UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

________________________________________

FORM 10-Q

________________________________________

(Mark One)


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

For the quarterly period ended ~~September~~March 3031, ~~2023~~2024


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

For the transition period from to

Commission File Number: 001-32886

____________________________________

CONTINENTAL RESOURCES, INC

(Exact name of registrant as specified in its charter)

____________________________________

(405) 234-9000

(Registrant’s telephone number, including area code)

Not Applicable

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

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

____________________________________

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

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

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


Large accelerated filer	☐	Accelerated filer	☐
Non-accelerated filer	x	Smaller reporting company	☐
		Emerging growth company	☐

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

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

As of ~~September~~March 3031, ~~2023~~2024, 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 Statements of Income	2
	Unaudited Condensed Consolidated Statements of Equity	3
	Unaudited Condensed Consolidated Statements of Cash Flows	54
	Notes to Unaudited Condensed Consolidated Financial Statements	65
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	1713
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	3021
Item 4.	Controls and Procedures	3122
PART II. Other Information
Item 1.	Legal Proceedings	3223
Item 1A.	Risk Factors	3223
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	3223
Item 3.	Defaults Upon Senior Securities	3223
Item 4.	Mine Safety Disclosures	3223
Item 5.	Other Information	3223
Item 6.	Exhibits	3324
	Signature	3425
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.

“completion” The process of treating a drilled well followed by the installation of permanent equipment for the production of crude oil and/or natural gas.

“developed acreage” The number of acres allocated or assignable to productive wells or wells capable of production.

“development well” A well drilled within the proved area of a crude oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

“dry hole” Exploratory or development well that does not produce crude oil and/or natural gas in economically producible quantities.

“exploratory well” A well drilled to find crude oil or natural gas in an unproved area, to find a new reservoir in an existing field previously found to be productive of crude oil or natural gas in another reservoir, or to extend a known reservoir beyond the proved area.

“field” An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

“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.

“Net crude oil, natural gas, and natural gas liquids sales” Represents total crude oil, natural gas, and natural gas liquids sales less total transportation expenses. Net crude oil, natural gas, and natural gas liquids sales presented herein are non-GAAP measures. See Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Financial Measures for a discussion and calculation of this measure.

“Net sales price” Represents the average net wellhead sales price received by the Company for its sales after deducting transportation expenses. Net sales price is calculated by taking revenues less transportation expenses divided by sales volumes for a period. Net sales prices presented herein are non-GAAP measures. See Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Financial Measures for a discussion and calculation of this measure.

“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.

“play” A portion of the exploration and production cycle following the identification by geologists and geophysicists of areas with potential crude oil and natural gas reserves.

“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.

“royalty interest” Refers to the ownership of a percentage of the resources or revenues produced from a crude oil or natural gas property. A royalty interest owner does not bear exploration, development, or operating expenses associated with drilling and producing a crude oil or natural gas property.i

“undeveloped acreage” Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of crude oil and/or natural gas.

“working interest” The right granted to the lessee of a property to explore for and to produce and own crude oil, natural gas, or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.

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 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;

•

current and potential litigation matters;

•

geopolitical events and conditions in, or affecting other, crude oil-producing and natural gas-producing nations;

•

credit markets;

•

our liquidity and access to capital;

•

the impact of governmental policies, laws and regulations, as well as regulatory and legal proceedings involving us and of scheduled or potential regulatory or legal changes;

•

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, ~~2022~~2023, and other announcements we make from time to time.

~~iii~~ii

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, ~~2022~~2023 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.

iviii

PART I. Financial Information

ITEM 1. Financial Statements

Continental Resources, Inc. and Subsidiaries

Condensed Consolidated Balance Sheets

	September 30, 2023			December 31, 2022
	March 31, 2024			December 31, 2023
In thousands, except par values and share data	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	49219,~~253~~664		$	~~137~~26,~~788~~397
Receivables:
Crude oil, natural gas, and natural gas liquids sales		1,~~321~~228,~~161~~233			1,~~313~~196,~~538~~262
Joint interest and other		~~384~~302,~~512~~009			~~458~~350,~~391~~907
Allowance for credit losses		(3,~~751~~731	)		(53,~~514~~172	)
Receivables, net		1,~~701~~526,~~922~~511			1,~~766~~543,~~415~~997
Derivative assets		78216,~~644~~385			39353,~~280~~261
Inventories		~~207~~218,~~635~~383			~~173~~190,~~264~~762
Prepaid expenses and other		3036,~~885~~554			2733,~~508~~450
Total current assets		2,~~068~~217,~~339~~497			2,~~144~~147,~~255~~867
Net property and equipment, based on successful efforts method of accounting		19,~~626~~822,~~889~~519			1819,~~471~~786,~~914~~889
Investment in unconsolidated affiliates		~~226~~247,~~340~~804			~~210~~240,~~805~~484
Operating lease right-of-use assets		4134,~~339~~560			2538,~~158~~656
Derivative assets, noncurrent		18142,~~935~~545			3155,~~548~~252
Other noncurrent assets		1721,~~960~~120			2218,~~670~~293
Total assets	$	2122,~~999~~486,~~802~~045		$	2022,~~878~~387,~~350~~441
Liabilities and equity
Current liabilities:
Accounts payable trade	$	~~907~~824,~~717~~616		$	~~850~~835,~~547~~012
Revenues and royalties payable		~~848~~730,~~043~~385			~~882~~768,~~256~~381
Accrued liabilities and other		~~332~~283,~~144~~609			~~343~~354,~~777~~537
Current portion of incentive compensation liability		~~130~~46,~~503~~450			~~125~~130,~~653~~583
Current portion of income tax liabilities		66190,~~667~~061			~~152~~84,~~149~~556
Derivative liabilities		~~175~~58,~~384~~858			~~88,136~~—
Current portion of operating lease liabilities		1715,~~847~~377			418,~~086~~112
Current portion of long-term debt		~~894~~895,~~777~~437			~~638~~895,~~058~~105
Total current liabilities		3,~~373~~044,~~082~~793			3,~~084~~086,~~662~~286
Long-term debt, net of current portion		65,~~454~~424,~~038~~983			75,~~571~~734,~~582~~007
Other noncurrent liabilities:
Deferred income tax liabilities, net		2,~~706~~879,~~680~~099			2,~~538~~867,~~312~~283
Incentive compensation liability, noncurrent		3717,~~818~~032			~~100~~41,~~066~~707
Asset retirement obligations, noncurrent		~~271~~404,~~048~~945			~~257~~391,~~152~~957
Derivative liabilities, noncurrent		~~39,494~~534			~~133,363~~586
Operating lease liabilities, noncurrent		2218,~~389~~101			2019,~~055~~482
Other noncurrent liabilities		3151,~~224~~840			4336,~~550~~346
Total other noncurrent liabilities		3,~~108~~371,~~653~~551			3,~~092~~357,~~498~~361
Commitments and contingencies (Note 9)
Commitments and contingencies (Note 8)
Equity:
Preferred stock, $0.01 par value; 25,000,000 shares authorized; no shares issued and outstanding		—			—
Common stock, $0.01 par value; 1,000,000,000 shares authorized
299,610,267 shares issued and outstanding at September 30, 2023;
299,610,267 shares issued and outstanding at March 31, 2024 and December 31, 2023		2,996			2,996
299,610,267 shares issued and outstanding at December 31, 2022;		2,996			2,996
Retained earnings		10,277,821			9,850,687
Retained earnings		8,700,724			6,754,174
Total shareholders’ equity attributable to Continental Resources		10,280,817			9,853,683
Total shareholders’ equity attributable to Continental Resources		8,703,720			6,757,170
Noncontrolling interests		363,901			356,104
Noncontrolling interests		360,309			372,438
Total equity		10,644,718			10,209,787
Total equity		9,064,029			7,129,608
Total liabilities and equity	$	22,486,045		$	22,387,441
Total liabilities and equity	$	21,999,802		$	20,878,350

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 September 30,						Nine months ended September 30,
	Three months ended March 31,
In thousands, except per share data	~~2023~~2024			~~2022~~2023			~~2023~~			~~2022~~
Revenues:
Crude oil, natural gas, and natural gas liquids sales	$	21,~~082~~909,~~331~~843		$	21,~~767~~791,~~262~~720		$	~~5,663,672~~		$	~~7,870,696~~
Gain (loss) on derivative instruments, net		(~~335~~113,~~111~~194	)		~~(337~~382,~~778~~779	)		~~270,795~~			~~(1,009,460~~	)
Crude oil and natural gas service operations		3023,~~119~~895			1719,~~747~~354			~~73,716~~			~~52,707~~
Total revenues		1,~~777~~820,~~339~~544			2,~~447~~193,~~231~~853			~~6,008,183~~			~~6,913,943~~
Operating costs and expenses:
Production expenses		~~175~~188,~~804~~697			~~166~~181,~~322~~986			~~532,197~~			~~456,840~~
Production and ad valorem taxes		~~162~~147,~~535~~127			~~200~~136,~~593~~175			~~440,364~~			~~563,204~~
Transportation, gathering, processing, and compression		86107,~~873~~946			8577,~~650~~869			~~245,267~~			~~236,851~~
Exploration expenses		24,~~835~~110			23,~~809~~378			~~10,747~~			~~20,460~~
Crude oil and natural gas service operations		2226,~~364~~640			1017,~~356~~832			~~61,343~~			~~29,361~~
Depreciation, depletion, amortization and accretion		~~576~~632,~~995~~763			~~490~~476,~~523~~454			~~1,603,618~~			~~1,396,185~~
Property impairments		1112,~~027~~062			1213,~~794~~074			~~46,469~~			~~52,868~~
General and administrative expenses		~~112~~82,~~368~~282			6863,~~687~~271			~~230,752~~			~~206,098~~
Net (gain) loss on sale of assets and other		~~51,389~~(287	)		(~~618~~186	)		~~51,041~~			~~(773~~	)
Total operating costs and expenses		1,~~202~~201,~~190~~340			1969,~~037,116~~853			~~3,221,798~~			~~2,961,094~~
Income from operations		~~575~~619,~~149~~204			1,~~410~~224,~~115~~000			~~2,786,385~~			~~3,952,849~~
Other income (expense):
Interest expense		(~~100~~79,~~885~~811	)		(7099,~~717~~681	)		~~(306,014~~	)		~~(215,508~~	)
Loss on extinguishment of debt		—			—			—			(403	)
Other		3,154			1,754
Other		3,902			4,490			8,561			4,503
		(76,657	)		(97,927	)
		(96,983	)		(66,227	)		(297,453	)		(211,408	)
Income before income taxes		542,547			1,126,073
Income before income taxes		478,166			1,343,888			2,488,932			3,741,441
Provision for income taxes		(114,054	)		(239,756	)
Provision for income taxes		(105,994	)		(323,390	)		(539,139	)		(903,745	)
Income before equity in net loss of affiliate		428,493			886,317
Income before equity in net loss of affiliate		372,172			1,020,498			1,949,793			2,837,696
Equity in net loss of affiliate		(907	)		(663	)
Equity in net loss of affiliate		(883	)		(660	)		(2,041	)		(736	)
Net income		427,586			885,654
Net income		371,289			1,019,838			1,947,752			2,836,960
Net income attributable to noncontrolling interests		464			1,357
Net income attributable to noncontrolling interests		501			6,731			1,854			17,349
Net income attributable to Continental Resources	$	427,122		$	884,297
Net income attributable to Continental Resources	$	370,788		$	1,013,107		$	1,945,898		$	2,819,611
Net income per share attributable to Continental Resources:
Basic	$	1.24		$	2.83		$	6.49		$	7.88
Diluted	$	1.24		$	2.80		$	6.49		$	7.79

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

Continental Resources, Inc. and Subsidiaries

Unaudited Condensed Consolidated Statements of Equity

Three months ended September 30, 2023
Three Months Ended March 31, 2024
	Shareholders’ equity attributable to Continental Resources
In thousands, except share data	Sharesoutstanding		Commonstock		~~Additionalpaid-incapital~~Retainedearnings		~~Treasurystock~~Totalshareholders’equity ofContinentalResources		~~Retainedearnings~~Noncontrollinginterests			~~Totalshareholders’equity~~Total ~~ofContinentalResources~~equity			~~Noncontrollinginterests~~			~~Total equity~~
Balance at June 30, 2023		299,610,267	$	2,996	$	—	$	—	$	8,329,936		$	8,332,932		$	362,513		$	8,695,445
Balance at December 31, 2023		299,610,267	$	2,996	$	9,850,687	$	9,853,683	$	356,104		$	10,209,787
Net income		—		—		—427,122		—427,122		~~370,788~~464			~~370~~427,~~788~~586			~~501~~			~~371,289~~
Change in dividends payable		—		—		—12		—12		—			—12			—			—
Contributions from noncontrolling interests		—		—		—		—		—14,040			—14,040			~~2,636~~			~~2,636~~
Distributions to noncontrolling interests		—		—		—		—		—(6,707	)		—(6,707	)		~~(5,341~~	)		~~(5,341~~	)
Balance at September 30, 2023		299,610,267	$	2,996	$	—	$	—	$	8,700,724		$	8,703,720		$	360,309		$	9,064,029
Balance at March 31, 2024		299,610,267	$	2,996	$	10,277,821	$	10,280,817	$	363,901		$	10,644,718

