sm-20250930

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 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 October 22, 2025, the registrant had 114,554,192 shares of common stock outstanding.

TABLE OF CONTENTS


Item		Page
	Cautionary Information about Forward-Looking Statements	3

	Part I	5

Item 1.	Financial Statements (unaudited)	5

	Condensed Consolidated Balance Sheets September 30, 2025, and December 31, 2024	5

	Condensed Consolidated Statements of Operations Three and Nine Months Ended September 30, 2025, and 2024	6

	Condensed Consolidated Statements of Comprehensive Income Three and Nine Months Ended September 30, 2025, and 2024	7

	Condensed Consolidated Statements of Stockholders’ Equity Continuous Quarterly Presentation Ended September 30, 2025, and 2024	8

	Condensed Consolidated Statements of Cash Flows Nine Months Ended September 30, 2025, and 2024	10

	Notes to Condensed Consolidated Financial Statements	12

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	26

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	43

Item 4.	Controls and Procedures	43

	Part II	44

Item 1.	Legal Proceedings	44

Item 1A.	Risk Factors	44

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	46

Item 4.	Mine Safety Disclosures	46

Item 5.	Other Information	46

Item 6.	Exhibits	47

	Signatures	48

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;

•risks related to the pending Merger with Civitas, including the risk that we may fail to consummate the Merger on the terms or timing currently contemplated, or at all, and the risk we may fail to realize the expected benefits of the Merger; see Note 13 - Subsequent Event in Part I, Item 1 of this report for discussion and definitions of the Merger and Civitas;

•risks related to the integration of the Merger or business disruptions that could result from the Merger;

•anticipated benefits of the Merger;

•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, the current or any future U.S. federal government shutdown, 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 subsequent to September 30, 2025 (“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)


	September 30, 2025		December 31, 2024
ASSETS
Current assets:
Cash and cash equivalents	$	162,251	$	—
Accounts receivable	367,688		360,976
Derivative assets	68,567		48,522
Prepaid expenses and other	34,452		25,201
Total current assets	632,958		434,699
Property and equipment (successful efforts method):
Proved oil and gas properties	15,653,507		14,301,502
Accumulated depletion, depreciation, and amortization	(8,477,647)		(7,603,195)
Unproved oil and gas properties, net of valuation allowance of $12,334 and $32,680, respectively	592,493		764,924
Wells in progress	424,891		481,893

Other property and equipment, net of accumulated depreciation of $64,658 and $61,737, respectively	71,669		47,585
Total property and equipment, net	8,264,913		7,992,709
Noncurrent assets:

Derivative assets	4,677		3,973
Other noncurrent assets	186,952		145,266
Total noncurrent assets	191,629		149,239
Total assets	$	9,089,500	$	8,576,647
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	674,157	$	760,473
Senior Notes, net	418,593		—
Derivative liabilities	9,888		7,058
Other current liabilities	32,688		22,419
Total current liabilities	1,135,326		789,950
Noncurrent liabilities:
Revolving credit facility	—		68,500
Senior Notes, net	2,294,118		2,708,243


Asset retirement obligations	150,127		145,313

Net deferred tax liabilities	690,446		545,295
Derivative liabilities	4,852		7,142
Other noncurrent liabilities	101,544		74,947
Total noncurrent liabilities	3,241,087		3,549,440

Commitments and contingencies (note 6)

Stockholders’ equity:
Common stock, $0.01 par value - authorized: 200,000,000 shares; issued and outstanding: 114,554,192 and 114,461,934 shares, respectively	1,146		1,145
Additional paid-in capital	1,507,875		1,501,779
Retained earnings	3,205,190		2,735,494
Accumulated other comprehensive loss	(1,124)		(1,161)
Total stockholders’ equity	4,713,087		4,237,257
Total liabilities and stockholders’ equity	$	9,089,500	$	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 September 30,				For the Nine Months Ended September 30,
	2025		2024		2025		2024
Operating revenues and other income:
Oil, gas, and NGL production revenue	$	811,009	$	642,380	$	2,435,705	$	1,835,427

Other operating income	582		1,233		13,373		2,611

Total operating revenues and other income	811,591		643,613		2,449,078		1,838,038
Operating expenses:
Oil, gas, and NGL production expense	229,036		148,380		678,117		422,377
Depletion, depreciation, and amortization	325,372		202,942		888,262		548,781
Exploration	11,532		12,097		38,650		47,772

General and administrative	39,317		35,141		120,753		96,431
Net derivative gain	(45,479)		(86,283)		(106,571)		(70,256)

Other operating expense, net	5,331		384		12,189		4,206
Total operating expenses	565,109		312,661		1,631,400		1,049,311
Income from operations	246,482		330,952		817,678		788,727
Interest expense	(42,937)		(50,682)		(129,871)		(94,362)
Interest income	828		18,017		1,123		31,120

Other non-operating expense, net	(80)		(637)		(134)		(684)
Income before income taxes	204,293		297,650		688,796		724,801
Income tax expense	(49,205)		(57,127)		(149,774)		(142,786)
Net income	$	155,088	$	240,523	$	539,022	$	582,015

Basic weighted-average common shares outstanding	114,826		114,405		114,592		114,870
Diluted weighted-average common shares outstanding	115,226		114,993		114,990		115,701
Basic net income per common share	$	1.35	$	2.10	$	4.70	$	5.07
Diluted net income per common share	$	1.35	$	2.09	$	4.69	$	5.03
Net dividends declared per common share	$	0.20	$	0.20	$	0.60	$	0.56

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 September 30,				For the Nine Months Ended September 30,
	2025		2024		2025		2024
Net income	$	155,088	$	240,523	$	539,022	$	582,015
Other comprehensive income, net of tax:
Pension liability adjustment	11		108		37		123
Total other comprehensive income, net of tax	11		108		37		123
Total comprehensive income	$	155,099	$	240,631	$	539,059	$	582,138

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
Net income	—	—		—		155,088		—		155,088
Other comprehensive income	—	—		—		—		11		11
Net cash dividends declared, $0.20 per share	—	—		—		(23,443)		—		(23,443)

Issuance of common stock upon vesting of RSUs and settlement of PSUs, net of shares used for tax withholdings	364,172	4		(4,660)		—		—		(4,656)
Stock-based compensation expense	—	—		8,124		—		—		8,124
Purchase of shares under Stock Repurchase Program	(444,705)	(4)		(12,131)		—		—		(12,135)

Balances, September 30, 2025	114,554,192	$	1,146	$	1,507,875	$	3,205,190	$	(1,124)	$	4,713,087

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) (Continued)

(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, 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
Net income	—	—		—		240,523		—		240,523
Other comprehensive income	—	—		—		—		108		108
Net cash dividends declared, $0.20 per share	—	—		—		(22,947)		—		(22,947)

Issuance of common stock upon vesting of RSUs, net of shares used for tax withholdings	349,528	3		(6,819)		—		—		(6,816)
Stock-based compensation expense	—	—		6,587		—		—		6,587

Purchase of shares under Stock Repurchase Program	—	—		151		—		—		151
Balances, September 30, 2024	114,418,413	$	1,144	$	1,492,778	$	2,570,108	$	(2,484)	$	4,061,546

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 Nine Months Ended September 30,
	2025		2024
Cash flows from operating activities:
Net income	$	539,022	$	582,015
Adjustments to reconcile net income to net cash provided by operating activities:

Depletion, depreciation, and amortization	888,262		548,781


Stock-based compensation expense	20,964		17,393
Net derivative gain	(106,571)		(70,256)
Net derivative settlement gain	86,363		46,288
Amortization of deferred financing costs	7,654		4,925

Deferred income taxes	145,149		116,522
Other, net	(6,888)		(25,590)
Net change in working capital	(14,867)		(15,433)





Net cash provided by operating activities	1,559,088		1,204,645

Cash flows from investing activities:

Capital expenditures	(1,221,736)		(957,156)
Acquisition of proved and unproved oil and gas properties	(21,504)		(836)
Other, net	(534)		80
Net cash used in investing activities	(1,243,774)		(957,912)

Cash flows from financing activities:
Proceeds from revolving credit facility	1,569,500		—
Repayment of revolving credit facility	(1,638,000)		—

Net proceeds from Senior Notes	—		1,477,032
Cash paid to repurchase Senior Notes	—		(349,118)
Repurchase of common stock	(12,776)		(83,991)
Dividends paid	(68,776)		(62,136)
Net proceeds from sale of common stock	1,927		1,844

Other, net	(4,938)		(9,215)
Net cash provided by (used in) financing activities	(153,063)		974,416

Net change in cash, cash equivalents, and restricted cash	162,251		1,221,149
Cash, cash equivalents, and restricted cash at beginning of period	—		616,164
Cash, cash equivalents, and restricted cash at end of period	$	162,251	$	1,837,313

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)


	For the Nine Months Ended September 30,
	2025		2024
Supplemental schedule of additional cash flow information and non-cash activities:
Operating activities:
Cash paid for interest, net of capitalized interest (1)	$	(164,550)	$	(83,130)
Net cash paid for income taxes	$	(6,268)	$	(7,623)
Investing activities:
Changes in capital expenditure accruals	$	(69,731)	$	(33,187)
Non-cash financing activities (2)

Reconciliation of cash, cash equivalents, and restricted cash:
Cash and cash equivalents	$	162,251	$	1,735,313
Restricted cash (3)	—		102,000
Cash, cash equivalents, and restricted cash at end of period	$	162,251	$	1,837,313

____________________________________________

(1) Cash paid for interest, net of capitalized interest during the nine months ended September 30, 2024, did not include $9.0 million in fees paid to secure firm commitments for senior unsecured bridge term loans in connection with the Uinta Basin assets acquired on October 1, 2024 (“Uinta Basin Acquisition”).

