What did SM Energy (SM) announce regarding new senior notes?

SM Energy intends a private offering of $750,000,000 senior notes due 2034. The notes will be sold only to qualified institutional buyers under Rule 144A and to non-U.S. persons under Regulation S, relying on exemptions from Securities Act registration requirements.

How is SM Energy (SM) using proceeds from the 2034 senior notes offering?

SM Energy plans to use net proceeds, with cash on hand and/or credit facility borrowings, to fund a cash tender offer. That offer targets up to $750,000,000 of its 8.375% senior notes due 2028, as described in the Offer to Purchase dated March 4, 2026.

What are the key terms of SM Energy’s (SM) tender offer for 2028 notes?

The company is offering to buy up to $750,000,000 of 8.375% notes due 2028 from $1.350 billion outstanding. Early tenders by March 17, 2026 receive total consideration of $1,031.75 per $1,000 principal, including a $50 early tender premium, plus accrued interest if purchased.

When does SM Energy’s (SM) tender offer for 2028 notes end?

The tender offer is scheduled to expire at 5:00 p.m. New York City time on April 1, 2026. An Early Tender Date of March 17, 2026 provides higher total consideration, and settlement dates are expected shortly after the early and final deadlines, subject to conditions.

What additional Civitas-related information did SM Energy (SM) file?

SM Energy filed Civitas Resources’ audited financial statements for 2024 and 2025, unaudited pro forma condensed combined financial information, and a Civitas reserve report as of December 31, 2025. These exhibits provide historical and pro forma data following SM Energy’s completed merger with Civitas.

Who can buy SM Energy’s (SM) new 2034 notes in the private offering?

The notes are being offered only to investors reasonably believed to be qualified institutional buyers under Rule 144A and to non-U.S. persons outside the United States under Regulation S. The securities will not be registered under the Securities Act or state securities laws.

SM Energy plans $750M notes and tender offer

Exhibit 99.1

News Release

SM ENERGY ANNOUNCES PRIVATE OFFERING OF $750 MILLION OF SENIOR NOTES DUE 2034

DENVER - Mar. 4, 2026 - SM Energy Company (“SM Energy” or “the Company”) (NYSE: SM) announced today that, subject to market conditions, it intends to offer $750 million aggregate principal amount of its senior notes due 2034 (the “Notes”).

SM Energy intends to use the net proceeds from the offering of the Notes, together with cash on hand and/or borrowings under its revolving credit facility, to fund an offer to purchase for cash up to $750 million of its outstanding $1.350 billion principal amount of its 8.375% Senior Notes due 2028 (the “2028 Notes”), solely upon the terms and conditions described in the Company's Offer to Purchase, dated March 4, 2026.

The Notes to be offered will not be registered under the Securities Act of 1933, as amended (the “Securities Act”), or under any state or other securities laws, and the Notes will be issued pursuant to an exemption therefrom, and may not be offered or sold within the United States, or to or for the account or benefit of any U.S. person, absent registration or an applicable exemption from registration requirements. The Notes are being offered only to persons reasonably believed to be qualified institutional buyers under Rule 144A under the Securities Act and non-U.S. persons outside the United States in accordance with Regulation S under the Securities Act.

This press release does not constitute an offer to sell, a solicitation to buy, or an offer to purchase or sell any securities, nor shall there be any sale of these securities in any state or jurisdiction in which such offer, solicitation, or sale would be unlawful prior to registration or qualification under the securities laws of any such state or jurisdiction. This press release is not an offer to purchase the 2028 Notes.

DISCLOSURES

FORWARD LOOKING STATEMENTS

This press release contains "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements in this release include the intended use of offering proceeds and other aspects of the Notes offering. These statements involve known and unknown risks and uncertainties, including market conditions, customary offering closing conditions and other factors described in the Confidential Offering Memorandum, which may cause SM Energy's actual results to differ materially from results expressed or implied by the forward-looking statements included in this communication. All such factors are difficult to predict and are beyond SM Energy's control, including those detailed in SM Energy's annual report on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K. All forward-looking statements are based on assumptions that SM Energy believes to be reasonable but that may not prove to be accurate. Such forward-looking statements are based on assumptions and analyses made by SM Energy in light of its perceptions of current conditions, expected future developments, and other factors that SM Energy believes are appropriate under the circumstances. These statements are subject to a number of known and unknown risks and uncertainties. Forward-looking statements are not guarantees of future performance and actual results may be materially different from those expressed or implied in the forward-looking statements. The forward-looking statements in this press release speak as of the date of this press release.

ABOUT THE COMPANY

SM Energy Company is an independent energy company engaged in the acquisition, exploration, development, and production of crude oil, natural gas, and NGLs in the states of Colorado, New Mexico, Texas and Utah. SM Energy routinely posts important information about the Company on its website.

INVESTOR CONTACTS

Patrick Lytle, plytle@sm-energy.com, 303-864-2502

Meghan Dack, mdack@sm-energy, 303-837-2426

Exhibit 99.2

News Release

SM ENERGY COMPANY ANNOUNCES CASH TENDER OFFER FOR UP TO $750.0 MILLION AGGREGATE PRINCIPAL AMOUNT OF 8.375% SENIOR NOTES DUE 2028 ORIGINALLY ISSUED BY CIVITAS RESOURCES

DENVER - Mar. 4, 2026 - SM Energy Company (“SM Energy”) (NYSE: SM) today announced that it has commenced a cash tender offer to purchase (the “Tender Offer”) up to an aggregate principal amount not to exceed $750,000,000 (as it may be modified by SM Energy, the “Maximum Tender Amount”), of the outstanding 8.375% Senior Notes due 2028 (CUSIP Numbers Rule 144A: 17888HAA1 / Reg. S: U1638HAA5) (the “Notes”), originally issued by Civitas Resources, Inc. (“Civitas”), and assumed by SM Energy in connection with the closing of its merger with Civitas, subject to the terms and conditions set forth in the Offer to Purchase dated March 4, 2026 (as it may be amended or supplemented from time to time, the “Offer to Purchase”). The following table sets forth certain terms of the Tender Offer:

Title of Notes		CUSIP Numbers / ISIN		Aggregate Principal Amount Outstanding⁽¹⁾				Maximum Tender Amount				Tender Offer Consideration⁽²⁾⁽³⁾				Early Tender Premium⁽²⁾⁽⁴⁾				Total Consideration⁽²⁾⁽⁵⁾
8.375% Senior Notes due 2028		17888HAA1 / US17888HAA14 U1638HAA5 / USU1638HAA50		$	1,350,000,000			$	750,000,000			$	981.75			$	50			$	1,031.75

(1)

As of the date of this press release.

(2)

Holders will also receive accrued and unpaid interest from the last interest payment with respect to the Notes accepted for purchase to, but not including, the Early Settlement Date (as defined below) or the Final Settlement Date (as defined below), as applicable.

(3)

For each $1,000 principal amount of Notes validly tendered in the Tender Offer after the Early Tender Date (as defined below) but at or prior to the Expiration Date (as defined below) and accepted for purchase.

(4)

For each $1,000 principal amount of Notes validly tendered and not validly withdrawn in the Tender Offer at or prior to the Early Tender Date and accepted for purchase.

(5)

For each $1,000 principal amount of Notes validly tendered and not validly withdrawn in the Tender Offer at or prior to the Early Tender Date and accepted for purchase. Includes the Early Tender Premium.

The Tender Offer will expire at 5:00 p.m., New York City time, on April 1, 2026, unless extended (such date and time, as the same may be extended, the “Expiration Date”). Holders who validly tender their Notes at or prior to 5:00 p.m., New York City time, on March 17, 2026, unless such date is extended or earlier terminated (the “Early Tender Date”), will be eligible to receive the “Total Consideration” set forth in the table above for each $1,000 principal amount of Notes. The Total Consideration includes the “Early Tender Premium” set forth in the table above. Holders who validly tender their Notes after the Early Tender Date, but at or prior to the Expiration Date, and do not validly withdraw such Notes, will only be eligible to receive the “Tender Offer Consideration” as set forth in the table above, which does not include the Early Tender Premium. In addition to the Total Consideration or the Tender Offer Consideration, as applicable, holders who validly tender and do not validly withdraw Notes and whose Notes are accepted for purchase will receive accrued and unpaid interest, up to, but not including, the applicable settlement date. The settlement date with respect to all Notes validly tendered at or prior to the Early Tender Date and not validly withdrawn and accepted for purchase is expected to be the second business day after the Early Tender Date, or as promptly as practicable thereafter (such date, as the same may be extended, the “Early Settlement Date”). The Early Settlement Date is currently expected to be on March 19, 2026. If the Tender Offer is not fully subscribed as of the Early Settlement Date, the settlement date with respect to all Notes validly tendered after the Early Tender Date, but at or prior to the Expiration Date, and not validly withdrawn, is expected to be on the second business day after the Expiration Date, or promptly thereafter (such date, as the same may be extended, the “Final Settlement Date”). The Final Settlement Date is currently expected to be April 3, 2026.

Notes validly tendered may not be withdrawn after 5:00 p.m., New York City time, on March 17, 2026 (such date and time, as the same may be extended, the “Withdrawal Date”), except as may be required by law.

Notes validly tendered at or prior to the Early Tender Date will be accepted for purchase with priority over the Notes validly tendered after the Early Tender Date, but at or prior to the Expiration Date.

Acceptance for tenders of the Notes may be subject to proration if the aggregate principal amount of the Notes validly tendered and not validly withdrawn is greater than the Maximum Tender Amount. Furthermore, if the Tender Offer to purchase Notes is fully subscribed as of the Early Tender Date, holders who validly tender Notes after the Early Tender Date will not have any of their Notes accepted for purchase and there will be no Final Settlement Date.

SM Energy reserves the right, but is under no obligation, to increase the Maximum Tender Amount at any time, subject to compliance with applicable law. If SM Energy increases the Maximum Tender Amount, it does not expect to extend the Withdrawal Date, subject to applicable law.

The completion of the Tender Offer is subject to a number of conditions that are set forth in the Offer to Purchase, including, among other things, the successful completion by SM Energy of a new senior debt offering. The Tender Offer is not conditioned on any minimum amount of Notes being tendered.

The terms and conditions of the Tender Offer, including SM Energy’s obligation to accept the Notes tendered and pay the purchase price therefor, are set forth in the Offer to Purchase. SM Energy may, at its own discretion, amend, extend or, subject to certain conditions, terminate the Tender Offer.

SM Energy has retained BofA Securities, Inc. as dealer manager and solicitation agent. Questions regarding the Tender Offer may be directed to BofA Securities, Inc. at (980) 683-1735 or by e-mail at debt_advisory@bofa.com. For questions concerning delivery by means of the Automated Tender Offer Program and to obtain copies of the Offer to Purchase, please contact the Information Agent, D.F. King & Co., Inc. at (877) 732-3617 (toll-free) and (212) 257-2543 or by e-mail at sm@dfking.com.

This press release does not constitute an offer to purchase or redeem or the solicitation of an offer to sell the securities described herein, nor shall there be any sale of these securities in any state or jurisdiction in which such offer, solicitation or sale would be unlawful prior to registration or qualification under the securities laws of any such state or jurisdiction.

DISCLOSURES

FORWARD-LOOKING STATEMENTS

This press release contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, included in this press release that address activities, events, or developments that we expect, believe, or anticipate will or may occur in the future are forward-looking statements. The words “action,” “anticipate,” “deliver,” “demonstrate,” “establish,” “estimate,” “expects,” “goal,” “generate,” “guidance,” “integrate,” “maintain,” “objectives,” “optimize,” “project,” “target,” and similar expressions are intended to identify forward-looking statements. Forward-looking statements in this release include, but are not limited to, among other things, the completion of the Tender Offer. Such forward-looking statements are based on assumptions and analyses made by SM Energy in light of its experience and its perception of historical trends, current conditions, expected future developments, and other factors that SM Energy believes are appropriate under the circumstances. These statements involve known and unknown risks, which may cause SM Energy’s actual results to differ materially from results expressed or implied by the forward-looking statements. Future results may be impacted by the risks discussed in the Risk Factors section of SM Energy’s most recent Annual Report on Form 10-K, as such risk factors may be updated from time to time in SM Energy’s other periodic reports filed with the Securities and Exchange Commission. Forward-looking statements are not guarantees of future performance and actual results or performance may be materially different from those expressed or implied in the forward-looking statements. The forward-looking statements contained herein speak as of the date of this release. Although SM Energy may from time to time voluntarily update its prior forward-looking statements, it disclaims any commitment to do so, except as required by securities laws.

ABOUT THE COMPANY

SM Energy Company is an independent energy company engaged in the acquisition, exploration, development, and production of crude oil, natural gas, and natural gas liquids in the states of Colorado, New Mexico, Texas and Utah. SM Energy routinely posts important information about the Company on its website. For more information about SM Energy, please visit its website at www.sm-energy.com.

INVESTOR CONTACTS

Patrick Lytle, plytle@sm-energy.com, 303-864-2502

Meghan Dack, mdack@sm-energy.com, 303-837-2426

Exhibit 99.3

CIVITAS RESOURCES, INC. AND SUBSIDIARIES

Annual Consolidated Financial Statements

For the Year Ended December 31, 2025

TABLE OF CONTENTS

		PAGE
Independent Auditor’s Report		1

Consolidated Financial Statements
Consolidated Balance Sheets as of December 31, 2025 and December 31, 2024		4
Consolidated Statements of Operations for the Years Ended December 31, 2025 and 2024		5
Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2025 and December 31, 2024		6
Consolidated Statements of Cash Flows for the Years Ended December 31, 2025 and 2024		7

Notes to the Consolidated Financial Statements		8

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.

1

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:

·	Exercise professional judgment and maintain professional skepticism throughout the audit.

·

Identify and assess the risks of material misstatement of the financial statements, whether due to fraud or error, and design and perform audit procedures responsive to those risks. Such procedures include examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements.

·	Obtain an understanding of internal control relevant to the audit in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control. Accordingly, no such opinion is expressed.

·	Evaluate the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluate the overall presentation of the financial statements.

·	Conclude whether, in our judgment, 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 a reasonable period of time.

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.

