UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

________________________________________

FORM 10-Q

________________________________________

(Mark One)


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

For the quarterly period ended ~~September~~ 30March 31, ~~2025~~2026


☐	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: 001-32886

____________________________________

CONTINENTAL RESOURCES, INC

(Exact name of registrant as specified in its charter)

____________________________________

(405) 234-9000

(Registrant’s telephone number, including area code)

Not Applicable

(Former name, former address and former fiscal year, if changed since last report)

Securities registered pursuant to Section 12(b) of the Act: None

____________________________________

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 x

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 x 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	x	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 x

As of ~~September~~March 3031, ~~2025~~2026, there are no publicly traded common shares of Continental Resources, Inc.

Table of Contents

PART I. Financial Information
Item 1.	Financial Statements	1
	Unaudited Condensed Consolidated Balance Sheets	1
	Unaudited Condensed Consolidated Statements of Income	2
	Unaudited Condensed Consolidated Statements of Income (Loss)	2
	Unaudited Condensed Consolidated Statements of Equity	3
	Unaudited Condensed Consolidated Statements of Cash Flows	4
	Notes to Unaudited Condensed Consolidated Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	14
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	2321
Item 4.	Controls and Procedures	2422
PART II. Other Information
Item 1.	Legal Proceedings	2523
Item 1A.	Risk Factors	2523
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	2523
Item 3.	Defaults Upon Senior Securities	2523
Item 4.	Mine Safety Disclosures	2523
Item 5.	Other Information	2523
Item 6.	Exhibits	2624
	Signature	2725
When we refer to “us,” “we,” “our,” “Company,” or “Continental” we are describing Continental Resources, Inc. and our subsidiaries.

Glossary of Crude Oil and Natural Gas Terms

The terms defined in this section may be used throughout this report:

“Bbl” One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil, condensate or natural gas liquids.

“Boe” Barrels of crude oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of crude oil based on the average equivalent energy content of the two commodities.

“Btu” British thermal unit, which represents the amount of energy needed to heat one pound of water by one degree Fahrenheit and can be used to describe the energy content of fuels.

“MBbl” One thousand barrels of crude oil, condensate or natural gas liquids.

“MBoe” One thousand Boe.

“Mcf” One thousand cubic feet of natural gas.

“MMBoe” One million Boe.

“MMBtu” One million British thermal units.

“MMcf” One million cubic feet of natural gas.

“NGL” or “NGLs” Refers to natural gas liquids, which are hydrocarbon products that are separated during natural gas processing and include ethane, propane, isobutane, normal butane, and natural gasoline.

“NYMEX” The New York Mercantile Exchange.

“proved reserves” The quantities of crude oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates renewal is reasonably certain.

Cautionary Statement for the Purpose of the “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995

This report and information incorporated by reference in this report include “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than statements of historical fact, including, but not limited to, forecasts or expectations regarding the Company’s business and statements or information concerning the Company’s future operations, performance, financial condition, production and reserves, schedules, plans, timing of development, rates of return, budgets, costs, business strategy, objectives, and cash flows, included in this report are forward-looking statements. The words “could,” “may,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project,” “budget,” “target,” “plan,” “continue,” “potential,” “guidance,” “strategy” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.

Forward-looking statements may include, but are not limited to, statements about:

•

our strategy;

•

our business and financial plans;

•

our future operations;

•

our proved reserves and related development plans;

•

technology;

•

future crude oil, natural gas liquids, and natural gas prices and differentials;

•

the timing and amount of future production of crude oil, natural gas liquids, and natural gas and flaring activities;

•

the amount, nature and timing of capital expenditures;

•

estimated revenues, expenses and results of operations;

•

drilling and completing of wells;

•

shutting in of production and the resumption of production activities;

•

competition;

•

marketing of crude oil, natural gas, and natural gas liquids;

•

transportation of crude oil, natural gas, and natural gas liquids to markets;

•

property exploitation, property acquisitions and dispositions, strategic investments, or joint domestic and foreign development opportunities;

•

costs of exploiting and developing our properties and conducting other operations, including any impacts from inflation;

•

our financial position;

•

the timing and amount of debt borrowings or repayments;

•

the timing and amount of income tax payments and payments the Company may be obligated to make pursuant to the stock redemption agreement described in Note 8. Commitments and Contingencies—Stock Redemption Agreement;

•

current and potential litigation matters;

•

geopolitical events and conditions in, or affecting other, crude oil-producing and natural gas-producing nations, including foreign jurisdictions where the Company may explore resource development opportunities;

•

credit markets;

•

our liquidity and access to capital;

•

the impact of U.S. and foreign governmental policies, laws, regulations, tariffs in the ~~United~~U.S. ~~States~~ and foreign jurisdictions, as well as regulatory and legal proceedings involving us and of scheduled or potential regulatory or legal changes in these areas;

•

our future operating and financial results;

•

our future commodity or other hedging arrangements; and

•

the ability and willingness of current or potential lenders, hedging contract counterparties, customers, and working interest owners to fulfill their obligations to us or to enter into transactions with us in the future on terms that are acceptable to us.

Forward-looking statements are based on the Company’s current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes these assumptions and expectations are reasonable, they are inherently subject to numerous business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company’s control. No assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate or will not change over time. The risks and

uncertainties that may affect the operations, performance and results of the business and forward-looking statements include, but are not limited to, those risk factors and other cautionary statements described under Part II, Item 1A. Risk Factors and elsewhere in this report, if any, our Annual Report on Form 10-K for the year ended December 31, ~~2024~~2025, and other announcements we make from time to time.

Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date on which such statement is made. Additionally, new factors emerge from time to time, and it is not possible for us to predict all such factors. Should one or more of the risks or uncertainties described in this report or our Annual Report on Form 10-K for the year ended December 31, ~~2024~~2025 occur, or should underlying assumptions prove incorrect, the Company’s actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by this cautionary statement.

Except as expressly stated above or otherwise required by applicable law, the Company undertakes no obligation to publicly correct or update any forward-looking statement whether as a result of new information, future events or circumstances after the date of this report, or otherwise.

iii

PART I. Financial Information

ITEM 1. Financial Statements

Continental Resources, Inc. and Subsidiaries

Unaudited Condensed Consolidated Balance Sheets

In thousands, except par values and share data	~~September~~March 3031, ~~2025~~2026		~~December 31, 2024~~	December 31, 2025
Assets
Current assets:
Cash and cash equivalents	$~~1,102,907~~	1,604,396	~~$39,064~~	$	1,375,861
Accounts receivable, net	~~1,461,991~~	1,580,193	~~1,553,919~~		1,406,796
Derivative assets	~~248,272~~	204,536	~~95,227~~		324,706
Inventories	~~227,245~~	262,923	~~184,251~~		227,407
Prepaid expenses and other	159,855		32,648
Income taxes receivable		400,933			58,762
Total current assets	3,200,270		1,905,109
Prepaid expenses and other		44,717			39,634
Net property and equipment, based on successful efforts method of accounting	20,533,367		20,037,922
Total current assets		4,097,698			3,433,166
Investment in unconsolidated affiliates	259,426		258,359
Net property and equipment, based on successful efforts method of accounting		20,862,859			20,656,908
Operating lease right-of-use assets	31,941		20,933
Investment in unconsolidated affiliates		313,658			261,333
Derivative assets, noncurrent	~~39,120~~	51,824	~~62,426~~		61,528
Other noncurrent assets	~~18,574~~	277,411	~~20,832~~		109,227
Total assets	$~~24,082,698~~	25,603,450	~~$22,305,581~~	$	24,522,162
Liabilities and equity
Current liabilities:
Accounts payable trade	$~~826,849~~	765,997	~~$845,160~~	$	700,669
Revenues and royalties payable	~~731,113~~	875,563	~~682,461~~		718,631
Accrued liabilities and other	~~317,673~~	360,152	~~413,036~~		410,554
Current portion of incentive compensation liability	66,016		74,494
Current portion of income tax liabilities		24			519
Current portion of income tax liabilities	1,808		21,659
Derivative liabilities		732,266			—
Derivative liabilities	—		—
Current portion of long-term debt		799,003			798,609
Current portion of operating lease liabilities	9,996		4,046
Total current liabilities		3,533,005			2,628,982
Current portion of long-term debt	—		2,587
Long-term debt, net of current portion		4,116,786			3,973,437
Total current liabilities	1,953,455		2,043,443
Other noncurrent liabilities:
Long-term debt, net of current portion	4,770,584		4,798,860
Deferred income tax liabilities, net		3,267,531			3,046,707
Other noncurrent liabilities:
Asset retirement obligations, noncurrent		511,563			505,382
Deferred income tax liabilities, net	2,987,357		2,704,069
Derivative liabilities, noncurrent		136,740			4,905
Incentive compensation liability, noncurrent	15,568		36,468
Other noncurrent liabilities		191,108			67,697
Asset retirement obligations, noncurrent	459,954		432,495
Total other noncurrent liabilities		4,106,942			3,624,691
Derivative liabilities, noncurrent	24,097		143
Commitments and contingencies (Note 8)
Operating lease liabilities, noncurrent	20,946		15,823
Equity:
Other noncurrent liabilities	32,449		48,783
Preferred stock, $0.01 par value: 25,000,000 shares authorized; no shares issued and outstanding		—			—
Total other noncurrent liabilities	3,540,371		3,237,781
Common stock, $0.01 par value: 400,000 shares authorized (187,256 shares issued) of Class A voting common stock and 400,000,000 shares authorized (299,423,011 shares issued) of Class B non-voting common stock		2,996			2,996
Commitments and contingencies (Note 8)
Retained earnings		13,499,729			13,940,956
Equity:
Total shareholders’ equity attributable to Continental Resources		13,502,725			13,943,952
Preferred stock, $0.01 par value: 25,000,000 shares authorized; no shares issued and outstanding	—		—
Noncontrolling interests		343,992			351,100
Common stock, $0.01 par value: 400,000 shares authorized (187,256 shares issued) of Class A voting common stock and 400,000,000 shares authorized (299,423,011 shares issued) of Class B non-voting common stock	2,996		2,996
Total equity		13,846,717			14,295,052
Retained earnings	13,461,688		11,862,515
Total liabilities and equity	$	25,603,450		$	24,522,162
Total shareholders’ equity attributable to Continental Resources	13,464,684		11,865,511
Noncontrolling interests	353,604		359,986
Total equity	13,818,288		12,225,497
Total liabilities and equity	$24,082,698		$22,305,581

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

Continental Resources, Inc. and Subsidiaries

Unaudited Condensed Consolidated Statements of Income (Loss)

	Three months ended September 30,						Nine months ended September 30,
	Three months ended March 31,
In thousands	~~2025~~2026			~~2024~~2025			~~2025~~			~~2024~~
Revenues:
Crude oil, natural gas, and natural gas liquids sales	$	1,~~824~~847,~~572~~583		$	1,~~711~~890,~~932~~207		$	~~5,341,153~~		$	~~5,523,563~~
Gain on derivative instruments, net		184,195			270,001			319,447			161,536
Loss on derivative instruments, net		(1,108,124	)		(316,002	)
Crude oil and natural gas service operations		3638,~~976~~588			2436,~~207~~248			~~106,974~~			~~68,532~~
Total revenues		2778,~~045,743~~047			21,~~006~~610,~~140~~453			~~5,767,574~~			~~5,753,631~~
Operating costs and expenses:
Production expenses		~~221~~210,~~620~~839			~~193~~199,~~838~~379			~~622,444~~			~~565,212~~
Production and ad valorem taxes		~~134~~129,~~233~~035			~~131~~135,~~753~~349			~~389,004~~			~~428,252~~
Transportation, gathering, processing, and compression		8782,~~958~~488			8978,~~206~~873			~~242,676~~			~~288,603~~
Exploration expenses		47,~~791~~728			32,~~900~~732			~~11,420~~			~~10,990~~
Crude oil and natural gas service operations		3035,~~047~~481			2023,~~318~~880			~~78,816~~			~~69,673~~
Depreciation, depletion, amortization and accretion		~~697~~679,~~474~~236			613,~~940~~560			~~1,943,602~~			~~1,873,282~~
Property impairments		1214,~~826~~144			1217,~~532~~022			~~45,674~~			~~34,718~~
General and administrative expenses		63118,~~582~~793			6467,~~630~~012			~~187,109~~			~~211,554~~
Net loss on sale of assets and other		1,174			3,439			7,446			37,971
Net (gain) loss on sale of assets and other		(1,752	)		3,129
Total operating costs and expenses		1,~~253~~275,~~705~~992			1,~~133~~140,~~556~~936			~~3,528,191~~			~~3,520,255~~
Income from operations		792,038			872,584			2,239,383			2,233,376
Income (loss) from operations		(497,945	)		469,517
Other income (expense):
Interest expense		(54,~~190~~279	)		(6355,~~677~~143	)		~~(163,573~~	)		~~(215,313~~	)
Loss on extinguishment of debt		—			—			(57	)		(1,600	)
Other		13,389			3,617
Other		8,175			49,449			19,311			(331,632	)
		(40,890	)		(51,526	)
		(46,015	)		(14,228	)		(144,319	)		(548,545	)
Income (loss) before income taxes		(538,835	)		417,991
Income before income taxes		746,023			858,356			2,095,064			1,684,831
Benefit (provision) for income taxes		123,432			(86,380	)
Provision for income taxes		(188,400	)		(138,470	)		(469,971	)		(401,059	)
Income (loss) before equity in net loss of affiliate		(415,403	)		331,611
Income before equity in net loss of affiliate		557,623			719,886			1,625,093			1,283,772
Equity in net loss of affiliate		(24,025	)		(12,887	)
Equity in net loss of affiliate		(32	)		(769	)		(14,447	)		(2,981	)
Net income (loss)		(439,428	)		318,724
Net income		557,591			719,117			1,610,646			1,280,791
Net income attributable to noncontrolling interests		1,799			2,718
Net income attributable to noncontrolling interests		1,625			60			11,475			333
Net income (loss) attributable to Continental Resources	$	(441,227	)	$	316,006
Net income attributable to Continental Resources	$	555,966		$	719,057		$	1,599,171		$	1,280,458