(2) Refer to Note 5 - Long-Term Debt for discussion of the redemption of the Company’s 5.625% Senior Notes due June 1, 2025 (“2025 Senior Notes”) during the nine months ended September 30, 2024.

(3) As of September 30, 2024, the amount represented a deposit held in a third-party escrow account related to the 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 September 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 nine months ended September 30, 2025. There is no comparable activity for the three and nine months ended September 30, 2024, because the Uinta Basin assets were acquired on October 1, 2024.


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

	(in thousands)
Oil production revenue	$	312,262		$	386,915		$	131,108		$	144,912		$	225,736		$	—		$	669,106		$	531,827
Gas production revenue	31,829			19,265			46,610			31,290			5,724			—			84,163			50,555
NGL production revenue	96			176			57,590			59,822			54			—			57,740			59,998
Total	$	344,187		$	406,356		$	235,308		$	236,024		$	231,514		$	—		$	811,009		$	642,380
Relative percentage	42		%	63		%	29		%	37		%	29		%	—		%	100		%	100		%


	Midland Basin						South Texas						Uinta Basin						Total
	Nine Months Ended September 30,						Nine Months Ended September 30,						Nine Months Ended September 30,						Nine Months Ended September 30,
	2025			2024			2025			2024			2025			2024			2025			2024

	(in thousands)
Oil production revenue	$	963,224		$	1,097,936		$	362,002		$	407,339		$	655,729		$	—		$	1,980,955		$	1,505,275
Gas production revenue	115,257			82,636			145,510			80,948			21,484			—			282,251			163,584
NGL production revenue	358			394			172,013			166,174			128			—			172,499			166,568
Total	$	1,078,839		$	1,180,966		$	679,525		$	654,461		$	677,341		$	—		$	2,435,705		$	1,835,427
Relative percentage	44		%	64		%	28		%	36		%	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 September 30, 2025, and December 31, 2024, were $235.8 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 September 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”).

The following table presents activity under the Company’s Stock Repurchase Program:


	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2025		2024		2025		2024

	(in thousands, except per share data)
Shares of common stock repurchased (1)	445		—		445		1,771
Weighted-average price per share (2)	$	27.25	$	—	$	27.25	$	47.40
Cost of shares of common stock repurchased (2) (3)	$	12,119	$	—	$	12,119	$	83,955

____________________________________________

(1) All repurchased shares of the Company’s common stock were retired upon repurchase.

(2) Amounts exclude excise taxes, commissions, and fees.

(3) Amounts may not calculate due to rounding.

As of September 30, 2025, $487.9 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 September 30,						For the Nine Months Ended September 30,
	2025			2024			2025			2024

	(in thousands)
Current portion of income tax (expense) benefit:
Federal	$	26,970		$	(10,201)		$	(1,128)		$	(23,675)
State	(489)			(1,311)			(3,497)			(2,589)
Deferred portion of income tax expense	(75,686)			(45,615)			(145,149)			(116,522)
Income tax expense	$	(49,205)		$	(57,127)		$	(149,774)		$	(142,786)

Effective tax rate	24.1		%	19.2		%	21.7		%	19.7		%

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 introducing changes to corporate tax provisions. The Company recorded the impact of this legislation on full-year income tax expense during the third quarter of 2025. As part of its evaluation of the OBBBA, and in accordance with ASC 740, the Company recorded increases to its deferred tax assets and liabilities. The adjustment to its deferred tax assets did not result in a change to the Company’s valuation allowance. Additionally, the Company recorded decreases to its current portion of income tax expense and current income taxes payable. These decreases were primarily attributable to the following provisions of the OBBBA: (i) reinstatement of the immediate expensing of domestic research and development (“R&D”) costs; (ii) allowance for the deduction of prior year capitalized and unamortized R&D costs; and (iii) the extension of 100 percent bonus depreciation for qualified property placed in service. The OBBBA also reinstated the option to elect a reduced R&D credit over capitalizing certain costs, which impacted the Company’s effective tax rate for the three and nine months ended September 30, 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 September 30, 2025, the borrowing base and aggregate revolving lender commitments under the Credit Agreement were $3.0 billion and $2.0 billion, respectively. Subsequent to September 30, 2025, the semi-annual borrowing base redetermination was completed, which reaffirmed both the Company’s borrowing base and aggregate lender commitments at existing amounts. The next borrowing base redetermination is scheduled to occur on April 1, 2026. In connection with the semi-annual borrowing base redetermination, the Company and its lenders entered into the Third Amendment to the Credit Agreement (“Third Amendment”) to amend certain provisions related to the maturity date of the Credit Agreement. The Third Amendment amends the springing maturity provision of the Credit Agreement and provides that the maturity date of the Credit Agreement of October 1, 2029, can be accelerated in the event that (i) the outstanding balance of all Senior Notes and other unsecured indebtedness that matures within 91 days exceeds $50.0 million in the aggregate, and (ii) the Company’s borrowing availability under the Credit Agreement, less the aggregate amount of outstanding Senior Notes and other unsecured indebtedness that matures within 91 days, is less than 20% of the current revolving loan commitment amount. The Third Amendment is included as Exhibit 10.4 to this report.

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 October 22, 2025		As of September 30, 2025		As of December 31, 2024

	(in thousands)
Revolving credit facility (1)	$	—	$	—	$	68,500
Letters of credit (2)	1,500		1,500		2,000
Available borrowing capacity	1,998,500		1,998,500		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 $15.8 million and $18.7 million as of September 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 items on the accompanying balance sheets as of September 30, 2025, and December 31, 2024, consisted of the following (collectively referred to as “Senior Notes”):


	As of September 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 (1)	$	419,235	$	642	$	418,593	$	419,235	$	1,168	$	418,067
6.625% Senior Notes due 2027	416,791		1,036		415,755		416,791		1,618		415,173
6.5% Senior Notes due 2028	400,000		2,875		397,125		400,000		3,636		396,364
6.75% Senior Notes due 2029	750,000		8,865		741,135		750,000		10,489		739,511
7.0% Senior Notes due 2032	750,000		9,897		740,103		750,000		10,872		739,128
Total	$	2,736,026	$	23,315	$	2,712,711	$	2,736,026	$	27,783	$	2,708,243

____________________________________________

(1) As of September 30, 2025, the 6.75% Senior Notes due 2026 (“2026 Senior Notes”) are presented in the current liabilities section of the accompanying balance sheets.

On July 25, 2024, the Company issued $750.0 million in aggregate principal amount of its 6.75% Senior Notes at par with a maturity date of August 1, 2029 (“2029 Senior Notes”). The Company received net proceeds of $738.5 million after deducting fees of $11.5 million, which are being amortized as deferred financing costs over the life of the 2029 Senior Notes. Also on July 25, 2024, the Company issued $750.0 million in aggregate principal amount of its 7.0% Senior Notes at par with a maturity date of August 1, 2032 (“2032 Senior Notes”). The Company received net proceeds of $738.5 million after deducting fees of $11.5 million, which are being amortized as deferred financing costs over the life of the 2032 Senior Notes.

On August 26, 2024 (“Redemption Date”), the Company redeemed the entirety of the $349.1 million of aggregate principal amount outstanding of its 2025 Senior Notes, pursuant to the terms of the indenture governing the 2025 Senior Notes which provided for a redemption price equal to 100 percent of the principal amount outstanding of the 2025 Senior Notes on the Redemption Date, plus accrued and unpaid interest. Upon redemption, the Company recorded a loss on extinguishment of debt of $0.5 million related to the accelerated expense recognition of the remaining unamortized deferred financing costs. The Company canceled all redeemed 2025 Senior Notes upon settlement.

