets |  |  |  |  |  |  |  |
Deferred compensation plan |  | $ | 20 |  |  | $ | — |  |  | $ | — |  |  | $ | 20 |
Derivative instruments |  | — |  |  | 30 |  |  | 123 |  |  | 153 |
|  | $ | 20 |  |  | $ | 30 |  |  | $ | 123 |  |  | $ | 173 |
Liabilities |  |  |  |  |  |  |  |
Deferred compensation plan |  | $ | 20 |  |  | $ | — |  |  | $ | — |  |  | $ | 20 |
Derivative instruments |  | — |  |  | — |  |  | 29 |  |  | 29 |
|  | $ | 20 |  |  | $ | — |  |  | $ | 29 |  |  | $ | 49 |

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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. 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. 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:

|  | Nine Months Ended September 30,
(In millions) |  | 2025 |  | 2024
Balance at beginning of period |  | $ | (9) |  |  | $ | 92 |
Total gain included in earnings |  | 140 |  |  | 48 |
Settlement gain |  | (37) |  |  | (90) |
Balance at end of period |  | $ | 94 |  |  | $ | 50 |
Change in unrealized gains relating to assets and liabilities still held at the end of the period |  | $ | 95 |  |  | $ | 30 |

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 September 30, 2025, additional disclosures were not required.
The estimated fair value of the Company’s asset retirement obligations at inception is determined by utilizing the income approach by applying a credit-adjusted risk-free rate, which takes into account the Company’s credit risk, the time value of
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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:

|  | September 30, 2025 |  | December 31, 2024
(In millions) |  | Carrying Amount |  | Estimated Fair Value |  | Carrying Amount |  | Estimated Fair Value
Total debt |  | $ | 3,922 |  |  | $ | 3,869 |  |  | $ | 3,535 |  |  | $ | 3,395 |
Current maturities |  | (250) |  |  | (248) |  |  | — |  |  | — |
Long-term debt, excluding current maturities |  | $ | 3,672 |  |  | $ | 3,621 |  |  | $ | 3,535 |  |  | $ | 3,395 |

7. Asset Retirement Obligations
Activity related to the Company’s asset retirement obligations is as follows:

|  | Nine Months Ended September 30,
(In millions) |  | 2025 |  | 2024
Balance at beginning of period |  | $ | 302 |  |  | $ | 289 |
Liabilities incurred |  | 8 |  |  | 6
Liabilities settled |  | (2) |  |  | (2) |
Liabilities assumed in acquisitions |  | 19 |  |  | — |
Accretion expense |  | 11 |  |  | 8
Balance at end of period |  | 338 |  |  | 301 |
Less: current asset retirement obligations |  | (12) |  |  | (13) |
Noncurrent asset retirement obligations |  | $ | 326 |  |  | $ | 288 |

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.
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Legal Matters
The Company is a defendant in various 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 September 30, |  | Nine Months Ended September 30,
(In millions) |  | 2025 |  | 2024 |  | 2025 |  | 2024
Oil |  | $ | 984 |  |  | $ | 765 |  |  | $ | 2,758 |  |  | $ | 2,240 |
Natural gas |  | 519 |  |  | 320 |  |  | 2,018 |  |  | 1,177 |
NGL |  | 213 |  |  | 186 |  |  | 638 |  |  | 535 |
Other |  | 39 |  |  | 24 |  |  | 90 |  |  | 63 |
|  | $ | 1,755 |  |  | $ | 1,295 |  |  | $ | 5,504 |  |  | $ | 4,015 |

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 September 30, 2025, the Company had $5.7 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 13 years.
Contract Balances
Receivables from contracts with customers are recorded when the right to consideration becomes unconditional, generally when control of the product has been transferred to the customer. Receivables from contracts with customers were $737 million and $820 million as of September 30, 2025 and December 31, 2024, respectively, and are reported in accounts receivable, net in the Condensed Consolidated Balance Sheet. As of September 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 (“OBBBA”). The OBBBA, among other tax provisions, (i) restores 100 percent bonus depreciation for qualified property acquired and placed in service after January 19, 2025, unless the property was subject to a legally binding written contract entered into before that date, (ii) restores immediate expensing of domestic research and development expenditures for tax years after December 31, 2024, (iii) restores a more favorable EBITDA-based calculation for the business interest expense deduction limitation 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.
The effects of the provisions of the OBBBA have been reflected in the Company’s financial statements for the quarter ended September 30, 2025. While the enactment of the OBBBA did not result in a material change to the Company’s total income tax expense, it had a material impact on the allocation between current and deferred taxes. Specifically, the
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reinstatement of 100 percent bonus depreciation and immediate expensing of domestic research and development costs resulted in a significant reduction to current tax expense, with a corresponding increase in deferred tax expense.
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 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 nine months ended September 30, 2025 and 2024:

|  | Rate Per Share (1) |  |  |  |  |  | Total Dividends Paid (In millions)
2025 |  |  |  |  |  |  |  |
First quarter |  | $ | 0.22 |  |  |  |  |  |  | $ | 170 |
Second quarter |  | 0.22 |  |  |  |  |  |  | 170 |
Third quarter |  | 0.22 |  |  |  |  |  |  | 170 |
|  | $ | 0.66 |  |  |  |  |  |  | $ | 510 |
2024 |  |  |  |  |  |  |  |
First quarter |  | $ | 0.21 |  |  |  |  |  |  | $ | 160 |
Second quarter |  | 0.21 |  |  |  |  |  |  | 158 |
Third quarter |  | 0.21 |  |  |  |  |  |  | 156 |
|  | $ | 0.63 |  |  |  |  |  |  | $ | 474 |

________________________________________________________
(1) Increases to the Company’s dividends were previously approved by the Company’s Board of Directors in the February meeting of the respective year presented.
Treasury Stock
During the nine months ended September 30, 2025 and 2024, the Company repurchased and retired 2 million shares for $47 million and 15 million shares for $404 million, respectively. As of September 30, 2025, the Company had $1.1 billion remaining under its current share repurchase program.
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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 September 30, |  | Nine Months Ended September 30,
(In millions) |  | 2025 |  | 2024 |  | 2025 |  | 2024
Restricted stock units - employees and non-employee directors |  | $ | 12 |  |  | $ | 11 |  |  | $ | 36 |  |  | $ | 32 |
Restricted stock awards |  | — |  |  | 3 |  |  | — |  |  | 6 |
Performance share awards |  | 1 |  |  | — |  |  | 7 |  |  | 5 |
Total stock-based compensation expense |  | $ | 13 |  |  | $ | 14 |  |  | $ | 43 |  |  | $ | 43 |
Income tax benefit |  | $ | 4 |  |  | $ | — |  |  | $ | 21 |  |  | $ | — |

