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 June ~~March 31~~30, 2025


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

For the transition period from to

Commission File Number: 001-32886

____________________________________

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 ~~March~~June 3130, 2025, there are no publicly traded common shares of Continental Resources, Inc.

Table of Contents

PART I. Financial Information
Item 1.	Financial Statements	1
	Condensed Consolidated Balance Sheets	1
	Unaudited Condensed Consolidated Balance Sheets	1
	Unaudited Condensed Consolidated Statements of Income	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	1314
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	2024
Item 4.	Controls and Procedures	2125
PART II. Other Information
Item 1.	Legal Proceedings	2226
Item 1A.	Risk Factors	2226
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	2226
Item 3.	Defaults Upon Senior Securities	2226
Item 4.	Mine Safety Disclosures	2226
Item 5.	Other Information	2226
Item 6.	Exhibits	2327
	Signature	2428
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 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, 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 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

	March 31, 2025			December 31, 2024
In thousands, except par values and share data	June 30, 2025		December 31, 2024
In thousands, except par values and share data	(Unaudited)
Assets
Assets
Current assets:
Current assets:
Cash and cash equivalents	$569,218		$39,064
Cash and cash equivalents	$	591,324		$	39,064
Accounts receivable, net	1,491,157		1,553,919
Receivables:
Derivative assets	185,443		95,227
Crude oil, natural gas, and natural gas liquids sales		1,132,912			1,176,280
Inventories	216,329		184,251
Joint interest and other		368,006			381,760
Prepaid expenses and other	44,521		32,648
Allowance for credit losses		(3,671	)		(4,121	)
Total current assets	2,506,668		1,905,109
Receivables, net		1,497,247			1,553,919
Net property and equipment, based on successful efforts method of accounting	20,432,711		20,037,922
Derivative assets		13,580			95,227
Investment in unconsolidated affiliates	254,829		258,359
Inventories		183,642			184,251
Operating lease right-of-use assets	34,661		20,933
Prepaid expenses and other		45,847			32,648
Derivative assets, noncurrent	43,847		62,426
Total current assets		2,331,640			1,905,109
Other noncurrent assets	17,830		20,832
Net property and equipment, based on successful efforts method of accounting		20,170,065			20,037,922
Total assets	$23,290,546		$22,305,581
Investment in unconsolidated affiliates		252,305			258,359
Liabilities and equity
Operating lease right-of-use assets		38,202			20,933
Current liabilities:
Derivative assets, noncurrent		8,198			62,426
Accounts payable trade	$945,046		$845,160
Other noncurrent assets		17,692			20,832
Revenues and royalties payable	669,905		682,461
Total assets	$	22,818,102		$	22,305,581
Accrued liabilities and other	332,888		413,036
Liabilities and equity
Current portion of incentive compensation liability	53,554		74,494
Current liabilities:
Current portion of income tax liabilities	18,815		21,659
Accounts payable trade	$	819,911		$	845,160
Derivative liabilities	391		—
Revenues and royalties payable		787,565			682,461
Current portion of operating lease liabilities	10,215		4,046
Accrued liabilities and other		311,409			413,036
Current portion of long-term debt	—		2,587
Current portion of incentive compensation liability		45,097			74,494
Total current liabilities	2,030,814		2,043,443
Current portion of income tax liabilities		101,947			21,659
Long-term debt, net of current portion	4,769,137		4,798,860
Derivative liabilities		162,642			—
Other noncurrent liabilities:
Current portion of operating lease liabilities		11,313			4,046
Deferred income tax liabilities, net	2,668,825		2,704,069
Current portion of long-term debt		2,610			2,587
Incentive compensation liability, noncurrent	10,797		36,468
Total current liabilities		2,242,494			2,043,443
Asset retirement obligations, noncurrent	449,600		432,495
Long-term debt, net of current portion		4,779,617			4,798,860
Derivative liabilities, noncurrent	41,222		143
Other noncurrent liabilities:
Operating lease liabilities, noncurrent	23,458		15,823
Deferred income tax liabilities, net		2,706,108			2,704,069
Other noncurrent liabilities	32,847		48,783
Incentive compensation liability, noncurrent		6,537			36,468
Total other noncurrent liabilities	3,226,749		3,237,781
Asset retirement obligations, noncurrent		440,202			432,495
Commitments and contingencies (Note 8)
Derivative liabilities, noncurrent		34,480			143
Equity:
Operating lease liabilities, noncurrent		25,843			15,823
Preferred stock, $0.01 par value; 25,000,000 shares authorized; no shares issued and outstanding	—		—
Other noncurrent liabilities		49,632			48,783
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 other noncurrent liabilities		3,262,802			3,237,781
Retained earnings	12,905,722		11,862,515
Commitments and contingencies (Note 8)
Total shareholders’ equity attributable to Continental Resources	12,908,718		11,865,511
Equity:
Noncontrolling interests	355,128		359,986
Preferred stock, $0.01 par value; 25,000,000 shares authorized; no shares issued and outstanding		—			—
Total equity	13,263,846		12,225,497
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 liabilities and equity	$23,290,546		$22,305,581
Retained earnings		12,178,523			11,862,515
Total shareholders’ equity attributable to Continental Resources		12,181,519			11,865,511
Noncontrolling interests		351,670			359,986
Total equity		12,533,189			12,225,497
Total liabilities and equity	$	22,818,102		$	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

	Three months ended March 31,
	Three months ended June 30,						Six months ended June 30,
In thousands, except per share data	2025			2024
In thousands	2025			2024			2025			2024
Revenues:
Crude oil, natural gas, and natural gas liquids sales	$	1,~~890~~626,~~207~~374		$	1,~~909~~901,~~843~~788		$	3,516,581		$	3,811,631
Loss on derivative instruments, net		(316,002	)		(113,194	)
Gain (loss) on derivative instruments, net		451,254			4,729			135,252			(108,465	)
Crude oil and natural gas service operations		3633,~~248~~750			2320,~~895~~430			69,998			44,325
Total revenues		12,~~610~~111,~~453~~378			1,~~820~~926,~~544~~947			3,721,831			3,747,491
Operating costs and expenses:
Production expenses		~~199~~201,~~379~~445			~~188~~182,~~697~~677			400,824			371,374
Production and ad valorem taxes		~~135~~119,~~349~~422			~~147~~149,~~127~~372			254,771			296,499
Transportation, gathering, processing, and compression		7875,~~873~~845			~~107~~91,~~946~~451			154,718			199,397
Exploration expenses		23,~~732~~897			42,~~110~~980			6,629			7,090
Crude oil and natural gas service operations		2324,~~880~~889			2622,~~640~~715			48,769			49,355
Depreciation, depletion, amortization and accretion		~~613~~632,~~560~~568			~~632~~626,~~763~~579			1,246,128			1,259,342
Property impairments		1715,~~022~~826			1210,~~062~~124			32,848			22,186
General and administrative expenses		6756,~~012~~515			8264,~~282~~642			123,527			146,924
Net (gain) loss on sale of assets and other		3,129			(287	)
Net loss on sale of assets and other		3,143			34,819			6,272			34,532
Total operating costs and expenses		1,~~140~~133,~~936~~550			1,~~201~~185,~~340~~359			2,274,486			2,386,699
Income from operations		~~469~~977,~~517~~828			~~619~~741,~~204~~588			1,447,345			1,360,792
Other income (expense):
Interest expense		(5554,~~143~~240	)		(7971,~~811~~825	)		(109,383	)		(151,636	)
Other		3,617			3,154
Loss on extinguishment of debt		(57	)		(1,600	)		(57	)		(1,600	)
		(51,526	)		(76,657	)
Other		7,519			(384,235	)		11,136			(381,081	)
Income before income taxes		417,991			542,547
		(46,778	)		(457,660	)		(98,304	)		(534,317	)
Provision for income taxes		(86,380	)		(114,054	)
Income before income taxes		931,050			283,928			1,349,041			826,475
Income before equity in net loss of affiliate		331,611			428,493
Provision for income taxes		(195,191	)		(148,535	)		(281,571	)		(262,589	)
Equity in net loss of affiliate		(12,887	)		(907	)
Income before equity in net loss of affiliate		735,859			135,393			1,067,470			563,886
Net income		318,724			427,586
Equity in net loss of affiliate		(1,528	)		(1,305	)		(14,415	)		(2,212	)
Net income attributable to noncontrolling interests		2,718			464
Net income		734,331			134,088			1,053,055			561,674
Net income attributable to Continental Resources	$	316,006		$	427,122
Net income (loss) attributable to noncontrolling interests		7,132			(191	)		9,850			273
Net income attributable to Continental Resources	$	727,199		$	134,279		$	1,043,205		$	561,401