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 September 30, 2025, and through the filing of this report.

Capitalized Interest

Capitalized interest costs for the three months ended September 30, 2025, and 2024, totaled $8.0 million and $5.4 million, respectively, and for the nine months ended September 30, 2025, and 2024, totaled $26.1 million and $17.6 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 nine months ended September 30, 2025, the Company entered into new railcar leases and amended certain of its existing railcar leases with terms extending into 2032, with a total remaining commitment of $76.7 million as of September 30, 2025.

Fracturing Services Contract. During the nine months ended September 30, 2025, the Company entered into a fracturing services contract with a term through March 31, 2026. As of September 30, 2025, the minimum commitment remaining under this contract was $24.4 million. As of the filing of this report, if the Company terminated the contract, it would be subject to liquidated damages of up to $20.8 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 September 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;

•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; and

•NYMEX HH and Inside FERC Houston Ship Channel (“IF HSC”) for a portion of its South Texas gas production with sales contracts that settle at IF HSC 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 September 30, 2025, the Company had commodity derivative contracts with terms through the third quarter of 2027 as summarized in the table below:


	Contract Period
	Fourth Quarter 2025		2026		2027
Oil Derivatives (volumes in MBbl and prices in $ per Bbl):
Swaps
NYMEX WTI Volumes	1,988		4,613		—
Weighted-Average Contract Price	$	67.91	$	63.03	$	—


Collars
NYMEX WTI Volumes	3,136		5,902		—
Weighted-Average Floor Price	$	60.11	$	56.92	$	—
Weighted-Average Ceiling Price	$	70.28	$	64.84	$	—
Basis Swaps
WTI Midland-NYMEX WTI Volumes	1,178		4,277		—
Weighted-Average Contract Price	$	1.18	$	0.99	$	—


WTI Houston MEH-NYMEX WTI Volumes	526		1,561		—
Weighted-Average Contract Price	$	1.86	$	2.01	$	—
Roll Differential Swaps
NYMEX WTI Volumes	3,450		1,329		—
Weighted-Average Contract Price	$	0.43	$	0.35	$	—

Gas Derivatives (volumes in BBtu and prices in $ per MMBtu):
Swaps
NYMEX HH Volumes	8,015		30,990		7,888
Weighted-Average Contract Price	$	4.37	$	3.94	$	4.34
IF HSC Volumes	—		957		—
Weighted-Average Contract Price	$	—	$	4.07	$	—
IF Waha Volumes	1,134		10,020		4,603
Weighted-Average Contract Price	$	2.02	$	2.34	$	3.64


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









Basis Swaps




IF Waha-NYMEX HH Volumes	5,046		574		2,503
Weighted-Average Contract Price	$	(0.66)	$	(1.75)	$	(0.74)
IF HSC-NYMEX HH Volumes	—		973		—
Weighted-Average Contract Price	$	—	$	(0.18)	$	—

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 September 30, 2025

Subsequent to September 30, 2025, and through the filing of this report, the Company entered into the following commodity derivative contracts:


	Contract Period
	Fourth Quarter 2025		2026		2027





















Gas Derivatives (volumes in BBtu and prices in $ per MMBtu):
Swaps
NYMEX HH Volumes	—		2,743		3,650
Weighted-Average Contract Price	$	—	$	4.08	$	3.62


IF Waha Volumes	—		553		—
Weighted-Average Contract Price	$	—	$	3.05	$	—
Basis Swaps
IF Waha-NYMEX HH Volumes	—		—		996
Weighted-Average Contract Price	$	—	$	—	$	(0.70)

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 September 30, 2025, and December 31, 2024, was a net asset of $58.5 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 September 30, 2025		As of December 31, 2024

	(in thousands)
Derivative assets:
Current assets	$	68,567	$	48,522
Noncurrent assets	4,677		3,973
Total derivative assets	$	73,244	$	52,495
Derivative liabilities:
Current liabilities	$	9,888	$	7,058
Noncurrent liabilities	4,852		7,142
Total derivative liabilities	$	14,740	$	14,200

Offsetting of Derivative Assets and Liabilities

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

	(in thousands)
Gross amounts presented in the accompanying balance sheets	$	73,244	$	52,495	$	(14,740)	$	(14,200)
Amounts not offset in the accompanying balance sheets	(14,534)		(12,995)		14,534		12,995
Net amounts	$	58,710	$	39,500	$	(206)	$	(1,205)

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


	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2025		2024		2025		2024

	(in thousands)
Net derivative settlement (gain) loss:
Oil contracts	$	(16,483)	$	487	$	(40,486)	$	(877)
Gas contracts	(22,384)		(16,735)		(48,187)		(46,639)
NGL contracts	—		(243)		2,310		1,228
Total net derivative settlement gain	$	(38,867)	$	(16,491)	$	(86,363)	$	(46,288)

Net derivative (gain) loss:
Oil contracts	$	1,172	$	(65,633)	$	(50,989)	$	(29,805)
Gas contracts	(46,367)		(15,291)		(56,007)		(41,624)
NGL contracts	(284)		(5,359)		425		1,173
Total net derivative gain	$	(45,479)	$	(86,283)	$	(106,571)	$	(70,256)

Credit Related Contingent Features

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

	(in thousands)
Assets:
Derivatives	$	—	$	73,244	$	—	$	—	$	52,495	$	—

Liabilities:
Derivatives	$	—	$	14,740	$	—	$	—	$	14,200	$	—

Both financial and non-financial assets and liabilities are categorized within the fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. The following is a description of the valuation methodologies 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. The Senior Notes were not presented at fair value on the accompanying balance sheets as of September 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 September 30, 2025				As of December 31, 2024
	Principal Amount		Fair Value		Principal Amount		Fair Value

	(in thousands)
6.75% Senior Notes due 2026 (1)	$	419,235	$	419,071	$	419,235	$	419,654
6.625% Senior Notes due 2027	$	416,791	$	416,645	$	416,791	$	416,149
6.5% Senior Notes due 2028	$	400,000	$	403,264	$	400,000	$	398,676
6.75% Senior Notes due 2029	$	750,000	$	754,688	$	750,000	$	742,275
7.0% Senior Notes due 2032	$	750,000	$	750,000	$	750,000	$	741,053

____________________________________________

(1) As of September 30, 2025, the 2026 Senior Notes are presented in the current liabilities section of the accompanying balance sheets.

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 10 - Compensation Plans in this report and 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 September 30,				For the Nine Months Ended September 30,
	2025		2024		2025		2024

	(in thousands, except per share data)
Net income	$	155,088	$	240,523	$	539,022	$	582,015

Basic weighted-average common shares outstanding	114,826		114,405		114,592		114,870
Dilutive effect of non-vested RSUs, contingent PSUs, and other	400		588		398		831
Diluted weighted-average common shares outstanding	115,226		114,993		114,990		115,701

Basic net income per common share	$	1.35	$	2.10	$	4.70	$	5.07
Diluted net income per common share	$	1.35	$	2.09	$	4.69	$	5.03

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 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 September 30,				For the Nine Months Ended September 30,
	2025		2024		2025		2024

	(in thousands)
Total operating revenues and other income	$	811,591	$	643,613	$	2,449,078	$	1,838,038
Less:
Lease operating expense	111,515		73,919		325,379		216,562
Transportation costs	74,225		33,299		222,322		88,651
Production taxes	33,220		29,322		100,302		81,676
Ad valorem tax expense	10,076		11,840		30,114		35,488
Depletion, depreciation, and amortization	325,372		202,942		888,262		548,781
Exploration	11,532		12,097		38,650		47,772

General and administrative	39,317		35,141		120,753		96,431
Net derivative gain	(45,479)		(86,283)		(106,571)		(70,256)
Other operating expense, net	5,331		384		12,189		4,206
Interest expense	42,937		50,682		129,871		94,362
Interest income	(828)		(18,017)		(1,123)		(31,120)

Other non-operating expense	80		637		134		684
Income tax expense	49,205		57,127		149,774		142,786
E&P Segment net income	$	155,088	$	240,523	$	539,022	$	582,015

___________________________________________

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 September 30, 2025, approximately 2.5 million shares of common stock were available for grant under the 2025 Equity Plan. The 2025 Equity Plan is included as Exhibit 10.1 to this report.

Performance Share Units

The Company has granted PSUs, which were determined to be equity awards, 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 2025, settlement will be determined based on the Company’s total shareholder return (“TSR”) measured over the three-year performance period, including equally weighted absolute TSR and TSR relative to certain peer companies. For PSUs granted in 2024 and 2023, settlement will be determined based on a combination of the following criteria measured over the three-year performance period: relative TSR, 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 the 2024 and 2023 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. During the nine months ended September 30, 2025, 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.

