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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

"Net crude oil and natural gas sales" Represents total crude oil, natural gas, and natural gas liquids sales less total transportation expenses. Net crude oil, natural gas, and natural gas liquids sales presented herein is a non-GAAP measure. See Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Financial Measures for a discussion and calculation of this measure.

"Net sales price" Represents the average net wellhead sales price received by the Company for sales after deducting transportation expenses. Net sales price is calculated by taking revenues less transportation expenses divided by sales volumes for a period. Net sales prices presented herein are non-GAAP measures. See Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Financial Measures for a discussion and calculation of this measure.

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

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

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

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

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

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

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

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

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

measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities.

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

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

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

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

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

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

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

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

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

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

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

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

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

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.

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

Following the completion of the transaction: (i) our common stock ceased to be listed on the New York Stock Exchange effective November 23, 2022, (ii) our common stock was deregistered under Section 12(b) of the Securities Exchange Act of 1934 as amended (the “Exchange Act”), and (iii) we suspended our reporting obligations under Section 15(d) of the Exchange Act. As a result, certain of the corporate governance, disclosure, and other provisions applicable to a company with listed equity securities and reporting obligations under the Exchange Act no longer apply to us. We will continue to furnish Quarterly Reports on Form 10-Q and Annual Reports on Form 10-K with the SEC as required by our senior note indentures.

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

We are an independent crude oil and natural gas company formed in 1967 engaged in the exploration, development, management, and production of crude oil and natural gas and associated products with properties primarily located in four leading basins in the United States – the Bakken field of North Dakota and Montana, the Anadarko Basin of Oklahoma, the Permian Basin of Texas, and the Powder River Basin of Wyoming. Additionally, we pursue the acquisition and management of perpetually owned minerals located in certain of our key operating areas.

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

As of December 31, 2022, our proved reserves were 1,864 MMBoe, with proved developed reserves representing 1,035 MMBoe, or 56%, of our total proved reserves. The standardized measure of our discounted future net cash flows totaled $31.91 billion at December 31, 2022. For 2022, we generated crude oil, natural gas, and natural gas liquids revenues of $10.1 billion and operating cash flows of $7.0 billion. Crude oil accounted for 50% of our total production and 69% of our crude oil, natural gas, and natural gas liquids revenues for 2022. Our total production averaged 401,800 Boe per day for 2022, an increase of 22% compared to 2021.

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

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

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

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

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

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

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

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

Financial Position and Liquidity. We have a credit facility with lender commitments totaling $2.255 billion that matures in October 2026. We had approximately $1.12 billion of borrowing availability on our credit facility at February 1, 2023 after considering outstanding borrowings and letters of credit. Our credit facility is unsecured and does not have a borrowing base requirement that is subject to periodic redetermination based on changes in commodity prices and proved reserves. Additionally, downgrades or other negative rating actions with respect to our credit rating do not trigger a reduction in our current credit facility commitments, nor do such actions trigger a security requirement or change in covenants.

Proved reserves are those quantities of crude oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates renewal is reasonably certain. In connection with the estimation of proved reserves, the term “reasonable certainty” implies a high degree of confidence the quantities of crude oil and/or natural gas actually recovered will equal or exceed the estimate. To achieve reasonable certainty, our internal reserve engineers and Ryder Scott Company, L.P (“Ryder Scott”), our independent reserve engineers, employed technologies demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, well logs, geologic maps including isopach and structure maps, analogy and statistical analysis, and available downhole, production, seismic, and well test data.

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

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

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

The following table provides additional information regarding our estimated proved crude oil and natural gas reserves by region as of December 31, 2022.

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

Revisions of previous estimates. Revisions for 2022 are comprised of (i) upward price revisions of 29 MMBo and 105 Bcf (totaling 46 MMBoe) due to an increase in average crude oil and natural gas prices in 2022 compared to 2021, (ii) the removal of 35 MMBo and 225 Bcf (totaling 72 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 71 MMBo and 401 Bcf (totaling 137 MMBoe) from the removal of PUD reserves due to changes in anticipated well densities, economics, performance, and other factors, and (iv) downward revisions for oil reserves of 9 MMBo and upward revisions for natural gas reserves of 236 Bcf (netting to 31 MMBoe of upward revisions) due to changes in ownership interests, operating costs, anticipated production, and other factors.

Extensions, discoveries and other additions. Extensions, discoveries and other additions for each of the three years reflected in the table above were due to successful drilling and completion activities and continual refinement of our drilling programs. For 2022, proved reserve additions totaled 109 MMBoe in the Bakken, 154 MMBoe in the Anadarko Basin, 18 MMBoe in the Powder River Basin, and 114 MMBoe in the Permian Basin. See the subsequent section titled Summary of Crude Oil and Natural Gas Properties and Projects for a discussion of our 2022 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 2022 and 2021 were primarily attributable to our acquisitions of properties in the Permian Basin and Powder River Basin as discussed in Part II. Item 8. Notes to Consolidated Financial Statements—Note 2. Property Acquisitions. We had no individually significant acquisitions of proved reserves in 2020.

All of our PUD reserves at December 31, 2022 are located in our most active development areas. The following table provides information regarding changes in our PUD reserves for the year ended December 31, 2022. Our PUD reserves at December 31, 2022 include 84 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 2022 we removed 35 MMBo and 225 Bcf (totaling 72 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 71 MMBo and 401 Bcf (totaling 137 MMBoe) in 2022. The increases in average crude oil and natural gas prices in 2022 resulted in upward price revisions of 6 MMBoe and 24 Bcf (totaling 10 MMBoe). Finally, changes in ownership interests, operating costs, anticipated production, and other factors resulted in upward revisions for PUD reserves of 4 MMBo and 31 Bcf (totaling 9 MMBoe) in 2022.

Extensions, discoveries and other additions. Extensions, discoveries and other additions were due to successful drilling activities and continual refinement of our drilling and development programs. For 2022, PUD reserve additions totaled 68 MMBo and 227 Bcf in the Bakken, 27 MMBo and 643 Bcf in the Anadarko Basin, 7 MMBo and 14 Bcf in the Powder River Basin, and 72 MMBo and 149 Bcf in the Permian Basin.

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

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

Conversion to proved developed reserves. In 2022, we developed approximately 21% of our PUD locations and 17% of our PUD reserves booked as of December 31, 2021 through the drilling and completion of 383 gross (150 net) development wells at an aggregate capital cost of approximately $892 million incurred in 2022.

Development plans. We have acquired substantial leasehold positions in our key operating areas. Our drilling programs to date in our historical operating areas have focused on proving our undeveloped leasehold acreage through strategic drilling, thereby increasing the amount of leasehold acreage in the secondary term of the lease with no further drilling obligations (i.e., categorized as held by production) and resulting in a reduced amount of leasehold acreage in the primary term of the lease. While we may opportunistically drill strategic exploratory wells, a substantial portion of our future capital expenditures will be focused on developing our PUD locations, including our drilled but not completed locations. Our inventory of DUC wells classified as PUDs total 317 gross (118 net) operated and non-operated locations at December 31, 2022 and represent 10% of our PUD reserves at that date. The costs to drill our uncompleted wells were incurred prior to December 31, 2022 and only the remaining completion costs are included in future development plans.

Estimated future development costs relating to the development of PUD reserves at December 31, 2022 are projected to be approximately $1.5 billion in 2023, $1.7 billion in 2024, $2.6 billion in 2025, $2.1 billion in 2026, and $1.7 billion in 2027. These capital expenditure projections have been established based on an expectation of drilling and completion costs, available cash flows, borrowing capacity, and the commodity price environment in effect at the time of preparing our reserve estimates and may be adjusted as market conditions evolve. Development of our existing PUD reserves at December 31, 2022 is expected to occur within five years of the date of initial booking of the PUDs. PUD reserves not expected to be drilled within five years of initial booking because of changes in business strategy or for other reasons have been removed from our reserves at December 31, 2022. We had no PUD reserves at December 31, 2022 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, 98% of our PV-10 and 98% of our total proved reserves as of December 31, 2022 included in this Form 10-K. The Ryder Scott technical personnel responsible for preparing the reserve estimates presented herein meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Refer to Exhibit 99 included with this Form 10-K for further discussion of the qualifications of Ryder Scott personnel.

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

Our Manager of Corporate Reserves is the technical person primarily responsible for overseeing the preparation of our reserve estimates. He has a Bachelor of Science degree in Petroleum Engineering, an MBA in Finance and 38 years of industry experience with positions of increasing responsibility in operations, acquisitions, engineering and evaluations. He has worked in the area of reserves and reservoir engineering most of his career and is a member of the Society of Petroleum Engineers. The Manager of Corporate Reserves reports to our Vice President of Resource and Business Development. The reserves estimates are reviewed and approved by certain members of the Company's senior management.

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

The following table sets forth the number of gross and net undeveloped acres as of December 31, 2022 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, 2022, we participated in the drilling and completion of exploratory and development wells as set forth in the table below.

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

The Bakken field of North Dakota and Montana is one of the largest crude oil resource plays in the United States. We are the largest producer and leasehold owner in the Bakken. As of December 31, 2022, we held approximately 1.2 million gross (746,900 net) acres under lease in the Bakken field.

Our total Bakken production averaged 174,397 Boe per day for the fourth quarter of 2022, down 1% from the 2021 fourth quarter. For the year ended December 31, 2022, our average daily Bakken production increased 1% compared to 2021. In 2022, we participated in the drilling and completion of 266 gross (93 net) wells in the Bakken compared to 252 gross (102 net) wells in 2021.

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

We are a leading producer, leasehold owner and operator in the Anadarko Basin of Oklahoma, which includes the SCOOP and STACK areas of the play. As of December 31, 2022, we controlled one of the largest leasehold positions in the Anadarko Basin with approximately 841,400 gross (473,300 net) acres under lease.

Our properties in the Anadarko Basin represented 37% of our total proved reserves as of December 31, 2022 and 40% of our average daily Boe production for the fourth quarter of 2022. Production in the Anadarko Basin averaged 165,225 Boe per day during the fourth quarter of 2022, up 13% compared to the 2021 fourth quarter. For the year ended December 31, 2022, average daily production in the Anadarko Basin increased 7% compared to 2021. We participated in the drilling and completion of 155 gross (44 net) wells in the Anadarko Basin during 2022 compared to 161 gross (63 net) wells in 2021.

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

In 2021, we executed strategic acquisitions to expand our operations into the Powder River Basin of Wyoming and subsequently completed additional acquisitions in the play in 2022. As of December 31, 2022, we held approximately 530,500 gross (377,800 net) acres under lease in the play.

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

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

On December 21, 2021, we executed a strategic acquisition to expand our operations into the Permian Basin of Texas. As of December 31, 2022, we held approximately 239,600 gross (187,700 net) acres under lease in the play.

Our Permian properties represented 16% of our total proved reserves at December 31, 2022 and 11% of our average daily Boe production for the 2022 fourth quarter. Our production in the Permian Basin averaged 44,925 Boe per day for the fourth quarter of 2022. For the year ended December 31, 2022, our average daily Permian production totaled 41,917 Boe per day. During 2022, we participated in the drilling and completion of 39 gross (35 net) wells in the play.

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

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

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

Gross wells represent the number of wells in which we own a working interest and net wells represent the total of our fractional working interests owned in gross wells. The following table presents the total gross and net productive wells by region and by crude oil or natural gas completion as of December 31, 2022. 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, SCOOP, and STACK areas 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 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 is a discussion of certain significant laws, rules and regulations, as amended from time to time, that may affect us in the areas in which we operate.

Our physical sales of crude oil and any derivative instruments relating to crude oil are subject to anti-market manipulation laws and related regulations enforced by the Federal Trade Commission (“FTC”) and the Commodity Futures Trading Commission (“CFTC”). These laws, among other things, prohibit fraudulent or deceptive conduct in connection with wholesale purchases or sales of crude oil and price manipulation in the commodity and futures markets. If we violate the anti-market manipulation laws and regulations, we can be subject to substantial penalties and related third-party damage claims by, among others, sellers, royalty owners and taxing authorities.

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

Further, interstate pipelines and intrastate common carrier pipelines must provide service on an equitable basis and offer service to all similarly situated shippers requesting service on the same terms and under the same rates. When such pipelines operate at full capacity we are subject to proration provisions, which are described in the pipelines’ published tariffs. We generally will have access to crude oil pipeline transportation services to the same extent as our similarly situated competitors.

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

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

We are also required to observe the aforementioned anti-market manipulation laws and related regulations enforced by the FERC and CFTC in connection with physical sales of natural gas and any derivative instruments relating to natural gas. Additionally, the FERC regulates interstate natural gas transportation rates and service conditions under the Natural Gas Act and the Natural Gas Policy Act of 1978, which affects the marketing of natural gas we produce, as well as revenues we receive for sales of our natural gas. The FERC has endeavored to increase competition and make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis and has issued a series of orders to implement its open access policies. We cannot provide any assurance the pro-competitive regulatory approach established by the FERC will continue. However, we do not believe any action taken by the FERC will affect us in a materially different way than similarly situated natural gas producers.

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

Intrastate natural gas transportation service is also subject to regulation by state regulatory agencies. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas we produce, as well as the revenues we receive for sales of our natural gas. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers on a comparable basis, the regulation of intrastate natural gas transportation in states in which we operate will not affect us in a way that materially differs from our similarly situated competitors.

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

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

where we own and operate properties have laws and regulations governing conservation, including provisions for the unitization or pooling of crude oil and natural gas properties, the establishment of maximum allowable rates of production from crude oil and natural gas wells, the regulation of well spacing, the plugging and abandonment of wells, the regulation of greenhouse gas emissions, and limitations or prohibitions on the venting or flaring of natural gas. These laws and regulations directly and indirectly limit the amount of crude oil and natural gas we can produce from our wells and the number of wells and locations we can drill, although we can and do apply for exceptions to such laws and regulations or to have reductions in well spacing. Moreover, each state generally imposes a production, severance or excise tax on the production and sale of crude oil, natural gas and natural gas liquids within its jurisdiction.

