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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
_______________________________ 
FORM 10-K
_______________________________ 
(Mark One)
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2021
or
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from              to             
Commission File Number: 001-32886
_______________________________ 
clr-20211231_g1.jpg
CONTINENTAL RESOURCES, INC.
(Exact name of registrant as specified in its charter)
_______________________________ 
Oklahoma 73-0767549
(State or other jurisdiction of incorporation or organization) (I.R.S. Employer Identification No.)
20 N. Broadway,Oklahoma City,Oklahoma73102
(Address of principal executive offices)(Zip Code)
Registrant’s telephone number, including area code: (405) 234-9000
Securities registered pursuant to Section 12(b) of the Act:
Title of each class Trading symbol(s)Name of each exchange on which registered
Common Stock, $0.01 par valueCLRNew York Stock Exchange
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  x    No  ¨
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  ¨    No  x
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  x    No  ¨
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.
Large accelerated filer x  Accelerated filer 
Non-accelerated filer   Smaller reporting company 
Emerging growth company
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨
Indicate by check mark whether the registrant 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.
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, 2021 was approximately $2.5 billion, based upon the closing price of $38.03 per share as reported by the New York Stock Exchange on such date.
364,298,349 shares of our $0.01 par value common stock were outstanding on January 31, 2022.

DOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive Proxy Statement of Continental Resources, Inc. for the Annual Meeting of Shareholders to be held in May 2022, which will be filed with the Securities and Exchange Commission within 120 days after the end of the fiscal year, are incorporated by reference into Part III of this Form 10-K.



Table of Contents 
PART I
Item 1.
Item 1A.
Item 1B.
Item 2.
Item 3.
Item 4.
PART II
Item 5.
Item 6.
Item 7.
Item 7A.
Item 8.
Item 9.
Item 9A.
Item 9B.
Item 9C.
PART III
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
PART IV
Item 15.



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.
“MBoe” One thousand Boe.
“Mcf” One thousand cubic feet of natural gas.
i


“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 and natural gas sales less total transportation expenses. Net crude oil and natural gas 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 its crude oil or natural gas sales after deducting transportation expenses. Net sales price is calculated by taking revenues less transportation expenses divided by sales volumes for a period, whether for crude oil or natural gas, as applicable. 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.
“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 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.
ii


“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.
iii


Cautionary Statement for the Purpose of the “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995
This report and information incorporated by reference in this report include “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than statements of historical fact, including, but not limited to, forecasts or expectations regarding the Company’s business and statements or information concerning the Company’s future operations, performance, financial condition, production and reserves, schedules, plans, timing of development, rates of return, budgets, costs, business strategy, objectives, and cash flows, included in this report are forward-looking statements. The words “could,” “may,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project,” “budget,” “target,” “plan,” “continue,” “potential,” “guidance,” “strategy” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.
Forward-looking statements may include, but are not limited to, statements about:
our strategy;
our business and financial plans;
our future operations;
our crude oil and natural gas reserves and related development plans;
technology;
future crude oil, natural gas liquids, and natural gas prices and differentials;
the timing and amount of future production of crude oil and natural gas and flaring activities;
the amount, nature and timing of capital expenditures;
estimated revenues, expenses and results of operations;
drilling and completing of wells;
shutting in of production and the resumption of production activities;
competition;
marketing of crude oil and natural gas;
transportation of crude oil, natural gas liquids, and natural gas to markets;
property exploitation, property acquisitions and dispositions, or joint development opportunities;
costs of exploiting and developing our properties and conducting other operations;
our financial position, dividend payments, bond repurchases, share repurchases, or income tax payments;
the impact of the COVID-19 (novel coronavirus) pandemic on economic conditions, the demand for crude oil, the Company's operations and the operations of its customers, suppliers, and service providers;
credit markets;
our liquidity and access to capital;
the impact of governmental policies, laws and regulations, as well as regulatory and legal proceedings involving us and of scheduled or potential regulatory or legal changes;
our future operating and financial results;
our future commodity or other hedging arrangements; and
the ability and willingness of current or potential lenders, hedging contract counterparties, customers, and working interest owners to fulfill their obligations to us or to enter into transactions with us in the future on terms that are acceptable to us.
Forward-looking statements are based on the Company’s current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes these assumptions and expectations are reasonable, they are inherently subject to numerous business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company’s control. No assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate or will not change over time. The risks and uncertainties that may affect the operations, performance and results of the business and forward-looking statements include, but are not limited to, those risk factors and other cautionary statements described under Part I, Item 1A. Risk Factors and elsewhere in this report, registration statements we file from time to time with the Securities and Exchange Commission, and other announcements we make from time to time.
Many of the foregoing risks and uncertainties have been, and may further be, exacerbated by the COVID-19 pandemic and any potential worsening of the global economic environment. New factors emerge from time to time, and it is not possible for us to predict all such factors. 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. 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
iv


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.
v


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
General
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 in the North, South and East regions of the United States. Additionally, we pursue the acquisition and management of perpetually owned minerals located in our key operating areas.
During 2021 we executed strategic acquisitions to expand our operations into the Permian Basin of Texas and the Powder River Basin of Wyoming. See the subsequent section titled Acquisition Activities as well as Part II, Item 8. Notes to Consolidated Financial Statements—Note 2. Property Acquisitions and Dispositions for additional information on these acquisitions.
Our North region consists of properties north of Kansas and west of the Mississippi River and includes North Dakota Bakken, Montana Bakken, Powder River Basin, and the Red River units. Our South region includes all properties south of Nebraska and west of the Mississippi River and includes the SCOOP and STACK areas of Oklahoma and the Permian Basin of Texas. Our East region is primarily comprised of undeveloped leasehold acreage east of the Mississippi River with no significant drilling or production operations.
Our operations in the North region comprised 55% of our crude oil and natural gas production and 63% of our crude oil and natural gas revenues for the year ended December 31, 2021. Approximately 46% of our proved reserves as of December 31, 2021 are located in the North region. Our operations in the South region comprised 45% of our crude oil and natural gas production, 37% of our crude oil and natural gas revenues, and 54% of our proved reserves as of and for the year ended December 31, 2021.
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. We also grew in 2021 through the strategic acquisitions described below under Part I, Item 1. Business—Acquisition Activities. From January 1, 2019 through December 31, 2021, proved reserves added through extensions, discoveries and other additions totaled 828 MMBoe and proved reserves added through property acquisitions totaled 252 MMBoe.
As of December 31, 2021, our proved reserves were 1,645 MMBoe, with proved developed reserves representing 908 MMBoe, or 55%, of our total proved reserves. The standardized measure of our discounted future net cash flows totaled $16.64 billion at December 31, 2021. For 2021, we generated crude oil and natural gas revenues of $5.79 billion and operating cash flows of $3.97 billion. Crude oil accounted for 49% of our total production and 68% of our crude oil and natural gas revenues for 2021. Our total production averaged 329,647 Boe per day for 2021, an increase of 10% compared to 2020.
The table below summarizes our total proved reserves, PV-10 (non-GAAP) and net producing wells as of December 31, 2021 and our average daily production for the quarter ended December 31, 2021 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. 
1


