10-K

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company

Emerging growth company

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 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

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.

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

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

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

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

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

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

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

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

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

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

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

“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.

“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.

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

“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.

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

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

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

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

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

Forward-looking statements are based on the Company’s current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes these assumptions and expectations are reasonable, they are inherently subject to numerous business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company’s control. No assurance can be given

that such expectations will be correct or achieved or that the assumptions are accurate or will not change over time. The risks and uncertainties that may affect the operations, performance and results of the business and forward-looking statements include, but are not limited to, those risk factors and other cautionary statements described under Part 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.

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.

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, pad/row development, and enhanced recovery technologies allow us to develop and produce crude oil and natural gas reserves from unconventional formations.

Effective November 22, 2022, Continental Resources, Inc. became a privately held corporation and has no publicly available common shares outstanding. We continue to furnish Quarterly Reports on Form 10-Q and Annual Reports on Form 10-K with the SEC as required by our senior note indentures. See Part II. Item 8. Notes to Consolidated Financial Statements—Note 1. Organization and Summary of Significant Accounting Policies—2022 Take-Private Transaction for additional information.

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 2025, our primary business strategies will include:

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, 2024. Proved reserves attributable to noncontrolling interests are not material relative to our consolidated reserves and are not separately presented herein. Our reserve estimates as of December 31, 2024 are based primarily on a reserve report prepared by Ryder Scott. In preparing its report, Ryder Scott evaluated properties representing approximately 97% of our total proved reserves as of December 31, 2024. 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 at December 31, 2024 were determined using the 12-month unweighted arithmetic average of the first-day-of-the-month commodity prices for the period of January 2024 through December 2024, without giving effect to derivative transactions, and were held constant throughout the lives of the properties. These prices were $75.48 per Bbl for crude oil and $2.13 per MMBtu for natural gas ($71.59 per Bbl for crude oil and $1.55 per Mcf for natural gas adjusted for location and quality differentials).

The following table summarizes our estimated proved reserves by commodity and reserve classification as of December 31, 2024.

The following table provides additional information regarding our estimated proved crude oil and natural gas reserves by region as of December 31, 2024.

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

Revisions of previous estimates. Revisions for 2024 are comprised of (i) downward price revisions of 6 MMBo and 138 Bcf (totaling 29 MMBoe) due to a decrease in average crude oil and natural gas prices in 2024 compared to 2023, (ii) the removal of 86 MMBo and 382 Bcf (totaling 149 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 79 MMBo and 569 Bcf (totaling 174 MMBoe) from the removal of PUD reserves due to changes in anticipated well densities, economics, performance, and other factors, and (iv) downward revisions of 13 MMBo and upward revisions of 528 Bcf (totaling a net upward revision of 75 MMBoe) 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 2024, proved reserve additions totaled 453 MMBoe. See the subsequent section titled Summary of Crude Oil and Natural Gas Properties and Projects for a discussion of our 2024 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 2024, 2023, and 2022 were attributable to our acquisitions of properties as discussed in Part II. Item 8. Notes to Consolidated Financial Statements—Note 2. Property Acquisitions and Dispositions.

All of our PUD reserves at December 31, 2024 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, 2024. Our PUD reserves at December 31, 2024 include 69 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.

Revisions of previous estimates. As previously discussed, in 2024 we removed 86 MMBo and 382 Bcf (totaling 149 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 79 MMBo and 569 Bcf (totaling 174 MMBoe) in 2024. The decreases in average crude oil and natural gas prices in 2024 resulted in downward price revisions of 1 MMBo and 14 Bcf (totaling 3 MMBoe). Finally, changes in ownership interests, operating costs, anticipated production, and other factors resulted in downward revisions of 5 MMBo and upward revisions of 106 Bcf (totaling a net upward revision of 12 MMBoe) in 2024.

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.

Sales of minerals in place. We had no individually significant dispositions of PUD reserves in 2024.

Conversion to proved developed reserves. In 2024, we developed approximately 16% of our PUD locations and 16% of our PUD reserves booked as of December 31, 2023 through the drilling and completion of 334 gross (184 net) development wells at an aggregate capital cost of approximately $1.3 billion incurred in 2024.

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 146 gross (76 net) operated and non-operated locations at December 31, 2024 and represent 8% of our PUD reserves at that date. The costs to drill our uncompleted wells were incurred prior to December 31, 2024 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, 2024 are projected to be approximately $1.9 billion in 2025, $1.8 billion in 2026, $2.1 billion in 2027, $2.2 billion in 2028, and $1.8 billion in 2029. 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, 2024 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, 2024. We had no PUD reserves at December 31, 2024 that remain undrilled beyond five years from the date of initial booking.

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, 97% of our total proved reserves as of December 31, 2024 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 Manager of Corporate Resource Development is the technical person primarily responsible for overseeing the preparation of our reserve estimates. The Manager of Corporate Resource Development reports to our Chief Financial Officer and Executive Vice President of Strategic Planning. 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.

The following table presents our total gross and net developed and undeveloped acres by region as of December 31, 2024:

The following table sets forth the number of gross and net undeveloped acres as of December 31, 2024 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.

During the three years ended December 31, 2024, we participated in the drilling and completion of exploratory and development wells as set forth in the table below.

As of December 31, 2024, there were 260 gross (134 net) operated and non-operated wells that have been spud and are in the process of drilling, completing or waiting on completion.

Our total Bakken production averaged 189,787 Boe per day for the fourth quarter of 2024, down 14% from the 2023 fourth quarter. For the year ended December 31, 2024, our average daily Bakken production decreased 4% compared to 2023. In 2024, we participated in the drilling and completion of 242 gross (96 net) wells in the Bakken compared to 363 gross (166 net) wells in 2023.

Our Bakken properties represented 31% of our total proved reserves at December 31, 2024 and 45% of our average daily Boe production for the 2024 fourth quarter. Our total proved Bakken field reserves as of December 31, 2024 were 558 MMBoe, a decrease of 14% compared to December 31, 2023. Our inventory of proved undeveloped drilling locations in the Bakken totaled 690 gross (368 net) wells as of December 31, 2024.

Our properties in the Anadarko Basin represented 40% of our total proved reserves as of December 31, 2024 and 30% of our average daily Boe production for the fourth quarter of 2024. Production in the Anadarko Basin averaged 126,068 Boe per day during the fourth quarter of 2024, down 13% compared to the 2023 fourth quarter. We participated in the drilling and completion of 95 gross (45 net) wells in the Anadarko Basin during 2024 compared to 120 gross (43 net) wells in 2023.

Our proved reserves in the Anadarko Basin as of December 31, 2024 totaled 732 MMBoe, an increase of 12% compared to December 31, 2023. Our inventory of proved undeveloped drilling locations in the Anadarko Basin totaled 338 gross (202 net) wells as of December 31, 2024.

Our Powder River properties represented 8% of our total proved reserves as of December 31, 2024 and 6% of our average daily Boe production for the 2024 fourth quarter. Our production in the Powder River Basin averaged 27,215 Boe per day for the fourth quarter of 2024, an increase of 6% compared to the 2023 fourth quarter. During 2024, we participated in the drilling and completion of 56 gross (25 net) wells in the play compared to 53 gross (17 net) wells in 2023.

Our proved reserves in the Powder River Basin totaled 143 MMBoe as of December 31, 2024, an increase of 3% compared to December 31, 2023. Our inventory of proved undeveloped drilling locations in the play totaled 133 gross (94 net) wells as of December 31, 2024.

Our Permian properties represented 20% of our total proved reserves at December 31, 2024 and 18% of our average daily Boe production for the 2024 fourth quarter. Our production in the Permian Basin averaged 74,334 Boe per day for the fourth quarter of 2024, an increase of 27% compared to the 2023 fourth quarter. During 2024, we participated in the drilling and completion of 73 gross (68 net) wells in the play compared to 72 gross (66 net) wells in 2023.

Our proved reserves in the Permian Basin totaled 364 MMBoe as of December 31, 2024, a decrease of 6% compared to December 31, 2023. Our inventory of proved undeveloped drilling locations in the play totaled 422 gross (361 net) wells at year-end 2024.

The following table sets forth information concerning our production results, average sales prices and production costs for the years ended December 31, 2024, 2023 and 2022 in total and for each field containing 15 percent or more of our total proved reserves as of December 31, 2024.

The following table sets forth information regarding our average daily production by region for the fourth quarter of 2024:

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, 2024. One or more completions in the same well bore are counted as one well.

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.

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, and Anadarko 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.

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.

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.

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, repealed, 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 are significant areas of regulation that may affect us in the areas in which we operate.

We are subject to stringent, complex, and overlapping federal, state, and local laws, rules and regulations governing environmental compliance, and occupational safety and health, as well as the discharge of materials into, and the protection of, the environment and natural resources. Environmental, health, and safety laws, rules and regulations may relate to, among other things:

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 our 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. Any regulatory 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. 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, health, and safety laws, rules, and regulations.

The Company’s oil and gas operations are subject to various federal, state, and local laws and regulations that relate to matters including, among other things:

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 royalty payments to the federal government, tribes or tribal members. Moreover, the permitting process for oil and gas activities on federal and Indian lands can sometimes be subject to delay, including as a result of challenges to permits or other regulatory decisions brought by non-governmental organizations or other parties, which can hinder development activities or otherwise adversely impact operations. The federal government has, from time to time, evaluated and, in some cases, promulgated new rules and regulations regarding competitive lease bidding, venting and flaring, oil and gas measurement and royalty payment obligations for production from federal lands.

For additional information on the Company’s regulatory risks, see Part 1, Item 1A. Risk Factors—Legal and Regulatory Risks of this report.

As of December 31, 2024, we employed 1,395 people, all of which were employed in the United States, with 795 employees being located at our corporate headquarters in Oklahoma City, Oklahoma and 600 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.

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 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.

We encourage each of our employees to be a proactive participant in ensuring the safety of all of the Company’s personnel. We’ve established programs to recognize and reward 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.

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.

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, 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, and smoking cessation programs to encourage total body wellness.

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.

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.

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.

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:

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

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 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.

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:

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

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. 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, 2024.

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 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.

In addition, the development of our proved undeveloped reserves may take longer than anticipated and may not be ultimately developed or produced. At December 31, 2024, approximately 47% 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, 2024 includes estimates of total future development costs over the next five years associated with our proved undeveloped reserves of approximately $9.8 billion. We cannot be certain the estimated costs of the development of these reserves are accurate, development will occur as scheduled, or the results of such development will be as estimated. If we choose not to spend the capital to develop these reserves, or if we are not otherwise able to successfully develop these reserves as a result of our inability to fund necessary capital expenditures or otherwise, we may be required to remove the associated volumes from our reported proved reserves. Proved undeveloped reserves generally must be drilled within five years from the date of initial booking under SEC reserve rules. Changes in the timing of development plans that impact our ability to develop such reserves in the required time frame have resulted, and may in the future result, in fluctuations in reserves between periods as reserves booked in one period may need to be removed in a subsequent period.

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 28% of our total net undeveloped acreage at December 31, 2024.

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.

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, cybersecurity attacks, adverse climatic events, natural disasters, seismic events, health epidemics and concerns, changes in tax and energy policies or tariffs, 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. 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.

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 2025 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:

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 $1.80 billion that matures in October 2029. 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.

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. Any of these factors may cause costs to rise 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.

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, 2024, non-operated properties represented 12% of our estimated proved developed reserves, 5% of our estimated proved undeveloped reserves, and 9% 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:

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:

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 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.

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 domestic and foreign 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.

Trade restrictions or other governmental actions related to domestic and foreign tariffs or trade policies have impacted in the past, 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, and certain manufactured production equipment, 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 in the past, 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.

A cybersecurity 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 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. 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, cybersecurity incidents, including deliberate attacks or unintentional events, have also evolved and increased in frequency. Cybersecurity attacks are becoming more sophisticated and include, but are not limited to, malicious software, surveillance, credential stuffing, spear phishing, social engineering, use of deepfakes (i.e., highly realistic synthetic media generated by artificial intelligence), ransomware attacks, attempts to gain unauthorized access to data, and other electronic security breaches. Our technologies, systems, networks, and those of our business associates have been and continue to be the target of cybersecurity 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, interruption of operating activities, challenges in maintaining our books 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 those incidents, we deployed our cybersecurity incidence response protocols and took steps to contain and remediate potential vulnerabilities. As of the date of this report, we are not aware of any material 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 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 may 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.

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, fires, 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.

Our revolving credit facility 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 contains 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 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. Debt for a discussion of how this ratio is calculated pursuant to our credit agreement. At December 31, 2024, we had $20 million of outstanding borrowings and $1.78 billion of available borrowing capacity on our credit facility and our consolidated net debt to total capitalization ratio, as defined, was 0.26.

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.

Our ability to comply with the provisions of our revolving credit facility 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 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 ($1.2 billion in receivables at December 31, 2024) and our joint interest and other receivables ($382 million at December 31, 2024). 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 commodity prices 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.

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 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. 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, repealed, or reinterpreted, we are unable to predict the future cost or impact of complying with such laws, rules and regulations.

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, and employees and labor relations.

Failure to comply with 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.

Changes in tax laws or tax rulings could materially affect our financial position, results of operations, and cash flows.

Rules and regulations governing U.S. federal, state, and local income taxation are continually under review and subject to change. It cannot be predicted if changes to current U.S. tax laws and regulations will be introduced as legislation or, if introduced, later enacted and, if enacted, what form such enacted legislation would take. While certain changes to tax laws and regulations may negatively impact our business, certain changes may be beneficial.

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. One or more of these developments could have an adverse effect on our assets and operations.

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

Companies across all industries are facing 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. Attention to climate change, 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 may become more attentive to lending practices that favor power sources such as wind and solar 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 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 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. Our CISO has received certifications relating to information security, security leadership, and forensics from the Global Information Assurance organization.

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.

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; and the Director of Corporate Security. 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.

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.

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

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

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.

The Company has no dividend policy and currently has no plans to pay cash dividends in the future year.

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.

We are an independent crude oil and natural gas company engaged in the exploration, development, management, and production of crude oil and natural gas and associated products with properties primarily located in four leading basins in the United States – the Bakken field of North Dakota and Montana, the Anadarko Basin of Oklahoma, the Permian Basin of Texas, and the Powder River Basin of Wyoming. Additionally, we pursue the acquisition and management of perpetually owned minerals located in certain of our key operating areas. We derive the majority of our operating income and cash flows from the sale of crude oil, natural gas, and natural gas liquids and expect this to continue in the future. As discussed in 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.

