UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
☑ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2026
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 001-31539
SM ENERGY COMPANY
(Exact name of registrant as specified in its charter)
| Delaware | 41-0518430 | |||||||||||||
| (State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | |||||||||||||
1700 Lincoln Street, Suite 3200, Denver, Colorado | 80203 | |||||||||||||
| (Address of principal executive offices) | (Zip Code) | |||||||||||||
(303) 861-8140
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class | Trading symbol(s) | Name of each exchange on which registered | |||||||||
| Common stock, $0.01 par value | SM | New York Stock Exchange | |||||||||
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☑ No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☑ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☑
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.
As of October 22, 2026, the registrant had 235,019,304 shares of common stock outstanding.
1
TABLE OF CONTENTS
Item | Page | ||||||||||
2
Cautionary Information about Forward-Looking Statements
This Report on Form 10-Q (“Form 10-Q” or “this report”) contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (“Exchange Act”). All statements included in this report, other than statements of historical fact, that address activities, conditions, events, or developments with respect to our financial condition, results of operations, business prospects or economic performance that we expect, believe, or anticipate will or may occur in the future, or that address plans and objectives of management for future operations, are forward-looking statements. The words “anticipate,” “assume,” “believe,” “budget,” “could,” “estimate,” “expect,” “forecast,” “goal,” “intend,” “outlook,” “pending,” “plan,” “potential,” “projected,” “seek,” “target,” “will,” and similar expressions are intended to identify forward-looking statements. Forward-looking statements appear throughout this report, and include statements about such matters as:
•our outlook on future prices for crude oil, natural gas, and natural gas liquids (also referred to throughout this report as “oil,” “gas,” and “NGLs,” respectively), and the effects of inflation, tariffs, trade restrictions, and economic or geopolitical developments;
•changes in general economic and financial conditions, including inflationary pressures, the potential for economic recession, tariffs and trade restrictions, and War and Geopolitical Instability, as defined below;
•armed conflict, political instability, or civil unrest in oil and gas producing regions and shipping channels, including: instability in the Middle East; armed conflicts and wars involving the United States, Israel, Iran, and other Middle Eastern countries and regional proxy groups; the war between Russia and Ukraine; restrictions in and closures of the Strait of Hormuz; and related potential effects on laws and regulations or the imposition of economic or trade sanctions (“War and Geopolitical Instability”);
•the amount and nature of future capital expenditures, well costs, service costs, production costs, and general and administrative (“G&A”) costs, the resilience of our assets to changes in commodity prices, the ability of our assets to generate returns in the current macroeconomic environment, and the availability of liquidity and capital resources to fund capital expenditures and other costs, each of which may be impacted by the factors discussed above;
•drilling and completion activities and other exploration and development activities undertaken by us, our joint development partners, and/or other third-party operators, each of which could be affected by supply chain disruptions, pipeline capacity, our ability to obtain permits and governmental approvals, and the factors discussed above;
•business strategies and plans for future operations, including expansion and growth of operations or reallocation of capital, future dividend payments, debt repayments or redemptions, equity repurchases, capital markets activities, sustainability goals and initiatives, and our outlook on our future financial condition or results of operations;
•possible or expected acquisitions and divestitures, including our plans to execute on our divestiture target within one year of the Merger, and the possible divestiture or farm-out of, or farm-in or joint development of, certain properties;
•our expectations regarding remaining Merger integration activities and the realization of anticipated benefits, synergies, efficiencies, and cost savings from the Merger and the combined operations; see Note 2 - Mergers, Acquisitions, and Divestitures in Part I, Item 1 of this report for discussion and definition of the Merger;
•any changes to the borrowing base or aggregate revolving lender commitments under, or maturity date of, our Seventh Amended and Restated Credit Agreement, as amended (“Credit Agreement”);
•cash flows, liquidity, interest and related debt service expenses, changes in our effective tax rate, and our ability to repay debt in the future;
•oil, gas, and NGL reserve estimates and estimates of both future net revenues and the present value of future net revenues associated with those reserve estimates, and the conversion of proved undeveloped reserves to proved developed reserves;
•our expected future production volumes, identified drilling locations and prospects, inventories, projects and programs;
•our expectations related to changes in proposed or final federal and state income tax laws and regulations; and
•other similar matters, such as those discussed in Management’s Discussion and Analysis of Financial Condition and Results of Operations in Part I, Item 2 of this report.
Our forward-looking statements are based on assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions, expected future developments, and other factors that we believe are appropriate under the circumstances. We caution you that forward-looking statements are not guarantees of future performance, and these statements are subject to known and unknown risks and uncertainties, which may cause our actual results or performance to be materially different from any future results or performance expressed or implied by the forward-looking statements. Factors that may cause our financial condition, results of operations, business prospects or economic performance to differ from expectations include among others, commodity price volatility; changes in capital markets or access to liquidity; integration risks and the anticipated benefits of acquisitions or divestitures; operational, drilling, and production risks; regulatory or environmental developments; and other risks as discussed in the Risk Factors section in Part I, Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2025 (“2025 Form 10-K”).
The forward-looking statements in this report speak only as of the filing of this report. Although we may from time to time voluntarily update our prior forward-looking statements, we disclaim any commitment to do so except as required by applicable securities laws.
3
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
SM ENERGY COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
(in millions, except share data)
| September 30, 2026 | December 31, 2025 | ||||||||||
| ASSETS | |||||||||||
| Current assets: | |||||||||||
| Cash and cash equivalents | $ | 442 | $ | 368 | |||||||
| Accounts receivable | 1,175 | 331 | |||||||||
| Derivative assets | 93 | 83 | |||||||||
| Prepaid expenses and other | 107 | 29 | |||||||||
| Total current assets | 1,817 | 811 | |||||||||
| Property and equipment (successful efforts method): | |||||||||||
| Proved oil and gas properties | 23,924 | 16,012 | |||||||||
| Accumulated depletion, depreciation, and amortization | (9,040) | (8,793) | |||||||||
Unproved oil and gas properties, net of valuation allowance of $12 and $12, respectively | 885 | 460 | |||||||||
| Wells in progress | 848 | 458 | |||||||||
Other property and equipment, net of accumulated depreciation of $68 and $63, respectively | 138 | 65 | |||||||||
| Total property and equipment, net | 16,755 | 8,202 | |||||||||
| Noncurrent assets: | |||||||||||
| Derivative assets | 12 | 6 | |||||||||
| Other noncurrent assets | 379 | 234 | |||||||||
| Total noncurrent assets | 391 | 240 | |||||||||
| Total assets | $ | 18,963 | $ | 9,253 | |||||||
LIABILITIES AND STOCKHOLDERS’ EQUITY | |||||||||||
| Current liabilities: | |||||||||||
| Accounts payable and accrued expenses | $ | 2,505 | $ | 690 | |||||||
| Senior Notes, net | — | 419 | |||||||||
| Derivative liabilities | 552 | 2 | |||||||||
| Other current liabilities | 130 | 58 | |||||||||
| Total current liabilities | 3,187 | 1,169 | |||||||||
| Noncurrent liabilities: | |||||||||||
| Revolving credit facility | — | — | |||||||||
| Senior Notes, net | 6,614 | 2,296 | |||||||||
| Asset retirement obligations | 426 | 150 | |||||||||
| Deferred tax liabilities, net | 609 | 724 | |||||||||
| Derivative liabilities | 13 | 2 | |||||||||
| Other noncurrent liabilities | 337 | 102 | |||||||||
| Total noncurrent liabilities | 7,999 | 3,274 | |||||||||
| Commitments and contingencies (Note 7) | |||||||||||
| Stockholders’ equity: | |||||||||||
Common stock, $0.01 par value - authorized: 400,000,000 and 200,000,000 shares, respectively; issued and outstanding: 235,615,045 and 114,630,905 shares, respectively | 2 | 1 | |||||||||
| Additional paid-in capital | 3,813 | 1,517 | |||||||||
| Retained earnings | 3,961 | 3,291 | |||||||||
| Accumulated other comprehensive income | 1 | 1 | |||||||||
| Total stockholders’ equity | 7,777 | 4,810 | |||||||||
| Total liabilities and stockholders’ equity | $ | 18,963 | $ | 9,253 | |||||||
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
4
SM ENERGY COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
(in millions, except per share data)
| For the Three Months Ended September 30, | For the Nine Months Ended September 30, | ||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | ||||||||||||||||||||
| Operating revenues and other income: | |||||||||||||||||||||||
| Oil, gas, and NGL production revenue | $ | 2,160 | $ | 811 | $ | 5,793 | $ | 2,436 | |||||||||||||||
| Gain (loss) on divestiture activity | (2) | — | 260 | — | |||||||||||||||||||
| Other operating income | 12 | 1 | 96 | 13 | |||||||||||||||||||
| Total operating revenues and other income | 2,170 | 812 | 6,149 | 2,449 | |||||||||||||||||||
| Operating expenses: | |||||||||||||||||||||||
| Oil, gas, and NGL production expense | 574 | 229 | 1,558 | 678 | |||||||||||||||||||
| Depletion, depreciation, and amortization | 590 | 325 | 1,614 | 888 | |||||||||||||||||||
| Exploration | 22 | 12 | 69 | 39 | |||||||||||||||||||
| General and administrative | 56 | 39 | 309 | 121 | |||||||||||||||||||
| Net derivative (gain) loss | 684 | (45) | 1,109 | (107) | |||||||||||||||||||
| Other operating expense | 8 | 5 | 56 | 12 | |||||||||||||||||||
| Total operating expenses | 1,934 | 565 | 4,715 | 1,631 | |||||||||||||||||||
| Income from operations | 236 | 246 | 1,434 | 818 | |||||||||||||||||||
| Interest expense | (116) | (43) | (340) | (130) | |||||||||||||||||||
| Other non-operating income, net | 3 | 1 | 8 | 1 | |||||||||||||||||||
| Income before income taxes | 123 | 204 | 1,102 | 689 | |||||||||||||||||||
| Income tax expense | (30) | (49) | (273) | (150) | |||||||||||||||||||
| Net income | $ | 93 | $ | 155 | $ | 829 | $ | 539 | |||||||||||||||
| Basic weighted-average common shares outstanding | 237 | 115 | 225 | 115 | |||||||||||||||||||
| Diluted weighted-average common shares outstanding | 239 | 115 | 226 | 115 | |||||||||||||||||||
| Basic net income per common share | $ | 0.39 | $ | 1.35 | $ | 3.67 | $ | 4.70 | |||||||||||||||
| Diluted net income per common share | $ | 0.39 | $ | 1.35 | $ | 3.66 | $ | 4.69 | |||||||||||||||
____________________________________________
Note: Per common share amounts, and prior year amounts may not calculate due to rounding.
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
5
SM ENERGY COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
(in millions)
| For the Three Months Ended September 30, | For the Nine Months Ended September 30, | ||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | ||||||||||||||||||||
| Net income | $ | 93 | $ | 155 | $ | 829 | $ | 539 | |||||||||||||||
| Other comprehensive loss, net of tax: | |||||||||||||||||||||||
| Pension liability adjustment | (1) | — | — | — | |||||||||||||||||||
| Total other comprehensive loss, net of tax | (1) | — | — | — | |||||||||||||||||||
| Total comprehensive income | $ | 92 | $ | 155 | $ | 829 | $ | 539 | |||||||||||||||
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
6
SM ENERGY COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (UNAUDITED)
(in millions, except share data and dividends per share)
| Additional Paid-in Capital | Accumulated Other Comprehensive Income (Loss) | Total Stockholders’ Equity | |||||||||||||||||||||||||||||||||
| Common Stock | Retained Earnings | ||||||||||||||||||||||||||||||||||
| Shares | Amount | ||||||||||||||||||||||||||||||||||
| Balances, December 31, 2025 | 114,630,905 | $ | 1 | $ | 1,517 | $ | 3,291 | $ | 1 | $ | 4,810 | ||||||||||||||||||||||||
| Net loss | — | — | — | (335) | — | (335) | |||||||||||||||||||||||||||||
Net cash dividends declared, $0.22 per share | — | — | — | (53) | — | (53) | |||||||||||||||||||||||||||||
| Issuance of common stock upon vesting of RSUs and settlement of PSUs, net of shares used for tax withholdings | 235,422 | — | (17) | — | — | (17) | |||||||||||||||||||||||||||||
| Stock-based compensation expense | 1,114,479 | — | 25 | — | — | 25 | |||||||||||||||||||||||||||||
| Replacement equity awards issued in connection with the Merger | — | — | 29 | — | — | 29 | |||||||||||||||||||||||||||||
| Issuance of common stock in connection with the Merger | 123,715,771 | 1 | 2,408 | — | — | 2,409 | |||||||||||||||||||||||||||||
| Balances, March 31, 2026 | 239,696,577 | $ | 2 | $ | 3,962 | $ | 2,903 | $ | 1 | $ | 6,868 | ||||||||||||||||||||||||
| Net income | — | — | — | 1,071 | — | 1,071 | |||||||||||||||||||||||||||||
| Other comprehensive income | — | — | — | — | 1 | 1 | |||||||||||||||||||||||||||||
Net cash dividends declared, $0.22 per share | — | — | — | (53) | — | (53) | |||||||||||||||||||||||||||||
| Issuance of common stock under Employee Stock Purchase Plan | 147,743 | — | 2 | — | — | 2 | |||||||||||||||||||||||||||||
| Issuance of common stock upon vesting of RSUs and settlement of PSUs, net of shares used for tax withholdings | 216,257 | — | (3) | — | — | (3) | |||||||||||||||||||||||||||||
| Stock-based compensation expense | 77,303 | — | 11 | — | — | 11 | |||||||||||||||||||||||||||||
| Purchase of shares under Stock Repurchase Program | (2,643,506) | — | (84) | — | — | (84) | |||||||||||||||||||||||||||||
| Balances, June 30, 2026 | 237,494,374 | $ | 2 | $ | 3,888 | $ | 3,921 | $ | 2 | $ | 7,813 | ||||||||||||||||||||||||
| Net income | — | — | — | 93 | — | 93 | |||||||||||||||||||||||||||||
| Other comprehensive loss | — | — | — | — | (1) | (1) | |||||||||||||||||||||||||||||
Net cash dividends declared, $0.22 per share | — | — | — | (53) | — | (53) | |||||||||||||||||||||||||||||
| Issuance of common stock upon vesting of RSUs and settlement of PSUs, net of shares used for tax withholdings | 423,998 | — | (6) | — | — | (6) | |||||||||||||||||||||||||||||
| Stock-based compensation expense | — | — | 14 | — | — | 14 | |||||||||||||||||||||||||||||
| Purchase of shares under Stock Repurchase Program | (2,303,327) | — | (83) | — | — | (83) | |||||||||||||||||||||||||||||
| Balances, September 30, 2026 | 235,615,045 | $ | 2 | $ | 3,813 | $ | 3,961 | $ | 1 | $ | 7,777 | ||||||||||||||||||||||||
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
7
SM ENERGY COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (UNAUDITED) (Continued)
(in millions, except share data and dividends per share)
| Additional Paid-in Capital | Accumulated Other Comprehensive Loss | Total Stockholders’ Equity | |||||||||||||||||||||||||||||||||
| Common Stock | Retained Earnings | ||||||||||||||||||||||||||||||||||
| Shares | Amount | ||||||||||||||||||||||||||||||||||
| Balances, December 31, 2024 | 114,461,934 | $ | 1 | $ | 1,502 | $ | 2,735 | $ | (1) | $ | 4,237 | ||||||||||||||||||||||||
| Net income | — | — | — | 182 | — | 182 | |||||||||||||||||||||||||||||
Net cash dividends declared, $0.20 per share | — | — | — | (23) | — | (23) | |||||||||||||||||||||||||||||
| Issuance of common stock upon vesting of RSUs, net of shares used for tax withholdings | 284 | — | — | — | — | — | |||||||||||||||||||||||||||||
| Stock-based compensation expense | — | — | 7 | — | — | 7 | |||||||||||||||||||||||||||||
| Balances, March 31, 2025 | 114,462,218 | $ | 1 | $ | 1,509 | $ | 2,895 | $ | (1) | $ | 4,404 | ||||||||||||||||||||||||
| Net income | — | — | — | 202 | — | 202 | |||||||||||||||||||||||||||||
Net cash dividends declared, $0.20 per share | — | — | — | (23) | — | (23) | |||||||||||||||||||||||||||||
| Issuance of common stock under Employee Stock Purchase Plan | 90,314 | — | 2 | — | — | 2 | |||||||||||||||||||||||||||||
| Stock-based compensation expense | 82,193 | — | 6 | — | — | 6 | |||||||||||||||||||||||||||||
| Balances, June 30, 2025 | 114,634,725 | $ | 1 | $ | 1,517 | $ | 3,074 | $ | (1) | $ | 4,590 | ||||||||||||||||||||||||
| Net income | — | — | — | 155 | — | 155 | |||||||||||||||||||||||||||||
Net cash dividends declared, $0.20 per share | — | — | — | (23) | — | (23) | |||||||||||||||||||||||||||||
| Issuance of common stock upon vesting of RSUs and settlement of PSUs, net of shares used for tax withholdings | 364,172 | — | (5) | — | — | (5) | |||||||||||||||||||||||||||||
| Stock-based compensation expense | — | — | 8 | — | — | 8 | |||||||||||||||||||||||||||||
| Purchase of shares under Stock Repurchase Program | (444,705) | — | (12) | — | — | (12) | |||||||||||||||||||||||||||||
| Balances, September 30, 2025 | 114,554,192 | $ | 1 | $ | 1,508 | $ | 3,205 | $ | (1) | $ | 4,713 | ||||||||||||||||||||||||
____________________________________________
Note: Prior year amounts may not calculate due to rounding.
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
8
SM ENERGY COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(in millions)
| For the Nine Months Ended September 30, | |||||||||||
| 2026 | 2025 | ||||||||||
| Cash flows from operating activities: | |||||||||||
| Net income | $ | 829 | $ | 539 | |||||||
| Adjustments to reconcile net income to net cash provided by operating activities: | |||||||||||
| Gain on divestiture activity | (260) | — | |||||||||
| Depletion, depreciation, and amortization | 1,614 | 888 | |||||||||
| Stock-based compensation expense | 50 | 21 | |||||||||
| Net derivative (gain) loss | 1,109 | (107) | |||||||||
| Net derivative settlement gain (loss) | (457) | 86 | |||||||||
| Amortization of deferred financing costs and debt premiums, net | (16) | 8 | |||||||||
| Deferred income tax expense | 224 | 145 | |||||||||
| Other, net | (18) | (7) | |||||||||
| Net change in working capital | (210) | (15) | |||||||||
| Net cash provided by operating activities | 2,865 | 1,559 | |||||||||
| Cash flows from investing activities: | |||||||||||
| Net proceeds from the sale of oil and gas properties | 889 | — | |||||||||
| Capital expenditures | (2,020) | (1,222) | |||||||||
| Acquisition of business, net of cash acquired | (49) | — | |||||||||
| Other | (51) | (22) | |||||||||
| Net cash used in investing activities | (1,231) | (1,244) | |||||||||
| Cash flows from financing activities: | |||||||||||
| Proceeds from revolving credit facility | 720 | 1,570 | |||||||||
| Repayment of revolving credit facility | (720) | (1,638) | |||||||||
| Net proceeds from Senior Notes | 984 | — | |||||||||
| Cash paid to repurchase Senior Notes | (2,160) | — | |||||||||
| Repurchase of common stock | (166) | (13) | |||||||||
| Dividends paid | (187) | (69) | |||||||||
| Other, net | (31) | (3) | |||||||||
| Net cash used in financing activities | (1,560) | (153) | |||||||||
| Net change in cash, cash equivalents, and restricted cash | 74 | 162 | |||||||||
| Cash, cash equivalents, and restricted cash at beginning of period | 368 | — | |||||||||
| Cash, cash equivalents, and restricted cash at end of period | $ | 442 | $ | 162 | |||||||
| Supplemental schedule of additional cash flow information: | |||||||||||
| Operating activities: Cash paid for interest, net of capitalized interest | $ | (331) | $ | (165) | |||||||
| Operating activities: Net cash paid for income taxes | $ | (30) | $ | (6) | |||||||
| Investing activities: Changes in capital expenditure accruals | $ | 116 | $ | (70) | |||||||
Non-cash investing and financing activities (1) | |||||||||||
____________________________________________
Note: Prior year amounts may not calculate due to rounding.
