UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

_______________________________

FORM 10-K

(Mark One)

☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934For the fiscal year ended December 31, ~~2022~~2023

    ☐

    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)

_______________________________

Registrant’s telephone number, including area code: (405) 234-9000

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

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

_______________________________

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes x No ¨

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, 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.

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 has filed a report on and attestation to its management's assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ¨

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive ~~oﬃcers~~officers during the relevant recovery period pursuant to §240.10D-1(b). ☐

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

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 30, 2022 was approximately $4.1 billion, based upon the closing price of $65.35 per share as reported by the New York Stock Exchange on such date.

Effective November 22, 2022, Continental Resources, Inc. became a privately held corporation and has no publicly available common shares outstanding at the time of this filing.

DOCUMENTS INCORPORATED BY REFERENCE

Part III (Items 10, 11, 12, 13 and 14) of this Annual Report on Form 10-K is incorporated by reference from the registrant’s amendment to this Form 10-K to be filed on Form 10-K/A with the Securities and Exchange Commission no later than 120 days after the end of the registrant’s fiscal year covered by this reportNone.

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PART I
Item 1.	Business	1
	General	1
	Our Business Strategies	2
	Our Business Strengths	2
	Crude Oil and Natural Gas Operations	1
	Crude Oil and Natural Gas Operations	3
	Proved Reserves	1
	Proved Reserves	3
	Developed and Undeveloped Acreage	4
	Developed and Undeveloped Acreage	6
	Drilling Activity	5
	Drilling Activity	7
	Summary of Crude Oil and Natural Gas Properties and Projects	5
	Summary of Crude Oil and Natural Gas Properties and Projects	7
	Production and Price History	6
	Production and Price History	9
	Productive Wells	7
	Productive Wells	10
	Title to Properties	7
	Title to Properties	10
	Marketing	7
	Marketing	10
	Competition	8
	Competition	11
	Regulation of the Crude Oil and Natural Gas Industry	8
	Regulation of the Crude Oil and Natural Gas Industry	11
	Human Capital	10
	Human Capital	17
	Company Contact Information	11
	Company Contact Information	18
Item 1A.	Risk Factors	12
Item 1A.	Risk Factors	19
Item 1B.	Unresolved Staff Comments	22
Item 1B.	Unresolved Staff Comments	29
Item 1C.	Cybersecurity	22
Item 2.	Properties	2923
Item 3.	Legal Proceedings	2923
Item 4.	Mine Safety Disclosures	3023
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	3124
Item 6.	Reserved	3124
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	3225
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	4637
Item 8.	Financial Statements and Supplementary Data	4839
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	8670
Item 9A.	Controls and Procedures	8670
Item 9B.	Other Information	8872
Item 9C.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	8872
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	8973
Item 11.	Executive Compensation	8974
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	8977
Item 13.	Certain Relationships and Related Transactions, and Director Independence	8978
Item 14.	Principal Accountant Fees and Services	8978
PART IV
Item 15.	Exhibits and Financial Statement Schedules	9079

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Glossary of Crude Oil and Natural Gas Terms

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

“basin” A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.

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

“Bcf” One billion cubic feet of natural gas.

“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.

“conventional play” An area believed to be capable of producing crude oil and natural gas occurring in discrete accumulations in structural and stratigraphic traps.

“DD&A” Depreciation, depletion, amortization and accretion.

“de-risked” Refers to acreage and locations in which the Company believes the geological risks and uncertainties related to recovery of crude oil and natural gas have been reduced as a result of drilling operations to date. However, only a portion of such acreage and locations have been assigned proved undeveloped reserves and ultimate recovery of hydrocarbons from such acreage and locations remains subject to all risks of recovery applicable to other acreage.

“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.

“enhanced recovery” The recovery of crude oil and natural gas through the injection of liquids or gases into the reservoir, supplementing its natural energy. Enhanced recovery methods are sometimes applied when production slows due to depletion of the natural pressure.

“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.

“formation” A layer of rock which has distinct characteristics that differs from nearby rock.

“fracture stimulation” A process involving the high pressure injection of water, sand and additives into rock formations to stimulate crude oil and natural gas production. Also may be referred to as hydraulic fracturing.

“gross acres” or “gross wells” Refers to the total acres or wells in which a working interest is owned.

“held by production” or “HBP” Refers to an oil and gas lease continued into effect into its secondary term for so long as a producing oil and/or gas well is located on any portion of the leased premises or lands pooled therewith.

“horizontal drilling” A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled horizontally within a specified interval.

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

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“MBoe” One thousand Boe.

“Mcf” One thousand cubic feet of natural gas.

“MMBo” One million barrels of crude oil.

“MMBoe” One million Boe.

“MMBtu” One million British thermal units.

“MMcf” One million cubic feet of natural gas.

“net acres” or “net wells” Refers to the sum of the fractional working interests owned in gross acres or gross wells.

"Net crude oil and natural gas 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 is a non-GAAP measure. See Part II, Item 7. 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 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 II, Item 7. 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.

“pad drilling” or “pad development” Describes a well site layout which allows for drilling multiple wells from a single pad resulting in less environmental impact and lower per-well drilling and completion costs.

“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.

“productive well” A well found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.

“prospect” A potential geological feature or formation which geologists and geophysicists believe may contain hydrocarbons. A prospect can be in various stages of evaluation, ranging from a prospect that has been fully evaluated and is ready to drill to a prospect that will require substantial additional seismic data processing and interpretation.

“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.

“proved developed reserves” Reserves expected to be recovered through existing wells with existing equipment and operating methods.

“proved undeveloped reserves” or “PUD” Proved reserves expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for completion.i

“PV-10” When used with respect to crude oil and natural gas reserves, PV-10 represents the estimated future gross revenues to be generated from the production of proved reserves using a 12-month unweighted arithmetic average of the first-day-of-the-month commodity prices for the period of January to December, net of estimated production and future development and abandonment costs based on costs in effect at the determination date, before income taxes, and without giving effect to non-property-related expenses, discounted to a present value using an annual discount rate of 10% in accordance with the guidelines of the Securities and Exchange Commission (“SEC”). PV-10 is not a financial measure calculated in accordance with generally accepted accounting principles (“GAAP”) and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of the Company’s crude oil and natural gas properties. The Company and others in the industry use PV-10 as a

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~~measure~~“proved toundeveloped ~~compare~~reserves” ~~the~~or ~~relative~~“PUD” ~~size~~Proved ~~and~~reserves ~~value~~expected ofto ~~proved~~be ~~reserves~~recovered ~~held~~from bynew ~~companies~~wells ~~without~~on ~~regard~~undrilled toacreage ~~the~~or ~~specific~~from ~~tax~~existing ~~characteristics~~wells ofwhere ~~such~~a ~~entities~~relatively major expenditure is required for completion.

“reservoir” A porous and permeable underground formation containing a natural accumulation of producible crude oil and/or natural gas that is confined by impermeable rock or water barriers and is separate from other reservoirs.

“residue gas” Refers to gas that has been processed to remove natural gas liquids.

“resource play” Refers to an expansive contiguous geographical area with prospective crude oil and/or natural gas reserves that has the potential to be developed uniformly with repeatable commercial success due to advancements in horizontal drilling and completion technologies.

“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.

“SCOOP” Refers to the South Central Oklahoma Oil Province, a term used to describe properties located in the Anadarko basin of Oklahoma in which we operate. Our SCOOP acreage extends across portions of Garvin, Grady, Stephens, Carter, McClain and Love counties of Oklahoma and has the potential to contain hydrocarbons from a variety of conventional and unconventional reservoirs overlying and underlying the Woodford formation.

“STACK” Refers to Sooner Trend Anadarko Canadian Kingfisher, a term used to describe a resource play located in the Anadarko Basin of Oklahoma characterized by stacked geologic formations with major targets in the Meramec, Osage and Woodford formations.

“spacing” The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres (e.g., 640-acre spacing) and is often established by regulatory agencies.

“Standardized Measure” Discounted future net cash flows estimated by applying the 12-month unweighted arithmetic average of the first-day-of-the-month commodity prices for the period of January to December to the estimated future production of year-end proved reserves. Future cash inflows are reduced by estimated future production and development costs based on period-end costs to determine pre-tax net cash inflows. Future income taxes, if applicable, are computed by applying the statutory tax rate to the excess of pre-tax cash inflows over the tax basis in the crude oil and natural gas properties. Future net cash inflows after income taxes are discounted using a 10% annual discount rate.

“unconventional play” An area believed to be capable of producing crude oil and natural gas occurring in accumulations that are regionally extensive, but may lack readily apparent traps, seals and discrete hydrocarbon-water boundaries that typically define conventional reservoirs. These areas tend to have low permeability and may be closely associated with source rock, as is the case with oil and gas shale, tight oil and gas sands and coalbed methane, and generally require horizontal drilling, fracture stimulation treatments or other special recovery processes in order to achieve economic production.

“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.

“unit” The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.

“well bore” The hole drilled by the bit that is equipped for crude oil or natural gas production on a completed well. Also called a well or borehole.

“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.

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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 or 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

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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 I, Item 1A. Risk Factors and elsewhere in this report and other disclosures or announcements we make from time to time.

Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date on which such statement is made. Additionally, new factors emerge from time to time, and it is not possible for us to predict all such factors. Should one or more of the risks or uncertainties described in this report 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.

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Part I

You should read this entire report carefully, including the risks described under Part I, Item 1A. Risk Factors and our consolidated financial statements and the notes to those consolidated financial statements included elsewhere in this report. Unless the context otherwise requires, references in this report to “Continental Resources,” “Continental,” “we,” “us,” “our,” “ours” or “the Company” refer to Continental Resources, Inc. and its subsidiaries.

Item 1. Business

Take-private transaction

On October 16, 2022, the Company entered into an Agreement and Plan of Merger (the “Merger Agreement”) with Omega Acquisition, Inc. (“Merger Sub”), an entity owned by the Company’s founder, Harold G. Hamm. Pursuant to the Merger Agreement, on November 22, 2022 Merger Sub completed a tender offer to purchase any and all of the outstanding shares of the Company’s common stock for $74.28 per share in cash, other than: (i) shares of common stock owned by Mr. Hamm, certain of his family members and their affiliated entities (collectively, the “Hamm Family”) and (ii) shares of common stock underlying unvested equity awards issued pursuant to the Company’s long-term incentive plans. Immediately prior to the consummation of the Offer, Mr. Hamm contributed 100% of the capital stock of Merger Sub to the Company, as a result of which Merger Sub became a wholly owned subsidiary of the Company. Following consummation of the Offer, Merger Sub merged with and into the Company, with the Company continuing as the surviving corporation wholly owned by the Hamm Family.

Following the completion of the transaction: (i) our common stock ceased to be listed on the New York Stock Exchange effective November 23, 2022, (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. As a result, certain of the corporate governance, disclosure, and other provisions applicable to a company with listed equity securities and reporting obligations under the Exchange Act no longer 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.

See Part II. Item 8. Notes to Consolidated Financial Statements—Note 1. Organization and Summary of Significant Accounting Policies—Take-Private Transaction for additional information.

Nature of business

We are an independent crude oil and natural gas company formed in 1967 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 focus our activities in large crude oil and natural gas plays that provide us the opportunity to acquire undeveloped acreage positions and apply our geologic and operational expertise to drill and develop properties at attractive rates of return. We have been successful in targeting large repeatable resource plays where three dimensional seismic, horizontal drilling, geosteering technologies, advanced completion technologies ~~(e.g.~~, ~~fracture stimulation),~~ pad/row development, and enhanced recovery technologies allow us to develop and produce crude oil and natural gas reserves from unconventional formations. ~~As a result of these efforts, we have grown substantially through the drill bit. Additionally, our operations have also grown in recent years from strategic acquisitions.~~

AsEffective ofNovember ~~December 31~~22, 2022, ~~our~~Continental ~~proved reserves were 1~~Resources,~~864~~ ~~MMBoe,~~Inc. ~~with~~became ~~proved~~a ~~developed~~privately ~~reserves~~held ~~representing~~corporation ~~1,035~~and ~~MMBoe,~~has orno ~~56%,~~publicly ofavailable ~~our~~common ~~total~~shares ~~proved reserves~~outstanding. ~~The~~We ~~standardized~~continue ~~measure~~to offurnish ~~our~~Quarterly ~~discounted~~Reports ~~future~~on ~~net~~Form ~~cash~~10-Q ~~flows~~and ~~totaled~~Annual ~~$31.91~~Reports ~~billion~~on atForm ~~December~~10-K ~~31,~~with ~~2022.~~the ~~For~~SEC ~~2022,~~as werequired ~~generated~~by ~~crude~~our ~~oil,~~senior ~~natural~~note ~~gas,~~indentures. ~~and~~See ~~natural~~Part ~~gas~~II. ~~liquids~~Item ~~revenues of $10~~8.1 ~~billion~~Notes ~~and~~to ~~operating~~Consolidated ~~cash~~Financial ~~flows~~Statements—Note ~~of $7~~1.0 ~~billion.~~Organization ~~Crude oil accounted for 50% of our total production~~ and ~~69%~~Summary of ~~our~~Significant ~~crude~~Accounting ~~oil, natural gas, and natural gas liquids revenues for~~ Policies—2022. ~~Our~~Take-Private ~~total~~Transaction ~~production averaged 401,800 Boe per day~~ for ~~2022,~~additional ~~an increase of 22% compared to 2021~~information.

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The table below summarizes our total proved reserves, PV-10 (non-GAAP) and net producing wells as of December 31, 2022 and our average daily production for the quarter ended December 31, 2022 for our principal operating areas. The PV-10 values shown below are not intended to represent the fair market value of our crude oil and natural gas properties. There are numerous uncertainties inherent in estimating quantities of crude oil and natural gas reserves. See Part I, Item 1A. Risk Factors and “Critical Accounting Policies and Estimates” in Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations of this report for further discussion of uncertainties inherent in the reserve estimates.

	December 31, 2022
	Provedreserves(MBoe)		Percentof total			PV-10 (1)(In millions)		Netproducingwells		4Q 2022 Daily Production (Boe per day)		Percentof total
Bakken		733,875		39.4	%	$	17,802		2,098		174,397		41.7	%
Anadarko Basin		697,219		37.4	%	$	12,060		845		165,225		39.5	%
Powder River Basin		103,941		5.6	%	$	2,106		433		28,057		6.7	%
Permian Basin		303,799		16.3	%	$	7,367		364		44,925		10.7	%
All other		24,930		1.3	%	$	626		257		5,552		1.4	%
Total		1,863,764		100.0	%	$	39,961		3,997		418,156		100.0	%

PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues of approximately $8.05 billion. Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of our crude oil and natural gas properties. We and others in the crude oil and natural gas industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific income tax characteristics of such entities. See Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Financial Measures for further discussion.

Our Business Strategies

Our business strategies continue to be focused on increasing enterprise value by finding and developing crude oil and natural gas reserves at low costs and attractive rates of return. For ~~2023~~2024, our primary business strategies will include:

•

Continuing to exercise capital discipline and operational ~~discipline~~excellence to maximize cash flow generation ~~and competitive returns on capital employed~~;

•

Reducing outstanding debt and ~~maintaining~~strengthening aour ~~strong~~ balance sheet to further enhance financial flexibility;

•

~~Maintaining~~Continuing ~~low-cost,~~to optimize the efficiency of our capital ~~efficient~~programs and production operations to further reduce costs and enhance returns; and

•

Driving continued improvement in our health, safety, and environmental performance and governance programs.

Our Business Strengths

We have a number of strengths to allow us to successfully execute our business strategies, including the following:

Large acreage inventory with access to both crude oil and natural gas resources. We held 605,179 net undeveloped acres and 1.52 million net developed acres under lease as of December 31, 2022 concentrated in core areas of premier U.S. resource plays that provide optionality and access to crude oil, natural gas, and natural gas liquids.

Expertise with pad and row development, horizontal drilling, and optimized completion methods. We have substantial experience with horizontal drilling and optimized completion methods and continue to be among industry leaders in the use of new drilling and completion technologies. We continue to improve drilling and completion efficiencies through the use of multi-well pad and row development strategies. Further, we are among industry leaders in drilling long lateral lengths. We have also been among industry leaders in testing and utilizing optimized completion technologies involving various combinations of fluid types, proppant types and volumes, and stimulation stage spacing to determine optimal methods for improving recoveries and rates of return. We continually refine our drilling and completion techniques in an effort to deliver improved results across our properties.

Control operations over a substantial portion of our assets and investments. As of December 31, 2022, we operated properties comprising 88% of our total proved reserves. By controlling a significant portion of our operations, we are able to more effectively manage the cost and timing of exploration and development of our properties, including the drilling and completion methods used. Additionally, we capitalize on our geologic knowledge and land expertise to strategically acquire minerals in areas of future growth, thereby allowing us to enhance cash flows and project economics through the alignment of mineral ownership with our drilling schedule. Further, we continue to grow our significant portfolio of water gathering, recycling, and disposal infrastructure assets which

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allow for uninterrupted flow back and recycling capabilities, supports timely completion activities, and generates additional service revenues and cash flows.

Experienced Management Team. Our senior management team has extensive expertise in the oil and gas industry and with operating in challenging commodity price environments. Our Executive Chairman, Harold G. Hamm, began his career in the oil and gas industry in 1967. Our 7 executive officers have an average of 40 years of oil and gas industry experience.

Financial Position and Liquidity. We have a credit facility with lender commitments totaling $2.255 billion that matures in October 2026. We had approximately $1.12 billion of borrowing availability on our credit facility at February 1, 2023 after considering outstanding borrowings and letters of credit. Our credit facility is unsecured and does not have a borrowing base requirement that is 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.

Crude Oil and Natural Gas Operations

Proved Reserves

Proved reserves are those 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. In connection with the estimation of proved reserves, the term “reasonable certainty” implies a high degree of confidence the quantities of crude oil and/or natural gas actually recovered will equal or exceed the estimate. To achieve reasonable certainty, our internal reserve engineers and Ryder Scott Company, L.P (“Ryder Scott”), our independent reserve engineers, employed technologies demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, well logs, geologic maps including isopach and structure maps, analogy and statistical analysis, and available downhole, production, seismic, and well test data.

The table below sets forth estimated proved crude oil and natural gas reserves information by reserve category as of December 31, ~~2022~~2023. Proved reserves attributable to noncontrolling interests are not material relative to our consolidated reserves and are not separately presented herein. ~~The standardized measure of our discounted future net cash flows totaled approximately $31.91 billion at December 31, 2022.~~ Our reserve estimates as of December 31, ~~2022~~2023 are based primarily on a reserve report prepared by Ryder Scott. In preparing its report, Ryder Scott evaluated properties representing approximately 9899% of our ~~PV-10 and 98% of our~~ total proved reserves as of December 31, ~~2022~~2023. Our internal technical staff evaluated the remaining properties. A copy of Ryder Scott’s summary report is included as an exhibit to this Annual Report on Form 10-K.

Our estimated proved reserves and related future net revenues, Standardized Measure and PV-10 at December 31, 2022 were determined using the 12-month unweighted arithmetic average of the first-day-of-the-month commodity prices for the period of January 2022 through December 2022, without giving effect to derivative transactions, and were held constant throughout the lives of the properties. These prices were $93.67 per Bbl for crude oil and $6.36 per MMBtu for natural gas ($89.47 per Bbl for crude oil and $6.12 per Mcf for natural gas adjusted for location and quality differentials). 1

The following table summarizes our estimated proved reserves by commodity and reserve classification as of December 31, 2022.

	Crude Oil(MBbls)		Natural Gas(MMcf)		Total(MBoe)		PV-10 (1)(in millions)
Proved developed producing		439,497		3,417,413		1,009,066	$	23,468.8
Proved developed non-producing		14,802		69,361		26,362		580.0
Proved undeveloped		435,240		2,358,578		828,336		15,912.6
Total proved reserves		889,539		5,845,352		1,863,764	$	39,961.4
Standardized Measure (1)							$	31,907.6

PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues of approximately $8.05 billion. See Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Financial Measures for further discussion.

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~~The~~Our ~~following~~estimated ~~table~~proved ~~provides~~reserves ~~additional~~and ~~information~~related ~~regarding~~future ~~our~~net ~~estimated~~revenues ~~proved~~at December 31, 2023 were determined using the 12-month unweighted arithmetic average of the first-day-of-the-month commodity prices for the period of January 2023 through December 2023, without giving effect to derivative transactions, and were held constant throughout the lives of the properties. These prices were $78.22 per Bbl for crude oil and $2.64 per MMBtu for natural gas ~~reserves~~($73.67 byper ~~region~~Bbl asfor ofcrude ~~December~~oil ~~31,~~and ~~2022~~$2.00 per Mcf for natural gas adjusted for location and quality differentials).

	Proved Developed						Proved Undeveloped
	Crude Oil(MBbls)		Natural Gas(MMcf)		Total(MBoe)		Crude Oil(MBbls)		Natural Gas(MMcf)		Total(MBoe)
Bakken		221,714		1,047,607		396,315		220,634		701,555		337,560
Anadarko Basin		77,781		2,072,290		423,163		57,863		1,297,162		274,056
Powder River Basin		34,382		154,902		60,199		27,782		95,760		43,742
Permian Basin		95,707		210,681		130,821		128,961		264,101		172,978
All other		24,715		1,294		24,930		—		—		—
Total		454,299		3,486,774		1,035,428		435,240		2,358,578		828,336

The following table summarizes our estimated proved reserves by commodity and reserve classification as of December 31, 2023.


	Crude Oil (MBbls)		Natural Gas (MMcf)		Total (MBoe)
Proved developed producing		394,532		3,186,722		925,653
Proved developed non-producing		7,319		34,844		13,126
Proved undeveloped		512,183		2,376,765		908,310
Total proved reserves		914,034		5,598,331		1,847,089

The following table provides additional information regarding our estimated proved crude oil and natural gas reserves by region as of December 31, 2023.


	Proved Developed						Proved Undeveloped
	Crude Oil (MBbls)		Natural Gas (MMcf)		Total (MBoe)		Crude Oil (MBbls)		Natural Gas (MMcf)		Total (MBoe)
Bakken		187,125		916,570		339,887		201,766		630,987		306,931
Anadarko Basin		80,047		1,933,019		402,216		77,239		1,042,211		250,941
Powder River Basin		30,871		150,785		56,002		57,496		155,329		83,384
Permian Basin		82,261		220,725		119,049		175,682		548,238		267,054
All other		21,547		467		21,625		—		—		—
Total		401,851		3,221,566		938,779		512,183		2,376,765		908,310

The following table provides information regarding changes in total estimated proved reserves for the periods presented.

Year Ended December 31,

MBoe

~~2022~~2023

~~2021~~2022

~~2020~~2021

Proved reserves at beginning of year

1,~~645~~863,~~310~~764

1,~~103~~645,~~762~~310

1,~~619~~103,~~265~~762

Revisions of previous estimates

(~~133~~369,~~061~~264

)

53(133,~~569~~061

)

~~(504~~53,~~874~~569

)

Extensions, discoveries and other additions

~~395~~438,~~490~~367

~~371~~395,~~105~~490

91371,~~387~~105

Production

(~~146~~160,~~657~~660

)

(~~120~~146,~~321~~657

)

(~~109~~120,~~833~~321

)

Sales of minerals in place

(~~144~~15,594

)

(~~148~~144

)

—(148

)

Purchases of minerals in place

~~102~~90,~~826~~476

~~237~~102,~~343~~826

7237,~~817~~343

Proved reserves at end of year

1,~~863~~847,~~764~~089

1,~~645~~863,~~310~~764

1,~~103~~645,~~762~~310

Revisions of previous estimates. Revisions for ~~2022~~2023 are comprised of (i) ~~upward~~downward price revisions of 2922 MMBo and ~~105~~344 Bcf (totaling 4679 MMBoe) due to ana ~~increase~~decrease in average crude oil and natural gas prices in ~~2022~~2023 compared to ~~2021~~2022, (ii) the removal of 3514 MMBo and ~~225~~148 Bcf (totaling 7239 MMBoe) of PUD reserves no longer scheduled to be drilled within five years of initial booking due to continual refinement of our drilling and development programs and reallocation of capital to areas providing the best opportunities to improve efficiencies, recoveries, and rates of return, (iii) downward revisions of 7195 MMBo and ~~401~~446 Bcf (totaling ~~137~~170 MMBoe) from the removal of PUD reserves due to changes in anticipated well densities, economics, performance, and other factors, and (iv) downward revisions ~~for oil reserves~~ of 957 MMBo and ~~upward~~149 ~~revisions for natural gas reserves of 236~~ Bcf (~~netting~~totaling to82 31 MMBoe ~~of upward revisions~~) due to changes in ownership interests, operating costs, anticipated production, and other factors.

Extensions, discoveries and other additions. Extensions, discoveries and other additions for each of the three years reflected in the table above were due to successful drilling and completion activities and continual refinement of our drilling programs. For ~~2022~~2023, proved reserve additions totaled ~~109~~438 MMBoe ~~in the Bakken, 154 MMBoe in the Anadarko Basin, 18 MMBoe in the Powder River Basin, and 114 MMBoe in the Permian Basin~~. See the subsequent section titled Summary of Crude Oil and Natural Gas Properties and Projects for a discussion of our ~~2022~~2023 drilling activities.

Sales of minerals in place. We had no individually significant dispositions of proved reserves in the past three years.

Purchases of minerals in place. Purchases in 2023, 2022, and 2021 were ~~primarily~~ attributable to our acquisitions of properties ~~in the Permian Basin and Powder River Basin~~ as discussed in Part II. Item 8. Notes to Consolidated Financial Statements—Note 2. Property Acquisitions. Weand ~~had no individually significant acquisitions of proved reserves in 2020~~Dispositions.

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Proved Undeveloped Reserves

All of our PUD reserves at December 31, ~~2022~~2023 are located in our most active development areas. The following table provides information regarding changes in our PUD reserves for the year ended December 31, ~~2022~~2023. Our PUD reserves at December 31, ~~2022~~2023 include 8449 MMBoe of reserves associated with wells where drilling has occurred but the wells have not been completed or are completed but not producing ("“DUC wells"”). Our DUC wells are classified as PUD reserves when relatively major expenditures are required to complete and produce from the wells.

	Crude Oil(MBbls)			Natural Gas(MMcf)			Total(MBoe)
Proved undeveloped reserves at December 31, 2021		369,377			2,209,532			737,632
Revisions of previous estimates		(95,108	)		(570,693	)		(190,223	)
Extensions, discoveries and other additions		173,738			1,033,726			346,025
Sales of minerals in place		—			—			—
Purchases of minerals in place		42,165			129,872			63,810
Conversion to proved developed reserves		(54,932	)		(443,859	)		(128,908	)
Proved undeveloped reserves at December 31, 2022		435,240			2,358,578			828,336
Revisions of previous estimates		(147,483	)		(908,770	)		(298,945	)
Extensions, discoveries and other additions		230,136			979,737			393,426
Sales of minerals in place		(242	)		(673	)		(354	)
Purchases of minerals in place		52,043			192,274			84,088
Conversion to proved developed reserves		(57,511	)		(244,381	)		(98,241	)
Proved undeveloped reserves at December 31, 2023		512,183			2,376,765			908,310

Revisions of previous estimates. As previously discussed, in ~~2022~~2023 we removed 3514 MMBo and ~~225~~148 Bcf (totaling 7239 MMBoe) of PUD reserves no longer scheduled to be drilled within five years of initial booking due to continual refinement of our drilling and development programs and reallocation of capital to areas providing the best opportunities to improve efficiencies, recoveries, and rates of return. Additionally, changes in anticipated well densities, economics, performance, and other factors resulted in downward PUD reserve revisions of 7195 MMBo and ~~401~~446 Bcf (totaling ~~137~~170 MMBoe) in ~~2022~~2023. The ~~increases~~decreases in average crude oil and natural gas prices in ~~2022~~2023 resulted in ~~upward~~downward price revisions of 62 ~~MMBoe~~MMBo and 24135 Bcf (totaling 1025 MMBoe). Finally, changes in ownership interests, operating costs, anticipated production, and other factors resulted in ~~upward~~downward revisions for PUD reserves of 436 MMBo and 31180 Bcf (totaling 965 MMBoe) in ~~2022~~2023.

Extensions, discoveries and other additions. Extensions, discoveries and other additions were due to successful drilling activities and continual refinement of our drilling and development programs. ~~For 2022,~~ PUD reserve additions totaled 68230 MMBo and ~~227~~980 Bcf in(totaling ~~the~~393 ~~Bakken,~~MMBoe) ~~27 MMBo and 643 Bcf~~ in ~~the Anadarko Basin, 7 MMBo and 14 Bcf in the Powder River Basin, and 72 MMBo and 149 Bcf in the Permian Basin~~2023.

Sales of minerals in place. We had no individually significant dispositions of PUD reserves in ~~2022~~2023.

Purchases of minerals in place. Purchases in ~~2022~~2023 were ~~primarily~~ attributable to our acquisitions of properties ~~in the Permian Basin and Powder River Basin~~ as discussed in Part II. Item 8. Notes to Consolidated Financial Statements—Note 2. Property Acquisitions and Dispositions.

Conversion to proved developed reserves. In ~~2022~~2023, we developed approximately 2120% of our PUD locations and 1712% of our PUD reserves booked as of December 31, ~~2021~~2022 through the drilling and completion of ~~383~~454 gross (~~150~~213 net) development wells at an aggregate capital cost of approximately $~~892~~1.2 ~~million~~billion incurred in ~~2022~~2023.

Development plans. We have acquired substantial leasehold positions in our key operating areas. Our drilling programs to date in our historical operating areas have focused on proving our undeveloped leasehold acreage through strategic drilling, thereby increasing the amount of leasehold acreage in the secondary term of the lease with no further drilling obligations (i.e., categorized as held by production) and resulting in a reduced amount of leasehold acreage in the primary term of the lease. While we may opportunistically drill strategic exploratory wells, a substantial portion of our future capital expenditures will be focused on developing our PUD locations, including our drilled but not completed locations. Our inventory of DUC wells classified as PUDs total ~~317~~164 gross (~~118~~65 net) operated and non-operated locations at December 31, ~~2022~~2023 and represent 105% of our PUD reserves at that date. The costs to drill our uncompleted wells were incurred prior to December 31, ~~2022~~2023 and only the remaining completion costs are included in future development plans.

Estimated future development costs relating to the development of PUD reserves at December 31, ~~2022~~2023 are projected to be approximately $12.50 billion in ~~2023~~2024, $1.78 billion in ~~2024~~2025, $2.6 billion in ~~2025~~2026, $2.17 billion in ~~2026~~2027, and $12.73 billion in ~~2027~~2028. These capital expenditure projections have been established based on an expectation of drilling and completion costs, available cash flows, borrowing capacity, and the commodity price environment in effect at the time of preparing our reserve estimates and may be adjusted as market conditions evolve. Development of our existing PUD reserves at December 31, ~~2022~~2023 is expected to occur within five years of the date of initial booking of the PUDs. PUD reserves not expected to be drilled within five years of initial booking because of changes in business strategy or for other reasons have been removed from our reserves at December 31, ~~2022~~2023. We had no PUD reserves at December 31, ~~2022~~2023 that remain undrilled beyond five years from the date of initial booking.

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Qualifications of Technical Persons and Internal Controls Over Reserves Estimation Process

Ryder Scott, our independent reserves evaluation consulting firm, estimated, in accordance with generally accepted petroleum engineering and evaluation principles and definitions and guidelines established by the SEC, 9899% of our ~~PV-10 and 98% of our~~ total proved reserves as of December 31, ~~2022~~2023 included in this Form 10-K. The Ryder Scott technical personnel responsible for preparing the reserve estimates presented herein meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Refer to Exhibit 99 included with this Form 10-K for further discussion of the qualifications of Ryder Scott personnel.

We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with our independent reserves engineers to ensure the integrity, accuracy and timeliness of data furnished to Ryder Scott in their reserves estimation process. Our technical team is in contact regularly with representatives of Ryder Scott to review properties and discuss methods and assumptions used in Ryder Scott’s preparation of the year-end reserves estimates. Proved reserves information is reviewed by certain members of senior management before the information is filed with the SEC on Form 10-K. Additionally, certain members of our senior management review and approve the Ryder Scott reserves report and on a semi-annual basis review any internal proved reserves estimates.

Our Manager of Corporate Reserves is the technical person primarily responsible for overseeing the preparation of our reserve estimates. He has a Bachelor of Science degree in Petroleum Engineering, an MBA in Finance and 3839 years of industry experience with positions ~~of increasing responsibility~~ in operations, acquisitions, engineering and evaluations. He has worked in the area of reserves and reservoir engineering most of his career and is a member of the Society of Petroleum Engineers. The Manager of Corporate Reserves reports to our Chief Financial Officer and Executive Vice President of ~~Resource~~Strategic ~~and Business Development~~Planning. The reserves estimates are reviewed and approved by certain members of the Company's senior management.

Developed and Undeveloped Acreage

The following table presents our total gross and net developed and undeveloped acres by region as of December 31, ~~2022~~2023:

Developed acres

Undeveloped acres

Total

Gross

Net

Gross

Net

Gross

Net

Bakken

1,~~127~~115,~~004~~481

~~703~~711,~~277~~024

7874,~~098~~353

4342,~~582~~151

1,~~205~~189,~~102~~834

~~746~~753,~~859~~175

Anadarko Basin

~~604~~636,~~876~~070

~~350~~372,~~084~~087

~~236~~239,~~552~~550

~~123~~130,~~201~~334

~~841~~875,~~428~~620

~~473~~502,~~285~~421

Powder River Basin

~~242~~247,~~000~~057

~~179~~181,~~069~~250

~~288~~279,~~525~~382

~~198~~194,~~747~~793

~~530~~526,~~525~~439

~~377~~376,~~816~~043

Permian Basin

~~111~~118,~~880~~803

~~102~~105,~~366~~930

~~127~~108,~~710~~950

8587,~~382~~345

~~239~~227,~~590~~753

~~187~~193,~~748~~275

All other

~~243~~186,~~269~~906

~~189~~152,~~259~~037

~~216~~234,~~135~~150

~~154~~147,~~267~~973

~~459~~421,~~404~~056

~~343~~300,~~526~~010

Total

2,~~329~~304,~~029~~317

1,~~524~~522,~~055~~328

~~947~~936,~~020~~385

~~605~~602,~~179~~596

3,~~276~~240,~~049~~702

2,~~129~~124,~~234~~924

The following table sets forth the number of gross and net undeveloped acres as of December 31, ~~2022~~2023 scheduled to expire over the next three years by region unless production is established within the spacing units covering the acreage prior to the expiration dates or the leases are renewed.

2023

2024

2025

2024

2025

2026

Gross

Net

Gross

Net

Gross

Net

Bakken

1114,~~207~~980

79,~~639~~441

146,~~290~~050

94,~~363~~246

21,~~760~~484

~~1,498~~918

Anadarko Basin

3934,~~321~~856

1513,~~348~~976

3382,~~771~~207

1648,~~314~~836

6629,~~712~~377

4522,~~523~~004

Powder River Basin

38,~~938~~715

14,~~712~~050

72,~~593~~707

32,~~021~~378

210,~~701~~258

27,~~504~~392

Permian Basin

~~845~~41,758

~~639~~33,594

5624,~~798~~713

4718,~~839~~181

4111,~~781~~486

1211,~~523~~159

All other

5731,~~243~~803

5514,~~212~~260

3216,~~989~~843

1511,~~545~~392

1323,~~489~~285

1015,~~466~~844

Total

~~112~~132,~~554~~112

8075,~~550~~321

~~145~~132,~~441~~520

9285,~~082~~033

~~127~~75,~~443~~890

7257,~~514~~317

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Drilling Activity

During the three years ended December 31, ~~2022~~2023, we participated in the drilling and completion of exploratory and development wells as set forth in the table below.

	2022				2021				2020
	2023				2022				2021
	Gross		Net		Gross		Net		Gross		Net
Exploratory wells:
Crude oil		1733		1225.19		1117		812.01		111		—8.0
Natural gas		2—		—		2		~~1.9~~—		12		—1.9
Dry holes		1—		1—		—1		—1		1—		~~0.9~~—
Total exploratory wells		2033		1325.19		1320		913.91		313		09.9
Development wells:
Crude oil		~~407~~548		~~153~~259.60		~~376~~407		~~144~~153.6		~~300~~376		~~115~~144.56
Natural gas		6527		287.86		3865		2028.38		3138		1520.93
Dry holes		—		—		—		—		—		—
Total development wells		~~472~~575		~~182~~266.46		~~414~~472		~~164~~182.94		~~331~~414		~~131~~164.49
Total wells		~~492~~608		~~195~~292.5		~~427~~492		~~174~~195.85		~~334~~427		~~132~~174.38

As of December 31, ~~2022~~2023, there were ~~427~~203 gross (~~178~~113 net) operated and non-operated wells that have been spud and are in the process of drilling, completing or waiting on completion.