The failure to comply with the above laws, rules, and regulations can result in substantial penalties. Our similarly situated competitors are generally subject to the same laws, rules, and regulations as we are.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

As of December 31, 2022, we employed 1,404 people, all of which were employed in the United States, with 790 employees being located at our corporate headquarters in Oklahoma City, Oklahoma and 614 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.

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

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 for holidays, vacation, sick leave, and other personal leave; and healthcare flexible spending accounts, among other things. In addition to these programs, we have a number of other programs designed to further promote the health and wellness of our employees. For instance, employees at our corporate headquarters have access to our fitness center. Additionally, we have an employee assistance program that offers counseling and referral services for a broad range of personal and family situations. We also offer a wellness plan that includes annual biometric screenings, flu shots, smoking cessation programs, and healthy snack options in our break rooms to encourage total body wellness.

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

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

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. 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 term loan, and limit our ability to access capital markets and execute aspects of our business plans. As a result, substantial declines in commodity prices or extended periods of low commodity prices may materially and adversely affect our future business, financial condition, results of operations, cash flows, liquidity and ability to meet our capital expenditure needs and commitments.

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

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

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

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

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

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

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

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

The process of estimating crude oil and natural gas reserves is complex and inherently imprecise. It requires interpretation of available technical data and many assumptions, including assumptions relating to current and future economic conditions, production rates, drilling and operating expenses, and commodity prices. Any significant inaccuracy in these interpretations or assumptions could

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

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

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

You should not assume the present value of future net revenues from our proved reserves is the current market value of our estimated crude oil and natural gas reserves. We base the estimated discounted future net revenues from proved reserves on the 12-month unweighted arithmetic average of the first-day-of-the-month commodity prices for the preceding twelve months. Actual future prices may be materially higher or lower than the average prices used in the calculations. In addition, the use of a 10% discount factor, which is required by the SEC to be used to calculate discounted future net revenues for reporting purposes, may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with our reserves or the crude oil and natural gas industry.

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, 2022, approximately 44% of our total estimated proved reserves (by volume) were undeveloped. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling operations. Our reserve estimates assume we can and will make these expenditures and conduct these operations successfully. These assumptions may not prove to be accurate. Our reserve report at December 31, 2022 includes estimates of total future development costs over the next five years associated with our proved undeveloped reserves of approximately $9.6 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. In 2022, 72 MMBoe of proved undeveloped reserves were removed from our year-end reserve estimates associated with locations no longer scheduled to be drilled within five years from the date of initial booking due to the 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, unless production is established within the spacing units covering the undeveloped acres on which some of the locations are identified, the leases for such acreage will expire. If we are not able to renew leases before they expire, any proved undeveloped reserves associated with such leases will be removed from our proved reserves. The combined net acreage expiring in the next three years represents 41% of our total net undeveloped acreage at December 31, 2022. At that date, we had leases representing 80,550 net acres expiring in 2023, 92,082 net acres expiring in 2024, and 72,514 net acres expiring in 2025.

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

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

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

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

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

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

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

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

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

The crude oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business for the exploration, development, exploitation, production and acquisition of crude oil and natural gas reserves. We monitor and adjust our capital spending plans upward or downward depending on market conditions. Our 2023 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 capital markets to fund our operations.

We have a revolving credit facility with lender commitments totaling $2.255 billion that matures in October 2026. In the future, we may not be able to access adequate funding under our revolving credit facility if our lenders are unwilling or unable to meet their funding obligations or increase their commitments under the credit facility. Our lenders could decline to increase their commitments based on our financial condition, the financial condition of our industry or the economy as a whole or for other reasons beyond our control. Due to these and other factors, we cannot be certain that funding, if needed, will be available to the extent required or on terms we find acceptable. If operating cash flows are insufficient and we are unable to access funding or execute 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. For instance, recent supply chain disruptions stemming from the COVID-19 pandemic have led to shortages of certain materials and equipment and increased costs. While we have not yet experienced material shortages in supply as a result of these disruptions, if they become prolonged or expand in scope the resulting shortages or higher costs could delay the execution of our drilling and development plans or cause us to incur expenditures not provided for in our capital budget or to not achieve the rates of return we are targeting for our development program, all of which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

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

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

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

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

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

Some of the properties in which we have an ownership interest are operated by other companies and involve third-party working interest owners. As of December 31, 2022, non-operated properties represented 14% of our estimated proved developed reserves, 9% of our estimated proved undeveloped reserves, and 12% 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 free cash flows and corporate returns, among other things. However, the anticipated benefits of the transactions may be less significant than expected or may take longer to achieve than anticipated. If we are not able to achieve these objectives and

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

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

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

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

In recent years, the United States government has initiated new tariffs on certain imported goods and has imposed increases to certain existing tariffs on imported goods. In response, certain foreign governments, most notably China, imposed retaliatory tariffs on certain goods their countries import from the United States. These and other events, including the United Kingdom's withdrawal from the European Union and the COVID-19 pandemic, have contributed to increased uncertainty for domestic and global economies. Additionally, growing trends toward populism and political polarization globally and in the U.S. have resulted in uncertainty regarding potential changes in regulations, fiscal policy, social programs, domestic and foreign relations, and government energy policies, which could pose a potential threat to domestic and global economic growth.

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

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

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

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

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

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

While the Company has well-established cyber security 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.

To our knowledge we have not experienced any material losses relating to cyber 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 cyber threats continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any information security vulnerabilities. Additionally, the growth of cyber attacks has resulted in evolving legal and compliance matters which may impose significant costs that are likely to increase over time.

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

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

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

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

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

Our revolving credit facility and term loan contain restrictive covenants with which we must comply, including covenants that limit our ability to, among other things, incur additional indebtedness, incur liens, engage in sale and leaseback transactions, and merge, consolidate or sell all or substantially all of our assets. Our revolving credit facility and term loan also contain a requirement that we maintain a consolidated net debt to total capitalization ratio of no greater than 0.65 to 1.00. This ratio represents the ratio of net debt (calculated as total face value of debt plus outstanding letters of credit less cash and cash equivalents) divided by the sum of net debt plus total shareholders' equity plus, to the extent resulting in a reduction of total shareholders' equity, the amount of any non-cash impairment charges incurred, net of any tax effect, after June 30, 2014. At December 31, 2022, we had $1.16 billion of outstanding borrowings on our credit facility and our consolidated net debt to total capitalization ratio, as defined, was 0.50.

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

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

Our principal exposure to credit risk is through the sale of our crude oil and natural gas production, which we market to energy marketing companies, crude oil refining companies, and natural gas gathering and processing companies ($1.3 billion in receivables at December 31, 2022) and our joint interest and other receivables ($458 million at December 31, 2022). 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 worsening of the commodity price environment may result in a material adverse impact on the liquidity and financial position of the parties with whom we do business, resulting in delays in payment of, or non-payment of, amounts owed to us, delays in operations, loss of access to equipment and facilities and similar impacts. These events could have an adverse impact on our business, financial condition, results of operations and cash flows.

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

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

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

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

Additionally, in August 2022 President Biden signed the Inflation Reduction Act of 2022 (“IRA”) into law, which provides various new tax provisions, incentives, and tax credits aimed at curbing inflation by lowering prescription drug costs, health care costs, and energy costs. The IRA introduces, among other things, (i) a 15% corporate alternative minimum tax on profits for corporations whose average annual adjusted financial statement income for any consecutive three-year period ending after December 31, 2021 exceeds $1

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

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

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

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

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

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

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

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, personal injury claims, regulatory compliance matters, disputes with tax authorities and other matters. While the outcome of these legal matters cannot be predicted with certainty, we do not expect them to have a material effect on our financial condition, results of operations or cash flows.

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

Our common stock previously traded on the New York Stock Exchange (“NYSE”) under the symbol “CLR.” As a result of the take-private transaction described in Part II. Item 8. Notes to Consolidated Financial Statements—Note 1. Organization and Summary of Significant Accounting Policies—Take-Private Transaction, our common stock ceased to be listed on the NYSE effective November 23, 2022 and there is no longer an established trading market for our common stock.

The following table provides information about purchases of our common stock during the quarter ended December 31, 2022 leading up to, and including, the take-private transaction:

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. Our corporate internet website is www.clr.com.

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

Commodity prices increased significantly in 2022 compared to 2021 levels resulting from the ongoing rebalancing of crude oil and natural gas supply and demand fundamentals coupled with the disruption of global hydrocarbon markets prompted by the outbreak of military conflict between Russia and Ukraine. The increase in commodity prices contributed to improved operating results and cash flows in 2022 compared to 2021. Additionally, our property acquisitions in the Permian Basin and Powder River Basin over the past year contributed to increased production, revenues, and cash flows in 2022 compared to 2021. Commodity prices remain volatile and unpredictable and our operating results for the year ended December 31, 2022 may not be indicative of future results. Given the uncertainty surrounding the Russia/Ukraine conflict and ongoing volatility in commodity prices, we are unable to predict the extent to which the conflict or other factors will have on the Company’s future performance.

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

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

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

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

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

The 20% increase in natural gas production in 2022 compared to 2021 was due in part to the previously described property acquisitions over the past year. Properties acquired in the Permian Basin and new well completions increased our 2022 production by 20,191 MMcf while properties acquired in the Powder River Basin and new well completions increased our production by 16,415 MMcf compared to 2021. Additionally, our natural gas production in the Anadarko Basin increased 32,264 MMcf, or 13%, in 2022 compared to 2021 due to new well completions over the past year.

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

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

Net crude oil, natural gas, and natural gas liquids sales. Net sales for 2022 totaled $9.76 billion, a 75% increase compared to net sales of $5.57 billion for 2021 due to significant increases in net sales prices and sales volumes as discussed below.

Total sales volumes for 2022 increased 26,120 MBoe, or 22%, compared to 2021, primarily due to new wells added from our property acquisitions over the past year. For 2022, our crude oil sales volumes increased 24% compared to 2021 and our natural gas sales volumes increased 20% compared to 2021.

Our crude oil net sales prices averaged $91.46 per barrel for 2022, an increase of 43% compared to $64.06 per barrel for 2021 due to the previously described increase in market prices along with improved price differentials. The discount between NYMEX West Texas Intermediate calendar month crude oil prices and our realized crude oil net sales prices improved to an average of $2.71 per barrel in 2022 compared to a discount of $4.00 per barrel in 2021, reflecting strong price realizations across our assets.

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

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

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

Production expenses. Production expenses increased $215.0 million, or 53%, to $621.9 million for 2022 compared to $406.9 million for 2021 due to an increase in the number of producing wells from drilling activities and property acquisitions, cost inflation for services and materials, and higher workover-related activities aimed at enhancing production from producing properties prompted by the favorable commodity price environment. Production expenses on a per-Boe basis averaged $4.24 per Boe for 2022 compared to $3.38 per Boe for 2021, the increase of which reflects higher workover-related activities, cost inflation, and the addition of oil-weighted production acquired in the Permian and Powder River basins over the past year which typically have higher per-unit operating costs compared to gas-weighted properties in the Anadarko Basin.

Production and ad valorem taxes. Production and ad valorem taxes increased $325.8 million, or 81%, to $730.1 million for 2022 compared to $404.4 million for 2021 due to the previously described increase in sales. Our production taxes as a percentage of net sales averaged 7.5% for 2022 compared to 7.3% for 2021.

Depreciation, depletion, amortization and accretion (“DD&A”). Total DD&A amounted to $1.89 billion for 2022, consistent with $1.90 billion for 2021, reflecting a 22% increase in total sales volumes the impact of which was nearly offset by a decrease in our DD&A rate per Boe as further discussed below. 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 upward over the past year prompted by significant increases in first-day-of-the-month commodity prices and other factors, which, when coupled with improvements in capital efficiency and strong well productivity, resulted in a decrease in our DD&A rate for crude oil and natural gas properties in 2022 compared to 2021 and helped offset the additional DD&A recognized in 2022 from increased sales volumes.

Property impairments. Property impairments increased $32.0 million to $70.4 million for 2022 compared to $38.4 million for 2021 due in part to $17.5 million of proved property impairments recognized in 2022 with no proved property impairments being recognized in the prior year. Additionally, impairments of unproved properties increased $14.5 million in 2022 compared to 2021 reflecting an increase in the amortization of undeveloped leasehold costs driven by an increase in our balance of unproved properties resulting from property acquisitions over the past year.

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

Total G&A expenses include non-cash charges for equity/incentive compensation of $217.8 million and $63.2 million for 2022 and 2021, respectively. This increase was primarily driven by the remeasurement of cumulative compensation expense on unvested restricted stock awards that were replaced with new liability-classified awards in conjunction with the Hamm Family's take-private transaction. This remeasurement resulted in the recognition of additional non-cash equity/incentive compensation expense totaling $136 million ($0.93 per Boe), reflecting the increase in the value of the awards from the original grant date to the November 2022 modification date.

G&A expenses other than equity compensation totaled $183.8 million for 2022, an increase of $13.4 million, or 8%, compared to $170.4 million for 2021 primarily due to the growth of our operations and increases in payroll costs and employee benefits, partially offset by higher overhead recoveries from joint interest owners driven by increased drilling, completion, and production activities compared to 2021.

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

Transaction costs. We incurred $32 million of legal and advisory fees related to the Hamm Family's take-private transaction, which are included in the caption "Transaction costs" in the consolidated statements of income (loss) for 2022. In 2021, we incurred $14 million of transaction-related fees in connection with our December 2021 acquisition of properties in the Permian Basin.

