Exhibit 99.3

CIVITAS RESOURCES, INC. AND SUBSIDIARIES

Annual Consolidated Financial Statements

For the Year Ended December 31, 2025 

TABLE OF CONTENTS

Deloitte & Touche LLP Suite 400 1601 Wewatta Street Denver, CO 80202 USA   Tel: +1 303 292 5400 Fax: +1 303 312 4000 www.deloitte.com

INDEPENDENT AUDITOR'S REPORT

To Those Charged With Governance

Opinion

We have audited the consolidated financial statements of Civitas Resources, Inc and subsidiaries (the "Company"), which comprise the consolidated balance sheets as of December 31, 2025 and December 31, 2024, and the related consolidated statements of operations, stockholders' equity, and cash flows for the years then ended, and the related notes to the consolidated financial statements (collectively referred to as the "financial statements").

In our opinion, the accompanying financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and December 31, 2024, and the results of its operations and its cash flows for the years then ended in accordance with accounting principles generally accepted in the United States of America.

Basis for Opinion

We conducted our audits in accordance with auditing standards generally accepted in the United States of America (GAAS). Our responsibilities under those standards are further described in the Auditor's Responsibilities for the Audit of the Financial Statements section of our report. We are required to be independent of the Company and to meet our other ethical responsibilities, in accordance with the relevant ethical requirements relating to our audits. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Responsibilities of Management for the Financial Statements

Management is responsible for the preparation and fair presentation of the financial statements in accordance with accounting principles generally accepted in the United States of America, and for the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error.

In preparing the financial statements, management is required to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the Company's ability to continue as a going concern for one year after the date that the financial statements are issued.

Auditor's Responsibilities for the Audit of the Financial Statements

Our objectives are to obtain reasonable assurance about whether the financial statements as a whole are free from material misstatement, whether due to fraud or error, and to issue an auditor's report that includes our opinion. Reasonable assurance is a high level of assurance but is not absolute assurance and therefore is not a guarantee that an audit conducted in accordance with GAAS will always detect a material misstatement when it exists. The risk of not detecting a material misstatement resulting from fraud is higher than for one resulting from error, as fraud may involve collusion, forgery, intentional omissions, misrepresentations, or the override of internal control. Misstatements are considered material if there is a substantial likelihood that, individually or in the aggregate, they would influence the judgment made by a reasonable user based on the financial statements.

In performing an audit in accordance with GAAS, we:

We are required to communicate with those charged with governance regarding, among other matters, the planned scope and timing of the audit, significant audit findings, and certain internal control-related matters that we identified during the audit.

Other Information Included in the Annual Report

Management is responsible for the other information included in the annual report. The other information comprises the information included in the annual report but does not include the financial statements and our auditor's report thereon. Our opinion on the financial statements does not cover the other information, and we do not express an opinion or any form of assurance thereon.

In connection with our audits of the financial statements, our responsibility is to read the other information and consider whether a material inconsistency exists between the other information and the financial statements, or the other information otherwise appears to be materially misstated. If, based on the work performed, we conclude that an uncorrected material misstatement of the other information exists, we are required to describe it in our report.

/s/ Deloitte & Touche LLP

February 26, 2026

CIVITAS RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in millions, except per share amounts)

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

CIVITAS RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in millions, except per share amounts)

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

CIVITAS RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(in millions, except share and per share amounts)

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

CIVITAS RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

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

CIVITAS RESOURCES, INC. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES 

Description of Operations

When we use the terms “Civitas,” the “Company,” “we,” “us,” or “our,” we are referring to Civitas Resources, Inc. and its consolidated subsidiaries unless the context otherwise requires. Civitas is an independent exploration and production company focused on the acquisition, development, and production of crude oil and associated liquids-rich natural gas in the Permian Basin in Texas and New Mexico and the DJ Basin in Colorado.

Merger Agreement

On November 2, 2025, SM Energy Company, a Delaware corporation (“SM Energy”), Cars Merger Sub, Inc., a Delaware corporation and direct wholly owned subsidiary of SM Energy (“Merger Sub”), and Civitas, entered into an Agreement and Plan of Merger (the “Merger Agreement”), pursuant to which, upon the terms and subject to the conditions set forth in the Merger Agreement, (i) Merger Sub will merge with and into Civitas, with Civitas surviving as a wholly owned subsidiary of SM Energy (the “First Company Merger”), and (ii) immediately following the First Company Merger, Civitas as the surviving corporation (the “First Surviving Corporation”) will merge with and into SM Energy, with SM Energy continuing as the surviving corporation (the “Second Company Merger” and, together with the First Company Merger, the “Merger”).

On January 30, 2026, following approval by stockholders of both SM Energy and Civitas, the Mergers and the other transactions contemplated by the Merger Agreement were consummated on that date (the “Closing Date”). Pursuant to the Merger Agreement, each share of our common stock issued and outstanding was converted into the right to receive 1.45 shares of common stock, par value $0.01 per share, of SM Energy. Our common stock was delisted from the New York Stock Exchange and deregistered under the Securities Exchange Act of 1934, and we ceased to be a publicly traded company.

For additional information related to the Merger, refer to the filings made with the Securities and Exchange Commission (“SEC”) in connection with such transaction.

Basis of Presentation

The accompanying consolidated financial statements include the accounts of Civitas and have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”). All intercompany balances and transactions have been eliminated in consolidation. Additionally, certain insignificant prior period amounts have been reclassified to conform to current period presentation in the accompanying consolidated financial statements. Such reclassifications did not have a material impact on prior period consolidated financial statements.

In connection with the preparation of the accompanying consolidated financial statements, we evaluated events subsequent to the balance sheet date of December 31, 2025 to the Closing Date.

Use of Estimates

The preparation of our consolidated financial statements in conformity with GAAP requires us to make various assumptions, judgments, and estimates to determine the reported amounts of assets, liabilities, revenues and expenses, and the disclosure of commitments and contingencies. Changes in these assumptions, judgments, and estimates will occur as a result of the passage of time and the occurrence of future events. Accordingly, actual results could differ from amounts previously estimated. Additionally, the prices received for crude oil, natural gas, and natural gas liquid(s) (“NGL”) production can heavily influence our assumptions, judgments and estimates, and continued volatility of crude oil and natural gas prices could have a significant impact on our estimates.

The more significant areas requiring the use of assumptions, judgments, and estimates include: (i) crude oil and natural gas reserves; (ii) cash flow estimates used in impairment tests for long-lived assets; (iii) depreciation, depletion and amortization; (iv) determining fair value and allocating purchase price in connection with business combinations and asset acquisitions; (v) accrued revenues; (vi) accrued liabilities; (vii) derivative valuations; (viii) asset retirement obligations; (ix) deferred income taxes; and (x) determining the fair values of certain stock-based compensation awards.

Industry Segment and Geographic Information

We report our operations in one reportable upstream segment, which is engaged in the acquisition, development, and production of crude oil and associated liquids-rich natural gas in the Permian Basin in Texas and New Mexico and the DJ Basin in Colorado. The Permian Basin and the DJ Basin are operating segments of the Company that we aggregate into the upstream segment due to the similar nature of these operations that are solely focused in the U.S. Refer to Note 16 - Segment Reporting for additional information.

Cash and Cash Equivalents

We consider all highly liquid investments with original maturity dates of three months or less to be cash equivalents. The carrying value of cash and cash equivalents approximate fair value due to the short-term nature of these instruments. We maintained cash balances in excess of federal deposit insurance limits as of December 31, 2025 and 2024, potentially subjecting us to a concentration of credit risk. To mitigate this risk, we maintain our cash and cash equivalents in the form of money market deposit and checking accounts with financial institutions that we believe are creditworthy and are also lenders under our Credit Facility, as defined below.

Accounts Receivable, Net

Our accounts receivable primarily consists of receivables due from purchasers of crude oil, natural gas, and NGL production and from joint interest owners on properties we operate. We are exposed to credit risk in the event of nonpayment by the purchasers of its production and joint interest owners, nearly all of which are concentrated in energy-related industries and may be similarly affected by changes in economic and financial conditions, commodity prices, or other conditions. Generally, payments for production are collected within one to two months. For receivables due from joint interest owners, we generally have the ability to withhold future revenue disbursements to recover non-payment of joint interest billings.

We do not require collateral and do not believe the loss of any single purchaser would materially impact our operating results, as crude oil, natural gas, and NGL are fungible products with well-established markets and numerous purchasers. For the periods presented below, the following purchasers of our production accounted for 10% or more of our total crude oil, natural gas, and NGL sales revenue for at least one of the periods as follows:

Property and Equipment

Proved Properties. We account for our crude oil and natural gas properties under the successful efforts method of accounting. Under this method, the costs of development wells are capitalized to proved properties whether those wells are successful or unsuccessful. Capitalized drilling and completion costs, including lease and well equipment, intangible development costs, and operational support facilities, are depleted using the units-of-production method based on estimated proved developed reserves. Proved leasehold costs are also depleted; however, the units-of-production method is based on estimated total proved reserves. We group our crude oil and natural gas properties with a common geological structure or stratigraphic condition for purposes of computing units-of-production depletion. During the years ended December 31, 2025 and 2024, we incurred depletion expense of $2.0 billion and $2.0 billion, respectively.