 December 31, 2021Average daily
production for
fourth quarter
2021
(Boe per day)
 
 Proved
reserves
(MBoe)
Percent
of total
PV-10 (1)
(In millions)
Net
producing
wells
Percent
of total
North Region:
Bakken708,369 43.2 %$9,659 1,997 175,585 51.6 %
Powder River Basin31,901 1.9 %$464 148 7,189 2.1 %
Red River Units23,354 1.4 %$396 251 6,212 1.8 %
South Region:
Oklahoma678,535 41.2 %$7,027 825 146,131 43.0 %
Permian Basin (2)203,103 12.3 %$2,946 319 4,997 1.5 %
Other48 — %$54 — %
Total1,645,310 100.0 %$20,493 3,544 340,168 100.0 %
 
(1)PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues of approximately $3.86 billion. Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of our crude oil and natural gas properties. We and others in the crude oil and natural gas industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific income tax characteristics of such entities. See Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Financial Measures for further discussion.
(2)The presentation of average daily 2021 fourth quarter production represents production during the period from the closing of our acquisition of Permian properties on December 21, 2021 through December 31, 2021 averaged over 92 days in the fourth quarter. At the time of closing, our Permian properties produced on average approximately 42,000 Boe per day based on two-stream reporting.
Our Business Strategies
Our business strategies continue to be focused on generating significant shareholder value by finding and developing crude oil and natural gas reserves at low costs and attractive rates of return. For 2022, our primary business strategies will include:
Continuing to exercise capital and operational discipline to maximize cash flow generation and competitive returns on capital employed;
Reducing outstanding debt and maintaining a strong balance sheet to enhance financial flexibility;
Maintaining strong shareholder alignment by maximizing capital and corporate returns to shareholders;
Developing our recently acquired properties in the Permian Basin and Powder River Basin by applying our geologic and operational expertise;
Maintaining low-cost, capital efficient operations; and
Driving continued improvement in our health, safety, and environmental performance and governance programs.
Our Business Strengths
We have a number of strengths to allow us to successfully execute our business strategies, including the following:
Large acreage inventory with access to both crude oil and natural gas resources. We held approximately 538,400 net undeveloped acres and 1.40 million net developed acres under lease as of December 31, 2021 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.
2


Control operations over a substantial portion of our assets and investments. As of December 31, 2021, we operated properties comprising 89% 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. Our strategies for growing our mineral ownership portfolio and water infrastructure assets serve as additional avenues to generate shareholder value.
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 Chairman of the Board, Harold G. Hamm, began his career in the oil and gas industry in 1967. Our 9 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 $2.0 billion that matures in October 2026. We had approximately $1.76 billion of borrowing availability on our credit facility at January 31, 2022 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.
Acquisition Activities
We regularly seek to acquire oil and gas properties that complement our operations, provide exploration and development opportunities, and provide enhanced cash flows and corporate returns. On December 21, 2021, we acquired oil and gas properties and related assets in the Permian Basin of Texas from certain subsidiaries of Pioneer Natural Resources Company for $3.06 billion of cash, representing a $3.25 billion purchase price less customary closing adjustments. The properties included approximately 92,000 net leasehold acres, approximately 50,000 net royalty acres in the same area normalized to a 1/8th royalty, production totaling approximately 42,000 Boe per day (~78% oil) based on two-stream reporting at the time of closing, and extensive water infrastructure. We funded the purchase price and related transaction costs through a combination of cash on hand, utilization of credit facility borrowing capacity, and the issuance of senior notes.
Additionally, in March 2021 and November 2021 we executed strategic acquisitions to expand our operations into the Powder River Basin of Wyoming for aggregate cash consideration of $453 million and, on January 24, 2022, we executed a definitive agreement to acquire additional oil and gas properties in the Powder River Basin for $450 million of cash, the closing of which is expected to occur in late March 2022 and remains subject to the completion of customary due diligence procedures and closing conditions. See Part II, Item 8. Notes to Consolidated Financial Statements—Note 2. Property Acquisitions and Dispositions and Note 20. Subsequent Events for additional information on the above acquisitions.
As a result of our acquisitions in the Permian Basin and Powder River Basin we now have substantial strategic positions in four leading basins in the United States, providing our Company and shareholders with enhanced geologic and geographic diversity and commodity optionality. We believe these transactions will be accretive on financial metrics and will complement our existing deep portfolio of assets in the Bakken and Oklahoma. We expect enhanced cash flows from the acquisitions will provide continued support for additional returns to shareholders via debt reduction, dividend increases, share repurchases, and increased returns on capital employed.
Information on the proved reserves and leasehold acreage associated with our new positions in the Permian Basin and Powder River Basin as of December 31, 2021 is presented in the tables that follow.





3



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, 2021. 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 $16.64 billion at December 31, 2021. Our reserve estimates as of December 31, 2021 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, 2021. 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, 2021 were determined using the 12-month unweighted arithmetic average of the first-day-of-the-month commodity prices for the period of January 2021 through December 2021, without giving effect to derivative transactions, and were held constant throughout the lives of the properties. These prices were $66.56 per Bbl for crude oil and $3.60 per MMBtu for natural gas ($62.19 per Bbl for crude oil and $3.46 per Mcf for natural gas adjusted for location and quality differentials). These average prices are significantly higher than 2020 levels, which resulted in significant upward price-related revisions to proved reserves in 2021, as further discussed below.
The following table summarizes our estimated proved reserves by commodity and reserve classification as of December 31, 2021.
Crude Oil
(MBbls)
Natural Gas
(MMcf)
Total
(MBoe)
PV-10 (1)
(in millions)
Proved developed producing415,861 2,853,980 891,524 $13,256.4 
Proved developed non-producing8,292 47,167 16,154 230.5 
Proved undeveloped369,377 2,209,532 737,632 7,006.0 
Total proved reserves793,530 5,110,679 1,645,310 $20,492.9 
Standardized Measure (1)$16,636.4 
 
(1)PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues of approximately $3.86 billion. See Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Financial Measures for further discussion.
4