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 $1.8 million and $1.1 million for the three months ended September 30, 2025, and 2024, respectively, and $4.7 million and $3.5 million for the nine months ended September 30, 2025, and 2024, respectively. As of September 30, 2025, there was $15.6 million of total unrecognized compensation expense related to non-vested PSUs, which is being amortized through mid-2028.

A summary of activity during the nine months ended September 30, 2025, is presented in the following table:


	PSUs (1)	Weighted-Average Grant-Date Fair Value (2)
Non-vested at beginning of year	694,366	$	32.99
Granted	374,692	$	27.45
Vested	(49,922)	$	30.02
Forfeited	(199,531)	$	31.01
Non-vested at end of quarter	819,605	$	32.27

____________________________________________

(1) The number of PSUs presented assumes a multiplier of one. The actual final number of shares of common stock to be issued at the end of the three-year performance will range from zero to two times the number of PSUs awarded depending on the three-year performance multiplier.

(2) Amounts represent price per unit.

During the nine months ended September 30, 2025, the Company settled PSUs that were granted in 2022, at a 0.28 times multiplier based on the same performance criteria utilized for PSUs granted in 2024 and 2023, as 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.

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. During the nine months ended September 30, 2025, the Company granted to employees a total of 981,046 RSUs with a grant date fair value of $25.8 million pursuant to the 2025 Equity Plan and 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 161,787 shares to satisfy income and payroll tax withholding obligations, the Company issued 324,981 shares of common stock in accordance with the terms of the applicable award agreements.

Total compensation expense recorded for RSUs was $5.1 million and $4.5 million for the three months ended September 30, 2025, and 2024, respectively, and $14.2 million and $12.0 million for the nine months ended September 30, 2025, and 2024, respectively. As of September 30, 2025, there was $37.9 million of total unrecognized compensation expense related to non-vested RSUs, which is being amortized through mid-2028.

A summary of activity during the nine months ended September 30, 2025, is presented in the following table:


	RSUs	Weighted-Average Grant-Date Fair Value (1)
Non-vested at beginning of year	1,039,837	$	37.87
Granted	981,046	$	26.34
Vested	(486,768)	$	36.39
Forfeited	(101,254)	$	34.38
Non-vested at end of quarter	1,432,861	$	30.73

____________________________________________

(1) Amounts represent price per unit.

Director Shares

During the nine months ended September 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 nine months ended September 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 nine months ended September 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.

Note 13 - Subsequent Event

On November 2, 2025, the Company entered into an Agreement and Plan of Merger (“Merger Agreement”) with Civitas Resources, Inc. (“Civitas”) and a subsidiary of the Company, pursuant to which, among other things, the Company has agreed to acquire Civitas through a series of mergers (collectively, the “Merger”). Under the terms of the Merger Agreement, each eligible share of Civitas’ common stock will be converted into the right to receive 1.45 shares of the Company’s common stock.

and New Mexico. Under the terms of the Merger, Civitas shareholders will receive 1.45 shares of the Company’s common stock in exchange for each common share of Civitas they own at closing.

The Merger has been unanimously approved by the boards of directors of both companies. The Merger is subject to customary closing conditions, including the approval of SM Energy and Civitas shareholders and receipt of required regulatory approvals. The transaction is expected to close in the first quarter of 2026.

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 June 30, 2025, filed with the Securities and Exchange Commission (“SEC”) on August 1, 2025. Throughout the following discussion, we explain changes between the three months ended September 30, 2025, and the three months ended June 30, 2025 (“sequential quarterly” or “sequentially”), and the year-to-date (“YTD”) change between the nine months ended September 30, 2025, and the nine months ended September 30, 2024 (“YTD 2025-over-YTD 2024”).

Overview of the Company

Merger with Civitas

On November 2, 2025, we entered into the Merger Agreement with Civitas and a subsidiary of SM Energy, pursuant to which, among other things, we have agreed to acquire Civitas through the Merger. Under the terms of the Merger Agreement, each eligible share of Civitas common stock will be converted into the right to receive 1.45 shares of our common stock.

Civitas is an independent exploration and production company focused on the acquisition, development, and production of crude oil and associated liquids-rich natural gas primarily in the Denver-Julesberg Basin in Colorado and the Permian Basin in Texas and New Mexico. We expect the Merger to generate value-enhancing scale, unlock meaningful synergies, and deliver accretive substance, ultimately creating superior long-term value for our stockholders. Under the terms of the Merger, Civitas shareholders will receive 1.45 shares of our common stock in exchange for each common share of Civitas they own at closing.

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 and development 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 transparently 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 impairments of proved and unproved properties in the future. Future impairments of proved and unproved properties are difficult to predict, especially in a volatile price environment.

The ongoing U.S. federal government shutdown has not had a material impact on our operations or financial condition to date; however, if it continues, it could affect our financial condition or results of operations in the fourth quarter of 2025 and beyond. Potential impacts may include delays in regulatory processes and approvals, disruptions to government-related activities, or broader economic effects.

Areas of Operations

Our Midland Basin assets are comprised of approximately 107,000 net acres located in the Permian Basin in West Texas (“Midland Basin”) and provide future development and exploration 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 62,000 net acres located in Duchesne and Uintah counties, Utah (“Uinta Basin”) and provide 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.

Third Quarter 2025 Overview and Outlook for the Remainder of 2025

During the third quarter of 2025, we resumed activity under our Stock Repurchase Program by repurchasing and subsequently retiring approximately 0.4 million shares of our outstanding common stock at a cost of $12.1 million, excluding excise taxes, commissions, and fees. Additionally, we continued to execute on our goal of sustainably returning capital to our stockholders through our fixed quarterly dividend by paying a net cash dividend of $0.20 per share, totaling $23.0 million. In September 2025, we declared a fixed cash dividend of $0.20 per share to be paid on November 3, 2025.

Financial and Operational Results. Average net daily equivalent production for the three months ended September 30, 2025, increased two percent sequentially to 213.8 MBOE. The overall increase consisted of an increase of 12 percent from our South Texas assets, mostly offset by decreases of five percent and two percent from our Uinta Basin and Midland Basin assets, respectively.

Oil, gas, and NGL realized price, before the effect of net derivative settlements (“realized price” or “realized prices”), remained flat sequentially. The second and third quarters of 2025 were impacted by weak Waha pricing, which we expect will continue to impact our realized price into 2026, when additional pipeline capacity is expected to be placed into service. A portion of the negative impact was mitigated by our commodity derivative contracts in effect during the second and third quarters of 2025, and we have additional commodity derivative contracts in place for future periods. Oil, gas, and NGL production revenue increased three percent sequentially and was $811.0 million for the three months ended September 30, 2025, compared with $785.1 million for the three months ended June 30, 2025. Oil, gas, and NGL production expense increased two percent sequentially to $229.0 million for the three months ended September 30, 2025, compared with $224.0 million for the three months ended June 30, 2025.

We recorded net derivative gains of $45.5 million and $78.3 million for the three months ended September 30, 2025, and June 30, 2025, respectively. Included within these amounts are net derivative settlement gains of $38.9 million and $39.7 million for the three months ended September 30, 2025, and June 30, 2025, respectively.

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

•Net income of $155.1 million, or $1.35 per diluted share, compared with net income of $201.7 million, or $1.76 per diluted share, for the three months ended June 30, 2025.

•Net cash provided by operating activities of $505.0 million, compared with $571.1 million for the three months ended June 30, 2025. The decrease 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 $588.2 million, compared with $569.6 million for the three months ended June 30, 2025. Refer to the caption Non-GAAP Financial Measures below for additional discussion and our definition of adjusted EBITDAX and reconciliations to net income and net cash provided by operating activities.