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 nine months ended September 30, 2025, the Company granted 2,427,872 restricted stock units to employees of the Company with a weighted average grant date value of $25.52 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 or five-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 nine months ended September 30, 2025, 1,806,642 restricted stock units granted in 2022 vested. The weighted average grant date value was $24.96 per unit.
Restricted Stock Units - Non-Employee Directors
During the nine months ended September 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 nine months ended September 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 nine months ended September 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 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.
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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 |  | September 30, 2025
Fair value per performance share award |  | $ | 21.49 |  |  | $2.24 - $3.54
Assumptions: |  |  |  |
Stock price volatility |  | 33.8 | % |  | 23.8% - 28.7%
Risk-free rate of return |  | 4.25 | % |  | 3.57% - 3.94%

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 September 30, |  | Nine Months Ended September 30,
(In millions, except per share amounts) |  | 2025 |  | 2024 |  | 2025 |  | 2024
Income (Numerator) |  |  |  |  |  |  |  |
Net income |  | $ | 322 |  |  | $ | 252 |  |  | $ | 1,349 |  |  | $ | 824 |
Less: dividends attributable to participating securities |  | (1) |  |  | (1) |  |  | (1) |  |  | (2) |
Net income available to common stockholders |  | $ | 321 |  |  | $ | 251 |  |  | $ | 1,348 |  |  | $ | 822 |
Shares (Denominator) |  |  |  |  |  |  |  |
Weighted average shares - Basic |  | 763 |  |  | 738 |  |  | 761 |  |  | 743 |
Dilution effect of stock awards at end of period |  | 4 |  |  | 6 |  |  | 3 |  |  | 6 |
Weighted average shares - Diluted |  | 767 |  |  | 744 |  |  | 764 |  |  | 749 |
Earnings per share |  |  |  |  |  |  |  |
Basic |  | $ | 0.42 |  |  | $ | 0.34 |  |  | $ | 1.77 |  |  | $ | 1.11 |
Diluted |  | $ | 0.42 |  |  | $ | 0.34 |  |  | $ | 1.76 |  |  | $ | 1.10 |

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

|  | Three Months Ended September 30, |  | Nine Months Ended September 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 |  |  | — |

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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:

|  | Nine Months Ended September 30,
(In millions) |  | 2025 |  | 2024
Balance at beginning of period |  | $ | 13 |  |  | $ | 47 |
Reductions related to severance payments |  | (11) |  |  | (27) |
Balance at end of period |  | $ | 2 |  |  | $ | 20 |

15. Additional Balance Sheet Information
Certain balance sheet amounts are comprised of the following:

(In millions) |  | September 30, 2025 |  | December 31, 2024
Accounts receivable, net |  |  |  |
Trade accounts |  | $ | 737 |  |  | $ | 820 |
Joint interest accounts |  | 271 |  |  | 133 |
Other accounts |  | 6 |  |  | — |
|  | 1,014 |  |  | 953 |
Allowance for credit losses |  | (2) |  |  | (2) |
|  | $ | 1,012 |  |  | $ | 951 |
Inventories |  |  |  |
Tubular goods and well equipment |  | $ | 45 |  |  | $ | 33 |
Commodity inventory |  | 16 |  |  | 13 |
|  | $ | 61 |  |  | $ | 46 |
Other current assets |  |  |  |
Prepaid balances |  | $ | 13 |  |  | $ | 14 |
Derivative instruments |  | 124 |  |  | 12 |
Other accounts |  | 3 |  |  | 1 |
|  | $ | 140 |  |  | $ | 27 |
Other assets |  |  |  |
Deferred compensation plan |  | $ | 20 |  |  | $ | 17 |
Debt issuance costs |  | 9 |  |  | 10 |
Operating lease right-of-use assets |  | 186 |  |  | 251 |
Derivative instruments |  | 12 |  |  | — |
Other accounts |  | 87 |  |  | 136 |
|  | $ | 314 |  |  | $ | 414 |
Accounts payable |  |  |  |
Trade accounts |  | $ | 81 |  |  | $ | 59 |
Royalty and other owners |  | 472 |  |  | 402 |
Accrued gathering, processing and transportation |  | 60 |  |  | 85 |
Accrued capital costs |  | 251 |  |  | 177 |
Taxes other than income |  | 62 |  |  | 37 |
Accrued lease operating costs |  | 79 |  |  | 48 |
Other accounts |  | 22 |  |  | 25 |
|  | $ | 1,027 |  |  | $ | 833 |

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(In millions) |  | September 30, 2025 |  | December 31, 2024
Accrued liabilities |  |  |  |
Employee benefits |  | $ | 69 |  |  | $ | 76 |
Taxes other than income |  | 33 |  |  | 46 |
Restructuring liabilities |  | 2 |  |  | 13 |
Derivative instruments |  | 3 |  |  | 17 |
Operating lease liabilities |  | 79 |  |  | 115 |
Financing lease liabilities |  | — |  |  | 7 |
Other accounts |  | 1 |  |  | 2 |
|  | $ | 187 |  |  | $ | 276 |
Other liabilities |  |  |  |
Deferred compensation plan |  | $ | 20 |  |  | $ | 17 |
Postretirement benefits |  | 10 |  |  | 16 |
Derivative instruments |  | 9 |  |  | 4 |
Operating lease liabilities |  | 116 |  |  | 145 |
Other accounts |  | 84 |  |  | 77 |
|  | $ | 239 |  |  | $ | 259 |

16. Interest Expense
Interest expense is comprised of the following:

|  | Three Months Ended September 30, |  | Nine Months Ended September 30,
(In millions) |  | 2025 |  | 2024 |  | 2025 |  | 2024
Interest Expense |  |  |  |  |  |  |  |
Interest expense |  | $ | 53 |  |  | $ | 27 |  |  | $ | 162 |  |  | $ | 76 |
Debt (premium) discount amortization, net |  | (5) |  |  | (5) |  |  | (16) |  |  | (16) |
Debt issuance cost amortization |  | 3 |  |  | 1 |  |  | 6 |  |  | 3 |
Other |  | (1) |  |  | 1 |  |  | 4 |  |  | 14 |
|  | $ | 50 |  |  | $ | 24 |  |  | $ | 156 |  |  | $ | 77 |

