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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2025
or
☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _________ to _________
Commission File Number: 001-35371
Civitas Resources, Inc.
(Exact name of registrant as specified in its charter)

Delaware |  | 61-1630631
(State or other jurisdiction of incorporation or organization) |  | (I.R.S. Employer Identification No.)

555 17th Street, | Suite 3700 |  |
Denver, | Colorado |  | 80202
(Address of principal executive offices) |  | (Zip Code)

(303) 293-9100
(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:
Title of each class | Trading Symbol | Name of exchange on which registered
Common Stock, par value $0.01 per share | CIVI | 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, 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 the filing date of this Quarterly Report on Form 10-Q, the registrant had 92,660,009 shares of common stock outstanding.

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CIVITAS RESOURCES, INC.
FORM 10-Q
FOR THE QUARTER ENDED JUNE 30, 2025
TABLE OF CONTENTS

|  |  | PAGE
Part I. | Financial Information |
| Item 1. | Financial Statements (Unaudited) |
|  | Condensed Consolidated Balance Sheets as of June 30, 2025 and December 31, 2024 | 6
|  | Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2025 and 2024 | 7
|  | Condensed Consolidated Statements of Stockholders’ Equity Continuous Quarterly Presentation Ended June 30, 2025 and 2024 | 8
|  | Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2025 and 2024 | 9
|  | Notes to the Condensed Consolidated Financial Statements | 10
| Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations | 28
| Item 3. | Quantitative and Qualitative Disclosures About Market Risk | 41
| Item 4. | Controls and Procedures | 42
Part II. | Other Information |
| Item 1. | Legal Proceedings | 43
| Item 1A. | Risk Factors | 43
| Item 2. | Unregistered Sales of Equity Securities, Use of Proceeds, and Issuer Purchases of Equity Securities | 43
| Item 3. | Defaults Upon Senior Securities | 44
| Item 4. | Mine Safety Disclosures | 44
| Item 5. | Other Information | 44
| Item 6. | Exhibits | 44
|  |  | Signatures | 46

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Information Regarding Forward-Looking Statements
This Quarterly Report on Form 10-Q contains various statements, including those that express belief, expectation or intention, as well as those that are not statements of historic fact, that are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities and Exchange Act of 1934, as amended (the “Exchange Act”). When used in this Quarterly Report on Form 10-Q, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project,” “plan,” “will,” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events.
Forward-looking statements include statements related to, among other things:
•our business strategies;
•reserves estimates;
•estimated sales volumes;
•the amount and allocation of forecasted capital expenditures and plans for funding capital expenditures and operating expenses;
•our ability to modify future capital expenditures;
•anticipated costs;
•compliance with debt covenants;
•our ability to fund and satisfy obligations related to ongoing operations;
•compliance with government regulations, including those related to climate change as well as environmental, health, and safety regulations and liabilities thereunder;
•our ability to achieve, reach, or otherwise meet initiatives, plans, or ambitions with respect to environmental, social, and governance matters;
•the adequacy of gathering systems and continuous improvement of such gathering systems;
•the impact from the lack of available gathering systems and processing facilities in certain areas;
•crude oil, natural gas, and natural gas liquids (“NGL”) prices and factors affecting the volatility of such prices;
•the ability to use derivative instruments to manage commodity price risk and ability to use such instruments in the future;
•our drilling inventory and drilling intentions;
•the impact of potentially disruptive technologies;
•the timing and success of specific projects;
•our implementation of standard and long reach laterals;
•our intention to continue to optimize enhanced completion techniques and well design changes;
•stated working interest percentages;
•our management and technical team;
•outcomes and effects of litigation, claims, and disputes;
•our ability to replace crude oil and natural gas reserves;
•our ability to convert proved undeveloped reserves to producing properties within five years of their initial proved booking;
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•existing or potential future capital allocation initiatives such as repurchases of our equity or debt securities or repayments of other outstanding debt, paying dividends on our common stock at their current level or at all, or additional mechanisms to return excess capital to our stockholders;
•the impact of the loss of a single customer or any purchaser of our products;
•the timing and ability to meet certain volume commitments related to purchase and transportation agreements;
•the impact of customary royalty interests, overriding royalty interests, obligations incident to operating agreements, liens for current taxes, and other industry-related constraints;
•our anticipated financial position, including our cash flow and liquidity;
•the adequacy of our insurance;
•plans and expectations with respect to our recent acquisitions and the anticipated impact of the recent acquisitions on our results of operations, financial position, future growth opportunities, reserve estimates, and competitive position;
•the results, effects, benefits, and synergies of other mergers and acquisitions; and
•other statements concerning our anticipated operations, economic performance, and financial condition.
We have based these forward-looking statements on certain assumptions and analyses we have made in light of our experience and our perception of historical trends, current conditions, and expected future developments as well as other factors we believe are appropriate under the circumstances. They can be affected by inaccurate assumptions or by known or unknown risks and uncertainties. Many such factors will be important in determining actual future results. The actual results or developments anticipated by these forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control, and may not be realized or, even if substantially realized, may not have the expected consequences. Actual results could differ materially from those expressed or implied in the forward-looking statements.
Factors that could cause actual results to differ materially include, but are not limited to, the following:
•the risk factors discussed in Part I, Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2024 (“2024 Form 10-K”);
•declines or volatility in the prices we receive for our crude oil, natural gas, and NGL;
•general economic conditions, whether internationally, nationally, or in the regional and local market areas in which we do business, including any future economic downturn, the impact of continued or further inflation, disruption in the financial markets, the imposition of tariffs or trade or other economic sanctions, political instability, and the availability of credit on acceptable terms;
•the effects of disruption of our operations or excess supply of crude oil and natural gas and other effects of world events, and actions taken by OPEC+ as it pertains to global supply and demand of, and prices for, crude oil, natural gas, and NGL;
•political conditions in or affecting other producing countries, including conflicts or hostilities in or relating to the Middle East (including the current events involving Israel and Iran), South America, and Russia (including the current events involving Russia and Ukraine), and other sustained military campaigns or acts of terrorism or sabotage and the effects therefrom;
•our ability to identify, select, and consummate possible additional acquisition and disposition opportunities;
•the ability of our customers and vendors to meet their obligations to us;
•our access to capital on acceptable terms;
•our ability to generate sufficient cash flow from operations, borrowings, or other sources to enable us to fully develop our undeveloped acreage positions and to meet our capital allocation initiatives;
•the presence or recoverability of estimated crude oil and natural gas reserves and the actual future sales volume rates and associated costs;
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•uncertainties associated with estimates of proved crude oil and natural gas reserves;
•changes in local, state, and federal laws, regulations or policies that may affect our business or our industry (such as the effects of tax law changes, and changes in environmental, health, and safety regulation and regulations addressing climate change, and trade policy and tariffs);
•environmental, health, and safety risks;
•seasonal weather conditions as well as severe weather and other natural events caused by climate change;
•lease stipulations;
•drilling and operating risks, including the risks associated with the employment of horizontal drilling and completion techniques;
•our ability to acquire adequate supplies of water for drilling and completion operations;
•availability of oilfield equipment, services, and personnel;
•exploration and development risks;
•operational interruption of centralized crude oil and natural gas processing facilities;
•competition in the crude oil and natural gas industry;
•management’s ability to execute our plans to meet our goals;
•our ability to attract and retain key members of our senior management and key technical employees;
•our ability to maintain effective internal controls;
•access to adequate gathering systems and pipeline take-away capacity;
•our ability to secure adequate processing capacity for natural gas we produce, to secure adequate transportation for crude oil, natural gas, and NGL we produce, and to sell the crude oil, natural gas, and NGL at market prices;
•costs and other risks associated with perfecting title for mineral rights in some of our properties;
•pandemics and other public health epidemics; and
•other economic, competitive, governmental, legislative, regulatory, geopolitical, and technological factors that may negatively impact our businesses, operations, or pricing.
All forward-looking statements speak only as of the date of this Quarterly Report on Form 10-Q. We disclaim any obligation to update or revise these statements unless required by law, and you should not place undue reliance on these forward-looking statements. Although we believe that our plans, intentions, and expectations reflected in or suggested by the forward-looking statements we make in this Quarterly Report on Form 10-Q are reasonable, we can give no assurance that these plans, intentions, or expectations will be achieved. We disclose other important factors that could cause our actual results to differ materially from our expectations under “Part I, Item 1A. Risk Factors” and elsewhere in our 2024 Form 10-K, which may be updated in subsequent Quarterly Reports on Form 10-Q and other documents we file with the Securities and Exchange Commission (the “SEC”). These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.
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PART I. FINANCIAL INFORMATION
Item 1. Financial Statements.
CIVITAS RESOURCES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
(in millions, except share and per share amounts)

| June 30, 2025 |  | December 31, 2024
ASSETS |  |  |
Current assets: |  |  |
Cash and cash equivalents | $ | 69 |  |  | $ | 76 |
Accounts receivable, net: |  |  |
Crude oil, natural gas, and NGL sales | 587 |  |  | 646 |
Joint interest and other | 138 |  |  | 125 |
Derivative assets | 174 |  |  | 67 |
Prepaid expenses and other | 82 |  |  | 74 |
Total current assets | 1,050 |  |  | 988 |
Property and equipment (successful efforts method): |  |  |
Proved properties | 18,328 |  |  | 16,897 |
Less: accumulated depreciation, depletion, and amortization | (5,212) |  |  | (4,288) |
Total proved properties, net | 13,116 |  |  | 12,609 |
Unproved properties | 462 |  |  | 631 |
Wells in progress | 543 |  |  | 506 |
Other property and equipment, net of accumulated depreciation of $8 million in 2025 and $9 million in 2024 | 57 |  |  | 48 |
Total property and equipment, net | 14,178 |  |  | 13,794 |
Derivative assets | 12 |  |  | 17 |
Other noncurrent assets | 163 |  |  | 145 |
Total assets | $ | 15,403 |  |  | $ | 14,944 |
LIABILITIES AND STOCKHOLDERS’ EQUITY |  |  |
Current liabilities: |  |  |
Accounts payable and accrued expenses | $ | 622 |  |  | $ | 561 |
Severance and ad valorem taxes payable | 283 |  |  | 323 |
Crude oil, natural gas, and NGL revenue distribution payable | 610 |  |  | 702 |
Derivative liability | 39 |  |  | 22 |
Deferred acquisition consideration | — |  |  | 479 |
Other liabilities | 129 |  |  | 118 |
Total current liabilities | 1,683 |  |  | 2,205 |
Long-term liabilities: |  |  |
Debt, net | 5,388 |  |  | 4,494 |
Ad valorem taxes | 129 |  |  | 294 |
Derivative liability | 15 |  |  | 13 |
Deferred income tax liabilities, net | 891 |  |  | 801 |
Asset retirement obligations | 384 |  |  | 399 |
Other long-term liabilities | 119 |  |  | 109 |
Total liabilities | 8,609 |  |  | 8,315 |
Commitments and contingencies (Note 6) |  |  |
Stockholders’ equity: |  |  |
Preferred stock, $.01 par value, 25,000,000 shares authorized, none outstanding | — |  |  | — |
Common stock, $.01 par value, 225,000,000 shares authorized, 92,596,829 and 93,933,857 issued and outstanding as of June 30, 2025 and December 31, 2024, respectively | 5 |  |  | 5 |
Additional paid-in capital | 5,030 |  |  | 5,095 |
Retained earnings | 1,759 |  |  | 1,529 |
Total stockholders’ equity | 6,794 |  |  | 6,629 |
Total liabilities and stockholders’ equity | $ | 15,403 |  |  | $ | 14,944 |

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
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CIVITAS RESOURCES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
(in millions, except share and per share amounts)

| Three Months Ended June 30, |  | Six Months Ended June 30,
| 2025 |  | 2024 |  | 2025 |  | 2024
Operating net revenues: |  |  |  |  |  |  |
Crude oil, natural gas, and NGL sales | $ | 1,054 |  |  | $ | 1,311 |  |  | $ | 2,246 |  |  | $ | 2,639 |
Other operating income | 3 |  |  | 2 |  |  | 5 |  |  | 3 |
Total operating net revenues | 1,057 |  |  | 1,313 |  |  | 2,251 |  |  | 2,642 |
Operating expenses: |  |  |  |  |  |  |
Lease operating expense | 158 |  |  | 127 |  |  | 332 |  |  | 258 |
Midstream operating expense | 12 |  |  | 12 |  |  | 26 |  |  | 26 |
Gathering, transportation, and processing | 83 |  |  | 94 |  |  | 170 |  |  | 183 |
Severance and ad valorem taxes | 75 |  |  | 102 |  |  | 164 |  |  | 204 |
Exploration | 3 |  |  | 2 |  |  | 6 |  |  | 13 |
Depreciation, depletion, and amortization | 501 |  |  | 521 |  |  | 946 |  |  | 988 |
Transaction costs | — |  |  | 8 |  |  | 6 |  |  | 31 |
General and administrative expense | 53 |  |  | 59 |  |  | 110 |  |  | 117 |
Other operating expense | 2 |  |  | 1 |  |  | 6 |  |  | 8 |
Total operating expenses | 887 |  |  | 926 |  |  | 1,766 |  |  | 1,828 |
Other income (expense): |  |  |  |  |  |  |
Derivative gain (loss), net | 104 |  |  | 8 |  |  | 156 |  |  | (102) |
Interest expense | (114) |  |  | (115) |  |  | (221) |  |  | (225) |
Other, net | 2 |  |  | 3 |  |  | (11) |  |  | 7 |
Total other expense | (8) |  |  | (104) |  |  | (76) |  |  | (320) |
Income from operations before income taxes | 162 |  |  | 283 |  |  | 409 |  |  | 494 |
Income tax expense | (38) |  |  | (67) |  |  | (99) |  |  | (102) |
Net income | $ | 124 |  |  | $ | 216 |  |  | $ | 310 |  |  | $ | 392 |
Earnings per common share: |  |  |  |  |  |  |
Basic | $ | 1.34 |  |  | $ | 2.17 |  |  | $ | 3.33 |  |  | $ | 3.92 |
Diluted | $ | 1.34 |  |  | $ | 2.15 |  |  | $ | 3.33 |  |  | $ | 3.88 |
Weighted-average common shares outstanding: |  |  |  |  |  |  |
Basic | 92,588,030 |  |  | 99,425,524 |  |  | 93,107,102 |  |  | 100,061,694 |
Diluted | 92,670,914 |  |  | 100,244,878 |  |  | 93,218,041 |  |  | 100,864,694 |

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
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CIVITAS RESOURCES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (UNAUDITED)
(in millions, except share and per share amounts)

|  |  |  |  | Additional |  |  |  |
| Common Stock |  | Paid-In |  | Retained |  |
| Shares |  | Amount |  | Capital |  | Earnings |  | Total
Balances, December 31, 2024 | 93,933,857 |  |  | $ | 5 |  |  | $ | 5,095 |  |  | $ | 1,529 |  |  | $ | 6,629 |
Restricted common stock issued | 304,697 |  |  | — |  |  | — |  |  | — |  |  | — |
Stock used for tax withholdings | (113,899) |  |  | — |  |  | (5) |  |  | — |  |  | (5) |
Exercise of stock options | 111 |  |  | — |  |  | — |  |  | — |  |  | — |
Common stock repurchased and retired | (1,540,340) |  |  | — |  |  | (84) |  |  | 11 |  |  | (73) |
Stock-based compensation | — |  |  | — |  |  | 13 |  |  | — |  |  | 13 |
Dividends declared, $0.50 per share | — |  |  | — |  |  | — |  |  | (45) |  |  | (45) |
Net income | — |  |  | — |  |  | — |  |  | 186 |  |  | 186 |
Balances, March 31, 2025 | 92,584,426 |  |  | 5 |  |  | 5,019 |  |  | 1,681 |  |  | 6,705 |
Restricted common stock issued | 48,824 |  |  | — |  |  | — |  |  | — |  |  | — |
Stock used for tax withholdings | (16,456) |  |  | — |  |  | — |  |  | — |  |  | — |
Common stock repurchased and retired | (19,965) |  |  | — |  |  | (2) |  |  | — |  |  | (2) |
Stock-based compensation | — |  |  | — |  |  | 13 |  |  | — |  |  | 13 |
Dividends declared, $0.50 per share | — |  |  | — |  |  | — |  |  | (46) |  |  | (46) |
Net income | — |  |  | — |  |  | — |  |  | 124 |  |  | 124 |
Balances, June 30, 2025 | 92,596,829 |  |  | $ | 5 |  |  | $ | 5,030 |  |  | $ | 1,759 |  |  | $ | 6,794 |