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 March 31, 2025
Three months ended June 30, 2025
	Shareholders’ equity attributable to Continental Resources
In thousands, except share data	Sharesoutstanding		Commonstock		Retainedearnings		~~Totalshareholders’equity ofContinentalResources~~Total		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		—		—		316,006		316,006		2,718			318,724
Change in dividends payable		—		—		2		2		—			2
Contributions from noncontrolling interests		—		—		—		—		1,740			1,740
Distributions to noncontrolling interests		—		—		—		—		(12,774	)		(12,774	)
Balance at March 31, 2025		299,610,267	$	2,996	$	12,178,523	$	12,181,519	$	351,670		$	12,533,189
Net income		—		—		727,199		727,199		7,132			734,331
Contributions from noncontrolling interests		—		—		—		—		3,015			3,015
Distributions to noncontrolling interests		—		—		—		—		(6,689	)		(6,689	)
Balance at June 30, 2025		299,610,267	$	2,996	$	12,905,722	$	12,908,718	$	355,128		$	13,263,846

Three Months Ended March 31, 2024
Six months ended June 30, 2025
	Shareholders’ equity attributable to Continental Resources
In thousands, except share data	Sharesoutstanding		Commonstock		Retainedearnings		~~Totalshareholders’equity ofContinentalResources~~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
Balance at December 31, 2024		299,610,267	$	2,996	$	11,862,515	$	11,865,511	$	359,986		$	12,225,497
Net income		—		—		~~427~~1,~~122~~043,205		~~427~~1,~~122~~043,205		~~464~~9,850			~~427~~1,~~586~~053,055
Change in dividends payable		—		—		122		122		—			122
Contributions from noncontrolling interests		—		—		—		—		144,~~040~~755			144,~~040~~755
Distributions to noncontrolling interests		—		—		—		—		(619,~~707~~463	)		(619,~~707~~463	)
Balance at March 31, 2024		299,610,267	$	2,996	$	10,277,821	$	10,280,817	$	363,901		$	10,644,718
Balance at June 30, 2025		299,610,267	$	2,996	$	12,905,722	$	12,908,718	$	355,128		$	13,263,846


Three months ended June 30, 2024
	Shareholders’ equity attributable to Continental Resources
In thousands, except share data	Shares outstanding		Common stock		Retained earnings		Total		Noncontrolling interests			Total equity
Balance at March 31, 2024		299,610,267	$	2,996	$	10,277,821	$	10,280,817	$	363,901		$	10,644,718
Net income (loss)		—		—		134,279		134,279		(191	)		134,088
Change in dividends payable		—		—		7		7		—			7
Contributions from noncontrolling interests		—		—		—		—		5,556			5,556
Distributions to noncontrolling interests		—		—		—		—		(5,381	)		(5,381	)
Balance at June 30, 2024		299,610,267	$	2,996	$	10,412,107	$	10,415,103	$	363,885		$	10,778,988


Six months ended June 30, 2024
	Shareholders’ equity attributable to Continental Resources
In thousands, except share data	Shares outstanding		Common stock		Retained earnings		Total		Noncontrolling interests			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		—		—		561,401		561,401		273			561,674
Change in dividends payable		—		—		19		19		—			19
Contributions from noncontrolling interests		—		—		—		—		19,596			19,596
Distributions to noncontrolling interests		—		—		—		—		(12,088	)		(12,088	)
Balance at June 30, 2024		299,610,267	$	2,996	$	10,412,107	$	10,415,103	$	363,885		$	10,778,988

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

	Three months ended March 31,
	Six months ended June 30,
In thousands	2025			2024
Cash flows from operating activities
Net income	$	~~318~~1,~~724~~053,055		$	~~427~~561,~~586~~674
Adjustments to reconcile net income to cash provided by operating activities:
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion		~~615~~1,~~028~~246,823			~~636~~1,~~659~~259,817
Property impairments		1732,~~022~~848			1222,~~062~~186
Non-cash loss on derivatives, net		332,854			208,390
Non-cash (gain) loss on derivatives		(30,167	)		291,119
Provision for deferred income taxes		2,039			11,816
Provision (benefit) for deferred income taxes		(35,244	)		48,733
Equity in net loss of affiliate		1214,~~887~~415			~~907~~2,212
Net (gain) loss on sale of assets and other		3,084			(287	)
Net loss on sale of assets and other		5,614			34,532
Other, net		4,447			23,567
Loss on extinguishment of debt		57			1,600
Other, net		7,997			417,091
Changes in assets and liabilities:
Accounts receivable		5563,~~962~~512			23141,~~062~~009
Inventories		(235,~~702~~415	)		(2712,~~564~~008	)
Other current assets		(1112,~~955~~067	)		(156,~~331~~048	)
Accounts payable trade		36121,~~967~~163			27(8,~~166~~018	)
Revenues and royalties payable		98(13,~~717~~379	)		(39119,~~001~~116	)
Accrued liabilities and other		(~~102~~82,~~376~~344	)		(7055,~~148~~435	)
Incentive compensation liability		(5946,~~329~~610	)		(~~108~~90,~~809~~254	)
Current income taxes liability		80(2,~~287~~844	)		~~105~~(83,~~504~~837	)
Other noncurrent assets and liabilities		(~~465~~17,306	)		(75,~~701~~549	)
Net cash provided by operating activities		12,~~401~~270,~~191~~108			12,~~221~~349,~~878~~708
Cash flows from investing activities
Exploration and development		(~~774~~1,~~514~~609,698	)		(~~663~~1,~~003~~356,454	)
Purchase of producing crude oil and natural gas properties		—(1,739	)		(~~870~~1,245	)
Purchase of other property and equipment		(4376,~~480~~920	)		(49104,~~963~~965	)
Proceeds from sale of assets		~~664~~9,383			4450,~~340~~625
Contributions to unconsolidated affiliates		(610,~~821~~885	)		(8,227	)
Net cash used in investing activities		(~~824~~1,~~151~~689,859	)		(~~717~~1,~~723~~020,266	)
Cash flows from financing activities
Credit facility borrowings		440,000			~~749~~2,012,000
Repayment of credit facility		(460,000	)		(~~959~~1,622,000	)
Repayment of other debt		(640	)		(100,616	)
Redemption of senior notes		—			(893,126	)
Debt issuance costs		(123	)		—
Repayment of other debt		(15,220	)		(751,237	)
Contributions from noncontrolling interests		3,019			7,740
Debt issuance costs		(127	)		—
Distributions to noncontrolling interests		(6,408	)		(5,681	)
Contributions from noncontrolling interests		4,582			17,208
Dividends paid on common stock		(628	)		(2,331	)
Distributions to noncontrolling interests		(18,702	)		(12,608	)
Net cash used in financing activities		(24,780	)		(310,888	)
Dividends paid on common stock		(628	)		(2,342	)
Net change in cash and cash equivalents		552,260			193,267
Net cash used in financing activities		(50,095	)		(1,252,105	)
Net change in cash and cash equivalents		530,154			77,337
Cash and cash equivalents at beginning of period		39,064			26,397
Cash and cash equivalents at end of period	$	~~591~~569,~~324~~218		$	~~219~~103,~~664~~734

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. Additionally, the Company pursues the acquisition and management of perpetually owned minerals located in certain of its key operating areas. For the ~~three~~six months ended ~~March~~June 3130, 2025, crude oil accounted for 55% of the Company’s total production and 7981% 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 ~~March~~June 3130, 2025, 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 (“2024 Form 10-K”), which includes a summary of the Company’s significant accounting policies and other disclosures.