17. Supplemental Cash Flow Information

| Nine Months Ended September 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 nine month periods ended September 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 nine months ended September 30, 2025 compared to the nine months ended September 30, 2024 reflect the following:
•Net income increased $525 million from $824 million, or $1.11 per share, in 2024 to $1.3 billion, or $1.77 per share, in 2025.
•Net cash provided by operating activities increased $882 million, from $2.2 billion in 2024 to $3.1 billion in 2025.
•Equivalent production increased 25.9 MMBoe from 184.9 MMBoe, or 674.8 MBoe per day, in 2024 to 210.8 MMBoe, or 772.0 MBoe per day, in 2025.
◦Oil production increased 12.8 MMBbl from 29.4 MMBbl, or 107.4 MBbl per day, in 2024 to 42.2 MMBbl, or 154.6 MBbl per day, in 2025.
◦Natural gas production increased 44.0 Bcf from 769.1 Bcf, or 2,806.8 MMcf per day, in 2024 to 813.1 Bcf, or 2,978.5 MMcf per day, in 2025.
◦NGL volumes increased 5.8 MMBbl from 27.3 MMBbl, or 99.6 MBbl per day, in 2024 to 33.1 MMBbl, or 121.1 MBbl per day, in 2025.
•Average realized prices (including impact of derivatives):
◦Oil was $65.89 per Bbl in 2025, 13 percent lower than the $76.17 per Bbl realized in 2024.
◦Natural gas was $2.52 per Mcf in 2025, 53 percent higher than the $1.65 per Mcf realized in 2024.
◦NGL price was $19.29 per Bbl in 2025, two percent lower than the $19.59 per Bbl realized in 2024.
•Total capital expenditures for drilling, completion and other fixed assets were $1.8 billion in 2025 compared to $1.3 billion in the corresponding period of the prior year.
Other financial highlights for the nine months ended September 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 dividend from $0.21 per share to $0.22 per share in February 2025.
•Repaid the full $500 million of the Tranche A Term Loan and paid down $100 million of the Tranche B Term Loan.
•Repurchased 2 million shares of our common stock 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 2025, with the largest decline occurring in April 2025 in both spot and forward pricing. Throughout 2025, forward pricing for oil prices has continued to decline due to growing global inventories and increased production quotas that have been announced by OPEC+ in the second and third quarters of 2025. 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. The impacts of these changes remain to be seen.
Natural gas prices, which rose in early 2025, have continued to trend downward through the third quarter, driven in part by lower natural gas power burns in the first and second quarter and record high domestic production. Heading into 2026, forward pricing for natural gas prices has increased, in part as a result of anticipated colder temperatures, shifting weather models, and expected growing LNG demand. However, shifting U.S. and international trade policy and related uncertainty, including potential retaliatory tariffs on U.S. exports of LNG, continue to contribute to ongoing volatility in natural gas pricing. Additionally, basis differentials have persisted in the U.S., with prices at the Waha Hub in the Permian Basin particularly depressed due to pipeline maintenance and production oversupply, reaching negative spot pricing at various times in September 2025. Despite these headwinds, we continue to expect natural gas prices overall to be stronger in 2025 and heading into 2026 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 (“OBBBA”). The effects of the provisions of the OBBBA have been reflected in our financial statements for the quarter ended September 30, 2025. While the enactment of the OBBBA did not result in a material change to our total income tax expense, it had 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 resulted in a significant reduction to current tax expense, with a corresponding increase in deferred tax expense.
Outlook
Our 2025 full-year capital program is expected to be approximately $2.3 billion. We expect to fund these capital expenditures with our operating cash flow. We expect to turn-in-line 194 to 198 total net wells in 2025 across our three
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operating regions. We currently expect to invest approximately 67 percent of our capital expenditures in the Permian Basin, 14 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 nine months ended September 30, 2025, our capital program focused on the Permian Basin, Marcellus Shale and Anadarko Basin, where we drilled 154.6 net wells and turned in line 146.4 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 September 30, 2025, our working capital surplus of $37 million was lower than prior year, primarily due to a lower cash position as a result of funding the purchase price of the Franklin Mountain Energy (“FME”) and Avant acquisitions that closed in January 2025, the full repayment of the Tranche A Term Loan of $500 million in 2025 and the partial repayment of the Tranche B Term Loan of $100 million in 2025. Additionally, we reclassified our 3.77% private placement senior notes due in September 2026 to current debt during the third quarter 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 and debt repayments over the next 12 months.
As of September 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 $98 million.
Our revolving credit agreement and term loan include a covenant potentially limiting our borrowing capacity as determined by our leverage ratio. As of September 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:

|  | Nine Months Ended September 30, |  | Variance
(In millions) |  | 2025 |  | 2024 |  | Amount |  | Percent
Cash flows provided by operating activities |  | $ | 3,051 |  |  | $ | 2,169 |  |  | $ | 882 |  |  | 41 | %
Cash flows used in investing activities |  | (5,033) |  |  | (1,327) |  |  | (3,706) |  |  | 279 | %
Cash flows used in financing activities |  | (192) |  |  | (959) |  |  | 767 |  |  | 80 | %
Net decrease in cash, cash equivalents and restricted cash |  | $ | (2,174) |  |  | $ | (117) |  |  | $ | (2,057) |  |  | 1,758 | %

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 nine months ended September 30, 2025 increased by $882 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 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 nine 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 $3.7 billion for the nine months ended September 30, 2025 compared to the nine months ended September 30, 2024. This increase was primarily due to $3.2 billion of net cash consideration paid for business combinations and $458 million higher cash paid for capital expenditures in 2025 compared to 2024.
Financing Activities. Cash flows used in financing activities decreased by $767 million for the nine months ended September 30, 2025 compared to the nine months ended September 30, 2024. The decrease was due to $947 million higher proceeds from issuance of debt due to the funding of our term loan in 2025 and borrowings under our revolver and $350 million lower common stock repurchases. These decreases were partially offset by the repayment of the $500 million Tranche A Term Loan in 2025, the partial repayment of $100 million of the Tranche B Term Loan in 2025 and the $446 million repayment of borrowings under our revolver during 2025, compared to the repayment of the $575 million 3.65% weighted-average senior notes at their maturity in September 2024. Further, the decrease was partially offset by $44 million of higher dividend payments and $29 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) |  | September 30, 2025 |  | December 31, 2024
Total debt (1) |  | $ | 3,922 |  |  | $ | 3,535 |
Stockholders’ equity |  | 14,718 |  |  | 13,122 |
Total capitalization |  | $ | 18,640 |  |  | $ | 16,657 |
Debt to total capitalization |  | 21 | % |  | 21 | %
Cash and cash equivalents |  | $ | 98 |  |  | $ | 2,038 |

________________________________________________________
(1) There were no borrowings outstanding under our revolving credit agreement as of September 30, 2025 and December 31, 2024.
Share repurchases. During the nine months ended September 30, 2025, we repurchased and retired 2 million shares of our common stock for $47 million. We repurchased and retired 15 million shares of our common stock for $404 million during the nine months ended September 30, 2024.
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As of September 30, 2025, we had $1.1 billion remaining under our current share repurchase program.
Dividends. In February 2025, our Board of Directors approved an increase in the quarterly dividend from $0.21 per share to $0.22 per share.
The following table summarizes our dividends on our common stock for the nine months ended September 30, 2025 and 2024:

|  | Rate Per Share |  |  |  |  |  | Total Dividends (In millions)
2025 |  |  |  |  |  |  |  |
First quarter |  | $ | 0.22 |  |  |  |  |  |  | $ | 170 |
Second quarter |  | 0.22 |  |  |  |  |  |  | 170 |
Third quarter |  | 0.22 |  |  |  |  |  |  | 170 |
|  | $ | 0.66 |  |  |  |  |  |  | $ | 510 |
2024 |  |  |  |  |  |  |  |
First quarter |  | $ | 0.21 |  |  |  |  |  |  | $ | 160 |
Second quarter |  | 0.21 |  |  |  |  |  |  | 158 |
Third quarter |  | 0.21 |  |  |  |  |  |  | 156 |
|  | $ | 0.63 |  |  |  |  |  |  | $ | 474 |