Interest expense. Interest expense increased $49.1 million, or 20%, to $300.7 million for 2022 compared to $251.6 million for 2021 due to an increase in our annual weighted average outstanding debt balance from $5.6 billion in 2021 to $6.8 billion in 2022. Our outstanding debt totaled $8.2 billion at December 31, 2022, reflecting an increase of $1.9 billion in the 2022 fourth quarter due to credit facility and term loan borrowings incurred to fund a portion of the November 2022 take-private transaction.

Gain (loss) on extinguishment of debt. See Part II, Item 8. Notes to Consolidated Financial Statements—Note 8. Long-Term Debt for discussion of gains and losses recognized on debt extinguishments in 2022 and 2021.

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

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.

As previously described, on November 22, 2022 the Hamm Family completed a tender offer to purchase any and all of the outstanding shares of the Company’s common stock for $74.28 per share in cash, other than: (i) shares of common stock owned by the Hamm Family and (ii) shares of common stock underlying unvested equity awards issued pursuant to the Company’s long-term incentive plans. A total of approximately 58.1 million shares of Continental’s common stock were purchased pursuant to the take-private transaction for total cash consideration of approximately $4.31 billion, inclusive of payments issued to holders who demanded appraisal rights for their untendered shares in accordance with Oklahoma law.

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

At February 1, 2023, we had approximately $1.12 billion of borrowing availability under our credit facility after considering outstanding borrowings and letters of credit. Our credit facility, which is unsecured and has no borrowing base subject to redetermination, does not mature until October 2026.

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

Net cash provided by operating activities increased $3.1 billion, or 77%, to $7.04 billion for 2022 compared to $3.97 billion for 2021 primarily due to a $4.28 billion increase in crude oil, natural gas, and NGL revenues due to the previously described increases in commodity prices and sales volumes in the current year. This increase was partially offset by a $308 million increase in realized cash losses on matured commodity derivatives, a $470 million increase in cash payments for U.S. federal income taxes, a $326 million increase in production and ad valorem taxes associated with higher revenues, and increases in certain other cash operating expenses primarily due to an increase in sales volumes and growth of our Company over the past year. Increased cash operating expenses included a $215 million increase in production expenses and a $91 million increase in transportation, gathering, processing, and compression expenses.

Net cash used in investing activities totaled $3.53 billion and $4.99 billion for 2022 and 2021, respectively, the decrease of which reflects a reduction in the magnitude of property acquisitions between periods as discussed in Part II, Item 8. Notes to Consolidated Financial Statements—Note 2. Property Acquisitions. Cash capital expenditures excluding acquisitions totaled $2.6 billion and $1.4 billion for 2022 and 2021, respectively, the increase of which reflects our planned increase in budgeted spending in 2022. Additionally, investing cash flows for 2022 include $210 million paid for our new strategic investment in an affiliate of Summit Carbon Solutions described in Note 18. Equity Investment with no similar contributions in 2021.

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

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

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, our budgeted capital spending plans for 2023 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 and business plans.

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

We have an unsecured credit facility, maturing in October 2026, with aggregate lender commitments totaling $2.255 billion. The commitments are from a syndicate of 13 banks and financial institutions. We believe each member of the current syndicate has the capability to fund its commitment. As of February 1, 2023, we had $1.12 billion of borrowing availability on our credit facility after considering outstanding borrowings and letters of credit.

The commitments under our credit facility are not dependent on a borrowing base calculation subject to periodic redetermination based on changes in commodity prices and proved reserves. Additionally, downgrades or other negative rating actions with respect to our credit rating do not trigger a reduction in our current credit facility commitments, nor do such actions trigger a security requirement or change in covenants. Downgrades of our credit rating will, however, trigger increases in our credit facility's interest rates and commitment fees paid on unused borrowing availability under certain circumstances.

Our credit facility contains restrictive covenants that may limit our ability to, among other things, incur additional indebtedness, incur liens, engage in sale and leaseback transactions, or merge, consolidate or sell all or substantially all of our assets. Our credit facility also contains a requirement that we maintain a consolidated net debt to total capitalization ratio of no greater than 0.65 to 1.00. See Part II, Item 8. Notes to Consolidated Financial Statements—Note 8. Long-Term Debt for a discussion of how this ratio is calculated pursuant to our credit agreement.

We were in compliance with our credit facility covenants at December 31, 2022 and expect to maintain compliance. At December 31, 2022, our consolidated net debt to total capitalization ratio was 0.50. 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, 2022, 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 $6.3 billion at December 31, 2022, exclusive of interest payment obligations thereon. Our senior notes are not subject to any mandatory redemption or sinking fund requirements. The earliest scheduled senior note maturity is our $636 million of 2023 Notes due in April 2023, which is reflected as a current liability in the caption “Current portion of long-term debt” in the consolidated balance sheets as of December 31, 2022. We expect to be able to generate or obtain sufficient funds necessary to fully redeem our 2023 Notes by the maturity date. For further information on the face values, maturity dates, semi-annual interest payment dates, optional redemption periods and covenant restrictions related to our senior notes, refer to Note 8. Long-Term Debt in Part II, Item 8. Notes to Consolidated Financial Statements.

We were in compliance with our senior note covenants at December 31, 2022 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, 2023, we had $1.14 billion of outstanding borrowings on our credit facility. Our credit facility matures in October 2026.

In November 2022, we borrowed $750 million under a three-year term loan agreement, the proceeds of which were used to fund a portion of the Hamm Family's November 2022 take-private transaction. The term loan matures in November 2025 and bears 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 covenant requirements in the term loan are consistent with the covenants in our revolving credit facility, including the requirement that we maintain a consolidated net debt to total capitalization ratio of no greater than 0.65 to 1.0. We were in compliance with the term loan covenants at December 31, 2022 and expect to maintain compliance. Downgrades or other negative rating actions with respect to the credit ratings assigned to our senior unsecured debt do not trigger a security requirement or change in covenants for the term loan. Downgrades of our credit rating will, however, trigger an increase in our term loan's interest rate.

We have entered into transportation, gathering, and processing commitments to guarantee capacity on crude oil and natural gas pipelines and natural gas processing facilities that require us to pay per-unit charges regardless of the amount of capacity used. Future commitments remaining as of December 31, 2022 under the arrangements amount to approximately $1.14 billion. See Part II, Item 8. Notes to Consolidated Financial Statements—Note 13. Commitments and Contingencies for additional information.

For the year ended December 31, 2022, we invested $2.70 billion in our capital program excluding $716.6 million of unbudgeted acquisitions, excluding $12.0 million of mineral acquisitions attributable to Franco-Nevada, and including $102.1 million of capital costs associated with increased accruals for capital expenditures as compared to December 31, 2021. Our 2022 capital expenditures were allocated as follows by quarter. See Part II, Item 8. Notes to Consolidated Financial Statements—Note 2. Property Acquisitions for discussion of our notable property acquisitions executed in 2022.

For 2023, our capital expenditures budget attributable to us is expected to be $3.25 billion. Costs of acquisitions and investments, such as those described in Note 18. Equity Investment in Part II, Item 8. Notes to Consolidated Financial Statements, are not included in our 2023 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.

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

For the year ended December 31, 2022, we made estimated quarterly payments for 2022 U.S. federal income taxes totaling $470 million based on an estimate of federal taxable income for the year. Significant judgment is involved in estimating future taxable income as we are required to make assumptions about future commodity prices, projected production, development activities, capital spending, profitability, and general economic conditions, all of which are subject to material revision in future periods as better information becomes available. If commodity prices remain at current levels, we expect to continue generating significant taxable income through at least year-end 2023, which would result in us continuing to make estimated tax payments on a quarterly basis in 2023 that could approximate the payments made in 2022. Because of the significant uncertainty inherent in numerous factors utilized in projecting taxable income, we cannot predict the amount of future income tax payments with certainty.

We have various natural gas volume delivery commitments that are related to our key operating areas. We expect to primarily fulfill our contractual natural gas obligations with production from our proved reserves. However, we may purchase third-party volumes to satisfy our commitments. Additionally, in the Permian Basin certain of our firm sales contracts for crude oil include delivery commitments that specify the delivery of a fixed and determinable quantity. We expect to primarily fulfill our contractual crude oil obligations with production from our proved reserves. As of December 31, 2022, 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.

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

In recent periods we have redeemed or repurchased a portion of our outstanding senior notes. From time to time, we may execute additional redemptions or repurchases of our senior notes for cash in open market transactions, privately negotiated transactions, or otherwise. The timing and amount of any such redemptions or repurchases will depend on prevailing market conditions, our liquidity and prospects for future access to capital, and other factors. The amounts involved in any such transactions, individually or in the

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

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

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

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

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

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

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

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

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.

Impairment provisions for proved properties totaled $17.5 million for the year ended December 31, 2022. Commodity price assumptions used for the year-end December 31, 2022 impairment calculations were based on publicly available average annual

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

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

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

In assessing the realizability of deferred tax assets, management must consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. We apply judgment to determine the weight of both positive and negative evidence in order to conclude whether a valuation allowance is necessary for our deferred tax assets. In determining whether a valuation allowance is required, we consider, among other factors, our financial position, results of operations, projected future taxable income, reversal of existing deferred tax liabilities against deferred tax assets, and tax planning strategies. Significant judgment is involved in this determination as we are required to make assumptions about future commodity prices, projected production, development activities, profitability of future business strategies and forecasted economics in the oil and gas industry. Additionally, changes in the effective tax rate resulting from changes in tax law and our level of earnings may limit utilization of deferred tax assets and may affect the valuation of deferred tax balances in the future. Changes in judgment regarding future realization of deferred tax assets may result in a reversal of all or a portion of the valuation allowance. We believe our deferred tax assets at December 31, 2022 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. President Biden, in pursuit of his regulatory agenda, has issued, and may continue to issue, executive orders that result in more stringent and costly requirements for the domestic crude oil and natural gas industry and there is the potential for the revision of existing laws and regulations or the adoption of new legislation that could adversely affect the oil and gas industry. Such changes, if enacted, could have a material adverse effect on our results of operations and cash flows. See Part I, Item 1. Business—Regulation of the Crude Oil and Natural Gas Industry for a discussion of significant laws and regulations that have been enacted or are currently being considered by regulatory bodies that may affect us in the areas in which we operate.

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

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

The general rate of inflation has increased in conjunction with overall imbalances in supply and demand recoveries from the COVID-19 pandemic. Some of the underlying factors impacting inflation may include, but are not limited to, global supply chain disruptions, shipping bottlenecks, labor market constraints, and side effects from monetary and fiscal expansions. Inflationary pressures are expected to continue in 2023. If these inflationary pressures persist or worsen, and commodity prices continue to remain at attractive levels that stimulate increased industry activity, we may face shortages of service providers, equipment, and materials. Such shortages could result in increased competition which may lead to further increases in costs. 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.

Revenues and transportation expenses associated with production from our operated properties are reported separately as discussed in Part II, Item 8. Notes to Consolidated Financial Statements—Note 9. Revenues. For non-operated properties, we receive a net payment from the operator for our share of sales proceeds which is net of costs incurred by the operator, if any. Such non-operated revenues are recognized at the net amount of proceeds received. As a result, the separate presentation of revenues and transportation expenses from our operated properties differs from the net presentation from non-operated properties. This impacts the comparability of certain operating metrics, such as per-unit sales prices, when such metrics are prepared in accordance with U.S. GAAP using gross presentation for some revenues and net presentation for others.

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

The following table presents a reconciliation of total Company crude oil, natural gas, and natural gas liquids sales (GAAP) to net crude oil, natural gas, and natural gas liquids sales and related net sales prices (non-GAAP) for 2022, 2021, and 2020.

The following tables present reconciliations of crude oil, natural gas, and natural gas liquids sales (GAAP) to net crude oil, natural gas, and natural gas liquids sales and related net sales prices (non-GAAP) for North Dakota Bakken, SCOOP, and the Permian Basin for 2022, 2021, and 2020 as presented in Part I, Item 1. Business—Crude Oil and Natural Gas Operations—Production and Price History.

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

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

Commodity Price Risk. Our primary market risk exposure is in the prices we receive from sales of our crude oil, natural gas, and natural gas liquids. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our natural gas and natural gas liquids production. Commodity prices have been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside of our control, including volatility in the differences between product prices at sales points and the applicable index prices. Based on our average daily production for the quarter ended December 31, 2022, and excluding any effect of our derivative instruments in place, our annual revenue would increase or decrease by approximately $746 million for each $10.00 per barrel change in crude oil prices at December 31, 2022 and $468 million for each $1.00 per Mcf change in natural gas prices at December 31, 2022.

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

The fair value of our derivative instruments at December 31, 2022 was a net liability of $178.7 million, which is comprised of a $193.2 million net liability associated with our natural gas derivatives partially offset by a $14.5 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, 2022.

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 ($1.3 billion in receivables at December 31, 2022) and our joint interest and other receivables ($458 million at December 31, 2022).

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 $16 million at December 31, 2022, which will be used to offset future capital costs when billed. In this manner, we reduce credit risk. We may have the right to place a lien on a co-owner’s interest in the well, to net production proceeds against amounts owed in order to secure payment or, if necessary, foreclose on the interest. Historically, our credit losses on joint interest receivables have been immaterial.

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

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

We had $1.14 billion of variable rate borrowings outstanding on our credit facility and $750 million of variable rate borrowings on our term loan at February 1, 2023. The impact of a 0.25% increase in interest rates on this amount of debt would result in increased interest expense and reduced income before income taxes of approximately $4.7 million per year.

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

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

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

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

We conducted our audits in accordance with the standards of the PCAOB and in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our 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 matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

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

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

acquired in the 2022 Powder River Basin Acquisition, and proved and unproved crude oil and natural gas reserves for the assessment/measurement of impairment of crude oil and natural gas properties as a critical audit matter.

