SEC Form 10-Q filed by SM Energy Company

8/1/25 8:55:30 AM ET

Oil & Gas Production

Energy

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sm-20250630

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

☑ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2025

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ___________ to ___________

Commission File Number 001-31539

SM ENERGY COMPANY

(Exact name of registrant as specified in its charter)

Delaware

41-0518430

(State or other jurisdiction of incorporation or organization)

(I.R.S. Employer Identification No.)

1700 Lincoln Street, Suite 3200, Denver, Colorado

80203

(Address of principal executive offices)

(Zip Code)

(303) 861-8140

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:


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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☑ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☑ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer

☑

Accelerated filer

☐

Non-accelerated filer

☐

Smaller reporting company

☐

Emerging growth company

☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☑

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

As of July 23, 2025, the registrant had 114,953,972 shares of common stock outstanding.

TABLE OF CONTENTS


Item		Page
	Cautionary Information about Forward-Looking Statements	3

	Part I	4

Item 1.	Financial Statements (unaudited)	4

	Condensed Consolidated Balance Sheets June 3 0 , 2025, and December 31, 2024	4

	Condensed Consolidated Statements of Operations Three and Six Months Ended June 3 0 , 2025, and 2024	5

	Condensed Consolidated Statements of Comprehensive Income Three and Six Months Ended June 3 0 , 2025, and 2024	6

	Condensed Consolidated Statements of Stockholders’ Equity Co ntinuous Quarterly Presentation Ended June 3 0 , 2025, and 2024	7

	Condensed Consolidated Statements of Cash Flows Six Months Ended June 3 0 , 2025, and 2024	8

	Notes to Condensed Consolidated Financial Statements	10

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	22

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	38

Item 4.	Controls and Procedures	38

	Part II	39

Item 1.	Legal Proceedings	39

Item 1A.	Risk Factors	39

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	39

Item 4.	Mine Safety Disclosures	39

Item 5.	Other Information	39

Item 6.	Exhibits	40

	Signatures	41

Cautionary Information about Forward-Looking Statements

This Report on Form 10-Q (“Form 10-Q” or “this report”) contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (“Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (“Exchange Act”). All statements included in this report, other than statements of historical fact, that address activities, conditions, events, or developments with respect to our financial condition, results of operations, business prospects or economic performance that we expect, believe, or anticipate will or may occur in the future, or that address plans and objectives of management for future operations, are forward-looking statements. The words “anticipate,” “assume,” “believe,” “budget,” “could,” “estimate,” “expect,” “forecast,” “goal,” “intend,” “pending,” “plan,” “potential,” “projected,” “seek,” “target,” “will,” and similar expressions are intended to identify forward-looking statements. Forward-looking statements appear throughout this report, and include statements about such matters as:

•the amount and nature of future capital expenditures, the resilience of our assets to declining commodity prices, the ability of our assets to generate returns in the current macroeconomic environment, and the availability of liquidity and capital resources to fund capital expenditures;

•our outlook on prices for future crude oil, natural gas, and natural gas liquids (also referred to throughout this report as “oil,” “gas,” and “NGLs,” respectively), well costs, service costs, production costs, and general and administrative costs, and the effects of inflation, tariffs or trade restrictions on each of these;

•changes in general economic and financial conditions, inflationary pressures, the potential for economic recession in the U.S., tariffs and trade restrictions, including the imposition of new and higher tariffs on imported goods, the uncertainty of evolving tariffs, and retaliatory tariffs implemented by other countries on U.S. goods, and the potential effects on our financial condition or results of operations;

•business strategies and other plans and objectives for future operations, including plans for expansion and growth of operations or reallocation of capital, plans with respect to future dividend payments, debt repayments or redemptions, equity repurchases, capital markets activities, sustainability goals and initiatives, and our outlook on our future financial condition or results of operations;

•armed conflict, political instability, or civil unrest in oil and gas producing regions and shipping channels, including instability in the Middle East, the wars and armed conflicts between Russia and Ukraine, and among Israel and Hamas, Hezbollah, and Iran and its proxy forces, including recent U.S. involvement in the Israel-Iran conflict, and related potential effects on laws and regulations, or the imposition of economic or trade sanctions (“War and Geopolitical Instability”);

•any changes to the borrowing base or aggregate revolving lender commitments under, or maturity date of, our Seventh Amended and Restated Credit Agreement, as amended (“Credit Agreement”);

•cash flows, liquidity, interest and related debt service expenses, changes in our effective tax rate, and our ability to repay debt in the future;

•our drilling and completion activities and other exploration and development activities, each of which could be affected by supply chain disruptions, inflation, tariffs or trade restrictions, pipeline capacity, our ability to obtain permits and governmental approvals, and plans by us, our joint development partners, and/or other third-party operators;

•possible or expected acquisitions and divestitures, including the possible divestiture or farm-out of, or farm-in or joint development of, certain properties;

•oil, gas, and NGL reserve estimates and estimates of both future net revenues and the present value of future net revenues associated with those reserve estimates, and the conversion of proved undeveloped reserves to proved developed reserves;

•our expected future production volumes, identified drilling locations, and drilling prospects, inventories, projects and programs;

•our expectations related to changes in proposed or final federal and state income tax laws and regulations, including the expected impacts of the One Big Beautiful Bill Act (“OBBBA”), enacted on July 4, 2025; and

•other similar matters, such as those discussed in Management’s Discussion and Analysis of Financial Condition and Results of Operations in Part I, Item 2 of this report.

Our forward-looking statements are based on assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions, expected future developments, and other factors that we believe are appropriate under the circumstances. We caution you that forward-looking statements are not guarantees of future performance, and these statements are subject to known and unknown risks and uncertainties, which may cause our actual results or performance to be materially different from any future results or performance expressed or implied by the forward-looking statements. Factors that may cause our financial condition, results of operations, business prospects or economic performance to differ from expectations include the factors discussed in the Risk Factors section in Part I, Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2024 (“2024 Form 10-K”).

The forward-looking statements in this report speak only as of the filing of this report. Although we may from time to time voluntarily update our prior forward-looking statements, we disclaim any commitment to do so except as required by applicable securities laws.

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

SM ENERGY COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

(in thousands, except share data)


	June 30, 2025		December 31, 2024
ASSETS
Current assets:
Cash and cash equivalents	$	101,877	$	—
Accounts receivable	364,296		360,976
Derivative assets	78,504		48,522
Prepaid expenses and other	30,413		25,201
Total current assets	575,090		434,699
Property and equipment (successful efforts method):
Proved oil and gas properties	15,378,464		14,301,502
Accumulated depletion, depreciation, and amortization	(8,157,601)		(7,603,195)
Unproved oil and gas properties, net of valuation allowance of $26,680 and $32,680, respectively	589,842		764,924
Wells in progress	395,532		481,893

Other property and equipment, net of accumulated depreciation of $63,685 and $61,737, respectively	54,531		47,585
Total property and equipment, net	8,260,768		7,992,709
Noncurrent assets:

Derivative assets	4,871		3,973
Other noncurrent assets	152,506		145,266
Total noncurrent assets	157,377		149,239
Total assets	$	8,993,235	$	8,576,647
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	794,002	$	760,473

Derivative liabilities	19,003		7,058
Other current liabilities	24,942		22,419
Total current liabilities	837,947		789,950
Noncurrent liabilities:
Revolving credit facility	—		68,500
Senior Notes, net	2,711,148		2,708,243


Asset retirement obligations	150,095		145,313

Net deferred tax liabilities	589,756		545,295
Derivative liabilities	12,480		7,142
Other noncurrent liabilities	101,711		74,947
Total noncurrent liabilities	3,565,190		3,549,440

Commitments and contingencies (note 6)

Stockholders’ equity:
Common stock, $0.01 par value - authorized: 200,000,000 shares; issued and outstanding: 114,634,725 and 114,461,934 shares, respectively	1,146		1,145
Additional paid-in capital	1,516,542		1,501,779
Retained earnings	3,073,545		2,735,494
Accumulated other comprehensive loss	(1,135)		(1,161)
Total stockholders’ equity	4,590,098		4,237,257
Total liabilities and stockholders’ equity	$	8,993,235	$	8,576,647

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

SM ENERGY COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

(in thousands, except per share data)


	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2025		2024		2025		2024
Operating revenues and other income:
Oil, gas, and NGL production revenue	$	785,076	$	633,451	$	1,624,696	$	1,193,047

Other operating income	7,867		1,104		12,791		1,378

Total operating revenues and other income	792,943		634,555		1,637,487		1,194,425
Operating expenses:
Oil, gas, and NGL production expense	224,008		136,622		449,081		273,997
Depletion, depreciation, and amortization	292,990		179,651		562,890		345,839
Exploration	15,355		17,094		27,118		35,675

General and administrative	42,097		31,112		81,436		61,290
Net derivative (gain) loss	(78,308)		(12,118)		(61,092)		16,027

Other operating expense, net	1,893		2,814		6,858		3,822
Total operating expenses	498,035		355,175		1,066,291		736,650
Income from operations	294,908		279,380		571,196		457,775
Interest expense	(42,561)		(21,807)		(86,934)		(43,680)
Interest income	182		6,333		295		13,103

Other non-operating expense	(27)		(23)		(54)		(47)
Income before income taxes	252,502		263,883		484,503		427,151
Income tax expense	(50,837)		(53,590)		(100,569)		(85,659)
Net income	$	201,665	$	210,293	$	383,934	$	341,492

Basic weighted-average common shares outstanding	114,520		114,634		114,518		115,138
Diluted weighted-average common shares outstanding	114,788		115,715		114,880		116,092
Basic net income per common share	$	1.76	$	1.83	$	3.35	$	2.97
Diluted net income per common share	$	1.76	$	1.82	$	3.34	$	2.94
Net dividends declared per common share	$	0.20	$	0.18	$	0.40	$	0.36

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

SM ENERGY COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

(in thousands)


	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2025		2024		2025		2024
Net income	$	201,665	$	210,293	$	383,934	$	341,492
Other comprehensive income, net of tax:
Pension liability adjustment	12		7		26		15
Total other comprehensive income, net of tax	12		7		26		15
Total comprehensive income	$	201,677	$	210,300	$	383,960	$	341,507

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

SM ENERGY COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (UNAUDITED)

(in thousands, except share data and dividends per share)


				Additional Paid-in Capital				Accumulated Other Comprehensive Loss		Total Stockholders’ Equity
	Common Stock					Retained Earnings
	Shares	Amount
Balances, December 31, 2024	114,461,934	$	1,145	$	1,501,779	$	2,735,494	$	(1,161)	$	4,237,257
Net income	—	—		—		182,269		—		182,269
Other comprehensive income	—	—		—		—		14		14
Net cash dividends declared, $0.20 per share	—	—		—		(22,893)		—		(22,893)

Issuance of common stock upon vesting of RSUs, net of shares used for tax withholdings	284	—		(3)		—		—		(3)
Stock-based compensation expense	—	—		7,089		—		—		7,089


Balances, March 31, 2025	114,462,218	$	1,145	$	1,508,865	$	2,894,870	$	(1,147)	$	4,403,733
Net income	—	—		—		201,665		—		201,665
Other comprehensive income	—	—		—		—		12		12
Net cash dividends declared, $0.20 per share	—	—		—		(22,990)		—		(22,990)
Issuance of common stock under Employee Stock Purchase Plan	90,314	1		1,926		—		—		1,927

Stock-based compensation expense	82,193	—		5,751		—		—		5,751



Balances, June 30, 2025	114,634,725	$	1,146	$	1,516,542	$	3,073,545	$	(1,135)	$	4,590,098


				Additional Paid-in Capital				Accumulated Other Comprehensive Loss		Total Stockholders’ Equity
	Common Stock					Retained Earnings
	Shares	Amount
Balances, December 31, 2023	115,745,393	$	1,157	$	1,565,021	$	2,052,279	$	(2,607)	$	3,615,850
Net income	—	—		—		131,199		—		131,199
Other comprehensive income	—	—		—		—		8		8
Net cash dividends declared, $0.18 per share	—	—		—		(20,707)		—		(20,707)

Issuance of common stock upon vesting of RSUs, net of shares used for tax withholdings	1,147	—		(22)		—		—		(22)
Stock-based compensation expense	1,839	—		5,018		—		—		5,018

Purchase of shares under Stock Repurchase Program	(712,235)	(7)		(33,088)		—		—		(33,095)
Balances, March 31, 2024	115,036,144	$	1,150	$	1,536,929	$	2,162,771	$	(2,599)	$	3,698,251
Net income	—	—		—		210,293		—		210,293
Other comprehensive income	—	—		—		—		7		7
Net cash dividends declared, $0.18 per share	—	—		—		(20,532)		—		(20,532)
Issuance of common stock under Employee Stock Purchase Plan	56,006	1		1,843		—		—		1,844

Stock-based compensation expense	35,691	1		5,787		—		—		5,788
Purchase of shares under Stock Repurchase Program	(1,058,956)	(11)		(51,700)		—		—		(51,711)

Balances, June 30, 2024	114,068,885	$	1,141	$	1,492,859	$	2,352,532	$	(2,592)	$	3,843,940

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

SM ENERGY COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(in thousands)


	For the Six Months Ended June 30,
	2025		2024
Cash flows from operating activities:
Net income	$	383,934	$	341,492
Adjustments to reconcile net income to net cash provided by operating activities:

Depletion, depreciation, and amortization	562,890		345,839


Stock-based compensation expense	12,840		10,806
Net derivative (gain) loss	(61,092)		16,027
Net derivative settlement gain	47,496		29,797
Amortization of deferred financing costs	5,102		2,743

Deferred income taxes	69,463		70,907
Other, net	(4,206)		(17,756)
Net change in working capital	37,701		(47,473)





Net cash provided by operating activities	1,054,128		752,382

Cash flows from investing activities:

Capital expenditures	(824,043)		(655,049)
Acquisition of proved and unproved oil and gas properties	(14,919)		2
Other, net	—		80
Net cash used in investing activities	(838,962)		(654,967)

Cash flows from financing activities:
Proceeds from revolving credit facility	1,384,500		—
Repayment of revolving credit facility	(1,453,000)		—



Repurchase of common stock	(648)		(83,991)
Dividends paid	(45,785)		(41,541)
Net proceeds from sale of common stock	1,927		1,844

Other, net	(283)		(22)
Net cash used in financing activities	(113,289)		(123,710)

Net change in cash, cash equivalents, and restricted cash	101,877		(26,295)
Cash, cash equivalents, and restricted cash at beginning of period	—		616,164
Cash, cash equivalents, and restricted cash at end of period	$	101,877	$	589,869

Supplemental schedule of additional cash flow information:
Operating activities:
Cash paid for interest, net of capitalized interest	$	(84,859)	$	(41,559)
Net cash paid for income taxes	$	(5,220)	$	(7,429)
Investing activities:
Changes in capital expenditure accruals	$	4,734	$	(21,491)

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

SM ENERGY COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) (Continued)

(in thousands)


	As of June 30,
	2025		2024
Reconciliation of cash, cash equivalents, and restricted cash:
Cash and cash equivalents	$	101,877	$	487,869
Restricted cash (1)	—		102,000
Cash, cash equivalents, and restricted cash at end of period	$	101,877	$	589,869

____________________________________________

(1) As of June 30, 2024, the amount represented a deposit held in a third-party escrow account related to the Uinta Basin assets acquired on October 1, 2024 (“Uinta Basin Acquisition”).