(1) Refer to Note 2 - Mergers, Acquisitions, and Divestitures for discussion and definition of the Merger completed during the nine months ended September 30, 2026, and refer to Note 6 - Long-Term Debt for discussion of the debt transactions completed during the nine months ended September 30, 2026.
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
9
SM ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
Note 1 - Summary of Significant Accounting Policies
Description of Operations
SM Energy Company, together with our consolidated subsidiaries (collectively, “SM Energy,” the “Company,” “we,” “us,” or “our”), is an independent energy company engaged in the acquisition, exploration, development, and production of oil, gas, and NGLs in Texas, Colorado, New Mexico, and Utah.
Basis of Presentation
The accompanying unaudited condensed consolidated financial statements include our accounts 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. These financial statements do not include all information and notes required by GAAP for annual financial statements. However, except as disclosed herein, there has been no material change in the information disclosed in the notes to the consolidated financial statements included in our 2025 Form 10-K. 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. Operating results for the periods presented are not necessarily indicative of expected results for the full year. As a result of the Merger, we expanded our Permian Basin position by increasing our Midland Basin footprint and establishing a new presence in the Delaware Basin in West Texas and New Mexico. Accordingly, positions and activity previously presented as “Midland Basin” are now included within “Permian Basin”. Refer to Note 2 - Mergers, Acquisitions, and Divestitures for additional discussion and definition of the Merger.
Significant Accounting Policies
Our significant accounting policies are set forth in Note 1 - Summary of Significant Accounting Policies in our 2025 Form 10-K and are supplemented by the notes to the unaudited condensed consolidated financial statements included in this report. These unaudited condensed consolidated financial statements should be read in conjunction with our 2025 Form 10-K.
Recently Issued Accounting Guidance
As of September 30, 2026, and through the filing of this report, no accounting guidance applicable to us has been issued and not yet adopted in 2026 that would have a material effect on our unaudited condensed consolidated financial statements and related disclosures. For information about accounting guidance issued in previous years but not yet adopted by us, refer to Note 1 - Summary of Significant Accounting Policies in our 2025 Form 10-K.
Note 2 - Mergers, Acquisitions, and Divestitures
Merger
On January 30, 2026 (“Closing Date”), we completed our previously announced merger with Civitas Resources, Inc. (“Civitas”), through which we acquired 100 percent of the outstanding voting equity interests of Civitas (“Merger”). Civitas was an independent exploration and production company focused on the acquisition, development, and production of crude oil and associated liquids-rich natural gas primarily in the DJ Basin in Colorado and the Permian Basin in Texas and New Mexico. We believe the Merger enhances our asset portfolio across high-return U.S. shale basins, enables the realization of operational and cost synergies, and provides opportunities for increased free cash flow to drive long-term differentiated stockholder value.
Under the terms of the Agreement and Plan of Merger (“Merger Agreement”), subject to certain exceptions, each share of Civitas common stock was converted into the right to receive 1.45 shares of SM Energy common stock with cash paid in lieu of fractional shares. Upon completion of the Merger, we issued 124 million shares to holders of Civitas common stock. The Merger was structured as a tax-free reorganization for United States federal income tax purposes.
We incurred $18 million of transaction-related costs in connection with the Merger during the nine months ended September 30, 2026. These costs primarily consist of success fees paid to financial advisors and legal fees that have been expensed as incurred and are included in other operating expense in the accompanying unaudited condensed consolidated statements of operations (“accompanying statements of operations”).
Consideration Transferred and Purchase Price Allocation
The Merger was accounted for as a business combination using the acquisition method of accounting under Accounting Standards Codification (“ASC”) Topic 805, Business Combinations (“ASC 805”), with SM Energy treated as the accounting acquirer.
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Under the acquisition method of accounting, we recorded all assets acquired and liabilities assumed from Civitas at their fair values as of the acquisition date, which was determined to be the Closing Date of the Merger. The purchase price allocation for the Merger is preliminary, and we will continue to assess the fair values of the Civitas assets acquired and liabilities assumed.
Determining the fair value of the assets and liabilities of Civitas requires judgment and the use of significant assumptions by our management at the time of acquisition. The most significant fair value estimates relate to the valuation of oil and gas properties, derivative assets and liabilities, and current and long-term debt. Oil and gas properties were valued using an income valuation technique based on Level 3 inputs including estimates of: (i) reserves; (ii) production rates; (iii) future operating and development costs; (iv) future commodity prices, including price differentials; (v) risk adjustment factors; and (vi) a market participant-based weighted-average cost of capital. Derivative assets and liabilities were valued using Level 2 inputs, consistent with our existing commodity derivative instruments, and current and long-term debt were valued using a market approach with observable Level 1 inputs. Refer to Note 9 - Fair Value Measurements for additional discussion of valuation techniques.
The following table presents consideration transferred and the preliminary purchase price allocation to the identifiable assets acquired and liabilities assumed based on respective estimated fair values as of the Closing Date of the Merger:
Preliminary Purchase Price Allocation | |||||
(in millions, except shares and per share amount) | |||||
| Consideration transferred | |||||
Cash consideration transferred (1) | $ | 226 | |||
Shares of common stock issued | 123,715,771 | ||||
Closing price per share (2) | $ | 19.47 | |||
Equity consideration transferred (3) | $ | 2,409 | |||
Replacement equity award consideration transferred (attributable to pre-combination service) | $ | 29 | |||
Total consideration transferred | $ | 2,664 | |||
Assets acquired | |||||
Proved oil and gas properties | $ | 7,537 | |||
Unproved oil and gas properties | 622 | ||||
Accounts receivable | 433 | ||||
Wells in progress | 386 | ||||
Other assets | 251 | ||||
Cash and cash equivalents | 177 | ||||
Derivative assets | 167 | ||||
Total identifiable assets acquired | 9,573 | ||||
Liabilities assumed | |||||
| Senior Notes | 5,090 | ||||
| Accounts payable and accrued expenses | 1,314 | ||||
| Other noncurrent liabilities | 351 | ||||
| Asset retirement obligations | 326 | ||||
| Other current liabilities | 90 | ||||
| Derivative liabilities | 62 | ||||
Deferred tax liabilities (assets), net (4) | (324) | ||||
Total liabilities assumed | 6,909 | ||||
Net identifiable assets acquired | $ | 2,664 | |||
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____________________________________________
(1) Cash consideration transferred consists of $201 million of cash paid to extinguish Civitas’ revolving credit facility balance on the Closing Date, and $25 million of cash paid related to an employee retention program contemplated by the Merger Agreement which required no post-closing service condition and was fully earned prior to the Closing Date.
(2) Based on the closing stock price of SM Energy common stock on January 30, 2026.
(3) Amount represents non-cash investing activity and is calculated using actual shares issued, rounded to the nearest million.
(4) Deferred tax amounts are recorded on a net basis by jurisdiction. Civitas’ deferred tax assets have been offset against our deferred tax liabilities, resulting in a net deferred tax liability balance.
Revenue and Earnings of the Acquiree
The results of operations of Civitas subsequent to the Closing Date are included in our unaudited consolidated financial statements for the three and nine months ended September 30, 2026. Revenue attributable to Civitas included in our accompanying statements of operations for the three and nine months ended September 30, 2026, was $1.3 billion and $3.3 billion, respectively. We have determined that it is impracticable to disclose the amount of net income included in the accompanying statements of operations that is attributable to the Civitas assets, as the acquired operations were immediately integrated into our operations to achieve our synergy targets. As a result, a significant portion of post-Merger expenses relates to the combined Company, and allocating these expenses would require significant assumptions by management.
Pro Forma Financial Information
The results of Civitas’ operations have been included in our consolidated financial statements since the Closing Date. The following unaudited pro forma financial information for the three and nine months ended September 30, 2026, and 2025, is based on historical consolidated financial statements adjusted to reflect the Merger as if it had occurred on January 1, 2025. The pro forma information is based on historical data and certain management assumptions and reflects accounting adjustments for transaction costs, certain restructuring and integration costs, depletion, depreciation, and amortization (“DD&A”) expense, interest expense, and estimated tax effects related to the Merger.
The pro forma information is not necessarily indicative of the results that might have occurred had the transaction actually occurred on January 1, 2025, and is not intended to be a projection of future results. Future results may vary significantly from the results reflected in the following pro forma information because of normal production declines, changes in commodity prices, future acquisitions and divestitures, future development and exploration activities, and other factors.
| For the Three Months Ended September 30, | For the Nine Months Ended September 30, | ||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | ||||||||||||||||||||
(in millions, except per share data) | |||||||||||||||||||||||
| Pro forma oil, gas, and NGL production revenue | $ | 2,160 | $ | 1,971 | $ | 6,097 | $ | 5,842 | |||||||||||||||
| Pro forma net income | $ | 93 | $ | 488 | $ | 898 | $ | 1,330 | |||||||||||||||
| Pro forma basic net income per common share | $ | 0.39 | $ | 2.03 | $ | 3.79 | $ | 5.55 | |||||||||||||||
| Pro forma diluted net income per common share | $ | 0.39 | $ | 2.02 | $ | 3.77 | $ | 5.53 | |||||||||||||||
South Texas Divestiture
On April 30, 2026, we completed the previously announced sale of all of our rights, titles, and interests in certain producing and non-producing assets encompassing approximately 61,000 net acres located in our southern Maverick Basin position in Webb County, Texas (“South Texas Divestiture”) to Caturus Energy, LLC, a Delaware limited liability company. Subsequent to September 30, 2026, we completed the final post-closing settlement, resulting in total cash proceeds of $894 million after final purchase price adjustments and selling costs (referred to throughout this report as “net cash proceeds”) and a final gain on divestiture activity of $260 million.
The South Texas Divestiture is considered to be a significant disposal group. The asset sale does not qualify for discontinued operations under GAAP because it does not represent a strategic shift in our operations that has or will have a significant effect on our operations and financial results.
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The following table presents earnings before income taxes attributable to the assets included in the South Texas Divestiture. Earnings before income taxes reflect oil, gas, and NGL production revenue, less oil, gas, and NGL production expense; DD&A expense; and exploration expense. Depletion expense ceased upon classification of the assets as held for sale during the first quarter of 2026.
| For the Three Months Ended September 30, | For the Nine Months Ended September 30, | ||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | ||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||
Earnings before income taxes attributable to the South Texas Divestiture assets (1) | $ | — | $ | 29 | $ | 61 | $ | 98 | |||||||||||||||
(1) As the South Texas Divestiture closed on April 30, 2026, the earnings amount presented reflects four months of activity during the nine months ended September 30, 2026.
Note 3 - Revenue from Contracts with Customers
We recognize our share of revenue from the sale of produced oil, gas, and NGLs from our Permian Basin, DJ Basin, South Texas, and Uinta Basin assets. Oil, gas, and NGL production revenue presented within the accompanying statements of operations reflects revenue generated from contracts with customers.
The following table presents oil, gas, and NGL production revenue by product type for each of our operating areas. The Permian Basin and DJ Basin results reflect activity from the assets acquired in the Merger only after the Closing Date of January 30, 2026, and the South Texas results reflect activity from the assets sold in the South Texas Divestiture only for the period from January 1, 2026, through the divestiture date of April 30, 2026.
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| For the Three Months Ended September 30, | For the Nine Months Ended September 30, | ||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | ||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||
| Oil production revenue | |||||||||||||||||||||||
| Permian Basin | $ | 944 | $ | 312 | $ | 2,779 | $ | 963 | |||||||||||||||
| DJ Basin | 460 | — | 1,213 | — | |||||||||||||||||||
| South Texas | 127 | 131 | 348 | 362 | |||||||||||||||||||
| Uinta Basin | 285 | 226 | 764 | 656 | |||||||||||||||||||
| Total | 1,816 | 669 | 5,104 | 1,981 | |||||||||||||||||||
| Gas production revenue | |||||||||||||||||||||||
| Permian Basin | 123 | 32 | 83 | 115 | |||||||||||||||||||
| DJ Basin | 60 | — | 147 | — | |||||||||||||||||||
| South Texas | 18 | 47 | 97 | 146 | |||||||||||||||||||
| Uinta Basin | 8 | 6 | 21 | 21 | |||||||||||||||||||
| Total | 209 | 84 | 348 | 282 | |||||||||||||||||||
| NGL production revenue | |||||||||||||||||||||||
| Permian Basin | 36 | — | 80 | — | |||||||||||||||||||
| DJ Basin | 60 | — | 141 | — | |||||||||||||||||||
| South Texas | 39 | 58 | 120 | 172 | |||||||||||||||||||
| Uinta Basin | — | — | — | — | |||||||||||||||||||
| Total | 135 | 58 | 341 | 172 | |||||||||||||||||||
| Oil, Gas, and NGL production revenue | |||||||||||||||||||||||
| Permian Basin | 1,103 | 344 | 2,942 | 1,079 | |||||||||||||||||||
| DJ Basin | 580 | — | 1,501 | — | |||||||||||||||||||
| South Texas | 184 | 235 | 565 | 680 | |||||||||||||||||||
| Uinta Basin | 293 | 232 | 785 | 677 | |||||||||||||||||||
| Total | $ | 2,160 | $ | 811 | $ | 5,793 | $ | 2,436 | |||||||||||||||
| Relative percentage of total Oil, Gas, and NGL production revenue | |||||||||||||||||||||||
| Permian Basin | 51% | 42% | 51% | 44% | |||||||||||||||||||
DJ Basin | 27% | —% | 26% | —% | |||||||||||||||||||
| South Texas | 9% | 29% | 10% | 28% | |||||||||||||||||||
| Uinta Basin | 13% | 29% | 13% | 28% | |||||||||||||||||||
____________________________________________
Note: Amounts may not calculate due to rounding.
As of September 30, 2026, there were no material unsatisfied or partially unsatisfied performance obligations.
Accrued oil, gas, and NGL production revenue included in accounts receivable in the accompanying unaudited condensed consolidated balance sheets (“accompanying balance sheets”) as of September 30, 2026, and December 31, 2025, was $791 million and $193 million, respectively.
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Note 4 - Income Taxes
The provision for income taxes consisted of the following:
| For the Three Months Ended September 30, | For the Nine Months Ended September 30, | ||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | ||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||
| Current portion of income tax (expense) benefit: | |||||||||||||||||||||||
| Federal | $ | (35) | $ | 27 | $ | (44) | $ | (1) | |||||||||||||||
| State | (2) | — | (5) | (3) | |||||||||||||||||||
| Deferred portion of income tax (expense) benefit | 7 | (76) | (224) | (145) | |||||||||||||||||||
| Income tax expense | $ | (30) | $ | (49) | $ | (273) | $ | (150) | |||||||||||||||
| Effective tax rate | 24.9 | % | 24.1 | % | 24.8 | % | 21.7 | % | |||||||||||||||
____________________________________________
Note: Amounts may not calculate due to rounding.
Income tax expense or benefit differs from the amount that would be calculated by applying the statutory United States federal income tax rate to income or loss before income taxes. These differences can relate to the effect of federal and state tax credits, state income taxes, excess tax benefits and deficiencies from stock-based compensation awards, tax deduction limitations on compensation of covered individuals, and the cumulative effect of other smaller permanent differences. The quarterly effective tax rate and the resulting income tax expense or benefit can also be affected by the proportional effects of forecast net income or loss and the correlative effect on the valuation allowance for each of the periods presented in the table above. Income tax expense or benefit can also reflect a period change from the remeasurement of deferred tax assets and liabilities resulting from a statutorily enacted tax rate change or a change in the composition of income and activities among multiple state tax jurisdictions due to a corporate reorganization. Due to the Merger and resulting increase in activity in the state of Colorado, we recorded a remeasurement tax expense during the first quarter of 2026, related to our historical net deferred tax balances.
As a result of the Merger, it was determined that an ownership change occurred under Sections 382 and 383 of the Internal Revenue Code (“IRC”), changing the timing of when we can utilize certain tax attributes. We have assessed the recoverability of our deferred tax assets by considering whether it is more likely than not that all or a portion of our deferred tax assets will be realized. In making such a determination, we considered both the positive and negative evidence, including our recent history of profitability, and concluded that no additional valuation allowance is currently required. We will continue to assess the realizability of our acquired tax attributes considering any potential impacts under IRC 382, as permitted under ASC 805.
On July 4, 2025, the One Big Beautiful Bill Act was enacted, introducing certain favorable changes to corporate tax provisions. As required, we recorded the full-year impact to current income tax expense during the third quarter of 2025.
We comply with authoritative accounting guidance regarding uncertain tax positions. The entire amount of unrecognized tax benefit we have reported would affect our effective tax rate if recognized. We do not expect a material change to our recorded unrecognized tax benefits in 2026.
We are no longer subject to United States federal or state income tax examinations by tax authorities for tax years prior to 2022. However, tax years in which net operating losses or tax credit carryforwards were generated remain subject to examination until such losses or credits are fully utilized or expire.
Note 5 - Equity
Common Stock
On January 27, 2026, our stockholders voted in favor of both proposals necessary to complete the Merger, which included approval of (i) the issuance of shares of SM Energy common stock to Civitas stockholders as contemplated by the Merger Agreement, and (ii) an amendment of our Restated Certificate of Incorporation to increase the number of authorized shares of our common stock from 200 million shares to 400 million shares. Upon completion of the Merger, we issued 124 million shares of our common stock to holders of Civitas common stock. Refer to Note 2 - Mergers, Acquisitions, and Divestitures for additional discussion.
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Dividends
In February 2026, our Board of Directors approved a 10 percent increase to our annual base dividend to $0.88 per share, to be paid in quarterly increments of $0.22 per share. Beginning with the first quarter of 2026, dividends are declared and paid within the same quarter, rather than being paid in the quarter subsequent to declaration. As a result of this change in timing, during the nine months ended September 30, 2026, we paid dividends that were declared in the fourth quarter of 2025 and the first, second, and third quarters of 2026, totaling $0.86 per share, or $187 million.
Stock Repurchase Program
Our stock repurchase program, which our Board of Directors authorized in June 2024, for the repurchase of up to $500 million in aggregate value of our outstanding common stock through December 31, 2027, permits us to repurchase our shares from time to time in open market transactions (including pursuant to Rule 10b5-1 trading plans), through privately negotiated transactions or by other means in accordance with federal securities laws and subject to certain provisions of our Credit Agreement and the indentures governing our Senior Notes (“Stock Repurchase Program”). Refer to Note 6 - Long-Term Debt for definition of Senior Notes.