The following table provides additional information regarding our estimated proved crude oil and natural gas reserves by region as of December 31, 2021. 
 Proved DevelopedProved Undeveloped
 Crude Oil
(MBbls)
Natural Gas
(MMcf)
Total
(MBoe)
Crude Oil
(MBbls)
Natural Gas
(MMcf)
Total
(MBoe)
North Region:
Bakken222,986 856,607 365,754 241,364 607,509 342,615 
Powder River Basin12,080 22,661 15,857 12,585 20,758 16,044 
Red River Units23,354 — 23,354 — — — 
South Region:
Oklahoma81,586 1,826,973 386,081 50,614 1,451,038 292,454 
Permian Basin84,122 194,769 116,584 64,814 130,227 86,519 
Other25 137 48 — — — 
Total424,153 2,901,147 907,678 369,377 2,209,532 737,632 
The following table provides information regarding changes in total estimated proved reserves for the periods presented.  
 Year Ended December 31,
MBoe202120202019
Proved reserves at beginning of year1,103,762 1,619,265 1,522,365 
Revisions of previous estimates53,569 (504,874)(148,848)
Extensions, discoveries and other additions371,105 91,387 365,034 
Production(120,321)(109,833)(124,244)
Sales of minerals in place(148)— (1,840)
Purchases of minerals in place237,343 7,817 6,798 
Proved reserves at end of year1,645,310 1,103,762 1,619,265 
Revisions of previous estimates. 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, and (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.
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. Proved reserve additions in the Bakken totaled 202 MMBoe, 41 MMBoe, and 160 MMBoe for 2021, 2020, and 2019, respectively, while reserve additions in Oklahoma totaled 169 MMBoe, 50 MMBoe, and 205 MMBoe for 2021, 2020, and 2019, respectively. See the subsequent section titled Summary of Crude Oil and Natural Gas Properties and Projects for a discussion of our 2021 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 2021 were primarily attributable to our acquisitions of properties in the Permian Basin and Powder River Basin described above. Proved reserves acquired in the Permian Basin totaled 149 MMBo and 326 Bcf (totaling 203 MMBoe) and proved reserves acquired in the Powder River Basin totaled 26 MMBo and 46 Bcf (totaling 34 MMBoe). We had no individually significant acquisitions of proved reserves in 2020 and 2019.
5


Proved Undeveloped Reserves
All of our PUD reserves at December 31, 2021 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, 2021. Our PUD reserves at December 31, 2021 include 68 MMBoe of reserves associated with wells where drilling has occurred but the wells have not been completed or are completed but not producing ("DUC wells"). Our DUC wells are classified as PUD reserves when relatively major expenditures are required to complete and produce from the wells.
 Crude Oil
(MBbls)
Natural Gas
(MMcf)
Total
(MBoe)
Proved undeveloped reserves at December 31, 2020215,069 1,567,713 476,355 
Revisions of previous estimates(45,340)(329,237)(100,214)
Extensions, discoveries and other additions157,384 1,183,484 354,631 
Sales of minerals in place— — — 
Purchases of minerals in place77,399 150,985 102,563 
Conversion to proved developed reserves(35,135)(363,413)(95,703)
Proved undeveloped reserves at December 31, 2021369,377 2,209,532 737,632 
Revisions of previous estimates. As previously discussed, in 2021 we removed 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. Of these removals, 25 MMBo and 53 Bcf (totaling 34 MMBoe) was related to Bakken properties and 6 MMBo and 102 Bcf (totaling 23 MMBoe) was related to Oklahoma properties. Additionally, changes in anticipated well densities, economics, performance, and other factors resulted in downward PUD reserve revisions of 12 MMBo and 263 Bcf (totaling 56 MMBoe) in 2021. The significant increases in average crude oil and natural gas prices in 2021 resulted in upward price revisions of 15 MMBo and 73 Bcf (totaling 27 MMBoe). Finally, changes in ownership interests, operating costs, anticipated production, and other factors resulted in downward revisions for oil PUD reserves of 17 MMBo and net upward revisions for natural gas PUD reserves of 16 Bcf (totaling a net downward revision of 15 MMBoe) in 2021.
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. PUD reserve additions in the Bakken totaled 133 MMBo and 359 Bcf (totaling 193 MMBoe) in 2021, while PUD reserve additions in Oklahoma totaled 24 MMBo and 824 Bcf (totaling 161 MMBoe).
Sales of minerals in place. We had no individually significant dispositions of PUD reserves in 2021.
Purchases of minerals in place. Purchases in 2021 were primarily attributable to our acquisitions of properties in the Permian Basin and Powder River Basin described above. PUD reserves acquired in the Permian Basin totaled 65 MMBo and 130 Bcf (totaling 87 MMBoe) and PUD reserves acquired in the Powder River Basin totaled 12 MMBo and 21 Bcf (totaling 16 MMBoe).
Conversion to proved developed reserves. In 2021, we developed approximately 24% of our PUD locations and 20% of our PUD reserves booked as of December 31, 2020 through the drilling and completion of 269 gross (137 net) development wells at an aggregate capital cost of approximately $508 million incurred in 2021.
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 259 gross (83 net) operated and non-operated locations at December 31, 2021 and represent 9% of our PUD reserves at that date. The costs to drill our uncompleted wells were incurred prior to December 31, 2021 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, 2021 are projected to be approximately $1.2 billion in 2022, $1.9 billion in 2023, $1.7 billion in 2024, $1.7 billion in 2025, and $1.2 billion in 2026. 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, 2021 is expected
6


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, 2021. We had no PUD reserves at December 31, 2021 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, 2021 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 our Audit Committee with representatives of Ryder Scott and by our internal technical staff 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 Vice President—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 37 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 Vice President—Corporate Reserves reports directly to our Vice Chairman of Strategic Growth Initiatives. The reserves estimates are reviewed and approved by certain members of the Company's executive management.
Proved Reserves, Standardized Measure, and PV-10 Sensitivities
Our year-end 2021 proved reserves, Standardized Measure, and PV-10 estimates were prepared using 2021 average first-day-of-the-month prices of $66.56 per Bbl for crude oil and $3.60 per MMBtu for natural gas ($62.19 per Bbl for crude oil and $3.46 per Mcf for natural gas adjusted for location and quality differentials). Actual future prices may be materially higher or lower than those used in our year-end estimates.
Provided below are sensitivities illustrating the potential impact on our estimated proved reserves, Standardized Measure, and PV-10 at December 31, 2021 under different commodity price scenarios for crude oil and natural gas. In these sensitivities, all factors other than the commodity price assumption have been held constant for each well. These sensitivities do not take into account a potential increase in our drilling activities and associated booking of additional proved reserves that may occur at higher commodity prices and there is no assurance the outcomes reflected below will be realized.