Summary of Crude Oil and Natural Gas Properties and Projects

Following is a discussion of ~~2022~~2023 activities in our key operating areas.

Bakken Field

~~The~~Our total Bakken ~~field~~production ofaveraged ~~North~~220,428 ~~Dakota~~Boe ~~and~~per ~~Montana~~day isfor ~~one of~~ the ~~largest~~fourth ~~crude~~quarter ~~oil~~of ~~resource~~2023, ~~plays~~up in26% from the ~~United~~2022 ~~States~~fourth quarter. WeFor ~~are~~ the ~~largest~~year ~~producer~~ended ~~and~~December ~~leasehold~~31, ~~owner~~2023, inour ~~the~~average daily Bakken. Asproduction ofincreased ~~December~~18% ~~31,~~compared to 2022. In 2023, we ~~held~~participated ~~approximately~~in ~~1.2~~the ~~million~~drilling and completion of 363 gross (~~746,900~~166 net) ~~acres~~wells ~~under lease~~ in the Bakken ~~field~~compared to 266 gross (93 net) wells in 2022.

Our ~~total~~ Bakken ~~production~~properties ~~averaged~~represented ~~174,397~~35% ~~Boe~~of ~~per~~our ~~day~~total ~~for~~proved ~~the~~reserves ~~fourth~~at ~~quarter~~December ~~of 2022~~31, ~~down~~2023 1and 49% ~~from~~of our average daily Boe production for the ~~2021~~2023 fourth quarter. ~~For~~Our ~~the~~total ~~year~~proved ~~ended~~Bakken field reserves as of December 31, ~~2022,~~2023 ~~our~~were ~~average~~647 ~~daily~~MMBoe, ~~Bakken~~a ~~production~~decrease ~~increased~~of 112% compared to ~~2021.~~December In31, 2022,. weOur ~~participated~~inventory ~~in the drilling and completion~~ of ~~266~~proved ~~gross~~undeveloped ~~(93~~drilling ~~net)~~locations ~~wells~~ in the Bakken ~~compared~~totaled to1,006 ~~252~~ gross (~~102~~539 net) wells inas ~~2021.~~of December 31, 2023.

Our Bakken properties represented 39% of our total proved reserves at December 31, 2022 and 42% of our average daily Boe production for the 2022 fourth quarter. Our total proved Bakken field reserves as of December 31, 2022 were 734 MMBoe, an increase of 4% compared to December 31, 2021. Our inventory of proved undeveloped drilling locations in the Bakken totaled 1,173 gross (596 net) wells as of December 31, 2022.

Anadarko Basin

WeOur ~~are~~properties ain ~~leading~~the ~~producer,~~Anadarko ~~leasehold~~Basin ~~owner~~represented 35% of our total proved reserves as of December 31, 2023 and ~~operator~~32% of our average daily Boe production for the fourth quarter of 2023. Production in the Anadarko Basin ofaveraged ~~Oklahoma~~144,158 ~~which~~Boe ~~includes~~per ~~the~~day ~~SCOOP~~during ~~and~~the ~~STACK~~fourth ~~areas~~quarter of ~~the~~2023, ~~play.~~down As13% ofcompared ~~December~~to ~~31,~~the 2022, wefourth ~~controlled~~quarter. ~~one~~We ofparticipated in the ~~largest~~drilling ~~leasehold~~and ~~positions~~completion of 120 gross (43 net) wells in the Anadarko Basin ~~with~~during ~~approximately~~2023 ~~841,400~~compared to 155 gross (~~473,300~~44 net) ~~acres~~wells ~~under~~in ~~lease~~2022.

Our ~~properties~~proved reserves in the Anadarko Basin ~~represented 37% of our total proved reserves~~ as of December 31, ~~2022~~2023 ~~and~~totaled ~~40%~~653 ~~of our average daily Boe production for the fourth quarter of 2022. Production in the Anadarko Basin averaged 165~~MMBoe,~~225~~ ~~Boe~~a ~~per~~decrease ~~day during the fourth quarter~~ of ~~2022, up 13~~6% compared to ~~the 2021 fourth quarter. For the year ended~~ December 31, 2022~~, average daily production in the Anadarko Basin increased 7% compared to 2021~~. WeOur ~~participated~~inventory ~~in the drilling and completion~~ of ~~155~~proved ~~gross~~undeveloped ~~(44~~drilling ~~net)~~locations ~~wells~~ in the Anadarko Basin ~~during~~totaled ~~2022~~272 ~~compared to 161~~ gross (63161 net) wells inas ~~2021.~~of December 31, 2023.

Our proved reserves in the Anadarko Basin as of December 31, 2022 totaled 697 MMBoe, an increase of 3% compared to December 31, 2021. Our inventory of proved undeveloped drilling locations in the Anadarko Basin totaled 312 gross (159 net) wells as of December 31, 2022.

Powder River Basin

InOur ~~2021,~~Powder weRiver ~~executed~~properties ~~strategic~~represented ~~acquisitions~~8% toof ~~expand~~our total proved reserves at December 31, 2023 and 6% of our ~~operations~~average ~~into~~daily Boe production for the 2023 fourth quarter. Our production in the Powder River Basin ofaveraged ~~Wyoming~~25,577 ~~and~~Boe ~~subsequently~~per ~~completed~~day ~~additional~~for ~~acquisitions~~the infourth ~~the~~quarter ~~play~~of in2023, ~~2022.~~a Asdecrease of ~~December~~9% ~~31,~~compared to the 2022 fourth quarter. During 2023, we ~~held~~participated ~~approximately~~in ~~530,500~~the drilling and completion of 53 gross (~~377,800~~17 net) ~~acres~~wells ~~under lease~~ in the play compared to 31 gross (23 net) wells in 2022.

7Our proved reserves in the Powder River Basin totaled 139 MMBoe as of December 31, 2023, an increase of 34% compared to December 31, 2022. Our inventory of proved undeveloped drilling locations in the play totaled 136 gross (103 net) wells as of December 31, 2023.

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Our Powder River properties represented 6% of our total proved reserves at December 31, 2022 and 7% of our average daily Boe production for the 2022 fourth quarter. Our production in the Powder River Basin averaged 28,057 Boe per day for the fourth quarter of 2022, an increase of 290% compared to the 2021 fourth quarter. For the year ended December 31, 2022, our average daily Powder River production increased 377% compared to 2021, reflecting new acquisitions and additional drilling and completion activities in 2022. During 2022, we participated in the drilling and completion of 31 gross (23 net) wells in the play compared to 10 gross (8 net) wells in 2021.

Our proved reserves in the Powder River Basin totaled 104 MMBoe as of December 31, 2022 compared to 32 MMBoe at December 31, 2021, and our inventory of proved undeveloped drilling locations in the play totaled 96 gross (57 net) wells at year-end 2022.

Permian Basin

OnOur ~~December~~Permian properties represented 21,% ~~2021,~~of weour ~~executed~~total aproved ~~strategic~~reserves ~~acquisition~~at toDecember ~~expand~~31, 2023 and 13% of our ~~operations~~average ~~into~~daily Boe production for the 2023 fourth quarter. Our production in the Permian Basin averaged 58,601 Boe per day for the fourth quarter of ~~Texas.~~2023, Asan increase of ~~December~~30% ~~31,~~compared to the 2022 fourth quarter. During 2023, we ~~held~~participated ~~approximately~~in ~~239,600~~the drilling and completion of 72 gross (~~187,700~~66 net) ~~acres~~wells ~~under lease~~ in the play compared to 39 gross (35 net) wells in 2022.

Our ~~Permian properties represented 16% of our total~~ proved reserves ~~at December 31, 2022 and 11% of our average daily Boe production for the 2022 fourth quarter. Our production~~ in the Permian Basin ~~averaged~~totaled ~~44,925~~386 ~~Boe~~MMBoe ~~per~~as ~~day for the fourth quarter~~ of ~~2022. For the year ended~~ December 31, ~~2022~~2023, ~~our~~an ~~average~~increase ~~daily~~of ~~Permian~~27% ~~production~~compared ~~totaled~~to 41December 31,~~917~~ ~~Boe~~2022. Our ~~per~~inventory ~~day.~~of ~~During~~proved ~~2022,~~undeveloped wedrilling ~~participated~~locations in the ~~drilling~~play ~~and~~totaled ~~completion~~459 ~~of 39~~ gross (35377 net) wells inat ~~the~~year-end ~~play~~2023.

Our proved reserves in the Permian Basin totaled 304 MMBoe as of December 31, 2022 compared to 203 MMBoe at December 31, 2021, and our inventory of proved undeveloped drilling locations in the play totaled 261 gross (237 net) wells at year-end 2022.

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Production and Price History

The following table sets forth information concerning our production results, average sales prices and production costs for the years ended December 31, ~~2022~~2023, ~~2021~~2022 and ~~2020~~2021 in total and for each field containing 15 percent or more of our total proved reserves as of December 31, ~~2022~~2023.

	Year ended December 31,
	2022		2021		2020
	2023		2022		2021
Net production volumes:
Crude oil (MBbls)
North Dakota Bakken		3948,~~917~~032		4039,~~121~~917		40,~~052~~121
SCOOP		1011,~~051~~652		1110,~~318~~051		1211,~~585~~318
Permian Basin		11,832		—		—
Permian Delaware		14,762		11,832		—
Total Company		7284,~~827~~710		5872,~~636~~827		58,~~745~~636
Natural gas (MMcf)
North Dakota Bakken		~~124~~146,~~411~~026		~~120~~124,~~517~~411		97120,~~532~~517
SCOOP		~~185~~179,~~755~~165		~~179~~185,~~553~~755		~~136~~179,~~410~~553
Permian Basin		20,804		—		—
Permian Delaware		27,980		20,804		—
Total Company		~~442~~455,~~980~~698		~~370~~442,~~110~~980		~~306~~370,~~528~~110
Crude oil equivalents (MBoe)
North Dakota Bakken		6072,~~652~~370		60,~~207~~652		5660,~~308~~207
SCOOP		41,~~010~~513		41,~~244~~010		3541,~~320~~244
Permian Basin		15,300		—		—
Permian Delaware		19,425		15,300		—
Total Company		~~146~~160,~~657~~660		~~120~~146,~~321~~657		~~109~~120,~~833~~321
Average net sales prices (1):
Average sales prices:
Crude oil ($/Bbl)
North Dakota Bakken	$	8976.9141	$	6394.2451	$	3367.5308
SCOOP		9476.2882		6694.4658		3766.8871
Permian Basin		92.73		—		—
Permian Delaware		76.21		95.14		69.54
Total Company		9176.4689		6494.0695		3467.7121
Natural gas ($/Mcf)
North Dakota Bakken	$	82.1854	$	48.5230	$	04.2356
SCOOP		62.8793		57.3300		15.6446
Permian Basin		6.95		—		—
Permian Delaware		2.53		7.27		7.33
Total Company		72.0160		47.8815		14.0498
Crude oil equivalents ($/Boe)
North Dakota Bakken	$	75.94	$	51.21	$	24.24
SCOOP		54.25		41.44		19.90
Permian Basin		81.13		—		—
Total Company		66.58		46.24		21.47
Average costs per Boe:
Production expenses ($/Boe)
North Dakota Bakken	$	5.0523	$	45.2705	$	4.3527
SCOOP		1.4450		1.2444		1.0624
Permian Basin		7.27		—		—
Permian Delaware		5.72		7.27		—
Total Company		4.2447		34.3824		3.2738
Production taxes ($/Boe)	$	4.98	$	3.36	$	1.75
Production and ad valorem taxes ($/Boe)	$	3.76	$	4.98	$	3.36
General and administrative expenses ($/Boe)	$	21.74	$	12.9474	$	1.7994
DD&A expense ($/Boe)	$	1214.8611	$	1512.7686	$	1715.1276

See Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Financial Measures for a discussion and calculation of net sales prices, which are non-GAAP measures. 6

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The following table sets forth information regarding our average daily production by region for the fourth quarter of ~~2022~~2023:

Fourth Quarter 2022 Daily Production

Fourth Quarter 2023 Daily Production

Crude Oil(Bbls per day)

Natural Gas(Mcf per day)

Total(Boe per day)

Bakken

~~114~~146,~~594~~841

~~358~~441,~~820~~521

~~174~~220,~~397~~428

Anadarko Basin

3133,~~403~~979

~~802~~661,~~930~~075

~~165~~144,~~225~~158

Powder River Basin

1715,~~740~~688

6159,~~898~~333

2825,~~057~~577

Permian Basin

3543,~~194~~647

5889,~~387~~727

4458,~~925~~601

All other

5,~~513~~635

~~234~~188

5,~~552~~666

Total

~~204~~245,~~444~~790

1,~~282~~251,~~269~~844

~~418~~454,~~156~~430

Productive Wells

Gross wells represent the number of wells in which we own a working interest and net wells represent the total of our fractional working interests owned in gross wells. The following table presents the total gross and net productive wells by region and by crude oil or natural gas completion as of December 31, ~~2022~~2023. One or more completions in the same well bore are counted as one well.

Crude Oil Wells

Natural Gas Wells

Total Wells

Gross

Net

Gross

Net

Gross

Net

Bakken

56,~~925~~127

2,~~098~~236

—

56,~~925~~127

2,~~098~~236

Anadarko Basin

1,~~287~~184

~~517~~525

~~1,003~~974

~~328~~321

2,~~290~~158

~~845~~846

Powder River Basin

~~553~~484

~~424~~379

126

~~565~~490

~~433~~384

Permian Basin

~~395~~473

~~356~~400

955

833

~~404~~528

~~364~~433

All other

~~270~~268

~~252~~254

2926

~~299~~294

~~257~~259

Total

8,~~430~~536

3,~~647~~794

1,~~053~~061

~~350~~364

9,~~483~~597

34,~~997~~158

Title to Properties

As is customary in the crude oil and natural gas industry, upon initiation of acquiring oil and gas leases covering fee mineral interests on undeveloped lands which do not have associated proved reserves, contract landmen conduct a title examination of courthouse records and production databases to determine fee mineral ownership and availability. Title, lease forms and terms are reviewed and approved by Company landmen prior to consummation.

For acquisitions from third parties, whether lands are producing crude oil and natural gas or non-producing, Company and contract landmen perform title examinations at applicable courthouses, obtain physical well site inspections, and examine the seller’s internal records (land, legal, operational, production, environmental, well, marketing and accounting) upon execution of a mutually acceptable purchase and sale agreement. Company landmen may also procure an acquisition title opinion from outside legal counsel on higher value properties.

Prior to the commencement of drilling operations, Company landmen procure an original title opinion, or supplement an existing title opinion, from outside legal counsel and perform curative work to satisfy requirements pertaining to material title issues, if any. Company landmen will not approve commencement of drilling operations until material title defects pertaining to the Company’s interest are cured.

The Company has cured material title opinion issues as to Company interests on substantially all of its producing properties and believes it holds at least defensible title to its producing properties in accordance with standards generally accepted in the crude oil and natural gas industry. The Company’s crude oil and natural gas properties are subject to customary royalty and leasehold burdens which do not materially interfere with the Company’s interest in the properties or affect the Company’s carrying value of such properties.

Marketing

We sell most of our operated crude oil production to crude oil refining companies or midstream marketing companies at major market centers. In the Bakken, Powder River, Permian, ~~SCOOP,~~ and ~~STACK~~Anadarko ~~areas~~basins we have significant volumes of production directly connected to pipeline gathering systems, with the remaining production primarily transported by truck to a point on a pipeline system for further delivery. We do not transport any of our oil production prior to sale by rail, but several purchasers of our Bakken production are connected to rail delivery systems and may choose those methods to transport the oil they have purchased from us. We sell some operated crude oil production at the lease. Our share of crude oil production from non-operated properties is marketed at the discretion of the operators.

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We sell most of our operated natural gas and natural gas liquids production to midstream customers at our lease locations based on market prices in the field where the sales occur, with the remaining production sold at centrally gathered locations or natural gas processing plants. These contracts include multi-year term agreements, many with acreage dedications. Under certain arrangements, we have the right to take a volume of processed residue gas and/or natural gas liquids ("NGLs") in-kind at the tailgate of the midstream customer's processing plant in lieu of a monetary settlement for the sale of our operated natural gas production. When we do take volumes in kind, we pay third parties to transport the volumes taken in kind to downstream delivery points, where we then sell to customers at prices applicable to those downstream markets. Sales at the downstream markets are mostly under daily and monthly packaged volumes deals, shorter term seasonal packages, and long term multi-year contracts. We continue to develop relationships and have the potential to enter into additional contracts with end-use customers, including utilities, industrial users, and liquefied natural gas exporters, for sale of products we elect to take in-kind in lieu of monetary settlement for our leasehold sales. Our share of natural gas and NGL production from non-operated properties is generally marketed at the discretion of the operators.

Competition

We operate in a highly competitive environment for acquiring properties, marketing crude oil and natural gas, and securing trained personnel. Also, there is substantial competition for capital available for investment in the crude oil and natural gas industry. Our competitors vary within the regions in which we operate, and some of our competitors may possess and employ financial, technical and personnel resources greater than ours. Those companies may be able to pay more for crude oil and natural gas properties, minerals, and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions economically in a highly competitive environment. In addition, supply chain disruptions in recent years have led to shortages of certain materials and equipment and increased costs. As a result, the likelihood of experiencing competition and shortages of materials and services may be further increased. Finally, the emerging impact of climate change activism, fuel conservation measures, governmental requirements for renewable energy resources, increasing demand for alternative forms of energy, and technological advances in energy generation devices may result in reduced demand for the crude oil and natural gas we produce.

Regulation of the Crude Oil and Natural Gas Industry

All of our operations are conducted onshore in the United States. The crude oil and natural gas industry in the United States is subject to various types of regulation at the federal, state and local levels. Laws, rules, regulations, policies, and interpretations affecting our industry have been and are pervasive with the frequent imposition of new or increased requirements. These laws, regulations and other requirements often carry substantial penalties for failure to comply and may have a significant effect on our operations and may increase the cost of doing business and reduce our profitability. In addition, because public policy changes affecting the crude oil and natural gas industry are commonplace and because laws, rules and regulations may be enacted, amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws, rules and regulations. We do not expect future legislative or regulatory initiatives will affect us materially different than they will affect our similarly situated competitors.

The following isare asignificant ~~discussion~~areas of ~~certain~~regulation ~~significant laws, rules and regulations, as amended from time to time,~~ that may affect us in the areas in which we operate.

~~Regulation~~Environmental, ofhealth, ~~sales~~ and ~~transportation~~safety ~~of crude oil and natural gas liquids~~regulation

~~Our~~We ~~physical sales of crude oil and any derivative instruments relating to crude oil~~ are subject to ~~anti-market~~stringent, ~~manipulation~~complex, ~~laws~~ and ~~related~~overlapping ~~regulations~~federal, ~~enforced~~state, ~~by the Federal Trade Commission (“FTC”)~~ and ~~the~~local ~~Commodity Futures Trading Commission (“CFTC”). These~~ laws, ~~among~~rules ~~other~~and ~~things,~~regulations ~~prohibit~~governing ~~fraudulent~~environmental orcompliance, ~~deceptive~~and ~~conduct~~occupational insafety ~~connection~~and ~~with~~health, ~~wholesale~~as ~~purchases~~well oras ~~sales~~the discharge of ~~crude~~materials ~~oil~~into, and ~~price~~the ~~manipulation~~protection inof, the ~~commodity~~environment and ~~futures~~natural ~~markets~~resources. IfEnvironmental, wehealth, ~~violate~~and ~~the~~safety ~~anti-market manipulation~~ laws ~~and regulations~~, werules ~~can be subject to substantial penalties~~ and ~~related~~regulations ~~third-party~~may ~~damage~~relate ~~claims by~~to, among ~~others,~~other ~~sellers, royalty owners and taxing authorities.~~things:

•

We transport most of our operated crude oil production to market centers using a combination of trucks and pipeline transportation facilities owned and operated by third parties. The U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration establishes safety regulations relating to transportation of crude oil by pipeline. Further, our sales of crude oil are affected by the ~~availability,~~discharge ~~terms~~or ~~and~~other ~~costs~~release of ~~transportation.~~pollutants ~~The~~into ~~transportation~~federal ~~of crude oil~~ and natural gas liquids (“NGLs”) is subject to rate and access regulation. The Federal Energy Regulatory Commission (“FERC”) regulates interstate crude oil and NGL pipeline transportation rates under the Interstate Commerce Act and the Energy Policy Act of 1992, and intrastate crude oil and NGL pipeline transportation rates may be subject to regulation by state ~~regulatory~~waters ~~commissions. As the interstate~~ and ~~intrastate transportation rates we pay are generally applicable to all comparable shippers,~~ the ~~regulation~~ambient ~~of such transportation rates will not affect us in a way that materially differs from the effect on our similarly situated competitors.~~air;

•

11assessing the environmental impact of seismic acquisition, drilling and construction activities;

•

the generation, storage, transportation and disposal of waste materials, including hazardous substances;

•

the emission of certain gases, including methane, into the atmosphere;

•

the acquisition of various permits to conduct exploration, drilling and production operations;

•

the restriction of types, quantities and concentrations of various substances that can be released into the environment in connection with drilling, production and transportation activities;

•

the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands and other protected areas including areas containing endangered species of plants and animals;

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•

~~Further,~~the ~~interstate~~requirement ~~pipelines~~of ~~and~~remedial ~~intrastate~~measures ~~common carrier pipelines must provide service on an equitable basis and offer service~~ to ~~all~~mitigate ~~similarly~~pollution ~~situated~~from ~~shippers~~former ~~requesting service on the same terms~~ and ~~under~~ongoing ~~the~~operations, ~~same rates. When~~ such ~~pipelines~~as ~~operate~~requirements ~~at full capacity we are subject~~ to ~~proration~~close ~~provisions,~~pits ~~which~~and ~~are~~plug ~~described~~abandoned ~~in the pipelines’ published tariffs. We generally will have access to crude oil pipeline transportation services to the same extent as our similarly situated competitors.~~wells;

•

~~From time to time we may sell our operated crude oil production at market centers in~~ the ~~United~~imposition ~~States to third parties who then subsequently export and sell the crude oil in international markets. The International Maritime Organization (“IMO”), an agency~~ of ~~the~~substantial ~~United~~liabilities ~~Nations,~~for ~~has~~pollution ~~issued~~resulting regulations requiring the maritime shipping industry to gradually reduce its carbon emissions over time by mandating a 1% improvement in the efficiency of fleets each year between 2015 and 2025. In conjunction with this initiative, the IMO issued regulations requiring ship owners to lower the concentration of the sulfur content used in their fuels from ~~3.5%~~drilling ~~to 0.5% beginning on January 1, 2020. To achieve~~ and maintain compliance with the new regulations, it is expected ship owners will either have to switch to more expensive higher quality marine fuel, install and utilize emissions-cleaning systems, or switch to alternative fuels such as liquefied natural gas. Failure to comply with the regulations may result in fines or shipping vessels being detained, thereby resulting in exportation capacity constraints that inhibit a third party's ability to transport and sell domestic crude oil production ~~overseas, which may have a material impact on the markets and prices for various grades of domestic and international crude oil. The ultimate long-term impact of the IMO regulations is uncertain.~~ operations;

•

~~We do not own or operate pipeline or rail transportation facilities, rail cars, or infrastructure used to facilitate~~ the ~~exportation~~development of ~~crude~~emergency ~~oil.~~response ~~However, regulations that impact the domestic transportation of crude oil could increase our costs of doing business~~ and ~~limit~~spill ~~our~~contingency ~~ability~~plans; ~~to transport~~ and ~~sell our crude oil at market centers throughout the United States. We do not expect such regulations will affect us in a materially different way than similarly situated competitors.~~

•

~~Regulation~~worker ~~of sales and transportation of natural gas~~protection.

WeThese ~~are~~laws, ~~also~~rules ~~required~~and toregulations ~~observe~~may restrict the ~~aforementioned~~level ~~anti-market~~of ~~manipulation~~substances ~~laws~~generated ~~and~~by ~~related~~our ~~regulations~~operations ~~enforced~~that bymay be emitted into the ~~FERC~~air, discharged to surface water, and ~~CFTC~~disposed inor ~~connection~~otherwise ~~with~~released ~~physical~~to ~~sales~~surface ofand ~~natural~~below-ground ~~gas~~soils and ~~any~~groundwater, ~~derivative~~and ~~instruments~~may ~~relating~~also torestrict the rate of our crude oil and natural gas production to a rate that is economically infeasible for continued production. ~~Additionally,~~The regulatory burden on the ~~FERC~~crude ~~regulates~~oil ~~interstate~~and natural gas ~~transportation~~industry ~~rates~~increases the cost of doing business and ~~service~~affects ~~conditions~~profitability. ~~under~~Any ~~the~~regulatory ~~Natural~~changes ~~Gas~~that ~~Act~~impose ~~and~~further ~~the~~requirements ~~Natural~~on ~~Gas~~domestic ~~Policy~~producers ~~Act~~for ofemissions ~~1978~~control, ~~which~~waste ~~affects~~handling, ~~the~~disposal, ~~marketing~~cleanup and remediation could have a significant impact on our operating costs and production of ~~natural~~oil and gas. weFor ~~produce~~example, asthe ~~well~~U.S. asEnvironmental ~~revenues~~Protection weAgency ~~receive~~finalized federal regulations in December 2023 regarding methane emissions for ~~sales~~new ofand ~~our~~existing ~~natural~~oil and gas sources. ~~The~~These ~~FERC~~rules ~~has~~require ~~endeavored~~more tostringent ~~increase~~emissions ~~competition~~controls for new sources and ~~make~~for ~~natural~~the first time impose similar requirements on existing sources, and fines and penalties for violations of the rules can be substantial. Separately, the Inflation Reduction Act of 2022 (“IRA”) established a methane emissions charge, effective January 1, 2024, on specific types of oil and gas ~~transportation~~production ~~more~~facilities ~~accessible~~that report emissions in excess of applicable thresholds. Failure to ~~natural~~comply ~~gas~~with ~~buyers~~these and ~~sellers~~other onlaws, anrules ~~open~~and regulations may result in the assessment of administrative, civil and ~~non-discriminatory~~criminal ~~basis~~penalties, the imposition of corrective or remedial obligations or the incurrence of capital expenditures, the occurrence of restrictions, delays or cancellations in the permitting, development or expansion of projects, the issuance of orders enjoining performance of some or all of our operations, and ~~has~~potential ~~issued~~litigation in a ~~series~~particular area. Additionally, certain of ~~orders~~these environmental laws may result in imposition of joint and several or strict liability, which could cause us to ~~implement~~become ~~its~~liable ~~open~~for ~~access~~the ~~policies~~conduct of others or for consequences of our own actions. WeFor ~~cannot~~instance, ~~provide~~an ~~any~~accidental ~~assurance~~release ~~the~~from ~~pro-competitive~~one ~~regulatory~~of ~~approach~~our ~~established~~wells could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by ~~the~~neighboring ~~FERC~~landowners ~~will~~or ~~continue~~other third parties for personal injury and property damage and fines or penalties for related violations of environmental laws or regulations. ~~However~~Certain environmental laws also provide for certain citizen suits, wewhich doallow ~~not~~persons ~~believe~~or ~~any~~organizations ~~action~~to ~~taken~~act byin place of the ~~FERC~~government and sue operators for alleged violations of environmental laws. We have incurred and will ~~affect~~continue usto inincur aoperating ~~materially~~and ~~different~~capital ~~way~~expenditures, ~~than~~some ~~similarly~~of ~~situated~~which ~~natural~~may ~~gas~~be ~~producers~~material, to comply with environmental, health, and safety laws, rules, and regulations.

~~The~~Other ~~gathering~~regulation of ~~natural gas, which occurs upstream of jurisdictional transmission services, is generally regulated by~~ the ~~states.~~oil Although its policies on gathering systems have varied in the past, the FERC has reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the potential to increase costs for our purchasers and ~~reduce the revenues we receive for our natural~~ gas stream. State regulation of natural gas gathering facilities generally includes various safety, environmental, and in some circumstances, equitable take requirements. We do not believe such regulations will affect us in a materially different way than our similarly situated competitors.industry

~~Intrastate~~The ~~natural~~Company’s ~~gas~~oil ~~transportation~~and ~~service~~gas isoperations ~~also~~are subject to ~~regulation~~various byfederal, state ~~regulatory agencies. Like the regulation of interstate transportation rates~~, the regulation of intrastate transportation rates affects the marketing of natural gas we produce, as well as the revenues we receive for sales of our natural gas. The basis for intrastate regulation of natural gas transportation and ~~the~~local ~~degree~~laws ~~of regulatory oversight~~ and ~~scrutiny~~regulations ~~given~~that torelate ~~intrastate natural gas pipeline rates and services varies from state~~ to ~~state.~~matters ~~Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers on a comparable basis~~including, ~~the~~among ~~regulation~~other ~~of intrastate natural gas transportation in states in which we operate will not affect us in a way that materially differs from our similarly situated competitors.~~things:

•

The U.S. Department of Energy (“U.S. DOE”) regulates the terms and conditions for the exportation and importation of natural gas (including liquefied natural gas or “LNG”). U.S. law provides for very limited regulation of exports to and imports from any country that has entered into a Free Trade Agreement (“FTA”) with the United States providing for national treatment of trade in natural gas; howeverlocation, ~~the~~drilling ~~U.S. DOE’s regulation of imports~~ and ~~exports~~casing ~~from and to countries without an FTA is more comprehensive. The FERC also regulates the construction and operation~~ of import and export facilities, including LNG terminals. Regulation of imports and exports and related facilities may materially affect natural gas markets and sales prices and could inhibit the development of LNG infrastructure.wells;

•

~~Regulation~~hydraulic ~~of production~~fracturing;

•

~~The~~well production ~~of crude oil and natural gas is regulated by a wide range of federal, state, and local laws, rules, and regulations, which require, among other matters, permits for drilling~~ operations~~, drilling bonds, and reports concerning operations. Each of the states~~ ;

•

12disposal of produced water;

•

regulation of transportation and sale of crude oil, natural gas, and natural gas liquids;

•

surface usage;

•

calculation and disbursement of royalty payments and production taxes; and

•

restoration of properties used for oil and gas operations.

Our operations also are subject to conservation regulations, including the regulation of the size of drilling and spacing units or proration units; the number of wells that may be drilled in a unit; the rate of production allowable from crude oil and natural gas wells; and the unitization or pooling of oil and gas properties. Some states allow the forced pooling or unitization of tracts to facilitate exploration and development, while other states rely on voluntary pooling of lands and leases. Such rules often impact the ultimate timing of our exploration and development plans. In addition, federal and state conservation laws generally limit the venting or flaring of natural gas. These regulations limit the amounts of oil and gas we can produce from our wells and the number of wells or the locations at which we can drill.

Certain of our leases are granted or approved by the federal government and administered by the Bureau of Land Management or Bureau of Indian Affairs of the Department of the Interior. Such leases require compliance with detailed federal regulations and orders that regulate, among other matters, drilling and operations on lands covered by these leases and calculation and disbursement of

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~~where~~royalty wepayments ~~own~~to ~~and~~the ~~operate~~federal ~~properties have laws and regulations governing conservation~~government, ~~including~~tribes ~~provisions for the unitization~~ or ~~pooling~~tribal ofmembers. ~~crude oil and natural gas properties~~Moreover, the ~~establishment~~permitting ofprocess ~~maximum~~for ~~allowable rates of production from crude~~ oil and ~~natural~~ gas ~~wells,~~activities ~~the~~on ~~regulation~~federal ~~of well spacing, the plugging~~ and ~~abandonment~~Indian oflands ~~wells,~~can ~~the~~sometimes ~~regulation~~be ofsubject ~~greenhouse~~to ~~gas emissions~~delay, ~~and~~including ~~limitations~~as ora ~~prohibitions~~result ~~on the venting or flaring~~ of ~~natural~~challenges ~~gas.~~to ~~These~~permits ~~laws~~or ~~and~~other ~~regulations~~regulatory ~~directly~~decisions ~~and~~brought ~~indirectly~~by ~~limit~~non-governmental ~~the~~organizations ~~amount~~or ofother ~~crude~~parties, ~~oil~~which ~~and natural gas we~~ can ~~produce~~hinder ~~from~~development ~~our~~activities ~~wells~~or ~~and~~otherwise ~~the~~adversely ~~number~~impact ofoperations. ~~wells~~The ~~and~~federal ~~locations~~government ~~we can drill~~has, ~~although~~from wetime ~~can and do apply for exceptions~~ to ~~such~~time, ~~laws~~evaluated and, ~~regulations or to have reductions~~ in ~~well~~some ~~spacing. Moreover~~cases, ~~each~~promulgated ~~state~~new ~~generally~~rules ~~imposes~~and aregulations ~~production,~~regarding ~~severance~~competitive orlease ~~excise~~bidding, ~~tax~~venting ~~on the production~~ and ~~sale~~flaring, ~~of crude~~ oil, ~~natural~~and gas measurement and ~~natural~~royalty ~~gas~~payment ~~liquids~~obligations ~~within~~for ~~its~~production ~~jurisdiction~~from federal lands.

~~The~~For ~~failure~~additional toinformation ~~comply~~on ~~with~~ the ~~above~~Company’s ~~laws,~~regulatory ~~rules~~risks, ~~and~~see ~~regulations~~Part ~~can~~1, ~~result~~Item ~~in substantial penalties~~1A. ~~Our~~Risk ~~similarly~~Factors—Legal ~~situated competitors are generally subject to the same laws, rules,~~ and ~~regulations~~Regulatory asRisks weof ~~are~~this report.

Environmental regulation

General. We are subject to stringent, complex, and overlapping federal, state, and local laws, rules and regulations governing environmental compliance, including the discharge of materials into the environment. These laws, rules and regulations may, among other things:

require the acquisition of various permits to conduct exploration, drilling and production operations;

restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling, production and transportation activities;

limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas including areas containing endangered species of plants and animals;

require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells; and

impose substantial liabilities for pollution resulting from drilling and production operations.

These laws, rules and regulations may restrict the level of substances generated by our operations that may be emitted into the air, discharged to surface water, and disposed or otherwise released to surface and below-ground soils and groundwater, and may also restrict the rate of crude oil and natural gas production to a rate that is economically infeasible for continued production. The regulatory burden on the crude oil and natural gas industry increases the cost of doing business and affects profitability. Additionally, in the name of combatting climate change, President Biden has issued, and may continue to issue, executive orders that result in more stringent and costly requirements for the domestic crude oil and natural gas industry, or which restrict, delay or ban oil and gas permitting or leasing on federal lands. Any regulatory or executive changes that impose further requirements on domestic producers for emissions control, waste handling, disposal, cleanup and remediation could have a significant impact on our operating costs and production of oil and gas. Failure to comply with these and other laws, rules and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of corrective or remedial obligations or the incurrence of capital expenditures, the occurrence of restrictions, delays or cancellations in the permitting, development or expansion of projects, the issuance of orders enjoining performance of some or all of our operations, and potential litigation in a particular area. Additionally, certain of these environmental laws may result in imposition of joint and several or strict liability, which could cause us to become liable for the conduct of others or for consequences of our own actions. For instance, an accidental release from one of our wells could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners or other third parties for personal injury and property damage and fines or penalties for related violations of environmental laws or regulations. Certain environmental laws also provide for certain citizen suits, which allow persons or organizations to act in place of the government and sue operators for alleged violations of environmental laws. We have incurred and will continue to incur operating and capital expenditures, some of which may be material, to comply with environmental laws and regulations. The following is a description of some of the environmental laws, rules and regulations, as amended from time to time, that apply to our operations.

Air emissions. Federal, state, and local laws, rules, and regulations have been and, in the future, will likely be enacted to address concerns about emissions of regulated air pollutants. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit standards or utilize specific equipment or technologies to control emissions of certain pollutants. For example, in October 2021, the U.S. Environmental Protection Agency (“EPA”) announced its intention to initiate a rule-making to reassess and lower, by the end of 2023, the current National Ambient Air Quality Standard (“NAAQS”) for ground-level ozone, which was last set by the EPA under the Obama Administration in 2015. State implementation of a revised NAAQS for ground-level ozone could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits, or result in increased expenditures for pollution control equipment, the costs of which could be significant.

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Regulation of greenhouse gas emissions. The threat of climate change continues to attract considerable attention in the United States and in foreign countries and, as a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit existing emissions of greenhouse gases as well as to reduce, restrict, or eliminate such future emissions. As a result, our operations as well as the operations of the oil and gas industry in general are subject to a series of regulatory, political, litigation and financial risks associated with the production of fossil fuels and emission of greenhouse gases.