Commodity prices have remained volatile due to various factors, some of which include global supply and demand, global inventory levels, and regional conflicts. Average NYMEX oil prices for the years ended December 31, 2024, 2023, and 2022 were $75.75, $77.57, and $94.17, respectively. Average NYMEX gas prices for the years ended December 31, 2024, 2023, and 2022 were $2.26, $2.73, and $6.72, respectively. The following table contains financial and operating metrics for the periods presented. Average sales prices exclude any effect of derivative transactions. Per-unit expenses have been calculated using sales volumes.

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

Below is a discussion of changes in our results of operations for 2024 compared to 2023. A discussion of changes in our results of operations for 2023 compared to 2022 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, 2023 as filed with the SEC on February 22, 2024.

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

The following table summarizes the changes in our production by product for the periods presented.

The 1% decrease in crude oil production and 5% decrease in natural gas production in 2024 compared to 2023 were primarily driven by natural declines in production coupled with planned moderation in capital spending, asset divestitures and variation in the timing of new well completions between years.

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

Crude oil, natural gas, and natural gas liquids sales. Sales for 2024 totaled $7.26 billion, a 6% decrease compared to sales of $7.68 billion for 2023 due to decreases in sales prices coupled with a decrease in sales volumes as discussed below.

Total sales volumes for 2024 decreased 4,515 MBoe, or 3%, compared to 2023 primarily due to the previously described decrease in natural gas production volumes. For 2024, our crude oil sales volumes were consistent with 2023 while our natural gas sales volumes decreased 5% compared to 2023.

Our crude oil sales prices averaged $75.18 per barrel for 2024, a decrease of 2% compared to $76.89 per barrel for 2023 due to a decrease in market prices resulting from changes in various macroeconomic conditions between periods.

Our natural gas sales prices averaged $2.16 per Mcf for 2024, a decrease of 17% compared to $2.60 per Mcf for 2023 due to a decrease in market prices for residue gas and natural gas liquids.

Derivatives. Changes in settled and future commodity prices in 2024 had a net favorable impact on the fair value of our derivatives, which resulted in positive revenue adjustments of $27.2 million for the year, representing $377.6 million of realized cash gains partially offset by $350.4 million of unsettled non-cash losses, compared to positive revenue adjustments totaling $943.8 million in 2023.

Crude oil and natural gas service operations. Our crude oil and natural gas service operations consist primarily of revenues associated with water gathering, recycling, delivery, 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 decreased $9.9 million, or 10%, from $103.7 million for 2023 to $93.8 million for 2024 due to decreased water handling activities resulting from decreases in completion activities and production volumes compared to 2023.

Production expenses. Production expenses increased $53.4 million, or 7%, to $770.9 million for 2024 compared to $717.5 million for 2023 due to an increase in the number of producing wells from drilling and completion activities, costs associated with adverse winter weather conditions in the Bakken and Powder River Basin in the 2024 first quarter, and higher workover-related activities aimed at enhancing production from producing properties. Production expenses on a per-Boe basis averaged $4.94 per Boe for 2024 compared to $4.47 per Boe for 2023.

Production and ad valorem taxes. Production and ad valorem taxes decreased $47.4 million, or 8%, to $556.2 million for 2024 compared to $603.5 million for 2023 due to the previously described decrease in crude oil, natural gas, and NGL sales. Our production taxes as a percentage of net sales averaged 8.1% for 2024 compared to 8.2% for 2023.

Transportation, gathering, processing, and compression. These charges increased $29.0 million, or 9%, to $367.2 million for 2024 compared to $338.2 million for 2023 due to changes in marketing terms and arrangements utilized between periods and an increase in our working interest share of cost burdens in certain operating areas.

Depreciation, depletion, amortization and accretion (“DD&A”). Total DD&A amounted to $2.48 billion for 2024, an increase of $219.1 million, or 10%, compared to $2.26 billion for 2023, due to an increase in our DD&A rate per Boe as further discussed below. The following table shows the components of our DD&A on a unit of sales basis for the periods presented.

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 downward over the past year prompted by decreases in rolling twelve-month average SEC commodity prices and other factors, which contributed to an increase in our DD&A rate for crude oil and natural gas properties in 2024 compared to 2023 along with variation in the mix of sales volumes across the Company's operating areas between periods.

Property impairments. Property impairments decreased $23.6 million to $43.2 million for 2024 compared to $66.8 million for 2023 due in part to $15.5 million of proved property impairments recognized in 2023 compared to no proved property impairments being recognized in 2024. Additionally, impairments of unproved properties decreased $8.1 million in 2024 compared to 2023 reflecting a decrease in the amortization of undeveloped leasehold costs over the past year.

General and administrative (“G&A”) expenses. G&A expenses decreased $15.3 million, or 5%, to $264.0 million for 2024 compared to $279.3 million for 2023. Total G&A expenses include charges for long-term incentive compensation awards of $83.7 million for 2024 compared to $91.3 million for 2023. G&A expenses other than incentive compensation awards totaled $180.3 million for 2024, a decrease of $7.6 million, or 4%, compared to $188.0 million for 2023 primarily due to higher overhead and cost recoveries from joint interest owners compared to 2023.

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

Interest expense. Interest expense decreased $120.0 million, or 30%, to $275.7 million for 2024 compared to $395.8 million for 2023 due to a decrease in our annual weighted average outstanding debt balance from $7.9 billion in 2023 to $5.8 billion in 2024. This decrease was driven by debt reduction throughout 2024, including the reduction of credit facility borrowings, the repayment of our $750 million term loan, and the redemption of our $893 million of 2024 Notes. Our outstanding debt totaled $4.8 billion at December 31, 2024.

Income Taxes. We provided for income taxes at a combined federal and state tax rate of 23.5% for both 2024 and 2023. We recorded income tax provisions of $471.8 million and $827.6 million for 2024 and 2023, respectively, which resulted in effective tax rates of 19.0% and 21.1%, 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 2024 and 2023.

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

At February 1, 2025, we had $1.8 billion of borrowing availability under our credit facility. Our credit facility, which is unsecured and has no borrowing base subject to redetermination, does not mature until October 2029.

Based on our planned capital spending, our forecasted cash flows, and projected levels of indebtedness, we expect to maintain compliance with the covenants under our credit facility and senior note indentures. Further, based on current market indications, we expect to meet our contractual cash commitments to third parties 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.

Net cash provided by operating activities decreased $422.2 million, or 8%, to $4.64 billion for 2024 compared to $5.06 billion for 2023. This decrease was driven by a $427.6 million decrease in crude oil, natural gas, and NGL revenues along with increases in certain cash operating expenses including a $53.4 million increase in production expenses, a $29.0 million increase in transportation, gathering, processing, and compression expenses, and a $139.2 million increase in cash payments for income taxes. These decreases in cash flows were partially offset by a $120.4 million improvement in realized cash settlements on matured commodity derivatives, a $116.8 million decrease in cash paid for interest, and a $47.4 million decrease in production and ad valorem taxes.

Net cash used in investing activities totaled $2.78 billion for 2024 compared to $3.56 billion for 2023. Our investing cash flows for 2024 included $3.03 billion of exploration and development costs compared to $3.55 billion of exploration and development costs for 2023, reflecting variation in the timing of our capital spending between periods. In addition, net cash used in investing activities was further decreased by lower acquisitions of producing crude oil and natural gas properties, with $9 million acquired in 2024 compared to $161 million acquired in 2023, as well as increased proceeds from the sale of assets with $546 million of proceeds received in 2024 compared to $390 million of proceeds received in 2023.

Net cash used in financing activities for 2024 totaled $1.84 billion, primarily consisting of $190 million of net repayments on our credit facility, $893 million of cash used to redeem senior notes, and $752 million of cash used for the repayment of our term loan.

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

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

Based on current market indications supported by cash flow protection provided by our hedge portfolio against commodity price declines, our budgeted capital spending plans for 2025 are expected to be funded from operating cash flows. Any deficiencies in operating cash flows relative to budgeted spending are expected to be funded by borrowings under our credit facility. If cash flows are materially impacted by declines in commodity prices, we have the ability to reduce our capital expenditures or utilize the availability of our credit facility if needed to fund our operations.

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

We have an unsecured credit facility, maturing in October 2029, with aggregate lender commitments totaling $1.8 billion. The commitments are from a syndicate of 14 banks and financial institutions. We believe each member of the current syndicate has the capability to fund its commitment.

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

Our credit facility contains restrictive covenants that may limit our ability to, among other things, incur additional indebtedness, incur liens, engage in sale and leaseback transactions, or merge, consolidate or sell all or substantially all of our assets. Our credit facility also contains a requirement that we maintain a consolidated net debt to total capitalization ratio of no greater than 0.65 to 1.00. See

Part II, Item 8. Notes to Consolidated Financial Statements—Note 8. 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, 2024 and expect to maintain compliance. At December 31, 2024, our consolidated net debt to total capitalization ratio was 0.26. 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.

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, 2024, recognizing we may be required to meet such commitments even if our business plan assumptions were to change.

Our debt includes outstanding senior note obligations totaling $4.8 billion at December 31, 2024, exclusive of interest payment obligations thereon. Our senior notes are not subject to any mandatory redemption or sinking fund requirements. The earliest scheduled senior note maturity is our $800 million of 2026 Notes due in November 2026. For further information on the face values, maturity dates, semi-annual interest payment dates, optional redemption periods and covenant restrictions related to our senior notes, refer to Note 8. Debt in Part II, Item 8. Notes to Consolidated Financial Statements.

We were in compliance with our senior note covenants at December 31, 2024 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.

As of February 1, 2025, we had no outstanding borrowings on our credit facility. Our credit facility matures in October 2029.

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, 2024 under the arrangements amount to approximately $799 million. A portion of these future costs will be borne by other interest owners. See Part II, Item 8. Notes to Consolidated Financial Statements—Note 13. Commitments and Contingencies for additional information.

For the year ended December 31, 2024, we invested $3.27 billion in our capital program excluding $24.3 million of unbudgeted acquisitions, excluding $20.5 million of mineral acquisitions attributable to Franco-Nevada, and including $9.2 million of capital costs associated with increased accruals for capital expenditures as compared to December 31, 2023.

For 2025, our capital expenditures budget attributable to us is $2.83 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 2025 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.

For the year ended December 31, 2024, we made cash payments for federal and state income taxes totaling $705.4 million, representing payments associated with 2023 tax return filing extensions and estimated quarterly payments for 2024 federal and state income taxes based on estimates of taxable income for 2024. Significant judgment is involved in estimating future taxable income as we are required to make assumptions about future commodity prices, projected production, development activities, capital spending,

profitability, and general economic conditions, all of which are subject to material revision in future periods as better information becomes available. If commodity prices remain at current levels, we expect to continue generating significant taxable income through at least year-end 2025, which would result in us continuing to make estimated tax payments on a quarterly basis in 2025. 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.

As discussed in Note 15. Incentive Compensation in Part II, Item 8. Notes to Consolidated Financial Statements we have recognized a current liability of $74.5 million and a non-current liability of $36.5 million in the consolidated balance sheets associated with unvested incentive compensation awards granted to employees that are scheduled to vest in 2025, 2026, and 2027. 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, 2024 was paid in cash to employees in February 2025 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.

See Note 7. Fair Value Measurements—Stock Redemption Option in Part II, Item 8. Notes to Consolidated Financial Statements.

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, 2024, 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.

In recent years 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.

The fair value of our derivative instruments at December 31, 2024 was a net asset of $157.5 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, 2024. The estimated fair value of our derivatives is highly sensitive to market price volatility and therefore subject to significant fluctuations from period to period. See Item 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, 2024. Between January 1, 2025 and February 14, 2025 we entered into additional derivative instruments as summarized below.

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.

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 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. 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.

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.

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.

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.

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.

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.

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.

No impairments were recognized for our proved crude oil and natural gas properties for the year ended December 31, 2024 as estimated future cash flows were determined to be in excess of cost basis. Commodity price assumptions used for the year-end December 31, 2024 impairment calculations were based on publicly available average annual forward commodity strip prices through year-end 2029 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, 2024, the publicly available forward commodity strip prices for the year 2029 used in our fourth quarter impairment calculations averaged $63.01 per barrel for crude oil and $3.58 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 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 a valuation allowance. We believe our deferred tax assets at December 31, 2024 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.

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.

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 that result in stringent and costly requirements for our business. See Part I, Item 1. Business—Regulation of the Crude Oil and Natural Gas Industry for a summary of significant laws and regulations that may affect us in the areas in which we operate. There is the potential for the revision or repeal of existing laws and regulations or the adoption of new legislation that could affect our industry.

Inflationary pressures experienced in recent years may continue in 2025. Some of the underlying factors impacting inflation may include, but are not limited to, global supply chain disruptions, the imposition of trade restrictions or other governmental actions related to tariffs or trade policies, shipping bottlenecks, labor market constraints, increased competition for goods and services in response to improved energy industry operating conditions, and side effects from monetary and fiscal policies. If inflationary pressures persist or worsen, we may incur additional costs for equipment and materials, and from service providers. Our budgeted expenditures include an estimate for the impact of cost inflation and, despite inflationary pressures, we expect to continue generating significant amounts of free cash flow at current commodity price levels.

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, 2024, and excluding any effect of our derivative instruments in place, our annual revenue would increase or decrease by approximately $846 million for each $10.00 per barrel change in crude oil prices at December 31, 2024 and $417 million for each $1.00 per Mcf change in natural gas prices at December 31, 2024.

To reduce price risk caused by market fluctuations in commodity prices, from time to time we economically hedge a portion of our anticipated production as part of our risk management program. In addition, we may utilize basis contracts to hedge the differential between derivative contract index prices and those of our physical pricing points. Reducing our exposure to price volatility helps secure funds to be used for our capital program and 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, 2024 was a net asset of $157.5 million, which is comprised of a $145 million net asset associated with our natural gas derivatives and a $12.5 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, 2024.

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 ($1.2 billion in receivables at December 31, 2024) and our joint interest and other receivables ($382 million at December 31, 2024).