We assess proved properties for impairment using the same units of account utilized in the determination of units-of production depletion whenever events or circumstances indicate that their carrying value may not be recoverable. If carrying values exceed undiscounted future net cash flows, impairment is measured and recorded at fair value. Because there is usually a lack of quoted market prices for proved properties, we estimate the fair value using valuation techniques that convert estimated future net cash flows to a single discounted amount. Significant inputs and assumptions to this estimation include, but are not limited to, reserves volumes, future operating and development costs, future commodity prices, inclusive of applicable differentials, and a market-based weighted average cost of capital rate. The expected future cash flows used for impairment reviews include future sales volumes associated with proved developed reserves and risk-adjusted proved undeveloped reserves.

As of December 31, 2025 and 2024, the net book value of our midstream assets in the accompanying consolidated balance sheets was $454 million and $407 million, respectively. Depreciation on the midstream assets is calculated using the straight-line method over the estimated useful lives of the assets and properties they serve, which is approximately 30 years. During the years ended December 31, 2025 and 2024, we incurred depreciation expense on our midstream assets of $20 million and $15 million, respectively.

Unproved Properties. Unproved properties consist of the costs to acquire undeveloped leases and are not subject to depletion until they are transferred to proved properties. Leasehold costs are transferred to proved properties on an ongoing basis as the properties to which they relate are evaluated and proved reserves established.

Additional costs not subject to depletion include costs associated with development wells in progress or awaiting completion at year-end. These costs are transferred into costs subject to depletion on an ongoing basis as these wells are completed and proved reserves are established or confirmed.

Unproved properties are routinely evaluated for impairment. On a quarterly basis, management assesses undeveloped leasehold costs for impairment by considering, among other things, remaining lease terms, future drilling plans and capital availability to execute such plans, commodity price outlooks, recent operational results, reservoir performance and geology, and estimated acreage value based on prices received for similar, recent acreage transactions by us or other market participants. If circumstances dictate that the carrying value of unproved properties may not be recoverable, we perform a recoverability test. If carrying values exceed the undiscounted future net cash flows associated with probable and possible reserves, impairment is measured and recorded at fair value. Because there usually is a lack of quoted market prices for unproved properties, we estimate the fair value using valuation techniques that convert estimated future net cash flows to a single discounted amount. Significant inputs and assumptions to this estimation include, but are not limited to, reserves volumes, future operating and development costs, future commodity prices, inclusive of applicable differentials, and a market-based weighted average cost of capital rate. The expected future cash flows used for impairment reviews include future sales volumes associated with probable and possible reserves. Changes in our assumptions of the estimated nonproductive portion of our undeveloped leases could result in additional impairment expense.

Exploratory. Exploratory geological and geophysical, including exploratory seismic studies, and the costs of carrying and retaining unproved acreage are expensed as incurred. Under the successful efforts method of accounting, exploratory well costs are capitalized pending further evaluation of whether economically recoverable reserves have been found. If economically recoverable reserves are found, exploratory well costs will be capitalized as proved properties. If economically recoverable reserves are not found, exploratory well costs are expensed as dry holes. The application of the successful efforts method of accounting requires judgment to determine the proper designation of wells as either development or exploratory, which will ultimately determine the proper accounting treatment of costs of dry holes. Once a well is drilled, the determination that economic proved reserves have been discovered may take considerable time and judgment.

Crude Oil and Natural Gas Reserves. The successful efforts method of accounting inherently relies on the estimation of proved crude oil and natural gas reserves. Reserve quantities and the related estimates of future net cash flows are critical inputs in our calculation of units-of-production depletion and our evaluation of proved and unproved properties for impairment. The process of estimating and evaluating crude oil and natural gas reserves is complex, requiring the evaluation of available geological, geophysical, engineering, and economic data to estimate underground accumulations of crude oil and natural gas that cannot be precisely measured. Consequently, we engage an independent third-party reserve engineering firm, Ryder Scott, to audit our estimates of crude oil and natural gas reserves. Significant inputs and engineering assumptions used in developing the estimates of proved crude oil and natural gas reserves include reserves volumes, future operating and development costs, historical commodity prices, and our ability to convert proved undeveloped reserves to producing properties within five years of their initial proved booking.

The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history, and a continual reassessment of the viability of production under changing economic conditions. As a result, revisions in existing reserve estimates occur. We cannot predict the amounts or timing of such future revisions. If such revisions are significant, they could significantly affect future amortization of capitalized costs and result in impairment of proved and unproved properties.

Other Property and Equipment

Other property and equipment such as land, buildings, overhead electrical, leasehold improvements, office furniture and equipment, and computer hardware and software are recorded at cost. Cost of renewals and improvements that substantially extend the useful lives of the assets are capitalized. Maintenance and repair costs are expensed as incurred. Depreciation is calculated using the straight-line method over the estimated useful lives of the assets, which range from two to 25 years.

Leases

We evaluate contractual arrangements at inception to determine if it is a lease or contains an identifiable lease component. We recognize operating and finance leases with terms greater than 12 months on the accompanying consolidated balance sheets. Right-of-use assets represent our right to use the underlying assets for the lease term and the corresponding lease liabilities represent our obligations to make lease payments arising from the leases. Right-of-use assets and lease liabilities are recognized at the lease commencement date based on the present value of the lease payments over the lease term. When evaluating a contractual arrangement, we apply certain judgments to determine, among other factors, lease classification as either operating or financing, lease term, and discount rate. The terms of certain of our leases include options to extend or terminate the lease, only when we can ascertain that it is reasonably certain we will exercise that option, as well as evergreen periods for which the penalties associated with termination are considered to be significant. As we do not have any leases with an implicit interest rate that can be readily determined, we utilize our incremental borrowing rate based on information available at the lease commencement date in determining the present value of lease payments. We determine our incremental borrowing rate at the lease commencement date using our Credit Facility benchmark rate and make adjustments for facility utilization and lease term. Subsequent measurement, as well as presentation of expenses and cash flows, is dependent upon the classification of the lease as either an operating or finance lease. Refer to Note 13 - Leases for additional discussion.

Deferred Financing Costs

Deferred financing costs include origination, legal, and other fees incurred to issue senior notes or amend our Credit Facility. Deferred financing costs related to the Credit Facility are capitalized to prepaid expenses and other and other noncurrent assets on the accompanying consolidated balance sheets and amortized to interest expense on the accompanying consolidated statements of operations on a straight-line basis over the life of the Credit Facility. Deferred financing costs related to senior notes are capitalized within debt, net on the accompanying consolidated balance sheets and amortized to interest expense on the accompanying consolidated statements of operations using the effective interest method over the life of the respective borrowings. Refer to Note 5 - Debt for additional information.

Asset Retirement Obligations

We recognize an asset retirement obligation at fair value based on the present value of costs expected to be incurred in connection with the future abandonment of our crude oil and natural gas properties, including wells and facilities, in accordance with applicable regulatory requirements. This obligation, and the corresponding capitalized cost recorded to proved properties, is recognized at the time assets are acquired, a well is completed and begins production, or a facility is constructed. We recognize a periodic expense in connection with the accretion of the discounted asset retirement obligation over the remaining estimated economic lives of the respective long-lived assets. The accretion expense is recorded as a component of depreciation, depletion, and amortization in our accompanying consolidated statements of operations. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the corresponding capitalized cost recorded to proved properties.

The recognition of an asset retirement obligation requires management to make various assumptions informed by historical experience and applicable regulatory requirements including estimated plugging and abandonment costs, economic lives, inflation rates, and our credit-adjusted risk-free rate.

Cash paid to settle asset retirement obligations is included in the cash flows from operating activities section of the accompanying consolidated statements of cash flows. Refer to Note 10 - Asset Retirement Obligations for a reconciliation of our total asset retirement obligation liability as of December 31, 2025 and 2024.

Environmental Liabilities

We are subject to federal, state, and local environmental laws and regulations. These laws regulate the release, disposal, or discharge of materials into the environment or otherwise relate to environmental protection and may require us to remove or mitigate the environmental effects of the discharge, disposal, or release of hydrocarbons at various sites. Liabilities for future expenditures, including any associated with acquired assets, are recorded when environmental assessments and/or remediation arising outside of normal operations of the asset is probable and the costs can be reasonably estimated. Environmental liabilities are recorded in accounts payable and accrued expenses in our accompanying consolidated balance sheet and expensed within lease operating expense in our accompanying consolidated statement of operations.

Derivatives

We periodically enter into commodity derivative contracts to mitigate a portion of our exposure to potentially adverse market changes in commodity prices for our expected future crude oil and natural gas production and the associated impact on cash flows. Our commodity derivative contracts consist of swaps, collars, and basis protection swaps. The crude oil instruments are indexed to the New York Mercantile Exchange (“NYMEX”) West Texas Intermediate index (“WTI”) prices, and natural gas instruments are indexed to NYMEX Henry Hub index (“HH”) and Waha prices, an index commonly used in the Permian Basin, all of which have a high degree of historical correlation with actual prices received by, before differentials. As of December 31, 2025, all derivative counterparties were members of the Credit Facility lender group and all commodity derivative contracts are entered into for other-than-trading purposes. We do not designate our commodity derivative contracts as hedging instruments.