The condensed consolidated financial statements as of ~~March~~June 3130, 2025 and for the three and six month periods ended ~~March~~June 3130, 2025 and 2024 are unaudited. The condensed consolidated balance sheet as of December 31, 2024 was derived from the audited balance sheet included in the 2024 Form 10-K. The Company evaluated its March 31, 2025 financial statements for subsequent events through May 2, 2025, the date the financial statements were available to be issued.

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

included in the 2024 Form 10-K. The Company evaluated its June 30, 2025 financial statements for subsequent events through August 1, 2025, 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 presentation 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.

	Three months ended March 31,
	Six months ended June 30,
In thousands	2025		2024
Supplemental cash flow information:
Cash paid for interest	$	66103,~~136~~935	$	86153,~~931~~652
Cash paid for income taxes		—315,605		—356,201
Cash received for income tax refunds		302		3,266
Non-cash investing activities:
Asset retirement obligation additions and revisions, net		27,~~895~~460		911,~~137~~302

As of ~~March~~June 3130, 2025 and December 31, 2024, the Company had $~~316~~344.54 million and $376.4 million, respectively, of accrued capital expenditures included in “Net property and equipment” with an offsetting amount in “Accounts payable trade” in the ~~condensed~~ consolidated balance sheets.

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, 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 March 31, 2025						Three months ended March 31, 2024
In thousands	Crude Oil		Natural Gasand NGLs		Total		Crude Oil		Natural Gasand NGLs		Total
Bakken	$	726,496	$	139,269	$	865,765	$	891,174	$	87,447	$	978,621
Anadarko Basin		233,499		204,320		437,819		241,924		154,284		396,208
Powder River Basin		113,230		19,258		132,488		117,274		13,830		131,104
Permian Basin		382,250		41,181		423,431		344,645		19,340		363,985
All other		30,681		23		30,704		39,890		35		39,925
Crude oil, natural gas, and natural gas liquids sales	$	1,486,156	$	404,051	$	1,890,207	$	1,634,907	$	274,936	$	1,909,843

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 six months ended June 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 June 30, 2025						Three months ended June 30, 2024
In thousands	Crude Oil		Natural Gas and NGLs		Total		Crude Oil		Natural Gas and NGLs		Total
Bakken	$	723,297	$	70,163	$	793,460	$	907,513	$	53,899	$	961,412
Anadarko Basin		178,266		156,838		335,104		274,101		119,015		393,116
Powder River Basin		97,185		9,039		106,224		105,268		8,605		113,873
Permian Basin		335,715		24,200		359,915		379,808		11,921		391,729
All other		31,666		5		31,671		41,643		15		41,658
Crude oil, natural gas, and natural gas liquids sales	$	1,366,129	$	260,245	$	1,626,374	$	1,708,333	$	193,455	$	1,901,788


	Six months ended June 30, 2025						Six months ended June 30, 2024
In thousands	Crude Oil		Natural Gas and NGLs		Total		Crude Oil		Natural Gas and NGLs		Total
Bakken	$	1,449,793	$	209,432	$	1,659,225	$	1,798,687	$	141,346	$	1,940,033
Anadarko Basin		411,765		361,158		772,923		516,025		273,299		789,324
Powder River Basin		210,415		28,297		238,712		222,542		22,435		244,977
Permian Basin		717,965		65,381		783,346		724,453		31,261		755,714
All other		62,347		28		62,375		81,533		50		81,583
Crude oil, natural gas, and natural gas liquids sales	$	2,852,285	$	664,296	$	3,516,581	$	3,343,240	$	468,391	$	3,811,631

Note 5. Derivative Instruments

From time to time the Company enters into 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 ~~March~~June 3130, 2025 the Company had outstanding 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

Swaps

Floor

Ceiling

April 2025 - March 2026

July 2025 - March 2026

Collars - Henry Hub

304,000

MMBtus/day

4.25

5.99

April 2025 - December 2025

July 2025 - December 2025

Swaps - Henry Hub

580,000

MMBtus/day

3.95

January 2026 - December 2026

Swaps - Henry Hub

~~635~~737,000

MMBtus/day

4.1113

January 2027 - December 2027

Swaps - Henry Hub

~~612~~647,~~500~~000

MMBtus/day

3.9294

Crude oil derivatives
				Weighted Average Hedge Price ($/Bbl)
Period and Type of Contract	Average Volumes Hedged			Roll Swaps		Fixed Swaps		Floor		Ceiling
April 2025 - December 2025
Fixed Swaps - WTI		58,600	Bbls/day			$	70.63
Collars - WTI		55,000	Bbls/day					$	60.00	$	68.27
Roll Swaps - NYMEX		53,000	Bbls/day	$	0.95
January 2026 - December 2026
Fixed Swaps - WTI		22,000	Bbls/day			$	62.49
Collars - WTI		21,000	Bbls/day					$	60.00	$	70.22

Derivative gains and losses

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

	Three months ended March 31,
Crude oil derivatives
In thousands	2025			2024
						Weighted Average Hedge Price ($/Bbl)
Cash received (paid) on derivatives:
Period and Type of Contract	Average Volumes Hedged					Roll Swaps		Fixed Swaps		Floor		Ceiling
Crude oil fixed price swaps	$	9,252		$	4,829
July 2025 - December 2025
Crude oil NYMEX roll swaps		669			2,473
Fixed Swaps - WTI		59,000		Bbls/day				$	70.63
Natural gas WAHA swaps		—			9,024
Collars - WTI		55,000		Bbls/day						$	60.00	$	68.27
Natural gas fixed price swaps		6,931			62,801
Roll Swaps - NYMEX		53,000		Bbls/day		$	0.95
Natural gas collars		—			16,069
January 2026 - December 2026
Cash received (paid) on derivatives, net		16,852			95,196
Fixed Swaps - WTI		55,000		Bbls/day				$	62.17
Non-cash gain (loss) on derivatives:
Collars - WTI		33,000		Bbls/day						$	60.00	$	69.38
Crude oil fixed price swaps		(9,550	)		(201,049	)
January 2027 - December 2027
Crude oil collars		(47,565	)		—
Fixed Swaps - WTI		19,000		Bbls/day				$	64.52
Crude oil NYMEX roll swaps		3,867			(10,254	)
Natural gas WAHA swaps		—			(329	)
Natural gas fixed price swaps		(287,165	)		15,165
Natural gas collars		7,559			(11,923	)
Non-cash gain (loss) on derivatives, net		(332,854	)		(208,390	)
Gain (loss) on derivative instruments, net	$	(316,002	)	$	(113,194	)

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

Cash receipts and payments in the following table reflect the gains or losses on 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 ~~recorded~~settled atbased ~~fair~~upon ~~value~~reported insettlement ~~the~~prices ~~condensed~~on ~~consolidated~~commodity ~~balance~~exchanges, ~~sheets~~with ~~under~~crude ~~the~~oil ~~captions~~derivative ~~“Derivative~~settlements ~~assets,”~~based ~~“Derivative~~on ~~assets,~~NYMEX ~~noncurrent,”~~West ~~“Derivative~~Texas ~~liabilities,~~Intermediate (“WTI”) pricing and ~~“Derivative~~natural ~~liabilities,~~gas ~~noncurrent”~~derivative assettlements ~~applicable~~based primarily on NYMEX Henry Hub pricing. ~~Derivative~~Non-cash ~~assets~~gains and ~~liabilities~~losses ~~with~~below represent the ~~same~~change ~~counterparty~~in ~~that~~fair ~~are~~value ~~subject~~of derivative instruments which continued to ~~contractual~~be ~~terms~~held ~~which~~at ~~provide~~period ~~for~~end ~~net~~and ~~settlement~~the ~~are~~reversal ~~reported~~of onpreviously arecognized ~~net~~non-cash ~~basis~~gains inor ~~the~~losses ~~condensed~~on ~~consolidated~~derivative ~~balance~~contracts ~~sheets~~that matured during the period.

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 condensed consolidated balance sheets for the periods presented, all at fair value.