Balances, December 31, 2023 | 93,774,901 |  |  | $ | 5 |  |  | $ | 4,964 |  |  | $ | 1,212 |  |  | $ | 6,181 |
Issuance pursuant to acquisition | 7,181,527 |  |  | — |  |  | 489 |  |  | — |  |  | 489 |
Restricted common stock issued | 255,442 |  |  | — |  |  | — |  |  | — |  |  | — |
Stock used for tax withholdings | (99,307) |  |  | — |  |  | (7) |  |  | — |  |  | (7) |
Common stock repurchased and retired | (1,028,468) |  |  | — |  |  | (54) |  |  | (13) |  |  | (67) |
Stock-based compensation | — |  |  | — |  |  | 11 |  |  | — |  |  | 11 |
Dividends declared, $1.45 per share | — |  |  | — |  |  | — |  |  | (148) |  |  | (148) |
Net income | — |  |  | — |  |  | — |  |  | 176 |  |  | 176 |
Balances, March 31, 2024 | 100,084,095 |  |  | 5 |  |  | 5,403 |  |  | 1,227 |  |  | 6,635 |
Restricted common stock issued | 48,999 |  |  | — |  |  | — |  |  | — |  |  | — |
Stock used for tax withholdings | (18,571) |  |  | — |  |  | (2) |  |  | — |  |  | (2) |
Exercise of stock options | 222 |  |  | — |  |  | — |  |  | — |  |  | — |
Common stock repurchased and retired | (1,766,808) |  |  | — |  |  | (95) |  |  | (29) |  |  | (124) |
Stock-based compensation | — |  |  | — |  |  | 12 |  |  | — |  |  | 12 |
Dividends declared, $1.50 per share | — |  |  | — |  |  | — |  |  | (151) |  |  | (151) |
Net income | — |  |  | — |  |  | — |  |  | 216 |  |  | 216 |
Balances, June 30, 2024 | 98,347,937 |  |  | $ | 5 |  |  | $ | 5,318 |  |  | $ | 1,263 |  |  | $ | 6,586 |

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
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CIVITAS RESOURCES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(in millions)

| Six Months Ended June 30,
| 2025 |  | 2024
Cash flows from operating activities: |  |  |
Net income | $ | 310 |  |  | $ | 392 |
Adjustments to reconcile net income to net cash provided by operating activities: |  |  |
Depreciation, depletion, and amortization | 946 |  |  | 988 |
Stock-based compensation | 26 |  |  | 23 |
Derivative (gain) loss, net | (156) |  |  | 102 |
Derivative cash settlement gain (loss), net | 73 |  |  | (24) |
Amortization of deferred financing costs and deferred acquisition consideration | 9 |  |  | 25 |
Deferred income tax expense | 90 |  |  | 93 |
Other, net | (3) |  |  | — |
Changes in operating assets and liabilities, net |  |  |
Accounts receivable, net | 47 |  |  | 3 |
Prepaid expenses and other | (16) |  |  | 7 |
Accounts payable, accrued expenses, and other liabilities | (309) |  |  | (437) |
Net cash provided by operating activities | 1,017 |  |  | 1,172 |
Cash flows from investing activities: |  |  |
Acquisitions of businesses, net of cash acquired | (756) |  |  | (868) |
Acquisitions of crude oil and natural gas properties | (20) |  |  | (14) |
Capital expenditures for drilling and completion activities and other fixed assets | (961) |  |  | (1,091) |
Proceeds from property transactions | 3 |  |  | 172 |
Purchases of carbon credits and renewable energy credits | — |  |  | (2) |
Net cash used in investing activities | (1,734) |  |  | (1,803) |
Cash flows from financing activities: |  |  |
Proceeds from credit facility | 1,550 |  |  | 1,300 |
Payments to credit facility | (1,400) |  |  | (1,200) |
Proceeds from issuance of senior notes | 743 |  |  | — |
Dividends paid | (97) |  |  | (297) |
Common stock repurchased and retired | (72) |  |  | (192) |
Payment of employee tax withholdings in exchange for the return of common stock | (5) |  |  | (9) |
Other, net | (9) |  |  | (6) |
Net cash provided by (used in) financing activities | 710 |  |  | (404) |
Net change in cash, cash equivalents, and restricted cash | (7) |  |  | (1,035) |
Cash, cash equivalents, and restricted cash: |  |  |
Beginning of period | 76 |  |  | 1,127 |
End of period | $ | 69 |  |  | $ | 92 |
Refer to Note 2 - Acquisitions and Divestitures and Note 13 - Supplemental Disclosures of Cash Flow Information for additional information.

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
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CIVITAS RESOURCES, INC. AND SUBSIDIARIES
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Description of Operations
When we use the terms “Civitas,” the “Company,” “we,” “us,” or “our,” we are referring to Civitas Resources, Inc. and its consolidated subsidiaries unless the context otherwise requires. Civitas is an independent exploration and production company focused on the acquisition, development, and production of crude oil and associated liquids-rich natural gas in the Permian Basin in Texas and New Mexico and the DJ Basin in Colorado.
Basis of Presentation
The accompanying unaudited condensed consolidated financial statements include the accounts of Civitas and have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim financial information, the instructions to Quarterly Report on Form 10-Q, and Regulation S-X. Accordingly, pursuant to such rules and regulations, certain notes and other financial information included in audited financial statements have been condensed or omitted. In the opinion of management, all adjustments, consisting of normal recurring adjustments considered necessary for a fair presentation of interim financial information, have been included. All intercompany balances and transactions have been eliminated in consolidation.
The December 31, 2024 unaudited condensed consolidated balance sheet data has been derived from the audited consolidated financial statements contained in our 2024 Form 10-K, but does not include all disclosures, including notes required by GAAP. As such, this Quarterly Report on Form 10-Q should be read in conjunction with the audited consolidated financial statements and related notes included in our 2024 Form 10-K. In connection with the preparation of the unaudited condensed consolidated financial statements, we evaluated events subsequent to the balance sheet date of June 30, 2025 through the filing date of this Quarterly Report on Form 10-Q. The results of operations for the three and six months ended June 30, 2025 are not necessarily indicative of the results that may be expected for the full year or any other future period. Additionally, certain insignificant prior period amounts have been reclassified to conform to current period presentation in the accompanying unaudited condensed consolidated financial statements. Such reclassifications did not have a material impact on prior period consolidated financial statements.
Significant Accounting Policies
The significant accounting policies followed by us are set forth in Note 1 - Summary of Significant Accounting Policies in the 2024 Form 10-K and are supplemented by the notes to the unaudited condensed consolidated financial statements included in this Quarterly Report on Form 10-Q.
Recently Issued and Adopted Accounting Standards
In December 2023, the Financial Accounting Standards Board (“FASB”) issued ASU No. 2023-09, Improvements to Income Tax Disclosures (“ASU 2023-09”). ASU 2023-09 is intended to enhance income tax disclosures by requiring disclosure of items such as the disaggregation of the income tax rate reconciliation as well as information regarding income taxes paid. This ASU is effective for annual reporting periods beginning after December 15, 2024, and early adoption is permitted. ASU 2023-09 should be applied on a prospective basis, and retrospective application is permitted. We adopted ASU 2023-09 on January 1, 2025, on a prospective basis, and will present the required new disclosures in the 2025 Form 10-K.
In November 2024, the FASB issued ASU No. 2024-03, Disaggregation of Income Statement Expenses (“ASU 2024-03”). ASU 2024-03 requires public entities to disclose disaggregated information about certain costs and expenses. This ASU is effective for annual reporting periods beginning after December 15, 2026, and early adoption is permitted. ASU 2024-03 should be applied on a prospective basis, and retrospective application is permitted. We are evaluating the impact that ASU 2024-03 will have on the consolidated financial statements and our plan for adoption, including the adoption date and transition method.
There are no other accounting standards applicable to us that would have a material effect on our consolidated financial statements and disclosures that have been issued but not yet adopted by us as of June 30, 2025, and through the filing date of this Quarterly Report on Form 10-Q.
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NOTE 2 - ACQUISITIONS AND DIVESTITURES
All acquisitions disclosed below are accounted for under the acquisition method of accounting for business combinations under ASC Topic 805, Business Combinations. Accordingly, we conducted assessments of the net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while transaction and integration costs associated with the acquisition were expensed as incurred. The fair value measurements of assets acquired and liabilities assumed were based on inputs that are not observable in the market, and therefore represent Level 3 inputs. The fair values of crude oil and natural gas properties were measured using valuation techniques that converted future cash flows to a single discounted amount. Significant inputs to the valuation of the crude oil and natural gas properties included estimates of reserves, future operating and development costs, future commodity prices, estimated future cash flows, reserve adjustment factors, and a market-based weighted-average cost of capital. These inputs required significant judgments and estimates by management at the time of the valuation.
Vencer Acquisition
On January 2, 2024, we completed the acquisition of certain crude oil and natural gas assets from Vencer Energy, LLC (“Vencer”) for adjusted aggregate consideration of approximately $2.0 billion, inclusive of customary post-closing adjustments and $550 million in cash to be paid on or before January 3, 2025 (the “Vencer Acquisition”). The following tables present the consideration transferred and the final purchase price allocation of the assets acquired and the liabilities assumed in the Vencer Acquisition:

Consideration (in millions, except share and per share amounts) |
Cash consideration | $ | 997 |
Deferred acquisition consideration(1) | $ | 532 |
Shares of common stock issued | 7,181,527 |
Closing price per share(2) | $ | 68.08 |
Equity consideration(3) | $ | 489 |
Total consideration | $ | 2,018 |

_______________________
(1)Based on discounted fixed and determinable future payments of cash. Amounts represent non-cash investing activities until such time payments are made, as applicable. Refer to Note 5 - Debt for additional information.
(2)Based on the closing stock price of Civitas common stock on January 2, 2024.
(3)Amounts represent non-cash financing activities.
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Final Purchase Price Allocation (in millions) |
Assets Acquired |
Proved properties | $ | 1,859 |
Unproved properties | 231 |
Other property and equipment | 1 |
Right-of-use assets | 4 |
Total assets acquired | $ | 2,095 |
Liabilities Assumed |
Accounts payable and accrued expenses | $ | 5 |
Crude oil and natural gas revenue distribution payable | 28 |
Asset retirement obligations | 40 |
Lease liability | 4 |
Total liabilities assumed | 77 |
Net assets acquired | $ | 2,018 |

The purchase price allocation for the Vencer Acquisition was finalized as of the fourth quarter of 2024 with immaterial adjustments made to the preliminary allocation initially presented in the Quarterly Report on Form 10-Q for the quarter ended March 31, 2024, filed with the SEC on May 2, 2024.
Revenue and earnings of the acquiree
The results of operations for the Vencer Acquisition since the closing date have been included in our unaudited condensed consolidated financial statements during the three and six months ended June 30, 2024. The amount of revenue of Vencer included in our accompanying unaudited condensed consolidated statements of operations (“statements of operations”) was approximately $200 million and $398 million during the three and six months ended June 30, 2024, respectively. We determined that disclosing the amount of Vencer-related net income included in the accompanying statements of operations is impracticable as the operations from the acquisition were integrated into our operations from the date of the acquisition.
Supplemental unaudited pro forma financial information
The results of operations for the Vencer Acquisition since the closing date have been included in our unaudited condensed consolidated financial statements and therefore do not require pro forma disclosure for the three and six months ended June 30, 2024.
Transaction costs
Transaction costs related to insignificant acquisitions in the Permian Basin in 2025 and the Vencer Acquisition in 2024 are accounted for separately from the assets acquired and liabilities assumed and are included in transaction costs in the accompanying statements of operations. We incurred transaction costs of zero and $8 million during the three months ended June 30, 2025 and 2024, respectively, and $6 million and $31 million during the six months ended June 30, 2025 and 2024, respectively.
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NOTE 3 - REVENUE RECOGNITION
Crude oil, natural gas, and NGL sales revenue presented within the accompanying statements of operations is reflective of the revenue generated from contracts with customers. Revenue attributable to each identified revenue stream and operating region is disaggregated below (in millions):

| Three Months Ended June 30, |  | Six Months Ended June 30,
Sales by Commodity and Operating Region | 2025 |  | 2024 |  | 2025 |  | 2024
Crude oil |  |  |  |  |  |  |
Permian Basin | $ | 484 |  |  | $ | 646 |  |  | $ | 971 |  |  | $ | 1,230 |
DJ Basin | 384 |  |  | 489 |  |  | 798 |  |  | 980 |
Total | 868 |  |  | 1,135 |  |  | 1,769 |  |  | 2,210 |
Natural gas |  |  |  |  |  |  |
Permian Basin | (3) |  |  | (31) |  |  | 22 |  |  | (18) |
DJ Basin | 51 |  |  | 40 |  |  | 151 |  |  | 114 |
Total | 48 |  |  | 9 |  |  | 173 |  |  | 96 |
NGL |  |  |  |  |  |  |
Permian Basin | 68 |  |  | 81 |  |  | 146 |  |  | 164 |
DJ Basin | 70 |  |  | 86 |  |  | 158 |  |  | 169 |
Total | 138 |  |  | 167 |  |  | 304 |  |  | 333 |
Crude oil, natural gas, and NGL |  |  |  |  |  |  |
Permian Basin | 549 |  |  | 696 |  |  | 1,139 |  |  | 1,376 |
DJ Basin | 505 |  |  | 615 |  |  | 1,107 |  |  | 1,263 |
Total | $ | 1,054 |  |  | $ | 1,311 |  |  | $ | 2,246 |  |  | $ | 2,639 |

We record revenue in the month production is delivered to the purchaser. However, purchaser statements may not be received for one to two months after the date production is delivered, and as a result, we estimate the volume of production delivered to the purchaser and the price that will be received for the sale of the product. Generally, we record the differences between our estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. Any identified differences between our revenue estimates and actual revenue received historically have not been significant. For the three and six months ended June 30, 2025 and 2024, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.
NOTE 4 - ACCOUNTS PAYABLE AND ACCRUED EXPENSES
Accounts payable and accrued expenses contain the following (in millions):

| June 30, 2025 |  | December 31, 2024
Accounts payable trade | $ | 61 |  |  | $ | 35 |
Accrued drilling and completion costs | 198 |  |  | 158 |
Accrued crude oil, natural gas, and NGL operating expense | 163 |  |  | 160 |
Accrued general and administrative expense | 22 |  |  | 37 |
Accrued interest expense | 141 |  |  | 136 |
Other accrued expenses | 37 |  |  | 35 |
Total accounts payable and accrued expenses | $ | 622 |  |  | $ | 561 |

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NOTE 5 - DEBT
Debt, net of unamortized discounts and deferred financing costs, consists of the following (in millions):

| June 30, 2025 |  | December 31, 2024
Outstanding principal balances on Senior Notes: |  |  |
2026 Senior Notes (5.000%) | $ | 400 |  |  | $ | 400 |
2028 Senior Notes (8.375%) | 1,350 |  |  | 1,350 |
2030 Senior Notes (8.625%) | 1,000 |  |  | 1,000 |
2031 Senior Notes (8.750%) | 1,350 |  |  | 1,350 |
2033 Senior Notes (9.625%) | 750 |  |  | — |
Outstanding principal balances on Senior Notes, gross | 4,850 |  |  | 4,100 |
Less: unamortized discount and deferred financing costs | (62) |  |  | (56) |
Outstanding principal balances on Senior Notes, net | 4,788 |  |  | 4,044 |
Outstanding balance on Credit Facility | 600 |  |  | 450 |
Long-term debt | 5,388 |  | 4,494
Deferred acquisition consideration | — |  |  | 479 |
Total debt | $ | 5,388 |  |  | $ | 4,973 |

Senior Notes
The table below summarizes the face values, interest rates, maturity dates, and semi-annual interest payment dates related to our outstanding senior note obligations as of June 30, 2025 ($ in millions):

| Interest Rate |  | Interest Payment Dates |  | Principal Amount |  | Maturity Date
2026 Senior Notes | 5.000% |  | April 15, October 15 |  | $ | 400 |  |  | October 15, 2026
2028 Senior Notes | 8.375% |  | January 1, July 1 |  | 1,350 |  |  | July 1, 2028
2030 Senior Notes | 8.625% |  | May 1, November 1 |  | 1,000 |  |  | November 1, 2030
2031 Senior Notes | 8.750% |  | January 1, July 1 |  | 1,350 |  |  | July 1, 2031
2033 Senior Notes | 9.625% |  | June 15, December 15 |  | 750 |  |  | June 15, 2033