Refer to Overview of Selected Production and Financial Information, Including Trends and Comparison of Financial Results and Trends Between the Three Months Ended September 30, 2025, and June 30, 2025, and Between the Nine Months Ended September 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 and includes certain 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 nine months ended September 30, 2025, costs incurred in oil and gas property acquisition, exploration, and development activities, whether capitalized or expensed, totaled $323.7 million and $1.17 billion, respectively. Total costs incurred includes activity in our core areas of operations and 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 operated two drilling rigs and one completion crew during the majority of the third quarter of 2025, and our operations focused on development optimization of our RockStar assets and delineation and development of our Sweetie Peck assets. Average net daily equivalent production decreased sequentially by two percent to 82.0 MBOE. Costs incurred during the three months ended September 30, 2025, totaled $128.5 million, or 40 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 operated one drilling rig and one spot completion crew during the third quarter of 2025, and our operations focused primarily on the development and further delineation of the Austin Chalk formation. Average net daily equivalent production increased sequentially by 12 percent to 86.4 MBOE. Costs incurred during the three months ended September 30, 2025, totaled $76.4 million, or 24 percent of our total costs incurred for the period. We anticipate operating one or two drilling rigs and one 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 third quarter of 2025, and our operations focused on delineation and development. Average net daily equivalent production decreased sequentially by five percent to 45.5 MBOE. Costs incurred during the three months ended September 30, 2025, totaled $107.7 million, or 33 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 nine months ended September 30, 2025:


	Midland Basin		South Texas (1)		Uinta Basin (2)		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
Wells drilled	6	4	8	8	15	12	29	24
Wells completed	(19)	(15)	(12)	(12)	—	—	(31)	(27)
Other (3)	—	—	—	—	—	1	—	1
Wells drilled but not completed at September 30, 2025	21	15	27	26	38	29	86	70

____________________________________________

(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.

(2) Completions activity in our Uinta Basin program is ongoing, but no official well completions occurred during the three months ended September 30, 2025, due to pad timing.

(3) Adjustment primarily relates to the acquisition of additional working interest in existing drilled but not completed wells.

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 Nine Months Ended
	September 30, 2025		June 30, 2025		September 30, 2025		September 30, 2024

Midland Basin Net Production:
Oil (MMBbl)	4.7		4.9		14.3		14.1
Gas (Bcf)	16.7		16.2		48.9		46.0
NGLs (MMBbl)	—		—		—		—
Equivalent (MMBOE)	7.5		7.6		22.5		21.8
Average net daily equivalent (MBOE per day)	82.0		83.6		82.4		79.6
Relative percentage	39	%	40	%	40	%	50	%

South Texas Net Production:
Oil (MMBbl)	2.1		1.8		5.5		5.4
Gas (Bcf)	18.7		16.7		53.0		51.9
NGLs (MMBbl)	2.8		2.4		7.6		7.4
Equivalent (MMBOE)	7.9		7.0		22.0		21.5
Average net daily equivalent (MBOE per day)	86.4		77.4		80.4		78.3
Relative percentage	40	%	37	%	39	%	50	%

Uinta Basin Net Production: (1)
Oil (MMBbl)	3.7		3.8		10.5		—
Gas (Bcf)	3.0		3.4		9.2		—
NGLs (MMBbl)	—		—		—		—
Equivalent (MMBOE)	4.2		4.4		12.0		—
Average net daily equivalent (MBOE per day)	45.5		48.0		44.0		—
Relative percentage	21	%	23	%	21	%	—	%

Total Net Production:
Oil (MMBbl)	10.5		10.5		30.3		19.5
Gas (Bcf)	38.5		36.2		111.1		97.9
NGLs (MMBbl)	2.8		2.5		7.6		7.4
Equivalent (MMBOE)	19.7		19.0		56.5		43.3
Average net daily equivalent (MBOE per day)	213.8		209.1		206.8		157.9

____________________________________________

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
	September 30, 2025		June 30, 2025		September 30, 2024
Oil (per Bbl):
Average NYMEX contract monthly price	$	64.93	$	63.74	$	75.10
Realized price	$	63.83	$	62.04	$	74.72
Effect of oil net derivative settlements	$	1.57	$	2.01	$	(0.07)
Gas:
Average NYMEX monthly settle price (per MMBtu)	$	3.07	$	3.44	$	2.16
Realized price (per Mcf)	$	2.19	$	2.15	$	1.46
Effect of gas net derivative settlements (per Mcf)	$	0.58	$	0.51	$	0.48
NGLs (per Bbl):
Average OPIS price (1)	$	25.58	$	26.99	$	26.68
Realized price	$	20.79	$	21.91	$	21.70
Effect of NGL net derivative settlements	$	—	$	0.01	$	0.09

____________________________________________

(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 October 22, 2025, and September 30, 2025:


	As of October 22, 2025		As of September 30, 2025
NYMEX WTI oil (per Bbl)	$	58.53	$	61.51
NYMEX Henry Hub gas (per MMBtu)	$	3.90	$	3.68
OPIS NGLs (per Bbl)	$	24.32	$	25.69

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 September 30, 2025, and the preceding three quarters:


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

	(in millions)
Net production (MMBOE)	19.7		19.0		17.8		19.1
Oil, gas, and NGL production revenue	$	811.0	$	785.1	$	839.6	$	835.9
Oil, gas, and NGL production expense	$	229.0	$	224.0	$	225.1	$	214.6
Depletion, depreciation, and amortization	$	325.4	$	293.0	$	269.9	$	260.5
Exploration	$	11.5	$	15.4	$	11.8	$	16.3
General and administrative	$	39.3	$	42.1	$	39.3	$	41.9
Net income	$	155.1	$	201.7	$	182.3	$	188.3

Selected Performance Metrics


	For the Three Months Ended
	September 30,			June 30,			March 31,			December 31,
	2025			2025			2025			2024
Average net daily equivalent production (MBOE per day)	213.8			209.1			197.3			208.0
Lease operating expense (per BOE)	$	5.67		$	5.52		$	6.13		$	5.35
Transportation costs (per BOE)	$	3.77		$	4.13		$	3.92		$	4.10
Production taxes as a percent of oil, gas, and NGL production revenue	4.1		%	3.9		%	4.4		%	4.1		%
Ad valorem tax expense (per BOE)	$	0.51		$	0.54		$	0.55		$	(0.03)
Depletion, depreciation, and amortization (per BOE)	$	16.54		$	15.40		$	15.20		$	13.61
General and administrative (per BOE)	$	2.00		$	2.21		$	2.22		$	2.19

____________________________________________

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 Nine Months Ended				Amount Change Between Periods			Percent Change Between Periods
	September 30,		June 30,						September 30,		September 30,
	2025		2025						2025		2024
Net production volumes: (1)
Oil (MMBbl)	10.5		10.5		—		—	%	30.3		19.5			10.8			55	%
Gas (Bcf)	38.5		36.2		2.2		6	%	111.1		97.9			13.2			13	%
NGLs (MMBbl)	2.8		2.5		0.3		13	%	7.6		7.4			0.2			2	%
Equivalent (MMBOE)	19.7		19.0		0.6		3	%	56.5		43.3			13.2			30	%
Average net daily production: (1)
Oil (MBbl per day)	113.9		115.7		(1.8)		(2)	%	111.2		71.3			39.9			56	%
Gas (MMcf per day)	418.2		398.3		19.9		5	%	406.9		357.3			49.7			14	%
NGLs (MBbl per day)	30.2		26.9		3.2		12	%	27.8		27.1			0.7			3	%
Equivalent (MBOE per day)	213.8		209.1		4.8		2	%	206.8		157.9			48.9			31	%
Oil, gas, and NGL production revenue (in millions): (1)
Oil production revenue	$	669.1	$	653.4	$	15.7	2	%	$	1,981.0	$	1,505.3		$	475.7		32	%
Gas production revenue	84.2		78.0		6.2		8	%	282.3		163.6			118.7			73	%
NGL production revenue	57.7		53.7		4.0		8	%	172.5		166.6			5.9			4	%
Total oil, gas, and NGL production revenue	$	811.0	$	785.1	$	25.9	3	%	$	2,435.7	$	1,835.4		$	600.3		33	%
Oil, gas, and NGL production expense (in millions): (1)
Lease operating expense	$	111.5	$	105.0	$	6.5	6	%	$	325.4	$	216.6		$	108.8		50	%
Transportation costs	74.2		78.5		(4.3)		(5)	%	222.3		88.7			133.7			151	%
Production taxes	33.2		30.2		3.0		10	%	100.3		81.7			18.6			23	%
Ad valorem tax expense	10.1		10.2		(0.1)		(1)	%	30.1		35.5			(5.4)			(15)	%
Total oil, gas, and NGL production expense	$	229.0	$	224.0	$	5.0	2	%	$	678.1	$	422.4		$	255.7		61	%
Realized price:
Oil (per Bbl)	$	63.83	$	62.04	$	1.79	3	%	$	65.28	$	77.08		$	(11.80)		(15)	%
Gas (per Mcf)	$	2.19	$	2.15	$	0.04	2	%	$	2.54	$	1.67		$	0.87		52	%
NGLs (per Bbl)	$	20.79	$	21.91	$	(1.12)	(5)	%	$	22.73	$	22.45		$	0.28		1	%
Per BOE	$	41.23	$	41.27	$	(0.04)	—	%	$	43.15	$	42.42		$	0.73		2	%
Per BOE data: (1)
Oil, gas, and NGL production expense:
Lease operating expense	$	5.67	$	5.52	$	0.15	3	%	$	5.76	$	5.01		$	0.75		15	%
Transportation costs	3.77		4.13		(0.36)		(9)	%	3.94		2.05			1.89			92	%
Production taxes	1.69		1.59		0.10		6	%	1.78		1.89			(0.11)			(6)	%
Ad valorem tax expense	0.51		0.54		(0.03)		(6)	%	0.53		0.82			(0.29)			(35)	%
Total oil, gas, and NGL production expense (1)	$	11.64	$	11.78	$	(0.14)	(1)	%	$	12.01	$	9.76		$	2.25		23	%
Depletion, depreciation, and amortization	$	16.54	$	15.40	$	1.14	7	%	$	15.73	$	12.68		$	3.05		24	%
General and administrative	$	2.00	$	2.21	$	(0.21)	(10)	%	$	2.14	$	2.23		$	(0.09)		(4)	%
Net derivative settlement gain (2)	$	1.98	$	2.09	$	(0.11)	(5)	%	$	1.53	$	1.07		$	0.46		43	%
Earnings per share information (in thousands, except per share data): (3)
Basic weighted-average common shares outstanding	114,826		114,520		306		—	%	114,592		114,870			(278)			—	%
Diluted weighted-average common shares outstanding	115,226		114,788		438		—	%	114,990		115,701			(711)			(1)	%
Basic net income per common share	$	1.35	$	1.76	$	(0.41)	(23)	%	$	4.70	$	5.07		$	(0.37)		(7)	%
Diluted net income per common share	$	1.35	$	1.76	$	(0.41)	(23)	%	$	4.69	$	5.03		$	(0.34)		(7)	%