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

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

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

Note 1. Organization and Summary of Significant Accounting Policies

Description of the Company

Continental Resources, Inc. (the “Company”) was formed in 1967 and is incorporated under the laws of the State of Oklahoma. The Company’s principal business is the exploration, development, management, and production of crude oil and natural gas and associated products with properties primarily located in four leading basins in the United States – the Bakken field of North Dakota and Montana, the Anadarko Basin of Oklahoma, the Permian Basin of Texas, and the Powder River Basin of Wyoming. Additionally, the Company pursues the acquisition and management of perpetually owned minerals located in certain of its key operating areas.

Take-Private Transaction

On October 16, 2022, the Company entered into an Agreement and Plan of Merger (the “Merger Agreement”) with Omega Acquisition, Inc. (“Merger Sub”), an entity owned by the Company’s founder, Harold G. Hamm. Pursuant to the Merger Agreement, on October 24, 2022 Merger Sub commenced a tender offer (the “Offer”) to purchase any and all of the outstanding shares of the Company’s common stock for $74.28 per share in cash (the “Offer Price”), other than: (i) shares of common stock owned by Mr. Hamm, certain of his family members and their affiliated entities (collectively, the “Hamm Family”) and (ii) shares of common stock underlying unvested equity awards issued pursuant to the Company’s long-term incentive plans (collectively, the “Rollover Shares”).

The Offer expired at one minute after 11:59 p.m., New York City time, on November 21, 2022. As of the expiration of the Offer, a total of approximately 36.3 million shares were validly tendered and not validly withdrawn pursuant to the Offer. In addition, notices of guaranteed delivery were delivered for approximately 3.4 million shares. Each condition to the Offer was satisfied and, on November 22, 2022, Merger Sub irrevocably accepted for payment all shares that were validly tendered and not withdrawn.

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

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

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

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Continental Resources, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

Following the completion of the take-private transaction: (i) our common stock ceased to be listed on the New York Stock Exchange effective November 23, 2022, (ii) our common stock was deregistered under Section 12(b) of the Securities Exchange Act of 1934 as amended (the “Exchange Act”), and (iii) we suspended our reporting obligations under Section 15(d) of the Exchange Act. As a result, certain of the corporate governance, disclosure, and other provisions applicable to a company with listed equity securities and reporting obligations under the Exchange Act no longer apply to us. We will continue to furnish Quarterly Reports on Form 10-Q and Annual Reports on Form 10-K with the SEC as required by our senior note indentures.

Basis of presentation of consolidated financial statements

The consolidated financial statements include the accounts of the Company, its wholly-owned subsidiaries, and entities in which the Company has a controlling financial interest. Intercompany accounts and transactions have been eliminated upon consolidation. Noncontrolling interests reflected herein represent third party ownership in the net assets of consolidated subsidiaries. The portions of consolidated net income (loss) and equity attributable to the noncontrolling interests are presented separately in the Company’s financial statements. For financial reporting purposes, the Company has one reportable segment due to the similar nature of its business, which is the exploration, development, and production of crude oil, natural gas, and natural gas liquids in the United States.

Investments in entities in which the Company has the ability to exercise significant influence, but does not control, are accounted for using the equity method of accounting. In applying the equity method, the investments are initially recognized at cost and are subsequently adjusted for the Company’s proportionate share of earnings, losses, contributions, and distributions as applicable. See Note 18. Equity Investment for discussion of a strategic investment made by the Company in 2022 that is accounted for under the equity method.

The Company evaluated its December 31, 2022 financial statements for subsequent events through February 22, 2023, 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, 2022, the Company had cash deposits in excess of federally insured amounts of approximately $136.4 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 $5.5 million and $2.8 million as of December 31, 2022 and 2021, respectively. See Note 10. Allowance for Credit Losses for additional information.

Concentration of credit risk

The Company is subject to credit risk resulting from the concentration of its crude oil and natural gas receivables with significant purchasers. For the year ended December 31, 2022, no purchaser accounted for more than 10% of the Company’s total crude oil, natural gas, and natural gas liquids sales for 2022. 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

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Continental Resources, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

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

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


	December 31,
In thousands	2022		2021
Tubular goods and equipment	$	38,636	$	12,506
Crude oil		130,192		93,062
Natural gas		4,436		—
Total	$	173,264	$	105,568

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		5-10
Machinery and equipment		6-30
Gathering and recycling systems		15-30
Storage tanks		10-30
Office and computer equipment, software, furniture and fixtures		3-25
Buildings and improvements		4-40

Depreciation, depletion and amortization

Depreciation, depletion and amortization of capitalized drilling and development costs of producing crude oil and natural gas properties, including related support equipment and facilities, are computed using the unit-of-production method on a field basis based

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Continental Resources, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

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

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, 2020 through December 31, 2022:


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

(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, 2022 and 2021, net property and equipment on the consolidated balance sheets included $96.5 million and $72.8 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.

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Continental Resources, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

Debt issuance costs

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

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

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

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

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

Derivative instruments

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

Fair value of financial instruments

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

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.

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Continental Resources, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

Earnings per share attributable to Continental Resources

Basic net income (loss) per share is computed by dividing net income (loss) attributable to the Company by the weighted-average number of shares outstanding for the period. Prior to the Hamm Family's take-private transaction, in periods where the Company had net income, diluted earnings per share reflected the potential dilution of non-vested restricted stock awards, which was calculated using the treasury stock method. The following table presents the calculation of basic and diluted weighted average shares outstanding and net income (loss) per share attributable to the Company for the years ended December 31, 2022, 2021, and 2020.


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

(1)

For the year ended December 31, 2020, the Company had a net loss and therefore the potential dilutive effect of approximately 934,000 weighted average non-vested restricted shares were not included in the calculation of diluted net loss per share because to do so would have been anti-dilutive to the computation. At December 31, 2022, the Company's outstanding Rollover Shares are expected to be paid in cash, not common stock, upon vesting and are classified as liability awards pursuant to ASC Topic 718, Compensation—Stock Compensation. As a result, no potential dilutive effect for the Rollover Shares is presented for the year ended December 31, 2022.

Note 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.

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Continental Resources, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

At December 31, 2022 the Company had outstanding derivative contracts as set forth in the tables below.


Natural gas derivatives				Weighted Average Hedge Price ($/MMBtu)
Period and Type of Contract	Average Volumes Hedged			Basis Swaps			Swaps		Sold Put		Floor		Ceiling
January 2023 - December 2023
Basis Swaps - NGPL TXOK		75,000	MMBtus/day	$	(0.17	)
January 2023 - March 2023
Collars - Henry Hub		360,000	MMBtus/day								$	3.91	$	5.45
Three-way collars - Henry Hub		50,000	MMBtus/day						$	3.00	$	4.32	$	5.00
Swaps - Henry Hub		210,000	MMBtus/day				$	4.26
Swaps - WAHA		55,000	MMBtus/day				$	2.81
April 2023 - September 2023
Swaps - Henry Hub		405,000	MMBtus/day				$	3.28
Swaps - WAHA		55,000	MMBtus/day				$	2.81
October 2023 - December 2023
Collars - Henry Hub		200,000	MMBtus/day								$	3.12	$	4.09
Swaps - Henry Hub		210,000	MMBtus/day				$	3.51
Swaps - WAHA		55,000	MMBtus/day				$	2.81
January 2024 - December 2024
Collars - Henry Hub		50,000	MMBtus/day								$	3.12	$	4.09
Swaps - Henry Hub		325,000	MMBtus/day				$	3.31
Swaps - WAHA		25,000	MMBtus/day				$	3.43
January 2025 - December 2025
Swaps - Henry Hub		60,000	MMBtus/day				$	3.75
January 2026 - December 2026
Swaps - Henry Hub		50,000	MMBtus/day				$	4.42

Crude oil derivatives

Weighted Average
Hedge Price ($/Bbl)

Period and Type of Contract

Average Volumes Hedged

Roll Swaps

Fixed Swaps

January 2023 - December 2023

Roll Swaps - NYMEX

12,000

Bbls/day

1.07

Fixed Swaps - WTI

8,000

Bbls/day

83.19

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Continental Resources, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

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	2022			2021			2020
Cash received (paid) on derivatives:
Crude oil fixed price swaps	$	—		$	(44,463	)	$	(31,179	)
Crude oil collars		—			(9,365	)		—
Crude oil NYMEX roll swaps		(9,234	)		(163	)		—
Natural gas basis swaps		9,674			—			—
Natural gas WAHA swaps		(16,350	)		—			—
Natural gas fixed price swaps		(353,326	)		(84,141	)		1,071
Natural gas collars		(66,596	)		(11,546	)		1,958
Natural gas three-way collars		(22,287	)		—			—
Cash received (paid) on derivatives, net		(458,119	)		(149,678	)		(28,150	)
Non-cash gain (loss) on derivatives:
Crude oil collars		—			227			(227	)
Crude oil fixed price swaps		11,696			—			—
Crude oil NYMEX roll swaps		1,879			957			—
Natural gas basis swaps		9,088			(177	)		—
Natural gas WAHA swaps		19,386			—			—
Natural gas fixed price swaps		(219,388	)		25,565			2,043
Natural gas collars		(34,303	)		(7,690	)		11,676
Natural gas three-way collars		(1,334	)		1,932			—
Non-cash gain (loss) on derivatives, net		(212,976	)		20,814			13,492
Loss on derivative instruments, net	$	(671,095	)	$	(128,864	)	$	(14,658	)

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, 2022, all at fair value.


	December 31,
In thousands	2022			2021
Commodity derivative assets:
Gross amounts of recognized assets	$	50,559		$	42,903
Gross amounts offset on balance sheet		(7,731	)		(7,381	)
Net amounts of assets on balance sheet		42,828			35,522
Commodity derivative liabilities:
Gross amounts of recognized liabilities		(229,230	)		(8,598	)
Gross amounts offset on balance sheet		7,731			7,381
Net amounts of liabilities on balance sheet	$	(221,499	)	$	(1,217	)

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Continental Resources, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

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	2022			2021
Derivative assets	$	39,280		$	22,334
Derivative assets, noncurrent		3,548			13,188
Net amounts of assets on balance sheet		42,828			35,522
Derivative liabilities		(88,136	)		(899	)
Derivative liabilities, noncurrent		(133,363	)		(318	)
Net amounts of liabilities on balance sheet		(221,499	)		(1,217	)
Total derivative assets (liabilities), net	$	(178,671	)	$	34,305

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.

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Continental Resources, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

The following tables summarize the valuation of derivative instruments by pricing levels that were accounted for at fair value on a recurring basis as of December 31, 2022 and 2021.


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


	Fair value measurements at December 31, 2021 using:
In thousands	Level 1		Level 2			Level 3		Total
Derivative assets (liabilities):
Natural gas fixed price swaps	$	—	$	27,608		$	—	$	27,608
Natural gas basis swaps		—		(177	)		—		(177	)
Natural gas collars		—		3,986			—		3,986
Natural gas three-way collars		—		1,931			—		1,931
Crude oil NYMEX roll swaps		—		957			—		957
Total	$	—	$	34,305		$	—	$	34,305

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, 2022, the Company’s commodity price assumptions were based on forward NYMEX strip prices through year-end 2027 and were then escalated at 3% per year thereafter. Operating cost assumptions were based on current costs escalated at 3% per year beginning in 2024.

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, 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 $17.5 million, which primarily reflected fair value adjustments on a property in an emerging play and on legacy properties in the Red River Units. The impaired properties were written down to their estimated fair value at the time of impairment of $2.1 million.

For the year ended December 31, 2021, estimated future net cash flows were determined to be in excess of cost basis, and therefore no impairment was recorded for the Company's proved crude oil and natural gas properties in 2021.

For the year ended December 31, 2020, the Company determined the carrying amounts of certain proved properties were not recoverable from future cash flows, and therefore, were impaired. Such impairments totaled $207.1 million, which reflected fair value

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Continental Resources, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

adjustments on legacy properties in the Red River Units totaling $168.1 million and various non-core properties in the North and South regions totaling $14.5 million. The impaired properties were written down to their estimated fair value at the time of impairment of $145.7 million. Impairments for 2020 also include a $24.5 million impairment recognized in the first quarter of 2020 to reduce the Company’s crude oil inventory to estimated net realizable value at the time of impairment.

Certain unproved crude oil and natural gas properties were impaired during the years ended December 31, 2022, 2021, and 2020, 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 (loss).


	Year ended December 31,
In thousands	2022		2021		2020
Proved property and inventory impairments	$	17,520	$	—	$	207,119
Unproved property impairments		52,897		38,370		70,822
Total	$	70,417	$	38,370	$	277,941

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. Long-Term Debt for discussion of the changes in the Company's outstanding debt in 2022 and 2021.


	December 31, 2022				December 31, 2021
In thousands	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Debt:
Credit facility	$	1,160,000	$	1,160,000	$	500,000	$	500,000
Term Loan		747,073		747,073		—		—
Notes payable		20,041		18,300		22,356		22,000
4.5% Senior Notes due 2023		635,648		633,600		648,078		670,200
3.8% Senior Notes due 2024		891,404		867,400		908,061		950,000
2.268% Senior Notes due 2026		794,062		693,100		792,621		795,200
4.375% Senior Notes due 2028		993,076		917,200		991,880		1,082,100
5.75% Senior Notes due 2031		1,483,843		1,412,300		1,482,319		1,769,600
2.875% Senior Notes due 2032		792,238		600,900		791,521		780,500
4.9% Senior Notes due 2044		692,255		527,900		692,056		781,500
Total debt	$	8,209,640	$	7,577,773	$	6,828,892	$	7,351,100

The fair value of credit facility and term loan 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.

Note 8. Long-Term Debt

Long-term debt, net of unamortized discounts, premiums, and debt issuance costs totaling $49.6 million and $54.2 million at December 31, 2022 and 2021, respectively, consists of the following.