2

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

3

CIVITAS RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in millions, except per share amounts)

	As of December 31,
	2025			2024
ASSETS
Current assets:
Cash and cash equivalents	$	77		$	76
Accounts receivable, net:
Crude oil, natural gas, and NGL sales		489			646
Joint interest and other		114			125
Derivative assets		192			67
Prepaid expenses and other		95			74
Total current assets		967			988
Property and equipment (successful efforts method):
Proved properties		19,092			16,897
Less: accumulated depreciation, depletion, and amortization		(6,103	)		(4,288	)
Total proved properties, net		12,989			12,609
Unproved properties		194			631
Wells in progress		387			506
Other property and equipment, net of accumulated depreciation of $11 million in 2025 and $9 million in 2024		58			48
Total property and equipment, net		13,628			13,794
Derivative assets		7			17
Other noncurrent assets		150			145
Total assets	$	14,752		$	14,944
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	515		$	561
Severance and ad valorem taxes payable		300			323
Crude oil, natural gas, and NGL revenue distribution payable		663			702
Deferred acquisition consideration		—			479
Current portion of debt, net		399			—
Derivative liability		4			22
Other liabilities		107			118
Total current liabilities		1,988			2,205
Long-term liabilities:
Debt, net		4,392			4,494
Ad valorem taxes		202			294
Deferred income tax liabilities, net		976			801
Asset retirement obligations		359			399
Derivative liability		—			13
Other long-term liabilities		110			109
Total liabilities		8,027			8,315
Commitments and contingencies (Note 6)
Stockholders’ equity:
Preferred stock, $.01 par value, 25,000,000 shares authorized, none outstanding		—			—
Common stock, $.01 par value, 225,000,000 shares authorized, 85,318,697 and 93,933,857 issued and outstanding as of December 31, 2025 and 2024, respectively		5			5
Additional paid-in capital		4,648			5,095
Retained earnings		2,072			1,529
Total stockholders’ equity		6,725			6,629
Total liabilities and stockholders’ equity	$	14,752		$	14,944

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

4

CIVITAS RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in millions, except per share amounts)

	Year Ended December 31,
	2025			2024
Operating net revenues:
Crude oil, natural gas, and NGL sales	$	4,370		$	5,203
Other operating income		23			4
Total operating net revenues		4,393			5,207
Operating expenses:
Lease operating expense		653			578
Midstream operating expense		50			48
Gathering, transportation, and processing		332			378
Severance and ad valorem taxes		319			377
Exploration		8			14
Depreciation, depletion, and amortization		1,953			2,057
General and administrative expense		214			227
Transaction costs		20			31
Other operating expense		18			17
Total operating expenses		3,567			3,727
Other income (expense):
Derivative gain, net		366			37
Interest expense		(453	)		(456	)
Other, net		(7	)		22
Total other expense		(94	)		(397	)
Income from operations before income taxes		732			1,083
Income tax expense		(171	)		(244	)
Net income	$	561		$	839

Earnings per common share
Basic	$	6.23		$	8.48
Diluted	$	6.23		$	8.46
Weighted-average common shares outstanding:
Basic		90,047,094			98,865,298
Diluted		90,177,464			99,176,051

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

5

CIVITAS RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(in millions, except share and per share amounts)

						Additional
	Common Stock					Paid-In			Retained
	Shares			Amount		Capital			Earnings			Total
Balances, December 31, 2023		93,774,901			5		4,964			1,212			6,181
Issuance pursuant to acquisition		7,181,527			—		489			—			489
Restricted common stock issued		456,890			—		—			—			—
Stock used for tax withholdings		(167,711	)		—		(12	)		—			(12	)
Exercise of stock options		333			—		—			—			—
Common stock repurchased and retired		(7,312,083	)		—		(394	)		(33	)		(427	)
Stock-based compensation		—			—		48			—			48
Dividends declared, $4.97 per share		—			—		—			(489	)		(489	)
Net income		—			—		—			839			839
Balances, December 31, 2024		93,933,857			5		5,095			1,529			6,629
Restricted common stock issued		509,957			—		—			—			—
Stock used for tax withholdings		(184,365	)		—		(7	)		—			(7	)
Exercise of stock options		111			—		—			—			—
Common stock repurchased and retired		(8,940,863	)		—		(486	)		160			(326	)
Stock-based compensation		—			—		46			—			46
Dividends declared, $2.00 per share		—			—		—			(178	)		(178	)
Net income		—			—		—			561			561
Balances, December 31, 2025		85,318,697		$	5	$	4,648		$	2,072		$	6,725

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

6

CIVITAS RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

	Year Ended December 31,
	2025			2024
Cash flows from operating activities:
Net income	$	561		$	839
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, and amortization		1,953			2,057
Stock-based compensation		46			48
Derivative gain, net		(366	)		(37	)
Derivative cash settlement gain, net		219			6
Amortization of deferred financing costs and deferred acquisition consideration		18			53
Deferred income tax expense		176			236
Other, net		2			3
Changes in operating assets and liabilities, net
Accounts receivable, net		172			(23	)
Prepaid expenses and other		(42	)		(18	)
Accounts payable, accrued expenses, and other liabilities		(229	)		(299	)
Net cash provided by operating activities		2,510			2,865
Cash flows from investing activities:
Acquisitions of businesses, net of cash acquired		(761	)		(905	)
Acquisitions of crude oil and natural gas properties		(63	)		(47	)
Capital expenditures for drilling and completion activities and other fixed assets		(1,817	)		(1,924	)
Proceeds from property transactions		366			209
Purchases of carbon credits and renewable energy credits		—			(6	)
Other, net		1			1
Net cash used in investing activities		(2,274	)		(2,672	)
Cash flows from financing activities:
Proceeds from credit facility		2,200			1,900
Payments to credit facility		(2,650	)		(2,200	)
Proceeds from issuance of senior notes		743			—
Dividends paid		(184	)		(494	)
Common stock repurchased and retired		(322	)		(427	)
Payment of employee tax withholdings in exchange for the return of common stock		(7	)		(12	)
Other, net		(15	)		(11	)
Net cash used in financing activities		(235	)		(1,244	)
Net change in cash, cash equivalents, and restricted cash		1			(1,051	)
Cash, cash equivalents, and restricted cash:
Beginning of period		76			1,127
End of period	$	77		$	76
Refer to Note 2 - Acquisitions and Divestitures and Note 14 - Supplemental Disclosures of Cash Flow Information for additional information.

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

7

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.

8

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:

	Year Ended December 31,
	2025			2024
Purchaser A		14	%		15	%
Purchaser B		10	%		10	%
Purchaser C		9	%		10	%

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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.

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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.

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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.

12

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.

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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.

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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:

Consideration (in millions, except share and per share amounts)
Cash consideration	$	997
Deferred acquisition consideration⁽¹⁾	$	532

Shares of common stock issued		7,181,527
Closing price per share⁽²⁾	$	68.08
Equity consideration⁽³⁾	$	489

Total consideration	$	2,018

⁽¹⁾

Based on discounted fixed and determinable future payments of cash. Amounts represent non-cash investing activities until such time payments are made, as applicable. Refer to Note 5 - Debt for additional information.

⁽²⁾

Based on the closing stock price of Civitas common stock on January 2, 2024.

⁽³⁾

Amounts represent non-cash financing activities.

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Final Purchase Price Allocation (in millions)
Assets Acquired
Proved properties	$	1,859
Unproved properties		231
Other property and equipment		1
Right-of-use assets		4
Total assets acquired	$	2,095

Liabilities Assumed
Accounts payable and accrued expenses	$	5
Crude oil and natural gas revenue distribution payable		28
Asset retirement obligations		40
Lease liability		4
Total liabilities assumed		77
Net assets acquired	$	2,018

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

Revenue and Earnings of the Acquiree

The results of operations for the Vencer Acquisition since the closing date have been included in our 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.

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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):

	Year Ended December 31,
Sales by Commodity and Operating Region	2025			2024
Crude oil
Permian Basin	$	1,958		$	2,363
DJ Basin		1,567			2,004
Total		3,525			4,367
Natural gas
Permian Basin		(6	)		(57	)
DJ Basin		283			226
Total		277			169
NGL
Permian Basin		282			326
DJ Basin		286			341
Total		568			667
Crude oil, natural gas, and NGL
Permian Basin		2,234			2,632
DJ Basin		2,136			2,571
Total	$	4,370		$	5,203

NOTE 4 - ACCOUNTS PAYABLE AND ACCRUED EXPENSES

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

	As of December 31,
	2025		2024
Accounts payable trade	$	27	$	35
Accrued drilling and completion costs		144		158
Accrued crude oil, natural gas, and NGL operating expense		130		160
Accrued general and administrative expense		38		37
Accrued interest expense		139		136
Other accrued expenses		37		35
Total accounts payable and accrued expenses	$	515	$	561

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NOTE 5 - DEBT

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

	As of December 31,
	2025			2024
Credit Facility	$	—		$	450

Senior Notes:
2026 Senior Notes (5.000%)		400			400
2028 Senior Notes (8.375%)		1,350			1,350
2030 Senior Notes (8.625%)		1,000			1,000
2031 Senior Notes (8.750%)		1,350			1,350
2033 Senior Notes (9.625%)		750			—
Senior Notes, gross		4,850			4,100
Less: unamortized discount and deferred financing costs		(59	)		(56	)
Senior Notes, net		4,791			4,044

Total debt, net		4,791			4,494
Less: current portion of debt, net		(399	)		—
Total long-term debt, net		4,392			4,494

Deferred acquisition consideration		—			479
Total debt	$	4,791		$	4,973

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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).

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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):

	January 29, 2026		December 31, 2025		December 31, 2024
Outstanding balance	$	200	$	—	$	450
Letters of credit		2		2		2
Available borrowing capacity		2,298		2,498		1,748
Total aggregate elected commitments	$	2,500	$	2,500	$	2,200

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:

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

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.

20

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.

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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.

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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):

	Minimum Volume⁽¹⁾
2026	$	39
2027		44
2028		40
2029		26
2030 and thereafter		5
Total	$	154

⁽¹⁾

The above calculation is based on the minimum volume commitment schedule (as defined in the relevant agreement) and applicable differential fees.

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.

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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.

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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):

	Year Ended December 31,
	2025		2024
Restricted and deferred stock units	$	30	$	28
Performance stock units		16		20
Total stock-based compensation	$	46	$	48

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):

	Unrecognized Compensation Expense		Final Year of Recognition
Restricted and deferred stock units	$	27		2028
Performance stock units		10		2027
Total unrecognized stock-based compensation	$	37

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:

	RSUs and DSUs			Weighted-Average Grant-Date Fair Value
Non-vested as of December 31, 2024		932,902		$	65.69
Granted		813,244			40.84
Vested		(433,130	)		65.16
Forfeited		(179,567	)		58.69
Non-vested as of December 31, 2025		1,133,449		$	49.17

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.

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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:

	PSUs			Weighted-Average Grant-Date Fair Value
Non-vested as of December 31, 2024		650,046		$	85.23
Granted⁽¹⁾		348,371			52.63
Additional shares based on performance⁽²⁾		(81,547	)		73.09
Vested⁽²⁾		(76,827	)		72.98
Forfeited		(187,968	)		72.77
Non-vested as of December 31, 2025⁽¹⁾		652,075		$	74.37

⁽¹⁾

The number of awards assumes that the associated performance condition is met at the target amount (multiplier of one). The final number of shares of our common stock issued may vary depending on the performance multiplier, which ranges from zero to 225%, depending on the level of satisfaction of the performance condition.

⁽²⁾

Upon completion of the performance period for the PSUs granted in 2022, a performance achievement of 46% or 54%, as applicable, was applied to each of the grants, resulting in a number of shares greater than the target amount of such PSUs vesting and being settled during 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:

	Year Ended December 31,
	2025			2024
Expected term (in years)		3.0			3.0
Risk-free interest rate		4.2	%		4.5	%
Expected daily volatility		2.7	%		3.0	%

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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.

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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):

	As of December 31,
	2025		2024
	Level 2		Level 2
Derivative assets	$	199	$	84
Derivative liabilities	$	4	$	35

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Long-Term Debt

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

				As of December 31, 2025					As of December 31, 2024
	Nominal Interest			Fair Value		Percent of Par			Fair Value		Percent of Par
2026 Senior Notes		5.000	%	$	400		100	%	$	394		99	%
2028 Senior Notes		8.375	%		1,393		103	%		1,405		104	%
2030 Senior Notes		8.625	%		1,047		105	%		1,049		105	%
2031 Senior Notes		8.750	%		1,402		104	%		1,408		104	%
2033 Senior Notes		9.625	%		810		108	%		—		—	%

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.

29

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):

	Year Ended December 31,
	2025		2024
Derivative cash settlement gain, net
Crude oil contracts	$	127	$	(42	)
Natural gas contracts		92		48
Total derivative cash settlement gain, net		219		6
Change in fair value gain		147		31
Total derivative gain, net	$	366	$	37

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

	Contract Period
	Q1 2026			Q2 2026			Q3 2026			Q4 2026			2027
Crude Oil Derivatives (volumes in Bbl/day and prices in $/Bbl)
Swaps
NYMEX WTI Volumes		37,000			46,500			21,000			—			—
Weighted-Average Contract Price	$	67.79		$	61.28		$	63.84		$	—		$	—
Collars
NYMEX WTI Volumes		15,000			7,000			6,000			—
Weighted-Average Ceiling Price	$	75.18		$	70.29		$	65.52		$	—		$	—
Weighted-Average Floor Price	$	60.00		$	60.00		$	57.50		$	—		$	—
Natural Gas Derivatives (volumes in MMBtu/day and prices in $/MMBtu)
Swaps
NYMEX HH Volumes		60,000			60,000			60,000			60,000			40,000
Weighted-Average Contract Price	$	4.42		$	4.42		$	4.42		$	4.42		$	4.00
Collars
NYMEX HH Volumes		200,000			200,000			200,000			200,000			40,000
Weighted-Average Ceiling Price	$	4.35		$	4.35		$	4.35		$	4.35		$	4.37
Weighted-Average Floor Price	$	3.52		$	3.52		$	3.52		$	3.52		$	3.73
Basis Protection Swaps
Waha Basis Volumes		130,000			130,000			130,000			130,000			60,000
Weighted-Average Contract Price	$	(1.31	)	$	(1.31	)	$	(1.31	)	$	(1.31	)	$	(0.74	)
Waha Index Volumes		130,000			130,000			130,000			130,000			20,000
Weighted-Average Contract Price	$	(0.57	)	$	(0.57	)	$	(0.57	)	$	(0.57	)	$	(0.37	)

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.