The following table presents activity under our Stock Repurchase Program for the periods presented:
| For the Three Months Ended September 30, | For the Nine Months Ended September 30, | ||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | ||||||||||||||||||||
Shares of common stock repurchased (1) | 2,303,327 | 444,705 | 4,946,833 | 444,705 | |||||||||||||||||||
Weighted-average price per share (2) | $ | 35.30 | $ | 27.25 | $ | 33.39 | $ | 27.25 | |||||||||||||||
Cost of shares of common stock repurchased (in millions) (2) (3) | $ | 81 | $ | 12 | $ | 165 | $ | 12 | |||||||||||||||
____________________________________________
(1) All repurchased shares of our common stock were subsequently retired.
(2) Amounts exclude excise taxes, commissions, and fees.
(3) Amounts may not calculate due to rounding.
As of September 30, 2026, $323 million remained available for repurchases of our outstanding common stock through December 31, 2027, under our Stock Repurchase Program.
Note 6 - Long-Term Debt
Credit Agreement
Our Credit Agreement provides for a senior secured revolving credit facility with a maximum loan amount of $5.0 billion. In connection with the closing of the Merger on January 30, 2026, we entered into the Fourth Amendment to the Credit Agreement (“Fourth Amendment”) with our lenders to, among other things: (i) permit the assumption of outstanding Civitas senior unsecured notes and add the subsidiaries of Civitas as guarantors under the Credit Agreement, (ii) extend the scheduled maturity date for elected revolving commitments to January 30, 2031, (iii) increase the aggregate revolving lender commitments available under the Credit Agreement from $2.0 billion to $2.5 billion and add three new lender counterparties, (iv) increase the borrowing base from $3.0 billion to $5.0 billion, (v) eliminate the credit spread adjustment applicable to term Secured Overnight Financing Rate (“SOFR”) loans (as defined in the Credit Agreement), and (vi) make certain other amendments to the financial covenant definitions and provide additional flexibility under certain affirmative covenants, negative covenants and events of default. As of September 30, 2026, the borrowing base and aggregate revolving lender commitments under the Credit Agreement were $5.0 billion and $2.5 billion, respectively. Subsequent to September 30, 2026, we completed the semi-annual borrowing base redetermination, which reaffirmed both our borrowing base and our aggregate lender commitments at existing levels. The next borrowing base redetermination is scheduled to occur on April 1, 2027.
Interest and commitment fees associated with the revolving credit facility are accrued based on a borrowing base utilization grid set forth in the Credit Agreement, as presented in Note 5 - Long-Term Debt in our 2025 Form 10-K. At our election, borrowings under the Credit Agreement may be in the form of SOFR revolving loans, Alternate Base Rate (“ABR”) revolving loans, or Swingline loans. SOFR revolving loans accrue interest at SOFR plus the applicable margin from the utilization grid, and ABR revolving loans and Swingline loans accrue interest at a market-based floating rate, plus the applicable margin from the utilization grid. Commitment fees are accrued on the unused portion of the aggregate revolving lender commitment amount at rates from the utilization grid.
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The following table presents the outstanding balance, total amount of letters of credit outstanding, and available borrowing capacity under the Credit Agreement:
| As of October 22, 2026 | As of September 30, 2026 | As of December 31, 2025 | |||||||||||||||
(in millions) | |||||||||||||||||
Revolving credit facility (1) | $ | — | $ | — | $ | — | |||||||||||
Letters of credit (2) | 2 | 2 | 2 | ||||||||||||||
| Available borrowing capacity | 2,498 | 2,498 | 1,999 | ||||||||||||||
Total aggregate revolving lender commitment amount | $ | 2,500 | $ | 2,500 | $ | 2,000 | |||||||||||
____________________________________________
Note: Amounts may not calculate due to rounding.
(1) Unamortized deferred financing costs attributable to the revolving credit facility are presented as a component of the other noncurrent assets line item in the accompanying balance sheets and totaled $20 million and $15 million as of September 30, 2026, and December 31, 2025, respectively. These costs are being amortized over the term of the Credit Agreement on a straight-line basis.
(2) Letters of credit outstanding reduce the amount available under the revolving credit facility on a dollar-for-dollar basis.
Assumption of Civitas Senior Notes and Payoff of Civitas Revolving Credit Facility
Upon the completion of the Merger, as contemplated by the Merger Agreement, we assumed $4.9 billion in aggregate principal amount of outstanding unsecured senior notes previously issued by Civitas (“Civitas Senior Notes”). Our Civitas Senior Notes were recorded at their respective fair values as of the Closing Date. Because the fair values exceeded the aggregate principal amounts outstanding, we recorded a premium, which is amortized over the remaining terms of the notes.
On the Closing Date of the Merger, as contemplated by the Merger Agreement, we used cash on hand to repay in full the outstanding borrowings under the Civitas revolving credit facility, including accrued and unpaid interest and applicable fees, resulting in a total payment of $201 million. This repayment extinguished the related obligations and released all associated liens. This payment was made by SM Energy on behalf of Civitas and has been reflected as consideration transferred in the preliminary purchase price allocation in accordance with ASC 805, as presented in Note 2 - Mergers, Acquisitions, and Divestitures.
Senior Notes
The table below summarizes the interest rates, maturity dates, and semi-annual interest payment dates related to our Senior Notes (collectively referred to as “Senior Notes”) as of September 30, 2026:
Interest Rate | Interest Payment Dates | Maturity Date | |||||||||||||||
Senior Notes due 2028 (1) | 8.375% | January 1, July 1 | July 1, 2028 | ||||||||||||||
Senior Notes due 2028 | 6.5% | January 15, July 15 | July 15, 2028 | ||||||||||||||
Senior Notes due 2029 | 6.75% | February 1, August 1 | August 1, 2029 | ||||||||||||||
Senior Notes due 2030 (1) | 8.625% | May 1, November 1 | November 1, 2030 | ||||||||||||||
Senior Notes due 2031 (1) | 8.75% | January 1, July 1 | July 1, 2031 | ||||||||||||||
Senior Notes due 2032 | 7.0% | February 1, August 1 | August 1, 2032 | ||||||||||||||
Senior Notes due 2033 (1) | 9.625% | June 15, December 15 | June 15, 2033 | ||||||||||||||
Senior Notes due 2034 | 6.625% | April 15, October 15 | April 15, 2034 | ||||||||||||||
____________________________________________
(1) Civitas Senior Notes assumed as part of the Merger.
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The Senior Notes, net line items in the accompanying balance sheets as of September 30, 2026, and December 31, 2025, consisted of the following:
| As of September 30, 2026 | |||||||||||||||||||||||
| Principal Amount | Unamortized Premium | Unamortized Deferred Financing Costs | Principal Amount, Net | ||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||
8.375% Senior Notes due 2028 (1) | $ | 456 | $ | 10 | $ | — | $ | 466 | |||||||||||||||
6.5% Senior Notes due 2028 | 400 | — | (2) | 398 | |||||||||||||||||||
6.75% Senior Notes due 2029 | 750 | — | (7) | 743 | |||||||||||||||||||
8.625% Senior Notes due 2030 (1) | 1,000 | 52 | — | 1,052 | |||||||||||||||||||
8.75% Senior Notes due 2031 (1) | 1,350 | 61 | — | 1,411 | |||||||||||||||||||
7.0% Senior Notes due 2032 | 750 | — | (8) | 742 | |||||||||||||||||||
9.625% Senior Notes due 2033 (1) | 750 | 67 | — | 817 | |||||||||||||||||||
6.625% Senior Notes due 2034 | 1,000 | — | (15) | 985 | |||||||||||||||||||
| Total | $ | 6,456 | $ | 190 | $ | (32) | $ | 6,614 | |||||||||||||||
____________________________________________
(1) Civitas Senior Notes assumed as part of the Merger.
| As of December 31, 2025 | |||||||||||||||||
| Principal Amount | Unamortized Deferred Financing Costs | Principal Amount, Net | |||||||||||||||
| (in millions) | |||||||||||||||||
6.75% Senior Notes due 2026 (1) | $ | 419 | $ | — | $ | 419 | |||||||||||
6.625% Senior Notes due 2027 | 417 | (1) | 416 | ||||||||||||||
6.5% Senior Notes due 2028 | 400 | (3) | 397 | ||||||||||||||
6.75% Senior Notes due 2029 | 750 | (8) | 742 | ||||||||||||||
7.0% Senior Notes due 2032 | 750 | (10) | 740 | ||||||||||||||
| Total | $ | 2,736 | $ | (22) | $ | 2,714 | |||||||||||
____________________________________________
(1) As of December 31, 2025, our 6.75% Senior Notes due 2026 (“2026 Senior Notes”) are presented in the current liabilities section of the accompanying balance sheets.
In March 2026, we commenced a cash tender offer (“Tender Offer”) to purchase a portion of our 8.375% Senior Notes due 2028 (“2028 Civitas Senior Notes”) at a repurchase price equal to 103.175 percent of the principal amount outstanding, plus accrued and unpaid interest. Pursuant to the Tender Offer, we repurchased $894 million aggregate principal amount and paid total consideration, including the early tender premium and certain fees but excluding accrued interest, of $924 million. The remaining aggregate principal amount outstanding of our 2028 Civitas Senior Notes is $456 million as of September 30, 2026.
To fund the Tender Offer, on March 9, 2026, we issued $1.0 billion aggregate principal amount of 6.625% Senior Notes due April 15, 2034 (“2034 Senior Notes”) at par, receiving net proceeds of $984 million after deducting fees of $16 million, which are being amortized as deferred financing costs over the life of the 2034 Senior Notes.
On May 11, 2026, pursuant to the terms of the governing indenture, we redeemed all $400 million aggregate principal amount outstanding of our 5.0% Senior Notes due October 15, 2026 (“2026 Civitas Senior Notes”) at a redemption price equal to 100 percent of the principal amount outstanding, plus accrued and unpaid interest. In connection with the redemption of our 2026 Civitas Senior Notes, we satisfied all remaining obligations under the governing indenture.
On June 1, 2026, pursuant to the terms of the governing indenture, we redeemed all $419 million aggregate principal amount outstanding of our 2026 Senior Notes at a redemption price equal to 100 percent of the principal amount outstanding, plus accrued and unpaid interest. In connection with the redemption of our 2026 Senior Notes, we satisfied all remaining obligations under the governing indenture related to our 2026 Senior Notes.
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On September 4, 2026, pursuant to the terms of the governing indenture, we redeemed all $417 million aggregate principal amount outstanding of our 6.625% Senior Notes due 2027 (“2027 Senior Notes”) at a redemption price equal to 100 percent of the principal amount outstanding of the 2027 Senior Notes, plus accrued and unpaid interest. In connection with the redemption of our 2027 Senior Notes, we satisfied all remaining obligations under the governing indenture related to our 2027 Senior Notes.
During the nine months ended September 30, 2026, we recorded a $4 million net loss on extinguishment of debt related to the repurchases and redemptions of the Senior Notes discussed above. The net loss primarily relates to the partial repurchase of our 2028 Civitas Senior Notes which included the early tender premium and certain fees, partially offset by the accelerated recognition of the unamortized fair value premium recorded on the Closing Date of the Merger. Following these transactions, we have no Senior Notes maturities until mid-2028.
Our 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 each of our existing subsidiaries that guarantee the Credit Agreement.
Covenants
We are subject to certain financial and non-financial covenants under the Credit Agreement and the indentures governing our Senior Notes that, among other terms, limit our ability to incur additional indebtedness, make restricted payments including dividends, sell assets, create liens that secure debt, enter into transactions with affiliates, make certain investments, or merge or consolidate with other entities. We were in compliance with all financial and non-financial covenants as of September 30, 2026, and through the filing of this report.
Capitalized Interest
Capitalized interest costs for the three months ended September 30, 2026, and 2025, totaled $15 million and $8 million, respectively, and for the nine months ended September 30, 2026, and 2025, totaled $43 million and $26 million, respectively. The amount of interest we capitalize generally fluctuates based on the amount borrowed, our capital program, and the timing and amount of costs associated with capital projects that are considered in progress. Capitalized interest costs are included in total costs incurred.
Note 7 - Commitments and Contingencies
We assumed various commitments through the Merger which are included in our commitments and contingencies disclosures as of September 30, 2026. Other than the items discussed below, there have been no changes in commitments and contingencies that differ materially from those disclosed in our 2025 Form 10-K through the filing of this report.
Commitments
Drilling and Completion Commitments. During the nine months ended September 30, 2026, we entered into an agreement requiring us to drill and complete minimum lateral footage on certain existing leases. Failure to satisfy these obligations by March 31, 2028, will require us to pay liquidated damages based on the difference between the actual footage drilled and completed and the minimum requirements. As of September 30, 2026, liquidated damages could range from zero to a maximum of $64 million, with the maximum exposure assuming no additional development activity occurs before March 31, 2028. As of the filing of this report, we expect to meet our obligations under this agreement.
In connection with the Merger, we assumed certain oil, gas, and produced water gathering agreements that collectively contain a drilling commitment. The commitment requires us to drill and complete a total of 106 qualifying wells by December 31, 2026, unless our obligation is excused under the terms of the agreements. As of September 30, 2026, we do not expect to meet this commitment; however, we believe our nonperformance is excused under the terms of the agreements. We cannot reasonably estimate the amount of damages, if any, that might be incurred if our position is not sustained.
Delivery Commitments. As of September 30, 2026, we have material, long-term transportation and delivery commitments with various parties. These agreements, some of which we assumed through the Merger, require us to make periodic deficiency payments for any shortfalls in delivering specified minimum volume commitments. In connection with the Merger, we assumed delivery commitments under which, as of September 30, 2026, we are required to deliver a minimum of 56 MMBbl of oil through 2030 and 45 Bcf of gas through 2029. As of September 30, 2026, if we fail to deliver any product under all applicable agreements, the aggregate undiscounted deficiency payments would total $205 million. We do not expect to incur material penalties or shortfalls with regard to these commitments.
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Contingencies
We are subject to litigation and claims arising in the ordinary course of business. We accrue for such items when a liability is both probable and the amount can be reasonably estimated. As of the filing of this report, in the opinion of management, the anticipated results of any pending litigation and claims are not expected to have a material effect on our results of operations, our financial position, or our cash flows.
Note 8 - Derivative Financial Instruments
Summary of Oil, Gas, and NGL Derivative Contracts in Place
We regularly enter into commodity derivative contracts to mitigate a portion of our exposure to oil, gas, and NGL price volatility and location differentials, and the associated effect on cash flows. All commodity derivative contracts that we enter into are for other-than-trading purposes. Our commodity derivative contracts consist of price swap and collar arrangements for oil and gas production, and price swap arrangements for NGL production.
In a typical commodity swap agreement, if the agreed-upon published third-party index price (“index price”) is lower than the swap price, we receive the difference between the index price and the agreed-upon swap price. If the index price is higher than the swap price, we pay the difference. For collar arrangements, we receive the difference between an agreed-upon index price and the floor price if the index price is below the floor price. We pay the difference between the agreed-upon ceiling price and the index price if the index price is above the ceiling price. No amounts are paid or received if the index price is between the floor and ceiling prices.
We have entered into fixed price oil and gas basis swaps to mitigate exposure to adverse pricing differentials between certain industry benchmark prices and the actual physical pricing points where our production is sold. As of September 30, 2026, we had basis swap contracts with fixed price differentials between:
•NYMEX WTI and Argus WTI Midland (“WTI Midland”) for a portion of our Permian Basin oil production with sales contracts that settle at WTI Midland prices;
•NYMEX WTI and Argus WTI Houston Magellan East Houston Terminal (“WTI Houston MEH”) for a portion of our South Texas oil production with sales contracts that settle at WTI Houston MEH prices;
•NYMEX Henry Hub (“HH”) and Inside FERC (“IF”) Waha hub in West Texas (“Waha”) for a portion of our Permian Basin gas production with sales contracts that settle at IF Waha prices; and
•NYMEX Henry Hub and Colorado Interstate Gas (“CIG Rockies”) for a portion of our DJ Basin natural gas production with sales contracts that settle at CIG Rockies prices.
We have also entered into oil swap contracts to fix the differential in pricing between the NYMEX calendar month average and the physical crude oil delivery month (“Roll Differential”) in which we pay the periodic variable Roll Differential and receive a weighted-average fixed price differential. The weighted-average fixed price differential represents the amount of net addition (reduction) to delivery month prices for the notional volumes covered by the swap contracts.
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As of September 30, 2026, we had commodity derivative contracts with terms through the second quarter of 2028 as summarized in the table below:
| Contract Period | ||||||||||||||||||||
| Fourth Quarter 2026 | 2027 | 2028 | ||||||||||||||||||
| Oil Derivatives (volumes in MBbl and prices in $ per Bbl): | ||||||||||||||||||||
| Swaps | ||||||||||||||||||||
| NYMEX WTI Volumes | 7,673 | 12,542 | — | |||||||||||||||||
| Weighted-Average Contract Price | $ | 61.22 | $ | 68.70 | $ | — | ||||||||||||||
| Collars | ||||||||||||||||||||
| NYMEX WTI Volumes | 3,289 | 13,157 | — | |||||||||||||||||
| Weighted-Average Floor Price | $ | 58.66 | $ | 63.93 | $ | — | ||||||||||||||
| Weighted-Average Ceiling Price | $ | 66.07 | $ | 72.37 | $ | — | ||||||||||||||
| Basis Swaps | ||||||||||||||||||||
WTI Midland-NYMEX WTI Volumes | 1,140 | 2,194 | — | |||||||||||||||||
| Weighted-Average Contract Price | $ | 0.99 | $ | 1.02 | $ | — | ||||||||||||||
WTI Houston MEH-NYMEX WTI Volumes | 378 | — | — | |||||||||||||||||
| Weighted-Average Contract Price | $ | 2.01 | $ | — | $ | — | ||||||||||||||
| Roll Differential Swaps | ||||||||||||||||||||
| NYMEX WTI Volumes | 719 | — | — | |||||||||||||||||
| Weighted-Average Contract Price | $ | 1.08 | $ | — | $ | — | ||||||||||||||
| Gas Derivatives (volumes in BBtu and prices in $ per MMBtu): | ||||||||||||||||||||
| Swaps | ||||||||||||||||||||
NYMEX HH Volumes | 13,696 | 41,556 | 3,259 | |||||||||||||||||
| Weighted-Average Contract Price | $ | 4.30 | $ | 3.96 | $ | 4.05 | ||||||||||||||
IF Waha Volumes | 1,067 | 4,603 | 7,280 | |||||||||||||||||
| Weighted-Average Contract Price | $ | 3.13 | $ | 3.64 | $ | 1.11 | ||||||||||||||
| Collars | ||||||||||||||||||||
NYMEX HH Volumes | 27,352 | 20,661 | — | |||||||||||||||||
| Weighted-Average Floor Price | $ | 3.53 | $ | 3.72 | $ | — | ||||||||||||||
| Weighted-Average Ceiling Price | $ | 4.67 | $ | 4.60 | $ | — | ||||||||||||||
| Basis Swaps | ||||||||||||||||||||
IF Waha-NYMEX HH Volumes | 11,960 | 28,053 | — | |||||||||||||||||
| Weighted-Average Contract Price | $ | (1.31) | $ | (0.77) | $ | — | ||||||||||||||
CIG Rockies-NYMEX HH Volumes | 11,960 | 7,300 | — | |||||||||||||||||
| Weighted-Average Contract Price | $ | (0.57) | $ | (0.37) | $ | — | ||||||||||||||
| NGL Derivatives (volumes in MBbl and prices in $ per Bbl): | ||||||||||||||||||||
| Swaps | ||||||||||||||||||||
| OPIS Ethane Mont Belvieu Non-TET Volumes | 141 | — | — | |||||||||||||||||
| Weighted-Average Contract Price | $ | 11.71 | $ | — | $ | — | ||||||||||||||
Derivative Assets and Liabilities Fair Value
Our commodity derivatives are measured at fair value and are included in the accompanying balance sheets as derivative assets and liabilities, with the exception of derivative instruments that meet the “normal purchase normal sale” exclusion. We do not designate our commodity derivative contracts as hedging instruments. The fair value of commodity derivative contracts at September 30, 2026, and December 31, 2025, was a net liability of $460 million and a net asset of $85 million, respectively.