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

Continental Resources, Inc. and Subsidiaries

Unaudited Condensed Consolidated Statements of Equity

Three months ended September 30, 2025
Three Months Ended March 31, 2026
	Shareholders’ equity attributable to Continental Resources
In thousands, except share data	Sharesoutstanding		Commonstock		Retainedearnings			~~Total~~Totalshareholders’equity ofContinentalResources			Noncontrollinginterests			Total equity
Balance at June 30, 2025		299,610,267	$	2,996	$	12,905,722		$	12,908,718		$	355,128		$	13,263,846
Balance at December 31, 2025		299,610,267	$	2,996	$	13,940,956		$	13,943,952		$	351,100		$	14,295,052
Net income		—		—		555,966			555,966			1,625			557,591
Net income (loss)		—		—		(441,227	)		(441,227	)		1,799			(439,428	)
Contributions from noncontrolling interests		—		—		—			—			25,~~845~~271			25,~~845~~271
Distributions to noncontrolling interests		—		—		—			—			(514,~~994~~178	)		(514,~~994~~178	)
Balance at September 30, 2025		299,610,267	$	2,996	$	13,461,688		$	13,464,684		$	353,604		$	13,818,288
Balance at March 31, 2026		299,610,267	$	2,996	$	13,499,729		$	13,502,725		$	343,992		$	13,846,717

Nine months ended September 30, 2025
Three Months Ended March 31, 2025
	Shareholders’ equity attributable to Continental Resources
In thousands, except share data	Sharesoutstanding		Commonstock		Retainedearnings		~~Total~~Totalshareholders’equity ofContinentalResources		Noncontrollinginterests			Total equity
Balance at December 31, 2024		299,610,267	$	2,996	$	11,862,515	$	11,865,511	$	359,986		$	12,225,497
Net income		—		—		1316,~~599,171~~006		1316,~~599,171~~006		112,~~475~~718			1318,~~610,646~~724
Change in dividends payable		—		—		2		2		—			2
Contributions from noncontrolling interests		—		—		—		—		71,~~600~~740			71,~~600~~740
Distributions to noncontrolling interests		—		—		—		—		(2512,~~457~~774	)		(2512,~~457~~774	)
Balance at September 30, 2025		299,610,267	$	2,996	$	13,461,688	$	13,464,684	$	353,604		$	13,818,288
Balance at March 31, 2025		299,610,267	$	2,996	$	12,178,523	$	12,181,519	$	351,670		$	12,533,189

Three months ended September 30, 2024
	Shareholders’ equity attributable to Continental Resources
In thousands, except share data	Sharesoutstanding		Commonstock		Retainedearnings		Total		Noncontrollinginterests			Total equity
Balance at June 30, 2024		299,610,267	$	2,996	$	10,412,107	$	10,415,103	$	363,885		$	10,778,988
Net income		—		—		719,057		719,057		60			719,117
Change in dividends payable		—		—		20		20		—			20
Contributions from noncontrolling interests		—		—		—		—		2,149			2,149
Distributions to noncontrolling interests		—		—		—		—		(5,182	)		(5,182	)
Balance at September 30, 2024		299,610,267	$	2,996	$	11,131,184	$	11,134,180	$	360,912		$	11,495,092

Nine months ended September 30, 2024
	Shareholders’ equity attributable to Continental Resources
In thousands, except share data	Sharesoutstanding		Commonstock		Retainedearnings		Total		Noncontrollinginterests			Total equity
Balance at December 31, 2023		299,610,267	$	2,996	$	9,850,687	$	9,853,683	$	356,104		$	10,209,787
Net income		—		—		1,280,458		1,280,458		333			1,280,791
Change in dividends payable		—		—		39		39		—			39
Contributions from noncontrolling interests		—		—		—		—		21,745			21,745
Distributions to noncontrolling interests		—		—		—		—		(17,270	)		(17,270	)
Balance at September 30, 2024		299,610,267	$	2,996	$	11,131,184	$	11,134,180	$	360,912		$	11,495,092

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

Continental Resources, Inc. and Subsidiaries

Unaudited Condensed Consolidated Statements of Cash Flows

	Nine months ended September 30,
	Three months ended March 31,
In thousands	~~2025~~2026			~~2024~~2025
Cash flows from operating activities
Cash flows from operating activities:
Net income	$	1,610,646		$	1,280,791
Net income (loss)	$	(439,428	)	$	318,724
Adjustments to reconcile net income to net cash provided by operating activities:
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depreciation, depletion, amortization and accretion		1684,~~941,272~~861			1615,~~867,675~~028
Property impairments		4514,~~674~~144			3417,~~718~~022
Non-cash (gain) loss on derivatives		(105,785	)		125,161
Non-cash loss on derivatives, net		993,975			332,854
Provision (benefit) for deferred income taxes		283,288			(30,710	)
Net provision for deferred income taxes		220,770			2,039
Equity in net loss of affiliate		1424,~~447~~025			212,~~981~~887
Net loss on sale of assets and other		5,666			36,401
Net (gain) loss on sale of assets and other		(1,912	)		3,084
Loss on extinguishment of debt		57			1,600
Other, net		3,078			4,447
Other, net		11,753			379,049
Changes in assets and liabilities:
Accounts receivable		91(173,~~535~~004	)		~~250~~55,~~153~~962
Inventories		(4635,~~340~~529	)		(2,~~406~~702	)
Other current assets		(~~128~~5,~~870~~906	)		(9016,~~196~~310	)
Accounts payable trade		7593,~~364~~556			5336,~~685~~967
Revenues and royalties payable		47148,~~924~~154			~~(182~~98,~~764~~717	)
Accrued liabilities and other		~~(99~~5,~~206~~009	)		(13102,~~501~~376	)
Incentive compensation liability		(2971,~~377~~009	)		(7559,~~118~~329	)
Current income taxes liability		(19,851	)		(84,556	)
Current income taxes		(342,666	)		84,642
Other noncurrent assets and liabilities		~~(18~~1,~~500~~391	)		(~~18,855~~465	)
Net cash provided by operating activities		31,~~679~~119,~~697~~509			31,~~534~~401,~~108~~191
Cash flows from investing activities
Cash flows from investing activities:
Exploration and development		(2934,~~451,624~~336	)		(2774,~~142,748~~514	)
Purchase of producing crude oil and natural gas properties		(41,~~103~~685	)		~~(1,246~~—	)
Purchase of other property and equipment		(~~117~~58,~~785~~655	)		(~~161~~43,~~188~~480	)
Proceeds from sale of assets		25107,~~503~~201			~~467,048~~664
Contributions to unconsolidated affiliates		(152,~~515~~985	)		(216,~~473~~821	)
Net cash used in investing activities		(2890,~~563,524~~460	)		(1824,~~859,607~~151	)
Cash flows from financing activities
Cash flows from financing activities:
Credit facility borrowings		~~440,000~~—			3440,~~016,~~000
Repayment of credit facility		~~(460,000~~—	)		(3460,~~041,~~000	)
Redemption of senior notes		—			(893,126	)
Repayment of other debt		—			(640	)
Repayment of other debt		(15,220	)		(751,863	)
Debt issuance costs		—			(123	)
Debt issuance costs		(135	)		—
Contributions from noncontrolling interests		4,879			3,019
Contributions from noncontrolling interests		8,566			21,560
Distributions to noncontrolling interests		(5,393	)		(6,408	)
Distributions to noncontrolling interests		(24,913	)		(17,334	)
Dividends paid on common stock		—			(628	)
Dividends paid on common stock		(628	)		(2,342	)
Net cash used in financing activities		(514	)		(24,780	)
Net cash used in financing activities		(52,330	)		(1,668,105	)
Net change in cash and cash equivalents		228,535			552,260
Net change in cash and cash equivalents		1,063,843			6,396
Cash and cash equivalents at beginning of period		1,375,861			39,064
Cash and cash equivalents at beginning of period		39,064			26,397
Cash and cash equivalents at end of period	$	1,604,396		$	591,324
Cash and cash equivalents at end of period	$	1,102,907		$	32,793

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

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

Note 1. Organization and Nature of Business

Nature of Business

Continental Resources, Inc. (the “Company”) was formed in 1967 and is incorporated under the laws of the State of Oklahoma. The Company’s principal business is the exploration, development, management, and production of crude oil and natural gas and associated products with properties primarily located in four leading basins in the United States – the Bakken field of North Dakota and Montana, the Anadarko Basin of Oklahoma, the Permian Basin of Texas, and the Powder River Basin of Wyoming. In the first quarter of 2026 the Company expanded its operations internationally via the acquisition of assets within the Vaca Muerta shale play in Argentina's Neuquén Basin. As of March 31, 2026 our activities in Argentina have no production or revenues and represent an immaterial portion of our consolidated assets. Additionally, the Company pursues the acquisition and management of perpetually owned minerals ~~located~~ in ~~certain of~~ its key operating areas as well as opportunities to participate and contribute in the growing power generation sector such as the new venture described in Note 10. Equity Investment. For the ~~nine~~three months ended ~~September~~March 3031, ~~2025~~2026, crude oil accounted for 5550% of the Company’s total production and 8378% of its crude oil, natural gas, and natural gas liquids revenues.

Voluntary Filer

The Company is privately owned by its founder, Harold G. Hamm, certain members of his family and their affiliated entities (the “Hamm Family”). As of ~~September~~March 3031, ~~2025~~2026, the Hamm Family holds approximately 299.6 million shares of common stock of the Company. As a privately held company, certain of the corporate governance, disclosure, and other provisions applicable to a company with listed equity securities and reporting obligations under the Securities Exchange Act of 1934 do not apply to us. We continue to furnish Quarterly Reports on Form 10-Q and Annual Reports on Form 10-K with the SEC as required by our senior note indentures.

Note 2. Basis of Presentation and Significant Accounting Policies

Basis of presentation

The condensed consolidated financial statements include the accounts of the Company, its wholly-owned subsidiaries, and entities in which the Company has a controlling financial interest. Intercompany accounts and transactions have been eliminated upon consolidation. Noncontrolling interests reflected herein represent third party ownership in the net assets of consolidated subsidiaries. The portions of consolidated net income and equity attributable to the noncontrolling interests are presented separately in the Company’s financial statements.

Investments in entities in which the Company has the ability to exercise significant influence, but does not control, are accounted for using the equity method of accounting. In applying the equity method, the investments are initially recognized at cost and are subsequently adjusted for the Company's proportionate share of earnings, losses, contributions, and distributions as applicable.

The Company has one reportable segment due to the similar nature of its business, which is the exploration, development, and production of crude oil, natural gas, and natural gas liquids ~~in the United States~~. The Company’'s President and CEO is the chief operating decision maker and he reviews consolidated net income to assess performance and determine how to allocate resources. The measure of segment assets is reported on the consolidated balance sheets as total assets. As a single reportable segment entity, the financial information is contained in Part I. Item 1. Financial Statements.

This report has been prepared pursuant to rules and regulations applicable to interim financial information. Because this is an interim period filing presented using a condensed format, it does not include all disclosures required by accounting principles generally accepted in the United States (“U.S. GAAP”), although the Company believes the disclosures are adequate to make the information not misleading. You should read this Quarterly Report on Form 10-Q (“Form 10-Q”) together with the Company’s Annual Report on Form 10-K for the year ended December 31, ~~2024~~2025 (“~~2024~~2025 Form 10-K”), which includes a summary of the Company’s significant accounting policies and other disclosures.

The condensed consolidated financial statements as of September 30, 2025 and for the three and nine month periods ended September 30, 2025 and 2024 are unaudited. The condensed consolidated balance sheet as of December 31, 2024 was derived from

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

The condensed consolidated financial statements as of March 31, 2026 and for the three month periods ended March 31, 2026 and 2025 are unaudited. The condensed consolidated balance sheet as of December 31, 2025 was derived from the audited balance sheet included in the ~~2024~~2025 Form 10-K. The Company evaluated its ~~September~~March 3031, ~~2025~~2026 financial statements for subsequent events through ~~November~~May 411, ~~2025~~2026, the date the financial statements were available to be issued.

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure and estimation of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting periods. Actual results may differ from those estimates. The most significant estimates and assumptions impacting reported results are estimates of the Company’s crude oil and natural gas reserves, which are used to compute depreciation, depletion, amortization and impairment of proved crude oil and natural gas properties. In the opinion of management, all adjustments (consisting only of normal recurring adjustments) necessary for a fair statement in accordance with U.S. GAAP have been included in these unaudited condensed consolidated financial statements. The results of operations for any interim period are not necessarily indicative of the results of operations that may be expected for any other interim period or for an entire year.

Note 3. Supplemental Cash Flow Information

The following table discloses supplemental cash flow information about cash paid for interest and income tax payments and refunds. Also disclosed is information about investing activities that affects recognized assets and liabilities but does not result in cash receipts or payments.

	Nine months ended September 30,
	Three months ended March 31,
In thousands	~~2025~~2026		~~2024~~2025
Supplemental cash flow information:
Cash paid for interest	$	~~168~~65,~~935~~000	$	~~227~~66,~~609~~136
Cash paid for income taxes		~~315,605~~—		~~614,401~~—
Cash received for income tax refunds		~~302~~1,559		~~3,266~~302
Non-cash investing activities:
Asset retirement obligation additions and revisions, net		131,~~092~~790		152,~~785~~895

As of ~~September~~March 3031, ~~2025~~2026 and December 31, ~~2024~~2025, the Company had $~~270~~216.24 million and $~~376~~251.48 million, respectively, of accrued capital expenditures included in “Net property and equipment” with an offsetting amount in “Accounts payable trade” in the consolidated balance sheets. See Note 10. Equity Investment for discussion of a promissory note borrowing and related investment which were transacted on a non-cash basis in March 2026.

Note 4. Revenues

The following table presents the disaggregation of the Company's crude oil and natural gas revenues by operating area for the three months ended March 31, 2026 and 2025. Sales of natural gas and NGLs are combined, as a substantial majority of the Company's natural gas sales contracts represent wellhead sales of unprocessed gas.


	Three months ended March 31, 2026						Three months ended March 31, 2025
In thousands	Crude Oil		Natural Gas and NGLs		Total		Crude Oil		Natural Gas and NGLs		Total
Bakken	$	715,587	$	141,825	$	857,412	$	726,496	$	139,269	$	865,765
Anadarko Basin		203,126		233,458		436,584		233,499		204,320		437,819
Powder River Basin		145,129		13,480		158,609		113,230		19,258		132,488
Permian Basin		350,896		17,557		368,453		382,250		41,181		423,431
All other		26,517		8		26,525		30,681		23		30,704
Crude oil, natural gas, and natural gas liquids sales	$	1,441,255	$	406,328	$	1,847,583	$	1,486,156	$	404,051	$	1,890,207

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

Note 4. Revenues

The following table presents the disaggregation of the Company's crude oil and natural gas revenues by operating area for the three and nine months ended September 30, 2025 and 2024. Sales of natural gas and NGLs are combined, as a substantial majority of the Company's natural gas sales contracts represent wellhead sales of unprocessed gas.