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 $65 million at December 31, 2024, 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 may have outstanding from time to time on our credit facility. Such borrowings bear interest at market-based interest rates plus a margin based on the terms of the

borrowing and the credit ratings assigned to our senior, unsecured, long-term indebtedness. All of our other long-term indebtedness is fixed rate and does not expose us to the risk of cash flow loss due to changes in market interest rates.

We had no variable rate borrowings outstanding on our credit facility at February 1, 2025.

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

The following table presents our debt maturities and the weighted average interest rates by expected maturity date as of December 31, 2024:

These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company’s consolidated 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 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. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such 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.

The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate 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 separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

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 of 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. 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 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 principle consideration for our determination that 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 is a critical audit matter is that relatively minor changes in certain highly subjective inputs and assumptions that are necessary to estimate the volumes of 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 the assessment/measurement of impairment expense 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, included the following, among others:

Accounting treatment and valuation of the optionality features of the share Redemption Agreement.

As described in Note 7 to the consolidated financial statements, the Company entered into a share Redemption Agreement in June 2024 with Harold Hamm and certain members of his family. This agreement was subsequently amended in December 2024. The resulting liability for the optionality features contained in this agreement is specifically impacted by the timing of the redemption, if any, and the potential estate tax liability for Mr. Hamm’s estate. We identified the accounting treatment and the valuation of the optionality features of the Redemption Agreement and the December 2024 amendment developed using significant level 3 unobservable inputs as a critical audit matter.

The principal consideration for our determination that the accounting treatment and valuation of the optionality features of the Redemption Agreement is a critical audit matter is that the estimate involves significant management judgment, highly subjective and complex estimations, and unobservable inputs. In addition, the audit effort involved the use of professionals with specialized skill and knowledge to assist in performing these procedures and evaluating the audit evidence obtained.

Our audit procedures related to the accounting and valuation of the optionality features of the Redemption Agreement and the December 2024 amendment included the following, among others.

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 November 22, 2022, the Company completed a series of take-private transactions with Omega Acquisition, Inc, an entity owned by the Company’s founder, Harold G. Hamm, pursuant to which the Company became wholly owned by Mr. Hamm, certain members of his family and their affiliated entities (the “Hamm Family”). A total of 58.1 million shares of Continental’s common stock were purchased pursuant to the take-private transaction for total cash consideration of $4.31 billion. The 2022 purchase of outstanding shares was funded by Continental through the use of $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. 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.

Following the consummation of the transactions in November 2022: (i) our common stock ceased to be listed on the New York Stock Exchange, (ii) our common stock was deregistered under Section 12(b) of the Securities Exchange Act of 1934 as amended (the “Exchange Act”), and (iii) we suspended our reporting obligations under Section 15(d) of the Exchange Act. 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 and equity attributable to the noncontrolling interests are presented separately in the Company’s financial statements.

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

The Company evaluated its December 31, 2024 financial statements for subsequent events through February 24, 2025, 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.

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, 2024, the Company had cash deposits in excess of federally insured amounts of approximately $37.1 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 $4.1 million and $3.2 million as of December 31, 2024 and 2023, 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, 2024, sales to the Company's largest purchaser accounted for approximately 10.2% of the Company's total crude oil and natural gas sales. No other purchaser accounted for more than 10% of the Company’s total crude oil, natural gas, and natural gas liquids sales for 2024. 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

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, 2024 and 2023 consisted of the following:


	December 31,
In thousands	2024		2023
Tubular goods and equipment	$	61,502	$	65,205
Crude oil		122,608		125,557
Natural gas		141		—
Total	$	184,251	$	190,762

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.

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		5-15
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 annual reserve reports. Revisions are accounted for prospectively as changes in accounting estimates.

Asset 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.

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, 2022 through December 31, 2024:


In thousands	2024			2023			2022
Asset retirement obligations at January 1	$	401,928		$	261,087		$	219,824
Accretion expense		22,239			14,818			12,857
Revisions (1)		15,352			112,803			(6,672	)
Plus: Additions for new assets		18,720			18,929			37,413
Less: Plugging costs and sold assets		(17,423	)		(5,709	)		(2,335	)
Total asset retirement obligations at December 31	$	440,816		$	401,928		$	261,087
Less: Current portion of asset retirement obligations at December 31 (2)		8,321			9,971			3,935
Non-current portion of asset retirement obligations at December 31	$	432,495		$	391,957		$	257,152

(1)

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, 2024 and 2023, net property and equipment on the consolidated balance sheets included $200.3 million and $204.2 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.

Debt issuance costs

Costs incurred in connection with the execution of the Company’s notes payable and revolving credit facility 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 $40.5 million and $46.5 million (net of accumulated amortization of $36.6 million and $37.3 million) relating to its long-term debt at December 31, 2024 and 2023, respectively.

Unamortized capitalized costs associated with the Company’s Notes and note payable totaled $31.7 million and $39.4 million at December 31, 2024 and 2023, 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 $8.7 million and $7.1 million at December 31, 2024 and 2023, respectively, and are reflected in “Other noncurrent assets” on the consolidated balance sheets.

For the years ended December 31, 2024, 2023 and 2022, the Company recognized amortization expense associated with capitalized debt issuance costs of $8.5 million, $10.0 million, and $9.3 million, respectively, which are reflected in “Interest expense” on the consolidated statements of income.

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 under the caption “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, stock redemption option, 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 at December 31, 2024 and 2023.

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.

Adoption of new accounting pronouncement and segment reporting

In November 2023, the Financial Accounting Standards Board issued Accounting Standards Update ("ASU") 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures. The ASU requires incremental disclosures related to reportable segments and requires additional disclosures of significant segment expenses among other items. The ASU is effective for fiscal years beginning after December 15, 2023, and interim periods in fiscal years beginning after December 15, 2024. The Company retrospectively adopted ASU 2023-07 for the year ending December 31, 2024.

The Company has one reportable segment due to the similar nature of its business, which is the exploration, development, and production of crude oil, natural gas, and natural gas liquids in the United States. The Company's President and CEO is the chief operating decision maker and he reviews consolidated net income to assess performance and determine how to allocate resources. The measure of segment assets is reported on the consolidated balance sheets as total assets. As a single reportable segment entity, the financial information is contained in Part II. Item 8. Consolidated Financial Statements.

Recently issued accounting pronouncements not yet adopted

In December 2023, the Financial Accounting Standards Board issued ASU 2023-09, Income Taxes (Topic 280): Improvements to Income Tax Disclosures. This ASU requires public business entities on an annual basis to disclose specific categories in a tabular rate reconciliation and provide additional information for reconciling items that meet a five percent quantitative threshold. Additionally, the ASU requires all entities to disclose the amount of income taxes paid disaggregated by federal, state, and foreign taxes, as well as individual jurisdictions where income taxes paid are equal to or greater than five percent of total income taxes paid. ASU 2023-09 is effective for annual periods beginning after December 15, 2024. Early adoption is permitted and the adoption should be applied on a prospective basis, with a retrospective application permitted in the financial statements. The Company is currently evaluating the impact of the new standard on its consolidated financial statements and related disclosures. We intend to adopt the provisions of this ASU in the fourth quarter of 2025.

In November 2024, the Financial Accounting Standards Board issued ASU 2024-03, Income Statement – Reporting Comprehensive Income – Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses. This ASU requires

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	2024		2023		2022
Supplemental cash flow information:
Cash paid for interest	$	270,934	$	387,686	$	279,571
Cash paid for income taxes (1)		705,405		566,253		470,147
Cash received for income tax refunds		3,266		2		16
Non-cash investing activities:
Asset retirement obligation additions and revisions, net		34,072		131,732		30,741

(1)

Amounts represent estimated quarterly payments for 2024, 2023, and 2022 federal and state income taxes based on an estimate of taxable income for each respective year.

As of December 31, 2024 and 2023, the Company had $376.4 million and $367.2 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.

Note 5. Accrued Liabilities and Other

Accrued liabilities and other includes the following at December 31, 2024 and 2023:


	December 31,
In thousands	2024		2023
Prepaid advances from joint interest owners	$	65,495	$	36,923
Accrued compensation		87,331		88,644
Accrued production taxes, ad valorem taxes and other non-income taxes		125,574		133,456
Accrued interest		70,581		79,640
Current portion of asset retirement obligations		8,321		9,971
Other		55,734		5,903
Accrued liabilities and other	$	413,036	$	354,537

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.

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


Natural gas derivatives
Period and Type of Contract	Average Volumes Hedged			Weighted Average Hedge Price ($/MMBtu)
January 2025 - December 2025
Swaps - Henry Hub		603,000	MMBtus/day	$	3.91
January 2026 - December 2026
Swaps - Henry Hub		635,000	MMBtus/day	$	4.11
January 2027 - December 2027
Swaps - Henry Hub		613,000	MMBtus/day	$	3.92


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

Derivative gains and losses

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


	Year ended December 31,
In thousands	2024			2023			2022
Cash received (paid) on derivatives:
Crude oil fixed price swaps	$	58,950		$	17,989		$	—
Crude oil NYMEX roll swaps		(12	)		3,519			(9,234	)
Natural gas basis swaps		—			4,818			9,674
Natural gas WAHA swaps		40,184			19,435			(16,350	)
Natural gas fixed price swaps		262,394			178,529			(353,326	)
Natural gas collars		16,069			29,139			(66,596	)
Natural gas three-way collars		—			3,741			(22,287	)
Cash received (paid) on derivatives, net		377,585			257,170			(458,119	)
Non-cash gain (loss) on derivatives:
Crude oil fixed price swaps		(133,711	)		134,548			11,696
Crude oil NYMEX roll swaps		(6,888	)		4,051			1,879
Natural gas basis swaps		—			(8,910	)		9,088
Natural gas WAHA swaps		(21,523	)		2,138			19,386
Natural gas fixed price swaps		(176,372	)		513,129			(219,388	)
Natural gas collars		(11,923	)		42,240			(34,303	)
Natural gas three-way collars		—			(598	)		(1,334	)
Non-cash gain (loss) on derivatives, net		(350,417	)		686,598			(212,976	)
Gain (loss) on derivative instruments, net	$	27,168		$	943,768		$	(671,095	)

Balance sheet offsetting of derivative assets and liabilities

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

The following table presents the gross amounts of recognized derivative assets and liabilities, the amounts offset under netting arrangements with counterparties, and the resulting net amounts presented in the consolidated balance sheets at December 31, 2024 and 2023, all at fair value.


	December 31,
In thousands	2024			2023
Commodity derivative assets:
Gross amounts of recognized assets	$	168,023		$	510,375
Gross amounts offset on balance sheet		(10,370	)		(1,862	)
Net amounts of assets on balance sheet		157,653			508,513
Commodity derivative liabilities:
Gross amounts of recognized liabilities		(10,513	)		(2,448	)
Gross amounts offset on balance sheet		10,370			1,862
Net amounts of liabilities on balance sheet	$	(143	)	$	(586	)

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


	December 31,
In thousands	2024			2023
Derivative assets	$	95,227		$	353,261
Derivative assets, noncurrent		62,426			155,252
Net amounts of assets on balance sheet		157,653			508,513
Derivative liabilities		—			—
Derivative liabilities, noncurrent		(143	)		(586	)
Net amounts of liabilities on balance sheet		(143	)		(586	)
Total derivative assets (liabilities), net	$	157,510		$	507,927

Note 7. Fair Value Measurements

The Company follows a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows:

•

Level 1: Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date.

•

Level 2: Observable market-based inputs or unobservable inputs corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date.

•

Level 3: Unobservable inputs not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value.

A financial instrument’s categorization within the hierarchy is based upon the lowest level of input that is significant to the fair value measurement. Level 1 inputs are given the highest priority in the fair value hierarchy while Level 3 inputs are given the lowest priority. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the hierarchy. As Level 1 inputs generally provide the most reliable evidence of fair value, the Company uses Level 1 inputs when available.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

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

The following tables summarize the valuation of derivative instruments by pricing levels that were accounted for at fair value on a recurring basis as of December 31, 2024 and 2023.


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


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

Assets Measured at Fair Value on a Nonrecurring Basis

Certain assets are reported at fair value on a nonrecurring basis in the consolidated financial statements. The following methods and assumptions were used to estimate the fair values for those assets.

Asset impairments – 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. 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. Due to the unavailability of relevant comparable market data, a discounted cash flow method is used to determine the fair value of proved properties. Significant unobservable inputs (Level 3) utilized in the determination of discounted future net cash flows include future commodity prices adjusted for differentials, forecasted production based on decline curve analysis, estimated future operating and development costs, property ownership interests, and a 10% discount rate. At December 31, 2024, the Company’s commodity price assumptions were based on forward NYMEX strip prices through year-end 2029 and were then escalated at 3% per year thereafter. Operating cost assumptions were based on current costs escalated at 3% per year beginning in 2026.

Unobservable inputs to the Company’s fair value assessments are reviewed and revised as warranted based on 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, or other economic factors. Fair value measurements of proved properties are reviewed and approved by certain members of the Company’s management.

For the year ended December 31, 2024, estimated future net cash flows were determined to be in excess of cost basis, and therefore no impairments were recorded for the Company's proved crude oil and natural gas properties in 2024. For the years ended December 31, 2023 and 2022, the Company determined the carrying amounts of certain proved properties were not recoverable from future cash flows, and therefore, were impaired. Such impairments totaled $15.5 million and $17.5 million for 2023 and 2022, respectively.

Certain unproved crude oil and natural gas properties were impaired during the years ended December 31, 2024, 2023, and 2022, reflecting recurring amortization of undeveloped leasehold costs on properties the Company expects 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 following table sets forth the non-cash impairments of both proved and unproved properties for the indicated periods. Proved and unproved property impairments are recorded under the caption “Property impairments” in the consolidated statements of income.


	Year ended December 31,
In thousands	2024		2023		2022
Proved property impairments	$	—	$	15,455	$	17,520
Unproved property impairments		43,199		51,343		52,897
Total	$	43,199	$	66,798	$	70,417

Financial Instruments Not Recorded at Fair Value

The following table sets forth the estimated fair values of financial instruments that are not recorded at fair value in the consolidated financial statements. See Note 8. Debt for discussion of the changes in the Company’s outstanding debt in 2024 and 2023.