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The following table details the fair value of commodity derivative contracts recorded in the accompanying balance sheets:
Offsetting of Derivative Assets and Liabilities
As of September 30, 2026, and December 31, 2025, all derivative instruments held were subject to master netting arrangements with various financial institutions. In general, our agreements with counterparties provide for the offsetting of amounts payable or receivable, at the election of both parties, for transactions that settle on the same date and in the same currency. Our agreements also provide that in the event of an early termination, the counterparties have the right to offset amounts owed or owing under that and any other agreement with the same counterparty. Our accounting policy is to not offset these positions in our accompanying balance sheets.
The following table provides a reconciliation between the gross assets and liabilities reflected in the accompanying balance sheets and the potential effects of master netting arrangements on the fair value of our commodity derivative contracts:
We recognize all gains and losses from changes in commodity derivative fair values immediately in earnings rather than deferring such amounts in accumulated other comprehensive income (loss). We had no commodity derivative contracts designated as hedging instruments as of September 30, 2026, and December 31, 2025. Refer to Note 9 - Fair Value Measurements for more information regarding our derivative instruments, including our valuation techniques.
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The following table summarizes the commodity components of the net derivative settlement gain (loss), and the net derivative (gain) loss line items presented within the accompanying unaudited condensed consolidated statements of cash flows (“accompanying statements of cash flows”) and the accompanying statements of operations, respectively:
| For the Three Months Ended September 30, | For the Nine Months Ended September 30, | ||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | ||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||
| Net derivative settlement (gain) loss: | |||||||||||||||||||||||
| Oil contracts | $ | 251 | $ | (16) | $ | 661 | $ | (40) | |||||||||||||||
| Gas contracts | (43) | (22) | (202) | (48) | |||||||||||||||||||
| NGL contracts | (1) | — | (2) | 2 | |||||||||||||||||||
| Total net derivative settlement (gain) loss | $ | 207 | $ | (39) | $ | 457 | $ | (86) | |||||||||||||||
| Net derivative (gain) loss: | |||||||||||||||||||||||
| Oil contracts | $ | 695 | $ | 1 | $ | 1,256 | $ | (51) | |||||||||||||||
| Gas contracts | (11) | (46) | (254) | (56) | |||||||||||||||||||
| NGL contracts | — | — | 107 | — | |||||||||||||||||||
| Total net derivative (gain) loss | $ | 684 | $ | (45) | $ | 1,109 | $ | (107) | |||||||||||||||
____________________________________________
Note: Prior year amounts may not calculate due to rounding.
Credit Related Contingent Features
As of September 30, 2026, all of our derivative counterparties were members of our Credit Agreement lender group. We do not enter into derivative contracts with counterparties that are not part of the lender group. Under the Credit Agreement, we are required to provide mortgage liens on assets having a value equal to at least 85 percent of the total PV-9, as defined in the Credit Agreement, of our proved oil and gas properties evaluated in the most recent reserve report. Collateral securing indebtedness under the Credit Agreement also secures our derivative agreement obligations.
Note 9 - Fair Value Measurements
We follow fair value measurement accounting guidance for all assets and liabilities measured at fair value. This guidance defines fair value as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Market or observable inputs are the preferred sources of values, followed by assumptions based on hypothetical transactions in the absence of market inputs. The fair value hierarchy for grouping these assets and liabilities is based on the significance level of the following inputs:
•Level 1 – quoted prices in active markets for identical assets or liabilities
•Level 2 – quoted prices in active markets for similar assets or 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
The following table is a listing of our assets and liabilities that are measured at fair value on a recurring basis in the accompanying balance sheets and where they are classified within the fair value hierarchy:
| As of September 30, 2026 | As of December 31, 2025 | ||||||||||||||||||||||||||||||||||
| Level 1 | Level 2 | Level 3 | Level 1 | Level 2 | Level 3 | ||||||||||||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||||||||||||||
Derivatives | $ | — | $ | 105 | $ | — | $ | — | $ | 89 | $ | — | |||||||||||||||||||||||
| Liabilities: | |||||||||||||||||||||||||||||||||||
Derivatives | $ | — | $ | 565 | $ | — | $ | — | $ | 4 | $ | — | |||||||||||||||||||||||
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Both financial and non-financial assets and liabilities are categorized within the fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. The following is a description of the valuation methodologies we use and the general classification of such instruments pursuant to the above fair value hierarchy.
Derivatives
We use Level 2 inputs to measure the fair value of oil, gas, and NGL commodity derivative instruments. Fair values are based upon interpolated data. We derive internal valuation estimates taking into consideration forward commodity price curves, counterparties’ credit ratings, our credit rating, and the time value of money. These valuations are then compared to the respective counterparties’ mark-to-market statements. The considered factors result in an estimated exit price that management believes provides a reasonable and consistent methodology for valuing derivative instruments. The commodity derivative instruments we utilize are not considered by management to be complex, structured, or illiquid. The oil, gas, and NGL commodity derivative markets are highly active. Refer to Note 8 - Derivative Financial Instruments for more information regarding our derivative instruments.
Acquisition of Proved and Unproved Properties
Assets acquired and liabilities assumed in transactions that meet the definition of a business combination under ASC 805 are recognized at their estimated fair values as of the acquisition date and are valued using an income valuation technique based on Level 3 inputs. Refer to Note 2 - Mergers, Acquisitions, and Divestitures for discussion of the valuation technique used for the Merger.
Long-Term Debt
The following table reflects the fair value of our Senior Notes measured using Level 1 inputs based on quoted secondary market trading prices. The Senior Notes were not presented at fair value in the accompanying balance sheets as of September 30, 2026, or December 31, 2025, as the Senior Notes were recorded at carrying value, net of any unamortized premium or unamortized deferred financing costs. Refer to Note 6 - Long-Term Debt for additional information.
| As of September 30, 2026 | As of December 31, 2025 | ||||||||||||||||||||||
| Principal Amount | Fair Value | Principal Amount | Fair Value | ||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||
6.75% Senior Notes due 2026 | $ | — | $ | — | $ | 419 | $ | 420 | |||||||||||||||
6.625% Senior Notes due 2027 | $ | — | $ | — | $ | 417 | $ | 419 | |||||||||||||||
8.375% Senior Notes due 2028 | $ | 456 | $ | 464 | $ | — | $ | — | |||||||||||||||
6.5% Senior Notes due 2028 | $ | 400 | $ | 400 | $ | 400 | $ | 405 | |||||||||||||||
6.75% Senior Notes due 2029 | $ | 750 | $ | 753 | $ | 750 | $ | 756 | |||||||||||||||
8.625% Senior Notes due 2030 | $ | 1,000 | $ | 1,035 | $ | — | $ | — | |||||||||||||||
8.75% Senior Notes due 2031 | $ | 1,350 | $ | 1,397 | $ | — | $ | — | |||||||||||||||
7.0% Senior Notes due 2032 | $ | 750 | $ | 747 | $ | 750 | $ | 739 | |||||||||||||||
9.625% Senior Notes due 2033 | $ | 750 | $ | 805 | $ | — | $ | — | |||||||||||||||
6.625% Senior Notes due 2034 | $ | 1,000 | $ | 970 | $ | — | $ | — | |||||||||||||||
Note 10 - Earnings Per Share
Basic net income or loss per common share is calculated by dividing net income or loss available to common stockholders by the basic weighted-average number of common shares outstanding for the respective period. Diluted net income or loss per common share is calculated by dividing net income or loss available to common stockholders by the diluted weighted-average number of common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities for this calculation consist primarily of non-vested restricted stock units (“RSU” or “RSUs”) and contingent performance share units (“PSU” or “PSUs”), which were measured using the treasury stock method as presented below. Refer to Note 12 - Stock-Based Compensation in this report and Note 9 - Earnings Per Share and Note 10 - Stock-Based Compensation in our 2025 Form 10-K for additional detail on these potentially dilutive securities.
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The following table sets forth the calculations of basic and diluted net income per common share:
| For the Three Months Ended September 30, | For the Nine Months Ended September 30, | ||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | ||||||||||||||||||||
| (in millions, except per share data) | |||||||||||||||||||||||
| Net income | $ | 93 | $ | 155 | $ | 829 | $ | 539 | |||||||||||||||
Basic weighted-average common shares outstanding (1) | 237 | 115 | 225 | 115 | |||||||||||||||||||
Dilutive effect of non-vested RSUs, contingent PSUs, and other | 2 | — | 1 | — | |||||||||||||||||||
| Diluted weighted-average common shares outstanding | 239 | 115 | 226 | 115 | |||||||||||||||||||
| Basic net income per common share | $ | 0.39 | $ | 1.35 | $ | 3.67 | $ | 4.70 | |||||||||||||||
| Diluted net income per common share | $ | 0.39 | $ | 1.35 | $ | 3.66 | $ | 4.69 | |||||||||||||||
____________________________________________
Note: Amounts may not calculate due to rounding.
(1) The nine months ended September 30, 2026, amount includes shares issued in connection with the Merger that were outstanding during a portion of that period.
Note 11 - Segment Reporting
We have one reportable segment: the oil, gas, and NGL exploration and production segment (“E&P Segment”), which operates exclusively in the United States. Following the Merger, management determined that we continue to operate as a single reportable segment. The E&P Segment constitutes all of the consolidated entity and the accompanying unaudited condensed consolidated financial statements and the notes to the accompanying unaudited condensed consolidated financial statements are representative of such amounts for the E&P Segment. Midstream operations acquired in the Merger are considered ancillary to, and are managed as part of, the E&P Segment.
Our Chief Operating Decision Maker (“CODM”) is the . The CODM uses net income as presented in the accompanying statements of operations to measure E&P Segment profit or loss, and to evaluate income generated from E&P Segment assets in deciding whether to reinvest profits into operational activities or to use profits for other purposes, such as debt reduction, acquisitions, or our Stock Repurchase Program. Additionally, net income is used to assess budget versus actual results and to benchmark against our competitors. The measure of segment assets is reported on the accompanying balance sheets as total assets, and capital expenditures are reported in the accompanying statements of cash flows.
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The following table summarizes our segment revenue, significant expenses, and net income during the periods presented:
For the Three Months Ended September 30, | For the Nine Months Ended September 30, | |||||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | |||||||||||||||||||||||
| (in millions) | ||||||||||||||||||||||||||
| Total operating revenues and other income | $ | 2,170 | $ | 812 | $ | 6,149 | $ | 2,449 | ||||||||||||||||||
| Less: | ||||||||||||||||||||||||||
| Lease operating expense | 280 | 112 | 757 | 325 | ||||||||||||||||||||||
| Transportation costs | 141 | 74 | 406 | 222 | ||||||||||||||||||||||
| Production taxes | 138 | 33 | 350 | 100 | ||||||||||||||||||||||
| Ad valorem tax expense | 15 | 10 | 45 | 30 | ||||||||||||||||||||||
Depletion, depreciation, and amortization | 590 | 325 | 1,614 | 888 | ||||||||||||||||||||||
| Exploration | 22 | 12 | 69 | 39 | ||||||||||||||||||||||
| General and administrative | 56 | 39 | 309 | 121 | ||||||||||||||||||||||
| Net derivative (gain) loss | 684 | (45) | 1,109 | (107) | ||||||||||||||||||||||
| Other operating expense | 8 | 5 | 56 | 12 | ||||||||||||||||||||||
| Interest expense | 116 | 43 | 340 | 130 | ||||||||||||||||||||||
Interest income (1) | (4) | (1) | (12) | (1) | ||||||||||||||||||||||
| Other non-operating expense | 1 | — | 4 | — | ||||||||||||||||||||||
| Income tax expense | 30 | 49 | 273 | 150 | ||||||||||||||||||||||
E&P Segment net income (2) | $ | 93 | $ | 155 | $ | 829 | $ | 539 | ||||||||||||||||||
___________________________________________
Note: Prior year amounts may not calculate due to rounding.
(1) Interest income is included in the Other non-operating income, net line item on the accompanying statements of operations.
(2) There are no reconciling items between net income presented in the accompanying statements of operations and E&P Segment net income.
Note 12 - Stock-Based Compensation
As of September 30, 2026, 1.2 million shares of common stock were available for grant under the SM Energy Company 2025 Equity Incentive Compensation Plan and 3.1 million shares were available for grant under the Civitas Resources, Inc. 2024 Long Term Incentive Plan acquired as part of the Merger. These amounts reflect decreases from the shares of common stock available for grant as of June 30, 2026, resulting from annual grants of RSUs and PSUs made during the three months ended September 30, 2026.
In connection with the closing of the Merger on January 30, 2026, we converted outstanding Civitas equity awards into RSUs of the Company. The converted awards were measured at fair value as of the Closing Date in accordance with ASC 805, and the portion attributable to post-combination service will be recognized as stock-based compensation in accordance with ASC Topic 718, Compensation—Stock Compensation.
In total, 2.5 million RSUs were issued in the conversion, with an aggregate fair value of $49 million. Of this amount, $20 million was attributable to future service and was recorded as unrecognized stock-based compensation, which will be recognized over the remaining requisite service periods of the awards. Other than the impact of the converted awards, there were no material changes to our stock-based compensation arrangements during the three and nine months ended September 30, 2026.
Note 13 - Restructuring Costs
During 2026, in connection with the Merger and the South Texas Divestiture, we announced workforce reductions to better align staffing levels and the organizational structure with our strategy. During the three and nine months ended September 30, 2026, we incurred restructuring costs of $1 million and $123 million, respectively, which are included in G&A expense in the accompanying statements of operations. These restructuring costs represent a component of total one-time Merger integration costs and consist primarily of employee severance and retention and accelerated vesting of stock-based compensation awards. As of September 30, 2026, we have incurred and paid substantially all expected restructuring costs.
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The following table summarizes restructuring cost activity during the nine months ended September 30, 2026, and our restructuring cost liabilities included in the accounts payable and accrued expenses line item in the accompanying balance sheets as of the dates presented:
| (in millions) | ||||||||
Balance as of December 31, 2025 | $ | — | ||||||
Restructuring costs incurred (1) | 123 | |||||||
| Restructuring costs paid or settled | (121) | |||||||
| Balance as of September 30, 2026 | $ | 2 | ||||||
___________________________________________
(1) Restructuring costs incurred exclude $36 million of other G&A integration costs including systems integration, advisory, and legal expenses, and salaries for transition employees.
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion includes forward-looking statements. Refer to the Cautionary Information about Forward-Looking Statements section of this report for important information about these types of statements. Throughout the following discussion, we explain changes between the three months ended September 30, 2026, and the three months ended June 30, 2026 (“sequential quarterly” or “sequentially”), and the year-to-date (“YTD”) change between the nine months ended September 30, 2026, and the nine months ended September 30, 2025 (“YTD 2026-over-YTD 2025”).
Overview of the Company
General Overview
Our purpose. Our purpose is to improve communities by providing affordable, reliable energy. We are a premier operator of top-tier assets, using state-of-the-art digital technology, data analytics, and artificial intelligence in our operations, and continually innovating to optimize capital efficiency and well performance, while reducing our impact on shared natural resources and operating efficiently, safely, and responsibly.
Strategic vision and value creation. Our asset portfolio consists of high-quality assets in the Midland Basin and Delaware Basin, both of which are part of the larger Permian Basin of West Texas and New Mexico; the DJ Basin of Northeast Colorado; the Maverick Basin of South Texas; and the Uinta Basin of Northeast Utah. We believe our assets are capable of generating strong returns in the current macroeconomic environment and provide resilience to commodity price risk and volatility. Through disciplined capital allocation, active portfolio management, and continued development and optimization, we seek to maximize returns and increase the long-term value of our asset portfolio.
Our long-term vision and strategy are focused on sustainably growing value for all of our stakeholders by maintaining and optimizing our high-quality asset portfolio, generating cash flows, and maintaining a strong balance sheet. Our team executes our strategy by prioritizing safety, technological innovation, and stewardship of natural resources, which are foundational to our corporate culture. Our near-term strategic focus is continuing to optimize operations across our multi-basin portfolio; maintaining safe operations; delivering consistent operational execution; maximizing free cash flow; and bolstering our balance sheet.
Responsible operations. We believe responsible operations and strong financial performance are mutually reinforcing. We are committed to operating safely and efficiently, managing environmental and operational risks, investing in our workforce, maintaining constructive relationships with the communities where we operate, and transparently reporting our performance. The Operations and Environmental, Health and Safety Committee of our Board of Directors assists the Board of Directors in overseeing operational performance, environmental stewardship, health and safety, sustainability reporting, and the management of operational and environmental risks. In addition, compensation for our executives and employees under certain aspects of our compensation plans is based in part on Company-wide performance metrics that include financial, operational, environmental, health and safety measures.
Merger with Civitas
On November 2, 2025, we entered into the Merger Agreement with Civitas. On January 27, 2026, our stockholders voted in favor of both proposals necessary to complete the Merger, which included approval of (i) the issuance of shares of SM Energy common stock to Civitas stockholders as contemplated by the Merger Agreement, and (ii) an amendment of our Restated Certificate of Incorporation to increase the number of authorized shares of our common stock from 200 million shares to 400 million shares.
On January 30, 2026, we completed the Merger in accordance with the terms of the Merger Agreement. Civitas was an independent exploration and production company focused on the acquisition, development, and production of crude oil and associated liquids-rich natural gas in the DJ Basin in Colorado and the Permian Basin in Texas and New Mexico. We believe that the Merger enhances our asset portfolio across high-return U.S. shale basins, enabling the realization of operational efficiencies and cost synergies and providing opportunities for increased free cash flow to drive long-term differentiated stockholder value.
Under the terms of the Merger Agreement, subject to certain exceptions, each share of Civitas common stock was converted into the right to receive 1.45 shares of SM Energy common stock, with cash paid in lieu of fractional shares. On January 30, 2026, we issued 124 million shares to holders of Civitas common stock, representing 52 percent of the shares of SM Energy’s common stock outstanding immediately following the closing of the Merger. Based on the closing price of SM Energy common stock on January 30, 2026, the total stock consideration was valued at $2.4 billion.
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South Texas Divestiture
On April 30, 2026, we completed the South Texas Divestiture. Subsequent to September 30, 2026, we completed the final post-closing settlement, resulting in total net cash proceeds of $894 million after final purchase price adjustments. The South Texas Divestiture substantially achieved our target of selling more than $1.0 billion in assets within one year of the completion of the Merger, which has enabled us to reduce debt and strengthen our capital structure. See Note 2 - Mergers, Acquisitions, and Divestitures in Part I, Item 1 of this report for additional discussion.
Debt Optimization
During the nine months ended September 30, 2026, we strengthened our debt maturity profile and reduced higher-coupon debt through the following transactions:
•We issued our 2034 Senior Notes and used the majority of the net proceeds to repurchase $894 million in aggregate principal amount of certain of our higher-coupon 2028 Civitas Senior Notes.
•We used the net cash proceeds from the South Texas Divestiture to redeem, at par, all $819 million aggregate principal amount outstanding of our 2026 Civitas Senior Notes and our 2026 Senior Notes.
•We used cash flows from operations to redeem, at par, all $417 million aggregate principal amount outstanding of our 2027 Senior Notes.