	Three months ended September 30, 2025						Three months ended September 30, 2024
In thousands	Crude Oil		Natural Gasand NGLs		Total		Crude Oil		Natural Gasand NGLs		Total
Bakken	$	822,304	$	53,658	$	875,962	$	835,950	$	51,336	$	887,286
Anadarko Basin		210,291		151,578		361,869		213,883		112,981		326,864
Powder River Basin		102,644		12,609		115,253		92,570		8,429		100,999
Permian Basin		407,228		37,159		444,387		349,384		11,537		360,921
All other		27,096		5		27,101		35,838		24		35,862
Crude oil, natural gas, and natural gas liquids sales	$	1,569,563	$	255,009	$	1,824,572	$	1,527,625	$	184,307	$	1,711,932

	Nine months ended September 30, 2025						Nine months ended September 30, 2024
In thousands	Crude Oil		Natural Gasand NGLs		Total		Crude Oil		Natural Gasand NGLs		Total
Bakken	$	2,272,097	$	263,090	$	2,535,187	$	2,634,637	$	192,682	$	2,827,319
Anadarko Basin		622,056		512,736		1,134,792		729,908		386,280		1,116,188
Powder River Basin		313,059		40,906		353,965		315,112		30,864		345,976
Permian Basin		1,125,193		102,540		1,227,733		1,073,837		42,798		1,116,635
All other		89,443		33		89,476		117,371		74		117,445
Crude oil, natural gas, and natural gas liquids sales	$	4,421,848	$	919,305	$	5,341,153	$	4,870,865	$	652,698	$	5,523,563

Note 5. Derivative Instruments

From time to time the Company enters into crude oil and natural gas derivative contracts to economically hedge against the variability in cash flows associated with future sales of production. The Company recognizes its derivative instruments on the balance sheet as either assets or liabilities measured at fair value. The estimated fair value is based upon various factors as described in Note 6. Fair Value Measurements.

At ~~September~~March 3031, ~~2025~~2026 the Company had outstanding crude oil and natural gas derivative contracts as set forth in the tables below.

Natural gas derivatives
				Weighted Average Hedge Price ($/MMBtu)
Period and Type of Contract	Average Volumes Hedged			Basis Swaps			Fixed Swaps		~~Floor~~		~~Ceiling~~
October 2025 - March 2026
April 2026 - December 2026
Collars - Henry Hub		304,000	MMBtus/day						$	4.25	$	5.99
Swaps - Henry Hub		771,000	MMBtus/day				$	4.14
October 2025 - December 2025
Basis Swaps - WAHA		117,000	MMBtus/day	$	(1.78	)
Swaps - Henry Hub		580,000	MMBtus/day				$	3.95
January 2027 - March 2027
January 2026 - December 2026
Basis Swaps - WAHA		120,000	MMBtus/day	$	(0.90	)
Swaps - Henry Hub		737,000	MMBtus/day				$	4.13
January 2027 - December 2027
Basis Swaps - WAHA		112,500	MMBtus/day	$	1.80
Swaps - Henry Hub		647,000	MMBtus/day				$	3.94
January 2027 - March 2027
January 2028 - December 2028
Basis Swaps - WAHA		120,000	MMBtus/day	$	0.90
Swaps - Henry Hub		50,000	MMBtus/day				$	3.80
January 2027 - December 2027
Swaps - Henry Hub		647,000	MMBtus/day				$	3.94


Crude oil derivatives
				Weighted Average Hedge Price ($/Bbl)
Period and Type of Contract	Average Volumes Hedged				Roll Swaps		Fixed Swaps		Floor		Ceiling
April 2026 - December 2026
Fixed Swaps - WTI		122,000	Bbls/day				$	64.28
Collars - WTI		33,000	Bbls/day						$	60.00	$	69.38
Roll Swaps - WTI		52,000	Bbls/day		$	1.45
January 2027 - December 2027
Fixed Swaps - WTI		58,000	Bbls/day				$	62.40
January 2028 - December 2028
Fixed Swaps - WTI		20,000	Bbls/day				$	61.42

Derivative gains and losses

Cash receipts and payments in the following table reflect the gains or losses on crude oil and natural gas derivative contracts which matured during the applicable period, calculated as the difference between the contract price and the market settlement price of matured contracts. The Company's derivative contracts are settled based upon reported settlement prices on commodity exchanges, with crude oil derivative settlements based on NYMEX West Texas Intermediate (“WTI”) pricing and natural gas derivative settlements based primarily on NYMEX Henry Hub pricing. Non-cash gains and losses below represent the change in fair value of crude oil and natural gas derivative instruments which continued to be held at period end and the reversal of previously recognized non-cash gains or losses on derivative contracts that matured during the period.

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

Crude oil derivatives
	Three months ended March 31,
						Weighted Average Hedge Price ($/Bbl)
In thousands	2026			2025
Period and Type of Contract	Average Volumes Hedged					Roll Swaps		Fixed Swaps		Floor		Ceiling
Cash received (paid) on derivatives:
October 2025 - December 2025
Crude oil fixed price swaps	$	(70,982	)	$	9,252
Fixed Swaps - WTI		59,000		Bbls/day				$	70.63
Crude oil collars		(22,113	)		—
Collars - WTI		55,000		Bbls/day						$	60.00	$	68.27
Crude oil NYMEX roll swaps		—			669
Roll Swaps - NYMEX		53,000		Bbls/day		$	0.95
Natural gas fixed price swaps		(48,246	)		6,931
January 2026 - December 2026
Natural gas collars		(429	)		—
Fixed Swaps - WTI		55,000		Bbls/day				$	62.17
Natural gas WAHA basis swaps		27,621			—
Collars - WTI		33,000		Bbls/day						$	60.00	$	69.38
Cash received (paid) on derivatives, net		(114,149	)		16,852
January 2027 - December 2027
Non-cash gain (loss) on derivatives:
Fixed Swaps - WTI		19,000		Bbls/day				$	64.52
Crude oil fixed price swaps		(858,627	)		(9,550	)
Crude oil collars		(180,271	)		(47,565	)
Crude oil NYMEX roll swaps		(33,931	)		3,867
Natural gas fixed price swaps		75,043			(287,165	)
Natural gas collars		(16,702	)		7,559
Natural gas WAHA basis swaps		20,513			—
Non-cash loss on derivatives, net		(993,975	)		(332,854	)
Loss on derivative instruments, net	$	(1,108,124	)	$	(316,002	)

~~Derivative~~Balance ~~gains~~sheet offsetting of derivative assets and ~~losses~~liabilities

~~Cash~~The ~~receipts~~Company’s ~~and~~crude ~~payments~~oil inand ~~the~~natural ~~following~~gas ~~table reflect the gains or losses on~~ derivative contracts ~~which~~are ~~matured~~recorded ~~during~~at ~~the~~fair ~~applicable~~value ~~period,~~in ~~calculated as~~ the ~~difference~~condensed ~~between~~consolidated ~~the~~balance ~~contract~~sheets ~~price~~under ~~and~~ the ~~market~~captions ~~settlement~~“Derivative ~~price~~assets,” of“Derivative ~~matured~~assets, ~~contracts. The Company's derivative contracts are settled based upon reported settlement prices on commodity exchanges~~noncurrent,” ~~with crude oil derivative settlements based on NYMEX West Texas Intermediate (~~“~~WTI~~Derivative liabilities,”) ~~pricing~~ and ~~natural~~“Derivative ~~gas~~liabilities, ~~derivative~~noncurrent” ~~settlements~~as ~~based primarily on NYMEX Henry Hub pricing~~applicable. ~~Non-cash~~Derivative ~~gains~~assets and ~~losses~~liabilities ~~below~~with ~~represent~~ the ~~change~~same incounterparty ~~fair~~that ~~value~~are ofsubject ~~derivative instruments which continued~~ to becontractual ~~held~~terms atwhich ~~period~~provide ~~end~~for ~~and~~net ~~the~~settlement ~~reversal~~are ofreported ~~previously recognized non-cash gains or losses~~ on ~~derivative~~a ~~contracts~~net ~~that~~basis ~~matured~~in ~~during~~ the ~~period~~consolidated balance sheets.

	Three months ended September 30,						Nine months ended September 30,
In thousands	2025			2024			2025			2024
Cash received (paid) on derivatives:
Crude oil fixed price swaps	$	30,613		$	18,258		$	76,743		$	3,410
Crude oil collars		(6	)		—			(34	)		—
Crude oil NYMEX roll swaps		(2,042	)		(1,957	)		349			76
Natural gas WAHA fixed price swaps		—			13,262			—			40,184
Natural gas fixed price swaps		47,062			74,480			81,201			226,958
Natural gas collars		32,950			—			55,403			16,069
Cash received on derivatives, net		108,577			104,043			213,662			286,697
Non-cash gain (loss) on derivatives:
Crude oil fixed price swaps		(31,902	)		113,723			75,073			(53,757	)
Crude oil collars		(6,125	)		—			35,657			—
Crude oil NYMEX roll swaps		2,588			1,851			2,197			(6,825	)
Natural gas WAHA fixed price swaps		—			(8,348	)		—			(21,523	)
Natural gas WAHA basis swaps		6,056			—			6,056			—
Natural gas fixed price swaps		106,510			58,732			(56,724	)		(31,133	)
Natural gas collars		(1,509	)		—			43,526			(11,923	)
Non-cash gain (loss) on derivatives, net		75,618			165,958			105,785			(125,161	)
Gain on derivative instruments, net	$	184,195		$	270,001		$	319,447		$	161,536

The following table presents the gross amounts of recognized crude oil and natural gas derivative assets and liabilities, as applicable, the amounts offset under netting arrangements with counterparties, and the resulting net amounts presented in the condensed consolidated balance sheets for the periods presented, all at fair value.


In thousands	March 31, 2026			December 31, 2025
Commodity derivative assets:
Gross amounts of recognized assets	$	273,386		$	392,348
Gross amounts offset on balance sheet		(17,026	)		(6,114	)
Net amounts of assets on balance sheet		256,360			386,234
Commodity derivative liabilities:
Gross amounts of recognized liabilities		(886,032	)		(11,019	)
Gross amounts offset on balance sheet		17,026			6,114
Net amounts of liabilities on balance sheet	$	(869,006	)	$	(4,905	)

The following table reconciles the net amounts disclosed above to the individual financial statement line items in the condensed consolidated balance sheets.


In thousands	March 31, 2026			December 31, 2025
Derivative assets	$	204,536		$	324,706
Derivative assets, noncurrent		51,824			61,528
Net amounts of assets on balance sheet		256,360			386,234
Derivative liabilities		(732,266	)		—
Derivative liabilities, noncurrent		(136,740	)		(4,905	)
Net amounts of liabilities on balance sheet		(869,006	)		(4,905	)
Total derivative assets (liabilities), net	$	(612,646	)	$	381,329

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

Balance sheet offsetting of derivative assets and liabilities

The Company’s derivative contracts are recorded at fair value in the condensed consolidated balance sheets under the captions “Derivative assets,” “Derivative assets, noncurrent,” “Derivative liabilities,” and “Derivative liabilities, noncurrent” as applicable. Derivative assets and liabilities with the same counterparty that are subject to contractual terms which provide for net settlement are reported on a net basis in the consolidated balance sheets.

The following table presents the gross amounts of recognized derivative assets and liabilities, as applicable, the amounts offset under netting arrangements with counterparties, and the resulting net amounts presented in the consolidated balance sheets for the periods presented, all at fair value.

In thousands	September 30, 2025			December 31, 2024
Commodity derivative assets:
Gross amounts of recognized assets	$	296,772		$	168,023
Gross amounts offset on balance sheet		(9,380	)		(10,370	)
Net amounts of assets on balance sheet		287,392			157,653
Commodity derivative liabilities:
Gross amounts of recognized liabilities		(33,477	)		(10,513	)
Gross amounts offset on balance sheet		9,380			10,370
Net amounts of liabilities on balance sheet	$	(24,097	)	$	(143	)

The following table reconciles the net amounts disclosed above to the individual financial statement line items in the condensed consolidated balance sheets.

In thousands	September 30, 2025			December 31, 2024
Derivative assets	$	248,272		$	95,227
Derivative assets, noncurrent		39,120			62,426
Net amounts of assets on balance sheet		287,392			157,653
Derivative liabilities		—			—
Derivative liabilities, noncurrent		(24,097	)		(143	)
Net amounts of liabilities on balance sheet		(24,097	)		(143	)
Total derivative assets, net	$	263,295		$	157,510

Note 6. Fair Value Measurements

The Company's derivative instruments are reported at fair value on a recurring basis. In determining the fair values of swap contracts, a discounted cash flow method is used due to the unavailability of relevant comparable market data for the Company’s exact contracts. The discounted cash flow method estimates future cash flows based on quoted market prices for forward commodity prices and a risk-adjusted discount rate. The fair values of swap contracts are calculated mainly using significant observable inputs (Level 2). Calculation of the fair values of collars requires the use of an industry-standard option pricing model that considers various inputs including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. These assumptions are observable in the marketplace or can be corroborated by active markets or broker quotes and are therefore designated as Level 2 within the valuation hierarchy. The Company’s calculation of fair value for each of its crude oil and natural gas derivative positions is compared to the counterparty valuation for reasonableness.

The following tables summarize the valuation of crude oil and natural gas derivative instruments by pricing levels that were accounted for at fair value on a recurring basis as of March 31, 2026 and December 31, 2025.


	Fair value measurements at March 31, 2026 using:
In thousands	Level 1		Level 2			Level 3		Total
Derivative assets (liabilities):
Crude oil fixed price swaps	$	—	$	(710,685	)	$	—	$	(710,685	)
Crude oil collars		—		(121,456	)		—		(121,456	)
Crude oil NYMEX roll swaps		—		(33,931	)		—		(33,931	)
Natural gas fixed price swaps		—		195,796			—		195,796
Natural gas WAHA basis swaps		—		57,630			—		57,630
Total	$	—	$	(612,646	)	$	—	$	(612,646	)


	Fair value measurements at December 31, 2025 using:
In thousands	Level 1		Level 2		Level 3		Total
Derivative assets:
Crude oil fixed price swaps	$	—	$	147,943	$	—	$	147,943
Crude oil collars		—		58,815		—		58,815
Natural gas fixed price swaps		—		120,753		—		120,753
Natural gas collars		—		16,702		—		16,702
Natural gas WAHA basis swaps		—		37,116		—		37,116
Total	$	—	$	381,329	$	—	$	381,329

Note 7. Debt

The Company's debt, net of unamortized discounts, premiums, and debt issuance costs totaling $26.5 million and $28.0 million at March 31, 2026 and December 31, 2025, respectively, consists of the following.