On June 3, 2025, we issued $750 million aggregate principal amount of 9.625% Senior Notes due 2033 (the “2033 Senior Notes”), at par, pursuant to an indenture among us, Computershare Trust Company, N.A., as trustee, and the guarantors party thereto. Upon issuance of the 2033 Senior Notes, we received net proceeds of $743 million after deducting fees of $7 million. The net proceeds were used to repay a portion of the outstanding borrowings under our Credit Facility (as defined below). The 2033 Senior Notes will mature on June 15, 2033. Interest on the 2033 Senior Notes will accrue at the rate of 9.625% per annum, and will be payable semi-annually in arrears on June 15 and December 15 of each year, commencing on December 15, 2025.
At any time prior to June 15, 2028, we may redeem all or part of the 2033 Senior Notes, in whole or in part, at a redemption price equal to the sum of (i) the principal amount thereof, plus (ii) the “make-whole” premium at the redemption date, plus (iii) accrued and unpaid interest, if any. On or after June 15, 2028, we may redeem all or part of the 2033 Senior Notes at redemption prices (expressed as percentages of the principal amount redeemed) equal to (i) 104.813% for the twelve-month period beginning on June 15, 2028; (ii) 102.406% for the twelve-month period beginning on June 15, 2029; and (iii) 100.000% for the period beginning June 15, 2030 and at any time thereafter, plus accrued and unpaid interest, if any.
We may redeem up to 35% of the aggregate principal amount of the 2033 Senior Notes at any time prior to June 15, 2028 with an amount not to exceed the net cash proceeds from certain equity offerings at a redemption price equal to 109.625% of the principal amount of the 2033 Senior Notes redeemed, plus accrued and unpaid interest, if any, thereon, provided, however, that (i) at least 65% of the aggregate principal amount of 2033 Senior Notes originally issued on the issue date (but excluding 2033 Senior Notes held by us and our subsidiaries) remains outstanding immediately after the occurrence of such redemption (unless all such 2033 Senior Notes are redeemed substantially concurrently) and (ii) the redemption occurs within 180 days after the date of the closing of such equity offering.
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The 2026 Senior Notes, 2028 Senior Notes, 2030 Senior Notes, 2031 Senior Notes, and 2033 Senior Notes (collectively, the “Senior Notes”) are unsecured senior obligations and rank equal in right of payment with all of our existing and any future unsecured senior debt and are senior in right of payment to any future subordinated debt. We may redeem some or all of our Senior Notes prior to their maturity at redemption prices that may include a premium, plus accrued and unpaid interest as described in the indentures governing the Senior Notes. The Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by all of our existing subsidiaries and are expected to be guaranteed by certain other future subsidiaries that may be required to guarantee the Senior Notes.
The indentures governing the Senior Notes contain covenants that limit, among other things, our ability and the ability of our subsidiaries to: (i) incur or guarantee additional indebtedness; (ii) create liens securing indebtedness; (iii) pay dividends on or redeem or repurchase stock or subordinated debt; (iv) make specified types of investments and acquisitions; (v) enter into or permit to exist contractual limits on the ability of our subsidiaries to pay dividends to us; (vi) enter into transactions with affiliates; and (vii) sell assets or merge with other companies. These covenants are subject to a number of important limitations and exceptions. We were in compliance with all covenants and all restricted payment provisions related to our Senior Notes as of June 30, 2025 and through the filing date of this Quarterly Report on Form 10-Q. The indentures governing the Senior Notes also contain customary events of default.
For additional details on our Senior Notes, refer to Note 5 - Debt in Item 8. Financial Statements and Supplementary Data included in our 2024 Form 10-K.
Credit Facility
We are party to a reserve-based revolving credit facility, as the borrower, with JPMorgan Chase Bank, N.A. (“JPMorgan”), as the administrative agent, and a syndicate of financial institutions, as lenders, that has an aggregate maximum commitment amount of $4.0 billion and is set to mature on August 2, 2028 (together with all amendments thereto, the “Credit Facility” or the “Credit Agreement”).
On February 21, 2025, we amended the Credit Agreement to increase our aggregate elected commitments from $2.2 billion to $2.5 billion. On May 28, 2025, we amended the Credit Agreement to, among other things, (i) decrease our borrowing base from $3.4 billion to $3.3 billion, (ii) reaffirm our aggregate elected commitments at $2.5 billion, and (iii) modify the definition of “Revolving Credit Maturity Date” (as defined in the Credit Agreement) to remove the springing maturity requirement that would otherwise cause the Credit Facility under the Credit Agreement to mature on the date that is 180 days prior to the scheduled maturity of our 2026 Senior Notes.
As of June 30, 2025, the borrowing base and aggregate elected commitments under the Credit Agreement were $3.3 billion and $2.5 billion, respectively. The next scheduled borrowing base redetermination date is set to occur in November 2025.
Interest and commitment fees associated with the Credit Facility are accrued based on a revolving loan commitment utilization grid set forth in the Credit Agreement. Borrowings under the Credit Facility bear interest at a per annum rate equal to, at our option, either (i) the Alternate Base Rate (“ABR”) plus the applicable margin, or (ii) the term-specific Secured Overnight Financing Rate (“SOFR”) plus the applicable margin. ABR is established as a rate per annum equal to the greatest of (a) the rate of interest publicly announced by JPMorgan as its prime rate, (b) the applicable rate of interest published by the Federal Reserve Bank of New York plus 0.5%, or (c) the term-specific SOFR for an interest period of one month plus 1.0%, in each case, subject to a 1.5% floor, plus an applicable margin of 0.75% to 1.75% based on the utilization of the Credit Facility. Term-specific SOFR is based on one-, three-, or six-month terms as selected by us and is subject to a 0.5% floor, plus an applicable margin of 1.75% to 2.75%, based on the utilization of the Credit Facility. Interest on borrowings that bear interest at the SOFR are payable on the last day of the applicable interest period selected by us, and interest on borrowings that bear interest at the ABR are payable quarterly in arrears.
The Credit Facility is guaranteed by all our restricted domestic subsidiaries and is secured by first priority security interests on substantially all assets, including a mortgage on at least 90% of the total value of the proved properties evaluated in the reserve reports most recently delivered to the lenders under the Credit Facility, including any engineering reports relating to the crude oil and natural gas properties of our restricted domestic subsidiaries, subject to customary exceptions.
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The Credit Facility contains customary representations and affirmative covenants. The Credit Facility also contains customary negative covenants, which, among other things, and subject to certain exceptions, including the suspension and/or modification of certain covenants in the event that we receive investment grade credit ratings, include restrictions on (i) liens, (ii) indebtedness, guarantees and other obligations, (iii) restrictions in agreements on liens and distributions, (iv) mergers or consolidations, (v) asset sales, (vi) restricted payments, (vii) investments, (viii) affiliate transactions, (ix) change of business, (x) foreign operations or subsidiaries, (xi) changes to organizational documents, (xii) use of proceeds from loans and letters of credit, (xiii) hedging transactions, (xiv) additional subsidiaries, (xv) changes in fiscal year or fiscal quarter, (xvi) prepayments of certain debt and other obligations, (xvii) sales or discounts of receivables, and (xviii) dividend payment thresholds.
In addition, we are subject to certain financial covenants under the Credit Facility, as tested on the last day of each fiscal quarter, including, without limitation, (a) a maximum ratio of our consolidated net indebtedness to earnings before interest, income taxes, depreciation, depletion, and amortization, exploration expense, and other non-cash charges (“permitted net leverage ratio”) of 3.00 to 1.00, (b) a current ratio, inclusive of the unused commitments under the Credit Facility then available to be borrowed, to not be less than 1.00 to 1.00, and (c) upon the achievement of investment grade credit ratings, a PV-9 coverage ratio of the net present value, discounted at 9% per annum, of the estimated future net revenues expected in the proved reserves to our total net indebtedness of not less than 1.50 to 1.00 (“PV-9 coverage ratio”). We were in compliance with all covenants under the Credit Facility as of June 30, 2025 and through the filing date of this Quarterly Report on Form 10-Q.
The following table presents the outstanding balance, letters of credit outstanding, and available borrowing capacity under the Credit Facility as of the dates indicated (in millions):

| The Filing Date of this Quarterly Report on Form 10-Q |  | June 30, 2025 |  | December 31, 2024
Outstanding balance | $ | 600 |  |  | $ | 600 |  |  | $ | 450 |
Letters of credit | 2 |  |  | 2 |  |  | 2 |
Available borrowing capacity | 1,898 |  |  | 1,898 |  |  | 1,748 |
Total aggregate elected commitments | $ | 2,500 |  |  | $ | 2,500 |  |  | $ | 2,200 |

As of June 30, 2025 and December 31, 2024, the unamortized deferred financing costs associated with amendments to the Credit Facility were $27 million and $29 million, respectively. Of the unamortized deferred financing costs, (i) $18 million and $21 million are presented within other noncurrent assets on the accompanying unaudited condensed consolidated balance sheets (“balance sheets”) as of June 30, 2025 and December 31, 2024, respectively, and (ii) $9 million and $8 million are presented within prepaid expenses and other on the accompanying balance sheets as of June 30, 2025 and December 31, 2024, respectively.
Deferred Acquisition Consideration
The Vencer Acquisition included deferred consideration of $550 million to be paid in cash on or before January 3, 2025. We discounted this obligation and recorded $532 million as deferred acquisition consideration upon closing and amortized the discount to interest expense in the accompanying statements of operations. During the year ended December 31, 2024, we paid $75 million of this deferred consideration and on January 3, 2025 we paid the remaining $475 million. These payments are recorded as a cash outflow within the acquisitions of businesses, net of cash acquired in the accompanying unaudited condensed consolidated statements of cash flows (“statements of cash flows”) in the period of occurrence.
Interest Expense
For the three months ended June 30, 2025 and 2024, we incurred interest expense of $114 million and $115 million, respectively. Interest expense for the three months ended June 30, 2025 and 2024 includes zero and $9 million, respectively, related to the amortization of deferred acquisition consideration associated with the Vencer Acquisition. For the six months ended June 30, 2025 and 2024, we incurred interest expense of $221 million and $225 million, respectively. Interest expense for the six months ended June 30, 2025 and 2024 includes zero and $18 million, respectively, related to the amortization of deferred acquisition consideration associated with the Vencer Acquisition.
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NOTE 6 - COMMITMENTS AND CONTINGENCIES
Commitments. We routinely enter into, extend, or amend operating agreements in the ordinary course of business. We have long-term transportation, sales, processing, and water delivery commitments. During the six months ended June 30, 2025 we entered into a transportation services agreement in the DJ Basin to deliver fixed and determinable quantities of crude oil. Under the terms of this agreement, we are required to make periodic deficiency payments for any shortfalls in delivering the minimum volume commitment of 25,000 Bbls per day over a term ending in April 2030. The aggregate financial commitment fee over the remaining term was $71 million as of June 30, 2025. We have not, and do not, expect to incur any deficiency payments. There were no other significant commitments entered into during the six months ended June 30, 2025. For details of our existing commitments, refer to Note 6 - Commitments and Contingencies in Item 8. Financial Statements and Supplementary Data included in our 2024 Form 10-K.
Litigation and Legal Items. We are involved in various legal proceedings. We review the status of these proceedings on an ongoing basis and, from time to time, may settle or otherwise resolve these matters on terms and conditions that management believes are in our best interests. We have provided the necessary estimated accruals in the accompanying balance sheets where deemed appropriate for litigation and legal related items that are ongoing and not yet concluded. Other than any ordinary routine litigation incidental to the business and except as described below, we are not currently a party to, nor is our property currently subject to, any material legal proceedings, and we are not aware of any such proceedings contemplated by governmental authorities.
On May 2, 2025, Jeremy Lin (the “Plaintiff”), individually and on behalf of all others similarly situated, filed a putative class action complaint for violation of federal securities laws against us, our Chief Executive Officer, and our Chief Financial Officer (collectively, the “Defendants”) in the United States District Court for the District of New Jersey (the “Complaint”). The Complaint purports to bring a federal securities class action on behalf of a class of persons and entities other than the Defendants who acquired our securities between February 27, 2024 and February 24, 2025 and asserts violations of Sections 10(b) and 20(a) of the Exchange Act and Rule 10b-5 promulgated thereunder. The Complaint alleges, among other things, that the Defendants made materially false and misleading statements related to our business, operations and prospects, including our anticipated production volumes and financial condition in 2025. The Plaintiff seeks, among other things, certification of a class, an award of unspecified compensatory damages, interest, costs and expenses, including attorneys’ fees and expert fees. We intend to vigorously defend against the claims brought by the Plaintiff in this matter. We cannot predict at this point the length of time that this action will be ongoing or the liability, if any, which may arise therefrom.
NOTE 7 - STOCK-BASED COMPENSATION
Long Term Incentive Plans
In June 2024, in connection with our stockholders’ approval at our 2024 annual meeting of stockholders, we adopted the 2024 Long Term Incentive Plan (the “2024 LTIP”), which provides for the issuance of restricted stock units, performance stock units, stock options, and various other forms of awards, and reserved 3,100,000 shares of common stock for issuance under the 2024 LTIP. The 2024 LTIP supersedes and replaces all of our previous long-term incentive plans (the “Prior Plans”), such that awards may not be granted under the Prior Plans subsequent to the adoption of the 2024 LTIP. Awards granted under the Prior Plans will remain subject to the terms and conditions set forth in the applicable Prior Plan. The Prior Plans and 2024 LTIP are collectively referred to herein as the “LTIP.”
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We record compensation expense associated with the issuance of awards under the LTIP on a straight-line basis over the vesting period based on the fair value of the awards as of the date of grant within general and administrative expense in the accompanying statements of operations. The following table outlines the compensation expense recorded by type of award (in millions):

| Three Months Ended June 30, |  | Six Months Ended June 30,
| 2025 |  | 2024 |  | 2025 |  | 2024
Restricted and deferred stock units | $ | 8 |  |  | $ | 7 |  |  | $ | 16 |  |  | $ | 13 |
Performance stock units | 5 |  |  | 5 |  |  | 10 |  |  | 10 |
Total stock-based compensation | $ | 13 |  |  | $ | 12 |  |  | $ | 26 |  |  | $ | 23 |

As of June 30, 2025, unrecognized compensation expense related to the awards granted under the LTIP will be amortized through the relevant periods as follows (in millions):

| Unrecognized Compensation Expense |  | Final Year of Recognition
Restricted and deferred stock units | $ | 42 |  |  | 2028
Performance stock units | 28 |  |  | 2027
Total unrecognized stock-based compensation | $ | 70 |  |  |

Restricted Stock Units and Deferred Stock Units
We grant time-based restricted stock units (“RSUs”) to our officers, executives, and employees and time-based deferred stock units (“DSUs”) to our non-employee directors under the LTIP. Each RSU and DSU represents a right to receive one share of our common stock after the RSU or DSU vests and is settled. RSUs vest ratably over a one, two, or three-year service period on each anniversary following the grant date. RSUs are settled in shares of our common stock shortly after vesting. DSUs vest over a one-year period following the grant date. DSUs are settled in shares of our common stock upon the non-employee director’s separation of service from our Board of Directors (our “Board”). The grant-date fair value of RSUs and DSUs is equal to the closing price of our common stock on the date of the grant.
The following table presents the changes in non-vested RSUs and DSUs for the six months ended June 30, 2025:

| RSUs and DSUs |  | Weighted-Average Grant-Date Fair Value
Non-vested, beginning of year | 932,902 |  |  | $ | 65.69 |
Granted | 672,806 |  |  | 43.45 |
Vested | (276,694) |  |  | 63.63 |
Forfeited | (73,014) |  |  | 63.74 |
Non-vested, end of period | 1,256,000 |  |  | $ | 54.35 |

The aggregate grant-date fair value of the RSUs and DSUs granted under the LTIP during the six months ended June 30, 2025 was $29 million.
Performance Stock Units
We grant market-based performance stock units (“PSUs”) to our officers and certain executives under the LTIP. The number of shares of our common stock issued to settle PSUs ranges from zero to 225% of the number of PSUs granted and is determined based on performance achievement against certain market-based criteria over a three-year performance period. Performance achievement is determined based on our annualized absolute total stockholder return (“TSR”). Absolute TSR is determined based upon the change in our stock price over the performance period plus dividends paid. PSUs generally vest on December 31 of the year preceding the third anniversary of the date of grant and settle by March 15 of the following year upon the determination and approval of performance achievement by the Compensation Committee of our Board.
The grant-date fair value of our PSUs is estimated using a Monte Carlo valuation model. The Monte Carlo valuation model is based on random projections of stock price paths and repeated numerous times to achieve a probabilistic assessment. Significant assumptions used in this valuation include our expected volatility as well as the volatilities for each of our peers and an interpolated risk-free interest rate based on U.S. Treasury yields with maturities consistent with the performance period.
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The following table presents the change of non-vested PSUs for the six months ended June 30, 2025:

| PSUs |  | Weighted-Average Grant-Date Fair Value
Non-vested, beginning of year | 650,046 |  |  | $ | 85.23 |
Granted(1) | 342,316 |  |  | 53.19 |
Adjusted shares based on performance(2) | (81,547) |  |  | 73.09 |
Vested(2) | (76,827) |  |  | 72.98 |
Forfeited | (45,659) |  |  | 84.98 |
Non-vested, end of period(1) | 788,329 |  |  | $ | 73.78 |

___________________________
(1)The number of awards assumes that the associated performance condition is met at the target amount (multiplier of one). The final number of shares of our common stock issued may vary depending on the performance multiplier, which ranges from zero to 225%, depending on the level of satisfaction of the performance condition.
(2)Upon completion of the performance period for the PSUs granted in 2022, a performance achievement of 46% or 54%, as applicable, was applied to each of the grants, resulting in a number of shares less than the target amount of such PSUs being settled during the six months ended June 30, 2025.
The aggregate grant-date fair value of the PSUs granted under the LTIP during the six months ended June 30, 2025 was $18 million.
NOTE 8 - FAIR VALUE MEASUREMENTS
We follow authoritative accounting guidance for measuring the fair value of assets and liabilities. This guidance defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Further, this guidance establishes a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available.
The fair value hierarchy is broken down into three levels based on the reliability of the inputs as follows:
Level 1: Quoted prices in active markets for identical assets or liabilities
Level 2: Quoted prices in active markets for similar assets and liabilities, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations whose inputs are observable or whose significant value drivers are observable
Level 3: Significant inputs to the valuation model are unobservable
We classify financial and non-financial assets and liabilities based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy.
Derivatives
We use Level 2 inputs to measure the fair value of crude oil and natural gas commodity price derivatives. The fair value of our commodity price derivatives is estimated using industry-standard models that contemplate various inputs including, but not limited to, the contractual price of the underlying position, current market prices, forward commodity price curves, volatility factors, time value of money, and the credit risk of both us and our counterparties. We validate our fair value estimate by corroborating the original source of inputs, monitoring changes in valuation methods and assumptions, and reviewing counterparty mark-to-market statements and other supporting documentation. Refer to Note 9 - Derivatives for more information regarding our derivative instruments.
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The following table presents our financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2025 and December 31, 2024 and their classification within the fair value hierarchy (in millions):

| As of June 30, 2025 |  | As of December 31, 2024
| Level 2 |  | Level 2
Derivative assets | $ | 186 |  |  | $ | 84 |
Derivative liabilities | 54 |  |  | 35 |