Commodity price derivative instruments are measured at fair value and are included in the accompanying consolidated balance sheets as derivative assets and liabilities, with the exception of derivative instruments that meet the “normal purchase normal sale” exclusion. We measure the fair value of our commodity price derivative instruments based upon a pricing model that utilizes market-based inputs, including, but not limited to, contractual price of the underlying position, current market prices, crude oil and natural gas forward curves, discount rates, volatility factors, and nonperformance risk. Changes in the fair value of our commodity price derivative instruments are recorded in the accompanying consolidated statements of operations as they occur.

As of December 31, 2025 and 2024, all of our derivative instruments are subject to master netting arrangements with various financial institutions. In general, the terms of our agreements provide for offsetting of amounts payable or receivable between us and the counterparty, 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 and therefore report our derivative asset and liability positions on a gross basis in the accompanying consolidated balance sheets.

Derivative gain, net as well as derivative cash settlement gain, net are included within the cash flows from operating activities section of the accompanying consolidated statements of cash flows. Refer to Note 9 - Derivatives for additional discussion.

Revenue Recognition

We recognize revenue from the sale of produced crude oil, natural gas, and NGL at the point in time when control of produced crude oil, natural gas, or NGL volumes transfer to the purchaser, which may differ depending on the applicable contractual terms. We consider the transfer of control to have occurred when the purchaser has the ability to direct the use of, and obtain substantially all of the remaining benefits from, the crude oil, natural gas, or NGL production. Transfer of control dictates the presentation of gathering, transportation, and processing costs within the accompanying consolidated statements of operations. Gathering, transportation, and processing costs incurred prior to the transfer of control are recorded gross within gathering, transportation, and processing in the accompanying consolidated statements of operations. Conversely, gathering, transportation, and processing costs incurred subsequent to the transfer of control are recorded net within crude oil, natural gas, and NGL sales on the accompanying consolidated statements of operations.

Crude oil sales. Under our crude purchase and marketing contracts, we deliver production at the wellhead or other contractually agreed-upon downstream delivery points and collect an agreed-upon index price, net of pricing differentials.

Natural gas and NGL sales. Under our natural gas processing contracts, we deliver natural gas to a midstream processing provider at the wellhead, inlet of the midstream processing provider’s system, or other contractually agreed-upon delivery points. The point at which control transfers varies between the inlet and tailgate of the midstream processing facility. The midstream processing provider gathers and processes the natural gas and remits proceeds to us for the resulting sales of NGL and residue gas.

For the contracts where we maintain control through the tailgate of the midstream processing facility, we recognize revenue on a gross basis, with gathering, transportation, and processing costs presented as an expense in the accompanying consolidated statements of operations. Alternatively, for those contracts where we relinquish control at the inlet of the midstream processing facility, we recognize natural gas and NGL revenues based on the contracted amount of the proceeds received from the midstream processing entity and, as a result, recognize revenue on a net basis.

In certain natural gas processing agreements, we may elect to take our natural gas residue and/or NGL in-kind at the tailgate of the midstream entity’s processing plant and subsequently market the product. Through the marketing process, we deliver product to the third-party purchaser at a contractually agreed-upon delivery point and receive a specified index price from the third-party purchaser. In this scenario, we recognize revenue when the control transfers to the third-party purchaser at the delivery point based on the transaction price received from the third-party purchaser. The gathering and processing costs attributable to the natural gas processing contracts, as well as any transportation cost incurred to deliver the product to the third-party purchaser, are presented as gathering, transportation, and processing in the consolidated statements of operations.

We record revenue for production in the month control is transferred to the purchaser. However, settlement statements and payment may not be received from the purchaser for one to two months after such time. Until settlement statements and payment are received from the purchaser, we record a revenue accrual based on, amongst other factors, an estimate of the production to which control has been transferred to the purchaser and the estimated prices to be received from the purchaser as determined by the applicable contractual terms. Generally, we record the differences between our revenue accrual and the actual amounts received for product sales in the month that payment is received from the purchaser. Any identified differences between our revenue accrual and actual amounts received for product sales historically have not been significant. For the years ended December 31, 2025 and 2024 revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material. Refer to Note 3 - Revenue Recognition for additional discussion.

Stock-Based Compensation

We recognize stock-based compensation based on the grant-date fair value of the equity instruments awarded. Stock-based compensation expense is recognized in the consolidated financial statements on a straight-line basis over the requisite service period for the entire award. We account for forfeitures of stock-based compensation awards as they occur. Refer to Note 7 - Stock-Based Compensation for additional discussion.

Income Taxes

We account for income taxes under the asset and liability method, which requires recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the balance sheet or tax returns. Deferred income tax assets and liabilities are measured using enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. If we determine that it is more-likely-than-not that some portion or all of the deferred income tax assets will not be realized, a valuation allowance is recorded, thereby reducing the deferred income tax assets to what is considered to be realizable.

We recognize the tax benefit from an uncertain tax position only if it is more-likely-than-not that the tax position will be sustained on examination by the taxing authorities based on the technical merits of the position. Our policy is to recognize interest and penalties related to uncertain tax positions in income tax expense. There were no uncertain tax positions during any period presented. Refer to Note 12 - Income Taxes for additional discussion.

Earnings Per Share

We use the treasury stock method to determine the effect of potentially dilutive instruments. Refer to Note 11 - Earnings Per Share for additional discussion.

Acreage Exchanges

From time to time, we enter into acreage exchanges in order to consolidate our core acreage positions, enabling us to have more control over the timing of development activities, achieve higher working interests, and provide us the ability to drill longer lateral length wells within those core areas. We account for our nonmonetary acreage exchanges in accordance with the guidance prescribed by Accounting Standards Codification (“ASC”) 845, Nonmonetary Transactions. For those exchanges that lack commercial substance, we record the acreage received at the net carrying value of the acreage surrendered to obtain it. For those acreage exchanges that are deemed to have commercial substance, we record the acreage received at fair value, with a related gain or loss recognized within other, net in the accompanying consolidated statements of operations in accordance with ASC 820, Fair Value Measurement.

Business Combinations

As part of our business strategy, we regularly pursue the acquisition of crude oil and natural gas properties. We utilize the acquisition method to account for acquisitions of businesses. Pursuant to this method, we allocate the cost of the acquisition, or purchase price, to assets acquired and liabilities assumed based on fair values as of the acquisition date. Refer to Note 2 - Acquisitions and Divestitures for additional discussion.

Fair Value of Financial Instruments

Our financial instruments consist of cash and cash equivalents, accounts receivable, and accounts payable and are carried at cost, which approximates fair value due to the short-term maturity of these instruments. As discussed above, our commodity price derivative instruments are recorded at fair value. Our Senior Notes, as defined in Note 5 - Debt, are recorded at cost, net of any unamortized discount and unamortized deferred financing costs, and their respective fair values are disclosed in Note 8 - Fair Value Measurements. The recorded value of our Credit Facility, as defined in Note 5 - Debt, approximates its fair value as it bears interest at a floating rate that approximates a current market rate. Our warrants are comprised of two tranches and were recorded at fair value upon issuance, with no recurring fair value measurement required. The first tranche expired out of the money in January 2025, and the second tranche was out of the money as of December 31, 2025 and expired out of the money in January 2026. No shares were issued pursuant to our warrants.

Considerable judgment is required to develop estimates of fair value. The estimates provided are not necessarily indicative of the amounts we would realize upon the sale or refinancing of such instruments. Refer to Note 8 - Fair Value Measurements for additional discussion.

NOTE 2 - ACQUISITIONS AND DIVESTITURES

The acquisition disclosed below is accounted for under the acquisition method of accounting for business combinations under ASC Topic 805, Business Combinations. Accordingly, we conducted assessments of the net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while transaction and integration costs associated with the acquisition were expensed as incurred. The fair value measurements of assets acquired and liabilities assumed were based on inputs that are not observable in the market, and therefore, represent Level 3 inputs. The fair values of crude oil and natural gas properties were measured using valuation techniques that converted future cash flows to a single discounted amount. Significant inputs to the valuation of the crude oil and natural gas properties included estimates of reserves, future operating and development costs, future commodity prices, estimated future cash flows, reserve adjustment factors, and a market-based weighted-average cost of capital. These inputs required significant judgments and estimates by management at the time of the valuation.

Vencer Acquisition

On January 2, 2024, we completed the acquisition of certain crude oil and natural gas assets from Vencer Energy, LLC (“Vencer”) for adjusted aggregate consideration of approximately $2.0 billion, inclusive of customary post-closing adjustments and $550 million in cash to be paid on or before January 3, 2025 (the “Vencer Acquisition”). The following tables present the consideration transferred and the final purchase price allocation of the assets acquired and the liabilities assumed in the Vencer Acquisition:

The purchase price allocation for the Vencer Acquisition was finalized as of the fourth quarter of 2024 with immaterial adjustments made to the preliminary allocation initially presented in the Quarterly Report on Form 10-Q for the quarter ended March 31, 2024, filed with the SEC on May 2, 2024.