Nine months ended September 30, 2023
Three Months Ended March 31, 2023
	Shareholders’ equity attributable to Continental Resources
In thousands, except share data	Sharesoutstanding		Commonstock		~~Additionalpaid-incapital~~Retainedearnings		~~Treasurystock~~Totalshareholders’equity ofContinentalResources		~~Retainedearnings~~Noncontrollinginterests			~~Totalshareholders’equity~~Total ~~ofContinentalResources~~equity			~~Noncontrollinginterests~~			~~Total equity~~
Balance at December 31, 2022		299,610,267	$	2,996	$	—6,754,174	$	—6,757,170	$	6372,~~754,174~~438		$	67,~~757~~129,~~170~~608		$	~~372,438~~		$	~~7,129,608~~
Net income		—		—		—884,297		—884,297		1,~~945,898~~357			1885,~~945,898~~654			~~1,854~~			~~1,947,752~~
Change in dividends payable		—		—		—616		—616		~~652~~—			~~652~~616			—			~~652~~
Contributions from noncontrolling interests		—		—		—		—		—2,526			—2,526			~~8,809~~			~~8,809~~
Distributions to noncontrolling interests		—		—		—		—		—(10,432	)		—(10,432	)		~~(22,792~~	)		~~(22,792~~	)
Balance at September 30, 2023		299,610,267	$	2,996	$	—	$	—	$	8,700,724		$	8,703,720		$	360,309		$	9,064,029
Balance at March 31, 2023		299,610,267	$	2,996	$	7,639,087	$	7,642,083	$	365,889		$	8,007,972

Three months ended September 30, 2022
	Shareholders’ equity attributable to Continental Resources
In thousands, except share data	Sharesoutstanding			Commonstock			Additionalpaid-incapital			Treasurystock		Retainedearnings			Totalshareholders’equity ofContinentalResources			Noncontrollinginterests			Total equity
Balance at June 30, 2022		363,002,130		$	3,630		$	1,042,891		$	—	$	7,961,406		$	9,007,927		$	377,897		$	9,385,824
Net income		—			—			—			—		1,013,107			1,013,107			6,731			1,019,838
Cash dividends declared		—			—			—			—		(101,639	)		(101,639	)		—			(101,639	)
Change in dividends payable		—			—			—			—		56			56			—			56
Stock-based compensation		—			—			16,664			—		—			16,664			—			16,664
Restricted stock:
Granted		107,134			1			—			—		—			1			—			1
Repurchased and canceled		(13,420	)		—			(922	)		—		—			(922	)		—			(922	)
Forfeited		(73,098	)		(1	)		—			—		—			(1	)		—			(1	)
Contributions from noncontrolling interests		—			—			—			—		—			—			4,329			4,329
Distributions to noncontrolling interests		—			—			—			—		—			—			(12,403	)		(12,403	)
Balance at September 30, 2022		363,022,746		$	3,630		$	1,058,633		$	—	$	8,872,930		$	9,935,193		$	376,554		$	10,311,747

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

Continental Resources, Inc. and Subsidiaries

Unaudited Condensed Consolidated Statements of ~~Equity~~Cash ~~(Continued)~~Flows

Nine months ended September 30, 2022
	Three months ended March 31,
	Shareholders’ equity attributable to Continental Resources
In thousands	2024			2023
In thousands, except share data	Sharesoutstanding			Commonstock			Additionalpaid-incapital			Treasurystock			Retainedearnings			Totalshareholders’equity ofContinentalResources			Noncontrollinginterests			Total equity
Cash flows from operating activities
Balance at December 31, 2021		364,297,520		$	3,643		$	1,131,602		$	—		$	6,340,211		$	7,475,456		$	380,869		$	7,856,325
Net income	$	427,586		$	885,654
Net income		—			—			—			—			2,819,611			2,819,611			17,349			2,836,960
Adjustments to reconcile net income to net cash provided by operating activities:
Cash dividends declared		—			—			—			—			(287,036	)		(287,036	)		—			(287,036	)
Depreciation, depletion, amortization and accretion		636,659			479,602
Change in dividends payable		—			—			—			—			144			144			—			144
Property impairments		12,062			13,074
Common stock repurchased		—			—			—			(99,855	)		—			(99,855	)		—			(99,855	)
Non-cash (gain) loss on derivatives		208,390			(331,089	)
Common stock retired		(1,842,422	)		(18	)		(99,837	)		99,855			—			—			—			—
Provision for deferred income taxes		11,816			100,693
Stock-based compensation		—			—			60,751			—			—			60,751			—			60,751
Equity in net loss of affiliate		907			663
Restricted stock:
Net (gain) loss on sale of assets and other		(287	)		(186	)
Granted		1,539,017			15			—			—			—			15			—			15
Other, net		23,567			3,988
Repurchased and canceled		(605,162	)		(6	)		(33,883	)		—			—			(33,889	)		—			(33,889	)
Changes in assets and liabilities:
Forfeited		(366,207	)		(4	)		—			—			—			(4	)		—			(4	)
Accounts receivable		23,062			253,744
Contributions from noncontrolling interests		—			—			—			—			—			—			8,135			8,135
Inventories		(27,564	)		(19,669	)
Distributions to noncontrolling interests		—			—			—			—			—			—			(29,799	)		(29,799	)
Other current assets		(1,331	)		(3,191	)
Balance at September 30, 2022		363,022,746		$	3,630		$	1,058,633		$	—		$	8,872,930		$	9,935,193		$	376,554		$	10,311,747
Accounts payable trade		27,166			61,761
Revenues and royalties payable		(39,001	)		(223,212	)
Accrued liabilities and other		(70,148	)		(66,745	)
Incentive compensation liability		(108,809	)		(129,362	)
Current income taxes liability		105,504			139,063
Other noncurrent assets and liabilities		(7,701	)		(14,950	)
Net cash provided by operating activities		1,221,878			1,149,838
Cash flows from investing activities
Exploration and development		(663,003	)		(863,989	)
Purchase of producing crude oil and natural gas properties		(870	)		(97,550	)
Purchase of other property and equipment		(49,963	)		(60,374	)
Proceeds from sale of assets		4,340			1,223
Contributions to unconsolidated affiliates		(8,227	)		—
Net cash used in investing activities		(717,723	)		(1,020,690	)
Cash flows from financing activities
Credit facility borrowings		749,000			1,073,000
Repayment of credit facility		(959,000	)		(1,272,000	)
Repayment of other debt		(100,616	)		(597	)
Debt issuance costs		—			(241	)
Contributions from noncontrolling interests		7,740			1,872
Distributions to noncontrolling interests		(5,681	)		(11,354	)
Dividends paid on common stock		(2,331	)		(2,051	)
Net cash used in financing activities		(310,888	)		(211,371	)
Net change in cash and cash equivalents		193,267			(82,223	)
Cash and cash equivalents at beginning of period		26,397			137,788
Cash and cash equivalents at end of period	$	219,664		$	55,565

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

Continental Resources, Inc. and Subsidiaries

Unaudited Condensed Consolidated Statements of Cash Flows

	Nine months ended September 30,
In thousands	2023			2022
Cash flows from operating activities
Net income	$	1,947,752		$	2,836,960
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion		1,607,034			1,395,312
Property impairments		46,469			52,868
Non-cash (gain) loss on derivatives		(61,371	)		605,822
Stock-based compensation		—			60,766
Provision for deferred income taxes		168,368			425,089
Equity in net loss of affiliate		2,041			736
Dry hole costs		—			12,107
Net (gain) loss on sale of assets and other		51,041			(773	)
Loss on extinguishment of debt		—			403
Other, net		11,547			11,544
Changes in assets and liabilities:
Accounts receivable		65,699			(527,975	)
Inventories		(34,626	)		(56,777	)
Other current assets		(2,955	)		(29,298	)
Accounts payable trade		(30,138	)		205,759
Revenues and royalties payable		(31,810	)		322,029
Accrued liabilities and other		(11,837	)		88,555
Incentive compensation liability		(57,399	)		—
Current income taxes liability		(85,482	)		62,893
Other noncurrent assets and liabilities		(14,976	)		(2,049	)
Net cash provided by operating activities		3,569,357			5,463,971
Cash flows from investing activities
Exploration and development		(2,798,272	)		(2,060,797	)
Purchase of producing crude oil and natural gas properties		(162,022	)		(432,651	)
Purchase of other property and equipment		(169,649	)		(53,372	)
Proceeds from sale of assets		377,428			3,163
Contributions to unconsolidated affiliates		(18,624	)		(153,665	)
Net cash used in investing activities		(2,771,139	)		(2,697,322	)
Cash flows from financing activities
Credit facility borrowings		4,084,000			1,916,000
Repayment of credit facility		(4,313,000	)		(2,416,000	)
Redemption and repurchase of Senior Notes		(636,000	)		(31,829	)
Repayment of other debt		(1,799	)		(1,736	)
Debt issuance costs		(242	)		(2,016	)
Contributions from noncontrolling interests		7,666			6,720
Distributions to noncontrolling interests		(25,326	)		(27,968	)
Repurchase of common stock prior to take-private transaction		—			(99,855	)
Repurchase of restricted stock for tax withholdings		—			(33,889	)
Dividends paid on common stock		(2,052	)		(283,762	)
Net cash used in financing activities		(886,753	)		(974,335	)
Net change in cash and cash equivalents		(88,535	)		1,792,314
Cash and cash equivalents at beginning of period		137,788			20,868
Cash and cash equivalents at end of period	$	49,253		$	1,813,182

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 ~~nine~~three months ended ~~September~~March 3031, ~~2023~~2024, crude oil accounted for 5254% of the Company’s total production and 8486% of its crude oil, natural gas, and natural gas liquids revenues.

~~2022~~Voluntary ~~Take-Private Transaction~~Filer

OnThe ~~November 22, 2022, the~~ Company ~~completed~~is aprivately ~~series of take-private transactions with Omega Acquisition, Inc., an entity~~ owned by ~~the~~its ~~Company’s~~ founder, Harold G. Hamm, ~~pursuant to which the Company became wholly owned by Mr. Hamm,~~ certain members of his family and their affiliated entities (the “"Hamm Family”"). ~~Following~~As ~~the consummation~~ of ~~the~~March ~~transactions:~~31, ~~(i)~~2024, ~~our~~the ~~common~~Hamm ~~stock~~Family ~~ceased~~holds toapproximately be299.6 ~~listed~~million onshares ~~the~~of ~~New York Stock Exchange; (ii) our~~ common stock ~~was deregistered under Section 12(b)~~ of the ~~Securities Exchange Act of 1934 as amended (the “Exchange Act”); and (iii) we suspended our reporting obligations under Section 15(d) of the Exchange Act~~Company. As a ~~result~~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 noof ~~longer~~1934 do not apply to us. We ~~will~~ 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.

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

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.

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, ~~2022~~2023 (“~~2022~~2023 Form 10-K”), which includes a summary of the Company’s significant accounting policies and other disclosures.

The condensed consolidated financial statements as of ~~September~~March 3031, ~~2023~~2024 and for the three ~~and nine~~ month periods ended ~~September~~March 3031, ~~2023~~2024 and ~~2022~~2023 are unaudited. The condensed consolidated balance sheet as of December 31, ~~2022~~2023 was derived from the audited balance sheet included in the ~~2022~~2023 Form 10-K. The Company evaluated its ~~September~~March 3031, ~~2023~~2024 financial statements for subsequent events through ~~November~~May 3, ~~2023~~2024, 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.

~~Earnings per share~~5

Basic net income per share is computed by dividing net income attributable to the Company by the weighted-average number of shares outstanding for the period. Prior to the Hamm Family's take-private transaction, in periods where the Company had net income, diluted earnings per share reflected the potential dilution of non-vested restricted stock awards, which was calculated using the

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

~~treasury~~natural ~~stock~~gas ~~method~~properties. ~~The~~In ~~following~~the ~~table~~opinion ~~presents~~of ~~the~~management, ~~calculation~~all adjustments (consisting only of ~~basic~~normal ~~and~~recurring ~~diluted~~adjustments) ~~weighted~~necessary ~~average~~for ~~shares~~a ~~outstanding~~fair ~~and~~presentation ~~net~~in ~~income~~accordance ~~per~~with ~~share~~U.S. ~~attributable~~GAAP tohave ~~the~~been ~~Company~~included in these unaudited condensed consolidated financial statements. The results of operations for any interim period are not necessarily indicative of the ~~three~~results ~~and~~of ~~nine~~operations ~~months~~that ~~ended~~may ~~September~~be ~~30,~~expected ~~2023~~for ~~and~~any ~~2022.~~other interim period or for an entire year.

	Three months ended September 30,				Nine months ended September 30,
In thousands, except per share data	2023		2022		2023		2022
Net income attributable to Continental Resources (numerator)	$	370,788	$	1,013,107	$	1,945,898	$	2,819,611
Weighted average shares (denominator):
Weighted average shares - basic		299,610		357,617		299,610		357,786
Non-vested restricted stock and long-term incentive awards (1)		—		3,904		—		4,239
Weighted average shares - diluted		299,610		361,521		299,610		362,025
Net income per share attributable to Continental Resources:
Basic	$	1.24	$	2.83	$	6.49	$	7.88
Diluted	$	1.24	$	2.80	$	6.49	$	7.79

Note 3. Supplemental Cash Flow Information

At September 30, 2023, the Company's outstanding long-term incentive awards are expected to be paid in cash, not common stock, upon vesting and are classified as liability awards pursuant to ASC Topic 718, Compensation—Stock Compensation. As a result, no potential dilutive effect for the awards is presented for the three and nine months ended September 30, 2023.

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

Note 3. Property Acquisitions and Dispositions

2023

During the nine months ended September 30, 2023, the Company executed acquisitions of oil and gas properties in various areas for cash consideration totaling $681 million. Of the purchase prices, a total of $162 million was allocated to proved properties and a total of $519 million was allocated to unproved properties.

During the nine months ended September 30, 2023, the Company executed sales of oil and gas properties in various areas for cash proceeds totaling $377 million and recognized pre-tax net losses on the transactions totaling $51 million. The disposed properties represented an immaterial portion of the Company's production and proved reserves.