	December 31, 2024				December 31, 2023
In thousands	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Debt:
Credit facility	$	20,000	$	20,000	$	210,000	$	210,000
Term Loan		—		—		748,092		748,092
Notes payable		15,159		13,900		17,642		16,300
3.8% Senior Notes due 2024		—		—		892,610		886,400
2.268% Senior Notes due 2026		797,056		758,400		795,541		736,400
4.375% Senior Notes due 2028		995,635		972,200		994,327		968,000
5.75% Senior Notes due 2031		1,487,175		1,481,700		1,485,460		1,490,900
2.875% Senior Notes due 2032		793,740		655,500		792,977		647,100
4.9% Senior Notes due 2044		692,682		564,800		692,463		556,400
Total debt	$	4,801,447	$	4,466,500	$	6,629,112	$	6,259,592

The fair value of credit facility borrowings approximate carrying value based on borrowing rates available to the Company for bank loans with similar terms and maturities and are classified as Level 2 in the fair value hierarchy.

The fair value of notes payable is determined using a discounted cash flow approach based on the interest rate and payment terms of the notes payable and an assumed discount rate. The fair value of notes payable is significantly influenced by the discount rate assumption, which is derived by the Company and is unobservable. Accordingly, the fair value of notes payable is classified as Level 3 in the fair value hierarchy.

The fair values of the Company’s senior notes are based on quoted market prices and, accordingly, are classified as Level 1 in the fair value hierarchy.

The carrying values of all classes of cash and cash equivalents, trade receivables, and trade payables are considered to be representative of their respective fair values due to the short term maturities of those instruments.

Stock Redemption Option

In conjunction with estate planning for Harold G. Hamm, in June 2024 Continental entered into a Redemption Agreement with Mr. Hamm and certain members of his family whereby, following Mr. Hamm’s passing, his estate may, but is not obligated to, elect from time-to-time to require Continental to redeem sufficient shares to enable the estate to fund the payment of estate taxes and interest as they become due. Mr. Hamm’s potential estate tax liability is expected to be primarily based on the fair market value his estate assigns to his Continental stock at the time of passing. The future value of Continental, the resulting estate tax liability, and the potential number of shares Continental may be required to redeem under the agreement are subject to numerous uncertainties and cannot be reasonably quantified at present. The agreement contemplates that Mr. Hamm’s estate will defer and pay the potential estate taxes and related interest in installments over a period of up to 14 years as permitted by the Internal Revenue Code, with the first five years being comprised of interest-only payments and the remaining nine years being comprised of principal and interest payments. Assuming the estate elects to exercise its redemption rights, Continental’s potential obligations are expected to occur over the same 14 year period in conjunction with the estate’s installment payments. The redemption agreement has no specified number of shares to be redeemed, no specified share repurchase price, no fixed duration of time, and no determinable cash outflows, all of which are unknown and subject to change based on the tax laws in effect and the value of Continental to be determined after Mr. Hamm’s passing.

In June 2024 upon execution of the agreement, the Company initially recognized a $388 million liability on its balance sheet within the caption “Other noncurrent liabilities” with a corresponding charge to "Other income (expense)—Other” on the statement of income for the second quarter of 2024 to reflect the fair value of the redemption optionality features contained in the arrangement pursuant to ASC Topic 820, Fair Value Measurement. Such value was determined using simulation models that consider various unobservable inputs and thus represents a Level 3 measurement under the ASC 820 valuation hierarchy.

Note 8. Debt

The Company's debt, net of unamortized discounts, premiums, and debt issuance costs totaling $33.8 million and $41.7 million at December 31, 2024 and 2023, respectively, consists of the following.


	December 31,
In thousands	2024		2023
Credit facility	$	20,000	$	210,000
Term loan		—		748,092
Notes payable		15,159		17,642
3.8% Senior Notes due 2024		—		892,610
2.268% Senior Notes due 2026		797,056		795,541
4.375% Senior Notes due 2028		995,635		994,327
5.75% Senior Notes due 2031		1,487,175		1,485,460
2.875% Senior Notes due 2032		793,740		792,977
4.9% Senior Notes due 2044		692,682		692,463
Total debt		4,801,447		6,629,112
Less: Current portion of long-term debt		2,587		895,105
Long-term debt, net of current portion	$	4,798,860	$	5,734,007

Credit Facility

The Company has a credit facility, maturing in October 2029, with aggregate lender commitments totaling $1.8 billion. The credit facility is unsecured and has no borrowing base requirement subject to redetermination.

The Company had $20 million of outstanding borrowings on its credit facility at December 31, 2024. Credit facility borrowings bear interest at market-based interest rates plus a margin based on the terms of the borrowing and the credit ratings assigned to the Company’s senior, unsecured, long-term indebtedness. The weighted-average interest rate on outstanding credit facility borrowings at December 31, 2024 was 6.1%.

The Company had approximately $1.78 billion of borrowing availability on its credit facility at December 31, 2024 after considering outstanding borrowings and letters of credit. The Company incurs commitment fees based on currently assigned credit ratings of 0.20% per annum on the daily average amount of unused borrowing availability.

The credit facility contains certain restrictive covenants, including a requirement that the Company maintain a consolidated net debt to total capitalization ratio of no greater than 0.65 to 1.00. This ratio represents the ratio of (a) net debt (calculated as total face value of debt plus outstanding letters of credit less cash and cash equivalents) divided by (b) the sum of net debt plus total shareholders' equity (i) plus, to the extent resulting in a reduction of total shareholders’ equity, the amount of any non-cash impairment charges incurred, net of any tax effect, after June 30, 2014 and (ii) plus (to the extent resulting in a reduction of total shareholders’ equity) or minus (to

the extent resulting in an increase of total shareholders’ equity), as applicable, the amount of the non-cash impact of the accounting treatment for the Redemption Agreement, which amount shall be further adjusted, (x) if the Redemption Agreement is amended without the lenders consent and has the effect of materially increasing the scope of the Company's obligations beyond the last form of the Redemption Agreement that was approved by the lenders and (y) to reflect the impact of any cash payments actually made under the agreement. The Company was in compliance with the credit facility covenants at December 31, 2024.

Senior Notes

The following table summarizes the face values, maturity dates, semi-annual interest payment dates, and optional redemption periods related to the Company’s outstanding senior note obligations at December 31, 2024.

         
        2026 Notes

        2028 Notes

        2031 Notes

        2032 Notes

        2044 Notes

Face value (in thousands)

800,000

1,000,000

1,500,000

800,000

700,000

        Maturity date

        November 15, 2026

        January 15, 2028

        January 15, 2031

        April 1, 2032

        June 1, 2044

        Interest payment dates

        May 15, Nov 15

        Jan 15, July 15

        Jan 15, Jul 15

        April 1, Oct 1

        June 1, Dec 1

        Make-whole redemption period (1)

        Nov 15, 2023

        Oct 15, 2027

        Jul 15, 2030

        January 1. 2032

        Dec 1, 2043

(1)

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

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

The indentures governing the Company’s senior notes contain covenants that, among other things, limit the Company’s ability to create liens securing certain indebtedness, enter into certain sale-leaseback transactions, or consolidate, merge or transfer certain assets. These covenants are subject to a number of important exceptions and qualifications. The Company was in compliance with these covenants at December 31, 2024.

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

Retirement of Senior Notes

2024

In June 2024, the Company repaid its outstanding $893.1 million of 2024 Notes that were scheduled to mature on June 1, 2024. The redemption price was equal to 100% of the principal amount plus accrued and unpaid interest to the redemption date. The aggregate of the principal amount and accrued interest paid upon redemption was $910.1 million.

2023

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

2022

In 2022, the Company repurchased a portion of its 2023 Notes and 2024 Notes in open market transactions, including $13.6 million face value of its 2023 Notes at an aggregate cost of $13.9 million and $17.9 million face value of its 2024 Notes at an aggregate cost of $18.3 million, in each case, including accrued and unpaid interest to the repurchase dates. The Company recognized pre-tax losses on extinguishment of debt totaling $0.4 million related to the repurchases.

Repayment of Term Loan

In November 2022, the Company borrowed $750 million under a three-year term loan agreement that was scheduled to mature in November 2025. The Company repaid $100 million of the term loan during the three months ended March 31, 2024 and repaid the

Note 9. Revenues

Below is a discussion of the nature, timing, and presentation of revenues arising from the Company’s major revenue-generating arrangements.

Operated crude oil revenues – The Company pays third parties to transport the majority of its operated crude oil production from lease locations to downstream market centers, at which time the Company’s customers take title and custody of the product in exchange for prices based on the particular market where the product was delivered. Operated crude oil 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. Crude oil sales proceeds from operated properties are generally received by the Company within one month after the month in which a sale has occurred. Operated crude oil revenues are presented separately from transportation expenses, as the Company controls the operated production prior to its transfer to customers. Transportation expenses associated with the Company’s operated crude oil production totaled $317.8 million, $284.2 million, and $254.0 million for the years ended December 31, 2024, 2023, and 2022, respectively.

Operated natural gas revenues – The Company sells a substantial majority of its operated natural gas production to midstream customers at its lease locations based on market prices in the field where the sales occur. Under these arrangements, the midstream customers obtain control of the unprocessed gas stream inclusive of natural gas liquids (“NGLs”) at the lease location and the Company’s revenues from each sale are determined using contractually agreed pricing formulas which contain multiple components, including the volume and Btu content of the natural gas sold, the midstream customer's proceeds from the sale of residue gas and NGLs at secondary downstream markets, and contractual pricing adjustments reflecting the midstream customer's estimated recoupment of its investment over time. Such revenues are recognized net of pricing adjustments applied by the midstream customer during the month in which control transfers to the customer at the delivery point and it is probable the Company will collect the consideration it is entitled to receive. Natural gas and NGL sales proceeds from operated properties are generally received by the Company within one month after the month in which a sale has occurred.

Under certain arrangements, the Company may elect to take a volume of processed residue gas and/or NGLs in-kind at the tailgate of the midstream customer’s processing plant in lieu of a monetary settlement for the sale of the Company's operated production. When the Company elects to take volumes in kind, it takes possession of the processed products at the tailgate of the processing facility and either sells them at the tailgate or pays third parties to transport the products to downstream delivery points, where it then sells to customers at prices applicable to those downstream markets. In such situations, operated revenues are recognized during the month in which control transfers to the customer at the delivery point and it is probable the Company will collect the consideration it is entitled to receive. Operated sales proceeds are generally received by the Company within one month after the month in which a sale has occurred. In these scenarios, the Company’s revenues include the pricing adjustments applied by the midstream processing entity according to the applicable contractual pricing formula, but exclude the transportation expenses the Company incurs to transport the processed products to downstream customers. Transportation expenses associated with these arrangements totaled $49.5 million, $54.0 million, and $62.4 million for the years ended December 31, 2024, 2023, and 2022, respectively.

Non-operated crude oil, natural gas, and NGL revenues – The Company’s proportionate share of production from non-operated properties is generally marketed at the discretion of the operators. For non-operated properties, the Company receives a net payment from the operator representing its proportionate 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 to be received 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. Proceeds are generally received by the Company within two to three months after the month in which production occurs.

Revenues from derivative instruments – See Note 6. Derivative Instruments for discussion of the Company’s accounting for its derivative instruments.

Revenues from service operations – Revenues from the Company’s crude oil and natural gas service operations consist primarily of revenues associated with water gathering, recycling, delivery, and disposal activities. Revenues associated with such activities, which are derived using market-based rates or rates commensurate with industry guidelines, are recognized during the month in which services are performed, the Company has an unconditional right to receive payment, and collectability is probable. Payment is generally received by the Company within one month after the month in which services are provided.

Disaggregation of revenues

The following table presents the disaggregation of the Company’s crude oil and natural gas revenues for the periods presented. Sales of natural gas and NGLs are combined, as a substantial majority of the Company’s natural gas sales contracts represent wellhead sales of unprocessed gas.


	Year ended December 31,
	2024						2023						2022
In thousands	Crude Oil		Natural Gas and NGLs		Total		Crude Oil		Natural Gas and NGLs		Total		Crude Oil		Natural Gas and NGLs		Total
Bakken	$	3,386,418	$	283,248	$	3,669,666	$	3,777,412	$	380,359	$	4,157,771	$	3,899,749	$	1,051,870	$	4,951,619
Anadarko Basin		968,795		532,747		1,501,542		999,009		687,687		1,686,696		1,109,405		1,839,473		2,948,878
Powder River Basin		428,667		46,412		475,079		410,963		43,968		454,931		557,943		125,065		683,008
Permian Basin		1,394,808		66,135		1,460,943		1,135,421		74,133		1,209,554		1,122,290		151,217		1,273,507
All other		149,361		94		149,455		175,118		193		175,311		216,616		1,047		217,663
Crude oil, natural gas, and natural gas liquids sales	$	6,328,049	$	928,636	$	7,256,685	$	6,497,923	$	1,186,340	$	7,684,263	$	6,906,003	$	3,168,672	$	10,074,675

Performance obligations

The Company satisfies the performance obligations under its commodity sales contracts upon delivery of its production and related transfer of control to customers. Judgment may be required in determining the point in time when control transfers to customers. Upon delivery of production, the Company has a right to receive consideration from its customers in amounts determined by the sales contracts.

The Company's outstanding crude oil sales contracts at December 31, 2024 are primarily short-term in nature with contract terms of less than one year. For such contracts, the Company has utilized the practical expedient in Accounting Standards Codification (“ASC”) 606-10-50-14 exempting the Company from disclosure of the transaction price allocated to remaining performance obligations, if any, if the performance obligation is part of a contract that has an original expected duration of one year or less.

The substantial majority of the Company’s operated natural gas production is sold at lease locations to midstream customers under multi-year term contracts. For such contracts having a term greater than one year, the Company has utilized the practical expedient in ASC 606-10-50-14A which indicates an entity is not required to disclose the transaction price allocated to remaining performance obligations, if any, if variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under the Company’s commodity sales contracts, each unit of production delivered to a customer represents a separate performance obligation; therefore, future volumes to be delivered are wholly unsatisfied at period-end and disclosure of the transaction price allocated to remaining performance obligations is not applicable.

Contract balances

Under the Company’s commodity sales contracts or activities that give rise to service revenues, the Company recognizes revenue after its performance obligations have been satisfied, at which point the Company has an unconditional right to receive payment. Accordingly, the Company’s commodity sales contracts and service activities generally do not give rise to contract assets or contract liabilities under ASC Topic 606. Instead, the Company’s unconditional rights to receive consideration are presented as a receivable within “Receivables–Crude oil, natural gas, and natural gas liquids sales” or “Receivables–Joint interest and other,” as applicable, in its consolidated balance sheets.