Revenue and Earnings of the Acquiree

The results of operations for the Vencer Acquisition since the closing date have been included in our consolidated financial statements during the year ended December 31, 2024. The amount of revenue of Vencer included in our accompanying consolidated statements of operations was approximately $769 million during the year ended December 31, 2024. We determined that disclosing the amount of Vencer-related net income included in the accompanying consolidated statements of operations is impracticable as the operations from the acquisition were integrated into our operations from the date of the acquisition.

Supplemental Unaudited Pro Forma Financial Information

The results of operations for the Vencer Acquisition since the closing date have been included in our consolidated financial statements and therefore do not require pro forma disclosure for the year ended December 31, 2024.

Transaction Costs

Transaction costs related to an insignificant acquisition in the Permian Basin in 2025 and the Vencer Acquisition in 2024 are accounted for separately from the assets acquired and liabilities assumed and are included in transaction costs in the accompanying consolidated statements of operations. Transaction costs also include Merger-related costs in 2025 (excluding those contingent on the closing thereof) and costs related to divestitures of certain non-core DJ Basin assets in both 2024 and 2025. We incurred transaction costs of $20 million and $31 million during the years ended December 31, 2025 and 2024, respectively.

Non-Core DJ Basin Divestitures

In July 2025, we executed two Purchase and Sale Agreements (each a “PSA”) with two different buyers to divest certain non-core DJ Basin assets. These transactions closed on August 29, 2025 and October 1, 2025. The aggregate purchase price for these transactions was $435 million in cash consideration, subject to certain customary purchase price adjustments as set forth in each PSA.

NOTE 3 - REVENUE RECOGNITION

Crude oil, natural gas, and NGL sales revenue presented within the accompanying consolidated statements of operations is reflective of the revenue generated from contracts with customers. Revenue attributable to each identified revenue stream and operating region is disaggregated below (in millions):

NOTE 4 - ACCOUNTS PAYABLE AND ACCRUED EXPENSES

Accounts payable and accrued expenses contain the following (in millions):

NOTE 5 - DEBT

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

Credit Facility

We are party to a reserve-based revolving facility, as the borrower, with JPMorgan Chase Bank, N.A. (“JPMorgan”), as the administrative agent, and a syndicate of financial institutions, as lenders, that has an aggregate maximum commitment amount of $4.0 billion and is set to mature on August 2, 2028 (together with all amendments thereto, the “Credit Facility” or the “Credit Agreement”).

On February 21, 2025, we amended the Credit Agreement to increase our aggregate elected commitments from $2.2 billion to $2.5 billion. On May 28, 2025, we amended the Credit Agreement to, among other things, (i) decrease our borrowing base from $3.4 billion to $3.3 billion, (ii) reaffirm our aggregate elected commitments at $2.5 billion, and (iii) modify the definition of “Revolving Credit Maturity Date” (as defined in the Credit Agreement) to remove the springing maturity requirement that would otherwise cause the Credit Facility under the Credit Agreement to mature on the date that is 180 days prior to the scheduled maturity of our 2026 Senior Notes.

In October 2025, we completed our scheduled borrowing base redetermination which reaffirmed our borrowing base and aggregate elected commitments under the Credit Agreement. As of December 31, 2025, the borrowing base and aggregate elected commitments under the Credit Agreement were $3.3 billion and $2.5 billion, respectively.

Interest and commitment fees associated with the Credit Facility are accrued based on a revolving loan commitment utilization grid set forth in the Credit Agreement. Borrowings under the Credit Facility bear interest at a per annum rate equal to, at our option, either (i) the ABR plus the applicable margin, or (ii) the term-specific SOFR plus the applicable margin. ABR is established as a rate per annum equal to the greatest of (a) the rate of interest publicly announced by JPMorgan as its prime rate, (b) the applicable rate of interest published by the Federal Reserve Bank of New York plus 0.5%, or (c) the term-specific SOFR for an interest period of one month plus 1.0%, in each case, subject to a 1.5% floor, plus an applicable margin of 0.75% to 1.75% based on the utilization of the Credit Facility. Term-specific SOFR is based on one-, three-, or six-month terms as selected by us and is subject to a 0.5% floor, plus an applicable margin of 1.75% to 2.75%, based on the utilization of the Credit Facility. Interest on borrowings that bear interest at the SOFR are payable on the last day of the applicable interest period selected by us, and interest on borrowings that bear interest at the ABR are payable quarterly in arrears.

The Credit Facility is guaranteed by all our restricted domestic subsidiaries and is secured by first priority security interests on substantially all assets, including a mortgage on at least 90% of the total value of the proved properties evaluated in the most recently delivered reserve reports, including any engineering reports relating to the crude oil and natural gas properties of our restricted domestic subsidiaries, subject to customary exceptions.

The Credit Facility contains customary representations and affirmative covenants. The Credit Facility also contains customary negative covenants, which, among other things, and subject to certain exceptions, including the suspension and/or modification of certain covenants in the event that we receive investment grade credit ratings, include restrictions on (i) liens, (ii) indebtedness, guarantees and other obligations, (iii) restrictions in agreements on liens and distributions, (iv) mergers or consolidations, (v) asset sales, (vi) restricted payments, (vii) investments, (viii) affiliate transactions, (ix) change of business, (x) foreign operations or subsidiaries, (xi) changes to organizational documents, (xii) use of proceeds from loans and letters of credit, (xiii) hedging transactions, (xiv) additional subsidiaries, (xv) changes in fiscal year or fiscal quarter, (xvi) prepayments of certain debt and other obligations, (xvii) sales or discounts of receivables, and (xviii) dividend payment thresholds. 

In addition, we are subject to certain financial covenants under the Credit Facility, as tested on the last day of each fiscal quarter, including, without limitation, (a) a maximum ratio of our consolidated net indebtedness to earnings before interest, income taxes, depreciation, depletion, and amortization, exploration expense, and other non-cash charges (“permitted net leverage ratio”) of 3.00 to 1.00, (b) a current ratio, inclusive of the unused commitments under the Credit Facility then available to be borrowed, to not be less than 1.00 to 1.00, and (c) upon the achievement of investment grade credit ratings, a PV-9 coverage ratio of the net present value, discounted at 9% per annum, of the estimated future net revenues expected in the proved reserves to our total net indebtedness of not less than 1.50 to 1.00 (“PV-9 coverage ratio”). We were in compliance with all covenants under the Credit Facility as of December 31, 2025 and through January 29, 2026 (the date prior to the Closing Date).

The following table presents the outstanding balance, letters of credit outstanding, and available borrowing capacity under the Credit Facility as of the dates indicated (in millions):

As of December 31, 2025 and 2024, the unamortized deferred financing costs associated with amendments to the Credit Facility were $23 million and $29 million, respectively. Of the unamortized deferred financing costs, (i) $14 million and $21 million are presented within other noncurrent assets on the accompanying consolidated balance sheets as of December 31, 2025 and 2024, respectively, and (ii) $9 million and $8 million are presented within prepaid expenses and other on the accompanying consolidated balance sheets as of December 31, 2025 and 2024, respectively.

Senior Notes

The table below summarizes the face values (in millions), interest rates, maturity dates, and semi-annual interest payment dates related to our outstanding senior note obligations as of December 31, 2025:

2033 Senior Notes. On June 3, 2025, we issued $750 million aggregate principal amount of 9.625% Senior Notes due 2033 (the “2033 Senior Notes”), at par, pursuant to an indenture among us, Computershare Trust Company, N.A., as trustee, and the guarantors party thereto. Upon issuance of the 2033 Senior Notes, we received net proceeds of $743 million after deducting fees of $7 million. The net proceeds were used to repay a portion of the outstanding borrowings under our Credit Facility.

At any time prior to June 15, 2028, we may redeem all or part of the 2033 Senior Notes, in whole or in part, at a redemption price equal to the sum of (i) the principal amount thereof, plus (ii) the “make-whole” premium at the redemption date, plus (iii) accrued and unpaid interest, if any. On or after June 15, 2028, we may redeem all or part of the 2033 Senior Notes at redemption prices (expressed as percentages of the principal amount redeemed) equal to (i) 104.813% for the twelve-month period beginning on June 15, 2028; (ii) 102.406% for the twelve-month period beginning on June 15, 2029; and (iii) 100.000% for the period beginning June 15, 2030 and at any time thereafter, plus accrued and unpaid interest, if any.

We may redeem up to 35% of the aggregate principal amount of the 2033 Senior Notes at any time prior to June 15, 2028 with an amount not to exceed the net cash proceeds from certain equity offerings at a redemption price equal to 109.625% of the principal amount of the 2033 Senior Notes redeemed, plus accrued and unpaid interest, if any, thereon, provided, however, that (i) at least 65% of the aggregate principal amount of 2033 Senior Notes originally issued on the issue date (but excluding 2033 Senior Notes held by us and our subsidiaries) remains outstanding immediately after the occurrence of such redemption (unless all such 2033 Senior Notes are redeemed substantially concurrently) and (ii) the redemption occurs within 180 days after the date of the closing of such equity offering.

2030 Senior Notes. On October 17, 2023, we issued $1.0 billion aggregate principal amount of 8.625% Senior Notes due November 1, 2030 (the “2030 Senior Notes”), pursuant to an indenture among us, Computershare Trust Company, N.A., as trustee, and the guarantors party thereto. Upon issuance of the 2030 Senior Notes, we received net proceeds of $988 million after deducting fees of $12 million. The net proceeds were used to fund a portion of the consideration for the Vencer Acquisition.