	Three months ended June 30,						Six months ended June 30,
In thousands	2025			2024			2025			2024
Cash received (paid) on derivatives:
Crude oil fixed price swaps	$	36,878		$	(19,677	)	$	46,130		$	(14,848	)
Crude oil collars		(28	)		—			(28	)		—
Crude oil NYMEX roll swaps		1,722			(440	)		2,391			2,033
Natural gas WAHA swaps		—			17,898			—			26,922
Natural gas fixed price swaps		27,208			89,677			34,139			152,478
Natural gas collars		22,453			—			22,453			16,069
Cash received on derivatives, net		88,233			87,458			105,085			182,654
Non-cash gain (loss) on derivatives:
Crude oil fixed price swaps		116,525			33,569			106,975			(167,480	)
Crude oil collars		89,347			—			41,782			—
Crude oil NYMEX roll swaps		(4,258	)		1,578			(391	)		(8,676	)
Natural gas WAHA swaps		—			(12,846	)		—			(13,175	)
Natural gas fixed price swaps		123,931			(105,030	)		(163,234	)		(89,865	)
Natural gas collars		37,476			—			45,035			(11,923	)
Non-cash gain (loss) on derivatives, net		363,021			(82,729	)		30,167			(291,119	)
Gain (loss) on derivative instruments, net	$	451,254		$	4,729		$	135,252		$	(108,465	)

In thousands	March 31, 2025			December 31, 2024
Commodity derivative assets:
Gross amounts of recognized assets	$	61,299		$	168,023
Gross amounts offset on balance sheet		(39,521	)		(10,370	)
Net amounts of assets on balance sheet		21,778			157,653
Commodity derivative liabilities:
Gross amounts of recognized liabilities		(236,643	)		(10,513	)
Gross amounts offset on balance sheet		39,521			10,370
Net amounts of liabilities on balance sheet	$	(197,122	)	$	(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	March 31, 2025			December 31, 2024
Derivative assets	$	13,580		$	95,227
Derivative assets, noncurrent		8,198			62,426
Net amounts of assets on balance sheet		21,778			157,653
Derivative liabilities		(162,642	)		—
Derivative liabilities, noncurrent		(34,480	)		(143	)
Net amounts of liabilities on balance sheet		(197,122	)		(143	)
Total derivative assets (liabilities), net	$	(175,344	)	$	157,510

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	June 30, 2025			December 31, 2024
Commodity derivative assets:
Gross amounts of recognized assets	$	250,892		$	168,023
Gross amounts offset on balance sheet		(21,602	)		(10,370	)
Net amounts of assets on balance sheet		229,290			157,653
Commodity derivative liabilities:
Gross amounts of recognized liabilities		(63,215	)		(10,513	)
Gross amounts offset on balance sheet		21,602			10,370
Net amounts of liabilities on balance sheet	$	(41,613	)	$	(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	June 30, 2025			December 31, 2024
Derivative assets	$	185,443		$	95,227
Derivative assets, noncurrent		43,847			62,426
Net amounts of assets on balance sheet		229,290			157,653
Derivative liabilities		(391	)		—
Derivative liabilities, noncurrent		(41,222	)		(143	)
Net amounts of liabilities on balance sheet		(41,613	)		(143	)
Total derivative assets, net	$	187,677		$	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 derivative positions is compared to the counterparty valuation for reasonableness.

The following tables summarize the valuation of derivative instruments by pricing levels that were accounted for at fair value on a recurring basis as of March 31, 2025 and December 31, 2024.

	Fair value measurements at March 31, 2025 using:
In thousands	Level 1		Level 2			Level 3		Total
Derivative assets (liabilities):
Crude oil fixed price swaps	$	—	$	2,983		$	—	$	2,983
Crude oil collars		—		(47,565	)		—		(47,565	)
Crude oil NYMEX roll swaps		—		3,867			—		3,867
Natural gas fixed price swaps		—		(142,188	)		—		(142,188	)
Natural gas collars		—		7,559			—		7,559
Total	$	—	$	(175,344	)	$	—	$	(175,344	)

	Fair value measurements at December 31, 2024 using:
In thousands	Level 1		Level 2		Level 3		Total
Derivative assets (liabilities):
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 $32.4 million and $33.8 million at March 31, 2025 and December 31, 2024, respectively, consists of the following.

In thousands	March 31, 2025		December 31, 2024
Credit facility	$	—	$	20,000
Notes payable		14,521		15,159
2.268% Senior Notes due 2026		797,441		797,056
4.375% Senior Notes due 2028		995,972		995,635
5.75% Senior Notes due 2031		1,487,620		1,487,175
2.875% Senior Notes due 2032		793,934		793,740
4.9% Senior Notes due 2044		692,739		692,682
Total debt	$	4,782,227	$	4,801,447
Less: Current portion of long-term debt		2,610		2,587
Long-term debt, net of current portion	$	4,779,617	$	4,798,860

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

The following tables summarize the valuation of derivative instruments by pricing levels that were accounted for at fair value on a recurring basis as of June 30, 2025 and December 31, 2024.


	Fair value measurements at June 30, 2025 using:
In thousands	Level 1		Level 2			Level 3		Total
Derivative assets (liabilities):
Crude oil fixed price swaps	$	—	$	119,507		$	—	$	119,507
Crude oil collars		—		41,782			—		41,782
Crude oil NYMEX roll swaps		—		(391	)		—		(391	)
Natural gas fixed price swaps		—		(18,256	)		—		(18,256	)
Natural gas collars		—		45,035			—		45,035
Total	$	—	$	187,677		$	—	$	187,677


	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 $30.9 million and $33.8 million at June 30, 2025 and December 31, 2024, respectively, consists of the following.


In thousands	June 30, 2025		December 31, 2024
Credit facility	$	—	$	20,000
Notes payable		—		15,159
2.268% Senior Notes due 2026		797,828		797,056
4.375% Senior Notes due 2028		996,312		995,635
5.75% Senior Notes due 2031		1,488,072		1,487,175
2.875% Senior Notes due 2032		794,129		793,740
4.9% Senior Notes due 2044		692,796		692,682
Total debt	$	4,769,137	$	4,801,447
Less: Current portion of long-term debt		—		2,587
Long-term debt, net of current portion	$	4,769,137	$	4,798,860

Credit Facility

The Company has a credit facility, maturing in October 2029, with aggregate lender commitments totaling $1.8 billion. 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 ~~March~~June 3130, 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, 2025.

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

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 June 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 ~~March~~June 3130, 2025.

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, ~~Jul~~July 15

April 1, Oct 1

June 1, Dec 1

Make-whole redemption period (1)

Nov 15, 2023

Oct 15, 2027

~~Jul~~July 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 ~~March~~June 3130, 2025.

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. 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.

10Notes Payable

In May 2025, the Company fully repaid the outstanding $14.4 million principal balance of its term loans, which were secured by the Company's corporate office building and parking facility interests in Oklahoma City, Oklahoma. These loans were scheduled to mature in May 2030.

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

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, require the Company to pay per-unit transportation, gathering, or processing charges regardless of the amount of capacity used. Future commitments remaining as of ~~March~~June 3130, 2025 under the arrangements amount to approximately $~~727~~654 million, of which $~~228~~155 million is expected to be incurred in the remainder of 2025, $218 million in 2026, $203 million in 2027, $70 million in 2028, $3 million in 2029, and $5 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 matter is currently set for trial in May 2026. The defendants continue to vigorously defend themselves against these claims.

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. 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~~In 9the 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 for the three and six month periods ended June 30, 2024 to reflect the intrinsic value of the redemption optionality features contained in the arrangement pursuant to ASC Topic 820, Fair Value Measurement. ~~Incentive~~That ~~Compensation~~financial statement impact 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 and subject to numerous uncertainties and cannot be reasonably quantified. There have been no share repurchases or settlements under the agreement since its inception.