2022

In March 2022, the Company acquired oil and gas properties in the Powder River Basin for cash consideration of $403 million. Of the purchase price, $381.3 million was allocated to proved properties and $21.7 million was allocated to unproved properties.

In April 2022, the Company acquired oil and gas properties in the Permian Basin for cash consideration of $197 million. Nearly all of the purchase price was allocated to unproved properties.

Note 4. Supplemental Cash Flow Information

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

	Nine months ended September 30,
	Three months ended March 31,
In thousands	~~2023~~2024		~~2022~~2023
Supplemental cash flow information:
Cash paid for interest	$	~~303~~86,~~011~~931	$	~~200~~94,~~206~~875
Cash paid for income taxes (1)		456,253		440,145
Cash paid for income taxes		—		—
Cash received for income tax refunds		23,266		162
Non-cash investing activities:
Asset retirement obligation additions and revisions, net		9,~~057~~137		~~28,243~~477

~~Amounts~~As ~~represent~~of ~~estimated~~March ~~quarterly~~31, ~~payments~~2024 ~~for~~and UDecember 31, 2023, the Company had $329.S6 million and $367.2 ~~federal~~million, respectively, of accrued capital expenditures included in “Net property and ~~state~~equipment” ~~income~~with ~~taxes~~an ~~based~~offsetting onamount ~~estimates~~in of“Accounts ~~taxable~~payable ~~income~~trade” ~~for~~in the ~~year~~condensed consolidated balance sheets.

AsNote ~~of September 30, 2023 and December 31, 2022, the Company had $431~~4.5 million and $344.9 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. Revenues

9The 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, 2024 and 2023. 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, 2024						Three months ended March 31, 2023
In thousands	Crude Oil		Natural Gas and NGLs		Total		Crude Oil		Natural Gas and NGLs		Total
Bakken	$	891,174	$	87,447	$	978,621	$	796,920	$	152,885	$	949,805
Anadarko Basin		241,924		154,284		396,208		200,981		220,220		421,201
Powder River Basin		117,274		13,830		131,104		100,748		14,257		115,005
Permian Basin		344,645		19,340		363,985		243,605		18,854		262,459
All other		39,890		35		39,925		43,182		68		43,250
Crude oil, natural gas, and natural gas liquids sales	$	1,634,907	$	274,936	$	1,909,843	$	1,385,436	$	406,284	$	1,791,720

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

Note 5. ~~Revenues~~Derivative Instruments

~~The~~From ~~following~~time ~~table~~to ~~presents~~time the ~~disaggregation~~Company ofenters ~~the~~into ~~Company's~~derivative ~~crude~~contracts ~~oil~~to ~~and~~economically ~~natural~~hedge ~~gas~~against ~~revenues~~the byvariability ~~operating~~in ~~area~~cash ~~for~~flows ~~the~~associated ~~three~~with ~~and~~future ~~nine~~sales ~~months~~of ~~ended~~production. ~~September~~The ~~30,~~Company ~~2023~~recognizes ~~and~~its ~~2022.~~derivative ~~Sales~~instruments ofon ~~natural~~the ~~gas~~balance ~~and~~sheet ~~NGLs~~as ~~are~~either ~~combined,~~assets asor aliabilities ~~substantial~~measured ~~majority~~at offair ~~the~~value. ~~Company's~~The ~~natural~~estimated ~~gas~~fair ~~sales~~value ~~contracts~~is ~~represent~~based ~~wellhead~~upon ~~sales~~various offactors ~~unprocessed~~as ~~gas~~described in Note 6. Fair Value Measurements.

	Three months ended September 30, 2023						Three months ended September 30, 2022
In thousands	Crude Oil		Natural Gasand NGLs		Total		Crude Oil		Natural Gasand NGLs		Total
Bakken	$	1,089,502	$	79,952	$	1,169,454	$	997,190	$	376,693	$	1,373,883
Anadarko Basin		288,993		168,442		457,435		258,267		562,896		821,163
Powder River Basin		106,407		9,333		115,740		177,129		47,892		225,021
Permian Basin		269,787		23,960		293,747		253,863		41,167		295,030
All other		45,921		34		45,955		51,965		200		52,165
Crude oil, natural gas, and natural gas liquids sales	$	1,800,610	$	281,721	$	2,082,331	$	1,738,414	$	1,028,848	$	2,767,262

At March 31, 2024 the Company had outstanding derivative contracts as set forth in the tables below.

	Nine months ended September 30, 2023								Nine months ended September 30, 2022
Natural gas derivatives
In thousands	Crude Oil		Natural Gasand NGLs				Total		Crude Oil		Natural Gasand NGLs		Total
Period and Type of Contract	Average Volumes Hedged				Weighted Average Hedge Price ($/MMBtu)
Bakken	$	2,732,748	$	292,621			$	3,025,369	$	3,031,550	$	870,168	$	3,901,718
April 2024 - June 2024
Anadarko Basin		754,983		527,240				1,282,223		869,095		1,435,607		2,304,702
Swaps - Henry Hub		660,000	MMBtus/day		$	3.38
Powder River Basin		302,577		31,437				334,014		418,687		94,400		513,087
Swaps - WAHA		60,000	MMBtus/day		$	3.20
Permian Basin		826,361		59,666				886,027		852,778		125,850		978,628
July 2024 - Sept 2024
All other		135,903		136				136,039		171,632		929		172,561
Swaps - Henry Hub		660,000	MMBtus/day		$	3.38
Crude oil, natural gas, and natural gas liquids sales	$	4,752,572	$	911,100			$	5,663,672	$	5,343,742	$	2,526,954	$	7,870,696
Swaps - WAHA		50,000	MMBtus/day		$	2.81
October 2024 - December 2024
Swaps - Henry Hub		697,000	MMBtus/day		$	3.38
January 2025 - December 2025
Swaps - Henry Hub		602,000	MMBtus/day		$	3.90
January 2026 - December 2026
Swaps - Henry Hub		635,000	MMBtus/day		$	4.11
January 2027 - December 2027
Swaps - Henry Hub		263,000	MMBtus/day		$	3.83

Note 6. Derivative Instruments

         Crude oil derivatives

         Weighted Average
Hedge Price ($/Bbl)

         Period and Type of Contract

         Average Volumes Hedged

         Roll Swaps

         Fixed Swaps

         April 2024 - December 2024

Roll Swaps - NYMEX

60,000

Bbls/day

0.72

Fixed Swaps - WTI

59,000

Bbls/day

76.45

~~From~~Derivative ~~time~~gains 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, including commodity exchange prices, over-the-counter quotations, and, in the case of collars, volatility, the risk-free interest rate, and the time to expiration. The calculation of the fair value of collars requires the use of an option-pricing model. See Note 7. Fair Value Measurements.losses

AtCash ~~September~~receipts ~~30,~~and ~~2023~~payments in the ~~Company~~following ~~had~~table ~~outstanding~~reflect the gains or losses on derivative contracts which matured during the applicable period, calculated as ~~set~~the ~~forth~~difference inbetween the ~~tables~~contract ~~below~~price and the market settlement price of matured contracts. The Company's derivative contracts are settled based upon reported settlement prices on commodity exchanges, with crude oil derivative settlements based on NYMEX West Texas Intermediate (“WTI”) pricing and natural gas derivative settlements based primarily on NYMEX Henry Hub pricing. Non-cash gains and losses below represent the change in fair value of derivative instruments which

Natural gas derivatives
				Weighted Average Hedge Price ($/MMBtu)
Period and Type of Contract	Average Volumes Hedged			Basis Swaps			Swaps		Floor		Ceiling
October 2023 - December 2023
Swaps - Henry Hub		420,000	MMBtus/day				$	3.70
Collars - Henry Hub		200,000	MMBtus/day						$	3.12	$	4.09
Swaps - WAHA		70,000	MMBtus/day				$	2.74
Basis Swaps - NGPL TXOK		75,000	MMBtus/day	$	(0.17	)
January 2024 - December 2024
Swaps - Henry Hub		618,000	MMBtus/day				$	3.44
Collars - Henry Hub		50,000	MMBtus/day						$	3.12	$	4.09
Swaps - WAHA		42,000	MMBtus/day				$	3.08
January 2025 - December 2025
Swaps - Henry Hub		545,000	MMBtus/day				$	3.93
January 2026 - December 2026
Swaps - Henry Hub		510,000	MMBtus/day				$	4.11

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

Crude oil derivatives				Weighted AverageHedge Price ($/Bbl)
Period and Type of Contract	Average Volumes Hedged			Roll Swaps		Fixed Swaps
October 2023 - December 2023
Roll Swaps - NYMEX		12,000	Bbls/day	$	1.07
Fixed Swaps - WTI		76,000	Bbls/day			$	78.71
January 2024 - March 2024
Fixed Swaps - WTI		127,000	Bbls/day			$	77.38
April 2024 - December 2024
Fixed Swaps - WTI		59,000	Bbls/day			$	76.45

continued to be held at period end and the reversal of previously recognized non-cash gains or losses on derivative contracts that matured during the period.

Derivative gains and losses


	Three months ended March 31,
In thousands	2024			2023
Cash received (paid) on derivatives:
Crude oil fixed price swaps	$	4,829		$	5,098
Crude oil NYMEX roll swaps		2,473			1,400
Natural gas basis swaps		—			1,357
Natural gas WAHA swaps		9,024			12
Natural gas fixed price swaps		62,801			15,702
Natural gas collars		16,069			24,380
Natural gas 3-way collars		—			3,741
Cash received (paid) on derivatives, net		95,196			51,690
Non-cash gain (loss) on derivatives:
Crude oil fixed price swaps		(201,049	)		78,539
Crude oil NYMEX roll swaps		(10,254	)		(608	)
Natural gas basis swaps		—			(6,741	)
Natural gas WAHA swaps		(329	)		15,671
Natural gas fixed price swaps		15,165			215,692
Natural gas collars		(11,923	)		29,134
Natural gas 3-way collars		—			(598	)
Non-cash gain (loss) on derivatives, net		(208,390	)		331,089
Gain (loss) on derivative instruments, net	$	(113,194	)	$	382,779

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 settled based upon reported settlement prices on commodity exchanges, with crude oil derivative settlements based on NYMEX West Texas Intermediate ("WTI") pricing and natural gas derivative settlements based primarily on NYMEX Henry Hub pricing. Non-cash gains and losses below represent the change in fair value of derivative instruments which continued to be held at period end and the reversal of previously recognized non-cash gains or losses on derivative contracts that matured during the period.

	Three months ended September 30,						Nine months ended September 30,
In thousands	2023			2022			2023			2022
Cash received (paid) on derivatives:
Crude oil fixed price swaps	$	(24,416	)	$	—		$	15,335		$	—
Crude oil NYMEX roll swaps		976			(5,836	)		3,542			(12,908	)
Natural gas basis swaps		960			2,843			2,942		$	4,335
Natural gas WAHA swaps		3,384			(15,536	)		12,747			(15,536	)
Natural gas fixed price swaps		53,110			(185,463	)		146,737			(327,047	)
Natural gas collars		—			(22,106	)		24,380		$	(36,023	)
Natural gas 3-way collars		—			—			3,741		$	(16,459	)
Cash received (paid) on derivatives, net		34,014			(226,098	)		209,424			(403,638	)
Non-cash gain (loss) on derivatives:
Crude oil fixed price swaps		(344,555	)		—			(191,926	)		—
Crude oil NYMEX roll swaps		(7,006	)		19,789			(7,723	)		3,630
Natural gas basis swaps		(806	)		6,981			(7,407	)		11,773
Natural gas WAHA swaps		3,193			2,159			(7,566	)		(11,914	)
Natural gas fixed price swaps		(24,707	)		(52,118	)		241,284			(420,613	)
Natural gas collars		4,756			(78,501	)		35,307			(168,758	)
Natural gas 3-way collars		—			(9,990	)		(598	)		(19,940	)
Non-cash gain (loss) on derivatives, net		(369,125	)		(111,680	)		61,371			(605,822	)
Gain (loss) on derivative instruments, net	$	(335,111	)	$	(337,778	)	$	270,795		$	(1,009,460	)

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 condensed consolidated balance sheets.

11The 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.


In thousands	March 31, 2024			December 31, 2023
Commodity derivative assets:
Gross amounts of recognized assets	$	368,709		$	510,375
Gross amounts offset on balance sheet		(9,779	)		(1,862	)
Net amounts of assets on balance sheet		358,930			508,513
Commodity derivative liabilities:
Gross amounts of recognized liabilities		(69,171	)		(2,448	)
Gross amounts offset on balance sheet		9,779			1,862
Net amounts of liabilities on balance sheet	$	(59,392	)	$	(586	)

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

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.

In thousands	September 30, 2023			December 31, 2022
Commodity derivative assets:
Gross amounts of recognized assets	$	119,941		$	50,559
Gross amounts offset on balance sheet		(22,362	)		(7,731	)
Net amounts of assets on balance sheet		97,579			42,828
Commodity derivative liabilities:
Gross amounts of recognized liabilities		(237,240	)		(229,230	)
Gross amounts offset on balance sheet		22,362			7,731
Net amounts of liabilities on balance sheet	$	(214,878	)	$	(221,499	)

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

In thousands	~~September~~March 3031, ~~2023~~2024			December 31, ~~2022~~2023
Derivative assets	$	78216,~~644~~385		$	39353,~~280~~261
Derivative assets, noncurrent		18142,~~935~~545			3155,~~548~~252
Net amounts of assets on balance sheet		97358,~~579~~930			42508,~~828~~513
Derivative liabilities		(~~175~~58,~~384~~858	)		~~(88,136~~—	)
Derivative liabilities, noncurrent		(~~39,494~~534	)		(~~133,363~~586	)
Net amounts of liabilities on balance sheet		(~~214~~59,~~878~~392	)		(~~221,499~~586	)
Total derivative assets (liabilities), net	$	~~(117,~~299,538	)	$	~~(178~~507,~~671~~927	)

Note 76. 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 ~~September~~March 3031, ~~2023~~2024 and December 31, ~~2022~~2023.