As of September 30, 2026, we had no outstanding borrowings under our revolving credit facility. After these transactions, we have no Senior Notes maturities until mid-2028. Subsequent to September 30, 2026, we completed our semi-annual borrowing base redetermination, reaffirming our borrowing base and our aggregate lender commitments at their existing levels. See Note 6 - Long-Term Debt in Part I, Item 1 of this report for additional discussion.
Areas of Operations
Our oil-weighted, liquids-rich asset base spans four operating areas within the United States. Each area described below provides future development and exploration opportunities within multiple proven formations, and gas composition across all areas is amenable to processing for NGL extraction.
Our Permian Basin assets comprise approximately 230,000 net acres located in the Midland Basin and Delaware Basin of West Texas and New Mexico (collectively referred to as the “Permian Basin”) with future development and exploration opportunities in the Spraberry, Wolfcamp, and Woodford-Barnett formations in the Midland Basin; and the Avalon, Bone Spring, and Wolfcamp formations in the Delaware Basin.
Our DJ Basin assets comprise approximately 300,000 net acres located primarily in northeastern Colorado (“DJ Basin”) with future development and exploration opportunities in the Niobrara and Codell formations.
Our South Texas assets comprise approximately 95,000 net acres located in Dimmit and Webb counties, Texas (“South Texas”) with future development and exploration opportunities across our overlapping acreage position covering a portion of the western Eagle Ford shale and Austin Chalk formations.
Our Uinta Basin assets comprise approximately 99,000 net acres in northeastern Utah (“Uinta Basin”), including acreage in Utah previously reported as other non-core acreage that has been reclassified to the Uinta Basin, with future development and exploration opportunities in the Lower Green River and Wasatch formations.
Market Trends and Uncertainties
During the nine months ended September 30, 2026, benchmark oil prices were substantially higher than the prior year period, primarily due to global supply disruptions and heightened risk associated with War and Geopolitical Instability. Despite sustained higher near-term prices, we have maintained our disciplined approach to capital allocation and have not materially altered our 2026 development program. We continue to monitor commodity market developments, including potential inflationary pressures on oilfield services, materials, and other key inputs associated with the elevated commodity price environment and the ongoing conflict in the Middle East.
Benchmark gas prices have fluctuated throughout 2026. Regional basis differentials in the Permian Basin and the DJ Basin have adversely impacted our realized gas prices, particularly during the first half of 2026. These differentials moderated during the third quarter, although regional pricing constraints continue to influence our realized prices. In the Permian Basin, gas gathering and takeaway capacity constraints contributed to widening basis differentials at the Waha hub during the first half of 2026, with differentials improving late in the second quarter and stabilizing in the third quarter of 2026 as new pipeline capacity entered service. We expect additional pipeline capacity to come online during the remainder of 2026 to further support takeaway out of the Permian Basin. In the DJ Basin, differentials at CIG Rockies widened during the first half of 2026, reflecting elevated regional storage following a mild winter,
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as well as lower demand during the spring shoulder season. Differentials narrowed through the late second and third quarters as regional demand strengthened.
Commodity prices and broader financial markets continue to be influenced by geopolitical developments, global supply and demand fundamentals, production decisions by the Organization of the Petroleum Exporting Countries (“OPEC”) plus other non-OPEC oil producing countries (collectively referred to as “OPEC+”), and broader economic and monetary conditions. The ongoing conflict in the Middle East, including disruptions to energy infrastructure and shipping routes such as the Strait of Hormuz, has contributed to elevated oil prices and increased uncertainty regarding future commodity market conditions.
These developments, together with evolving U.S. and international trade policies, including tariffs and other trade restrictions, may also contribute to inflationary pressures, supply chain disruptions, and increased costs for oilfield services, equipment, materials and other key inputs. We continue to monitor these conditions and their potential effects on our operating costs, capital expenditures, and development economics.
The duration and magnitude of these factors remain uncertain. Changes in commodity prices, regional pricing differentials, operating costs and broader economic conditions could materially affect our business, financial condition, and results of operations. In addition, sustained declines in oil, gas, and NGL prices could result in impairments of certain oil and gas properties.
Third Quarter 2026 Overview and Outlook for the Remainder of 2026
During the third quarter of 2026:
•We substantially completed the integration of the Merger across all key operational and organizational workstreams and have captured targeted synergies from our combined operations, with remaining integration activities expected to continue in the normal course.
•We redeemed the entire $417 million aggregate principal amount outstanding of our 2027 Senior Notes, at par.
•We repurchased and subsequently retired 2.3 million shares of our common stock at a cost of $81 million, excluding excise taxes, commissions, and fees.
Refer to Note 2 - Mergers, Acquisitions, and Divestitures, Note 5 - Equity, and Note 6 - Long-Term Debt in Part I, Item 1 of this report for additional discussion.
Financial and Operational Results. Oil, gas, and NGL production revenue remained relatively flat sequentially at $2.2 billion. Average net daily equivalent production decreased two percent sequentially to 433.1 MBOE per day for the three months ended September 30, 2026, compared with 439.7 MBOE per day for the three months ended June 30, 2026. This decrease reflects the impact of the divestiture of a portion of our South Texas assets which contributed one month of production in the prior quarter, partially offset by a net increase in average net daily equivalent production from our retained assets, including our retained South Texas assets. Total realized price per BOE, before the effect of net derivative settlements (“realized price” or “realized prices”) increased slightly sequentially, as higher realized natural gas prices, resulting from narrower price differentials at Waha, and higher realized NGL prices were largely offset by lower benchmark oil prices. Oil, gas, and NGL production expense increased three percent sequentially to $574 million for the three months ended September 30, 2026, compared with $556 million for the three months ended June 30, 2026.
We recorded a net derivative loss of $684 million and a net derivative gain of $272 million for the three months ended September 30, 2026, and June 30, 2026, respectively. Included within these amounts are net derivative settlement losses of $207 million and $220 million for the three months ended September 30, 2026, and June 30, 2026, respectively.
Operational and financial activities during the three months ended September 30, 2026, resulted in the following:
•Net income of $93 million, or $0.39 per diluted share, compared with net income of $1.1 billion, or $4.46 per diluted share, for the three months ended June 30, 2026, which included an estimated gain of $262 million related to the South Texas Divestiture.
•Net cash provided by operating activities of $1.1 billion remained unchanged compared with the three months ended June 30, 2026.
•Adjusted EBITDAX, a non-GAAP financial measure, of $1.3 billion, compared with $1.4 billion for the three months ended June 30, 2026. Refer to the caption Non-GAAP Financial Measures below for additional discussion and our definition of adjusted EBITDAX and reconciliations to net income and net cash provided by operating activities.
Refer to Overview of Selected Production and Financial Information, Including Trends and Comparison of Financial Results and Trends Between the Three Months Ended September 30, 2026, and June 30, 2026, and Between the Nine Months Ended September 30, 2026, and 2025 below for additional discussion.
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Operational Activities. Our capital program for 2026 is expected to be approximately $2.75 billion, excluding acquisitions. We remain focused on applying our strength in geosciences and development optimization to highly economic oil and liquids-rich development projects in our areas of operations that support our priority of strategic inventory replacement and growth. Refer to Overview of Liquidity and Capital Resources below for discussion of how we expect to fund the remainder of our 2026 capital program.
During the three and nine months ended September 30, 2026, costs incurred in oil and gas property acquisition, exploration, and development activities, whether capitalized or expensed, totaled $782 million and $2.2 billion, respectively. Total costs incurred includes activity in our core areas of operations, corporate charges incurred in exploration activities, and costs related to exploration efforts outside of our core areas of operation.
In our Permian Basin program, we operated an average of six drilling rigs and two completion crews during the third quarter of 2026. Average net daily equivalent production decreased sequentially by five percent to 222.7 MBOE per day. Costs incurred during the three months ended September 30, 2026, totaled $394 million, or 50 percent of our total costs incurred for the period. We anticipate operating an average of six drilling rigs and an average of one completion crew for the remainder of 2026.
In our DJ Basin program, we operated one drilling rig and one completion crew during the third quarter of 2026. Average net daily equivalent production remained flat sequentially at 119.4 MBOE per day. Costs incurred during the three months ended September 30, 2026, totaled $145 million, or 19 percent of our total costs incurred for the period. We anticipate operating an average of one drilling rig for the remainder of 2026 and one completion crew for a portion of the fourth quarter of 2026.
In our South Texas program, we operated one drilling rig and averaged one completion crew during the third quarter of 2026. Average net daily equivalent production remained flat sequentially at 46.3 MBOE per day, despite the second quarter benefiting from one month of production from the divested South Texas assets. Costs incurred during the three months ended September 30, 2026, totaled $95 million, or 12 percent of our total costs incurred for the period. We anticipate operating one drilling rig and no completion crews for the remainder of 2026.
In our Uinta Basin program, we operated an average of two drilling rigs and one completion crew during the third quarter of 2026. Average net daily equivalent production increased sequentially by 12 percent to 44.7 MBOE per day. Costs incurred during the three months ended September 30, 2026, totaled $129 million, or 16 percent of our total costs incurred for the period. We anticipate operating an average of three drilling rigs and one completion crew during the remainder of 2026.
The table below provides a quarterly summary of changes in our drilled but not completed well count and current year drilling and completion activity in our operated programs by quarter:
Permian Basin | DJ Basin | South Texas | Uinta Basin | Total | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | Gross | Net | Gross | Net | ||||||||||||||||||||||||||||||||||||||||||||||||||
Wells drilled but not completed at December 31, 2025 | 15 | 12 | — | — | 25 | 24 | 38 | 28 | 78 | 64 | |||||||||||||||||||||||||||||||||||||||||||||||||
Wells acquired (1) | 40 | 33 | 43 | 41 | — | — | — | — | 83 | 74 | |||||||||||||||||||||||||||||||||||||||||||||||||
Wells drilled (2) | 31 | 28 | 16 | 15 | 12 | 12 | 11 | 7 | 70 | 62 | |||||||||||||||||||||||||||||||||||||||||||||||||
Wells completed (2) | (26) | (23) | (25) | (23) | (12) | (11) | (12) | (9) | (75) | (66) | |||||||||||||||||||||||||||||||||||||||||||||||||
Wells drilled but not completed at March 31, 2026 | 60 | 50 | 34 | 33 | 25 | 25 | 37 | 26 | 156 | 134 | |||||||||||||||||||||||||||||||||||||||||||||||||
| Wells drilled | 44 | 37 | 22 | 18 | 11 | 9 | 10 | 6 | 87 | 70 | |||||||||||||||||||||||||||||||||||||||||||||||||
| Wells completed | (48) | (39) | (12) | (12) | (13) | (13) | (9) | (7) | (82) | (71) | |||||||||||||||||||||||||||||||||||||||||||||||||
Wells sold (3) | — | — | — | — | (10) | (10) | — | — | (10) | (10) | |||||||||||||||||||||||||||||||||||||||||||||||||
Other (4) | — | 1 | — | 1 | — | — | — | — | — | 2 | |||||||||||||||||||||||||||||||||||||||||||||||||
Wells drilled but not completed at June 30, 2026 | 56 | 49 | 44 | 40 | 13 | 11 | 38 | 25 | 151 | 125 | |||||||||||||||||||||||||||||||||||||||||||||||||
| Wells drilled | 37 | 29 | 11 | 8 | 7 | 7 | 9 | 7 | 64 | 51 | |||||||||||||||||||||||||||||||||||||||||||||||||
| Wells completed | (33) | (31) | (25) | (24) | (6) | (5) | (14) | (10) | (78) | (70) | |||||||||||||||||||||||||||||||||||||||||||||||||
| Wells drilled but not completed at September 30, 2026 | 60 | 47 | 30 | 24 | 14 | 13 | 33 | 22 | 137 | 106 | |||||||||||||||||||||||||||||||||||||||||||||||||
____________________________________________
(1) We acquired these drilled but not completed wells as part of the Merger on January 30, 2026.
(2) All drilling and completion activity related to the acquired assets in the Permian Basin and DJ Basin occurred after the Closing Date of the Merger.
(3) On April 30, 2026, as part of the South Texas Divestiture, we sold 10 gross (10 net) drilled but not completed wells.
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(4) Includes adjustments related to normal business activities, including working interest changes for certain existing drilled but not completed wells and for certain wells completed during the second quarter of 2026. Working interest changes can result from divestitures, joint development agreements, farm-outs, and other activities.
Production Results. The table below presents the disaggregation of our net production volumes by product type for each of our assets for the periods presented. The Permian Basin and DJ Basin results include production from properties acquired in the Merger after the Closing Date of January 30, 2026.
| For the Three Months Ended | For the Nine Months Ended | ||||||||||||||||||||||
| September 30, 2026 | June 30, 2026 | September 30, 2026 | September 30, 2025 | ||||||||||||||||||||
Permian Basin Net Production: | |||||||||||||||||||||||
| Oil (MMBbl) | 10.9 | 11.5 | 31.8 | 14.3 | |||||||||||||||||||
| Gas (Bcf) | 50.3 | 50.2 | 137.9 | 48.9 | |||||||||||||||||||
| NGLs (MMBbl) | 1.2 | 1.3 | 3.4 | — | |||||||||||||||||||
| Equivalent (MMBOE) | 20.5 | 21.2 | 58.2 | 22.5 | |||||||||||||||||||
| Average net daily equivalent (MBOE per day) | 222.7 | 233.5 | 213.1 | 82.4 | |||||||||||||||||||
| Relative percentage | 51 | % | 53 | % | 51 | % | 40 | % | |||||||||||||||
DJ Basin Net Production: | |||||||||||||||||||||||
| Oil (MMBbl) | 5.2 | 5.0 | 13.6 | — | |||||||||||||||||||
| Gas (Bcf) | 22.7 | 23.7 | 62.0 | — | |||||||||||||||||||
| NGLs (MMBbl) | 2.0 | 1.9 | 5.2 | — | |||||||||||||||||||
| Equivalent (MMBOE) | 11.0 | 10.8 | 29.1 | — | |||||||||||||||||||
| Average net daily equivalent (MBOE per day) | 119.4 | 118.8 | 106.7 | — | |||||||||||||||||||
| Relative percentage | 28 | % | 27 | % | 26 | % | — | % | |||||||||||||||
| South Texas Net Production: | |||||||||||||||||||||||
| Oil (MMBbl) | 1.5 | 1.3 | 4.1 | 5.5 | |||||||||||||||||||
| Gas (Bcf) | 7.6 | 9.8 | 33.7 | 53.0 | |||||||||||||||||||
| NGLs (MMBbl) | 1.5 | 1.4 | 4.9 | 7.6 | |||||||||||||||||||
| Equivalent (MMBOE) | 4.3 | 4.3 | 14.7 | 22.0 | |||||||||||||||||||
| Average net daily equivalent (MBOE per day) | 46.3 | 47.4 | 53.8 | 80.4 | |||||||||||||||||||
| Relative percentage | 11 | % | 11 | % | 13 | % | 39 | % | |||||||||||||||
Uinta Basin Net Production: | |||||||||||||||||||||||
| Oil (MMBbl) | 3.5 | 3.1 | 9.6 | 10.5 | |||||||||||||||||||
| Gas (Bcf) | 3.7 | 3.1 | 9.9 | 9.2 | |||||||||||||||||||
| NGLs (MMBbl) | — | — | — | — | |||||||||||||||||||
| Equivalent (MMBOE) | 4.1 | 3.6 | 11.3 | 12.0 | |||||||||||||||||||
| Average net daily equivalent (MBOE per day) | 44.7 | 40.1 | 41.3 | 44.0 | |||||||||||||||||||
| Relative percentage | 10 | % | 9 | % | 10 | % | 21 | % | |||||||||||||||
| Total Net Production: | |||||||||||||||||||||||
| Oil (MMBbl) | 21.2 | 20.9 | 59.2 | 30.3 | |||||||||||||||||||
| Gas (Bcf) | 84.4 | 86.8 | 243.5 | 111.1 | |||||||||||||||||||
| NGLs (MMBbl) | 4.6 | 4.6 | 13.5 | 7.6 | |||||||||||||||||||
| Equivalent (MMBOE) | 39.8 | 40.0 | 113.3 | 56.5 | |||||||||||||||||||
| Average net daily equivalent (MBOE per day) | 433.1 | 439.7 | 414.9 | 206.8 | |||||||||||||||||||
____________________________________________
Note: Amounts may not calculate due to rounding.
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Refer to Overview of Selected Production and Financial Information, Including Trends and Comparison of Financial Results and Trends Between the Three Months Ended September 30, 2026, and June 30, 2026, and Between the Nine Months Ended September 30, 2026, and 2025 below for discussion of production.
Oil, Gas, and NGL Prices
Our financial condition and the results of our operations are significantly affected by the prices we receive for our oil, gas, and NGL production, which can fluctuate dramatically. When we refer to realized oil, gas, and NGL prices below, the disclosed price represents the average price for the respective period, before the effect of net derivative settlements. While quoted NYMEX oil and gas and OPIS NGL prices are generally used as a basis for comparison within our industry, the prices we receive are affected by quality, energy content, location and transportation differentials, and contracted pricing benchmarks for these products.
The following table summarizes commodity price data, and the effect of net derivative settlements, for the periods presented:
| For the Three Months Ended | |||||||||||||||||
| September 30, 2026 | June 30, 2026 | September 30, 2025 | |||||||||||||||
| Oil (per Bbl): | |||||||||||||||||
| Average NYMEX contract monthly price | $ | 85.79 | $ | 92.79 | $ | 64.93 | |||||||||||
| Realized price | $ | 85.76 | $ | 96.85 | $ | 63.83 | |||||||||||
| Effect of oil net derivative settlements | $ | (11.84) | $ | (16.23) | $ | 1.57 | |||||||||||
| Gas: | |||||||||||||||||
| Average NYMEX monthly settle price (per MMBtu) | $ | 2.95 | $ | 2.90 | $ | 3.07 | |||||||||||
| Realized price (per Mcf) | $ | 2.48 | $ | 0.17 | $ | 2.19 | |||||||||||
| Effect of gas net derivative settlements (per Mcf) | $ | 0.51 | $ | 1.37 | $ | 0.58 | |||||||||||
| NGLs (per Bbl): | |||||||||||||||||
Average OPIS price (1) | $ | 31.64 | $ | 31.33 | $ | 25.58 | |||||||||||
| Realized price | $ | 29.40 | $ | 24.69 | $ | 20.79 | |||||||||||
| Effect of NGL net derivative settlements | $ | 0.04 | $ | 0.14 | $ | — | |||||||||||
____________________________________________
(1) Average OPIS price per barrel of NGL, historical or strip, assumes a composite barrel product mix of 42% ethane, 28% propane, 6% isobutane, 11% normal butane, and 13% natural gasoline. This product mix represents the industry standard composite barrel and does not necessarily represent our product mix for NGL production. Realized prices reflect our actual product mix.
Commodity prices remain subject to uncertainty arising from global supply and demand fundamentals, geopolitical developments and broader economic conditions. While these factors influence benchmark prices, our realized prices are also affected by regional supply and demand, basis differentials, and transportation and infrastructure constraints, including capacity limitations and outages in or affecting our operating areas. We continue to monitor these conditions and their potential impacts on our realized prices and financial results. Refer to Market Trends and Uncertainties above for additional discussion of factors impacting pricing.