The Company has granted incentive compensation awards to employees pursuant to the Continental Resources, Inc. 2022 Long-Term Incentive Plan (“2022 Plan”). Awards granted 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 12

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

~~settle~~Note ~~all~~9. ~~outstanding~~Incentive ~~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.~~

AtThe ~~March 31, 2025, the~~ Company ~~had~~has ~~recorded~~granted aincentive ~~current~~compensation ~~liability~~awards ofto ~~$45.1~~employees ~~million~~pursuant ~~and~~to athe ~~non-current~~Continental ~~liability~~Resources, ~~of $6~~Inc.5 ~~million~~2022 inLong-Term ~~the~~Incentive ~~captions~~Plan (“~~Current~~2022 ~~portion of incentive compensation liability~~Plan”). ~~and~~Awards ~~“Incentive~~granted ~~compensation~~prior ~~liability,~~to ~~noncurrent,”~~2024 ~~respectively,~~generally invest ~~the~~after ~~condensed~~three ~~consolidated~~years ~~balance~~of ~~sheets~~employee ~~associated with the awards~~service. ~~Such~~Awards ~~amounts~~granted ~~reflect~~in ~~the~~2024 ~~Company’s~~and ~~estimate~~thereafter ofgenerally ~~expected~~vest ~~future~~annually, ~~cash~~in ~~payments~~one-third ~~multiplied~~increments, byover ~~the~~three ~~percentage~~years of ~~requisite~~employee service ~~periods that employees have completed as of March 31, 2025~~. The Company’s ~~compensation~~intends ~~expense~~to ~~associated~~settle ~~with~~all ~~such~~outstanding incentive awards, ~~which~~vesting ~~is included~~ in the ~~caption~~future ~~“General and administrative expenses”~~ in ~~the~~cash ~~condensed consolidated statements of income, was $23.4 million~~ and ~~$32.5 million for the three months ended March 31~~, ~~2025 and 2024~~thus, ~~respectively.~~the Asawards ofare ~~March~~classified ~~31,~~as ~~2025,~~liability ~~there was approximately $115.5 million of unrecognized liabilities and compensation expense related to unvested~~ awards, ~~which~~pursuant ~~are expected~~ to beASC ~~recognized~~Topic ~~over~~718, aCompensation—Stock ~~weighted average period of 1~~Compensation.6 ~~years.~~

At June 30, 2025, the Company had recorded a current liability of $53.6 million and a non-current liability of $10.8 million in the captions “Current portion of incentive compensation liability” and “Incentive compensation liability, noncurrent,” respectively, in the 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 June 30, 2025. The compensation expense associated with such awards totaled $13.4 million and $20.8 million for the three months ended June 30, 2025 and 2024, respectively, and $36.8 million and $53.3 million for the six months ended June 30, 2025 and 2024, respectively, which is included in the caption “General and administrative expenses” in the consolidated statements of income. As of June 30, 2025, there was approximately $84.8 million of unrecognized liabilities and compensation expense related to unvested awards, which are expected to be recognized over a weighted average period of 1.4 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.

12Note 10. Subsequent Event

On July 4, 2025, the One Big Beautiful Bill Act (the “Act”) was signed into law, which includes a broad range of tax reform provisions affecting businesses. The Company is in the process of evaluating the impact of the Act and will include changes resulting from the Act in its financial statements for the third quarter of 2025, the period of enactment. The Act is generally expected to have an overall favorable impact on the Company’s business primarily due to expected cash tax savings from the ability to accelerate certain income tax deductions. Because of the significant uncertainty inherent in numerous factors utilized in projecting financial statement income, taxable income, and potential tax payments, the Company cannot predict the impact of the Act’s future tax benefits with certainty.

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.

The following discussion and analysis includes forward-looking statements and should be read in conjunction with the risk factors described in Part II, Item 1A. Risk Factors included in this report, if any, and in our Form 10-K for the year ended December 31, 2024, 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, we pursue the acquisition and management of perpetually owned minerals located in certain of our key operating areas. We derive 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 has no publicly available common shares outstanding.

~~First~~Second Quarter 2025 Financial and Operating Metrics

Commodity prices have remained volatile due to various factors. Average NYMEX crude oil ~~prices for the three months ended March 31, 2025~~ and ~~2024 were $71.33 and $77.04, respectively. Average NYMEX~~ natural gas market prices for the ~~three~~periods ~~months~~presented ~~ended~~are ~~March~~shown ~~31,~~in ~~2025 and 2024 were $3.66 and $2.23, respectively. Crude oil prices have decreased subsequent to March 31, 2025, averaging $62.96 per barrel for~~ the ~~month of April 2025. The following~~ table ~~contains financial and operating metrics for the first quarter periods of 2025 and 2024~~below. ~~Average sales prices exclude any effect of derivative transactions. Per-unit expenses have been calculated using sales volumes.~~

	Three months ended March 31,
	Three months ended June 30,						Six months ended June 30,
	2025			2024			2025		2024
Average daily production:
Average NYMEX prices:
Crude oil (Bbl per day)		236,421			237,908
WTI Crude oil ($/Bbl)	$	64.57		$	81.81		$	68.12	$	79.69
Natural gas (Mcf per day) (1)		1,156,581			1,204,433
Henry Hub natural gas ($/MMBtu)	$	3.19		$	2.06		$	3.66	$	2.10
Crude oil equivalents (Boe per day)		429,185			438,647
Average sales prices:
Crude oil ($/Bbl)	$	70.26		$	75.96
Natural gas ($/Mcf) (1)	$	3.88		$	2.51
Production expenses ($/Boe)	$	5.18		$	4.74
Production and ad valorem taxes (% of net crude oil and natural gas sales)		7.5	%		8.2	%
Depreciation, depletion, amortization and accretion ($/Boe)	$	15.94		$	15.90
Total general and administrative expenses ($/Boe)	$	1.74		$	2.07

~~Natural~~The ~~gas~~following ~~production~~table ~~volumes,~~contains ~~sales~~financial ~~volumes,~~ and ~~sales~~operating ~~prices~~metrics for the periods presented. ~~throughout~~Average ~~management’s~~sales ~~discussion~~prices ~~and~~exclude ~~analysis~~any ~~reflect~~effect ~~the~~of ~~combined~~derivative ~~value~~transactions. ~~for~~Per-unit ~~natural~~expenses ~~gas~~have ~~and~~been ~~natural~~calculated ~~gas~~using ~~liquids~~sales volumes.


	Three months ended June 30,						Six months ended June 30,
	2025			2024			2025			2024
Average daily production:
Crude oil (Bbl per day)		238,910			231,646			237,673			234,777
Natural gas (Mcf per day) (1)		1,208,484			1,212,286			1,182,676			1,208,359
Crude oil equivalents (Boe per day)		440,324			433,693			434,785			436,170
Average sales prices:
Crude oil ($/Bbl)	$	62.52		$	80.22		$	66.33		$	78.08
Natural gas ($/Mcf) (1)	$	2.37		$	1.75		$	3.10		$	2.13
Production expenses ($/Boe)	$	5.01		$	4.60		$	5.09		$	4.67
Production and ad valorem taxes (% of net crude oil and natural gas sales)		7.7	%		8.3	%		7.6	%		8.2	%
Depreciation, depletion, amortization and accretion ($/Boe)	$	15.74		$	15.79		$	15.84		$	15.85
Total general and administrative expenses ($/Boe)	$	1.40		$	1.63		$	1.57		$	1.85

(1)

~~Three~~Natural ~~months~~gas ~~ended~~production ~~March~~volumes, 31sales volumes, ~~2025~~and ~~compared~~sales toprices presented throughout management's discussion and analysis reflect the ~~three~~combined ~~months~~value ~~ended~~for ~~March~~natural ~~31,~~gas ~~2024~~and natural gas liquids.