In thousands	March 31, 2026		December 31, 2025
2.268% Senior Notes due 2026 (1)	$	799,003	$	798,609
4.375% Senior Notes due 2028		997,357		997,005
5.75% Senior Notes due 2031		1,489,467		1,488,995
2.875% Senior Notes due 2032		794,725		794,525
4.9% Senior Notes due 2044		692,972		692,912
Note Payable		142,265		—
Total debt	$	4,915,789	$	4,772,046
Less: Current portion of long-term debt		799,003		798,609
Long-term debt, net of current portion	$	4,116,786	$	3,973,437

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

(1) The ~~following~~Company’s ~~tables~~2026 ~~summarize~~Notes, ~~the~~which ~~valuation~~have ofa ~~derivative~~face ~~instruments~~value byof ~~pricing~~$800 ~~levels~~million ~~that~~at ~~were~~March ~~accounted~~31, ~~for~~2026, atare ~~fair~~scheduled ~~value~~to mature on November 15, 2026 and, accordingly, are included as a ~~recurring~~current ~~basis~~liability in the caption “Current portion of long-term debt” in the condensed consolidated balance sheets as of ~~September~~March 3031, ~~2025~~2026 and December 31, ~~2024~~2025.

	Fair value measurements at September 30, 2025 using:
In thousands	Level 1		Level 2		Level 3		Total
Derivative assets:
Crude oil fixed price swaps	$	—	$	87,606	$	—	$	87,606
Crude oil collars		—		35,657		—		35,657
Crude oil NYMEX roll swaps		—		2,197		—		2,197
Natural gas WAHA basis swaps		—		6,056		—		6,056
Natural gas fixed price swaps		—		88,253		—		88,253
Natural gas collars		—		43,526		—		43,526
Total	$	—	$	263,295	$	—	$	263,295

	Fair value measurements at December 31, 2024 using:
In thousands	Level 1		Level 2		Level 3		Total
Derivative assets:
Crude oil fixed price swaps	$	—	$	12,533	$	—	$	12,533
Natural gas fixed price swaps		—		144,977		—		144,977
Total	$	—	$	157,510	$	—	$	157,510

Note 7. Debt

The Company's debt, net of unamortized discounts, premiums, and debt issuance costs totaling $29.4 million and $33.8 million at September 30, 2025 and December 31, 2024, respectively, consists of the following.

In thousands	September 30, 2025		December 31, 2024
Credit facility	$	—	$	20,000
Notes payable		—		15,159
2.268% Senior Notes due 2026		798,217		797,056
4.375% Senior Notes due 2028		996,657		995,635
5.75% Senior Notes due 2031		1,488,530		1,487,175
2.875% Senior Notes due 2032		794,326		793,740
4.9% Senior Notes due 2044		692,854		692,682
Total debt	$	4,770,584	$	4,801,447
Less: Current portion of long-term debt		—		2,587
Long-term debt, net of current portion	$	4,770,584	$	4,798,860

Credit Facility

The Company has a credit facility, maturing in October 2029, with aggregate lender commitments totaling $1.8 billion. The Company has the option to extend the October 2029 maturity date by up to two additional one-year periods subject to lender consent. The credit facility is unsecured and has no borrowing base requirement subject to redetermination.

The Company had no outstanding borrowings on its credit facility at ~~September~~March 3031, 2026 and December 31, 2025. The Company incurs commitment fees based on currently assigned credit ratings of 0.20% per annum on the daily average amount of unused borrowing availability. Credit facility borrowings bear interest at market-based interest rates plus a margin based on the terms of the borrowing and the credit ratings assigned to the Company’s senior, unsecured, long-term indebtedness.

The credit facility contains certain restrictive covenants, including a requirement that the Company maintain a consolidated net debt to total capitalization ratio of no greater than 0.65 to 1.00. This ratio represents the ratio of (a) net debt (calculated as total face value of debt plus outstanding letters of credit less cash and cash equivalents) divided by (b) the sum of net debt plus total shareholders' equity (i) plus, to the extent resulting in a reduction of total shareholders’ equity, the amount of any non-cash impairment charges incurred, net of any tax effect, after June 30, 2014 and (ii) plus (to the extent resulting in a reduction of total shareholders’ equity) or minus (to the extent resulting in an increase of total shareholders’ equity), as applicable, the amount of the non-cash impact of the accounting treatment for the Redemption Agreement described in Note 8. Commitments and Contingencies, which amount shall be further adjusted, (x) if the Redemption Agreement is amended without the lenders consent and has the effect of materially increasing the scope of the Company's obligations beyond the last form of the Redemption Agreement that was approved by the lenders and (y) to reflect the impact of any cash payments actually made under the agreement. The Company was in compliance with the credit facility covenants at March 31, 2026.

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

net of any tax effect, after June 30, 2014 and (ii) plus (to the extent resulting in a reduction of total shareholders’ equity) or minus (to the extent resulting in an increase of total shareholders’ equity), as applicable, the amount of the non-cash impact of the accounting treatment for the Redemption Agreement described in Note 8. Commitments and Contingencies, which amount shall be further adjusted, (x) if the Redemption Agreement is amended without the lenders consent and has the effect of materially increasing the scope of the Company's obligations beyond the last form of the Redemption Agreement that was approved by the lenders and (y) to reflect the impact of any cash payments actually made under the agreement. The Company was in compliance with the credit facility covenants at September 30, 2025.

Senior Notes

The following table summarizes the face values, maturity dates, semi-annual interest payment dates, and optional redemption periods related to the Company’s outstanding senior note obligations at ~~September~~March 3031, ~~2025~~2026.

2026 Notes

2028 Notes

2031 Notes

2032 Notes

2044 Notes

Face value (in thousands)

800,000

1,000,000

1,500,000

800,000

700,000

Maturity date

November 15, 2026

January 15, 2028

January 15, 2031

April 1, 2032

June 1, 2044

Interest payment dates

May 15, Nov 15

Jan 15, July 15

Jan 15, ~~July~~Jul 15

April 1, Oct 1

June 1, Dec 1

Make-whole redemption period (1)

Nov 15, 2023

Oct 15, 2027

~~July~~Jul 15, 2030

January 1,. 2032

Dec 1, 2043

(1)

At any time prior to the indicated dates, the Company has the option to redeem all or a portion of its senior notes of the applicable series at the “make-whole” redemption amounts specified in the respective senior note indentures plus any accrued and unpaid interest to the date of redemption. On or after the indicated dates, the Company may redeem all or a portion of its senior notes at a redemption amount equal to 100% of the principal amount of the senior notes being redeemed plus any accrued and unpaid interest to the date of redemption.

The Company’s senior notes are not subject to any mandatory redemption or sinking fund requirements.

The indentures governing the Company’s senior notes contain covenants that, among other things, limit the Company’s ability to create liens securing certain indebtedness, enter into certain sale-leaseback transactions, or consolidate, merge or transfer certain assets. These covenants are subject to a number of important exceptions and qualifications. The Company was in compliance with these covenants at ~~September~~March 3031, ~~2025~~2026.

The senior notes are obligations of Continental Resources, Inc. Additionally, certain of the Company’s wholly-owned consolidated subsidiaries (Banner Pipeline Company, L.L.C., CLR Asset Holdings, LLC, The Mineral Resources Company, LLC, SCS1 Holdings LLC, Continental Innovations LLC, Jagged Peak Energy LLC, ~~and~~ Parsley SoDe Water LLC~~) fully and unconditionally guarantee the senior notes on a joint and several basis as of September 30~~, 2025. The financial information of the guarantor group is not materially different from the consolidated financial statements of the Company. The Company’s other subsidiaries as of September 30, 2025, whose assets, equity, and ~~results~~Continental ofPecos ~~operations attributable to the Company are not material~~Power, doLLC) ~~not~~fully ~~guarantee the senior notes.~~

1110

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

and unconditionally guarantee or will guarantee the senior notes on a joint and several basis. The Company's subsidiaries formed under the laws of foreign jurisdictions (Continental Resources Argentina S.A.U. and Continental Resources Turkey Petrol Arama ve Üretim Limited Şirketi) are not currently required to guarantee the senior notes under the terms of the indentures governing such notes. The financial information of the guarantor group is not materially different from the consolidated financial statements of the Company. The Company’s other subsidiaries, whose assets, equity, and results of operations attributable to the Company are not material, do not guarantee the senior notes.

Note payable

See Note 10. Equity Investment for discussion of a promissory note entered into by the Company in March 2026.

Note 8. Commitments and Contingencies

Transportation, gathering, and processing commitments

The Company has entered into transportation, gathering, and processing commitments to guarantee capacity on crude oil and natural gas pipelines and natural gas processing facilities. Certain of the commitments, which have varying terms extending as far as ~~2031~~2038, require the Company to pay per-unit transportation, gathering, or processing charges regardless of the amount of capacity used. Future commitments remaining as of ~~September~~March 3031, ~~2025~~2026 under the arrangements amount to approximately $~~579~~1.3 ~~million~~billion, of which $77186 million is expected to be incurred in the remainder of ~~2025~~2026, $~~221~~233 million in ~~2026~~2027, $~~203~~135 million in ~~2027~~2028, $7085 million in ~~2028~~2029, $385 million in ~~2029~~2030, and $5579 million thereafter. A portion of these future costs will be borne by other interest owners. The Company is not committed under the above contracts to deliver fixed and determinable quantities of crude oil or natural gas in the future. These commitments do not qualify as leases under ASC Topic 842 and are not recognized on the Company's balance sheet.

Litigation pertaining to 2022 take-private transaction

In April 2023, three separate putative class action lawsuits were consolidated under the caption In re Continental Resources, Inc. Shareholder Litigation, Case No. CJ-2022-4162, in the District Court of Oklahoma County, Oklahoma (the “Consolidated Action”). In the Consolidated Action, the plaintiffs, on behalf of themselves and all other similarly situated former shareholders of the Company, allege that Mr. Hamm, certain trusts established for the benefit of Mr. Hamm and/or his family members, and the Company’s other directors breached their fiduciary duties in connection with the 2022 take-private transaction and seek: (i) monetary damages; (ii) the costs and expenses associated with the lawsuits; and (iii) other equitable relief. ~~This~~On ~~matter~~April is14, ~~currently~~2026, ~~set~~the ~~for~~parties ~~trial~~reached an agreement-in-principle ~~May~~to ~~2026~~resolve this matter without any admission of liability, wrongdoing, or fault. The ~~defendants~~terms ~~continue~~and conditions of the agreement-in-principle remain subject to ~~vigorously~~the ~~defend~~execution ~~themselves~~of ~~against~~a ~~these~~formal ~~claims~~settlement agreement between the parties which shall not become effective until the District Court of Oklahoma County, Oklahoma has entered an order approving the settlement. Resolution of this matter does not have a material impact on the Company’s financial condition, results of operations, or cash flows.

In January 2023, FourWorld Deep Value Opportunities Fund I, LLC, FourWorld Event Opportunities, LP, FW Deep Value Opportunities I, LLC, FourWorld Global Opportunities Fund, Ltd., FourWorld Special Opportunities Fund, LLC, Corbin ERISA Opportunity Fund Ltd., and Quadre Investments, L.P. (collectively, “FourWorld”), all former shareholders of the Company, filed a petition in the District Court of Oklahoma County, Oklahoma, seeking appraisal of their respective shares of the Company’s common stock in connection with the 2022 take-private transaction. In April 2024, Quadre Investments, L.P. filed a voluntary dismissal with prejudice. The Company continues to vigorously defend itself against these claims.

Stock Redemption Agreement

In 2024, Continental entered into a Redemption Agreement with Mr. Hamm and certain members of his family whereby, following Mr. Hamm’s passing, his estate may, but is not obligated to, elect from time-to-time to require Continental to redeem sufficient shares to enable the estate to fund the payment of estate taxes and interest as they become due. Mr. Hamm’s potential estate tax liability is expected to be primarily based on the fair market value his estate assigns to his Continental stock at the time of passing. The agreement contemplates that the estate will defer and pay the potential estate taxes and related interest in installments over a period of up to 14 years as permitted by the Internal Revenue Code. Assuming the estate elects to exercise its redemption rights, Continental’s ~~potential obligations are expected to occur over the same 14 year period in conjunction with the estate’s installment payments.~~

In the second quarter of 2024, the Company initially recognized a $388 million liability on its balance sheet with a corresponding charge to "Other income (expense)—Other” on the statements of income to reflect the fair value of the redemption optionality features contained in the arrangement pursuant to ASC Topic 820, Fair Value Measurement. In the third quarter of 2024, the fair value of the liability was remeasured which resulted in a $46 million decrease in the liability to $342 million and corresponding recognition of income in the caption "Other income (expense)—Other” for the 2024 third quarter period. The cumulative financial statement impact recognized in the second and third quarters of 2024 was later reversed in the fourth quarter of 2024 upon derecognition of the liability to reflect a December 2024 amendment of the terms of the agreement, and no additional financial statement impacts have been recognized in 2025. The future value of Continental, the future tax laws and resulting estate tax liability, the timing of any redemptions, and the potential number and value of shares Continental may be required to redeem under the agreement are unknown 11

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

potential obligations are expected to occur over the same 14 year period in conjunction with the estate’s installment payments. The future value of Continental, the future tax laws and resulting estate tax liability, the timing of any redemptions, and the potential number and value of shares Continental may be required to redeem under the agreement are unknown and subject to numerous uncertainties and cannot be reasonably quantified. There have been no share repurchases or settlements under the agreement since its inception.

Note 9. Incentive Compensation

The Company has granted incentive compensation awards to employees pursuant to the Continental Resources, Inc. 2022 Long-Term Incentive Plan ~~(“2022 Plan”)~~. ~~Awards~~Such ~~granted~~awards ~~prior to 2024~~ generally vest ~~after three years of employee service. Awards granted in 2024 and thereafter generally vest~~ annually, in one-third increments, over three years of employee service. The Company intends to settle all outstanding incentive awards vesting in the future in cash and, thus, the awards are classified as liability awards pursuant to ASC Topic 718, Compensation—Stock Compensation.