At any time prior to November 1, 2026, we may redeem all or part of the 2030 Senior Notes, in whole or in part, at a redemption price equal to the sum of (i) the principal amount thereof, plus (ii) the “make-whole” premium at the redemption date, plus (iii) accrued and unpaid interest, if any. On or after November 1, 2026, we may redeem all or part of the 2030 Senior Notes at redemption prices (expressed as percentages of the principal amount redeemed) equal to (i) 104.313% for the twelve-month period beginning on November 1, 2026; (ii) 102.156% for the twelve-month period beginning on November 1, 2027; and (iii) 100.000% for the period beginning November 1, 2028 and at any time thereafter, plus accrued and unpaid interest, if any, to, but excluding, the redemption date (subject to the right of the noteholders on the relevant record date to receive interest on the relevant interest payment date).

We may redeem up to 35% of the aggregate principal amount of the 2030 Senior Notes at any time prior to November 1, 2026 with an amount not to exceed the net cash proceeds from certain equity offerings at a redemption price equal to 108.625% of the principal amount of the 2030 Senior Notes redeemed, plus accrued and unpaid interest, if any, provided, however, that (i) at least 65.0% of the aggregate principal amount of 2030 Senior Notes originally issued on the issue date (but excluding 2030 Senior Notes held by us and our subsidiaries) remains outstanding immediately after the occurrence of such redemption (unless all such 2030 Senior Notes are redeemed substantially concurrently) and (ii) the redemption occurs within 180 days after the date of the closing of such equity offering.

2028 Senior Notes and 2031 Senior Notes. On June 29, 2023, we issued $1.4 billion aggregate principal amount of 8.375% Senior Notes due July 1, 2028 (the “2028 Senior Notes”), pursuant to an indenture among us, Computershare Trust Company, N.A., as trustee, and the guarantors party thereto, and $1.4 billion aggregate principal amount of 8.750% Senior Notes due July 1, 2031 (the “2031 Senior Notes”), pursuant to an indenture among us, Computershare Trust Company, N.A., as trustee, and the guarantors party thereto. Upon issuance of the 2028 Senior Notes and 2031 Senior Notes, we received net proceeds of $2.7 billion after deducting fees of $34 million.

On or after July 1, 2025, we may redeem all or part of the 2028 Senior Notes at redemption prices (expressed as percentages of the principal amount redeemed) equal to (i) 104.188% for the twelve-month period beginning on July 1, 2025; (ii) 102.094% for the twelve-month period beginning on July 1, 2026; and (iii) 100.000% on or after July 1, 2027, plus accrued and unpaid interest, if any to, but excluding the redemption date.

At any time prior to July 1, 2026, we may redeem all or part of the 2031 Senior Notes, in whole or in part, at a redemption price equal to the sum of (i) the principal amount thereof, plus (ii) the “make-whole” premium at the redemption date, plus (iii) accrued and unpaid interest, if any. On or after July 1, 2026, we may redeem all or part of the 2031 Senior Notes at redemption prices (expressed as percentages of the principal amount redeemed) equal to (i) 104.375% for the twelve-month period beginning on July 1, 2026; (ii) 102.188% for the twelve-month period beginning on July 1, 2027; and (iii) 100.000% for the period beginning July 1, 2028 and at any time thereafter, plus accrued and unpaid interest, if any.

We may redeem up to 35% of the aggregate principal amount of the 2028 Senior Notes or 2031 Senior Notes at any time prior to July 1, 2025 or 2026, respectively, with an amount not to exceed the net cash proceeds from certain equity offerings at a redemption price equal to 108.375%, with respect to the 2028 Senior Notes, and 108.750%, with respect to the 2031 Senior Notes, of the principal amount of such series of 2028 Senior Notes and 2031 Senior Notes redeemed, plus accrued and unpaid interest, if any, provided, however, that (i) at least 65.0% of the aggregate principal amount of 2028 Senior Notes and 2031 Senior Notes of such series originally issued on the issue date (but excluding the 2028 Senior Notes and 2031 Senior Notes of such series held by us and our subsidiaries) remains outstanding immediately after the occurrence of such redemption (unless all such 2028 Senior Notes and 2031 Senior Notes are redeemed substantially concurrently) and (ii) the redemption occurs within 180 days after the date of the closing of such equity offering.

2026 Senior Notes. On October 13, 2021, we issued $400 million aggregate principal amount of 5.000% Senior Notes due November 1, 2026 (the “2026 Senior Notes”), pursuant to an indenture among us, Wells Fargo Bank, National Association, as trustee, and the guarantors party thereto. Given that the 2026 Senior Notes mature within 12 months of December 31, 2025, we have reclassified the principal and associated unamortized deferred financing costs to current liabilities.

We may redeem all or part of the 2026 Senior Notes at redemption prices equal to 100.000% on or after October 15, 2025, plus accrued and unpaid interest, if any.

The 2026 Senior Notes, 2028 Senior Notes, 2030 Senior Notes, 2031 Senior Notes, and 2033 Senior Notes (collectively, the “Senior Notes”) are unsecured senior obligations and rank equal in right of payment with all of the Company’s existing and any future unsecured senior debt and are senior in right of payment to any future subordinated debt. The Company may redeem some or all of its Senior Notes prior to their maturity at redemption prices that may include a premium, plus accrued and unpaid interest as described in the indentures governing the Senior Notes. The Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by all of our existing subsidiaries and are expected to be guaranteed by certain other future subsidiaries that may be required to guarantee the Senior Notes.

The indentures governing the Senior Notes contain covenants that limit, among other things, our ability and the ability of our subsidiaries to: (i) incur or guarantee additional indebtedness; (ii) create liens securing indebtedness; (iii) pay dividends on or redeem or repurchase stock or subordinated debt; (iv) make specified types of investments and acquisitions; (v) enter into or permit to exist contractual limits on the ability of our subsidiaries to pay dividends to us; (vi) enter into transactions with affiliates; and (vii) sell assets or merge with other companies. These covenants are subject to a number of important limitations and exceptions. We were in compliance with all covenants and all restricted payment provisions related to our Senior Notes as of December 31, 2025 and through January 29, 2026. The indentures governing the Senior Notes also contain customary events of default.

Deferred Acquisition Consideration

The Vencer Acquisition included deferred consideration of $550 million to be paid in cash on or before January 3, 2025. We discounted this obligation and recorded $532 million as deferred acquisition consideration upon closing and amortized the discount to interest expense in the accompanying consolidated statements of operations. During the year ended December 31, 2024, we paid $75 million of this deferred consideration, and during the year ended December 31, 2025, we paid the remaining $475 million. These payments are recorded as a cash outflow within the acquisitions of businesses, net of cash acquired in the accompanying consolidated statements of cash flows in the period of occurrence.

Interest Expense

For the years ended December 31, 2025 and 2024, we incurred interest expense of $453 million and $456 million, respectively. Interest expense for the year ended December 31, 2024 includes $37 million related to the amortization of deferred acquisition consideration associated with the Vencer Acquisition.

Impact of the Merger

Pursuant to the Merger Agreement, at the Closing Date, SM Energy fully repaid the outstanding borrowings (as applicable) and all outstanding commitments under the Credit Facility were terminated. The Senior Notes remain outstanding after the closing of the Merger, and SM Energy succeeded us as the issuer under the indentures governing the Senior Notes.

NOTE 6 - COMMITMENTS AND CONTINGENCIES

Commitments

Minimum Volume Agreement - Crude Oil. We are party to two transportation service agreements to deliver fixed and determinable quantities of crude oil. Under the terms of these agreements, we are required to make periodic deficiency payments for any shortfalls in delivering the minimum volume commitment of 20,000 Bbls per day over a term ending in December 2028, and 25,000 Bbls per day over a term ending in April 2030, resulting in a financial commitment fee over the remaining terms of $46 million and $64 million, respectively, as of December 31, 2025. We have not, and do not, expect to incur any deficiency payments.

Minimum Volume Agreement - Gas and Other. We are party to a gas gathering and processing agreement (the “Gathering Agreement”) with a third-party midstream provider over a term ending in December 2029 with an annual minimum volume commitment of 13.0 billion cubic feet of natural gas. The Gathering Agreement also includes a commitment to sell take-in-kind NGL from other processing agreements of 7,500 Bbls a day through 2026 with the ability to roll forward up to a 10% shortfall in a given month to the subsequent month. The Gathering Agreement is a value-based percentage of proceeds sales contract and our financial commitment fluctuates with commodity prices. The aggregate financial commitment fee over the remaining term was $39 million as of December 31, 2025. During the year ended December 31, 2025, we recorded $5 million in other operating expense in the accompanying consolidated statements of operations based on volume deficiencies relative to the minimum volume commitment. Based on current projections, we may incur approximately $7 million in additional shortfall payments under the Gathering Agreement during the remaining term of approximately four years. We are actively engaging alternative strategies to reduce any potential contract deficiencies incurred in future periods.

We are also party to additional individually immaterial agreements that require us to pay fees associated with the minimum volumes over various terms ending in December 2027, regardless of the amount delivered. The aggregate financial commitment fee over the remaining term for these contracts was $5 million as of December 31, 2025. We have not, and do not, expect to incur any deficiency payments.