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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):

	As of December 31,
	2025			2024
Derivative Assets:
Commodity contracts - current	$	192		$	67
Commodity contracts - noncurrent		7			17
Total derivative assets		199			84
Amounts not offset in the accompanying consolidated balance sheets		(4	)		(27	)
Total derivative assets, net	$	195		$	57

Derivative Liabilities:
Commodity contracts - current	$	(4	)	$	(22	)
Commodity contracts - long-term		—			(13	)
Total derivative liabilities		(4	)		(35	)
Amounts not offset in the accompanying consolidated balance sheets		4			27
Total derivative liabilities, net	$	—		$	(8	)

NOTE 10 - ASSET RETIREMENT OBLIGATIONS

We recognize an estimated liability for future costs associated with the abandonment of our crude oil and natural gas properties, including facilities requiring decommissioning. A liability for the fair value of an asset retirement obligation and a corresponding increase to the carrying value of the related long-lived asset are recorded at the time a well is drilled or acquired, or a facility is constructed. The increase in carrying value is included in proved properties in the accompanying 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.

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

	Year Ended December 31,
	2025			2024
Balance, beginning of year	$	458		$	337
Additional liabilities incurred with development activities and other		7			9
Additional liabilities incurred with acquisitions		2			37
Obligations discharged with divestitures		(38	)		(28	)
Liabilities settled		(66	)		(47	)
Accretion expense⁽¹⁾		31			24
Revisions to estimate⁽²⁾		17			126
Balance, end of year	$	411		$	458
Current portion⁽³⁾		52			59
Long-term portion		359		$	399

⁽¹⁾

Accretion expense is included in depreciation, depletion, and amortization on the accompanying consolidated statements of operations and consolidated statements of cash flows.

⁽²⁾

Revisions to estimates for the year ended December 31, 2024 was primarily a result of (a) increases in our estimated plugging and abandonment cost driven by increased regulatory burden, service costs, complexity of plugging activities, and reclamation and environmental obligations that arose from normal operation of the assets, as evidenced through our plugging program activities during 2024, particularly in the DJ Basin, and (b) the acceleration of the estimated settlement date for certain wells.

⁽³⁾

The current portion of the asset retirement obligation is included in other liabilities on the accompanying consolidated balance sheets.

NOTE 11 - EARNINGS PER SHARE

Earnings per basic and diluted share are calculated under the treasury stock method. Basic net income per common share is calculated by dividing net income by the basic weighted-average common shares outstanding. 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.

32

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

	Year Ended December 31,
	2025		2024
Net income	$	561	$	839

Basic earnings per common share	$	6.23	$	8.48
Diluted earnings per common share	$	6.23	$	8.46

Weighted-average shares outstanding - basic		90,047,094		98,865,298
Add: dilutive effect of stock awards		130,370		310,753
Weighted-average shares outstanding - diluted		90,177,464		99,176,051

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):

	Year Ended December 31,
	2025			2024
Current tax expense (benefit)
Federal	$	(5	)	$	5
State		—			3
Total current tax expense (benefit)		(5	)		8
Deferred tax expense
Federal		160			224
State		16			12
Total deferred tax expense		176			236
Total income tax expense	$	171		$	244

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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):

	As of December 31,
	2025			2024
Deferred tax liabilities:
Oil and gas properties	$	1,665		$	1,484
Right-of-use assets		25			26
Commodity derivative contracts		46			6
Total deferred tax liabilities		1,736			1,516
Deferred tax assets:
Federal and state tax net operating loss carryforward		587			469
Interest expense carryforward		27			97
Asset retirement obligations		96			107
Stock-based compensation		14			10
Lease liability		26			26
Transaction costs		8			6
Other long-term assets		27			25
Total deferred tax assets		785			740
Less: Valuation allowance		25			25
Total deferred tax assets after valuation allowance		760			715
Deferred income tax liabilities, net	$	(976	)	$	(801	)

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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):

	Year Ended December 31,
	2025			2024
Federal statutory tax expense	$	154		$	227
Increase (decrease) in tax resulting from:
State tax expense, net of federal benefit		19			29
State tax rate change		(3	)		(13	)
Return to provision		(1	)		(1	)
Compensation of covered individuals		—			5
Stock-based compensation		3			(1	)
Tax credits		(1	)		(2	)
Total income tax expense	$	171		$	244

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.

35

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):

	As of December 31,
	2025		2024
Operating Leases
Field equipment⁽¹⁾	$	71	$	69
Corporate leases		17		13
Vehicles		9		12
Total right-of-use asset	$	97	$	94

Field equipment⁽¹⁾	$	71	$	69
Corporate leases		21		14
Vehicles		9		12
Total lease liability	$	101	$	95

⁽¹⁾

Includes drilling rigs, compressors, certain natural gas processing equipment, and other field equipment.

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

	Year Ended December 31,
	2025		2024
Operating lease cost	$	72	$	58
Short-term lease cost⁽¹⁾		151		141
Total lease cost⁽²⁾	$	223	$	199

⁽¹⁾

Includes drilling rigs and other equipment. Short-term drilling rig costs include a non-lease labor component, which is treated as a single lease component.

⁽²⁾

Variable lease costs represent differences between lease obligations and actual costs incurred for certain leases that do not have fixed payments related to both lease and non-lease components. Such incremental costs include lease payment increases or decreases driven by market price fluctuations and leased asset maintenance costs. Variable lease costs were not material for the years ended December 31, 2025 and 2024.

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:

	Operating Leases
Weighted-average lease term (years)		2.66
Weighted-average discount rate		5.5	%

36

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):

	Operating Leases
2026	$	49
2027		34
2028		14
2029		7
2030		3
Thereafter		1
Total lease payments		108
Less: Imputed interest		(7	)
Total lease liability	$	101

NOTE 14 - SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION

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

	Year Ended December 31,
	2025			2024
Supplemental cash flow information:
Cash (paid) refunded for income taxes	$	(3	)	$	3
Cash paid for interest		(430	)		(408	)
Supplemental non-cash investing and financing activities:
Changes in working capital related to capital expenditures		13			(8	)
Supplemental cash flow information related to leases:
Cash paid for amounts included in the measurement of lease liabilities - operating cash flows from operating leases		(69	)		(58	)
Right-of-use assets obtained in exchange for new operating lease obligations		73			69

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.

37

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:

	Number of Shares		Weighted-Average Price		Total Purchase Price (in millions)⁽¹⁾
2025
ASR Agreement		7,380,558	$	33.87	$	250
Open market repurchases		1,560,305		46.08		72
Total stock repurchases		8,940,863	$	36.00	$	322
2024
Privately negotiated transactions
NGP		876,193	$	64.54	$	57
Vitol		1,041,667		71.99		75
Open market repurchases		5,394,223		54.81		295
Total stock repurchases		7,312,083	$	58.42	$	427

⁽¹⁾

Excludes commissions paid and excise taxes accrued related to stock repurchases.

These stock repurchases were funded from our cash on hand, and the shares were immediately retired. As of 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):

	Year Ended December 31,
	2025		2024
Base dividend	$	2.00	$	2.00
Variable dividend		—		2.97
Total dividend	$	2.00	$	4.97

Total dividend	$	178	$	489

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.

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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):

	Year Ended December 31,
	2025			2024
Adjusted EBITDAX	$	3,073		$	3,652
Interest expense, net⁽¹⁾		(447	)		(445	)
Depreciation, depletion, and amortization		(1,953	)		(2,057	)
Exploration		(8	)		(14	)
Transaction costs		(20	)		(31	)
Derivative gain, net		366			37
Derivative cash settlement gain, net		(219	)		(6	)
Non-recurring cash severance⁽²⁾⁽³⁾		(7	)		—
Stock-based compensation⁽²⁾		(46	)		(48	)
Other, net⁽⁴⁾		(7	)		(5	)
Income from operations before income taxes	$	732		$	1,083

⁽¹⁾

Includes interest income of $6 million and $11 million for the years ended December 31, 2025 and 2024, respectively. Interest income is included as a portion of other, net in the accompanying consolidated statements of operations.

⁽²⁾

Included as a portion of general and administrative expense in the accompanying consolidated statements of operations.

⁽³⁾

The year ended December 31, 2025 includes non-recurring cash severance charges incurred in connection with our announced reduction in force and our CEO separation.

⁽⁴⁾

Other, net activity primarily includes (i) non-recurring cash unused commitment fees that are included in other operating expense in the accompanying consolidated statements of operations for each period presented and (ii) non-capitalized expenses incurred in connection with our ERP implementation that are included in general and administrative expense in the accompanying statements of operations during the year ended December 31, 2025.

39

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):

	Year Ended December 31,
	2025		2024
Acquisition⁽¹⁾	$	352	$	2,155
Development⁽²⁾		1,811		2,066
Exploration		8		14
Total	$	2,171	$	4,235

⁽¹⁾

Acquisition costs for proved properties for the years ended December 31, 2025 and 2024 were $276 million and $1.9 billion, respectively. Acquisition costs for unproved properties for the years ended December 31, 2025 and 2024 were $76 million and $257 million, respectively.

⁽²⁾

Includes amounts relating to asset retirement obligations of $24 million and $135 million, for the years ended December 31, 2025 and 2024, respectively.

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.

40

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:

	Crude Oil			Natural Gas			NGL			Total
	(MBbl)			(MMcf)			(MBbl)			(MBoe)
Proved reserves-December 31, 2023		272,805			1,320,302			204,943			697,799
Extensions, discoveries, and other additions		51,253			155,483			24,650			101,817
Production		(58,025	)		(218,905	)		(31,626	)		(126,135	)
Divestitures of reserves⁽¹⁾		(9,695	)		(41,774	)		(6,271	)		(22,929	)
Removed from capital program		(9,887	)		(40,657	)		(7,401	)		(24,064	)
Acquisition of reserves		55,978			354,438			64,297			179,348
Revisions to previous estimates⁽¹⁾		2,932			10,631			(12,816	)		(8,112	)
Proved reserves-December 31, 2024		305,361			1,539,518			235,776			797,724
Extensions, discoveries, and other additions		63,052			261,720			38,844			145,516
Production		(54,656	)		(197,612	)		(29,835	)		(117,426	)
Divestiture of reserves⁽¹⁾		(15,441	)		(51,674	)		(7,397	)		(31,450	)
Removed from capital program		(3,364	)		(10,216	)		(1,761	)		(6,828	)
Acquisition of reserves		32,735			84,404			14,663			61,465
Revisions to previous estimates		4,799			14,996			2,278			9,576
Proved reserves-December 31, 2025⁽¹⁾		332,486			1,641,136			252,568			858,577

Proved developed reserves:
December 31, 2024		235,626			1,323,856			203,182			659,451
December 31, 2025		246,455			1,336,046			206,312			675,442
Proved undeveloped reserves:
December 31, 2024		69,735			215,662			32,594			138,273
December 31, 2025		86,031			305,090			46,256			183,135

⁽¹⁾Items may not recalculate due to rounding.

41

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):

	Year Ended December 31,
	2025			2024
Future cash flows	$	28,486		$	28,251
Future production costs		(13,212	)		(12,007	)
Future development costs		(2,706	)		(2,491	)
Future income tax expense		(1,157	)		(1,244	)
Future net cash flows		11,411			12,509
10% annual discount for estimated timing of cash flows		(3,791	)		(4,194	)
Standardized measure of discounted future net cash flows	$	7,620		$	8,315

42

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):

	Year Ended December 31,
	2025			2024
Beginning of period	$	8,315		$	8,269
Crude oil, natural gas, and NGL sales, net of production costs		(3,008	)		(3,807	)
Net changes in prices and production costs		(1,071	)		(1,639	)
Net changes in extensions, discoveries, and other additions		1,481			1,416
Development costs incurred		933			811
Changes in estimated development cost		(137	)		40
Acquisition of reserves		771			2,342
Divestiture of reserves		(434	)		(257	)
Revisions of previous quantity estimates		30			(225	)
Net change in income taxes		103			211
Accretion of discount		922			1,172
Changes in production rates and other		(285	)		(18	)
End of period	$	7,620		$	8,315

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.

	Year Ended December 31,
	2025		2024
Crude Oil (per Bbl)	$	65.31	$	74.12
Natural Gas (per Mcf)	$	1.45	$	0.62
NGL (per Bbl)	$	17.47	$	19.80

43

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:

	Year Ended December 31,
	2025		2024		Percent Change
Crude oil (MBbls)
Permian Basin		30,254		30,968		(2	)%
DJ Basin		24,402		27,057		(10	)%
Total		54,656		58,025		(6	)%
Natural gas (MMcf)
Permian Basin		99,097		101,854		(3	)%
DJ Basin		98,515		117,051		(16	)%
Total		197,612		218,905		(10	)%
NGL (MBbls)
Permian Basin		17,287		17,672		(2	)%
DJ Basin		12,548		13,954		(10	)%
Total		29,835		31,626		(6	)%
Total sales volumes (MBoe)
Permian Basin		64,057		65,616		(2	)%
DJ Basin		53,369		60,519		(12	)%
Total		117,426		126,135		(7	)%
Average sales volumes per day (MBoe/d)
Permian Basin		176		179		(2	)%
DJ Basin		146		165		(12	)%
Total		322		344		(6	)%

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.

44

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):

	Year Ended December 31,
	2025			2024
Net income	$	561		$	839
Interest expense, net⁽¹⁾		447			445
Income tax expense		171			244
Depreciation, depletion, and amortization		1,953			2,057
Exploration		8			14
Transaction costs		20			31
Derivative gain, net		(366	)		(37	)
Derivative cash settlement gain (loss), net		219			6
Non-recurring cash severance⁽²⁾⁽³⁾		7			—
Stock-based compensation⁽²⁾		46			48
Other, net⁽⁴⁾		7			5
Adjusted EBITDAX	$	3,073		$	3,652

⁽¹⁾

Includes interest income of $6 million and $11 million for the years ended December 31, 2025 and 2024, respectively. Interest income is included as a portion of other, net in the accompanying consolidated statements of operations.

⁽²⁾

Included as a portion of general and administrative expense in the accompanying consolidated statements of operations.

⁽³⁾

The year ended December 31, 2025 includes non-recurring cash severance charges incurred in connection with our announced reduction in force and our CEO separation.

⁽⁴⁾

Other, net activity primarily includes (i) non-recurring cash unused commitment fees that are included in other operating expense in the accompanying consolidated statements of operations for each year presented and (ii) non-capitalized expenses incurred in connection with our ERP implementation that are included in general and administrative expense in the accompanying statements of operations during the year ended December 31, 2025.