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

SM ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Note 1 - Summary of Significant Accounting Policies

Description of Operations

SM Energy Company, together with its consolidated subsidiaries (“SM Energy” or the “Company”), is an independent energy company engaged in the acquisition, exploration, development, and production of oil, gas, and NGLs in Texas and Utah.

Basis of Presentation

The accompanying unaudited condensed consolidated financial statements include the accounts of the Company and have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim financial information, the instructions to Quarterly Report on Form 10-Q, and Regulation S-X. These financial statements do not include all information and notes required by GAAP for annual financial statements. However, except as disclosed herein, there has been no material change in the information disclosed in the notes to the consolidated financial statements included in the 2024 Form 10-K. In the opinion of management, all adjustments, consisting of normal recurring adjustments considered necessary for a fair presentation of interim financial information, have been included. Operating results for the periods presented are not necessarily indicative of expected results for the full year. Additionally, certain prior period amounts have been reclassified to conform to current period presentation in the accompanying unaudited condensed consolidated financial statements.

Significant Accounting Policies

The significant accounting policies followed by the Company are set forth in Note 1 - Summary of Significant Accounting Policies in the 2024 Form 10-K and are supplemented by the notes to the unaudited condensed consolidated financial statements included in this report. These unaudited condensed consolidated financial statements should be read in conjunction with the 2024 Form 10-K.

Recently Issued Accounting Guidance

As of June 30, 2025, and through the filing of this report, no accounting guidance applicable to the Company has been issued and not yet adopted in 2025 that would have a material effect on the Company’s unaudited condensed consolidated financial statements and related disclosures. For information about accounting guidance issued in previous years but not yet adopted by the Company, refer to Note 1 - Summary of Significant Accounting Policies in the 2024 Form 10-K.

Note 2 - Revenue from Contracts with Customers

The Company recognizes its share of revenue from the sale of produced oil, gas, and NGLs from its Midland Basin, South Texas, and Uinta Basin assets. Oil, gas, and NGL production revenue presented within the accompanying unaudited condensed consolidated statements of operations (“accompanying statements of operations”) reflects revenue generated from contracts with customers.

The tables below present oil, gas, and NGL production revenue by product type for each of the Company’s operating areas. Amounts below for the Uinta Basin reflect activity for the three and six months ended June 30, 2025. There is no comparable activity for the three and six months ended June 30, 2024, because the Uinta Basin assets were acquired on October 1, 2024.


	Midland Basin						South Texas						Uinta Basin						Total
	Three Months Ended June 30,						Three Months Ended June 30,						Three Months Ended June 30,						Three Months Ended June 30,
	2025			2024			2025			2024			2025			2024			2025			2024

	(in thousands)
Oil production revenue	$	314,535		$	378,830		$	113,480		$	153,724		$	225,363		$	—		$	653,378		$	532,554
Gas production revenue	27,215			22,833			44,481			22,352			6,298			—			77,994			45,185
NGL production revenue	109			134			53,521			55,578			74			—			53,704			55,712
Total	$	341,859		$	401,797		$	211,482		$	231,654		$	231,735		$	—		$	785,076		$	633,451
Relative percentage	43		%	63		%	27		%	37		%	30		%	—		%	100		%	100		%


	Midland Basin						South Texas						Uinta Basin						Total
	Six Months Ended June 30,						Six Months Ended June 30,						Six Months Ended June 30,						Six Months Ended June 30,
	2025			2024			2025			2024			2025			2024			2025			2024

	(in thousands)
Oil production revenue	$	650,962		$	711,021		$	230,894		$	262,427		$	429,993		$	—		$	1,311,849		$	973,448
Gas production revenue	83,428			63,371			98,900			49,658			15,760			—			198,088			113,029
NGL production revenue	262			218			114,423			106,352			74			—			114,759			106,570
Total	$	734,652		$	774,610		$	444,217		$	418,437		$	445,827		$	—		$	1,624,696		$	1,193,047
Relative percentage	45		%	65		%	27		%	35		%	28		%	—		%	100		%	100		%

The Company recognizes oil, gas, and NGL production revenue at the point in time when custody and title (“control”) of the product transfers to the purchaser, which may differ depending on the applicable contractual terms. Transfer of control determines the presentation of transportation, gathering, processing, and other post-production expenses (“costs and other deductions”) within the accompanying statements of operations. Costs and other deductions incurred by the Company prior to transfer of control are recorded within the oil, gas, and NGL production expense line item on the accompanying statements of operations. When control is transferred, sales are based on a market price that may be affected by costs and other deductions incurred by the purchaser subsequent to the transfer of control.

Revenue is recorded in the month when performance obligations are satisfied. However, settlement statements from the purchasers of hydrocarbons and the related cash consideration are received 30 to 90 days after production has occurred. As a result, the Company must estimate the amount of production delivered to the customer and the consideration that will ultimately be received for sale of the product. Estimated revenue due to the Company is recorded within the accounts receivable line item on the accompanying unaudited condensed consolidated balance sheets (“accompanying balance sheets”) until payment is received. The accounts receivable balances from contracts with customers within the accompanying balance sheets as of June 30, 2025, and December 31, 2024, were $234.9 million and $246.4 million, respectively. To estimate accounts receivable from contracts with customers, the Company uses knowledge of its properties, historical performance, contractual arrangements, index pricing, quality and transportation differentials, and other factors as the basis for these estimates. Differences between estimates and actual amounts received for product sales are recorded in the month that payment is received from the purchaser. The time period between production and satisfaction of performance obligations is generally less than one day for volumes sold at, or in close proximity, to the wellhead or to the inlet or tailgate of the midstream processing facility, and is generally less than two weeks for volumes transported by rail. As of June 30, 2025, there were no material unsatisfied or partially unsatisfied performance obligations.

Note 3 - Equity

Stock Repurchase Program

The Company’s stock repurchase program permits the Company to repurchase shares of its common stock from time to time in open market transactions, through privately negotiated transactions or by other means in accordance with federal securities laws and subject to certain provisions of the Credit Agreement and the indentures governing the Senior Notes, as defined in Note 5 - Long-Term Debt (“Stock Repurchase Program”).

During the three and six months ended June 30, 2025, the Company did not repurchase any shares of its common stock under the Stock Repurchase Program. During the three and six months ended June 30, 2024, the Company repurchased and subsequently retired 1.1 million and 1.8 million shares, respectively, of its common stock at a weighted-average share price of $48.35 and $47.40, respectively, for a total cost of $51.2 million and $84.0 million, respectively, excluding excise taxes, commissions, and fees.

As of June 30, 2025, $500.0 million remained available for repurchases of the Company’s outstanding common stock through December 31, 2027, under the Stock Repurchase Program.

Note 4 - Income Taxes

The provision for income taxes consisted of the following:


	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2025			2024			2025			2024

	(in thousands)
Current portion of income tax expense:
Federal	$	(6,749)		$	(9,220)		$	(28,098)		$	(13,474)
State	(884)			(854)			(3,008)			(1,278)
Deferred portion of income tax expense	(43,204)			(43,516)			(69,463)			(70,907)
Income tax expense	$	(50,837)		$	(53,590)		$	(100,569)		$	(85,659)

Effective tax rate	20.1		%	20.3		%	20.8		%	20.1		%

Income tax expense or benefit differs from the amount that would be calculated by applying the statutory United States federal income tax rate to income or loss before income taxes. These differences can relate to the effect of federal tax credits, state income taxes, changes in valuation allowances, excess tax benefits and deficiencies from stock-based compensation awards, tax deduction limitations on compensation of covered individuals, the cumulative effect of other smaller permanent differences, and can also reflect the cumulative effect of an enacted tax rate change, in the period of enactment, on the Company’s net deferred tax asset and liability balances. The quarterly effective tax rate and the resulting income tax expense or benefit can also be affected by the proportional effects of forecast net income or loss and the correlative effect on the valuation allowance for each of the periods presented in the table above.

On July 4, 2025, the OBBBA was enacted into law. The Company is evaluating the potential impacts of the OBBBA and currently expects to benefit from certain provisions. The effects of changes in tax laws are recognized in the period of enactment, therefore, the Company expects to record the impacts of the OBBBA on full-year income tax expense during the third quarter of 2025.

The Company complies with authoritative accounting guidance regarding uncertain tax positions. The entire amount of unrecognized tax benefit reported by the Company would affect its effective tax rate if recognized. The Company does not expect a significant change to the recorded unrecognized tax benefits in 2025.

For all years before 2021, the Company is generally no longer subject to United States federal or state income tax examinations by tax authorities.

Note 5 - Long-Term Debt

Credit Agreement

The Company’s Credit Agreement provides for a senior secured revolving credit facility with a maximum loan amount of $3.0 billion. As of June 30, 2025, the borrowing base and aggregate revolving lender commitments under the Credit Agreement were $3.0 billion and $2.0 billion, respectively. The next borrowing base redetermination is scheduled to occur on October 1, 2025. The Credit Agreement is scheduled to mature on the earlier of (a) October 1, 2029 (“Stated Maturity Date”), or (b) 91 days prior to the maturity date of any of the Company’s outstanding Senior Notes, as defined below, to the extent that, on or before such date, the respective Senior Notes have not been repaid, exchanged, repurchased, refinanced, or otherwise redeemed in a manner that results in no more than $50.0 million remaining due on the originally scheduled maturity date, and, if refinanced or exchanged, with a scheduled maturity date that is not earlier than at least 180 days after the Stated Maturity Date.

Interest and commitment fees associated with the revolving credit facility are accrued based on a borrowing base utilization grid set forth in the Credit Agreement, as presented in Note 5 - Long-Term Debt in the 2024 Form 10-K. At the Company’s election, borrowings under the Credit Agreement may be in the form of Secured Overnight Financing Rate (“SOFR”) revolving loans, Alternate

Base Rate (“ABR”) revolving loans, or Swingline loans. SOFR revolving loans accrue interest at SOFR plus the applicable margin from the utilization grid, and ABR revolving loans and Swingline loans accrue interest at a market-based floating rate, plus the applicable margin from the utilization grid. Commitment fees are accrued on the unused portion of the aggregate revolving lender commitment amount at rates from the utilization grid.

The following table presents the outstanding balance, total amount of letters of credit outstanding, and available borrowing capacity under the Credit Agreement:


	As of July 23, 2025		As of June 30, 2025		As of December 31, 2024

	(in thousands)
Revolving credit facility (1)	$	—	$	—	$	68,500
Letters of credit (2)	2,000		2,000		2,000
Available borrowing capacity	1,998,000		1,998,000		1,929,500
Total aggregate revolving lender commitment amount	$	2,000,000	$	2,000,000	$	2,000,000

____________________________________________

(1) Unamortized deferred financing costs attributable to the revolving credit facility are presented as a component of the other noncurrent assets line item on the accompanying balance sheets and totaled $16.8 million and $18.7 million as of June 30, 2025, and December 31, 2024, respectively. These costs are being amortized over the term of the Credit Agreement on a straight-line basis.

(2) Letters of credit outstanding reduce the amount available under the revolving credit facility on a dollar-for-dollar basis.

Senior Notes

The Company’s Senior Notes, net line item on the accompanying balance sheets as of June 30, 2025, and December 31, 2024, consisted of the following (collectively referred to as “Senior Notes”):


	As of June 30, 2025						As of December 31, 2024
	Principal Amount		Unamortized Deferred Financing Costs		Principal Amount, Net		Principal Amount		Unamortized Deferred Financing Costs		Principal Amount, Net

	(in thousands)
6.75% Senior Notes due 2026	$	419,235	$	817	$	418,418	$	419,235	$	1,168	$	418,067
6.625% Senior Notes due 2027	416,791		1,230		415,561		416,791		1,618		415,173
6.5% Senior Notes due 2028	400,000		3,128		396,872		400,000		3,636		396,364
6.75% Senior Notes due 2029	750,000		9,444		740,556		750,000		10,489		739,511
7.0% Senior Notes due 2032	750,000		10,259		739,741		750,000		10,872		739,128
Total	$	2,736,026	$	24,878	$	2,711,148	$	2,736,026	$	27,783	$	2,708,243

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.

Covenants

The Company is subject to certain financial and non-financial covenants under the Credit Agreement and the indentures governing the Senior Notes that, among other terms, limit the Company’s ability to incur additional indebtedness, make restricted payments including dividends, sell assets, create liens that secure debt, enter into transactions with affiliates, make certain investments, or merge or consolidate with other entities. The Company was in compliance with all financial and non-financial covenants as of June 30, 2025, and through the filing of this report.

Capitalized Interest

Capitalized interest costs for the three months ended June 30, 2025, and 2024, totaled $9.4 million and $6.1 million, respectively, and for the six months ended June 30, 2025, and 2024, totaled $18.1 million and $12.2 million, respectively. The amount of interest the Company capitalizes generally fluctuates based on the amount borrowed, the Company’s capital program, and the timing

and amount of costs associated with capital projects that are considered in progress. Capitalized interest costs are included in total costs incurred.

Note 6 - Commitments and Contingencies

Commitments

Other than those items discussed below, there have been no changes in commitments through the filing of this report that differ materially from those disclosed in the 2024 Form 10-K.