Note 10. Allowance for Credit Losses

The Company’s principal exposure to credit risk is through the sale of its crude oil, natural gas, and NGL production and its receivables associated with billings to joint interest owners. Accordingly, the Company classifies its receivables into two portfolio segments as depicted on the consolidated balance sheets as “Receivables—Crude oil, natural gas, and natural gas liquids sales” and “Receivables—Joint interest and other.”

Historically, the Company’s credit losses on receivables have been immaterial. The Company’s aggregate allowance for credit losses totaled $4.1 million and $3.2 million at December 31, 2024 and 2023, respectively, which is reported as “Allowance for credit losses” in the consolidated balance sheets. Aggregate credit loss expenses totaled $1.4 million, $0.1 million, and $3.3 million for the years ended December 31, 2024, 2023, and 2022, respectively, which are included in “General and administrative expenses” in the consolidated statements of income.

Receivables—Crude oil, natural gas, and natural gas liquids sales

The Company’s crude oil, natural gas, and NGL production from operated properties is generally sold to energy marketing companies, crude oil refining companies, and natural gas gathering and processing companies. The Company monitors its credit loss exposure to these counterparties primarily by reviewing credit ratings, financial statements, and payment history. Credit terms are extended based on an evaluation of each counterparty’s credit worthiness. The Company has not generally required its counterparties to provide collateral to secure its crude oil, natural gas, and NGL sales receivables.

Receivables associated with crude oil, natural gas, and NGL sales are short term in nature. Receivables from the sale of crude oil, natural gas, and NGLs from operated properties are generally collected within one month after the month in which a sale has occurred, while receivables associated with non-operated properties are generally collected within two to three months after the month in which production occurs.

The Company’s allowance for credit losses on crude oil, natural gas, and NGL sales was negligible at both December 31, 2024 and December 31, 2023. The allowance was determined by considering a number of factors, primarily including the Company’s history of credit losses with adjustment as needed to reflect current conditions, the length of time accounts are past due, whether amounts relate to operated properties or non-operated properties, and the counterparty's ability to pay. There were no significant write-offs, recoveries, or changes in the provision for credit losses on this portfolio segment during the years ended December 31, 2024, 2023, and 2022.

Receivables—Joint interest and other

Joint interest and other receivables primarily arise from billing the individuals and entities who own a partial interest in the wells we operate. Joint interest receivables are due within 30 days and are considered delinquent after 60 days. In order to minimize our exposure to credit risk with these counterparties we generally request prepayment of drilling costs where it is allowed by contract or state law. Such prepayments are used to offset future capital costs when billed, thereby reducing the Company’s 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 co-owner’s interest.

The Company’s allowance for credit losses on joint interest receivables totaled $4.1 million and $3.2 million at December 31, 2024 and 2023, respectively. The allowance was determined by considering a number of factors, primarily including the Company’s history of credit losses with adjustment as needed to reflect current conditions, the length of time accounts are past due, the ability to recoup amounts owed through netting of production proceeds, the balance of co-owner prepayments if any, and the co-owner’s ability to pay. There were no significant write-offs, recoveries, or changes in the provision for credit losses on this portfolio segment during the years ended December 31, 2024, 2023, and 2022.

Note 11. Income Taxes

The items comprising the Company’s provision for income taxes are as follows for the periods presented:


	Year ended December 31,
In thousands	2024			2023			2022
Current income tax provision:
United States federal	$	591,706		$	461,487		$	538,704
Various states		43,357			37,173			83,671
Total current income tax provision		635,063			498,660			622,375
Deferred income tax provision (benefit):
United States federal		(148,273	)		318,484			374,802
Various states		(14,941	)		10,486			23,627
Total deferred income tax provision (benefit)		(163,214	)		328,970			398,429
Provision for income taxes	$	471,849		$	827,630		$	1,020,804
Effective tax rate		19.0	%		21.1	%		20.1	%

The Company’s effective tax rate differs from the United States federal statutory tax rate due to the effect of state income taxes, permanent taxable differences, tax credits, and other tax items as reflected in the table below.


	Year ended December 31,
In thousands, except tax rates	2024			2023			2022
Income before income taxes	$	2,488,567		$	3,928,947		$	5,068,413
U.S. federal statutory tax rate		21.0	%		21.0	%		21.0	%
Expected income tax provision based on U.S. federal statutory tax rate		522,599			825,079			1,064,367
Items impacting the effective tax rate:
State and local income taxes, net of federal benefit		62,675			98,257			126,932
Tax (benefit) deficiency from stock-based compensation		—			—			(5,282	)
Tax credits for increasing research activities		(96,680	)		(70,412	)		(151,913	)
Other, net		(16,745	)		(25,294	)		(13,300	)
Provision for income taxes	$	471,849		$	827,630		$	1,020,804
Effective tax rate		19.0	%		21.1	%		20.1	%

In assessing the realizability of deferred tax assets the Company must consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The Company applies judgment to determine the weight of both positive and negative evidence in order to conclude whether a valuation allowance is necessary for its deferred tax assets. In determining whether a valuation allowance is required, the Company considers, among other factors, the Company’s financial position, results of operations, projected future taxable income, reversal of existing deferred tax liabilities against deferred tax assets, and tax planning strategies. No valuation allowances were recognized during the years ended December 31, 2024, 2023, and 2022.

The Company will continue to evaluate both the positive and negative evidence on a periodic basis in determining the need for a valuation allowance with respect to its deferred tax assets. Changes in positive and negative evidence, including differences between estimated and actual results, could result in changes in the valuation of our deferred tax assets that could have a material impact on our consolidated financial statements. Changes in existing tax laws could also affect actual tax results and the realization of deferred tax assets over time.

The components of the Company’s deferred tax assets and deferred tax liabilities as of December 31, 2024 and 2023 are reflected in the table below.


	December 31,
In thousands	2024			2023
Deferred tax assets
Net operating loss carryforwards	$	30,298		$	56,377
Incentive compensation		26,224			40,929
Other		34,343			28,080
Total deferred tax assets		90,865			125,386
Deferred tax liabilities
Property and equipment		(2,755,011	)		(2,870,259	)
Net deferred hedge gains		(37,226	)		(120,662	)
Other		(2,697	)		(1,748	)
Total deferred tax liabilities		(2,794,934	)		(2,992,669	)
Deferred income tax liabilities, net	$	(2,704,069	)	$	(2,867,283	)

As of December 31, 2024, the Company had net operating loss (“NOL”) carryforwards in Oklahoma totaling $954 million that have an indefinite life. The Company files income tax returns in U.S. federal and state jurisdictions. With few exceptions, the Company is no longer subject to U.S. federal or state income tax examinations by tax authorities for years prior to 2021.

Note 12. Leases

The Company’s lease liabilities recognized on the balance sheet as a lessee totaled $19.9 million and $37.6 million as of December 31, 2024 and 2023, respectively, at discounted present value, which is comprised of the asset classes reflected in the table below. The amounts disclosed herein primarily represent costs associated with properties operated by the Company that are presented on a gross basis and do not represent the Company’s net proportionate share of such amounts. A portion of these costs have been or will be billed to other working interest owners. Once paid, the Company’s share of these costs are included in property and equipment, production expenses, or general and administrative expenses, as applicable.

The Company accounts for lease and non-lease components in its contracts as a single lease component for all asset classes. Additionally, the Company does not apply the recognition requirements of ASC Topic 842 to leases with durations of twelve months or less and uses hindsight in determining the lease term for all leases. The Company’s leasing activities as a lessor are negligible.


	December 31,
In thousands	2024		2023
Surface use agreements	$	16,370	$	17,263
Field equipment		3,034		19,713
Other		465		618
Total	$	19,869	$	37,594

Minimum future commitments by year for the Company’s operating leases as of December 31, 2024 are presented in the table below. Such commitments are reflected at undiscounted values and are reconciled to the discounted present value recognized on the balance sheet.


In thousands	Amount
2025		4,966
2026		1,848
2027		1,827
2028		1,765
2029		1,768
Thereafter		14,818
Total operating lease liabilities, at undiscounted value	$	26,992
Less: Imputed interest		(7,123	)
Total operating lease liabilities, at discounted present value	$	19,869
Less: Current portion of operating lease liabilities		(4,046	)
Operating lease liabilities, noncurrent	$	15,823

Additional information for the Company’s operating leases is presented below. Lease costs primarily represent costs incurred for drilling rigs, most of which are short term contracts that are not recognized as right-of-use assets and lease liabilities on the balance sheet. Variable lease costs primarily represent differences between minimum payment obligations and actual operating day-rate charges incurred by the Company for any long term drilling rig contracts. Short-term lease costs primarily represent operating day-rate charges for drilling rig contracts with durations of one year or less and month-to-month field equipment rentals. A portion of such lease costs are borne by other interest owners.


	Year ended December 31,
In thousands, except weighted average data	2024			2023			2022
Lease costs:
Operating lease costs	$	20,073		$	13,121		$	3,484
Variable lease costs		1,174			896			650
Short-term lease costs		180,830			168,680			124,535
Total lease costs	$	202,077		$	182,697		$	128,669

Other information:
Right-of-use assets obtained in exchange for new operating lease liabilities	$	1,097		$	24,949		$	19,944
Operating cash flows from operating leases included in lease liabilities		20,076			13,166			4,370
Weighted average remaining lease term as of December 31 (in years)		11.1			6.9			12.0
Weighted average discount rate as of December 31		4.8	%		4.7	%		4.8	%

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

Stock-Based Compensation

Prior to the Hamm Family’s take-private transaction described in Note 1. Organization and Summary of Significant Accounting Policies—2022 Take-Private Transaction, the Company granted restricted stock to employees and directors pursuant to the Continental Resources, Inc. 2013 Long-Term Incentive Plan as amended (“2013 Plan”) and 2022 Plan. The Company’s compensation expense associated with such awards, which is included in the caption “General and administrative expenses” in the consolidated statements of income, was $217.8 million for the year ended December 31, 2022.

As of the November 22, 2022 effective time of the Hamm Family’s take-private transaction, each unvested restricted stock award previously issued to employees under the Company’s 2013 Plan and 2022 Plan that was outstanding immediately prior to the effective time was replaced with a restricted stock unit award (the “Rollover Shares”) 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. Upon this event, the Company remeasured the cumulative compensation expense recognized on the modified awards pursuant to ASC Topic 718, Compensation—Stock Compensation, which resulted in the recognition of additional non-cash compensation expense in 2022 within “General and administrative expenses” totaling approximately $136 million, reflecting the increase in the value of the awards from the original grant date to the subsequent modification date.

As of December 31, 2022, the Company had 5.3 million Rollover Shares which are classified as liability awards under ASC 718. A summary of changes in non-vested restricted shares outstanding prior to the take-private transaction from December 31, 2021 to December 31, 2022 is presented below.


	Number of non-vested shares			Weighted average grant-date fair value
Non-vested restricted shares at December 31, 2021		5,894,508		$	28.38
Granted		1,575,847			56.52
Vested		(1,736,678	)		36.04
Forfeited		(384,536	)		27.82
Canceled shares due to take-private transaction		(5,349,141	)		34.22
Non-vested restricted shares at December 31, 2022		—		$	—

The grant date fair value of restricted stock granted prior to the Hamm Family’s take-private transaction represented the closing market price of the Company’s common stock on the date of grant. Compensation expense for a restricted stock grant was determined at the grant date fair value and was recognized over the vesting period as services were rendered by employees and directors. The Company estimated the number of forfeitures expected to occur in determining the amount of stock-based compensation expense to recognize. There were no post-vesting restrictions related to the Company’s restricted stock. The fair value at the vesting date of restricted stock that vested during 2022 was $98.4 million.

Note 19. Capitalized Exploratory Well Costs

Under the successful efforts method of accounting, the costs of drilling an exploratory well are capitalized pending determination of whether proved reserves can be attributed to the discovery. When initial drilling and completion operations are complete, management attempts to determine whether the well has discovered crude oil and natural gas reserves and, if so, whether those reserves can be classified as proved reserves. Often, the determination of whether proved reserves can be recorded under SEC guidelines cannot be made when drilling is completed. In those situations where management believes that economically producible hydrocarbons have not been discovered, the exploratory drilling costs are reflected on the consolidated statements of income as dry hole costs, a component of “Exploration expenses.” Where sufficient hydrocarbons have been discovered to justify further exploration or appraisal activities, exploratory drilling costs are deferred under the caption “Net property and equipment” on the consolidated balance sheets pending the outcome of those activities.

On a periodic basis, operating and financial management review the status of all deferred exploratory drilling costs in light of ongoing exploration activities—in particular, whether the Company is making sufficient progress in its ongoing exploration and appraisal efforts. If management determines that future appraisal drilling or development activities are not likely to occur, any associated exploratory well costs are expensed in that period of determination.

The following table presents the amount of capitalized exploratory well costs pending evaluation at December 31 for each of the last three years and changes in those amounts during the years then ended:


	Year ended December 31,
In thousands	2024			2023			2022
Balance at January 1	$	159,734		$	84,822		$	37,673
Additions to capitalized exploratory well costs pending determination of proved reserves		449,747			345,434			286,059
Reclassification to proved crude oil and natural gas properties based on the determination of proved reserves		(435,333	)		(270,490	)		(229,348	)
Capitalized exploratory well costs charged to expense		(702	)		(32	)		(9,562	)
Balance at December 31	$	173,446		$	159,734		$	84,822
Number of gross wells		42			34			36

As of December 31, 2024, the Company had no significant exploratory well costs that were suspended one year beyond the completion of drilling.

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.

Reserves at December 31, 2024, 2023, and 2022 were computed using the 12-month unweighted average of the first-day-of-the-month commodity prices as required by SEC rules. All proved reserves stated herein are located in the United States. Proved reserves attributable to noncontrolling interests are not material relative to the Company's consolidated reserves and are not separately presented. Natural gas imbalance receivables and payables for each of the three years ended December 31, 2024, 2023, and 2022 were not material and have not been included in the reserve estimates.

Proved crude oil and natural gas reserves

The following information sets forth the estimated quantities of proved developed and proved undeveloped crude oil and natural gas reserves of the Company as of December 31, 2024, 2023, and 2022.