	December 31,
In thousands	2022		2021
Credit facility	$	1,160,000	$	500,000
Term loan		747,073		—
Notes payable		20,041		22,356
4.5% Senior Notes due 2023 (1)		635,648		648,078
3.8% Senior Notes due 2024		891,404		908,061
2.268% Senior Notes due 2026		794,062		792,621
4.375% Senior Notes due 2028		993,076		991,880
5.75% Senior Notes due 2031		1,483,843		1,482,319
2.875% Senior Notes due 2032		792,238		791,521
4.9% Senior Notes due 2044		692,255		692,056
Total debt		8,209,640		6,828,892
Less: Current portion of long-term debt		638,058		2,326
Long-term debt, net of current portion	$	7,571,582	$	6,826,566

(1) The Company's 2023 Notes, which have a face value of $636.0 million at December 31, 2022, are scheduled to mature on April 15, 2023 and, accordingly, are included as a current liability in the caption “Current portion of long-term debt” in the consolidated balance sheets as of December 31, 2022 along with the current portion of the Company's notes payable.

Credit Facility

On August 24, 2022, the Company amended its credit facility to increase the amount of aggregate commitments by $255 million from $2.0 billion to $2.255 billion and to replace LIBOR as a benchmark reference rate with Term SOFR, with all other terms, conditions, and covenants remaining substantially unchanged. The Company’s credit facility, which matures in October 2026, is unsecured and has no borrowing base requirement subject to redetermination.

The Company had $1.16 billion of outstanding borrowings on its credit facility at December 31, 2022, which were incurred to fund a portion of the Hamm Family's November 2022 take-private transaction. 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, 2022 was 5.9%.

The Company had approximately $1.09 billion of borrowing availability on its credit facility at December 31, 2022 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 net debt (calculated as total face value of debt plus outstanding letters of credit less cash and cash equivalents) divided by the sum of net debt plus total shareholders’ equity plus, to the extent resulting in a reduction of total shareholders’ equity, the amount of any non-cash impairment charges incurred, net of any tax effect, after June 30, 2014. The Company was in compliance with the credit facility covenants at December 31, 2022.

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, 2022.

2023 Notes

2024 Notes

2026 Notes

2028 Notes

2031 Notes

2032 Notes

2044 Notes

Face value (in thousands)

636,000

893,126

800,000

1,000,000

1,500,000

800,000

700,000

Maturity date

April 15, 2023

June 1, 2024

November 15, 2026

January 15, 2028

January 15, 2031

April 1, 2032

June 1, 2044

Interest payment dates

April 15, Oct 15

June 1, Dec 1

May 15, Nov 15

Jan 15, July 15

Jan 15, Jul 15

April 1, Oct 1

June 1, Dec 1

Make-whole redemption period (1)

Jan 15, 2023

Mar 1, 2024

Nov 15, 2023

Oct 15, 2027

Jul 15, 2030

January 1. 2032

Dec 1, 2043

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Continental Resources, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

(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, 2022.

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, 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.

Issuance of Senior Notes

2021

In November 2021, the Company issued $800 million of 2.268% Senior Notes due 2026 and $800 million of 2.875% Senior Notes due 2032 and received combined total net proceeds from the offerings of $1.59 billion after deducting the initial purchasers' fees and original issuance discount. The Company used the net proceeds from the offerings to finance a portion of its December 2021 acquisition of properties in the Permian Basin as discussed in Note 2. Property Acquisitions.

2020

In November 2020, the Company issued $1.5 billion of 5.75% Senior Notes due 2031 and received total net proceeds of $1.49 billion after deducting the initial purchasers' fees. The Company used the net proceeds from the offering to finance the partial repurchases of its 2022 Notes and 2023 Notes in November 2020 as further discussed below, to repay a portion of the borrowings then-outstanding on its credit facility, and for general corporate purposes.

Retirement of Senior Notes

2022

In the second quarter of 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. The losses are reflected in the caption “Gain (loss) on extinguishment of debt” in the consolidated statements of income (loss).

2021

In January 2021, the Company redeemed $400.0 million principal amount of its outstanding 2022 Notes and subsequently redeemed the remaining $230.8 million principal amount of its 2022 Notes in April 2021. The Company recognized pre-tax losses on extinguishment of debt totaling $0.3 million related to the redemptions.

2020

In March and April 2020, the Company repurchased a portion of its 2023 Notes and 2024 Notes in open market transactions at a substantial discount to the face value of the notes, including $50.4 million face value of its 2023 Notes at an aggregate cost of $29.3 million and $89.0 million face value of its 2024 Notes at an aggregate cost of $46.9 million, in each case, including accrued and unpaid interest to the repurchase dates. The Company recognized pre-tax gains on extinguishment of debt totaling $64.6 million related to the repurchases.

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Continental Resources, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

In November 2020, the Company repurchased $469.2 million of its 2022 Notes and $800.0 million of its 2023 Notes using proceeds from its November 2020 issuance of $1.5 billion of 5.75% Senior Notes due 2031. The aggregate of the principal amount, premium, and accrued interest paid upon repurchase of the 2022 Notes and 2023 Notes was $475.0 million and $828.0 million, respectively. The Company recorded pre-tax losses on extinguishment of debt totaling $28.9 million related to these repurchases.

Term Loan

In November 2022, the Company borrowed $750 million under a three-year term loan agreement, the proceeds of which were used to fund a portion of the Hamm Family’s November 2022 take-private transaction. The term loan matures in November 2025 and bears 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 interest rate on the term loan was 6.1% at December 31, 2022.

The term loan 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 1.0, consistent with the covenant requirement in the Company’s revolving credit facility. The Company was in compliance with the term loan covenants at December 31, 2022.

Notes Payable

In June 2020, the Company borrowed an aggregate of $26.0 million under two 10-year amortizing term loans secured by the Company’s corporate office building and its interest in parking facilities in Oklahoma City, Oklahoma. The loans mature in May 2030 and bear interest at a fixed rate of 3.50% per annum through June 9, 2025, at which time the interest rate will be reset and fixed through the maturity date. Principal and interest are payable monthly through the maturity date and, accordingly, $2.4 million is included as a current liability in the caption “Current portion of long-term debt” in the consolidated balance sheets as of December 31, 2022 associated with the loans.

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 $254.0 million, $185.1 million, and $159.0 million for the years ended December 31, 2022, 2021, and 2020, 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

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Continental Resources, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

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 $62.4 million, $39.9 million, and $37.7 million for the years ended December 31, 2022, 2021, and 2020, 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, and disposal activities and the treatment and sale of crude oil reclaimed from waste products. 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,
	2022						2021						2020
In thousands	Crude Oil		Natural Gas and NGLs		Total		Crude Oil		Natural Gas and NGLs		Total		Crude Oil		Natural Gas and NGLs			Total
Bakken	$	3,899,749	$	1,051,870	$	4,951,619	$	2,786,320	$	562,695	$	3,349,015	$	1,523,348	$	28,858		$	1,552,206
Anadarko Basin		1,109,405		1,839,473		2,948,878		874,752		1,264,069		2,138,821		572,653		326,626			899,279
Powder River Basin		557,943		125,065		683,008		101,705		13,110		114,815		—		—			—
Permian Basin		1,122,290		151,217		1,273,507		24,857		4,499		29,356		—		—			—
All other		216,616		1,047		217,663		161,660		74		161,734		103,975		(26	)		103,949
Crude oil, natural gas, and natural gas liquids sales	$	6,906,003	$	3,168,672	$	10,074,675	$	3,949,294	$	1,844,447	$	5,793,741	$	2,199,976	$	355,458		$	2,555,434

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, 2022 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

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Continental Resources, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

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.

Revenues from previously satisfied performance obligations

To record revenues for commodity sales, at the end of each month the Company estimates the amount of production delivered and sold to customers and the prices to be received for such sales. Differences between estimated revenues and actual amounts received for all prior months are recorded in the month payment is received from the customer and are reflected in the financial statements within the caption “Crude oil, natural gas, and natural gas liquids sales”. Revenues recognized during the years ended December 31, 2022, 2021, and 2020 related to performance obligations satisfied in prior reporting periods were not material.

Note 11. Income Taxes

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


	Year ended December 31,
In thousands	2022			2021			2020
Current income tax provision (benefit):
United States federal	$	538,704		$	—		$	(2,248	)
Various states		83,671			—			29
Total current income tax provision (benefit)		622,375			—			(2,219	)
Deferred income tax provision (benefit):
United States federal		374,802			467,051			(148,828	)
Various states		23,627			52,679			(18,143	)
Total deferred income tax provision (benefit)		398,429			519,730			(166,971	)
Provision (benefit) for income taxes	$	1,020,804		$	519,730		$	(169,190	)
Effective tax rate		20.1	%		23.8	%		21.8	%

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


	Year ended December 31,
In thousands, except tax rates	2022			2021			2020
Income (loss) before income taxes	$	5,068,413		$	2,186,138		$	(774,751	)
U.S. federal statutory tax rate		21.0	%		21.0	%		21.0	%
Expected income tax provision (benefit) based on U.S. federal statutory tax rate		1,064,367			459,089			(162,698	)
Items impacting the effective tax rate:
State and local income taxes, net of federal benefit		126,932			77,979			(24,808	)
Tax (benefit) deficiency from stock-based compensation		(5,282	)		5,869			4,927
Change in valuation allowance		—			(14,474	)		14,474
Federal tax credit for increasing research activities (1)		(151,913	)		—			—
Other, net		(13,300	)		(8,733	)		(1,085	)
Provision (benefit) for income taxes	$	1,020,804		$	519,730		$	(169,190	)
Effective tax rate		20.1	%		23.8	%		21.8	%

(1)

In 2022, the Company commenced a study to determine the amount of its qualified research activities performed during the tax years of 2018 to 2022 that qualify for a research and development income tax credit under the Internal Revenue Code. A $152 million decrease in the Company’s income tax provision was recognized in 2022 to account for eligible tax credits identified as a result of the study.

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

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Continental Resources, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

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. During 2020, a $14.5 million valuation allowance was established for the deferred tax asset associated with a portion of the Company’s Oklahoma state net operating loss carryforwards. In 2021, the Company reassessed the realizability of the deferred tax asset related to Oklahoma state net operating loss carryforwards and determined it was more likely than not that such assets would be realized. Therefore, it was determined that the previously recorded valuation allowance in 2020 should be released in 2021. No valuation allowances were recognized during the year ended December 31, 2022.

The Company 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 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, 2022 and 2021 are reflected in the table below.


	December 31,
In thousands	2022			2021
Deferred tax assets
United States net operating loss carryforwards	$	63,128		$	365,602
Incentive/equity compensation		34,987			12,751
Net deferred hedge losses		42,898			—
Other		31,324			29,421
Total deferred tax assets		172,337			407,774
Valuation allowance		—			—
Total deferred tax assets, net of valuation allowance		172,337			407,774
Deferred tax liabilities
Property and equipment		(2,708,641	)		(2,536,938	)
Other		(2,008	)		(10,720	)
Total deferred tax liabilities		(2,710,649	)		(2,547,658	)
Deferred income tax liabilities, net	$	(2,538,312	)	$	(2,139,884	)

As of December 31, 2022, the Company had net operating loss (“NOL”) carryforwards in Oklahoma totaling $1.99 billion, of which $881 million expires between 2034 and 2037, and the remaining $1.11 billion has an indefinite life. In 2022, the Company utilized all of its previously generated federal NOL carryforwards to offset a portion of its 2022 federal taxable income and no federal NOL or tax credit carryforwards remain at December 31, 2022. Additionally, in 2022 the Company utilized all of its previously generated NOL carryforwards in North Dakota to offset a portion of its 2022 taxable income in that state and no North Dakota NOL carryforwards remain at December 31, 2022. Any available statutory depletion carryforwards will be recognized when realized. 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 2019.

Note 12. Leases

The Company’s lease liabilities recognized on the balance sheet as a lessee totaled $24.1 million and $15.5 million as of December 31, 2022 and 2021, respectively, at discounted present value, which is comprised of the asset classes reflected in the table below. All leases recognized on the Company’s balance sheet are classified as operating leases. 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.

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Continental Resources, Inc. and Subsidiaries

Notes to Consolidated Financial Statements


	December 31,
In thousands	2022		2021
Surface use agreements	$	18,136	$	12,354
Field equipment		5,224		2,095
Other		781		1,025
Total	$	24,141	$	15,474

Minimum future commitments by year for the Company’s operating leases as of December 31, 2022 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
2023	$	5,180
2024		4,172
2025		1,885
2026		1,848
2027		1,827
Thereafter		18,351
Total operating lease liabilities, at undiscounted value	$	33,263
Less: Imputed interest		(9,122	)
Total operating lease liabilities, at discounted present value	$	24,141
Less: Current portion of operating lease liabilities		(4,086	)
Operating lease liabilities, net of current portion	$	20,055

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 its 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	2022			2021			2020
Lease costs:
Operating lease costs	$	3,484		$	6,653		$	6,444
Variable lease costs		650			3,271			4,956
Short-term lease costs		124,535			77,551			107,984
Total lease costs	$	128,669		$	87,475		$	119,384

Other information:
Right-of-use assets obtained in exchange for new operating lease liabilities	$	19,944		$	10,481		$	7,377
Operating cash flows from operating leases included in lease liabilities		4,370			1,731			890
Weighted average remaining lease term as of December 31 (in years)		12.0			14.4			13.2
Weighted average discount rate as of December 31		4.8	%		5.0	%		4.8	%

Note 13. Commitments and Contingencies

Transportation, gathering, and processing commitments – The Company has entered into transportation, gathering, and processing commitments to guarantee capacity on crude oil and natural gas pipelines and natural gas processing facilities. The commitments, which have varying terms extending as far as 2031, require the Company to pay per-unit transportation, gathering, or processing charges regardless of the amount of capacity used. Future commitments remaining as of December 31, 2022 under the arrangements amount to approximately $1.14 billion, of which $328 million is expected to be incurred in 2023, $291 million in 2024, $164 million in 2025, $139 million in 2026, $136 million in 2027, and $78 million thereafter. A portion of these future costs will be borne by other interest owners. The Company is not committed under the above contracts to deliver fixed and determinable quantities of crude oil or natural gas in the future. These commitments do not qualify as leases under ASC Topic 842 and are not recognized on the Company’s balance sheet.