Federal regulatory initiatives have focused on establishing construction and operating permit reviews for greenhouse gas emissions from certain large stationary sources, requiring the monitoring and annual reporting of greenhouse gas emissions from certain petroleum and natural gas system sources, and reducing methane emissions from oil and gas production and natural gas processing and transmission operations through limitations on venting and flaring and the implementation of enhanced emission leak detection and repair requirements. In recent years, there has been considerable uncertainty surrounding regulation of methane emissions. Following attempts from the Trump Administration to revise standards related to the emission of methane from the oil and gas sectors, the Biden Administration has taken several steps to impose more stringent controls on methane emissions. For example, in November 2021 the EPA issued a proposed rule that, if finalized, would establish new source (“Quad Ob”) and first-time existing source (“Quad Oc”) standards of performance for methane and volatile organic compound (“VOC”) emissions in the crude oil and natural gas source category. This proposed rule would apply to upstream and midstream facilities at oil and natural gas well sites, natural gas gathering and boosting compressor stations, natural gas processing plants, and transmission and storage facilities. Owners or operators of affected emission units or processes would have to comply with specific standards of performance that may include leak detection using optical gas imaging and subsequent repair requirements, reduction of emissions by 95% through capture and control systems, zero-emission requirements, operation and maintenance requirements, and so-called green well completion requirements. The EPA issued a supplemental proposal to this proposed rulemaking in November 2022 that, among other items, sets forth specific revisions strengthening the first nationwide emission guidelines for states to limit methane emissions from existing crude oil and natural gas facilities. The proposal also revises requirements for fugitive emissions monitoring and repair as well as equipment leaks and the frequency of monitoring surveys, establishes a “super-emitter” response program to timely mitigate emissions events as detected by governmental agencies or qualified third parties. Additionally, in August 2022, the Inflation Reduction Act of 2022 (“IRA 2022”) was signed into law. This law, among other provisions, amends the federal Clean Air Act to establish the first ever federal fee on methane emissions from sources required to report their greenhouse gas emissions to the EPA, including certain oil and gas operations. The methane emissions charge will start in calendar year 2024 at $900 per ton of methane, increase to $1,200 in 2025, and be set at $1,500 for 2026 and subsequent years. Calculation of the methane fee is based on certain thresholds established in the IRA 2022. The IRA 2022 additionally appropriates significant federal funding for renewable energy initiatives. The methane emissions fee could increase our operating costs, and the funding and incentives established for renewable energy sources could accelerate the transition away from fossil fuels, which could in turn reduce demand for our products and adversely affect our business and results of operations.

Additionally, various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas as greenhouse gas cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions. At the international level, there exists the United Nations-sponsored “Paris Agreement,” which is a non-binding agreement among participating nations to limit their greenhouse gas emissions through individually-determined reduction goals every five years after 2020. As part of the U.S.’s obligations under the Paris Agreement, the Biden Administration has announced a goal of reducing economy-wide net GHG emissions 50%-52% by 2030. Moreover, in November 2021 at the 26th Conference of the Parties (“COP26”), multiple announcements (not having the effect of law) were made, including a call for parties to eliminate certain measures perceived to subsidize fossil fuel production and consumption, and to pursue further action on non-CO2 GHGs. Relatedly, the United States and European Union jointly announced at COP26 the launch of a Global Methane Pledge, an initiative which over 100 counties joined, committing to a collective goal of reducing global methane emissions by at least 30 percent from 2020 levels by 2030, including “all feasible reductions” in the energy sector. The impacts of these orders, pledges, agreements and any legislation or regulation promulgated to fulfill the United States' commitments under the Paris Agreement, COP26, or other international conventions cannot be predicted at this time.

Governmental, scientific and public concern over the threat of climate change arising from greenhouse gas emissions has given rise to increasing federal political risk for the domestic crude oil and natural gas industry. In the United States, President Biden has issued several executive orders calling for more expansive action to address climate change and suspend new oil and gas operations on federal lands and waters. The suspension of the federal leasing activities prompted legal action by several states against the Biden Administration, resulting in issuance of a nationwide permanent injunction by a federal district judge in Louisiana in August 2022, effectively halting implementation of the leasing suspension. Litigation risks are also increasing, as a number of states, municipalities and other parties have sought to bring suit against the largest oil and natural gas exploration and production companies in state or federal court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to global warming effects, such as rising sea levels, and therefore are responsible for roadway and infrastructure damages, or that the companies have been aware of the adverse effects of climate change for some time but failed to adequately disclose those impacts.

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Moreover, our access to capital may be impacted by climate change policies. Stockholders and bondholders currently invested in energy companies but concerned about the potential effects of climate change may elect to shift some or all of their investments into non-energy related sectors. Institutional investors who provide financing to energy companies have also focused on sustainability lending practices that favor alternative power sources perceived to be more clean (despite their negative impacts on the environment), such as wind and solar. Some of these investors may elect not to provide traditional funding for energy companies. Many of the largest U.S. banks have made “net zero” carbon emission commitments and have announced that they will be assessing financed emissions across their portfolios and taking steps to quantify and reduce those emissions. These and other developments in the financial sector could lead to some lenders restricting or eliminating access to capital for or divesting from certain industries or companies, including the oil and natural gas sector, or requiring that borrowers take additional steps to reduce their GHG emissions. Additionally, there is the possibility that financial institutions will be required to adopt policies that limit funding to the fossil fuel sector. In late 2020, the Federal Reserve announced that it had joined the Network for Greening the Financial System (“NGFS”), a consortium of financial regulators focused on addressing climate-related risks in the financial sector. In November 2021, the Federal Reserve issued a statement in support of the efforts of the NGFS to identify key issues and potential solutions for the climate-related challenges most relevant to central banks and supervisory authorities. Subsequently, in September 2022, the Federal Reserve announced that six of the largest banks in the U.S. will participate in a pilot climate scenario analysis exercise, expected to be launched in early 2023, to enhance the ability of firms and supervisors to measure and mange climate-related financial risk. While we cannot predict what policies may result from this, a material reduction in the capital available to the fossil fuel industry could make it more difficult to secure funding for exploration, development, production, transportation, and processing activities, which could reduce demand for our products.

Environmental protection and natural gas flaring. One of our environmental initiatives is the reduction of air emissions produced from our operations, including the flaring of natural gas from our operated well sites in the Bakken field of North Dakota. North Dakota law permits flaring of natural gas from a well that has not been connected to a gas gathering line for a period of one year from the date of a well’s first production. After one year, a producer is required to cap the well, connect it to a gas gathering line, find acceptable alternative uses for a percentage of the flared gas, or apply to the North Dakota Industrial Commission (“NDIC”) for a written exemption for any future flaring; otherwise, the producer is required to pay royalties and production taxes based on the volume and value of the gas flared from the unconnected well.

In addition, NDIC rules for new drilling permit applications also require the submission of gas capture plans setting forth plans taken by operators to capture and not flare produced gas, regardless of whether it has been or will be connected within the first year of production. The NDIC currently requires us to capture 91% of the natural gas produced from a field. We capture in excess of the NDIC requirement. If an operator is unable to attain the applicable gas capture percentage goal at maximum efficient rate, wells will be restricted in production to 200 barrels of crude oil per day if at least 60% of the monthly volume of associated natural gas produced from the well is captured, or otherwise crude oil production from such wells is not permitted to exceed 100 barrels of crude oil per day. However, the NDIC will consider temporary exemptions from the foregoing restrictions or for other types of extenuating circumstances after notice and hearing if the effect is a significant net increase in gas capture within one year of the date such relief is granted. Monetary penalty provisions also apply under this regulation if an operator fails to timely file for a hearing with the NDIC upon being unable to meet such percentage goals or if the operator fails to timely implement production restrictions once below the applicable percentage goals. Ongoing compliance with the NDIC’s flaring requirements or the imposition of any additional limitations on flaring could result in increased costs and have an adverse effect on our operations.

We seek to reduce or eliminate natural gas flaring, but our efforts may not always be successful or cost-effective. Our levels of flaring are impacted by external factors such as investment from third parties in the development and continued operation of gas gathering and processing facilities and the granting of reasonable right-of-way access by land owners. Increased emissions from our facilities due to flaring could subject our facilities to more stringent air emission permitting requirements, resulting in increased compliance costs and potential construction delays.

Hydraulic fracturing. Hydraulic fracturing involves the injection of water, sand or other proppant and additives under pressure into rock formations to stimulate crude oil and natural gas production. In recent years there has been public concern regarding an alleged potential for hydraulic fracturing to adversely affect drinking water supplies or to induce seismic events. As a result, several federal and state agencies have studied the environmental risks with respect to hydraulic fracturing, and proposals have been made to enact separate federal, state and local legislation that would potentially increase the regulatory burden imposed on hydraulic fracturing.

At the federal level, the EPA has asserted federal regulatory authority pursuant to the federal Safe Drinking Water Act (“SDWA”) over certain hydraulic fracturing activities involving the use of diesel fuels and published permitting guidance related to such activities. Also, the EPA has issued a final regulation under the Clean Water Act prohibiting discharges to publicly owned treatment works of wastewater from onshore unconventional oil and gas extraction facilities. We do not discharge wastewater to publicly owned treatment works, so the impact of this regulation on us is not currently, and is not expected to be, material.

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In late 2016 the EPA published a final study of the potential impacts of hydraulic fracturing activities on water resources in which the EPA indicated it found evidence that such activities can impact drinking water resources under some circumstances. In its final report, the EPA indicated it was not able to calculate or estimate the national frequency of impacts on drinking water resources from hydraulic fracturing activities or fully characterize the severity of impacts. Nonetheless, the results of the EPA’s study or similar governmental reviews could spur initiatives to regulate hydraulic fracturing under the SDWA or otherwise.

In 2016, the BLM under the Obama Administration published final rules related to the regulation of hydraulic fracturing activities on federal lands, including requirements for chemical disclosure, well bore integrity, and handling of flowback water. However, the BLM under the Trump Administration published a final rule rescinding the 2016 final rule in November 2018. Litigation challenging the BLM’s 2016 final rule as well as its 2018 final rule rescinding the 2016 rule has been pursued by various states and industry and environmental groups. While a California federal court vacated the 2018 final rule in July 2020, a Wyoming federal court subsequently vacated the 2016 final rule in October 2020 and, accordingly, the 2016 final rule is no longer in effect. However, appeals to those decisions are ongoing. Additionally, in 2022 the BLM proposed rules that would limit flaring from well sites on federal lands, as well as allow for the delay or denial of permits if the BLM finds that an operator's methane waste minimization plan is insufficient. This rule is currently receiving public comments and, if finalized, may also be subject to legal challenge. Notwithstanding these recent legal developments, further administrative and regulatory restrictions may be adopted by the Biden Administration that could restrict hydraulic fracturing activities on federal lands and waters.

In addition, regulators in states in which we operate have adopted additional requirements related to seismicity and its potential association with hydraulic fracturing. For example, the Oklahoma Corporation Commission (the “OCC”) has promulgated guidance for operators of crude oil and natural gas wells in certain seismically-active areas of the SCOOP and STACK plays in Oklahoma. The OCC’s guidance provides for seismic monitoring and for implementation of mitigation procedures, which may include curtailment or even suspension of operations in the event of concurrent seismic events within a particular radius of operations of a magnitude exceeding 2.5 on the Richter scale. If seismic events exceeding the OCC guidance thresholds were to occur near our active stimulation operations on a frequent basis, they could have an adverse effect on our operations.

Waste water disposal. Underground injection wells are a predominant method for disposing of waste water from oil and gas activities. In response to seismic events near underground injection wells used for the disposal of oil and gas-related waste waters, federal and some state agencies have investigated whether such wells have caused increased seismic activity. To address concerns regarding seismicity, some states, including states in which we operate, have pursued remedies that included delaying permit approvals, mandating a reduction in injection volumes, or shutting down or imposing moratoria on the use of injection wells. Moreover, regulators in states in which we operate have implemented additional requirements related to seismicity. For example, the OCC has adopted rules for operators of saltwater disposal wells in certain seismically-active areas in the Arbuckle formation of Oklahoma. These rules require, among other things, that disposal well operators conduct mechanical integrity testing or make certain demonstrations of such wells’ respective depths that, depending on the depth, could require plugging the well and/or the reduction of volumes disposed in such wells. Oklahoma utilizes a “traffic light” system wherein the OCC reviews new or existing disposal wells for proximity to faults, seismicity in the area and other factors in determining whether such wells should be permitted, permitted only with special restrictions, or not permitted. At the federal level, the EPA’s current regulatory requirements for such wells do not require the consideration of seismic impacts when issuing permits. We cannot predict the EPA’s future actions in this regard.

The introduction of new environmental laws and regulations related to the disposal of wastes associated with the exploration, development or production of hydrocarbons could limit or prohibit our ability to utilize underground injection wells. A lack of waste water disposal sites could cause us to delay, curtail or discontinue our exploration and development plans. Additionally, increased costs associated with the transportation and disposal of produced water, including the cost of complying with regulations concerning produced water disposal, may reduce our profitability. These costs are commonly incurred by oil and gas producers and we do not expect the costs associated with the disposal of produced water will have a material adverse effect on our operations to any greater degree than other similarly situated competitors. In recent years, we have increased our operation and use of water recycling and distribution facilities that economically reuse stimulation water for both operational efficiencies and environmental benefits.

We have incurred in the past, and expect to incur in the future, capital and other expenditures related to environmental compliance. Such expenditures are included within our overall capital and operating budgets and are not separately itemized. Historically, our environmental compliance costs have not had a material adverse impact on our financial condition and results of operations; however, there can be no assurance that such costs will not be material in the future or that such future compliance will not have a material impact on our business, financial condition, results of operations or cash flows.

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Employee Health and Safety. We are also subject to the requirements of the federal Occupational Safety and Health Act and comparable state laws that regulate the protection of the health and safety of workers. In addition, the U.S. Occupational Safety and Health Administration hazard communication standard, the EPA community right-to-know regulation under Title III of the federal superfund Amendment and Reauthorization Act and similar state laws and regulations require information be maintained about hazardous materials used or produced in operations and this information be provided to employees, state and local governmental authorities and citizens.

Human Capital

Employees and Labor Relations

As of December 31, ~~2022~~2023, we employed 1,~~404~~457 people, all of which were employed in the United States, with ~~790~~818 employees being located at our corporate headquarters in Oklahoma City, Oklahoma and ~~614~~639 employees located in our field offices located in Oklahoma, North Dakota, South Dakota, Montana, Wyoming, and Texas. None of our employees are subject to collective bargaining agreements. We believe our overall relations with our workforce are good.

Compensation

Because we operate in a highly competitive environment, we have designed our compensation program to attract, retain and motivate experienced, talented individuals. Our program is also designed to align employee’s interests with those of our owners and to reward them for achieving the business and strategic objectives determined to be important to help the Company create and maintain advantage in a competitive environment. We align our employee’s interests with those of our owners by making annual long-term incentive awards to virtually all of our salaried employees. We reward our employees for their performance in helping the Company achieve its annual business and strategic objectives through our bonus program, which is also available to virtually all of our employees. In order to ensure our compensation package remains competitive and fulfills our goal of recruiting and retaining talented employees, we consider competitive market compensation paid by other companies comparable to the Company in size, geographic location, and operations.

Safety

Safety is our highest priority and one of our core values. We promote safety with a robust health and safety program that includes employee orientation and training, contractor management, risk assessments, hazard identification and mitigation, audits, incident reporting and investigation, and corrective/preventative action development.

Through our “Brother’s Keeper” program, we encourage each of our employees to be a proactive participant in ensuring the safety of all of the Company’s personnel. We developed this program to leverage and continuously improve our ability to identify and prevent reoccurrence of unsafe behaviors and conditions. This program recognizes and rewards Company employees and contractors who observe and report outstanding safety and environmental behavior such as utilizing stop work authority, looking out for a co-worker, reporting incidents and near misses, or following proper safety procedures. This program positively impacts safety culture and performance and has contributed to a substantial increase in our reporting rates and to decreases in recordable incident and lost time incident rates.

Training and Development

We are committed to the training and development of our employees. We believe that supporting our employees in achieving their career and development goals is a key element of our approach to attracting and retaining top talent. We have invested in a variety of resources to support employees in achieving their career and development goals, including developing learning paths for individual contributors and leaders, operating the Continental Leadership Learning Center which offers numerous instructor-led programs designed to foster employee development and maintaining a learning management system which provides access to numerous technical and soft skills online courses. We also invest time and resources in supporting the creation of individual development plans for our employees.

Health and Wellness

We offer various benefit programs designed to promote the health and well-being of our employees and their families. These benefits include medical, dental, and vision insurance plans; disability and life insurance plans; paid time off ~~for holidays~~, ~~vacation, sick leave,~~ and other personal leave; and healthcare flexible spending accounts, among other things. In addition to these programs, we have a number of other programs designed to further promote the health and wellness of our employees. For instance, employees at our corporate headquarters have access to our fitness center. Additionally, we have an employee assistance program that offers counseling and referral services for a broad range of personal and family situations. We also offer a wellness plan that includes annual biometric screenings, flu shots, smoking cessation programs, and healthy snack options in our break rooms to encourage total body wellness.

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access to our fitness center. Additionally, we have an employee assistance program that offers counseling and referral services for a broad range of personal and family situations. We also offer a wellness plan that includes annual biometric screenings, flu shots, smoking cessation programs, and healthy snack options in our break rooms to encourage total body wellness.

Diversity and Inclusion

We are committed to providing a diverse and inclusive workplace and career development opportunities to attract and retain talented employees. We prohibit discrimination and harassment of any type and afford equal employment opportunities to employees and applicants without regard to race, color, religion, sex, sexual orientation, gender identity, national origin, political affiliation, age, disability, genetic information, veteran status, or any other basis protected by local, state, or federal law. We also maintain a robust compliance program rooted in our Code of Business Conduct, which provides policies and guidance on non-discrimination, anti-harassment, and equal employment opportunities.

We believe embracing diversity and inclusion is more than a matter of compliance. We recognize and appreciate the importance of creating an environment in which all employees feel valued, included, and empowered to do their best work and bring great ideas to the table. We believe a diverse and inclusive workforce provides the best opportunity to obtain unique perspectives, experiences, ideas, and solutions to help sustain our business success; a diverse and inclusive culture is the high-performance fuel that enhances our ability to innovate, execute and grow. To that end, we have implemented a long-term initiative for enhancing awareness of, and continuously improving our approach to, building and sustaining a diverse and inclusive culture. We have chartered a Diversity and Inclusion Committee comprised of employees across all company functions. We have engaged external training resources for our entire workforce, including interview training for hiring managers focused on ensuring a fair and systematic approach for recruiting and selecting individuals from diverse backgrounds for competitive job openings. We are intentional about proactively conducting outreach and recruitment at job fairs and other events hosted by diverse organizations. Through our Diversity and Inclusion Committee we provide new opportunities for our leadership and all employees to hold targeted discussions on issues related to diversity and inclusion, such as unconscious bias, disability inclusion, and equality through inclusive interaction. We are committed to continuous improvement in this critical area, evaluating more ways to sustain and strengthen our diverse and inclusive workforce.

Company Contact Information

Our corporate internet website is www.clr.com. Through the "“Stakeholders"” section of our website, we make available free of charge reports filed with or furnished to the SEC. Information contained on our website is not incorporated by reference into this report and you should not consider information contained on our website as part of this report.

We electronically file periodic reports with the SEC as required by our senior note indentures. The SEC maintains an internet website that contains reports and other information registrants file with the SEC. The address of the SEC’s website is www.sec.gov.

Our principal executive offices are located at 20 N. Broadway, Oklahoma City, Oklahoma 73102, and our telephone number at that address is (405) 234-9000.

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Item 1A. Risk Factors

You should carefully consider each of the risks described below, together with all other information contained in this report in connection with an investment in our debt securities. If any of the following risks develop into actual events, our business, financial condition, results of operations, or cash flows could be materially adversely affected.

Business and Operating Risks

Substantial declines in commodity prices or extended periods of low commodity prices adversely affect our business, financial condition, results of operations and cash flows and our ability to meet our capital expenditure needs and financial commitments.

The prices we receive for sales of our crude oil and natural gas production impact our revenue, profitability, cash flows, access to capital, capital budget, rate of growth, and carrying value of our properties. Crude oil and natural gas are commodities and prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for crude oil and natural gas have been volatile and unpredictable and commodity prices will likely remain volatile in the future.

The prices we receive for sales of our production depend on numerous factors beyond our control. These factors include, but are not limited to, the following:

•

worldwide, domestic, and regional economic conditions impacting the supply of, and demand for, crude oil, natural gas, and natural gas liquids;

•

the actions of the Organization of Petroleum Exporting Countries (“OPEC”) and other petroleum producing nations;

•

the nature, extent, and impact of domestic and foreign governmental laws, regulations, and taxation, including environmental laws and regulations governing the imposition of trade restrictions and tariffs;

•

executive, regulatory or legislative actions by Congress, the Biden Administration, or states in which we operate;

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geopolitical events and conditions, including domestic political uncertainty or foreign regime changes that impact government energy policies;

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the level of global, national, and regional crude oil and natural gas exploration and production activities;

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the level of global, national, and regional crude oil and natural gas inventories, which may be impacted by economic sanctions applied to certain producing nations;

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the level and effect of speculative trading in commodity futures markets;

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the relative strength of the United States dollar compared to foreign currencies;

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the price and quantity of imports of foreign crude oil;

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the price and quantity of exports of crude oil or liquefied natural gas from the United States;

•

military and political conditions in, or affecting other, crude oil-producing and natural gas-producing nations, including the continuation of, or any increase in the severity of, the conflict ~~between~~in ~~Russia~~Ukraine, Israel and ~~Ukraine~~Palestine and the Middle East;

•

localized supply and demand fundamentals;

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the cost and availability, proximity and capacity of transportation, processing, storage and refining facilities for various quantities and grades of crude oil, natural gas, and natural gas liquids;

•

adverse climatic conditions, natural disasters, and national and global health epidemics and concerns~~, including the COVID-19 pandemic~~;

•

technological advances affecting energy production and consumption;

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the effect of worldwide energy conservation and greenhouse gas emission limitations or other environmental protection efforts;

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the impact arising from increasing attention to environmental, social, and governance (“ESG”) matters; and

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the price and availability of alternative fuels or other energy sources.

Sustained material declines in commodity prices reduce cash flows available for capital expenditures, repayment of indebtedness and other corporate purposes; may limit our ability to borrow money or raise additional capital; and may reduce our proved reserves and the amount of crude oil and natural gas we can economically produce.

In addition to reducing our revenue, cash flows and earnings, depressed prices for crude oil and/or natural gas may adversely affect us in a variety of other ways. If commodity prices decrease substantially, some of our exploration and development projects could become uneconomic, and we may also have to make significant downward adjustments to our estimated proved reserves and our

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estimates of the present value of those reserves. If these price effects occur, or if our estimates of production or economic factors change, accounting rules may require us to write down the carrying value of our crude oil and/or natural gas properties.

Lower commodity prices may also lead to reductions in our drilling and completion programs, which may result in insufficient production to satisfy our transportation and processing commitments. If production is not sufficient to meet our commitments we would incur deficiency fees that would need to be paid absent any cash inflows generated from the sale of production.

Lower commodity prices may also reduce our access to capital and lead to a downgrade or other negative rating action with respect to our credit rating. A downgrade of our credit rating could negatively impact our cost of capital, increase borrowing costs under our revolving credit facility and term loan, and limit our ability to access debt capital markets and execute aspects of our business plans. As a result, substantial declines in commodity prices or extended periods of low commodity prices may materially and adversely affect our future business, financial condition, results of operations, cash flows, liquidity and ability to meet our capital expenditure needs and commitments.

The ability or willingness of Saudi Arabia and other members of OPEC, and other oil exporting nations, including Russia, to set and maintain production levels has a significant impact on crude oil prices.

OPEC is an intergovernmental organization that seeks to manage the price and supply of crude oil on the global energy market. Actions taken by OPEC members, including those taken alongside other oil exporting nations such as Russia, may have a significant impact on global oil supply and pricing. There can be no assurance that OPEC members and other oil exporting nations will comply with agreed-upon production targets, agree to further production targets in the future, or utilize other actions to support and stabilize oil prices, nor can there be any assurance they will not increase production or deploy other actions aimed at reducing oil prices. Uncertainty regarding future actions to be taken by OPEC members or other oil exporting countries could lead to increased volatility in the price of oil, which could have a material adverse effect on our business, financial condition, results of operations, and cash flows.

Drilling for and producing crude oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations. We may not be insured for, or our insurance may be inadequate to protect us against, these risks.

Our future financial condition and results of operations depend on the success of our exploration, development and production activities. Our crude oil and natural gas exploration and production activities are subject to numerous risks, including the risk that drilling will not result in commercially viable crude oil or natural gas production. Our decisions to purchase, explore, or develop prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data, and engineering studies, the results of which are often inconclusive or subject to varying interpretations. Our cost of drilling, completing and operating wells may be uncertain before drilling commences.

~~In this report, we describe our current prospects and key operating areas.~~ Our management has specifically identified prospects and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. Our ability to drill and develop these locations is subject to a number of risks and uncertainties as described herein. If future drilling results do not establish sufficient reserves to achieve an economic return, we may curtail our drilling and completion activities. Prospects we decide to drill that do not produce crude oil or natural gas in expected quantities may adversely affect our results of operations, financial condition, and rates of return on capital employed. The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether crude oil or natural gas will be present in expected or economically producible quantities. We cannot assure you the wells we drill will be as productive as anticipated or whether the analogies we draw from other wells, more fully explored prospects, or producing fields will be applicable to our drilling prospects. Because of these uncertainties, we do not know if our potential drilling locations will ever be drilled or if we will be able to produce crude oil or natural gas from these or any other potential drilling locations in sufficient quantities to achieve an economic return.

Risks we face while drilling include, but are not limited to, failing to place our well bore in the desired target producing zone; not staying in the desired drilling zone while drilling horizontally through the formation; failing to run our casing the entire length of the well bore; and not being able to run tools and other equipment consistently through the horizontal well bore. Risks we face while completing our wells include, but are not limited to, not being able to fracture stimulate the planned number of stages; failing to run tools the entire length of the well bore during completion operations; not successfully cleaning out the well bore after completion of the final fracture stimulation stage; increased seismicity in areas near our completion activities; unintended interference of completion activities performed by us or by third parties with nearby operated or non-operated wells being drilled, completed, or producing; and failure of our optimized completion techniques to yield expected levels of production.

Further, many factors may occur that cause us to curtail, delay or cancel scheduled drilling and completion projects, including but not limited to:

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abnormal pressure or irregularities in geological formations;

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shortages of or delays in obtaining equipment or qualified personnel;

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shortages of or delays in obtaining components used in fracture stimulation processes such as water and proppants;

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delays associated with suspending our operations to accommodate nearby drilling or completion operations being conducted by other operators;

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mechanical difficulties, fires, explosions, equipment failures or accidents, including ruptures of pipelines or storage facilities, or train derailments;

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restrictions on the use of underground injection wells for disposing of waste water from oil and gas activities;

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political events, public protests, civil disturbances, terrorist acts or ~~cyber~~cybersecurity attacks;

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decreases in, or extended periods of low, crude oil and natural gas prices;

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title problems;

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environmental hazards, such as uncontrollable flows of crude oil, natural gas, brine, well fluids, hydraulic fracturing fluids, toxic gas or other pollutants into the environment, including groundwater and shoreline contamination;

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adverse climatic conditions and natural disasters;

•

spillage or mishandling of crude oil, natural gas, brine, well fluids, hydraulic fracturing fluids, toxic gas or other pollutants by us or by third party service providers;

•

limitations in infrastructure, including transportation, processing, refining and exportation capacity, or markets for crude oil and natural gas; and

•

delays imposed by or resulting from compliance with regulatory requirements including permitting.

Any of the above risks could adversely affect our ability to conduct operations or result in substantial losses to us as a result of:

•

injury or loss of life;

•

damage to or destruction of property, natural resources and equipment;

•

pollution and other environmental damage;

•

regulatory investigations and penalties;

•

suspension of our operations;

•

repair and remediation costs; and

•

litigation.

We are not insured against all risks associated with our business. We may elect to not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented or for other reasons. In addition, pollution and environmental risks are generally not fully insurable.

Losses and liabilities arising from any of the above events could hinder our ability to conduct normal operations and could adversely affect our business, financial condition, results of operations and cash flows.

Reserve estimates depend on many assumptions that may turn out to be inaccurate. ~~The present value of future net revenues from our proved reserves will not necessarily be the same as the current market value of our estimated crude oil and natural gas reserves.~~ Any material inaccuracies in our reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves. The Company's current estimates of reserves could change, potentially in material amounts, in the future due to changes in commodity prices, business strategies, and other factors. Additionally, unless we replace our crude oil and natural gas reserves, our total reserves and production will decline, which could adversely affect our cash flows and results of operations.

The process of estimating crude oil and natural gas reserves is complex and inherently imprecise. It requires interpretation of available technical data and many assumptions, including assumptions relating to current and future economic conditions, production rates, drilling and operating expenses, and commodity prices. Any significant inaccuracy in these interpretations or assumptions could materially affect our estimated quantities and value of our reserves. See Part I, Item 1. Business—Crude Oil and Natural Gas Operations—Proved Reserves for information about our estimated crude oil and natural gas reserves as of December 31, 2023.

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materially affect our estimated quantities and present value of our reserves. See Part I, Item 1. Business—Crude Oil and Natural Gas Operations—Proved Reserves for information about our estimated crude oil and natural gas reserves, standardized measure of discounted future net cash flows, and PV-10 as of December 31, 2022.

In order to prepare reserve estimates, we must project production rates and the amount and timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data in preparing reserve estimates. The extent, quality and reliability of this data can vary which in turn can affect our ability to model the porosity, permeability and pressure relationships in unconventional resources. The process also requires economic assumptions, based on historical data projected into the future, about crude oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes, and availability of funds.

Actual future production, crude oil and natural gas sales prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable crude oil and natural gas reserves will vary and could vary significantly from our estimates. Any significant variance could materially affect the estimated quantities and ~~present~~ value of our reserves, which in turn could have an adverse effect on the value of our assets. In addition, we may remove or adjust estimates of proved reserves, potentially in material amounts, to reflect production history, results of exploration and development activities, changes in business strategies, prevailing crude oil and natural gas prices and other factors, some of which are beyond our control.

~~You~~In ~~should~~addition, the development of our proved undeveloped reserves may take longer than anticipated and may not ~~assume~~be ~~the~~ultimately ~~present~~developed ~~value~~or ofproduced. ~~future~~At ~~net~~December ~~revenues~~31, ~~from~~2023, approximately 49% of our total estimated proved reserves is(by ~~the~~volume) ~~current~~were ~~market~~undeveloped. ~~value~~Recovery of ~~our~~undeveloped ~~estimated~~reserves ~~crude~~requires ~~oil~~significant capital expenditures and ~~natural~~successful ~~gas~~drilling ~~reserves~~operations. WeOur ~~base~~reserve ~~the~~estimates ~~estimated~~assume ~~discounted~~we ~~future~~can ~~net~~and ~~revenues~~will ~~from~~make ~~proved~~these ~~reserves~~expenditures onand ~~the~~conduct ~~12-month~~these ~~unweighted~~operations ~~arithmetic~~successfully. ~~average~~These ofassumptions ~~the~~may ~~first-day-~~not prove to be accurate. Our reserve report at December 31, 2023 includes estimates of~~-the-month~~ ~~commodity~~total ~~prices~~future ~~for~~development costs over the ~~preceding~~next ~~twelve~~five ~~months.~~years ~~Actual~~associated ~~future~~with ~~prices~~our ~~may~~proved undeveloped reserves of approximately $11.4 billion. We cannot be ~~materially~~certain ~~higher~~the orestimated ~~lower~~costs ~~than~~of the ~~average~~development ~~prices~~of ~~used~~these inreserves ~~the~~are ~~calculations.~~accurate, Indevelopment ~~addition~~will occur as scheduled, or the ~~use~~results of asuch ~~10%~~development ~~discount~~will ~~factor,~~be ~~which~~as isestimated. ~~required~~If bywe choose not to spend the ~~SEC~~capital to bedevelop ~~used~~these reserves, or if we are not otherwise able to ~~calculate~~successfully ~~discounted~~develop ~~future~~these ~~net~~reserves ~~revenues~~as ~~for~~a ~~reporting~~result ~~purposes~~of our inability to fund necessary capital expenditures or otherwise, we may ~~not~~be required to remove the associated volumes from our reported proved reserves. Proved undeveloped reserves generally must be drilled within five years from the ~~most~~date ~~appropriate~~of ~~discount~~initial ~~factor~~booking ~~based~~under onSEC ~~interest~~reserve ~~rates~~rules. Changes in ~~effect~~the ~~from~~timing ~~time~~of development plans that impact our ability to develop such reserves in the required time frame have resulted, and ~~risks~~may ~~associated~~in ~~with~~the ~~our~~future result, in fluctuations in reserves orbetween ~~the~~periods ~~crude~~as ~~oil~~reserves ~~and~~booked ~~natural~~in ~~gas~~one ~~industry~~period may need to be removed in a subsequent period.

~~In addition~~Additionally, ~~the~~unless ~~development~~production ofis ~~our~~established ~~proved~~within ~~undeveloped~~the ~~reserves~~spacing ~~may~~units ~~take~~covering longer than anticipated and may not be ultimately developed or produced. At December 31, 2022, approximately 44% of our total estimated proved reserves (by volume) were undeveloped. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling operations. Our reserve estimates assume we can and will make these expenditures and conduct these operations successfully. These assumptions may not prove to be accurate. Our reserve report at December 31, 2022 includes estimates of total future development costs over the ~~next five years associated with our proved~~ undeveloped ~~reserves~~acres ofon ~~approximately~~which ~~$9.6~~some ~~billion. We cannot be certain the estimated costs~~ of the ~~development~~locations ~~of these reserves~~ are ~~accurate~~identified, ~~development will occur as scheduled, or~~ the ~~results~~leases offor such ~~development~~acreage will ~~be as estimated~~expire. If we ~~choose not to spend the capital to develop these reserves, or if we~~ are not ~~otherwise~~ able to ~~successfully~~renew ~~develop~~leases ~~these~~before ~~reserves~~they ~~as a result of our inability to fund necessary capital expenditures or otherwise~~expire, weany ~~may be required to remove the associated volumes from our reported~~ proved ~~reserves. Proved~~ undeveloped reserves ~~generally~~associated ~~must~~with besuch ~~drilled~~leases ~~within~~will ~~five~~be ~~years~~removed from ~~the date of initial booking under SEC reserve rules. Changes in the timing of development plans that impact~~ our ~~ability~~proved ~~to develop such~~ reserves. inThe ~~the~~combined ~~required~~net ~~time~~acreage ~~frame~~expiring ~~have resulted, and may~~ in the ~~future~~next ~~result,~~three in fluctuations in reserves between periods as reserves booked in one period may need to be removed in a subsequent period. In 2022, 72 MMBoe of proved undeveloped reserves were removed from our year-end reserve estimates associated with locations no longer scheduled to be drilled within five years ~~from~~represents ~~the~~36% ~~date~~ of ~~initial booking due to the continual refinement of~~ our ~~drilling~~total ~~and~~net ~~development~~undeveloped ~~programs~~acreage ~~and~~at ~~reallocation~~December ~~of capital to areas providing the best opportunities to improve efficiencies~~31, ~~recoveries, and rates of return~~2023.

Additionally, unless production is established within the spacing units covering the undeveloped acres on which some of the locations are identified, the leases for such acreage will expire. If we are not able to renew leases before they expire, any proved undeveloped reserves associated with such leases will be removed from our proved reserves. The combined net acreage expiring in the next three years represents 41% of our total net undeveloped acreage at December 31, 2022. At that date, we had leases representing 80,550 net acres expiring in 2023, 92,082 net acres expiring in 2024, and 72,514 net acres expiring in 2025.

Furthermore, unless we conduct successful exploration, development and exploitation activities or acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Producing crude oil and natural gas reservoirs are generally characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future crude oil and natural gas reserves and production, and therefore our cash flows and results of operations, are highly dependent on our success in efficiently developing our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire sufficient additional reserves to replace our current and future production. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations could be materially adversely affected.

Our business depends on crude oil and natural gas transportation, processing, refining, and export facilities, most of which are owned by third parties.