At ~~September~~March 3031, ~~2025~~2026, the Company had recorded a current liability of $6624.03 million and a non-current liability of $157.62 million in the captions “~~Current~~Accrued ~~portion~~liabilities ofand ~~incentive compensation liability~~other” and “~~Incentive~~Other ~~compensation~~noncurrent ~~liability~~liabilities, ~~noncurrent,~~” respectively, in the condensed consolidated balance sheets associated with the awards. Such amounts reflect the Company’s estimate of expected future cash payments multiplied by the percentage of requisite service periods that employees have completed as of ~~September~~March 3031, ~~2025~~2026. The compensation expense associated with such awards, ~~totaled~~which ~~$18.1~~is ~~million~~included ~~and~~in ~~$15.9~~the ~~million~~caption ~~for~~“General ~~the~~and ~~three~~administrative ~~months~~expenses” ~~ended~~in ~~September~~the ~~30,~~condensed ~~2025~~consolidated ~~and~~statements ~~2024,~~of ~~respectively~~income (loss), ~~and~~was $5423.93 million and $6923.24 million for the ~~nine~~three months ended ~~September~~March 3031, ~~2025~~2026 and ~~2024~~2025, respectively~~, which is included in the caption “General and administrative expenses” in the consolidated statements of income~~. As of ~~September~~March 3031, ~~2025~~2026, there was approximately $65105.91 million of unrecognized liabilities and compensation expense related to unvested awards, which are expected to be recognized over a weighted average period of 1.37 years.

The Company’s incentive compensation liability will be remeasured each reporting period leading up to the applicable award vesting dates to reflect additional service rendered by employees and to reflect changes in expected cash payments arising from underlying changes in the value of the Company based on independent third party appraisals. Changes in the liability will be recorded as increases or decreases to compensation expense. The Company has estimated the number of forfeitures expected to occur in determining the amount of liability and expense to recognize.

Note 10. Equity Investment

In March 2026, Continental entered into a joint venture with Mercuria Investments US, Inc. (“Mercuria”) pursuant to that certain Contribution Agreement, by and among Mercuria, Continental Pecos Power, LLC, a wholly-owned subsidiary of Continental (“Continental Pecos Power”), and Pecos Intermediate LLC, which serves as the joint venture entity (“Pecos Intermediate”) (the “Contribution Agreement”). The joint venture is building a 452 megawatt gas-fired power generation plant in Pecos, Texas. Pursuant to the Contribution Agreement and as of March 31, 2026, Continental Pecos Power had contributed $142.2 million to Pecos Intermediate to fund construction and development costs incurred to date (the “Initial Contribution”) in exchange for membership interests in Pecos Intermediate representing a 50% economic interest. Continental Pecos Power has board representation and holds a 50% non-controlling equity ownership interest in Pecos Intermediate. Continental is not deemed to be the primary beneficiary of the venture for accounting purposes under U.S. GAAP and thus accounts for its investment under the equity method of accounting within the caption "Investment in unconsolidated affiliates."

Continental Pecos Power has capital commitment obligations to Pecos Intermediate of up to $257.8 million, inclusive of the Initial Contribution. In addition, Pecos Intermediate’s operating agreement requires Continental Pecos Power to provide 50% of the credit support for certain credit support instruments in effect prior to Continental Pecos Power’s entry into the Contribution Agreement and certain third party credit support anticipated to be required in the future. The power generation plant is expected to become operational in 2027.

In connection with its entry into the joint venture, in March 2026 Continental Pecos Power executed a $150 million secured promissory note with Mercuria pursuant to which it borrowed the amount needed to fund the Initial Contribution. The note payable, which is included in the caption "Long-term debt, net of current portion" in the condensed consolidated balance sheet, matures in

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

December 2035. The note contains customary affirmative and negative covenants and customary events of default. The note is secured by a pledge of Continental Pecos Power’s equity interests in Pecos Intermediate and, subject to limited exceptions, the proceeds of any cash generated by the joint venture and related agreements which is payable to Continental or Continental Pecos Power and is guaranteed by Continental.

Note 11. Property Acquisitions

During the three months ended March 31, 2026, the Company executed several acquisitions of oil and gas properties in various areas for cash consideration totaling $378.3 million. The Company accounted for each acquisition as an asset acquisition under ASC Topic 805—Business Combinations. Of the purchase prices, a total of $1.7 million was allocated to proved properties and a total of $376.6 million was allocated to unproved properties. The acquired properties, a portion of which include the Company's first international acquisition of oil and gas assets in Argentina, represented undeveloped acreage with no production or revenues.

Note 12. Income Taxes

In July 2025, the One Big Beautiful Bill Act (the “Act”) was enacted, which included a broad range of tax reform provisions affecting businesses such as the repeal of mandatory capitalization of research and development expenditures and the extension of 100% bonus depreciation. Upon implementing the provisions included in the Act in 2025, the Company incurred a corporate alternative minimum tax (“CAMT”) liability of $285 million. CAMT is a 15% minimum tax on the adjusted financial statement income (“AFSI”) of certain large corporations. The Company also recorded a deferred tax asset for CAMT credit carryforwards of $285 million at December 31, 2025.

On February 18, 2026, the Internal Revenue Service issued Notice 2026-7 (the “Notice”) that provides additional guidance on calculating CAMT. The Notice addresses disparities between financial accounting treatment and tax treatment in certain areas and provides new or modified AFSI adjustments that taxpayers may apply in determining their CAMT liability, including adjustments for domestic research and development costs which can reduce CAMT exposure for affected taxpayers.

The Notice is considered new information that clarifies the interpretation of existing income tax law for accounting purposes. In accordance with U.S. GAAP, the Company recognized the tax effects of the Notice in the first quarter of 2026, the reporting period that includes the issuance date. As a result, the Company’s CAMT liability for the 2025 tax year was reduced by $224 million, with the impact reflected as an increase in the Company's net federal income tax receivable and a corresponding decrease in the deferred tax asset relating to CAMT credit carryforwards on the condensed consolidated balance sheet at March 31, 2026. The Notice had no impact on the Company's income tax expense (benefit) or effective tax rate for the three months ended March 31, 2026.

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

The following discussion and analysis should be read in conjunction with the unaudited condensed consolidated financial statements and notes thereto included elsewhere in this report and our historical consolidated financial statements and notes included in our Form 10-K for the year ended December 31, ~~2024~~2025.

The following discussion and analysis includes forward-looking statements and should be read in conjunction with the risk factors, if any, described in Part II, Item 1A. Risk Factors included in this report, and in our Form 10-K for the year ended December 31, ~~2024~~2025, along with Cautionary Statement for the Purpose of the “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995 at the beginning of this report, for information about the risks and uncertainties that could cause our actual results to be materially different than our forward-looking statements.

Overview

We are an independent crude oil and natural gas company engaged in the exploration, development, management, and production of crude oil and natural gas and associated products with properties primarily located in four leading basins in the United States – the Bakken field of North Dakota and Montana, the Anadarko Basin of Oklahoma, the Permian Basin of Texas, and the Powder River Basin of Wyoming. ~~Additionally,~~In ~~we pursue~~ the ~~acquisition~~first ~~and~~quarter ~~management~~ of ~~perpetually~~2026 ~~owned~~we ~~minerals~~expanded ~~located~~our inoperations ~~certain~~internationally ofvia ~~our~~the ~~key~~acquisition ~~operating~~of ~~areas.~~assets Wewithin ~~derive~~ the ~~majority~~Vaca ofMuerta ~~our~~shale ~~operating~~play ~~income~~in ~~and~~Argentina's ~~cash~~Neuquén ~~flows~~Basin. ~~from~~As ~~the sale~~ of ~~crude~~March ~~oil~~31, ~~natural~~2026 ~~gas,~~our ~~and~~activities ~~natural~~in ~~gas~~Argentina ~~liquids~~have ~~and~~no ~~expect~~production ~~this~~or torevenues ~~continue~~and inrepresent ~~the~~an ~~future.~~immaterial Asportion ~~discussed~~of inour ~~Note~~consolidated 1assets. ~~Organization~~Additionally, ~~and~~we ~~Nature~~pursue ofthe ~~Business—Voluntary~~acquisition ~~Filer~~and inmanagement ~~Notes~~of toperpetually ~~Unaudited~~owned ~~Condensed~~minerals ~~Consolidated~~in ~~Financial~~our ~~Statements,~~key ~~Continental~~operating ~~Resources,~~areas ~~Inc.~~as iswell aas ~~privately~~opportunities ~~held~~to ~~corporation~~participate and ~~has~~contribute noin ~~publicly~~the ~~available~~growing ~~common~~power ~~shares~~generation ~~outstanding~~sector.

~~Third~~We ~~Quarter~~derive ~~2025~~the majority of our operating income and cash flows from the sale of crude oil, natural gas, and natural gas liquids and expect this to continue in the future. As discussed in Note 1. Organization and Nature of Business—Voluntary Filer in Notes to Unaudited Condensed Consolidated Financial Statements, Continental Resources, Inc. is a privately held corporation and ~~Operating~~has ~~Metrics~~no publicly available common shares outstanding.

~~Commodity~~First ~~prices~~Quarter ~~have~~2026 ~~remained~~Financial ~~volatile due to various factors. Average NYMEX crude oil~~ and ~~natural~~Operating ~~gas market prices for the periods presented are shown in the table below.~~Metrics

	Three months ended September 30,				Nine months ended September 30,
	2025		2024		2025		2024
Average NYMEX prices:
WTI Crude oil ($/Bbl)	$	65.78	$	76.43	$	67.31	$	78.58
Henry Hub natural gas ($/MMBtu)	$	3.03	$	2.11	$	3.45	$	2.11

Average NYMEX crude oil prices for the three months ended March 31, 2026 and 2025 were $72.74 and $71.78 per barrel, respectively. Average NYMEX natural gas prices for the three months ended March 31, 2026 and 2025 were $4.71 and $4.14 per Mcf, respectively. Crude oil prices increased significantly in March 2026, averaging $91.38 per barrel for the month, and have remained elevated through the date of this filing as a result of geopolitical events and military actions in the Middle East that have impacted the global supply of crude oil. Crude oil prices remain volatile and unpredictable. The following table contains financial and operating metrics for the first quarter periods of 2026 and 2025. Average sales prices exclude any effect of derivative transactions. Per-unit expenses have been calculated using sales volumes.

The following table contains financial and operating metrics for the periods presented. Average sales prices exclude any effect of derivative transactions. Per-unit expenses have been calculated using sales volumes.


	Three months ended March 31,
	2026			2025
Average daily production:
Crude oil (Bbl per day)		227,923			236,421
Natural gas (Mcf per day) (1)		1,354,995			1,156,581
Crude oil equivalents (Boe per day)		453,755			429,185
Average sales prices:
Crude oil ($/Bbl)	$	71.54		$	70.26
Natural gas ($/Mcf) (1)	$	3.33		$	3.88
Production expenses ($/Boe)	$	5.21		$	5.18
Production and ad valorem taxes (% of net crude oil and natural gas sales)		7.3	%		7.5	%
DD&A ($/Boe)	$	16.78		$	15.94
Total general and administrative expenses ($/Boe)	$	2.94		$	1.74

(1)

	Three months ended September 30,						Nine months ended September 30,
	2025			2024			2025			2024
Average daily production:
Crude oil (Bbl per day)		260,441			218,196			245,346			229,210
Natural gas (Mcf per day) (1)		1,318,435			1,147,213			1,228,426			1,187,829
Crude oil equivalents (Boe per day)		480,181			409,398			450,083			427,181
Average sales prices:
Crude oil ($/Bbl)	$	65.11		$	74.80		$	65.89		$	77.02
Natural gas ($/Mcf) (1)	$	2.10		$	1.75		$	2.74		$	2.01
Production expenses ($/Boe)	$	5.00		$	5.10		$	5.06		$	4.81
Production and ad valorem taxes (% of net crude oil and natural gas sales)		7.7	%		8.1	%		7.6	%		8.2	%
Depreciation, depletion, amortization and accretion ($/Boe)	$	15.74		$	16.15		$	15.80		$	15.94
Total general and administrative expenses ($/Boe)	$	1.43		$	1.70		$	1.52		$	1.80

Natural gas production volumes, sales volumes, and sales prices presented throughout management’s discussion and analysis reflect the combined value for natural gas and natural gas liquids.

Natural gas production volumes, sales volumes, and sales prices presented throughout management's discussion and analysis reflect the combined value for natural gas and natural gas liquids.

Three months ended ~~September~~March 3031, ~~2025~~2026 compared to the three months ended ~~September~~March 3031, ~~2024~~2025

Results of Operations

The following table presents selected financial and operating information for the periods presented.

	Three months ended September 30,
	Three months ended March 31,
In thousands	~~2025~~2026			~~2024~~2025
Crude oil, natural gas, and natural gas liquids sales	$	1,~~824~~847,~~572~~583		$	1,~~711~~890,~~932~~207
Gain on derivative instruments, net		184,195			270,001
Loss on derivative instruments, net		(1,108,124	)		(316,002	)
Crude oil and natural gas service operations		3638,~~976~~588			2436,~~207~~248
Total revenues		2778,~~045,743~~047			21,~~006~~610,~~140~~453
Operating costs and expenses		(1,~~253~~275,~~705~~992	)		(1,~~133~~140,~~556~~936	)
Other expenses, net		(4640,~~015~~890	)		(1451,~~228~~526	)
Income before income taxes		746,023			858,356
Income (loss) before income taxes		(538,835	)		417,991
Provision for income taxes		(188,400	)		(138,470	)
Benefit (provision) for income taxes		123,432			(86,380	)
Income before equity in net loss of affiliate		557,623			719,886
Income (loss) before equity in net loss of affiliate		(415,403	)		331,611
Equity in net loss of affiliate		(3224,025	)		(~~769~~12,887	)
Net income		557,591			719,117
Net (loss) income		(439,428	)		318,724
Net income attributable to noncontrolling interests		1,~~625~~799			602,718
Net income attributable to Continental Resources	$	555,966		$	719,057
Net income (loss) attributable to Continental Resources	$	(441,227	)	$	316,006
Production volumes:
Crude oil (MBbl)		2320,~~960~~513			2021,~~074~~278
Natural gas (MMcf)		121,~~296~~950			~~105~~104,~~544~~092
Crude oil equivalents (MBoe)		4440,~~177~~838			3738,~~665~~627
Sales volumes:
Crude oil (MBbl)		2420,~~107~~147			2021,~~424~~152
Natural gas (MMcf)		121,~~296~~950			~~105~~104,~~544~~092
Crude oil equivalents (MBoe)		4440,~~324~~472			38,~~014~~501

Production

The following table summarizes the changes in our average daily Boe production by major operating area for the ~~third~~first quarter period.