Long-Term Debt
The portion of our long-term debt related to our Credit Facility, if any, approximates its fair value as it bears interest at a floating rate that approximates a current market rate. The portion of our long-term debt related to our Senior Notes is recorded at cost, net of any unamortized discount and deferred financing costs. The fair value of our Senior Notes is based on quoted market prices, and as such, is designated as Level 1 within the fair value hierarchy. The following table presents the fair value of our Senior Notes as of the dates indicated ($ in millions):

|  |  | As of June 30, 2025 |  | As of December 31, 2024
| Nominal Interest |  | Fair Value |  | Percent of Par |  | Fair Value |  | Percent of Par
2026 Senior Notes | 5.000% |  | $ | 395 |  |  | 99% |  | $ | 394 |  |  | 99%
2028 Senior Notes | 8.375% |  | 1,384 |  |  | 102% |  | 1,405 |  |  | 104%
2030 Senior Notes | 8.625% |  | 1,016 |  |  | 102% |  | 1,049 |  |  | 105%
2031 Senior Notes | 8.750% |  | 1,366 |  |  | 101% |  | 1,408 |  |  | 104%
2033 Senior Notes | 9.625% |  | 770 |  |  | 103% |  | — |  |  | —%

Our deferred acquisition consideration was recorded in connection with the Vencer Acquisition using an estimated fair value discount at the time of the transaction based on quoted market prices from our debt as well as other inputs classified as Level 2 within the fair value hierarchy. As of December 31, 2024, the carrying value of the deferred acquisition consideration approximated fair value. Refer to Note 5 - Debt for additional information.
Acquisitions and Impairments of Proved and Unproved Properties
We measure acquired assets or businesses at fair value on a nonrecurring basis and review our proved and unproved crude oil and natural gas properties for impairment using inputs that are not observable in the market and are therefore designated as Level 3 within the valuation hierarchy. The most significant fair value determinations for non-financial assets and liabilities are related to crude oil and natural gas properties acquired. Refer to Note 2 - Acquisitions and Divestitures for additional information. During the three and six months ended June 30, 2025 and 2024, we recorded no impairments of proved or unproved properties. Refer to Note 1 – Summary of Significant Accounting Policies in Item 8. Financial Statements and Supplementary Data included in our 2024 Form 10-K for information on our policies for determining fair value of proved and unproved properties and related impairment expense.
NOTE 9 - DERIVATIVES
We periodically enter into commodity derivative contracts to mitigate a portion of our exposure to potentially adverse market changes in commodity prices for our expected future crude oil and natural gas production and the associated impact on our cash flows. Our commodity derivative contracts consist of swaps, collars, and basis protection swaps. As of June 30, 2025, all of our derivative counterparties were members of our Credit Facility lender group, and all commodity derivative contracts are entered into for other-than-trading purposes. We do not designate our commodity derivative contracts as hedging instruments.
A typical swap arrangement guarantees a fixed price on contracted volumes. If the agreed upon published third-party index price (“index price”) is lower than the fixed contract price at the time of settlement, we receive the difference between the index price and the fixed contract price. If the index price is higher than the fixed contact price at the time of settlement, we pay the difference between the index price and the fixed contract price.
A typical collar arrangement establishes a floor and ceiling price on contracted volumes through the use of a short call and a long put. When the index price is below the floor price at the time of settlement, we receive the difference between the index price and floor price. When the index price is above the ceiling price at the time of settlement, we pay the difference between the index price and the ceiling price. When the index price is between the floor price and ceiling price, no payment or receipt occurs.
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Basis protection swaps are arrangements that guarantee a price differential from a specified delivery point. For basis protection swaps, we receive a payment from the counterparty if the price differential is greater than the stated terms of the contract and pay the counterparty if the price differential is less than the stated terms of the contract.
The following table summarizes the components of the derivative gain (loss), net presented on the accompanying statements of operations for the periods below (in millions):

| Three Months Ended June 30, |  | Six Months Ended June 30,
| 2025 |  | 2024 |  | 2025 |  | 2024
Derivative cash settlement gain (loss), net |  |  |  |  |  |  |
Crude oil contracts | $ | 36 |  |  | $ | (19) |  |  | $ | 37 |  |  | $ | (30) |
Natural gas contracts | 33 |  |  | 6 |  |  | 36 |  |  | 6 |
Total derivative cash settlement gain (loss), net | 69 |  |  | (13) |  |  | 73 |  |  | (24) |
Change in fair value gain (loss) | 35 |  |  | 21 |  |  | 83 |  |  | (78) |
Total derivative gain (loss), net | $ | 104 |  |  | $ | 8 |  |  | $ | 156 |  |  | $ | (102) |

As of June 30, 2025, we had entered into the following commodity price derivative contracts:

|  | Contract Period
|  | Q3 2025 |  | Q4 2025 |  | Q1 2026 |  | Q2 2026 |  | Q3 2026 |  | Q4 2026
Crude Oil Derivatives (volumes in Bbl/day and prices in $/Bbl) |  |  |  |
Swaps |  |  |  |  |  |  |  |  |  |  |  |
NYMEX WTI Volumes |  | 47,700 |  | 71,700 |  | 33,000 |  | 42,500 |  | 12,000 |  | —
Weighted-Average Contract Price |  | $ | 70.89 |  |  | $ | 66.37 |  |  | $ | 68.28 |  |  | $ | 61.00 |  |  | $ | 65.21 |  |  | $ | — |
Collars |  |  |  |  |  |  |  |  |  |  |  |
NYMEX WTI Volumes |  | 46,500 |  | 19,000 |  | 15,000 |  | 5,000 |  | — |  | —
Weighted-Average Ceiling Price |  | $ | 76.99 |  |  | $ | 75.11 |  |  | $ | 75.18 |  |  | $ | 71.28 |  |  | $ | — |  |  | $ | — |
Weighted-Average Floor Price |  | $ | 66.31 |  |  | $ | 60.00 |  |  | $ | 60.00 |  |  | $ | 60.00 |  |  | $ | — |  |  | $ | — |
Natural Gas Derivatives (volumes in MMBtu/day and prices in $/MMBtu) |  |  |  |
Swaps |  |  |  |  |  |  |  |  |  |  |  |
NYMEX HH Volumes |  | 240,000 |  | 240,000 |  | 60,000 |  | 60,000 |  | 60,000 |  | 60,000
Weighted-Average Contract Price |  | $ | 3.83 |  |  | $ | 3.83 |  |  | $ | 4.42 |  |  | $ | 4.42 |  |  | $ | 4.42 |  |  | $ | 4.42 |
Collars |  |  |  |  |  |  |  |  |  |  |  |
NYMEX HH Volumes |  | 50,000 |  | 50,000 |  | 200,000 |  | 200,000 |  | 200,000 |  | 200,000
Weighted-Average Ceiling Price |  | $ | 4.30 |  |  | $ | 4.30 |  |  | $ | 4.35 |  |  | $ | 4.35 |  |  | $ | 4.35 |  |  | $ | 4.35 |
Weighted-Average Floor Price |  | $ | 3.66 |  |  | $ | 3.66 |  |  | $ | 3.52 |  |  | $ | 3.52 |  |  | $ | 3.52 |  |  | $ | 3.52 |
Basis Protection Swaps |  |  |  |  |  |  |  |  |  |  |  |
Waha Basis Volumes |  | 140,000 |  | 140,000 |  | 130,000 |  | 130,000 |  | 130,000 |  | 130,000
Weighted-Average Contract Price |  | $ | (1.32) |  |  | $ | (1.32) |  |  | $ | (1.31) |  |  | $ | (1.31) |  |  | $ | (1.31) |  |  | $ | (1.31) |
CIG Basis Volumes |  | $ | 150,000 |  |  | $ | 150,000 |  |  | $ | 130,000 |  |  | $ | 130,000 |  |  | $ | 130,000 |  |  | $ | 130,000 |
Weighted-Average Contract Price |  | $ | (0.83) |  |  | $ | (0.83) |  |  | $ | (0.57) |  |  | $ | (0.57) |  |  | $ | (0.57) |  |  | $ | (0.57) |

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Subsequent to June 30, 2025 and as of August 1, 2025, we had entered into the following commodity price derivative contracts:

|  |  |  | Contract Period
|  |  |  | Q3 2025 |  | Q4 2025 |  | Q1 2026 |  | Q2 2026 |  | Q3 2026 |  | Q4 2026
Crude Oil Derivatives (volumes in Bbl/day and prices in $/Bbl) |  |  |  |  |  |
Swaps |  |  |  |  |  |  |  |  |  |  |  |  |  |
NYMEX WTI Volumes |  |  |  | 663 |  | 3,000 |  | — |  | 2,000 |  | — |  | —
Weighted-Average Contract Price |  |  |  | $ | 68.00 |  |  | $ | 67.33 |  |  | $ | — |  |  | $ | 65.38 |  |  | $ | — |  |  | $ | — |

Derivative Assets and Liabilities Fair Value
Our commodity price derivatives are measured at fair value and are included in the accompanying balance sheets as derivative assets and liabilities. The following table contains a summary of all our derivative positions reported on the accompanying balance sheets as well as a reconciliation between the gross assets and liabilities and the potential effects of master netting arrangements on the fair value of our commodity derivative contracts as of June 30, 2025, and December 31, 2024 (in millions):

| June 30, 2025 |  | December 31, 2024
Derivative Assets: |  |  |
Commodity contracts - current | $ | 174 |  |  | $ | 67 |
Commodity contracts - noncurrent | 12 |  |  | 17 |
Total derivative assets | 186 |  |  | 84 |
Amounts not offset in the accompanying balance sheets | (54) |  |  | (27) |
Total derivative assets, net | $ | 132 |  |  | $ | 57 |
Derivative Liabilities: |  |  |
Commodity contracts - current | $ | (39) |  |  | $ | (22) |
Commodity contracts - long-term | (15) |  |  | (13) |
Total derivative liabilities | (54) |  |  | (35) |
Amounts not offset in the accompanying balance sheets | 54 |  |  | 27 |
Total derivative liabilities, net | $ | — |  |  | $ | (8) |

NOTE 10 - ASSET RETIREMENT OBLIGATIONS
We recognize an estimated liability for future costs associated with the abandonment of our crude oil and natural gas properties, including facilities requiring decommissioning. A liability for the fair value of an asset retirement obligation and a corresponding increase to the carrying value of the related long-lived asset are recorded at the time a well is drilled or acquired, or a facility is constructed. The increase in carrying value is included in proved properties in the accompanying balance sheets. We deplete the amount added to proved properties and recognize expense in connection with the accretion of the discounted liability over the remaining estimated economic lives of the respective long-lived assets. Cash paid to settle asset retirement obligations is included in the cash flows from operating activities section of our accompanying statements of cash flows.
Our estimated asset retirement obligation liability is based on historical experience plugging and abandoning wells, estimated plugging and abandonment cost, estimated economic lives, and regulatory requirements. The liability is discounted using the credit-adjusted risk-free rate estimated at the time the liability is incurred or revised.
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A roll-forward of our asset retirement obligation is as follows (in millions):

| Amount
Balance as of December 31, 2024 | $ | 458 |
Additional liabilities incurred with development activities and other | 4 |
Additional liabilities incurred with acquisitions | 2 |
Liabilities settled | (36) |
Accretion expense(1) | 15 |
Balance as of June 30, 2025 | $ | 443 |
Current portion(2) | $ | 59 |
Long-term portion | $ | 384 |

___________________________
(1)Accretion expense is included in depreciation, depletion, and amortization on the accompanying statements of operations and statements of cash flows.
(2)The current portion of the asset retirement obligation is included in other liabilities on the accompanying balance sheets.
NOTE 11 - EARNINGS PER SHARE
Earnings per basic and diluted share are calculated under the treasury stock method. Basic net income per common share is calculated by dividing net income by the basic weighted-average common shares outstanding for the respective period. Diluted net income per common share is calculated by dividing net income by the diluted weighted-average common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities consist of unvested RSUs, DSUs, PSUs as well as outstanding in-the-money stock options and warrants. When we recognize a loss from continuing operations, all potentially dilutive shares are anti-dilutive and are consequently excluded from the calculation of diluted earnings per share.
As discussed in Note 7 - Stock-Based Compensation, PSUs represent the right to receive a number of shares of the Company’s common stock ranging from zero to 225% of PSUs granted based on the performance achievement over the applicable performance period. The number of potentially dilutive shares related to PSUs is based on the number of shares, if any, that would be issuable at the end of the respective reporting period, assuming that date was the end of the performance period applicable to such awards.
We have also issued warrants, which represent the right to purchase our common stock at a specified exercise price. The number of potentially dilutive shares related to the warrants is based on the number of shares, if any, that would be exercisable at the end of the respective reporting period, assuming that date was the end of such warrants’ term. Warrants are only dilutive when the average price of the common stock during the period exceeds the exercise price. The exercise price of our warrants was in excess of our stock price during the three and six months ended June 30, 2025 and 2024; therefore, they were excluded from the earnings per share calculation.
The following table sets forth the calculations of basic and diluted net earnings per common share (in millions, except share and per share amounts):

| Three Months Ended June 30, |  | Six Months Ended June 30,
| 2025 |  | 2024 |  | 2025 |  | 2024
Net income | $ | 124 |  |  | $ | 216 |  |  | $ | 310 |  |  | $ | 392 |
Basic earnings per common share | $ | 1.34 |  |  | $ | 2.17 |  |  | $ | 3.33 |  |  | $ | 3.92 |
Diluted earnings per common share | $ | 1.34 |  |  | $ | 2.15 |  |  | $ | 3.33 |  |  | $ | 3.88 |
Weighted-average shares outstanding - basic | 92,588,030 |  |  | 99,425,524 |  |  | 93,107,102 |  |  | 100,061,694 |
Add: dilutive effect of stock awards | 82,884 |  |  | 819,354 |  |  | 110,939 |  |  | 803,000 |
Weighted-average shares outstanding - diluted | 92,670,914 |  |  | 100,244,878 |  |  | 93,218,041 |  |  | 100,864,694 |

There were 821,952 and 5,507 unvested awards that were anti-dilutive for the three months ended June 30, 2025 and 2024, respectively. There were 676,142 and 206,285 unvested awards that were anti-dilutive for the six months ended June 30, 2025 and 2024, respectively.
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NOTE 12 - INCOME TAXES
Deferred tax assets and liabilities are measured by applying the provisions of enacted tax laws to determine the amount of taxes payable or refundable currently or in future years related to cumulative temporary differences between the tax basis of assets and liabilities and amounts reported in the accompanying balance sheets. The tax effect of the net change in the cumulative temporary differences during each period in the deferred tax assets and liabilities determines the periodic provision for deferred taxes.
We assess the recoverability of our deferred tax assets each period by considering whether it is more likely than not that all or a portion of the deferred tax assets will be realized. In making such a determination, we consider all available evidence (both positive and negative), including future reversals of temporary differences, tax-planning strategies, projected future taxable income, and results of operations. As a result of merger activity in 2021, we recorded a valuation allowance of $25 million, which continued to be recorded as of June 30, 2025 and December 31, 2024, against certain acquired net operating losses and other tax attributes due to the limitation on realizability caused by the change of ownership provisions of Section 382 of the Internal Revenue Code. We will continue to monitor facts and circumstances in the reassessment of the likelihood that the deferred tax assets will be realized.
The net deferred tax liability as of June 30, 2025 and December 31, 2024 was $891 million and $801 million, respectively. Additionally, income tax payable of $9 million and $2 million is included in other liabilities on the accompanying balance sheets as of June 30, 2025 and December 31, 2024, respectively.
During the three months ended June 30, 2025 and 2024, we recorded income tax expense of $38 million and $67 million, respectively. During the six months ended June 30, 2025 and 2024, we recorded income tax expense of $99 million and $102 million, respectively. Income tax expense differs from the amount that would be provided by applying the statutory United States federal income tax rate of 21% to income from operations before income taxes due to the effect of state income taxes, excess tax benefits and deficiencies on stock-based compensation awards, tax limitations on compensation of covered individuals, tax credits, and other permanent differences. During the six months ended June 30, 2024, income tax expense was additionally impacted by deferred tax benefits from state apportionment changes as a result of the Vencer Acquisition.
We had no unrecognized tax benefits as of June 30, 2025 and December 31, 2024. We do not believe that there are any new items or changes in facts or judgments that would impact our tax position taken thus far in 2025.
On July 4, 2025, President Trump signed into law the One Big Beautiful Bill Act (“OBBBA”). The OBBBA makes permanent key elements of the Tax Cuts and Jobs Act of 2017, including 100% bonus depreciation and the business interest expense limitation. ASC Topic 740, Income Taxes, requires the effects of changes in tax rates and laws on deferred tax balances to be recognized in the period in which the legislation is enacted. Consequently, we are evaluating the impact of the OBBBA, and the results of such evaluations will be reflected in our Form 10-Q for the quarterly period ended September 30, 2025.
NOTE 13 - SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
Supplemental cash flow disclosures are presented below (in millions):

| Six Months Ended June 30,
| 2025 |  | 2024
Supplemental cash flow information: |  |  |
Cash (paid) refunded for income taxes, net | $ | (1) |  |  | $ | 4 |
Cash paid for interest | (207) |  |  | (204) |
Supplemental non-cash investing and financing activities: |  |  |
Changes in working capital related to capital expenditures | (40) |  |  | (125) |

