CONTINENTAL RESOURCES, INC - Annual Report: 2022 (Form 10-K)

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

_______________________________

FORM 10-K

(Mark One)

or

Commission File Number: 001-32886

_______________________________

CONTINENTAL RESOURCES, INC.

(Exact name of registrant as specified in its charter)

_______________________________

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

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

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

_______________________________

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

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

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

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

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

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

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

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

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers 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.

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Glossary of Crude Oil and Natural Gas Terms

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

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

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

“Bcf” One billion cubic feet of natural gas.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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“MBoe” One thousand Boe.

“Mcf” One thousand cubic feet of natural gas.

“MMBo” One million barrels of crude oil.

“MMBoe” One million Boe.

“MMBtu” One million British thermal units.

“MMcf” One million cubic feet of natural gas.

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

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

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

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

“NYMEX” The New York Mercantile Exchange.

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

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

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

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

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

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

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

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

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measure 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.

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

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

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

Forward-looking statements are based on the Company’s current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes these assumptions and expectations are reasonable, they are inherently subject to numerous business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company’s control. No assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate or will not change over time. The risks and

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uncertainties that may affect the operations, performance and results of the business and forward-looking statements include, but are not limited to, those risk factors and other cautionary statements described under Part I, Item 1A. Risk Factors and elsewhere in this report and other disclosures or announcements we make from time to time.

Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date on which such statement is made. Additionally, new factors emerge from time to time, and it is not possible for us to predict all such factors. Should one or more of the risks or uncertainties described in this report occur, or should underlying assumptions prove incorrect, the Company's actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by this cautionary statement.

Except as expressly stated above or otherwise required by applicable law, the Company undertakes no obligation to publicly correct or update any forward-looking statement whether as a result of new information, future events or circumstances after the date of this report, or otherwise.

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Part I

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

Item 1. Business

Take-private transaction

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

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

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

Nature of business

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

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

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.

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

Our Business Strategies

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

Our Business Strengths

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

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

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

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

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

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

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

Crude Oil and Natural Gas Operations

Proved Reserves

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

The table below sets forth estimated proved crude oil and natural gas reserves information by reserve category as of December 31, 2022. 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.

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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.

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Proved Undeveloped Reserves

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.

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Qualifications of Technical Persons and Internal Controls Over Reserves Estimation Process

Ryder Scott, our independent reserves evaluation consulting firm, estimated, in accordance with generally accepted petroleum engineering and evaluation principles and definitions and guidelines established by the SEC, 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.

Developed and Undeveloped Acreage

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.

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Drilling Activity

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.

Summary of Crude Oil and Natural Gas Properties and Projects

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

Bakken Field

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.

Anadarko Basin

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.

Powder River Basin

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.

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

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

Permian Basin

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.

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Production and Price History

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

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

Productive Wells

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