The crude oil price sensitivities provided below show the impact on proved reserves, Standardized Measure, and PV-10 under certain crude oil price scenarios, with natural gas prices being held constant at the 2021 average first-day-of-the-month price of $3.60 per MMBtu.
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clr-20211231_g2.jpg
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The natural gas price sensitivities provided below show the impact on proved reserves, Standardized Measure, and PV-10 under certain natural gas price scenarios, with crude oil prices being held constant at the 2021 average first-day-of-the-month price of $66.56 per Bbl.
clr-20211231_g3.jpg
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Developed and Undeveloped Acreage
The following table presents our total gross and net developed and undeveloped acres by region as of December 31, 2021: 
 Developed acresUndeveloped acresTotal
 GrossNetGrossNetGrossNet
North Region:
Bakken1,125,023 702,709 116,922 69,175 1,241,945 771,884 
Powder River Basin111,197 76,750 189,180 140,835 300,377 217,585 
Red River Units154,643 139,363 19,891 10,186 174,534 149,549 
Other80,287 54,113 29,040 25,654 109,327 79,767 
South Region:
Oklahoma581,811 341,056 219,872 107,231 801,683 448,287 
Permian Basin80,605 80,605 76,015 65,756 156,620 146,361 
Other20,916 9,364 90,425 72,763 111,341 82,127 
East Region734 661 52,929 46,815 53,663 47,476 
Total2,155,216 1,404,621 794,274 538,415 2,949,490 1,943,036 
The following table sets forth the number of gross and net undeveloped acres as of December 31, 2021 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. 
 202220232024
 GrossNetGrossNetGrossNet
North Region:
Bakken47,272 29,243 9,779 7,639 10,467 6,986 
Powder River Basin10,893 10,142 3,044 1,703 2,268 1,695 
Other— — 17,847 17,847 — — 
South Region:
Oklahoma54,083 29,789 35,837 16,704 26,109 13,426 
Permian Basin— — — — 26,347 16,285 
Other14,660 11,031 13,436 13,086 37,399 9,985 
East Region4,856 3,732 5,968 5,272 3,052 2,717 
Total131,764 83,937 85,911 62,251 105,642 51,094 
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Drilling Activity
During the three years ended December 31, 2021, we participated in the drilling and completion of exploratory and development wells as set forth in the table below.
 202120202019
 GrossNetGrossNetGrossNet
Exploratory wells:
Crude oil11 8.0 — 1.6 
Natural gas1.9 — 1.8 
Dry holes— — 0.9 — — 
Total exploratory wells13 9.9 0.9 3.4 
Development wells:
Crude oil376 144.6 300 115.5 615 222.9 
Natural gas38 20.3 31 15.9 68 9.7 
Dry holes— — — — — — 
Total development wells414 164.9 331 131.4 683 232.6 
Total wells427 174.8 334 132.3 689 236.0 
As of December 31, 2021, there were 393 gross (153 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
In the following discussion, we review our budgeted number of wells and capital expenditures for 2022 in our key operating areas. Our 2022 capital budget, based on our current expectations of commodity prices and costs, is expected to be funded from operating cash flows. 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, the availability of drilling and completion rigs and other services and equipment, the availability of transportation 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 scale back our spending should commodity prices materially decrease from current levels.
The following table provides information regarding well counts and budgeted capital expenditures for 2022.
 2022 Plan
 Gross wells (1)Net wells (1)Capital expenditures 
(in millions) (2)
 