NOTE 14 - STOCKHOLDERS’ EQUITY
Stock Repurchases
Our Board authorized a stock repurchase program authorizing repurchases of up to $500 million of our outstanding shares of common stock, in the open market, in privately negotiated transactions, or through block trades, derivative transactions, or purchases made in accordance with Rule 10b-18 and Rule 10b5-1 of the Exchange Act. The stock repurchase program does not have a termination date, does not require any specific number of shares to be acquired, and can be modified or discontinued by our Board at any time.
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We record stock repurchases at cost, which includes transaction costs that are direct and incremental to the repurchase, as a reduction to stockholders’ equity. As part of the transaction costs that are direct and incremental to the repurchase and, subject to netting against the fair value of stock issuances, we record a 1% excise tax with the corresponding liability recorded within accounts payable and accrued expenses on the accompanying balance sheets. Any excess of cost over the par value is charged to additional paid-in-capital on a pro-rata basis, with any remaining cost charged to retained earnings.
The table below summarizes stock repurchases pursuant to the stock repurchase program during the six months ended June 30, 2025 and 2024:

| Number of Shares |  | Weighted-Average Price |  | Total Purchase Price (in millions)(1)
2025 |  |  |  |  |
Open market repurchases | 1,560,305 |  | $ | 46.08 |  |  | $ | 72 |
Total stock repurchases | 1,560,305 |  | $ | 46.08 |  |  | $ | 72 |
2024 |  |  |  |  |
Privately negotiated transactions |  |  |  |  |
NGP Tap Rock Holdings, LLC and certain of its affiliates | 876,193 |  | $ | 64.54 |  |  | $ | 57 |
Vencer | 1,041,667 |  | 71.99 |  |  | 75 |
Open market repurchases | 877,416 |  | 68.73 |  |  | 60 |
Total stock repurchases | 2,795,276 |  | $ | 68.63 |  |  | $ | 192 |

_________________________
(1)Excludes commissions paid and excise taxes accrued related to stock repurchases.
These stock repurchases were funded from our cash on hand, and the shares were immediately retired. As of June 30, 2025, $193 million remained available under the program for repurchase of our outstanding common stock.
Dividends
The following table summarizes the dividends declared for the six months ended June 30, 2025 and 2024:

| Base |  | Variable |  | Total |  | Total
| (per share) |  | (per share) |  | (per share) |  | (in millions)
2025 |  |  |  |  |  |  |
First quarter | $ | 0.50 |  |  | $ | — |  |  | $ | 0.50 |  |  | $ | 45 |
Second quarter | $ | 0.50 |  |  | $ | — |  |  | $ | 0.50 |  |  | $ | 46 |
2024 |  |  |  |  |  |  |
First quarter | $ | 0.50 |  |  | $ | 0.95 |  |  | $ | 1.45 |  |  | $ | 148 |
Second quarter | $ | 0.50 |  |  | $ | 1.00 |  |  | $ | 1.50 |  |  | $ | 151 |

All RSUs, DSUs, and PSUs receive a dividend equivalent per unit, recognized as a liability included in other liabilities and other long-term liabilities on the accompanying balance sheets until the recipients receive the dividend equivalents. Refer to Note 7 - Stock-Based Compensation for further discussion around our LTIP.
Capital Return Program
Beginning in February 2025, our Board approved a capital return program that prioritizes directing the majority of our free cash flow to debt reduction, following the payment of our base dividend, which remains $0.50 per share quarterly. Any incremental returns of capital beyond the base dividend and debt reduction will occur at the discretion of our Board and will be in the form of share repurchases and/or variable dividends. Future dividend payments must be approved by our Board and will depend on our liquidity, financial requirements, and other factors considered relevant by our Board.
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NOTE 15 - SEGMENT REPORTING
We aggregate and report our crude oil and natural gas exploration and production operations in one reportable upstream segment. The Permian Basin and the DJ Basin are operating segments of the Company that we aggregate into the upstream segment due to the similarity of these domestic operations. The upstream segment derives revenue from the sale of produced crude oil, natural gas, and NGL. We consider our midstream functions as ancillary to our upstream segment. Our chief operating decision maker (“CODM”) is our Chief Executive Officer.
The measure of profit or loss that the CODM uses to assess performance and allocate resources for the upstream segment is Adjusted EBITDAX. Adjusted EBITDAX is defined as earnings before interest, income taxes, depreciation, depletion, and amortization, exploration expense, and other non-cash and non-recurring charges. The measure of segment assets is reported on the accompanying consolidated balance sheets as total consolidated assets and capital expenditures are reported in our statements of cash flows. The CODM uses Adjusted EBITDAX to evaluate income generated from segment assets in deciding whether to reinvest profits into the upstream segment or into other activities, such as for acquisitions, debt reduction, or to return capital to stockholders.
The following table presents a reconciliation of reportable segment Adjusted EBITDAX to income from operations before income taxes (in millions):

| Three Months Ended June 30, |  | Six Months Ended June 30,
| 2025 |  | 2024 |  | 2025 |  | 2024
Adjusted EBITDAX | $ | 749 |  |  | $ | 919 |  |  | $ | 1,535 |  |  | $ | 1,847 |
Interest expense, net(1) | (112) |  |  | (113) |  |  | (217) |  |  | (219) |
Depreciation, depletion, and amortization | (501) |  |  | (521) |  |  | (946) |  |  | (988) |
Exploration | (3) |  |  | (2) |  |  | (6) |  |  | (13) |
Transaction costs | — |  |  | (8) |  |  | (6) |  |  | (31) |
Derivative gain (loss), net | 104 |  |  | 8 |  |  | 156 |  |  | (102) |
Derivative cash settlement (gain) loss, net | (69) |  |  | 13 |  |  | (73) |  |  | 24 |
Stock-based compensation(2) | (13) |  |  | (12) |  |  | (26) |  |  | (23) |
Other, net(3) | 7 |  |  | (1) |  |  | (8) |  |  | (1) |
Income from operations before income taxes | $ | 162 |  |  | $ | 283 |  |  | $ | 409 |  |  | $ | 494 |

_________________________
(1)Includes interest income of $2 million for both the three months ended June 30, 2025 and 2024, and $4 million and $6 million for the six months ended June 30, 2025 and 2024 respectively. Interest income is included as a portion of other, net in the accompanying statements of operations.
(2)Included as a portion of general and administrative expense in the accompanying statements of operations.
(3)The three months ended June 30, 2025 includes (i) a $9 million reduction related to the unrealized loss on crude oil linefill contracts recorded during the three months ended March 31, 2025 that settled during the quarter that is included in other, net and (ii) $2 million for non-recurring cash unused commitment fees that are included in other operating expense, both of which are in the accompanying statements of operations for the period. The three months ended June 30, 2024 includes $1 million for non-recurring cash unused commitment fees that are included in other operating expense in the accompanying statements of operations for the period. The six months ended June 30, 2025 includes (i) $4 million of non-recurring cash severance charges incurred in connection with our announced reduction in force that are included in general and administrative expense and (ii) $4 million for non-recurring cash unused commitment fees that are included in other operating expense, both of which are in the accompanying statements of operations for the period. The six months ended June 30, 2024 includes (i) $2 million of loss on sale of properties that is included in other, net and (ii) $1 million gain for non-recurring cash unused commitment fees that are included in other operating expense, both of which are in the accompanying statements of operations for the period.
NOTE 16 - SUBSEQUENT EVENTS
Non-Core DJ Basin Divestitures
In July 2025, we executed two Purchase and Sale Agreements (each a “PSA”) with two different buyers to divest certain non-core DJ Basin assets. These transactions are expected to close around the end of the third quarter. We will receive an aggregate of $435 million in cash consideration, subject to certain customary purchase price adjustments and closing conditions set forth in each PSA.
Capital Return Program
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In August 2025, our Board reinstated a capital return strategy of allocating 50% of Adjusted Free Cash Flow, after the base dividend, which remains $0.50 per share quarterly, to share buybacks on an annual basis. In conjunction with this decision, our Board increased the amount authorized for repurchases under our existing stock repurchase program to $750 million, pursuant to which we may, from time to time, acquire shares of our common stock in the open market, in privately negotiated transactions, or through block trades, derivative transactions, or purchases made in accordance with Rule 10b-18 and Rule 10b5-1 of the Exchange Act. The stock repurchase program does not have a termination date, does not require any specific number of shares to be acquired, and can be modified or discontinued by our Board at any time.
Future dividend payments and share buybacks must be approved by our Board and will depend on our liquidity, financial requirements, and other factors considered relevant by our Board.
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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” contained in our 2024 Form 10-K, as well as with our unaudited condensed consolidated financial statements and notes thereto included in this Quarterly Report on Form 10-Q. Further, we encourage you to review the Information Regarding Forward-Looking Statements.
Executive Summary
We are an independent exploration and production company focused on the acquisition, development, and production of crude oil and associated liquids-rich natural gas from our premier assets in the Permian Basin in Texas and New Mexico and the DJ Basin in Colorado. Our proven business model to maximize stockholder returns is focused on four key strategic pillars: generate significant free cash flow, maintain a premier balance sheet, return capital to our stockholders, and demonstrate ESG leadership.
Financial and Operating Results
Our financial and operating results for the three months ended June 30, 2025:
•Total sales volumes of 29 MMBoe and average sales volumes of 317 MBoe per day;
•Net income of $124 million, or $1.34 per diluted share. Adjusted EBITDAX(1) of $749 million;
•Cash flows provided by operating activities of $298 million. Adjusted Free Cash Flow(2) was $123 million;
•Capital expenditures in drilling, completions, facilities, land, midstream assets, and other were $506 million;
•Cash dividends paid of $47 million.
Our financial and operating results for the six months ended June 30, 2025:
•Total sales volumes of 57 MMBoe and average sales volumes of 314 MBoe per day;
•Net income of $310 million, or $3.33 per diluted share. Adjusted EBITDAX(1) of $1.5 billion;
•Cash flows provided by operating activities of $1.0 billion. Adjusted Free Cash Flow(2) was $294 million;
•Capital expenditures in drilling, completions, facilities, land, midstream assets, and other were $1.0 billion;
•Repurchases of approximately 1.6 million shares of our common stock totaling $72 million; and
•Cash dividends paid of $97 million.
(1) Adjusted EBITDAX is a non-GAAP financial measure. Refer to the “Non-GAAP Financial Measures - Reconciliation of Net Income to Adjusted EBITDAX” below for additional discussion.
(2) Adjusted Free Cash Flow is a non-GAAP financial measure. Refer to the “Non-GAAP Financial Measures - Reconciliation of Adjusted Free Cash Flow to Cash Provided by Operating Activities” and “Liquidity and Capital Resources” below for additional discussion.
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Commodity Prices and Certain Other Market Conditions
The crude oil and natural gas industry is cyclical and commodity prices are inherently volatile. During the first half of 2025, crude oil prices experienced significant volatility as a result of (i) the conflicts in the Middle East (including current events involving Israel and Iran), South America, and Russia (including current events involving Russia and Ukraine), (ii) trade and tariff uncertainties driving concerns over an increase in inflation, as well as disruption to global supply chains and consumer demand, (iii) continued concerns over economic growth, specifically in China and India as both are significant oil consumers, and (iv) OPEC+’s decision to increase crude oil output, creating additional global supply and further downward pressure on oil prices. These factors have led to declining average crude oil prices, with NYMEX WTI crude oil closing at $57.13 on May 5, 2025, the lowest levels seen since 2021.
U.S. inflation rates during the first half of 2025 were relatively stable, yet remained slightly higher than historical averages. Inflationary pressures, such as trade tariffs, can lead to economic slowdown and/or lead to a recession. A slowdown or recession can cause a decrease in short-term or longer-term demand for commodities, resulting in oversupply and potential for lower commodity prices.
The foregoing destabilizing factors have led to significant fluctuations in global financial markets and uncertainty about world-wide crude oil and natural gas supply and demand, which in turn has increased the volatility of crude oil and natural gas prices. Prolonged lower crude oil prices and inflationary costs could adversely affect our drilling program and could result in a significant triggering event that may cause an impairment over our crude oil and natural gas assets. Consequently, we may incur substantial impairment charges in the future, which could have a material adverse effect on our results of operations. We maintain operational flexibility to control the pace of our capital spending and we regularly monitor these external factors that may negatively influence it. As a result, we may revise our capital program during the year.
The below graph depicts monthly average NYMEX WTI crude oil and NYMEX HH natural gas price from January 2024 through June 2025.
____________________________
(1) The average NYMEX WTI crude oil price for the three months ended June 30, 2025 and March 31, 2025 was $63.74 and $71.42, respectively. The average NYMEX WTI crude oil price for the six months ended June 30, 2025 and 2024 was $67.58 and $78.77, respectively.
(2) The average NYMEX natural gas HH price for the three months ended June 30, 2025 and March 31, 2025 was $3.44 and $3.65, respectively. The average NYMEX natural gas HH price for the six months ended June 30, 2025 and 2024 was $3.55 and $2.07, respectively.
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In light of uncertainty associated with crude oil and natural gas demand, future monetary policy relating to inflationary pressures, and governmental policies aimed at transitioning toward lower carbon energy, we cannot predict any future volatility in or levels of commodity prices or demand for crude oil and natural gas.
We receive a premium or discount to the benchmark WTI price for our crude oil production. The differential between the benchmark price and the price we receive can reflect adjustments for quality, location, and transportation. Our Permian Basin crude oil price generally includes a transportation differential for delivery to Cushing, Oklahoma. During the three and six months ended June 30, 2025, our Permian Basin crude oil differential was a premium to WTI. Our DJ Basin crude oil price generally includes a higher-grade quality differential. A transportation differential is also charged for delivery to Cushing, Oklahoma and may be presented net within crude oil, natural gas, and NGL sales or gross within gathering, transportation, and processing in our accompanying statement of operations based on when control is transferred within the associated contracts with customers. Basis differentials can be volatile and can change at various times given their high correlation with market dynamics, supply and demand, and overall production.
Our natural gas production is typically sold at a discount to the benchmark NYMEX Henry Hub price. Our Permian Basin natural gas production is sold based on prices established for the Waha Hub in West Texas, and our DJ Basin natural gas production is sold based on prices established for Colorado Interstate Gas (“CIG”). The pricing we receive for our natural gas in both basins is correlated with the capacity of in-field gathering systems, compression, and processing facilities, as well as transportation pipelines out of the basins, of which are majority owned and operated by third parties. During 2024 and continuing into 2025, the Waha Hub experienced periods of negative pricing due to oversupply, seasonal maintenance, and limited pipeline capacity. During 2025, periods of negative pricing have occurred less often as pricing has been positively impacted by winter seasonal demand and improvements in available pipeline capacity. CIG pricing is often impacted by seasonality and typically receives a higher price during the winter months as local demand increases as temperatures decrease.
We periodically enter into natural gas basis protection swaps to mitigate a portion of our exposure to adverse market changes. Refer to Note 9 - Derivatives under Part I, Item 1 of this Quarterly Report on Form 10-Q for further discussion on our derivative contracts.
Our NGL production is sold based on Mt. Belvieu market benchmarks. Our realized prices reflect adjustments, both premiums and discounts, driven by crude oil prices and various other factors including seasonal demand fluctuations, transportation, processing and logistics costs, regional location differentials, and broader market dynamics. In the DJ Basin, we take the majority of our NGL in kind from third party processors and sell them to directly to the markets via pipeline or trucks. In the Permian Basin, the majority of our NGL are marketed on our behalf by third-party processors.
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Results of Operations
The following table summarizes our product revenues, sales volumes, and average sales prices for the periods indicated:

| Three Months Ended |  |  |  | Six Months Ended |  |
| June 30, 2025 |  | March 31, 2025 |  | Percent Change |  | June 30, 2025 |  | June 30, 2024 |  | Percent Change
Revenues (in millions): |  |  |  |  |  |  |  |  |  |  |
Crude oil sales | $ | 868 |  |  | $ | 901 |  |  | (4) | % |  | $ | 1,769 |  |  | $ | 2,210 |  |  | (20) | %
Natural gas sales | 48 |  |  | 125 |  |  | (62) | % |  | 173 |  |  | 96 |  |  | 80 | %
NGL sales | 138 |  |  | 166 |  |  | (17) | % |  | 304 |  |  | 333 |  |  | (9) | %
Product revenue | $ | 1,054 |  |  | $ | 1,192 |  |  | (12) | % |  | $ | 2,246 |  |  | $ | 2,639 |  |  | (15) | %
Sales Volumes: |  |  |  |  |  |  |  |  |  |  |
Crude oil (MBbl) | 13,583 |  |  | 12,709 |  |  | 7 | % |  | 26,292 |  |  | 28,346 |  |  | (7) | %
Natural gas (MMcf) | 47,709 |  |  | 50,471 |  |  | (5) | % |  | 98,180 |  |  | 108,729 |  |  | (10) | %
NGL (MBbl) | 7,285 |  |  | 6,871 |  |  | 6 | % |  | 14,156 |  |  | 15,263 |  |  | (7) | %
Total sales volumes (MBoe) | 28,819 |  |  | 27,992 |  |  | 3 | % |  | 56,811 |  |  | 61,731 |  |  | (8) | %
Average Sales Prices (before derivatives): |  |  |  |  |  |  |  |  |  |  |
Crude oil (per Bbl) | $ | 63.87 |  |  | $ | 70.90 |  |  | (10) | % |  | $ | 67.27 |  |  | $ | 77.98 |  |  | (14) | %
Natural gas (per Mcf) | $ | 1.00 |  |  | $ | 2.48 |  |  | (60) | % |  | $ | 1.77 |  |  | $ | 0.89 |  |  | 99 | %
NGL (per Bbl) | $ | 18.99 |  |  | $ | 24.07 |  |  | (21) | % |  | $ | 21.46 |  |  | $ | 21.79 |  |  | (2) | %
Total (per Boe) | $ | 36.56 |  |  | $ | 42.58 |  |  | (14) | % |  | $ | 39.53 |  |  | $ | 42.75 |  |  | (8) | %
Average Sales Prices (after derivatives)(1): |  |  |  |  |  |  |  |  |  |  |
Crude oil (per Bbl) | $ | 66.55 |  |  | $ | 70.96 |  |  | (6) | % |  | $ | 68.68 |  |  | $ | 76.91 |  |  | (11) | %
Natural gas (per Mcf) | $ | 1.69 |  |  | $ | 2.56 |  |  | (34) | % |  | $ | 2.14 |  |  | $ | 0.94 |  |  | 128 | %
NGL (per Bbl) | $ | 18.99 |  |  | $ | 24.07 |  |  | (21) | % |  | $ | 21.46 |  |  | $ | 21.79 |  |  | (2) | %
Total (per Boe) | $ | 38.97 |  |  | $ | 42.73 |  |  | (9) | % |  | $ | 40.82 |  |  | $ | 42.37 |  |  | (4) | %