45

Exhibit 99.4

UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS

Merger with Civitas

On November 2, 2025, SM Energy entered into an Agreement and Plan of Merger (“Merger Agreement”) with Civitas Resources, Inc., a Delaware Corporation (“Civitas”), and Cars Merger Sub, Inc., a wholly owned subsidiary of SM Energy (“Merger Sub”). The Merger (as defined below) was consummated on January 30, 2026 (“Merger Closing Date”). Pursuant to the Merger Agreement, SM Energy acquired Civitas through a series of mergers under the laws of the State of Delaware. On the Merger Clo sing Date, Merger Sub merged with and into Civitas, with Civitas surviving as a wholly-owned subsidiary of SM Energy (“First Merger”). Civitas then became the surviving corporation in the First Merger and merged with and into SM Energy, with SM Energy continuing as the surviving corporation (together with the First Merger, the “Merger”). On the Merger Closing Date, each share of Civitas common stock issued and outstanding (other than shares held in treasury, or owned directly or indirectly by SM Energy or Merger Sub) was automatically converted into the right to receive 1.45 shares of SM Energy common stock (“Exchange Ratio”), with cash paid in lieu of fractional shares in accordance with the terms of the Merger Agreement. In addition, Civitas’ equity awards outstanding immediately prior to the Merger Closing Date, including restricted stock units, performance stock units and options were converted into corresponding awards of SM Energy common stock, adjusted to reflect the Exchange Ratio and subject to the terms and conditions set forth in the Merger Agreement. The Civitas warrants expired on January 20, 2026 and were not assumed by SM Energy at the Merger Closing Date and no further purchase consideration was provided for these warrants.

The Merger will be accounted for as a business combination pursuant to Accounting Standards Codification Topic 805, Business Combinations (“ASC 805”), with SM Energy being identified as the accounting acquirer.

Maverick Basin Divestiture

On February 17, 2026, SM Energy entered into a Purchase and Sale Agreement (“PSA”) with Caturus Energy, LLC, a Delaware limited liability company (“Caturus”) to sell all of its rights, titles, and interests in certain producing and non-producing assets encompassing approximately 61,000 net acres located in the southern Maverick Basin of SM Energy’s South Texas region (“Maverick Basin Divestiture”). Upon closing, Caturus will pay cash consideration of $950 million subject to customary purchase price adjustments as set forth in the PSA . The Maverick Basin Divestiture is expected to close during the second quarter of 2026. The Pro Forma Financial Information (defined below) reflects SM Energy’s intent to use the proceeds from the Maverick Basin Divestiture to redeem the 6.750% Senior Notes due 2026 (“2026 Notes”) which have an outstanding principal amount of $419 million, and the 5.000% Senior Notes due 2026 originally issued by Civitas (“2026 CIVI Notes”) which have an outstanding principal amount of $400 million. The current redemption price for the 2026 Notes and the 2026 CIVI Notes is 100%.

The Maverick Basin Divestiture will be accounted for as a disposition to be reflected within continuing operations as it does not rise to the level of a strategic shift for SM Energy as defined within Subtopic ASC 205-20 for reporting discontinued operations.

Notes Offering

This Offering Memorandum contains a firm commitment to issue $750 million of eight-year maturity senior notes due 2034. The proceeds will be used to repurchase a portion of the 8.375% Senior Notes due 2028 originally issued by Civitas (“2028 CIVI Notes”), which have a par value of $1.35 billion. The current redemption price for the 2028 CIVI Notes is 104.188%, which is effective through June 30, 2026. These transactions are referred to throughout this section as the “Notes Offering”.

The unaudited pro forma combined financial statements and the corresponding notes thereto (“Pro Forma Financial Information”) is prepared on the basis as required by Article 11 of Regulation S-X (“Article 11”), as amended by the final rule, SEC Release No. 33-10786 “Amendments to Financial Disclosures about Acquired and Disposed Businesses”. The Pro Forma Financial Information is not intended to represent or be indicative of the combined financial position or results of operations that the Company would have reported had the Merger, the Maverick Basin Divestiture, or the Notes Offering been completed as of the dates set forth in the Pro Forma Financial Information. Additionally, the Pro Forma Financial Information should not be taken as indicative of the combined company’s future performance for reasons, including, but not limited to, differences between the assumptions used to prepare the Pro Forma Financial Information and actual results. The Pro Forma Financial Information is based on the information available to management at the time of preparation and assumptions that management believes are reasonable and supportable. Significant estimates and assumptions include, but are not limited to, preliminary allocation of the purchase price of the Merger, the closure and timing of closure of the Maverick Basin Divestiture, the final adjusted purchase price of the Maverick Basin Divestiture, the subsequent use of proceeds from the Maverick Basin Divestiture, the results of the Notes Offering, and estimated transaction and financing costs related to such transactions. The pro forma adjustments, which are described in the accompanying notes, may be revised as additional information becomes available and is evaluated. The actual adjustments recorded upon the final purchase price allocation of the Merger, the timing of close and the final purchase price adjustments for the Maverick Basin Divestiture, and the final issued terms of the Notes Offering may differ from the pro forma adjustments presented and such differences could be material.

The Pro Forma Financial Information should be read in conjunction with the following:

·	SM Energy’s audited consolidated financial statements and related notes included in its Annual Report on Form 10-K for the year ended December 31, 2025, filed with the SEC on February 26, 2026.

·	Civitas’ audited consolidated financial statements and related notes for the year ended December 31, 2025, included within this Offering Memorandum.

·	SM Energy’s Current Report on Form 8-K announcing the consummation of the Merger filed with the SEC on January 30, 2026.

·	SM Energy’s Current Report on Form 8-K announcing entry into the PSA with Caturus filed with the SEC on February 18, 2026.

SM Energy Company

Unaudited Pro Forma Combined Balance Sheet

As of December 31, 2025

(in millions)

				Civitas Merger
	SM Energy			Civitas As Adjusted (Note 2)			Transaction Accounting Adjustments (Note 5)				Maverick Basin Divestiture (Note 3) and Transaction Accounting Adjustments (Note 5)				Notes Offering (Note 4) and Transaction Accounting Adjustments (Note 5)				Pro Forma as Adjusted
ASSETS
Current assets:
Cash and cash equivalents	$	368		$	77		$	(201	)	a	$	105		g	$	(62	)	j	$	287
Accounts receivable		331			603			(149	)	b		-				-				785
Derivative assets		83			192			-				-				-				275
Prepaid expenses and other		29			76			(9	)	c		-				-				96
Total current assets		811			948			(359	)			105				(62	)			1,443
Property and equipment (successful efforts method):
Proved oil and gas properties		16,012			19,092			(11,196	)	c		(1,920	)	h		-				21,988
Accumulated depletion, depreciation, and amortization		(8,793	)		(6,103	)		6,103		c		1,313		h		-				(7,480	)
Unproved oil and gas properties, net of valuation allowance		460			194			322		c		-				-				976
Wells in progress		458			387			-				(15	)	h		-
Other property and equipment, net of accumulated depreciation		65			77			-				-				-				142
Total property and equipment, net		8,202			13,647			(4,771	)			(622	)			-				16,456
Noncurrent assets:
Derivative assets		6			7			-				-				-				13
Other noncurrent assets		234			150			(14	)	c		(8	)	h		-				362
Total noncurrent assets		240			157			(14	)			(8	)			-				375
Total assets	$	9,253		$	14,752		$	(5,144	)		$	(525	)		$	(62	)		$	18,274

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	690		$	1,530		$	15		b, d	$	71		g, h, i	$	(33	)	k, l	$	2,273
Senior Notes, net		419			399			1		c		(819	)	g		-				-
Derivative liabilities		2			4			-				-				-				6
Other current liabilities		58			55			-				-				-				113
Total current liabilities		1,169			1,988			16				(748	)			(33	)			2,392
Noncurrent liabilities:
Senior Notes, net		2,296			4,393			297		c		-				(23	)	m		6,963
Asset retirement obligations		150			359			-				(45	)	h		-				464
Net deferred tax liabilities		724			976			(1,086	)	e		-				-				614
Derivative liabilities		2			-			-				-				-				2
Other noncurrent liabilities		102			311			-				-				-				413
Total noncurrent liabilities		3,274			6,039			(789	)			(45	)			(23	)			8,456
Commitments and contingencies
Stockholders’ equity:
Common stock		1			5			(4	)	f		-				-				2
Additional paid-in capital		1,517			4,648			(2,203	)	f		-				-				3,962
Retained earnings		3,291			2,072			(2,164	)	f		268		h		(6	)	n		3,461
Accumulated other comprehensive loss		1			-			-				-				-				1
Total stockholders’ equity		4,810			6,725			(4,371	)			268				(6	)			7,426
Total liabilities and stockholders’ equity	$	9,253		$	14,752		$	(5,144	)		$	(525	)		$	(62	)		$	18,274

SM Energy Company

Unaudited Pro Forma Combined Statements of Operations

Year Ended December 31, 2025

(in millions, except per share data)

				Civitas Merger
	SM Energy			Civitas As Adjusted (Note 2)			Transaction Accounting Adjustments (Note 5)				Maverick Basin Divestiture (Note 3) and Transaction Accounting Adjustments (Note 5)				Notes Offering (Note 4) and Transaction Accounting Adjustments (Note 5)				Pro Forma as Adjusted
Operating revenues and other income:
Oil, gas, and NGL production revenue	$	3,138		$	4,370		$	-			$	(380	)	u	$	-			$	7,128
Net gain on divestiture activity		-			-			-				347		h		-				347
Other operating income, net		16			10			-				-				-				26
Total operating revenues and other income		3,154			4,380			-				(33	)			-				7,501

Operating expenses:
Oil, gas, and NGL production expense		885			1,391			-				(136	)	u		-				2,140
Depletion, depreciation, and amortization		1,207			1,953			(850	)	o		(114	)	u		-				2,196
Exploration		57			8			-				-				-				65
General and administrative		161			177			73		p, q		-				-				411
Net derivative gain		(178	)		(366	)		-				-				-				(544	)
Other operating expense, net		22			38			19		r		10		v		-				89
Total operating expenses		2,154			3,201			(758	)			(240	)			-				4,357

Income from operations		1,000			1,179			758				207				-				3,144

Interest expense		(173	)		(453	)		160		s		49		w		1		x		(416	)
Interest income		3			6			-				-				-				9
Other non-operating expense		-			-			-				-				(8	)	n		(8	)
Income from operations before income taxes		830			732			918				256				(7	)			2,729
Income tax expense		(182	)		(171	)		(209	)	t		(58	)	t		2		t		(618	)
Net income	$	648		$	561		$	709			$	198			$	(5	)		$	2,111

Basic weighted-average common shares outstanding		115			90															240		y
Diluted weighted-average common shares outstanding		115			90															241		y
Basic net income per common share	$	5.65		$	6.23														$	8.80		y
Diluted net income per common share	$	5.64		$	6.23														$	8.76		y

SM Energy Company

Notes to Unaudited Pro Forma Combined Financial Statements

1.

Basis of Presentation

The unaudited pro forma combined financial statements have been prepared in accordance with Article 11 using the assumptions set forth below. The historical financial information of SM Energy and Civitas has been derived from their respective historical consolidated financial statements, which were prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The unaudited pro forma combined balance sheet as of December 31, 2025, gives effect to the Merger, the Maverick Basin Divestiture, and the Notes Offering as if they had occurred on December 31, 2025. The unaudited pro forma combined statements of operations for the year ended December 31, 2025, gives effect to the Merger, the Maverick Basin Divestiture, and the Notes Offering as if they had occurred on January 1, 2025. Adjustments made to reflect the pro forma financial effects are described as Transaction Accounting Adjustments.

Adjustments made to reflect the pro forma financial effects of the Merger, the Maverick Basin Divestiture, and the Notes Offering are described as Transaction Accounting Adjustments giving effect to the following:

·

with respect to the Merger, the Pro Forma Financial Information combines the historical consolidated financial statements of SM Energy and Civitas, each for the year ended December 31, 2025, and reflects only those adjustments that are directly attributable to the Merger;

·

the removal of the historical results of the Maverick Basin Divestiture from SM Energy;

·

SM Energy’s intent to use the proceeds from the Maverick Basin Divestiture to redeem the 2026 Notes and the 2026 CIVI Notes at par; and

·

the Notes Offering, based on indicative terms as described herein.

Article 11 permits presentation of reasonably estimable synergies and other transaction effects that have occurred or are reasonably expected to occur (“Management Adjustments”). The Company has elected not to present Management Adjustments.

2.

Accounting for the Merger with Civitas

Purchase Price Consideration

Under the terms of the Merger Agreement, each share of Civitas common stock issued and outstanding immediately prior to the Merger Closing Date (other than shares held in treasury, or owned directly or indirectly by SM Energy or Merger Sub) were automatically converted into the right to receive 1.45 shares of SM Energy common stock, with cash paid in lieu of fractional shares in accordance with the terms of the Merger Agreement. The fair value of the purchase consideration was determined using the number of shares of Civitas common stock outstanding at the Merger Closing Date and the closing price of SM Energy common stock price on January 30, 2026. In addition, the fair value of replacement equity awards attributable to pre-combination service is included in the total purchase price consideration.

The following table presents the calculation of purchase price consideration:

(In millions, except per share amounts)	Purchase Price Consideration
Total shares of Civitas common stock outstanding as of the Merger		85
Exchange Ratio as defined in the Merger Agreement		1.45
Number of shares of SM Energy common stock to be issued		124
SM Energy share price on the Merger Closing Date	$	19.47
Preliminary purchase price consideration for Civitas’ stock outstanding	$	2,409
Fair value of replacement shares for Civitas’ stock-based compensation awards attributable to pre-combination service		29
Cash paid to settle the Civitas credit facility less Civitas unrestricted cash balance ⁽¹⁾		201
Retention bonuses to be paid to Civitas employees on the Merger Closing Date ⁽²⁾		25
Total purchase price consideration	$	2,664

(1)

Represents the outstanding Civitas credit facility of approximately $201 million inclusive of accrued interest, as of the Merger Closing Date. There was no balance on the Civitas credit facility at December 31, 2025.

(2)

Represents retention bonuses paid to Civitas employees on the Merger Closing Date, based on agreements intended to ensure continuity of key personnel.

The purchase price consideration applied in the Pro Forma Financial Information is preliminary and subject to modification as SM Energy completes its accounting for the Merger. The final purchase price allocation, which will be reflected in future financial statements of SM Energy may reflect different values and such differences may be material compared to the estimated allocations set forth below. The Civitas credit facility had no balance at December 31, 2025, but the purchase price consideration presented above reflects borrowed amounts inclusive of accrued interest at the Merger Closing Date. The Civitas credit facility was paid in full by SM Energy in connection with the closing of the Merger.