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:

|  | Nine Months Ended September 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 |  | $ | 1,652 |  |  | $ | 1,261 |
Pipeline and gathering |  | 94 |  |  | 73 |
Other |  | 33 |  |  | 11 |
Capital expenditures for drilling, completion and other fixed asset additions |  | 1,779 |  |  | 1,345 |
Capital expenditures for leasehold and property acquisitions |  | 86 |  |  | 6 |
Exploration expenditures (1) |  | 21 |  |  | 19 |
|  | $ | 1,886 |  |  | $ | 1,370 |

________________________________________________________
(1)Exploration expenditures include no exploratory dry hole costs for the nine months ended September 30, 2025 and $5 million of exploratory dry hole costs for the nine months ended September 30, 2024.
For the nine months ended September 30, 2025, our capital program focused on the Permian Basin, Marcellus Shale and Anadarko Basin, where we drilled 154.6 net wells and turned-in-line 146.4 net wells. We expect that our full-year 2025 capital program will be approximately $2.3 billion. 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.
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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 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
Third Quarters of 2025 and 2024 Compared
Operating Revenues

|  | Three Months Ended September 30, |  | Variance
(In millions) |  | 2025 |  | 2024 |  | Amount |  | Percent
Operating Revenues |  |  |  |  |  |  |  |
Oil |  | $ | 984 |  |  | $ | 765 |  |  | $ | 219 |  |  | 29 | %
Natural gas |  | 519 |  |  | 320 |  |  | 199 |  |  | 62 | %
NGL |  | 213 |  |  | 186 |  |  | 27 |  |  | 15 | %
Gain (loss) on derivative instruments, net |  | 62 |  |  | 64 |  |  | (2) |  |  | (3) | %
Other |  | 39 |  |  | 24 |  |  | 15 |  |  | 63 | %
|  | $ | 1,817 |  |  | $ | 1,359 |  |  | $ | 458 |  |  | 34 | %

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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 September 30, |  | Variance
|  | 2025 |  | 2024 |  | Amount |  | Percent
Production Volumes |  |  |  |  |  |  |  |
Oil (MMBbl) |  | 15.3 |  | 10.3 |  | 5.0 |  |  | 49 | %
Natural gas (Bcf) |  | 266.3 |  | 246.7 |  | 19.6 |  |  | 8 | %
NGL (MMBbl) |  | 12.5 |  | 10.1 |  | 2.4 |  |  | 24 | %
Equivalents (MMBoe) |  | 72.2 |  | 61.6 |  | 10.6 |  |  | 17 | %
Average Daily Production Volumes |  |  |  |  |  |  |  |
Oil (MBbl) |  | 166.8 |  | 112.3 |  | 54.5 |  | 49 | %
Natural gas (MMcf) |  | 2,894.6 |  | 2,682.0 |  | 212.6 |  | 8 | %
NGL (MBbl) |  | 135.8 |  | 109.7 |  | 26.1 |  | 24 | %
Equivalents (MBoe) |  | 785.0 |  | 669.1 |  | 115.9 |  | 17 | %
Average Sales Price |  |  |  |  |  |  |  |
Excluding Derivative Settlements |  |  |  |  |  |  |  |
Oil ($/Bbl) |  | $ | 64.10 |  |  | $ | 74.04 |  |  | $ | (9.94) |  |  | (13) | %
Natural gas ($/Mcf) |  | $ | 1.95 |  |  | $ | 1.30 |  |  | $ | 0.65 |  |  | 50 | %
NGL ($/Bbl) |  | $ | 17.02 |  |  | $ | 18.42 |  |  | $ | (1.40) |  |  | (8) | %
Including Derivative Settlements |  |  |  |  |  |  |  |
Oil ($/Bbl) |  | $ | 64.79 |  |  | $ | 74.18 |  |  | $ | (9.39) |  |  | (13) | %
Natural gas ($/Mcf) |  | $ | 2.05 |  |  | $ | 1.41 |  |  | $ | 0.64 |  |  | 45 | %
NGL ($/Bbl) |  | $ | 17.02 |  |  | $ | 18.42 |  |  | $ | (1.40) |  |  | (8) | %

Oil Revenues

|  | Three Months Ended September 30, |  | Variance |  | Increase (Decrease) (In millions)
|  | 2025 |  | 2024 |  | Amount |  | Percent |
Volume (MMBbl) |  | 15.3 |  | 10.3 |  | 5.0 |  |  | 49 | % |  | $ | 371 |
Price ($/Bbl) |  | $ | 64.10 |  |  | $ | 74.04 |  |  | $ | (9.94) |  |  | (13) | % |  | (152) |
|  |  |  |  |  |  |  |  |  | $ | 219 |

Oil revenues increased $219 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 September 30, |  | Variance |  | Increase (Decrease) (In millions)
|  | 2025 |  | 2024 |  | Amount |  | Percent |
Volume (Bcf) |  | 266.3 |  | 246.7 |  | 19.6 |  | 8 | % |  | $ | 25 |
Price ($/Mcf) |  | $ | 1.95 |  |  | $ | 1.30 |  |  | $ | 0.65 |  |  | 50 | % |  | 174 |
|  |  |  |  |  |  |  |  |  | $ | 199 |

Natural gas revenues increased $199 million primarily due to significantly higher natural gas prices and higher production in all areas of our operations. Production increased in the Permian Basin due to the FME and Avant acquisitions that closed in January 2025 and in all areas due to higher production from our legacy properties.
NGL Revenues

|  | Three Months Ended September 30, |  | Variance |  | Increase (Decrease) (In millions)
|  | 2025 |  | 2024 |  | Amount |  | Percent |
Volume (MMBbl) |  | 12.5 |  | 10.1 |  | 2.4 |  |  | 24 | % |  | $ | 44 |
Price ($/Bbl) |  | $ | 17.02 |  |  | $ | 18.42 |  |  | $ | (1.40) |  |  | (8) | % |  | (17) |
|  |  |  |  |  |  |  |  |  | $ | 27 |