The following table summarizes 12-month strip prices for NYMEX WTI oil, NYMEX Henry Hub gas, and OPIS NGLs as of October 22, 2026, and September 30, 2026:
| As of October 22, 2026 | As of September 30, 2026 | ||||||||||
| NYMEX WTI oil (per Bbl) | $ | 90.76 | $ | 83.62 | |||||||
| NYMEX Henry Hub gas (per MMBtu) | $ | 2.90 | $ | 3.08 | |||||||
| OPIS NGLs (per Bbl) | $ | 36.25 | $ | 31.91 | |||||||
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We use financial derivative instruments as part of our financial risk management program. We have a financial risk management policy governing our use of derivatives, and decisions regarding entering into commodity derivative contracts are overseen by a financial risk management committee consisting of certain senior executive officers and finance personnel. The volume of our expected production that we cover with commodity derivative contracts is determined by our balance sheet objectives, capital allocation priorities, anticipated development activity and associated capital requirements, and prevailing commodity market conditions, including available future prices and derivative structures. Our current commodity derivative contracts partially reduce our exposure to volatility in commodity prices and basis differentials in the near term. Our use of costless collars for a portion of our commodity derivative contracts allows us to participate in some of the upward movements in oil and gas prices while also setting a price floor below which we are insulated from further price decreases. Refer to Note 8 - Derivative Financial Instruments in Part I, Item 1 of this report and to Commodity Price Risk in Overview of Liquidity and Capital Resources below for additional information regarding our oil, gas, and NGL derivatives.
Financial Results of Operations and Additional Comparative Data
The tables below provide information regarding selected production and financial information and selected performance metrics for the three months ended September 30, 2026, and the preceding three quarters.
Selected Production and Financial Information
| For the Three Months Ended | |||||||||||||||||||||||
| September 30, | June 30, | March 31, | December 31, | ||||||||||||||||||||
| 2026 | 2026 | 2026 | 2025 | ||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||
| Net production (MMBOE) | 39.8 | 40.0 | 33.4 | 19.0 | |||||||||||||||||||
| Oil, gas, and NGL production revenue | $ | 2,160 | $ | 2,156 | $ | 1,477 | $ | 703 | |||||||||||||||
| Oil, gas, and NGL production expense | $ | 574 | $ | 556 | $ | 428 | $ | 207 | |||||||||||||||
Depletion, depreciation, and amortization | $ | 590 | $ | 592 | $ | 432 | $ | 319 | |||||||||||||||
| Exploration | $ | 22 | $ | 21 | $ | 26 | $ | 18 | |||||||||||||||
| General and administrative | $ | 56 | $ | 79 | $ | 174 | $ | 40 | |||||||||||||||
| Net income (loss) | $ | 93 | $ | 1,071 | $ | (335) | $ | 109 | |||||||||||||||
Selected Performance Metrics
| For the Three Months Ended | |||||||||||||||||||||||
| September 30, | June 30, | March 31, | December 31, | ||||||||||||||||||||
| 2026 | 2026 | 2026 | 2025 | ||||||||||||||||||||
| Average net daily equivalent production (MBOE per day) | 433.1 | 439.7 | 371.2 | 206.9 | |||||||||||||||||||
| Lease operating expense (per BOE) | $ | 7.02 | $ | 6.71 | $ | 6.25 | $ | 5.55 | |||||||||||||||
| Transportation costs (per BOE) | $ | 3.53 | $ | 3.57 | $ | 3.65 | $ | 3.67 | |||||||||||||||
| Production taxes as a percent of oil, gas, and NGL production revenue | 6.4 | % | 6.1 | % | 5.5 | % | 3.8 | % | |||||||||||||||
| Ad valorem tax expense (per BOE) | $ | 0.38 | $ | 0.37 | $ | 0.47 | $ | 0.23 | |||||||||||||||
Depletion, depreciation, and amortization (per BOE) | $ | 14.81 | $ | 14.81 | $ | 12.91 | $ | 16.73 | |||||||||||||||
| General and administrative (per BOE) | $ | 1.40 | $ | 1.98 | $ | 5.20 | $ | 2.10 | |||||||||||||||
____________________________________________
Note: Amounts may not calculate due to rounding.
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Overview of Selected Production and Financial Information, Including Trends
| For the Three Months Ended | Amount Change Between Periods | Percent Change Between Periods | For the Nine Months Ended | Amount Change Between Periods | Percent Change Between Periods | ||||||||||||||||||||||||||||||||||||||||||
| September 30, 2026 | June 30, 2026 | September 30, 2026 | September 30, 2025 | ||||||||||||||||||||||||||||||||||||||||||||
Net production volumes: (1) | |||||||||||||||||||||||||||||||||||||||||||||||
| Oil (MMBbl) | 21.2 | 20.9 | 0.3 | 1 | % | 59.2 | 30.3 | 28.9 | 95 | % | |||||||||||||||||||||||||||||||||||||
| Gas (Bcf) | 84.4 | 86.8 | (2.4) | (3) | % | 243.5 | 111.1 | 132.4 | 119 | % | |||||||||||||||||||||||||||||||||||||
| NGLs (MMBbl) | 4.6 | 4.6 | — | (1) | % | 13.5 | 7.6 | 5.9 | 77 | % | |||||||||||||||||||||||||||||||||||||
| Equivalent (MMBOE) | 39.8 | 40.0 | (0.2) | — | % | 113.3 | 56.5 | 56.8 | 101 | % | |||||||||||||||||||||||||||||||||||||
Average net daily production: (1) | |||||||||||||||||||||||||||||||||||||||||||||||
| Oil (MBbl per day) | 230.2 | 229.8 | 0.3 | — | % | 216.9 | 111.2 | 105.8 | 95 | % | |||||||||||||||||||||||||||||||||||||
| Gas (MMcf per day) | 917.0 | 953.7 | (36.7) | (4) | % | 892.0 | 406.9 | 485.1 | 119 | % | |||||||||||||||||||||||||||||||||||||
| NGLs (MBbl per day) | 50.1 | 51.0 | (0.9) | (2) | % | 49.3 | 27.8 | 21.5 | 77 | % | |||||||||||||||||||||||||||||||||||||
| Equivalent (MBOE per day) | 433.1 | 439.7 | (6.7) | (2) | % | 414.9 | 206.8 | 208.1 | 101 | % | |||||||||||||||||||||||||||||||||||||
Oil, gas, and NGL production revenue (in millions): (1) | |||||||||||||||||||||||||||||||||||||||||||||||
| Oil production revenue | $ | 1,816 | $ | 2,026 | $ | (210) | (10) | % | $ | 5,104 | $ | 1,981 | $ | 3,123 | 158 | % | |||||||||||||||||||||||||||||||
| Gas production revenue | 209 | 15 | 194 | 1,280 | % | 348 | 282 | 66 | 23 | % | |||||||||||||||||||||||||||||||||||||
| NGL production revenue | 135 | 115 | 21 | 18 | % | 341 | 172 | 169 | 98 | % | |||||||||||||||||||||||||||||||||||||
| Total oil, gas, and NGL production revenue | $ | 2,160 | $ | 2,156 | $ | 5 | — | % | $ | 5,793 | $ | 2,436 | $ | 3,358 | 138 | % | |||||||||||||||||||||||||||||||
Oil, gas, and NGL production expense (in millions): (1) | |||||||||||||||||||||||||||||||||||||||||||||||
| Lease operating expense | $ | 280 | $ | 268 | $ | 11 | 4 | % | $ | 757 | $ | 325 | $ | 432 | 133 | % | |||||||||||||||||||||||||||||||
| Transportation costs | 141 | 143 | (2) | (2) | % | 406 | 222 | 183 | 82 | % | |||||||||||||||||||||||||||||||||||||
| Production taxes | 138 | 131 | 8 | 6 | % | 350 | 100 | 249 | 249 | % | |||||||||||||||||||||||||||||||||||||
| Ad valorem tax expense | 15 | 14 | 1 | 3 | % | 45 | 30 | 15 | 51 | % | |||||||||||||||||||||||||||||||||||||
| Total oil, gas, and NGL production expense | $ | 574 | $ | 556 | $ | 18 | 3 | % | $ | 1,558 | $ | 678 | $ | 880 | 130 | % | |||||||||||||||||||||||||||||||
| Realized price: | |||||||||||||||||||||||||||||||||||||||||||||||
| Oil (per Bbl) | $ | 85.76 | $ | 96.85 | $ | (11.09) | (11) | % | $ | 86.19 | $ | 65.28 | $ | 20.91 | 32 | % | |||||||||||||||||||||||||||||||
| Gas (per Mcf) | $ | 2.48 | $ | 0.17 | $ | 2.31 | 1,359 | % | $ | 1.43 | $ | 2.54 | $ | (1.11) | (44) | % | |||||||||||||||||||||||||||||||
| NGLs (per Bbl) | $ | 29.40 | $ | 24.69 | $ | 4.71 | 19 | % | $ | 25.33 | $ | 22.73 | $ | 2.60 | 11 | % | |||||||||||||||||||||||||||||||
| Per BOE | $ | 54.23 | $ | 53.86 | $ | 0.37 | 1 | % | $ | 51.15 | $ | 43.15 | $ | 8.00 | 19 | % | |||||||||||||||||||||||||||||||
Per BOE data: (1) | |||||||||||||||||||||||||||||||||||||||||||||||
| Oil, gas, and NGL production expense: | |||||||||||||||||||||||||||||||||||||||||||||||
| Lease operating expense | $ | 7.02 | $ | 6.71 | $ | 0.31 | 5 | % | $ | 6.69 | $ | 5.76 | $ | 0.93 | 16 | % | |||||||||||||||||||||||||||||||
| Transportation costs | 3.53 | 3.57 | (0.04) | (1) | % | 3.58 | 3.94 | (0.36) | (9) | % | |||||||||||||||||||||||||||||||||||||
| Production taxes | 3.47 | 3.25 | 0.22 | 7 | % | 3.09 | 1.78 | 1.31 | 74 | % | |||||||||||||||||||||||||||||||||||||
| Ad valorem tax expense | 0.38 | 0.37 | 0.01 | 3 | % | 0.40 | 0.53 | (0.13) | (25) | % | |||||||||||||||||||||||||||||||||||||
| Total oil, gas, and NGL production expense | $ | 14.40 | $ | 13.90 | $ | 0.50 | 4 | % | $ | 13.75 | $ | 12.01 | $ | 1.74 | 14 | % | |||||||||||||||||||||||||||||||
Depletion, depreciation, and amortization | $ | 14.81 | $ | 14.81 | $ | — | — | % | $ | 14.25 | $ | 15.73 | $ | (1.48) | (9) | % | |||||||||||||||||||||||||||||||
General and administrative (2) | $ | 1.40 | $ | 1.98 | $ | (0.58) | (29) | % | $ | 2.72 | $ | 2.14 | $ | 0.58 | 27 | % | |||||||||||||||||||||||||||||||
Net derivative settlement gain (loss) (3) | $ | (5.20) | $ | (5.50) | $ | 0.30 | 5 | % | $ | (4.04) | $ | 1.53 | $ | (5.57) | (364) | % | |||||||||||||||||||||||||||||||
Earnings per share information (in millions, except per share data): (4) | |||||||||||||||||||||||||||||||||||||||||||||||
| Basic weighted-average common shares outstanding | 237 | 239 | (2) | (1) | % | 225 | 115 | 110 | 96 | % | |||||||||||||||||||||||||||||||||||||
| Diluted weighted-average common shares outstanding | 239 | 240 | (1) | — | % | 226 | 115 | 111 | 97 | % | |||||||||||||||||||||||||||||||||||||
| Basic net income per common share | $ | 0.39 | $ | 4.48 | $ | (4.09) | (91) | % | $ | 3.67 | $ | 4.70 | $ | (1.03) | (22) | % | |||||||||||||||||||||||||||||||
| Diluted net income per common share | $ | 0.39 | $ | 4.46 | $ | (4.07) | (91) | % | $ | 3.66 | $ | 4.69 | $ | (1.03) | (22) | % | |||||||||||||||||||||||||||||||
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___________________________________________
Note: Results for the nine months ended September 30, 2026, reflect activity from the assets acquired in the Merger only after the Closing Date of January 30, 2026, and reflect activity from the assets sold in the South Texas Divestiture only for the period from January 1, 2026, through April 30, 2026.
(1) Amounts and percentage changes may not calculate due to rounding.
(2) G&A expense per BOE for the three and nine months ended September 30, 2026, includes one-time Merger-related integration costs, the majority of which were incurred during the six months ended June 30, 2026. See below and refer to Comparison of Financial Results and Trends Between the Three Months Ended September 30, 2026, and June 30, 2026, and Between the Nine Months Ended September 30, 2026, and 2025 for additional discussion.
(3) Net derivative settlements for the three months ended September 30, 2026, and for the nine months ended September 30, 2026, and 2025, are included within the net derivative (gain) loss line item in the accompanying statements of operations.
(4) Refer to Note 10 - Earnings Per Share in Part I, Item 1 of this report for additional discussion.
The Merger, which closed on January 30, 2026, and the South Texas Divestiture, which closed on April 30, 2026, have materially affected our operating and financial results and will continue to affect comparability with prior periods. The addition of the Civitas assets and operations has increased production volumes and revenues and has impacted oil, gas, and NGL production expense, G&A expense, and other expense categories with the nine months ended September 30, 2026, reflecting eight months of activity from the acquired assets. With respect to the South Texas Divestiture, the three months ended June 30, 2026, include one month of activity from the divested assets prior to the April 30, 2026 closing date, while the three months ended September 30, 2026, reflect only our retained South Texas assets. The nine months ended September 30, 2026, include four months of activity from the divested assets. The magnitude and timing of ongoing impacts will depend, in part, on operating performance, commodity prices, and other factors and may not be directly comparable to our historical results.
Average net daily equivalent production for the three months ended September 30, 2026, decreased two percent sequentially to 433.1 MBOE per day, compared with 439.7 MBOE per day for the three months ended June 30, 2026. This decrease reflects the impact of the divestiture of a portion of our South Texas assets which contributed one month of production in the prior quarter, partially offset by a net increase in average net daily equivalent production from our retained assets, including our retained South Texas assets. Average net daily production increased 101 percent YTD 2026-over-YTD 2025 primarily driven by production from assets acquired in the Merger.
We present certain information on a per BOE basis to evaluate our performance relative to our peers and to identify and measure trends we believe may require additional analysis and discussion.
Our realized price on a per BOE basis increased slightly sequentially as higher realized natural gas prices, primarily resulting from narrower price differentials at Waha and higher realized NGL prices, were largely offset by lower benchmark oil prices. Our realized price on a per BOE basis increased 19 percent YTD 2026-over-YTD 2025 primarily due to increases in benchmark oil prices, partially offset by decreases in realized gas prices driven by unfavorable price differentials at Waha. We recognized net losses on the settlement of our commodity derivative contracts of $5.20 per BOE and $5.50 per BOE during the three months ended September 30, 2026, and June 30, 2026, respectively. During the nine months ended September 30, 2026, and 2025, we recognized a net loss of $4.04 per BOE and a net gain of $1.53 per BOE, respectively.
Lease operating expense (“LOE”) per BOE increased five percent sequentially, primarily due to the timing of workover activity and a shift in our geographic production mix toward higher-cost assets. LOE per BOE increased 16 percent YTD 2026-over-YTD 2025 primarily as a result of assets acquired in the Merger, which have a higher LOE per BOE profile relative to our pre-Merger asset base. For the full-year 2026, we expect LOE per BOE to increase compared with 2025, driven by the inclusion of higher-cost acquired assets and a shift in production mix across our assets following the South Texas Divestiture. We expect to realize operational and cost synergies which will partially offset this increase. We anticipate volatility in LOE per BOE as a result of changes in geographic and commodity mix of our production, timing of workover projects, changes in service provider costs, integration-related activities and broader industry conditions, all of which affect total LOE.
Transportation costs per BOE remained flat sequentially. Transportation costs per BOE decreased nine percent YTD 2026-over-YTD 2025 primarily due to changes in our production mix across our assets as a result of the Merger and the South Texas Divestiture. We expect transportation costs to vary based on production volumes and commodity mix, contractual transportation agreements, applicable rates, and the utilization of transportation capacity across our operating areas. On a per BOE basis, we expect transportation costs for 2026 to decrease slightly compared with 2025.
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Production tax expense per BOE increased seven percent sequentially, primarily due to higher production taxes attributable to our DJ Basin assets. Production tax expense per BOE increased 74 percent YTD 2026-over-YTD 2025, primarily due to higher realized oil prices, and a higher production tax rate associated with our acquired DJ Basin assets relative to our pre-Merger asset base. Our overall production tax rate was 6.4 percent, 6.1 percent, and 4.1 percent for the three months ended September 30, 2026, June 30, 2026, and September 30, 2025, respectively. Production taxes are primarily driven by oil, gas, and NGL revenues, with effective tax rates varying by jurisdiction based on applicable tax structures and available incentives. We generally expect our Uinta Basin and South Texas assets to incur lower production tax rates compared with our Permian and DJ Basin assets. Accordingly, changes in commodity prices, production volumes, and the geographic and commodity mix of our production may impact both total production tax expense and our production tax rate.
Ad valorem tax expense per BOE increased three percent sequentially and decreased 25 percent YTD 2026-over-YTD 2025. We anticipate volatility in ad valorem tax expense on a per BOE and absolute basis due to varying tax policies and assessment methodologies across the counties in which we operate, changes in our commodity and production mix across our assets, and fluctuations in commodity prices.
DD&A expense per BOE remained flat sequentially. DD&A expense per BOE decreased nine percent YTD 2026-over-YTD 2025, primarily due to the impacts of the Merger on DD&A rates, the South Texas Divestiture, and shifts in our production mix. For the full-year 2026, we expect DD&A expense on an absolute basis to increase compared with 2025 due to higher production volumes, while we expect DD&A expense to decrease on a per BOE basis. Our DD&A rate fluctuates as a result of changes in the geographic and commodity mix of our production, changes in our total estimated net proved reserve volumes, changes in capital allocation, impairments, acquisition and divestiture activity, and carrying cost funding and sharing arrangements with third parties.
G&A expense on a per BOE basis decreased 29 percent sequentially, primarily due to a decrease in Merger-related one-time costs compared with the three months ended June 30, 2026. G&A expense on a per BOE basis increased 27 percent YTD 2026-over-YTD 2025, primarily due to Merger-related one-time costs. These costs include one-time severance and retention payments; accelerated stock-compensation expense related to terminated employees; transition employee costs; one-time systems integration, advisory, and legal expenses; and higher compensation expense due to increased headcount. During the nine months ended September 30, 2026, we recognized $159 million of one-time Merger integration costs in G&A expense. For the full-year 2026, we expect G&A expense on an absolute basis to increase compared with 2025, primarily due to an increase in employee headcount as a result of the Merger, and one-time integration costs, a majority of which were incurred during the first half of 2026.
Basic and diluted weighted-average common shares outstanding increased YTD 2026-over-YTD 2025, primarily as a result of shares issued in connection with the Merger, slightly offset by the repurchase of 4.9 million shares of our common stock under our Stock Repurchase Program. Refer to Note 5 - Equity and Note 10 - Earnings Per Share in Part I, Item 1 of this report for additional discussion.
Refer to Comparison of Financial Results and Trends Between the Three Months Ended September 30, 2026, and June 30, 2026, and Between the Nine Months Ended September 30, 2026, and 2025 below for additional discussion of operating expenses.
Comparison of Financial Results and Trends Between the Three Months Ended September 30, 2026, and June 30, 2026, and Between the Nine Months Ended September 30, 2026, and 2025
Refer to Overview of Selected Production and Financial Information, Including Trends above for additional discussion, including discussion of trends on a per BOE basis.