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The value we receive for our crude oil and natural gas production depends in part on the availability, proximity and capacity of gathering, pipeline and rail systems and processing, refining, and export facilities owned by third parties. The inadequacy or unavailability of capacity on these systems and facilities could result in the shut-in of producing wells, the delay or discontinuance of development plans for properties, or higher operational costs associated with air quality compliance controls. Although we have some contractual control over the transportation of our products, changes in these business relationships or failure to obtain such services on acceptable terms could adversely affect our operations. If our production becomes shut-in for any of these or other reasons, we will be unable to realize revenue from those wells until other arrangements are made for the sale or delivery of our products and acreage lease terminations could result if production is shut-in for a prolonged period.

The disruption of transportation, processing, refining, or export facilities due to contractual disputes or litigation, labor disputes, maintenance, civil disturbances, international trade disputes, public protests, terrorist attacks, ~~cyber~~cybersecurity attacks, adverse climatic events, natural disasters, seismic events, health epidemics and concerns, changes in tax and energy policies, federal, state and international regulatory developments, changes in supply and demand, equipment failures or accidents, including pipeline and gathering system ruptures or train derailments, and general economic conditions could negatively impact our ability to achieve the most favorable prices for our crude oil and natural gas production. We have no control over when or if access to such facilities would be restored or the impact on prices in the areas we operate. A significant shut-in of production in connection with any of the aforementioned items could materially affect our cash flows, and if a substantial portion of the impacted production fulfills transportation or processing commitments or is hedged at lower than market prices, those commitments or financial hedges would have to be paid from borrowings in the absence of sufficient operating cash flows.

Our operated crude oil and natural gas production is ultimately transported to downstream market centers in the United States primarily using transportation facilities and equipment owned and operated by third parties. See Part I, Item 1. Business—Regulation of the Crude Oil and Natural Gas Industry for a discussion of regulations impacting the transportation of crude oil and natural gas. From time to time we may sell our operated crude oil production at market centers in the United States to third parties who then subsequently export and sell the crude oil in international markets. We do not currently own or operate infrastructure used to facilitate the transportation and exportation of crude oil; however, third party compliance with regulations that impact the transportation or exportation of our production may increase our costs of doing business and inhibit a third party's ability to transport and sell our production, whether domestically or internationally, the consequences of which could have a material adverse effect on our business, financial condition, results of operations and cash flows.15

InTable ~~response to a July 2020 U.S. District Court decision vacating the U.S. Army Corps~~ of ~~Engineers~~Contents (“Corps”) grant of an easement to the Dakota Access Pipeline (“DAPL”) and issuance of an order requiring the Corps to conduct an Environmental Impact Statement (“EIS”) for the pipeline, the Corps is currently conducting the court-ordered environmental review to determine whether DAPL poses a threat to the drinking water supply of the Standing Rock Sioux Reservation. DAPL currently remains in operation and, while the owners of DAPL appealed the District Court decision to the U.S. Supreme Court in September 2021, the Corps continues to conduct the review, which is estimated to be completed in the spring of 2023, following a pause on its work in 2022. Once the review is completed, the Corps will determine whether DAPL is safe to operate or must be shut down. There has not been any decision on whether the U.S. Supreme Court will hear the appeal and we are unable to determine the outcome or the impact on DAPL in the future.

aforementioned items could materially affect our cash flows, and if a substantial portion of the impacted production fulfills transportation or processing commitments or is hedged at lower than market prices, those commitments or financial hedges would have to be paid from borrowings in the absence of sufficient operating cash flows.

Our operated crude oil and natural gas production is ultimately transported to downstream market centers in the United States primarily using transportation facilities and equipment owned and operated by third parties. From time to time we may sell our operated crude oil production at market centers in the United States to third parties who then subsequently export and sell the crude oil in international markets. We do not currently own or operate infrastructure used to facilitate the transportation and exportation of crude oil; however, third party compliance with regulations that impact the transportation or exportation of our production may increase our costs of doing business and inhibit a third party's ability to transport and sell our production, whether domestically or internationally, the consequences of which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

In response to a July 2020 U.S. District Court decision vacating the U.S. Army Corps of Engineers (“Corps”) grant of an easement to the Dakota Access Pipeline (“DAPL”) and issuance of an order requiring the Corps to conduct an Environmental Impact Statement (“EIS”) for the pipeline, the Corps is currently conducting the court-ordered environmental review to determine the potential effects of the pipeline, including whether DAPL poses a threat to the drinking water supply of the Standing Rock Sioux Reservation. The Corps published a draft EIS on September 8, 2023 and anticipates issuing a final EIS in 2024. Once the review is completed, the Corps will determine whether DAPL is safe to operate or must be shut down. DAPL currently remains in operation, but we are unable to determine the outcome or the impact of these actions on DAPL in the future.

We utilize DAPL to transport a portion of our Bakken crude oil production to ultimate markets on the U.S. gulf coast. Our transportation commitment on the pipeline totals 30,000 barrels per day which will continue through February 2026 at which time the commitment decreases to 26,450 barrels per day through July 2028.

If transportation capacity on DAPL becomes restricted or unavailable, we have the ability to utilize other third party pipelines or rail facilities to transport our Bakken crude oil production to market, although such alternatives may be more costly. A restriction of DAPL's takeaway capacity may have an impact on prices for Bakken-produced barrels and result in wider differentials relative to WTI benchmark prices in the future, the amount of which is uncertain.

Our exploration, development and exploitation projects require substantial capital expenditures. We may be unable to obtain needed capital or financing on acceptable terms, which could lead to a decline in our crude oil and natural gas reserves, production and revenues.

The crude oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business for the exploration, development, exploitation, production and acquisition of crude oil and natural gas reserves. We monitor and adjust our capital spending plans upward or downward depending on market conditions. Our ~~2023~~2024 capital budget, based on our current expectations of commodity prices and costs, is expected to be funded from operating cash flows. However, the sufficiency of our cash flows from operations is subject to a number of variables, including but not limited to:

•

the prices at which crude oil and natural gas are sold;

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the volume of our proved reserves;

•

the volume of crude oil and natural gas we are able to produce and sell from existing wells; and

•

our ability to acquire, locate and produce new reserves;

If oil and gas industry conditions weaken as a result of low commodity prices or other factors, we may not be able to generate sufficient cash flows and may have limited ability to obtain the capital necessary to sustain our operations at current or planned levels. A decline in cash flows from operations may require us to revise our capital program or seek financing in banking or debt capital markets to fund our operations.

We have a revolving credit facility with lender commitments totaling $2.255 billion that matures in October 2026. In the future, we may not be able to access adequate funding under our revolving credit facility if our lenders are unwilling or unable to meet their funding obligations or increase their commitments under the credit facility. Our lenders could decline to increase their commitments based on our financial condition, the financial condition of our industry or the economy as a whole or for other reasons beyond our control. Due to these and other factors, we cannot be certain that funding, if needed, will be available to the extent required or on terms we find acceptable. If operating cash flows are insufficient and we are unable to access funding or execute debt capital transactions when needed on acceptable terms, we may not be able to fully implement our business plans, fund our capital program and commitments, complete new property acquisitions to replace reserves, take advantage of business opportunities, respond to competitive pressures, or refinance debt obligations as they come due. Should any of the above risks occur, they could have a material adverse effect on our business, financial condition, results of operations and cash flows.

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competitive pressures, or refinance debt obligations as they come due. Should any of the above risks occur, they could have a material adverse effect on our business, financial condition, results of operations and cash flows.

The unavailability or high cost of drilling rigs, well completion crews, water, equipment, supplies, personnel and field services could adversely affect our ability to execute our exploration and development plans within budget and on a timely basis.

In the regions in which we operate, there have been shortages of drilling rigs, well completion crews, equipment, personnel, field services, and supplies, including key components used in fracture stimulation processes such as water and proppants, as well as high costs associated with these critical components of our operations. With current technology, water is an essential component of drilling and hydraulic fracturing processes. The availability of water sources and disposal facilities is becoming increasingly competitive, constrained, subject to social and regulatory scrutiny, and impacted by third-party supply chains over which we may have limited control. Limitations or restrictions on our ability to secure, transport, and use sufficient amounts of water, including limitations resulting from natural causes such as drought, could adversely impact our operations. In some cases, water may need to be obtained from new sources and transported to drilling or completion sites, resulting in increased costs.

The demand for qualified and experienced field service providers and associated equipment, supplies, and materials can fluctuate significantly, often in correlation with commodity prices or supply chain disruptions, causing periodic shortages and/or higher costs. ~~For~~Any ~~instance, recent supply chain disruptions stemming from the COVID-19 pandemic have led to shortages~~ of ~~certain materials and equipment and increased costs. While we have not yet experienced material shortages in supply as a result of~~ these ~~disruptions,~~factors ifmay ~~they~~cause ~~become prolonged or expand in scope the resulting shortages or higher~~ costs ~~could delay the execution of our drilling and development plans or cause us~~ to ~~incur~~rise ~~expenditures not provided for in our capital budget or to not achieve the rates of return we are targeting for our development program, all of~~ which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

We have been an early entrant into new or emerging plays. As a result, our drilling results in these areas are uncertain, and the value of our undeveloped acreage will decline if drilling results are unsuccessful.

While our costs to acquire undeveloped acreage in new or emerging plays have generally been less than those of later entrants into a developing play, our drilling results in new or emerging areas are more uncertain than drilling results in developed and producing areas. Since new or emerging plays have limited or no production history, we are unable to use past drilling results in those areas to help predict our future drilling results. As a result, our cost of drilling, completing and operating wells in these areas may be higher than initially expected, and the value of our undeveloped acreage in the emerging areas may decline if drilling results are unsuccessful.

Our business operations, financial position, results of operations, and cash flows have been and may in the future be materially and adversely affected by the COVID-19 pandemic.

The initial outbreak of COVID-19 negatively impacted the global economy and led to, among other things, reduced global demand for crude oil, disruption of global supply chains, and significant volatility and disruption of financial and commodity markets. In response to the initial outbreak of COVID-19, many state and local jurisdictions imposed quarantines and restrictions on their residents to control the spread of COVID-19. Such quarantines and restrictions resulted in business closures, work stoppages, slowdowns and delays, work-from-home policies, travel restrictions and cancellation of events, among other effects. During 2021 and 2022, the distribution of

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COVID-19 vaccines progressed and many government-imposed restrictions were relaxed or rescinded. While the prices of and demand for crude oil have recovered, further outbreaks, or the emergence of new strains of the COVID-19 virus, could result in the reimposition of domestic and international regulations directing individuals to stay at home, limiting travel, requiring facility closures and imposing quarantines. Widespread implementation of these or similar restrictions could result in commodity price volatility and reduced demand for crude oil and natural gas, which could materially and adversely affect our financial position and results of operations.

We have limited control over the activities on properties we do not operate.

Some of the properties in which we have an ownership interest are operated by other companies and involve third-party working interest owners. As of December 31, ~~2022~~2023, non-operated properties represented 1413% of our estimated proved developed reserves, 98% of our estimated proved undeveloped reserves, and 1210% of our estimated total proved reserves. We have limited ability to influence or control the operations or future development of non-operated properties, including the marketing of oil and gas production, compliance with environmental, occupational safety and health and other regulations, or the amount of expenditures required to fund the development and operation of such properties. Moreover, we are dependent on other working interest owners on these projects to fund their contractual share of capital and operating expenditures. These limitations and our dependence on the operators and other working interest owners for these projects could cause us to incur unexpected future costs and could have a material adverse effect on our business, financial condition, results of operations and cash flows.

We may be subject to risks in connection with acquisitions, divestitures, and joint development arrangements.

As part of our business strategy, we have made and expect to continue making acquisitions of oil and gas properties, divest assets, and enter into joint development arrangements. The successful acquisition of oil and gas properties requires an assessment of several factors, including but not limited to:

•

reservoir modeling and evaluation of recoverable reserves;

•

future crude oil and natural gas prices and location and quality differentials;

•

the quality of the title to acquired properties;

•

the ability to access future drilling locations;

•

availability and cost of gathering, processing, and transportation facilities;

•

availability and cost of drilling and completion equipment and of skilled personnel;

•

future development and operating costs and potential environmental and other liabilities; and

•

regulatory, permitting and similar matters.

The accuracy of these acquisition assessments is inherently uncertain. In connection with these assessments, we perform a review, which we believe to be generally consistent with industry practices, of the subject properties. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities prior to acquisition. Inspections may not always be performed on every property, and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller of the subject properties may be unwilling or unable to provide effective contractual protection against all or part of the problems. We sometimes are not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis. Significant acquisitions and other strategic transactions may involve other risks that may impact our business, including:

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potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities prior to acquisition. Inspections may not always be performed on every property, and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller of the subject properties may be unwilling or unable to provide effective contractual protection against all or part of the problems. We sometimes are not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis. Significant acquisitions and other strategic transactions may involve other risks that may impact our business, including:

•

diversion of our management's attention to evaluating, negotiating and integrating significant acquisitions and strategic transactions;

•

the challenge and cost of integrating acquired assets and operations with our preexisting assets and operations while carrying on our ongoing business; and

•

the failure to realize the full benefit that we expect in estimated proved reserves, production volume, cost savings from operating synergies or other benefits anticipated from an acquisition, or to realize these benefits within the expected time frame.

As a result of our strategy of assessing and executing on accretive acquisitions, the size and geographic footprint of our business has increased and may continue to do so, including into new jurisdictions. Our future success will depend, in part, on our ability to manage our expanded business, which may pose challenges including those related to the management and monitoring of new operations and basins and associated increased costs and complexity. We believe our acquisitions will complement our business strategies by delivering enhanced free cash flows and corporate returns, among other things. However, the anticipated benefits of the transactions may be less significant than expected or may take longer to achieve than anticipated. If we are not able to achieve these objectives and realize the anticipated benefits within anticipated timing or at all, our business, financial condition and operating results may be adversely affected.

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realize the anticipated benefits within anticipated timing or at all, our business, financial condition and operating results may be adversely affected.

In addition, from time to time we may sell or otherwise dispose of certain assets as a result of an evaluation of our asset portfolio or to provide cash flow for use in reducing debt and enhancing liquidity. Such divestitures have inherent risks, including possible delays in closing, the risk of lower-than-expected sales proceeds for the disposed assets, and potential post-closing adjustments and claims for indemnification. Additionally, volatility and unpredictability in commodity prices may result in fewer potential bidders, unsuccessful sales efforts, and a higher risk that buyers may seek to terminate a transaction prior to closing. The occurrence of any of the matters described above could have an adverse impact on our business, financial condition, results of operations and cash flows.

Volatility in the financial markets or in global economic conditions, including consequences resulting from domestic political uncertainty, geopolitical events, international trade disputes and tariffs, and health epidemics could adversely impact our business.

United States and global economies may experience periods of volatility and uncertainty from time to time, resulting in unstable consumer confidence, diminished consumer demand and spending, diminished liquidity and credit availability, and inability to access capital markets. In recent years, certain global economies have experienced periods of political uncertainty, slowing economic growth, rising interest rates, inflation, changing economic sanctions, health-related concerns, and currency volatility. These global macroeconomic conditions may have a negative impact on commodity prices and the availability and cost of materials used in our industry, which in turn could have a material adverse effect on our business, financial condition, results of operations and cash flows.

InTrade ~~recent~~restrictions ~~years,~~or ~~the~~other ~~United~~governmental ~~States~~actions ~~government~~related ~~has~~to ~~initiated~~tariffs ~~new~~or ~~tariffs~~trade onpolicies ~~certain~~have ~~imported~~impacted ~~goods~~in the past, and ~~has~~have ~~imposed~~the ~~increases~~potential to ~~certain~~further ~~existing~~impact, ~~tariffs~~our onbusiness ~~imported~~and ~~goods.~~industry Inby ~~response,~~increasing ~~certain~~the ~~foreign~~cost ~~governments,~~of ~~most~~materials ~~notably~~used ~~China~~in various aspects of upstream, ~~imposed~~midstream, ~~retaliatory~~and ~~tariffs~~downstream onoil ~~certain~~and ~~goods~~gas ~~their~~activities. ~~countries~~Furthermore, tariffs and any quantitative import ~~from~~restrictions, ~~the~~particularly ~~United~~those ~~States.~~impacting ~~These~~the cost and ~~other~~availability ~~events~~of steel and aluminum, ~~including~~may cause disruption in the ~~United~~energy ~~Kingdom~~industry's ~~withdrawal~~supply ~~from~~chain, resulting in the ~~European~~delay ~~Union~~or cessation of drilling and ~~the~~completion ~~COVID-19~~efforts ~~pandemic,~~or ~~have~~the ~~contributed~~postponement toor ~~increased~~cancellation ~~uncertainty~~of ~~for~~new ~~domestic~~pipeline ~~and~~transportation ~~global~~projects ~~economies~~the U.S. ~~Additionally,~~industry ~~growing~~is ~~trends~~relying ~~toward~~on ~~populism~~to ~~and~~transport ~~political~~its ~~polarization~~onshore ~~globally~~production ~~and~~to inmarket, ~~the~~as well as endangering U.S. ~~have~~liquefied ~~resulted~~natural gas export projects resulting in ~~uncertainty~~negative ~~regarding~~impacts ~~potential~~on ~~changes~~natural ingas ~~regulations~~production. Additionally, ~~fiscal~~trade ~~policy~~and/or tariff disputes have impacted in the past, ~~social~~and ~~programs~~have the potential to further impact, domestic and ~~foreign~~global ~~relations~~economies overall, which could result in reduced demand for crude oil and ~~government~~natural ~~energy~~gas. ~~policies,~~Any ~~which~~of the above consequences could ~~pose~~have a ~~potential~~material ~~threat~~adverse toeffect ~~domestic~~on ~~and~~our ~~global~~business, ~~economic~~financial ~~growth~~condition, results of operations and cash flows.

Trade restrictions or other governmental actions related to tariffs or trade policies have impacted, and have the potential to further impact, our business and industry by increasing the cost of materials used in various aspects of upstream, midstream, and downstream oil and gas activities. Furthermore, tariffs and any quantitative import restrictions, particularly those impacting the cost and availability of steel and aluminum, may cause disruption in the energy industry's supply chain, resulting in the delay or cessation of drilling and completion efforts or the postponement or cancellation of new pipeline transportation projects the U.S. industry is relying on to transport its onshore production to market, as well as endangering U.S. liquefied natural gas export projects resulting in negative impacts on natural gas production. Additionally, trade and/or tariff disputes have impacted, and have the potential to further impact, domestic and global economies overall, which could result in reduced demand for crude oil and natural gas. Any of the above consequences could have a material adverse effect on our business, financial condition, results of operations and cash flows.18

A cyber incident could result in information theft, data corruption, operational disruption, and/or financial loss.

Our business and industry has become increasingly dependent on digital technologies to conduct day-to-day operations including certain exploration, development and production activities. We rely heavily on digital technologies, including information systems and related infrastructure as well as cloud applications and services, to process and record financial and operating data; analyze seismic, drilling, completion and production information; manage production equipment; conduct reservoir modeling and reserves estimation; communicate with employees and business associates; perform compliance reporting and many other activities. The availability and integrity of these systems are essential for us to conduct our operations. Our business associates, including employees, vendors, service providers, financial institutions, and transporters, processors, and purchasers of our production are also heavily dependent on digital technology.

As dependence on digital technologies has increased, cyber incidents, including deliberate attacks or unintentional events, have also increased. Our technologies, systems, networks, and those of our business associates have been and continue to be the target of cyber attacks or information security breaches, which could lead to disruptions in critical systems, unauthorized release or theft of confidential or protected information, corruption of data or other disruptions of our business operations. For example, there have been well-publicized cases in recent years involving cyber attacks on software vendors utilized by the Company. In response to those incidents, we deployed our cybersecurity incidence response protocols and promptly took steps to contain and remediate potential vulnerabilities. We believe there have been no compromises to our operations as a result of the attacks; however, other similar attacks in the future could have a significant negative impact on our systems and operations.

A cyber attack involving our information systems and related infrastructure, and/or that of our business associates and customers, could disrupt our business and negatively impact our operations in a variety of ways, including but not limited to unauthorized access

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~~to,~~A orcybersecurity ~~theft~~incident ~~of,~~could ~~sensitive~~result orin ~~proprietary~~ information ~~and~~theft, data corruption, or operational disruption ~~that adversely affects our ability to carry on our business. Any such event could damage our reputation and lead to financial losses from remedial actions~~, ~~loss of business,~~ and/or ~~potential liability, which could have a material adverse effect on our business,~~ financial ~~condition, results of operations or cash flows~~loss. In addition, certain cyber incidents such as reconnaissance of our systems and those of our business associates, may remain undetected for an extended period, which could result in significant consequences. We do not maintain specialized insurance for possible liability resulting from cyber attacks due to lack of coverage for what we consider sensitive and proprietary data.

~~While~~Our ~~the~~business ~~Company~~and industry has ~~well~~become increasingly dependent on digital technologies to conduct day-~~established~~to-day ~~cyber~~operations ~~security~~including ~~systems~~certain exploration, development and ~~controls~~production activities. We rely heavily on digital technologies, ~~disclosure~~including ~~controls~~information and ~~procedures~~operational systems and ~~incident~~related ~~response~~infrastructure ~~protocols~~as well as cloud applications and services, ~~these~~to ~~systems~~process and record financial and operating data; analyze seismic, ~~controls~~drilling, ~~procedures~~completion and ~~protocols~~production ~~may~~information; ~~not~~manage ~~identify~~production ~~all~~equipment; ~~risks~~conduct reservoir modeling and ~~threats~~reserves weestimation; ~~face,~~communicate orwith ~~may~~employees ~~fail~~and business associates; perform compliance reporting and many other activities. The availability and integrity of these systems are essential for us to ~~protect~~conduct ~~data~~our oroperations. ~~mitigate~~Our ~~the~~business ~~adverse~~associates, ~~effects~~including employees, vendors, service providers, financial institutions, and transporters, processors, and purchasers of ~~data~~our ~~loss~~production are also heavily dependent on digital technology.

ToAs ~~our~~dependence ~~knowledge~~on wedigital ~~have~~technologies ~~not~~has ~~experienced~~increased, ~~any~~cybersecurity ~~material~~incidents, ~~losses~~including ~~relating~~deliberate toattacks ~~cyber~~or ~~attacks;~~unintentional ~~however~~events, ~~there~~have ~~can~~also beevolved noand ~~assurance~~increased ~~that~~in wefrequency. ~~will~~Cybersecurity attacks are becoming more sophisticated and include, but are not ~~suffer~~limited ~~material~~to, ~~losses~~malicious insoftware, ~~the~~surveillance, ~~future~~credential ~~either~~stuffing, asspear aphishing, ~~result~~social engineering, use of adeepfakes ~~breach~~(i.e., ofhighly ~~our~~realistic synthetic media generated by artificial intelligence), ransomware attacks, attempts to gain unauthorized access to data, and other electronic security breaches. Our technologies, systems, ornetworks, and those of our business associates. Ashave ~~cyber~~been ~~threats~~and continue to ~~evolve,~~be wethe ~~may~~target beof ~~required~~cybersecurity toattacks ~~expend~~or ~~significant~~information ~~additional~~security ~~resources~~breaches, towhich ~~continue~~could lead to ~~modify~~disruptions in critical systems, unauthorized release or ~~enhance~~theft of confidential or protected information, corruption of data, interruption of operating activities, challenges in maintaining our ~~protective~~books ~~measures~~and records, environmental damage, communication interruptions or other disruptions of our business operations. For example, there have been well-publicized cases in recent years involving cybersecurity attacks on software vendors utilized by the Company. In response to ~~investigate~~those incidents, we deployed our cybersecurity incidence response protocols and ~~remediate~~took ~~any~~steps ~~information~~to ~~security~~contain and remediate potential vulnerabilities. ~~Additionally,~~As of the ~~growth~~date of ~~cyber~~this ~~attacks~~report, ~~has~~we ~~resulted~~are innot ~~evolving~~aware ~~legal~~of ~~and~~any ~~compliance~~material ~~matters~~compromises ~~which~~to ~~may~~our ~~impose~~operations ~~significant~~as ~~costs~~a ~~that~~result ~~are~~of ~~likely~~the toattacks; ~~increase~~however, ~~over~~other ~~time~~similar attacks in the future could have a significant negative impact on our systems and operations.

A cybersecurity attack involving our information or operational systems and related infrastructure, and/or that of our business associates and customers, could disrupt our business and negatively impact our operations in a variety of ways, including but not limited to unauthorized access to, or theft of, confidential, sensitive or proprietary information, data corruption, interruption of operating activities, challenges in maintaining our books and records, environmental damage, communication interruptions or operational disruption that adversely affects our ability to carry on our business. Any such event could damage our reputation and lead to financial losses from remedial actions, loss of business, legal claims or proceedings, litigation costs, regulatory investigations and enforcement, penalties and fines, increased costs for compliance requirements or potential liability, which could have a material adverse effect on our business, financial condition, results of operations or cash flows. In addition, certain cybersecurity incidents such as reconnaissance of our systems and those of our business associates, may remain undetected for an extended period, which could result in significant consequences. We do not maintain specialized insurance for possible liability resulting from cybersecurity attacks due to lack of coverage for what we consider sensitive and proprietary data.

While the Company maintains cybersecurity systems and controls, disclosure controls and procedures and incident response protocols, these systems, controls, procedures and protocols may not identify all risks and threats we face, or may fail to protect data or mitigate the adverse effects of data loss. No security measure is infallible.

As of the date of this report, we do not believe that the Company has experienced any material losses relating to cybersecurity attacks; however, there can be no assurance that we will not suffer material losses in the future either as a result of a breach of our systems or those of our business associates. As cybersecurity threats continue to evolve, we may be required to expend significant additional resources to modify or enhance our protective measures or to investigate and remediate any information security vulnerabilities. Additionally, the growth of cybersecurity attacks has resulted in evolving legal and compliance matters which may impose significant costs that are likely to increase over time.

Competition in the crude oil and natural gas industry is intense, making it more difficult for us to acquire properties, market crude oil and natural gas and secure trained personnel.

Our ability to acquire additional prospects and find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, securing long-term transportation and processing capacity, marketing crude oil and natural gas, and securing trained personnel. Also, there is substantial competition for capital available for investment in the crude oil and natural gas industry. Our competitors may possess and employ financial, technical and personnel resources greater than ours. Those companies may be able to pay more for productive crude oil and natural gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Our inability to effectively compete in this environment could have a material adverse effect on our financial condition, results of operations and cash flows.

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Severe weather events and natural disasters could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Severe weather events and natural disasters such as hurricanes, tornadoes, seismic events, floods, blizzards, extreme cold, drought, and ice storms affecting the areas in which we operate, including our corporate headquarters, could cause disruptions and in some cases suspension of our or our third party service providers' operations, which could have a material adverse effect on our business. Our planning for normal climatic variation, natural disasters, insurance programs and emergency recovery plans may inadequately mitigate the effects of such climatic conditions, and not all such effects can be predicted, eliminated or insured against. Longer term changes in temperature and precipitation patterns may result in changes to the amount, timing, or location of demand for energy or our production. While we consider these factors in our disaster preparedness and response and business continuity planning, we may not consider or prepare for every eventuality in such planning.

Financial Risks

Our revolving credit facility, term loan, and indentures for our senior notes contain certain covenants and restrictions, the violation of which could adversely affect our business, financial condition and results of operations.

Our revolving credit facility and term loan contain restrictive covenants with which we must comply, including covenants that limit our ability to, among other things, incur additional indebtedness, incur liens, engage in sale and leaseback transactions, and merge, consolidate or sell all or substantially all of our assets. Our revolving credit facility and term loan also contain a requirement that we 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 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. At December 31, ~~2022~~2023, we had $~~1.16~~210 ~~billion~~million of outstanding borrowings and $2.04 billion of available borrowing capacity on our credit facility and our consolidated net debt to total capitalization ratio, as defined, was 0.5037.

The indentures governing our senior notes contain covenants that, among other things, limit our ability to create liens securing certain indebtedness, enter into certain sale and leaseback transactions, and consolidate, merge or transfer certain assets.

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Our ability to comply with the provisions of our revolving credit facility, term loan or senior note indentures may be impacted by changes in economic or business conditions, results of operations, or events beyond our control. The breach of any covenant could result in a default under our revolving credit facility, term loan or senior note indentures, in which case, depending on the actions taken by the lenders or trustees thereunder or their successors or assignees, could result in all amounts outstanding thereunder, together with accrued interest, to be due and payable. If our indebtedness is accelerated, our assets may not be sufficient to repay in full such indebtedness, which would have a material adverse effect our business, financial condition, results of operations, and cash flows.

The inability of joint interest owners, significant customers, and service providers to meet their obligations to us may adversely affect our financial results.

Our principal exposure to credit risk is through the sale of our crude oil and natural gas production, which we market to energy marketing companies, crude oil refining companies, and natural gas gathering and processing companies ($1.32 billion in receivables at December 31, ~~2022~~2023) and our joint interest and other receivables ($~~458~~351 million at December 31, ~~2022~~2023). These counterparties may experience insolvency or liquidity issues and may not be able to meet their obligations and liabilities owed to us, particularly during a period of depressed commodity prices. Defaults by these counterparties could adversely impact our financial condition and results of operations.

Additionally, we rely on field service companies and midstream companies for services associated with the drilling and completion of wells and for certain midstream services. A prolonged worsening of the commodity price environment may result in a material adverse impact on the liquidity and financial position of the parties with whom we do business, resulting in delays in payment of, or non-payment of, amounts owed to us, delays in operations, loss of access to equipment and facilities and similar impacts. These events could have an adverse impact on our business, financial condition, results of operations and cash flows.

Legal and Regulatory Risks

Laws, regulations, guidance, executive actions or other regulatory initiatives regarding environmental protection and occupational safety and health could increase our costs of doing business and result in operating restrictions, delays, or cancellations in the drilling and completion of crude oil and natural gas wells, which could have a material adverse effect on our business, results of operations, financial condition and cash flows.

Our crude oil and natural gas exploration and production operations are subject to stringent federal, state and local legal requirements governing environmental protection and occupational safety and health. These requirements may take the form of laws, regulations, executive actions and various other legal initiatives. See Part I, Item 1. Business—Regulation of the Crude Oil and Natural Gas Industry for a discussion of certain environmental and occupational safety and health legal requirements that govern us, including with respect to air emissions, including natural gas flaring limitations and ozone standards; climate change, including restriction of methane or other greenhouse gas emissions and suspensions of, or more stringent limitations upon, new leasing and permitting on federal lands and waters; hydraulic fracturing; waste water disposal regulatory developments; occupational safety standards, and other risks or regulations relating to environmental protection. One or more of these legal requirements could have a material adverse effect on our business, financial condition, results of operations, and cash flows.20

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Our crude oil and natural gas exploration and production operations are subject to stringent federal, state and local legal requirements governing environmental protection and occupational safety and health. These requirements may take the form of laws, regulations, executive actions and various other legal initiatives. See Part I, Item 1. Business—Regulation of the Crude Oil and Natural Gas Industry for a summary of certain significant environmental and occupational safety and health legal requirements that govern us. Such requirements include those pertaining to air emissions, including natural gas flaring limitations and ozone standards; climate change, including restriction of methane or other greenhouse gas emissions and suspensions of, or more stringent limitations upon, new leasing and permitting on federal lands and waters; hydraulic fracturing; waste water disposal; occupational safety standards, and other risks or regulations relating to environmental protection. One or more of these legal requirements could have a material adverse effect on our business, financial condition, results of operations, and cash flows.

We are subject to certain complex federal, state and local laws and regulations in areas other than environmental protection and occupational safety and health that could result in increased costs, operating restrictions or delays, limitations or prohibitions on our ability to develop and produce reserves, or expose us to significant liabilities.

Our crude oil and natural gas exploration and production operations are subject to complex and stringent federal, state and local laws and regulations in areas other than environmental protection and occupational safety and health, including with respect to production, sales and transport of crude oil, NGLs and natural gas, employees and labor relations, and taxation. For instance, President Biden's administration has pursued, and may continue to pursue, legislative changes to eliminate or defer certain key U.S. federal income tax deductions historically available to oil and gas exploration and production companies, including: (i) the elimination of deductions for intangible drilling and exploration and development costs; (ii) a repeal of the percentage depletion allowance for crude oil and natural gas properties; (iii) the elimination of the deduction for certain production activities; and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is uncertain whether these or other changes being pursued will be enacted or, if enacted, how soon any such changes would become effective.

Additionally, in August 2022 President Biden signed the ~~Inflation Reduction Act of 2022 (“~~IRA”) into law, which provides various ~~new~~ tax provisions, incentives, and tax credits aimed at curbing inflation by lowering prescription drug costs, health care costs, and energy costs. The IRA introduces, among other things, (i) a 15% corporate alternative minimum tax on profits for corporations whose average annual adjusted financial statement income for any consecutive three-year period ending after December 31, 2021 exceeds $1 billion and (ii) a methane emissions charge, effective January 1, 2024, on specific types of oil and gas production facilities that report emissions in excess of applicable thresholds.

28Failure to comply with the above and other laws and regulations, including those summarized in Part I, Item 1. Business—Regulation of the Crude Oil and Natural Gas Industry, may trigger a variety of administrative, civil and criminal enforcement investigations or actions, including investigatory actions, the assessment of monetary penalties, the imposition of remedial requirements, the issuance of orders or judgments limiting or enjoining future operations, criminal sanctions, or litigation. Moreover, changes to existing laws or regulations or changes in interpretations of laws and regulations may unfavorably impact us or the infrastructure used for transporting our products. Similarly, changes in regulatory policies and priorities could result in the imposition of new laws or regulations that adversely impact us or our industry. Any such changes could increase our operating costs, delay our operations or otherwise alter the way we conduct our business, which could have a material adverse effect on our financial condition, results of operations and cash flows.

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billion and (ii) a methane emissions charge, effective January 1, 2024, on specific types of oil and gas production facilities that report emissions in excess of applicable thresholds.

Failure to comply with the above and other laws and regulations, including those described in Part I, Item 1. Business—Regulation of the Crude Oil and Natural Gas Industry, may trigger a variety of administrative, civil and criminal enforcement investigations or actions, including investigatory actions, the assessment of monetary penalties, the imposition of remedial requirements, the issuance of orders or judgments limiting or enjoining future operations, criminal sanctions, or litigation. Moreover, changes to existing laws or regulations or changes in interpretations of laws and regulations may unfavorably impact us or the infrastructure used for transporting our products. Similarly, changes in regulatory policies and priorities could result in the imposition of new laws or regulations that adversely impact us or our industry. Any such changes could increase our operating costs, delay our operations or otherwise alter the way we conduct our business, which could have a material adverse effect on our financial condition, results of operations and cash flows.

Our operations and the operations of our customers are subject to a number of risks arising out of the threat of climate change, energy conservation measures, or initiatives that stimulate demand for alternative forms of energy that could result in increased operating costs, limit the areas in which oil and natural gas production may occur, and reduce the demand for the crude oil and natural gas we produce.

Risks arising out of the threat of climate change, fuel conservation measures, governmental requirements for renewable energy resources, increasing consumer demand for alternative forms of energy, and technological advances in fuel economy and energy generation devices may create new competitive conditions that result in reduced demand for the crude oil and natural gas we produce. The potential impact of changing demand for crude oil and natural gas services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows. Additionally, variability in power generation output from alternative energy facilities that are dependent on weather conditions, such as wind and solar, may result in intermittent changes in demand for the commodities we produce which could lead to increased volatility in commodity prices. See Part I, Item 1. Business—Regulation of the Crude Oil and Natural Gas Industry for further discussion relating to risks arising out of the threat of climate change and emission of greenhouse gases, climate change activism, energy conservation measures, initiatives that stimulate demand for alternative forms of energy, and physical effects of climate change. One or more of these developments could have an adverse effect on our assets and operations.

Increasing scrutiny on environmental, social, and corporate governance matters may impact our business.

Companies across all industries are facing increasing scrutiny from a wide array of stakeholders related to their ESG practices. ESG standards are evolving and if we are perceived to have not responded appropriately to certain standards, regardless of whether there is a legal requirement to do so, we may suffer from reputational damage and our business or financial condition, could be materially and adversely affected. Increasing attention to climate change, increasing societal expectations on companies to address climate change, and potential consumer use of alternative forms of energy may result in increased costs, reduced demand for hydrocarbon products, reduced profits, increased investigations and litigation, and negative impacts on our ability to recruit necessary talent, and our access to capital markets.

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adversely affected. Increasing attention to climate change, increasing societal expectations on companies to address climate change, and potential consumer use of alternative forms of energy may result in increased costs, reduced demand for hydrocarbon products, reduced profits, increased investigations and litigation, and negative impacts on our ability to recruit necessary talent, and our access to debt capital markets.