	Fair value measurements at September 30, 2023 using:
	Fair value measurements at March 31, 2024 using:
In thousands	Level 1		Level 2			Level 3		Total
Derivative assets (liabilities):
Crude oil fixed price swaps	$	—	$	(~~180~~54,~~230~~805	)	$	—	$	(~~180~~54,~~230~~805	)
Crude oil NYMEX roll swaps		—		(43,~~887~~366	)		—		(43,~~887~~366	)
Natural gas basis swaps		—		1,503			—		1,503
Natural gas WAHA swaps		—		21,194			—		21,194
Natural gas WAHA swaps		—		11,820			—		11,820
Natural gas fixed price swaps		—		336,515			—		336,515
Natural gas fixed price swaps		—		49,505			—		49,505
Total	$	—	$	299,538		$	—	$	299,538
Natural gas collars		—		4,990			—		4,990
Total	$	—	$	(117,299	)	$	—	$	(117,299	)


	Fair value measurements at December 31, 2023 using:
In thousands	Level 1		Level 2		Level 3		Total
Derivative assets (liabilities):
Crude oil fixed price swaps	$	—	$	146,243	$	—	$	146,243
Crude oil NYMEX roll swaps		—		6,888		—		6,888
Natural gas WAHA swaps		—		21,523		—		21,523
Natural gas fixed price swaps		—		321,350		—		321,350
Natural gas collars		—		11,923		—		11,923
Total	$	—	$	507,927	$	—	$	507,927

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

	Fair value measurements at December 31, 2022 using:
In thousands	Level 1		Level 2			Level 3		Total
Derivative assets (liabilities):
Crude oil fixed price swaps	$	—	$	11,696		$	—	$	11,696
Crude oil NYMEX roll swaps		—		2,836			—		2,836
Natural gas basis swaps		—		8,910			—		8,910
Natural gas WAHA swaps		—		19,386			—		19,386
Natural gas fixed price swaps		—		(191,779	)		—		(191,779	)
Natural gas collars		—		(30,318	)		—		(30,318	)
Natural gas 3-way collars		—		598			—		598
Total	$	—	$	(178,671	)	$	—	$	(178,671	)

Note 7. Debt

~~Note~~The Company's debt, net of unamortized discounts, premiums, and debt issuance costs totaling $39.8 million and $41.7 ~~Debt~~million at March 31, 2024 and December 31, 2023, respectively, consists of the following.

The Company's debt, net of unamortized discounts, premiums, and debt issuance costs totaling $43.6 million and $49.6 million at September 30, 2023 and December 31, 2022, respectively, consists of the following.


In thousands	March 31, 2024		December 31, 2023
Credit facility	$	—	$	210,000
Term Loan		648,346		748,092
Notes payable		17,029		17,642
3.8% Senior Notes due 2024		892,918		892,610
2.268% Senior Notes due 2026		795,916		795,541
4.375% Senior Notes due 2028		994,648		994,327
5.75% Senior Notes due 2031		1,485,880		1,485,460
2.875% Senior Notes due 2032		793,166		792,977
4.9% Senior Notes due 2044		692,517		692,463
Total debt	$	6,320,420	$	6,629,112
Less: Current portion of long-term debt		895,437		895,105
Long-term debt, net of current portion	$	5,424,983	$	5,734,007

In thousands	September 30, 2023		December 31, 2022
Credit facility	$	931,000	$	1,160,000
Term Loan		747,837		747,073
Notes payable		18,251		20,041
4.5% Senior Notes due 2023		—		635,648
3.8% Senior Notes due 2024 (1)		892,304		891,404
2.268% Senior Notes due 2026		795,167		794,062
4.375% Senior Notes due 2028		994,008		993,076
5.75% Senior Notes due 2031		1,485,047		1,483,843
2.875% Senior Notes due 2032		792,791		792,238
4.9% Senior Notes due 2044		692,410		692,255
Total debt	$	7,348,815	$	8,209,640
Less: Current portion of long-term debt (1)		894,777		638,058
Long-term debt, net of current portion	$	6,454,038	$	7,571,582

The Company's 2024 Notes, which have a face value of $893.1 million at September 30, 2023, are scheduled to mature on June 1, 2024 and, accordingly, are included as a current liability in the caption "Current portion of long-term debt" in the condensed consolidated balance sheets as of September 30, 2023.

Credit Facility

The Company has a credit facility, maturing in October 2026, with aggregate lender commitments totaling $2.255 billion. The credit facility is unsecured and has no borrowing base requirement subject to redetermination.

The Company had no outstanding borrowings and $~~931~~2.255 ~~million~~billion of ~~outstanding~~borrowing ~~borrowings~~availability on its credit facility at ~~September~~March 3031, ~~2023~~2024. ~~Credit~~Subsequent ~~facility~~to ~~borrowings~~March ~~bear~~31, ~~interest~~2024, atthe ~~market-based~~Company ~~interest~~repaid ~~rates~~the ~~plus~~remaining a$650 ~~margin~~million ~~based~~term loan using available cash on-hand ~~the~~and ~~terms~~credit facility borrowings. As of April 30, 2024, the ~~borrowing~~balance ~~and~~on the credit ~~ratings~~facility ~~assigned~~was to$490 million and the Company’s ~~senior,~~had ~~unsecured,~~$1.8 ~~long-term~~billion ~~indebtedness~~of borrowing availability. The ~~weighted-average~~Company ~~interest~~incurs ~~rate~~commitment fees based on ~~outstanding~~currently assigned credit ~~facility~~ratings ~~borrowings~~of at0.20% ~~September~~per ~~30,~~annum ~~2023~~on ~~was~~the 6daily average amount of unused borrowing availability.~~9%.~~

The credit facility contains certain restrictive covenants including a requirement that the Company ~~had~~maintain ~~approximately~~a $consolidated net debt to total capitalization ratio of no greater than 0.65 to 1.300. ~~billion~~This ratio represents the ratio of ~~borrowing~~net ~~availability~~debt on(calculated ~~its~~as total face value of debt plus outstanding letters of credit ~~facility~~less atcash ~~September~~and 30cash equivalents) divided by the sum of net debt plus total shareholders' equity plus, ~~2023~~to ~~after~~the ~~considering~~extent ~~outstanding~~resulting ~~borrowings~~in ~~and~~a ~~letters~~reduction of ~~credit.~~total ~~The~~shareholders’ ~~Company~~equity, ~~incurs~~the ~~commitment~~amount ~~fees~~of ~~based~~any onnon-cash ~~currently~~impairment ~~assigned~~charges ~~credit~~incurred, ~~ratings~~net of 0any tax effect, after June 30, 2014.~~20%~~ ~~per~~The ~~annum~~Company onwas in compliance with the ~~daily~~credit ~~average~~facility ~~amount~~covenants ofat ~~unused~~March ~~borrowing~~31, ~~availability~~2024.

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 net debt (calculated as total face value of debt plus outstanding letters of credit less cash and cash equivalents) divided by the sum of net debt plus total shareholders' equity plus, to

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

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. The Company was in compliance with the credit facility covenants at September 30, 2023.

Senior Notes

The following table summarizes the face values, maturity dates, semi-annual interest payment dates, and optional redemption periods related to the Company’s outstanding senior note obligations at ~~September~~March 3031, ~~2023~~2024.

2024 Notes

2026 Notes

2028 Notes

2031 Notes

2032 Notes

2044 Notes

Face value (in thousands)

893,126

800,000

1,000,000

1,500,000

800,000

700,000

Maturity date

June 1, 2024

November 15, 2026

January 15, 2028

January 15, 2031

April 1, 2032

June 1, 2044

Interest payment dates

June 1, Dec 1

May 15, Nov 15

Jan 15, July 15

Jan 15, Jul 15

April 1, Oct 1

June 1, Dec 1

Make-whole redemption period (1)

Mar 1, 2024

Nov 15, 2023

Oct 15, 2027

Jul 15, 2030

January 1,. 2032

Dec 1, 2043

(1)

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

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

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

The indentures governing the Company’s senior notes contain covenants that, among other things, limit the Company’s ability to create liens securing certain indebtedness, enter into certain sale-leaseback transactions, or consolidate, merge or transfer certain assets. These covenants are subject to a number of important exceptions and qualifications. The Company was in compliance with these covenants at ~~September~~March 3031, ~~2023~~2024.

The senior notes are obligations of Continental Resources, Inc. Additionally, certain of the Company’s wholly-owned subsidiaries (Banner Pipeline Company, L.L.C., CLR Asset Holdings, LLC, The Mineral Resources Company, 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.

Redemption of Senior Notes

On April 14, 2023, the Company repaid its outstanding $636 million of 2023 Notes that were scheduled to mature on April 15, 2023. The redemption price was equal to 100% of the principal amount plus accrued and unpaid interest to the redemption date. The aggregate of the principal amount and accrued interest paid upon redemption was $650.3 million.

Term Loan

InSubsequent ~~November~~to ~~2022~~March 31, 2024, the Company ~~borrowed~~repaid the remaining $~~750~~650 million ~~under a three-year~~ term loan ~~agreement,~~using ~~the~~available ~~proceeds~~cash ofon-hand ~~which~~and ~~were~~credit ~~used~~facility toborrowings. ~~fund~~As ~~a portion~~ of ~~the~~April ~~Hamm~~30, ~~Family’s~~2024, ~~November~~the ~~2022 take-private transaction. The~~ term loan ~~matures~~was infully ~~November~~repaid ~~2025~~ and ~~bears~~the ~~interest~~balance ~~at market-based interest rates plus a margin based~~ on the ~~terms of the borrowing and the~~ credit ~~ratings~~facility ~~assigned to the Company’s senior, unsecured, long-term indebtedness. The interest rate on the term loan~~ was ~~7.0%~~$490 ~~at September 30, 2023~~million.

~~The~~In November 2022, the Company borrowed $750 million under a three-year term loan ~~contains~~agreement. ~~certain~~The ~~restrictive~~Company ~~covenants~~repaid ~~including~~$100 amillion ~~requirement~~of ~~that~~the term loan during the ~~Company~~three ~~maintain~~months aended ~~consolidated~~March ~~net~~31, ~~debt~~2024 toand ~~total~~the ~~capitalization~~remaining ~~ratio~~balance oftotaled no$650 ~~greater~~million ~~than~~at ~~0.65~~March to31, 12024.0, ~~consistent~~The ~~with~~term ~~the~~loan ~~covenant~~would ~~requirement~~have matured in November 2025 and bore 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 ~~revolving~~senior, ~~credit~~unsecured, ~~facility~~long-term indebtedness. The ~~Company~~interest ~~was~~rate inon ~~compliance with~~ the term loan ~~covenants~~was 6.93% at ~~September~~March 3031, ~~2023~~2024.

14The term loan contained 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 1.0, consistent with the covenant requirement in the Company’s revolving credit facility. The Company was in compliance with the term loan covenants at March 31, 2024.

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 31, 2024 under the arrangements amount to approximately $1.04 billion, of which $265 million is expected to be incurred in the remainder of 2024, $278 million in 2025, $218 million in 2026, $203 million in 2027, $70 million in 2028, and $8 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 take-private transaction and seek: (i) monetary damages; (ii) the costs and expenses associated with the lawsuits; and (iii) other equitable relief. The defendants continue to vigorously defend themselves against these claims.

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

Note 9. 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 September 30, 2023 under the arrangements amount to approximately $909 million, of which $88 million is expected to be incurred in the remainder of 2023, $304 million in 2024, $164 million in 2025, $139 million in 2026, $136 million in 2027, and $78 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 take-private transaction – Transactions such as the Hamm Family’s take-private transaction described in Note 1. Organization and Nature of Business—2022 Take-Private Transaction often attract litigation and demands from minority shareholders.

In April 2023, three separate putative class actions 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 take-private transaction and seek: (i) monetary damages; (ii) the costs and expenses associated with the lawsuits; and (iii) other equitable relief. 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 take-private transaction. The Company continues to vigorously defend itself against these claims.

Note 109. Long-Term Incentive Compensation

The Company has granted ~~long-term~~ incentive compensation awards to employees pursuant to the Continental Resources, Inc. 2022 Long-Term Incentive Plan ("“2022 Plan"”). ~~Such~~Awards ~~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 settle all outstanding incentive awards vesting in the future in cash and, thus, the awards are classified as liability awards pursuant to ASC Topic 718, Compensation—Stock Compensation. At September 30, 2023, the Company had recorded a current liability of $130.5 million and a non-current liability of $37.8 million in the captions “Current portion of incentive compensation liability” and “Incentive compensation liability, noncurrent,” respectively, in the unaudited condensed consolidated balance sheets associated with the awards. Such amounts reflect the Company’s estimate of expected future cash payments multiplied by the percentage of requisite service periods that employees have completed as of September 30, 2023.

At March 31, 2024, the Company had recorded a current liability of $46.4 million and a non-current liability of $17.0 million in the captions “Current portion of incentive compensation liability” and “Incentive compensation liability, noncurrent,” respectively, in the condensed consolidated balance sheets associated with the awards. Such amounts reflect the Company’s estimate of expected future cash payments multiplied by the percentage of requisite service periods that employees have completed as of March 31, 2024. The Company’s compensation expense associated with such awards, which is included in the caption “General and administrative expenses” in the condensed consolidated statements of income, was $32.5 million and $1.0 million for the three months ended March 31, 2024 and 2023, respectively. As of March 31, 2024, there was approximately $147.2 million of unrecognized liabilities and compensation expense related to unvested awards, which are expected to be recognized over a weighted average period of 1.7 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.