Three months ended June 30, 2025 compared to the three months ended June 30, 2024

Results of Operations

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

	Three months ended March 31,
	Three months ended June 30,
In thousands	2025			2024
Crude oil, natural gas, and natural gas liquids sales	$	1,~~890~~626,~~207~~374		$	1,~~909~~901,~~843~~788
Gain (loss) on derivative instruments, net		(316,002	)		(113,194	)
Gain on derivative instruments, net		451,254			4,729
Crude oil and natural gas service operations		3633,~~248~~750			2320,~~895~~430
Total revenues		12,~~610~~111,~~453~~378			1,~~820~~926,~~544~~947
Operating costs and expenses		(1,~~140~~133,~~936~~550	)		(1,~~201~~185,~~340~~359	)
Other expenses, net		(5146,~~526~~778	)		(76457,~~657~~660	)
Income before income taxes		~~417~~931,~~991~~050			~~542~~283,~~547~~928
Provision for income taxes		(86195,~~380~~191	)		(~~114~~148,~~054~~535	)
Income before equity in net loss of affiliate		~~331~~735,~~611~~859			~~428~~135,~~493~~393
Equity in net loss of affiliate		(121,~~887~~528	)		(~~907~~1,305	)
Net income		~~318~~734,~~724~~331			~~427~~134,~~586~~088
Net income attributable to noncontrolling interests		2,718			464
Net income (loss) attributable to noncontrolling interests		7,132			(191	)
Net income attributable to Continental Resources	$	~~316~~727,~~006~~199		$	~~427~~134,~~122~~279
Production volumes:
Crude oil (MBbl)		21,~~278~~741			21,~~650~~079
Natural gas (MMcf)		~~104~~109,~~092~~972			~~109~~110,~~603~~318
Crude oil equivalents (MBoe)		3840,~~627~~069			39,~~917~~466
Sales volumes:
Crude oil (MBbl)		21,~~152~~853			21,~~524~~294
Natural gas (MMcf)		~~104~~109,~~092~~972			~~109~~110,~~603~~318
Crude oil equivalents (MBoe)		3840,~~501~~181			39,~~791~~681

Production

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

	Three months ended March 31,
Boe production per day	2Q 2025		2Q 2024		% Change
Boe production per day	2025		2024		% Change
Bakken		199,215		195,470		2	%
Bakken		183,879		201,466		(9	)%
Anadarko Basin		125,755		141,034		(11	)%
Anadarko Basin		127,879		141,745		(10	)%
Powder River Basin		26,280		23,894		10	%
Powder River Basin		27,578		26,539		4	%
Permian Basin		84,184		67,910		24	%
Permian Basin		84,892		63,489		34	%
All other		4,890		5,385		(9	)%
All other		4,957		5,408		(8	)%
Total		440,324		433,693		2	%
Total		429,185		438,647		(2	)%

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

	Three months ended March 31,													Volume
	Three months ended June 30,													Volume
	2025					2024					Volume			percent
	Volume		Percent			Volume		Percent			~~decrease~~change			~~decrease~~change
Crude oil (MBbl)		21,~~278~~741		5554	%		21,~~650~~079		5453	%		~~(372~~662	)	3%	(2	)%
Natural gas (MMcf)		~~104~~109,~~092~~972		4546	%		~~109~~110,~~603~~318		4647	%		(~~5,511~~346	)	–%	(5	)%
Total (MBoe)		3840,~~627~~069		100	%		39,~~917~~466		100	%		~~(1,290~~603	)	2%	(3	)%

The 23% ~~decrease~~increase in crude oil production and 5%slight decrease in natural gas production in the 2025 ~~first~~second quarter compared to the 2024 ~~first~~second quarter ~~were~~was primarily driven by ~~natural~~an ~~declines~~increase in ~~production~~allocation ~~coupled~~of ~~with~~capital ~~planned~~to ~~moderation~~oil-weighted projects in ~~capital~~our ~~spending,~~operating ~~asset~~areas ~~divestitures~~ and variation in the timing of new well completions ~~compared~~between ~~to the prior period~~years.

1415

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 $1.8963 billion for the ~~first~~second quarter of 2025, a 114% decrease compared to sales of $1.9190 billion for the ~~2024~~second ~~first~~ quarter of 2024 due to ~~decreases~~a decrease in ~~sales volumes and~~ crude oil sales prices, partially offset by an increase in natural gas sales prices and crude oil sales volumes.

Total sales volumes for the ~~first~~second quarter of 2025 ~~decreased~~increased ~~1,290~~500 MBoe, or 31%, compared to the ~~2024~~second ~~first~~ quarter ~~primarily~~of 2024 due to the previously described ~~decrease~~increase in crude oil production volumes. For the ~~first~~second quarter of 2025, our crude oil sales volumes ~~decreased~~increased 23%, ~~and~~while our natural gas sales volumes ~~decreased~~remained 5%consistent compared to the ~~2024~~second ~~first~~ quarter of 2024.

Our crude oil sales prices averaged $7062.2652 per barrel in the ~~2025~~second ~~first~~ quarter of 2025 compared to $7580.9622 per barrel for the second quarter of 2024. ~~first~~Our natural gas sales prices averaged $2.37 per Mcf for the second quarter of 2025 compared to $1.75 per Mcf for the second quarter of 2024.

~~Our~~Derivatives. ~~natural~~Changes ~~gas~~in ~~sales~~settled and future commodity prices ~~averaged~~during the second quarter of 2025 had a net favorable impact on the fair value of our derivatives, which resulted in positive revenue adjustments totaling $3451.883 ~~per~~million ~~Mcf~~ for the ~~2025~~period, ~~first~~representing ~~quarter~~$88.2 million of cash gains and $363.0 million of unsettled non-cash gains, compared to positive revenue adjustments totaling $24.517 ~~per~~million ~~Mcf~~in ~~for~~ the ~~2024~~second ~~first~~ quarter of 2024.

Derivatives. Changes in settled and future commodity prices during the first quarter of 2025 resulted in overall negative revenue adjustments totaling $316.0 million for the period, representing $16.9 million of cash gains more than offset by $332.9 million of unsettled non-cash losses, compared to overall negative revenue adjustments totaling $113.2 million in the first quarter of 2024.

Operating Costs and Expenses

Production Expenses. Production expenses increased $1018.78 million, or 610%, to $~~199~~201.4 million for the ~~first~~second quarter of 2025 compared to $~~188~~182.7 million for the ~~first~~second 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 $5.1801 per Boe for the ~~2025~~second ~~first~~ quarter of 2025 compared to $4.7460 per Boe for the ~~2024~~second ~~first~~ quarter of 2024.

Production and Ad Valorem Taxes. Production and ad valorem taxes decreased $1130.80 million, or 820%, to $~~135~~119.34 million for the ~~first~~second quarter of 2025 compared to $~~147~~149.14 million for the ~~first~~second quarter of 2024 primarily due to ~~the~~a ~~previously described~~ decrease in crude oil, ~~natural gas and NGL sales~~revenues. Our production taxes as a percentage of net sales averaged 7.57% for the ~~first~~second quarter of 2025, ~~a decrease~~ compared to 8.23% for the ~~first~~second quarter of 2024., ~~This~~the decrease ~~was~~of ~~the~~which ~~result~~resulted offrom changes in sales mix of crude oil and natural gas in ~~the~~our ~~Company’s~~ operating areas between periods.

Transportation, gathering, processing, and compression. These charges decreased $2915.06 million, or 2717%, to $7875.98 million for the ~~first~~second quarter of 2025 compared to $~~107~~91.95 million for the ~~first~~second 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 ~~decreased~~increased $196.20 million, or 31%, to $~~613~~632.6 million for the ~~first~~second quarter of 2025 compared to $~~632~~626.86 million for the ~~first~~second quarter of 2024 due to the previously described 31% ~~decrease~~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,
	Three months ended June 30,
$/Boe	2025		2024
Crude oil and natural gas	$	15.2001	$	15.2714
Other equipment		0.58		0.4951
Asset retirement obligation accretion		0.1615		0.14
Depreciation, depletion, amortization and accretion	$	15.9474	$	15.9079

General and Administrative Expenses. Total G&A expenses decreased $158.31 million, or 1913%, to $6756.05 million for the ~~first~~second quarter of 2025 compared to $8264.36 million for the ~~first~~second quarter of 2024. Such expenses include charges for incentive compensation awards of $13.4 million and $20.8 million for the second quarters 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

Total G&A expenses include charges for long-term incentive compensation awards of $23.4 million and $32.5 million for the first quarters of 2025 and 2024, respectively. This decrease is primarily due to a decrease in estimated incentive compensation payment 16

15volatility in the magnitude of expense recognized. G&A expenses other than incentive compensation awards totaled $43.1 million for the second quarter of 2025, consistent with $43.8 million recognized for the second quarter of 2024.

obligations arising from changes in the value of Company awards as of March 31, 2025 compared to the March 31, 2024 valuation date.