______________________________________

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

(2) Net derivative settlements for the three months ended September 30, 2025, and for the nine months ended September 30, 2025, and 2024, are included within the net derivative gain 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 September 30, 2025, increased slightly sequentially as a 12 percent increase from our South Texas assets was mostly offset by decreases of five percent and two percent from our Uinta Basin assets and Midland Basin assets, respectively. Average net daily equivalent production increased 31 percent YTD 2025-over-YTD 2024 primarily driven by the addition of 44.0 MBOE per day of production from our Uinta Basin assets.

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 remained flat sequentially. The second and third quarters of 2025 were impacted by weak Waha pricing, which we expect will continue to impact our realized price into 2026, when additional pipeline capacity is expected to be placed into service. A portion of the negative impact was mitigated by our commodity derivative contracts in effect during the second and third quarters of 2025, and we have additional commodity derivative contracts in place for future periods. We recognized net gains on the settlement of our commodity derivative contracts of $1.98 per BOE and $2.09 per BOE during the three months ended September 30, 2025, and June 30, 2025, respectively. Our total realized price increased $0.73 YTD 2025-over-YTD 2024 primarily as a result of a shift in our production mix towards more oil production, which was offset by a decrease in the benchmark oil price. We recognized net gains on the settlement of our commodity derivative contracts of $1.53 per BOE and $1.07 per BOE during the nine months ended September 30, 2025, and September 30, 2024, respectively.

Lease operating expense (“LOE”) per BOE increased three percent sequentially as a result of timing of workover projects. LOE per BOE increased 15 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 production mix, timing of workover projects, changes in service provider costs, and industry activity, all of which affect total LOE.

Transportation costs per BOE decreased nine percent sequentially, primarily as a result of a five percent decrease in average net daily equivalent production from our Uinta Basin assets, which have higher transportation costs per BOE. Transportation costs per BOE increased 92 percent YTD 2025-over-YTD 2024 primarily as a result of the addition of oil production from our Uinta Basin 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. Additionally, transportation costs related to our Uinta Basin assets can vary depending on the terms of the applicable sales contracts and the transportation method used. 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 increased six percent sequentially primarily as a result of an increase in oil realized price and changes in production mix across our assets. Production tax expense per BOE decreased six 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 4.1 percent and 3.9 percent for the three months ended September 30, 2025, and June 30, 2025, respectively, and was 4.1 percent and 4.4 percent for the nine months ended September 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 six percent sequentially and 35 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 increased seven percent sequentially, primarily driven by expected increases in DD&A rates as our capital allocation shifts with the inclusion of our Uinta Basin assets. DD&A expense per BOE increased 24 percent YTD 2025-over-YTD 2024 as 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 decreased 10 percent sequentially driven by decreased G&A expense on an absolute basis and increased total net equivalent production. G&A expense on a per BOE basis decreased four percent YTD 2025-over-YTD 2024 as increased total net equivalent production outpaced increased G&A expense on an absolute basis. 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 September 30, 2025, and June 30, 2025, and Between the Nine Months Ended September 30, 2025, and 2024 below for additional discussion of operating expenses.

Comparison of Financial Results and Trends Between the Three Months Ended September 30, 2025, and June 30, 2025, and Between the Nine Months Ended September 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 September 30, 2025, and June 30, 2025:


	Average Net Equivalent Production Increase (Decrease)	Oil, Gas, and NGL Production Revenue Increase (Decrease)	Oil, Gas, and NGL Production Expense Increase (Decrease)
	(MBOE per day)	(in millions)	(in millions)
Midland Basin	(1.7)		$	2.3	$	7.7
South Texas	9.0		23.8		4.7
Uinta Basin	(2.5)		(0.2)		(7.3)
Total	4.8		$	25.9	$	5.0

__________________________________________

Note: Amounts may not calculate due to rounding.

Average net daily equivalent production increased slightly, and total realized price remained relatively flat, resulting in a three percent increase in oil, gas, and NGL production revenue. Oil, gas, and NGL production expense increased slightly as increases in LOE and production tax expense were partially offset by a decrease in transportation expense.

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 nine months ended September 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	2.8		$	(102.1)	$	17.4
South Texas	2.1		25.1		20.0
Uinta Basin (1)	44.0		677.3		218.3
Total	48.9		$	600.3	$	255.7

__________________________________________

Note: Amounts may not calculate due to rounding.

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

Average net daily equivalent production increased 31 percent and oil, gas, and NGL production revenue increased 33 percent, primarily driven by the addition of 44.0 MBOE per day of production from our Uinta Basin assets. Oil, gas, and NGL production expense increased 61 percent driven by increases in transportation expense and LOE associated with the addition of our Uinta Basin assets.

Depletion, depreciation, and amortization


	For the Three Months Ended				For the Nine Months Ended
	September 30, 2025		June 30, 2025		September 30, 2025		September 30, 2024

	(in millions)
Depletion, depreciation, and amortization	$	325.4	$	293.0	$	888.3	$	548.8

DD&A expense increased 11 percent sequentially and 62 percent YTD 2025-over-YTD 2024. The sequential quarterly increase was primarily driven by increases in DD&A rates across all of our assets. The YTD 2025-over-YTD 2024 increase was 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 Nine Months Ended
	September 30, 2025		June 30, 2025		September 30, 2025		September 30, 2024

	(in millions)
Geological, geophysical, and other expenses	$	2.0	$	5.8	$	9.8	$	22.7
Overhead	9.5		9.6		28.9		25.1
Total exploration	$	11.5	$	15.4	$	38.7	$	47.8

Exploration expense decreased 25 percent sequentially and 19 percent YTD 2025-over-YTD 2024 as a result of decreases in geological, geophysical, and other expenses. Exploration expense fluctuates based on actual geological and geophysical studies we perform within an exploratory area, exploratory dry hole expense incurred, and changes in the amount of allocated overhead.

General and administrative


	For the Three Months Ended				For the Nine Months Ended
	September 30, 2025		June 30, 2025		September 30, 2025		September 30, 2024

	(in millions)
General and administrative	$	39.3	$	42.1	$	120.8	$	96.4

G&A expense decreased seven percent sequentially and increased 25 percent YTD 2025-over-YTD 2024. The YTD 2025-over-YTD 2024 increase was primarily due to increased headcount and one-time G&A expenses, both of which related to the Uinta Basin Acquisition.