The minimum annual payments under these agreements for the next five years as of December 31, 2025 are presented below (in millions):

Other commitments. We are party to a drilling commitment agreement with a third-party midstream provider such that we are required to drill and complete a total of 106 qualifying wells, whereby a minimum number of wells out of the total must be drilled by a deadline occurring every two years over a period ending December 31, 2026. The drilling commitment agreement provides for, among other things, a number of specifications such as minimum consecutive days of production, well performance, and lateral length. Wells operated by others can satisfy this commitment, subject to limitations. If we were to fail to complete the wells by the applicable deadline and our failure was not excused under the agreement, we would be in breach of the agreement and the third-party midstream provider could attempt to assert damages against us and our affiliates. As of January 29, 2026, we cannot reasonably estimate how much, if any, damages will be paid.

Refer to Note 13 - Leases for lease commitments.

Litigation and Legal Items 

We are involved in various legal proceedings. We review the status of these proceedings on an ongoing basis and, from time to time, may settle or otherwise resolve these matters on terms and conditions that management believes are in our best interests. We have provided the necessary estimated accruals in the accompanying balance sheets where deemed appropriate for litigation and legal related items that are ongoing and not yet concluded. Other than any ordinary routine litigation incidental to the business and except as described below, we are not currently a party to, nor is our property currently subject to, any material legal proceedings, and we are not aware of any such proceedings contemplated by governmental authorities.

On May 2, 2025, Jeremy Lin (the “Plaintiff”), individually and on behalf of all others similarly situated, filed a putative class action complaint for violation of federal securities laws against us, our former Chief Executive Officer, and our Chief Financial Officer (collectively, the “Defendants”) in the United States District Court for the District of New Jersey (the “Complaint”). The Complaint purported to bring a federal securities class action on behalf of a class of persons and entities other than the Defendants who acquired our securities between February 27, 2024 and February 24, 2025 and asserted violations of Sections 10(b) and 20(a) of the Exchange Act and Rule 10b-5 promulgated thereunder. The Complaint alleged, among other things, that the Defendants made materially false and misleading statements related to our business, operations and prospects, including our anticipated production volumes and financial condition in 2025. The Plaintiff sought, among other things, certification of a class, an award of unspecified compensatory damages, interest, costs and expenses, including attorneys’ fees and expert fees. On October 27, 2025, the Plaintiff filed a notice of voluntary dismissal of the action without prejudice and, on October 28, 2025, the court entered an order closing the case.

NOTE 7 - STOCK-BASED COMPENSATION

Long Term Incentive Plans

In June 2024, in connection with our stockholders’ approval at our 2024 annual meeting of stockholders, we adopted the 2024 Long Term Incentive Plan (the “2024 LTIP”), which provides for the issuance of restricted stock units, performance stock units, stock options, and various other forms of awards, and reserved 3,100,000 shares of common stock for issuance under the 2024 LTIP. The 2024 LTIP supersedes and replaces all of our previous long-term incentive plans (the “Prior Plans”), such that awards may not be granted under the Prior Plans subsequent to the adoption of the 2024 LTIP. Awards granted under the Prior Plans will remain subject to the terms and conditions set forth in the applicable Prior Plan. The Prior Plans and 2024 LTIP are collectively referred to herein as the “LTIP.”

We record compensation expense associated with the issuance of awards under the LTIP on a straight-line basis over the vesting period based on the fair value of the awards as of the date of grant within general and administrative expense in the accompanying consolidated statements of operations. The following table outlines the compensation expense recorded by type of award (in millions):

As of December 31, 2025, unrecognized compensation expense related to the awards granted under the LTIP will be amortized through the relevant periods as follows (in millions):

Restricted Stock Units and Deferred Stock Units

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

The following table presents the changes in non-vested RSUs and DSUs for the year ended December 31, 2025:

The aggregate grant-date fair value of the RSUs and DSUs granted under the LTIP during the year ended December 31, 2025 was $33 million.

Performance Stock Units

We grant market-based performance stock units (“PSUs”) to our officers and certain executives under the LTIP. The number of shares of our common stock issued to settle PSUs ranges from zero to 225% of the number of PSUs granted and is determined based on performance achievement against certain market-based criteria over a three-year performance period. Performance achievement is determined based on our annualized absolute total stockholder return (“TSR”). Absolute TSR is determined based upon the change in our stock price over the performance period plus dividends paid. PSUs generally vest on December 31 of the year preceding the third anniversary of the date of grant and settle by March 15 of the following year upon the determination and approval of performance achievement by the Compensation Committee of our Board.

The grant-date fair value of our PSUs is estimated using a Monte Carlo valuation model. The Monte Carlo valuation model is based on random projections of stock price paths and repeated numerous times to achieve a probabilistic assessment. Significant assumptions used in this valuation include our expected volatility as well as the volatilities for each of our peers and an interpolated risk-free interest rate based on U.S. Treasury yields with maturities consistent with the performance period.

The following table presents the change of non-vested PSUs for the year ended December 31, 2025:

The aggregate grant-date fair value of the PSUs granted under the LTIP during the year ended December 31, 2025 was $18 million. The performance period for PSUs granted in 2023 ended on December 31, 2025. In consideration of the Merger, the Compensation Committee of our Board approved performance achievement at target. These PSUs were assumed by SM Energy, as discussed below, and will be released during the first quarter of 2026.

The following table presents the range of assumptions used to determine the fair value of the PSUs with market-based settlement criteria as granted under the LTIP throughout each of the periods presented:

Impact of the Merger

Each of our non-vested RSU and DSU awards were assumed by SM Energy and remain subject to the same terms and conditions as were applicable to such award as of immediately prior to the Closing Date of the Merger. The non-vested RSUs and DSUs were converted into an award with respect to a number of shares of SM Energy equal to the product of (i) the number of shares of Civitas common stock subject to such RSU or DSU award immediately prior to the Closing Date of the Merger multiplied by (ii) 1.45. Pursuant to the terms of the RSU and DSU awards, a portion of the non-vested awards accelerated upon the closing of the merger related to the termination of certain employees without cause or separation of service for non-employee directors.

Each of our non-vested PSU awards were assumed by SM Energy and remain subject to the same terms and conditions as were applicable to such award as of immediately prior to the Closing Date of the Merger, excluding performance conditions. The PSUs were converted into an award with respect to a number of shares of SM Energy equal to the product of the target number of shares of Civitas common stock subject to such PSU award as of immediately prior to the Closing Date of the Merger multiplied by (ii) 1.45. Pursuant to the terms of the PSU awards, a portion of the non-vested awards accelerated upon closing of the merger related to the termination of certain employees without cause.

NOTE 8 - FAIR VALUE MEASUREMENTS

We follow authoritative accounting guidance for measuring the fair value of assets and liabilities. This guidance defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Further, this guidance establishes a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available.

The fair value hierarchy is broken down into three levels based on the reliability of the inputs as follows:

Level 1: Quoted prices in active markets for identical assets or liabilities 

Level 2: Quoted prices in active markets for similar assets and liabilities, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations whose inputs are observable or whose significant value drivers are observable

Level 3: Significant inputs to the valuation model are unobservable

We classify financial and non-financial assets and liabilities based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy.

Derivatives

We use Level 2 inputs to measure the fair value of crude oil and natural gas commodity price derivatives. The fair value of our commodity price derivatives is estimated using industry-standard models that contemplate various inputs including, but not limited to, the contractual price of the underlying position, current market prices, forward commodity price curves, volatility factors, time value of money, and the credit risk of both us and our counterparties. We validate our fair value estimate by corroborating the original source of inputs, monitoring changes in valuation methods and assumptions, and reviewing counterparty mark-to-market statements and other supporting documentation. Refer to Note 9 - Derivatives for more information regarding our derivative instruments.

The following table presents our financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2025 and 2024 and their classification within the fair value hierarchy (in millions):

Long-Term Debt

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

Our deferred acquisition consideration was recorded in connection with the Vencer Acquisition using an estimated fair value discount at the time of the transaction based on quoted market prices from our debt as well as other inputs classified as Level 2 within the fair value hierarchy. As of December 31, 2024, the carrying value of the deferred acquisition consideration approximated fair value. As of December 31, 2025, the remaining deferred acquisition consideration had been paid in full. Refer to Note 5 - Debt for additional information.

Acquisitions and Impairments of Proved and Unproved Properties

We measure acquired assets or businesses at fair value on a nonrecurring basis and review our proved and unproved crude oil and natural gas properties for impairment using inputs that are not observable in the market and are therefore designated as Level 3 within the valuation hierarchy. The most significant fair value determinations for non-financial assets and liabilities are related to crude oil and natural gas properties acquired. Refer to Note 2 - Acquisitions and Divestitures for additional information. During the years ended December 31, 2025 and 2024, we recorded no impairments of proved or unproved properties. Refer to Note 1 - Summary of Significant Accounting Policies for information on our policies for determining fair value of proved and unproved properties and related impairment expense.