Institutional lenders who provide financing for fossil fuel energy companies also have become more attentive to sustainable lending practices that favor “clean” power sources such as wind and solar, making those sources more attractive for investment, and some of them may elect not to provide funding for fossil fuel energy companies or impose certain ESG-related targets or goals as a condition to funding. While we cannot predict what polices may result from these developments, such efforts could make it more difficult for fossil fuel companies to secure funding as well as negatively affect the cost of, and terms for, financings to fund growth projects or other aspects of our business.

Item 1B. Unresolved Staff Comments

~~None~~Not applicable.

Item 1C. Cybersecurity

Our business and industry has become increasingly dependent upon digital technologies, including information and operational systems and related infrastructure as well as cloud applications and services, to process and record financial and operating data; analyze seismic, drilling, completion and production information; manage production equipment; conduct reservoir modeling and reserves estimation; communicate with employees and business associates; perform compliance reporting and many other activities. We recognize the importance of developing, implementing, and maintaining effective cybersecurity measures to safeguard our information systems and protect the confidentiality, integrity, and availability of our data. The Company has an Insider Threat and Data Loss Prevention program that is designed to protect the confidentiality, integrity and availability of such data, and we maintain processes designed to assess, identify, and manage material risks from cybersecurity threats.

The Company has a cybersecurity team with relevant subject-matter expertise that is part of the Company’s Information Technology department (the “Cybersecurity Team”). This team reports to the Company’s Vice President and Chief Information Officer (“CIO”) and is led by the Company’s Chief Information Security Officer (“CISO”), who has primary responsibility for oversight of the Company’s assessment, identification, and management of cybersecurity risks. The CISO has 27 years of cybersecurity experience, 17 of which are in the oil and gas industry. The Company’s CISO is certified in strategic planning, policy and leadership, and is one of less than 400 CISOs globally that has graduated from the FBI’s CISO Academy in Quantico, Virginia. The CIO and CISO jointly determine whether a given cybersecurity matter is sufficiently important to warrant elevating it to the attention of the Company’s Cybersecurity Executive Committee (defined below) and/or Board of Directors.

The Cybersecurity Team monitors the cybersecurity environment for threats and indicators of compromise. It also considers the risks attendant to the Company’s business operations and strategy and develops solutions and mitigation measures for the risks identified, including risks arising in connection with third-party interactions and the integration of newly acquired assets. In addition, the Company invests in Security Awareness training to help promote employee awareness of cybersecurity.

The Company’s internal cybersecurity efforts are supported by a team of outside consultants, assessors, and third-party vendors who assist with identifying and monitoring risks and indications of compromise.

The Cybersecurity Team regularly engages third-party assessors to conduct evaluations of the Company’s cybersecurity risk mitigation efforts and strategy. The Company also engages a third-party auditing firm to periodically assess our information security program. Audits are also conducted from time-to-time by other third parties, such as insurance adjusters and regulators.

The Cybersecurity Team engages third-party vendors to assist with managing endpoint security, managing the Company’s security operations center, providing threat detection and response capabilities, monitoring certain operational technology and control system environments, and providing threat detection and vulnerability identification and remediation services. Additionally, the Company is a member of the Oil and Natural Gas Information and Analysis Center. This center provides the Company with information regarding threats to the oil and gas industry and threats reported by other industry participants. Finally, the Cybersecurity Team periodically engages with the cybersecurity-related guidance of other third parties such as law enforcement, industry trade groups and vendors.

The Cybersecurity Team reviews the integrity of services provided by vendors engaged to support the Company’s cybersecurity efforts using the same methods as are used to evaluate the services provided by other vendors engaged to support the Company’s regular business operations.

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The above cybersecurity risk management processes are integrated into the Company’s overall enterprise risk management program. Cybersecurity risks are understood to be significant business risks, and as such, are considered an important component of our enterprise-wide risk management approach.

Since the Company is private, it has no independent members of its Board of Directors. All of the Company’s directors are also executive officers. The body primarily responsible for oversight of the Cybersecurity Team is the Cybersecurity Executive Committee, which is composed of the Company’s President and Chief Executive Officer; Executive Vice President, Chief Culture Officer and Administrative Officer (both of whom are also members of the Company’s Board of Directors); Chief Financial Officer and Executive Vice President of Strategic Planning; Senior Vice President, General Counsel and Secretary; CIO; Director of Corporate Security; and the Information Security Manager. The Cybersecurity Executive Committee meets regularly and during these meetings its members review and discuss cybersecurity information provided by the CISO, which may include: (i) metrics relevant to cybersecurity issues; (ii) summaries of changes or proposed changes to the Company’s cybersecurity program; and (iii) cybersecurity risk and threat updates. Information regarding any critical cybersecurity-related matter is communicated to the Cybersecurity Executive Committee as soon as practicable.

In addition, the CISO annually briefs the Company's Audit Committee regarding cybersecurity matters at a regularly scheduled committee meeting and these briefings cover the same types of information as is presented to the Cybersecurity Executive Committee. The Audit Committee is composed of the two members of the Board of Directors who are also members of the Cybersecurity Executive Committee.

The Company has developed a Cybersecurity Incident Response Plan (the “Response Plan”), which is based upon NASA’s mission control incident response procedures to address and manage certain cybersecurity incidents. If an incident meets certain criteria, the incident response plan is invoked by the CISO and General Counsel. Once the plan is invoked, an impact assessment is conducted and a remediation plan is developed, if needed. The plan also sets forth procedures for monitoring incidents and post-incident follow-up so that any lessons learned can be discussed. Where appropriate, the post-incident follow up identifies measures that can be implemented to aid with future incident prevention and detection. Under the Response Plan any incident-related information is communicated using the channels outlined in the Response Plan.

As of the date of this report, though the Company and our service providers have experienced certain cybersecurity incidents, the Company does not believe any prior cybersecurity threat or incident has materially affected or are reasonably likely to materially affect the Company, including its business operations or prospects. However, the Company acknowledges that cybersecurity threats are continually evolving and the possibility of future cybersecurity incidents remains. Despite the implementation of our cybersecurity processes, our security measures cannot guarantee that a significant cyberattack will not occur. A successful attack on our information technology systems could have significant consequences for the business. While we devote resources to our security measures to protect our systems and information, these measures cannot provide absolute security. No security measure is infallible. For additional information about the risks to our business associated with cybersecurity incidents, please see “A cybersecurity incident could result in information theft, data corruption, operational disruption, and/or financial loss” under Part I, Item IA. Risk Factors.

Item 2. Properties

The information required by Item 2 is contained in Part I, Item 1. Business—Crude Oil and Natural Gas Operations and Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Delivery Commitments and is incorporated herein by reference.

Item 3. Legal Proceedings

29We 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 the 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 effect on our financial condition, results of operations or cash flows.

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We are involved in various legal proceedings including, but not limited to, commercial disputes, claims from royalty and surface owners, property damage claims, 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 effect on our financial condition, results of operations or cash flows.

Item 4. Mine Safety Disclosures

Not applicable.

3023

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Part II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

~~Our~~Effective ~~common~~November ~~stock~~22, ~~previously~~2022, ~~traded~~Continental onResources, ~~the New York Stock Exchange (“NYSE”) under the symbol “CLR~~Inc.” Asbecame a ~~result~~privately ofheld ~~the~~corporation ~~take-private transaction described in Part II. Item 8. Notes to Consolidated Financial Statements—Note 1. Organization~~ and ~~Summary~~has ofno ~~Significant~~publicly ~~Accounting~~available ~~Policies—Take-Private Transaction, our~~ common ~~stock~~shares ~~ceased~~outstanding toat ~~be listed on~~ the ~~NYSE~~time ~~effective~~of ~~November~~this ~~23, 2022 and there is no longer an established trading market for our common stock~~filing.

The ~~following~~Company ~~table~~has ~~provides~~no ~~information~~dividend ~~about~~policy ~~purchases~~and ofcurrently ~~our~~has ~~common~~no ~~stock~~plans ~~during~~to ~~the~~pay ~~quarter~~cash ~~ended~~dividends ~~December~~in ~~31, 2022 leading up to, and including,~~ the ~~take-private~~future ~~transaction:~~year.

Period	Total number of shares purchased		Average price paid per share		Total number of shares purchased as part of publicly announced plans or programs (1)		Maximum dollar value of shares that may yet be purchased under the plans or programs (in millions) (1)
October 1, 2022 to October 31, 2022
Repurchases for tax withholdings (1)		20,081	$	68.22		—	$	—
November 1, 2022 to November 30, 2022
Repurchases for tax withholdings (1)		2,499	$	74.07		—	$	—
Take-private transaction (2)		58,059,259	$	74.28		—	$	—
Total for the quarter		58,081,839	$	74.28

Amounts represent shares surrendered by employees to cover tax liabilities in connection with the vesting of restricted stock granted under the Company's 2013 Long-Term Incentive Plan. We paid the associated taxes to the applicable taxing authorities. The price paid per share was the closing price of our common stock on the date the restrictions lapsed on such shares.

Represents shares purchased in conjunction with the Hamm Family's take-private transaction, inclusive of payments issued to holders who demanded appraisal rights for their untendered shares in accordance with Oklahoma law.

Item 6. Reserved

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ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with our consolidated financial statements and notes included elsewhere in this report. Results attributable to noncontrolling interests are not material relative to consolidated results and are not separately presented or discussed below.

The following discussion and analysis includes forward-looking statements and should be read in conjunction with Part I, Item 1A. Risk Factors in this report, 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 Part II. Item 8. Notes to Consolidated Financial Statements—Note 1. Organization and Summary of Significant Accounting Policies—2022 Take-Private Transaction, effective November 22, 2022 Continental Resources, Inc. became a privately held corporation and has no publicly available common shares outstanding.

Take-private transaction

See Part II. Item 8. Notes to Consolidated Financial Statements—Note 1. Organization and Summary of Significant Accounting Policies—Take-Private Transaction for additional information.

Financial and Operating Metrics

Commodity prices ~~increased~~have ~~significantly~~remained involatile ~~2022~~due ~~compared~~ to ~~2021~~various ~~levels~~factors, ~~resulting~~some ~~from the ongoing rebalancing~~ of ~~crude~~which ~~oil~~include ~~and~~global ~~natural gas~~ supply and demand, ~~fundamentals coupled with the disruption of~~ global ~~hydrocarbon~~inventory ~~markets~~levels, ~~prompted by the outbreak of military conflict between Russia~~ and ~~Ukraine~~regional conflicts. ~~The~~Average ~~increase~~NYMEX inoil ~~commodity~~ prices ~~contributed~~for tothe ~~improved~~years ~~operating~~ended ~~results~~December ~~and~~31, ~~cash~~2023, ~~flows in~~ 2022 ~~compared to 2021. Additionally~~, ~~our property acquisitions in the Permian Basin~~ and ~~Powder~~2021 ~~River~~were ~~Basin over the past year contributed to increased production~~$77.57, ~~revenues~~$94.17, and ~~cash~~$68.05, ~~flows~~respectively. inAverage ~~2022~~NYMEX ~~compared~~gas ~~to 2021. Commodity~~ prices ~~remain volatile and unpredictable and our operating results~~ for the ~~year~~years ended December 31, 2023, 2022, ~~may~~and ~~not~~2021 bewere ~~indicative~~$2.73, of$6.72, ~~future~~and ~~results~~$3.88, ~~Given~~respectively. ~~the~~The ~~uncertainty~~following ~~surrounding~~table ~~the~~contains ~~Russia/Ukraine~~financial ~~conflict~~ and ~~ongoing~~operating ~~volatility~~metrics infor ~~commodity~~the ~~prices,~~periods wepresented. ~~are~~Average ~~unable~~sales toprices ~~predict~~exclude ~~the~~any ~~extent~~effect toof ~~which~~derivative ~~the~~transactions. ~~conflict~~Per-unit orexpenses ~~other factors will~~ have onbeen ~~the~~calculated ~~Company’s~~using ~~future~~sales ~~performance~~volumes.

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


	Year ended December 31,
	2023			2022			2021
Average daily production:
Crude oil (Bbl per day)		232,083			199,526			160,647
Natural gas (Mcf per day) (1)		1,248,488			1,213,643			1,014,000
Crude oil equivalents (Boe per day)		440,164			401,800			329,647
Average sales prices:
Crude oil ($/Bbl)	$	76.89		$	94.95		$	67.21
Natural gas ($/Mcf) (1)	$	2.60		$	7.15		$	4.98
Production expenses ($/Boe)	$	4.47		$	4.24		$	3.38
Production and ad valorem taxes (% of net crude oil and natural gas sales)		8.2	%		7.5	%		7.3	%
DD&A ($/Boe)	$	14.11		$	12.86		$	15.76
Total general and administrative expenses ($/Boe)	$	1.74		$	2.74		$	1.94

(1)

32Natural gas production volumes, sales volumes, and sales prices presented throughout management's discussion and analysis reflect the combined value for natural gas and natural gas liquids.

Table of Contents

	Year ended December 31,
	2022			2021			2020
Average daily production:
Crude oil (Bbl per day)		199,526			160,647			160,505
Natural gas (Mcf per day) (1)		1,213,643			1,014,000			837,509
Crude oil equivalents (Boe per day)		401,800			329,647			300,090
Average net sales prices (2):
Crude oil ($/Bbl)	$	91.46		$	64.06		$	34.71
Natural gas ($/Mcf) (1)	$	7.01		$	4.88		$	1.04
Crude oil equivalents ($/Boe)	$	66.58		$	46.24		$	21.47
Crude oil net sales price discount to NYMEX ($/Bbl)	$	(2.71	)	$	(4.00	)	$	(5.80	)
Natural gas net sales price premium (discount) to NYMEX ($/Mcf)	$	0.29		$	1.00		$	(1.10	)
Production expenses ($/Boe)	$	4.24		$	3.38		$	3.27
Production taxes (% of net crude oil and natural gas sales)		7.5	%		7.3	%		8.2	%
DD&A ($/Boe)	$	12.86		$	15.76		$	17.12
Total general and administrative expenses ($/Boe)	$	2.74		$	1.94		$	1.79

Natural gas production volumes, sales volumes, and net sales price 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.

Results of Operations

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

	Year Ended December 31,
In thousands	~~2022~~2023			~~2021~~2022			~~2020~~2021
Crude oil, natural gas, and natural gas liquids sales	$	107,~~074~~684,~~675~~263		$	510,~~793~~074,~~741~~675		$	25,~~555~~793,~~434~~741
Loss on derivative instruments, net		(671,095	)		(128,864	)		(14,658	)
Gain (loss) on derivative instruments, net		943,768			(671,095	)		(128,864	)
Crude oil and natural gas service operations		70103,~~128~~710			5470,~~441~~128			4554,~~694~~441
Total revenues		98,~~473~~731,~~708~~741			59,~~719~~473,~~318~~708			25,~~586~~719,~~470~~318
Operating costs and expenses		(4,~~120~~419,~~028~~008	)		(34,~~257~~120,~~638~~028	)		(3,~~140~~257,~~362~~638	)
Other expenses, net		(~~285~~383,~~267~~786	)		(~~275~~285,~~542~~267	)		(~~220~~275,~~859~~542	)
Income (loss) before income taxes		5,068,413			2,186,138			(774,751	)
Income before income taxes		3,928,947			5,068,413			2,186,138
(Provision) benefit for income taxes		(1,020,804	)		(519,730	)		169,190
Provision for income taxes		(827,630	)		(1,020,804	)		(519,730	)
Income (loss) before equity in net loss of affiliate		4,047,609			1,666,408			(605,561	)
Income before equity in net loss of affiliate		3,101,317			4,047,609			1,666,408
Equity in net loss of affiliate		(13,~~489~~129	)		—(1,489	)		—
Net income (loss)		4,046,120			1,666,408			(605,561	)
Net income		3,098,188			4,046,120			1,666,408
Net income (loss) attributable to noncontrolling interests		21,562			5,440			(8,692	)
Net income attributable to noncontrolling interests		2,361			21,562			5,440
Net income (loss) attributable to Continental Resources	$	4,024,558		$	1,660,968		$	(596,869	)
Net income attributable to Continental Resources	$	3,095,827		$	4,024,558		$	1,660,968
Production volumes:
Crude oil (MBbl)		7284,~~827~~710			5872,~~636~~827			58,~~745~~636
Natural gas (MMcf)		~~442~~455,~~980~~698			~~370~~442,~~110~~980			~~306~~370,~~528~~110
Crude oil equivalents (MBoe)		~~146~~160,~~657~~660			~~120~~146,~~321~~657			~~109~~120,~~833~~321
Sales volumes:
Crude oil (MBbl)		7284,~~732~~508			5872,~~757~~732			58,~~793~~757
Natural gas (MMcf)		~~442~~455,~~980~~698			~~370~~442,~~110~~980			~~306~~370,~~528~~110
Crude oil equivalents (MBoe)		~~146~~160,~~562~~457			~~120~~146,~~442~~562			~~109~~120,~~881~~442

33Year ended December 31, 2023 compared to the year ended December 31, 2022

~~Table~~Below is a discussion of ~~Contents~~changes in our results of operations for 2023 compared to 2022. A discussion of changes in our results of operations for 2022 compared to 2021 has been omitted from this Form 10-K, but may be found in Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations of our Form 10-K for the year ended December 31, 2022 as filed with the SEC on February 22, 2023.

Year ended December 31, 2022 compared to the year ended December 31, 2021

Below is a discussion of changes in our results of operations for 2022 compared to 2021. A discussion of changes in our results of operations for 2021 compared to 2020 has been omitted from this Form 10-K, but may be found in Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations of our Form 10-K for the year ended December 31, 2021 as filed with the SEC on February 14, 2022.

Production

The following table summarizes the changes in our average daily Boe production by major operating area for the periods presented.

	Fourth Quarter							Year Ended December 31,
Boe production per day	~~2022~~2023		~~2021~~2022		% Change			~~2022~~2023		~~2021~~2022		% Change
Bakken		~~174~~220,~~397~~428		~~175~~174,~~585~~397		(126	)%		~~171~~202,~~025~~610		~~169~~171,~~636~~025		118	%
Anadarko Basin		~~165~~144,~~225~~158		~~146~~165,~~131~~225		(13	)%		~~158~~153,~~221~~426		~~147~~158,~~249~~221		7(3	)%
Powder River Basin		2825,~~057~~577		728,~~189~~057		~~290~~(9	)%		2423,~~602~~757		524,~~161~~602		~~377~~(3	)%
Permian Basin (1)		44,925		4,997		-			41,917		1,260		-
Permian Basin		58,601		44,925		30	%		54,651		41,917		30	%
All other		5,~~552~~666		65,~~266~~552		~~(11~~2	)%		65,~~035~~720		6,~~341~~035		(5	)%
Total		~~418~~454,~~156~~430		~~340~~418,~~168~~156		239	%		~~401~~440,~~800~~164		~~329~~401,~~647~~800		2210	%

~~Production~~The ~~figures~~following ~~for~~table ~~the~~summarizes ~~Permian Basin for~~ the ~~2021~~changes ~~periods~~in ~~represent~~our production ~~during~~by ~~the~~product ~~period~~for ~~from~~ the ~~closing of our acquisition of Permian properties on December 21, 2021 through December 31, 2021 averaged over the respective fourth quarter and full year~~ periods. presented.

The following tables reflect our production by product and region for the periods presented.


	Year Ended December 31,												Volume
	2023					2022					Volume		percent
	Volume		Percent			Volume		Percent			increase		increase
Crude oil (MBbl)		84,710		53	%		72,827		50	%		11,883		16	%
Natural gas (MMcf)		455,698		47	%		442,980		50	%		12,718		3	%
Total (MBoe)		160,660		100	%		146,657		100	%		14,003		10	%

	Year Ended December 31,												Volume
	2022					2021					Volume		percent
	Volume		Percent			Volume		Percent			increase		increase
Crude oil (MBbl)		72,827		50	%		58,636		49	%		14,191		24	%
Natural gas (MMcf)		442,980		50	%		370,110		51	%		72,870		20	%
Total (MBoe)		146,657		100	%		120,321		100	%		26,336		22	%

~~The~~Table 24% increase in crude oil production in 2022 compared to 2021 was primarily driven by our property acquisitions in the Permian Basin and Powder River Basin over the past year and in late 2021, which contributed to an increase in our 2022 production by 11,474 MBbls and 4,360 MBbls, respectively, compared to 2021. These increases were partially offset by a 1,373 MBbls, or 10%, decrease in Anadarko Basin crude oil production due to a change in allocation of ~~capital~~Contents ~~from oil-weighted projects to gas-weighted projects in the play over the past year and the timing of well completions.~~

The 2016% increase in ~~natural~~crude ~~gas~~oil production in ~~2022~~2023 compared to ~~2021~~2022 was ~~due~~primarily indriven ~~part~~by tonew ~~the~~well ~~previously~~completions ~~described~~in ~~property~~the ~~acquisitions~~Bakken field over the past year., ~~Properties~~which ~~acquired~~led into ~~the~~an ~~Permian~~increase ~~Basin~~of ~~and~~7,939 ~~new~~MBbls, ~~well~~or ~~completions~~19%, ~~increased~~compared ~~our~~to 2022. ~~production~~The increase was also driven by ~~20,191~~our ~~MMcf~~property ~~while~~acquisitions ~~properties~~and ~~acquired~~subsequent new well completions in the ~~Powder~~Permian ~~River~~ Basin ~~and~~over ~~new~~the ~~well~~past ~~completions~~year, ~~increased~~which contributed to an increase in our 2023 production by 163,~~415~~275 ~~MMcf~~MBbls, or 28%, compared to ~~2021~~2022. Additionally, as a result of new well completions over the past year our ~~natural~~crude ~~gas~~oil production increased 1,240 MBbls, or 11%, in the Anadarko Basin ~~increased~~in ~~32,264~~2023 ~~MMcf~~compared to 2022. These increases were partially offset by a 467 MBbls, or 138%, decrease in ~~2022~~crude ~~compared~~oil toproduction ~~2021~~in the Powder River Basin due to variation in the timing of new well completions ~~over~~between ~~the past year~~years.

The 3% increase in natural gas production in 2023 compared to 2022 was primarily driven by new well completions in the Bakken field over the past year, which led to an increase of 21,534 MMcf, or 17%, compared to 2022. The increase was also 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 8,240 MMcf, or 40%, compared to 2022. These increases were partially offset by a 17,943 MMcf, or 6%, decrease in natural gas production in the Anadarko Basin due to capital spending over the past year being allocated primarily to oil-weighted projects in the play.

Revenues

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

~~Net~~Crude ~~crude~~ oil, natural gas, and natural gas liquids sales. ~~and~~Sales ~~related~~for ~~net~~2023 ~~sales~~totaled ~~prices~~$7.68 ~~presented~~billion, ~~below~~a ~~are~~24% ~~non-GAAP~~decrease ~~measures~~compared to sales of $10.07 ~~See~~billion ~~the~~for ~~subsequent~~2022 ~~section~~due ~~titled~~to ~~Non-GAAP~~decreases ~~Financial~~in ~~Measures~~sales ~~for~~prices, ~~discussion~~partially ~~and~~offset ~~calculation~~by ofincreases ~~these~~in ~~measures~~sales volumes as discussed below.

~~Net~~Total ~~crude~~sales ~~oil~~volumes for 2023 increased 13,895 ~~natural~~MBoe, ~~gas~~or 9%, ~~and~~compared ~~natural~~to ~~gas~~2022 ~~liquids~~due ~~sales.~~to ~~Net~~additional ~~sales~~drilling ~~for~~and ~~2022~~completion ~~totaled~~activities ~~$9.76~~and ~~billion,~~new awells ~~75%~~added ~~increase~~from ~~compared~~our toproperty ~~net~~acquisitions ~~sales~~over ofthe $5past year.57 ~~billion~~For ~~for~~2023, ~~2021~~our ~~due~~crude tooil ~~significant~~sales ~~increases~~volumes inincreased ~~net~~16% ~~sales~~compared ~~prices~~to 2022 and our natural gas sales volumes asincreased ~~discussed~~3% ~~below.~~compared to 2022.

~~Total~~Our ~~sales~~crude ~~volumes~~oil ~~for~~sales ~~2022~~prices ~~increased~~averaged ~~26,120~~$76.89 ~~MBoe,~~per orbarrel ~~22%~~for 2023, ~~compared~~a todecrease ~~2021,~~of ~~primarily~~19% ~~due~~compared to ~~new~~$94.95 ~~wells~~per ~~added~~barrel ~~from~~for ~~our property acquisitions over the past year. For~~ 2022, ~~our~~due ~~crude~~to ~~oil~~a ~~sales~~significant ~~volumes~~decrease ~~increased~~in ~~24%~~market ~~compared~~prices toresulting ~~2021~~from ~~and~~changes ~~our~~in ~~natural~~various ~~gas~~macroeconomic ~~sales~~conditions ~~volumes~~between ~~increased 20% compared to 2021~~periods.

34Our natural gas sales prices averaged $2.60 per Mcf for 2023 compared to $7.15 per Mcf for 2022 due to a significant decrease in market prices for residue gas and natural gas liquids.

~~Table~~Derivatives. Reduced commodity prices in 2023 had an overall favorable impact on the fair value of ~~Contents~~our derivatives, which resulted in positive revenue adjustments of $943.8 million for the year, representing $257.2 million of realized cash gains and $686.6 million of unsettled non-cash gains, compared to negative revenue adjustments totaling $671.1 million in 2022.

Crude oil and natural gas service operations. Our crude oil ~~net~~and ~~sales~~natural ~~prices~~gas ~~averaged~~service ~~$91.46~~operations ~~per~~consist ~~barrel~~primarily ~~for~~of ~~2022,~~revenues anassociated ~~increase~~with ofwater ~~43%~~gathering, ~~compared~~recycling, todelivery, ~~$64.06~~and ~~per~~disposal ~~barrel~~activities, ~~for~~which ~~2021~~are ~~due~~impacted toby ~~the~~our ~~previously~~production ~~described~~volumes ~~increase~~and inthe ~~market~~timing ~~prices~~and ~~along~~extent ~~with~~of ~~improved~~our ~~price~~drilling ~~differentials~~and completion projects. ~~The~~Revenues ~~discount~~associated ~~between~~with ~~NYMEX~~such ~~West~~activities ~~Texas~~increased ~~Intermediate~~$33.6 ~~calendar~~million, ~~month~~or ~~crude~~48%, ~~oil~~from ~~prices~~$70.1 ~~and~~million ~~our~~for ~~realized~~2022 ~~crude~~to ~~oil~~$103.7 ~~net~~million ~~sales~~for ~~prices~~2023 ~~improved~~due to anincreased ~~average~~water ofhandling ~~$2.71~~activities ~~per~~resulting ~~barrel~~from increases in ~~2022~~completion activities and production volumes compared to a2022, ~~discount~~which ofalso ~~$4.00~~contributed ~~per~~to ~~barrel~~an increase in ~~2021,~~service-related ~~reflecting~~operating ~~strong~~expenses ~~price~~in ~~realizations~~the ~~across~~current ~~our assets~~year.

Our natural gas net sales prices averaged $7.01 per Mcf for 2022 compared to $4.88 per Mcf for 2021 due to the previously described increase in market prices. The difference between our net sales prices and NYMEX Henry Hub calendar month natural gas prices was a premium of $0.29 per Mcf for 2022 compared to a premium of $1.00 per Mcf for 2021. The decrease in premium was driven by price volatility, wider basis differentials between prices received in our sales markets and NYMEX settlement prices, and significant improvement in Henry Hub prices as compared to increases in NGL prices, causing the uplift in price realizations for our full gas stream relative to benchmark prices to be less significant in the current year.

Derivatives. The significant improvement in commodity prices in 2022 had an overall unfavorable impact on the fair value of our derivatives, which resulted in negative revenue adjustments of $671.1 million for the year, representing $458.1 million of cash losses and $213.0 million of unsettled non-cash losses, compared to negative revenue adjustments totaling $128.9 million for cash and non-cash losses for 2021.

Crude oil and natural gas service operations. Our crude oil and natural gas service operations consist primarily of revenues associated with water gathering, recycling, and disposal activities, which are impacted by our production volumes and the timing and extent of our drilling and completion projects. Revenues associated with such activities increased $15.7 million, or 29%, from $54.4 million for 2021 to $70.1 million for 2022 due to increased water handling activities resulting from increases in completion activities and production volumes compared to 2021, which also contributed to an increase in service-related operating expenses in the current year.

Operating Costs and Expenses

Production expenses. Production expenses increased $~~215~~95.06 million, or 5315%, to $~~621~~717.95 million for ~~2022~~2023 compared to $~~406~~621.9 million for ~~2021~~2022 due to an increase in the number of producing wells from drilling activities and property acquisitions, cost inflation for services and materials, and higher workover-related activities aimed at enhancing production from producing properties ~~prompted by the favorable commodity price environment~~. Production expenses on a per-Boe basis averaged $4.2447 per Boe for ~~2022~~2023 compared to $34.3824 per Boe for ~~2021~~2022, the increase of which reflects higher workover-related activities, cost inflation, and ~~the~~a ~~addition~~higher proportion of ~~oil-weighted~~ production ~~acquired~~coming infrom ~~the~~oil-weighted ~~Permian~~properties ~~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 ~~increased~~decreased $~~325~~126.86 million, or 8117%, to $~~730~~603.15 million for ~~2022~~2023 compared to $~~404~~730.41 million for ~~2021~~2022 due to the previously described ~~increase~~decrease in crude oil, natural gas, and NGL sales. Our production taxes as a percentage of net sales averaged 78.52% for ~~2022~~2023 compared to 7.35% for ~~2021~~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~~Transportation, ~~depletion~~gathering, ~~amortization~~processing, and ~~accretion (“DD&A”)~~compression. ~~Total~~These ~~DD&A~~charges ~~amounted~~increased to $121.898 ~~billion~~million, ~~for~~or ~~2022~~7%, ~~consistent~~to ~~with~~ $1338.902 ~~billion~~million for ~~2021,~~2023 ~~reflecting~~compared ato ~~22% increase in total sales volumes the impact of which was nearly offset by a decrease in our DD&A rate per Boe as further discussed below~~$316.4 ~~The~~million ~~following~~for ~~table~~2022 ~~shows~~primarily ~~the~~due ~~components~~to of our ~~DD&A~~9% onincrease ain ~~unit~~total of sales ~~basis for the periods presented~~volumes.

	Year ended December 31,
$/Boe	2022		2021
Crude oil and natural gas properties	$	12.57	$	15.45
Other equipment		0.20		0.22
Asset retirement obligation accretion		0.09		0.09
Depreciation, depletion, amortization and accretion	$	12.86	$	15.76

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.

Our proved reserves have been revised upward over the past year prompted by significant increases in first-day-of-the-month commodity prices and other factors, which, when coupled with improvements in capital efficiency and strong well productivity, resulted in a decrease in our DD&A rate for crude oil and natural gas properties in 2022 compared to 2021 and helped offset the additional DD&A recognized in 2022 from increased sales volumes.

Table of Contents

~~Property~~Depreciation, ~~impairments.~~depletion, ~~Property~~amortization ~~impairments~~and ~~increased~~accretion ~~$32~~(“DD&A”).0 ~~million~~Total DD&A amounted to $702.426 ~~million~~billion for ~~2022~~2023, ~~compared~~an toincrease of $38378.49 million, ~~for~~or ~~2021~~20%, ~~due~~compared ~~in part~~ to $171.589 ~~million~~billion offor ~~proved~~2022, ~~property~~reflecting ~~impairments~~a ~~recognized~~9% increase in ~~2022~~total ~~with~~sales novolumes ~~proved~~as ~~property~~well ~~impairments~~as ~~being~~an ~~recognized~~increase in ~~the~~our ~~prior~~DD&A ~~year.~~rate ~~Additionally,~~per ~~impairments~~Boe ofas ~~unproved~~further ~~properties~~discussed ~~increased $14~~below.5 ~~million~~The infollowing ~~2022~~table ~~compared~~shows ~~to 2021 reflecting an increase in~~ the ~~amortization~~components of ~~undeveloped~~our ~~leasehold~~DD&A ~~costs~~on ~~driven~~a byunit ~~an increase in our balance~~ of ~~unproved~~sales ~~properties~~basis ~~resulting~~for ~~from property acquisitions over~~ the ~~past~~periods ~~year~~presented.

General and administrative ("G&A") expenses. G&A expenses increased $167.9 million, or 72%, to $401.6 million for 2022 compared to $233.6 million for 2021.


	Year ended December 31,
$/Boe	2023		2022
Crude oil and natural gas properties	$	13.58	$	12.57
Other equipment		0.44		0.20
Asset retirement obligation accretion		0.09		0.09
Depreciation, depletion, amortization and accretion	$	14.11	$	12.86

~~Total~~Estimated ~~G&A~~proved ~~expenses~~reserves ~~include~~are ~~non-cash~~a ~~charges~~key ~~for~~component ~~equity/incentive~~in ~~compensation~~our computation of ~~$217~~DD&A expense.8 ~~million~~Proved ~~and~~reserves ~~$63.2~~are ~~million~~determined ~~for~~using ~~2022~~the ~~and~~unweighted ~~2021,~~arithmetic ~~respectively.~~average ~~This~~of ~~increase~~the ~~was~~first-day-of-the-month ~~primarily~~commodity ~~driven~~prices byfor the ~~remeasurement~~preceding oftwelve ~~cumulative~~months ~~compensation~~as ~~expense~~required onby ~~unvested~~SEC ~~restricted~~rules. ~~stock~~Holding ~~awards~~all ~~that~~other ~~were~~factors ~~replaced~~constant, ~~with~~if ~~new~~proved ~~liability-classified~~reserves ~~awards~~are inrevised ~~conjunction~~downward ~~with~~due ~~the~~to ~~Hamm~~commodity ~~Family's~~price ~~take-private~~declines ~~transaction.~~or ~~This~~other ~~remeasurement~~reasons, ~~resulted in~~ the ~~recognition~~rate ofat ~~additional~~which ~~non-cash~~we ~~equity/incentive~~record ~~compensation~~DD&A expense ~~totaling $136 million ($0~~increases.93 ~~per Boe)~~Conversely, ~~reflecting~~if ~~the~~proved ~~increase~~reserves inare ~~the~~revised ~~value~~upward, of the ~~awards~~rate ~~from~~at ~~the~~which ~~original~~we ~~grant~~record ~~date~~DD&A toexpense ~~the November 2022 modification date~~decreases.

~~G&A~~Our ~~expenses~~proved ~~other~~reserves ~~than~~have ~~equity~~been ~~compensation~~revised ~~totaled~~downward ~~$183.8~~over ~~million~~the ~~for~~past ~~2022,~~year anprompted ~~increase~~by ofdecreases ~~$13.4~~in ~~million,~~first-day-of-the-month orcommodity ~~8%,~~prices ~~compared~~and toother ~~$170.4~~factors, ~~million~~which ~~for~~resulted ~~2021~~in ~~primarily~~an ~~due~~increase toin ~~the growth of~~ our ~~operations~~DD&A ~~and~~rate ~~increases~~for incrude ~~payroll~~oil ~~costs~~ and ~~employee~~natural ~~benefits,~~gas ~~partially~~properties ~~offset~~in by2023 ~~higher~~compared ~~overhead~~to ~~recoveries~~2022. ~~from~~Our ~~joint~~DD&A ~~interest~~rate ~~owners~~totaled ~~driven~~$15.76 byper ~~increased~~Boe ~~drilling,~~for ~~completion,~~the ~~and~~2023 ~~production~~fourth ~~activities compared to 2021~~quarter.

Property impairments. Property impairments decreased $3.6 million to $66.8 million for 2023 compared to $70.4 million for 2022 due in part to $17.5 million of proved property impairments recognized in 2022 compared to $15.5 million of proved property impairments being recognized in 2023. Additionally, impairments of unproved properties decreased $1.6 million in 2023 compared to 2022 reflecting a decrease in the amortization of undeveloped leasehold costs over the past year.

General and administrative (“G&A”) expenses. G&A expenses decreased $122.3 million, or 30%, to $279.3 million for 2023 compared to $401.6 million for 2022.

Total G&A expenses include non-cash charges for incentive compensation/prior equity awards of $91.3 million and $217.7 million for 2023 and 2022, respectively. This decrease was primarily driven by the prior year remeasurement of cumulative compensation expense on restricted stock awards that were replaced with new liability-classified awards in conjunction with the Hamm Family’s take-private transaction. The remeasurement in 2022 resulted in the recognition of additional non-cash equity/incentive compensation expense totaling $136 million ($0.93 per Boe), reflecting the increase in the value of the awards from the original grant date to the November 2022 modification date.

G&A expenses other than incentive compensation/prior equity awards totaled $188.0 million for 2023, an increase of $4.2 million, or 2%, compared to $183.8 million for 2022 primarily due to the growth of our operations and increases in payroll costs and employee benefits, partially offset by higher overhead recoveries from joint interest owners driven by increased drilling, completion, and production activities compared to 2022.