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Notes to Consolidated Financial Statements

Lease commitments – The Company has various lease commitments primarily associated with surface use agreements and field equipment. See Note 12. Leases for additional information.

Strategic investment – See Note 18. Equity Investment for discussion of future spending commitments associated with a strategic investment announced by the Company in the first quarter of 2022.

Litigation pertaining to the Company's routine operations

In March 2022, the Company was named as a defendant in a case filed in the U.S. District Court for the Northern District of California by gasoline consumer plaintiffs alleging that, beginning in March 2020, the Company and the other named defendants conspired with Russia, OPEC and others to raise the price of oil and gasoline by reducing the supply of these products. The plaintiffs are seeking unspecified damages and injunctive relief. On July 1, 2022, the Company, together with other named defendants, filed motions to dismiss. On January 9, 2023, the court granted the defendants' respective motions to dismiss without leave to amend.

The Company is involved in various other legal proceedings including, but not limited to, commercial disputes, claims from royalty and surface owners, property damage claims, personal injury claims, regulatory compliance matters, disputes with tax authorities and other matters. While the outcome of these legal matters cannot be predicted with certainty, the Company does not expect them to have a material adverse effect on its financial condition, results of operations or cash flows. As of December 31, 2022 and 2021, the Company had recognized a liability within “Other noncurrent liabilities” of $20.2 million and $7.9 million, respectively, for various matters, none of which are believed to be individually significant.

Litigation pertaining to take-private transaction

Transactions such as the Hamm Family's take-private transaction described in Note 1. Organization and Summary of Significant Accounting Policies—Take-Private Transaction often attract litigation and demands from minority shareholders.

On August 25, 2022, Walter T. Doggett, on behalf of himself and a class of all other similarly situated shareholders (“Doggett”), filed a class action petition in the District Court of Oklahoma County, Oklahoma, against Mr. Hamm, as the controlling shareholder of the Company, for alleged breaches of fiduciary duties in connection with the take-private transaction. On November 7, 2022, Doggett filed an amended class action petition adding as additional defendants the Company, certain trusts established for the benefit of Mr. Hamm and/or his family members (the “Hamm Family Trusts”), and the Company’s other directors. Doggett alleges that the defendants breached their fiduciary duties in the connection with the take-private transaction and seeks: (i) monetary damages; (ii) the costs and expenses associated with the lawsuit; and (iii) other equitable relief.

On November 23, 2022, Ralph Donald Turlington, Alroc Real Estate Associates (Del.) LLC, and the Turlington Family Irrevocable Trust, on behalf of themselves and a class of all other similarly situated former shareholders (“Turlington”), filed a class action petition in the District Court of Oklahoma County, Oklahoma, against Mr. Hamm, the Hamm Family Trusts, and the Company’s other directors. Turlington alleges the defendants breached their fiduciary duties in connection with the take-private transaction and seeks: (i) monetary damages; (ii) the costs and expenses associated with the lawsuit; and (iii) other equitable relief.

On November 30, 2022, Doggett and Turlington filed a motion to consolidate the Doggett and Turlington lawsuits and to appoint lead and liaison counsel.

On August 11, 2022, Pembroke Pines Firefighters & Police Officers Pension Fund (“Pembroke”), a shareholder, delivered a letter (the “Pembroke Request”) to the Company requesting the inspection of certain books and records of the Company purportedly to investigate potential breaches of fiduciary duties by the Company’s directors and senior management in connection with the take-private transaction. On August 18, 2022, the Company responded to the Pembroke Request. On October 20, 2022, Pembroke updated the Pembroke Request, and the Company again responded to the Pembroke Request on October 27, 2022. The Company has subsequently produced certain information to Pembroke identified in the Pembroke Request. On November 17, 2022, Pembroke filed a verified petition in the District Court of Pottawatomie County, Oklahoma, against the Company seeking: (i) the production of certain Company books and records identified in the Pembroke Request; (ii) the costs and expenses associated with the lawsuit; and (iii) other equitable relief.

On December 6, 2022, Pembroke filed a motion to intervene and stay the Doggett and Turlington lawsuits until Pembroke completes its inspection of the Company’s books and records and prepares its own lawsuit.

On November 2, 2022, Kevin Barry (“Barry”), a shareholder, delivered a letter (the “Barry Request”) to the Company requesting the inspection of certain books and records of the Company purportedly to investigate potential breaches of fiduciary duties by the

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Continental Resources, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

Company’s directors and senior management in connection with the take-private transaction. On November 9, 2022, the Company responded to the Barry Request. The Company has subsequently produced certain information to Barry identified in the Barry Request. On November 18, 2022, Barry filed a verified petition in the District Court of Oklahoma County, Oklahoma, against the Company seeking: (i) the production of certain Company books and records identified in the Barry Request; (ii) the costs and expenses associated with the lawsuit; and (iii) other equitable relief.

On November 10, 2022, Kerry Panozzo (“Panozzo”), a shareholder, delivered a letter (the “Panozzo Request”) to the Company requesting the inspection of certain books and records of the Company purportedly to investigate potential breaches of fiduciary duties by the Company’s directors and senior management in connection with the take-private transaction. On November 17, 2022, the Company responded to the Panozzo Request. The Company has subsequently produced certain information to Panozzo identified in the Panozzo Request. On November 21, 2022, Panozzo filed a verified petition in the District Court of Oklahoma County, Oklahoma, against the Company seeking: (i) the production of certain Company books and records identified in the Panozzo Request; (ii) the costs and expenses associated the lawsuit; and (iii) other equitable relief.

In November 2022, the Company received letters demanding appraisal of their respective shares of the Company’s common stock from FourWorld Deep Value Opportunities Fund I, LLC, FourWorld Event Opportunities, LP, FW Deep Value Opportunities I, LLC, FourWorld Global Opportunities Fund, Ltd., FourWorld Special Opportunities Fund, LLC, Corbin ERISA Opportunity Fund Ltd., and Quadre Investments, L.P. (collectively, “FourWorld”). On January 5, 2023, these parties filed a petition in the District Court of Oklahoma County, Oklahoma, seeking appraisal of their respective shares of the Company’s common stock in connection with the take-private transaction.

On January 13, 2023, the Company, Mr. Hamm, the Hamm Family Trusts, and the Company’s other directors filed a motion to consolidate the Doggett, Turlington, and FourWorld lawsuits. On January 26, 2023, the Company filed a motion to stay the FourWorld appraisal lawsuit pending adjudication of the Company’s motion to consolidate the Doggett, Turlington, and FourWorld lawsuits.

On February 14, 2023, Pembroke and Panozzo, on behalf of themselves and a class of all other similarly situated former shareholders, filed a class action petition in the District Court of Oklahoma County, Oklahoma, against Mr. Hamm, the Hamm Family Trusts, and the Company’s other directors. Pembroke and Panozzo allege the defendants breached their fiduciary duties in connection with the take-private transaction and seek: (i) monetary damages; (ii) the costs and expenses associated with the lawsuit; and (iii) other equitable relief.

The Company, Mr. Hamm, the Hamm Family Trusts, and the Company’s other directors intend to vigorously defend themselves against the foregoing matters.

Environmental risk – Due to the nature of the crude oil and natural gas business, the Company is exposed to possible environmental risks. The Company is not aware of any material environmental issues or claims.

Note 15. Stock-Based Compensation

Prior to the Hamm Family’s take-private transaction described in Note 1. Organization and Summary of Significant Accounting Policies—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 Long-Term Incentive Plan (“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 (loss), was $217.8 million, $63.2 million, and $64.6 million for the years ended December 31, 2022, 2021, and 2020, respectively.

As of the November 22, 2022 effective time of the Hamm Family’s take-private transaction, each unvested restricted stock award previously issued 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 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, of which the Company currently intends to settle all awards vesting in 2023, 2024, and 2025 in cash. Thus, the Rollover Shares are classified as a liability award under ASC 718 and, as of December 31, 2022, the Company had recorded a current liability of $125.7 million and a non-current liability of $100.1 million in the captions “Current portion of incentive compensation liability” and “Incentive compensation liability, net of current portion,” respectively, in the consolidated balance sheets. Such amounts reflect the Company’s estimate of expected future cash payments multiplied by the percentage of requisite service periods that employees have completed as of December 31, 2022. The Company’s liability will be remeasured each reporting period to reflect additional services rendered by employees and to reflect changes in expected cash payments arising from underlying changes in the value of the Company. 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.

A summary of changes in non-vested restricted shares from December 31, 2019 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, 2019		3,461,908		$	46.82
Granted		2,738,625			26.93
Vested		(1,146,618	)		45.78
Forfeited		(163,277	)		36.69
Non-vested restricted shares at December 31, 2020		4,890,638		$	36.26
Granted		3,050,491			24.73
Vested		(1,750,483	)		44.36
Forfeited		(296,138	)		26.61
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		—		$	—

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Continental Resources, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

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, 2021, and 2020 was approximately $98.4 million, $46.7 million, and $27.5 million, respectively.

Note 19. Crude Oil and Natural Gas Property Information

The tables reflected below represent consolidated figures for the Company and its subsidiaries. Results attributable to noncontrolling interests are not material relative to the Company's consolidated results and are not separately presented below.

The following table sets forth the Company’s consolidated results of operations from crude oil and natural gas producing activities for the years ended December 31, 2022, 2021, and 2020.


	Year ended December 31,
In thousands	2022			2021			2020
Crude oil, natural gas, and natural gas liquids sales	$	10,074,675		$	5,793,741		$	2,555,434
Production expenses		(621,921	)		(406,906	)		(359,267	)
Production and ad valorem taxes		(730,132	)		(404,362	)		(192,718	)
Transportation, gathering, processing, and compression		(316,414	)		(224,989	)		(196,692	)
Exploration expenses		(23,068	)		(21,047	)		(17,732	)
Depreciation, depletion, amortization and accretion		(1,856,067	)		(1,872,075	)		(1,859,893	)
Property impairments		(70,417	)		(38,370	)		(277,941	)
Income tax (provision) benefit (1)		(1,512,132	)		(690,902	)		83,427
Results from crude oil and natural gas producing activities	$	4,944,524		$	2,135,090		$	(265,382	)

(1)

Income taxes reflect the application of a combined federal and state tax rate of 23.5% for 2022 and 24.5% for both 2021 and 2020 on pre-tax income/loss generated by our operations.

Costs incurred in crude oil and natural gas activities

Costs incurred, both capitalized and expensed, in connection with the Company’s consolidated crude oil and natural gas acquisition, exploration and development activities for the years ended December 31, 2022, 2021 and 2020 are presented below. See Note 2. Property Acquisitions for discussion of notable property acquisitions that gave rise to changes in acquisition costs incurred between periods.


	Year ended December 31,
In thousands	2022		2021		2020
Property acquisition costs:
Proved	$	458,762	$	2,580,271	$	60,494
Unproved		412,571		1,197,507		201,919
Total property acquisition costs		871,333		3,777,778		262,413
Exploration Costs		343,117		171,549		48,282
Development Costs		2,185,645		1,174,828		1,053,532
Total	$	3,400,095	$	5,124,155	$	1,364,227

Costs incurred above include asset retirement costs and revisions thereto of $30.8 million, $31.1 million and $18.1 million for the years ended December 31, 2022, 2021 and 2020, respectively.

Aggregate capitalized costs

Aggregate capitalized costs relating to the Company’s consolidated crude oil and natural gas producing activities and related accumulated depreciation, depletion and amortization as of December 31, 2022 and 2021 are as follows:


	December 31,
In thousands	2022			2021
Proved crude oil and natural gas properties	$	34,741,054		$	31,613,656
Unproved crude oil and natural gas properties		1,513,627			1,358,673
Total		36,254,681			32,972,329
Less accumulated depreciation, depletion and amortization		(18,134,473	)		(16,310,054	)
Net capitalized costs	$	18,120,208		$	16,662,275

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

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Continental Resources, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

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 (loss) 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 at least a quarterly 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	2022			2021			2020
Balance at January 1	$	37,673		$	32,737		$	6,257
Additions to capitalized exploratory well costs pending determination of proved reserves		286,059			122,068			32,880
Reclassification to proved crude oil and natural gas properties based on the determination of proved reserves		(229,348	)		(117,131	)		(72	)
Capitalized exploratory well costs charged to expense		(9,562	)		(1	)		(6,328	)
Balance at December 31	$	84,822		$	37,673		$	32,737
Number of gross wells		36			17			16

As of December 31, 2022, the Company had no significant exploratory well costs that were suspended one year beyond the completion of drilling.

Note 20. Supplemental Crude Oil and Natural Gas Information (Unaudited)

The table below shows estimates of proved reserves prepared by the Company’s internal technical staff and independent external reserve engineers in accordance with SEC definitions. Ryder Scott Company, L.P. prepared reserve estimates for properties comprising approximately 98%, 98%, and 95% of the Company’s total proved reserves as of December 31, 2022, 2021, and 2020, respectively. Remaining reserve estimates were prepared by the Company’s internal technical staff. 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 in the tables below.

Proved reserves are estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be economically producible in future periods from known reservoirs 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. There are numerous uncertainties inherent in estimating quantities of proved crude oil and natural gas reserves. 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, and estimates of engineers other than the Company’s might differ materially from the estimates set forth herein. 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.