_____________________________
(1)Average sale prices, after derivatives is a non-GAAP financial measure. For a reconciliation of average sales price, before derivatives to average sales price, after derivatives, see Non-GAAP Financial Measures below.
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The following table presents crude oil, natural gas, and NGL sales volumes by operating region for the periods presented:

| Three Months Ended |  |  |  | Six Months Ended |  |
| June 30, 2025 |  | March 31, 2025 |  | Percent Change |  | June 30, 2025 |  | June 30, 2024 |  | Percent Change
Crude oil (MBbl) |  |  |  |  |  |  |  |  |  |  |
Permian Basin | 7,552 |  |  | 6,807 |  |  | 11 | % |  | 14,359 |  |  | 15,518 |  |  | (7) | %
DJ Basin | 6,031 |  |  | 5,902 |  |  | 2 | % |  | 11,933 |  |  | 12,828 |  |  | (7) | %
Total | 13,583 |  |  | 12,709 |  |  | 7 | % |  | 26,292 |  |  | 28,346 |  |  | (7) | %
Natural gas (MMcf) |  |  |  |  |  |  |  |  |  |  |
Permian Basin | 23,190 |  |  | 24,567 |  |  | (6) | % |  | 47,757 |  |  | 48,755 |  |  | (2) | %
DJ Basin | 24,519 |  |  | 25,904 |  |  | (5) | % |  | 50,423 |  |  | 59,974 |  |  | (16) | %
Total | 47,709 |  |  | 50,471 |  |  | (5) | % |  | 98,180 |  |  | 108,729 |  |  | (10) | %
NGL (MBbl) |  |  |  |  |  |  |  |  |  |  |
Permian Basin | 4,076 |  |  | 3,886 |  |  | 5 | % |  | 7,962 |  |  | 8,427 |  |  | (6) | %
DJ Basin | 3,209 |  |  | 2,985 |  |  | 8 | % |  | 6,194 |  |  | 6,836 |  |  | (9) | %
Total | 7,285 |  |  | 6,871 |  |  | 6 | % |  | 14,156 |  |  | 15,263 |  |  | (7) | %
Total sales volumes (MBoe) |  |  |  |  |  |  |  |  |  |  |
Permian Basin | 15,492 |  |  | 14,788 |  |  | 5 | % |  | 30,280 |  |  | 32,071 |  |  | (6) | %
DJ Basin | 13,327 |  |  | 13,204 |  |  | 1 | % |  | 26,531 |  |  | 29,660 |  |  | (11) | %
Total | 28,819 |  |  | 27,992 |  |  | 3 | % |  | 56,811 |  |  | 61,731 |  |  | (8) | %
Average sales volumes per day (MBoe/d) |  |  |  |  |  |  |  |  |  |  |
Permian Basin | 171 |  |  | 164 |  |  | 4 | % |  | 167 |  |  | 176 |  |  | (5) | %
DJ Basin | 146 |  |  | 147 |  |  | (1) | % |  | 147 |  |  | 163 |  |  | (10) | %
Total | 317 |  |  | 311 |  |  | 2 | % |  | 314 |  |  | 339 |  |  | (7) | %

The following table sets forth information regarding crude oil, natural gas, and NGL sales prices, excluding the impact of commodity derivatives and production costs for the periods presented.

| Three Months Ended |  |  |  | Six Months Ended |  |
Average Sales Price | June 30, 2025 |  | March 31, 2025 |  | Percent Change |  | June 30, 2025 |  | June 30, 2024 |  | Percent Change
Crude Oil (Per Bbl) |  |  |  |  |  |  |  |  |  |  |
Permian Basin | $ | 64.06 |  |  | $ | 71.57 |  |  | (10) | % |  | $ | 67.62 |  |  | $ | 79.26 |  |  | (15) | %
DJ Basin | $ | 63.63 |  |  | $ | 70.12 |  |  | (9) | % |  | $ | 66.84 |  |  | $ | 76.42 |  |  | (13) | %
Total | $ | 63.87 |  |  | $ | 70.90 |  |  | (10) | % |  | $ | 67.27 |  |  | $ | 77.98 |  |  | (14) | %
Natural Gas (Per Mcf) |  |  |  |  |  |  |  |  |  |  |
Permian Basin | $ | (0.11) |  |  | $ | 1.00 |  |  | ** |  | $ | 0.46 |  |  | $ | (0.38) |  |  | **
DJ Basin | $ | 2.06 |  |  | $ | 3.89 |  |  | (47) | % |  | $ | 3.00 |  |  | $ | 1.92 |  |  | 56 | %
Total | $ | 1.00 |  |  | $ | 2.48 |  |  | (60) | % |  | $ | 1.77 |  |  | $ | 0.89 |  |  | 99 | %
NGL (Per Bbl) |  |  |  |  |  |  |  |  |  |  |
Permian Basin | $ | 16.68 |  |  | $ | 19.99 |  |  | (17) | % |  | $ | 18.30 |  |  | $ | 19.48 |  |  | (6) | %
DJ Basin | $ | 21.92 |  |  | $ | 29.39 |  |  | (25) | % |  | $ | 25.52 |  |  | $ | 24.64 |  |  | 4 | %
Total | $ | 18.99 |  |  | $ | 24.07 |  |  | (21) | % |  | $ | 21.46 |  |  | $ | 21.79 |  |  | (2) | %
Production Cost (Per Boe)(1) |  |  |  |  |  |  |  |  |  |  |
Permian Basin | $ | 6.52 |  |  | $ | 7.81 |  |  | (17) | % |  | $ | 7.15 |  |  | $ | 5.15 |  |  | 39 | %
DJ Basin | $ | 5.20 |  |  | $ | 5.48 |  |  | (5) | % |  | $ | 5.34 |  |  | $ | 3.99 |  |  | 34 | %
Total | $ | 5.91 |  |  | $ | 6.71 |  |  | (12) | % |  | $ | 6.31 |  |  | $ | 4.59 |  |  | 37 | %

_____________________________
** Percent not meaningful
(1)Represents lease operating expense and midstream operating expense per Boe using total sales volumes and excludes ad valorem and severance taxes.
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Product revenues decreased 12% to $1.1 billion for the three months ended June 30, 2025 compared to $1.2 billion for the three months ended March 31, 2025. The decrease was primarily due to a 14% decrease in crude oil equivalent pricing, excluding the impact of derivatives. The decrease was partially offset by a 3% increase in total sales volumes primarily due to the timing of wells turned-in-line in both basins.
Product revenues decreased 15% to $2.2 billion for the six months ended June 30, 2025 compared to $2.6 billion for the six months ended June 30, 2024. The decrease was primarily due to (i) an 8% decrease in crude oil equivalent pricing, excluding the impact of derivatives and (ii) an 8% decrease in total sales volumes primarily due to the timing of wells turned-in-line in both basins and normal decline in production from our existing wells.
The following table summarizes our operating expenses for the periods indicated ($ in millions, except per Boe amounts):

| Three Months Ended |  |  |  | Six Months Ended |  |
| June 30, 2025 |  | March 31, 2025 |  | Percent Change |  | June 30, 2025 |  | June 30, 2024 |  | Percent Change
Operating Expenses: |  |  |  |  |  |  |  |  |  |  |
Lease operating expense | $ | 158 |  |  | $ | 174 |  |  | (9) | % |  | $ | 332 |  |  | $ | 258 |  |  | 29 | %
Midstream operating expense | 12 |  |  | 14 |  |  | (14) | % |  | 26 |  |  | 26 |  |  | — | %
Gathering, transportation, and processing | 83 |  |  | 87 |  |  | (5) | % |  | 170 |  |  | 183 |  |  | (7) | %
Severance and ad valorem taxes | 75 |  |  | 89 |  |  | (16) | % |  | 164 |  |  | 204 |  |  | (20) | %
Exploration | 3 |  |  | 3 |  |  | — | % |  | 6 |  |  | 13 |  |  | (54) | %
Depreciation, depletion, and amortization | 501 |  |  | 445 |  |  | 13 | % |  | 946 |  |  | 988 |  |  | (4) | %
Transaction costs | — |  |  | 6 |  |  | (100) | % |  | 6 |  |  | 31 |  |  | (81) | %
General and administrative expense | 53 |  |  | 57 |  |  | (7) | % |  | 110 |  |  | 117 |  |  | (6) | %
Other operating expense | 2 |  |  | 4 |  |  | (50) | % |  | 6 |  |  | 8 |  |  | (25) | %
Total operating expenses | $ | 887 |  |  | $ | 879 |  |  | 1 | % |  | $ | 1,766 |  |  | $ | 1,828 |  |  | (3) | %
Selected Operating Expenses (per Boe): |  |  |  |  |  |  |  |  |  |  |
Lease operating expense | $ | 5.49 |  |  | $ | 6.22 |  |  | (12) | % |  | $ | 5.85 |  |  | $ | 4.18 |  |  | 40 | %
Midstream operating expense | 0.42 |  |  | 0.49 |  |  | (14) | % |  | 0.46 |  |  | 0.41 |  |  | 12 | %
Gathering, transportation, and processing | 2.87 |  |  | 3.12 |  |  | (8) | % |  | 2.99 |  |  | 2.97 |  |  | 1 | %
Severance and ad valorem taxes | 2.58 |  |  | 3.20 |  |  | (19) | % |  | 2.88 |  |  | 3.30 |  |  | (13) | %
Depreciation, depletion, and amortization | 17.36 |  |  | 15.91 |  |  | 9 | % |  | 16.65 |  |  | 16.00 |  |  | 4 | %
General and administrative expense | 1.86 |  |  | 2.02 |  |  | (8) | % |  | 1.94 |  |  | 1.90 |  |  | 2 | %
Total selected operating expenses (per Boe) | $ | 30.58 |  |  | $ | 30.96 |  |  | (1) | % |  | $ | 30.77 |  |  | $ | 28.76 |  |  | 7 | %

Lease operating expense. Our lease operating expense decreased 9% to $158 million for the three months ended June 30, 2025, compared to $174 million for the three months ended March 31, 2025, and decreased 12% on an equivalent basis per Boe. The Permian Basin accounted for nearly all of the decrease per Boe primarily attributable to (i) the timing of maintenance and workover activity, as well as decreases in (ii) saltwater disposal costs and (iii) fuel and power usage.
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Our lease operating expense increased 29% to $332 million for the six months ended June 30, 2025, compared to $258 million for the six months ended June 30, 2024, and increased 40% on an equivalent basis per Boe. The Permian Basin accounted for approximately 60% of the increase on an equivalent basis per Boe primarily due to increases in operational activities related to (i) increased salt water disposal costs, including costs incurred to dispose of produced water arising from takeaway capacity constraints with certain of our vendors, (ii) fuel and power usage, (iii) compression, and (iv) maintenance. The DJ Basin accounted for the remaining approximately 40% of the increase on an equivalent basis per Boe primarily due to (i) increases in our plugging and abandonment program and related environmental remediation costs incurred on old vertical well sites, many of which we never operated, (ii) increased electric power rates and usage, and (iii) declining production volumes relative to fixed costs.
Gathering, transportation, and processing. Our gathering, transportation, and processing (“GTP”) expense decreased 5% to $83 million for the three months ended June 30, 2025, compared to $87 million for the three months ended March 31, 2025, and decreased 8% on an equivalent basis per Boe. The decrease in GTP expense is mainly driven by certain of our contracts that are value-based percentage of proceeds sales contracts that track solely with natural gas and NGL pricing. The decrease in natural gas and NGL sales prices were 60% and 21%, respectively. Partially offsetting the decrease is an increase in GTP expense associated with entering a new crude oil gathering contract in the DJ Basin. Pursuant to this contract, GTP costs are now incurred prior to the transfer of control and thereby recorded as GTP expense compared to the former contract where GTP costs were incurred subsequent to the transfer of control and thereby recorded net within crude oil, natural gas, and NGL sales.
Our gathering, transportation, and processing expense decreased 7% to $170 million for the six months ended June 30, 2025, compared to $183 million for the six months ended June 30, 2024, and increased 1% on an equivalent basis per Boe. The decrease in gathering, transportation, and processing expense is mainly driven by the decrease in total sales volumes of 8%, partially offset by the new crude oil gathering contract in the DJ Basin described above.
Severance and ad valorem taxes. Severance taxes are imposed by the states in which we operate based on the value of the crude oil, natural gas, and NGL we produce. Ad valorem taxes are imposed by specific jurisdictions in which we operate based on the assessed value of our properties in that region. For our operations in Texas, the assessed value of our properties is determined using a discounted cash flow methodology. For our operations in Colorado and New Mexico, assessed value is determined by the value of the crude oil, natural gas, and NGL sold less various deductions.
Our severance and ad valorem taxes decreased 16% to $75 million for the three months ended June 30, 2025, from $89 million for the three months ended March 31, 2025, and decreased 19% on an equivalent basis per Boe. Decreases in both total and on an equivalent basis per Boe resulted from the decrease of 12% in total product revenue for the three months ended June 30, 2025 when compared to the three months ended March 31, 2025. In addition, during the three months ended June 30, 2025, we updated our Texas ad valorem tax estimates to reflect updated assessed values resulting in a further decrease in our severance and ad valorem taxes.
Our severance and ad valorem taxes decreased 20% to $164 million for the six months ended June 30, 2025, from $204 million for the six months ended June 30, 2024, and decreased 13% on an equivalent basis per Boe. Decreases in both total and on an equivalent basis per Boe resulted from the decrease of 15% in total product revenue for the six months ended June 30, 2025 when compared to the six months ended June 30, 2024. In addition, during the three months ended June 30, 2025, we updated our Texas ad valorem tax estimates to reflect updated assessed values resulting in a further decrease in our severance and ad valorem taxes.
Depreciation, depletion, and amortization. Our depreciation, depletion, and amortization expense (“DD&A”) increased 13% to $501 million for the three months ended June 30, 2025, from $445 million for the three months ended March 31, 2025, and increased 9% on an equivalent basis per Boe. The increase in total DD&A expense was primarily due to an increase in the depletion rate driven by a greater increase in the depletable property base in proportion to proved reserves. particularly in the Permian Basin, as well as a 3% increase in sales volumes.
Our DD&A decreased 4% to $946 million for the six months ended June 30, 2025, from $988 million for the six months ended June 30, 2024, and increased 4% on an equivalent basis per Boe. The decrease in total DD&A expense was primarily due to an 8% decrease in sales volumes between periods and was partially offset by an increase in the depletion rate driven by a greater increase in the depletable property base in proportion to proved reserves. particularly in the Permian Basin.
General and administrative expense. Our general and administrative expense decreased 7% to $53 million for the three months ended June 30, 2025, from $57 million for the three months ended March 31, 2025, and decreased 8% on an equivalent basis per Boe. The decrease in general and administrative expense was primarily due to $4 million of non-recurring cash severance charges and $1 million of additional stock compensation expense incurred in connection with our announced
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reduction in force during the three months ended March 31, 2025. General and administrative expense per Boe decreased due to a 3% increase in sales volumes.
Our general and administrative expense decreased 6% to $110 million for the six months ended June 30, 2025, from $117 million for the six months ended June 30, 2024, and increased 2% on an equivalent basis per Boe. The decrease in general and administrative expense was primarily due to (i) increases in the portion of labor billable to joint interest accounts and (ii) cost savings initiatives resulting in a reduction in professional services and contract labor. The decrease in general and administrative expense was partially offset by $4 million of non-recurring cash severance charges and $1 million of additional stock compensation expense incurred in connection with our announced reduction in force during the three months ended March 31, 2025. General and administrative expense per Boe increased due to an 8% decrease in sales volumes.
Derivative gain (loss), net. Our derivative gain for the three months ended June 30, 2025 was $104 million, as compared to a gain of $52 million for the three months ended March 31, 2025. Our derivative gains for the three months ended June 30, 2025 and March 31, 2025 were due to fair market value adjustments resulting from lower market prices relative to our open positions and cash settlement gains.
Our derivative gain for the six months ended June 30, 2025 was $156 million, as compared to a loss of $102 million for the six months ended June 30, 2024. Our derivative gain for the six months ended June 30, 2025 was due to fair market value adjustments resulting from lower market prices relative to our open positions and cash settlement gains. Our derivative loss for the six months ended June 30, 2024 was due to fair market value adjustments resulting from higher market prices relative to our open positions and cash settlement losses.
Refer to Note 9 - Derivatives under Part I, Item 1 of this Quarterly Report on Form 10-Q for additional discussion.
Interest expense. Our interest expense for the three months ended June 30, 2025 and March 31, 2025 was $114 million and $107 million, respectively. Average debt outstanding for the three months ended June 30, 2025 and March 31, 2025 was $5.4 billion and $5.2 billion, respectively.
Our interest expense for the six months ended June 30, 2025 and 2024 was $221 million and $225 million, respectively. Average debt outstanding for the six months ended June 30, 2025 and 2024 was $5.3 billion and $4.7 billion, respectively. The components of interest expense for the periods presented are as follows (in millions):