Net derivative gain


	For the Three Months Ended				For the Nine Months Ended
	September 30, 2025		June 30, 2025		September 30, 2025		September 30, 2024

	(in millions)
Net derivative gain	$	(45.5)	$	(78.3)	$	(106.6)	$	(70.3)

Net derivative gain 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 Nine Months Ended
	September 30, 2025		June 30, 2025		September 30, 2025		September 30, 2024

	(in millions)
Interest expense	$	(42.9)	$	(42.6)	$	(129.9)	$	(94.4)

Interest expense remained relatively flat sequentially and increased 38 percent YTD 2025-over-YTD 2024. The YTD 2025-over-YTD 2024 increase was primarily a result of the issuance of our 2029 Senior Notes and our 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 Nine Months Ended
	September 30, 2025			June 30, 2025			September 30, 2025			September 30, 2024

	(in millions, except tax rate)
Income tax expense	$	(49.2)		$	(50.8)		$	(149.8)		$	(142.8)
Effective tax rate	24.1		%	20.1		%	21.7		%	19.7		%

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 increased both sequentially and YTD 2025-over-YTD 2024, primarily as a result of the impact of newly enacted limitations on the R&D credit calculation under the OBBBA, partially offset by the impact of statutory changes related to the Texas R&D credit calculation that benefited the second quarter of 2025. The sequential quarterly increase also reflects the impact of excess tax deficiencies from stock-based compensation awards.

The effects of changes in tax laws are recognized in the period of enactment. 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. During the third quarter of 2025, we recorded the impacts of the OBBBA on our full-year income tax expense, which resulted in a decrease to the current portion of income tax expense. This change reflects the impacts of 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.

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 financial obligations, including near-term maturities of our outstanding Senior Notes. 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 nine months ended September 30, 2025, we primarily funded our capital expenditures and return of capital program with cash flows from operating activities. 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 September 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. Subsequent to September 30, 2025, our lender group reaffirmed our borrowing base and aggregate lender commitments at existing amounts. The next borrowing base redetermination is scheduled to occur on April 1, 2026. In connection with the semi-annual borrowing base redetermination, we entered into the Third Amendment with our lenders to amend the springing maturity provision of the Credit Agreement to provide a more flexible structure based on the amount of our short-term debt outstanding and our borrowing availability. No individual bank participating in our Credit Agreement represents more than 10 percent of the lender commitments under the Credit Agreement. We must comply with certain financial and non-financial covenants under the terms of the Credit Agreement. We were in compliance with all financial and non-financial covenants under the Credit Agreement as of September 30, 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 Nine Months Ended
	September 30, 2025		June 30, 2025		September 30, 2025		September 30, 2024

	(in millions)
Daily weighted-average revolving credit facility balance	$	12.5	$	66.3	$	66.0	$	—

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

Refer to Note 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 October 22, 2025, September 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 Nine Months Ended
	September 30, 2025		June 30, 2025		September 30, 2025		September 30, 2024
Weighted-average interest rate	7.4	%	7.4	%	7.4	%	7.2	%
Weighted-average borrowing rate	6.7	%	6.8	%	6.8	%	6.6	%

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 increase slightly 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 nine months ended September 30, 2025, we spent $1.22 billion on capital expenditures. This amount differs from the costs incurred amount of $1.17 billion for the nine months ended September 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 approximately $1.375 billion and includes certain 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.

As of September 30, 2025, we reclassified $419.2 million of principal balance of our 2026 Senior Notes as current liabilities, net of unamortized deferred financing costs, on our accompanying balance sheets. As of the filing of this report, based on current commodity prices, we expect to meet this obligation using cash on hand and projected cash provided by operating activities. As of September 30, 2025, our cash and cash equivalents balance was $162.3 million, and as of the filing of this report, we had $2.0 billion of available borrowing capacity under our revolving credit facility.

During the nine months ended September 30, 2025, and 2024, we repurchased and subsequently retired 0.4 million and 1.8 million shares, respectively, of our common stock at a total cost of $12.1 million and $84.0 million, respectively, excluding excise taxes, commissions, and fees. As of September 30, 2025, $487.9 million was available under the Stock Repurchase Program for repurchases of our common stock through December 31, 2027.

During the nine months ended September 30, 2025, and 2024, we paid $68.8 million and $62.1 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 and we recorded the impacts of the OBBBA on our full-year income tax expense during the third quarter of 2025. As a result, we 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 September 30, 2025, and June 30, 2025, and Between the Nine Months Ended September 30, 2025, and 2024 for discussion of the OBBBA.

Analysis of Cash Flow Changes Between the Nine Months Ended September 30, 2025, and 2024

The following tables present changes in cash flows between the nine months ended September 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 Nine Months Ended September 30,				Amount Change Between Periods
	2025		2024

	(in millions)
Net cash provided by operating activities	$	1,559.1	$	1,204.6	$	354.5

Net cash provided by operating activities increased for the nine months ended September 30, 2025, compared with the same period in 2024, primarily as a result of an increase of $482.8 million in cash received from oil, gas, and NGL production revenue net of transportation costs and production taxes and an increase of $31.9 million in cash received on settled derivative trades, partially offset by an increase of $131.5 million in cash paid for LOE, ad valorem taxes, and certain G&A expenses and an increase of $81.4 million of cash paid for interest. These changes are largely a result of the Uinta Basin Acquisition. Net cash provided by operating activities is also affected by working capital changes and the timing of cash receipts and disbursements.

Investing activities


	For the Nine Months Ended September 30,				Amount Change Between Periods
	2025		2024

	(in millions)
Net cash used in investing activities	$	(1,243.8)	$	(957.9)	$	(285.9)

Net cash used in investing activities increased for the nine months ended September 30, 2025, compared with the same period in 2024, as a result of a $264.6 million increase in capital expenditures and $21.5 million of cash paid related to acquisition activity, primarily post-closing adjustments related to final settlement of the Uinta Basin Acquisition during the first quarter of 2025.

Financing activities


	For the Nine Months Ended September 30,				Amount Change Between Periods
	2025		2024

	(in millions)
Net cash provided by (used in) financing activities	$	(153.1)	$	974.4	$	(1,127.5)

Net cash used in financing activities for the nine months ended September 30, 2025, primarily related to $68.8 million of dividends paid to our stockholders, net repayments of $68.5 million under our revolving credit facility, and $12.8 million cash paid, including excise taxes, commissions, and fees, to repurchase and subsequently retire 0.4 million shares of our common stock under the Stock Repurchase Program.

Net cash provided by financing activities for the nine months ended September 30, 2024, primarily related to the net cash proceeds of $1.48 billion received from the issuance of the 2029 Senior Notes and 2032 Senior Notes, partially offset by $349.1 million of cash paid to redeem our 2025 Senior Notes, $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 $62.1 million of dividends paid to our stockholders.

Interest Rate Risk

We are exposed to market and credit risk due to the floating interest rate associated with any outstanding balance under our revolving credit facility. Our Credit Agreement allows us to fix the interest rate for all or a portion of the principal balance of our revolving credit facility for a period of up to six months. To the extent that the interest rate is fixed, interest rate changes will affect the revolving credit facility’s fair value but will not affect results of operations or cash flows. Conversely, for the portion of the revolving credit facility that has a floating interest rate, interest rate changes will not affect the fair value, but will affect future results of operations and cash flows. Changes in interest rates do not affect the amount of interest we pay on our fixed-rate Senior Notes, but can affect their fair values. As of September 30, 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 nine months ended September 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 $198.1 million, $28.2 million, and $17.2 million, respectively. If commodity prices had been 10 percent lower, our net derivative settlements for the nine months ended September 30, 2025, would have offset the declines in oil, gas, and NGL production revenue by approximately $77.9 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 September 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 $79.8 million, $31.7 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 nine months ended September 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 Nine Months Ended
	September 30, 2025		September 30, 2024		September 30, 2025		September 30, 2024



	(in thousands)
Net income (GAAP)	$	155,088	$	240,523	$	539,022	$	582,015
Interest expense	42,937		50,682		129,871		94,362
Interest income	(828)		(18,017)		(1,123)		(31,120)
Income tax expense	49,205		57,127		149,774		142,786
Depletion, depreciation, and amortization	325,372		202,942		888,262		548,781
Exploration (1)	10,042		10,759		34,460		44,121

Stock-based compensation expense	8,124		6,587		20,964		17,393
Net derivative gain	(45,479)		(86,283)		(106,571)		(70,256)
Net derivative settlement gain	38,867		16,491		86,363		46,288


Other, net	4,828		706		5,628		2,126
Adjusted EBITDAX (non-GAAP)	588,156		481,517		1,746,650		1,376,496
Interest expense	(42,937)		(50,682)		(129,871)		(94,362)
Interest income	828		18,017		1,123		31,120
Income tax expense	(49,205)		(57,127)		(149,774)		(142,786)
Exploration (1) (2)	(10,042)		(10,456)		(34,221)		(34,892)
Amortization of deferred financing costs	2,552		2,182		7,654		4,925
Deferred income taxes	75,686		45,615		145,149		116,522
Other, net	(7,510)		(8,843)		(12,755)		(36,945)
Net change in working capital	(52,568)		32,040		(14,867)		(15,433)
Net cash provided by operating activities (GAAP)	$	504,960	$	452,263	$	1,559,088	$	1,204,645

____________________________________________

(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 nine months ended September 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 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 third 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

Risks Related to the Pending Merger

The Company’s stockholders and Civitas’ stockholders, in each case as of immediately prior to the Merger, will have reduced ownership in the combined company.