Boe production per day	3Q 2025		3Q 2024		% Change
	Three months ended March 31,
Bakken		209,741		191,784		9	%
Boe production per day	2026		2025		% Change
Anadarko Basin		132,210		121,578		9	%
Bakken		183,353		183,879		—	%
Powder River Basin		26,101		22,273		17	%
Anadarko Basin		132,199		127,879		3	%
Permian Basin		107,295		68,562		56	%
Powder River Basin		31,170		27,578		13	%
All other		4,834		5,201		(7	)%
Permian Basin		102,535		84,892		21	%
Total		480,181		409,398		17	%
All other		4,498		4,957		(9	)%
Total		453,755		429,185		6	%

The following table summarizes the changes in our production by product for the ~~third~~first quarter period.

	Three months ended September 30,													Volume
	Three months ended March 31,													Volume
	2025					2024					Volume			percent
	2026					2025					Volume			percent
	Volume		Percent			Volume		Percent			~~change~~increase (decrease)			~~change~~increase (decrease)
Crude oil (MBbl)		2320,~~960~~513		5450	%		2021,~~074~~278		5355	%		~~3,886~~(765	)		19(4	)%
Natural gas (MMcf)		121,~~296~~950		4650	%		~~105~~104,~~544~~092		4745	%		1517,~~752~~858			1517	%
Total (MBoe)		4440,~~177~~838		100	%		3738,~~665~~627		100	%		62,~~512~~211			176	%

The 194% ~~increase~~decrease in crude oil production and 1517% increase in natural gas production in the ~~2025~~2026 ~~third~~first quarter compared to the ~~2024~~2025 ~~third~~first quarter ~~was~~were driven by ~~variation~~changes in the ~~timing~~allocation of ~~new~~capital ~~well~~between ~~completions~~our ~~between~~operating ~~years~~areas and ~~improvements~~variation in the timing of new well ~~productivity~~completions compared to the prior period.

Revenues

Our revenues consist of sales of crude oil, natural gas, and natural gas liquids, gains and losses resulting from changes in the fair value of our derivative instruments, and revenues associated with crude oil and natural gas service operations.

Crude oil, natural gas, and natural gas liquids sales. Sales totaled $1.82 billion for the third quarter of 2025, a 7% increase compared to sales of $1.71 billion for the third quarter of 2024 due to an increase in sales volumes as discussed below, coupled with an increase in natural gas sales prices, partially offset by a decrease in crude oil sales prices.

Total sales volumes for the third quarter of 2025 increased 6,310 MBoe, or 17%, compared to the third quarter of 2024 due to the previously described increases in crude oil and natural gas production volumes. For the third quarter of 2025, our crude oil sales volumes increased 18% and our natural gas sales volumes increased 15% compared to the third quarter of 2024.

Our crude oil sales prices averaged $65.11 per barrel in the third quarter of 2025 compared to $74.80 per barrel for the third quarter of 2024. Our natural gas sales prices averaged $2.10 per Mcf for the third quarter of 2025 compared to $1.75 per Mcf for the third quarter of 2024.

Derivatives. Changes in settled and future commodity prices during the third quarter of 2025 had a net favorable impact on the fair value of our derivatives, which resulted in positive revenue adjustments totaling $184.2 million for the period, representing $108.6 million of cash gains and $75.6 million of unsettled non-cash gains, compared to positive revenue adjustments totaling $270.0 million in the third quarter of 2024.

Operating Costs and Expenses

Production Expenses. Production expenses increased $27.8 million, or 14%, to $221.6 million for the third quarter of 2025 compared to $193.8 million for the third quarter of 2024 due to an increase in the number of producing wells from drilling and completion activities and higher workover-related activities aimed at enhancing production from producing properties. Production expenses on a per-Boe basis averaged $5.00 per Boe for the third quarter of 2025 compared to $5.10 per Boe for the third quarter of 2024.

Production and Ad Valorem Taxes. Production and ad valorem taxes increased $2.5 million, or 2%, to $134.2 million for the third quarter of 2025 compared to $131.8 million for the third quarter of 2024 primarily due to an increase in crude oil and natural gas revenues. Our production taxes as a percentage of net sales averaged 7.7% for the third quarter of 2025 compared to 8.1% for the third quarter of 2024, the decrease of which resulted from changes in sales mix of crude oil and natural gas in our operating areas between periods.

Transportation, gathering, processing, and compression. These charges decreased $1.2 million, or 1%, to $88.0 million for the third quarter of 2025 compared to $89.2 million for the third quarter of 2024 due to changes in marketing terms and arrangements utilized between periods and changes in our working interest share of cost burdens in certain operating areas.

Depreciation, Depletion, Amortization and Accretion. Total DD&A increased $83.5 million, or 14%, to $697.5 million for the third quarter of 2025 compared to $613.9 million for the third quarter of 2024 due to the previously described 17% increase in total sales volumes. The following table shows the components of our DD&A on a unit of sales basis for the periods presented.

	Three months ended September 30,
$/Boe	2025		2024
Crude oil and natural gas	$	15.06	$	15.48
Other equipment		0.53		0.53
Asset retirement obligation accretion		0.15		0.14
Depreciation, depletion, amortization and accretion	$	15.74	$	16.15

General and Administrative Expenses. Total G&A expenses decreased $1.0 million, or 2%, to $63.6 million for the third quarter of 2025 compared to $64.6 million for the third quarter of 2024. Such expenses include charges for incentive compensation awards of $18.1 million and $15.9 million for the third quarters of 2025 and 2024, respectively. This increase was driven by changes in the remeasurement of outstanding award liabilities resulting from variation in the value of the Company between periods, which led to changes in the magnitude of expense recognized. G&A expenses other than incentive compensation awards totaled $45.5 million for the third quarter of 2025, a decrease of $3.2 million compared to $48.7 million recognized for the third quarter of 2024 primarily due to higher overhead recoveries from joint interest owners associated with our drilling, completion, and production activities compared to the prior period.

The following table shows the components of G&A expenses on a unit of sales basis for the periods presented.

	Three months ended September 30,
$/Boe	2025		2024
General and administrative expenses	$	1.02	$	1.28
Long-term incentive compensation awards		0.41		0.42
Total general and administrative expenses	$	1.43	$	1.70

Interest Expense. Interest expense decreased $9.5 million, or 15%, to $54.2 million for the third quarter of 2025 compared to $63.7 million for the third quarter of 2024 due to a decrease in our weighted average outstanding debt balance from $5.3 billion for the third quarter of 2024 to $4.8 billion for the third quarter of 2025.

Other income (expense)—Other. See Note 8. Commitments and Contingencies—Stock Redemption Agreement in Notes to Unaudited Condensed Consolidated Financial Statements.

Income Taxes. For the third quarters of 2025 and 2024 we provided for income taxes at a combined federal and state tax rate of 23.5% of our pre-tax income. We recorded income tax provisions of $188.4 million and $138.5 million for the third quarters of 2025 and 2024, respectively, which resulted in effective tax rates of 25.3% and 16.1%, respectively, after taking into account the application of statutory tax rates, permanent taxable differences, estimated tax credits, and other items.

Nine months ended September 30, 2025 compared to the nine months ended September 30, 2024

Results of Operations

The following table presents selected financial and operating information for the periods presented.

	Nine months ended September 30,
In thousands	2025			2024
Crude oil, natural gas, and natural gas liquids sales	$	5,341,153		$	5,523,563
Gain on derivative instruments, net		319,447			161,536
Crude oil and natural gas service operations		106,974			68,532
Total revenues		5,767,574			5,753,631
Operating costs and expenses		(3,528,191	)		(3,520,255	)
Other expenses, net		(144,319	)		(548,545	)
Income before income taxes		2,095,064			1,684,831
Provision for income taxes		(469,971	)		(401,059	)
Income before equity in net loss of affiliate		1,625,093			1,283,772
Equity in net loss of affiliate		(14,447	)		(2,981	)
Net income		1,610,646			1,280,791
Net income attributable to noncontrolling interests		11,475			333
Net income attributable to Continental Resources	$	1,599,171		$	1,280,458
Production volumes:
Crude oil (MBbl)		66,979			62,803
Natural gas (MMcf)		335,360			325,465
Crude oil equivalents (MBoe)		122,873			117,048
Sales volumes:
Crude oil (MBbl)		67,112			63,242
Natural gas (MMcf)		335,360			325,465
Crude oil equivalents (MBoe)		123,006			117,486

Production

The following table summarizes the changes in our average daily Boe production by major operating area for the year to date period.

Boe production per day	YTD 9/30/2025		YTD 9/30/2024		% Change
Bakken		197,706		196,224		1	%
Anadarko Basin		128,630		134,737		(5	)%
Powder River Basin		26,648		24,228		10	%
Permian Basin		92,206		66,660		38	%
All other		4,893		5,332		(8	)%
Total		450,083		427,181		5	%

The following table summarizes the changes in our production by product for the year to date period.

	Nine months ended September 30,												Volume
	2025					2024					Volume		percent
	Volume		Percent			Volume		Percent			change		change
Crude oil (MBbl)		66,979		55	%		62,803		54	%		4,176		7	%
Natural gas (MMcf)		335,360		45	%		325,465		46	%		9,895		3	%
Total (MBoe)		122,873		100	%		117,048		100	%		5,825		5	%

The 7% increase in crude oil production and 3% increase in natural gas production for year to date 2025 compared to year to date 2024 was driven by variation in the timing of new well completions between years and improvements in well productivity.

Revenues

~~Crude~~Our revenues consist of sales of crude oil, natural gas, and natural gas liquids ~~sales. Sales for year to date 2025 totaled $5.34 billion~~, agains 3%and ~~decrease~~losses ~~compared~~resulting tofrom ~~$5.52~~changes ~~billion~~in ~~for~~ the ~~comparable~~fair ~~2024~~value ~~period~~of ~~driven~~our bycrude aoil ~~decrease~~and innatural ~~crude~~gas ~~oil~~derivative ~~sales prices~~instruments, ~~partially~~and ~~offset~~revenues byassociated ~~increases~~with incrude ~~sales~~oil ~~volumes~~ and natural gas ~~sales~~service ~~prices as discussed below~~operations.

~~Total~~Crude oil, natural gas, and natural gas liquids sales. ~~volumes~~Sales ~~for~~totaled ~~year~~$1.85 tobillion ~~date~~for ~~2025~~the ~~increased~~first ~~5,520~~quarter ~~MBoe~~of 2026, ora 52%, decrease compared to ~~year~~sales toof ~~date~~$1.89 ~~2024~~billion ~~primarily~~for ~~due~~the to2025 ~~the~~first ~~previously~~quarter ~~described~~due ~~increases~~to decreases in crude oil sales volumes and natural gas ~~production~~sales ~~volumes. For year to date 2025~~prices, ~~our~~partially ~~crude~~offset ~~oil~~by ~~sales~~increases ~~volumes~~in ~~increased 6% and our~~ natural gas sales volumes ~~increased~~and 3%crude ~~compared~~oil tosales ~~year to date 2024~~prices.

~~Our~~Total ~~crude~~sales ~~oil~~volumes ~~sales~~for ~~prices~~the ~~averaged~~first ~~$65.89~~quarter ~~per~~of ~~barrel~~2026 ~~for~~increased ~~year~~1,971 toMBoe, ~~date~~or ~~2025~~5%, compared to ~~$77.02~~the ~~per~~2025 ~~barrel~~first ~~for~~quarter ~~year~~primarily due to ~~date~~the ~~2024.~~previously ~~Our~~described increase in natural gas ~~sales~~production ~~prices~~volumes. ~~averaged~~For ~~$2.74~~the ~~per~~first ~~Mcf~~quarter ~~for~~of ~~year~~2026, toour ~~date~~natural ~~2025~~gas ~~compared~~sales tovolumes ~~$2.01~~increased ~~per~~17%, ~~Mcf~~while ~~for~~our ~~year~~crude oil sales volumes decreased 5% compared to ~~date~~the ~~2024~~2025 first quarter.

~~Derivatives.~~Our ~~Changes~~crude inoil ~~settled~~sales ~~and future commodity~~ prices ~~during~~averaged ~~the~~$71.54 ~~nine~~per ~~months~~barrel ~~ended~~in ~~September 30, 2025 had a net favorable impact on~~ the ~~fair~~2026 ~~value~~first ofquarter ~~our~~compared ~~derivatives,~~to ~~which resulted in positive revenue adjustments totaling~~ $~~319~~70.426 ~~million~~per barrel for the ~~period,~~2025 ~~representing~~first ~~$213~~quarter.7 ~~million~~Our ofnatural ~~cash~~gas ~~gains~~sales ~~and~~prices averaged $~~105~~3.833 ~~million~~per ofMcf ~~unsettled~~for ~~non-cash~~the ~~gains,~~2026 first quarter compared to ~~positive revenue adjustments totaling~~ $~~161~~3.588 ~~million~~per inMcf for the ~~comparable~~2025 ~~2024~~first ~~period~~quarter.

Derivatives. Changes in settled and future commodity prices during the first quarter of 2026 resulted in overall negative revenue adjustments totaling $1.1 billion for the period, representing $114.1 million of cash losses and $994.0 million of unsettled non-cash losses, compared to overall negative revenue adjustments totaling $316.0 million in the first quarter of 2025. The significant cash and non-cash losses recognized in the 2026 first quarter were primarily driven by the aforementioned increase in crude oil prices in March 2026. See Note 5. Derivative Instruments in Notes to Unaudited Condensed Consolidated Financial Statements for further information on the gains and losses recognized on our derivative instruments in the first quarter of 2026.

Operating Costs and Expenses

Production Expenses. Production expenses increased $5711.25 million, or 106%, to $~~622~~210.48 million for ~~year~~the tofirst ~~date~~quarter ~~2025~~of 2026 compared to $~~565~~199.24 million for ~~year~~the tofirst ~~date~~quarter ~~2024~~of 2025 due to an increase in the number of producing wells from drilling and completion activities and higher workover-related activities aimed at enhancing production from producing properties. Production expenses on a per-Boe basis averaged $5.0621 per Boe for ~~year~~the to2026 ~~date~~first ~~2025~~quarter, ~~compared~~consistent towith $45.8118 per Boe for ~~year~~the to2025 ~~date~~first ~~2024~~quarter.