Compensation expense associated with the Company’s awards totaled $61.4 million and $16.7 million for the three months ended September 30, 2023 and 2022, respectively, and $86.9 million and $60.8 million for the nine months ended September 30, 2023 and 2022, respectively, which is included in the caption “General and administrative expenses” in the unaudited condensed consolidated 12

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

statements of income. As of September 30, 2023, there was approximately $136 million of unrecognized liabilities and compensation expense related to unvested awards, which are expected to be recognized over a weighted average period of 1.6 years.

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, ~~2022~~2023.

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, ~~2022~~2023, 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. Our corporate internet website is www.clr.com. As discussed in Note 1. Organization and Nature of Business—~~2022~~Voluntary ~~Take-Private~~Filer ~~Transaction~~ in Notes to Unaudited Condensed Consolidated Financial Statements, ~~effective November 22, 2022~~ Continental Resources, Inc. ~~became~~is a privately held corporation and has no publicly available common shares outstanding.

~~Third~~First Quarter ~~2023~~2024 Financial and Operating Metrics

Commodity prices have remained volatile due to various factors, some of which include global supply and demand, global inventory levels, and regional conflicts. Average NYMEX oil prices for the three months ended March 31, 2024 and 2023 were $77.04 and $76.05, respectively. Average NYMEX gas prices for the three months ended March 31, 2024 and 2023 were $2.23 and $3.43, respectively. The following table contains financial and operating metrics for the first quarter periods ~~presented~~of 2024 and 2023. Average ~~net~~ sales prices exclude any effect of derivative transactions. Per-unit expenses have been calculated using sales volumes.

	Three months ended September 30,						Nine months ended September 30,
	Three months ended March 31,
	2023			2022			2023			2022
	2024			2023
Average daily production:
Crude oil (Bbl per day)		~~240~~237,~~205~~908			~~200~~206,~~464~~232			~~227,464~~			~~197,869~~
Natural gas (Mcf per day) (1)		1,~~292~~204,~~533~~433			1,~~283~~205,~~865~~772			~~1,247,358~~			~~1,190,516~~
Crude oil equivalents (Boe per day)		~~455~~438,~~627~~647			~~414~~407,~~441~~194			~~435,357~~			~~396,288~~
Average net sales prices (2):
Average sales prices:
Crude oil ($/Bbl)	$	7875.6196		$	8975.4677		$	~~73.62~~		$	~~95.51~~
Natural gas ($/Mcf) (1)	$	2.2651		$	83.5674		$	~~2.56~~		$	~~7.63~~
Crude oil net sales price discount to NYMEX ($/Bbl)	$	(3.57	)	$	(2.16	)	$	(3.76	)	$	(2.63	)
Production expenses ($/Boe)	$	4.74		$	5.00
Natural gas net sales price premium (discount) to NYMEX ($/Mcf) (1)	$	(0.29	)	$	0.37		$	(0.13	)	$	0.74
Production and ad valorem taxes (% of net crude oil and natural gas sales)		8.2	%		7.9	%
Production expenses ($/Boe)	$	4.21		$	4.34		$	4.49		$	4.22
Depreciation, depletion, amortization and accretion ($/Boe)	$	15.90		$	13.10
Production and ad valorem taxes (% of net crude oil and natural gas sales)		8.1	%		7.5	%		8.1	%		7.4	%
Total general and administrative expenses ($/Boe)	$	2.07		$	1.74
Depreciation, depletion, amortization and accretion ($/Boe)	$	13.81		$	12.79		$	13.53		$	12.91
Total general and administrative expenses ($/Boe)	$	2.69		$	1.79		$	1.95		$	1.91

(1)

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

~~See the subsequent section titled Non-GAAP Financial Measures for a discussion and calculation of net sales prices, which are non-GAAP measures.~~13

17Three months ended March 31, 2024 compared to the three months ended March 31, 2023

Three months ended September 30, 2023 compared to the three months ended September 30, 2022

Results of Operations

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

	Three months ended September 30,
	Three months ended March 31,
In thousands	~~2023~~2024			~~2022~~2023
Crude oil, natural gas, and natural gas liquids sales	$	21,~~082~~909,~~331~~843		$	21,~~767~~791,~~262~~720
Loss on derivative instruments, net		(335,111	)		(337,778	)
Gain (loss) on derivative instruments, net		(113,194	)		382,779
Crude oil and natural gas service operations		3023,~~119~~895			1719,~~747~~354
Total revenues		1,~~777~~820,~~339~~544			2,~~447~~193,~~231~~853
Operating costs and expenses		(1,~~202~~201,~~190~~340	)		(1969,~~037,116~~853	)
Other expenses, net		(9676,~~983~~657	)		(6697,~~227~~927	)
Income before income taxes		~~478~~542,~~166~~547			1,~~343~~126,~~888~~073
Provision for income taxes		(~~105~~114,~~994~~054	)		(~~323~~239,~~390~~756	)
Income before equity in net loss of affiliate		~~372~~428,~~172~~493			1886,~~020,498~~317
Equity in net loss of affiliate		(~~883~~907	)		(~~660~~663	)
Net income		~~371~~427,~~289~~586			1885,~~019,838~~654
Net income attributable to noncontrolling interests		~~501~~464			61,~~731~~357
Net income attributable to Continental Resources	$	~~370~~427,~~788~~122		$	1884,~~013,107~~297
Production volumes:
Crude oil (MBbl)		2221,~~099~~650			18,~~443~~561
Natural gas (MMcf)		~~118~~109,~~913~~603			~~118~~108,~~116~~519
Crude oil equivalents (MBoe)		4139,~~918~~917			3836,~~129~~647
Sales volumes:
Crude oil (MBbl)		21,~~960~~524			18,~~674~~286
Natural gas (MMcf)		~~118~~109,~~913~~603			~~118~~108,~~116~~519
Crude oil equivalents (MBoe)		4139,~~779~~791			3836,~~360~~372

Production

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

Boe production per day

3Q1Q ~~2023~~2024

3Q1Q ~~2022~~2023

% Change

Bakken

~~214~~201,~~551~~466

~~175~~179,~~383~~280

2212

Anadarko Basin

~~159~~141,~~090~~745

~~162~~152,~~829~~554

(27

Powder River Basin

2226,~~750~~539

3123,~~234~~333

~~(27~~14

Permian Basin

5363,~~646~~489

3846,~~948~~152

All other

5,~~590~~408

65,~~047~~875

Total

~~455~~438,~~627~~647

~~414~~407,~~441~~194

108

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

	Three months ended September 30,												Volume
	Three months ended March 31,												Volume
	2023					2022					Volume		percent
	2024					2023					Volume		percent
	Volume		Percent			Volume		Percent			increase		increase
Crude oil (MBbl)		2221,~~099~~650		5354	%		18,~~443~~561		4851	%		3,~~656~~089		2017	%
Natural gas (MMcf)		~~118~~109,~~913~~603		4746	%		~~118~~108,~~116~~519		5249	%		~~797~~1,084		1	%
Total (MBoe)		4139,~~918~~917		100	%		3836,~~129~~647		100	%		3,~~789~~270		109	%

The 2017% increase in crude oil production in the ~~2023~~2024 ~~third~~first quarter was primarily driven by new well completions in the ~~Bakken~~Permian ~~field~~Basin ~~over the past year, which led to an increase of 2,583 MBbls, or 24%, compared to the 2022 third quarter. The increase was also partly driven by our property acquisitions~~ and ~~subsequent~~Powder ~~new~~River ~~well completions in the Permian~~ Basin over the past year, which contributed to an increase in our ~~2023~~2024 ~~third~~first quarter production by ~~937~~1,371 MBbls, or 3430%, compared to the ~~2022~~2023 ~~third~~first quarter. Additionally, asour acrude ~~result~~oil ofproduction ~~new~~in ~~well completions over~~ the ~~past~~Bakken ~~year~~field ~~our crude oil production~~ increased ~~719~~1,225 MBbls, or 2611%, inand ~~the~~our ~~Anadarko~~crude ~~Basin~~oil production in the ~~2023~~Anadarko ~~third~~Basin ~~quarter~~increased ~~compared~~530 ~~to the 2022 third quarter. These increases were partially offset by a 542~~ MBbls, or 3020%, ~~decrease~~ in ~~crude oil production in~~ the ~~Powder~~2024 ~~River~~first ~~Basin~~quarter due to ~~fewer~~ new well completions ~~compared~~over to the ~~prior~~past year ~~third quarter~~.

1814

The 1% increase in natural gas production in the ~~2023~~2024 ~~third~~first quarter was driven in part by new well completions in the ~~Bakken~~Permian ~~field~~Basin ~~over~~and ~~the~~Powder ~~past~~River ~~year~~Basin, which ~~led~~contributed to an increase of 63,~~124~~405 MMcf, or 1834%, compared to the ~~2022~~prior ~~third quarter~~period. ~~The~~ ~~increase~~Additionally, ~~was~~natural ~~also~~gas ~~partly~~production ~~driven by our property acquisitions and subsequent new well completions~~ in the ~~Permian~~Bakken ~~Basin~~field ~~over~~increased ~~the past year~~5,839 ~~which contributed to an increase in our 2023 third quarter production by 2,492~~ MMcf, or 4818%, compared to the ~~2022~~2023 ~~third~~first quarter. These increases were partially offset by a 68,~~381~~159 MMcf, or 912%, decrease in natural gas production in the Anadarko Basin due to ~~recent~~allocation of capital ~~spending being allocated primarily~~ to oil-weighted projects in the ~~play~~basin ~~and~~as awell ~~1,434~~as ~~MMcf,~~variation ~~or 23%, decrease~~ in ~~natural gas production in~~ the ~~Powder~~timing ~~River~~of ~~Basin due to fewer~~ new well completions ~~compared~~between ~~to the prior year third quarter~~years.

Revenues

~~Net~~Our revenues consist of sales of crude oil, natural gas, and natural gas liquids, ~~sales~~gains and ~~related~~losses ~~net~~resulting ~~sales~~from ~~prices~~changes ~~presented~~in ~~below~~the ~~are~~fair ~~non-GAAP~~value ~~measures.~~of ~~See~~our ~~the~~derivative ~~subsequent~~instruments, ~~section~~and ~~titled~~revenues ~~Non-GAAP~~associated ~~Financial~~with ~~Measures~~crude ~~for~~oil ~~a discussion~~ and ~~calculation~~natural ofgas ~~these~~service ~~measures~~operations.

~~Net~~Crude ~~crude~~ oil, natural gas, and natural gas liquids sales. ~~Net~~Sales ~~sales~~ totaled $21.0091 billion for the ~~third~~first quarter of ~~2023~~2024, a 257% ~~decrease~~increase compared to ~~net~~ sales of $21.6879 billion for the ~~2022~~2023 ~~third~~first quarter due to ~~decreases~~increases in ~~net~~ sales ~~prices~~volumes and crude oil pricing, partially offset by ~~increases~~a decrease in ~~sales~~natural ~~volumes~~gas ~~as discussed below~~pricing.

Total sales volumes for the ~~third~~first quarter of ~~2023~~2024 increased 3,419 MBoe, or 9%, compared to the ~~2022~~2023 ~~third~~first quarter due to additional drilling and completion activities ~~and new wells added from property acquisitions over the past year~~. For the ~~third~~first quarter of ~~2023~~2024, our crude oil sales volumes increased 18% and our natural gas sales volumes increased 1% compared to the ~~2022~~2023 ~~third~~first quarter.

Our crude oil ~~net~~ sales prices averaged $7875.6196 per barrel in the ~~2023~~2024 ~~third~~first quarter compared to $8975.4677 per barrel for the 2022 third quarter due to a significant decrease in market prices resulting from changes in various macroeconomic conditions between periods. The differential between NYMEX West Texas Intermediate calendar month prices and our realized crude oil net sales prices averaged $3.57 per barrel for the 2023 ~~third~~first quarter ~~compared to $2~~.16 ~~per barrel for the 2022 third quarter.~~

Our natural gas ~~net~~ sales prices averaged $2.2651 per Mcf for the ~~2023~~2024 ~~third~~first quarter compared to $83.5674 per Mcf for the 2022 third quarter due to a significant decrease in market prices and price realizations. The difference between our net sales prices and NYMEX Henry Hub calendar month natural gas prices was a discount of $0.29 per Mcf for the 2023 ~~third~~first quarter ~~compared to a premium of $0~~.37 per Mcf for the 2022 third quarter. We sell the majority of our operated natural gas production to midstream customers at lease locations based on market prices in the field where the sales occur. The field markets are impacted by residue gas and natural gas liquids (“NGLs”) prices at secondary, downstream markets. NGL prices in 2023 have decreased from 2022 levels in conjunction with decreased crude oil prices and other factors, resulting in reduced price realizations for our natural gas sales stream relative to benchmark prices.

Derivatives. ~~Increased~~Changes ~~forward~~in settled and future commodity prices during the ~~third~~first quarter of ~~2023~~2024 ~~had an overall unfavorable impact on the fair value of our derivatives, which~~ resulted in overall negative revenue adjustments totaling $~~335~~113.12 million for the period, representing $3495.02 million of cash gains ~~and~~more than offset by $~~369~~208.14 million of unsettled non-cash losses, compared to ~~negative~~overall positive revenue adjustments totaling $~~337~~382.8 million in the ~~third~~first quarter of ~~2022~~2023.