Railcar Leases. During the six months ended June 30, 2025, the Company entered into new railcar leases and amended certain of its existing railcar leases with terms extending into 2030, with a total remaining commitment of $80.5 million as of June 30, 2025.

Fracturing Services Contract. During the six months ended June 30, 2025, the Company entered into a fracturing services contract with a term through March 31, 2026. As of June 30, 2025, the minimum commitment remaining under this contract was $36.8 million. As of the filing of this report, if the Company terminated the contract, it would be subject to liquidated damages of up to $33.3 million; however, the Company expects to meet its obligation under this contract.

Contingencies

The Company is subject to litigation and claims arising in the ordinary course of business. The Company accrues for such items when a liability is both probable and the amount can be reasonably estimated. As of the filing of this report, in the opinion of management, the anticipated results of any pending litigation and claims are not expected to have a material effect on the results of operations, the financial position, or the cash flows of the Company.

Note 7 - Derivative Financial Instruments

Summary of Oil, Gas, and NGL Derivative Contracts in Place

The Company regularly enters into commodity derivative contracts to mitigate a portion of its exposure to oil, gas, and NGL price volatility and location differentials, and the associated effect on cash flows. All commodity derivative contracts that the Company enters into are for other-than-trading purposes. The Company’s commodity derivative contracts consist of price swap and collar arrangements for oil and gas production, and price swap arrangements for NGL production. In a typical commodity swap agreement, if the agreed upon published third-party index price (“index price”) is lower than the swap price, the Company receives the difference between the index price and the agreed upon swap price. If the index price is higher than the swap price, the Company pays the difference. For collar arrangements, the Company receives the difference between an agreed upon index price and the floor price if the index price is below the floor price. The Company pays the difference between the agreed upon ceiling price and the index price if the index price is above the ceiling price. No amounts are paid or received if the index price is between the floor and ceiling prices.

The Company has entered into fixed price oil and gas basis swaps in order to mitigate exposure to adverse pricing differentials between certain industry benchmark prices and the actual physical pricing points where the Company’s production is sold. As of June 30, 2025, the Company had basis swap contracts with fixed price differentials between:

•NYMEX WTI and Argus WTI Midland (“WTI Midland”) for a portion of its Midland Basin oil production with sales contracts that settle at WTI Midland prices;

•NYMEX WTI and Argus WTI Houston Magellan East Houston Terminal (“WTI Houston MEH”) for a portion of its South Texas oil production with sales contracts that settle at WTI Houston MEH prices; and

•NYMEX Henry Hub (“HH”) and Inside FERC (“IF”) Waha hub in West Texas (“Waha”) for a portion of its Midland Basin gas production with sales contracts that settle at IF Waha prices.

The Company has also entered into oil swap contracts to fix the differential in pricing between the NYMEX calendar month average and the physical crude oil delivery month (“Roll Differential”) in which the Company pays the periodic variable Roll Differential and receives a weighted-average fixed price differential. The weighted-average fixed price differential represents the amount of net addition (reduction) to delivery month prices for the notional volumes covered by the swap contracts.

As of June 30, 2025, the Company had commodity derivative contracts with terms through the third quarter of 2027 as summarized in the table below:


	Contract Period
		Third Quarter 2025		Fourth Quarter 2025		2026		2027
Oil Derivatives (volumes in MBbl and prices in $ per Bbl):
Swaps
NYMEX WTI Volumes		2,668		1,500		3,718		—
Weighted-Average Contract Price		$	71.07	$	69.02	$	62.81	$	—


Collars
NYMEX WTI Volumes		2,247		2,648		4,569		—
Weighted-Average Floor Price		$	61.24	$	60.13	$	56.32	$	—
Weighted-Average Ceiling Price		$	72.92	$	69.53	$	64.86	$	—
Basis Swaps
WTI Midland-NYMEX WTI Volumes		1,104		1,178		4,045		—
Weighted-Average Contract Price		$	1.18	$	1.18	$	0.99	$	—


WTI Houston MEH-NYMEX WTI Volumes		544		526		1,546		—
Weighted-Average Contract Price		$	1.86	$	1.86	$	2.02	$	—
Roll Differential Swaps
NYMEX WTI Volumes		2,421		2,420		1,329		—
Weighted-Average Contract Price		$	0.44	$	0.44	$	0.35	$	—

Gas Derivatives (volumes in BBtu and prices in $ per MMBtu):
Swaps
NYMEX HH Volumes		10,257		8,015		26,627		7,888
Weighted-Average Contract Price		$	4.17	$	4.37	$	3.89	$	4.34
Inside FERC Houston Ship Channel Volumes		—		—		957		—
Weighted-Average Contract Price		$	—	$	—	$	4.07	$	—
IF Waha Volumes		1,150		1,134		5,593		4,094
Weighted-Average Contract Price		$	1.67	$	2.02	$	2.80	$	3.63


Collars
NYMEX HH Volumes		7,497		7,982		22,598		896
Weighted-Average Floor Price		$	3.24	$	3.25	$	3.49	$	4.00
Weighted-Average Ceiling Price		$	4.12	$	5.31	$	5.14	$	5.60









Basis Swaps




IF Waha-NYMEX HH Volumes		5,117		5,046		574		1,008
Weighted-Average Contract Price		$	(0.72)	$	(0.66)	$	(1.75)	$	(0.70)



NGL Derivatives (volumes in MBbl and prices in $ per Bbl):
Swaps






OPIS Ethane Mont Belvieu Non-TET Volumes		—		123		674		—
Weighted-Average Contract Price		$	—	$	13.07	$	12.04	$	—

Commodity Derivative Contracts Entered Into Subsequent to June 30, 2025

Subsequent to June 30, 2025, and through July 23, 2025, the Company entered into the following commodity derivative contracts:


	Contract Period
	Third Quarter 2025		Fourth Quarter 2025		2026		2027
Oil Derivatives (volumes in MBbl and prices in $ per Bbl):
Swaps
NYMEX WTI Volumes	—		488		448		—
Weighted-Average Contract Price	$	—	$	64.50	$	63.00	$	—

















Gas Derivatives (volumes in BBtu and prices in $ per MMBtu):
Swaps
NYMEX HH Volumes	—		—		1,835		—
Weighted-Average Contract Price	$	—	$	—	$	4.52	$	—


IF Waha Volumes	—		—		4,427		—
Weighted-Average Contract Price	$	—	$	—	$	1.76	$	—

Derivative Assets and Liabilities Fair Value

The Company’s commodity derivatives are measured at fair value and are included in the accompanying balance sheets as derivative assets and liabilities, with the exception of derivative instruments that meet the “normal purchase normal sale” exclusion. The Company does not designate its commodity derivative contracts as hedging instruments. The fair value of commodity derivative contracts at June 30, 2025, and December 31, 2024, was a net asset of $51.9 million and $38.3 million, respectively.

The following table details the fair value of commodity derivative contracts recorded in the accompanying balance sheets:


	As of June 30, 2025		As of December 31, 2024

	(in thousands)
Derivative assets:
Current assets	$	78,504	$	48,522
Noncurrent assets	4,871		3,973
Total derivative assets	$	83,375	$	52,495
Derivative liabilities:
Current liabilities	$	19,003	$	7,058
Noncurrent liabilities	12,480		7,142
Total derivative liabilities	$	31,483	$	14,200

Offsetting of Derivative Assets and Liabilities

As of June 30, 2025, and December 31, 2024, all derivative instruments held by the Company were subject to master netting arrangements with various financial institutions. In general, the terms of the Company’s agreements provide for offsetting of amounts payable or receivable between it and the counterparty, at the election of both parties, for transactions that settle on the same date and in the same currency. The Company’s 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. The Company’s accounting policy is to not offset these positions in its accompanying balance sheets.

The following table provides a reconciliation between the gross assets and liabilities reflected on the accompanying balance sheets and the potential effects of master netting arrangements on the fair value of the Company’s commodity derivative contracts:


	Derivative Assets as of				Derivative Liabilities as of
	June 30, 2025		December 31, 2024		June 30, 2025		December 31, 2024

	(in thousands)
Gross amounts presented in the accompanying balance sheets	$	83,375	$	52,495	$	(31,483)	$	(14,200)
Amounts not offset in the accompanying balance sheets	(31,197)		(12,995)		31,197		12,995
Net amounts	$	52,178	$	39,500	$	(286)	$	(1,205)

The following table summarizes the commodity components of the net derivative settlement gain, and the net derivative (gain) loss line items presented within the accompanying unaudited condensed consolidated statements of cash flows (“accompanying statements of cash flows”) and the accompanying statements of operations, respectively:


	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2025		2024		2025		2024

	(in thousands)
Net derivative settlement (gain) loss:
Oil contracts	$	(21,120)	$	1,161	$	(24,003)	$	(1,364)
Gas contracts	(18,608)		(17,684)		(25,803)		(29,904)
NGL contracts	(17)		—		2,310		1,471
Total net derivative settlement gain	$	(39,745)	$	(16,523)	$	(47,496)	$	(29,797)

Net derivative (gain) loss:
Oil contracts	$	(55,033)	$	(1,271)	$	(52,160)	$	35,828
Gas contracts	(21,714)		(11,505)		(9,640)		(26,333)
NGL contracts	(1,561)		658		708		6,532
Total net derivative (gain) loss	$	(78,308)	$	(12,118)	$	(61,092)	$	16,027

Credit Related Contingent Features

As of June 30, 2025, all of the Company’s derivative counterparties were members of the Company’s Credit Agreement lender group. The Company does not enter into derivative contracts with counterparties that are not part of the lender group. Under the Credit Agreement, the Company is required to provide mortgage liens on assets having a value equal to at least 85 percent of the total PV-9, as defined in the Credit Agreement, of the Company’s proved oil and gas properties evaluated in the most recent reserve report. Collateral securing indebtedness under the Credit Agreement also secures the Company’s derivative agreement obligations.

Note 8 - Fair Value Measurements

The Company follows fair value measurement accounting guidance for all assets and liabilities measured at fair value. This guidance defines fair value as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Market or observable inputs are the preferred sources of values, followed by assumptions based on hypothetical transactions in the absence of market inputs. The fair value hierarchy for grouping these assets and liabilities is based on the significance level of the following inputs:

•Level 1 – quoted prices in active markets for identical assets or liabilities

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

•Level 3 – significant inputs to the valuation model are unobservable

The following table is a listing of the Company’s assets and liabilities that are measured at fair value on a recurring basis in the accompanying balance sheets and where they are classified within the fair value hierarchy:


	As of June 30, 2025						As of December 31, 2024
	Level 1		Level 2		Level 3		Level 1		Level 2		Level 3

	(in thousands)
Assets:
Derivatives	$	—	$	83,375	$	—	$	—	$	52,495	$	—

Liabilities:
Derivatives	$	—	$	31,483	$	—	$	—	$	14,200	$	—

Both financial and non-financial assets and liabilities are categorized within the above fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. The following is a description of the valuation methodologies used by the Company as well as the general classification of such instruments pursuant to the above fair value hierarchy.

Derivatives

The Company uses Level 2 inputs to measure the fair value of oil, gas, and NGL commodity derivative instruments. Fair values are based upon interpolated data. The Company derives internal valuation estimates taking into consideration forward commodity price curves, counterparties’ credit ratings, the Company’s credit rating, and the time value of money. These valuations are then compared to the respective counterparties’ mark-to-market statements. The considered factors result in an estimated exit price that management believes provides a reasonable and consistent methodology for valuing derivative instruments. The commodity derivative instruments utilized by the Company are not considered by management to be complex, structured, or illiquid. The oil, gas, and NGL commodity derivative markets are highly active. Refer to Note 7 - Derivative Financial Instruments for more information regarding the Company’s derivative instruments.

Long-Term Debt

The following table reflects the fair value of the Company’s Senior Notes obligations measured using Level 1 inputs based on quoted secondary market trading prices. These notes were not presented at fair value on the accompanying balance sheets as of June 30, 2025, or December 31, 2024, as they were recorded at carrying value, net of any unamortized deferred financing costs. Refer to Note 5 - Long-Term Debt for additional information.


	As of June 30, 2025				As of December 31, 2024
	Principal Amount		Fair Value		Principal Amount		Fair Value

	(in thousands)
6.75% Senior Notes due 2026	$	419,235	$	419,990	$	419,235	$	419,654
6.625% Senior Notes due 2027	$	416,791	$	416,753	$	416,791	$	416,149
6.5% Senior Notes due 2028	$	400,000	$	403,624	$	400,000	$	398,676
6.75% Senior Notes due 2029	$	750,000	$	747,128	$	750,000	$	742,275
7.0% Senior Notes due 2032	$	750,000	$	740,588	$	750,000	$	741,053

As of December 31, 2024, the carrying value of the Company’s revolving credit facility approximated its fair value, as the applicable interest rates are floating, based on prevailing market rates.

Note 9 - Earnings Per Share

Basic net income or loss per common share is calculated by dividing net income or loss available to common stockholders by the basic weighted-average number of common shares outstanding for the respective period. Diluted net income or loss per common share is calculated by dividing net income or loss available to common stockholders by the diluted weighted-average number of common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities for this calculation consist primarily of non-vested restricted stock units (“RSU” or “RSUs”) and contingent performance share units (“PSU” or “PSUs”), which were measured using the treasury stock method. Refer to Note 9 - Earnings Per Share and Note 10 - Compensation Plans in the 2024 Form 10-K for additional detail on these potentially dilutive securities.

The following table sets forth the calculations of basic and diluted net income per common share:


	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2025		2024		2025		2024

	(in thousands, except per share data)
Net income	$	201,665	$	210,293	$	383,934	$	341,492

Basic weighted-average common shares outstanding	114,520		114,634		114,518		115,138
Dilutive effect of non-vested RSUs, contingent PSUs, and other	268		1,081		362		954
Diluted weighted-average common shares outstanding	114,788		115,715		114,880		116,092

Basic net income per common share	$	1.76	$	1.83	$	3.35	$	2.97
Diluted net income per common share	$	1.76	$	1.82	$	3.34	$	2.94

Note 10 - Segment Reporting

The Company has one reportable segment: the oil, gas, and NGL exploration and production segment (“E&P Segment”), which operates exclusively in the United States. The E&P Segment constitutes all of the consolidated entity and the accompanying condensed consolidated financial statements and the notes to the accompanying condensed consolidated financial statements are representative of such amounts for the E&P Segment. The Company’s Chief Operating Decision Maker (“CODM”) is the President and Chief Executive Officer. The CODM uses net income as presented on the accompanying statements of operations to measure E&P Segment profit or loss, and to evaluate income generated from E&P Segment assets in deciding whether to reinvest profits into operational activities or to use profits for other purposes, such as debt reduction, acquisitions, or the Company’s Stock Repurchase Program. Additionally, net income is used in assessing budget versus actual results and in benchmarking to the Company’s competitors.