Production and Ad Valorem Taxes. Production and ad valorem taxes decreased $396.23 million, or 95%, to $~~389~~129.0 million for ~~year~~the tofirst ~~date~~quarter ~~2025~~of 2026 compared to $~~428~~135.3 million for ~~year~~the tofirst ~~date~~quarter ~~2024~~of ~~primarily~~2025 due to a decrease in crude oil revenues. Our production taxes as a percentage of net sales averaged 7.63% for ~~year~~the tofirst ~~date~~quarter ~~2025~~of 2026 compared to 87.25% for ~~year~~the tofirst ~~date~~quarter ~~2024~~of 2025, the decrease of which resulted from changes in sales mix of crude oil and natural gas in our operating areas between periods.

18Transportation, gathering, processing, and compression. These charges increased $3.6 million, or 5%, to $82.5 million for the first quarter of 2026 compared to $78.9 million for the first quarter of 2025 due to the previously described 5% increase in our total sales volumes.

~~Transportation~~Depreciation, ~~gathering~~Depletion, ~~processing,~~Amortization and ~~compression~~Accretion. ~~These~~Total ~~charges~~DD&A ~~decreased~~increased $4565.97 million, or 1611%, to $~~242~~679.72 million for ~~year~~the tofirst ~~date~~quarter ~~2025~~of 2026 compared to $~~288~~613.6 million for ~~year~~the first quarter of 2025 due to ~~date~~the ~~2024~~5% increase in our total sales volumes coupled with an increase in our DD&A rate per Boe prompted by downward revisions of proved reserves at year-end 2025 due to ~~changes~~a decrease in ~~marketing~~first-day-of-the-month ~~terms~~crude oil prices and ~~arrangements~~other ~~utilized~~factors. ~~between~~The ~~periods~~following ~~and~~table ~~changes~~shows inthe components of our ~~working~~DD&A ~~interest~~on ~~share~~a unit of ~~cost~~sales ~~burdens~~basis infor ~~certain~~the ~~operating~~periods ~~areas~~presented.

Depreciation, Depletion, Amortization and Accretion. Total DD&A increased $70.3 million, or 4%, to $1.94 billion for year to date 2025 compared to $1.87 billion for year to date 2024 due to the previously described 5% increase in total sales volumes. The following table shows the components of our DD&A on a unit of sales basis for the periods presented.


	Three months ended March 31,
$/Boe	2026		2025
Crude oil and natural gas properties	$	15.97	$	15.20
Other equipment		0.63		0.58
Asset retirement obligation accretion		0.18		0.16
Depreciation, depletion, amortization and accretion	$	16.78	$	15.94

	Nine months ended September 30,
$/Boe	2025		2024
Crude oil and natural gas	$	15.09	$	15.29
Other equipment		0.56		0.51
Asset retirement obligation accretion		0.15		0.14
Depreciation, depletion, amortization and accretion	$	15.80	$	15.94

General and Administrative Expenses. G&A expenses increased $51.8 million to $118.8 million for the first quarter of 2026 compared to $67.0 million for the first quarter of 2025. This increase was driven by the growth of our operations over the past year including our

General and Administrative Expenses. Total G&A expenses decreased $24.4 million, or 12%, to $187.1 million for year to date 2025 compared to $211.6 million for year to date 2024. Such expenses include charges for incentive compensation awards of $54.9 million and $69.2 million for the year to date periods of 2025 and 2024, respectively. This decrease was driven by changes in the remeasurement of outstanding award liabilities resulting from variation in the value of the Company between periods, which led to changes in the magnitude of expense recognized. G&A expenses other than incentive compensation awards totaled $132.2 million for year to date 2025, a decrease of $10.2 million compared to $142.4 million for year to date 2024 primarily due to higher overhead recoveries from joint interest owners associated with our drilling, completion, and production activities compared to the prior period. 16

expansion into international jurisdictions, an annual increase in employee-related costs and benefits, software enhancements, certain nonrecurring legal costs, and lower overhead and cost recoveries from joint interest owners due to a decrease in drilling and completion spending compared to the prior period. The following table shows the components of G&A expenses on a unit of sales basis for the periods presented. The per-unit G&A rate recognized for the first quarter of 2026 is not expected to continue and future periods are expected to be more in line with our historical averages.

	Nine months ended September 30,
	Three months ended March 31,
$/Boe	~~2025~~2026		~~2024~~2025
General and administrative expenses	$	12.0736	$	1.2113
Long-term incentive compensation awards		0.4558		0.5961
Total general and administrative expenses	$	12.5294	$	1.8074

~~Interest~~Income ~~Expense~~Taxes. ~~Interest~~For ~~expense~~the ~~decreased~~first ~~$51.7~~quarters ~~million,~~of or2026 24and 2025 we provided for income taxes at a combined federal and state tax rate of 23.5%, toof our pre-tax income (loss). We recorded an income tax benefit of $~~163~~123.64 million for ~~year~~the to2026 ~~date~~first ~~2025~~quarter ~~compared~~and toan income tax provision of $~~215~~86.34 million for ~~year~~the to2025 ~~date~~first ~~2024~~quarter, ~~due~~which toresulted ain ~~decrease~~effective intax ~~our~~rates ~~weighted~~of ~~average~~22.9% ~~outstanding~~and ~~debt~~20.7%, ~~balance~~respectively, ~~from~~after ~~$6.0~~taking ~~billion~~into ~~for~~account ~~year~~the toapplication ~~date~~of ~~2024~~statutory totax ~~$4.8~~rates, ~~billion~~permanent ~~for~~taxable ~~year~~differences, toestimated ~~date~~tax ~~2025~~credits, and other items.

Other income (expense)—Other. See Note 8. Commitments and Contingencies—Stock Redemption Agreement in Notes to Unaudited Condensed Consolidated Financial Statements.

Income Taxes. For the nine months ended September 30, 2025 and 2024 we provided for income taxes at a combined federal and state tax rate of 23.5% of our pre-tax income. We recorded income tax provisions of $470.0 million and $401.1 million for the year to date periods of 2025 and 2024, respectively, which resulted in effective tax rates of 22.4% and 23.8%, respectively, after taking into account the application of statutory tax rates, permanent taxable differences, estimated tax credits, and other items.

Liquidity and Capital Resources

Our primary sources of liquidity have historically been cash flows generated from operating activities, financing provided by our credit facility, and the issuance of debt securities. Additionally, asset dispositions and joint development arrangements have provided a source of cash flow for use in reducing debt and enhancing liquidity.

At ~~September~~March 3031, ~~2025~~2026, we had $1.8 billion of borrowing availability with no outstanding borrowings under our credit facility, along with $1.16 billion of cash on hand. Our credit facility, which is unsecured and has no borrowing base subject to redetermination, does not mature until October 2029. ~~The~~We ~~Company~~have ~~has~~the ~~been~~option ~~able~~ to ~~build~~extend ~~its~~the ~~cash~~October ~~reserves~~2029 ~~due~~maturity todate aby ~~combination~~up ~~of its focus on debt reduction and improving its overall operational efficiency. The Company anticipates using a substantial majority of its current cash reserves~~ to ~~repay~~two ~~its~~additional ~~senior~~one-year ~~notes~~periods ~~maturing~~subject ~~in 2026 and~~ to ~~acquire~~lender ~~additional operating assets~~consent.

19The Company anticipates using a portion of its current cash reserves to repay its senior notes maturing in November 2026 and to acquire additional operating assets.

Based on our planned capital spending, our forecasted cash flows and projected levels of indebtedness, we expect to maintain compliance with the covenants under our credit facility and senior note indentures. Further, based on current market indications, we expect to meet our contractual cash commitments to third parties as of ~~September~~March 3031, ~~2025~~2026, including those subsequently described under the heading Future Capital Requirements, recognizing we may be required to meet such commitments even if our business plan assumptions were to change. We monitor our capital spending closely based on actual and projected cash flows and have the ability to reduce spending or dispose of assets if needed to preserve liquidity and financial flexibility to fund our operations.

Cash Flows

Cash flows from operating activities

Net cash provided by operating activities ~~increased~~decreased $~~146~~281.7 million, or 420%, to $31.6812 billion for ~~year~~the tofirst ~~date~~quarter ~~2025~~of 2026 compared to $31.5340 billion for ~~year~~the tofirst ~~date~~quarter ~~2024~~of 2025. ~~The~~This ~~increase~~decrease was primarily driven by aour $~~299~~43 million decrease in ~~cash~~crude ~~payments for income taxes~~oil, anatural ~~$59 million decrease in cash paid for interest~~gas, ~~a $46 million decrease in transportation, gathering, processing,~~ and ~~compression~~NGL ~~expenses~~revenues, a $3952 million ~~decrease~~increase in ~~production~~G&A ~~and ad valorem taxes~~expenses, and a $60131 million ~~decrease~~increase in cash payments for incentive compensation compared to the prior year to date period. These improvements in operating cash flows were partially offset by a $182 million decrease in crude oil, natural gas and NGL revenues, a $73 million decrease in realized cash ~~gains~~losses on matured commodity derivatives, ~~and a $57 million increase in production expenses,~~ along with changes in working capital items from period to period.

Cash flows from investing activities

Net cash used in investing activities totaled $2890.565 ~~billion~~million for ~~year~~the tofirst ~~date~~quarter ~~2025~~of ~~compared~~2026, toan increase of $166.863 ~~billion~~million, or 8%, from $824.2 million for ~~year~~the tofirst ~~date~~quarter ~~2024~~of 2025. Our investing cash flows for ~~year~~first toquarter ~~date~~2026 ~~2025~~ included $2934.453 ~~billion~~million of exploration and development costs compared to $2774.145 ~~billion~~million for ~~year~~first toquarter ~~date 2024~~2025, the increase of which reflects changes in the planned timing of our annual capital spending and magnitude of leasehold acquisitions between periods. InFor ~~addition,~~full ~~proceeds~~year ~~received~~2026 ~~from~~our ~~the~~capital ~~sale~~expenditures ofbudget ~~assets~~excluding ~~decreased~~acquisitions byis approximately $~~441~~2.8 ~~million~~billion ~~for~~compared ~~year~~ to ~~date~~$3.1 ~~2025~~billion ~~compared~~of tonon-acquisition ~~the~~capital ~~prior~~spending ~~year~~in tofull ~~date~~year ~~period~~2025.

Cash flows from financing activities

Net cash used in financing activities for ~~year~~the tofirst ~~date~~quarter ~~2025 totaled $52.3 million, primarily consisting~~ of ~~$35.2~~2026 ~~million~~totaled ~~of net repayments on outstanding debt and~~ $~~16.3~~1 million of net distributions to noncontrolling interests. ~~Net cash used in financing activities for year to date 2024 totaled $1.67 billion due to $1.67 billion of net repayments on outstanding debt.~~

Net cash used in financing activities for the first quarter of 2025 totaled $25 million, primarily consisting of $20 million of net repayments on our credit facility.

Future Sources of Financing

Although we cannot provide any assurance, we believe funds from operating cash flows, our cash balance, and availability under our credit facility should be sufficient to meet our normal operating needs, debt service obligations, budgeted capital expenditures, and cash payments for income taxes for at least the next 12 months and to meet our contractual cash commitments to third parties described under the heading Future Capital Requirements beyond 12 months.

Based on current market indications ~~supported by cash flow protection provided by our hedge portfolio against commodity price declines~~, our budgeted capital spending plans over the next 12 months are expected to be funded from operating cash flows. Any deficiencies in operating cash flows relative to budgeted spending are expected to be funded by our cash balance and borrowings under our credit facility. If cash flows are materially impacted by declines in commodity prices or an increase in costs, we have the ability to reduce our capital expenditures or utilize the availability of our credit facility if needed to fund our operations.

We may choose to access banking or debt capital markets for additional financing or capital to fund our operations or take advantage of business opportunities that may arise. Further, we may sell assets or enter into strategic joint development opportunities in order to obtain funding if such transactions can be executed on satisfactory terms. However, no assurance can be given that such transactions will occur.

Credit facility

We have an unsecured credit facility, maturing in October 2029, with aggregate lender commitments totaling $1.8 billion. We have the option to extend the October 2029 maturity date by up to two additional one-year periods subject to lender consent. The commitments are from a syndicate of 14 banks and financial institutions. We believe each member of the current syndicate has the capability to fund its commitment.

The commitments under our credit facility are not dependent on a borrowing base calculation subject to periodic redetermination based on changes in commodity prices and proved reserves. Additionally, downgrades or other negative rating actions with respect to our credit rating do not trigger a reduction in our current credit facility commitments, nor do such actions trigger a security requirement or change in covenants.

Our credit facility contains restrictive covenants that may limit our ability to, among other things, incur additional indebtedness, incur liens, engage in sale and leaseback transactions, or merge, consolidate or sell all or substantially all of our assets. Our credit facility also contains a requirement that we maintain a consolidated net debt to total capitalization ratio of no greater than 0.65 to 1.00. See Notes to Unaudited Condensed Consolidated Financial Statements–Note 7. Debt for a discussion of how this ratio is calculated pursuant to our credit agreement.

We were in compliance with our credit facility covenants at September 30, 2025 and expect to maintain compliance. At September 30, 2025, our consolidated net debt to total capitalization ratio was 0.20. We do not believe the credit facility covenants are reasonably likely to limit our ability to undertake additional debt financing if needed to support our business. 18

We were in compliance with our credit facility covenants at March 31, 2026 and expect to maintain compliance. At March 31, 2026, our consolidated net debt to total capitalization ratio was 0.18. We do not believe the credit facility covenants are reasonably likely to limit our ability to undertake additional debt financing if needed to support our business.

Future Capital Requirements

Our material future cash requirements are summarized below. Based on current market indications, we expect to meet our contractual cash commitments to third parties as of ~~September~~March 3031, ~~2025~~2026, recognizing we may be required to meet such commitments even if our business plan assumptions were to change.

Senior notes

Our debt includes outstanding senior note obligations totaling $4.8 billion at ~~October~~March 31, ~~2025~~2026, exclusive of interest payment obligations thereon. Our senior notes are not subject to any mandatory redemption or sinking fund requirements. The earliest scheduled senior note maturity is our $800 million of 2026 Notes due in November 2026, which is reflected as a current liability in the caption "Current portion of long-term debt" in the condensed consolidated balance sheet. We expect to fully redeem our 2026 Notes by the maturity date using available cash on hand. For further information on the face values, maturity dates, semi-annual interest payment dates, optional redemption periods and covenant restrictions related to our senior notes, refer to Note 7. Debt in Notes to Unaudited Condensed Consolidated Financial Statements.