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

	Year ended December 31,
$/Boe	~~2022~~2023		~~2021~~2022
General and administrative expenses	$	1.2517	$	1.4225
Non-cash equity/incentive compensation		1.49		0.52
Incentive compensation/prior equity awards		0.57		1.49
Total general and administrative expenses	$	21.74	$	12.9474

Transaction costs. WeIn 2022, we incurred $32 million of legal and advisory fees related to the Hamm Family's take-private transaction, which are included in the caption "Transaction costs" in the consolidated statements of income ~~(loss)~~ for 2022~~. In 2021~~, ~~we incurred $14 million of transaction-related fees in connection~~ with ~~our~~no ~~December~~similar ~~2021~~charges ~~acquisition~~being ofincurred ~~properties~~ in ~~the Permian Basin~~2023.

Interest expense. Interest expense increased $4995.1 million, or 2032%, to $~~300~~395.78 million for ~~2022~~2023 compared to $~~251~~300.67 million for ~~2021~~2022 due to an increase in our annual weighted average outstanding debt balance from $5.6 ~~billion in 2021 to $6~~.8 billion in 2022. ~~Our~~to ~~outstanding debt totaled~~ $87.29 billion atin ~~December~~2023 ~~31,~~coupled ~~2022,~~with ~~reflecting~~ an increase ~~of $1.9 billion~~ in the ~~2022~~variable ~~fourth~~interest ~~quarter~~rates ~~due~~incurred toon outstanding credit facility and term loan borrowings. ~~incurred~~Our tooutstanding ~~fund~~debt atotaled ~~portion~~$6.6 ofbillion ~~the~~at ~~November~~December ~~2022~~31, ~~take-private transaction~~2023.

~~Gain~~Income ~~(loss)~~Taxes. onWe ~~extinguishment~~provided for income taxes at a combined federal and state tax rate of ~~debt~~23.5% ~~See~~for ~~Part~~both ~~II,~~2023 ~~Item~~and 82022. ~~Notes~~We torecorded ~~Consolidated~~income ~~Financial~~tax ~~Statements—Note~~provisions 8of $827.6 ~~Long-Term~~million ~~Debt~~and ~~for~~$1.02 ~~discussion~~billion offor ~~gains~~2023 and ~~losses~~2022, ~~recognized~~respectively, onwhich ~~debt~~resulted ~~extinguishments~~ in ~~2022~~effective ~~and~~tax ~~2021.~~rates of

Income Taxes. We provided for income taxes at a combined federal and state tax rate of 23.5% for 2022 and 24.5% for 2021. We recorded income tax provisions of $1.02 billion and $519.7 million for 2022 and 2021, respectively, which resulted in effective tax rates of 20.1% and 23.8%, respectively, after taking into account the application of statutory tax rates, permanent taxable differences, tax credits, tax effects from equity/incentive compensation, changes in valuation allowances, and other items. See Part II, Item 8. Notes to Consolidated Financial Statements—Note 11. Income Taxes for a summary of the sources and tax effects of items comprising our income tax provision and resulting effective tax rates for 2022 and 2021. 28

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21.1% and 20.1%, respectively, after taking into account the application of statutory tax rates, permanent taxable differences, estimated tax credits, and other items. See Part II, Item 8. Notes to Consolidated Financial Statements—Note 11. Income Taxes for a summary of the sources and tax effects of items comprising our income tax provision and resulting effective tax rates for 2023 and 2022.

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.

AsAt ~~previously~~February ~~described~~1, ~~on November 22~~2024, ~~2022~~we ~~the~~had ~~Hamm~~approximately ~~Family completed a tender offer to purchase any and all of the outstanding shares of the Company’s common stock for~~ $742.282 ~~per~~billion ~~share~~of inborrowing ~~cash,~~availability ~~other~~under ~~than:~~our ~~(i)~~credit ~~shares~~facility ofafter ~~common~~considering ~~stock~~outstanding ~~owned~~borrowings ~~by the Hamm Family~~ and ~~(ii)~~letters ~~shares~~ of ~~common stock underlying unvested equity awards issued pursuant to the Company’s long-term incentive plans~~credit. AOur ~~total~~credit offacility, ~~approximately~~which ~~58.1~~is ~~million~~unsecured ~~shares~~and ofhas ~~Continental’s~~no ~~common~~borrowing ~~stock~~base ~~were~~subject ~~purchased pursuant~~ to ~~the take-private transaction for total cash consideration of approximately $4.31 billion~~redetermination, ~~inclusive~~does ofnot ~~payments~~mature ~~issued~~until toOctober ~~holders who demanded appraisal rights for their untendered shares in accordance with Oklahoma law~~2026.

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The purchase of outstanding shares was funded by Continental through the use of approximately $2.2 billion of cash on hand, $1.3 billion of credit facility borrowings, and the execution of a $750 million three-year term loan. As a result of the transaction, the Company’s leverage has increased and its liquidity has decreased. We remain committed to operating in a responsible manner to preserve financial flexibility, liquidity, and the strength of our balance sheet.

At February 1, 2023, we had approximately $1.12 billion of borrowing availability under our credit facility after considering outstanding borrowings and letters of credit. Our credit facility, which is unsecured and has no borrowing base subject to redetermination, does not mature until October 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 subsequently described under the heading Future Capital Requirements, recognizing we may be required to meet such commitments even if our business plan assumptions were to change. We monitor our capital spending closely based on actual and projected cash flows and have the ability to reduce spending or dispose of assets if needed to preserve liquidity and financial flexibility to fund our operations.

Cash Flows

Cash flows from operating activities

Net cash provided by operating activities ~~increased~~decreased $32.10 billion, or 7728%, to $75.0406 billion for ~~2022~~2023 compared to $37.9704 billion for ~~2021~~2022. ~~primarily~~The ~~due~~decrease towas driven by a $42.2839 billion ~~increase~~decrease in crude oil, natural gas, and NGL revenues due to the previously described ~~increases~~decrease in commodity prices and increases in certain other cash operating expenses associated with increased sales volumes inand the ~~current~~growth of our Company over the past year. ~~This~~Increased ~~increase~~cash ~~was~~operating ~~partially~~expenses ~~offset~~included by a $~~308~~96 million increase in ~~realized~~production ~~cash~~expenses, ~~losses~~a on$22 ~~matured~~million ~~commodity~~increase ~~derivatives~~in transportation, gathering, processing, and compression expenses, a $~~470~~108 million increase in cash ~~payments~~paid for ~~U.S. federal income taxes~~interest, a $~~326~~96 million increase in ~~production~~cash ~~and~~payments adfor ~~valorem~~income taxes ~~associated with higher revenues~~, and ~~increases~~$130 inmillion ~~certain~~of ~~other~~ cash ~~operating~~payments ~~expenses~~for ~~primarily~~vested ~~due~~incentive tocompensation anawards. ~~increase~~These inincreases ~~sales~~were ~~volumes~~partially ~~and~~offset ~~growth~~by ofa ~~our~~$715 ~~Company~~million ~~over~~improvement ~~the~~in ~~past~~realized ~~year.~~cash ~~Increased~~settlements ~~cash~~on ~~operating~~matured ~~expenses~~commodity ~~included~~derivatives and a $~~215~~127 million ~~increase~~decrease in production ~~expenses~~ and aad ~~$91~~valorem ~~million~~taxes ~~increase~~associated inwith ~~transportation,~~lower ~~gathering, processing, and compression expenses~~revenues.

Cash flows used in investing activities

Net cash used in investing activities totaled $3.5356 billion ~~and~~for 2023, consistent with $43.9953 billion for 2022. ~~and~~Our ~~2021,~~investing ~~respectively,~~cash ~~the~~flows ~~decrease~~for of2023 ~~which~~included ~~reflects~~$3.55 abillion ~~reduction~~of inexploration ~~the~~and ~~magnitude~~development ofcosts ~~property~~compared ~~acquisitions~~to ~~between~~$2.84 ~~periods~~billion asof ~~discussed~~exploration inand ~~Part~~development ~~II,~~costs ~~Item~~for 8.2022, ~~Notes~~reflecting toa ~~Consolidated~~planned ~~Financial~~increase ~~Statements—Note~~in 2.budgeted ~~Property Acquisitions~~spending. ~~Cash~~This ~~capital~~increase ~~expenditures~~in ~~excluding~~spending ~~acquisitions~~was ~~totaled~~partially ~~$2.6~~offset ~~billion~~by ~~and~~lower ~~$1.4~~acquisitions ~~billion~~of ~~for~~producing ~~2022~~crude oil and ~~2021,~~natural ~~respectively~~gas properties, ~~the~~with ~~increase~~$161 ofmillion ~~which~~acquired ~~reflects~~in ~~our~~2023 ~~planned~~compared ~~increase~~to in$422 ~~budgeted~~million ~~spending~~acquired in 2022~~. Additionally~~, ~~investing~~as ~~cash~~well ~~flows~~as ~~for~~increased ~~2022~~proceeds ~~include~~from the sale of assets with $~~210~~390 million ~~paid~~of ~~for~~proceeds ~~our~~received ~~new~~in ~~strategic~~2023 ~~investment~~compared into an$6 ~~affiliate~~million of ~~Summit~~proceeds ~~Carbon~~received ~~Solutions~~in ~~described~~2022. inAdditionally, ~~Note~~contributions ~~18.~~to ~~Equity~~unconsolidated ~~Investment~~affiliates ~~with~~decreased no$178 ~~similar~~million ~~contributions~~from $212 million in ~~2021.~~2022 to $34 million in 2023.

Cash flows from financing activities

Net cash used in financing activities for 2023 totaled $1.61 billion, primarily consisting of $950 million of net repayments on our credit facility, $636 million of cash used to redeem senior notes and $31 million of cash distributed to noncontrolling interests.

Net cash used in financing activities for 2022 totaled $3.39 billion, primarily consisting of $4.3 billion of cash used to fund the Hamm Family's take-private transaction, $284 million of cash dividends paid on common stock, $100 million of cash used to repurchase shares of our common stock prior to the take-private transaction, and $32 million of cash used to repurchase senior notes. These cash outflows were partially offset by $660 million of net borrowings on our credit facility and $750 million of proceeds from the issuance of a new term loan to fund a portion of the take-private transaction.

Net cash provided by financing activities for 2021 totaled $989.1 million, primarily resulting from $1.59 billion of net proceeds received from our November 2021 issuance of senior notes and $340 million of net credit facility borrowings incurred to fund a portion of our December 2021 Permian Basin acquisition. These increases were partially offset by $631 million of senior note redemptions during 2021, $124 million of cash used to repurchase shares of our common stock, and $166 million of cash dividends paid on common stock.29

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Future Sources of Financing

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

Based on current market indications supported by cash flow protection provided by our hedge portfolio against commodity price declines, our budgeted capital spending plans for ~~2023~~2024 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.

37We 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.

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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 and business plans.

We may choose to access banking or 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. ~~As of February 1, 2023, we had $1.12 billion of borrowing availability on our credit facility after considering outstanding borrowings and letters of credit.~~

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. ~~Downgrades of our credit rating will, however, trigger increases in our credit facility's interest rates and commitment fees paid on unused borrowing availability under certain circumstances.~~

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 Part II, Item 8. Notes to Consolidated Financial Statements—Note 8. ~~Long-Term~~ 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 December 31, ~~2022~~2023 and expect to maintain compliance. At December 31, ~~2022~~2023, our consolidated net debt to total capitalization ratio was 0.5037. 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 December 31, ~~2022~~2023, 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 $65.37 billion at December 31, ~~2022~~2023, 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 $~~636~~893 million of ~~2023~~2024 Notes due in ~~April~~June ~~2023~~2024, which is reflected as a current liability in the caption “Current portion of long-term debt” in the consolidated balance sheets as of December 31, ~~2022~~2023. We expect to befully ~~able~~redeem toour ~~generate~~2024 orNotes ~~obtain~~by ~~sufficient~~the ~~funds~~maturity ~~necessary~~date tousing ~~fully~~a ~~redeem~~combination ~~our~~of ~~2023~~available ~~Notes~~cash byflows ~~the~~and ~~maturity~~utilization ~~date~~of credit facility borrowing capacity if necessary. 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 8. ~~Long-Term~~ Debt in Part II, Item 8. Notes to Consolidated Financial Statements.

We were in compliance with our senior note covenants at December 31, ~~2022~~2023 and expect to maintain compliance. We do not believe the senior note covenants will materially limit our ability to undertake additional debt financing. Downgrades or other negative rating actions with respect to the credit ratings assigned to our senior unsecured debt do not trigger additional senior note covenants.

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Credit facility borrowings

As of February 1, ~~2023~~2024, we had $~~1.14~~10 ~~billion~~million of outstanding borrowings on our credit facility. Our credit facility matures in October 2026.

Term loan

InWe ~~November~~have ~~2022,~~a ~~we borrowed~~ $750 million ~~under~~term aloan ~~three-year~~that matures in November 2025. The covenant requirements in the term loan ~~agreement~~are consistent with the covenants in our revolving credit facility, including the ~~proceeds~~requirement ofthat ~~which~~we ~~were~~maintain ~~used~~a consolidated net debt to ~~fund~~total acapitalization ~~portion~~ratio of ~~the~~no ~~Hamm~~greater ~~Family's~~than ~~November~~0.65 ~~2022~~to ~~take-private transaction~~1.0. ~~The~~We were in compliance with the term loan ~~matures~~covenants inat ~~November~~December ~~2025~~31, 2023 and ~~bears~~expect ~~interest~~to atmaintain 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.

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market-based interest rates plus a margin based on the terms of the borrowing and the credit ratings assigned to the Company's senior, unsecured, long-term indebtedness.

The 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 December 31, 2022 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. Downgrades of our credit rating will, however, trigger an increase in our term loan's interest rate.

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 December 31, ~~2022~~2023 under the arrangements amount to approximately $~~1.14~~824 ~~billion~~million. See Part II, Item 8. Notes to Consolidated Financial Statements—Note 13. Commitments and Contingencies for additional information.

Capital Expenditures

~~2022~~2023 Capital Spending

For the year ended December 31, ~~2022~~2023, we invested $23.7025 billion in our capital program excluding $~~716~~681.62 million of unbudgeted acquisitions, excluding $129.07 million of mineral acquisitions attributable to Franco-Nevada, and including $~~102~~22.13 million of capital costs associated with increased accruals for capital expenditures as compared to December 31, ~~2021~~2022. Our ~~2022~~2023 capital expenditures were allocated as ~~follows~~shown byin ~~quarter.~~the ~~See~~table ~~Part II, Item 8~~below. ~~Notes to Consolidated Financial Statements—Note 2. Property Acquisitions for discussion of our notable property acquisitions executed in 2022.~~

In millions	~~1Q 2022~~2023		~~2Q 2022~~		~~3Q 2022~~		~~4Q 2022~~		~~Total 2022~~
Exploration and development drilling	$	~~426.~~2,734.9	$	~~504.7~~	$	~~686.0~~	$	~~576.6~~	$	~~2,193.5~~
Land costs		24134.36		~~31.2~~		~~30.6~~		~~55.5~~		~~141.6~~
Mineral acquisitions attributable to Continental		02.54		~~0.4~~		~~1.0~~		~~1.0~~		~~2.9~~
Capital facilities, workovers, water infrastructure, and other corporate assets		72381.35		~~110.9~~		~~97.4~~		~~81.2~~		~~361.8~~
Seismic		0.6		1.3		0.9		0.4		3.2
Capital expenditures attributable to Continental, excluding unbudgeted acquisitions	$	3,253.4
Capital expenditures attributable to Continental, excluding unbudgeted acquisitions	$	523.9	$	648.5	$	815.9	$	714.7	$	2,703.0
Unbudgeted acquisitions		681.2
Unbudgeted acquisitions		443.1		219.2		43.1		11.2		716.6
Total capital expenditures attributable to Continental	$	3,934.6
Total capital expenditures attributable to Continental	$	967.0	$	867.7	$	859.0	$	725.9	$	3,419.6
Mineral acquisitions attributable to Franco-Nevada		9.7
Mineral acquisitions attributable to Franco-Nevada		1.9		1.8		4.2		4.1		12.0
Total capital expenditures	$	3,944.3
Total capital expenditures	$	968.9	$	869.5	$	863.2	$	730.0	$	3,431.6

~~2023~~2024 Capital Expenditures Budget

For ~~2023~~2024, our capital expenditures budget attributable to us is ~~expected to be~~ $3.254 billion. Costs of acquisitions and investments, such as those described in Note 18. Equity Investment in Part II, Item 8. Notes to Consolidated Financial Statements, are not included in our ~~2023~~2024 capital budget, with the exception of planned levels of spending for mineral acquisitions.

Our drilling and completion activities and the actual amount and timing of our capital expenditures may differ materially from our budget as a result of, among other things, available cash flows, unbudgeted acquisitions, actual drilling and completion results, operational process improvements, the availability of drilling and completion rigs and other services and equipment, cost inflation, the 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.

Strategic Investment

See Note 18. Equity Investment in Part II, Item 8. Notes to Consolidated Financial Statements for discussion of future spending commitments associated with a strategic investment made by the Company with Summit Carbon Solutions beginning in 2022.

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Cash Payments for Income Taxes

For the year ended December 31, ~~2022~~2023, we made ~~estimated~~cash ~~quarterly~~ payments for ~~2022~~federal ~~U.S.~~and ~~federal~~state income taxes totaling $~~470~~566 million, ~~based~~representing onpayments anassociated ~~estimate~~with of2022 tax return filing extensions and estimated quarterly payments for 2023 federal and state income taxes based on estimates of taxable income for ~~the year~~2023. 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 2023, which would result in us continuing to make estimated tax payments on a quarterly basis in 2023 that could approximate the payments made in 2022. 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.

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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 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

As discussed in Note 15. Incentive Compensation in Part II, Item 8. Notes to Consolidated Financial Statements we have recognized a current liability of $130.6 million and a non-current liability of $41.7 million in the consolidated balance sheets associated with unvested incentive compensation awards granted to employees that are scheduled to vest in 2024, 2025, and 2026. We intend to settle these awards in cash at the time vesting occurs. Our recognized liabilities 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. The current liability at December 31, 2023 was paid in cash to employees in February 2024 upon the scheduled vesting of awards. We intend to grant additional awards on an annual basis that we plan to settle in cash upon vesting.

Delivery Commitments

We have various natural gas volume delivery commitments that are related to our key operating areas. We expect to primarily fulfill our contractual natural gas obligations with production from our proved reserves. However, we may purchase third-party volumes to satisfy our commitments. Additionally, in the Permian Basin certain of our firm sales contracts for crude oil include delivery commitments that specify the delivery of a fixed and determinable quantity. We expect to primarily fulfill our contractual crude oil obligations with production from our proved reserves. As of December 31, ~~2022~~2023, we were committed to deliver the following fixed quantities of natural gas and crude oil production. The volumes disclosed herein represent gross production associated with properties operated by us and do not reflect our net proportionate share of such amounts.

Year Ending	Natural Gas		Crude Oil
December 31,	Bcf		MMBo
2023		167		13
2024		126		13
2024		119		3
2025		74		3
2025		70		—
2026		38		—
2027		4		—

Derivative Instruments

See Note 6. Derivative Instruments in Part II, Item 8. Notes to Consolidated Financial Statements for discussion of our hedging activities, including a summary of derivative contracts in place as of December 31, 2022. Between January 1, 2023 and February 17, 2023 we entered into additional derivative instruments as summarized in the tables below.

Natural gas derivatives
Period and Type of Contract	Average Volumes Hedged			Weighted Average Hedge Price ($/MMBtu)
April 2023 - December 2023
Swaps - Henry Hub		210,000	MMBtus/day	$	3.89
July 2023 - September 2024
Swaps - WAHA		22,000	MMBtus/day	$	2.64
January 2024 - December 2024
Swaps - Henry Hub		172,400	MMBtus/day	$	3.71
January 2025 - December 2025
Swaps - Henry Hub		180,000	MMBtus/day	$	3.99
January 2026 - December 2026
Swaps - Henry Hub		150,000	MMBtus/day	$	4.03

Crude oil derivatives
Period and Type of Contract	Average Volumes Hedged			Weighted Average Hedge Price ($/Bbl)
April 2023 - March 2024
Swaps - WTI		52,000	Bbls/day	$	77.92

Senior note repurchases and redemptions

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 fully redeem our 2024 Notes by the maturity date using a combination of available cash flows and utilization of credit facility borrowing capacity if necessary.

40Derivative Instruments

The fair value of our derivative instruments at December 31, 2023 was a net asset of $508 million. See Note 6. Derivative Instruments in Part II, Item 8. Notes to Consolidated Financial Statements for further discussion of our hedging activities, including a summary of derivative contracts in place as of December 31, 2023. 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 7A. 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 December 31, 2023.

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aggregate, may be material. Our $636 million of 2023 Notes is due in April 2023. We expect to be able to generate or obtain sufficient funds necessary to fully redeem our 2023 Notes by the maturity date.

Critical Accounting Policies and Estimates

Our consolidated financial statements and related footnotes contain information that is pertinent to our management’s discussion and analysis of financial condition and results of operations. The preparation of financial statements in conformity with generally accepted accounting principles requires management to select appropriate accounting policies and to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses, and the disclosure and estimation of contingent assets and liabilities. See Part II, Item 8. Notes to Consolidated Financial Statements—Note 1. Organization and Summary of Significant Accounting Policies and Note 9. Revenues for descriptions of our major accounting policies. Certain of these accounting policies involve judgments and uncertainties to such an extent that there is a reasonable likelihood that materially different amounts could have been reported under different conditions or if different assumptions had been used.

In management’s opinion, the most significant reporting areas impacted by management’s judgments and estimates are crude oil and natural gas reserve estimations, revenue recognition, the choice of accounting method for crude oil and natural gas activities and derivatives, impairment of assets, income taxes and contingent liabilities. These areas are discussed below. Management’s judgments and estimates in these areas are based on information available from both internal and external sources, including engineers, geologists and historical experience in similar matters and are believed to be reasonable under the circumstances. We evaluate our estimates and assumptions on a regular basis. Actual results could differ from the estimates as additional information becomes known.

Crude Oil and Natural Gas Reserves Estimation ~~and Standardized Measure of Future Cash Flows~~

Our external independent reserve engineers, Ryder Scott, and internal technical staff prepare the estimates of our crude oil and natural gas reserves and associated future net cash flows. Even though Ryder Scott and our internal technical staff are knowledgeable and follow authoritative guidelines for estimating reserves, they must make a number of subjective assumptions based on professional judgments in developing the reserve estimates. Estimates of reserves and their values, future production rates, and future costs and expenses are inherently uncertain for various reasons, including many factors beyond the Company’s control. Reserve estimates are updated by us at least semi-annually and take into account recent production levels and other technical information about each of our properties.

Crude oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be precisely measured. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Periodic revisions or removals of estimated reserves and future cash flows may be necessary as a result of a number of factors, including reservoir performance, new drilling, crude oil and natural gas prices, changes in costs, technological advances, new geological or geophysical data, changes in business strategies, or other economic factors. Accordingly, reserve estimates may differ significantly from the quantities of crude oil and natural gas ultimately recovered. ~~For the years ended December 31, 2022, 2021, and 2020, net upward (downward) revisions of our proved reserves totaled approximately (133) MMBoe, 54 MMBoe, and (505) MMBoe, respectively.~~ We cannot predict the amounts or timing of future reserve revisions or removals.

Estimates of proved reserves are key components of the Company’s most significant financial estimates including the computation of depreciation, depletion, amortization and impairment of proved crude oil and natural gas properties. Holding all other factors constant, if proved reserves are revised downward, the rate at which we record DD&A expense would increase, reducing net income. Conversely, if proved reserves are revised upward, the rate at which we record DD&A expense would decrease. Future revisions of reserves may be material and could significantly alter future depreciation, depletion, and amortization expense and may result in material impairments of assets.

Our DD&A calculations for oil and gas properties are performed on a field basis and revisions to proved reserves will not necessarily be applied ratably across all fields and may not be applied to some fields at all. Further, reserve revisions in significant fields may individually affect our DD&A rate. As a result, the impact on DD&A expense from revisions in reserves cannot be predicted with certainty and may result in changes in expense that are greater or less than the underlying changes in reserves.

Revenue Recognition

We derive substantially all of our revenues from the sale of crude oil, natural gas, and NGLs. See Part II, Item 8. Notes to Consolidated Financial Statements—Note 9. Revenues for discussion of our accounting policies governing the recognition and presentation of revenues.

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Operated crude oil, natural gas, and NGL revenues are recognized during the month in which control transfers to the customer and it is probable the Company will collect the consideration it is entitled to receive. For non-operated properties, the Company's proportionate share of production is generally marketed at the discretion of the operators. Non-operated revenues are recognized by the Company during the month in which production occurs and it is probable the Company will collect the consideration it is entitled to receive.

At the end of each month, to record revenues we estimate the amount of production delivered and sold to customers and the prices at which they were sold. Variances between estimated revenues and actual amounts received for all prior months are recorded in the ~~month payment is received and are reflected in our financial statements as crude oil and natural gas sales. These variances have historically not been material.~~

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month payment is received and are reflected in our financial statements as crude oil and natural gas sales. These variances have historically not been material.

For the sale of crude oil, natural gas, and NGLs we evaluate whether we are the principal, and report revenues on a gross basis (revenues presented separately from associated expenses), or an agent, and report revenues on a net basis. In this assessment, we consider if we obtain control of the products before they are transferred to the customer as well as other indicators. Judgment may be required in determining the point in time when control of products transfers to customers.

Successful Efforts Method of Accounting

Our business is subject to accounting rules that are unique to the crude oil and natural gas industry. Two generally accepted methods of accounting for oil and gas activities are available—the successful efforts method and the full cost method. The most significant differences between these two methods are the treatment of exploration costs and the manner in which the carrying value of oil and gas properties are amortized and evaluated for impairment. We use the successful efforts method of accounting for our oil and gas properties. See Part II, Item 8. Notes to Consolidated Financial Statements—Note 1. Organization and Summary of Significant Accounting Policies for further discussion of the accounting policies applicable to the successful efforts method of accounting.

Derivative Activities

From time to time we utilize derivative contracts to hedge against the variability in cash flows associated with the forecasted sale of future production and for other purposes. We have elected not to designate any of our price risk management activities as cash flow hedges. As a result, we mark our derivative instruments to fair value and recognize the changes in fair value in current earnings.

In determining the amounts to be recorded for outstanding derivative contracts, we are required to estimate the fair value of the derivatives. We use an independent third party to provide our derivative valuations. The third party’s valuation models for derivative contracts are industry-standard models that consider 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. The fair value calculations for collars requires the use of an option-pricing model. The estimated future prices are compared to the prices fixed by the derivative agreements and the resulting estimated future cash inflows or outflows over the lives of the derivatives are discounted to calculate the fair value of the derivative contracts. These pricing and discounting variables are sensitive to market volatility as well as changes in future price forecasts and interest rates.

We validate our derivative valuations through management review and by comparison to our counterparties’ valuations for reasonableness. Differences between our fair value calculations and counterparty valuations have historically not been material.

Impairment of Assets

All of our long-lived assets are monitored for potential impairment when circumstances indicate the carrying value of an asset may be greater than its future net cash flows, including cash flows from risk-adjusted proved reserves. Risk-adjusted probable and possible reserves may be taken into consideration when determining estimated future net cash flows and fair value when such reserves exist and are economically recoverable.

Proved crude oil and natural gas properties are reviewed for impairment on a field-by-field basis. If the carrying amount of a field exceeds its estimated undiscounted future cash flows, the carrying amount of the field is reduced to its estimated fair value using a discounted cash flow model. For producing properties, the impairment evaluations involve a significant amount of judgment since the results are based on estimated future events, such as future sales prices for crude oil and natural gas, future costs to produce those products, estimates of future crude oil and natural gas reserves to be recovered and the timing thereof, the economic and regulatory climates and other factors. The need to test a field for impairment may result from significant declines in sales prices or downward revisions or removals of crude oil and natural gas reserves. Estimates of anticipated sales prices and recoverable reserves are highly judgmental and are subject to material revision in future periods.

Impairment provisions for proved properties totaled $1715.5 million for the year ended December 31, ~~2022~~2023. Commodity price assumptions used for the year-end December 31, ~~2022~~2023 impairment calculations were based on publicly available average annual forward commodity strip prices through year-end 2028 and were then escalated at 3% per year thereafter. Holding all other factors constant, as forward commodity prices decrease, our probability for recognizing producing property impairments may increase, or the magnitude of impairments to be recognized may increase. Conversely, as forward commodity prices increase, our probability for recognizing producing property impairments may decrease, or the magnitude of impairments to be recognized may decrease or be eliminated. As of December 31, 2023 , the publicly available forward commodity strip prices for the year 2028 used in our fourth quarter impairment calculations averaged $61.94 per barrel for crude oil and $3.80 per Mcf for natural gas. If forward commodity prices materially decrease from current levels for an extended period, impairments of producing properties may be recognized in the

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forward commodity strip prices through year-end 2027 and were then escalated at 3% per year thereafter. Holding all other factors constant, as forward commodity prices decrease, our probability for recognizing producing property impairments may increase, or the magnitude of impairments to be recognized may increase. Conversely, as forward commodity prices increase, our probability for recognizing producing property impairments may decrease, or the magnitude of impairments to be recognized may decrease or be eliminated. As of December 31, 2022, the publicly available forward commodity strip prices for the year 2027 used in our fourth quarter impairment calculations averaged $63.87 per barrel for crude oil and $4.50 per Mcf for natural gas. If forward commodity prices materially decrease from current levels for an extended period, impairments of producing properties may be recognized in the future. Because of the uncertainty inherent in the numerous factors utilized in determining the fair value of producing properties, we cannot predict the timing and amount of future impairment charges, if any.

Impairment losses for unproved properties are generally recognized by amortizing the portion of the properties’ costs which management estimates will not be transferred to proved properties over the lives of the leases based on drilling plans, experience of successful drilling, and the average holding period. The impairment assessments are affected by economic factors such as the results of exploration activities, commodity price outlooks, anticipated drilling programs, remaining lease terms, and potential shifts in business strategy employed by management. The estimated timing and rate of successful drilling is highly judgmental and is subject to material revision in future periods as better information becomes available.

Income Taxes

Income taxes are accounted for using the asset and liability method. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.

In assessing the realizability of deferred tax assets, management must consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. We apply judgment to determine the weight of both positive and negative evidence in order to conclude whether a valuation allowance is necessary for our deferred tax assets. In determining whether a valuation allowance is required, we consider, among other factors, our financial position, results of operations, projected future taxable income, reversal of existing deferred tax liabilities against deferred tax assets, and tax planning strategies. Significant judgment is involved in this determination as we are required to make assumptions about future commodity prices, projected production, development activities, profitability of future business strategies and forecasted economics in the oil and gas industry. Additionally, changes in the effective tax rate resulting from changes in tax law and our level of earnings may limit utilization of deferred tax assets and may affect the valuation of deferred tax balances in the future. Changes in judgment regarding future realization of deferred tax assets may result in a reversal of all or a portion of ~~the~~a valuation allowance. We believe our deferred tax assets at December 31, ~~2022~~2023 will ultimately be realized. We will continue to evaluate both the positive and negative evidence on a quarterly basis in determining the need for a valuation allowance with respect to our deferred tax assets.

We make certain estimates and judgments in determining our income tax expense for financial reporting purposes. Our federal and state income tax returns are generally not prepared or filed before our consolidated financial statements are prepared; therefore, we estimate the tax basis of our assets and liabilities at the end of each period as well as the effects of tax rate changes, tax credits, and net operating loss carryforwards, among other things. Adjustments related to these estimates are recorded in our tax provision in the period in which we file our income tax returns. Accordingly, our effective tax rate is subject to variability from period to period as a result of factors other than changes in federal and state tax rates and/or changes in tax laws which can affect tax-paying companies. For instance, our effective tax rate is affected by, among other things, permanent taxable differences, tax credits, valuation allowances, and changes in the apportionment of property, revenues, and payroll between states in which we own property as rates vary from state to state, all of which could have a material effect on current period earnings.

Contingent Liabilities

A provision for legal, environmental and other contingencies is charged to expense when a loss is probable and the loss or range of loss can be reasonably estimated. Determining when liabilities and expenses should be recorded for these contingencies and the appropriate amounts of accruals is subject to an estimation process that requires subjective judgment of management. In certain cases, management’s judgment is based on the advice and opinions of legal counsel and other advisers, the interpretation of laws and regulations which can be interpreted differently by regulators and/or courts of law, the experience of the Company and other companies dealing with similar matters, and management’s decision on how it intends to respond to a particular matter; for example, a decision to contest it vigorously or a decision to seek a negotiated settlement. Actual losses can differ from estimates for various reasons, including differing interpretations of laws and opinions and assessments on the amount of damages. We closely monitor known and potential legal, environmental and other contingencies and make our best estimate of when or if to record liabilities and losses for matters based on available information.

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Legislative and Regulatory Developments

The crude oil and natural gas industry in the United States is subject to various types of regulation at the federal, state and local levels. President Biden, in pursuit of his regulatory agenda, has issued, and may continue to issue, executive orders that result in more stringent and costly requirements for the domestic crude oil and natural gas industry and there is the potential for the revision of existing laws and regulations or the adoption of new legislation that could adversely affect the oil and gas industry. Such changes, if enacted, could have a material adverse effect on our results of operations and cash flows. See Part I, Item 1. Business—Regulation of the Crude Oil and Natural Gas Industry for a discussion of significant laws and regulations that have been enacted or are currently being considered by regulatory bodies that may affect us in the areas in which we operate.

~~Inflation Reduction Act~~35

InTable ~~August 2022, President Biden signed the Inflation Reduction Act~~ of ~~2022~~Contents (“IRA”) into law, which provides various new tax provisions, incentives, and tax credits aimed at curbing inflation by lowering prescription drug costs, health care costs, and energy costs. The IRA introduces, among other things, (i) a 15% corporate alternative minimum tax on profits for corporations whose average annual adjusted financial statement income for any consecutive three-year period ending after December 31, 2021 exceeds $1 billion, (ii) a methane emissions charge, effective January 1, 2024, on specific types of oil and gas production facilities that report emissions in excess of applicable thresholds, and (iii) various updates to Section 45Q of the Internal Revenue Code to incentivize development of carbon sequestration projects such as our investment in the carbon capture project being developed by Summit Carbon Solutions, including increasing the value of Section 45Q tax credits, expanding eligibility for Section 45Q tax credits by extending project construction deadlines, and allowing taxpayers to elect for direct payment of Section 45Q tax credits.

~~We are in~~ the ~~process~~Crude ofOil ~~evaluating the new IRA legislation~~ and ~~are~~Natural ~~unable~~Gas toIndustry estimate its future impact on our business at this time. Based on current expectations, we expect our average annual adjusted financial statement income over the three-year period including 2020, 2021, and 2022 will exceed the IRA's $1 billion threshold and, therefore, we expect to be subject to the 15% alternative minimum tax regime for ~~the~~a ~~2023~~summary ~~tax year. Because~~ of ~~the~~ significant ~~uncertainty~~laws ~~inherent in numerous factors utilized in projecting financial statement income~~ and ~~taxable~~regulations ~~income,~~that ~~including~~may ~~those~~affect ~~pertaining~~us toin ~~future~~the ~~commodity~~areas ~~prices,~~in ~~production,~~which ~~capital spending, profitability, and general economic conditions,~~ we ~~cannot predict what impact the minimum tax will have, if any, on our future operating results and cash flows with certainty~~operate.

Inflation

~~The~~Inflationary ~~general~~pressures ~~rate~~experienced ~~of inflation has increased~~ in ~~conjunction~~recent ~~with~~years ~~overall~~may ~~imbalances~~continue in ~~supply and demand recoveries from the COVID-19 pandemic~~2024. Some of the underlying factors impacting inflation may include, but are not limited to, global supply chain disruptions, shipping bottlenecks, labor market constraints, and side effects from monetary and fiscal expansions. ~~Inflationary pressures are expected to continue in 2023.~~ If these inflationary pressures persist or worsen, ~~and commodity prices continue to remain at attractive levels that stimulate increased industry activity,~~ we may ~~face~~incur ~~shortages~~additional ofcosts ~~service~~for ~~providers,~~ equipment, and materials., ~~Such~~and ~~shortages~~from ~~could~~service ~~result in increased competition which may lead to further increases in costs~~providers. Our budgeted expenditures include an estimate for the impact of cost inflation and, despite inflationary pressures, we expect to continue generating significant amounts of free cash flow at current commodity price levels.