Proved developed reserves are reserves expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are reserves expected to be recovered from new wells on undrilled acreage or from existing wells that require relatively major capital expenditures to recover, including most wells where drilling has occurred but the wells have not been completed. Natural gas reserves are converted to barrels of crude oil equivalent using a conversion factor of six thousand cubic feet per barrel of crude oil based on the average equivalent energy content of natural gas compared to crude oil.


	December 31,
	2024		2023		2022
Proved Developed Reserves
Crude oil (MBbl)		408,394		401,851		454,299
Natural Gas (MMcf)		3,308,345		3,221,566		3,486,774
Total (MBoe)		959,785		938,779		1,035,428
Proved Undeveloped Reserves
Crude oil (MBbl)		430,512		512,183		435,240
Natural Gas (MMcf)		2,607,079		2,376,765		2,358,578
Total (MBoe)		865,025		908,310		828,336
Total Proved Reserves
Crude oil (MBbl)		838,906		914,034		889,539
Natural Gas (MMcf)		5,915,424		5,598,331		5,845,352
Total (MBoe)		1,824,810		1,847,089		1,863,764

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

There have been no changes in accountants or any disagreements with accountants.

As of the end of the period covered by this report, an evaluation of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) was performed under the supervision and with the participation of the Company’s management, including its Chief Executive Officer and Chief Financial Officer. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded the Company’s disclosure controls and procedures were effective as of December 31, 2024 to ensure information required to be disclosed in the reports it files and submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and information required to be disclosed under the Exchange Act is accumulated and communicated to the Company’s management, including its Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, of our internal control over financial reporting to determine whether any changes occurred during the fourth quarter of 2024 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. Based on that evaluation, there were no changes in our internal control over financial reporting or in other factors during the fourth quarter of 2024 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Our Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our consolidated financial statements for external purposes in accordance with generally accepted accounting principles. Under the supervision and with the participation of our Company’s management, including the Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

Our internal control over financial reporting includes those policies and procedures that: (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of our consolidated financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our consolidated financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Based on our evaluation under the framework in Internal Control—Integrated Framework (2013), the management of our Company concluded that our internal control over financial reporting was effective as of December 31, 2024.

Item 10. Directors, Executive Officers and Corporate Governance Information About Our Executive Officers

Harold G. Hamm serves as Executive Chairman, a position he has held since November 2022. Prior to this, he served as non-employee Chairman from May 19, 2021, to November 22, 2022. Prior to assuming the role of Chairman, he served as Executive Chairman of the Board from January 1, 2020, to May 19, 2021, and as employee Chairman prior to that. He has served as a director since our inception in 1967 and served as our Chief Executive Officer from 1967 to December 31, 2019. In addition, Mr. Hamm served as our President from October 31, 2008 to November 3, 2009. He served as Chairman of the board of directors of the publicly traded general partners of Hiland Partners, LP (“Hiland”) and Hiland Holdings GP, LP (“Hiland Holdings”), former affiliates of ours through February 13, 2015. From September 2005 through February 2012, Mr. Hamm served as a director of Complete Production Services, Inc., an oil and gas service company publicly traded on the New York Stock Exchange (“NYSE”). Mr. Hamm is Chairman of Domestic Energy Producers Alliance and served as Chairman of the Oklahoma Independent Petroleum Association from June 2005 to June 2007 (currently known as the Petroleum Alliance of Oklahoma). He was President of the National Stripper Well Association, founder and Chairman of Save Domestic Oil, Inc., served on the board of directors of the Oklahoma Energy Explorers, Oklahoma Independent Petroleum Association and is co-chairman of the Council for a Secure America.

Robert D. (“Doug”) Lawler is our President and Chief Executive Officer, a position he has held since January 1, 2023. Prior to then, he served as our Chief Operating Officer and Executive Vice President from February 1, 2022 through August 17, 2022. From August 17, 2022 through December 31, 2022, Mr. Lawler served as our President and Chief Operating Officer. On January 22, 2023, Mr. Lawler was appointed to serve as a director. Prior to joining the Company, he served as the President and Chief Executive Officer of Chesapeake Energy Corporation (“Chesapeake”) from June 2013 to April 2021. Chesapeake voluntarily filed for Chapter 11 bankruptcy protection in June of 2020 and emerged from bankruptcy in February of 2021. Mr. Lawler has served as a director of Pilot Travel Centers LLC (dba Pilot/Flying J) since 2016. Mr. Lawler holds a degree in petroleum engineering from the Colorado School of Mines and an M.B.A. from Rice University.

John D. Hart joined us as Vice President, Chief Financial Officer, and Treasurer in November 2005. He was promoted to Senior Vice President in May 2009 and served in that capacity to mid-March 2021. In March 2021, his title was changed to Senior Vice President, Chief Financial Officer and Chief Strategy Officer and he served in that capacity through January 11, 2022. On January 12, 2022, Mr. Hart was promoted to his current position as our Chief Financial Officer and Executive Vice President of Strategic Planning. Prior to joining us, he was a Senior Audit Manager with Ernst & Young LLP. Mr. Hart was employed by Ernst & Young LLP from April 1998 to November 2005 and by Arthur Andersen LLP from December 1991 to April 1998, working with numerous public companies in a wide variety of securities and exchange matters and capital markets activities. He is a member of the American Institute of Certified Public Accountants and The Petroleum Alliance of Oklahoma. Mr. Hart serves on the executive board of the Greater Oklahoma City Chamber of Commerce and serves as Chairman of the Casady School Board of Trustees. Mr. Hart is a Certified Public Accountant and received a Bachelor of Science in Accounting and Finance and a Master of Science in Accounting from Oklahoma State University.

Shelly Lambertz serves as Executive Vice President, Chief Culture and Administrative Officer, a position she has held since January 12, 2022. Prior to this she served as our Chief Culture Officer and Senior Vice President, Human Resources from February 2020 to January 12, 2022, and as the Company’s Vice President, Human Resources from October 2018 to February 2020. Ms. Lambertz served as a director from May 2018 to November 2022, and on January 22, 2023, she was again appointed to serve as a director. Before joining the Company as an employee, she served as the Chief Operating Officer at Hamm Capital, a family investment and advisory firm based in Oklahoma City, from August 2011 to October 2018. Ms. Lambertz also serves as Director of the Harold Hamm Foundation. From 1999 to 2005, Ms. Lambertz was the Executive Director of the YWCA in Enid, Oklahoma. From 1996 to 1998, Ms. Lambertz was Director of Human Resources and Business Development Advisor for Hamm & Phillips Service Company. She began her career working for the U.S. House of Representatives in Washington, D.C. Positions there included Office Manager for Congressman Mickey Edwards (OK), Legislative Assistant for the Leadership Office of Minority Leader Bob Michel (IL), and

Deputy Chief of Staff for Frank Lucas (OK). Ms. Lambertz holds a bachelor’s degree in business administration from Oklahoma State University.

Jeffrey B. Hume became our Vice Chairman of Strategic Growth Initiatives in June 2012. He previously served as our President from November 3, 2009 until June 2012. From November 2008 to June 2012, Mr. Hume also served as our Chief Operating Officer after serving as our Senior Vice President of Operations since November 2006. He was previously appointed as Senior Vice President of Resource and Business Development in October 2005, Senior Vice President of Resource Development in July 2002, and served as Vice President of Drilling Operations from 1996 to 2002. Prior to joining us in May 1983 as Vice President of Engineering and Operations, Mr. Hume held various engineering positions with Sun Oil Company, Monsanto Company, and FCD Oil Corporation. Mr. Hume is a Registered Professional Engineer and member of the Society of Petroleum Engineers, The Petroleum Alliance of Oklahoma, and the Oklahoma and National Professional Engineering Societies. Mr. Hume graduated from Oklahoma State University with a Bachelor of Science in Petroleum Engineering Technology.

James R. Webb is Senior Vice President, General Counsel, and Secretary, a position he has held since November 2022. From September 2021 to November 2022, Mr. Webb served as Senior Vice President, General Counsel, Chief Risk Officer, and Secretary. Prior to joining the Company, Mr. Webb served in various executive roles at Chesapeake from 2012 to 2021, most recently as Executive Vice President – General Counsel and Corporate Secretary from January 2014 to June 2021. Chesapeake voluntarily filed for Chapter 11 bankruptcy protection in June of 2020 and emerged from bankruptcy in February of 2021. Immediately prior to joining Chesapeake, Mr. Webb was an attorney with the law firm of McAfee & Taft from 1995 to October 2012.

Robert Hagens is our Senior Vice President, Commercial Development, a position he has held since December 12, 2023. Prior to this, he served as our Senior Vice President, Land, a position he held from October 2020 (when he joined the Company) to December 12, 2023. Over the years, he has engaged in all levels of leadership within land, land administration and regulatory. Mr. Hagens started his career as a Landman with Atlantic Richfield Company (“ARCO”) in Midland, Texas and has held positions of increasing responsibility across multiple offices within the lower 48 and Alaska with ARCO and its subsidiaries. Shortly following the merger with BP plc (“BP”) in 2000, Mr. Hagens assumed the position of U.S. Onshore Land Manager with BP. Prior to joining the Company, he spent the previous 15 years as Vice President and Senior Vice President of Land for Pioneer Natural Resources Company. Mr. Hagens holds a degree in Petroleum Land Management from the University of Texas at Austin.

For information about our directors, please see the information pertaining to Mr. Hamm, Mr. Lawler, and Ms. Lambertz above. Since all directors are also executive officers, we do not have any independent directors and our directors do not receive any compensation outside their compensation for serving as executive officers.

We have adopted a Code of Business Conduct as a matter of sound corporate governance to promote honest and ethical conduct, consistent with our core values. We adopted the current version of our Code of Business Conduct in November 2022. The Code of Business Conduct is reviewed annually in order to evaluate whether further revisions are necessary or desirable. Since November 2022, the annual review process has resulted in non-substantive changes, with the last of such revisions occurring in December 2024. The Code of Business Conduct is applicable to all employees, officers, and directors, including our principal executive, financial, and accounting officers.

The Company has an Insider Trading Policy governing the purchase, sale and other dispositions of its securities by directors, officers, employees, and contractors that is reasonably designed to promote compliance with insider trading laws, rules and regulations. The Insider Trading Policy is filed with this Form 10-K as Exhibit 19.

Our Board has an Audit Committee, and Mr. Lawler and Ms. Lambertz are currently serving as members of this committee. Our Board has not determined that either Mr. Lawler or Ms. Lambertz are Audit Committee financial experts for purposes of serving on this committee. As a result of our common stock ceasing to be listed on the NYSE, our Audit Committee is not required to have an Audit Committee financial expert.

The discussion below summarizes the approach taken with respect to the compensation of our Principal Executive Officer, Principal Financial Officer, and the three other most highly compensated executive officers during 2024. These individuals are identified below and are referred to collectively in the discussion below as the “NEOs” for 2024. The discussion summarizes our compensation philosophy, the different components of our compensation program, the mix of compensation paid to our NEOs, and provides information regarding the financial statement impact for 2024 associated with the compensation program for our NEOs.

Our NEOs for 2024 (determined in accordance with the requirements of Item 402 of Regulation S-K) are:

As a result of the take-private transaction, the only group with an interest in any Company issued securities outside of Mr. Hamm, certain members of his family, and entities under their control (referred to collectively herein as the “Hamm Family”) are the holders of our outstanding bonds. As a result of the take-private transaction, we are now a voluntary filer.

Because we operate in a highly competitive environment, we have designed our executive compensation program to attract, retain, and motivate experienced, talented individuals. We also designed our executive compensation program to reward our executives for achieving the strategic and business objectives determined to be important to help the Company create and maintain advantage in a competitive environment.

In determining individual compensation, we consider the performance of the Company against specific operational and financial factors determined to be relevant for the period in question. We also consider competitive market compensation paid by other companies comparable to us in size, geographic location, and operations. We maintain and incorporate flexibility into our compensation programs and in the assessment process, which we believe is particularly important in a changing commodity price environment. As such, we do not apply rigid formulas in determining the amount and mix of compensation elements.

For 2024, our Executive Chairman, President and Chief Executive Officer and Executive Vice President, Chief Culture and Administrative Officer (collectively, referred to herein as the “Management Compensation Group”) evaluated how the following elements (collectively, the “Primary Compensation Elements”) of our compensation program compared to the compensation awarded by the members of the then current compensation survey group as identified by the Management Compensation Group. The Management Compensation Group’s analysis consisted of comparing the market data of base salary, cash bonus, long-term incentive awards, and total compensation at the 25th, 50th, and 75th percentiles of the then current compensation survey group to the compensation of each of our NEOs. Total compensation for each NEO is structured to target compensation levels near the 50th percentile, taking into account responsibilities and duties, experience, individual performance, and time in position.

The Management Compensation Group is responsible for overseeing all aspects of our benefit and compensation plans and programs for our executive officers. For 2024, the Management Compensation Group reviewed and determined the individual elements of total compensation of the NEOs listed above, as well as our other executive officers. Since our compensation programs are relatively simple, we do not have complex equity plans or significant change in control or severance obligations. Mr. Lawler does have an agreement on market terms specifying what Mr. Lawler will receive in the event he is terminated: (x) for reasons other than cause, disability, or death; (y) for good reason during a transition period following customary specified events; and (z) for cause, death, or disability. Given Mr. Lawler’s key role within the Company’s business, the Company determined it was important for retention purposes to provide Mr. Lawler with customary market protection in relation to these types of events.

The Management Compensation Group did not use tally sheets in analyzing the compensation of our NEOs, but instead reviewed each element of compensation, as described below, in evaluating and approving the total compensation of each of our NEOs. When making decisions with respect to each element of our compensation program, the Management Compensation Group considered how the terms

of that particular element may impact the overall compensation package awarded to each NEO. As a result, any decision made with respect to each element of our compensation program was influenced by the decisions made with respect to the other elements of our compensation program.

The Management Compensation Group believed targeting near the 50th percentile for base salary, cash bonus, and long-term incentive awards resulted in competitive compensation and aligned overall pay with shareholder interests, while preserving considerable upside potential should Company and individual executive performance merit higher compensation. As the Management Compensation Group worked to achieve alignment close to the 50th percentile, it also considered an individual executive officer’s performance and the external business environment, and any final compensation decision ultimately reflected the Management Compensation Group’s discretion, which can be a significant factor in its final compensation decisions.