Average net daily equivalent production, production revenue, and production expense
Sequential Quarterly Changes. The following table presents changes in our average net daily equivalent production; oil, gas, and NGL production revenue; and oil, gas, and NGL production expense, by area, between the three months ended September 30, 2026, and June 30, 2026:
| Average Net Equivalent Production Increase (Decrease) | Oil, Gas, and NGL Production Revenue Increase (Decrease) | Oil, Gas, and NGL Production Expense Increase | |||||||||||||||
| (MBOE per day) | (in millions) | (in millions) | |||||||||||||||
Permian Basin | (10.8) | $ | (6) | $ | — | ||||||||||||
DJ Basin | 0.6 | — | 2 | ||||||||||||||
| South Texas | (1.1) | 4 | 2 | ||||||||||||||
| Uinta Basin | 4.6 | 7 | 14 | ||||||||||||||
| Total | (6.7) | $ | 5 | $ | 18 | ||||||||||||
__________________________________________
Note: Amounts may not calculate due to rounding.
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Average net daily equivalent production decreased two percent, as the three months ended June 30, 2026, included one month of production from our divested South Texas assets. Total realized price increased slightly, resulting in oil, gas, and NGL production revenue remaining relatively flat. Oil, gas, and NGL production expense increased three percent primarily driven by increases in LOE and production tax expense.
YTD 2026-over-YTD 2025 Changes. The following table presents changes in our average net daily equivalent production; oil, gas, and NGL production revenue; and oil, gas, and NGL production expense, by area, between the nine months ended September 30, 2026, and 2025:
| Average Net Equivalent Production Increase (Decrease) | Oil, Gas, and NGL Production Revenue Increase (Decrease) | Oil, Gas, and NGL Production Expense Increase (Decrease) | |||||||||||||||
| (MBOE per day) | (in millions) | (in millions) | |||||||||||||||
Permian Basin | 130.7 | $ | 1,863 | $ | 485 | ||||||||||||
DJ Basin | 106.7 | 1,501 | 436 | ||||||||||||||
| South Texas | (26.6) | (115) | (52) | ||||||||||||||
Uinta Basin | (2.7) | 108 | 10 | ||||||||||||||
| Total | 208.1 | $ | 3,358 | $ | 880 | ||||||||||||
__________________________________________
Note: Amounts may not calculate due to rounding.
Average net daily equivalent production increased 101 percent, and total realized price increased 19 percent, resulting in a 138 percent increase in oil, gas, and NGL production revenue. Oil, gas, and NGL production expense increased 130 percent. These increases are primarily due to the inclusion of eight months of activity from the assets acquired in the Merger during the nine months ended September 30, 2026, and higher benchmark oil prices. These increases were partially offset by the divestiture of a portion of our South Texas assets, which contributed four months of activity during the nine months ended September 30, 2026, compared to a full nine months during the prior-year period.
Gain (loss) on divestiture activity
| For the Three Months Ended | For the Nine Months Ended | ||||||||||||||||||||||
| September 30, 2026 | June 30, 2026 | September 30, 2026 | September 30, 2025 | ||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||
| Gain (loss) on divestiture activity | $ | (2) | $ | 262 | $ | 260 | $ | — | |||||||||||||||
During the nine months ended September 30, 2026, we recorded a gain on divestiture activity of $260 million related to the South Texas Divestiture. Refer to Note 2 - Mergers, Acquisitions, and Divestitures in Part I, Item 1 of this report for additional discussion.
Other operating income
| For the Three Months Ended | For the Nine Months Ended | ||||||||||||||||||||||
| September 30, 2026 | June 30, 2026 | September 30, 2026 | September 30, 2025 | ||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||
| Other operating income | $ | 12 | $ | 82 | $ | 96 | $ | 13 | |||||||||||||||
Other operating income decreased $70 million sequentially and increased $83 million YTD 2026-over-YTD 2025, primarily due to a Texas natural gas severance tax refund recorded during the three months ended June 30, 2026.
Depletion, depreciation, and amortization
| For the Three Months Ended | For the Nine Months Ended | ||||||||||||||||||||||
| September 30, 2026 | June 30, 2026 | September 30, 2026 | September 30, 2025 | ||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||
| Depletion, depreciation, and amortization | $ | 590 | $ | 592 | $ | 1,614 | $ | 888 | |||||||||||||||
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DD&A expense remained flat sequentially. DD&A expense increased 82 percent YTD 2026-over-YTD 2025 primarily due to higher production volumes and the impact of the Merger on DD&A rates.
Exploration
| For the Three Months Ended | For the Nine Months Ended | ||||||||||||||||||||||
| September 30, 2026 | June 30, 2026 | September 30, 2026 | September 30, 2025 | ||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||
Exploration | $ | 22 | $ | 21 | $ | 69 | $ | 39 | |||||||||||||||
Exploration expense remained relatively flat sequentially. Exploration expense increased 77 percent YTD 2026-over-YTD 2025 due to increases in overhead as a result of the Merger. Exploration expense fluctuates based on actual geological and geophysical studies we perform within an exploratory area, exploratory dry hole expense incurred, and changes in the amount of allocated overhead.
General and administrative
| For the Three Months Ended | For the Nine Months Ended | ||||||||||||||||||||||
| September 30, 2026 | June 30, 2026 | September 30, 2026 | September 30, 2025 | ||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||
| General and administrative | $ | 56 | $ | 79 | $ | 309 | $ | 121 | |||||||||||||||
G&A expense decreased 29 percent sequentially and increased 155 percent YTD 2026-over-YTD 2025, both primarily due to the timing of Merger-related one-time costs, the majority of which were incurred during the six months ended June 30, 2026. The YTD 2026-over-YTD 2025 increase also reflects higher compensation expense due to increased headcount resulting from the Merger. One-time costs of $159 million for the nine months ended September 30, 2026, include severance and retention payments, accelerated stock-based compensation expense related to terminated employees, transition employee costs, and systems integration, advisory, and legal expenses.
Net derivative (gain) loss
| For the Three Months Ended | For the Nine Months Ended | ||||||||||||||||||||||
| September 30, 2026 | June 30, 2026 | September 30, 2026 | September 30, 2025 | ||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||
| Net derivative (gain) loss | $ | 684 | $ | (272) | $ | 1,109 | $ | (107) | |||||||||||||||
Net derivative (gain) loss is a result of changes in fair values associated with fluctuations in the forward price curves for the commodities underlying our outstanding derivative contracts and the monthly cash settlements of our derivative positions during the period. We expect increases in benchmark commodity prices to result in net derivative losses and decreases in benchmark commodity prices to result in net derivative gains, as measured against our derivative contract prices. Refer to Note 8 - Derivative Financial Instruments in Part I, Item 1 of this report for additional discussion.
Interest expense
| For the Three Months Ended | For the Nine Months Ended | ||||||||||||||||||||||
| September 30, 2026 | June 30, 2026 | September 30, 2026 | September 30, 2025 | ||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||
| Interest expense | $ | (116) | $ | (111) | $ | (340) | $ | (130) | |||||||||||||||
Interest expense increased 162 percent YTD 2026-over-YTD 2025 primarily driven by interest expense attributable to our Civitas Senior Notes assumed in connection with the Merger, partially offset by the refinancing of higher-coupon debt and redemptions of Senior Notes. Total interest expense can vary based on the amount of our outstanding fixed-rate debt securities, fluctuations in the amount of capitalized interest as a result of the timing of the development of our wells in progress, and the timing and amount of borrowings under our revolving credit facility.
39
Income tax expense
| For the Three Months Ended | For the Nine Months Ended | ||||||||||||||||||||||
| September 30, 2026 | June 30, 2026 | September 30, 2026 | September 30, 2025 | ||||||||||||||||||||
| (in millions, except tax rate) | |||||||||||||||||||||||
| Income tax expense | $ | (30) | $ | (318) | $ | (273) | $ | (150) | |||||||||||||||
| Effective tax rate | 24.9 | % | 22.9 | % | 24.8 | % | 21.7 | % | |||||||||||||||
Our effective tax rate for the three and nine months ended September 30, 2026, reflects the proportional effects of forecast net income on estimated permanent items between periods and state apportionment factors affecting the allocation of taxable income across jurisdictions with varying statutory tax rates. Our effective tax rate increased both sequentially and YTD 2026-over-YTD 2025, primarily due to changes in these factors. Additionally, the tax rates include the effects of projected research and development credit claims and tax deduction limitations on compensation of covered individuals.
During the nine months ended September 30, 2026, we made estimated payments, net of refunds received, of $25 million for federal income taxes and $5 million for state income taxes. Our IRC Section 382 analysis and state tax planning indicate that certain tax attributes are expected to be utilized in 2026. However, higher operating income limits the amount of tax attributes available to offset taxable income. Consequently, current federal and state income tax expense represents a greater percentage of total income tax expense both sequentially and YTD 2026-over-YTD 2025.
Refer to Note 4 - Income Taxes in Part I, Item 1 of this report, and to the Risk Factors section in Part I, Item 1A of our 2025 Form 10-K for additional discussion.
Overview of Liquidity and Capital Resources
Based on our current liquidity position, anticipated operating cash flows, and available sources of capital, we believe we have sufficient financial resources to execute our business plan and meet our short-term and long-term financial obligations, including maturities of our outstanding Senior Notes. We continue to manage the duration and level of our drilling and completion commitments to maintain flexibility with regard to our activity level and capital expenditures.
Sources of Cash
During the nine months ended September 30, 2026, we primarily funded our capital expenditures, 2027 Senior Notes redemption, and return of capital program with cash flows from operations. For the remainder of 2026, we expect to fund our capital expenditures and return of capital program with cash flows from operations, with any remaining cash needs being funded by borrowings under our revolving credit facility. Although we expect cash flows from these sources to be sufficient for the remainder of 2026, we may also elect to raise funds through new debt or equity offerings or from other sources of financing. If we raise additional funds through the issuance of equity or convertible debt securities, the percentage ownership of our current stockholders could be diluted, and these newly issued securities may have rights, preferences, or privileges senior to those of certain existing stockholders and bondholders. Additionally, we may enter into carrying cost and sharing arrangements with third parties for certain exploration or development programs.
During the first quarter of 2026, we issued our 2034 Senior Notes. See below for discussion on the use of net proceeds received, and refer to Note 6 - Long-Term Debt in Part I, Item 1 of this report for additional discussion.
During the second quarter of 2026, we completed the South Texas Divestiture. Subsequent to September 30, 2026, we completed the final post-closing settlement, resulting in total net cash proceeds of $894 million after final purchase price adjustments. We used the proceeds to reduce debt and strengthen our capital structure as further discussed under Uses of Cash below. See Note 2 - Mergers, Acquisitions, and Divestitures in Part I, Item 1 of this report for additional discussion.
Our credit ratings affect the availability of, and cost for us to borrow, additional funds. Any future downgrades in our credit ratings could make it more difficult or expensive for us to borrow additional funds. Two major credit rating agencies upgraded our credit ratings following the close of the Merger on January 30, 2026, citing our increased size, scale and diversification, and enhanced and consistently positive free cash flow generation.
All of our liquidity sources can be affected by the broader economic environment, force majeure events, fluctuations in commodity prices, operating costs, interest rate changes, tax law changes, and volumes produced, all of which affect us and our industry.
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We have no control over the market prices for oil, gas, or NGLs, although we may be able to influence the amount of our realized revenues from our oil, gas, and NGL sales through the use of commodity derivative contracts as part of our financial risk management program. Commodity derivative contracts may limit the prices we receive for our oil, gas, and NGL sales if oil, gas, or NGL prices rise over the price established by the commodity derivative contract. Refer to Note 8 - Derivative Financial Instruments in Part I, Item 1 of this report for additional information about our commodity derivative contracts currently in place.
Credit Agreement
Our Credit Agreement provides for a senior secured revolving credit facility with a maximum loan amount of $5.0 billion. In connection with the closing of the Merger on January 30, 2026, we entered into the Fourth Amendment with our lenders which, among other things, increased the aggregate revolving lender commitments available under our Credit Agreement to $2.5 billion and increased the borrowing base to $5.0 billion. As of September 30, 2026, the borrowing base and aggregate revolving lender commitments under our Credit Agreement were $5.0 billion and $2.5 billion, respectively. The borrowing base is subject to regular, semi-annual redetermination, and considers the value of both our proved oil and gas properties reflected in our most recent reserve report and commodity derivative contracts, each as determined by our lender group. Subsequent to September 30, 2026, our lender group reaffirmed our borrowing base and aggregate lender commitments at existing levels. The next borrowing base redetermination is scheduled to occur on April 1, 2027. No individual bank participating in our Credit Agreement represents more than 10 percent of the lender commitments under the Credit Agreement. We must comply with certain financial and non-financial covenants under the terms of the Credit Agreement. We were in compliance with all financial and non-financial covenants under the Credit Agreement as of September 30, 2026, and through the filing of this report.
The following table summarizes our daily weighted-average revolving credit facility balance during the periods presented:
| For the Three Months Ended | For the Nine Months Ended | ||||||||||||||||||||||
| September 30, 2026 | June 30, 2026 | September 30, 2026 | September 30, 2025 | ||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||
Daily weighted-average revolving credit facility balance | $ | 32 | $ | 18 | $ | 18 | $ | 66 | |||||||||||||||
The amount we borrow under our revolving credit facility is impacted by cash flows provided by our operating activities, proceeds received from divestitures of properties, capital markets activities including open market debt repurchases, debt redemptions, and repayment of scheduled debt maturities, other financing activities, and our capital expenditures, including acquisitions.
Refer to Note 6 - Long-Term Debt in Part I, Item 1 of this report for additional discussion, and the presentation of the outstanding balance, total amount of letters of credit, and available borrowing capacity under the Credit Agreement as of October 22, 2026, September 30, 2026, and December 31, 2025.
Weighted-Average Interest and Weighted-Average Borrowing Rates
Our weighted-average interest rate includes paid and accrued interest, fees on the unused portion of the aggregate revolving lender commitment amount under the Credit Agreement, letter of credit fees, and the non-cash amortization of deferred financing costs and debt premiums. The amortization of deferred financing costs increases interest expense, while the amortization of debt premiums decreases interest expense. Our weighted-average borrowing rate includes paid and accrued interest only.
The following table presents our weighted-average interest rates and our weighted-average borrowing rates for the periods presented:
| For the Three Months Ended | For the Nine Months Ended | ||||||||||||||||||||||
| September 30, 2026 | June 30, 2026 | September 30, 2026 | September 30, 2025 | ||||||||||||||||||||
| Weighted-average interest rate | 7.6 | % | 7.5 | % | 7.6 | % | 7.4 | % | |||||||||||||||
| Weighted-average borrowing rate | 7.3 | % | 7.2 | % | 7.3 | % | 6.8 | % | |||||||||||||||
Our weighted-average interest rate and weighted-average borrowing rate each remained relatively flat sequentially. Our weighted-average interest rate and weighted-average borrowing rate each increased YTD 2026-over-YTD 2025, primarily due to our Civitas Senior Notes, the majority of which carry a higher average coupon rate than our Senior Notes outstanding prior to the Merger. Our weighted-average interest rate benefited from the amortization of the premiums on our Civitas Senior Notes, which were recorded based on the fair value of the Civitas Senior Notes on the Closing Date of the Merger. We expect our weighted-average interest rate and weighted-average borrowing rate to increase slightly for the full-year 2026 compared with 2025.
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Our weighted-average interest rate and weighted-average borrowing rate are affected by the occurrence and timing of long-term debt issuances and redemptions and the average outstanding balance under our revolving credit facility. Additionally, our weighted-average interest rate is affected by the fees paid on the unused portion of our aggregate revolving lender commitments.
Uses of Cash
We use cash for the development, exploration, and acquisition of oil and gas properties; for the payment of operating and G&A costs, income taxes, debt obligations, including interest and early repayments or redemptions, and dividends; and for repurchases of shares of our outstanding common stock under the Stock Repurchase Program. Expenditures for the development and exploration of oil and gas properties are the primary use of our capital resources and totaled $2.0 billion during the nine months ended September 30, 2026. This amount differs from the costs incurred amount of $2.2 billion for the nine months ended September 30, 2026, largely due to the timing of payments associated with accrued capital activity as costs incurred is an accrual-based amount that also includes asset retirement obligations, acquisitions of proved and unproved oil and gas properties, geological and geophysical expenses, and exploration overhead.
The amount and allocation of our future capital expenditures will depend upon a number of factors, including our cash flows from operating, investing, and financing activities, our ability to execute our development program, inflation, and the number and size of acquisitions that we complete. In addition, the impact of oil, gas, and NGL prices on investment opportunities, the availability of capital, tax law and other regulatory changes, and the timing and results of our exploration and development activities may lead to changes in funding requirements for future development. We periodically review our capital expenditure budget and guidance to assess if changes are necessary based on current and projected cash flows, acquisition and divestiture activities, debt requirements, and other factors. Our capital program for 2026 is expected to be approximately $2.75 billion, excluding acquisitions.
We may from time to time repurchase shares of our outstanding common stock, or repurchase or redeem all or portions of our outstanding debt securities, for cash, through exchanges for other securities, or a combination of both. Such repurchases or redemptions may be made in open market transactions (including pursuant to Rule 10b5-1 trading plans), privately negotiated transactions, tender offers, pursuant to contractual provisions, or otherwise. Any such repurchases or redemptions will depend on our business strategy, prevailing market conditions, our liquidity requirements, contractual restrictions or covenants, compliance with securities laws, and other factors. The amounts involved in any such transaction may be material.
Under our stockholder return framework announced in February 2026, we currently target approximately 20 percent of free cash flow, calculated on a quarterly basis and after dividend payments, for share repurchases, with the potential to repurchase in excess of this level as we continue to execute on our strategy and bolster our balance sheet.
During the nine months ended September 30, 2026, we used cash proceeds from the issuance of our 2034 Senior Notes to fund the repurchase of $894 million in aggregate principal amount of our 2028 Civitas Senior Notes through the Tender Offer. As a result of the Tender Offer, we paid total consideration of $924 million, including the early tender premium and certain fees, and we paid $16 million of accrued interest. Refer to Note 6 - Long-Term Debt in Part I, Item 1 of this report for additional discussion.
Subsequent to the Tender Offer, on May 11, 2026, we used cash proceeds from the South Texas Divestiture to redeem all $400 million aggregate principal amount outstanding of our 2026 Civitas Senior Notes, at par, and on June 1, 2026, we used the remaining proceeds to redeem all $419 million aggregate principal amount outstanding of our 2026 Senior Notes, at par. On September 4, 2026, we used cash flows from operations to redeem all $417 million aggregate principal amount outstanding of our 2027 Senior Notes, at par. After these redemptions, we have no Senior Notes maturities until mid-2028. Refer to Note 6 - Long-Term Debt in Part I, Item 1 of this report for additional discussion.
During the nine months ended September 30, 2026, and 2025, we repurchased and subsequently retired 4,946,833 and 444,705 shares, respectively, of our common stock at a cost of $165 million and $12 million, respectively, excluding excise taxes, commissions, and fees. As of September 30, 2026, $323 million was available under the Stock Repurchase Program for repurchases of our outstanding common stock through December 31, 2027.