~~Non-GAAP Financial Measures~~36

Net crude oil and natural gas sales and net sales prices

Revenues and transportation expenses associated with production from our operated properties are reported separately as discussed in Part II, Item 8. Notes to Consolidated Financial Statements—Note 9. Revenues. For non-operated properties, we receive a net payment from the operator for our share of sales proceeds which is net of costs incurred by the operator, if any. 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 NGL 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.

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The following table presents a reconciliation of total Company 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 2022, 2021, and 2020.

Total Company	Year Ended December 31, 2022									Year Ended December 31, 2021									Year Ended December 31, 2020
In thousands	Crude oil			Natural gas and NGLs			Total			Crude oil			Natural gas and NGLs			Total			Crude oil			Natural gas and NGLs			Total
Crude oil, natural gas, and NGL sales (GAAP)	$	6,906,003		$	3,168,672		$	10,074,675		$	3,949,294		$	1,844,447		$	5,793,741		$	2,199,976		$	355,458		$	2,555,434
Less: Transportation expenses		(253,981	)		(62,433	)		(316,414	)		(185,130	)		(39,859	)		(224,989	)		(158,989	)		(37,703	)		(196,692	)
Net crude oil, natural gas, and NGL sales (non-GAAP)	$	6,652,022		$	3,106,239		$	9,758,261		$	3,764,164		$	1,804,588		$	5,568,752		$	2,040,987		$	317,755		$	2,358,742
Sales volumes (MBbl/MMcf/MBoe)		72,732			442,980			146,562			58,757			370,110			120,442			58,793			306,528			109,881
Net sales price (non-GAAP)	$	91.46		$	7.01		$	66.58		$	64.06		$	4.88		$	46.24		$	34.71		$	1.04		$	21.47

The following tables present reconciliations 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 North Dakota Bakken, SCOOP, and the Permian Basin for 2022, 2021, and 2020 as presented in Part I, Item 1. Business—Crude Oil and Natural Gas Operations—Production and Price History.

North Dakota Bakken	Year Ended December 31, 2022									Year Ended December 31, 2021									Year Ended December 31, 2020
In thousands	Crude oil			Natural gas and NGLs			Total			Crude oil			Natural gas and NGLs			Total			Crude oil			Natural gas and NGLs			Total
Crude oil, natural gas, and NGL sales (GAAP)	$	3,768,200		$	1,033,098		$	4,801,298		$	2,695,738		$	549,932		$	3,245,670		$	1,469,450		$	24,714		$	1,494,164
Less: Transportation expenses		(183,471	)		(15,573	)		(199,044	)		(154,359	)		(4,831	)		(159,190	)		(127,036	)		(2,580	)		(129,616	)
Net crude oil, natural gas, and NGL sales (non-GAAP)	$	3,584,729		$	1,017,525		$	4,602,254		$	2,541,379		$	545,101		$	3,086,480		$	1,342,414		$	22,134		$	1,364,548
Sales volumes (MBbl/MMcf/MBoe)		39,871			124,411			60,606			40,186			120,517			60,272			40,040			97,532			56,295
Net sales price (non-GAAP)	$	89.91		$	8.18		$	75.94		$	63.24		$	4.52		$	51.21		$	33.53		$	0.23		$	24.24

SCOOP	Year Ended December 31, 2022									Year Ended December 31, 2021									Year Ended December 31, 2020
In thousands	Crude oil			Natural gas and NGLs			Total			Crude oil			Natural gas and NGLs			Total			Crude oil			Natural gas and NGLs			Total
Crude oil, natural gas, and NGL sales (GAAP)	$	951,754		$	1,300,731		$	2,252,485		$	756,596		$	980,323		$	1,736,919		$	486,076		$	246,125		$	732,201
Less: Transportation expenses		(3,027	)		(23,915	)		(26,942	)		(2,854	)		(23,808	)		(26,662	)		(5,275	)		(21,909	)		(27,184	)
Net crude oil, natural gas, and NGL sales (non-GAAP)	$	948,727		$	1,276,816		$	2,225,543		$	753,742		$	956,515		$	1,710,257		$	480,801		$	224,216		$	705,017
Sales volumes (MBbl/MMcf/MBoe)		10,063			185,755			41,022			11,341			179,553			41,267			12,694			136,410			35,429
Net sales price (non-GAAP)	$	94.28		$	6.87		$	54.25		$	66.46		$	5.33		$	41.44		$	37.88		$	1.64		$	19.90

Permian Basin	Year Ended December 31, 2022
In thousands	Crude oil			Natural gas and NGLs			Total
Crude oil, natural gas, and NGL sales (GAAP)	$	1,122,290		$	151,217		$	1,273,507
Less: Transportation expenses		(28,499	)		(6,594	)		(35,093	)
Net crude oil, natural gas, and NGL sales (non-GAAP)	$	1,093,791		$	144,623		$	1,238,414
Sales volumes (MBbl/MMcf/MBoe)		11,796			20,804			15,264
Net sales price (non-GAAP)	$	92.73		$	6.95		$	81.13

PV-10

Our PV-10 value, a non-GAAP financial measure, is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable financial measure computed using U.S. GAAP. PV-10 generally differs from Standardized Measure because it does not include the effects of income taxes on future net revenues. At December 31, 2022, our PV-10 totaled approximately $39.96 billion. The standardized measure of our discounted future net cash flows was approximately $31.91 billion at December 31, 2022, representing an $8.05 billion difference from PV-10 due to the effect of deducting estimated future income taxes in arriving at Standardized Measure. We believe the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to proved reserves held by companies without regard to the specific income tax characteristics of such entities and is a useful measure of evaluating the relative monetary significance of our crude oil and natural gas properties. Investors may utilize PV-10 as a basis for comparing the relative size and value of our proved reserves to other companies. PV-10 should not be considered as a substitute for, or more meaningful than, the Standardized Measure as determined in accordance with U.S. GAAP. Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of our crude oil and natural gas properties.

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Item 7A. 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 our 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 volatility in the differences between product prices at sales points and the applicable index prices. Based on our average daily production for the quarter ended December 31, ~~2022~~2023, and excluding any effect of our derivative instruments in place, our annual revenue would increase or decrease by approximately $~~746~~897 million for each $10.00 per barrel change in crude oil prices at December 31, ~~2022~~2023 and $~~468~~457 million for each $1.00 per Mcf change in natural gas prices at December 31, ~~2022~~2023.

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 for 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, may limit the downside risk of adverse price movements, it also may limit future revenues from upward price movements.

The fair value of our derivative instruments at December 31, ~~2022~~2023 was a net ~~liability~~asset of $~~178.7~~508 million, which is comprised of a $~~193.2~~355 million net ~~liability~~asset associated with our natural gas derivatives ~~partially~~and ~~offset by~~ a $~~14.5~~153 million net asset associated with our crude oil derivatives. The following table shows how a hypothetical +/- 10% change in the underlying forward prices used to calculate the fair value of our derivatives would impact the fair value estimates as of December 31, ~~2022~~2023.

		Hypothetical Fair Value
In thousands	Change in Forward Price	Asset (Liability)
Crude Oil	-10%	$	37347,~~210~~530
Crude Oil	+10%	$	(841,~~146~~267	)
Natural Gas	-10%	$	~~(63~~578,~~363~~959	)
Natural Gas	+10%	$	~~(323~~130,~~396~~894	)

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 crude oil and natural gas production, which we market to energy marketing companies, crude oil refining companies, and natural gas gathering and processing companies ($1.32 billion in receivables at December 31, ~~2022~~2023) and our joint interest and other receivables ($~~458~~351 million at December 31, ~~2022~~2023).

We monitor our exposure to counterparties on crude oil and natural gas 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 crude oil and natural gas sales receivables owed to us. Historically, our credit losses on crude oil and natural gas 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 $1637 million at December 31, ~~2022~~2023, which will be used to offset future capital costs when billed. In this manner, we reduce credit risk. We may have the right to place a lien on a co-owner’s interest in the well, to net production proceeds against amounts owed in order to secure payment or, if necessary, foreclose on the interest. Historically, our credit losses on joint interest receivables have been immaterial.

Interest Rate Risk. Our exposure to changes in interest rates relates to variable-rate borrowings we have outstanding under our credit facility and our $750 million term loan. Such borrowings bear interest at market-based interest rates plus a margin based on the terms

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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 $~~1.14~~10 ~~billion~~million of variable rate borrowings outstanding on our credit facility and $750 million of variable rate borrowings on our term loan at February 1, ~~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 $41.79 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.

The following table presents our debt maturities and the weighted average interest rates by expected maturity date as of December 31, ~~2022~~2023:

In thousands	~~2023~~2024			~~2024~~2025			~~2025~~2026			~~2026~~2027			~~2027~~2028			Thereafter			Total
Fixed rate debt:
Senior Notes:
Principal amount (1)	$	~~636~~893,~~000~~126		$	~~893,126~~—		$	—800,000		$	~~800,000~~—		$	—1,000,000		$	43,000,000		$	65,~~329~~693,126
Weighted-average interest rate		43.58	%		~~3.8~~—	%		—2.3	%		~~2.3~~—	%		—4.4	%		4.78	%		4.2	%
Notes payable:
Principal amount (1)	$	2,~~410~~495		$	2,~~495~~587		$	2,~~587~~681		$	2,~~681~~777		$	2,~~777~~876		$	74,~~175~~299		$	2017,~~125~~715
Interest rate		3.5	%		3.5	%		3.5	%		3.5	%		3.5	%		3.5	%		3.5	%
Variable rate debt:
Credit facility:
Principal amount	$	—		$	—		$	—210,000		$	~~1,160,000~~—		$	—		$	—		$	1210,~~160,~~000
Weighted-average interest rate		—			—			—7.0	%		~~5.9~~—	%		—			—			57.90	%
Term loan:
Principal amount	$	—		$	—750,000		$	~~750,000~~—		$	—		$	—		$	—		$	750,000
Interest rate		—			—			6.1	%		—			—			—			6.1	%
Weighted-average interest rate		—			7.0	%		—			—			—			—			7.0	%

(1)

Amounts represent scheduled maturities and do not reflect any discount or premium at which the notes were issued or any debt issuance costs.

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Item 8. Financial Statements and Supplementary Data

Index to Consolidated Financial Statements

Report of Independent Registered Public Accounting Firm	(PCAOB ID Number 248)	4940
Consolidated Balance Sheets as of December 31, 2022 and 2021		51
Consolidated Balance Sheets as of December 31, 2023 and 2022		42
Consolidated Statements of Income (Loss) for the Years Ended December 31, 2022, 2021 and 2020		52
Consolidated Statements of Income for the Years Ended December 31, 2023, 2022 and 2021		43
Consolidated Statements of Equity for the Years Ended December 31, 2022, 2021 and 2020		53
Consolidated Statements of Equity for the Years Ended December 31, 2023, 2022 and 2021		44
Consolidated Statements of Cash Flows for the Years Ended December 31, 2022, 2021 and 2020		54
Consolidated Statements of Cash Flows for the Years Ended December 31, 2023, 2022 and 2021		45
Notes to Consolidated Financial Statements		5546

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors

Continental Resources, Inc.

Opinion on the financial statements

We have audited the accompanying consolidated balance sheets of Continental Resources, Inc. (an Oklahoma corporation) and subsidiaries (the “Company”) as of December 31, ~~2022~~2023 and ~~2021~~2022, the related consolidated statements of income ~~(loss)~~, equity, and cash flows for each of the three years in the period ended December 31, ~~2022~~2023, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, ~~2022~~2023 and ~~2021~~2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, ~~2022~~2023, in conformity with accounting principles generally accepted in the United States of America.

Basis for opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB and in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. ~~Our~~The ~~audits~~Company ~~included~~is ~~performing~~not ~~procedures~~required to ~~assess~~have, ~~the~~nor ~~risks~~were ofwe ~~material~~engaged ~~misstatement of the financial statements, whether due~~ to ~~error or fraud~~perform, ~~and~~an ~~performing~~audit ~~procedures~~of ~~that~~its ~~respond~~internal tocontrol ~~those~~over ~~risks~~financial reporting. ~~Such~~As ~~procedures~~part ~~included~~of ~~examining,~~our onaudits awe ~~test~~are ~~basis,~~required ~~evidence~~to ~~regarding~~obtain ~~the~~an ~~amounts~~understanding ~~and~~of ~~disclosures~~internal incontrol ~~the~~over financial ~~statements.~~reporting ~~Our~~but ~~audits~~not ~~also~~for ~~included evaluating~~ the ~~accounting~~purpose ~~principles~~of ~~used~~expressing ~~and~~an ~~significant~~opinion ~~estimates~~on ~~made~~the byeffectiveness ~~management,~~of ~~as well as evaluating~~ the ~~overall~~Company’s ~~presentation~~internal ofcontrol ~~the~~over financial ~~statements~~reporting. WeAccordingly, ~~believe~~we ~~that~~express ~~our~~no ~~audits~~such ~~provide a reasonable basis for our~~ opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical audit matter

The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Estimation of proved crude oil and natural gas reserves as it relates to the recognition of depletion expense, proved and unproved crude oil and natural gas reserves used in the assessment and measurement of impairment, and the valuation of crude oil and natural gas properties infrom ~~the~~certain ~~2022~~2023 ~~Powder~~executed ~~River~~acquisitions ~~Basin~~of ~~Acquisition~~proved oil and gas properties (herein referred to as "“the crude oil and natural gas reserves"”) .

As described in Note 1 to the consolidated financial statements, the Company accounts for its crude oil and natural gas properties using the successful efforts method of accounting, which requires management to make estimates of proved crude oil and natural gas reserve volumes and future cash flows to record depletion expense and proved and unproved crude oil and natural gas reserves to assess its crude oil and natural gas properties for impairment. Additionally, as described in Note 2 to the consolidated financial statements, the Company acquired ~~significant~~ oil and natural gas properties through asset acquisitions. Crude oil and natural gas reserves are a significant input to the determination of the acquisition date fair value of crude oil and natural gas properties acquired by the Company in asset acquisitions. To estimate the crude oil and natural gas reserves and future cash flows, management makes significant estimates and assumptions including forecasting the production decline rate of producing crude oil and natural gas properties and forecasting the timing and volume of production associated with the Company's development plan for proved undeveloped properties and unproved properties. In addition, the estimation of the crude oil and natural gas reserves is also impacted by management's judgments and estimates regarding the financial performance of wells associated with the crude oil and natural gas reserves to determine if wells are expected with reasonable certainty to be economical under the appropriate pricing assumptions required in the estimation of depletion expense and impairment assessments/measurements. We identified the estimation of proved crude oil and natural gas reserves as it relates to the recognition of depletion expense and the recording of fair values of properties

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~~acquired~~expense inand impairment assessments/measurements. We identified the ~~2022~~estimation ~~Powder~~of ~~River~~proved ~~Basin~~crude ~~Acquisition~~oil and natural gas reserves as it relates to the recognition of depletion expense and the recording of fair values of properties acquired in the 2023 acquisitions, and proved and unproved crude oil and natural gas reserves for the assessment/measurement of impairment of crude oil and natural gas properties as a critical audit matter.

The principal consideration for our determination that the estimation of proved crude oil and natural gas reserves as it relates to the recognition of depletion expense and proved and unproved crude oil and natural gas reserves for the assessment / measurement of impairment of crude oil and natural gas properties and the recording of oil and natural gas property values in the ~~2022~~2023 ~~Powder~~acquisitions ~~River Basin Acquisition~~ is a critical audit matter is that relatively minor changes in certain highly subjective inputs and assumptions that are necessary to estimate the volume and future cash flows of the Company's crude oil and natural gas reserves could have a significant impact on the measurement of depletion expense or assessment / measurement of impairment expense and the acquisition date values of crude oil and natural gas properties.

Our audit procedures related to the estimation of proved crude oil and natural gas reserves as it relates to the recognition of depletion expense and proved and unproved crude oil and natural gas reserves for the assessment and measurement of impairment and the amount of crude oil and natural gas properties recorded from acquisitions included the following, among others:

•

We tested the design and operating effectiveness of controls relating to management's estimation of proved crude oil and natural gas reserves for the purpose of estimating depletion expense and proved and unproved crude oil and natural gas reserves for assessing / measuring the Company's proved crude oil and gas properties for impairment and acquisitions.

We assessed the independence, objectivity, and professional qualifications of the Company's reservoir engineer specialists, made inquiries of these specialists (internal and external) regarding the process followed and judgments used to make significant estimates, including but not limited to crude oil and natural gas reserve volumes, decline rates, and economically recoverable crude oil and natural gas reserves and reviewed the reserve estimates prepared by the Company's specialists.

•

To the extent key inputs and assumptions used to determine crude oil and natural gas reserve volumes and other cash flow inputs and assumptions are derived from the Company's accounting records, including, but not limited to: historical pricing differentials, operating costs, estimated capital costs, discount rates, and ownership interests, we tested management's process for determining the assumptions, including examining underlying support on a sample basis. Specifically, our audit procedures related to testing management's assumptions included the following:

◦

We compared the estimated pricing differentials used in the reserve report to realized prices related to revenue transactions recorded in the current year and examined contractual support for the pricing differentials.

◦

We evaluated the models used to estimate the operating costs at year-end and compared to historical operating costs.

◦

We compared the estimates of future capital expenditures in the reserve reports to management's forecasts and amounts expended for recently drilled and completed wells.

◦

We evaluated the working and net revenue interests used in the reserve report by inspecting land and division order records.

◦

We evaluated the Company's evidence supporting the amount of proved undeveloped properties reflected in the reserve report by examining historical conversion rates and support for the Company's ability to fund and intent to develop the proved undeveloped properties.

◦

We applied analytical procedures to the reserve report by comparing to historical actual results and to the prior year reserve report.

◦

We evaluated the reasonableness of the Company’s classification of reserves as proved or unproved.

◦

We evaluated the reasonableness of risk-adjustment factors applied to unproved crude oil and natural gas reserves that were taken into consideration to determine estimated future net cash flows used to evaluate proved property impairment ~~and for asset acquisitions~~.

◦

As it relates to the recording of the acquisition date values of crude oil and natural gas properties in asset acquisitions, we utilized internal valuation specialists to assist with evaluating certain assumptions, such as risk-adjustment factors and the valuation of unproved oil and gas properties on a per net acre basis, as compared to industry surveys and publicly available market data.

/s/ GRANT THORNTON LLP

We have served as the Company’s auditor since 2004.

Oklahoma City, Oklahoma

February 22, ~~2023~~2024

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Continental Resources, Inc. and Subsidiaries

Consolidated Balance Sheets

	December 31,
In thousands, except par values and share data	~~2022~~2023			~~2021~~2022
Assets
Current assets:
Cash and cash equivalents	$	~~137~~26,~~788~~397		$	20137,~~868~~788
Receivables:
Crude oil, natural gas, and natural gas liquids sales		1,~~313~~196,~~538~~262			1,~~122~~313,~~415~~538
Joint interest and other		~~458~~350,~~391~~907			~~278~~458,~~753~~391
Allowance for credit losses		(53,~~514~~172	)		(25,~~814~~514	)
Receivables, net		1,~~766~~543,~~415~~997			1,~~398~~766,~~354~~415
Derivative assets		39353,~~280~~261			2239,~~334~~280
Inventories		~~173~~190,~~264~~762			~~105~~173,~~568~~264
Prepaid expenses and other		2733,~~508~~450			1727,~~266~~508
Total current assets		2,~~144~~147,~~255~~867			12,~~564~~144,~~390~~255
Net property and equipment, based on successful efforts method of accounting		1819,~~471~~786,~~914~~889			1618,~~975~~471,~~465~~914
Investment in unconsolidated affiliates		~~210~~240,~~805~~484			—210,805
Operating lease right-of-use assets		2538,~~158~~656			1625,~~370~~158
Derivative assets, noncurrent		3155,~~548~~252			133,~~188~~548
Other noncurrent assets		2218,~~670~~293			2122,~~698~~670
Total assets	$	2022,~~878~~387,~~350~~441		$	1820,~~591~~878,~~111~~350
Liabilities and equity
Current liabilities:
Accounts payable trade	$	~~850~~835,~~547~~012		$	~~582~~850,~~317~~547
Revenues and royalties payable		~~882~~768,~~256~~381			~~627~~882,~~171~~256
Accrued liabilities and other		~~343~~354,~~777~~537			~~285~~343,~~740~~777
Current portion of incentive compensation liability		~~125~~130,~~653~~583			—125,653
Current portion of income tax liabilities		~~152~~84,~~149~~556			—152,149
Derivative liabilities		~~88,136~~—			~~899~~88,136
Current portion of operating lease liabilities		418,~~086~~112			14,~~674~~086
Current portion of long-term debt		~~638~~895,~~058~~105			2638,~~326~~058
Total current liabilities		3,~~084~~086,~~662~~286			13,~~500~~084,~~127~~662
Long-term debt, net of current portion		75,~~571~~734,~~582~~007			67,~~826~~571,~~566~~582
Other noncurrent liabilities:
Deferred income tax liabilities, net		2,~~538~~867,~~312~~283			2,~~139~~538,~~884~~312
Incentive compensation liability, net of current portion		100,066			—
Incentive compensation liability, noncurrent		41,707			100,066
Asset retirement obligations, net of current portion		257,152			215,701
Asset retirement obligations, noncurrent		391,957			257,152
Derivative liabilities, noncurrent		~~133,363~~586			~~318~~133,363
Operating lease liabilities, net of current portion		20,055			13,800
Operating lease liabilities, noncurrent		19,482			20,055
Other noncurrent liabilities		4336,~~550~~346			3843,~~390~~550
Total other noncurrent liabilities		3,~~092~~357,~~498~~361			23,~~408~~092,~~093~~498
Commitments and contingencies (Note 13)
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 December 31, 2022;
299,610,267 shares issued and outstanding at December 31, 2023 and 2022;		2,996			2,996
364,297,520 shares issued and outstanding at December 31, 2021;		2,996			3,643
Retained earnings		9,850,687			6,754,174
Additional paid-in capital		—			1,131,602
Total shareholders’ equity attributable to Continental Resources		9,853,683			6,757,170
Retained earnings		6,754,174			6,340,211
Noncontrolling interests		356,104			372,438
Total shareholders’ equity attributable to Continental Resources		6,757,170			7,475,456
Total equity		10,209,787			7,129,608
Noncontrolling interests		372,438			380,869
Total liabilities and equity	$	22,387,441		$	20,878,350
Total equity		7,129,608			7,856,325
Total liabilities and equity	$	20,878,350		$	18,591,111

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

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Continental Resources, Inc. and Subsidiaries

Consolidated Statements of Income ~~(Loss)~~

	Year Ended December 31,
In thousands, except per share data	~~2022~~2023			~~2021~~2022			~~2020~~2021
Revenues:
Crude oil, natural gas, and natural gas liquids sales	$	107,~~074~~684,~~675~~263		$	510,~~793~~074,~~741~~675		$	25,~~555~~793,~~434~~741
Loss on derivative instruments, net		(671,095	)		(128,864	)		(14,658	)
Gain (loss) on derivative instruments, net		943,768			(671,095	)		(128,864	)
Crude oil and natural gas service operations		70103,~~128~~710			5470,~~441~~128			4554,~~694~~441
Total revenues		98,~~473~~731,~~708~~741			59,~~719~~473,~~318~~708			25,~~586~~719,~~470~~318
Operating costs and expenses:
Production expenses		~~621~~717,~~921~~478			~~406~~621,~~906~~921			~~359~~406,~~267~~906
Production and ad valorem taxes		~~730~~603,~~132~~534			~~404~~730,~~362~~132			~~192~~404,~~718~~362
Transportation, gathering, processing, and compression		~~316~~338,~~414~~217			~~224~~316,~~989~~414			~~196~~224,~~692~~989
Exploration expenses		2316,~~068~~368			2123,~~047~~068			1721,~~732~~047
Crude oil and natural gas service operations		3782,~~002~~392			2137,~~480~~002			1821,~~294~~480
Depreciation, depletion, amortization and accretion		12,~~885~~264,~~465~~334			1,~~898~~885,~~082~~465			1,~~880~~898,~~959~~082
Property impairments		7066,~~417~~798			3870,~~370~~417			~~277~~38,~~941~~370
Transaction costs		~~33,796~~—			1333,~~920~~796			—13,920
General and administrative expenses		~~401~~279,~~551~~306			~~233~~401,~~628~~551			~~196~~233,~~572~~628
Net (gain) loss on sale of assets and other		~~262~~50,581			~~(5,146~~262	)		~~187~~(5,146	)
Total operating costs and expenses		4,~~120~~419,~~028~~008			34,~~257~~120,~~638~~028			3,~~140~~257,~~362~~638
Income (loss) from operations		5,353,680			2,461,680			(553,892	)
Income from operations		4,312,733			5,353,680			2,461,680
Other income (expense):
Interest expense		(~~300~~395,~~662~~765	)		(~~251~~300,~~598~~662	)		(~~258~~251,~~240~~598	)
Gain (loss) on extinguishment of debt		(403	)		(290	)		35,719
Loss on extinguishment of debt		—			(403	)		(290	)
Other		1511,~~798~~979			~~(23~~15,~~654~~798	)		1(23,~~662~~654	)
		(285,267	)		(275,542	)		(220,859	)
		(383,786	)		(285,267	)		(275,542	)
Income (loss) before income taxes		5,068,413			2,186,138			(774,751	)
Income before income taxes		3,928,947			5,068,413			2,186,138
(Provision) benefit for income taxes		(1,020,804	)		(519,730	)		169,190
Provision for income taxes		(827,630	)		(1,020,804	)		(519,730	)
Income (loss) before equity in net loss of affiliate		4,047,609			1,666,408			(605,561	)
Income before equity in net loss of affiliate		3,101,317			4,047,609			1,666,408
Equity in net loss of affiliate		(13,~~489~~129	)		—(1,489	)		—
Net income (loss)		4,046,120			1,666,408			(605,561	)
Net income		3,098,188			4,046,120			1,666,408
Net income (loss) attributable to noncontrolling interests		21,562			5,440			(8,692	)
Net income attributable to noncontrolling interests		2,361			21,562			5,440
Net income (loss) attributable to Continental Resources	$	4,024,558		$	1,660,968		$	(596,869	)
Net income attributable to Continental Resources	$	3,095,827		$	4,024,558		$	1,660,968
Net income (loss) per share attributable to Continental Resources:
Net income per share attributable to Continental Resources:
Basic	$	1110.4533		$	411.6145		$	(14.6561	)
Diluted	$	1110.4533		$	411.5645		$	(14.6556	)

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

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Continental Resources, Inc. and Subsidiaries

Consolidated Statements of Equity

	Shareholders’ equity attributable to Continental Resources
In thousands, except share data	Sharesoutstanding			Commonstock			Additionalpaid-incapital			Treasurystock			Retainedearnings			Total shareholders’ equity of Continental Resources			Noncontrollinginterests			Totalequity
Balance at December 31, 2019		371,074,036		$	3,711		$	1,274,732		$	—		$	5,463,224		$	6,741,667		$	366,684		$	7,108,351
Net loss		—			—			—			—			(596,869	)		(596,869	)		(8,692	)		(605,561	)
Cumulative effect adjustment from adoption of ASU 2016-13														(137	)		(137	)					(137	)
Cash dividends declared		—			—			—			—			(18,580	)		(18,580	)		—			(18,580	)
Change in dividends payable		—			—			—			—			8			8			—			8
Common stock repurchased		—			—			—			(126,906	)		—			(126,906	)		—			(126,906	)
Common stock retired		(8,122,104	)		(81	)		(126,825	)		126,906			—			—			—			—
Stock-based compensation		—			—			64,585			—			—			64,585			—			64,585
Restricted stock:
Granted		2,738,625			27			—			—			—			27			—			27
Repurchased and canceled		(306,845	)		(3	)		(7,344	)		—			—			(7,347	)		—			(7,347	)
Forfeited		(163,277	)		(2	)		—			—			—			(2	)		—			(2	)
Contributions from noncontrolling interests		—			—			—			—			—			—			21,557			21,557
Distributions to noncontrolling interests		—			—			—			—			—			—			(13,270	)		(13,270	)
Balance at December 31, 2020		365,220,435		$	3,652		$	1,205,148		$	—		$	4,847,646		$	6,056,446		$	366,279		$	6,422,725
Net income		—			—			—			—			1,660,968			1,660,968			5,440			1,666,408
Cash dividends declared		—			—			—			—			(168,536	)		(168,536	)		—			(168,536	)
Change in dividends payable		—			—			—			—			133			133			—			133
Common stock repurchased		—			—			—			(123,924	)		—			(123,924	)		—			(123,924	)
Common stock retired		(3,198,571	)		(32	)		(123,892	)		123,924			—			—			—			—
Stock-based compensation		—			—			63,145			—			—			63,145			—			63,145
Restricted stock:
Granted		3,050,491			31			—			—			—			31			—			31
Repurchased and canceled		(478,697	)		(5	)		(12,799	)		—						(12,804	)		—			(12,804	)
Forfeited		(296,138	)		(3	)		—			—			—			(3	)		—			(3	)
Contributions from noncontrolling interests		—			—			—			—			—			—			33,086			33,086
Distributions to noncontrolling interests		—			—			—			—			—			—			(23,936	)		(23,936	)
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		—			—			—			—			4,024,558			4,024,558			21,562			4,046,120
Cash dividends declared		—			—			—			—			(287,035	)		(287,035	)		—			(287,035	)
Change in dividends payable		—			—			—			—			205			205			—			205
Common stock repurchased prior to take-private transaction		—			—			—			(99,855	)		—			(99,855	)		—			(99,855	)
Common stock retired prior to take-private transaction		(1,842,422	)		(18	)		(99,837	)		99,855			—			—			—			—
Stock-based compensation		—			—			(8,085	)		—			—			(8,085	)		—			(8,085	)
Restricted stock:
Granted		1,575,847			16			—			—			—			16			—			16
Repurchased and canceled		(627,742	)		(7	)		(35,438	)		—						(35,445	)		—			(35,445	)
Forfeited		(384,536	)		(4	)		—			—			—			(4	)		—			(4	)
Restricted stock canceled from take-private transaction (see Note 15)		(5,349,141	)		(53	)											(53	)					(53	)
Take-private transaction (see Note 1)		(58,059,259	)		(581	)		(988,242	)					(3,323,765	)		(4,312,588	)		—			(4,312,588	)
Contributions from noncontrolling interests		—			—			—			—			—			—			12,498			12,498
Distributions to noncontrolling interests		—			—			—			—			—			—			(42,491	)		(42,491	)
Balance at December 31, 2022		299,610,267		$	2,996		$	—		$	—		$	6,754,174		$	6,757,170		$	372,438		$	7,129,608
Net income		—			—			—			—			3,095,827			3,095,827			2,361			3,098,188
Change in dividends payable		—			—			—			—			686			686			—			686
Contributions from noncontrolling interests		—			—			—			—			—			—			10,188			10,188
Distributions to noncontrolling interests		—			—			—			—			—			—			(28,883	)		(28,883	)
Balance at December 31, 2023		299,610,267		$	2,996		$	—		$	—		$	9,850,687		$	9,853,683		$	356,104		$	10,209,787

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

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Continental Resources, Inc. and Subsidiaries

Consolidated Statements of Cash Flows

	Year Ended December 31,
In thousands	~~2022~~2023			~~2021~~2022			~~2020~~2021
Cash flows from operating activities:
Net income (loss)	$	4,046,120		$	1,666,408		$	(605,561	)
Net income	$	3,098,188		$	4,046,120		$	1,666,408
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation, depletion, amortization and accretion		12,~~886~~265,~~491~~948			1,~~893~~886,~~106~~491			1,~~882~~893,~~458~~106
Property impairments		7066,~~417~~798			3870,~~370~~417			~~277~~38,~~941~~370
Non-cash (gain) loss on derivatives, net		~~212~~(686,~~976~~598	)		~~(20~~212,~~814~~976	)		(1320,~~492~~814	)
Stock/incentive-based compensation		217,650			63,173			64,613
Stock-based compensation		—			217,650			63,173
Provision (benefit) for deferred income taxes		398,429			519,730			(166,971	)
Provision for deferred income taxes		328,970			398,429			519,730
Equity in net loss of affiliate		13,~~489~~129			—1,489			—
Dry hole costs		~~12,305~~—			—12,305			—
Net (gain) loss on sale of assets and other		~~262~~50,581			~~(5,146~~262	)		~~187~~(5,146	)
(Gain) loss on extinguishment of debt		403			290			(35,719	)
Loss on extinguishment of debt		—			403			290
Other, net		2721,~~294~~594			3527,~~614~~294			1635,~~970~~614
Changes in assets and liabilities:
Accounts receivable		~~(372~~222,~~529~~091	)		(~~694~~372,~~981~~529	)		~~332~~(694,~~128~~981	)
Inventories		(6717,~~478~~600	)		(3367,~~411~~478	)		12(33,~~859~~411	)
Other current assets		(106,~~242~~118	)		(210,~~144~~242	)		1(2,~~471~~144	)
Accounts payable trade		~~164~~(38,~~071~~740	)		~~106~~164,~~367~~071			~~(133~~106,~~977~~367	)
Revenues and royalties payable		~~253~~(111,~~286~~738	)		~~298~~253,~~552~~286			~~(143~~298,~~260~~552	)
Accrued liabilities and other		512,~~222~~940			~~109~~51,~~540~~222			~~(66~~109,~~071~~540	)
Current income taxes liability		152,149			—			—
Incentive compensation liability		(53,429	)		—			—
Other noncurrent assets and liabilities		(4,625	)		(803	)		(1,272	)
Current income taxes liability		(67,593	)		152,149			—
Net cash provided by operating activities		7,039,690			3,973,851			1,422,304
Other noncurrent assets and liabilities		(17,436	)		(4,625	)		(803	)
Net cash provided by operating activities		5,060,987			7,039,690			3,973,851
Cash flows from investing activities:
Exploration and development		(23,~~838~~550,~~075~~502	)		(2,~~382~~838,~~413~~075	)		(12,~~408~~382,~~149~~413	)
Purchase of producing crude oil and natural gas properties		(~~421~~161,~~850~~408	)		(2421,~~548,575~~850	)		(812,~~994~~548,575	)
Purchase of other property and equipment		(68205,~~189~~356	)		(6668,~~598~~189	)		(2366,~~994~~598	)
Proceeds from sale of assets		5390,~~740~~034			85,~~041~~740			28,~~779~~041
Contributions to unconsolidated affiliates		(~~212~~33,~~294~~862	)		—(212,294	)		—
Net cash used in investing activities		(3,~~534~~561,~~668~~094	)		(43,~~989~~534,~~545~~668	)		(14,~~511~~989,~~358~~545	)
Cash flows from financing activities:
Credit facility borrowings		34,~~886~~792,000			13,~~663~~886,000			21,~~052~~663,000
Repayment of credit facility		(35,~~226~~742,000	)		(13,~~323~~226,000	)		(1,~~947~~323,000	)
Proceeds from issuance of Senior Notes		—			~~1,587,776~~—			1,~~485~~587,~~000~~776
Redemption and repurchase of Senior Notes		(31636,~~829~~000	)		(~~630~~31,~~782~~829	)		(1630,~~343,250~~782	)
Premium and costs on redemption of Senior Notes		—			—			(25,173	)
Proceeds from other debt		—			750,000			—
Proceeds from other debt		750,000			—			26,000
Repayment of other debt		(2,410	)		(2,326	)		(2,243	)
Repayment of other debt		(2,326	)		(2,243	)		(6,679	)
Debt issuance costs		(242	)		(5,148	)		(12,082	)
Debt issuance costs		(5,148	)		(12,082	)		(4,368	)
Contributions from noncontrolling interests		10,580			13,665			31,493
Contributions from noncontrolling interests		13,665			31,493			27,116
Distributions to noncontrolling interests		(31,156	)		(40,685	)		(22,447	)
Distributions to noncontrolling interests		(40,685	)		(22,447	)		(13,809	)
Repurchase of common stock prior to take-private transaction		—			(99,855	)		(123,924	)
Repurchase of common stock prior to take-private transaction		(99,855	)		(123,924	)		(126,906	)
Take-private transaction (see Note 1)		—			(4,312,642	)		—
Take-private transaction (see Note 1)		(4,312,642	)		—			—
Repurchase of restricted stock for tax withholdings		—			(35,444	)		(12,804	)
Repurchase of restricted stock for tax withholdings		(35,444	)		(12,804	)		(7,347	)
Dividends paid on common stock		(2,056	)		(283,838	)		(165,895	)
Dividends paid on common stock		(283,838	)		(165,895	)		(18,460	)
Net cash provided by (used in) financing activities		(1,611,284	)		(3,388,102	)		989,092
Net cash provided by (used in) financing activities		(3,388,102	)		989,092			97,124
Net change in cash and cash equivalents		(111,391	)		116,920			(26,602	)
Net change in cash and cash equivalents		116,920			(26,602	)		8,070
Cash and cash equivalents at beginning of period		137,788			20,868			47,470
Cash and cash equivalents at beginning of period		20,868			47,470			39,400
Cash and cash equivalents at end of period	$	26,397		$	137,788		$	20,868
Cash and cash equivalents at end of period	$	137,788		$	20,868		$	47,470

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

5445

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Continental Resources, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

Note 1. Organization and Summary of Significant Accounting Policies

Description of the Company

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.