Operating Costs and Expenses

Production Expenses. Production expenses increased $96.57 million, or 64%, to $~~175~~188.87 million for the ~~third~~first quarter of ~~2023~~2024 compared to $~~166~~182.30 million for the ~~third~~first quarter of ~~2022~~2023 due to an increase in the number of producing wells from drilling activities ~~and~~over ~~property~~the ~~acquisitions,~~past ~~cost inflation for services and materials, and higher workover-related activities aimed at enhancing production from producing properties~~year. Production expenses on a per-Boe basis averaged $4.2174 per Boe for the ~~2023~~2024 ~~third~~first quarter compared to $45.3400 per Boe for the ~~2022~~2023 ~~third~~first quarter. The decrease in per-Boe costs is primarily due to higher sales volumes coupled with continued efforts to reduce cost of supply and inflation impacts in comparison to the prior period.

Production and Ad Valorem Taxes. Production and ad valorem taxes ~~decreased~~increased $3810.19 million, or 198%, to $~~162~~147.51 million for the ~~third~~first quarter of ~~2023~~2024 compared to $~~200~~136.62 million for the ~~third~~first quarter of ~~2022~~2023 due to the previously described ~~decrease~~increase in crude oil and natural gas revenues. Our production taxes as a percentage of net sales averaged 8.12% for the ~~third~~first quarter of ~~2023~~2024, an increase compared to 7.59% for the ~~third~~first quarter of ~~2022~~2023. This increase was the result of changes in sales mix of crude oil and natural gas in the Company’s operating areas between periods.

19Depreciation, Depletion, Amortization and Accretion. Total DD&A increased $156.3 million, or 33%, to $632.8 million for the first quarter of 2024 compared to $476.5 million for the first quarter of 2023 due to the previously described 9% increase in total sales volumes coupled with an increase in our DD&A rate per Boe as further discussed below. The following table shows the components of our DD&A on a unit of sales basis for the periods presented.

Depreciation, Depletion, Amortization and Accretion. Total DD&A increased $86.5 million, or 18%, to $577.0 million for the third quarter of 2023 compared to $490.5 million for the third quarter of 2022 due to the previously described 9% increase in total sales volumes coupled with an increase in our DD&A rate per Boe as further discussed below. The following table shows the components of our DD&A on a unit of sales basis for the periods presented.


	Three months ended March 31,
$/Boe	2024		2023
Crude oil and natural gas	$	15.27	$	12.57
Other equipment		0.49		0.43
Asset retirement obligation accretion		0.14		0.10
Depreciation, depletion, amortization and accretion	$	15.90	$	13.10

	Three months ended September 30,
$/Boe	2023		2022
Crude oil and natural gas	$	13.28	$	12.51
Other equipment		0.45		0.20
Asset retirement obligation accretion		0.08		0.08
Depreciation, depletion, amortization and accretion	$	13.81	$	12.79

Estimated proved reserves are a key component in our computation of DD&A expense. Proved reserves are determined using the unweighted arithmetic average of the first-day-of-the-month commodity prices for the preceding twelve months as required by SEC rules. Holding all other factors constant, if proved reserves are revised downward due to commodity price declines or other reasons, the rate at which we record DD&A expense increases. Conversely, if proved reserves are revised upward, the rate at which we record DD&A expense decreases. 15

~~Certain~~rules. ofHolding ~~our~~all other factors constant, if proved reserves ~~were~~are revised downward indue ~~mid-2023~~to ~~prompted by decreases in first-day-of-the-month~~ commodity ~~prices~~price indeclines ~~the~~or ~~first half of 2023 and~~ other ~~factors~~reasons, ~~which~~the ~~resulted~~rate inat anwhich ~~increase~~we inrecord ~~our~~ DD&A ~~rate~~expense ~~for~~increases. ~~crude~~Conversely, ~~oil~~if ~~and~~proved ~~natural~~reserves ~~gas~~are ~~properties~~revised inupward, the ~~third~~rate ~~quarter~~at ofwhich ~~2023~~we ~~compared~~record toDD&A ~~the~~expense ~~third quarter of 2022~~decreases.

~~Property~~Our ~~Impairments.~~proved ~~Total~~reserves ~~property~~have ~~impairments~~been ~~decreased~~revised ~~$1.8~~downward ~~million~~over ~~to $11.0 million for~~ the ~~third~~past ~~quarter~~year ofprompted ~~2023~~by ~~compared~~decreases toin ~~$12.8 million for~~ first-day-of-the-month ~~third~~commodity ~~quarter~~prices ofand ~~2022~~other factors, ~~reflecting~~which aresulted ~~decrease~~ in ~~the~~an ~~amortization~~increase ~~of undeveloped leasehold costs driven by changes~~ in ~~management's~~our ~~estimates~~DD&A ofrate ~~unproved~~for ~~properties~~crude ~~not~~oil ~~expected~~and tonatural begas ~~transferred to proved~~ properties ~~over~~in the ~~lives~~first quarter of ~~the~~2024 ~~leases.~~compared ~~There~~to ~~were no proved property impairments recognized in~~ the ~~third~~first quarter ~~periods~~ of 2023 ~~and 2022~~.

~~General~~Property ~~and Administrative Expenses~~Impairments. Total ~~G&A~~property ~~expenses~~impairments ~~increased~~decreased $431.70 million, ~~or 64%,~~ to $~~112~~12.41 million for the ~~third~~first quarter of ~~2023~~2024 compared to $6813.71 million for the ~~third~~first quarter of ~~2022~~2023. Amortization of undeveloped leasehold costs remained fairly consistent in the first quarter of 2024 in comparison to the prior period.

General and Administrative Expenses. Total G&A expenses ~~include~~increased ~~charges for incentive compensation/prior equity awards of~~ $6119.40 million, ~~and~~or 30%, to $1682.73 million for the ~~third~~first ~~quarters~~quarter of ~~2023~~2024 ~~and~~compared ~~2022,~~to ~~respectively,~~$63.3 ~~the~~million ~~increase~~for ~~of which was driven by an increase in estimated incentive compensation payment obligations arising from changes in~~ the ~~value~~first quarter of ~~the Company between periods primarily resulting from an increase in forward commodity prices in September~~ 2023.

Total G&A expenses ~~other~~include ~~than~~charges for long-term incentive compensation~~/prior~~ ~~equity~~ awards ~~totaled~~of $5132.5 million and $1.0 million for the first quarters of 2024 and 2023, ~~third~~respectively. ~~quarter~~This increase is primarily due to an increase in estimated incentive compensation payment obligations arising from changes in the value of the Company awards as of March 31, ~~consistent~~2024 compared to the March 31, 2023 valuation date, coupled with ~~$52.0~~a ~~million~~greater ~~for~~amount ~~the~~of ~~2022~~forfeiture ~~third~~reversals ~~quarter~~of expense during the 2023 period.

G&A expenses other than incentive compensation awards totaled $49.8 million for the 2024 first quarter, a decrease of $12.5 million compared to $62.3 million for the 2023 first quarter primarily due to changes in the nature and timing of employee-related costs and benefits recognized between periods.

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

	Three months ended September 30,
	Three months ended March 31,
$/Boe	~~2023~~2024		~~2022~~2023
General and administrative expenses	$	1.2225	$	1.3671
Incentive compensation/prior equity awards		1.47		0.43
Long-term incentive compensation awards		0.82		0.03
Total general and administrative expenses	$	2.6907	$	1.7974

Interest Expense. Interest expense ~~increased~~decreased $3019.29 million, or 4320%, to $~~100~~79.98 million for the ~~third~~first quarter of ~~2023~~2024 compared to $7099.7 million for the ~~third~~first quarter of ~~2022~~2023 due to ana ~~increase~~decrease in our weighted average outstanding debt balance from $68.42 billion for the ~~third~~first quarter of ~~2022~~2023 to $76.96 billion for the ~~third~~first quarter of ~~2023~~2024. ~~coupled~~This ~~with~~decrease anwas ~~increase~~driven inby ~~variable~~debt ~~interest~~reduction ~~rates~~throughout ~~incurred~~the onpast ~~outstanding~~year, ~~credit~~including ~~facility~~the ~~and~~redemption ~~term~~of ~~loan~~our ~~borrowings.~~$636 ~~The~~million ~~increase~~senior innotes ~~our~~on ~~outstanding~~April ~~debt~~15, ~~was~~2023 ~~primarily~~coupled ~~driven~~with byno ~~debt~~amounts ~~incurred~~outstanding inunder ~~the~~our ~~fourth~~credit ~~quarter~~facility as of ~~2022~~March to31, ~~fund~~2024 acompared ~~portion~~to of$961 ~~the~~million ~~Hamm~~outstanding ~~Family's~~as ~~November~~of ~~2022~~March ~~take-private~~31, ~~transaction~~2023.

Income Taxes. For the ~~third~~first quarters of ~~2023~~2024 and ~~2022~~2023 we provided for income taxes at a combined federal and state tax rate of 23.5% ~~and 24.5%, respectively,~~ of our pre-tax income. We recorded an income tax provision of $~~106~~114.01 million for the ~~2023~~2024 ~~third~~first quarter and an income tax provision of $~~323~~239.48 million for the ~~2022~~2023 ~~third~~first quarter, which resulted in effective tax rates of 2221.20% and 2421.13%, respectively, after taking into account the application of statutory tax rates, permanent taxable differences, estimated tax credits, and other items.

respectively, after taking into account the application of statutory tax rates, permanent taxable differences, estimated tax credits, tax effects from equity/incentive compensation, and other items.

Nine months ended September 30, 2023 compared to the nine months ended September 30, 2022

Results of Operations

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

	Nine months ended September 30,
In thousands	2023			2022
Crude oil, natural gas, and natural gas liquids sales	$	5,663,672		$	7,870,696
Gain (loss) on derivative instruments, net		270,795			(1,009,460	)
Crude oil and natural gas service operations		73,716			52,707
Total revenues		6,008,183			6,913,943
Operating costs and expenses		(3,221,798	)		(2,961,094	)
Other expenses, net		(297,453	)		(211,408	)
Income before income taxes		2,488,932			3,741,441
Provision for income taxes		(539,139	)		(903,745	)
Income before equity in net loss of affiliate		1,949,793			2,837,696
Equity in net loss of affiliate		(2,041	)		(736	)
Net income		1,947,752			2,836,960
Net income attributable to noncontrolling interests		1,854			17,349
Net income attributable to Continental Resources	$	1,945,898		$	2,819,611
Production volumes:
Crude oil (MBbl)		62,098			54,018
Natural gas (MMcf)		340,529			325,011
Crude oil equivalents (MBoe)		118,852			108,187
Sales volumes:
Crude oil (MBbl)		61,780			53,979
Natural gas (MMcf)		340,529			325,011
Crude oil equivalents (MBoe)		118,535			108,147

Production

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

Boe production per day	YTD 9/30/2023		YTD 9/30/2022		% Change
Bakken		196,605		169,889		16	%
Anadarko Basin		156,550		155,861		0	%
Powder River Basin		23,144		23,438		(1	)%
Permian Basin		53,320		40,903		30	%
All other		5,738		6,197		(7	)%
Total		435,357		396,288		10	%

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

	Nine months ended September 30,												Volume
	2023					2022					Volume		percent
	Volume		Percent			Volume		Percent			increase		increase
Crude oil (MBbl)		62,098		52	%		54,018		50	%		8,080		15	%
Natural gas (MMcf)		340,529		48	%		325,011		50	%		15,518		5	%
Total (MBoe)		118,852		100	%		108,187		100	%		10,665		10	%

The 15% increase in crude oil production for year to date 2023 compared to year to date 2022 was primarily driven by new well completions in the Bakken field over the past year, which led to an increase of 4,973 MBbls, or 16%, compared to the prior year period. The increase was also partly driven by our property acquisitions and subsequent new well completions in the Permian Basin over the past year, which contributed to an increase in our 2023 production by 2,497 MBbls, or 29%, compared to 2022 production. Additionally, as a result of new well completions over the past year our crude oil production increased 1,003 MBbls, or 11%, in the

Anadarko Basin for year to date 2023 compared to year to date 2022. These increases were partially offset by a 278 MBbls, or 7%, decrease in crude oil production in the Powder River Basin due to fewer new well completions compared to the prior period.

The 5% increase in natural gas production for year to date 2023 was due in part to new well completions in the Bakken field over the past year, which led to an increase of 13,925 MMcf, or 15%, compared to the prior year period. The increase was also partly driven by our property acquisitions and subsequent new well completions in the Permian Basin and Powder River Basin over the past year, which contributed to an increase in our year to date 2023 production by 6,545 MMcf compared to the year to date 2022 period. These increases were partially offset by a 4,889 MMcf, or 2%, decrease in natural gas production in the Anadarko Basin due to recent capital spending being allocated primarily to oil-weighted projects in the play.

Revenues

Net crude oil, natural gas, and natural gas liquids sales and related net sales prices presented below are non-GAAP measures. See the subsequent section titled Non-GAAP Financial Measures for a discussion and calculation of these measures.

Net crude oil, natural gas, and natural gas liquids sales. Net sales for year to date 2023 totaled $5.42 billion, a 29% decrease compared to $7.63 billion for the comparable 2022 period due to decreases in net sales prices, partially offset by increases in sales volumes as discussed below.

Total sales volumes for year to date 2023 increased 10,388 MBoe, or 10%, compared to year to date 2022 due to additional drilling and completion activities and new wells added from property acquisitions over the past year. For year to date 2023, our crude oil sales volumes increased 14% and our natural gas sales volumes increased 5% compared to year to date 2022.