| Three Months Ended |  | Six Months Ended
| June 30, 2025 |  | March 31, 2025 |  | June 30, 2025 |  | June 30, 2024
Senior Notes | $ | 90 |  |  | $ | 84 |  |  | $ | 174 |  |  | $ | 169 |
Credit Facility | 18 |  |  | 17 |  |  | 35 |  |  | 27 |
Amortization of deferred financing costs and deferred acquisition consideration | 5 |  |  | 4 |  |  | 9 |  |  | 25 |
Other | 1 |  |  | 2 |  |  | 3 |  |  | 4 |
Total interest expense | $ | 114 |  |  | $ | 107 |  |  | $ | 221 |  |  | $ | 225 |

Income tax expense. Our effective tax rate differs from the amount that would be provided by applying the statutory United States federal income tax rate of 21% to income before income taxes due to the effect of state income taxes, excess tax benefits and deficiencies on stock-based compensation awards, tax limitations on compensation of covered individuals, tax credits, and other permanent differences. Refer to Note 12 - Income Taxes under Part I, Item 1 of this Quarterly Report on Form 10-Q for additional discussion.
Our income tax expense for the three months ended June 30, 2025 and March 31, 2025 was $38 million and $61 million, resulting in an effective tax rate of 23.5% and 24.6% on pre-tax income, respectively.
Our income tax expense for the six months ended June 30, 2025 and 2024 was $99 million and $102 million, resulting in an effective tax rate of 24.2% and 20.7% on pre-tax income, respectively. During the six months ended June 30, 2024, income tax expense was additionally impacted by deferred tax benefits from state apportionment changes as a result of the Vencer Acquisition.
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Liquidity and Capital Resources
Our primary sources of liquidity include cash flows from operating activities, available borrowing capacity under the Credit Facility, potential proceeds from equity and/or debt capital markets transactions, and potential proceeds from sales of assets. We may use our available liquidity for operating activities, working capital requirements, capital expenditures, acquisitions, the return of capital to stockholders, and for general corporate purposes. Additionally, our available liquidity may be used for debt reduction and we may, at any time and from time to time, seek to repurchase and retire our outstanding senior notes through cash purchases and/or exchanges for debt in the open market, in privately negotiated transactions, or otherwise. Such repurchases or exchanges, if any, would be made upon the terms and at the prices as our Board and management may determine, and will depend on prevailing market conditions, our liquidity requirements, contractual restrictions, and other factors. In addition, we may issue additional securities in capital markets transactions to refinance portions of our Credit Facility or other debt obligations as market conditions permit.
Our primary source of cash flows from operating activities is the sale of crude oil, natural gas, and NGL. As such, our cash flows are subject to significant volatility due to changes in commodity prices, as well as variations in our sales volumes. The prices for these commodities are driven by a number of factors beyond our control, including global and regional product supply and demand, the impact of inflation and monetary policy, weather, product distribution, transportation, processing, and refining capacity, regulatory constraints, and other supply chain dynamics, among other factors.
As of June 30, 2025, our liquidity was $2.0 billion, consisting of cash on hand of $69 million and $1.9 billion of available borrowing capacity on our Credit Facility. Borrowing capacity under the Credit Facility is primarily based on the value assigned to the proved reserves attributable to our crude oil and natural gas interests. As of the filing date of this Quarterly Report on Form 10-Q, the available borrowing capacity on our Credit Facility was $1.9 billion. Our Credit Facility is set to mature in August 2028, with the next scheduled borrowing base redetermination date to occur in November 2025.
The Credit Facility contains customary representations and various affirmative and negative covenants as well as certain financial covenants, including (a) a permitted net leverage ratio of not greater than 3.00 to 1.00, (b) a current ratio, inclusive of the unused commitments under the Credit Facility then available to be borrowed, of not less than 1.00 to 1.00, and (c) upon the achievement of investment grade credit ratings, a PV-9 coverage ratio. We were in compliance with all covenants under the Credit Facility as of June 30, 2025, and through the filing date of this Quarterly Report on Form 10-Q. Refer to Note 5 - Debt in Part I, Item 1 for additional information.
Our material short-term cash requirements include: operating activities, working capital requirements, capital expenditures, dividends, and payments of contractual obligations. Our material long-term cash requirements from various contractual and other obligations include: debt obligations and related interest payments, firm transportation and minimum volume agreements, taxes, asset retirement obligations, and leases. Refer to Part I, Item 1 for additional information. Our future capital requirements, both near-term and long-term, will depend on many factors, including, but not limited to, commodity prices, market conditions, our available liquidity and financing, acquisitions and divestitures of crude oil and natural gas properties, the availability of drilling rigs and completion crews, the cost of completion services, success of drilling programs, land and industry partner issues, weather delays, the acquisition of leases with drilling commitments, and other factors. We regularly consider which resources, including debt and equity financing, are available to meet our future financial obligations, planned capital expenditures, and liquidity requirements.
Funding for these requirements may be provided by any combination of the sources of liquidity outlined above. We expect our 2025 capital program to be funded by cash flows from operations. Although we cannot provide any assurance, based on our projected cash flows from operations, our cash on hand, and available borrowing capacity on our Credit Facility, we believe that we will have sufficient capital available to fund these requirements through the 12-month period following the filing date of this Quarterly Report on Form 10-Q, and based on current expectations, the long-term.
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Sources and Uses of Cash and Cash Equivalents
The following table presents the sources and uses of our cash and cash equivalents for the periods indicated (in millions):

|  |  | Six Months Ended |  |
| Activity Type |  | June 30, 2025 |  | June 30, 2024 |  |
Sources of Cash and Cash Equivalents |  |  |  |  |  |  |
Net cash provided by operating activities | Operating |  | $ | 1,017 |  |  | $ | 1,172 |  |  |
Proceeds from property transactions | Investing |  | 3 |  |  | 172 |  |  |
Proceeds from credit facility | Financing |  | 1,550 |  |  | 1,300 |  |  |
Proceeds from issuance of senior notes | Financing |  | 743 |  |  | — |  |  |
Total sources of cash and cash equivalents |  |  | $ | 3,313 |  |  | $ | 2,644 |  |  |
Uses of Cash and Cash Equivalents |  |  |  |  |  |  |
Acquisitions of businesses, net of cash acquired | Investing |  | (756) |  |  | (868) |  |  |
Acquisitions of crude oil and natural gas properties | Investing |  | (20) |  |  | (14) |  |  |
Capital expenditures for drilling and completion activities and other fixed assets | Investing |  | (961) |  |  | (1,091) |  |  |
Payments to credit facility | Financing |  | (1,400) |  |  | (1,200) |  |  |
Dividends paid | Financing |  | (97) |  |  | (297) |  |  |
Common stock repurchased and retired | Financing |  | (72) |  |  | (192) |  |  |
Other, net | Investing/Financing |  | (14) |  |  | (17) |  |  |
Total uses of cash and cash equivalents |  |  | $ | (3,320) |  |  | $ | (3,679) |  |  |
Net change in cash and cash equivalents |  |  | $ | (7) |  |  | $ | (1,035) |  |  |

Sources of Cash and Cash Equivalents
Our sources of cash and cash equivalents increased by $669 million year over year, primarily driven by proceeds from issuance of our 2033 Senior Notes of $743 million and increased draws on our Credit Facility of $250 million. This increase was partially offset by a decrease in proceeds from property transactions of $169 million, as well as a decrease in net cash provided by operating activities of $155 million. Our net cash provided by operating activities are primarily impacted by commodity prices, sales volumes, net settlements from our commodity derivative positions, operating costs, and changes in our working capital. See “Results of Operations” above for more information on the factors driving these changes.
Uses of Cash and Cash Equivalents
Our uses of cash and cash equivalents decreased by $359 million year over year, primarily driven by decreased dividends paid of $200 million, decreased capital expenditures for drilling and completion activities and other fixed assets of $130 million, decreased common stock repurchased and retired of $120 million, and decreases in acquisitions of businesses, net of cash acquired of $112 million. This decrease was partially offset by an increase in payments on our Credit Facility of $200 million.
Beginning in February 2025, our Board elected to prioritize directing the majority of our free cash flow to debt reduction, following the payment of our base dividend, which remains $0.50 per share quarterly. As a result of this change, dividends declared and paid during the year decreased by $1.95 per share, or $200 million, and common stock repurchased and retired decreased by $120 million when compared to the six months ended June 30, 2024.
Capital expenditures for drilling and completion activities and other fixed assets decreased by $130 million, largely attributable to a 5% reduction in our 2025 capital investment program when compared to 2024 as well as efforts to level-load our capital to more evenly distribute investments throughout the year. During the six months ended June 30, 2025, we drilled, completed, and turned to sales 49, 64, and 88 net operated wells, respectively, in the Permian Basin, and 55, 61, and 49 net operated wells, respectively, in the DJ Basin. During the six months ended June 30, 2024, we drilled, completed, and turned to sales 68, 72, and 76 net operated wells, respectively, in the Permian Basin, and 53, 53, and 42 net operated wells, respectively, in the DJ Basin.
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Cash proceeds from draws on our Credit Facility increased by $250 million year over year, primarily driven by the payment of the remaining Vencer deferred acquisition consideration of $475 million as well as acquisition of certain crude oil and natural gas properties accounted for as a business combination in the Permian Basin for cash consideration of $281 million during the six months ended June 30, 2025, offset by the cash consideration paid at closing for the Vencer Acquisition during the six months ended June 30, 2024. The increase in payments to our Credit Facility is driven by the use of the net proceeds from the 2033 Senior Notes of $743 million to repay a portion of the outstanding borrowings under our Credit Facility.
Material Commitments
There have been no significant changes from our 2024 Form 10-K in our obligations and commitments, other than what is disclosed within Note 6 - Commitments and Contingencies under Part I, Item 1 of this Quarterly Report on Form 10-Q.
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Non-GAAP Financial Measures
Reconciliation of Net Income to Adjusted EBITDAX
Adjusted EBITDAX is a supplemental non-GAAP financial measure that represents earnings before interest, income taxes, depreciation, depletion, and amortization, exploration expense, and other non-cash and non-recurring charges. Adjusted EBITDAX excludes certain items that we believe affect the comparability of operating results and can exclude items that are generally non-recurring in nature. We present Adjusted EBITDAX because we believe it provides useful additional information to investors and analysts, as a performance measure, for analysis of our ability to internally generate funds for exploration, development, acquisitions, and to service debt. We are also subject to financial covenants under our Credit Facility based on Adjusted EBITDAX ratios. In addition, Adjusted EBITDAX is widely used by professional research analysts and others in the valuation, comparison, and investment recommendations of companies in the crude oil and natural gas exploration and production industry. Adjusted EBITDAX should not be considered in isolation or as a substitute for net income, net cash provided by operating activities, or other profitability or liquidity measures prepared under GAAP. Because Adjusted EBITDAX excludes some, but not all items that affect net income and may vary among companies, the Adjusted EBITDAX amounts presented may not be comparable to similar metrics of other companies.
The following table presents a reconciliation of the GAAP financial measure of net income to the non-GAAP financial measure of Adjusted EBITDAX for the periods presented (in millions):

| Three Months Ended |  | Six Months Ended
| June 30, 2025 |  | March 31, 2025 |  | June 30, 2025 |  | June 30, 2024
Net income | $ | 124 |  |  | $ | 186 |  |  | $ | 310 |  |  | $ | 392 |
Interest expense, net(1) | 112 |  |  | 105 |  |  | 217 |  |  | 219 |
Income tax expense | 38 |  |  | 61 |  |  | 99 |  |  | 102 |
Depreciation, depletion, and amortization | 501 |  |  | 445 |  |  | 946 |  |  | 988 |
Exploration | 3 |  |  | 3 |  |  | 6 |  |  | 13 |
Transaction costs | — |  |  | 6 |  |  | 6 |  |  | 31 |
Derivative (gain) loss, net | (104) |  |  | (52) |  |  | (156) |  |  | 102 |
Derivative cash settlement gain (loss), net | 69 |  |  | 4 |  |  | 73 |  |  | (24) |
Stock-based compensation(2) | 13 |  |  | 13 |  |  | 26 |  |  | 23 |
Other, net(3) | (7) |  |  | 15 |  |  | 8 |  |  | 1 |
Adjusted EBITDAX | $ | 749 |  |  | $ | 786 |  |  | $ | 1,535 |  |  | $ | 1,847 |

________________________
(1)Includes interest income of $2 million for both the three months ended June 30, 2025 and March 31, 2025, and $4 million and $6 million for the six months ended June 30, 2025 and 2024, respectively. Interest income is included as a portion of other, net in the accompanying statements of operations.
(2)Included as a portion of general and administrative expense in the accompanying statements of operations.
(3)The three months ended June 30, 2025 includes (i) a $9 million reduction related to the unrealized loss on crude oil linefill contracts recorded during the three months ended March 31, 2025 that settled during the quarter that is included in other, net and (ii) $2 million for non-recurring unused commitment fees that are included in other operating expense, both of which are in the accompanying statements of operations for the period. The three months ended March 31, 2025 includes (i) a $9 million increase related to the unrealized loss on crude oil linefill contracts that is included in other, net, (ii) $4 million of non-recurring cash severance charges incurred in connection with our announced reduction in force that are included in general and administrative expense, and (iii) $2 million for non-recurring cash unused commitment fees that are included in other operating expense, all of which are in the accompanying statement of operations for the period. The six months ended June 30, 2025 includes (i) $4 million of non-recurring cash severance charges incurred in connection with our announced reduction in force that are included in general and administrative expense and (ii) $4 million for non-recurring cash unused commitment fees that are included in other operating expense, both of which are in the accompanying statements of operations for the period. The six months ended June 30, 2024 includes a $1 million gain for non-recurring cash unused commitment fees that are included in other operating expense and (ii) $2 million of loss on sale of properties that is included in other, net, all of which are in the accompanying statements of operations for the period.
Reconciliation of Cash Provided by Operating Activities to Adjusted Free Cash Flow
Adjusted Free Cash Flow is a supplemental non-GAAP financial measure that is calculated as net cash provided by operating activities before changes in operating assets and liabilities and less exploration and development of crude oil and natural gas properties, changes in working capital related to capital expenditures, and purchases of carbon credits and renewable energy credits. We believe that Adjusted Free Cash Flow provides additional information that may be useful to investors and analysts in evaluating our ability to generate cash from our existing crude oil and natural gas assets to fund future exploration and development activities and to return cash to stockholders. Adjusted Free Cash Flow is a supplemental measure of liquidity and should not be viewed as a substitute for cash flows from operations because it excludes certain required cash expenditures.
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The following table presents a reconciliation of the GAAP financial measure of net cash provided by operating activities to the non-GAAP financial measure of Adjusted Free Cash Flow for the periods presented (in millions):

| Three Months Ended |  | Six Months Ended
| June 30, 2025 |  | March 31, 2025 |  | June 30, 2025 |  | June 30, 2024
Net cash provided by operating activities | $ | 298 |  |  | $ | 719 |  |  | $ | 1,017 |  |  | $ | 1,172 |
Add back: Changes in operating assets and liabilities, net | 331 |  |  | (53) |  |  | 278 |  |  | 427 |
Cash flow from operations before changes in operating assets and liabilities | 629 |  |  | 666 |  |  | 1,295 |  |  | 1,599 |
Less: Cash paid for capital expenditures for drilling and completion activities and other fixed assets | (486) |  |  | (475) |  |  | (961) |  |  | (1,091) |
Less: Changes in working capital related to capital expenditures | (20) |  |  | (20) |  |  | (40) |  |  | (125) |
Capital expenditures | (506) |  |  | (495) |  |  | (1,001) |  |  | (1,216) |
Less: Purchases of carbon credits and renewable energy credits | — |  |  | — |  |  | — |  |  | (2) |
Adjusted Free Cash Flow | $ | 123 |  |  | $ | 171 |  |  | $ | 294 |  |  | $ | 381 |