Preliminary Purchase Price Allocation

The allocation of the consideration, including any related tax effects, is preliminary and pending finalization of various estimates, inputs and analyses used in the valuation assessment of the specifically identifiable tangible and intangible assets acquired and liabilities assumed. ASC 805 requires, among other things, that the assets acquired, and liabilities assumed in a business combination be recognized at their fair values as of the acquisition date with certain measurement exceptions such as deferred taxes, which are not reflected on a fair value basis. Since the Pro Forma Financial Information has been prepared based on preliminary estimates of fair values attributable to the Merger, the actual amounts eventually recorded in accordance with the acquisition method of accounting may differ materially from the information presented.

The preliminary purchase price allocation is subject to change due to several factors, including changes in the estimated fair value of Civitas’ identifiable assets acquired and liabilities assumed (such as identifiable intangible assets and liabilities and the measurement of deferred tax assets and liabilities), third-party appraisals and other potential adjustments.

The following table presents the preliminary allocation of the purchase price consideration:

(In millions)	Carrying Value			Fair Value			Preliminary Purchase Price Allocation Adjustment
Assets acquired
Cash and cash equivalents	$	77		$	77		$	-
Accounts receivable		603			603			-
Derivative assets		192			192			-
Prepaid expenses and other		76			67			(9	)
Proved oil and gas properties		19,092			7,896			(11,196	)
Accumulated depletion, depreciation, and amortization		(6,103	)		-			6,103
Unproved oil and gas properties		194			516			322
Wells in progress		387			387			-
Other property and equipment		77			77			-
Derivative assets - noncurrent		7			7			-
Other noncurrent assets		150			136			(14	)
Total assets acquired	$	14,752		$	9,958		$	(4,794	)
Liabilities assumed
Accounts payable and accrued expenses	$	1,530		$	1,585		$	55
Senior Notes, net - current		399			400			1
Derivative liabilities		4			4			-
Other current liabilities		55			55			-
Senior Notes, net – noncurrent		4,393			4,690			297
Asset retirement obligations		359			359			-
Net deferred tax liabilities ⁽¹⁾		976			(110	)		(1,086	)
Other noncurrent liabilities		311			311			-
Total liabilities assumed	$	8,027		$	7,294		$	(733	)

Total purchase consideration				$	2,664

(1)

Reflects a deferred tax asset using a combined, blended tax rate of 22.8% due to the enacted tax rates expected to be in effect in future periods when the temporary differences are expected to reverse. The deferred tax asset is presented as a negative net deferred tax liability since the combined company has an overall net deferred tax liability position.

As the purchase price allocation has not been completed, certain assumptions, inputs, and estimates could vary prior to finalization. As the largest component of value resides within the proved oil & gas properties, certain changes in estimates of value can have a material impact on the expense recognition of depletion, depreciation, and amortization. A 10% increase in the value of proved oil & gas properties would result in a $109 million increase in annual pro forma depletion, depreciation and amortization expense, while a 10% decrease in value would reduce the same expense by $109 million.

3.

Accounting for the Maverick Basin Divestiture

The Maverick Basin Divestiture will be accounted for as a disposition to be reflected within continuing operations as it does not rise to the level of a strategic shift for SM Energy as defined within Subtopic ASC 205-20 for reporting discontinued operations. The Maverick Basin Divestiture contains customary post-closing and effective date adjustments, and those estimated adjustments have been reflected in the pro forma gain in the table below. The resulting pro forma gain from the anticipated divestiture is calculated as follows:

(In millions)	As of December 31, 2025
Cash consideration for divestment	$	950
Less: Effective date estimated cash adjustment		(8	)
Less: Estimated transaction costs		(10	)
Less: Divested Maverick Basin assets		(630	)
Less: Divested Maverick Basin liabilities		45
Pro forma pre-tax gain on divestiture activity		347
Less: Estimated tax provision (see tickmark i)		(79	)
Pro forma gain on divestiture activity	$	268

The net proceeds from the Maverick Basin Divesture will be used to redeem the outstanding 2026 Notes and 2026 CIVI Notes. There is no pro forma gain or loss reflected on the repayment as the unamortized deferred financing costs and fair value premium associated with the 2026 Notes and 2026 CIVI Notes, respectively, are not material.

4.

Accounting for the Notes Offering

The proceeds from the Notes Offering, after estimated issuance costs, will be used to repurchase a portion of the assumed 2028 CIVI Notes, and estimated cash on hand will be used to pay the premium on early redemption. For purposes of these pro forma financial statements, the premium on repurchase was estimated using the current redemption price of 104.188%. The Company anticipates accounting for the repurchase as an extinguishment under Subtopic ASC 470-50, Debt Modifications and Extinguishments. The pro forma loss resulting from the Notes Offering is estimated to be as follows:

(in millions)	As of December 31, 2025
Principle repurchase on the 2028 CIVI Notes	$	739
Less: Carrying value of 2028 CIVI Notes (1)		(762	)
Add: Redemption price associated with 2028 CIVI Notes		31
Pro forma pre-tax loss on extinguishment		8
Less: Estimated tax provision (see tickmark l)		(2	)
Pro forma loss on extinguishment	$	6

(1)

The 2028 CIVI Notes includes $23 million of fair value premium resulting from the Civitas acquisition allocated to the portion repurchased.

5.

Transaction Accounting Adjustments

Explanations of the adjustments to the Pro Forma Financial Information are as follows:

Unaudited Pro Forma Combined Balance Sheet

Merger with Civitas

(a)

Represents cash paid to settle the Civitas credit facility including accrued and unpaid interest.

(b)

Represents the net-down adjustment of Civitas’ accounts receivable and corresponding royalty payables to align with SM Energy’s policy of reporting revenue accruals and associated payables on a net basis.

(c)

Represents the preliminary fair value adjustments to Civitas’ property and equipment, senior notes and write-off of the deferred financing costs of the Civitas credit facility in connection with the application of ASC 805 to reflect the preliminary allocation of the purchase price consideration. See Note 2 – Accounting for the Merger with Civitas for further details.

(d)

Represents accruals for the following which are expected to be incurred by SM Energy subsequent to December 31, 2025:

(in millions)	As of December 31, 2025
Accrual for estimated transaction-related costs	$	19
Accrual for directors’ and officers’ (“D&O”) insurance coverage		2
Accrual for estimated severance payable to certain Civitas officers who are expected to be terminated following the Mergers		37
Accrual for estimated retention bonuses payable to Civitas employees ⁽¹⁾		50
Accrual for equity issuance costs		1
Net down of Civitas’ royalty payables to align with SM Energy’s accounting policy described in tick mark (b) above		(149	)
Accrual for success fees associated with closing the transaction included in purchase price allocation		55
Total adjustments made to Accounts payable and accrued expenses	$	15

(1)

Represents $25 million of retention bonuses without any future service requirements to be paid to Civitas employees on the Merger Closing Date, and $25 million of estimated retention bonuses payable to Civitas employees after the Merger Closing Date.

(e)

Represents the adjustment to deferred income taxes to record the acquisition of a net deferred tax asset. This is primarily the result of the purchase price allocated to the acquired oil and gas properties, which decreased in value. The Company will need to perform further valuation allowance analysis along with Sections 382 and 383 analyses to ensure the combined company will have sufficient taxable income to utilize all deferred tax assets. The deferred tax adjustment assumes a forecasted blended statutory rate of 22.8%. Since the tax rates used for these unaudited pro forma combined financial statements are an estimate, the blended rate will likely vary from the actual effective rate in periods subsequent to the completion of the Merger.

(f)

Represents the issuance of SM Energy common stock to Civitas’ stockholders as consideration for the Merger, including the stock-based compensation value of pre-combination service awards. Values are measured at SM Energy’s share price as of the Merger Closing Date of January 30, 2026. The amount is offset by Civitas’ historical equity balances, including common stock, additional paid-in capital, retained earnings and the following discrete adjustments:

(in millions)	Removal of Civitas Historical Equity ⁽¹⁾			Equity Consideration Issued for the Merger ⁽²⁾		Equity Issuance Cost			Severance (Equity Component) ⁽³⁾			Retained Earnings Adjustment ⁽⁴⁾			Total Pro Forma Adjustment
Common stock	$	(5	)	$	1	$	-		$	-		$	-		$	(4	)
Additional paid-in capital		(4,648	)		2,437		(1	)		9			-			(2,203	)
Retained earnings		(2,072	)		-		-			(9	)		(83	)		(2,164	)
Total adjustments to Stockholders’ equity	$	(6,725	)	$	2,438	$	(1	)	$	-		$	(83	)	$	(4,371	)

(1)

To remove the historical equity of Civitas as a result of the Merger.

(2)

To recognize the fair value of the equity consideration paid by SM Energy for the First Merger. See Note 2 – Accounting for the Merger with Civitas for the components of the purchase price consideration.

(3)

Reflects the accelerated stock awards of certain Civitas officers due to double-trigger severance provisions. The amount is reflected as an increase in Common stock and Additional paid-in capital for the vested awards with an offsetting expense to Retained earnings.

(4)

Represents sum of estimated transaction costs, D&O insurance and estimated cash-based severance costs for Civitas executives and estimated retention bonuses payable to Civitas employees.

Maverick Basin Divestiture

(g)

Represents reconciliation of net proceeds as of December 31, 2025:

(In millions)
Cash proceeds from sale	$	950
Estimated transaction costs		(10	)
Estimated closing adjustments		(8	)
Net cash proceeds		932
Redemption of 2026 CIVI Notes		(400	)
Redemption of 2026 Notes		(419	)
Paydown of accrued interest		(8	)
Net proceeds	$	105

(h)

Refer to footnote 3, the accounting for the Maverick Basin Divestiture for assets and liabilities divested and for the pro forma after-tax gain.

(i)

Reflects the estimated blended federal and state statutory rate of approximately 22.8%, which is applied to the pro forma pre-tax gain on the Maverick Basin Divestiture with the corresponding tax payable recorded in accounts payable and accrued expenses.

Notes Offering

(j)

Represents reconciliation of net proceeds as of December 31, 2025:

(in millions)
Net proceeds from Notes Offering reduced for estimated issuance costs of $11 million	$	739
Less: Repurchase of 2028 CIVI Notes at par value		(739	)
Less: Redemption price associated with the 2028 CIVI Notes		(31	)
Less: Paydown of accrued interest related to the portion of repurchased 2028 CIVI Notes		(31	)
Total adjustments to Cash and cash equivalents	$	(62	)

(k)

Represents the paydown of accrued interest associated with the 2028 CIVI Notes.

(l)

Reflects the estimated blended federal and state statutory rate of approximately 22.8%, which is applied to the pro forma pre-tax loss on the extinguishment of 2028 CIVI Notes with the corresponding tax payable recorded in accounts payable and accrued expenses.

(m)

Represents total adjustments to senior notes, net:

(in millions)
Net proceeds from Notes Offering reduced for estimated issuance costs of $11 million	$	739
Less: Repurchase of 2028 CIVI Notes at carrying value (1)		(762	)
Total adjustments to Senior Notes, net	$	(23	)

(1) The 2 028 CIVI Notes includes $23 million of fair value premium resulting from the Civitas acquisition allocated to the portion repurchased.

(n)

Represents the pro forma after-tax loss on the extinguishment of the 2028 CIVI Notes as described in footnote 4, accounting for the Notes Offering.

Unaudited Pro Forma Combined Statements of Operations

Merger with Civitas

(o)

Represents the adjustment to depreciation, depletion and amortization expense related to the assets acquired in the Merger, which is based on the preliminary purchase price allocation. Depletion was calculated using the unit-of-production method under the successful efforts method of accounting. The depletion expense was adjusted based on revised depletion rates calculated using the acquisition costs and the reserve volumes attributable to the acquired oil and gas properties. The pro forma depletion rate attributable to the Merger was $8.97 per barrel of oil equivalent. In addition, depreciation expense related to Other property, plant and equipment has been adjusted to reflect the preliminary fair value assigned to these assets and their estimated useful lives. All amounts are preliminary and subject to change upon finalization of the purchase price allocation and completion of valuation studies. See Note 2 – Accounting for the Merger with Civitas for accounting treatment and preliminary purchase price allocation.

(p)

Represents the expensing of the premium of the D&O insurance of $2 million to be purchased on the Merger Closing Date as stipulated in the Merger Agreement.

(q)

Represents $46 million of estimated severance costs payable to certain Civitas officers who were terminated following the Merger Closing Date and $25 million of estimated retention bonuses payable to Civitas employees after the Merger Closing Date. These costs reflect information known as of Merger Closing Date. Additional amounts for severance costs for other former Civitas employees may occur and such amounts may be material. These costs are nonrecurring and will not affect SM Energy’s statement of operations beyond twelve months after the Merger Closing Date.

(r)

Represents $19 million of estimated transaction-related costs including legal, advisory and other deal-related expenses expected to be incurred by SM Energy subsequent to December 31, 2025. These transaction costs are preliminary estimates; the final amounts and the resulting effect on SM Energy’s results of operations may differ significantly. These costs are nonrecurring and will not affect SM Energy’s statement of operations beyond twelve months after the Merger Closing Date.

(s)

Represents the net decrease to interest expense resulting from the following:

(In millions)	Year Ended December 31, 2025
Elimination of interest expense on Civitas’ credit facility	$	55
Adjustment to align Civitas and SM Energy capitalized interest policies		44
Amortization of the premium related to the Civitas senior notes		52
Removal of historical amortization of deferred financing costs on Civitas’ credit facility		9
Total adjustments to Interest expense	$	160

(t)

Represents the estimated income tax impact of the pro forma adjustments from the Merger Agreement, the Maverick Basin Divestiture and the Notes Offering at the estimated blended federal and state statutory rate of approximately 22.8% for the year ended December 31, 2025. Since the tax rates used for these Pro Forma Financial Information are an estimate, the blended rate will likely vary from the actual effective rate in periods subsequent to completion of the Merger Agreement, Maverick Basin Divestiture and the Notes Offering.

Maverick Basin Divestiture

(u)

Represents derecognition of revenue and expense for oil, gas, and NGL production and depletion, depreciation, and amortization.

(v)

Represents estimated transaction costs associated with the Maverick Basin Divesture.

(w)

Represents derecognition of interest expense for the Maverick Basin Divesture, which includes the elimination of interest expense of $29 million on the 2026 Notes and $20 million on the 2026 CIVI Notes.

Notes Offering

(x)

Reflects the anticipated interest expense adjustment on the Notes Offering. The Notes Offering has not been completed, and the Company is estimating the market-based rate of interest that it expects to receive in the offering. Current market indications prior to the launch of the Notes Offering reflect a coupon interest rate of 6.75%. Using the current market indications, the adjustment to interest expense is calculated as follows:

(In millions)	Year Ended December 31, 2025
Elimination of interest expense on the 2028 CIVI Notes (1)	$	62
Elimination of amortized premium on the 2028 CIVI Notes reflected as result of the Civitas acquisition		(10	)
Interest expense on the anticipated Notes Offering at estimated market rates		(50	)
Deferred financing costs amortization associated with the Notes Offering		(1	)
Total adjustments to Interest expense	$	1

(1)

The 2028 CIVI Notes includes $23 million of fair value premium resulting from the Civitas acquisition allocated to the portion repurchased.