Our crude oil net sales prices averaged $73.62 per barrel for year to date 2023 compared to $95.51 per barrel for year to date 2022 due to a significant decrease in market prices resulting from changes in various macroeconomic conditions between periods. The differential between NYMEX West Texas Intermediate calendar month prices and our realized crude oil net sales prices averaged $3.76 per barrel for year to date 2023 compared to $2.63 per barrel for year to date 2022.

Our natural gas net sales prices averaged $2.56 per Mcf for year to date 2023 compared to $7.63 per Mcf for year to date 2022 due to a significant decrease in market prices and price realizations. The difference between our net sales prices and NYMEX Henry Hub calendar month natural gas prices was a discount of $0.13 per Mcf for year to date 2023 compared to a premium of $0.74 per Mcf for year to date 2022. NGL prices in 2023 have decreased from 2022 levels in conjunction with decreased crude oil prices and other factors, resulting in reduced price realizations for our natural gas sales stream relative to benchmark prices.

Derivatives. Reduced commodity prices during the nine months ended September 30, 2023 had an overall favorable impact on the fair value of our derivatives, which resulted in positive revenue adjustments totaling $270.8 million for the period, representing $209.4 million of cash gains and $61.4 million of unsettled non-cash gains, compared to negative revenue adjustments totaling $1.0 billion in the comparable 2022 period.

Operating Costs and Expenses

Production Expenses. Production expenses increased $75.4 million, or 16%, to $532.2 million for year to date 2023 compared to $456.8 million for year to date 2022 due to an increase in the number of producing wells from drilling activities and property acquisitions, cost inflation for services and materials, costs associated with adverse winter weather conditions in the Bakken and Powder River Basin, and higher workover-related activities aimed at enhancing production from producing properties. Production expenses on a per-Boe basis averaged $4.49 per Boe for year to date 2023 compared to $4.22 per Boe for year to date 2022, the increase of which primarily reflects higher workover-related activities, cost inflation, and an increase in oil-weighted production from the Permian and Powder River basins over the past year which typically have higher per-unit operating costs compared to gas-weighted properties in the Anadarko Basin.

Production and Ad Valorem Taxes. Production and ad valorem taxes decreased $122.8 million, or 22%, to $440.4 million for year to date 2023 compared to $563.2 million for year to date 2022 due to the previously described decrease in crude oil and natural gas revenues. Our production taxes as a percentage of net sales averaged 8.1% for year to date 2023, an increase compared to 7.4% for year to date 2022. This increase was the result of changes in sales mix of crude oil and natural gas in the Company’s operating areas between periods.

Depreciation, Depletion, Amortization and Accretion. Total DD&A increased $207.4 million, or 15%, to $1.6 billion for year to date 2023 compared to $1.4 billion for year to date 2022 primarily due to the previously described 10% 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.

	Nine months ended September 30,
$/Boe	2023		2022
Crude oil and natural gas	$	13.00	$	12.62
Other equipment		0.44		0.20
Asset retirement obligation accretion		0.09		0.09
Depreciation, depletion, amortization and accretion	$	13.53	$	12.91

Property Impairments. Total property impairments decreased $6.4 million to $46.5 million for year to date 2023 compared to $52.9 million for year to date 2022, primarily reflecting a decrease in the amortization of undeveloped leasehold costs driven by changes in management's estimates of unproved properties not expected to be transferred to proved properties over the lives of the leases.

General and Administrative Expenses. Total G&A expenses increased $24.7 million, or 12%, to $230.8 million for year to date 2023 compared to $206.1 million for year to date 2022.

Total G&A expenses include charges for incentive compensation/prior equity awards of $86.9 million and $60.8 million for the year to date periods of 2023 and 2022, respectively. This increase is primarily due to an increase in estimated incentive compensation payment obligations arising from changes in the value of the Company, which is partially offset by the reversal of previously recognized expense associated with incentive compensation awards that are no longer expected to vest.

G&A expenses other than incentive compensation/prior equity awards totaled $143.9 million for year to date 2023, consistent with $145.3 million for year to date 2022.

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

	Nine months ended September 30,
$/Boe	2023		2022
General and administrative expenses	$	1.21	$	1.35
Incentive compensation/prior equity awards		0.74		0.56
Total general and administrative expenses	$	1.95	$	1.91

Interest Expense. Interest expense increased $90.5 million, or 42%, to $306.0 million for year to date 2023 compared to $215.5 million year to date 2022 due to an increase in our weighted average outstanding debt balance from $6.6 billion for year to date 2022 to $8.1 billion for year to date 2023 coupled with an increase in variable interest rates incurred on outstanding credit facility and term loan borrowings. The increase in our outstanding debt was primarily driven by debt incurred in the fourth quarter of 2022 to fund a portion of the Hamm Family's November 2022 take-private transaction.

Income Taxes. For the nine months ended September 30, 2023 and 2022 we provided for income taxes at a combined federal and state tax rate of 23.5% and 24.5%, respectively, of our pre-tax income. We recorded an income tax provision of $539.1 million for the year to date period of 2023 and an income tax provision of $903.7 million for the year to date period of 2022, which resulted in effective tax rates of 21.7% and 24.2%, respectively, after taking into account the application of statutory tax rates, permanent taxable differences, estimated tax credits, tax effects from equity/incentive compensation, 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.

AtIn ~~October~~April 312024, ~~2023,~~ we ~~had~~repaid ~~$701~~the ~~million of~~ outstanding ~~borrowings and~~ $~~1.55~~650 ~~billion~~million ofterm ~~borrowing~~loan ~~availability~~balance ~~under~~using ~~our~~available ~~credit~~cash ~~facility.~~on-hand ~~Our~~and credit facility, ~~which~~borrowings. isAs ~~unsecured~~of ~~and~~April ~~has~~30, ~~no borrowing base subject to redetermination~~2024, ~~does~~the ~~not~~term ~~mature~~loan ~~until~~was ~~October~~fully ~~2026.~~repaid ~~We remain committed to reducing debt~~ and ~~plan~~the tobalance ~~continue~~on ~~prioritizing~~ the ~~repayment of~~ credit facility ~~borrowings~~was ~~over~~$490 ~~the~~million, ~~next~~with ~~12 months using available cash flows and expect our credit facility~~ borrowing availability ~~and~~of ~~liquidity to improve from current levels based on current market conditions~~$1.8 ~~As discussed in Note 6~~billion. ~~Derivative~~Our ~~Instruments~~credit facility, wewhich ~~have~~is ~~hedged~~unsecured aand ~~significant~~has ~~portion~~no ofborrowing ~~our~~base ~~forecasted~~subject ~~future production~~ to ~~reduce exposure to adverse price volatility and help secure cash flows to support our capital program~~redetermination, ~~debt~~does ~~reduction~~not ~~plans,~~mature ~~and~~until ~~general~~October ~~corporate needs~~2026.

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, term loan, and senior note indentures. Further, based on current market indications, we expect to meet our contractual cash commitments to third parties as of September 30, 2023, 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.16

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, 2024, 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 ~~decreased~~increased $172.890 ~~billion~~million, or 356%, to $31.5722 billion for ~~year~~the tofirst ~~date~~quarter ~~2023~~of 2024 compared to $51.4615 billion for ~~year~~the tofirst ~~date~~quarter ~~2022~~of 2023. The ~~decrease~~increase was driven by a $2118.211 ~~billion~~million ~~decrease~~increase in crude oil, natural gas, and NGL revenues due to the previously described ~~decrease~~increase in ~~commodity~~sales ~~prices~~volumes, ~~and~~which ~~increases~~was partially offset by an increase in certain ~~other~~ cash operating expenses associated with ~~increased~~higher sales volumes ~~and the growth of our Company~~ over the past year. Increased cash operating expenses included a $756.47 million increase in production expenses, ana $830.41 million increase in transportation, gathering, processing, and compression expenses, aand ~~$102.8~~an ~~million increase in cash paid for interest, a~~ $1611.10 million increase in ~~cash~~production ~~payments~~and ~~for~~ad ~~income~~valorem taxes~~, and $129~~.5 ~~million~~Additionally, ofour ~~cash payments for vested incentive compensation awards. These increases were partially offset by a $613.1 million increase in~~ realized cash gains on matured commodity derivatives ~~and~~increased a $~~122~~43.85 million ~~decrease~~compared into ~~production~~the ~~and~~prior ~~ad valorem taxes associated with lower revenues~~period.

Cash flows from investing activities

Net cash used in investing activities totaled $2717.777 ~~billion~~million for ~~year~~the tofirst ~~date~~quarter ~~2023~~of 2024, ~~consistent~~a ~~with~~decrease of $2303.700 million, or 30%, from $1.02 billion for ~~year~~the tofirst ~~date~~quarter ~~2022~~of 2023. Our investing cash flows for ~~year~~first toquarter ~~date~~2024 ~~2023~~ included $2663.800 ~~billion~~million of exploration and development costs compared to $2864.060 ~~billion~~million ~~of exploration and development costs~~ for ~~year~~first toquarter ~~date 2022~~2023, reflecting achanges ~~planned increase~~ in ~~budgeted~~the ~~spending.~~timing ~~This~~of ~~increase~~our incapital spending ~~was~~between ~~partially~~periods. ~~offset~~For byfull ~~lower~~year ~~acquisitions~~2024 ofour ~~producing~~capital ~~crude~~expenditures ~~oil~~budget ~~and~~attributable ~~natural~~to ~~gas~~us ~~properties,~~is ~~with~~ $~~162~~3.04 ~~million~~billion ~~acquired~~compared ~~for year~~ to ~~date~~$3.3 ~~2023~~billion ~~compared~~of tonon-acquisition ~~$432.7~~capital ~~million~~spending ~~acquired~~in ~~for~~full year to2023. ~~date 2022~~Additionally, aswe ~~well~~had aslower ~~increased~~acquisitions ~~proceeds~~of ~~from~~producing ~~the~~crude ~~sale~~oil ofand ~~assets~~natural gas properties, with $~~377~~0.49 million ofacquired ~~proceeds~~in ~~received~~first ~~for~~quarter ~~year~~of to2024 ~~date 2023~~ compared to $397.26 million ofacquired ~~proceeds~~in ~~for~~first ~~year~~quarter toof ~~date 2022~~2023.

Cash flows from financing activities

Net cash used in financing activities for ~~year~~the tofirst ~~date~~quarter ~~2023~~of 2024 totaled $~~886.8~~311 million, primarily consisting of $~~229~~210 million of net repayments on our credit facility, and a $~~636~~100 million repayment of ~~cash~~our ~~used~~term toloan ~~redeem~~due ~~senior~~in ~~notes~~November ~~and $25~~2025.~~3 million of cash distributed to noncontrolling interests.~~

24Net cash used in financing activities for the first quarter of 2023 totaled $211 million, primarily consisting of $199 million of net repayments on our credit facility and $11 million of cash distributed to noncontrolling interests.

Net cash used in financing activities for year to date 2022 totaled $974 million, primarily consisting of $500 million of net repayments on our credit facility, $284 million of cash dividends paid on common stock, $100 million of cash used to repurchase shares of our common stock, and $32 million of cash used to repurchase senior notes.

Future Sources of Financing

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

Based on current market indications supported by cash flow protection provided by our hedge portfolio against commodity price declines, our budgeted capital spending plans ~~over~~for ~~the~~2024 ~~next 12 months~~ are expected to be funded from operating cash flows. Any deficiencies in operating cash flows relative to budgeted spending are expected to be funded by borrowings under our credit facility. If cash flows are materially impacted by declines in commodity prices, 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 2026, with aggregate lender commitments totaling $2.255 billion. The commitments are from a syndicate of 13 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 87. Debt for a discussion of how this ratio is calculated pursuant to our credit agreement.

We were in compliance with our credit facility covenants at ~~September~~March 3031, ~~2023~~2024 and expect to maintain ~~such~~ compliance. At ~~September~~March 3031, ~~2023~~2024, our consolidated net debt to total capitalization ratio was 0.4234. We do not believe the credit facility covenants are reasonably likely to limit our ability to undertake additional debt financing if needed to support our business.

Future Capital Requirements

Our material future cash requirements are summarized below. Based on current market indications, we expect to meet our contractual cash commitments to third parties as of ~~September~~March 3031, ~~2023~~2024, 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 $5.7 billion at ~~September~~April 30, ~~2023~~2024, 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 $893 million of 2024 Notes due inon June 1, 2024., Wewhich ~~expect~~is toreflected beas ~~able~~a tocurrent ~~generate~~liability orin ~~borrow~~the ~~sufficient~~caption ~~funds~~“Current ~~necessary~~portion of long-term debt” in the condensed consolidated balance sheet. We plan to fully redeem our 2024 Notes by the June 1, 2024 maturity date using a combination of available cash and utilization of credit facility borrowing capacity. 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 87. Debt in Notes to Unaudited Condensed Consolidated Financial Statements.

We were in compliance with our senior note covenants at ~~September~~March 3031, ~~2023~~2024 and expect to maintain ~~such~~ compliance. We do not believe the senior note covenants will materially limit our ability to undertake additional debt financing. Downgrades or other negative rating actions with respect to the credit ratings assigned to our senior unsecured debt do not trigger additional senior note covenants.

Credit facility borrowings

As of ~~October~~April 3130, ~~2023~~2024, we had $~~701~~490 million of outstanding borrowings on our credit facility. Our credit facility matures in October 2026.

Term loan

We have a $750 million term loan that matures in November 2025. The covenant requirements in the term loan are consistent with the covenants in our revolving credit facility, including the requirement that we maintain a consolidated net debt to total capitalization ratio of no greater than 0.65 to 1.0. We were in compliance with the term loan covenants at September 30, 2023 and expect to maintain compliance. Downgrades or other negative rating actions with respect to the credit ratings assigned to our senior unsecured debt do not trigger a security requirement or change in covenants for the term loan.