The following table summarizes the results of the Company’s segment revenue, significant expenses, and net income during the periods presented:


	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2025		2024		2025		2024

	(in thousands)
Total operating revenues and other income	$	792,943	$	634,555	$	1,637,487	$	1,194,425
Less:
Lease operating expense	105,001		69,538		213,864		142,643
Transportation costs	78,542		28,035		148,097		55,352
Production taxes	30,240		27,209		67,082		52,354
Ad valorem tax expense	10,225		11,840		20,038		23,648
Depletion, depreciation, and amortization	292,990		179,651		562,890		345,839
Exploration	15,355		17,094		27,118		35,675

General and administrative	42,097		31,112		81,436		61,290
Net derivative (gain) loss	(78,308)		(12,118)		(61,092)		16,027
Other operating expense, net	1,893		2,814		6,858		3,822
Interest expense	42,561		21,807		86,934		43,680
Interest income	(182)		(6,333)		(295)		(13,103)

Other non-operating expense	27		23		54		47
Income tax expense	50,837		53,590		100,569		85,659
E&P Segment net income	$	201,665	$	210,293	$	383,934	$	341,492

___________________________________________

Note: There are no reconciling items between net income presented on the accompanying statements of operations and E&P Segment net income.

Note 11 - Acquisitions

During the first quarter of 2025, the Company finalized post-closing adjustments related to the Uinta Basin Acquisition. The final adjusted purchase price was $2.1 billion. In accordance with GAAP, this transaction was considered to be an asset acquisition.

Note 12 - Compensation Plans

On May 22, 2025, the Company’s stockholders approved the 2025 Equity Incentive Compensation Plan (“2025 Equity Plan”), which succeeded the SM Energy Company Equity Incentive Compensation Plan, as amended and restated effective as of May 22, 2018 (“Predecessor Equity Plan” and together with the 2025 Equity Plan, the “Equity Plans”). The Company ceased granting awards under the Predecessor Equity Plan following the approval of the 2025 Equity Plan, however, existing awards remain outstanding under the Predecessor Equity Plan. Among other items, the 2025 Equity Plan authorized an increase in the total number of shares of the Company’s common stock available for grant of approximately 2.0 million shares. As of June 30, 2025, approximately 3.7 million shares of common stock were available for grant under the 2025 Equity Plan.

The Company may grant various types of both short-term and long-term incentive-based awards such as time-based cash awards, performance-based cash awards, and equity awards to eligible employees. Additionally, the Company grants stock-based compensation to its Board of Directors and provides an employee stock purchase plan and a 401(k) plan to eligible employees.

Performance Share Units

The Company has granted PSUs to eligible employees pursuant to its Equity Plans. The number of shares of the Company’s common stock issued to settle PSUs ranges from zero to two times the number of PSUs awarded and is determined based on certain criteria over a three-year performance period. PSUs generally vest on the third anniversary of the grant date or upon other triggering events as set forth in the applicable Equity Plan.

For PSUs granted in 2024 and 2023, which the Company determined to be equity awards, settlement will be determined based on a combination of the following criteria measured over the three-year performance period: the Company’s Total Shareholder Return (“TSR”) relative to the TSR of certain peer companies, the Company’s absolute TSR, free cash flow (“FCF”) generation, and the achievement of certain sustainability targets, in each case as defined by the award agreement. The Company initially records compensation expense associated with the issuance of PSUs based on the fair value of the awards as of the grant date. Because a portion of these awards depends on performance-based settlement criteria, compensation expense may be adjusted in future periods as the expected number of shares of the Company’s common stock issued to settle the units increases or decreases based on the Company’s expected FCF generation and achievement of certain sustainability targets.

Compensation expense for PSUs is recognized within general and administrative expense and exploration expense over the vesting periods of the respective awards. Total compensation expense recorded for PSUs was $0.6 million and $1.4 million for the three months ended June 30, 2025, and 2024, respectively, and $2.8 million and $2.4 million for the six months ended June 30, 2025, and 2024, respectively. As of June 30, 2025, there was $7.9 million of total unrecognized compensation expense related to non-vested PSUs, which is being amortized through mid-2027. There were no material changes to the outstanding and non-vested PSUs during the six months ended June 30, 2025.

Subsequent to June 30, 2025, the Company settled PSUs that were granted in 2022, which earned a 0.28 times multiplier based on the same performance criteria described above. The Company and all eligible recipients mutually agreed to net share settle a portion of the awards to cover income and payroll tax withholdings, as provided for in the Predecessor Equity Plan and applicable award agreements. After withholding 26,397 shares to satisfy income and payroll tax withholding obligations, the Company issued 39,475 shares of common stock in accordance with the terms of the applicable award agreement. Additionally, the Company granted a total of 374,692 PSUs with a grant date fair value of $10.3 million pursuant to the 2025 Equity Plan.

Employee Restricted Stock Units

The Company has granted RSUs to eligible employees pursuant to its Equity Plans. Each RSU represents a right to receive one share of the Company’s common stock upon settlement of the award at the end of the specified vesting period. RSUs generally vest in one-third increments on each anniversary of the applicable grant date over the applicable vesting period or upon other triggering events as set forth in the applicable Equity Plan.

The Company records compensation expense associated with the issuance of RSUs based on the fair value of the awards as of the grant date. The fair value of an RSU is equal to the closing price of the Company’s common stock on the grant date. Compensation expense for RSUs is recognized within general and administrative expense and exploration expense over the vesting periods of the respective awards. Total compensation expense recorded for RSUs was $4.5 million and $3.8 million for the three months ended June 30, 2025, and 2024, respectively, and $9.1 million and $7.5 million for the six months ended June 30, 2025, and 2024, respectively. As of June 30, 2025, there was $20.8 million of total unrecognized compensation expense related to non-vested

RSUs, which is being amortized through mid-2027. There were no material changes to the outstanding and non-vested RSUs during the six months ended June 30, 2025.

Subsequent to June 30, 2025, the Company settled RSUs upon the vesting of awards granted in previous years. The Company and the majority of eligible recipients mutually agreed to net share settle a portion of the awards to cover income and payroll tax withholdings, as provided for in the Predecessor Equity Plan and applicable award agreements. After withholding 157,426 shares to satisfy income and payroll tax withholding obligations, the Company issued 319,247 shares of common stock in accordance with the terms of the applicable award agreements. Additionally, the Company granted to employees a total of 958,194 RSUs with a grant date fair value of $25.0 million pursuant to the 2025 Equity Plan.

Director Shares

During the six months ended June 30, 2025, and 2024, the Company issued a total of 82,193 and 37,530 shares, respectively, of its common stock to its non-employee directors under the Equity Plans. All shares issued to non-employee directors fully vest during the year in which they are granted.

Employee Stock Purchase Plan

Under the Company’s Employee Stock Purchase Plan (“ESPP”), eligible employees may purchase shares of the Company’s common stock through payroll deductions of up to 15 percent of their eligible compensation, subject to a maximum of 2,500 shares per offering period and a maximum of $25,000 in value related to purchases for each calendar year. The purchase price of the common stock is 85 percent of the lower of the trading price of the common stock on either the first or last day of the six-month offering period. The ESPP is intended to qualify as an “employee stock purchase plan” under Section 423 of the Internal Revenue Code. There were a total of 90,314 and 56,006 shares issued under the ESPP during the second quarters of June 30, 2025, and 2024, respectively. Total proceeds to the Company for the issuance of these shares was $1.9 million and $1.8 million during the six months ended June 30, 2025, and 2024, respectively. The fair value of ESPP grants is measured at the date of grant using the Black-Scholes option-pricing model.

The 2025 Equity Plan is included as Exhibit 10.1 to this report. Refer to Note 10 - Compensation Plans in the 2024 Form 10-K for additional detail on the Company’s compensation plans.

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion includes forward-looking statements. Refer to the Cautionary Information about Forward-Looking Statements section of this report for important information about these types of statements. Additionally, the following discussion includes sequential quarterly comparison to the financial information presented in our Quarterly Report on the Form 10-Q for the quarter ended March 31, 2025, filed with the SEC on May 2, 2025. Throughout the following discussion, we explain changes between the three months ended June 30, 2025, and the three months ended March 31, 2025 (“sequential quarterly” or “sequentially”), and the year-to-date (“YTD”) change between the six months ended June 30, 2025, and the six months ended June 30, 2024 (“YTD 2025-over-YTD 2024”).

Overview of the Company

General Overview

Our purpose is to make people’s lives better by responsibly producing energy supplies, contributing to domestic energy security and prosperity, and having a positive impact in the communities where we live and work. Our long-term vision and strategy is to sustainably grow value for all of our stakeholders as a premier operator of top-tier assets by maintaining and optimizing our high-quality asset portfolio, generating cash flows, and maintaining a strong balance sheet. Our team executes this strategy by prioritizing safety, technological innovation, and stewardship of natural resources, all of which are integral to our corporate culture. During the first half of 2025, we focused on the successful integration of our Uinta Basin assets. We have shifted our focus for the second half of 2025 to optimizing operations to deliver sustained value from this core asset. Our near-term goals include focusing on operational execution; generating cash flows that enable us to continue returning value to stockholders through fixed dividend payments, debt repayments, and our Stock Repurchase Program; and expanding our portfolio of top-tier economic drilling inventory through acquisition and exploration.

Our asset portfolio is comprised of high-quality assets in the Midland Basin of West Texas, the Maverick Basin of South Texas, and the Uinta Basin of Northeast Utah, which we believe are capable of generating strong returns in the current macroeconomic environment and provide resilience to commodity price risk and volatility. We seek to maximize returns and increase the value of our top-tier assets through disciplined capital spending, strategic acquisitions, and continued development and optimization. We believe that our high-quality assets facilitate a sustainable approach to prioritizing operational execution, maintaining a strong balance sheet, generating cash flows, returning capital to stockholders, and maintaining financial flexibility.

We are committed to exceptional safety, health, and environmental stewardship; supporting the professional development of a diverse and thriving team of employees; building and maintaining partnerships with our stakeholders by investing in and connecting with the communities where we live and work; and transparency in reporting on our progress in these areas. The Governance and Sustainability Committee of our Board of Directors oversees, among other things, the effectiveness of our sustainability policies, programs and initiatives, monitors and responds to emerging trends, issues, and associated risks, and, together with management, reports to our Board of Directors regarding such matters. Further demonstrating our commitment to sustainable operations and environmental stewardship, compensation for our executives and employees under certain aspects of our compensation plans is calculated based on Company-wide performance metrics that include key financial, operational, environmental, health, and safety measures.

Market Trends and Uncertainties

Global commodity and financial markets, which remain subject to heightened levels of uncertainty and volatility, affect our financial performance. Key factors contributing to market fluctuations include tariffs and trade restrictions; production output from the Organization of the Petroleum Exporting Countries (“OPEC”) plus other non-OPEC oil producing countries (collectively referred to as “OPEC+”); fluctuations in oil and gas demand from China and other markets; War and Geopolitical Instability; United States Federal Reserve monetary policy; global shipping channel constraints and disruptions; the potential for economic recession in the U.S.; and changes in global oil inventory in storage. These factors have driven commodity price volatility, contributed to instances of supply chain disruptions, inflation, and fluctuations in interest rates, and could have further industry-specific impacts that may require us to adjust our business plan. Future impacts of these and other events on commodity and financial markets are inherently unpredictable.

Historically, tariffs have led to increased costs for products exchanged in international trade, and have heightened global political tensions. Recent U.S. government policies, including new and higher tariffs on imported goods, have increased economic uncertainty. These tariffs, along with retaliatory tariffs from other countries, could lead to reduced trade resulting from increased costs for imported goods and decreased demand for U.S. exports, as well as reduced investment and technological exchange between major economies. These outcomes could negatively impact global economic conditions, financial market stability, and commodity prices. Volatility in political, trade, regulatory, and economic conditions could have a material adverse effect on our financial condition or results of operations. We are unable to reasonably estimate the period of time that these market conditions will exist or the extent to which they will impact our business, results of operations, and financial condition.

Continuing volatility in political, trade, regulatory and economic conditions could impact supply and demand fundamentals, and any related declines in oil, gas, and NGL prices could lead to proved and unproved property impairments in the future. Future impairments of proved and unproved properties are difficult to predict, especially in a volatile price environment.

Areas of Operations

Our Midland Basin assets are comprised of approximately 108,000 net acres located in the Permian Basin in West Texas (“Midland Basin”). Our Midland Basin position provides future development opportunities within multiple oil-rich intervals, including the Spraberry, Wolfcamp, and Woodford Barnett formations.

Our South Texas assets are comprised of approximately 155,000 net acres located in Dimmit and Webb counties, Texas (“South Texas”). Our overlapping acreage position in South Texas covers a significant portion of the western Eagle Ford shale and Austin Chalk formations, and includes acreage across the oil, gas-condensate, and dry gas windows with gas composition amenable to processing for NGL extraction.

Our Uinta Basin assets are comprised of approximately 64,000 net acres located in Duchesne and Uintah counties, Utah (“Uinta Basin”). Our Uinta Basin position provides future development and exploration opportunities within multiple oil-rich intervals in the Lower Green River and Wasatch formations, and includes acreage with waxy crude and gas composition amenable to processing for NGL extraction.

Second Quarter 2025 Overview and Outlook for the Remainder of 2025

During the second quarter of 2025, we completed the integration of the Uinta Basin assets into our portfolio. We also reduced our total outstanding debt by paying off the balance on our revolving credit facility and ending the quarter with a cash and cash equivalents balance of $101.9 million as of June 30, 2025. Additionally, we continued to execute on our goal of sustainably returning capital to our stockholders by paying a quarterly net cash dividend of $0.20 per share, totaling $22.9 million.