During the nine months ended September 30, 2026, and 2025, we paid $187 million and $69 million, respectively, in dividends to our stockholders. In the first quarter of 2026, we began declaring and paying dividends within the same quarter, rather than paying in the quarter after declaration. As a result of this timing change, cash dividend payments during 2026 will include five payments: the fourth quarter 2025 dividend paid in the first quarter of 2026, plus the four quarterly dividends declared and paid during 2026. In February 2026, our Board of Directors approved a 10 percent increase to our annual base dividend to $0.88 per share, payable quarterly, effective beginning with the March 2026 dividend. We currently intend to continue paying dividends to our stockholders for the foreseeable future, subject to our future earnings, our financial condition, covenants under our Credit Agreement and the indentures governing our Senior Notes, and other factors that could arise. The payment and amount of future dividends remain at the discretion of our Board of Directors.
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Analysis of Cash Flow Changes Between the Nine Months Ended September 30, 2026, and 2025
The following tables present changes in cash flows between the nine months ended September 30, 2026, and 2025, for our operating, investing, and financing activities. The analysis following each table should be read in conjunction with our accompanying statements of cash flows in Part I, Item 1 of this report.
Operating activities
| For the Nine Months Ended September 30, | Amount Change Between Periods | ||||||||||||||||
| 2026 | 2025 | ||||||||||||||||
| (in millions) | |||||||||||||||||
| Net cash provided by operating activities | $ | 2,865 | $ | 1,559 | $ | 1,306 | |||||||||||
Net cash provided by operating activities increased for the nine months ended September 30, 2026, compared with the same period in 2025, primarily as a result of an increase of $2.4 billion in cash received from oil, gas, and NGL production revenue net of transportation costs and production taxes. This increase was partially offset by increases in cash paid of $406 million for settled derivative trades, $390 million for LOE, $166 million for interest, and $165 million for certain G&A expenses. These changes are largely a result of the Merger. Net cash provided by operating activities is also affected by working capital changes and the timing of cash receipts and disbursements.
Investing activities
| For the Nine Months Ended September 30, | Amount Change Between Periods | ||||||||||||||||
| 2026 | 2025 | ||||||||||||||||
| (in millions) | |||||||||||||||||
| Net cash used in investing activities | $ | (1,231) | $ | (1,244) | $ | 13 | |||||||||||
Net cash used in investing activities decreased for the nine months ended September 30, 2026, compared with the same period in 2025, primarily as a result of net cash proceeds of $888 million received from the South Texas Divestiture, partially offset by a $798 million increase in capital expenditures and $49 million of cash paid in connection with the Merger, net of cash acquired.
Financing activities
| For the Nine Months Ended September 30, | Amount Change Between Periods | ||||||||||||||||
| 2026 | 2025 | ||||||||||||||||
| (in millions) | |||||||||||||||||
| Net cash used in financing activities | $ | (1,560) | $ | (153) | $ | (1,407) | |||||||||||
Net cash used in financing activities of $1.6 billion for the nine months ended September 30, 2026, primarily reflects $1.2 billion used to redeem our 2026 Civitas Senior Notes, 2026 Senior Notes, and 2027 Senior Notes, $924 million, including the early tender premium and certain fees but excluding accrued interest, used to repurchase a portion of our 2028 Civitas Senior Notes through the Tender Offer, $187 million of dividends paid to our stockholders and $166 million of cash paid, including commissions and fees, to repurchase and subsequently retire 4.9 million shares of our common stock under the Stock Repurchase Program. These uses were partially offset by net proceeds of $984 million from the issuance of our 2034 Senior Notes.
Net cash used in financing activities for the nine months ended September 30, 2025, primarily related to net repayments of $69 million under our revolving credit facility and $69 million of dividends paid to our stockholders.
Interest Rate Risk
We are exposed to market and credit risk due to the floating interest rate associated with any outstanding balance under our revolving credit facility. Our Credit Agreement allows us to fix the interest rate for all or a portion of the principal balance of our revolving credit facility for a period of up to six months. To the extent that the interest rate is fixed, interest rate changes will affect the revolving credit facility’s fair value but will not affect results of operations or cash flows. Conversely, for the portion of the revolving credit facility that has a floating interest rate, interest rate changes will not affect the fair value, but will affect future results of operations and cash flows. Changes in interest rates do not affect the amount of interest we pay on our fixed-rate Senior Notes, but can affect their fair values. As of September 30, 2026, our outstanding principal amount of fixed-rate debt totaled $6.5 billion, and we had no floating-rate debt outstanding. As of September 30, 2025, our outstanding principal amount of fixed-rate debt totaled $2.7 billion and we had no floating-rate debt outstanding. Refer to Note 9 - Fair Value Measurements in Part I, Item 1 of this report for additional discussion on the fair values of our Senior Notes.
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Commodity Price Risk
The prices we receive for our oil, gas, and NGL production directly affect our revenue, profitability, access to capital, ability to return capital to our stockholders, and future rate of growth. Oil, gas, and NGL prices are subject to unpredictable fluctuations resulting from a variety of factors that are typically beyond our control, including changes in supply and demand associated with the broader macroeconomic environment, War and Geopolitical Instability, constraints on gathering systems, processing facilities, pipelines, rail systems and other transportation systems, and weather-related events. The markets for oil, gas, and NGLs have been volatile, especially over the last decade, and remain subject to high levels of uncertainty and volatility. The realized prices we receive at local sales points for our production have been and may continue to be affected by infrastructure capacity or outages in the areas of our operations and beyond, and also depend on numerous factors that are typically beyond our control. Based on our production for the nine months ended September 30, 2026, a 10 percent decrease in our average realized oil, gas, and NGL prices would have reduced our oil, gas, and NGL production revenue by approximately $510 million, $35 million, and $34 million, respectively. If commodity prices had been 10 percent lower, our net derivative settlements for the nine months ended September 30, 2026, would have offset the declines in oil, gas, and NGL production revenue by approximately $277 million.
We enter into commodity derivative contracts to reduce the risk of fluctuations in commodity prices. The fair value of our commodity derivative contracts is largely determined by estimates of the forward curves of the relevant price indices. As of September 30, 2026, a 10 percent increase or decrease in the forward curves associated with our oil, gas, and NGL commodity derivative instruments would have changed our net derivative positions for these products by approximately $282 million, $89 million, and less than $1 million, respectively.
Off-Balance Sheet Arrangements
We have not participated in transactions that generate relationships with unconsolidated entities or financial partnerships, such as entities often referred to as structured finance or special purpose entities (“SPE”), which would have been established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes.
We evaluate our transactions to determine if any variable interest entities exist. If we determine that we are the primary beneficiary of a variable interest entity, that entity is consolidated into our consolidated financial statements. We have not been involved in any unconsolidated SPE transactions during the nine months ended September 30, 2026, or through the filing of this report.
Critical Accounting Estimates
Refer to the corresponding section in Part II, Item 7 and to Note 1 - Summary of Significant Accounting Policies included in Part II, Item 8 of our 2025 Form 10-K for discussion of our accounting estimates. Additionally, the estimate discussed below was identified as critical to the understanding of our business and results of operations and required the application of significant management judgment during the year-to-date period covered by this report.
Purchase Price Allocation. Accounting for the acquisition of a business requires the allocation of the purchase price to the various assets and liabilities acquired based on their estimated fair value as of the acquisition date. Various assumptions are made when estimating fair values assigned to proved and unproved oil and gas properties including: (i) reserves; (ii) production rates; (iii) future operating and development costs; (iv) future commodity prices, including price differentials; (v) risk adjustment factors; and (vi) a market participant-based weighted-average cost of capital. These inputs require significant judgment by management at the time of the valuation.
Accounting Matters
Refer to Note 1 - Summary of Significant Accounting Policies in Part I, Item 1 of this report for information on new authoritative accounting guidance.
Non-GAAP Financial Measures
Adjusted EBITDAX represents net income (loss) before interest expense, interest income, income taxes, depletion, depreciation, and amortization expense, exploration expense, property abandonment and impairment expense, non-cash stock-based compensation expense, derivative gains and losses net of settlements, gains and losses on divestitures, gains and losses on extinguishment of debt, non-recurring or one-time costs including transaction and integration costs associated with the Merger, and certain other items. 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 or whose timing and/or amount cannot be reasonably estimated. Adjusted EBITDAX is a non-GAAP measure that we believe 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 Agreement based on adjusted EBITDAX ratios as further described in Note 5 - Long-Term Debt in our 2025 Form 10-K. In addition, adjusted EBITDAX is widely used by professional research analysts and others in the valuation, comparison, and investment recommendations of companies in the oil and gas exploration and production industry, and
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many investors use the published research of industry research analysts in making investment decisions. Adjusted EBITDAX should not be considered in isolation or as a substitute for net income (loss), income (loss) from operations, 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 (loss) and may vary among companies, the adjusted EBITDAX amounts presented may not be comparable to similar metrics of other companies. Our revolving credit facility provides a material source of liquidity for us. Under the terms of our Credit Agreement, if we failed to comply with the covenants that establish a maximum permitted ratio of total funded debt, as defined in the Credit Agreement, to adjusted EBITDAX, we would be in default, an event that would prevent us from borrowing under our revolving credit facility and would therefore materially limit a significant source of our liquidity. In addition, if we are in default under our revolving credit facility and are unable to obtain a waiver of that default from our lenders, lenders under that facility and under the indentures governing each series of our outstanding Senior Notes would be entitled to exercise all of their remedies for default.
The following table provides reconciliations of our net income (GAAP) and net cash provided by operating activities (GAAP) to adjusted EBITDAX (non-GAAP) for the periods presented:
| For the Three Months Ended | For the Nine Months Ended | ||||||||||||||||||||||
| September 30, 2026 | September 30, 2025 | September 30, 2026 | September 30, 2025 | ||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||
| Net income (GAAP) | $ | 93 | $ | 155 | $ | 829 | $ | 539 | |||||||||||||||
| Interest expense | 116 | 43 | 340 | 130 | |||||||||||||||||||
| Income tax expense | 30 | 49 | 273 | 150 | |||||||||||||||||||
| Depletion, depreciation, and amortization | 590 | 325 | 1,614 | 888 | |||||||||||||||||||
Exploration (1) | 20 | 10 | 62 | 34 | |||||||||||||||||||
Stock-based compensation expense (2) | 13 | 8 | 30 | 21 | |||||||||||||||||||
| Net derivative (gain) loss | 684 | (45) | 1,109 | (107) | |||||||||||||||||||
| Net derivative settlement gain (loss) | (207) | 39 | (457) | 86 | |||||||||||||||||||
| (Gain) loss on divestiture activity | 2 | — | (260) | — | |||||||||||||||||||
Transaction and integration costs (3) | 5 | — | 177 | — | |||||||||||||||||||
| Other, net | (5) | 4 | — | 5 | |||||||||||||||||||
| Adjusted EBITDAX (non-GAAP) | 1,341 | 588 | 3,717 | 1,747 | |||||||||||||||||||
| Interest expense | (116) | (43) | (340) | (130) | |||||||||||||||||||
| Income tax expense | (30) | (49) | (273) | (150) | |||||||||||||||||||
Exploration (1) | (20) | (10) | (62) | (34) | |||||||||||||||||||
| Amortization of deferred financing costs and debt premiums, net | (6) | 3 | (16) | 8 | |||||||||||||||||||
Transaction and integration costs (3) | (5) | — | (157) | — | |||||||||||||||||||
| Deferred income tax expense (benefit) | (7) | 76 | 224 | 145 | |||||||||||||||||||
| Other, net | 26 | (7) | (18) | (12) | |||||||||||||||||||
| Net change in working capital | (61) | (53) | (210) | (15) | |||||||||||||||||||
| Net cash provided by operating activities (GAAP) | $ | 1,122 | $ | 505 | $ | 2,865 | $ | 1,559 | |||||||||||||||
____________________________________________
Note: Prior year amounts may not calculate due to rounding.
(1) The exploration line item shown in the reconciliation above differs from the amount shown in the accompanying statements of operations because it excludes the portion of stock-based compensation expense recorded to exploration expense, which is separately presented in the stock-based compensation expense line item above.
(2) For the nine months ended September 30, 2026, the stock-based compensation expense line item in the reconciliation above differs from the amount shown in the accompanying statements of cash flows because it excludes stock-based compensation expense included within the transaction and integration costs line item above.
(3) Transaction and integration costs include expenses associated with the Merger and post-Merger integration activities. For the three and nine months ended September 30, 2026, these costs consisted of $4 million and $159 million, respectively, of one-time integration costs (including less than $1 million and $20 million, respectively, of stock-based compensation), which were included in G&A expense in the accompanying statements of operations, and $1 million and $18 million, respectively, of one-time transaction costs included in other operating expense in the accompanying statements of operations.
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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The information required by this item is provided under the captions Interest Rate Risk and Commodity Price Risk in Item 2 above, and under the section entitled Summary of Oil, Gas, and NGL Derivative Contracts in Place in Note 8 - Derivative Financial Instruments in Part I, Item 1 of this report and is incorporated herein by reference. Also refer to the information under Interest Rate Risk and Commodity Price Risk in Management’s Discussion and Analysis of Financial Condition and Results of Operations in Part II, Item 7 of our 2025 Form 10-K.
ITEM 4. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
We maintain a system of disclosure controls and procedures that are designed to reasonably ensure that information required to be disclosed in our Securities and Exchange Commission (“SEC”) reports is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms, and to reasonably ensure that such information is accumulated and communicated to our management, including our Chief Executive Officer (Principal Executive Officer) and our Chief Financial Officer (Principal Financial Officer), as appropriate, to allow for timely decisions regarding required disclosure.
Our management, including our Chief Executive Officer and our Chief Financial Officer, does not expect that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act) (“Disclosure Controls”) will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within our company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. We monitor our Disclosure Controls and make modifications as necessary; our intent in this regard is that the Disclosure Controls will be modified as systems change and conditions warrant.
An evaluation of the effectiveness of the design and operation of our Disclosure Controls was performed as of the end of the period covered by this report. This evaluation was performed under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our Disclosure Controls are effective at a reasonable assurance level as of September 30, 2026.
Changes in Internal Control Over Financial Reporting
During the third quarter of 2026, we completed the integration of the operations acquired in the Merger into our internal control over financial reporting. This integration included the alignment of accounting processes and systems, and the implementation of additional controls where necessary.
There have been no other changes during the third quarter of 2026 that have 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
At times, we may be involved in litigation relating to claims arising out of our business and operations in the normal course of business. As of the filing of this report, no legal proceedings are pending against us that we believe individually or collectively are likely to have a materially adverse effect upon our financial condition, results of operations, or cash flows.
With respect to administrative or judicial proceedings involving the environment, we have determined that we will disclose any such proceeding if we reasonably believe such proceeding will result in monetary sanctions, exclusive of interest and costs, of $1 million or more.
ITEM 1A. RISK FACTORS
There have been no material changes to the risk factors as previously disclosed in our 2025 Form 10-K.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
The following table provides information about purchases made by us and any affiliated purchaser (as defined in Rule 10b-18(a)(3) under the Exchange Act) during the three months ended September 30, 2026, of shares of our common stock, which is the sole class of equity securities registered by us pursuant to Section 12 of the Exchange Act:
PURCHASES OF EQUITY SECURITIES BY ISSUER AND AFFILIATED PURCHASERS | ||||||||||||||
| Period | Total Number of Shares Purchased | Weighted Average Price Paid per Share | Total Number of Shares Purchased as Part of Publicly Announced Program (1) | Approximate Dollar Value of Shares that May Yet Be Purchased Under the Program (in millions, as of the period end date) (1) | ||||||||||
| 07/01/2026 - 07/31/2026 | — | $ | — | — | $ | 404 | ||||||||
| 08/01/2026 - 08/31/2026 | 1,058,265 | $ | 34.14 | 1,058,265 | $ | 368 | ||||||||
| 09/01/2026 - 09/30/2026 | 1,245,062 | $ | 36.28 | 1,245,062 | $ | 323 | ||||||||
| Total: | 2,303,327 | $ | 35.30 | 2,303,327 | ||||||||||
___________________________________
(1) Our Stock Repurchase Program, which our Board of Directors authorized in June 2024, for the repurchase of up to $500 million in aggregate value of our outstanding common stock through December 31, 2027, permits us to repurchase our shares from time to time in open market transactions (including pursuant to Rule 10b5-1 trading plans), through privately negotiated transactions or by other means, in accordance with federal securities laws and subject to certain provisions of our Credit Agreement and the indentures governing our Senior Notes.
Under our stockholder return framework announced in February 2026, we currently target approximately 20 percent of free cash flow, calculated on a quarterly basis and after dividend payments, for share repurchases, with the potential to repurchase in excess of this level as we continue to execute on our strategy and bolster our balance sheet. During the three months ended September 30, 2026, we repurchased 2,303,327 shares of common stock at a weighted-average share price of $35.30, for a total cost of $81 million, excluding excise taxes, commissions, and fees. Since announcing the framework, our outstanding principal amount of debt has decreased, and we continue to evaluate our share repurchase allocation in the context of our leverage trajectory and the broader operating environment. Refer to Overview of Liquidity and Capital Resources in Part I, Item 2 of this report for further discussion.
The timing, and the number and value of shares repurchased under the Stock Repurchase Program are determined by certain authorized officers of the Company at their discretion and depend on a variety of factors, including the market price of our common stock, general market and economic conditions and applicable legal requirements. The value of shares authorized for repurchase by our Board of Directors does not require us to repurchase such shares or guarantee that such shares will be repurchased, and the Stock Repurchase Program may be suspended, modified, or discontinued at any time without prior notice. No assurance can be given that any particular number or dollar value of our shares will be repurchased.
Our payment of cash dividends to our stockholders and repurchases of our outstanding common stock are each subject to certain covenants under the terms of our Credit Agreement and the indentures governing our Senior Notes. Based on our current performance, we do not anticipate that any of these covenants will limit our potential repurchases of our outstanding common stock or our payment of dividends at our current rate for the foreseeable future if any dividends are declared by our Board of Directors.
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ITEM 4. MINE SAFETY DISCLOSURES
The required disclosure under Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K is included in Exhibit 95.1 to this report.
ITEM 5. OTHER INFORMATION
During the three months ended September 30, 2026, none of our directors or Section 16 officers adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408 of Regulation S-K.
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ITEM 6. EXHIBITS
The following exhibits are filed or furnished with, or incorporated by reference into this report:
Exhibit Number | Description | ||||
| 101.INS | Inline XBRL Instance Document - The instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. | ||||
| 101.SCH* | Inline XBRL Schema Document | ||||
| 101.CAL* | Inline XBRL Calculation Linkbase Document | ||||
| 101.LAB* | Inline XBRL Label Linkbase Document | ||||
| 101.PRE* | Inline XBRL Presentation Linkbase Document | ||||
| 101.DEF* | Inline XBRL Taxonomy Extension Definition Linkbase Document | ||||
| 104 | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101.INS) | ||||
_____________________________________
| * | Filed with this report. | ||||
| ** | Furnished with this report. | ||||
| † | Exhibit constitutes a management contract or compensatory plan or agreement. | ||||
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SIGNATURES
Pursuant to the requirements of the Exchange Act, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
| SM ENERGY COMPANY | |||||||||||
| November 4, 2026 | By: | /s/ ELIZABETH A. MCDONALD | |||||||||
Elizabeth A. McDonald | |||||||||||
President and Chief Executive Officer | |||||||||||
| (Principal Executive Officer) | |||||||||||
| November 4, 2026 | By: | /s/ A. WADE PURSELL | |||||||||
| A. Wade Pursell | |||||||||||
| Executive Vice President and Chief Financial Officer | |||||||||||
| (Principal Financial Officer) | |||||||||||
| November 4, 2026 | By: | /s/ ALAN D. BENNETT | |||||||||
Alan D. Bennett | |||||||||||
Vice President - Controller | |||||||||||
| (Principal Accounting Officer) | |||||||||||
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