Reserves at December 31, 2022, 2021, and 2020 were computed using the 12-month unweighted average of the first-day-of-the-month commodity prices as required by SEC rules.

Natural gas imbalance receivables and payables for each of the three years ended December 31, 2022, 2021, and 2020 were not material and have not been included in the reserve estimates.

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Notes to Consolidated Financial Statements

Proved crude oil and natural gas reserves

Changes in proved reserves were as follows for the periods presented:


	Crude Oil (MBbls)			Natural Gas (MMcf)			Total (MBoe)
Proved reserves as of December 31, 2019		760,187			5,154,471			1,619,265
Revisions of previous estimates		(249,845	)		(1,530,174	)		(504,874	)
Extensions, discoveries and other additions		42,106			295,686			91,387
Production		(58,745	)		(306,528	)		(109,833	)
Sales of minerals in place		—			—			—
Purchases of minerals in place		3,272			27,269			7,817
Proved reserves as of December 31, 2020		496,975			3,640,724			1,103,762
Revisions of previous estimates		14,574			233,966			53,569
Extensions, discoveries and other additions		165,268			1,235,022			371,105
Production		(58,636	)		(370,110	)		(120,321	)
Sales of minerals in place		(70	)		(469	)		(148	)
Purchases of minerals in place		175,419			371,546			237,343
Proved reserves as of December 31, 2021		793,530			5,110,679			1,645,310
Revisions of previous estimates		(85,604	)		(284,738	)		(133,061	)
Extensions, discoveries and other additions		194,848			1,203,850			395,490
Production		(72,827	)		(442,980	)		(146,657	)
Sales of minerals in place		(25	)		(712	)		(144	)
Purchases of minerals in place		59,617			259,253			102,826
Proved reserves as of December 31, 2022		889,539			5,845,352			1,863,764

Revisions for 2021 are comprised of (i) upward price revisions of 92 MMBo and 458 Bcf (totaling 168 MMBoe) due to the significant increase in average crude oil and natural gas prices in 2021 compared to 2020 resulting from the lifting of COVID-19 restrictions, the resumption of normal economic activity, and the resulting improvement in supply and demand fundamentals, (ii) the removal of 31 MMBo and 155 Bcf (totaling 57 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 12 MMBo and 263 Bcf (totaling 56 MMBoe) from the removal of PUD reserves due to changes in anticipated well densities, economics, performance, and other factors, (iv) downward revisions for oil reserves of 35 MMBo and upward revisions for natural gas reserves of 195 Bcf (netting to 2 MMBoe of downward revisions) due to changes in ownership interests, operating costs, anticipated production, and other factors.

Revisions for 2020 are comprised of (i) the removal of 50 MMBo and 345 Bcf (totaling 107 MMBoe) of PUD reserves no longer scheduled to be drilled within five years of initial booking due to a reduction in the scope of future drilling programs based on adverse market conditions, reduced demand, and lower prices caused by the COVID-19 pandemic and our resulting allocation of capital to areas providing the best opportunities to improve efficiencies, recoveries, and rates of return, (ii) downward revisions of 29 MMBo and 172 Bcf (totaling 58 MMBoe) from the removal of PUD reserves due to changes in economics, performance, and other factors, (iii) downward price revisions of 214 MMBo and 1,043 Bcf (totaling 388 MMBoe) due to a significant decrease in average crude oil and natural gas prices in 2020 compared to 2019 resulting from the economic turmoil caused by the COVID-19 pandemic and other factors, and (iv) net upward revisions for oil reserves of 43 MMBo and 31 Bcf (totaling 48 MMBoe) due to changes in ownership interests, operating costs, anticipated production, and other factors.

Table of Contents

Continental Resources, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

proved reserve additions totaled 69 MMBo and 241 Bcf (totaling 109 MMBoe) in the Bakken, 29 MMBo and 751 Bcf (totaling 154 MMBoe) in the Anadarko Basin, 13 MMBo and 32 Bcf (totaling 18 MMBoe) in the Powder River Basin, and 84 MMBo and 178 Bcf (totaling 114 MMBoe) in the Permian Basin.

Sales of minerals in place. There were no individually significant dispositions of proved reserves in the three years reflected in the table above.

Purchases of minerals in place. See Note 2. Property Acquisitions for discussion of notable property acquisitions for the years ended December 31, 2022, 2021, and 2020.

The following reserve 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, 2022, 2021, and 2020:


	December 31,
	2022		2021		2020
Proved Developed Reserves
Crude oil (MBbl)		454,299		424,153		281,906
Natural Gas (MMcf)		3,486,774		2,901,147		2,073,011
Total (MBoe)		1,035,428		907,678		627,407
Proved Undeveloped Reserves
Crude oil (MBbl)		435,240		369,377		215,069
Natural Gas (MMcf)		2,358,578		2,209,532		1,567,713
Total (MBoe)		828,336		737,632		476,355
Total Proved Reserves
Crude oil (MBbl)		889,539		793,530		496,975
Natural Gas (MMcf)		5,845,352		5,110,679		3,640,724
Total (MBoe)		1,863,764		1,645,310		1,103,762

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 is 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.

Table of Contents

Continental Resources, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

Standardized measure of discounted future net cash flows relating to proved crude oil and natural gas reserves

The standardized measure of discounted future net cash flows presented in the following table was computed using the 12-month unweighted average of the first-day-of-the-month commodity prices, the costs in effect at December 31 of each year and a 10% discount factor. The Company cautions that actual future net cash flows may vary considerably from these estimates. Although the Company’s estimates of total proved reserves, development costs and production rates were based on the best available information, the development and production of the crude oil and natural gas reserves may not occur in the periods assumed. Actual prices realized, costs incurred and production quantities may vary significantly from those used. Therefore, the estimated future net cash flow computations should not be considered to represent the Company’s estimate of the expected revenues or the current value of existing proved reserves.

The following table sets forth the standardized measure of discounted future net cash flows attributable to proved crude oil and natural gas reserves as of December 31, 2022, 2021, and 2020. Discounted future net cash flows attributable to noncontrolling interests are not material relative to the Company's consolidated amounts and are not separately presented below.


	December 31,
In thousands	2022			2021			2020
Future cash inflows	$	115,338,240		$	67,034,046		$	21,334,235
Future production costs		(26,570,673	)		(18,837,000	)		(7,750,834	)
Future development and abandonment costs		(9,651,656	)		(7,751,678	)		(3,950,752	)
Future income taxes (1)		(16,158,309	)		(7,862,849	)		(724,569	)
Future net cash flows		62,957,602			32,582,519			8,908,080
10% annual discount for estimated timing of cash flows		(31,050,041	)		(15,946,126	)		(4,254,515	)
Standardized measure of discounted future net cash flows	$	31,907,561		$	16,636,393		$	4,653,565

(1)

Estimated future income taxes were calculated by applying existing statutory tax rates, including any known future changes, to the estimated pre-tax net cash flows related to proved crude oil and natural gas reserves, giving effect to any permanent taxable differences and tax credits, less the tax basis of the properties involved. The U.S. federal statutory tax rate utilized in estimating future income taxes was 21% at December 31, 2022, 2021, and 2020.

The weighted average crude oil price (adjusted for location and quality differentials) utilized in the computation of future cash inflows was $89.47, $62.19, and $34.34 per barrel at December 31, 2022, 2021, and 2020, respectively. The weighted average natural gas price (adjusted for location and quality differentials) utilized in the computation of future cash inflows was $6.12, $3.46, and $1.17 per Mcf at December 31, 2022, 2021, and 2020, respectively. Future cash flows are reduced by estimated future costs to develop and produce the proved reserves, as well as certain abandonment costs, based on year-end cost estimates assuming continuation of existing economic conditions. The expected tax benefits to be realized from the utilization of net operating loss carryforwards and tax credits are used in the computation of future income tax cash flows.

The changes in the aggregate standardized measure of discounted future net cash flows attributable to proved crude oil and natural gas reserves are presented below for each of the past three years.


	December 31,
In thousands	2022			2021			2020
Standardized measure of discounted future net cash flows at January 1	$	16,636,393		$	4,653,565		$	10,461,641
Extensions, discoveries and improved recoveries, less related costs		7,331,375			2,985,056			187,981
Revisions of previous quantity estimates		(3,096,189	)		816,674			(2,952,489	)
Changes in estimated future development and abandonment costs		1,283,405			706,168			4,760,286
Purchases (sales) of minerals in place, net		1,852,313			3,408,365			53,742
Net change in prices and production costs		15,251,976			9,396,945			(6,912,031	)
Accretion of discount		2,049,284			489,273			1,183,993
Sales of crude oil and natural gas produced, net of production costs		(8,406,208	)		(4,757,483	)		(1,806,758	)
Development costs incurred during the period		1,302,693			683,212			863,101
Change in timing of estimated future production and other		1,899,889			1,871,903			(2,325,024	)
Change in income taxes		(4,197,370	)		(3,617,285	)		1,139,123
Net change		15,271,168			11,982,828			(5,808,076	)
Standardized measure of discounted future net cash flows at December 31	$	31,907,561		$	16,636,393		$	4,653,565

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, 2022 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 2022 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 2022 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, 2022.

Information as to Item 10 will be set forth in an amendment to this Form 10-K to be filed on Form 10-K/A with the Securities and Exchange Commission no later than 120 days after the end of our fiscal year covered by this report and is incorporated herein by reference.

Information as to Item 11 will be set forth in an amendment to this Form 10-K to be filed on Form 10-K/A with the Securities and Exchange Commission no later than 120 days after the end of our fiscal year covered by this report and is incorporated herein by reference.

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

Information as to Item 12 will be set forth in an amendment to this Form 10-K to be filed on Form 10-K/A with the Securities and Exchange Commission no later than 120 days after the end of our fiscal year covered by this report and is incorporated herein by reference.

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

Information as to Item 13 will be set forth in an amendment to this Form 10-K to be filed on Form 10-K/A with the Securities and Exchange Commission no later than 120 days after the end of our fiscal year covered by this report and is incorporated herein by reference.

Information as to Item 14 will be set forth in an amendment to this Form 10-K to be filed on Form 10-K/A with the Securities and Exchange Commission no later than 120 days after the end of our fiscal year covered by this report and is incorporated herein by reference.

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.


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


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


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


	Developed acres				Undeveloped acres				Total
	Gross		Net		Gross		Net		Gross		Net
Bakken		1,127,004		703,277		78,098		43,582		1,205,102		746,859
Anadarko Basin		604,876		350,084		236,552		123,201		841,428		473,285
Powder River Basin		242,000		179,069		288,525		198,747		530,525		377,816
Permian Basin		111,880		102,366		127,710		85,382		239,590		187,748
All other		243,269		189,259		216,135		154,267		459,404		343,526
Total		2,329,029		1,524,055		947,020		605,179		3,276,049		2,129,234


PART I
Item 1.	Business	1
	General	1
	Our Business Strategies	2
	Our Business Strengths	2
	Crude Oil and Natural Gas Operations	3
	Proved Reserves	3
	Developed and Undeveloped Acreage	6
	Drilling Activity	7
	Summary of Crude Oil and Natural Gas Properties and Projects	7
	Production and Price History	9
	Productive Wells	10
	Title to Properties	10
	Marketing	10
	Competition	11
	Regulation of the Crude Oil and Natural Gas Industry	11
	Human Capital	17
	Company Contact Information	18
Item 1A.	Risk Factors	19
Item 1B.	Unresolved Staff Comments	29
Item 2.	Properties	29
Item 3.	Legal Proceedings	29
Item 4.	Mine Safety Disclosures	30

PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	31
Item 6.	Reserved	31
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	32
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	46
Item 8.	Financial Statements and Supplementary Data	48
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	86
Item 9A.	Controls and Procedures	86
Item 9B.	Other Information	88
Item 9C.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	88

PART III
Item 10.	Directors, Executive Officers and Corporate Governance	89
Item 11.	Executive Compensation	89
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	89
Item 13.	Certain Relationships and Related Transactions, and Director Independence	89
Item 14.	Principal Accountant Fees and Services	89

PART IV
Item 15.	Exhibits and Financial Statement Schedules	90


	Year Ended December 31,
MBoe	2022			2021			2020
Proved reserves at beginning of year		1,645,310			1,103,762			1,619,265
Revisions of previous estimates		(133,061	)		53,569			(504,874	)
Extensions, discoveries and other additions		395,490			371,105			91,387
Production		(146,657	)		(120,321	)		(109,833	)
Sales of minerals in place		(144	)		(148	)		—
Purchases of minerals in place		102,826			237,343			7,817
Proved reserves at end of year		1,863,764			1,645,310			1,103,762


	Fourth Quarter 2022 Daily Production
	Crude Oil (Bbls per day)		Natural Gas (Mcf per day)		Total (Boe per day)
Bakken		114,594		358,820		174,397
Anadarko Basin		31,403		802,930		165,225
Powder River Basin		17,740		61,898		28,057
Permian Basin		35,194		58,387		44,925
All other		5,513		234		5,552
Total		204,444		1,282,269		418,156


	Crude Oil Wells				Natural Gas Wells				Total Wells
	Gross		Net		Gross		Net		Gross		Net
Bakken		5,925		2,098		—		—		5,925		2,098
Anadarko Basin		1,287		517		1,003		328		2,290		845
Powder River Basin		553		424		12		9		565		433
Permian Basin		395		356		9		8		404		364
All other		270		252		29		5		299		257
Total		8,430		3,647		1,053		350		9,483		3,997


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


	Fourth Quarter							Year Ended December 31,
Boe production per day	2022		2021		% Change			2022		2021		% Change
Bakken		174,397		175,585		(1	)%		171,025		169,636		1	%
Anadarko Basin		165,225		146,131		13	%		158,221		147,249		7	%
Powder River Basin		28,057		7,189		290	%		24,602		5,161		377	%
Permian Basin (1)		44,925		4,997		-			41,917		1,260		-
All other		5,552		6,266		(11	)%		6,035		6,341		(5	)%
Total		418,156		340,168		23	%		401,800		329,647		22	%