Financial and Operational Results. Average net daily equivalent production for the three months ended June 30, 2025, increased six percent sequentially to 209.1 MBOE. The overall increase consisted of increases of 25 percent and three percent from our Uinta Basin and Midland Basin assets, respectively. Average net daily equivalent production from our South Texas assets remained flat sequentially.

Oil, gas, and NGL realized prices per BOE, before the effect of net derivative settlements (“realized price” or “realized prices”), decreased sequentially by 12 percent, 35 percent, and 15 percent, respectively, as a result of decreases in oil, gas and NGL benchmark prices during the second quarter of 2025. The decrease in our realized gas price was also a result of weaker Waha pricing during the second quarter of 2025. Total realized price per BOE decreased 13 percent sequentially, resulting in a six percent decrease in oil, gas, and NGL production revenue, which was $785.1 million for the three months ended June 30, 2025, compared with $839.6 million for the three months ended March 31, 2025. Oil, gas, and NGL production expense remained flat sequentially at $224.0 million for the three months ended June 30, 2025, compared with $225.1 million for the three months ended March 31, 2025, as the increase in transportation expense was offset by decreases in production tax expense and lease operating expense (“LOE”).

We recorded a net derivative gain of $78.3 million and a net derivative loss of $17.2 million for the three months ended June 30, 2025, and March 31, 2025, respectively. Included within these amounts are net derivative settlement gains of $39.7 million and $7.8 million for the three months ended June 30, 2025, and March 31, 2025, respectively.

Operational and financial activities during the three months ended June 30, 2025, resulted in the following:

•Net income of $201.7 million, or $1.76 per diluted share, compared with net income of $182.3 million, or $1.59 per diluted share, for the three months ended March 31, 2025.

•Net cash provided by operating activities of $571.1 million, compared with $483.0 million for the three months ended March 31, 2025. The increase in net cash provided by operating activities was primarily a result of timing of interest payments on our Senior Notes.

•Adjusted EBITDAX, a non-GAAP financial measure, of $569.6 million, compared with $588.9 million for the three months ended March 31, 2025. The decrease in adjusted EBITDAX was primarily a result of decreased realized prices. Refer to the caption Non-GAAP Financial Measures below for additional discussion and our definition of adjusted EBITDAX and reconciliations to net income and net cash provided by operating activities.

Refer to Overview of Selected Production and Financial Information, Including Trends and Comparison of Financial Results and Trends Between the Three Months Ended June 30, 2025, and March 31, 2025, and Between the Six Months Ended June 30, 2025, and 2024 below for additional discussion.

Operational Activities. Our capital program for 2025, excluding acquisitions, is expected to be approximately $1.375 billion which is an increase from our original expectation of approximately $1.3 billion. This increase is primarily to accommodate certain previously excluded non-operated capital projects. Our capital program remains focused on applying our strength in geosciences and development optimization to highly economic oil development projects in our areas of operations that support our priority of strategic inventory replacement and growth. Refer to Overview of Liquidity and Capital Resources below for discussion of how we expect to fund the remainder of our 2025 capital program.

During the three and six months ended June 30, 2025, costs incurred in oil and gas property acquisition, exploration, and development activities, whether capitalized or expensed, totaled $392.7 million and $842.4 million, respectively. Total costs incurred also includes corporate charges incurred in exploration activities and costs related to exploration efforts outside of our core areas of operation.

In our Midland Basin program, we averaged two drilling rigs and one completion crew during the second quarter of 2025, and our operations focused on development optimization of our RockStar assets, and delineation and development of our Sweetie Peck and Klondike assets. Average net daily equivalent production volumes increased sequentially by three percent to 83.6 MBOE. Costs incurred during the three months ended June 30, 2025, totaled $148.1 million, or 38 percent of our total costs incurred for the period. We anticipate operating an average of two drilling rigs and a spot completion crew for the majority of the remainder of 2025, focused on developing formations within our RockStar and Sweetie Peck assets.

In our South Texas program, we averaged one drilling rig and one completion crew during the second quarter of 2025, and our operations focused primarily on the development and further delineation of the Austin Chalk formation. Average net daily equivalent production volumes remained flat sequentially at 77.4 MBOE. Costs incurred during the three months ended June 30, 2025, totaled $112.4 million, or 29 percent of our total costs incurred for the period. We anticipate operating between one and two drilling rigs and a spot completion crew for a majority of the remainder of 2025, focused primarily on developing the Austin Chalk formation.

In our Uinta Basin program, we operated three drilling rigs and one completion crew during the second quarter of 2025, and our operations focused on delineation and development. Average net daily equivalent production volumes increased sequentially by 25 percent to 48.0 MBOE. Costs incurred during the three months ended June 30, 2025, totaled $120.2 million, or 31 percent of our total costs incurred for the period. We anticipate operating three drilling rigs and one completion crew during the remainder of 2025, focused primarily on delineating and developing the Lower Green River and Wasatch formations.

The table below provides a quarterly summary of changes in our drilled but not completed well count and current year drilling and completion activity in our operated programs for the three and six months ended June 30, 2025:


	Midland Basin		South Texas (1)		Uinta Basin		Total
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Wells drilled but not completed at December 31, 2024	40	29	35	35	48	38	123	102
Wells drilled	24	21	10	10	14	10	48	41
Wells completed	(15)	(10)	(5)	(5)	(30)	(24)	(50)	(39)

Wells drilled but not completed at March 31, 2025	49	40	40	40	32	24	121	104
Wells drilled	12	9	7	6	12	9	31	24
Wells completed	(27)	(23)	(16)	(16)	(21)	(17)	(64)	(56)

Wells drilled but not completed at June 30, 2025	34	26	31	30	23	16	88	72

____________________________________________

(1) As of December 31, 2024, the drilled but not completed well count included nine gross (nine net) wells that were not included in our five-year development plan as of December 31, 2024, eight of which were in the Eagle Ford shale.

Production Results. The table below presents the disaggregation of our net production volumes by product type for each of our assets for the periods presented:


	For the Three Months Ended				For the Six Months Ended
	June 30, 2025		March 31, 2025		June 30, 2025		June 30, 2024

Midland Basin Net Production:
Oil (MMBbl)	4.9		4.7		9.6		9.0
Gas (Bcf)	16.2		16.0		32.2		29.9
NGLs (MMBbl)	—		—		—		—
Equivalent (MMBOE)	7.6		7.3		14.9		14.0
Average net daily equivalent (MBOE per day)	83.6		81.5		82.6		77.1
Relative percentage	40	%	41	%	41	%	51	%

South Texas Net Production:
Oil (MMBbl)	1.8		1.7		3.5		3.4
Gas (Bcf)	16.7		17.6		34.3		33.4
NGLs (MMBbl)	2.4		2.4		4.8		4.6
Equivalent (MMBOE)	7.0		7.0		14.0		13.6
Average net daily equivalent (MBOE per day)	77.4		77.4		77.4		74.7
Relative percentage	37	%	39	%	38	%	49	%

Uinta Basin Net Production: (1)
Oil (MMBbl)	3.8		3.0		6.8		—
Gas (Bcf)	3.4		2.8		6.1		—
NGLs (MMBbl)	—		—		—		—
Equivalent (MMBOE)	4.4		3.5		7.8		—
Average net daily equivalent (MBOE per day)	48.0		38.4		43.3		—
Relative percentage	23	%	20	%	21	%	—	%

Total Net Production:
Oil (MMBbl)	10.5		9.3		19.9		12.4
Gas (Bcf)	36.2		36.4		72.6		63.4
NGLs (MMBbl)	2.5		2.4		4.8		4.7
Equivalent (MMBOE)	19.0		17.8		36.8		27.6
Average net daily equivalent (MBOE per day)	209.1		197.3		203.2		151.8

____________________________________________

Note: Amounts may not calculate due to rounding.

(1) The Uinta Basin assets were acquired on October 1, 2024.

Oil, Gas, and NGL Prices

Our financial condition and the results of our operations are significantly affected by the prices we receive for our oil, gas, and NGL production, which can fluctuate dramatically. When we refer to realized oil, gas, and NGL prices below, the disclosed price represents the average price for the respective period, before the effect of net derivative settlements. While quoted NYMEX oil and gas and OPIS NGL prices are generally used as a basis for comparison within our industry, the prices we receive are affected by quality, energy content, location and transportation differentials, and contracted pricing benchmarks for these products.

The following table summarizes commodity price data, as well as the effect of net derivative settlements, for the periods presented:


	For the Three Months Ended
	June 30, 2025		March 31, 2025		June 30, 2024
Oil (per Bbl):
Average NYMEX contract monthly price	$	63.74	$	71.42	$	80.57
Realized price	$	62.04	$	70.56	$	80.48
Effect of oil net derivative settlements	$	2.01	$	0.31	$	(0.18)
Gas:
Average NYMEX monthly settle price (per MMBtu)	$	3.44	$	3.65	$	1.89
Realized price (per Mcf)	$	2.15	$	3.30	$	1.40
Effect of gas net derivative settlements (per Mcf)	$	0.51	$	0.20	$	0.55
NGLs (per Bbl):
Average OPIS price (1)	$	26.99	$	31.29	$	27.96
Realized price	$	21.91	$	25.86	$	22.86
Effect of NGL net derivative settlements	$	0.01	$	(0.99)	$	—

____________________________________________

(1) Average OPIS price per barrel of NGL, historical or strip, assumes a composite barrel product mix of 42% ethane, 28% propane, 6% isobutane, 11% normal butane, and 13% natural gasoline. This product mix represents the industry standard composite barrel and does not necessarily represent our product mix for NGL production. Realized prices reflect our actual product mix.

Given the uncertainty surrounding global financial markets, we expect benchmark prices for oil, gas, and NGLs to remain volatile for the foreseeable future. In addition to supply and demand fundamentals, as global commodities, the prices for oil, gas, and NGLs are affected by real or perceived geopolitical risks in various regions of the world, as well as the relative strength of the United States dollar compared to other currencies. Additionally, our realized prices at local sales points have been and may continue to be affected by infrastructure capacity or outages in the areas of our operations and beyond. We cannot reasonably predict the timing or likelihood of any future volatility or the related impacts. Refer to Market Trends and Uncertainties above for additional discussion of factors impacting pricing.

The following table summarizes 12-month strip prices for NYMEX WTI oil, NYMEX Henry Hub gas, and OPIS NGLs as of July 23, 2025, and June 30, 2025:


	As of July 23, 2025		As of June 30, 2025
NYMEX WTI oil (per Bbl)	$	63.66	$	62.35
NYMEX Henry Hub gas (per MMBtu)	$	3.75	$	3.95
OPIS NGLs (per Bbl)	$	25.84	$	26.20

We use financial derivative instruments as part of our financial risk management program. We have a financial risk management policy governing our use of derivatives, and decisions regarding entering into commodity derivative contracts are overseen by a financial risk management committee consisting of certain senior executive officers and finance personnel. We make decisions about the amount of our expected production that we cover by derivatives based on the amount of debt on our balance sheet, the level of capital commitments and long-term obligations we have in place, and the terms and futures prices that are made available by our approved counterparties. With our current commodity derivative contracts, we believe we have partially reduced our exposure to volatility in commodity prices and basis differentials in the near term. Our use of costless collars for a portion of our derivatives allows us to participate in some of the upward movements in oil and gas prices while also setting a price floor below which we are insulated from further price decreases. Refer to Note 7 - Derivative Financial Instruments in Part I, Item 1 of this report and to Commodity Price Risk in Overview of Liquidity and Capital Resources below for additional information regarding our oil, gas, and NGL derivatives.

Financial Results of Operations and Additional Comparative Data

The tables below provide information regarding selected production and financial information for the three months ended June 30, 2025, and the preceding three quarters:


	For the Three Months Ended
	June 30,		March 31,		December 31,		September 30,
	2025		2025		2024		2024

	(in millions)
Net production (MMBOE)	19.0		17.8		19.1		15.6
Oil, gas, and NGL production revenue	$	785.1	$	839.6	$	835.9	$	642.4
Oil, gas, and NGL production expense	$	224.0	$	225.1	$	214.6	$	148.4
Depletion, depreciation, and amortization	$	293.0	$	269.9	$	260.5	$	202.9
Exploration	$	15.4	$	11.8	$	16.3	$	12.1
General and administrative	$	42.1	$	39.3	$	41.9	$	35.1
Net income	$	201.7	$	182.3	$	188.3	$	240.5

Selected Performance Metrics


	For the Three Months Ended
	June 30,			March 31,			December 31,			September 30,
	2025			2025			2024			2024
Average net daily equivalent production (MBOE per day)	209.1			197.3			208.0			170.0
Lease operating expense (per BOE)	$	5.52		$	6.13		$	5.35		$	4.73
Transportation costs (per BOE)	$	4.13		$	3.92		$	4.10		$	2.13
Production taxes as a percent of oil, gas, and NGL production revenue	3.9		%	4.4		%	4.1		%	4.6		%
Ad valorem tax expense (per BOE)	$	0.54		$	0.55		$	(0.03)		$	0.76
Depletion, depreciation, and amortization (per BOE)	$	15.40		$	15.20		$	13.61		$	12.98
General and administrative (per BOE)	$	2.21		$	2.22		$	2.19		$	2.25

____________________________________________

Note: Amounts may not calculate due to rounding.