Many factors could impact this rate when the Notes Offering is complete. A 0.125% change in the variable interest rate on the SM Energy revolving credit facility would increase or decrease interest expense presented in the unaudited pro forma condensed combined statements of operations for the year ended December 31, 2025 by $1 million.

(y)

Represents the calculation of the weighted-average shares outstanding and earnings per share included in the unaudited pro forma condensed combined statements of operations for the year ended December 31, 2025. Because the unaudited pro forma condensed combined statement of operations give effect to the Merger Agreement and the Maverick Basin Divestiture as if they had occurred on January 1, 2025, the calculation of weighted-average shares outstanding for basic and diluted earnings per share assumes that the shares issuable pursuant to the Merger Agreement have been outstanding for the entire year.

(in millions, except per share data)	Year Ended December 31, 2025
Pro forma net income	$	2, 111
Basic shares:
Shares of SM Energy common stock outstanding		115
Shares of SM Energy common stock issued in exchange for shares of Civitas common stock as part of consideration transferred		124
Shares issued attributable to accelerated vesting of Civitas’ restricted stock units (“RSU”) and performance stock units (“PSU”) for executives subject to double-trigger severance provisions		1
Pro forma weighted average common shares outstanding, basic		240
Diluted shares:
Pro forma weighted average shares outstanding, basic		240
Dilutive effect of shares convertible from RSU and PSU unvested equity awards		1
Pro forma weighted average common shares outstanding, diluted		241
Earnings attributable to SM Energy per share, basic	$	8.80
Earnings attributable to SM Energy per share, diluted	$	8.76

6.

Reclassifications

Certain reclassifications have been made in the historical presentation of Civitas’ financial statements to conform to SM Energy’s historical presentation.

Balance Sheet Reclassifications – As of December 31, 2025

The table below summarizes reclassifications made to Civitas’ historical balance sheet to conform to the SM Energy presentation as of December 31, 2025:

As of December 31, 2025 (in millions)
Civitas Presentation	Civitas Historical			Reclassification Adjustments				Civitas as Adjusted			SM Energy Presentation
ASSETS											ASSETS
Current assets:											Current assets:
Cash and cash equivalents	$	77		$	-			$	77		Cash and cash equivalents
Accounts receivable, net:		-			603		i		603		Accounts receivable
Crude oil, natural gas, and NGL sales		489			(489	)	i		-
Joint interest and other		114			(114	)	i		-
Derivative assets		192			-				192		Derivative assets
Prepaid expenses and other		95			(19	)	ii		76		Prepaid expenses and other
Total current assets		967			(19	)			948		Total current assets

Property and equipment (successful efforts method):											Property and equipment (successful efforts method):
Proved properties		19,092			-				19,092		Proved oil and gas properties
Less: accumulated depreciation, depletion, and amortization		(6,103	)		-				(6,103	)	Accumulated depletion, depreciation, and amortization
Total proved properties, net		12,989			-				12,989
Unproved properties		194			-				194		Unproved oil and gas properties, net of valuation allowance
Wells in progress		387			-				387		Wells in progress
Other property and equipment, net of accumulated depreciation		58			19		ii		77		Other property and equipment, net of accumulated depreciation
Total property and equipment, net		13,628			19			$	13,647		Total property and equipment, net
											Noncurrent assets:
Derivative assets		7			-				7		Derivative assets
Other noncurrent assets		150			-				150		Other noncurrent assets
		157			-				157		Total noncurrent assets
Total assets	$	14,752		$	-			$	14,752		Total assets

LIABILITIES AND STOCKHOLDERS’ EQUITY											LIABILITIES AND STOCKHOLDERS’ EQUITY
re Current liabilities:											Current liabilities:
Accounts payable and accrued expenses	$	515		$	1,015		iii	$	1,530		Accounts payable and accrued expenses
Derivative liability		4			-				4		Derivative liabilities
Other liabilities		107			(52	)	iii		55		Other current liabilities
Current portion of debt, net		399			-				399		Senior Notes, net
Severance and ad valorem taxes payable		300			(300	)	iii		-
Crude oil, natural gas, and NGL revenue distribution payable		663			(663	)	iii		-
Total current liabilities		1,988			-				1,988		Total current liabilities
Long-term liabilities:											Noncurrent liabilities:
Debt, net		4,392			1		iv		4,393		Senior Notes, net
Asset retirement obligations		359			-				359		Asset retirement obligations
Deferred income tax liabilities, net		976			-				976		Net deferred tax liabilities
Other long-term liabilities		110			201		v		311		Other noncurrent liabilities
Ad valorem taxes		202			(202	)	iv		-
		6,039			-				6,039		Total noncurrent liabilities
Total Liabilities		8,027			-				8,027
Commitments and contingencies											Commitments and contingencies

Stockholders’ equity:											Stockholders’ equity:
Common stock		5			-				5		Common stock
Additional paid-in capital		4,648			-				4,648		Additional paid-in capital
Retained earnings		2,072			-				2,072		Retained earnings
Total stockholders’ equity		6,725			-				6,725		Total stockholders’ equity
Total liabilities and stockholders’ equity	$	14,752		$	-			$	14,752		Total liabilities and stockholders’ equity

(i)

Represents the reclassification of “Crude oil, natural gas, and NGL sales” and “Joint interest and other” within the “Accounts Receivable, net” subsection on Civitas’ historical balance sheet to “Accounts receivable” to conform to the Company’s balance sheet presentation.

(ii)

Represents the reclassification of “Prepaid expenses and other” on Civitas’ historical balance sheet to “Other property and equipment, net of accumulated depreciation” to conform to the Company’s balance sheet presentation.

(iii)

Represents the reclassification of “Other liabilities,” "Severance and ad valorem taxes payable," and "Crude oil, natural gas, and NGL revenue distribution payable," on Civitas' historical balance sheet to "Accounts payable and accrued expenses" to conform to the Company's balance sheet presentation.

(iv)

Represents the reclassification of "Ad valorem taxes" on Civitas' historical balance sheet to " Other noncurrent liabilities" to conform to the Company's balance sheet presentation.

Statement of Operations Reclassifications – Year Ended December 31, 2025

The table below summarizes reclassifications made to Civitas’ historical statement of operations to conform to the SM Energy presentation for the year ended December 31, 2025:

Year Ended December 31, 2025 (in millions)
Civitas Presentation	Civitas Historical			Reclassification Adjustments				Civitas as Adjusted			SM Energy Presentation
Operating net revenues:											Operating revenues and other income:
Crude oil, natural gas, and NGL sales	$	4,370		$	-			$	4,370		Oil, gas, and NGL production revenue
Other operating income		23			(13	)	i		10		Other operating income
Total operating net revenues		4,393			(13	)			4,380		Total operating revenues and other income

Operating expenses:											Operating expenses:
		-			1,391		ii		1,391		Oil, gas, and NGL production expense
Lease operating expense		653			(653	)	ii		-
Midstream operating expense		50			(50	)	ii		-
Gathering, transportation, and processing		332			(332	)	ii		-
Severance and ad valorem taxes		319			(319	)	ii		-
Depreciation, depletion, and amortization		1,953			-				1,953		Depletion, depreciation, and amortization
Exploration		8			-				8		Exploration
General and administrative expense		214			(37	)	ii		177		General and administrative
Transaction costs		20			(20	)	iii		-		Transaction costs
		-			(366	)	iv		(366	)	Net derivative gain
Other operating expense		18			20		iii		38		Other operating expense, net

Total operating expenses		3,567			(366	)			3,201		Total operating expenses

											Income from operations
Other income (expense):
Derivative gain, net		366			(366	)	iv		-
Interest expense		(453	)		-				(453	)	Interest expense
		-			6		v		6		Interest income
Other, net		(7	)		7		i, v		-
		-			-				-		Other non-operating expense, net
Income from operations before income taxes		732			-				732		Income before income taxes
Income tax expense		(171	)		-				(171	)	Income tax expense
Net income	$	561		$	-			$	561		Net income

(i)

Represents the reclassification of miscellaneous income balances including loss on divestitures contained in in "Other, net" on Civitas’ historical statement of operations to " Other operating income, net" to conform to the Company's financial statement captions.

(ii)

Represents the reclassification of “Lease operating expense,” “Midstream operating expense,” “Gathering, transportation, and processing,” “Severance and ad valorem taxes,” and “General and administrative expense” on Civitas' historical statement of operations into "Oil, gas, and NGL production expense" to conform to the Company's financial statement captions.

(iii)

Represents the reclassification of "Transaction costs" on Civitas’ historical statement of operations to "Other operating expense" to conform to the Company's financial statement captions.

(iv)

Represents the reclassification of " Derivative gain, net" on Civitas’ historical statement of operations from below operating expense to above it, as well as changing the directional value as gains are presented in this section of the Company's financial statement as negative values.

(v)

Represents the reclassification interest income contained in "Other, net" on Civitas’ historical statement of operations to "Interest income" to conform to the Company's financial statement captions .

7.

Supplemental Unaudited Pro Forma Combined Additional Information

Pro Forma Oil and Gas Reserves

The tables below present the following historical and preliminary pro forma combined information:

·

net proved developed and undeveloped oil and gas reserves as of December 31, 2025;

·

a summary of changes in quantities of net remaining proved reserves during the year ended December 31, 2025;

·

future net cash flows relating to proved oil and gas reserves based on the standardized measure of discounted future net cash flows (“standardized measure of discounted future net cash flows”) as of December 31, 2025; and

·

a summary of changes to the standardized measure of discounted future net cash flows during the year ended December 31, 2025.

The historical information is based on each of SM Energy’s and Civitas’ consolidated financial statements as of and for the year ended December 31, 2025. The reserve estimates and standardized measure of discounted future net cash flows have been prepared in accordance with GAAP requirements for disclosures about oil and gas producing activities and SEC rules for oil and gas reporting of reserve estimation and disclosure. An explanation of the underlying methodology applied, as required by SEC regulations, can be found within the notes to the aforementioned consolidated financial statements of each of SM Energy and Civitas. The proved undeveloped reserves estimates of Civitas were based on Civitas’ development plans and reserve estimation methodologies. SM Energy will develop such proved undeveloped reserves in accordance with its own development plan and, in the future, will estimate proved undeveloped reserves in accordance with its own methodologies, therefore, the estimates presented herein for Civitas may not be representative of SM Energy’s future proved reserve estimates with respect to these properties or the reserve estimates SM Energy would have reported if it had owned such properties as of December 31, 2025.

The pro forma reserve information gives effect to the Merger as if it had occurred on December 31, 2025. The pro forma reserve information is not necessarily indicative of the results that might have occurred had the Merger occurred on December 31, 2025, and is not intended to be a projection of future results.

SM Energy’s net proved reserves in the tables below include the net proved reserves associated with the Maverick Basin Divestiture. The net proved reserves related to the Maverick Basin Divestiture as of December 31, 2025 totaled 168.1 MMBOE. This is approximately 25% of SM Energy’s net proved reserves and 11% of pro forma combined net proved reserves as of December 31, 2025.

All of SM Energy’s and Civitas’ estimated net proved reserves are located in the United States.

	Oil (MMBbl)
	Historical
	SM Energy			Civitas			Pro Forma Combined
Total net proved reserves:
As of December 31, 2024		296.0			305.4			601.4
Revision of previous estimates^{(1) (2)}		(0.2	)		1.4			1.2
Discoveries and extensions⁽³⁾		28.7			63.1			91.8
Sales of reserves⁽⁴⁾		(1.2	)		(15.4	)		(16.6	)
Purchase of minerals in place⁽⁵⁾		1.0			32.7			33.7
Production		(40.3	)		(54.7	)		(95.0	)
As of December 31, 2025		283.9			332.5			616.4
Net proved developed reserves as of:
December 31, 2024		160.3			235.6			395.9
December 31, 2025		163.7			246.5			410.2
Net proved undeveloped reserves as of:
December 31, 2024		135.7			69.7			205.4
December 31, 2025		120.2			86.0			206.2

Note: Amounts may not calculate due to rounding.

(1)

(3.4) MMBbl historically presented as “Removed from capital program” by Civitas has been included in this line item to conform with SM Energy’s presentation.

Certain Civitas line items were historically presented using different naming conventions than those used by SM Energy. For consistency, the following Civitas captions have been conformed to SM Energy’s presentation:

(2)

Revisions to previous estimates

(3)

Extensions, discoveries, and other additions

(4)

Divestiture of reserves

(5)

Acquisition of reserves

	Gas (Bcf)
	Historical
	SM Energy			Civitas			Pro Forma Combined
Total net proved reserves:
As of December 31, 2024		1,549.1			1,539.5			3,088.6
Revision of previous estimates^{(1) (2)}		150.5			4.8			155.3
Discoveries and extensions⁽³⁾		50.2			261.7			311.9
Sales of reserves⁽⁴⁾		(3.2	)		(51.7	)		(54.9	)
Purchase of minerals in place⁽⁵⁾		2.4			84.4			86.8
Production		(150.5	)		(197.6	)		(348.1	)
As of December 31, 2025		1,598.5			1,641.1			3,239.6
Net proved developed reserves as of:
December 31, 2024		1,031.3			1,323.9			2,355.2
December 31, 2025		1,069.7			1,336.0			2,405.7
Net proved undeveloped reserves as of:
December 31, 2024		517.8			215.7			733.5
December 31, 2025		528.8			305.1			833.9

Note: Amounts may not calculate due to rounding.

(1)

(10.2) Bcf historically presented as “Removed from capital program” by Civitas has been included in this line item to conform with SM Energy’s presentation.

Certain Civitas line items were historically presented using different naming conventions than those used by SM Energy. For consistency, the following Civitas captions have been conformed to SM Energy’s presentation:

(2)

Revisions to previous estimates

(3)

Extensions, discoveries, and other additions

(4)

Divestiture of reserves

(5)

Acquisition of reserves

	NGLs (MMBbl)
	Historical
	SM Energy			Civitas			Pro Forma Combined
Total net proved reserves:
As of December 31, 2024		124.1			235.8			359.9
Revision of previous estimates^{(1) (2)}		6.0			0.5			6.5
Discoveries and extensions⁽³⁾		2.6			38.8			41.4
Sales of reserves⁽⁴⁾		-			(7.4	)		(7.4	)
Purchase of minerals in place⁽⁵⁾		-			14.7			14.7
Production		(10.1	)		(29.8	)		(39.9	)
As of December 31, 2025		122.6			252.6			375.2
Net proved developed reserves as of:
December 31, 2024		71.8			203.2			275.0
December 31, 2025		70.3			206.3			276.6
Net proved undeveloped reserves as of:
December 31, 2024		52.4			32.6			85.0
December 31, 2025		52.3			46.3			98.6

Note: Amounts may not calculate due to rounding.