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


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


In millions	1Q 2022		2Q 2022		3Q 2022		4Q 2022		Total 2022
Exploration and development drilling	$	426.2	$	504.7	$	686.0	$	576.6	$	2,193.5
Land costs		24.3		31.2		30.6		55.5		141.6
Mineral acquisitions attributable to Continental		0.5		0.4		1.0		1.0		2.9
Capital facilities, workovers, water infrastructure, and other corporate assets		72.3		110.9		97.4		81.2		361.8
Seismic		0.6		1.3		0.9		0.4		3.2
Capital expenditures attributable to Continental, excluding unbudgeted acquisitions	$	523.9	$	648.5	$	815.9	$	714.7	$	2,703.0
Unbudgeted acquisitions		443.1		219.2		43.1		11.2		716.6
Total capital expenditures attributable to Continental	$	967.0	$	867.7	$	859.0	$	725.9	$	3,419.6
Mineral acquisitions attributable to Franco-Nevada		1.9		1.8		4.2		4.1		12.0
Total capital expenditures	$	968.9	$	869.5	$	863.2	$	730.0	$	3,431.6


	2023				2024				2025
	Gross		Net		Gross		Net		Gross		Net
Bakken		11,207		7,639		14,290		9,363		2,760		1,498
Anadarko Basin		39,321		15,348		33,771		16,314		66,712		45,523
Powder River Basin		3,938		1,712		7,593		3,021		2,701		2,504
Permian Basin		845		639		56,798		47,839		41,781		12,523
All other		57,243		55,212		32,989		15,545		13,489		10,466
Total		112,554		80,550		145,441		92,082		127,443		72,514


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


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


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


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


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


		Hypothetical Fair Value
In thousands	Change in Forward Price	Asset (Liability)
Crude Oil	-10%	$	37,210
Crude Oil	+10%	$	(8,146	)
Natural Gas	-10%	$	(63,363	)
Natural Gas	+10%	$	(323,396	)


Report of Independent Registered Public Accounting Firm	(PCAOB ID Number 248)	49
Consolidated Balance Sheets as of December 31, 2022 and 2021		51
Consolidated Statements of Income (Loss) for the Years Ended December 31, 2022, 2021 and 2020		52
Consolidated Statements of Equity for the Years Ended December 31, 2022, 2021 and 2020		53
Consolidated Statements of Cash Flows for the Years Ended December 31, 2022, 2021 and 2020		54
Notes to Consolidated Financial Statements		55


	December 31,
In thousands, except par values and share data	2022			2021
Assets
Current assets:
Cash and cash equivalents	$	137,788		$	20,868
Receivables:
Crude oil, natural gas, and natural gas liquids sales		1,313,538			1,122,415
Joint interest and other		458,391			278,753
Allowance for credit losses		(5,514	)		(2,814	)
Receivables, net		1,766,415			1,398,354
Derivative assets		39,280			22,334
Inventories		173,264			105,568
Prepaid expenses and other		27,508			17,266
Total current assets		2,144,255			1,564,390
Net property and equipment, based on successful efforts method of accounting		18,471,914			16,975,465
Investment in unconsolidated affiliates		210,805			—
Operating lease right-of-use assets		25,158			16,370
Derivative assets, noncurrent		3,548			13,188
Other noncurrent assets		22,670			21,698
Total assets	$	20,878,350		$	18,591,111
Liabilities and equity
Current liabilities:
Accounts payable trade	$	850,547		$	582,317
Revenues and royalties payable		882,256			627,171
Accrued liabilities and other		343,777			285,740
Current portion of incentive compensation liability		125,653			—
Current portion of income tax liabilities		152,149			—
Derivative liabilities		88,136			899
Current portion of operating lease liabilities		4,086			1,674
Current portion of long-term debt		638,058			2,326
Total current liabilities		3,084,662			1,500,127
Long-term debt, net of current portion		7,571,582			6,826,566
Other noncurrent liabilities:
Deferred income tax liabilities, net		2,538,312			2,139,884
Incentive compensation liability, net of current portion		100,066			—
Asset retirement obligations, net of current portion		257,152			215,701
Derivative liabilities, noncurrent		133,363			318
Operating lease liabilities, net of current portion		20,055			13,800
Other noncurrent liabilities		43,550			38,390
Total other noncurrent liabilities		3,092,498			2,408,093
Commitments and contingencies (Note 13)
Equity:
Preferred stock, $0.01 par value; 25,000,000 shares authorized; no shares issued and outstanding		—			—
Common stock, $0.01 par value; 1,000,000,000 shares authorized;
299,610,267 shares issued and outstanding at December 31, 2022;
364,297,520 shares issued and outstanding at December 31, 2021;		2,996			3,643
Additional paid-in capital		—			1,131,602
Retained earnings		6,754,174			6,340,211
Total shareholders’ equity attributable to Continental Resources		6,757,170			7,475,456
Noncontrolling interests		372,438			380,869
Total equity		7,129,608			7,856,325
Total liabilities and equity	$	20,878,350		$	18,591,111


	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, 2019		371,074,036		$	3,711		$	1,274,732		$	—		$	5,463,224		$	6,741,667		$	366,684		$	7,108,351
Net loss		—			—			—			—			(596,869	)		(596,869	)		(8,692	)		(605,561	)
Cumulative effect adjustment from adoption of ASU 2016-13														(137	)		(137	)					(137	)
Cash dividends declared		—			—			—			—			(18,580	)		(18,580	)		—			(18,580	)
Change in dividends payable		—			—			—			—			8			8			—			8
Common stock repurchased		—			—			—			(126,906	)		—			(126,906	)		—			(126,906	)
Common stock retired		(8,122,104	)		(81	)		(126,825	)		126,906			—			—			—			—
Stock-based compensation		—			—			64,585			—			—			64,585			—			64,585
Restricted stock:
Granted		2,738,625			27			—			—			—			27			—			27
Repurchased and canceled		(306,845	)		(3	)		(7,344	)		—			—			(7,347	)		—			(7,347	)
Forfeited		(163,277	)		(2	)		—			—			—			(2	)		—			(2	)
Contributions from noncontrolling interests		—			—			—			—			—			—			21,557			21,557
Distributions to noncontrolling interests		—			—			—			—			—			—			(13,270	)		(13,270	)
Balance at December 31, 2020		365,220,435		$	3,652		$	1,205,148		$	—		$	4,847,646		$	6,056,446		$	366,279		$	6,422,725
Net income		—			—			—			—			1,660,968			1,660,968			5,440			1,666,408
Cash dividends declared		—			—			—			—			(168,536	)		(168,536	)		—			(168,536	)
Change in dividends payable		—			—			—			—			133			133			—			133
Common stock repurchased		—			—			—			(123,924	)		—			(123,924	)		—			(123,924	)
Common stock retired		(3,198,571	)		(32	)		(123,892	)		123,924			—			—			—			—
Stock-based compensation		—			—			63,145			—			—			63,145			—			63,145
Restricted stock:
Granted		3,050,491			31			—			—			—			31			—			31
Repurchased and canceled		(478,697	)		(5	)		(12,799	)		—						(12,804	)		—			(12,804	)
Forfeited		(296,138	)		(3	)		—			—			—			(3	)		—			(3	)
Contributions from noncontrolling interests		—			—			—			—			—			—			33,086			33,086
Distributions to noncontrolling interests		—			—			—			—			—			—			(23,936	)		(23,936	)
Balance at December 31, 2021		364,297,520		$	3,643		$	1,131,602		$	—		$	6,340,211		$	7,475,456		$	380,869		$	7,856,325
Net income		—			—			—			—			4,024,558			4,024,558			21,562			4,046,120
Cash dividends declared		—			—			—			—			(287,035	)		(287,035	)		—			(287,035	)
Change in dividends payable		—			—			—			—			205			205			—			205
Common stock repurchased prior to take-private transaction		—			—			—			(99,855	)		—			(99,855	)		—			(99,855	)
Common stock retired prior to take-private transaction		(1,842,422	)		(18	)		(99,837	)		99,855			—			—			—			—
Stock-based compensation		—			—			(8,085	)		—			—			(8,085	)		—			(8,085	)
Restricted stock:
Granted		1,575,847			16			—			—			—			16			—			16
Repurchased and canceled		(627,742	)		(7	)		(35,438	)		—						(35,445	)		—			(35,445	)
Forfeited		(384,536	)		(4	)		—			—			—			(4	)		—			(4	)
Restricted stock canceled from take-private transaction (see Note 15)		(5,349,141	)		(53	)											(53	)					(53	)
Take-private transaction (see Note 1)		(58,059,259	)		(581	)		(988,242	)					(3,323,765	)		(4,312,588	)		—			(4,312,588	)
Contributions from noncontrolling interests		—			—			—			—			—			—			12,498			12,498
Distributions to noncontrolling interests		—			—			—			—			—			—			(42,491	)		(42,491	)
Balance at December 31, 2022		299,610,267		$	2,996		$	—		$	—		$	6,754,174		$	6,757,170		$	372,438		$	7,129,608


	Number of shares		Aggregate cost (in thousands)
2020 Share Repurchases		8,122,104	$	126,906
2021 Share Repurchases		3,198,571		123,924
2022 Share Repurchases		1,842,422		99,855
Total		13,163,097	$	350,685


	Amount (in thousands)		Dividend per share
Year Ended December 31, 2020
First quarter	$	18,367	$	0.05
Total	$	18,367
Year Ended December 31, 2021
Second quarter	$	39,735	$	0.11
Third quarter		54,141	$	0.15
Fourth quarter		71,793	$	0.20
Total	$	165,669
Year Ended December 31, 2022
First quarter	$	82,529	$	0.23
Second quarter		100,123	$	0.28
Third quarter		100,131	$	0.28
Total	$	282,783



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

3.2*		Fifth Amended and Restated Bylaws of Continental Resources, Inc.

4.1		Indenture dated as of April 5, 2013 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 Form 10-Q for the quarter ended March 31, 2018 (Commission File No. 001-32886) filed May 2, 2018 and incorporated herein by reference.

4.2		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.

4.3		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.

4.4		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.

4.5		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*†		Form of Indemnification Agreement between Continental Resources, Inc. and each of the directors, executive officers and advisory board members.

10.2		Revolving Credit Agreement dated October 29, 2021 among Continental Resources, Inc., as borrower, and its subsidiaries Banner Pipeline Company L.L.C., CLR Asset Holdings, LLC and The Mineral Resources Company as guarantors, MUFG Union Bank, N.A., as Administrative Agent, MUFG Union Bank, N.A., BofA Securities, Inc., Mizuho Bank, Ltd., TD Securities (USA) LLC, U.S. Bank National Association, Royal Bank of Canada, Wells Fargo Securities, LLC, and Truist Securities, Inc. as Joint Lead Arrangers and Joint Bookrunners, and the other lenders named therein filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K (Commission File No. 001-32886) filed November 3, 2021 and incorporated herein by reference.



10.3		Amendment No. 1 and Agreement dated August 24, 2022 among Continental Resources, Inc., as borrower, and its subsidiaries 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, MUFG Bank, Ltd. (as successor to MUFG Union Bank, N.A.), as Administrative Agent, the lenders party thereto and the Issuing Banks, filed as Exhibit (d)(16) to the Schedule TO (Commission File No. 005-82887) filed October 24, 2022 and incorporated herein by reference.

10.4		Term Loan Agreement, dated as of November 10, 2022, by and among Continental Resources, Inc., as borrower, and MUFG Bank, LTD., as administrative agent, and the banks and other financial institutions party thereto as lenders filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K (Commission File No. 001-32886) filed November 10, 2022 and incorporated herein by reference.

10.5		Amendment No. 2 to Revolving Credit Agreement, dated as of November 10, 2022, 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 10.2 to the Company’s Current Report on Form 8-K (Commission File No. 001-32886) filed November 10, 2022 and incorporated herein by reference.

10.6†		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.

10.7†		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.

10.8†		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.

10.9*†		Third Amended and Restated Continental Resources, Inc 2013 Long-Term Incentive Plan.

10.10*†		Continental Resources, Inc. Second Amended and Restated 2022 Long-Term Incentive Plan.

10.11*†		Replacement Restricted Stock Unit Agreement – Employee Agreement for Continental Resources, Inc. 2013 Long-Term Incentive Plan and 2022 Long-Term Incentive Plan.

10.12*†		Cash Award Agreement – Continental Resources, Inc. Second Amended and Restated 2022 Long-Term Incentive Plan.

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)

32**		Certification of the Company’s Chief Executive Officer and Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350)

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 Document

101.CAL*		Inline XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF*		Inline XBRL Taxonomy Extension Definition Linkbase Document

101.LAB*		Inline XBRL Taxonomy Extension Label Linkbase Document

101.PRE*		Inline XBRL Taxonomy Extension Presentation Linkbase Document

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


CONTINENTAL RESOURCES, INC.

By:		/S/ DOUG LAWLER
Name:		Doug Lawler
Title:		President and Chief Executive Officer
Date:		February 22, 2023


Signature	Title	Date

/s/ HAROLD G. HAMM	Executive Chairman and Director	February 22, 2023
Harold G. Hamm

/s/ DOUG LAWLER	President, Chief Executive Officer, and Director (principal executive officer)	February 22, 2023
Doug Lawler

/s/ SHELLY LAMBERTZ	Executive Vice President, Chief Culture and Administrative Officer and Director	February 22, 2023
Shelly Lambertz

/s/ JOHN D. HART	Chief Financial Officer and Executive Vice President of Strategic Planning (principal financial and accounting officer)	February 22, 2023
John D. Hart