Overview of Selected Production and Financial Information, Including Trends


	For the Three Months Ended				Amount Change Between Periods		Percent Change Between Periods		For the Six Months Ended				Amount Change Between Periods			Percent Change Between Periods
	June 30,		March 31,						June 30,		June 30,
	2025		2025						2025		2024
Net production volumes: (1)
Oil (MMBbl)	10.5		9.3		1.2		13	%	19.9		12.4			7.5			60	%
Gas (Bcf)	36.2		36.4		(0.1)		—	%	72.6		63.4			9.3			15	%
NGLs (MMBbl)	2.5		2.4		0.1		4	%	4.8		4.7			0.2			3	%
Equivalent (MMBOE)	19.0		17.8		1.3		7	%	36.8		27.6			9.2			33	%
Average net daily production: (1)
Oil (MBbl per day)	115.7		103.7		12.0		12	%	109.7		68.2			41.5			61	%
Gas (MMcf per day)	398.3		404.2		(5.9)		(1)	%	401.2		348.1			53.1			15	%
NGLs (MBbl per day)	26.9		26.2		0.7		3	%	26.6		25.6			1.0			4	%
Equivalent (MBOE per day)	209.1		197.3		11.8		6	%	203.2		151.8			51.4			34	%
Oil, gas, and NGL production revenue (in millions): (1)
Oil production revenue	$	653.4	$	658.5	$	(5.1)	(1)	%	$	1,311.8	$	973.4		$	338.4		35	%
Gas production revenue	78.0		120.1		(42.1)		(35)	%	198.1		113.0			85.1			75	%
NGL production revenue	53.7		61.1		(7.4)		(12)	%	114.8		106.6			8.2			8	%
Total oil, gas, and NGL production revenue	$	785.1	$	839.6	$	(54.5)	(6)	%	$	1,624.7	$	1,193.0		$	431.6		36	%
Oil, gas, and NGL production expense (in millions): (1)
Lease operating expense	$	105.0	$	108.9	$	(3.9)	(4)	%	$	213.9	$	142.6		$	71.2		50	%
Transportation costs	78.5		69.6		9.0		13	%	148.1		55.4			92.7			168	%
Production taxes	30.2		36.8		(6.6)		(18)	%	67.1		52.4			14.7			28	%
Ad valorem tax expense	10.2		9.8		0.4		4	%	20.0		23.6			(3.6)			(15)	%
Total oil, gas, and NGL production expense	$	224.0	$	225.1	$	(1.1)	—	%	$	449.1	$	274.0		$	175.1		64	%
Realized price:
Oil (per Bbl)	$	62.04	$	70.56	$	(8.52)	(12)	%	$	66.04	$	78.43		$	(12.39)		(16)	%
Gas (per Mcf)	$	2.15	$	3.30	$	(1.15)	(35)	%	$	2.73	$	1.78		$	0.95		53	%
NGLs (per Bbl)	$	21.91	$	25.86	$	(3.95)	(15)	%	$	23.85	$	22.90		$	0.95		4	%
Per BOE	$	41.27	$	47.29	$	(6.02)	(13)	%	$	44.17	$	43.19		$	0.98		2	%
Per BOE data: (1)
Oil, gas, and NGL production expense:
Lease operating expense	$	5.52	$	6.13	$	(0.61)	(10)	%	$	5.81	$	5.16		$	0.65		13	%
Transportation costs	4.13		3.92		0.21		5	%	4.03		2.00			2.03			102	%
Production taxes	1.59		2.07		(0.48)		(23)	%	1.82		1.90			(0.08)			(4)	%
Ad valorem tax expense	0.54		0.55		(0.01)		(2)	%	0.54		0.86			(0.32)			(37)	%
Total oil, gas, and NGL production expense (1)	$	11.78	$	12.68	$	(0.90)	(7)	%	$	12.21	$	9.92		$	2.29		23	%
Depletion, depreciation, and amortization	$	15.40	$	15.20	$	0.20	1	%	$	15.30	$	12.52		$	2.78		22	%
General and administrative	$	2.21	$	2.22	$	(0.01)	—	%	$	2.21	$	2.22		$	(0.01)		—	%
Net derivative settlement gain (2)	$	2.09	$	0.44	$	1.65	375	%	$	1.29	$	1.08		$	0.21		19	%
Earnings per share information (in thousands, except per share data): (3)
Basic weighted-average common shares outstanding	114,520		114,515		5		—	%	114,518		115,138			(620)			(1)	%
Diluted weighted-average common shares outstanding	114,788		114,948		(160)		—	%	114,880		116,092			(1,212)			(1)	%
Basic net income per common share	$	1.76	$	1.59	$	0.17	11	%	$	3.35	$	2.97		$	0.38		13	%
Diluted net income per common share	$	1.76	$	1.59	$	0.17	11	%	$	3.34	$	2.94		$	0.40		14	%

______________________________________

(1) Amounts and percentage changes may not calculate due to rounding.

(2) Net derivative settlements for the three months ended June 30, 2025, and for the six months ended June 30, 2025, and 2024, are included within the net derivative (gain) loss line item in the accompanying statements of operations.

(3) Refer to Note 9 - Earnings Per Share in Part I, Item 1 of this report for additional discussion.

Average net daily equivalent production for the three months ended June 30, 2025, increased six percent sequentially. The overall increase consisted of increases of 25 percent and three percent from our Uinta Basin and Midland Basin assets, respectively. Average net daily equivalent production increased 34 percent YTD 2025-over-YTD 2024 primarily driven by the addition of 43.3 MBOE per day of production from our Uinta Basin assets, and as a result of strong well performance and the timing of well completions; average net daily equivalent production from our Midland Basin and South Texas assets increased seven percent and four percent respectively.

We present certain information on a per BOE basis in order to evaluate our performance relative to our peers and to identify and measure trends we believe may require additional analysis and discussion.

Our total realized price per BOE decreased $6.02 sequentially as a result of decreases in oil, gas and NGL benchmark prices. The decrease in our realized gas price was also a result of weaker Waha pricing during the second quarter of 2025. We expect lower Waha pricing to continue to impact our realized prices for gas into 2026, when additional pipeline capacity is expected to be placed into service. Our total realized price per BOE increased $0.98 YTD 2025-over-YTD 2024 as a result of a shift in our production mix towards more oil production, and an increase in gas benchmark prices, partially offset by decreases in oil and NGL benchmark prices. We recognized net gains on the settlement of our commodity derivative contracts of $2.09 per BOE and $0.44 per BOE, during the three months ended June 30, 2025, and March 31, 2025, respectively, and $1.29 per BOE and $1.08 per BOE, during the six months ended June 30, 2025, and 2024, respectively.

LOE per BOE decreased 10 percent sequentially as a result of decreases in certain operating costs including workover expense, and increased average net daily equivalent production. LOE per BOE increased 13 percent YTD 2025-over-YTD 2024 as a result of a shift in our production mix towards more oil production and increases in certain operating costs. For the full-year 2025, we expect LOE per BOE to increase, compared with 2024, due to higher oil production and expected increases in certain operating costs associated with our Midland Basin assets. We anticipate volatility in LOE per BOE as a result of changes in total production, timing of workover projects, changes in service provider costs, and industry activity, all of which affect total LOE.

Transportation costs per BOE increased five percent sequentially, primarily due to a shift in production mix, with a higher contribution from our Uinta Basin assets, which have higher transportation costs per BOE. Transportation costs per BOE increased 102 percent YTD 2025-over-YTD 2024 primarily as a result of the addition of oil production from our Uinta Basin assets and increased production from our South Texas assets. In general, we expect total transportation costs to fluctuate relative to changes in gas and NGL production from our South Texas assets and oil production from our Uinta Basin assets, where we incur a majority of our transportation costs. For the full-year 2025, we expect transportation costs per BOE to increase compared with 2024, as a result of the addition of our Uinta Basin assets.

Production tax expense per BOE decreased 23 percent sequentially primarily as a result of a decrease in total realized price per BOE. Production tax expense per BOE decreased four percent YTD 2025-over-YTD 2024, primarily as a result of a decrease in oil realized price per BOE. Our overall production tax rate was 3.9 percent and 4.4 percent for the three months ended June 30, 2025, and March 31, 2025, respectively, and was 4.1 percent and 4.4 percent for the six months ended June 30, 2025, and 2024, respectively. We expect that our Uinta Basin assets will incur a lower production tax rate compared with our Midland Basin and South Texas assets. We generally expect production tax expense to correlate with oil, gas, and NGL production revenue on a per BOE and absolute basis. Product mix, the location of production, and incentives to encourage oil and gas development can also impact the amount of production tax expense that we recognize.

Ad valorem tax expense per BOE decreased two percent sequentially and 37 percent YTD 2025-over-YTD 2024, as a result of fluctuations in commodity prices which impact the expected valuation of our producing properties. We anticipate volatility in ad valorem tax expense on a per BOE and absolute basis as the valuation of our producing properties changes, which is generally driven by fluctuations in commodity prices, and as a result of varying tax policies across the different counties in which we operate.

Depletion, depreciation, and amortization (“DD&A”) expense per BOE remained relatively flat sequentially and increased 22 percent YTD 2025-over-YTD 2024. The YTD 2025-over-YTD 2024 increase was a result of the addition of our Uinta Basin assets, and a shift in our production mix. Our Midland Basin and Uinta Basin assets have higher DD&A rates than our South Texas assets. Our DD&A rate fluctuates as a result of changes in our production mix, changes in our total estimated net proved reserve volumes, changes in capital allocation, impairments, acquisition and divestiture activity, and carrying cost funding and sharing arrangements with third parties. For the full-year 2025, we expect DD&A expense per BOE and on an absolute basis to increase, compared with 2024, primarily as a result of expected increased production resulting from the addition of our Uinta Basin assets and a shift in our production mix.

General and administrative (“G&A”) expense on a per BOE basis remained flat sequentially and YTD 2025-over-YTD 2024. For the full-year 2025, we expect G&A expense on an absolute basis to increase compared with 2024, primarily as a result of an

increase in employee headcount attributable to the Uinta Basin Acquisition. We expect G&A expense per BOE to remain relatively flat for the full-year 2025 compared with 2024, as expected increases in G&A expense on an absolute basis are expected to be mostly offset by increases in production.

Refer to Comparison of Financial Results and Trends Between the Three Months Ended June 30, 2025, and March 31, 2025, and Between the Six Months Ended June 30, 2025, and 2024 below for additional discussion of operating expenses.

Comparison of Financial Results and Trends Between the Three Months Ended June 30, 2025, and March 31, 2025, and Between the Six Months Ended June 30, 2025, and 2024

Refer to Overview of Selected Production and Financial Information, Including Trends above for additional discussion, including discussion of trends on a per BOE basis.

Average net daily equivalent production, production revenue, and production expense

Sequential Quarterly Changes. The following table presents changes in our average net daily equivalent production; oil, gas, and NGL production revenue; and oil, gas, and NGL production expense, by area, between the three months ended June 30, 2025, and March 31, 2025:


	Average Net Equivalent Production Increase	Oil, Gas, and NGL Production Revenue Increase (Decrease)	Oil, Gas, and NGL Production Expense Increase (Decrease)
	(MBOE per day)	(in millions)	(in millions)
Midland Basin	2.1		$	(50.9)	$	(4.0)
South Texas	—		(21.3)		(0.9)
Uinta Basin	9.6		17.6		3.8
Total	11.8		$	(54.5)	$	(1.1)

__________________________________________

Note: Amounts may not calculate due to rounding.

Average net daily equivalent production volumes increased six percent, consisting of increases of 25 percent and three percent from our Uinta Basin and Midland Basin assets, respectively. As a result of decreases in benchmark commodity prices, total realized price per BOE decreased 13 percent. The decrease in total realized price per BOE was partially offset by the increase in average net daily equivalent production volumes resulting in a six percent decrease in oil, gas, and NGL production revenue. Oil, gas, and NGL production expense remained flat, as a result of an increase in transportation expense which was offset by decreases in production tax expense and LOE.

YTD 2025-over-YTD 2024 Changes. The following table presents changes in our average net daily equivalent production; oil, gas, and NGL production revenue; and oil, gas, and NGL production expense, by area, between the six months ended June 30, 2025, and 2024:


	Average Net Equivalent Production Increase	Oil, Gas, and NGL Production Revenue Increase (Decrease)	Oil, Gas, and NGL Production Expense Increase
	(MBOE per day)	(in millions)	(in millions)
Midland Basin	5.5		$	(40.0)	$	9.0
South Texas	2.7		25.8		16.9
Uinta Basin (1)	43.3		445.8		149.1
Total	51.4		$	431.6	$	175.1

__________________________________________

Note: Amounts may not calculate due to rounding.

(1) Amounts reflect Uinta Basin activity for the six months ended June 30, 2025. There was no comparable activity for the six months ended June 30, 2024, as the Uinta Basin assets were acquired on October 1, 2024.

Average net daily equivalent production volumes increased 34 percent, primarily driven by the addition of 43.3 MBOE per day of production from our Uinta Basin assets. Average net daily equivalent production from our Midland Basin and South Texas assets increased seven percent and four percent, respectively. Oil, gas, and NGL production revenue increased 36 percent, primarily driven by the addition of our Uinta Basin assets, and oil, gas, and NGL production expense increased 64 percent, driven by increases in transportation expense, LOE, and production tax expense.

Depletion, depreciation, and amortization


	For the Three Months Ended				For the Six Months Ended
	June 30, 2025		March 31, 2025		June 30, 2025		June 30, 2024

	(in millions)
Depletion, depreciation, and amortization	$	293.0	$	269.9	$	562.9	$	345.8

DD&A expense increased nine percent sequentially, primarily driven by an increase in average net daily equivalent production. DD&A expense increased 63 percent YTD 2025-over-YTD 2024 as a result of increased average net daily equivalent production, including the addition of production from our Uinta Basin assets, and increases in our DD&A rates. Our Midland Basin and Uinta Basin assets have higher DD&A rates than our South Texas assets.

Exploration


	For the Three Months Ended				For the Six Months Ended
	June 30, 2025		March 31, 2025		June 30, 2025		June 30, 2024

	(in millions)
Geological, geophysical, and other expenses	$	5.8	$	1.9	$	7.7	$	19.7
Overhead	9.6		9.9		19.4		16.0
Total exploration	$	15.4	$	11.8	$	27.1	$	35.7

Exploration expense increased 31 percent sequentially, primarily due to an increase in geological, geophysical, and other expenses. Exploration expense decreased 24 percent YTD 2025-over-YTD 2024 primarily as a result of a decrease in geological, geophysical, and other expenses, partially offset by an increase in exploration overhead expense. Exploration expense fluctuates based on actual geological and geophysical studies we perform within an exploratory area, exploratory dry hole expense incurred, and changes in the amount of allocated overhead.

General and administrative


	For the Three Months Ended				For the Six Months Ended
	June 30, 2025		March 31, 2025		June 30, 2025		June 30, 2024

	(in millions)
General and administrative	$	42.1	$	39.3	$	81.4	$	61.3

G&A expense increased seven percent sequentially, primarily due to increased compensation expense. G&A expense increased 33 percent YTD 2025-over-YTD 2024 primarily due to increased headcount and one-time G&A expenses, both of which related to the Uinta Basin Acquisition.