Transportation, gathering, and processing commitments

We have entered into transportation, gathering, and processing commitments to guarantee capacity on crude oil and natural gas pipelines and natural gas processing facilities that require us to pay per-unit charges regardless of the amount of capacity used. Future commitments remaining as of ~~September~~March 3031, ~~2023~~2024 under the arrangements amount to approximately $~~909~~1.04 ~~million~~billion. See Note 98. Commitments and Contingencies in Notes to Unaudited Condensed Consolidated Financial Statements for additional information.

Capital expenditures

Our capital expenditures budget for ~~2023~~2024 is expected to be $3.254 billion. Costs of acquisitions and investments are not budgeted, with the exception of planned levels of spending for mineral acquisitions.

For the ~~nine~~three months ended ~~September~~March 3031, ~~2023~~2024, we invested $2657.539 ~~billion~~million in our capital program, excluding $~~681~~4.8 million of unbudgeted acquisitions and $813.38 million of mineral acquisitions attributable to Franco-Nevada~~, and including $86~~.6 million of capital costs associated with increased accruals for capital expenditures as compared to December 31, 2022. Our 2023 year to date capital expenditures were allocated as shown in the table below.

In millions	1Q 2023		2Q 2023		3Q 2023		YTD 2023
Exploration and development drilling	$	740.6	$	700.5	$	671.8	$	2,112.9
Land costs		42.5		43.8		24.5		110.8
Mineral acquisitions attributable to Continental		0.6		0.9		0.6		2.1
Capital facilities, workovers, water infrastructure, and other corporate assets		115.0		102.2		89.0		306.2
Capital expenditures attributable to Continental, excluding unbudgeted acquisitions		898.7		847.4		785.9		2,532.0
Unbudgeted acquisitions		240.7		56.3		384.2		681.2
Total capital expenditures attributable to Continental	$	1,139.4	$	903.7	$	1,170.1	$	3,213.2
Mineral acquisitions attributable to Franco-Nevada		2.3		3.5		2.5		8.3
Total capital expenditures	$	1,141.7	$	907.2	$	1,172.6	$	3,221.5

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 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.

Cash payments for income taxes

~~For~~During ~~the~~April ~~nine months ended September 30~~2024, ~~2023,~~ we made cash payments for federal and state income taxes totaling $~~456~~213 million, representing payments associated with ~~2022~~2023 tax return filing extensions and estimated quarterly payments for ~~2023~~2024 federal and state income taxes based on estimates of taxable income for ~~2023~~2024. Significant judgment is involved in estimating future taxable income, as we are required to make assumptions about future commodity prices, projected production, development activities, capital spending, profitability, and general economic conditions, all of which are subject to material revision in future periods as better information becomes available. If commodity prices remain at current levels, we expect to continue generating significant taxable income through at least year-end 2024, which would result in us continuing to make estimated tax payments on a quarterly basis in 2024 ~~that could approximate the payments made thus far in 2023~~. Because of the significant uncertainty inherent in numerous factors utilized in projecting taxable income, we cannot predict the amount of future income tax payments with certainty.

Long-term incentive compensation awards

AsAt ~~discussed~~December ~~in Note 10. Incentive Compensation in Notes to Unaudited Condensed Consolidated Financial Statements~~31, ~~at September 30,~~ 2023 we ~~have~~had recognized a current liability of $~~130.5~~131 million ~~and~~on ~~a non-current liability of $37.8 million in~~ the ~~unaudited~~ condensed consolidated balance ~~sheets~~sheet associated with unvested incentive compensation awards granted to employees, ~~that~~which ~~are~~was ~~scheduled~~subsequently topaid ~~vest~~ in ~~2024,~~cash ~~2025,~~to ~~and~~employees ~~2026.~~in WeFebruary ~~intend~~2024 toupon ~~settle~~the ~~these~~scheduled ~~awards~~vesting inof ~~cash at~~ the ~~time~~awards. ~~vesting~~We ~~occurs.~~granted ~~Our~~additional ~~recognized~~incentive ~~liabilities~~compensation ~~will~~awards bein ~~remeasured~~the ~~each~~2024 ~~reporting~~first ~~period~~quarter ~~leading~~and upintend to ~~the~~continue ~~applicable~~granting ~~award~~additional ~~vesting~~awards ~~dates~~on toan ~~reflect~~annual ~~additional~~basis ~~service~~that ~~rendered~~we byplan ~~employees and~~ to ~~reflect~~settle ~~changes~~ in ~~expected~~ cash ~~payments~~upon ~~arising from underlying changes in the value of the Company based on independent third party appraisals~~vesting.

~~Senior~~At ~~note~~March ~~redemptions~~31, 2024 we have recognized a current liability of $46.5 million and ~~repurchases~~a non-current liability of $17.0 million associated with unvested awards granted to employees that are scheduled to vest in 2025, 2026, and 2027. Our recognized liabilities will be remeasured each reporting period leading up to the applicable award vesting dates to reflect additional services 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.

In recent periods we have redeemed or repurchased a portion of our outstanding senior notes. From time to time, we may execute additional redemptions or repurchases of our senior notes for cash in open market transactions, privately negotiated transactions, or otherwise. The timing and amount of any such redemptions or repurchases will depend on prevailing market conditions, our liquidity, and prospects for future access to capital, and other factors. The amounts involved in any such transactions, individually or in the aggregate, may be material. Our $893 million of 2024 Notes is due in June 2024. We expect to be able to generate or borrow sufficient funds necessary to fully redeem our 2024 Notes by the maturity date.

Derivative Instruments

The fair value of our derivative instruments at ~~September~~March 3031, ~~2023~~2024 was a net ~~liability~~asset of $~~117~~299.35 million. See Note 65. Derivative Instruments in Notes to Unaudited Condensed Consolidated Financial Statements for further discussion of our hedging activities, including a summary of derivative contracts in place as of ~~September~~March 3031, ~~2023~~2024. The estimated fair value of our derivatives is highly sensitive to market price volatility and therefore subject to significant fluctuations from period to period. See Item 3. Quantitative and Qualitative Disclosures About Market Risk for information on how hypothetical changes in commodity prices would impact the fair value of our derivatives as of ~~September~~March 3031, ~~2023~~2024.

Subsequent to March 31, 2024 and through May 1, 2024 we entered into additional derivative contracts as set forth in the tables below.


Natural gas derivatives
Period and Type of Contract	Average Volumes Hedged			Weighted Average Hedge Price ($/MMBtu)
January 2027 - December 2027
Swaps - Henry Hub		260,000	MMBtus/day	$	3.99


Crude oil derivatives
Period and Type of Contract	Average Volumes Hedged			Weighted Average Hedge Price ($/Bbl)
May 2024 - February 2025
Swaps - WTI		24,000	Bbls/day	$	80.25

Critical Accounting Policies and Estimates

There have been no changes in our critical accounting policies and estimates from those disclosed in our ~~2022~~2023 Form 10-K.

~~Non-GAAP Financial Measures~~20

Net crude oil, natural gas, and natural gas liquids sales and net sales prices

Revenues and transportation expenses associated with production from our operated properties are reported separately. For non-operated properties, we receive a net payment from the operator for our share of sales proceeds which is net of costs, if any, incurred by the operator. Such non-operated revenues are recognized at the net amount of proceeds received. As a result, the separate presentation of revenues and transportation expenses from our operated properties differs from the net presentation from non-operated properties. This impacts the comparability of certain operating metrics, such as per-unit sales prices, when such metrics are prepared in accordance with U.S. GAAP using gross presentation for some revenues and net presentation for others.

In order to provide metrics prepared in a manner consistent with how management assesses the Company's operating results and to achieve comparability between operated and non-operated revenues, we have presented crude oil, natural gas, and natural gas liquids sales net of transportation expenses in Management’s Discussion and Analysis of Financial Condition and Results of Operations, which we refer to as "net crude oil, natural gas, and natural gas liquids sales," a non-GAAP measure. Average sales prices calculated using net sales are referred to as "net sales prices," a non-GAAP measure, and are calculated by taking revenues less transportation expenses divided by sales volumes. Management believes presenting our revenues and sales prices net of transportation expenses is useful because it normalizes the presentation differences between operated and non-operated revenues and allows for a useful comparison of net realized prices to NYMEX benchmark prices on a Company-wide basis.

The following tables present a reconciliation of crude oil, natural gas, and natural gas liquids sales (GAAP) to net crude oil, natural gas, and natural gas liquids sales and related net sales prices (non-GAAP) for the three and nine months ended September 30, 2023 and 2022.

	Three months ended September 30, 2023									Three months ended September 30, 2022
In thousands	Crude oil			Natural gasand NGLs			Total			Crude oil			Natural gasand NGLs			Total
Crude oil, natural gas, and NGL sales (GAAP)	$	1,800,610		$	281,721		$	2,082,331		$	1,738,414		$	1,028,848		$	2,767,262
Less: Transportation expenses		(74,320	)		(12,553	)		(86,873	)		(67,818	)		(17,832	)		(85,650	)
Net crude oil, natural gas, and NGL sales (non-GAAP)	$	1,726,290		$	269,168		$	1,995,458		$	1,670,596		$	1,011,016		$	2,681,612
Sales volumes (MBbl/MMcf/MBoe)		21,960			118,913			41,779			18,674			118,116			38,360
Net sales price (non-GAAP)	$	78.61		$	2.26		$	47.76		$	89.46		$	8.56		$	69.91

	Nine months ended September 30, 2023									Nine months ended September 30, 2022
In thousands	Crude oil			Natural gasand NGLs			Total			Crude oil			Natural gasand NGLs			Total
Crude oil, natural gas, and NGL sales (GAAP)	$	4,752,572		$	911,100		$	5,663,672		$	5,343,742		$	2,526,954		$	7,870,696
Less: Transportation expenses		(204,613	)		(40,654	)		(245,267	)		(188,418	)		(48,433	)		(236,851	)
Net crude oil, natural gas, and NGL sales (non-GAAP)	$	4,547,959		$	870,446		$	5,418,405		$	5,155,324		$	2,478,521		$	7,633,845
Sales volumes (MBbl/MMcf/MBoe)		61,780			340,529			118,535			53,979			325,011			108,147
Net sales price (non-GAAP)	$	73.62		$	2.56		$	45.71		$	95.51		$	7.63		$	70.59

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 ~~nine~~three months ended ~~September~~March 3031, ~~2023~~2024, and excluding the effect of derivative instruments in place, our annual revenue would increase or decrease by approximately $~~830~~871 million for each $10.00 per barrel change in crude oil prices at ~~September~~March 3031, ~~2023~~2024 and $~~455~~441 million for each $1.00 per Mcf change in natural gas prices at ~~September~~March 3031, ~~2023~~2024.

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

The fair value of our derivative instruments at ~~September~~March 3031, ~~2023~~2024 was a net ~~liability~~asset of $~~117~~299.35 million, which is comprised of a $67357.87 million net asset associated with our natural gas derivatives ~~and~~partially offset by a $~~185~~58.12 million net liability 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 ~~September~~March 3031, ~~2023~~2024.

		Hypothetical Fair Value
In thousands	Change in Forward Price	Asset (Liability)
Crude Oil	-10%	$	9469,~~774~~916
Crude Oil	+10%	$	(~~465~~186,~~008~~259	)
Natural Gas	-10%	$	~~299~~582,~~052~~536
Natural Gas	+10%	$	~~(163~~132,~~056~~882	)

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 ($1.32 billion in receivables at ~~September~~March 3031, ~~2023~~2024), and our joint interest and other receivables ($~~385~~302 million at ~~September~~March 3031, ~~2023~~2024).

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 $2537 million at ~~September~~March 3031, ~~2023~~2024, which will be used to

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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 ~~and $750 million term loan~~. ~~Such~~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 $~~701~~490 million of variable rate borrowings outstanding on our credit facility ~~and $750 million of variable rate borrowings on our term loan~~ at ~~October~~April 3130, ~~2023~~2024. The impact of a 0.25% increase in interest rates on this amount of debt would result in increased interest expense and reduced income before income taxes of approximately $31.62 million per year.

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 ~~September~~March 3031, ~~2023~~2024 to ensure information required to be disclosed in the reports it files and submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and information required to be disclosed under the Exchange Act is accumulated and communicated to the Company’s management, including its Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control over Financial Reporting

During the three months ended ~~September~~March 3031, ~~2023~~2024, there were no changes in our internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Inherent Limitations on Controls and Procedures

A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risks that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Accordingly, even an effective system of internal control will provide only reasonable assurance that the objectives of the internal control system are met.

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PART II. Other Information

ITEM 1. Legal Proceedings

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

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 ~~2022~~2023 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 ~~2022~~2023 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 ~~2022~~2023 Form 10-K.

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

Not applicable.

ITEM 3. Defaults Upon Senior Securities

Not applicable.

ITEM 4. Mine Safety Disclosures

Not applicable.

ITEM 5. Other Information

Not applicable.

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ITEM 6. Exhibits

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

3.1		Conformed version of Fifth 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, 2022 (Commission File No. 001-32886) filed February 22, 2023 and incorporated herein by reference.
3.2		Fifth Amended and Restated Bylaws of Continental Resources, Inc. filed as Exhibit 3.2 to the Company’s Form 10-K for the year ended December 31, 2022 (Commission File No. 001-32886) filed February 22, 2023 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
101.CAL*		Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*		Inline XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*		Inline XBRL Taxonomy Extension Label Linkbase Document
101.PRE*		Inline XBRL Taxonomy Extension Presentation Linkbase Document
104		Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

* Filed herewith

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SIGNATURE

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

		CONTINENTAL RESOURCES, INC.
Date:	~~November~~May 3, ~~2023~~2024	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)

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(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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