For 2024, the Management Compensation Group retained the services of an independent compensation consulting firm, Meridian Compensation Partners (“Meridian”). Meridian reported directly to the Management Compensation Group. During 2024, Meridian was consulted on select compensation questions, but did not have the level of involvement in providing benchmarking, market data and compensation structure recommendations as it had in prior years. Instead, the Company’s human resources team used various paid and publicly available resources to provide this type of information to the Management Compensation Group. During 2024, Meridian provided no other services, resulting in total fees of less than $120,000.

As a result of the take-private transaction, we have not formally assessed the independence of Meridian in connection with the preparation of this filing. However, the relationship with Meridian has not changed in any substantial respect versus prior years when it was determined Meridian was independent under New York Stock Exchange and Securities and Exchange Commission rules.

Primary Compensation Elements. The table below describes each of our “Primary Compensation Elements”, the purpose of each element, and how each element fits within the Company’s compensation philosophy and objectives.

Role of Discretion in Determining Primary Compensation Elements. All base salary adjustments, cash bonuses, and long-term incentive awards for NEOs have been determined on a discretionary basis. While not linked to specific corporate goals or objectives, the overall performance of the Company and individual performance were considered in determining pay generally, including target award amounts. The Management Compensation Group retained discretion over all aspects of the annual cash bonus plan and the awards made for 2024 under that plan.

Other Compensation. Compensation and benefits that are outside of our three main compensation elements are designed to attract and retain employees by enhancing our overall compensation package. During 2024, we provided fuel cards to certain NEOs and automobiles to certain other employees for business and/or personal use. The personal use is valued according to IRS guidelines and reported as taxable income to the individuals.

We have a defined contribution retirement plan (“401(k)”) covering all full-time employees. Our contributions to the plan are discretionary and based on a percentage of eligible compensation. The 401(k) provides for Company dollar for dollar matching of up to a maximum of 10% of a covered employee’s eligible compensation, depending on the employee’s level of contribution into the employee’s account and subject to IRS limits. During 2024, the Company match was in effect the entire year.

All full-time employees may participate in our health and welfare benefit programs, including medical, dental, vision care, life insurance, and disability insurance. We provide all full-time employees with life insurance coverage of the lesser of two times base salary or $1,000,000 and allow them to purchase supplemental coverage. We do not sponsor any qualified or non-qualified defined benefit plans.

Risk Assessment Related to our Compensation Structure. We believe our executive compensation program is appropriately structured and not reasonably likely to result in risks that could have a material adverse effect on us. We believe our approach of subjectively evaluating the overall performance of each executive assists in mitigating excessive risk-taking that could harm our value or reward poor judgment by our executives. Several features of our programs reflect sound risk management practices. We believe we have allocated our compensation among base salary and short and long-term compensation opportunities in such a way as to discourage excessive risk-taking. Further, one of the primary factors we take into consideration in setting compensation is the performance of the Company as a whole. This is based on our belief that applying Company-wide metrics encourages decision-making that is in the best long-term interests of the Company and our shareholders as a whole. Metrics used may include financial and operating metrics pertaining to production volumes, capital spending, cash flows, return on capital employed, resource replacement, and health, safety, and environmental performance. Finally, the time-based vesting over a multi-year period for our long-term incentive awards ensures our employees’ interests align with those of our shareholders for the long-term performance of our Company.

The following charts illustrate the mix of Primary Compensation Elements for our Chief Executive Officer and the other NEOs as a group, and reflect the following: (i) base salary received by the NEO during 2024; (ii) the cash bonus for 2024 paid in February 2025; and (iii) the grant date target value of the long-term incentive awards granted to the NEOs in 2024 (which is the target value of the awards on the date of grant, and not necessarily reflective of the amounts the NEOs may receive at the time of settlement).

The aggregate total amount of annual compensation-related expenses recognized in the Company’s financial statements related to the 2024 compensation of the NEOs as a group represented less than 1% of our total income from operations, our total operating cash flows and our total liabilities as of and for the year ended December 31, 2024.

Management Compensation Group Report (in lieu of a Compensation Committee Report)

As a result of the take-private transaction, the Compensation Committee was eliminated by the Board and ceased to function. As a result, it is not possible to provide a report of the Compensation Committee at the time of the filing of this report. The Management Compensation Group (which is composed of the same individuals as currently comprise our Board and has assumed many of the duties previously performed by the Compensation Committee) has reviewed and discussed the Compensation Discussion and Analysis (“CD&A”) above with other members of management. Based on this review and discussion, the Management Compensation Group has determined that it is appropriate to include this CD&A in this filing.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

As a result of the completion of the take-private transaction, the Company is 100% owned by the Hamm Family. As a result, none of our directors and/or executive officers who are not members of the Hamm Family have any security ownership reportable to this item.

Item 13. Certain Relationships and Related Transactions, and Director Independence

Prior to the completion of the take-private transaction, our Audit Committee (then composed of independent directors meeting applicable NYSE and SEC requirements) reviewed related party transactions, as required by the terms of the Audit Committee charter then in place, and recommended approval or disapproval to the Board of any such transaction. During this time, the Audit Committee recommended for approval only those related party transactions that were, in its business judgment, in our best interests and on terms no less favorable to us than we could have achieved with an unaffiliated party. Following the completion of the take-private transaction, an Audit Committee composed of Mr. Lawler and Ms. Lambertz was voluntarily established for the purpose of reviewing related party transactions as a matter of sound corporate governance and to provide oversight to ensure that any transactions with related parties meet existing covenant requirements pertaining to affiliate transactions set forth in our senior credit facility. The standard for review and approval of related party transactions under our current structure is substantially the same as applied prior to the take private transaction. None of the transactions reviewed by the full Audit Committee since December 31, 2022 are transactions in which the related party had a direct or indirect material interest, and so are not discussed in detail in this filing. The stock redemption agreement described in Note 7. Fair Value Measurements was approved by the sole disinterested member of the Audit Committee.

Grant Thornton served as our independent registered public accounting firm during 2024 and 2023. The aggregate fees for various services performed by Grant Thornton for the years ended December 31, 2024 and 2023 are set forth below:

Fees for audit services include fees associated with our annual consolidated and subsidiary audits, the review of our quarterly reports on Form 10-Q, Sarbanes Oxley Act compliance review, accounting consultations, and services normally provided by the accounting firm in connection with statutory or regulatory filings.

As necessary, the Audit Committee considers whether the provision of non-audit services by Grant Thornton is compatible with maintaining auditor independence and has adopted a policy that requires pre-approval of all audit and non-audit services for Grant Thornton. Such policy requires the Audit Committee to approve services and fees in advance and requires documentation regarding the specific services to be performed. All 2024 audit fees were approved in advance in accordance with the Audit Committee’s policies.

The consolidated financial statements of Continental Resources, Inc. and Subsidiaries and the Report of Independent Registered Public Accounting Firm are included in Part II, Item 8 of this report. Reference is made to the accompanying Index to Consolidated Financial Statements.

All financial statement schedules have been omitted because they are not applicable or the required information is presented in the financial statements or the notes thereto.

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

† Management contracts or compensatory plans or arrangements filed pursuant to Item 601(b)(10)(iii) of Regulation S-K.

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Continental Resources, Inc. has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of Continental Resources, Inc. and in the capacities and on the dates indicated.


	Crude Oil (MBbls)		Natural Gas (MMcf)		Total (MBoe)
Proved developed producing		405,269		3,288,444		953,343
Proved developed non-producing		3,125		19,901		6,442
Proved undeveloped		430,512		2,607,079		865,025
Total proved reserves		838,906		5,915,424		1,824,810


	Proved Developed						Proved Undeveloped
	Crude Oil (MBbls)		Natural Gas (MMcf)		Total (MBoe)		Crude Oil (MBbls)		Natural Gas (MMcf)		Total (MBoe)
Bakken		172,985		998,121		339,339		133,569		507,806		218,203
Anadarko Basin		76,801		1,871,025		388,638		91,933		1,510,066		343,611
Powder River Basin		38,208		133,604		60,475		62,982		118,219		82,685
Permian Basin		93,688		298,052		143,364		142,028		470,988		220,526
All other		26,712		7,543		27,969		—		—		—
Total		408,394		3,308,345		959,785		430,512		2,607,079		865,025


	Year Ended December 31,
MBoe	2024			2023			2022
Proved reserves at beginning of year		1,847,089			1,863,764			1,645,310
Revisions of previous estimates		(276,784	)		(369,264	)		(133,061	)
Extensions, discoveries and other additions		452,530			438,367			395,490
Production		(155,914	)		(160,660	)		(146,657	)
Sales of minerals in place		(42,223	)		(15,594	)		(144	)
Purchases of minerals in place		112			90,476			102,826
Proved reserves at end of year		1,824,810			1,847,089			1,863,764


	Crude Oil (MBbls)			Natural Gas (MMcf)			Total (MBoe)
Proved undeveloped reserves at December 31, 2023		512,183			2,376,765			908,310
Revisions of previous estimates		(171,172	)		(859,093	)		(314,354	)
Extensions, discoveries and other additions		181,047			1,398,906			414,198
Sales of minerals in place		(1,448	)		(4,273	)		(2,160	)
Conversion to proved developed reserves		(90,098	)		(305,226	)		(140,969	)
Proved undeveloped reserves at December 31, 2024		430,512			2,607,079			865,025


PART I
Item 1.	Business	1
	General	1
	Our Business Strategies	1
	Crude Oil and Natural Gas Operations	1
	Proved Reserves	1
	Developed and Undeveloped Acreage	4
	Drilling Activity	4
	Summary of Crude Oil and Natural Gas Properties and Projects	5
	Production and Price History	6
	Productive Wells	7
	Title to Properties	7
	Marketing	7
	Competition	8
	Regulation of the Crude Oil and Natural Gas Industry	8
	Human Capital	9
	Company Contact Information	10
Item 1A.	Risk Factors	11
Item 1B.	Unresolved Staff Comments	21
Item 1C.	Cybersecurity	21
Item 2.	Properties	22
Item 3.	Legal Proceedings	22
Item 4.	Mine Safety Disclosures	22

PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	23
Item 6.	Reserved	23
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	24
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	35
Item 8.	Financial Statements and Supplementary Data	37
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	69
Item 9A.	Controls and Procedures	69
Item 9B.	Other Information	71
Item 9C.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	71

PART III
Item 10.	Directors, Executive Officers and Corporate Governance	72
Item 11.	Executive Compensation	74
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	77
Item 13.	Certain Relationships and Related Transactions, and Director Independence	77
Item 14.	Principal Accountant Fees and Services	78

PART IV
Item 15.	Exhibits and Financial Statement Schedules	79


	Developed acres				Undeveloped acres				Total
	Gross		Net		Gross		Net		Gross		Net
Bakken		1,104,072		710,177		99,035		56,591		1,203,107		766,768
Anadarko Basin		471,644		284,833		413,208		218,831		884,852		503,664
Powder River Basin		238,865		181,252		252,114		179,424		490,979		360,676
Permian Basin		127,409		112,743		153,308		102,964		280,717		215,707
All other		164,345		141,272		220,880		141,424		385,225		282,696
Total		2,106,335		1,430,277		1,138,545		699,234		3,244,880		2,129,511


	Fourth Quarter 2024 Daily Production
	Crude Oil (Bbls per day)		Natural Gas (Mcf per day)		Total (Boe per day)
Bakken		120,054		418,400		189,787
Anadarko Basin		37,169		533,390		126,068
Powder River Basin		17,948		55,600		27,215
Permian Basin		51,692		135,850		74,334
All other		5,050		68		5,061
Total		231,913		1,143,308		422,465


	Crude Oil Wells				Natural Gas Wells				Total Wells
	Gross		Net		Gross		Net		Gross		Net
Bakken		6,181		2,328		—		—		6,181		2,328
Anadarko Basin		997		453		731		242		1,728		695
Powder River Basin		652		454		12		10		664		464
Permian Basin		619		520		52		29		671		549
All other		264		250		20		2		284		252
Total		8,713		4,005		815		283		9,528		4,288


	Fourth Quarter							Year Ended December 31,
Boe production per day	2024		2023		% Change			2024		2023		% Change
Bakken		189,787		220,428		(14	)%		194,606		202,610		(4	)%
Anadarko Basin		126,068		144,158		(13	)%		132,558		153,426		(14	)%
Powder River Basin		27,215		25,577		6	%		24,979		23,757		5	%
Permian Basin		74,334		58,601		27	%		68,589		54,651		26	%
All other		5,061		5,666		(11	)%		5,263		5,720		(8	)%
Total		422,465		454,430		(7	)%		425,995		440,164		(3	)%


	Year Ended December 31,													Volume
	2024					2023					Volume			percent
	Volume		Percent			Volume		Percent			decrease			decrease
Crude oil (MBbl)		84,139		54	%		84,710		53	%		(571	)		(1	)%
Natural gas (MMcf)		430,649		46	%		455,698		47	%		(25,049	)		(5	)%
Total (MBoe)		155,914		100	%		160,660		100	%		(4,746	)		(3	)%


	Year ended December 31,
$/Boe	2024		2023
Crude oil and natural gas properties	$	15.26	$	13.58
Other equipment		0.53		0.44
Asset retirement obligation accretion		0.14		0.09
Depreciation, depletion, amortization and accretion	$	15.93	$	14.11


Year Ending	Natural Gas		Crude Oil
December 31,	Bcf		MMBo
2025		117		13
2026		99		3
2027		70		—
2028		30		—
2029		10		—
2030		10		—
2031		8		—


		Hypothetical Fair Value
In thousands	Change in Forward Price	Asset (Liability)
Crude Oil	-10%	$	22,574
Crude Oil	+10%	$	2,491
Natural Gas	-10%	$	376,230
Natural Gas	+10%	$	(86,275	)


	2025				2026				2027
	Gross		Net		Gross		Net		Gross		Net
Bakken		5,410		3,134		12,047		7,584		2,766		1,300
Anadarko Basin		88,060		48,187		36,939		22,798		29,456		16,771
Powder River Basin		4,198		2,985		10,206		6,764		2,332		915
Permian Basin		20,221		15,163		35,714		27,401		28,595		11,456
All other		11,438		6,111		23,290		16,356		15,355		8,974
Total		129,327		75,580		118,196		80,903		78,504		39,416