NGL revenues increased $27 million primarily due to higher NGL volumes in the Permian and Anadarko Basins, partially offset by lower prices.
Gain (Loss) on Derivative Instruments, Net
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, net” for the periods indicated:

|  | Three Months Ended September 30, |  |  |  |
(In millions) |  | 2025 |  | 2024 |  |  |  |
Cash received on settlement of derivative instruments |  |  |  |  |  |  |  |
Oil contracts |  | $ | 10 |  |  | $ | 1 |  |  |  |  |
Gas contracts |  | 26 |  |  | 27 |  |  |  |  |
Non-cash gain (loss) on derivative instruments |  |  |  |  |  |  |  |
Oil contracts |  | (25) |  |  | 48 |  |  |  |  |
Gas contracts |  | 51 |  |  | (12) |  |  |  |  |
|  | $ | 62 |  |  | $ | 64 |  |  |  |  |

Operating Costs and Expenses
Costs associated with producing oil and natural gas are substantial. Among other factors, some of these costs vary with commodity prices, some trend with the volume and commodity mix, some are a function of the number of wells we own and operate, some depend on the prices charged by service companies, and some fluctuate based on a combination of the foregoing. Our costs for services, labor and supplies have modestly declined driven by lower industry activity levels and current oil prices. These savings are being partially offset by tariff impacts that many vendors have faced. 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 September 30, |  | Variance |  | Per BOE
(In millions, except per BOE) |  | 2025 |  | 2024 |  | Amount |  | Percent |  | 2025 |  | 2024
Operating Expenses |  |  |  |  |  |  |  |  |  |  |  |
Direct operations |  | $ | 275 |  |  | $ | 165 |  |  | $ | 110 |  |  | 67 | % |  | $ | 3.80 |  |  | $ | 2.69 |
Gathering, processing and transportation |  | 270 |  |  | 245 |  |  | 25 |  |  | 10 | % |  | 3.75 |  |  | 3.97 |
Taxes other than income |  | 93 |  |  | 66 |  |  | 27 |  |  | 41 | % |  | 1.29 |  |  | 1.08 |
Exploration |  | 7 |  |  | 9 |  |  | (2) |  |  | (22) | % |  | 0.09 |  |  | 0.15 |
Depreciation, depletion and amortization |  | 619 |  |  | 475 |  |  | 144 |  |  | 30 | % |  | 8.58 |  |  | 7.73 |
General and administrative |  | 83 |  |  | 75 |  |  | 8 |  |  | 11 | % |  | 1.15 |  |  | 1.24 |
|  | $ | 1,347 |  |  | $ | 1,035 |  |  | $ | 312 |  |  | 30 | % |  | $ | 18.66 |  |  | $ | 16.86 |

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 September 30, |  |  |  | Per BOE
(In millions, except per BOE) |  | 2025 |  | 2024 |  | Variance |  | 2025 |  | 2024
Direct Operations Expense |  |  |  |  |  |  |  |  |  |
Lease operating expense |  | $ | 214 |  |  | $ | 138 |  |  | $ | 76 |  |  | $ | 2.96 |  |  | $ | 2.25 |
Workover expense |  | 61 |  |  | 27 |  |  | 34 |  |  | 0.84 |  |  | 0.44 |
|  | $ | 275 |  |  | $ | 165 |  |  | $ | 110 |  |  | $ | 3.80 |  |  | $ | 2.69 |

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 $34 million primarily due to increased expenses related to the FME and Avant acquisitions and higher workover activity in the Permian 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 $25 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 September 30, |  |
(In millions) |  | 2025 |  | 2024 |  | Variance
Taxes Other than Income |  |  |  |  |  |
Production |  | $ | 79 |  | $ | 53 |  | $ | 26 |
Drilling impact fees |  | 6 |  | 4 |  | 2 |
Ad valorem |  | 8 |  | 9 |  | (1) |
|  | $ | 93 |  | $ | 66 |  | $ | 27 |
Production taxes as percentage of revenue (Permian and Anadarko Basins) |  | 6.1 | % |  | 5.5 | % |  |

Taxes other than income increased primarily due to an increase in our production taxes related to higher production as a result of 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 production tax rate increased as a result of higher production mix from properties in areas with higher production tax rates.
Depreciation, Depletion and Amortization (“DD&A”)
DD&A expense consisted of the following for the periods indicated:

|  | Three Months Ended September 30, |  |  |  | Per BOE
(In millions, except per BOE) |  | 2025 |  | 2024 |  | Variance |  | 2025 |  | 2024
DD&A Expense |  |  |  |  |  |  |  |  |  |
Depletion |  | $ | 576 |  |  | $ | 443 |  |  | $ | 133 |  |  | $ | 7.98 |  |  | $ | 7.19 |
Depreciation |  | 22 |  |  | 18 |  |  | 4 |  |  | 0.28 |  |  | 0.32 |
Amortization of unproved properties |  | 17 |  |  | 12 |  |  | 5 |  |  | 0.25 |  |  | 0.19 |
Accretion of ARO |  | 4 |  |  | 2 |  |  | 2 |  |  | 0.07 |  |  | 0.03 |
|  | $ | 619 |  |  | $ | 475 |  |  | $ | 144 |  |  | $ | 8.58 |  |  | $ | 7.73 |

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 $133 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, which ended in the third quarter of 2025.
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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 September 30, |  |
(In millions) |  | 2025 |  | 2024 |  | Variance
G&A Expense |  |  |  |  |  |
General and administrative expense |  | $ | 70 |  |  | $ | 61 |  |  | $ | 9 |
Stock-based compensation expense |  | 13 |  |  | 14 |  |  | (1) |
|  | $ | 83 |  |  | $ | 75 |  |  | $ | 8 |

G&A expense, excluding stock-based compensation expense, increased $9 million primarily due to higher employee-related costs and legal and professional fees.
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 September 30, |  |
(In millions) |  | 2025 |  | 2024 |  | Variance
Interest Expense |  |  |  |  |  |
Interest expense |  | $ | 53 |  |  | $ | 27 |  |  | $ | 26 |
Debt premium and discount amortization, net |  | (5) |  |  | (5) |  |  | — |
Debt issuance cost amortization |  | 3 |  |  | 1 |  |  | 2 |
Other |  | (1) |  |  | 1 |  |  | (2) |
|  | $ | 50 |  |  | $ | 24 |  |  | $ | 26 |

Interest expense increased primarily due to an increase of $26 million related to interest on debt balances. This increase was primarily due to the issuance of $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 partially 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 $600 million of our term loans in 2025.
Interest Income
Interest income decreased $14 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 September 30, |  |
(In millions) |  |  | 2025 |  | 2024 |  | Variance
Income Tax Expense |  |  |  |  |  |  |
Current tax (benefit) expense |  |  | $ | (123) |  |  | $ | 104 |  | $ | (227) |
Deferred tax expense (benefit) |  |  | 224 |  |  | (37) |  | 261 |
|  |  | $ | 101 |  |  | $ | 67 |  | $ | 34 |
Combined federal and state effective income tax rate |  |  | 24.1 | % |  | 21.0 | % |  |