Bakken264 116 $800 
Powder River Basin34 20 200 
Oklahoma117 41 400 
Permian Basin49 46 400 
Total exploration and development464 223 $1,800 
Land127 
Mineral acquisitions attributable to Continental (3)23 
Capital facilities, workovers, water infrastructure, and other344 
Seismic
2022 capital budget attributable to Continental$2,300 
Mineral acquisitions attributable to Franco-Nevada (3)91 
Total 2022 capital budget (4)$2,391 
(1) Represents operated and non-operated wells expected to have first production in 2022.
(2) Represents total capital expenditures for operated and non-operated wells expected to have first production in 2022 and wells spud that will be in the process of drilling, completing or waiting on completion as of year-end 2022.
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(3)    Represents planned spending for mineral acquisitions by The Mineral Resources Company II, LLC ("TMRC II") under our relationship with Franco-Nevada Corporation described in Part II, Item 8. Notes to Consolidated Financial Statements—Note 17. Noncontrolling Interests. Continental holds a controlling financial interest in TMRC II and therefore consolidates the financial results and capital expenditures of the entity. With a carry structure in place, Continental will fund 20% of 2022 planned spending, or $23 million, and Franco-Nevada will fund the remaining 80%, or $91 million.
(4)    Amount excludes the $450 million purchase price for our pending acquisition of properties in the Powder River Basin as discussed in Part II, Item 8. Notes to Consolidated Financial Statements—Note 20. Subsequent Events.
North Region
Our properties in the North region represented 46% of our total proved reserves as of December 31, 2021 and 55% of our average daily Boe production for the fourth quarter of 2021. Our principal producing properties in the North region are located in the Bakken field of North Dakota and Montana and our recently acquired properties in the Powder River Basin of Wyoming.
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 a leading producer, leasehold owner and operator in the Bakken. As of December 31, 2021, we controlled one of the largest leasehold positions in the Bakken with approximately 1.2 million gross (771,900 net) acres under lease.
Our total Bakken production averaged 175,585 Boe per day for the fourth quarter of 2021, down 4% from the 2020 fourth quarter. For the year ended December 31, 2021, our average daily Bakken production increased 7% compared to 2020, reflecting the impact of voluntary production curtailments in 2020 and additional drilling and completion activities in 2021. In 2021, we participated in the drilling and completion of 252 gross (102 net) wells in the Bakken compared to 188 gross (77 net) wells in 2020. Our 2021 activities in the Bakken focused on ongoing multi-zone unit development in core areas of the play.
Our Bakken properties represented 43% of our total proved reserves at December 31, 2021 and 52% of our average daily Boe production for the 2021 fourth quarter. Our total proved Bakken field reserves as of December 31, 2021 were 708 MMBoe, an increase of 39% compared to December 31, 2020 primarily due to reserves added from our drilling program and upward reserve revisions prompted by improved commodity prices. Our inventory of proved undeveloped drilling locations in the Bakken totaled 1,254 gross (701 net) wells as of December 31, 2021.
For 2022, our budget for exploration and development capital expenditures in the Bakken is $800 million. In 2022, we plan to average approximately six operated rigs and two well completion crews in the Bakken and expect to have first production on 264 gross (116 net) operated and non-operated wells during the year. Our 2022 drilling and completion activities in the Bakken will continue to focus on multi-zone unit development in areas that provide opportunities to improve capital efficiency, reduce finding and development costs, improve recoveries and rates of return, and maximize cash flows.
Powder River Basin
Our production in the Powder River Basin averaged 7,189 Boe per day for the fourth quarter of 2021. During 2021, we participated in the drilling and completion of 10 gross (8 net) wells in the play. Our Powder River properties represented 2% of our total proved reserves at December 31, 2021 and 2% of our average daily Boe production for the 2021 fourth quarter. Our proved reserves in the play totaled 32 MMBoe as of December 31, 2021 and our inventory of proved undeveloped drilling locations totaled 55 gross (34 net) wells.
For 2022, our budget for exploration and development capital expenditures in the Powder River Basin is $200 million. In 2022, we plan to average approximately two operated rigs and one well completion crew in the play and expect to have first production on 34 gross (20 net) operated and non-operated wells during the year.
South Region
Our properties in the South region represented 54% of our total proved reserves as of December 31, 2021 and 45% of our average daily Boe production for the fourth quarter of 2021. Our principal producing properties in the South region are located in the SCOOP and STACK areas of Oklahoma and our recently acquired properties in the Permian Basin of Texas.
Oklahoma
We are a leading producer, leasehold owner and operator in Oklahoma. As of December 31, 2021, we controlled one of the largest leasehold positions in Oklahoma with approximately 801,700 gross (448,300 net) acres under lease.
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Our properties in Oklahoma represented 41% of our total proved reserves as of December 31, 2021 and 43% of our average daily Boe production for the fourth quarter of 2021. Production in Oklahoma averaged 146,131 Boe per day during the fourth quarter of 2021, down 2% compared to the 2020 fourth quarter. For the year ended December 31, 2021, average daily production in Oklahoma increased 9% compared to 2020, reflecting the impact of voluntary production curtailments in 2020 and additional drilling and completion activities in 2021. We participated in the drilling and completion of 161 gross (63 net) wells in Oklahoma during 2021 compared to 145 gross (54 net) wells in 2020. Our proved reserves in Oklahoma as of December 31, 2021 totaled 679 MMBoe, an increase of 18% compared to December 31, 2020 primarily due to reserves added from our drilling program and upward reserve revisions prompted by improved commodity prices. Our inventory of proved undeveloped drilling locations in Oklahoma totaled 313 gross (170 net) wells as of December 31, 2021.
For 2022, our aggregate budget for exploration and development capital expenditures in Oklahoma is $400 million. In 2022, we plan to average approximately seven operated rigs and two well completion crews in Oklahoma and expect to have first production on 117 gross (41 net) operated and non-operated wells during the year. Our 2022 activities will focus on continued development in areas that provide opportunities to improve capital efficiency, reduce finding and development costs, improve recoveries and rates of return, and maximize cash flows.
Permian Basin
Proved reserves associated with our Permian Basin properties acquired in late 2021 totaled 203 MMBoe, representing 12% of our total proved reserves as of December 31, 2021. Production from our Permian properties averaged approximately 42,000 Boe per day based on two-stream reporting during our short duration of ownership from December 21, 2021 to December 31, 2021.
For 2022, our budget for exploration and development capital expenditures in the Permian Basin is $400 million. In 2022, we plan to average approximately four operated rigs and one well completion crew in the play and expect to have first production on 49 gross (46 net) operated and non-operated wells during the year.
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Production and Price History
The following table sets forth information concerning our production results, average sales prices and production costs for the years ended December 31, 2021, 2020 and 2019 in total and for each field containing 15 percent or more of our total proved reserves as of December 31, 2021.  
 Year ended December 31,
 202120202019
Net production volumes:
Crude oil (MBbls)
North Dakota Bakken40,121 40,052 52,420 
SCOOP 11,318 12,585 11,679 
Total Company58,636 58,745 72,267 
Natural gas (MMcf)
North Dakota Bakken120,517 97,532 98,186 
SCOOP 179,553 136,410 111,436 
Total Company370,110 306,528 311,865 
Crude oil equivalents (MBoe)
North Dakota Bakken60,207 56,308 68,784 
SCOOP 41,244 35,320 30,252 
Total Company120,321 109,833 124,244 
Average net sales prices (1):
Crude oil ($/Bbl)
North Dakota Bakken$63.24 $33.53 $50.96 
SCOOP 66.46 37.88 54.92 
Total Company64.06 34.71 51.82 
Natural gas ($/Mcf)
North Dakota Bakken$4.52 $0.23 $1.28 
SCOOP 5.33 1.64 2.36 
Total Company4.88 1.04 1.77 
Crude oil equivalents ($/Boe)
North Dakota Bakken$51.21 $24.24 $40.66 