NOTE 9 - DERIVATIVES

We periodically enter into commodity derivative contracts to mitigate a portion of our exposure to potentially adverse market changes in commodity prices for our expected future crude oil and natural gas production and the associated impact on our cash flows. Our commodity derivative contracts consist of swaps, collars, and basis protection swaps. As of December 31, 2025, all of our derivative counterparties were members of our Credit Facility lender group, and all commodity derivative contracts are entered into for other-than-trading purposes. We do not designate our commodity derivative contracts as hedging instruments.

A typical swap arrangement guarantees a fixed price on contracted volumes. If the agreed upon published third-party index price (“index price”) is lower than the fixed contract price at the time of settlement, we receive the difference. If the index price is higher than the fixed contact price at the time of settlement, we pay the difference.

A typical collar arrangement establishes a floor and ceiling price on contracted volumes through the use of a short call and a long put. When the index price is below the floor price at the time of settlement, we receive the difference. When the index price is above the ceiling price at the time of settlement, we pay the difference. When the index price is between the floor price and ceiling price, no payment or receipt occurs.

A typical basis protection swap arrangement guarantees a fixed price differential from a specified delivery point on contracted volumes. If the price differential is greater than the fixed contract differential at the time of settlement, we receive the difference. If the price differential is less than the fixed contract differential at the time of settlement, we pay the difference.

The following table summarizes the components of the derivative gain, net presented on the accompanying consolidated statements of operations for the periods below (in millions):

As of December 31, 2025, we had entered into the following commodity price derivative contracts:

Subsequent to December 31, 2025 and as of January 29, 2026, no additional commodity price derivative contracts were entered into.

Impact of the Merger

Upon the termination of the Credit Facility, all of our commodity price derivative contracts were novated to SM Energy.

Derivative Assets and Liabilities Fair Value 

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

NOTE 10 - ASSET RETIREMENT OBLIGATIONS

We recognize an estimated liability for future costs associated with the abandonment of our crude oil and natural gas properties, including facilities requiring decommissioning. A liability for the fair value of an asset retirement obligation and a corresponding increase to the carrying value of the related long-lived asset are recorded at the time a well is drilled or acquired, or a facility is constructed. The increase in carrying value is included in proved properties in the accompanying consolidated balance sheets. We deplete the amount added to proved properties and recognize expense in connection with the accretion of the discounted liability over the remaining estimated economic lives of the respective long-lived assets. Cash paid to settle asset retirement obligations is included in the cash flows from operating activities section of our accompanying consolidated statements of cash flows.

Our estimated asset retirement obligation liability is based on historical experience plugging and abandoning wells, estimated plugging and abandonment cost, estimated economic lives, and regulatory requirements. The liability is discounted using the credit-adjusted risk-free rate estimated at the time the liability is incurred or revised.

A roll-forward of our asset retirement obligation is as follows (in millions):

NOTE 11 - EARNINGS PER SHARE

Earnings per basic and diluted share are calculated under the treasury stock method. Basic net income per common share is calculated by dividing net income by the basic weighted-average common shares outstanding. Diluted net income per common share is calculated by dividing net income by the diluted weighted-average common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities consist of unvested RSUs, DSUs, PSUs as well as outstanding in-the-money stock options and warrants. When we recognize a loss from continuing operations, all potentially dilutive shares are anti-dilutive and are consequently excluded from the calculation of diluted earnings per share.

As discussed in Note 7 - Stock-Based Compensation, PSUs represent the right to receive a number of shares of the Company’s common stock ranging from zero to 225% of PSUs granted based on the performance achievement over the applicable performance period. The number of potentially dilutive shares related to PSUs is based on the number of shares, if any, that would be issuable at the end of the respective reporting period, assuming that date was the end of the performance period applicable to such awards.

We have also issued warrants, which represent the right to purchase our common stock at a specified exercise price. The number of potentially dilutive shares related to the warrants is based on the number of shares, if any, that would be exercisable at the end of the respective reporting period, assuming that date was the end of such warrants’ term. Warrants are only dilutive when the average price of the common stock during the period exceeds the exercise price. The exercise price of our warrants was in excess of our stock price during the years ended December 31, 2025 and 2024; therefore, they were excluded from the earnings per share calculation.

The following table sets forth the calculations of basic and diluted net earnings per common share (in millions, except share and per share amounts):

There were 657,420 and 253,489 unvested awards that were anti-dilutive for the years ended December 31, 2025 and 2024, respectively.

NOTE 12 - INCOME TAXES

Deferred tax assets and liabilities are measured by applying the provisions of enacted tax laws to determine the amount of taxes payable or refundable currently or in future years related to cumulative temporary differences between the tax basis of assets and liabilities and amounts reported in the accompanying consolidated balance sheets. The tax effect of the net change in the cumulative temporary differences during each period in the deferred tax assets and liabilities determines the periodic provision for deferred taxes.

The provision for income taxes consists of the following (in millions):

Temporary differences between the financial statement carrying amounts and tax basis of assets and liabilities that give rise to the net deferred tax liability and asset result from the following components (in millions):

We had $2.4 billion and $1.9 billion of net operating loss carryovers for federal income tax purposes as of December 31, 2025 and 2024, respectively. Due to change of ownership provisions of Section 382 of the Internal Revenue Code, utilization of net operating loss carryovers and other tax attributes are limited. Federal net operating loss carryforwards incurred prior to January 1, 2018 of $369 million will begin to expire in 2037. Federal net operating loss carryforwards incurred after December 31, 2017 of $2.0 billion have no expiration and can only be used to offset 80% of taxable income when utilized.

We assess the recoverability of our deferred tax assets each period by considering whether it is more likely than not that all or a portion of the deferred tax assets will be realized. In making such a determination, we consider all available evidence (both positive and negative), including future reversals of temporary differences, tax-planning strategies, projected future taxable income, and results of operations. As a result of merger activity in 2021, we recorded a valuation allowance of $25 million, which continued to be recorded as of December 31, 2025 and 2024, against certain acquired net operating losses and other tax attributes due to the limitation on realizability caused by the change of ownership provisions of Section 382 of the Internal Revenue Code. We will continue to monitor facts and circumstances in the reassessment of the likelihood that the deferred tax assets will be realized.

Recorded income tax expense differs from the amount that would be provided by applying the statutory United States federal income tax rate of 21% to income before income taxes due to state income taxes and other changes outlined as follows (in millions):

Acquisitions, divestitures, drilling activity, and the prices received for crude oil, natural gas, and NGL impact the apportionment of taxable income to the states where we own crude oil and natural gas properties. As these factors change, our state income tax rate changes. This change, when applied to our total temporary differences, impacts the total state income tax expense (benefit) reported in the current year.

We had no unrecognized tax benefits as of December 31, 2025 and 2024. As of December 31, 2025, the Company is subject to U.S. federal and state income tax examination for the years ended December 31, 2024, 2023, and 2022. Tax returns for years prior to 2022 may remain open with respect to net operating loss carryforwards that are utilized in a later year, as tax attributes from prior years can be adjusted during an audit of a later year.

On July 4, 2025, President Trump signed into law the One Big Beautiful Bill Act (“OBBBA”). The OBBBA made permanent key elements of the Tax Cuts and Jobs Act of 2017, including favorable tax treatment of 100% bonus depreciation and interest expense. Consistent with ASC Topic 740, Income Taxes, we have completed our evaluation of the impact of the OBBBA and recognized the effects in the income tax provision for the year ended December 31, 2025. While the OBBBA did not materially impact our income tax expense or effective tax rate for the year ended December 31, 2025, its favorable provisions resulted in the deferral of certain income taxes previously reflected in income taxes payable on the accompanying balance sheets as of December 31, 2025.

NOTE 13 - LEASES

Our right-of-use assets and lease liabilities are recognized on the accompanying consolidated balance sheets within other noncurrent assets, other liabilities, and other long-term liabilities based on the present value of the expected lease payments over the lease term. The following table summarizes the asset classes of our operating leases (in millions):

The following table summarizes the components of our gross lease costs incurred for the periods below (in millions):

Lease costs disclosed above are presented on a gross basis. A portion of these costs may have been or will be billed to other working interest owners. Our net share of these costs is included in various line items on the accompanying consolidated statements of operations or capitalized to proved properties or other property and equipment, as applicable.

We recognize operating lease cost on a straight-line basis. Short-term lease costs are recognized as incurred and represent payments for leases with a lease term of one year or less, excluding leases with a term of one month or less.

Our weighted-average remaining lease terms and discount rates as of December 31, 2025 are as follows:

Future commitments by year for our leases with a lease term of greater than one year as of December 31, 2025 are presented in the table below. Such commitments are reflected at undiscounted values and are reconciled to the discounted present value recognized on the accompanying consolidated balance sheets as follows (in millions):

NOTE 14 - SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION

Supplemental cash flow disclosures are presented below (in millions):

NOTE 15 - STOCKHOLDERS’ EQUITY

Capital Return Program

In August 2025, our Board reinstated a capital return strategy of allocating 50% of our annual Adjusted Free Cash Flow, after the base dividend, which remained $0.50 per share quarterly, to share repurchases. In conjunction with this decision, our Board increased the amount authorized for repurchases remaining under our then existing stock repurchase program to $750 million. However, pursuant to terms of the Merger Agreement, we were prohibited from (i) repurchasing shares of our common stock pending the closing of the Merger and (ii) paying quarterly dividends in excess of our $0.50 base dividend.