Reconciliation of average sales price, after derivatives
Average sales price, after derivatives is a non-GAAP financial measure that incorporates the net effect of derivative cash receipts from or payments on commodity derivatives that are presented in our accompanying statements of cash flows, netted into the average sales price, before derivatives, the most directly comparable GAAP financial measure. We believe that the presentation of average sales price, after derivatives is a useful means to reflect the actual cash performance of our commodity derivatives for the respective periods and is useful to management and our stockholders in determining the effectiveness of our price risk management program.
The following table provides a reconciliation of the GAAP financial measure of average sales price, before derivatives to the non-GAAP financial measure of average sales prices, after derivatives for the periods presented:

| Three Months Ended |  | Six Months Ended
| June 30, 2025 |  | March 31, 2025 |  | June 30, 2025 |  | June 30, 2024
Average crude oil sales price (per Bbl) | $ | 63.87 |  |  | $ | 70.90 |  |  | $ | 67.27 |  |  | $ | 77.98 |
Effects of derivatives, net (per Bbl) (1) | 2.68 |  |  | 0.06 |  |  | 1.41 |  |  | (1.07) |
Average crude oil sales price (after derivatives) (per Bbl) | $ | 66.55 |  |  | $ | 70.96 |  |  | $ | 68.68 |  |  | $ | 76.91 |
Average natural gas sales price (per Mcf) | $ | 1.00 |  |  | $ | 2.48 |  |  | $ | 1.77 |  |  | $ | 0.89 |
Effects of derivatives, net (per Mcf) (1) | 0.69 |  |  | 0.08 |  |  | 0.37 |  |  | 0.05 |
Average natural gas sales price (after derivatives) (per Mcf) | $ | 1.69 |  |  | $ | 2.56 |  |  | $ | 2.14 |  |  | $ | 0.94 |
Average NGL sales price (per Bbl) | $ | 18.99 |  |  | $ | 24.07 |  |  | $ | 21.46 |  |  | $ | 21.79 |
Effects of derivatives, net (per Bbl) (1) | — |  |  | — |  |  | — |  |  | — |
Average NGL sales price (after derivatives) (per Bbl) | $ | 18.99 |  |  | $ | 24.07 |  |  | $ | 21.46 |  |  | $ | 21.79 |

_________________________
(1)Derivatives economically hedge the price we receive for crude oil, natural gas, and NGL. For the three months ended June 30, 2025, the derivative cash settlement gain for crude oil and natural gas was $36 million and $33 million, respectively. For the three months ended March 31, 2025, the derivative cash settlement gain for crude oil and natural gas was $1 million and $3 million respectively. For the six months ended June 30, 2025, the derivative cash settlement gain for crude oil and natural gas was $37 million and $36 million, respectively. For the six months ended June 30, 2024, the derivative cash settlement loss for crude oil was $30 million, and the derivative cash settlement gain for natural gas was $6 million. We did not hedge the price we received for NGL during the periods presented. Refer to Note 9 - Derivatives under Part I, Item 1 of this Quarterly Report on Form 10-Q for additional disclosures.
New Accounting Pronouncements
Refer to Note 1 - Summary of Significant Accounting Policies under Part I, Item 1 of this Quarterly Report on Form 10-Q and Note 1 - Summary of Significant Accounting Policies in the 2024 Form 10-K for any recently issued or adopted accounting standards.
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Critical Accounting Estimates
Information regarding our critical accounting estimates is contained in Part II, Item 7 of our 2024 Form 10-K. During the three months ended June 30, 2025, there were no significant changes in the application of critical accounting policies.
Item 3. Quantitative and Qualitative Disclosures About Market Risk.
Crude Oil and Natural Gas Price Risk
Our financial condition, results of operations, and capital resources are highly dependent upon the prevailing market prices of crude oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control. Factors influencing crude oil and natural gas prices include the level of global demand for crude oil and natural gas, the global supply of crude oil and natural gas, the establishment of and compliance with production quotas by crude oil exporting countries, weather conditions which impact the supply and demand for crude oil and natural gas, the price and availability of alternative fuels, local and global politics, and overall economic conditions. It is impossible to predict future crude oil and natural gas prices with any degree of certainty. Sustained weakness in crude oil and natural gas prices may adversely affect our financial condition and results of operations and may also reduce the amount of crude oil and natural gas reserves that we can produce economically. Any reduction in our crude oil and natural gas reserves, including reductions due to price fluctuations, can have an adverse effect on our ability to obtain capital for our exploration and development activities. Similarly, any improvements in crude oil and natural gas prices can have a favorable impact on our financial condition, results of operations, and capital resources.
Commodity Price Derivative Contracts
Our primary commodity risk management objective is to protect our balance sheet. We periodically enter into commodity derivative contracts to mitigate a portion of our exposure to potentially adverse market changes in commodity prices for our expected future crude oil and natural gas production and the associated impact on cash flows. Our commodity derivative contracts consist of swaps, collars, and basis protection swaps. Upon settlement of the contract(s), if the relevant market commodity price exceeds our contracted swap price, or the collar’s ceiling strike price, we are required to pay our counterparty the difference for the volume of production associated with the contract. Generally, this payment is made up to 15 business days prior to the receipt of cash payments from our customers. This could have an adverse impact on our cash flows for the period between derivative settlements and payments for revenue earned. While we may reduce the potential negative impact of lower commodity prices, we may also be prevented from realizing the benefits of favorable price changes in the physical market. Refer to Note 9 - Derivatives under Part I, Item 1 of this Quarterly Report on Form 10-Q for summary derivative activity tables.
Interest Rates
As of June 30, 2025 and the filing date of this Quarterly Report on Form 10-Q, we had $0.6 billion outstanding under our Credit Facility. Borrowings under our Credit Facility bear interest at a fluctuating rate that is tied to the ABR or SOFR, in each case, plus the applicable margin, at our option. Any increases in these interest rates can have an adverse impact on our results of operations and cash flows. As of June 30, 2025, and through the filing date of this Quarterly Report on Form 10-Q, we were in compliance with all financial and non-financial covenants under the Credit Facility.
Counterparty and Customer Credit Risk
We are exposed to counterparty credit risk associated with our derivative activities. As of June 30, 2025 and August 1, 2025, our derivative contracts have been executed with 16 counterparties, all of which are members of the Credit Facility lender group and have investment grade credit ratings. However, if our counterparties fail to perform their obligations under the contracts, we could suffer financial loss.
We are also subject to credit risk due to the concentration of our crude oil and natural gas receivables with certain significant customers. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. We review the credit rating, payment history, and financial resources of our customers, but we do not require our customers to post collateral.
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Marketability of Our Production
The marketability of our production depends in part upon the availability, proximity, and capacity of third-party refineries, access to regional pipeline infrastructure, natural gas gathering systems, and processing facilities. We deliver crude oil and natural gas produced primarily through pipelines and trucking services that we do not own. The lack of availability or capacity on these systems and facilities could reduce the price offered for our production or result in the shut-in of producing wells or the delay or discontinuance of development plans for properties.
A portion of our production may also be interrupted, or shut in, from time to time for numerous other reasons, including as a result of accidents, weather, field labor issues or strikes, or we might voluntarily curtail production in response to market conditions. If a substantial amount of our production is interrupted at the same time, it could adversely affect our cash flow.
Item 4. Controls and Procedures.
Evaluation of Disclosure Controls and Procedures
Our management, with the participation of our principal executive officer and principal financial officer, evaluated the effectiveness of our disclosure controls and procedures as of June 30, 2025. The term “disclosure controls and procedures,” as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act, means controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act (15 U.S.C. 78a et seq.) is recorded, processed, summarized, and reported, within the time periods specified in SEC rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the company’s management, including its principal executive and principal financial officers and internal audit function, as appropriate, to allow timely decisions regarding required disclosure. Based on the evaluation of our disclosure controls and procedures as of June 30, 2025, our principal executive officer and principal financial officer concluded that, as of such date, our disclosure controls and procedures were effective at the reasonable assurance level.
Management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving their objectives, and management necessarily applies its judgment in evaluating the cost-benefit relationship of possible controls and procedures. To assist management, we have established an internal audit function to verify and monitor our internal controls and procedures. Our internal control system is supported by written policies and procedures, contains self-monitoring mechanisms, and is audited by the internal audit function. Appropriate actions are taken by management to correct deficiencies as they are identified.
Changes in Internal Control over Financial Reporting
There were no changes in our internal control over financial reporting identified in management’s evaluation pursuant to Rules 13a-15(d) or 15d-15(d) of the Exchange Act during the quarter ended June 30, 2025 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
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PART II. OTHER INFORMATION
Item 1. Legal Proceedings.
Information regarding our legal proceedings can be found in Note 6 - Commitments and Contingencies under Part I, Item 1 of this Quarterly Report on Form 10-Q.
Disclosure of certain environmental matters is required when a governmental authority is a party to the proceedings and the proceedings involve potential monetary sanctions that we reasonably believe could exceed a specified threshold. Pursuant to Item 103 of Regulation S-K, we have elected to apply a threshold of $1 million for purposes of determining whether disclosure of any such proceedings is required. Applying this threshold, we are not aware of any such proceedings required to be disclosed for the quarter ended June 30, 2025.
In July 2025, the Company, among other operators, received Notices of Alleged Violation (“NOAVs”) from the Colorado Energy and Carbon Management Commission (“ECMC”) citing violations of ECMC regulations governing oil and gas operations resulting from environmental reports that were submitted on our behalf by a third party contractor who, without our knowledge, falsified certain analytical soil, groundwater, and inorganic and organic contaminant data contained in the reports (the “Alleged Violations”). At this time, the ECMC has not established a proposed penalty for the Alleged Violations. Given the inherent uncertainty in administrative actions of this nature, we are currently unable to predict the ultimate outcome of this matter. However, although a potential penalty and required expenditures may exceed $1 million, we do not believe that any such penalty or expenditure associated with the Alleged Violations will have a material adverse effect on our financial position, cash flows, or results of operations.
Item 1A. Risk Factors.
Our business faces many risks. Any of the risk factors discussed in this Quarterly Report on Form 10-Q or our other SEC filings could have a material impact on our business, financial position, or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also impair our business operation. For a discussion of our potential risks and uncertainties, see the risk factors identified in Part I, Item 1A in our 2024 Form 10-K, together with other information in this Quarterly Report on Form 10-Q and other reports and materials we may subsequently file with the SEC. We have identified these risk factors as important factors that could cause our actual results to differ materially from those contained in any written or oral forward-looking statements made by us or on our behalf.
Item 2. Unregistered Sales of Equity Securities, Use of Proceeds, and Issuer Purchases of Equity Securities.
The following table provides information about our purchases of our common stock during the three months ended June 30, 2025:

| Total Number of Shares Purchased(1) |  | Average Price Paid per Share(2) |  | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs(3) |  | Maximum Dollar Value that May Yet be Purchased as Part of Publicly Announced Plans or Programs (in millions)(3)
April 1, 2025 – April 30, 2025 | 26,210 |  |  | $ | 33.42 |  |  | 19,965 |  |  | $ | 193 |
May 1, 2025 – May 31, 2025 | 9,061 |  |  | 28.70 |  |  | — |  |  | 193 |
June 1, 2025 – June 30, 2025 | 1,150 |  |  | 33.35 |  |  | — |  |  | 193 |
Total | 36,421 |  |  | $ | 32.24 |  |  | 19,965 |  |  | $ | 193 |

________________________
(1)Purchases outside of the stock repurchase program represent shares withheld from officers, former officers, executives, and employees for the payment of personal income tax withholding obligations upon the vesting of restricted stock awards. The withheld shares are not considered common stock repurchased under the stock repurchase program.
(2)Excludes commissions paid and excise taxes accrued related to stock repurchases.
(3)Our Board authorized a stock repurchase program authorizing repurchases of up to $500 million of our outstanding shares of common stock, pursuant to which we are authorized, from time to time, to acquire shares of our common stock in the open market, in privately negotiated transactions, or through block trades, derivative transactions, or purchases made in accordance with Rule 10b-18 and Rule 10b5-1 of the Exchange Act. The stock repurchase program does not have a termination date, does not require any specific number of shares to be acquired, and can be modified or discontinued by our Board at any time.
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Item 3. Defaults Upon Senior Securities.
None.
Item 4. Mine Safety Disclosures.
Not applicable.
Item 5. Other Information.
During the three months ended June 30, 2025, no director or officer of the Company adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408 of Regulation S-K.
Item 6. Exhibits.

Exhibit Number | Description
2.1* | Purchase and Sale Agreement, dated as of October 3, 2023, by and among Vencer Energy, LLC, as seller, and Civitas Resources, Inc., as buyer (incorporated by reference to Exhibit 2.1 to Civitas Resources, Inc.’s Current Report on Form 8-K filed on October 4, 2023)
3.1 | Fourth Amended and Restated Certificate of Incorporation of Civitas Resources, Inc. (incorporated by reference to Exhibit 3.1 to Civitas Resources, Inc’s Quarterly Report on Form 10-Q filed on August 2, 2023)
3.2 | Seventh Amended and Restated Bylaws of Civitas Resources, Inc. (incorporated by reference to Exhibit 3.1 to Civitas Resources, Inc.’s Current Report on Form 8-K filed on June 5, 2023)
4.1 | Indenture, dated June 3, 2025, by and among Civitas Resources, Inc., as issuer, the guarantors party thereto and Computershare Trust Company, N.A., as trustee, pursuant to which the 2033 Senior Notes were issued (incorporated by reference to Exhibit 4.1 to Civitas Resources, Inc.’s Current Report on Form 8-K filed on June 3, 2025)
10.1 | Eighth Amendment to Amended and Restated Credit Agreement, dated May 28, 2025, among Civitas Resources, Inc., the guarantors party thereto, the lenders party thereto, and JPMorgan Chase Bank, N.A., as the administrative agent (incorporated by reference to Exhibit 10.1 to Civitas Resources, Inc.’s Current Report on Form 8-K filed on May 29, 2025)
10.2+* | Employment Letter, dated as of May 7, 2025, by and between Civitas Resources, Inc. and Clayton A. Carrell (incorporated by reference to Exhibit 10.1 to Civitas Resources, Inc.’s Current Report on Form 8-K filed on May 7, 2025)
10.3+ | Employment Side Letter, dated as of May 7, 2025, by and between Civitas Resources, Inc. and Clayton A. Carrell (incorporated by reference to Exhibit 10.2 to Civitas Resources, Inc.’s Current Report on Form 8-K filed on May 7, 2025)
10.4+ | Civitas Resources, Inc. Eighth Amended and Restated Executive Change in Control and Severance Benefit Plan (incorporated by reference to Exhibit 10.1 to Civitas Resources, Inc.’s Current Report on Form 8-K filed on January 25, 2022)
1 0.5+ | Form of Indemnity Agreement between Civitas Resources, Inc. and the directors and executive officers of Civitas Resources, Inc. (incorporated by reference to Exhibit 10.9 to Civitas Resources, Inc.’s Current Report on Form 8-K filed on November 3, 2021)
31.1† | Certification of the Chief Executive Officer pursuant to Rule 13a-14(a)
31.2† | Certification of the Chief Financial Officer pursuant to Rule 13a-14(a)
32.1† | Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith)
32.2† | Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith)
101.INS† | XBRL Instance Document
101.SCH† | XBRL Taxonomy Extension Schema
101.CAL† | XBRL Taxonomy Extension Calculation Linkbase
101.DEF† | XBRL Taxonomy Extension Definition Linkbase
101.LAB† | XBRL Taxonomy Extension Label Linkbase
101.PRE† | XBRL Taxonomy Extension Presentation Linkbase
104 | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

_________________________
* Certain of the schedules and exhibits to the agreement have been omitted pursuant to Item 601(a)(5) of Regulation
S-K. A copy of any omitted schedule or exhibit will be furnished to the SEC upon request.
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+ Management contract or compensatory plan or arrangement.
† Filed or furnished 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.

|  |  | CIVITAS RESOURCES, INC.
Date: | August 6, 2025 |  | By: | /s/ Wouter van Kempen
|  |  |  | Wouter van Kempen
|  |  |  | Interim Chief Executive Officer and Director (principal executive officer)
|  |  | By: | /s/ Marianella Foschi
|  |  |  | Marianella Foschi
|  |  |  | Chief Financial Officer and Treasurer (principal financial officer)
|  |  | By: | /s/ Kayla D. Baird
|  |  |  | Kayla D. Baird
|  |  |  | Senior Vice President and Chief Accounting Officer (principal accounting officer)

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