SCOOP 41.44 19.90 29.80 
Total Company46.24 21.47 34.56 
Average costs per Boe:
Production expenses ($/Boe)
North Dakota Bakken$4.27 $4.35 $4.28 
SCOOP 1.24 1.06 1.21 
Total Company3.38 3.27 3.58 
Production taxes ($/Boe)$3.36 $1.75 $2.88 
General and administrative expenses ($/Boe)$1.94 $1.79 $1.57 
DD&A expense ($/Boe)$15.76 $17.12 $16.25 
(1)     See Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Financial Measures for a discussion and calculation of net sales prices, which are non-GAAP measures.
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The following table sets forth information regarding our average daily production by region for the fourth quarter of 2021: 
 Fourth Quarter 2021 Daily Production
 Crude Oil
(Bbls per day)
Natural Gas
(Mcf per day)
Total
(Boe per day)
North Region:
Bakken116,548 354,222 175,585 
Powder River Basin5,704 8,912 7,189 
Red River Units6,212 — 6,212 
South Region:
Oklahoma34,314 670,904 146,131 
Permian Basin (1)3,885 6,671 4,997 
Other31 133 54 
Total166,694 1,040,842 340,168 
(1)The presentation of average daily 2021 fourth quarter production represents production during the period from the closing of our acquisition of Permian properties on December 21, 2021 through December 31, 2021 averaged over 92 days in the fourth quarter. At the time of closing, our Permian properties produced on average approximately 42,000 Boe per day (78% oil) based on two-stream reporting.
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, 2021. One or more completions in the same well bore are counted as one well.
 Crude Oil WellsNatural Gas WellsTotal Wells
 Gross    Net    Gross    Net    Gross    Net    
North Region:
Bakken5,610 1,997 — — 5,610 1,997 
Powder River Basin235 143 242 148 
Red River Units267 251 — — 267 251 
South Region:
Oklahoma1,214 521 943 304 2,157 825 
Permian Basin409 318 411 319 
Other23 25 
Total7,737 3,232 975 312 8,712 3,544 
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Title to Properties
As is customary in the crude oil and natural gas industry, upon initiation of acquiring oil and gas leases covering fee mineral interests on undeveloped lands which do not have associated proved reserves, contract landmen conduct a title examination of courthouse records and production databases to determine fee mineral ownership and availability. Title, lease forms and terms are reviewed and approved by Company landmen prior to consummation.
For acquisitions from third parties, whether lands are producing crude oil and natural gas or non-producing, Company and contract landmen perform title examinations at applicable courthouses, obtain physical well site inspections, and examine the seller’s internal records (land, legal, operational, production, environmental, well, marketing and accounting) upon execution of a mutually acceptable purchase and sale agreement. Company landmen may also procure an acquisition title opinion from outside legal counsel on higher value properties.
Prior to the commencement of drilling operations, Company landmen procure an original title opinion, or supplement an existing title opinion, from outside legal counsel and perform curative work to satisfy requirements pertaining to material title issues, if any. Company landmen will not approve commencement of drilling operations until material title defects pertaining to the Company’s interest are cured.
The Company has cured material title opinion issues as to Company interests on substantially all of its producing properties and believes it holds at least defensible title to its producing properties in accordance with standards generally accepted in the crude oil and natural gas industry. The Company’s crude oil and natural gas properties are subject to customary royalty and leasehold burdens which do not materially interfere with the Company’s interest in the properties or affect the Company’s carrying value of such properties.
Marketing
We sell most of our operated crude oil production to crude oil refining companies or midstream marketing companies at major market centers. In the Bakken, Powder River, Permian, SCOOP, and STACK 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 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 residue gas 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 production from non-operated properties is generally marketed at the discretion of the operators.
Environmental Stewardship
Throughout our operations, we seek to limit associated waste through emissions management and mitigation programs, increased recycling and re-use of produced water, and the use of footprint-reducing measures. Our environmental stewardship strategies, policies, and efforts are monitored by our Board of Directors’ Nominating, Environmental, Social and Governance Committee (“Committee”), which is the primary Committee responsible for overseeing and managing our ESG initiatives in respect of our business goals. Our focus on continuous improvement in ESG performance has resulted in sustained, year-over-year decreases since 2016 in both greenhouse gas and methane intensities. From 2019 through 2020, the most recent reporting year, we achieved a 28% decrease in greenhouse gas intensity and a 34% decrease in methane intensity.
Competition
We operate in a highly competitive environment for acquiring properties, marketing crude oil and natural gas, and securing trained personnel. Also, there is substantial competition for capital available for investment in the crude oil and natural gas industry. Our competitors vary within the regions in which we operate, and some of our competitors may possess and employ financial, technical and personnel resources greater than ours. Those companies may be able to pay more for crude oil and
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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, as a result of depressed commodity prices in recent years, the number of providers of materials and services has decreased in the regions where we operate. Further, recent supply chain disruptions stemming from the COVID-19 pandemic 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 in connection with any period of sustained commodity price recovery. Finally, the emerging impact of climate change activism, fuel conservation measures, governmental requirements for renewable energy resources, increasing demand for alternative forms of energy, and technological advances in energy generation devices may result in reduced demand for the crude oil and natural gas we produce.
Regulation of the Crude Oil and Natural Gas Industry
All of our operations are conducted onshore in the United States. The crude oil and natural gas industry in the United States is subject to various types of regulation at the federal, state and local levels. Laws, rules, regulations, policies, and interpretations affecting our industry have been and are pervasive with the frequent imposition of new or increased requirements. These laws, regulations and other requirements often carry substantial penalties for failure to comply and may have a significant effect on our operations and may increase the cost of doing business and reduce our profitability. In addition, because public policy changes affecting the crude oil and natural gas industry are commonplace and because laws, rules and regulations may be enacted, amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws, rules and regulations. We do not expect future legislative or regulatory initiatives will affect us materially different than they will affect our similarly situated competitors.
The following 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.
Regulation of sales and transportation of crude oil and natural gas liquids
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
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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.
Regulation of sales and transportation of natural gas
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.
Regulation of production
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.
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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.
Environmental regulation
General. We are subject to stringent, complex, and overlapping federal, state, and local laws, rules and regulations governing environmental compliance, including the discharge of materials into the environment. These laws, rules and regulations may, among other things:
require the acquisition of various permits to conduct exploration, drilling and production operations;
restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling, production and transportation activities;
limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas including areas containing endangered species of plants and animals;
require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells; and
impose substantial liabilities for pollution resulting from drilling and production operations.