Income tax expense increased $34 million for the three months ended September 30, 2025 compared to the three months ended September 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 September 30, 2025 and 2024.
First Nine Months of 2025 and 2024 Compared
Operating Revenues

|  | Nine Months Ended September 30, |  | Variance
(In millions) |  | 2025 |  | 2024 |  | Amount |  | Percent
Oil |  | $ | 2,758 |  |  | $ | 2,240 |  |  | $ | 518 |  |  | 23 | %
Natural gas |  | 2,018 |  |  | 1,177 |  |  | 841 |  |  | 71 | %
NGL |  | 638 |  |  | 535 |  |  | 103 |  |  | 19 | %
Gain (loss) on derivative instruments, net |  | 182 |  |  | 48 |  |  | 134 |  |  | 279 | %
Other |  | 90 |  |  | 63 |  |  | 27 |  |  | 43 | %
|  | $ | 5,686 |  |  | $ | 4,063 |  |  | $ | 1,623 |  |  | 40 | %

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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.

|  | Nine Months Ended September 30, |  | Variance
|  | 2025 |  | 2024 |  | Amount |  | Percent
Production Volumes |  |  |  |  |  |  |  |
Oil (MMBbl) |  | 42.2 |  | 29.4 |  | 12.8 |  |  | 44 | %
Natural gas (Bcf) |  | 813.1 |  | 769.1 |  | 44.0 |  |  | 6 | %
NGL (MMBbl) |  | 33.1 |  | 27.3 |  | 5.8 |  |  | 21 | %
Equivalents (MMBoe) |  | 210.8 |  | 184.9 |  | 25.9 |  |  | 14 | %
Average Daily Production Volumes |  |  |  |  |  |  |  |
Oil (MBbl) |  | 154.6 |  | 107.4 |  |  | 47.2 |  |  | 44 | %
Natural gas (MMcf) |  | 2,978.5 |  |  | 2,806.8 |  |  | 171.7 |  |  | 6 | %
NGL (MBbl) |  | 121.1 |  | 99.6 |  | 21.5 |  |  | 22 | %
Equivalents (MBoe) |  | 772.0 |  | 674.8 |  | 97.2 |  |  | 14 | %
Average Sales Price |  |  |  |  |  |  |  |
Excluding Derivative Settlements |  |  |  |  |  |  |  |
Oil ($/Bbl) |  | $ | 65.36 |  |  | $ | 76.16 |  |  | $ | (10.80) |  |  | (14) | %
Natural gas ($/Mcf) |  | $ | 2.48 |  |  | $ | 1.53 |  |  | $ | 0.95 |  |  | 62 | %
NGL ($/Bbl) |  | $ | 19.29 |  |  | $ | 19.59 |  |  | $ | (0.30) |  |  | (2) | %
Including Derivative Settlements |  |  |  |  |  |  |  |
Oil ($/Bbl) |  | $ | 65.89 |  |  | $ | 76.17 |  |  | $ | (10.28) |  |  | (13) | %
Natural gas ($/Mcf) |  | $ | 2.52 |  |  | $ | 1.65 |  |  | $ | 0.87 |  |  | 53 | %
NGL ($/Bbl) |  | $ | 19.29 |  |  | $ | 19.59 |  |  | $ | (0.30) |  |  | (2) | %

Oil Revenues

|  | Nine Months Ended September 30, |  | Variance |  | Increase (Decrease) (In millions)
|  | 2025 |  | 2024 |  | Amount |  | Percent |
Volume (MMBbl) |  | 42.2 |  | 29.4 |  | 12.8 |  |  | 44 | % |  | $ | 973 |
Price ($/Bbl) |  | $ | 65.36 |  |  | $ | 76.16 |  |  | $ | (10.80) |  |  | (14) | % |  | (455) |
|  |  |  |  |  |  |  |  |  | $ | 518 |

Oil revenues increased $518 million primarily 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

|  | Nine Months Ended September 30, |  | Variance |  | Increase (Decrease) (In millions)
|  | 2025 |  | 2024 |  | Amount |  | Percent |
Volume (Bcf) |  | 813.1 |  | 769.1 |  | 44.0 |  |  | 6 | % |  | $ | 67 |
Price ($/Mcf) |  | $ | 2.48 |  |  | $ | 1.53 |  |  | $ | 0.95 |  |  | 62 | % |  | 774 |
|  |  |  |  |  |  |  |  |  | $ | 841 |

Natural gas revenues increased $841 million primarily due to significantly higher natural gas prices and higher production in the Permian and Anadarko Basins, partially offset by slightly 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.
NGL Revenues

|  | Nine Months Ended September 30, |  | Variance |  | Increase (Decrease) (In millions)
|  | 2025 |  | 2024 |  | Amount |  | Percent |
Volume (MMBbl) |  | 33.1 |  | 27.3 |  | 5.8 |  |  | 21 | % |  | $ | 113 |
Price ($/Bbl) |  | $ | 19.29 |  |  | $ | 19.59 |  |  | $ | (0.30) |  |  | (2) | % |  | (10) |
|  |  |  |  |  |  |  |  |  | $ | 103 |

NGL revenues increased $103 million primarily due to higher volumes in the Permian and Anadarko Basins and slightly lower NGL prices.
Gain (Loss) on Derivative Instruments, Net
The following table presents the components of “Gain (loss) on derivative instruments, net” for the periods indicated:

|  | Nine Months Ended September 30, |  |  |  |
(In millions) |  | 2025 |  | 2024 |  |  |  |
Cash received on settlement of derivative instruments |  |  |  |  |  |  |  |
Oil contracts |  | $ | 22 |  |  | $ | — |  |  |  |  |
Gas contracts |  | 27 |  |  | 90 |  |  |  |  |
Non-cash gain (loss) on derivative instruments |  |  |  |  |  |  |  |
Oil contracts |  | 63 |  |  | 14 |  |  |  |  |
Gas contracts |  | 70 |  |  | (56) |  |  |  |  |
|  | $ | 182 |  |  | $ | 48 |  |  |  |  |