	Year ended December 31,
	2024		2023		2022
Net production volumes:
Crude oil (MBbls)
North Dakota Bakken		44,197		48,032		39,917
SCOOP		12,426		11,652		10,051
Permian Delaware		17,343		14,762		11,832
Total Company		84,139		84,710		72,827
Natural gas (MMcf)
North Dakota Bakken		153,389		146,026		124,411
SCOOP		169,031		179,165		185,755
Permian Delaware		38,414		27,980		20,804
Total Company		430,649		455,698		442,980
Crude oil equivalents (MBoe)
North Dakota Bakken		69,762		72,370		60,652
SCOOP		40,598		41,513		41,010
Permian Delaware		23,745		19,425		15,300
Total Company		155,914		160,660		146,657
Average sales prices:
Crude oil ($/Bbl)
North Dakota Bakken	$	75.01	$	76.41	$	94.51
SCOOP		74.92		76.82		94.58
Permian Delaware		76.39		76.21		95.14
Total Company		75.18		76.89		94.95
Natural gas ($/Mcf)
North Dakota Bakken	$	1.80	$	2.54	$	8.30
SCOOP		2.76		2.93		7.00
Permian Delaware		1.54		2.53		7.27
Total Company		2.16		2.60		7.15
Average costs per Boe:
Production expenses ($/Boe)
North Dakota Bakken	$	5.82	$	5.23	$	5.05
SCOOP		1.79		1.50		1.44
Permian Delaware		5.41		5.72		7.27
Total Company		4.94		4.47		4.24
Production and ad valorem taxes ($/Boe)	$	3.57	$	3.76	$	4.98
General and administrative expenses ($/Boe)	$	1.69	$	1.74	$	2.74
DD&A expense ($/Boe)	$	15.93	$	14.11	$	12.86


Report of Independent Registered Public Accounting Firm	(PCAOB ID Number 248)	38
Consolidated Balance Sheets as of December 31, 2024 and 2023		41
Consolidated Statements of Income for the Years Ended December 31, 2024, 2023 and 2022		42
Consolidated Statements of Equity for the Years Ended December 31, 2024, 2023 and 2022		43
Consolidated Statements of Cash Flows for the Years Ended December 31, 2024, 2023 and 2022		44
Notes to Consolidated Financial Statements		45


	December 31,
In thousands, except par values and share data	2024			2023
Assets
Current assets:
Cash and cash equivalents	$	39,064		$	26,397
Receivables:
Crude oil, natural gas, and natural gas liquids sales		1,176,280			1,196,262
Joint interest and other		381,760			350,907
Allowance for credit losses		(4,121	)		(3,172	)
Receivables, net		1,553,919			1,543,997
Derivative assets		95,227			353,261
Inventories		184,251			190,762
Prepaid expenses and other		32,648			33,450
Total current assets		1,905,109			2,147,867
Net property and equipment, based on successful efforts method of accounting		20,037,922			19,786,889
Investment in unconsolidated affiliates		258,359			240,484
Operating lease right-of-use assets		20,933			38,656
Derivative assets, noncurrent		62,426			155,252
Other noncurrent assets		20,832			18,293
Total assets	$	22,305,581		$	22,387,441
Liabilities and equity
Current liabilities:
Accounts payable trade	$	845,160		$	835,012
Revenues and royalties payable		682,461			768,381
Accrued liabilities and other		413,036			354,537
Current portion of incentive compensation liability		74,494			130,583
Current portion of income tax liabilities		21,659			84,556
Current portion of operating lease liabilities		4,046			18,112
Current portion of long-term debt		2,587			895,105
Total current liabilities		2,043,443			3,086,286
Long-term debt, net of current portion		4,798,860			5,734,007
Other noncurrent liabilities:
Deferred income tax liabilities, net		2,704,069			2,867,283
Incentive compensation liability, noncurrent		36,468			41,707
Asset retirement obligations, noncurrent		432,495			391,957
Derivative liabilities, noncurrent		143			586
Operating lease liabilities, noncurrent		15,823			19,482
Other noncurrent liabilities		48,783			36,346
Total other noncurrent liabilities		3,237,781			3,357,361
Commitments and contingencies (Note 13)
Equity:
Preferred stock, $0.01 par value; 25,000,000 shares authorized; no shares issued and outstanding		—			—
Common stock (Note 16)		2,996			2,996
Retained earnings		11,862,515			9,850,687
Total shareholders’ equity attributable to Continental Resources		11,865,511			9,853,683
Noncontrolling interests		359,986			356,104
Total equity		12,225,497			10,209,787
Total liabilities and equity	$	22,305,581		$	22,387,441


	Year Ended December 31,
In thousands, except per share data	2024			2023			2022
Revenues:
Crude oil, natural gas, and natural gas liquids sales	$	7,256,685		$	7,684,263		$	10,074,675
Gain (loss) on derivative instruments, net		27,168			943,768			(671,095	)
Crude oil and natural gas service operations		93,776			103,710			70,128
Total revenues		7,377,629			8,731,741			9,473,708

Operating costs and expenses:
Production expenses		770,875			717,478			621,921
Production and ad valorem taxes		556,174			603,534			730,132
Transportation, gathering, processing, and compression		367,247			338,217			316,414
Exploration expenses		12,369			16,368			23,068
Crude oil and natural gas service operations		88,078			82,392			37,002
Depreciation, depletion, amortization and accretion		2,483,444			2,264,334			1,885,465
Property impairments		43,199			66,798			70,417
Transaction costs		—			—			33,796
General and administrative expenses		264,029			279,306			401,551
Net (gain) loss on sale of assets and other		38,516			50,581			262
Total operating costs and expenses		4,623,931			4,419,008			4,120,028
Income from operations		2,753,698			4,312,733			5,353,680
Other income (expense):
Interest expense		(275,748	)		(395,765	)		(300,662	)
Loss on extinguishment of debt		(1,600	)		—			(403	)
Other		12,217			11,979			15,798
		(265,131	)		(383,786	)		(285,267	)
Income before income taxes		2,488,567			3,928,947			5,068,413
Provision for income taxes		(471,849	)		(827,630	)		(1,020,804	)
Income before equity in net loss of affiliate		2,016,718			3,101,317			4,047,609
Equity in net loss of affiliate		(3,653	)		(3,129	)		(1,489	)
Net income		2,013,065			3,098,188			4,046,120
Net income attributable to noncontrolling interests		1,287			2,361			21,562
Net income attributable to Continental Resources	$	2,011,778		$	3,095,827		$	4,024,558


	Shareholders’ equity attributable to Continental Resources
In thousands, except share data	Shares outstanding			Common stock			Additional paid-in capital			Treasury stock			Retained earnings			Total shareholders’ equity of Continental Resources			Noncontrolling interests			Total equity
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		(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
Net income		—			—			—			—			2,011,778			2,011,778			1,287			2,013,065
Change in dividends payable		—			—			—			—			50			50			—			50
Contributions from noncontrolling interests		—			—			—			—			—			—			24,459			24,459
Distributions to noncontrolling interests		—			—			—			—			—			—			(21,864	)		(21,864	)
Balance at December 31, 2024		299,610,267		$	2,996		$	—		$	—		$	11,862,515		$	11,865,511		$	359,986		$	12,225,497


	Number of shares		Aggregate cost (in thousands)
2022 Share Repurchases		1,842,422	$	99,855



Name	Age	Position
Harold G. Hamm	79	Executive Chairman
Robert D. (“Doug”) Lawler	58	President and Chief Executive Officer and Director
John D. Hart	57	Chief Financial Officer and Executive Vice President of Strategic Planning
Shelly Lambertz	58	Executive Vice President, Chief Culture and Administrative Officer and Director
Jeffrey B. Hume	73	Vice-Chairman, Strategic Growth Initiatives
James R. Webb	57	Senior Vice President, General Counsel, and Secretary
Robert Hagens	66	Senior Vice President, Commercial Development



Compensation Element	Description	Purpose and Philosophy
Base Salary	Fixed cash compensation	Provides a stable, fixed element of cash compensation. Attract and retain executive officers by paying a wage commensurate with such officer’s experience, skills, and responsibilities. It also recognizes and considers the internal value of the position within the Company, the officer’s leadership potential and demonstrated performance.
Annual Cash Bonus	Annual cash bonus related to individual contribution toward achievement of annual financial and operating results	Rewards executives for the achievement of specific annual financial, operating, and strategic goals and individual performance. Allows the Management Compensation Group to evaluate both objective and subjective considerations when exercising discretion to determine final payout amounts. Important to the Company’s ability to attract, motivate, and retain the Company’s executive officers.
Long-term Incentive Awards	Long-term cash-based awards and restricted stock units (which are held by executive officers, but which haven’t been awarded since 2022 and are not expected to be awarded in the future)	Aligns the executive’s long-term interests with those of shareholders. Long-term incentive awards align executive’s interests with those of shareholders by increasing or decreasing in value based on changes in the overall value of the Company. Important to the Company’s ability to attract, motivate, and retain the Company’s executive officers.



	2024	2023
Audit Fees	$1,011,000	$994,000
Audit-Related Fees	—	—
Tax Fees	—	—
All Other Fees	—	—
Total Fees	$1,011,000	$994,000



3.1*		Conformed version of Seventh Amended and Restated Certificate of Incorporation of Continental Resources, Inc.

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

4.1		Indenture dated as of May 19, 2014 among Continental Resources, Inc., Banner Pipeline Company, L.L.C., CLR Asset Holdings, LLC and Wilmington Trust, National Association, as trustee, filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K (Commission File No. 001-32886) filed May 22, 2014 and incorporated herein by reference.

4.2		Indenture dated as of December 8, 2017 among Continental Resources, Inc., Banner Pipeline Company, L.L.C., CLR Asset Holdings, LLC, The Mineral Resources Company and Wilmington Trust, National Association, as trustee, filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K (Commission File No. 001-32886) filed December 12, 2017 and incorporated herein by reference.

4.3		Indenture dated as of November 25, 2020 among Continental Resources, Inc., Banner Pipeline Company, L.L.C., CLR Asset Holdings, LLC, The Mineral Resources Company and Wilmington Trust, National Association, as trustee, filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K (Commission File No. 001-32886) filed November 25, 2020 and incorporated herein by reference.

4.4		Indenture dated as of November 22, 2021 among Continental Resources, Inc., Banner Pipeline Company, L.L.C., CLR Asset Holdings, LLC, The Mineral Resources Company and Wilmington Trust, National Association, as trustee, filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K (Commission File No. 001-32886) filed November 22, 2021 and incorporated herein by reference.

10.1		Revolving Credit Agreement dated as of October 29, 2024 by and among (i) Continental Resources, Inc. as borrower, (ii) Banner Pipeline Company, L.L.C., CLR Asset Holdings, LLC, The Mineral Resources Company, Continental Innovations LLC, SCS1 Holdings LLC, Jagged Peak Energy LLC and Parsley SoDe Water LLC, as guarantors, (iii) MUFG Bank, LTD., as administrative agent, and (iv) the banks and other financial institutions party thereto as lenders filed as Exhibit 10.1 to the Company’s Form 10-Q for the quarter ended September 30, 2024 (Commission File No. 001-32886) filed November 12, 2024 and incorporated herein by reference.

10.2†		Continental Resources, Inc. Deferred Compensation Plan filed as Exhibit 10.2 to the Company’s Form 10-Q for the quarter ended September 30, 2018 (Commission File No. 001-32886) filed October 29, 2018 and incorporated herein by reference.


10.3†		First Amendment to the Continental Resources, Inc. Deferred Compensation Plan filed as Exhibit 10.1 to the Company’s Form 10-Q for the quarter ended March 31, 2014 (Commission File No. 001-32886) filed May 8, 2014 and incorporated herein by reference.

10.4†		Second Amendment to the Continental Resources, Inc. Deferred Compensation Plan adopted and effective as of May 23, 2014 filed as Exhibit 10.15 to the Company’s Registration Statement on Form S-4 (Commission File No. 333-196944) filed June 20, 2014 and incorporated herein by reference.

10.5†		Third Amended and Restated Continental Resources, Inc 2013 Long-Term Incentive Plan filed as Exhibit 10.9 to the Company’s Form 10-K for the year ended December 31, 2022 (Commission File No. 001-32886) filed February 22, 2023 and incorporated herein by reference.

10.6†		Continental Resources, Inc. Second Amended and Restated 2022 Long-Term Incentive Plan filed as Exhibit 10.10 to the Company’s Form 10-K for the year ended December 31, 2022 (Commission File No. 001-32886) filed February 22, 2023 and incorporated herein by reference.

10.7†		Replacement Restricted Stock Unit Agreement – Employee Agreement for Continental Resources, Inc. 2013 Long-Term Incentive Plan and 2022 Long-Term Incentive Plan filed as Exhibit 10.11 to the Company’s Form 10-K for the year ended December 31, 2022 (Commission File No. 001-32886) filed February 22, 2023 and incorporated herein by reference.

10.8†		Cash Award Agreement – Continental Resources, Inc. Second Amended and Restated 2022 Long-Term Incentive Plan filed as Exhibit 10.12 to the Company’s Form 10-K for the year ended December 31, 2022 (Commission File No. 001-32886) filed February 22, 2023 and incorporated herein by reference.

19*		Insider Trading Policy of Continental Resources, Inc.

21*		Subsidiaries of Continental Resources, Inc.

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

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

99*		Report of Ryder Scott Company, L.P., Independent Petroleum Engineers and Geologists

101.INS*		Inline XBRL Instance Document - the Inline XBRL Instance Document does not appear in the Interactive Data file because its XBRL tags are embedded within the Inline XBRL document

101.SCH*		Inline XBRL Taxonomy Extension Schema With Embedded Linkbases Document

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


CONTINENTAL RESOURCES, INC.

By:		/S/ ROBERT D. LAWLER
Name:		Robert D. Lawler
Title:		President, Chief Executive Officer, and Director
Date:		February 24, 2025


Signature	Title	Date

/s/ HAROLD G. HAMM	Executive Chairman and Director	February 24, 2025
Harold G. Hamm

/s/ ROBERT D. LAWLER	President, Chief Executive Officer, and Director (principal executive officer)	February 24, 2025
Robert D. Lawler

/s/ SHELLY LAMBERTZ	Executive Vice President, Chief Culture and Administrative Officer and Director	February 24, 2025
Shelly Lambertz

/s/ JOHN D. HART	Chief Financial Officer and Executive Vice President of Strategic Planning (principal financial and accounting officer)	February 24, 2025
John D. Hart