Net derivative (gain) loss


	For the Three Months Ended				For the Six Months Ended
	June 30, 2025		March 31, 2025		June 30, 2025		June 30, 2024

	(in millions)
Net derivative (gain) loss	$	(78.3)	$	17.2	$	(61.1)	$	16.0

Net derivative (gain) loss is a result of changes in fair values associated with fluctuations in the forward price curves for the commodities underlying our outstanding derivative contracts and the monthly cash settlements of our derivative positions during the period. We expect increases in benchmark commodity prices to result in net derivative losses and decreases in benchmark commodity prices to result in net derivative gains, as measured against our derivative contract prices. Refer to Note 7 - Derivative Financial Instruments in Part I, Item 1 of this report for additional discussion.

Interest expense


	For the Three Months Ended				For the Six Months Ended
	June 30, 2025		March 31, 2025		June 30, 2025		June 30, 2024

	(in millions)
Interest expense	$	(42.6)	$	(44.4)	$	(86.9)	$	(43.7)

Interest expense decreased four percent sequentially due to a decrease in our daily weighted-average revolving credit facility balance. Interest expense increased 99 percent YTD 2025-over-YTD 2024 primarily as a result of the issuance of our 6.75% Senior Notes due 2029 (“2029 Senior Notes”) and our 7.0% Senior Notes due 2032 (“2032 Senior Notes”) during the third quarter of 2024, and an increase in interest expense associated with borrowings under our revolving credit facility. Total interest expense can vary based on the amount of our outstanding fixed-rate debt securities, fluctuations in the amount of capitalized interest as a result of the timing of the development of our wells in progress, and the timing and amount of borrowings under our revolving credit facility.

Income tax expense


	For the Three Months Ended						For the Six Months Ended
	June 30, 2025			March 31, 2025			June 30, 2025			June 30, 2024

	(in millions, except tax rate)
Income tax expense	$	(50.8)		$	(49.7)		$	(100.6)		$	(85.7)
Effective tax rate	20.1		%	21.4		%	20.8		%	20.1		%

Our effective tax rate is impacted by proportional effects of forecast net income on estimated permanent items between periods and estimated state revenue changes affecting the apportionment of taxable income to states with higher statutory tax rates. Our effective tax rate benefited both sequentially and YTD 2025-over-YTD 2024 from enacted statutory changes related to Texas research and development (“R&D”) credits during the second quarter of 2025, and we expect to continue to benefit from these changes in future periods.

On July 4, 2025, the OBBBA was enacted into law and includes, among other things, tax reform provisions that amend, eliminate, and extend tax rules under the Inflation Reduction Act and Tax Cuts and Jobs Act. We are currently evaluating the potential impacts of the OBBBA on our financial statements, tax position, liquidity, and financial condition. While this evaluation is ongoing, we expect to benefit from certain provisions including: the reinstatement of 100 percent bonus depreciation on tangible assets; the immediate expensing of qualified R&D expenditures and the expensing of unamortized, previously capitalized, qualified R&D expenditures; and a less restrictive limitation on the business interest expense deduction. Additionally, the OBBBA allows for the deduction of intangible drilling costs from adjusted financial statement income (“AFSI”) when determining whether a company is subject to and liable for the Corporate Alternative Minimum Tax (“CAMT”). As a result, we do not expect to become subject to or liable for the CAMT for the foreseeable future, notwithstanding other factors that may impact our AFSI.

The effects of changes in tax laws are recognized in the period of enactment, therefore, we expect to record the impacts of the OBBBA on full-year income tax expense during the third quarter of 2025.

Refer to Note 4 - Income Taxes in Part I, Item 1 of this report, and to the Risk Factors section in Part 1, Item 1A of our 2024 Form 10-K for additional discussion.

Overview of Liquidity and Capital Resources

Based on the current commodity price environment, we believe we have sufficient liquidity and capital resources to execute our business plan while continuing to meet our current financial obligations. We continue to manage the duration and level of our drilling and completion service commitments in order to maintain flexibility with regard to our activity level and capital expenditures.

Sources of Cash

During the six months ended June 30, 2025, we funded our capital expenditures and return of capital program with cash flows from operating activities and cash on hand. For the remainder of 2025, we expect to fund our capital expenditures and return of capital program with cash flows from operations, with any remaining cash needs being funded by borrowings under our revolving credit facility. Although we expect cash flows from these sources to be sufficient for the remainder of 2025, we may also elect to raise funds through new debt or equity offerings or from other sources of financing. If we raise additional funds through the issuance of equity or convertible debt securities, the percentage ownership of our current stockholders could be diluted, and these newly issued securities may have rights, preferences, or privileges senior to those of certain existing stockholders and bondholders. Additionally, we may enter into carrying cost and sharing arrangements with third parties for certain exploration or development programs.

Our credit ratings affect the availability of, and cost for us to borrow, additional funds. Any future downgrades in our credit ratings could make it more difficult or expensive for us to borrow additional funds. All of our sources of liquidity can be affected by the general conditions of the broader economy, force majeure events, fluctuations in commodity prices, operating costs, interest rate changes, tax law changes, and volumes produced, all of which affect us and our industry.

We have no control over the market prices for oil, gas, or NGLs, although we may be able to influence the amount of our realized revenues from our oil, gas, and NGL sales through the use of commodity derivative contracts as part of our financial risk management program. Commodity derivative contracts may limit the prices we receive for our oil, gas, and NGL sales if oil, gas, or NGL prices rise over the price established by the commodity derivative contract. Refer to Note 7 - Derivative Financial Instruments in Part I, Item 1 of this report for additional information about our commodity derivative contracts currently in place.

Credit Agreement

Our Credit Agreement provides for a senior secured revolving credit facility with a maximum loan amount of $3.0 billion. As of June 30, 2025, the borrowing base and aggregate revolving lender commitments under our Credit Agreement were $3.0 billion and $2.0 billion, respectively. The borrowing base is subject to regular, semi-annual redetermination, and considers the value of both our proved oil and gas properties reflected in our most recent reserve report and commodity derivative contracts, each as determined by our lender group. The next borrowing base redetermination is scheduled to occur on October 1, 2025. No individual bank participating in our Credit Agreement represents more than 10 percent of the lender commitments under the Credit Agreement. We must comply with certain financial and non-financial covenants under the terms of the Credit Agreement. We were in compliance with all financial and non-financial covenants under the Credit Agreement as of June 30, 2025, and through the filing of this report.

The following table summarizes our daily weighted-average revolving credit facility balance during the periods presented:


	For the Three Months Ended				For the Six Months Ended
	June 30, 2025		March 31, 2025		June 30, 2025		June 30, 2024
Daily weighted-average revolving credit facility balance	$	66.3	$	120.5	$	93.2	$	—

The amount we borrow under our revolving credit facility is impacted by cash flows provided by our operating activities, proceeds received from divestitures of properties, capital markets activities including open market debt repurchases, debt redemptions, repayment of scheduled debt maturities, other financing activities, and our capital expenditures, including acquisitions.

Refer to Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional discussion, as well as the presentation of the outstanding balance, total amount of letters of credit, and available borrowing capacity under the Credit Agreement as of July 23, 2025, June 30, 2025, and December 31, 2024.

Weighted-Average Interest and Weighted-Average Borrowing Rates

Our weighted-average interest rate includes paid and accrued interest, fees on the unused portion of the aggregate revolving lender commitment amount under the Credit Agreement, letter of credit fees, and the non-cash amortization of deferred financing costs. Our weighted-average borrowing rate includes paid and accrued interest only.

The following table presents our weighted-average interest rates and our weighted-average borrowing rates for the periods presented:


	For the Three Months Ended				For the Six Months Ended
	June 30, 2025		March 31, 2025		June 30, 2025		June 30, 2024
Weighted-average interest rate	7.4	%	7.5	%	7.5	%	7.1	%
Weighted-average borrowing rate	6.8	%	6.9	%	6.9	%	6.4	%

Our weighted-average interest and weighted-average borrowing rate each remained relatively flat sequentially, and each increased YTD 2025-over-YTD 2024 as a result of the issuance of our 2029 Senior Notes and 2032 Senior Notes, which have greater outstanding aggregate principal balances and higher interest rates than our other outstanding Senior Notes, and as a result of borrowings under our revolving credit facility. We expect our weighted-average interest rate and weighted-average borrowing rate to remain relatively flat for the full-year 2025 compared with 2024.

Our weighted-average interest rate and weighted-average borrowing rate are affected by the occurrence and timing of long-term debt issuances and redemptions and the average outstanding balance under our revolving credit facility. Additionally, our weighted-average interest rate is affected by the fees paid on the unused portion of our aggregate revolving lender commitments.

Uses of Cash

We use cash for the development, exploration, and acquisition of oil and gas properties; for the payment of operating and general and administrative costs, income taxes, debt obligations, including interest and early repayments or redemptions, and dividends; and for repurchases of shares of our outstanding common stock under the Stock Repurchase Program. Expenditures for the development, exploration, and acquisition of oil and gas properties are the primary use of our capital resources. During the six months ended June 30, 2025, we spent $824.0 million on capital expenditures. This amount differs from the costs incurred amount of $842.4 million for the six months ended June 30, 2025, as costs incurred is an accrual-based amount that also includes asset retirement obligations, geological and geophysical expenses, acquisitions of oil and gas properties, and exploration overhead amounts.

The amount and allocation of our future capital expenditures will depend upon a number of factors, including our cash flows from operating, investing, and financing activities, our ability to execute our development program, inflation, and the number and size of acquisitions that we complete. In addition, the impact of oil, gas, and NGL prices on investment opportunities, the availability of capital, tax law and other regulatory changes, and the timing and results of our exploration and development activities may lead to changes in funding requirements for future development. We periodically review our capital expenditure budget and guidance to assess if changes are necessary based on current and projected cash flows, acquisition and divestiture activities, debt requirements, and other factors. Our capital program for 2025, excluding acquisitions, is expected to be $1.375 billion which is an increase from our original expectation of approximately $1.3 billion. This increase is primarily to accommodate certain previously excluded non-operated capital projects.

We may from time to time repurchase shares of our common stock, or repurchase or redeem all or portions of our outstanding debt securities, for cash, through exchanges for other securities, or a combination of both. Such repurchases or redemptions may be made in open market transactions, privately negotiated transactions, tender offers, pursuant to contractual provisions, or otherwise. Any such repurchases or redemptions will depend on our business strategy, prevailing market conditions, our liquidity requirements, contractual restrictions or covenants, compliance with securities laws, and other factors. The amounts involved in any such transaction may be material.

During the six months ended June 30, 2025, we did not repurchase any shares of our common stock under the Stock Repurchase Program. During the six months ended June 30, 2024, we repurchased and subsequently retired 1.8 million shares of our common stock at a cost of $84.0 million, excluding excise taxes, commissions, and fees. As of June 30, 2025, $500.0 million was available under the Stock Repurchase Program for repurchases of our common stock through December 31, 2027.

During the six months ended June 30, 2025, and 2024, we paid $45.8 million and $41.5 million, respectively, in dividends to our stockholders. We currently intend to continue paying dividends to our stockholders for the foreseeable future, subject to our future earnings, our financial condition, covenants under our Credit Agreement and indentures governing each series of our outstanding Senior Notes, and other factors that could arise. The payment and amount of future dividends remain at the discretion of our Board of Directors.

On July 4, 2025, the OBBBA was enacted into law. While our evaluation of the potential impacts of the OBBBA on our financial statements, tax position, liquidity, and financial condition is ongoing, we currently expect a reduction in the amount of cash we would have been required to pay for federal income taxes during 2025. Additional changes in federal and state income tax laws and other possible future legislation, including changes in the corporate tax rate, could have a material effect on our net cash provided by operating activities, income tax expense, tax receivable, and deferred tax liabilities. Refer to Comparison of Financial Results and Trends Between the Three Months Ended June 30, 2025, and March 31, 2025, and Between the Six Months Ended June 30, 2025, and 2024 for discussion of the OBBBA.

Analysis of Cash Flow Changes Between the Six Months Ended June 30, 2025, and 2024

The following tables present changes in cash flows between the six months ended June 30, 2025, and 2024, for our operating, investing, and financing activities. The analysis following each table should be read in conjunction with our accompanying statements of cash flows in Part I, Item 1 of this report.

Operating activities


	For the Six Months Ended June 30,				Amount Change Between Periods
	2025		2024

	(in millions)
Net cash provided by operating activities	$	1,054.1	$	752.4	$	301.7

Net cash provided by operating activities increased for the six months ended June 30, 2025, compared with the same period in 2024, primarily as a result of an increase of $386.4 million in cash received from oil, gas, and NGL production revenue net of transportation costs and production taxes and an increase of $14.4 million in cash received on settled derivative trades, partially offset by an increase of $100.0 million in cash paid for LOE, ad valorem taxes, and G&A expense, and an increase of $43.3 million in cash paid for interest. These changes are largely a result of the Uinta Basin Acquisition and related financing, which resulted in the increase

in cash paid for interest. Net cash provided by operating activities is also affected by working capital changes and the timing of cash receipts and disbursements, including the timing of our Senior Notes interest payments which are currently concentrated in the first and third quarters.

Investing activities


	For the Six Months Ended June 30,				Amount Change Between Periods
	2025		2024

	(in millions)
Net cash used in investing activities	$	(839.0)	$	(655.0)	$	(184.0)

Net cash used in investing activities increased for the six months ended June 30, 2025, compared with the same period in 2024, as a result of a $169.0 million increase in capital expenditures and $14.9 million of post-closing adjustments related to final settlement of the Uinta Basin Acquisition during the first quarter of 2025.

Financing activities


	For the Six Months Ended June 30,				Amount Change Between Periods
	2025		2024

	(in millions)
Net cash used in financing activities	$	(113.3)	$	(123.7)	$	10.4

Net cash used in financing activities for the six months ended June 30, 2025, primarily related to net repayments of $68.5 million under our revolving credit facility and $45.8 million of dividends paid to our stockholders.