These laws, rules and regulations may restrict the level of substances generated by our operations that may be emitted into the air, discharged to surface water, and disposed or otherwise released to surface and below-ground soils and groundwater, and may also restrict the rate of crude oil and natural gas production to a rate that is economically infeasible for continued production. The regulatory burden on the crude oil and natural gas industry increases the cost of doing business and affects profitability. Additionally, in the name of combatting climate change, President Biden has issued, and may continue to issue, executive orders that result in more stringent and costly requirements for the domestic crude oil and natural gas industry, or which restrict, delay or ban oil and gas permitting or leasing on federal lands. Any regulatory or executive changes that impose further requirements on domestic producers for emissions control, waste handling, disposal, cleanup and remediation could have a significant impact on our operating costs and production of oil and gas. Failure to comply with these and other laws, rules and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of corrective or remedial obligations or the incurrence of capital expenditures, the occurrence of restrictions, delays or cancellations in the permitting, development or expansion of projects, the issuance of orders enjoining performance of some or all of our operations, and potential litigation in a particular area. Additionally, certain of these environmental laws may result in imposition of joint and several or strict liability, which could cause us to become liable for the conduct of others or for consequences of our own actions. For instance, an accidental release from one of our wells could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners or other third parties for personal injury and property damage and fines or penalties for related violations of environmental laws or regulations. Certain environmental laws also provide for certain citizen suits, which allow persons or organizations to act in place of the government and sue operators for alleged violations of environmental laws. We have incurred and will continue to incur operating and capital expenditures, some of which may be material, to comply with environmental laws and regulations. The following is a description of some of the environmental laws, rules and regulations, as amended from time to time, that apply to our operations.
Air emissions. Federal, state, and local laws, rules, and regulations have been and, in the future, will likely be enacted to address concerns about emissions of regulated air pollutants. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit standards or utilize specific equipment or technologies to control emissions of certain pollutants. For example, in October 2021, the U.S. Environmental Protection Agency (“EPA”) announced its intention to initiate a rule-making to reassess and lower, by the end of 2023, the current National Ambient Air Quality Standard (“NAAQS”) for ground-level ozone, which was last set by the EPA under the Obama Administration in 2015. State implementation of a revised NAAQS for ground-level ozone could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits, or result in increased expenditures for pollution control equipment, the costs of which could be significant.
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.
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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. During 2020, the Trump Administration revised performance standards for methane established in 2016 to lessen the impact of those standards and remove the transmission and storage segments from the source category for certain regulations. However, shortly after taking office in 2021, President Biden issued an executive order calling on the EPA to revisit federal regulations regarding methane and establish new or more stringent standards for existing or new sources in the oil and gas sector, including the transmission and storage segments. The U.S. Congress also passed, and President Biden signed into law, a revocation of the 2020 rulemaking, effectively reinstating the 2016 standards. In response to President Biden’s executive order, in November 2021 the EPA issued a proposed rule that, if finalized, would establish Quad Ob new source and Quad Oc first-time existing source 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 plans to issue a supplemental proposal enhancing this proposed rulemaking in 2022 that will contain additional requirements that were not included in the November 2021 proposed rule. The EPA anticipates issuing a final rule before end-of-year 2022. Additionally, the House of Representatives version of the Build Back Better Act included a fee on methane emissions, targeting industries that produce, transport, and store natural gas throughout the United States at $900 per ton in 2023, $1,200 per ton in 2024, and $1,500 per ton in 2025 and beyond. Congress could seek to include this or a similar fee in future legislation.
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. President Biden announced in April 2021 a new, more rigorous nationally determined emissions reduction level of 50%-52% reduction from 2005 levels in economy-wide net GHG emissions 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 preliminary injunction by a federal district judge in Louisiana in June 2021, effectively halting implementation of the leasing suspension. The federal government is appealing the district court decision. 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
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emissions. At COP26, the Glasgow Financial Alliance for Net Zero (“GFANZ”) announced that commitments from over 450 firms across 45 countries had resulted in over $130 trillion in capital committed to net zero goals. The various sub-alliances of GFANZ generally require participants to set short-term, sector-specific targets to transition their financing, investing, and/or underwriting activities to net zero emissions by 2050. 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. More recently, 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. 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 acquisition, exploration, development, production, transportation, and processing activities, which could impact our business and operations. To the extent the rules impose additional reporting obligations, we could face increased costs. Furthermore, the SEC has announced it will propose rules that, among other matters, will establish a framework for the reporting of climate risks. However, no such rules have been proposed to date and we cannot predict what any such rules may require. To the extent rules impose additional reporting obligations, we could face increased costs. Separately, the SEC has also announced it is scrutinizing existing climate-change related disclosures in public filings, increasing the potential for enforcement if the SEC was to allege that an issuer’s existing climate disclosures were misleading or deficient.
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
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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. Notwithstanding these recent legal developments, further administrative and regulatory restrictions may be adopted by the Biden Administration that could restrict hydraulic fracturing activities on federal lands and waters.
In addition, regulators in states in which we operate have adopted additional requirements related to seismicity and its potential association with hydraulic fracturing. For example, the Oklahoma Corporation Commission (the “OCC”) has promulgated guidance for operators of crude oil and natural gas wells in certain seismically-active areas of the SCOOP and STACK plays in Oklahoma. The OCC's guidance provides for seismic monitoring and for implementation of mitigation procedures, which may include curtailment or even suspension of operations in the event of concurrent seismic events within a particular radius of operations of a magnitude exceeding 2.5 on the Richter scale. If seismic events exceeding the OCC guidance thresholds were to occur near our active stimulation operations on a frequent basis, they could have an adverse effect on our operations.
Waste water disposal. Underground injection wells are a predominant method for disposing of waste water from oil and gas activities. In response to seismic events near underground injection wells used for the disposal of oil and gas-related waste waters, federal and some state agencies have investigated whether such wells have caused increased seismic activity. To address concerns regarding seismicity, some states, including states in which we operate, have pursued remedies that included delaying permit approvals, mandating a reduction in injection volumes, or shutting down or imposing moratoria on the use of injection wells. Moreover, regulators in states in which we operate have implemented additional requirements related to seismicity. For example, the OCC has adopted rules for operators of saltwater disposal wells in certain seismically-active areas in the Arbuckle formation of Oklahoma. These rules require, among other things, that disposal well operators conduct mechanical integrity testing or make certain demonstrations of such wells’ respective depths that, depending on the depth, could require plugging the well and/or the reduction of volumes disposed in such wells. Oklahoma utilizes a “traffic light” system wherein the OCC reviews new or existing disposal wells for proximity to faults, seismicity in the area and other factors in determining whether such wells should be permitted, permitted only with special restrictions, or not permitted. At the federal level, the EPA’s current regulatory requirements for such wells do not require the consideration of seismic impacts when issuing permits. We cannot predict the EPA’s future actions in this regard.
The introduction of new environmental laws and regulations related to the disposal of wastes associated with the exploration, development or production of hydrocarbons could limit or prohibit our ability to utilize underground injection wells. A lack of waste water disposal sites could cause us to delay, curtail or discontinue our exploration and development plans. Additionally, increased costs associated with the transportation and disposal of produced water, including the cost of complying with regulations concerning produced water disposal, may reduce our profitability. These costs are commonly incurred by oil and gas producers and we do not expect the costs associated with the disposal of produced water will have a material adverse effect on our operations to any greater degree than other similarly situated competitors. In recent years, we have increased our operation and use of water recycling and distribution facilities that economically reuse stimulation water for both operational efficiencies and environmental benefits.
We have incurred in the past, and expect to incur in the future, capital and other expenditures related to environmental compliance. Such expenditures are included within our overall capital and operating budgets and are not separately itemized. Historically, our environmental compliance costs have not had a material adverse impact on our financial condition and results of operations; however, there can be no assurance that such costs will not be material in the future or that such future compliance will not have a material impact on our business, financial condition, results of operations or cash flows.
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Employee Health and Safety. We are also subject to the requirements of the federal Occupational Safety and Health Act and comparable state laws that regulate the protection of the health and safety of workers. In addition, the U.S. Occupational Safety and Health Administration hazard communication standard, the EPA community right-to-know regulation under Title III of the federal superfund Amendment and Reauthorization Act and similar state laws and regulations require information be maintained about hazardous materials used or produced in operations and this information be provided to employees, state and local governmental authorities and citizens.
Human Capital