Based on the number of issued and outstanding shares of Civitas common stock as of October 31, 2025, and the number of issued and outstanding Civitas equity awards currently estimated to be payable in shares of the Company’s common stock in connection with the Merger, the Company anticipates issuing approximately 126.3 million shares of Company common stock pursuant to the Merger Agreement. The actual number of shares of Company common stock to be issued pursuant to the Merger Agreement will be determined at the completion of the Merger based on the number of shares of Civitas common stock issued and outstanding immediately prior to such time and the number of issued and outstanding Civitas equity awards payable in shares of Company common stock in connection with the Merger. The issuance of these new shares could have the effect of depressing the market price of the Company’s common stock, through dilution of earnings per share or otherwise. Any dilution of, or delay of any accretion to, the Company’s earnings per share could cause the price of the Company’s common stock to decline or increase at a reduced rate.

The consummation of the Merger is subject to a number of conditions that may not be satisfied or completed on a timely basis or at all. Accordingly, there can be no assurance as to when or if the Merger will be completed, and the failure to complete the Merger could have a material adverse effect on our business, financial condition, or results of operations.

Although we expect to complete the Merger in the first quarter of 2026, there can be no assurances as to the exact timing of the closing or that the Merger will be completed at all. The consummation of the Merger is subject to the satisfaction or waiver of a number of conditions contained in the related Merger Agreement, including, among others, approval by the Company’s and Civitas’ shareholders and the receipt of required regulatory approvals. Such conditions, some of which are beyond our control, may not be satisfied or waived in a timely manner or at all and therefore make the completion and timing of the Merger uncertain. In addition, the Merger Agreement contains certain termination rights for both parties, which if exercised will also result in the Merger not being consummated. Any such termination or any failure to otherwise complete the Merger could result in various consequences, including, among others: our business being adversely impacted by the failure to pursue other beneficial opportunities due to the time and resources committed by our management to the Merger, without realizing any of the benefits of completing the Merger; being required to pay our legal, accounting and other expenses relating to the Merger; the market price of our common stock being adversely impacted to the extent that the current market price reflects a market assumption that the Merger will be completed; and negative reactions from the financial markets and customers that may occur if the anticipated benefits of the Merger are not realized. Such consequences could have a material adverse effect on our business, financial condition, or results of operations.

The Merger Agreement restricts the Company's ability to pursue alternatives to the Merger.

The Merger Agreement contains provisions that restrict the ability of the Company to undertake certain business combinations with a party other than Civitas. In addition, the Company will be required to pay a termination fee of approximately $79.0 billion to Civitas if (i) the Merger Agreement is terminated by Civitas because the Company materially breached the terms of the Merger Agreement, (ii) an acquisition proposal or offer for a competing transaction had been publicly announced or communicated to the Company’s stockholders or board of directors between the signing and termination of the Merger Agreement and (iii) the Company engages in certain competing transactions within 12 months after the termination of the Merger Agreement.

Even if the Merger is completed, we may be unable to successfully integrate Civitas’ business into our business or achieve the anticipated benefits of the Merger, which may have a material adverse effect on our business, financial condition or results of operations.

The success of the Merger depends in part on whether we can complete the integration of the Civitas assets that we have not previously operated into our existing business in an efficient and effective manner, and there can be no assurance that we will be able to successfully integrate or otherwise realize the anticipated benefits of the Merger. The integration process may result in the disruption of ongoing business and there could be potential unknown liabilities and unforeseen expenses associated with the Merger that were not discovered in the course of performing due diligence. The integration may also require significant time and focus from management following the Merger that may disrupt our business and results of operations. Potential risks or difficulties include, among others:

•complexities associated with integrating our existing complex systems, technologies and other workflows with new assets;

•the inability to retain the services of key management and personnel;

•the accuracy of our assessments of the assets acquired in the Merger, including recoverable reserves, transportation costs and availability, drilling and completion equipment cost and availability, regulatory, permitting, and related matters;

•establishing business relationships with new third party contractors and other service providers with whom we have no prior experience; and

•potential unknown liabilities and unforeseen expenses, delays or regulatory conditions associated with the Merger.

Any of these issues could adversely affect our ability to maintain relationships with customers, suppliers, employees, and other constituencies. We may fail to realize the anticipated benefits expected from the Merger. The success of the Merger will depend, in significant part, on our ability to successfully complete the integration of the acquired assets, grow the revenue, and realize the anticipated strategic benefits from the Merger. The anticipated benefits of the Merger may not be realized fully or at all or may take longer to realize than expected. Actual operating, technological, strategic, and revenue opportunities, if achieved at all, may be less significant than expected or may take longer to achieve than anticipated. If we are not able to realize the anticipated benefits expected from the Merger within the anticipated timing or at all, our business and operating results may be adversely affected.

We have incurred additional costs in connection with the Merger, which will continue during 2025 and for a portion of 2026.

During the three months ended September 30, 2025, we incurred non-recurring costs associated with the Merger, and we expect to continue to incur such costs during 2025 and for a portion of 2026. A substantial majority of non-recurring expenses consist of transaction costs and include, among others, fees paid to financial, legal, accounting, and other advisors. Although we expect that the elimination of any duplicative costs, as well as the realization of expected benefits related to the integration of the Civitas assets, should allow us to offset these transaction costs over time, this net benefit may not be achieved in the near term or at all.

Securities class action and derivative lawsuits may be brought against us in connection with the Merger, which could result in substantial costs.

Securities class action lawsuits and derivative lawsuits are often brought against public companies that have entered into acquisition, merger, or other business combination agreements. Even if such a lawsuit is without merit, defending against these claims can result in substantial costs and divert management time and resources. An adverse judgment could result in monetary damages, which could have a negative impact on our liquidity and financial condition.

There have been no other 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

The following table provides information about purchases made by us and any affiliated purchaser (as defined in Rule 10b-18(a)(3) under the Exchange Act) during the three months ended September 30, 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:


PURCHASES OF EQUITY SECURITIES BY ISSUER AND AFFILIATED PURCHASERS
Period	Total Number of Shares Purchased (1)	Weighted Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Program (2)	Maximum Number or Approximate Dollar Value of Shares that May Yet Be Purchased Under the Program (as of the period end date) (2)
07/01/2025 - 07/31/2025	183,823	$	24.71	—	$	500,000,000
08/01/2025 - 08/31/2025	144,705	$	27.88	144,705	$	495,965,431
09/01/2025 - 09/30/2025	304,240	$	26.94	300,000	$	487,881,090
Total:	632,768	$	26.51	444,705

___________________________________

(1) 188,063 shares purchased by us in the third quarter of 2025 were to offset tax withholding obligations that occurred upon the delivery of outstanding shares underlying RSUs and PSUs issued under the terms of award agreements granted under the Equity Plans.

(2) 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 September 30, 2025, we repurchased and subsequently retired 444,705 shares of our common stock under the Stock Repurchase Program at a weighted-average share price of $27.25 for a total cost of $12.1 million, excluding excise taxes, commissions, and fees.

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)
10.2†			Form of Restricted Stock Unit Award Agreement dated as of July 1, 2025 (filed as Exhibit 10.2 to the registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2025, and incorporated herein by reference)
10.3†			Form of Performance Share Unit Award Agreement dated as of July 1, 2025 (filed as Exhibit 10.3 to the registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2025, and incorporated herein by reference)
10.4			Third Amendment to Seventh Amended and Restated Credit Agreement, dated as of October 13, 2025, by and among SM Energy Company, a Delaware corporation, each of the Lenders that is a party thereto, and Wells Fargo Bank, National Association, as administrative agent for the Lenders, the Issuing Banks and the Swingline Lender (file d as Exhibit 10.1 to the registrant ’s Current Report on Form 8-K filed on October 1 6 , 2025, and incorporated herein by reference)
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

November 3, 2025	By:	/s/ HERBERT S. VOGEL
		Herbert S. Vogel
		Chief Executive Officer
		(Principal Executive Officer)

November 3, 2025	By:	/s/ A. WADE PURSELL
		A. Wade Pursell
		Executive Vice President and Chief Financial Officer
		(Principal Financial Officer)

November 3, 2025	By:	/s/ ALAN D. BENNETT
		Alan D. Bennett
		Vice President - Controller
		(Principal Accounting Officer)