G&A expenses other than incentive compensation awards totaled $43.6 million for the 2025 first quarter, a decrease of $6.2 million compared to $49.8 million for the 2024 first quarter primarily due to changes in the extent of cost recoveries from joint interest owners 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 March 31,
	Three months ended June 30,
$/Boe	2025		2024
General and administrative expenses	$	1.1307	$	1.2511
Long-term incentive compensation awards		0.6133		0.8252
Total general and administrative expenses	$	1.7440	$	21.0763

Interest Expense. Interest expense decreased $2417.76 million, or 3124%, to $5554.12 million for the ~~first~~second quarter of 2025 compared to $7971.8 million for the ~~first~~second quarter of 2024 due to a decrease in our weighted average outstanding debt balance from $6.61 billion for the ~~first~~second quarter of 2024 to $4.98 billion for the ~~first~~second quarter of 2025. This decrease was driven by debt reduction throughout the past year, including the repayment of our $750 million term loan and redemption of our $893 million of 2024 senior notes. Our outstanding debt totaled $4.8 billion at March 31, 2025.

~~Income~~Other ~~Taxes. For the first quarters of 2025 and 2024 we provided for~~ income ~~taxes at a combined federal and state tax rate of 23~~(expense)—Other.5% ofSee ~~our~~Note ~~pre-tax income~~8. WeCommitments ~~recorded an income tax provision of $86.4 million for the 2025 first quarter~~ and anContingencies—Stock ~~income~~Redemption ~~tax~~Agreement ~~provision of $114.1 million for the 2024 first quarter, which resulted~~ in ~~effective~~Notes ~~tax~~to ~~rates~~Unaudited ofCondensed ~~20.7%~~Consolidated ~~and~~Financial 21Statements.~~0%, respectively, after taking into account the application of statutory tax rates, permanent taxable differences, estimated tax credits, and other items.~~

Income Taxes. For the second 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 $195.2 million and $148.5 million for the second quarters of 2025 and 2024, respectively, which resulted in effective tax rates of 21.0% and 52.3%, respectively, after taking into account the application of statutory tax rates, permanent taxable differences primarily related to the stock redemption agreement that impacted our effective tax rate for the second quarter of 2024 by 28.7%, estimated tax credits, and other items.

Six months ended June 30, 2025 compared to the six months ended June 30, 2024

Results of Operations

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


	Six months ended June 30,
In thousands	2025			2024
Crude oil, natural gas, and natural gas liquids sales	$	3,516,581		$	3,811,631
Gain (loss) on derivative instruments, net		135,252			(108,465	)
Crude oil and natural gas service operations		69,998			44,325
Total revenues		3,721,831			3,747,491
Operating costs and expenses		(2,274,486	)		(2,386,699	)
Other expenses, net		(98,304	)		(534,317	)
Income before income taxes		1,349,041			826,475
Provision for income taxes		(281,571	)		(262,589	)
Income before equity in net loss of affiliate		1,067,470			563,886
Equity in net loss of affiliate		(14,415	)		(2,212	)
Net income		1,053,055			561,674
Net income attributable to noncontrolling interests		9,850			273
Net income attributable to Continental Resources	$	1,043,205		$	561,401

Production volumes:
Crude oil (MBbl)		43,019			42,729
Natural gas (MMcf)		214,064			219,921
Crude oil equivalents (MBoe)		78,696			79,383
Sales volumes:
Crude oil (MBbl)		43,005			42,818
Natural gas (MMcf)		214,064			219,921
Crude oil equivalents (MBoe)		78,682			79,472

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 6/30/2025		YTD 6/30/2024		% Change
Bakken		191,589		198,468		(3	)%
Anadarko Basin		126,811		141,390		(10	)%
Powder River Basin		26,926		25,216		7	%
Permian Basin		84,536		65,699		29	%
All other		4,923		5,397		(9	)%
Total		434,785		436,170		(1	)%

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


	Six months ended June 30,													Volume
	2025					2024					Volume			percent
	Volume		Percent			Volume		Percent			change			change
Crude oil (MBbl)		43,019		55	%		42,729		54	%		290			1	%
Natural gas (MMcf)		214,064		45	%		219,921		46	%		(5,857	)		(3	)%
Total (MBoe)		78,696		100	%		79,383		100	%		(687	)		(1	)%

The 1% increase in crude oil production and 3% decrease in natural gas production for year to date 2025 compared to year to date 2024 was driven by an increase in allocation of capital to oil-weighted projects in our operating areas and variation in the timing of new well completions between years.

Revenues

Crude oil, natural gas, and natural gas liquids sales. Sales for year to date 2025 totaled $3.52 billion, an 8% decrease compared to $3.81 billion for the comparable 2024 period driven by decreases in crude oil sales prices and natural gas sales volumes, partially offset by an increase in natural gas sales prices as discussed below.

Total sales volumes for year to date 2025 decreased 790 MBoe, or 1%, compared to year to date 2024 primarily due to the previously described decrease in natural gas production volumes. For year to date 2025, our natural gas sales volumes decreased 3% while our crude oil sales volumes remained consistent compared to year to date 2024.

Our crude oil sales prices averaged $66.33 per barrel for year to date 2025 compared to $78.08 per barrel for year to date 2024. Our natural gas sales prices averaged $3.10 per Mcf for year to date 2025 compared to $2.13 per Mcf for year to date 2024.

Derivatives. Changes in settled and future commodity prices during the six months ended June 30, 2025 had a net favorable impact on the fair value of our derivatives, which resulted in positive revenue adjustments totaling $135.3 million for the period, representing $105.1 million of cash gains and $30.2 million of unsettled non-cash gains, compared to negative revenue adjustments totaling $108.5 million in the comparable 2024 period.

Operating Costs and Expenses

Production Expenses. Production expenses increased $29.5 million, or 8%, to $400.8 million for year to date 2025 compared to $371.4 million for year to date 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 $5.09 per Boe for year to date 2025 compared to $4.67 per Boe for year to date 2024.

Production and Ad Valorem Taxes. Production and ad valorem taxes decreased $41.7 million, or 14%, to $254.8 million for year to date 2025 compared to $296.5 million for year to date 2024 primarily due to a decrease in crude oil revenues. Our production taxes as a percentage of net sales averaged 7.6% for year to date 2025 compared to 8.2% for year to date 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 $44.7 million, or 22%, to $154.7 million for year to date 2025 compared to $199.4 million for year to date 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 decreased $13.2 million, or 1%, to $1.25 billion for year to date 2025 compared to $1.26 billion for year to date 2024 due to the previously described 1% decrease in total sales volumes. The following table shows the components of our DD&A on a unit of sales basis for the periods presented.


	Six months ended June 30,
$/Boe	2025		2024
Crude oil and natural gas	$	15.10	$	15.21
Other equipment		0.58		0.50
Asset retirement obligation accretion		0.16		0.14
Depreciation, depletion, amortization and accretion	$	15.84	$	15.85

General and Administrative Expenses. Total G&A expenses decreased $23.4 million, or 16%, to $123.5 million for year to date 2025 compared to $146.9 million for year to date 2024. Such expenses include charges for incentive compensation awards of $36.8 million and $53.3 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 volatility in the magnitude of expense recognized. G&A expenses other than incentive compensation awards totaled $86.7 million for year to date 2025, a decrease of $6.9 million compared to $93.6 million for year to date 2024 primarily due to changes in the nature and timing of employee-related costs and benefits recognized between periods and 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.