(1)

(1.8) MMBbl historically presented as “Removed from capital program” by Civitas has been included in this line item to conform with SM Energy’s presentation.

Certain Civitas line items were historically presented using different naming conventions than those used by SM Energy. For consistency, the following Civitas captions have been conformed to SM Energy’s presentation:

(2)

Revisions to previous estimates

(3)

Extensions, discoveries, and other additions

(4)

Divestiture of reserves

(5)

Acquisition of reserves

	Total (MMBOE)
	Historical
	SM Energy			Civitas			Pro Forma Combined
Total net proved reserves:
As of December 31, 2024		678.3			797.7			1,476.0
Revision of previous estimates^{(1) (2)}		30.9			2.8			33.7
Discoveries and extensions⁽³⁾		39.7			145.5			185.2
Sales of reserves⁽⁴⁾		(1.8	)		(31.5	)		(33.3	)
Purchase of minerals in place⁽⁵⁾		1.4			61.5			62.9
Production		(75.5	)		(117.4	)		(192.9	)
As of December 31, 2025		673.0			858.6			1,531.6
Net proved developed reserves as of:
December 31, 2024		404.0			659.5			1,063.5
December 31, 2025		412.3			675.4			1,087.7
Net proved undeveloped reserves as of:
December 31, 2024		274.3			138.3			412.6
December 31, 2025		260.7			183.1			443.8

Note: Amounts may not calculate due to rounding.

(1)

(6.8) MMBOE historically presented as “Removed from capital program” by Civitas has been included in this line item to conform with SM Energy’s presentation.

Certain Civitas line items were historically presented using different naming conventions than those used by SM Energy. For consistency, the following Civitas captions have been conformed to SM Energy’s presentation:

(2)

Revisions to previous estimates

(3)

Extensions, discoveries, and other additions

(4)

Divestiture of reserves

(5)

Acquisition of reserves

Pro Forma Standardized Measure of Discounted Future Net Cash Flows

The historical and preliminary pro forma combined future net cash flows relating to proved oil and gas reserves based on the standardized measure of discounted future net cash flows as of December 31, 2025, are presented in the tables below. The standardized measure of discounted future net cash flows includes the future net cash flows of the Maverick Basin Divestiture. The effect of removing the Maverick Basin Divestiture would remove $660 million of discounted future net cash flows resulting in approximately $5.3 billion of discounted net cash flows for SM Energy. This is approximately 11% of SM Energy’s discounted future net cash flows and 5% of pro forma combined discounted future net cash flows at December 31, 2025.

	As of December 31, 2025
	Historical
(In millions)	SM Energy			Civitas			Pro Forma Combined
Future cash inflows	$	24,750		$	28,486		$	53,236
Future production costs		(10,060	)		(13,212	)		(23,272	)
Future development costs		(2,877	)		(2,706	)		(5,583	)
Future income taxes		(1,539	)		(1,157	)		(2,696	)
Future net cash flows		10,274			11,411			21,685
10 percent annual discount		(4,318	)		(3,791	)		(8,109	)
Standardized measure of discounted future net cash flows	$	5,956		$	7,620		$	13,576

The historical and preliminary pro forma combined principal sources of changes in the standardized measure of discounted future net cash flows during the year ended December 31, 2025, are as follows:

	As of December 31, 2025
	Historical
(In millions)	SM Energy			Civitas			Pro Forma Combined
Standardized measure of discounted future net cash flows, beginning of year	$	7,268		$	8,315		$	15,583
Sales of oil, gas, and NGLs produced, net of production costs⁽¹⁾		(2,253	)		(3,008	)		(5,261	)
Net changes in prices and production costs		(1,281	)		(1,071	)		(2,352	)
Extensions and discoveries, net of related costs⁽²⁾		338			1,481			1,819
Sales of reserves in place⁽³⁾		(22	)		(434	)		(456	)
Purchase of reserves in place⁽⁴⁾		14			771			785
Previously estimated development costs incurred during the period⁽⁵⁾		987			933			1,920
Changes in estimated future development costs⁽⁶⁾		(57	)		(137	)		(194	)
Revisions of previous quantity estimates		146			30			176
Accretion of discount		835			922			1,757
Net change in income taxes		197			103			300
Changes in timing and other⁽⁷⁾		(216	)		(285	)		(501	)
Standardized measure of discounted future net cash flows, end of year	$	5,956		$	7,620		$	13,576

Note: Amounts may not calculate due to rounding.

Certain Civitas line items were historically presented using different naming conventions than those used by SM Energy. For consistency, the following Civitas captions have been conformed to SM Energy’s presentation:

(1)

Crude oil, natural gas, and NGL sales, net of production costs

(2)

Net changes in extensions, discoveries, and other additions

(3)

Divestiture of reserves

(4)

Acquisition of reserves

(5)

Development costs incurred

(6)

Changes in estimated development costs

(7)

Changes in production rates and other

Exhibit 99.5

CIVITAS RESOURCES, INC

Estimated

Future Reserves and Income

Attributable to Certain

Leasehold and Royalty Interests

SEC Parameters

As of

December 31, 2025

/s/ Scott J. Wilson		/s/ Edward M. Polishuk
Scott J. Wilson, P.E., MBA		Edward M. Polishuk
Colorado License No. 36112		Senior Petroleum Evaluator
Senior Vice President

[SEAL]

RYDER SCOTT COMPANY, L.P.

TBPELS Firm Registration No. F-1580

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

TBPELS REGISTERED ENGINEERING FIRM F-1580
555 17TH STREET SUITE 985	DENVER, COLORADO 80202	TELEPHONE (303) 339-8110

February 25, 2026

Civitas Resources, Inc.

555 17^th Street, Suite 3700

Denver, Colorado 80202

Ladies and Gentlemen:

At the request of Civitas Resources, Inc. (Civitas), Ryder Scott Company, L.P. (Ryder Scott) has conducted a reserves audit of the estimates of the proved reserves, future production and discounted future net income as of December 31, 2025 prepared by Civitas’s engineering and geological staff based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our reserves audit, completed on February 25, 2026 and presented herein, was prepared for public disclosure by Civitas in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations. The estimated reserves and income data shown herein represent Civitas’s estimated net reserves and income data attributable to the leasehold and royalty interests in certain properties owned by Civitas and reviewed by Ryder Scott, as of December 31, 2025. The properties reviewed by Ryder Scott incorporate Civitas’s reserves determinations and are located in the states of Colorado, New Mexico, Texas and Wyoming. This report supersedes the previously published January 21, 2026 and February 24, 2026 reports to include the addition of unaudited reserves to the net reserves and income table.

The properties reviewed by Ryder Scott represent approximately 99 percent of Civitas’s total net proved liquid hydrocarbon and gas reserves as of December 31, 2025.

As prescribed by the Society of Petroleum Engineers in Paragraph 2.2(f) of the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (SPE auditing standards), a reserves audit is defined as “the process of reviewing certain of the pertinent facts interpreted and assumptions made that have resulted in an estimate of reserves and/or Reserves Information prepared by others and the rendering of an opinion about (1) the appropriateness of the methodologies employed; (2) the adequacy and quality of the data relied upon; (3) the depth and thoroughness of the reserves estimation process; (4) the classification of reserves appropriate to the relevant definitions used; and (5) the reasonableness of the estimated reserves quantities and/or Reserves Information.” Reserves Information may consist of various estimates pertaining to the extent and value of petroleum properties.

Based on our review, including the data, technical processes and interpretations presented by Civitas, it is our opinion that the overall procedures and methodologies utilized by Civitas in preparing their estimates of the proved reserves, future production and discounted future net income as of December 31, 2025 comply with the current SEC regulations and that the overall proved reserves, future production and discounted future net income for the reviewed properties as estimated by Civitas are, in the aggregate, reasonable within the established audit tolerance guidelines of 10 percent as set forth in the SPE auditing standards.

1100 LOUISIANA, SUITE 4600	HOUSTON, TEXAS 77002-5294	TEL (713) 651-9191
SUITE 2800, 350 7TH AVENUE, S.W.	CALGARY, ALBERTA T2P 3N9	TEL (403) 262-2799

Civitas Resources, Inc. – SEC Parameters (1P)

February 25, 2026

Page 2

The estimated reserves and future net income amounts presented in this report are related to hydrocarbon prices. Civitas has informed us that in the preparation of their reserves and income projections, as of December 31, 2025, they used average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, as required by the SEC regulations. Actual future prices may vary considerably from the prices required by SEC regulations. The reserves volumes and the income attributable thereto have a direct relationship to the hydrocarbon prices actually received; therefore, volumes of reserves actually recovered and amounts of income actually received may differ significantly from the estimated quantities presented in this report. The net reserves and net income data as estimated by Civitas attributable to Civitas's interest in properties that we reviewed are summarized below:

SEC PARAMETERS

Estimated Net Reserves and Income Data

Certain Leasehold and Royalty Interests of

Civitas Resources, Inc.

As of December 31, 2025

Audited by Ryder Scott

	Proved
	Developed						Total
	Producing		Non-Producing		Undeveloped		Proved
*Net Reserves*
Oil/Condensate – Mbbl		231,490		11,080		85,150		327,720
Plant Products – Mbbl		197,666		5,369		45,920		248,955
Gas – MMcf		1,277,095		39,520		302,796		1,619,410

Income Data ($M)
Future Gross Revenue	$	19,787,661	$	842,047	$	6,621,718	$	27,251,426
Deductions		9,114,925		241,138		3,979,609		13,335,672
Future Net Income (FNI)	$	10,672,736	$	600,909	$	2,642,108	$	13,915,753

Discounted FNI @ 10%	$	7,192,133	$	453,329	$	1,451,714	$	9,097,177

Not Audited by Ryder Scott
	Proved
	Developed								Total
	Producing			Non-Producing			Undeveloped		Proved
Net Reserves
Oil/Condensate – Mbbl		3,885			0			882		4,767
Plant Products – Mbbl		3,277			0			336		3,612
Gas – MMcf		19,432			0			2,294		21,726

Income Data ($M)
Future Gross Revenue	$	323,856		$	0		$	67,262	$	391,118
Deductions		1,390,469			305,606			42,235		1,738,310
Future Net Income (FNI)	$	(1,066,613	)	$	(305,606	)	$	25,027	$	(1,347,192	)

Discounted FNI @ 10%	$	(456,642	)	$	(234,871	)	$	11,319	$	(680,193	)

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Civitas Resources, Inc. – SEC Parameters (1P)

February 25, 2026

Page 3

	Proved
	Developed						Total
	Producing		Non-Producing		Undeveloped		Proved
*Total Net Reserves and Income*
*Net Reserves*
Oil/Condensate – Mbbl		235,375		11,080		86,031		332,487
Plant Products – Mbbl		200,943		5,369		46,256		252,568
Gas – MMcf		1,296,526		39,520		305,090		1,641,136

Income Data ($M)
Future Gross Revenue	$	20,717,276	$	875,616	$	6,893,480	$	28,486,373
Deductions		11,111,157		580,313		4,226,345		15,917,815
Future Net Income (FNI)	$	9,606,119	$	295,303	$	2,667,136	$	12,568,558

Discounted FNI @ 10%	$	6,735,491	$	218,459	$	1,463,034	$	8,416,984

Values may not sum to total due to rounding.

Liquid hydrocarbons are expressed in standard 42 U.S. gallon barrels and shown herein as thousands of barrels (Mbbl). All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMcf) at the official temperature and pressure bases of the area in which the gas reserves are located. In this report, the revenues, deductions, and income data are expressed as thousands of U.S. dollars ($M).

The future gross revenue is after the deduction of production taxes. The deductions incorporate the normal direct costs of operating the wells, plant treatment costs, ad valorem taxes, development costs, and certain abandonment costs net of salvage. Other deductions include gathering and transportations costs. In Colorado, certain properties are exempt from production taxes due to the level of ad valorem taxes paid. The future net income is before the deduction of state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist nor does it include any adjustment for cash on hand or undistributed income.

Reserves Included in This Report

In our opinion, the proved reserves presented in this report conform to the definition as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “PETROLEUM RESERVES DEFINITIONS” is included as an attachment to this report.

The various proved reserves status categories are defined in the attachment entitled “PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES” in this report. The proved developed non-producing reserves included herein consist of the shut-in status category for wells shut in due to offset completion activity, wells waiting on facility connection, and wells waiting for abandonment.

Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.” All reserves estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends primarily on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal categories, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-categorized as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At Civitas’s request, this report addresses only the proved reserves attributable to the properties reviewed herein.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Civitas Resources, Inc. – SEC Parameters (1P)

February 25, 2026

Page 4

Proved oil and gas reserves are “those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward.” The proved reserves included herein were estimated using deterministic methods. The SEC has defined reasonable certainty for proved reserves, when based on deterministic methods, as a “high degree of confidence that the quantities will be recovered.

Proved reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities. They may or may not be actually recovered, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.

Audit Data, Methodology, Procedure and Assumptions

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy. These methods may be used individually or in combination by the reserves evaluator in the process of estimating the quantities of reserves. Reserves evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated and the stage of development or producing maturity of the property.

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserves quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserves category assigned by the evaluator. Therefore, it is the categorization of reserves quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely to be achieved than not.” The SEC states that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserves category must meet the SEC definitions as noted above.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Civitas Resources, Inc. – SEC Parameters (1P)

February 25, 2026

Page 5

Estimates of reserves quantities and their associated reserves categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserves categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

The reserves prepared by Civitas for the properties that we reviewed were estimated by performance methods or analogy. In general, the reserves attributable to producing wells and/or reservoirs were estimated by performance methods. These performance methods include decline curve analysis, which utilized extrapolations of historical production data available through December 2025 in those cases where such data were considered to be definitive. The data used in these analyses were furnished to Ryder Scott by Civitas or obtained from public data sources and were considered sufficient for the purpose thereof. In certain cases, producing reserves were estimated by analogy. This method was used where there were inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the estimates was considered to be inappropriate.