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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:

|  | Nine Months Ended September 30, |  | Variance |  | Per Boe
(In millions, except per Boe) |  | 2025 |  | 2024 |  | Amount |  | Percent |  | 2025 |  | 2024
Operating Expenses |  |  |  |  |  |  |  |  |  |  |  |
Direct operations |  | $ | 727 |  |  | $ | 481 |  |  | $ | 246 |  |  | 51 | % |  | $ | 3.45 |  |  | $ | 2.60 |
Gathering, processing and transportation |  | 823 |  |  | 737 |  |  | 86 |  |  | 12 | % |  | 3.91 |  |  | 3.98 |
Taxes other than income |  | 276 |  |  | 194 |  |  | 82 |  |  | 42 | % |  | 1.31 |  |  | 1.05 |
Exploration |  | 21 |  |  | 19 |  |  | 2 |  |  | 11 | % |  | 0.10 |  |  | 0.10 |
Depreciation, depletion and amortization |  | 1,704 |  |  | 1,354 |  |  | 350 |  |  | 26 | % |  | 8.09 |  |  | 7.32 |
General and administrative |  | 259 |  |  | 218 |  |  | 41 |  |  | 19 | % |  | 1.23 |  |  | 1.19 |
|  | $ | 3,810 |  |  | $ | 3,003 |  |  | $ | 807 |  |  | 27 | % |  | $ | 18.09 |  |  | $ | 16.24 |

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

|  | Nine Months Ended September 30, |  |  |  | Per Boe
(In millions, except per Boe) |  | 2025 |  | 2024 |  | Variance |  | 2025 |  | 2024
Direct Operations |  |  |  |  |  |  |  |  |  |
Lease operating expense |  | $ | 597 |  |  | $ | 402 |  |  | $ | 195 |  |  | $ | 2.83 |  |  | $ | 2.17 |
Workover expense |  | 130 |  |  | 79 |  |  | 51 |  |  | 0.62 |  |  | 0.43 |
|  | $ | 727 |  |  | $ | 481 |  |  | $ | 246 |  |  | $ | 3.45 |  |  | $ | 2.60 |

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 $51 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 $86 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:

|  | Nine Months Ended September 30, |  |
(In millions) |  | 2025 |  | 2024 |  | Variance
Taxes Other than Income |  |  |  |  |  |
Production |  | $ | 226 |  | $ | 159 |  | $ | 67 |
Drilling impact fees |  | 17 |  | 11 |  | 6 |
Ad valorem |  | 32 |  | 25 |  | 7 |
Other |  | 1 |  | (1) |  | 2 |
|  | $ | 276 |  | $ | 194 |  | $ | 82 |
Production taxes as percentage of revenue (Permian and Anadarko Basins) |  | 6.0 | % |  | 5.6 | % |  |

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Taxes other than income increased $82 million primarily due to an increase in our production, drilling impact fees 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. Drilling impact fees increased due to increased drilling activity in the Marcellus Shale during 2025 compared to 2024. 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:

|  | Nine Months Ended September 30, |  |  |  | Per BOE
(In millions, except per BOE) |  | 2025 |  | 2024 |  | Variance |  | 2025 |  | 2024
DD&A Expense |  |  |  |  |  |  |  |  |  |
Depletion |  | $ | 1,579 |  |  | $ | 1,256 |  |  | $ | 323 |  |  | $ | 7.49 |  |  | $ | 6.79 |
Depreciation |  | 69 |  |  | 54 |  |  | 15 |  |  | 0.34 |  |  | 0.30 |
Amortization of unproved properties |  | 45 |  |  | 36 |  |  | 9 |  |  | 0.21 |  |  | 0.19 |
Accretion of ARO |  | 11 |  |  | 8 |  |  | 3 |  |  | 0.05 |  |  | 0.04 |
|  | $ | 1,704 |  |  | $ | 1,354 |  |  | $ | 350 |  |  | $ | 8.09 |  |  | $ | 7.32 |

Our depletion expense increased $323 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.
Our depreciation expense increased primarily due to fixed assets acquired from FME and Avant.
Our amortization of unproved properties increased primarily due to unproved properties acquired from FME and Avant.
General and Administrative (“G&A”)
The table below reflects our G&A expense for the periods indicated:

|  | Nine Months Ended September 30, |  |
(In millions) |  | 2025 |  | 2024 |  | Variance
G&A Expense |  |  |  |  |  |
General and administrative expense |  | $ | 216 |  |  | $ | 175 |  |  | $ | 41 |
Stock-based compensation expense |  | 43 |  |  | 43 |  |  | — |
|  | $ | 259 |  |  | $ | 218 |  |  | $ | 41 |

G&A expense, excluding stock-based compensation expense, increased $41 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:

|  | Nine Months Ended September 30, |  |
(In millions) |  | 2025 |  | 2024 |  | Variance
Interest Expense |  |  |  |  |  |
Interest expense |  | $ | 162 |  |  | $ | 76 |  |  | $ | 86 |
Debt premium and discount amortization, net |  | (16) |  |  | (16) |  |  | — |
Debt issuance cost amortization |  | 6 |  |  | 3 |  |  | 3 |
Other |  | 4 |  |  | 14 |  |  | (10) |
|  | $ | 156 |  |  | $ | 77 |  |  | $ | 79 |

Interest expense increased $79 million primarily due to an increase of $86 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 $600 million of term loans. Other interest expense decreased $10 million primarily due to assessments arising from the timing of certain regulatory filings in 2024.
Interest Income
Interest income decreased $39 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

|  | Nine Months Ended September 30, |  |
(In millions) |  | 2025 |  | 2024 |  | Variance
Income Tax Expense |  |  |  |  |  |
Current tax expense |  | $ | 104 |  | $ | 273 |  | $ | (169) |
Deferred tax expense (benefit) |  | 285 |  | (60) |  | 345 |
|  | $ | 389 |  | $ | 213 |  | $ | 176 |
Combined federal and state effective income tax rate |  | 22.4 | % |  | 20.5 | % |  |

Income tax expense increased $176 million for the nine months ended September 30, 2025 compared to the nine months ended September 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 nine months ended September 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,
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market prices (including geographic basis differentials) of oil and natural gas, impacts of inflation, labor shortages and 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 September 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 September 30, 2025, we had the following outstanding financial commodity derivatives:

|  |  |  |  |  |  |  |  |  |  |  | 2025 |  | 2026 |  |  |  |  |  |  |  |  | Fair Value Asset (Liability) (In millions)
Oil |  |  |  |  |  |  |  |  |  |  |  | Fourth Quarter |  | First Quarter |  | Second Quarter |  | Third Quarter |  | Fourth Quarter |  |  |  |  |  |  |  |  |
WTI oil collars |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | $ | 37 |
Volume (MBbl) |  |  |  |  |  |  |  |  |  |  |  | 5,152 |  | 3,600 |  | 3,640 |  | 3,680 |  | 3,680 |  |  |  |  |  |  |  |  |  |
Weighted average floor ($/Bbl) |  |  |  |  |  |  |  |  |  |  |  | $ | 61.34 |  |  | $ | 56.25 |  |  | $ | 56.25 |  |  | $ | 56.25 |  |  | $ | 56.25 |  |  |  |  |  |  |  |  |  |  |
Weighted average ceiling ($/Bbl) |  |  |  |  |  |  |  |  |  |  |  | $ | 79.00 |  |  | $ | 70.81 |  |  | $ | 70.81 |  |  | $ | 70.81 |  |  | $ | 70.81 |  |  |  |  |  |  |  |  |  |  |
WTI-NYMEX oil swaps |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 30
Volume (MBbl) |  |  |  |  |  |  |  |  |  |  |  | 1,748 |  | 900 |  | 910 |  | 920 |  | 920 |  |  |  |  |  |  |  |  |  |
Weighted average price ($/Bbl) |  |  |  |  |  |  |  |  |  |  |  | $ | 69.18 |  |  | $ | 66.14 |  |  | $ | 66.14 |  |  | $ | 66.14 |  |  | $ | 66.14 |  |  |  |  |  |  |  |  |  |  |
WTI Midland oil basis swaps |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 1
Volume (MBbl) |  |  |  |  |  |  |  |  |  |  |  | 5,520 |  | 4,500 |  | 4,550 |  | 4,600 |  | 4,600 |  |  |  |  |  |  |  |  |  |
Weighted average differential ($/Bbl) |  |  |  |  |  |  |  |  |  |  |  | $ | 1.02 |  |  | $ | 0.97 |  |  | $ | 0.97 |  |  | $ | 0.97 |  |  | $ | 0.97 |  |  |  |  |  |  |  |  |  |  |

|  |  |  |  |  |  |  |  |  |  |  | 2025 |  | 2026 |  | Fair Value Asset (Liability) (In millions) |  |  |  |  |  |  |  |  |
Natural Gas |  |  |  |  |  |  |  |  |  |  |  | Fourth Quarter |  | First Quarter |  | Second Quarter |  | Third Quarter |  | Fourth Quarter |  |  |  |  |  |  |  |  |  |
NYMEX gas collars |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | $ | 27 |  |  |  |  |  |  |  |  |  |
Volume (MMBtu) |  |  |  |  |  |  |  |  |  |  |  | 87,400,000 |  | 81,000,000 |  | 54,600,000 |  | 55,200,000 |  | 55,200,000 |  |  |  |  |  |  |  |  |  |  |
Weighted average floor ($/MMBtu) |  |  |  |  |  |  |  |  |  |  |  | $ | 3.08 |  |  | $ | 3.06 |  |  | $ | 3.21 |  |  | $ | 3.21 |  |  | $ | 3.21 |  |  |  |  |  |  |  |  |  |  |  |
Weighted average ceiling ($/MMBtu) |  |  |  |  |  |  |  |  |  |  |  | $ | 5.66 |  |  | $ | 6.39 |  |  | $ | 5.76 |  |  | $ | 5.76 |  |  | $ | 5.76 |  |  |  |  |  |  |  |  |  |  |  |
Transco Leidy gas basis swaps |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 3 |  |  |  |  |  |  |  |  |
Volume (MMBtu) |  |  |  |  |  |  |  |  |  |  |  | 18,400,000 |  | — |  | — |  | — |  | — |  |  |  |  |  |  |  |  |  |  |
Weighted average differential ($/MMBtu) |  |  |  |  |  |  |  |  |  |  |  | $ | (0.70) |  |  | — |  | — |  | — |  | — |  |  |  |  |  |  |  |  |  |  |
Transco Zone 6 Non-NY gas basis swaps |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (10) |  |  |  |  |  |  |  |  |
Volume (MMBtu) |  |  |  |  |  |  |  |  |  |  |  | 18,400,000 |  | 13,500,000 |  | 13,650,000 |  | 13,800,000 |  | 13,800,000 |  |  |  |  |  |  |  |  |  |  |
Weighted average differential ($/MMBtu) |  |  |  |  |  |  |  |  |  |  |  | $ | (0.49) |  |  | $ | (0.26) |  |  | $ | (0.26) |  |  | $ | (0.26) |  |  | $ | (0.26) |  |  |  |  |  |  |  |  |  |  |  |
Waha gas basis swaps |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Volume (MMBtu) |  |  |  |  |  |  |  |  |  |  |  | 13,800,000 |  | 13,500,000 |  | 13,650,000 |  | 13,800,000 |  | 13,800,000 |  | 36 |  |  |  |  |  |  |  |  |  |
Weighted average differential ($/MMBtu) |  |  |  |  |  |  |  |  |  |  |  | $ | (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 nine months ended September 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 15.3 MMBbls, or 36 percent, of our oil production at a weighted-average price of $66.40 per Bbl. Oil swaps covered 5.2 MMBbls, or 12 percent, of our oil production at a weighted-average price of $69.18 per Bbl. Oil basis swaps covered 18.2 MMBbls, or 43 percent, of our oil production at a weighted-average differential of $1.05 per Bbl.
During the nine months ended September 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 192.3 Bcf, or 24 percent of our natural gas production at a weighted-average price of $3.45 per MMBtu. Gas basis swaps covered 122.6 Bcf, or 15 percent of natural gas production at a weighted-average differential of $(0.86) per MMBtu.
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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 September 30, 2025, we had total debt of $3.9 billion. Our debt portfolio 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 September 30, 2025, we had no outstanding balance under our revolving credit agreement and $400 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 $5 million. Actual results may vary due to changes in the amount of floating rate debt outstanding.
As of September 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:

|  | September 30, 2025 |  | December 31, 2024
(In millions) |  | Carrying Amount |  | Estimated Fair Value |  | Carrying Amount |  | Estimated Fair Value
Total debt |  | $ | 3,922 |  |  | $ | 3,869 |  |  | $ | 3,535 |  |  | $ | 3,395 |
Current maturities |  | (250) |  |  | (248) |  |  | — |  |  | — |
Long-term debt, excluding current maturities |  | $ | 3,672 |  |  | $ | 3,621 |  |  | $ | 3,535 |  |  | $ | 3,395 |

ITEM 4. Controls and Procedures
As of September 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 reasonable assurance with respect to the recording, processing, summarizing and reporting, within the time periods specified in
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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.
There were no changes in the Company’s internal control over financial reporting that occurred during the third 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
None.
ITEM 5. Other Information
Trading Plan Arrangements
During the three months ended September 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. (incorporated herein by reference to Exhibit 3.2 of Coterra's Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2025).
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 (incorporated herein by reference to Exhibit 10.1 of Coterra's Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2025).
**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)
November 4, 2025 | By: | /s/ THOMAS E. JORDEN
|  | Thomas E. Jorden
|  | Chairman, Chief Executive Officer and President
|  | (Principal Executive Officer)
November 4, 2025 | By: | /s/ SHANNON E. YOUNG III
|  | Shannon E. Young III
|  | Executive Vice President and Chief Financial Officer
|  | (Principal Financial Officer)
November 4, 2025 | By: | /s/ GREGORY F. CONAWAY
|  | Gregory F. Conaway
|  | Vice President and Chief Accounting Officer
|  | (Principal Accounting Officer)

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