We were in compliance with our senior note covenants at ~~September~~March 3031, ~~2025~~2026 and expect to maintain compliance. We do not believe the senior note covenants will materially limit our ability to undertake additional debt financing. Downgrades or other negative rating actions with respect to the credit ratings assigned to our senior unsecured debt do not trigger additional senior note covenants.

Credit facility borrowings

As of ~~October~~April 3130, ~~2025~~2026, we ~~had~~continued to have no outstanding borrowings on our credit facility. ~~Our credit facility matures in October 2029.~~

Transportation, gathering, and processing commitments

We have entered into transportation, gathering, and processing commitments to guarantee capacity on crude oil and natural gas pipelines and natural gas processing facilities that require us to pay per-unit charges regardless of the amount of capacity used. Future commitments remaining as of ~~September~~March 3031, ~~2025~~2026 under the arrangements amount to approximately $~~579~~1.3 ~~million~~billion. See Note 8. Commitments and Contingencies in Notes to Unaudited Condensed Consolidated Financial Statements for additional information.

Capital expenditures

~~Our~~For 2026, our capital expenditures excluding acquisitions are forecasted to be approximately $~~3.0 billion to $3.1 billion for 2025. For the nine months ended September 30, 2025, we invested $~~2.58 billion ~~in our capital program~~.

21For the three months ended March 31, 2026, we invested $617.8 million in our capital program excluding $378.3 million of unbudgeted acquisitions.

Our drilling and completion activities and the actual amount and timing of our capital expenditures may differ materially from our budget as a result of, among other things, available cash flows, unbudgeted acquisitions, actual drilling and completion results, operational process improvements, the availability of drilling and completion rigs and other services and equipment, cost inflation, the impact of tariffs or trade restrictions, the availability of transportation, gathering and processing capacity, changes in commodity prices, and regulatory, technological and competitive developments. We monitor our capital spending closely based on actual and projected cash flows and may adjust our spending should commodity prices materially change from current levels. We expect to continue participating as a buyer of properties when and if we have the ability to increase our position in strategic plays at attractive terms.

Stock redemption agreement

See Note 8. Commitments and Contingencies—Stock Redemption Agreement in Notes to Unaudited Condensed Consolidated ~~Financial Statements.~~

Financial Statements.

Derivative Instruments

The fair value of our crude oil and natural gas derivative instruments at March 31, 2026 was a net liability of $612.6 million. See Note 5. Derivative Instruments in Notes to Unaudited Condensed Consolidated Financial Statements for further discussion of our hedging activities, including a summary of derivative contracts in place as of March 31, 2026. The estimated fair value of our derivatives is highly sensitive to market price volatility and therefore subject to significant fluctuations from period to period. See Part I, Item 3. Quantitative and Qualitative Disclosures About Market Risk for information on how hypothetical changes in commodity prices would impact the fair value of our derivatives as of March 31, 2026.

Equity investment

See Note 10. Equity Investment in Notes to Unaudited Condensed Consolidated Financial Statements for discussion of a joint venture entered into by the Company in March 2026 and related promissory note, capital commitments, and guarantees associated with the venture.

Critical Accounting Policies and Estimates

There have been no changes in our critical accounting policies and estimates from those disclosed in our ~~2024~~2025 Form 10-K.

Inflation

Inflationary pressures experienced in recent years may persist or worsen ~~over~~in ~~the next 12 months~~2026. Some of the underlying factors impacting inflation may include, but are not limited to, geopolitical events and military actions affecting crude oil-producing nations that impact the global supply of crude oil, global supply chain disruptions, the imposition of trade restrictions or other governmental actions related to tariffs or trade policies, shipping bottlenecks, labor market constraints, increased competition for goods and services, and side effects from monetary and fiscal policies. It is uncertain at this time to what extent ~~recent~~ changes in trade restrictions and tariffs will have on our business. Tariffs on foreign goods and services could result in reciprocal tariffs on U.S. goods and services, which could impact the demand for and price of crude oil, natural gas, and natural gas liquids and increase inflationary pressures on, or impact the availability of, certain supplies, equipment and materials that we use to conduct our business. If inflationary pressures persist or worsen, we may incur additional costs for equipment and materials and from service providers. Our budgeted expenditures include an estimate for the potential impact of cost inflation and increased costs resulting from tariffs and, despite inflationary pressures, we expect to continue generating significant amounts of free cash flow at current commodity price levels.

~~Legislative and Regulatory Developments~~20

On July 4, 2025, President Trump signed into law the One Big Beautiful Bill Act (the “Act”), which includes a broad range of tax reform provisions affecting businesses. Below is a summary of notable changes included in the Act.

Bonus depreciation – The Act permanently restored 100% immediate expensing for qualifying tangible property placed into service after January 19, 2025.

Research and development (R&D) costs – The Act repealed a provision that required domestic R&D costs to be capitalized and amortized over five years. Companies can now immediately expense R&D costs incurred in tax years beginning after December 31, 2024. In addition, companies are permitted to make an election to accelerate the deductions for unamortized R&D costs that were previously capitalized from 2022 to 2024 effective for tax years beginning after December 31, 2024.

Intangible drilling and development costs – The Act introduced a new adjustment for intangible drilling and development costs that will be included in the computation of adjusted financial statement income to determine liability for the corporate minimum tax effective for tax years beginning after December 31, 2025.  

In accordance with US GAAP, we recognized the tax effects from the Act in the third quarter of 2025, the reporting period that included the enactment date, which did not have a material impact on our condensed consolidated financial statements at September 30, 2025 or for the three and nine month periods then ended.

ITEM 3. Quantitative and Qualitative Disclosures About Market Risk

General. We are exposed to a variety of market risks including commodity price risk, credit risk, ~~and~~ interest rate risk, and foreign currency exchange risk. We seek to address these risks through a program of risk management which may include the use of derivative instruments.

Commodity Price Risk. Our primary market risk exposure is in the prices we receive from sales of crude oil, natural gas, and natural gas liquids. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our natural gas and natural gas liquids production. Commodity prices have been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside of our control, including differences between product prices at sales points and the applicable index prices. Based on our average daily production for ~~the~~three ~~nine~~ months ended ~~September~~March 3031, ~~2025~~2026, and excluding the effect of derivative instruments in place, our annual revenue would increase or decrease by approximately $~~896~~832 million for each $10.00 per barrel change in crude oil prices at ~~September~~March 3031, ~~2025~~2026 and $~~448~~495 million for each $1.00 per Mcf change in natural gas prices at ~~September~~March 3031, ~~2025~~2026.

To reduce price risk caused by market fluctuations in commodity prices, from time to time we economically hedge a portion of our anticipated production as part of our risk management program. In addition, we may utilize basis contracts to hedge the differential between derivative contract index prices and those of our physical pricing points. Reducing our exposure to price volatility helps secure funds to be used for our capital program and general corporate purposes. Our decision on the quantity and price at which we choose to hedge our production is based in part on our view of current and future market conditions. We may choose not to hedge future production if the price environment for certain time periods is deemed to be unfavorable. Additionally, we may choose to settle existing derivative positions prior to the expiration of their contractual maturities. While hedging, if utilized, limits the downside risk of adverse price movements, it also limits future revenues from upward price movements.

The fair value of our derivative instruments at ~~September~~March 3031, ~~2025~~2026 was a net ~~asset~~liability of $~~263~~612.36 million, which is comprised of aan $~~137~~866.80 million net ~~asset~~liability associated with our ~~natural~~crude ~~gas~~oil derivatives, ~~and~~partially offset by a $~~125~~253.54 million net asset associated with our ~~crude~~natural ~~oil~~gas derivatives. The following table shows how a hypothetical +/- 10% change in the underlying forward prices used to calculate the fair value of our derivatives would impact the fair value estimates as of ~~September~~March 3031, ~~2025~~2026.

		Hypothetical Fair Value
In thousands	Change in Forward Price	Asset (Liability)
Crude Oil	-10%	$	~~392~~(348,~~585~~467	)
Crude Oil	+10%	$	(~~137~~1,~~138~~386,053	)
Natural Gas	-10%	$	~~345~~396,~~486~~379
Natural Gas	+10%	$	~~(68~~110,~~619~~472	)

Changes in the fair value of our derivatives from the above price sensitivities would produce a corresponding change in our total revenues.

Credit Risk. We monitor our risk of loss due to non-performance by counterparties of their contractual obligations. Our principal exposure to credit risk is through the sale of our production, which we market to energy marketing companies, crude oil refining companies, and natural gas gathering and processing companies ($1.03 billion in receivables at ~~September~~March 3031, ~~2025~~2026), and our joint interest and other receivables ($~~419~~326.64 million at ~~September~~March 3031, ~~2025~~2026).

We monitor our exposure to counterparties on our commodity sales primarily by reviewing credit ratings, financial statements and payment history. We extend credit terms based on our evaluation of each counterparty’s credit worthiness. We have not generally required our counterparties to provide collateral to secure commodity sales receivables owed to us. Historically, our credit losses on commodity sales receivables have been immaterial.

Joint interest receivables arise from billing the individuals and entities who own a partial interest in the wells we operate. These individuals and entities participate in our wells primarily based on their ownership in leases included in units on which we wish to drill. We can do very little to choose who participates in our wells. In order to minimize our exposure to this credit risk we generally request prepayment of drilling costs where it is allowed by contract or state law. For such prepayments, a liability is recorded and ~~subsequently reduced as the associated work is performed. This liability was $42.3 million at September 30, 2025, which will be used~~

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subsequently reduced as the associated work is performed. This liability was $33.5 million at March 31, 2026, which will be used to offset future capital costs when billed. In this manner, we reduce credit risk. We may have the right to place a lien on a co-owner's interest in the well, to net production proceeds against amounts owed in order to secure payment or, if necessary, foreclose on the interest. Historically, our credit losses on joint interest receivables have been immaterial.

Interest Rate Risk. Our exposure to changes in interest rates relates primarily to variable-rate borrowings we may have outstanding from time to time under our credit facility. Credit facility borrowings bear interest at market-based interest rates plus a margin based on the terms of the borrowing and the credit ratings assigned to our senior, unsecured, long-term indebtedness. All of our other long-term indebtedness is fixed rate and does not expose us to the risk of cash flow loss due to changes in market interest rates.

We had no variable rate borrowings outstanding on our credit facility at ~~October~~April 3130, ~~2025~~2026.

We manage our interest rate exposure by monitoring both the effects of market changes in interest rates and the proportion of our debt portfolio that is variable-rate versus fixed-rate debt. We may utilize interest rate derivatives to alter interest rate exposure in an attempt to reduce interest rate expense related to existing debt issues. Interest rate derivatives may be used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio. We currently have no interest rate derivatives.

Foreign Currency Exchange Risk. We expect to be exposed to foreign currency exchange risk in the future associated with our emerging international operations in Argentina. We currently have no foreign currency derivative instruments in place to manage foreign currency risk. However, we may enter into such instruments in the future as our international operations increase in size and scope.

ITEM 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As of the end of the period covered by this report, an evaluation of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) was performed under the supervision and with the participation of the Company’s management, including its Chief Executive Officer and Chief Financial Officer. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded the Company’s disclosure controls and procedures were effective as of ~~September~~March 3031, ~~2025~~2026 to ensure information required to be disclosed in the reports it files and submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and information required to be disclosed under the Exchange Act is accumulated and communicated to the Company’s management, including its Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control over Financial Reporting

During the three months ended ~~September~~March 3031, ~~2025~~2026, there were no changes in our internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Inherent Limitations on Controls and Procedures

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. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risks that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Accordingly, even an effective system of internal control will provide only reasonable assurance that the objectives of the internal control system are met.

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PART II. Other Information

ITEM 1. Legal Proceedings

We are involved in various legal proceedings including, but not limited to, commercial disputes, claims from royalty and surface owners, property damage claims, claims made by former shareholders in connection with our take-private transaction, antitrust claims related to the market price of hydrocarbons, personal injury claims, regulatory compliance matters, disputes with tax authorities and other matters. While the outcome of these legal matters cannot be predicted with certainty, we do not expect them to have a material adverse effect on our financial condition, results of operations or cash flows. See Note 8. Commitments and Contingencies in Notes to Unaudited Condensed Consolidated Financial Statements for additional information on litigation pertaining to our 2022 take-private transaction.

ITEM 1A. Risk Factors

In addition to the information set forth in this Form 10-Q, you should carefully consider the risk factors discussed in Part I, Item 1A. Risk Factors in our ~~2024~~2025 Form 10-K, which could materially affect our business, financial condition or future results. The risks described in this Form 10-Q, if any, and in our ~~2024~~2025 Form 10-K are not the only risks facing our Company. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results.

There have been no material changes in our risk factors from those disclosed in our ~~2024~~2025 Form 10-K.

ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds

Not applicable.

ITEM 3. Defaults Upon Senior Securities

Not applicable.

ITEM 4. Mine Safety Disclosures

Not applicable.

ITEM 5. Other Information

Not applicable.

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ITEM 6. Exhibits

The exhibits required to be filed pursuant to Item 601 of Regulation S-K are set forth below.


3.1		Conformed version of Seventh Amended and Restated Certificate of Incorporation of Continental Resources, Inc. filed as Exhibit 3.1 to the Company's Form 10-K for the year ended December 31, 2024 (Commission File No. 001-32886) filed February 24, 2025 and incorporated herein by reference.

3.2		Sixth Amended and Restated Bylaws of Continental Resources, Inc. filed as Exhibit 3.2 to the Company’s Form 10-Q for the quarter ended September 30, 2024 (Commission File No. 001-32886) filed November 12, 2024 and incorporated herein by reference.

31.1*		Certification of the Company’s Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (15 U.S.C. Section 7241).

31.2*		Certification of the Company’s Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (15 U.S.C. Section 7241).

101.INS*		Inline XBRL Instance Document - the Inline XBRL 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 Taxonomy Extension Schema Document with Embedded Linkbases Document

104		Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

* Filed herewith

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SIGNATURE

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.

		CONTINENTAL RESOURCES, INC.
Date:	~~November~~May 411, ~~2025~~2026	By:	/s/ John D. Hart
			John D. Hart
			Chief Financial Officer and Executive Vice President of Strategic Planning(Duly Authorized Officer and Principal Financial Officer)

2725

(State or other jurisdiction of incorporation or organization)

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

20 N. Broadway,

Oklahoma City,

(Address of principal executive offices)

(Zip Code)

Filing Compare · CONTINENTAL RESOURCES, INC