The reserves prepared by Civitas attributable to the non-producing status category were estimated by historical performance prior to the wells being shut in or by analogy, in the case of newly completed wells. The data utilized from the shut-in wells were considered sufficient for the purpose thereof. Reserves prepared by Civitas attributable to the proved undeveloped category were estimated by analogy. The data utilized from the analogues were considered sufficient for the purpose thereof.

To estimate economically producible proved oil and gas reserves and related future net cash flows, many factors and assumptions are considered including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in conducting this review.

As stated previously, proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. To confirm that the proved reserves reviewed by us meet the SEC requirements to be economically producible, we have reviewed certain primary economic data utilized by Civitas relating to hydrocarbon prices and costs as noted herein.

The hydrocarbon prices furnished by Civitas for the properties reviewed by us are based on SEC price parameters using the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Civitas Resources, Inc. – SEC Parameters (1P)

February 25, 2026

Page 6

The initial SEC hydrocarbon benchmark prices in effect on December 31, 2025 for the properties reviewed by us were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used by Civitas for the geographic area reviewed by us.

The product prices which were actually used by Civitas to determine the future gross revenue for each property reviewed by us reflect adjustments to the benchmark prices for gravity, quality, local conditions, gathering and transportation fees and/or distance from market, referred to herein as “differentials.” The differentials used by Civitas were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Civitas.

The table below summarizes Civitas’s net volume weighted benchmark prices adjusted for differentials for the properties reviewed by us and referred to herein as Civitas’s “average realized prices.” The average realized prices shown in the table below were determined from Civitas’s estimate of the total future gross revenue before production taxes for the properties reviewed by us and Civitas’s estimate of the total net reserves for the properties reviewed by us for the geographic area. The data shown in the table below is presented in accordance with SEC disclosure requirements for the geographic area reviewed by us.

Geographic Area	Product	Price Reference	Average Benchmark Prices	Average Proved Realized Prices
North America
United States	Oil/Condensate	WTI Cushing	$65.34/bbl	$65.31/bbl
	NGLs	WTI Cushing	$65.34/bbl	$17.47/bbl
	Gas	Henry Hub	$3.39/MMBTU	$1.45/Mcf

The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in Civitas’s individual property evaluations.

Operating costs furnished by Civitas are based on the operating expense reports of Civitas and include only those costs directly applicable to the leases or wells for the properties reviewed by us. For Civitas operated properties, the operating costs include an appropriate level of corporate general administrative and overhead costs. The operating costs for non-operated properties include the COPAS overhead costs that are allocated directly to the leases and wells under terms of operating agreements. The operating costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the operating cost data used by Civitas. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.

Development costs furnished by Civitas are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of these costs.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Civitas Resources, Inc. – SEC Parameters (1P)

February 25, 2026

Page 7

The estimated net cost of abandonment after salvage included in this report was provided by Civitas. Civitas’s estimates of the abandonment costs after salvage were accepted without independent verification. We have made no inspections to determine if any additional abandonment, decommissioning, and /or restoration costs may be necessary in addition to the costs provided by Civitas and included herein.

The proved developed non-producing and undeveloped reserves for the properties reviewed by us have been incorporated herein in accordance with Civitas’s plans to develop these reserves as of December 31, 2025. The implementation of Civitas’s development plans as presented to us is subject to the approval process adopted by Civitas’s management. As the result of our inquiries during the course of our review, Civitas has informed us that the development activities for the properties reviewed by us have been subjected to and received the internal approvals required by Civitas’s management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to Civitas. Civitas has provided written documentation supporting their commitment to proceed with the development activities as presented to us. Additionally, Civitas has informed us that they are not aware of any legal, regulatory, or political obstacles that would significantly alter their plans. While these plans could change from those under existing economic conditions as of December 31, 2025, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

Current costs used by Civitas were held constant throughout the life of the properties.

Civitas’s forecasts of future production rates are based on historical performance from wells currently on production. If a decline trend has been established, this trend was used as the basis for estimating future production rates. If no production decline trend has been established, future production rates were based on analogy.

Test data and other related information were used by Civitas to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by Civitas. Wells or locations that are not currently producing may start producing earlier or later than anticipated in Civitas’s estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies.

The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

Civitas’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax, and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Civitas Resources, Inc. – SEC Parameters (1P)

February 25, 2026

Page 8

The estimates of proved reserves presented herein were based upon a review of the properties in which Civitas owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included by Civitas for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

Certain technical personnel of Civitas are responsible for the preparation of reserves estimates on new properties and for the preparation of revised estimates, when necessary, on old properties. These personnel assembled the necessary data and maintained the data and workpapers in an orderly manner. We consulted with these technical personnel and had access to their workpapers and supporting data in the course of our audit.

Civitas has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In performing our audit of Civitas’s forecast of future proved production, we have relied upon data furnished by Civitas with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or gathering and processing fees, production taxes, development costs, development plans, certain abandonment costs, product prices based on the SEC regulations and adjustments or differentials to product prices. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by Civitas. We consider the factual data furnished to us by Civitas to be appropriate and sufficient for the purpose of our review of Civitas’s estimates of reserves. In summary, we consider the assumptions, data, methods and analytical procedures used by Civitas and as reviewed by us appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate under the circumstances to render the conclusions set forth herein.

Audit Opinion

Based on our review, including the data, technical processes and interpretations presented by Civitas, it is our opinion that the overall procedures and methodologies utilized by Civitas in preparing their estimates of the proved reserves, future production and discounted future net income as of December 31, 2025 comply with the current SEC regulations and that the overall proved reserves, future production and discounted future net income for the reviewed properties as estimated by Civitas are, in the aggregate, reasonable within the established audit tolerance guidelines of 10 percent as set forth in the SPE auditing standards. Ryder Scott found the processes and controls used by Civitas in their estimation of proved reserves to be effective and, in the aggregate, we found no bias in the utilization and analysis of data in estimates for these properties.

We were in reasonable agreement with Civitas's estimates of proved reserves, future production and discounted future net income for the properties which we reviewed; although in certain cases there was more than an acceptable variance between Civitas's estimates and our estimates due to a difference in interpretation of data or due to our having access to data which were not available to Civitas when its reserves estimates were prepared. However notwithstanding, it is our opinion that on an aggregate basis the data presented herein for the properties that we reviewed fairly reflects the estimated net reserves, future production and discounted future net income owned by Civitas.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Civitas Resources, Inc. – SEC Parameters (1P)

February 25, 2026

Page 9

Other Properties

Other properties, as used herein, are those properties of Civitas which we did not review. The proved net reserves attributable to the other properties account for approximately 1 percent of the total proved net liquid hydrocarbon and gas reserves of Civitas on a barrel of oil equivalent, BOE basis, based on estimates prepared by Civitas as of December 31, 2025.

The same technical personnel of Civitas were responsible for the preparation of the reserves estimates for the properties that we reviewed as well as for the properties not reviewed by Ryder Scott.

Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1937. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have approximately eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.

Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.

Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists receive professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization. Regulating agencies require that, in order to maintain active status, a certain amount of continuing education hours be completed annually, including an hour of ethics training. Ryder Scott fully supports this technical and ethics training with our internal requirement mentioned above.

We are independent petroleum engineers with respect to Civitas. Neither we nor any of our employees have any financial interest in the subject properties, and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

The results of this audit, presented herein, are based on technical analyses conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing, reviewing and approving the review of the reserves information discussed in this report, are included as an attachment to this letter.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Civitas Resources, Inc. – SEC Parameters (1P)

February 25, 2026

Page 10

Terms of Usage

The results of our third party audit, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by Civitas.

Civitas makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act. Furthermore, Civitas has certain registration statements filed with the SEC under the 1933 Securities Act into which any subsequently filed Form 10-K is incorporated by reference. We have consented to the incorporation by reference in the registration statements on Form S-8 of Civitas, of the references to our name, as well as to the references to our third party audit for Civitas, which appears in the December 31, 2025 annual report on Form 10-K of Civitas. Our written consent for such use is included as a separate exhibit to the filings made with the SEC by Civitas.

We have provided Civitas with a digital version of the original signed copy retained in our files. In the event there are any differences between the digital version included in filings made by Civitas and the original signed copy in our files, the original signed file copy shall control and supersede.

The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

	Very truly yours,

	RYDER SCOTT COMPANY, L.P.
	TBPELS Firm Registration No. F-1580

	/s/ Scott J. Wilson

	Scott J. Wilson, P.E., MBA
	Colorado License No. 36112
	Senior Vice President                 [SEAL]

	/s/ Edward M. Polishuk

	Edward M. Polishuk
	Senior Petroleum Evaluator

SJW-EMP (DRO)/pl

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Professional Qualifications of Primary Technical Person

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Mr. Scott James Wilson was the primary technical person responsible for the estimate of the reserves, future production, and income presented herein.

Mr. Wilson, an employee of Ryder Scott Company L.P. (Ryder Scott) since 2000, is a Senior Vice President responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Wilson served in a number of engineering positions with Atlantic Richfield Company. For more information regarding Mr. Wilson's geographic and job specific experience, please refer to the Ryder Scott Company website at https://www.ryderscott.com/company/employees/denver-employees.

Mr. Wilson earned a Bachelor of Science degree in Petroleum Engineering from the Colorado School of Mines in 1983 and an MBA in Finance from the University of Colorado in 1985, graduating from both with High Honors. He is a registered Professional Engineer by exam in the States of Alaska, Colorado, Texas, and Wyoming. He is also an active member of the Society of Petroleum Engineers; serving as co-Chairman of the SPE Reserves and Economics Technology Interest Group, and Gas Technology Editor for SPE's Journal of Petroleum Technology. He is a member and past chairman of the Denver section of the Society of Petroleum Evaluation Engineers. Mr. Wilson has published several technical papers, one chapter in Marine and Petroleum Geology and two in SPEE monograph 4, which was published in 2016. He is the primary inventor on four US patents and won the 2017 Reservoir Description and Dynamics award for the SPE Rocky Mountain Region.

In addition to gaining experience and competency through prior work experience, several state Boards of Professional Engineers require a minimum number of hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Wilson fulfills as part of his registration in four states. As part of his continuing education, Mr. Wilson attends internally presented training as well as public forums relating to the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, and Final Rule released January 14, 2009 in the Federal Register. Mr. Wilson attends additional hours of formalized external training covering such topics as the SPE/WPC/AAPG/SPEE Petroleum Resources Management System, reservoir engineering and petroleum economics evaluation methods, procedures and software and ethics for consultants.

Based on his educational background, professional training and more than 36 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Wilson has attained the professional qualifications as a Reserves Estimator and Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of June 2019.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

PREAMBLE

On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics herein).

Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.

Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.

Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale. Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

Page 2

Reserves do not include quantities of petroleum being held in inventory.

Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.

RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:

Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

PROVED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:

Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

Page 3

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

and

2018 PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)

Sponsored and Approved by:

SOCIETY OF PETROLEUM ENGINEERS (SPE)

WORLD PETROLEUM COUNCIL (WPC)

AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)

SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)

SOCIETY OF EXPLORATION GEOPHYSICISTS (SEG)

SOCIETY OF PETROPHYSICISTS AND WELL LOG ANALYSTS (SPWLA)

EUROPEAN ASSOCIATION OF GEOSCIENTISTS & ENGINEERS (EAGE)

Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).

DEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:

Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Developed Producing (SPE-PRMS Definitions)

While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.

Developed Producing Reserves

Developed Producing Reserves are expected quantities to be recovered from completion intervals that are open and producing at the effective date of the estimate.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES
Page 2

Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Developed Non-Producing

Developed Non-Producing Reserves include shut-in and behind-pipe Reserves.

Shut-In

Shut-in Reserves are expected to be recovered from:

(1)

completion intervals that are open at the time of the estimate but which have not yet started producing;

(2)

wells which were shut-in for market conditions or pipeline connections; or

(3)

wells not capable of production for mechanical reasons.

Behind-Pipe

Behind-pipe Reserves are expected to be recovered from zones in existing wells that will require additional completion work or future re-completion before start of production with minor cost to access these reserves.

In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

UNDEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:

Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Delaware		001-31539		41-0518430
(State or other jurisdiction of incorporation)		(Commission File Number)		(I.R.S. Employer Identification No.)

1700 Lincoln Street, Suite 3200, Denver, Colorado	80203
(Address of principal executive offices)	(Zip Code)

Title of each class		Trading symbol(s)		Name of each exchange on which registered
Common stock, $0.01 par value		SM		New York Stock Exchange

(d) Exhibits.

	Number	Exhibit
	23.1	Consent of Deloitte LLP
	23.2	Consent of Ryder Scott Company
	99.1	Press release of the Company dated March 4, 2026, entitled “SM Energy Announces Private Offering of $750 Million of Senior Notes due 2034”
	99.2	Press release of the Company dated March 4, 2026, entitled “SM Energy Company Announces Cash Tender Offer For Up To $750.0 Million Aggregate Principal Amount Of 8.375% Senior Notes Due 2028 Originally Issued by Civitas Resources”
	99.3	Audited historical financial statements for the fiscal years ended December 31, 2025 and 2024, for Civitas
	99.4	Unaudited pro forma condensed combined financial information for the periods presented, for the Company and Civitas
	99.5	Reserve Report as of December 31, 2025 for Civitas
	104	Cover Page Interactive Data File (formatted as Inline XBRL and included as Exhibit 101).

	SM ENERGY COMPANY

Date: March 4, 2026	By:	/s/ James B. Lebeck
		James B. Lebeck
		Executive Vice President – Chief Corporate Development Officer, General Counsel and Corporate Secretary

SM Energy (NYSE: SM) launches $750M 2034 notes sale, $750M tender

Rhea-AI Filing Summary

Positive

Negative

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FAQ

What did SM Energy (SM) announce regarding new senior notes?

How is SM Energy (SM) using proceeds from the 2034 senior notes offering?

What are the key terms of SM Energy’s (SM) tender offer for 2028 notes?

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What additional Civitas-related information did SM Energy (SM) file?

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Filing Exhibits & Attachments

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NYSE:SM

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Trending News

SM Energy (NYSE: SM) launches $750M 2034 notes sale, $750M tender

Rhea-AI Filing Summary

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Insights

Credit and capital-structure analyst neutral

FAQ

What did SM Energy (SM) announce regarding new senior notes?

How is SM Energy (SM) using proceeds from the 2034 senior notes offering?

What are the key terms of SM Energy’s (SM) tender offer for 2028 notes?

When does SM Energy’s (SM) tender offer for 2028 notes end?

What additional Civitas-related information did SM Energy (SM) file?

Who can buy SM Energy’s (SM) new 2034 notes in the private offering?

Filing Exhibits & Attachments

Press Releases

Financial & Certifications

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NYSE:SM

SM Rankings

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SM Stock Data