Stock Repurchases

Prior to entry into the Merger Agreement, we were permitted, under our then existing stock repurchase program, to repurchase our outstanding shares of common stock, in the open market, in privately negotiated transactions, or through block trades, derivative transactions, or purchases made in accordance with Rule 10b-18 and Rule 10b5-1 of the Exchange Act.

We record stock repurchases at cost, which includes transaction costs that are direct and incremental to the repurchase, as a reduction to stockholders’ equity. As part of the transaction costs that are direct and incremental to the repurchase and, subject to netting against the fair value of stock issuances, we record a 1% excise tax with the corresponding liability recorded within accounts payable and accrued expenses on the accompanying consolidated balance sheets. Any excess cost over the par value is charged to additional paid-in-capital on a pro-rata basis, with any remaining cost charged to retained earnings.

On August 8, 2025, we entered into an accelerated share repurchase agreement (the “ASR Agreement”) with a financial institution (the “Counterparty”) to repurchase an aggregate of $250 million (the “Repurchase Price”) of our common stock. Under the terms of the ASR Agreement, we paid the Repurchase Price and received an initial delivery of 6,646,726 shares of our common stock from the Counterparty, representing 80% of the Repurchase Price based on the closing price of our common stock on August 7, 2025. Final settlement of the ASR Agreement occurred in September 2025, pursuant to which we received an additional 733,832 shares of our common stock from the Counterparty.

The table below summarizes stock repurchases pursuant to the stock repurchase program during the year ended December 31, 2025 and 2024:

These stock repurchases were funded from our cash on hand, and the shares were immediately retired. As of December 31, 2025, $500 million remained available under the program for repurchase of our outstanding common stock.

Dividends

The following table summarizes the dividends declared for the years ended December 31, 2025 and 2024 (in millions, except per share amounts):

All RSUs, DSUs, and PSUs receive a dividend equivalent per unit, recognized as a liability included in other liabilities and other long-term liabilities on the accompanying consolidated balance sheets until the recipients receive the dividend equivalents. Refer to Note 7 - Stock-Based Compensation for further discussion around our LTIP.

NOTE 16 - SEGMENT REPORTING

We aggregate and report our crude oil and natural gas exploration and production operations in one reportable upstream segment. The Permian Basin and the DJ Basin are operating segments of the Company that we aggregate into the upstream segment due to the similarity of these domestic operations. The upstream segment derives revenue from the sale of produced crude oil, natural gas, and NGL. We consider our midstream functions as ancillary to our upstream segment. Our chief operating decision maker (“CODM”) is our Interim Chief Executive Officer.

The accounting policies of the upstream segment are the same as those described in Note 1 - Summary of Significant Accounting Policies. The measure of profit or loss that the CODM uses to assess performance and allocate resources for the upstream segment is Adjusted EBITDAX. Adjusted EBITDAX is defined as earnings before interest, income taxes, depreciation, depletion, and amortization, exploration expense, and other non-cash and non-recurring charges. The measure of segment assets is reported on the accompanying consolidated balance sheets as total consolidated assets and capital expenditures are reported in our statements of cash flows. The CODM uses Adjusted EBITDAX to evaluate income generated from segment assets in deciding whether to reinvest profits into the upstream segment or into other activities, such as for acquisitions, debt reduction, or to return capital to stockholders.

The CODM is regularly provided with only the consolidated expenses as noted on the face of the consolidated statements of operations. Significant segment expenses included in Adjusted EBITDAX are lease operating expense, midstream operating expense, gathering, transportation, and processing, severance and ad valorem taxes, general and administrative expenses, and derivative cash settlement gain, net.

The following table presents a reconciliation of reportable segment Adjusted EBITDAX to income from operations before income taxes (in millions):

NOTE 17 - DISCLOSURES ABOUT CRUDE OIL AND NATURAL GAS PRODUCING ACTIVITIES (UNAUDITED)

Our crude oil and natural gas activities are located entirely within the United States. Costs incurred in the acquisition, development, and exploration of crude oil and natural gas properties, whether capitalized or expensed, are summarized below (in millions):

Suspended Well Costs

We did not incur any exploratory well costs during the years ended December 31, 2025 and 2024.

Reserves

The proved reserve estimates as of December 31, 2025 and 2024 were audited by Ryder Scott. The estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes, and other factors.

All of our crude oil, natural gas, and NGL reserves are attributable to properties within the United States. A summary of our changes in quantities of proved crude oil, natural gas, and NGL reserves for the years ended December 31, 2025 and 2024 are as follows:

⁽¹⁾        Items may not recalculate due to rounding.

During the years ended December 31, 2025 and 2024, horizontal development resulted in extensions, discoveries, and other additions of 145.5 MMBoe and 101.8 MMBoe, respectively.

During the years ended December 31, 2025 and 2024, proved undeveloped reserves were reduced by 6.8 MMBoe and 24.1 MMBoe, respectively, primarily due to the removal of proved undeveloped locations from our five-year drilling program.

As of December 31, 2025, we revised our proved reserves upward by 9.6 MMBoe. The 9.6 MMBoe positive revision of proved reserves as compared to previous estimates was the result of: (i) positive revisions of 33.5 MMBoe related to lower operating costs and (ii) positive revisions of 4.5 MMBoe related to increases in interest and other. These positive revisions were partially offset by (iii) negative price-related revisions of 17.9 MMBoe that resulted from the decrease to SEC prices for crude oil of $10.14 to $65.34 per Bbl WTI, which were partially offset by an increase in SEC prices for natural gas of $1.26 to $3.39 per MMBtu HH and (iv) negative performance-related revisions of 10.5 MMBoe.

As of December 31, 2024, we revised our proved reserves downward by 8.1 MMBoe. The 8.1 MMBoe negative revision of proved reserves as compared to previous estimates was the result of: (i) negative revisions of 23.0 MMBoe driven by 2024 negative Waha pricing differentials, natural gas shrinks, and NGL yields, (ii) negative revisions of 12.8 MMBoe from non-producing wells that have been or are planned to be plugged and abandoned and other, and (iii) negative price-related revisions of 9.6 MMBoe that resulted from the decrease to SEC prices of $2.74 to $75.48 per Bbl WTI for crude oil and $0.51 to $2.13 per MMBtu HH for natural gas. Negative revisions were partially offset by 27.6 MMBoe from updates to well performance and 9.7 MMBoe for increases in interest and other.

The standardized measure of discounted future net cash flows relating to proved reserves were prepared in accordance with authoritative accounting guidance. Future cash inflows were computed by applying prices to estimated future production. Future production and development costs are computed by estimating the expenditures to be incurred in developing, producing, and plugging and abandoning the proved reserves at year-end, based on current costs and assuming continuation of existing economic conditions.

Future income tax expenses are calculated by applying appropriate year-end tax rates to future pretax net cash flows relating to proved reserves. Future income tax expenses give effect to permanent differences, tax credits, and loss carryforwards relating to the proved reserves. Future net cash flows are discounted at a rate of 10% annually to derive the standardized measure of discounted future net cash flows. This calculation procedure does not necessarily result in an estimate of the fair market value or the present value of our crude oil and natural gas properties.

The standardized measure of discounted future net cash flows relating to proved reserves are as follows (in millions):

Future cash flows as shown above were reported without consideration for the effects of derivative transactions outstanding at period end.

The changes in the standardized measure of discounted future net cash flows relating to proved reserves are as follows (in millions):

Reserve estimates are based on an unweighted 12-month arithmetic average of first-day-of-the-month prices inclusive of adjustments for quality and location as of December 31, 2025 and 2024, as required by the SEC.

CIVITAS RESOURCES, INC. AND SUBSIDIARIES

SUPPLEMENTAL FINANCIAL INFORMATION (UNAUDITED)

Sales Volumes

The following table presents crude oil, natural gas, and NGL sales volumes by operating region for the periods presented:

Reconciliation of Net Income to Adjusted EBITDAX

Adjusted EBITDAX is a supplemental non-GAAP financial measure that represents earnings before interest, income taxes, depreciation, depletion, and amortization, exploration expense, and other non-cash and non-recurring charges. Adjusted EBITDAX excludes certain items that we believe affect the comparability of operating results and can exclude items that are generally non-recurring in nature or whose timing and/or amount cannot be reasonably estimated. We present Adjusted EBITDAX because we believe it provides useful additional information to investors and analysts, as a performance measure, for analysis of our ability to internally generate funds for exploration, development, acquisitions, and to service debt. We are also subject to financial covenants under our Credit Facility based on Adjusted EBITDAX ratios. In addition, Adjusted EBITDAX is widely used by professional research analysts and others in the valuation, comparison, and investment recommendations of companies in the crude oil and natural gas exploration and production industry. Adjusted EBITDAX should not be considered in isolation or as a substitute for net income, net cash provided by operating activities, or other profitability or liquidity measures prepared under GAAP. Because Adjusted EBITDAX excludes some, but not all items that affect net income and may vary among companies, the Adjusted EBITDAX amounts presented may not be comparable to similar metrics of other companies.

The following table presents a reconciliation of the GAAP financial measure of net income to the non-GAAP financial measure of Adjusted EBITDAX for the periods presented (in millions):