2022 Take-Private Transaction

On ~~October~~November 1622, 2022, the Company ~~entered~~completed ~~into~~a anseries ~~Agreement and Plan~~ of ~~Merger~~take-private ~~(the~~transactions ~~“Merger Agreement”)~~ with Omega Acquisition, Inc~~. (“Merger Sub”)~~, an entity owned by the Company’s founder, Harold G. Hamm., ~~Pursuant~~pursuant to which the ~~Merger~~Company ~~Agreement,~~became onwholly ~~October~~owned 24by Mr. Hamm, ~~2022~~certain ~~Merger~~members ~~Sub~~of ~~commenced~~his afamily ~~tender~~and ~~offer~~their affiliated entities (the “~~Offer~~Hamm Family”). toA ~~purchase~~total ~~any and all~~ of ~~the~~approximately ~~outstanding~~58.1 million shares of ~~the Company~~Continental’s common stock ~~for~~were ~~$74.28~~purchased ~~per~~pursuant ~~share~~to inthe take-private transaction for total cash ~~(the~~consideration ~~“Offer~~of ~~Price”),~~approximately ~~other~~$4.31 ~~than:~~billion. ~~(i)~~The ~~shares~~2022 purchase of ~~common~~outstanding ~~stock~~shares ~~owned~~was funded by MrContinental through the use of approximately $2.2 ~~Hamm~~billion of cash on hand, ~~certain~~$1.3 billion of ~~his~~credit ~~family~~facility ~~members~~borrowings, and ~~their~~the ~~affiliated~~execution ~~entities~~of ~~(collectively,~~a ~~the~~$750 ~~“Hamm~~million ~~Family”)~~three-year ~~and~~term ~~(ii)~~loan. ~~shares~~See the Consolidated Statements of ~~common~~Equity ~~stock~~for ~~underlying~~the ~~unvested~~year ~~equity~~ended ~~awards~~December ~~issued~~31, ~~pursuant~~2022 tofor the ~~Company~~impact on the components of Shareholders’s ~~long~~Equity resulting from the take-~~term~~private ~~incentive~~transaction. ~~plans~~The ~~(collectively,~~Company incurred $32 million of legal and advisory fees in 2022 in connection with the take-private transaction which are included in the caption “~~Rollover~~Transaction ~~Shares~~costs”). in the Consolidated Statements of Income for the year ended December 31, 2022.

~~The~~Following ~~Offer~~the ~~expired~~consummation atof ~~one~~the ~~minute~~transactions ~~after~~in 11November 2022:59 ~~p.m.,~~(i) our common stock ceased to be listed on the New York ~~City~~Stock ~~time~~Exchange, on(ii) ~~November~~our ~~21,~~common ~~2022.~~stock Aswas ofderegistered ~~the~~under ~~expiration~~Section 12(b) of the ~~Offer,~~Securities aExchange ~~total~~Act of ~~approximately~~1934 ~~36.3~~as ~~million~~amended ~~shares~~(the ~~were~~“Exchange ~~validly~~Act”), ~~tendered~~ and ~~not~~(iii) ~~validly~~we ~~withdrawn~~suspended ~~pursuant~~our toreporting obligations under Section 15(d) of the ~~Offer~~Exchange Act. InAs ~~addition~~a result, ~~notices~~certain of ~~guaranteed~~the ~~delivery~~corporate ~~were~~governance, ~~delivered~~disclosure, ~~for~~and ~~approximately~~other ~~3.4~~provisions ~~million~~applicable ~~shares.~~to ~~Each~~a ~~condition~~company towith listed equity securities and reporting obligations under the ~~Offer~~Exchange ~~was~~Act ~~satisfied~~no ~~and,~~longer apply to us. We will continue to furnish Quarterly Reports on ~~November~~Form ~~22,~~10-Q ~~2022,~~and ~~Merger~~Annual ~~Sub~~Reports ~~irrevocably~~on ~~accepted~~Form ~~for~~10-K ~~payment~~with ~~all~~the ~~shares~~SEC ~~that~~as ~~were~~required ~~validly~~by ~~tendered~~our ~~and~~senior ~~not~~note ~~withdrawn~~indentures.

On November 22, 2022, immediately prior to the acceptance of shares for payment, Mr. Hamm contributed 100% of the capital stock of Merger Sub to the Company. In addition, following consummation of the Offer, Merger Sub merged with and into the Company, with the Company continuing as the surviving corporation wholly-owned by the Hamm Family (the “Merger”). At the effective time of the Merger, each remaining share of the Company not purchased in the Offer (other than (i) the Rollover Shares; (ii) shares owned by the Company as treasury stock or owned by any wholly owned subsidiary of the Company, including shares irrevocably accepted by Merger Sub pursuant to the Offer; and (iii) shares held by a holder who properly demanded appraisal rights for such shares in accordance with Oklahoma law), was converted into the right to receive an amount in cash equal to the Offer Price, without interest and subject to any required tax withholding.

At the effective time of the Merger: (i) each share of the Company held by a member of the Hamm Family was converted into an identical number of newly issued shares of the Company, as the surviving corporation, having identical rights to the previously existing shares held by such holder, and such converted shares of the surviving corporation are the only capital stock of the surviving corporation outstanding following the Merger; and (ii) the Rollover Shares underlying each unvested restricted stock award issued under the Company’s long-term incentive plans that was outstanding immediately prior to the effective time were replaced with a restricted stock unit award issued by the Company that provides the holder of such previous award with the right to receive, on the date that such restricted stock award otherwise would have been settled, and at the Company’s sole discretion, either a share of the Company, a cash award designed to provide substantially equivalent value, or any combination of the two, in each case, together with any unpaid dividends accrued on such restricted stock award.

A total of approximately 58.1 million shares of Continental’s common stock were purchased pursuant to the take-private transaction for total cash consideration of approximately $4.31 billion, inclusive of payments issued to holders who demanded appraisal rights for their untendered shares in accordance with Oklahoma law. The purchase of outstanding shares was funded by Continental through the use of approximately $2.2 billion of cash on hand, $1.3 billion of credit facility borrowings, and the execution of a $750 million three-year term loan as further described in Note 8. Long-Term Debt. See the Consolidated Statements of Equity for the year ended December 31, 2022 for the impact on the components of Shareholders’ Equity resulting from the take-private transaction. As of December 31, 2022, the Hamm Family holds approximately 299.6 million shares of capital stock of the Company, as the surviving corporation, and there remains approximately 5.3 million Rollover Shares. See Note 15. Stock-Based Compensation for a discussion of the Company’s accounting for the Rollover Shares. The Company incurred $32 million of legal and advisory fees in connection with the take-private transaction which are included in the caption “Transaction costs” in the consolidated statements of income (loss) for the year ended December 31, 2022.

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Continental Resources, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

Following the completion of the take-private transaction: (i) our common stock ceased to be listed on the New York Stock Exchange effective November 23, 2022, (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. As a result, certain of the corporate governance, disclosure, and other provisions applicable to a company with listed equity securities and reporting obligations under the Exchange Act no longer 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.

Basis of presentation of consolidated financial statements

The 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 ~~(loss)~~ and equity attributable to the noncontrolling interests are presented separately in the Company’s financial statements. For financial reporting purposes, the Company has one reportable segment due to the similar nature of its business, which is the exploration, development, and production of crude oil, natural gas, and natural gas liquids in the United States.

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. ~~See Note 18. Equity Investment for discussion of a strategic investment made by the Company in 2022 that is accounted for under the equity method.~~

The Company evaluated its December 31, ~~2022~~2023 financial statements for subsequent events through February 22, ~~2023~~2024, the date the financial statements were available to be issued.

Use of estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States (“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.

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Continental Resources, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

Cash and cash equivalents

The Company considers all highly liquid investments with original maturities of three months or less to be cash equivalents. The Company maintains its cash and cash equivalents in accounts that may not be federally insured. As of December 31, ~~2022~~2023, the Company had cash deposits in excess of federally insured amounts of approximately $~~136~~24.47 million. The Company has not experienced any losses in such accounts and believes it is not exposed to significant credit risk in this area.

Accounts receivable

Receivables arising from crude oil and natural gas sales and joint interest receivables are generally unsecured. Accounts receivable are due within 30 days and are considered delinquent after 60 days. The Company writes off specific receivables when they become noncollectable and any payments subsequently received on those receivables are credited to the allowance for credit losses. Write-offs of noncollectable receivables have historically not been material. The Company’s allowance for credit losses totaled $53.52 million and $25.85 million as of December 31, ~~2022~~2023 and ~~2021~~2022, respectively. See Note 10. Allowance for Credit Losses for additional information.

Concentration of credit risk

The Company is subject to credit risk resulting from the concentration of its crude oil and natural gas receivables with significant purchasers. For the year ended December 31, ~~2022~~2023, no purchaser accounted for more than 10% of the Company’s total crude oil, natural gas, and natural gas liquids sales for ~~2022~~2023. The Company generally does not require collateral and does not believe the loss of any single purchaser would materially impact its operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers in various regions.

Inventories

Table of Contents

Continental Resources, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

Inventory is comprised of crude oil held in storage or as line fill in pipelines, pipeline imbalances, and tubular goods and equipment to be used in the Company’s exploration and development activities. Crude oil inventories are valued at the lower of cost or net realizable value primarily using the first-in, first-out inventory method. Tubular goods and equipment are valued primarily using a weighted average cost method applied to specific classes of inventory items.

The components of inventory as of December 31, ~~2022~~2023 and ~~2021~~2022 consisted of the following:

	December 31,
In thousands	~~2022~~2023		~~2021~~2022
Tubular goods and equipment	$	3865,~~636~~205	$	1238,~~506~~636
Crude oil		~~130~~125,~~192~~557		93130,~~062~~192
Natural gas		~~4,436~~—		—4,436
Total	$	~~173~~190,~~264~~762	$	~~105~~173,~~568~~264

Crude oil and natural gas properties

The Company uses the successful efforts method of accounting for crude oil and natural gas properties whereby costs incurred to acquire interests in crude oil and natural gas properties, to drill and equip exploratory wells that find proved reserves, to drill and equip development wells, and expenditures for enhanced recovery operations are capitalized. Geological and geophysical costs, seismic costs incurred for exploratory projects, lease rentals and costs associated with unsuccessful exploratory wells or projects are expensed as incurred. Costs of seismic studies that are utilized in development drilling within an area of proved reserves are capitalized as development costs. To the extent a seismic project covers areas of both developmental and exploratory drilling, those seismic costs are proportionately allocated between capitalized development costs and exploration expense. Maintenance and repairs are expensed as incurred.

Under the successful efforts method of accounting, the Company capitalizes exploratory drilling costs on the balance sheet pending determination of whether the well has found proved reserves in economically producible quantities. The Company capitalizes costs associated with the acquisition or construction of support equipment and facilities with the drilling and development costs to which they relate. If proved reserves are found by an exploratory well, the associated capitalized costs become part of well equipment and facilities. However, if proved reserves are not found, the capitalized costs associated with the well are expensed, net of any salvage value.

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Continental Resources, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

Production expenses are those costs incurred by the Company to operate and maintain its crude oil and natural gas properties and associated equipment and facilities. Production expenses include but are not limited to labor costs to operate the Company’s properties, repairs and maintenance, certain waste water disposal costs, utility costs, certain workover-related costs, and materials and supplies utilized in the Company’s operations.

Service property and equipment

Service property and equipment consist primarily of automobiles and aircraft; machinery and equipment; gathering and recycling systems; storage tanks; office and computer equipment, software, furniture and fixtures; and buildings and improvements. Major renewals and replacements are capitalized and stated at cost, while maintenance and repairs are expensed as incurred.

Depreciation and amortization of service property and equipment are provided in amounts sufficient to expense the cost of depreciable assets to operations over their estimated useful lives using the straight-line method. The estimated useful lives of service property and equipment are as follows:


Service property and equipment		Useful Lives In Years
Automobiles and aircraft		5-10
Machinery and equipment		6-30
Gathering and recycling systems		15-30
Storage tanks		10-30
Office and computer equipment, software, furniture and fixtures		3-25
Buildings and improvements		4-40

Depreciation, depletion and amortization

Depreciation, depletion and amortization of capitalized drilling and development costs of producing crude oil and natural gas properties, including related support equipment and facilities, are computed using the unit-of-production method on a field basis based on total estimated proved developed reserves. Amortization of producing leaseholds is based on the unit-of-production method using total estimated proved reserves. In arriving at rates under the unit-of-production method, the quantities of recoverable crude oil and natural gas reserves are established based on estimates made by the Company’s internal geologists and engineers and external independent reserve engineers. Upon sale or retirement of properties, the cost and related accumulated depreciation, depletion and amortization are eliminated from the accounts and the resulting gain or loss, if any, is recognized. Sales of proved properties constituting a part of an amortization base are accounted for as normal retirements with no gain or loss recognized if doing so does not significantly affect the unit-of-production amortization rate. Unit-of-production rates are revised whenever there is an indication of a need, but at least in conjunction with semi-annual reserve reports. Revisions are accounted for prospectively as changes in accounting estimates.

57Asset retirement obligations

The Company accounts for its asset retirement obligations by recording the fair value of a liability for an asset retirement obligation in the period in which a legal obligation is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Subsequently, the capitalized asset retirement costs are charged to expense through the depreciation, depletion and amortization of crude oil and natural gas properties and the liability is accreted to the expected future abandonment cost ratably over the related asset’s life.

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Continental Resources, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

onThe ~~total~~Company’s ~~estimated~~primary ~~proved~~asset ~~developed~~retirement ~~reserves.~~obligations ~~Amortization~~relate ofto ~~producing~~future ~~leaseholds~~plugging isand ~~based~~abandonment oncosts ~~the~~and ~~unit-of-production~~related ~~method~~disposal ~~using total estimated proved reserves. In arriving at rates under the unit-~~of~~-production~~ ~~method,~~facilities ~~the~~on ~~quantities~~its ~~of recoverable~~ crude oil and natural gas ~~reserves~~properties. ~~are~~The ~~established~~following ~~based~~table onsummarizes ~~estimates~~the ~~made~~changes byin the Company’s ~~internal~~future ~~geologists~~abandonment ~~and~~liabilities ~~engineers and external independent reserve engineers. Upon sale or retirement of properties, the cost and related accumulated depreciation, depletion and amortization are eliminated~~ from ~~the~~January ~~accounts and the resulting gain or loss~~1, if2021 ~~any,~~through isDecember recognized. Sales of proved properties constituting a part of an amortization base are accounted for as normal retirements with no gain or loss recognized if doing so does not significantly affect the unit-of-production amortization rate. Unit-of-production rates are revised whenever there is an indication of a need31, ~~but~~2023: ~~at least in conjunction with semi-annual reserve reports. Revisions are accounted for prospectively as changes in accounting estimates.~~

Asset retirement obligations


In thousands	2023			2022			2021
Asset retirement obligations at January 1	$	261,087		$	219,824		$	179,676
Accretion expense		14,818			12,857			11,125
Revisions (1)		112,803			(6,672	)		(1,291	)
Plus: Additions for new assets		18,929			37,413			32,351
Less: Plugging costs and sold assets		(5,709	)		(2,335	)		(2,037	)
Total asset retirement obligations at December 31	$	401,928		$	261,087		$	219,824
Less: Current portion of asset retirement obligations at December 31 (2)		9,971			3,935			4,123
Non-current portion of asset retirement obligations at December 31	$	391,957		$	257,152		$	215,701

(1)

The Company’s primary asset retirement obligations relate to future plugging and abandonment costs and related disposal of facilities on its crude oil and natural gas properties. The following table summarizes the changes in the Company’s future abandonment liabilities from January 1, 2020 through December 31, 2022:

In thousands	2022			2021			2020
Asset retirement obligations at January 1	$	219,824		$	179,676		$	153,673
Accretion expense		12,857			11,125			9,393
Revisions (1)		(6,672	)		(1,291	)		10,743
Plus: Additions for new assets		37,413			32,351			7,048
Less: Plugging costs and sold assets		(2,335	)		(2,037	)		(1,181	)
Total asset retirement obligations at December 31	$	261,087		$	219,824		$	179,676
Less: Current portion of asset retirement obligations at December 31 (2)		3,935			4,123			2,482
Non-current portion of asset retirement obligations at December 31	$	257,152		$	215,701		$	177,194

Revisions primarily represent changes in the present value of liabilities resulting from changes in estimated costs and economic lives of producing properties.

(2)

Balance is included in the caption “Accrued liabilities and other” in the consolidated balance sheets.

As of December 31, ~~2022~~2023 and ~~2021~~2022, net property and equipment on the consolidated balance sheets included $96204.52 million and $7296.85 million, respectively, of net asset retirement costs.

Asset impairment

Proved crude oil and natural gas properties are reviewed for impairment on a field-by-field basis each quarter. The estimated future cash flows expected in connection with the field are compared to the carrying amount of the field to determine if the carrying amount is recoverable. If the carrying amount of the field exceeds its estimated undiscounted future cash flows, the carrying amount of the field is reduced to its estimated fair value.

Impairment losses for unproved properties are generally recognized by amortizing the portion of the properties’ costs which management estimates will not be transferred to proved properties over the lives of the leases based on drilling plans, experience of successful drilling, and the average holding period. The Company’s impairment assessments are affected by economic factors such as the results of exploration activities, commodity price outlooks, anticipated drilling programs, remaining lease terms, and potential shifts in business strategy employed by management.

58Debt issuance costs

Costs incurred in connection with the execution of the Company’s notes payable, revolving credit facility, term loan and any amendments thereto are capitalized and amortized over the terms of the arrangements on a straight-line basis, the use of which approximates the effective interest method. Costs incurred upon the issuances of the Company’s various senior notes (collectively, the “Notes”) were capitalized and are being amortized over the terms of the Notes using the effective interest method.

The Company had aggregate capitalized costs of $46.5 million and $56.3 million (net of accumulated amortization of $37.3 million and $46.3 million) relating to its long-term debt at December 31, 2023 and 2022, respectively.

Unamortized capitalized costs associated with the Company’s Notes, note payable, and term loan totaled $39.4 million and $46.8 million at December 31, 2023 and 2022, respectively, and are reflected as a reduction of “Long-term debt, net of current portion” on the consolidated balance sheets.

Unamortized capitalized costs associated with the Company’s revolving credit facility totaled $7.1 million and $9.4 million at December 31, 2023 and 2022, respectively, and are reflected in “Other noncurrent assets” on the consolidated balance sheets.

For the years ended December 31, 2023, 2022 and 2021, the Company recognized amortization expense associated with capitalized debt issuance costs of $10.0 million, $9.3 million, and $7.2 million, respectively, which are reflected in “Interest expense” on the consolidated statements of income.

Table of Contents

Continental Resources, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

Debt issuance costs

The Company had aggregate capitalized costs of $56.3 million and $60.6 million (net of accumulated amortization of $46.3 million and $36.9 million) relating to its long-term debt at December 31, 2022 and 2021, respectively.

Unamortized capitalized costs associated with the Company’s Notes, note payable, and term loan totaled $46.8 million and $50.9 million at December 31, 2022 and 2021, respectively, and are reflected as a reduction of “Long-term debt, net of current portion” on the consolidated balance sheets.

Unamortized capitalized costs associated with the Company’s revolving credit facility totaled $9.4 million and $9.7 million at December 31, 2022 and 2021, respectively, and are reflected in “Other noncurrent assets” on the consolidated balance sheets.

For the years ended December 31, 2022, 2021 and 2020, the Company recognized amortization expense associated with capitalized debt issuance costs of $9.3 million, $7.2 million, and $7.8 million, respectively, which are reflected in “Interest expense” on the consolidated statements of income (loss).

Derivative instruments

The Company recognizes its derivative instruments on the balance sheet as either assets or liabilities measured at fair value with such amounts classified as current or long-term based on contractual settlement dates. The accounting for the changes in fair value of a derivative depends on the intended use of the derivative and resulting designation. The Company has not designated its derivative instruments as hedges for accounting purposes and, as a result, marks its derivative instruments to fair value and recognizes the changes in fair value in the consolidated statements of income ~~(loss)~~ under the caption “~~Loss~~Gain (loss) on derivative instruments, net.” See Note 6. Derivative Instruments for additional information.

Fair value of financial instruments

The Company’s financial instruments consist primarily of cash, trade receivables, trade payables, derivative instruments and long-term debt. See Note 7. Fair Value Measurements for a discussion of the methods used to determine fair value for the Company’s financial instruments and the quantification of fair value for its derivatives and long-term debt obligations at December 31, ~~2022~~2023 and ~~2021~~2022.

Income taxes

Income taxes are accounted for using the asset and liability method under which deferred income taxes are recognized for the future tax effects of temporary differences between financial statement carrying amounts and the tax basis of existing assets and liabilities using the enacted statutory tax rates in effect at period-end. The effect on deferred taxes for a change in tax rates is recognized in income in the period that includes the enactment date. The Company’s policy is to recognize penalties and interest related to unrecognized tax benefits, if any, in income tax expense.

The Company establishes a valuation allowance if it believes it is more likely than not that some or all of its deferred tax assets will not be realized. Significant judgment is applied in evaluating the need for and the magnitude of appropriate valuation allowances against deferred tax assets. See Note 11. Income Taxes for additional information.

59Earnings per share attributable to Continental Resources

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 treasury stock method. The following table presents the calculation of basic and diluted weighted average shares outstanding and net income per share attributable to the Company for the years ended December 31, 2023, 2022, and 2021.


	Year ended December 31,
In thousands, except per share data	2023		2022		2021
Net income attributable to Continental Resources (numerator)	$	3,095,827	$	4,024,558	$	1,660,968
Weighted average shares (denominator):
Weighted average shares - basic		299,610		351,392		360,434
Non-vested restricted stock and restricted stock units (1)		—		—		4,019
Weighted average shares - diluted		299,610		351,392		364,453
Net income per share attributable to Continental Resources:
Basic	$	10.33	$	11.45	$	4.61
Diluted	$	10.33	$	11.45	$	4.56

(1)

For the years ended December 31, 2023 and 2022, 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 years ended December 31, 2023 and 2022.

Note 2. Property Acquisitions and Dispositions

2023

During the year ended December 31, 2023, the Company executed acquisitions of oil and gas properties in various areas for cash consideration totaling $681 million. The Company accounted for each acquisition as an asset acquisition under ASC Topic 805—Business Combinations. Of the purchase prices, a total of $161 million was allocated to proved properties and a total of $520 million was allocated to unproved properties.

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Continental Resources, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

~~Earnings~~During ~~per~~the ~~share~~year ~~attributable~~ended toDecember ~~Continental~~31, ~~Resources~~2023, the Company executed sales of oil and gas properties in various areas for cash proceeds totaling $390 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.

Basic net income (loss) per share is computed by dividing net income (loss) 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 treasury stock method. The following table presents the calculation of basic and diluted weighted average shares outstanding and net income (loss) per share attributable to the Company for the years ended December 31, 2022, 2021, and 2020.

	Year ended December 31,
In thousands, except per share data	2022		2021		2020
Net income (loss) attributable to Continental Resources (numerator)	$	4,024,558	$	1,660,968	$	(596,869	)
Weighted average shares (denominator):
Weighted average shares - basic		351,392		360,434		361,538
Non-vested restricted stock and restricted stock units (1)		—		4,019		—
Weighted average shares - diluted		351,392		364,453		361,538
Net income (loss) per share attributable to Continental Resources:
Basic	$	11.45	$	4.61	$	(1.65	)
Diluted	$	11.45	$	4.56	$	(1.65	)

For the year ended December 31, 2020, the Company had a net loss and therefore the potential dilutive effect of approximately 934,000 weighted average non-vested restricted shares were not included in the calculation of diluted net loss per share because to do so would have been anti-dilutive to the computation. At December 31, 2022, the Company's outstanding Rollover Shares 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 Rollover Shares is presented for the year ended December 31, 2022.

Note 2. Property Acquisitions

2022

InDuring ~~March~~the year ended December 31, 2022, the Company ~~acquired~~executed acquisitions of oil and gas properties in ~~the~~various ~~Powder~~areas ~~River Basin~~ for cash consideration oftotaling $~~403~~714 million~~, representing a $450 million purchase price less customary closing adjustments made pursuant to the acquisition agreement~~. The ~~acquisition~~Company ~~was~~ accounted for each acquisition as an asset acquisition under ASC Topic 805—Business Combinations ~~and included approximately 172,000 net leasehold acres and producing properties with production totaling approximately 18,000 net barrels of oil equivalent per day at the time of closing~~. Of the purchase ~~price~~prices, ~~$381.3~~a ~~million~~total ~~was~~of ~~allocated to proved properties and~~ $~~21.7~~422 million was allocated to ~~unproved~~proved properties. ~~The~~and ~~Company~~a ~~recognized~~total ~~approximately $15.3 million~~ of ~~asset retirement obligations,~~ $~~31.3~~292 million ofwas ~~assumed~~allocated ~~production~~to ~~and~~unproved ~~ad valorem tax payment obligations, and $10.1 million of right-of-use assets and corresponding lease liabilities associated with the acquired~~ properties.

In April 2022, the Company acquired oil and gas properties in the Permian Basin for cash consideration of $197.0 million, representing a $200 million purchase price less customary closing adjustments made pursuant to the acquisition agreement. The acquisition was accounted for as an asset acquisition under ASC Topic 805 and was comprised primarily of undeveloped leasehold acreage with an immaterial amount of production. Nearly all of the purchase price was allocated to unproved properties.

2021

Permian Basin Acquisition

In December 2021, the Company acquired oil and gas assets and properties from certain subsidiaries of Pioneer Natural Resources Company ~~pursuant~~for to$3.06 abillion ~~purchase and sale agreement~~ in ~~which~~cash. ~~the~~The ~~Company~~acquisition ~~purchased:~~method ~~(a)~~under ~~100%~~ASC ofTopic ~~the~~805 ~~issued~~was ~~and~~used ~~outstanding~~to ~~limited~~record ~~liability~~the ~~company interests of Jagged Peak Energy LLC~~transaction, which inrequired ~~turn~~all ~~owned~~assets ~~100%~~acquired ~~of the issued~~ and ~~outstanding~~liabilities ~~limited~~assumed ~~liability~~to ~~company~~be ~~interests~~recorded ofat ~~Parsley~~fair ~~SoDe~~value ~~Water~~at ~~LLC;~~the ~~and~~acquisition ~~(b)~~date. ~~certain~~Of ~~oil and gas assets and properties in~~ the ~~Permian~~purchase ~~Basin (collectively~~price, ~~the “Pioneer Acquisition”)~~$2.4 ~~The~~billion ~~properties~~was ~~included~~allocated ~~approximately~~to ~~92,000~~proved ~~net~~properties ~~leasehold~~and ~~acres,~~$0.7 ~~approximately~~billion ~~50,000~~was ~~net~~allocated ~~royalty acres in the same area normalized~~ to aunproved ~~1/8th royalty, production totaling approximately 42,000 net barrels of oil equivalent per day at the time of closing, and extensive water infrastructure~~properties.

The ~~purchase~~acquisition ~~price~~contributed ~~paid~~$29.4 tomillion ~~the~~of ~~sellers~~revenues ~~was~~and ~~approximately~~$14.1 million ($30.0604 ~~billion~~per inbasic ~~cash,~~and ~~representing~~diluted ashare) ~~$3.25~~of ~~billion~~net ~~purchase~~income ~~price~~to ~~less~~the ~~customary~~Company's ~~closing~~consolidated ~~adjustments~~results ~~made~~during ~~pursuant~~the period of ownership from December 21, 2021 to ~~the~~December ~~agreement~~31, 2021, excluding transaction expenses. The Company ~~funded~~incurred ~~the~~$13.9 ~~purchase~~million ~~price~~of ~~through~~expenses ain ~~combination~~connection ofwith ~~cash~~the ontransaction ~~hand,~~which ~~utilization~~are ofreflected ~~credit~~in ~~facility~~the ~~borrowing~~caption ~~capacity,~~“Transaction ~~and~~costs” in the ~~issuance~~consolidated statements of ~~senior~~income ~~notes.~~for the year ended December 31, 2021.

60The table below summarizes the Company’s pro forma results as if the Pioneer Acquisition and associated increase in debt described in Note 8. Debt had been completed on January 1, 2020 and were combined with the Company's historical results. The following pro forma information is unaudited, is provided for informational purposes only, and does not represent actual results that would have occurred if the Pioneer Acquisition was completed on January 1, 2020, nor are they indicative of future results.

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	Year Ended December 31,
In millions	2021
Pro forma combined total revenues	$	6,657
Pro forma combined net income attributable to Continental	$	2,097

Continental Resources, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

The Pioneer Acquisition was accounted for using the acquisition method under ASC Topic 805, which required all assets acquired and liabilities assumed to be recorded at fair value at the acquisition date. Of the purchase price, $2.4 billion was allocated to proved properties and $0.7 billion was allocated to unproved properties. The Company recognized approximately $16 million of asset retirement obligations and $2 million of right-of-use assets and corresponding lease liabilities associated with the acquired properties.

The Pioneer Acquisition contributed $29.4 million of revenues and $14.1 million ($0.04 per basic and diluted share) of net income to the Company's consolidated results during the period of ownership from December 21, 2021 to December 31, 2021, excluding transaction expenses. The Company incurred $13.9 million of expenses in connection with the transaction which are reflected in the caption “Transaction costs” in the consolidated statements of income (loss) for the year ended December 31, 2021.

The table below summarizes the Company’s pro forma results as if the Pioneer Acquisition and associated increase in debt described in Note 8. Long-Term Debt had been completed on January 1, 2020 and were combined with the Company's historical results. The following pro forma information is unaudited, is provided for informational purposes only, and does not represent actual results that would have occurred if the Pioneer Acquisition was completed on January 1, 2020, nor are they indicative of future results.

	Year Ended December 31,
In millions	2021		2020
Pro forma combined total revenues	$	6,657	$	3,174
Pro forma combined net income (loss) attributable to Continental	$	2,097	$	(481	)

Powder River Basin Acquisitions

InDuring ~~March~~the year ended December 31, 2021, the Company ~~acquired~~completed acquisitions of oil and gas properties in the Powder River Basin for cash consideration oftotaling $~~206.6~~453 million~~, consisting of a $21~~.5 ~~million escrow deposit paid in December 2020 upon execution of the definitive purchase agreement and a $185.1 million payment made at closing in March 2021.~~ The ~~acquisition~~Company ~~was~~ accounted for each acquisition as an asset acquisition under ASC Topic 805—Business ~~and included approximately 130,000 net acres and producing properties with production totaling approximately 7,200 net barrels of oil equivalent per day at the time of closing~~Combinations. Of the purchase ~~price~~prices, ~~$183~~a ~~million~~total ~~was~~of ~~allocated to proved properties and~~ $24210 million was allocated to ~~unproved~~proved properties. ~~The~~and ~~Company~~a ~~recognized~~total ~~approximately $4.9 million~~ of ~~asset retirement obligations and~~ $~~8.2~~243 million ofwas ~~right-of-use~~allocated ~~assets~~to ~~and~~unproved ~~corresponding lease liabilities associated with the acquired~~ properties.

In November 2021, the Company acquired oil and gas properties in the Powder River Basin for cash consideration of $246.8 million. The acquisition was accounted for as an asset acquisition under ASC Topic 805 and included approximately 72,000 net acres and immaterial amounts of production. Of the purchase price, $27 million was allocated to proved properties and $220 million was allocated to unproved properties. The Company recognized approximately $0.5 million of asset retirement obligations and an immaterial amount of right-of-use assets and corresponding lease liabilities associated with the acquired properties.

2020

In October 2020, the Company acquired oil and gas properties in the SCOOP play in the Anadarko Basin for cash consideration of $162.8 million. The acquisition included approximately 19,500 net acres and immaterial amounts of production. Of the purchase price, $15.3 million was allocated to proved properties and $147.5 million was allocated to unproved properties.

Note 3. Supplemental Cash Flow Information

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

Year ended December 31,

In thousands

~~2022~~2023

~~2021~~2022

~~2020~~2021

Supplemental cash flow information:

Cash paid for interest

~~279~~387,~~571~~686

~~214~~279,~~727~~571

~~256~~214,~~633~~727

Cash paid for income taxes (1)

~~470~~566,~~147~~253

3470,147

Cash received for income tax refunds

162

5816

~~9,600~~58

Non-cash investing activities:

Asset retirement obligation additions and revisions, net

30131,~~741~~732

3130,~~060~~741

1731,~~791~~060

(1)

61Amounts for 2023 and 2022 represent estimated quarterly payments for 2023 and 2022 federal and state income taxes based on an estimate of taxable income for each respective year.

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Continental Resources, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

~~Amount~~As ~~for~~of December 31, 2023 and 2022, ~~represents~~the ~~estimated~~Company ~~quarterly~~had ~~payments~~$367.2 ~~for~~million ~~2022~~and U$344.S.9 ~~federal~~million, ~~income~~respectively, ~~taxes~~of ~~based~~accrued oncapital expenditures included in “Net property and equipment” with an ~~estimate~~offsetting ofamount ~~federal~~in ~~taxable~~“Accounts ~~income~~payable ~~for~~trade” in the ~~year.~~consolidated balance sheets.

As of December 31, 2022 and 2021, the Company had $344.9 million and $242.9 million, respectively, of accrued capital expenditures included in “Net property and equipment” with an offsetting amount in “Accounts payable trade” in the consolidated balance sheets.

As of December 31, 2022 and 2021, the Company had $0.5 million and $1.7 million, respectively, of accrued contributions from noncontrolling interests included in “Receivables–Joint interest and other” with an offsetting amount in “Equity–Noncontrolling interests” in the consolidated balance sheets.

As of December 31, 2022 and 2021, the Company had $4.3 million and $2.5 million, respectively, of accrued distributions to noncontrolling interests included in "Revenues and royalties payable" with an offsetting amount in “Equity–Noncontrolling interests” in the consolidated balance sheets.

Note 4. Net Property and Equipment

Net property and equipment includes the following at December 31, ~~2022~~2023 and ~~2021~~2022.

	December 31,
In thousands	~~2022~~2023			~~2021~~2022
Proved crude oil and natural gas properties	$	3437,~~741~~400,~~054~~304		$	3134,~~613~~741,~~656~~054
Unproved crude oil and natural gas properties		1,~~513~~775,~~627~~662			1,~~358~~513,~~673~~627
Service properties, equipment and other		~~549~~1,~~528~~014,093			~~484~~549,~~989~~528
Total property and equipment		3640,~~804~~190,~~209~~059			3336,~~457~~804,~~318~~209
Accumulated depreciation, depletion and amortization		(1820,~~332~~403,~~295~~170	)		(1618,~~481~~332,~~853~~295	)
Net property and equipment	$	1819,~~471~~786,~~914~~889		$	1618,~~975~~471,~~465~~914

Note 5. Accrued Liabilities and Other

Accrued liabilities and other includes the following at December 31, ~~2022~~2023 and ~~2021~~2022:

	December 31,
In thousands	~~2022~~2023		~~2021~~2022
Prepaid advances from joint interest owners	$	1536,~~575~~923	$	1815,~~964~~575
Accrued compensation		8188,~~646~~644		8281,~~844~~646
Accrued production taxes, ad valorem taxes and other non-income taxes		~~145~~133,~~436~~456		90145,~~597~~436
Accrued interest		8379,~~724~~640		7583,~~983~~724
Current portion of asset retirement obligations		39,~~935~~971		43,~~123~~935
Other		135,~~461~~903		13,~~229~~461
Accrued liabilities and other	$	~~343~~354,~~777~~537	$	~~285~~343,~~740~~777

Note 6. Derivative Instruments

From time to time the Company enters into derivative contracts to economically hedge against the variability in cash flows associated with future sales of production. The Company recognizes its derivative instruments on the balance sheet as either assets or liabilities measured at fair value. The estimated fair value is based upon various factors, 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.

62At December 31, 2023 the Company had outstanding derivative contracts as set forth in the tables below.

        Natural gas derivatives

         
        Weighted Average Hedge Price ($/MMBtu)

        Period and Type of Contract

        Average Volumes Hedged

        Swaps

        Floor

        Ceiling

        January 2024 - December 2024

(State or other jurisdiction)

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

20 N. Broadway,

Oklahoma City,

(Address of principal executive offices)

(Zip Code)

Filing Compare · CONTINENTAL RESOURCES, INC