	Six months ended June 30,
$/Boe	2025		2024
General and administrative expenses	$	1.10	$	1.18
Long-term incentive compensation awards		0.47		0.67
Total general and administrative expenses	$	1.57	$	1.85

Interest Expense. Interest expense decreased $42.3 million, or 28%, to $109.4 million for year to date 2025 compared to $151.6 million for year to date 2024 due to a decrease in our weighted average outstanding debt balance from $6.3 billion for year to date 2024 to $4.8 billion for year to date 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 six months ended June 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 $281.6 million and $262.6 million for the year to date periods of 2025 and 2024, respectively, which resulted in effective tax rates of 20.9% and 31.8%, respectively, after taking into account the application of statutory tax rates, permanent taxable differences primarily related to the stock redemption agreement that impacted our effective tax rate for the year to date period of 2024 by 9.9%, 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 ~~March~~June 3130, 2025, we had $1.8 billion of borrowing availability with no outstanding borrowings under our credit facility, along with $~~591~~569.2 million of cash on hand. Our credit facility, which is unsecured and has no borrowing base subject to redetermination, does not mature until October 2029.

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 March 31, 2025, 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.19

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 June 30, 2025, 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 $~~179.3~~80 million, or 153%, to $12.4027 billion for ~~the~~year ~~first~~to ~~quarter~~date of 2025 compared to $12.2235 billion for ~~the~~year ~~first~~to ~~quarter~~date of 2024. The ~~increase~~decrease was primarily driven by aour $295.1 million decrease in ~~certain~~crude ~~cash~~oil, ~~operating~~natural ~~expenses~~gas and NGL revenues. In addition, ~~which~~our ~~included~~production aexpenses increased $29.1 million ~~decrease~~and inour ~~transportation,~~realized ~~gathering,~~cash ~~processing,~~gains ~~and~~on ~~compression~~matured ~~expenses~~commodity ~~and~~derivatives andecreased $~~11.8~~78 million ~~decrease~~compared into ~~production~~the ~~and~~prior adyear ~~valorem~~to ~~taxes,~~date ~~along~~period. ~~with~~These ~~changes~~decreases in ~~working~~operating ~~capital~~cash ~~items~~flows ~~from~~were ~~period~~partially tooffset ~~period.~~by ~~Additionally,~~a ~~our~~$50 million decrease in cash ~~payments~~paid for ~~incentive~~interest, ~~compensation~~a ~~decreased~~ $~~58.7~~45 million ~~and~~decrease ~~interest~~in ~~paid~~transportation, ongathering, ~~outstanding~~processing, ~~debt~~and ~~decreased~~compression expenses, a $~~20.8~~42 million. ~~These~~decrease ~~benefits~~in toproduction ~~operating~~and ~~cash~~ad ~~flows~~valorem ~~were~~taxes, ~~partially offset by~~ a $~~19.6~~60 million decrease in ~~crude~~cash ~~oil,~~payments ~~natural~~for ~~gas~~incentive compensation, and ~~NGL revenues and~~ a $~~78.3~~41 million decrease in ~~realized~~ cash ~~gains~~payments onfor ~~matured~~income ~~commodity~~taxes, ~~derivatives~~along ~~compared~~with tochanges ~~the~~in ~~prior~~working capital items from period to period.

Cash flows from investing activities

Net cash used in investing activities totaled $~~824~~1.269 ~~million~~billion for ~~the~~year ~~first~~to ~~quarter~~date of 2025, ancompared ~~increase~~to of $~~106~~1.402 ~~million,~~billion ~~or 15%, from $717.7 million~~ for ~~the~~year ~~first~~to ~~quarter~~date of 2024. Our investing cash flows for ~~first~~year ~~quarter~~to date 2025 included $~~774~~1.661 ~~million~~billion of exploration and development costs compared to $~~663~~1.036 ~~million~~billion for ~~first~~year ~~quarter~~to date 2024, the increase of which reflects changes in the planned timing of our annual capital spending between periods. ~~For~~In ~~full~~addition, ~~year~~proceeds ~~2025~~received ~~our~~from ~~capital~~the ~~expenditures~~sale ~~budget~~of ~~attributable~~assets todecreased usby ~~is approximately~~ $2441.82 ~~billion~~million ~~compared~~for year to ~~$3.3~~date ~~billion~~2025 ofcompared ~~non-acquisition~~to ~~capital~~the ~~spending~~prior inyear ~~full~~to ~~year~~date ~~2024~~period.

Cash flows from financing activities

Net cash used in financing activities for ~~the~~year ~~first~~to ~~quarter~~date of 2025 totaled $2550.1 million, primarily consisting of $2035.2 million of net repayments on ~~our~~outstanding ~~credit~~debt ~~facility~~and $18.7 million of cash distributed to noncontrolling interests. Net cash used in financing activities for year to date 2024 totaled $1.25 billion due to $1.25 billion of net repayments on outstanding debt.

Net cash used in financing activities for the first quarter of 2024 totaled $311 million, primarily consisting of $210 million of net repayments on our credit facility and a $100 million repayment of our $750 million term loan.

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 for 2025 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 resulting from tariffs, 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. 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 ~~March~~June 3130, 2025 and expect to maintain compliance. At ~~March~~June 3130, 2025, our consolidated net debt to total capitalization ratio was 0.23. 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 ~~March~~June 3130, 2025, 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 ~~April~~July 3031, 2025, 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. 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 ~~March~~June 3130, 2025 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 ~~April~~July 3031, 2025, we had 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 ~~March~~June 3130, 2025 under the arrangements amount to approximately $~~727~~654 million. See Note 8. Commitments and Contingencies in Notes to Unaudited Condensed Consolidated Financial Statements for additional information.

Capital expenditures

Our capital expenditures budget for 2025 is ~~expected to be~~ approximately $2.8 billion. Costs of acquisitions and investments are not budgeted, with the exception of planned levels of spending for mineral acquisitions.

~~For the three months ended March 31, 2025, we invested $755.1 million in our capital program excluding $2.7 million of mineral acquisitions attributable to Franco-Nevada.~~21

For the six months ended June 30, 2025, we invested $1.6 billion in our capital program, excluding $1.8 million of unbudgeted acquisitions and $5.2 million of mineral acquisitions attributable to Franco-Nevada.

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.

Critical Accounting Policies and Estimates

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

Inflation

Inflationary pressures experienced in recent years may persist or worsen in 2025. Some of the underlying factors impacting inflation may include, but are not limited to, global supply chain disruptions, 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.

19Legislative and Regulatory Developments

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 that we expect will be impactful to our business.

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

Research and development (R&D) costs – The Act repeals a current provision that requires 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 introduces 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.  

We are in the process of evaluating the impact of the Act. The Act is generally expected to have an overall favorable impact on our business primarily due to expected cash tax savings from the ability to accelerate income tax deductions as described above. Because of the significant uncertainty inherent in numerous factors utilized in projecting financial statement income, taxable income, and potential tax payments, we cannot predict the impact of the Act’s future tax benefits with certainty.

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. 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 ~~three~~the six months ended ~~March~~June 3130, 2025, and excluding the effect of derivative instruments in place, our annual revenue would increase or decrease by approximately $~~863~~868 million for each $10.00 per barrel change in crude oil prices at ~~March~~June 3130, 2025 and $~~422~~432 million for each $1.00 per Mcf change in natural gas prices at ~~March~~June 3130, 2025.

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 ~~March~~June 3130, 2025 was a net ~~liability~~asset of $~~175~~187.37 million, which is comprised of a $~~134~~26.68 million net ~~liability~~asset associated with our natural gas derivatives and a $40160.79 million net ~~liability~~asset associated with our crude oil 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 ~~March~~June 3130, 2025.

		Hypothetical Fair Value
In thousands	Change in Forward Price	Asset (Liability)
Crude Oil	-10%	$	~~227~~482,~~196~~602
Crude Oil	+10%	$	(~~323~~161,~~579~~879	)
Natural Gas	-10%	$	~~138~~280,~~526~~280
Natural Gas	+10%	$	(~~405~~225,~~863~~326	)

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 ($1.10 billion in receivables at ~~March~~June 3130, 2025), and our joint interest and other receivables ($~~368~~446.5 million at ~~March~~June 3130, 2025).

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 $4957.89 million at ~~March~~June 3130, 2025, which will be used to

2024

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 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 ~~April~~July 3031, 2025.

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.

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 ~~March~~June 3130, 2025 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 ~~March~~June 3130, 2025, 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.

2125

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.

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 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 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 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.

2226

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

2327

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:	~~May~~August 21, 2025	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)

2428

(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)

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