Net cash used in financing activities for the six months ended June 30, 2024, primarily related to $84.0 million of cash paid, including commissions and fees, to repurchase and subsequently retire 1.8 million shares of our common stock under the Stock Repurchase Program and $41.5 million of dividends paid to our stockholders.

Interest Rate Risk

We are exposed to market and credit risk due to the floating interest rate associated with any outstanding balance under our revolving credit facility. Our Credit Agreement allows us to fix the interest rate for all or a portion of the principal balance of our revolving credit facility for a period of up to six months. To the extent that the interest rate is fixed, interest rate changes will affect the revolving credit facility’s fair value but will not affect results of operations or cash flows. Conversely, for the portion of the revolving credit facility that has a floating interest rate, interest rate changes will not affect the fair value but will affect future results of operations and cash flows. Changes in interest rates do not affect the amount of interest we pay on our fixed-rate Senior Notes, but can affect their fair values. As of June 30, 2025, our outstanding principal amount of fixed-rate debt totaled $2.7 billion, and we had no floating-rate debt outstanding. Refer to Note 8 - Fair Value Measurements in Part I, Item 1 of this report for additional discussion on the fair values of our Senior Notes.

Commodity Price Risk

The prices we receive for our oil, gas, and NGL production directly affect our revenue, profitability, access to capital, ability to return capital to our stockholders, and future rate of growth. Oil, gas, and NGL prices are subject to unpredictable fluctuations resulting from a variety of factors that are typically beyond our control, including changes in supply and demand associated with the broader macroeconomic environment, constraints on gathering systems, processing facilities, pipelines, rail systems, and other transportation systems, and weather-related events. The markets for oil, gas, and NGLs have been volatile, especially over the last decade, and remain subject to high levels of uncertainty and volatility. The realized prices we receive at local sales points for our production have been and may continue to be affected by infrastructure capacity or outages in the areas of our operations and beyond, and also depend on numerous factors that are typically beyond our control. Based on our production for the six months ended June 30, 2025, a 10 percent decrease in our average realized oil, gas, and NGL prices would have reduced our oil, gas, and NGL production revenue by approximately $131.2 million, $19.8 million, and $11.5 million, respectively. If commodity prices had been 10 percent lower, our net derivative settlements for the six months ended June 30, 2025, would have offset the declines in oil, gas, and NGL production revenue by approximately $48.8 million.

We enter into commodity derivative contracts in order to reduce the risk of fluctuations in commodity prices. The fair value of our commodity derivative contracts is largely determined by estimates of the forward curves of the relevant price indices. As of June 30, 2025, a 10 percent increase or decrease in the forward curves associated with our oil, gas, and NGL commodity derivative instruments would have changed our net derivative positions for these products by approximately $90.9 million, $30.4 million, and $0.9 million, respectively.

Off-Balance Sheet Arrangements

We have not participated in transactions that generate relationships with unconsolidated entities or financial partnerships, such as entities often referred to as structured finance or special purpose entities (“SPE”), which would have been established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes.

We evaluate our transactions to determine if any variable interest entities exist. If we determine that we are the primary beneficiary of a variable interest entity, that entity is consolidated into our consolidated financial statements. We have not been involved in any unconsolidated SPE transactions during the six months ended June 30, 2025, or through the filing of this report.

Critical Accounting Estimates

Refer to the corresponding section in Part II, Item 7 and to Note 1 - Summary of Significant Accounting Policies included in Part II, Item 8 of our 2024 Form 10-K for discussion of our accounting estimates.

Accounting Matters

Refer to Note 1 - Summary of Significant Accounting Policies in Part I, Item 1 of this report for information on new authoritative accounting guidance.

Non-GAAP Financial Measures

Adjusted EBITDAX represents net income (loss) before interest expense, interest income, income taxes, depletion, depreciation, amortization and asset retirement obligation liability accretion expense, exploration expense, property abandonment and impairment expense, non-cash stock-based compensation expense, derivative gains and losses net of settlements, gains and losses on divestitures, gains and losses on extinguishment of debt, and certain other items. Adjusted EBITDAX excludes certain items that we believe affect the comparability of operating results and can exclude items that are generally non-recurring in nature or whose timing and/or amount cannot be reasonably estimated. Adjusted EBITDAX is a non-GAAP measure that we believe provides useful additional information to investors and analysts, as a performance measure, for analysis of our ability to internally generate funds for exploration, development, acquisitions, and to service debt. We are also subject to financial covenants under our Credit Agreement based on adjusted EBITDAX ratios as further described in Note 5 - Long-Term Debt in the 2024 Form 10-K. In addition, adjusted EBITDAX is widely used by professional research analysts and others in the valuation, comparison, and investment recommendations of companies in the oil and gas exploration and production industry, and many investors use the published research of industry research analysts in making investment decisions. Adjusted EBITDAX should not be considered in isolation or as a substitute for net income (loss), income (loss) from operations, net cash provided by operating activities, or other profitability or liquidity measures prepared under GAAP. Because adjusted EBITDAX excludes some, but not all items that affect net income (loss) and may vary among companies, the adjusted EBITDAX amounts presented may not be comparable to similar metrics of other companies. Our revolving credit facility provides a material source of liquidity for us. Under the terms of our Credit Agreement, if we failed to comply with the covenants that establish a maximum permitted ratio of total funded debt, as defined in the Credit Agreement, to adjusted EBITDAX, we would be in default, an event that would prevent us from borrowing under our revolving credit facility and would therefore materially limit a significant source of our liquidity. In addition, if we are in default under our revolving credit facility and are unable to obtain a waiver of that default from our lenders, lenders under that facility and under the indentures governing each series of our outstanding Senior Notes would be entitled to exercise all of their remedies for default.

The following table provides reconciliations of our net income (GAAP) and net cash provided by operating activities (GAAP) to adjusted EBITDAX (non-GAAP) for the periods presented:


	For the Three Months Ended		For the Six Months Ended
	June 30, 2025		June 30, 2024		June 30, 2025		June 30, 2024



	(in thousands)
Net income (GAAP)	$	201,665	$	210,293	$	383,934	$	341,492
Interest expense	42,561		21,807		86,934		43,680
Interest income	(182)		(6,333)		(295)		(13,103)
Income tax expense	50,837		53,590		100,569		85,659
Depletion, depreciation, and amortization	292,990		179,651		562,890		345,839
Exploration (1)	14,107		15,906		24,418		33,362

Stock-based compensation expense	5,751		5,788		12,840		10,806
Net derivative (gain) loss	(78,308)		(12,118)		(61,092)		16,027
Net derivative settlement gain	39,745		16,523		47,496		29,797


Other, net	409		823		800		1,420
Adjusted EBITDAX (non-GAAP)	569,575		485,930		1,158,494		894,979
Interest expense	(42,561)		(21,807)		(86,934)		(43,680)
Interest income	182		6,333		295		13,103
Income tax expense	(50,837)		(53,590)		(100,569)		(85,659)
Exploration (1) (2)	(13,868)		(14,897)		(24,179)		(24,436)
Amortization of deferred financing costs	2,552		1,372		5,102		2,743
Deferred income taxes	43,204		43,516		69,463		70,907
Other, net	(6,369)		(20,690)		(5,245)		(28,102)
Net change in working capital	69,265		50,215		37,701		(47,473)
Net cash provided by operating activities (GAAP)	$	571,143	$	476,382	$	1,054,128	$	752,382

____________________________________________

(1) Stock-based compensation expense is a component of the exploration expense and general and administrative expense line items on the accompanying statements of operations. Therefore, the exploration line items shown in the reconciliation above will vary from the amount shown on the accompanying statements of operations for the component of stock-based compensation expense recorded to exploration expense.

(2) For the three and six months ended June 30, 2024, amounts exclude certain capital expenditures primarily related to one well deemed non-commercial.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The information required by this item is provided under the captions Interest Rate Risk and Commodity Price Risk in Item 2 above, as well as under the section entitled Summary of Oil, Gas, and NGL Derivative Contracts in Place in Note 7 - Derivative Financial Instruments in Part I, Item 1 of this report and is incorporated herein by reference. Also refer to the information under Interest Rate Risk and Commodity Price Risk in Management’s Discussion and Analysis of Financial Condition and Results of Operations in Part II, Item 7 of our 2024 Form 10-K.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

We maintain a system of disclosure controls and procedures that are designed to reasonably ensure that information required to be disclosed in our Securities and Exchange Commission (“SEC”) reports is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms, and to reasonably ensure that such information is accumulated and communicated to our management, including our Chief Executive Officer (Principal Executive Officer) and our Chief Financial Officer (Principal Financial Officer), as appropriate, to allow for timely decisions regarding required disclosure.

Our management, including our Chief Executive Officer and our Chief Financial Officer, does not expect that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act) (“Disclosure Controls”) will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within our Company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. We monitor our Disclosure Controls and make modifications as necessary; our intent in this regard is that the Disclosure Controls will be modified as systems change and conditions warrant.

An evaluation of the effectiveness of the design and operation of our Disclosure Controls was performed as of the end of the period covered by this report. This evaluation was performed under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our Disclosure Controls are effective at a reasonable assurance level.

Changes in Internal Control Over Financial Reporting

There have been no changes during the second quarter of 2025 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

At times, we may be involved in litigation relating to claims arising out of our business and operations in the normal course of business. As of the filing of this report, no legal proceedings are pending against us that we believe individually or collectively are likely to have a materially adverse effect upon our financial condition, results of operations, or cash flows.

ITEM 1A. RISK FACTORS

There have been no material changes to the risk factors as previously disclosed in our 2024 Form 10-K.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

There were no purchases made by us and any affiliated purchaser (as defined in Rule 10b-18(a)(3) under the Exchange Act) during the three months ended June 30, 2025, of shares of our common stock, which is the sole class of equity securities registered by us pursuant to Section 12 of the Exchange Act.

Our Stock Repurchase Program, which authorizes us to repurchase up to $500.0 million in aggregate value of our common stock through December 31, 2027, permits us to repurchase our shares from time to time in open market transactions, through privately negotiated transactions or by other means in accordance with federal securities laws and subject to certain provisions of our Credit Agreement and the indentures governing our Senior Notes. The timing, as well as the number and value of shares repurchased under the Stock Repurchase Program, is determined by certain authorized officers of the Company at their discretion and depends on a variety of factors, including the market price of our common stock, general market and economic conditions and applicable legal requirements. The value of shares authorized for repurchase by our Board of Directors does not require us to repurchase such shares or guarantee that such shares will be repurchased, and the Stock Repurchase Program may be suspended, modified, or discontinued at any time without prior notice. No assurance can be given that any particular number or dollar value of our shares will be repurchased. During the three months ended June 30, 2025, we did not repurchase any shares of our common stock under the Stock Repurchase Program. As of June 30, 2025, $500.0 million remained available under the Stock Repurchase Program for repurchases of our common stock through December 31, 2027.

Our payment of cash dividends to our stockholders and repurchases of our common stock are each subject to certain covenants under the terms of our Credit Agreement and Senior Notes. Based on our current performance, we do not anticipate that any of these covenants will limit our potential repurchases of our common stock or our payment of dividends at our current rate for the foreseeable future if any dividends are declared by our Board of Directors.

ITEM 4. MINE SAFETY DISCLOSURES

The required disclosure under Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K is included in Exhibit 95.1 to this report.

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS

The following exhibits are filed or furnished with, or incorporated by reference into this report:


Exhibit Number			Description
3.1			Restated Certificate of Incorporation of SM Energy Company, as amended through June 1, 2010 (filed as Exhibit 3.1 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, and incorporated herein by reference)
3.2			Certificate of Amendment of Restated Certificate of Incorporation of SM Energy Company, as amended through June 1, 2010, dated May 25, 2023 (filed as Exhibit 3.1 to the registrant’s Current Report on Form 8-K filed on May 30, 2023, and incorporated herein by reference)
3.3			Amended and Restated By-Laws of SM Energy Company, effective as of February 21, 2017 (filed as Exhibit 3.2 to the registrant’s Annual Report on Form 10-K for the year ended December 31, 2016, and incorporated herein by reference)
10.1†			SM Energy Company Equity Incentive Compensation Plan, amended and restated effective as of May 22, 2025 (filed as Annex A in the registrant’s Definitive Proxy Statement on Schedule 14A, filed on April 7, 2025, and incorporated herein by reference)
1 0.2*†			Form of Restricted Stock Unit Award Agreement dated as of July 1, 2025
10.3 *†			Form of Performance Share Unit Award Agreement dated as of July 1, 2025
31.1*			Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes - Oxley Act of 2002
31.2*			Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes - Oxley Act of 2002
32.1**			Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes - Oxley Act of 2002
95.1*			Mine Safety Disclosures
101.INS			Inline XBRL Instance Document - The instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
101.SCH*			Inline XBRL Schema Document
101.CAL*			Inline XBRL Calculation Linkbase Document
101.LAB*			Inline XBRL Label Linkbase Document
101.PRE*			Inline XBRL Presentation Linkbase Document
101.DEF*			Inline XBRL Taxonomy Extension Definition Linkbase Document
104			Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101.INS)

_____________________________________


*			Filed with this report.
**			Furnished with this report.
†			Exhibit constitutes a management contract or compensatory plan or agreement.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


	SM ENERGY COMPANY

August 1, 2025	By:	/s/ HERBERT S. VOGEL
		Herbert S. Vogel
		President and Chief Executive Officer
		(Principal Executive Officer)

August 1, 2025	By:	/s/ A. WADE PURSELL
		A. Wade Pursell
		Executive Vice President and Chief Financial Officer
		(Principal Financial Officer)

August 1, 2025	By:	/s/ ALAN D. BENNETT
		Alan D. Bennett
		Vice President - Controller
		(Principal Accounting Officer)

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Date	Price Target	Rating	Analyst
6/24/2025		Outperform → Underperform	Raymond James
12/5/2024	$51.00 → $53.00	Overweight → Neutral	Analyst
10/15/2024	$64.00 → $60.00	Hold → Buy	TD Cowen
8/21/2024		Hold → Buy	Tudor, Pickering, Holt & Co.
6/25/2024	$51.00	Hold	Truist
6/21/2024	$63.00	Overweight	Stephens
1/31/2024	$50.00	Neutral → Buy	Seaport Research Partners
11/15/2023	$40.00	Equal Weight	Wells Fargo

SEC Form 10-Q filed by SM Energy Company

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