Employees and Labor Relations
As of December 31, 2021, we employed 1,254 people, all of which were employed in the United States, with 721 employees being located at our corporate headquarters in Oklahoma City, Oklahoma and 533 employees located in our field offices located in Oklahoma, North Dakota, South Dakota, Montana, Wyoming, and Texas. None of our employees are subject to collective bargaining agreements.  We believe our overall relations with our workforce are good.

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

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

Through our “Brother’s Keeper” program, we encourage each of our employees to be a proactive participant in ensuring the safety of all of the Company’s personnel.  We developed this program to leverage and continuously improve our ability to identify and prevent reoccurrence of unsafe behaviors and conditions.  This program recognizes and rewards Company employees and contractors who observe and report outstanding safety and environmental behavior such as utilizing stop work authority, looking out for a co-worker, reporting incidents and near misses, or following proper safety procedures. This program positively impacts safety culture and performance and has contributed to a substantial increase in our reporting rates and to decreases in recordable incident and lost time incident rates. Our Total Recordable Incident Rate (TRIR), a commonly used safety metric that measures the number of recordable incidents per 100 full-time employees and contractors during a one year period, has decreased sequentially in each of the past four years and measured 0.33 for 2021, a 61% decrease compared to 2017.

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

Health and Wellness
We offer various benefit programs designed to promote the health and well-being of our employees and their families. These benefits include medical, dental, and vision insurance plans; disability and life insurance plans; paid time off for holidays, vacation, sick leave, and other personal leave; and healthcare flexible spending accounts, among other things. In addition to these programs, we have a number of other programs designed to further promote the health and wellness of our employees. For
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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.
From the earliest days of the COVID-19 pandemic we have taken, and continue to take, proactive measures to protect the health and safety of our employees, both at work and at home. These measures have included offering free in-office testing, providing flexible work schedules for impacted employees, holding in-office vaccination clinics so that interested employees and household members could conveniently receive vaccinations as soon as possible, maintaining physical distancing policies, limiting the number of employees attending meetings, reducing the number of people at our sites, requiring the use of masks in certain circumstances, frequently and extensively disinfecting common areas, and implementing self-isolation and quarantine requirements, among other things. We are committed to maintaining best practices with our COVID-19 response protocols and will continue to work under the guidance of public health officials to ensure a safe workplace as long as COVID-19 remains a threat to our employees and communities.

Diversity and Inclusion
We are committed to providing a diverse and inclusive workplace and career development opportunities to attract and retain talented employees. We prohibit discrimination and harassment of any type and afford equal employment opportunities to employees and applicants without regard to race, color, religion, sex, national origin, 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 and Ethics, 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 begun implementing 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. We are working with our newly formed Diversity and Inclusion Committee to provide new opportunities for our leadership and all employees to hold targeted discussions on issues related to diversity and inclusion, such as unconscious bias, disability inclusion, and equality through inclusive interaction. We are committed to continuous improvement in this critical area, evaluating more ways to sustain and strengthen our diverse and inclusive workforce.
Company Contact Information
Our corporate internet website is www.clr.com. Through the investor relations section of our website, we make available free of charge our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and any amendments to those reports as soon as reasonably practicable after the report is filed with or furnished to the SEC. For a current version of various corporate governance documents, including our Code of Business Conduct and Ethics, Corporate Governance Guidelines, and the charters for various committees of our Board of Directors, please see our website. We intend to disclose amendments to, or waivers from, our Code of Business Conduct and Ethics by posting to our website. 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 intend to use our website as a means of disclosing material information and for complying with our disclosure obligations under SEC Regulation FD. Such disclosures will be included on our website in the “Investors” section. Accordingly, investors should monitor that portion of our website in addition to following our press releases, SEC filings and public conference calls and webcasts.
We electronically file periodic reports and proxy statements with the SEC. The SEC maintains an internet website that contains reports, proxy and information statements, and other information registrants file with the SEC. The address of the SEC’s website is www.sec.gov.
Our principal executive offices are located at 20 N. Broadway, Oklahoma City, Oklahoma 73102, and our telephone number at that address is (405) 234-9000.
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Item 1A.    Risk Factors
You should carefully consider each of the risks described below, together with all other information contained in this report in connection with an investment in our 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, the trading price of our securities could decline and you may lose all or part of your investment.
Business and Operating Risks
Substantial declines in commodity prices or extended periods of low commodity prices adversely affect our business, financial condition, results of operations and cash flows and our ability to meet our capital expenditure needs and financial commitments.
The prices we receive for sales of our crude oil and natural gas production impact our revenue, profitability, cash flows, access to capital, capital budget, rate of growth, and carrying value of our properties. Crude oil and natural gas are commodities and prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for crude oil and natural gas have been volatile and unpredictable and commodity prices will likely remain volatile in the future. Our future crude oil production and a portion of our future natural gas production is unhedged as of the time of this filing and is exposed to continued volatility in market prices, whether favorable or unfavorable.
The prices we receive for sales of our production depend on numerous factors beyond our control. These factors include, but are not limited to, the following:
worldwide, domestic, and regional economic conditions impacting the supply of, and demand for, crude oil, natural gas, and natural gas liquids;
the actions of the Organization of Petroleum Exporting Countries and other petroleum producing nations;
the nature, extent, and impact of domestic and foreign governmental laws, regulations, and taxation, including environmental laws and regulations governing the imposition of trade restrictions and tariffs;
executive, regulatory or legislative actions by Congress, the Biden Administration, or states in which we operate;
geopolitical events and conditions, including domestic political uncertainty or foreign regime changes that impact government energy policies;
the level of global, national, and regional crude oil and natural gas exploration and production activities;
the level of global, national, and regional crude oil and natural gas inventories, which may be impacted by economic sanctions applied to certain producing nations;
the level and effect of speculative trading in commodity futures markets;
the relative strength of the United States dollar compared to foreign currencies;
the price and quantity of imports of foreign crude oil;
the price and quantity of exports of crude oil or liquefied natural gas from the United States;
military and political conditions in, or affecting other, crude oil-producing and natural gas-producing nations;
localized supply and demand fundamentals;
the cost and availability, proximity and capacity of transportation, processing, storage and refining facilities for various quantities and grades of crude oil, natural gas, and natural gas liquids;
adverse climatic conditions, natural disasters, and national and global health epidemics and concerns, including the COVID-19 pandemic;
technological advances affecting energy production and consumption;
the effect of worldwide energy conservation and greenhouse gas emission limitations or other environmental protection efforts;
the impact arising from increasing attention to environmental, social, and governance (“ESG”) matters; and
the price and availability of alternative fuels or other energy sources.
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Sustained material declines in commodity prices reduce cash flows available for capital expenditures, repayment of indebtedness and other corporate purposes; may limit our ability to borrow money or raise additional capital; and may reduce our proved reserves and the amount of crude oil and natural gas we can economically produce.
In addition to reducing our revenue, cash flows and earnings, depressed prices for crude oil and/or natural gas may adversely affect us in a variety of other ways. If commodity prices decrease substantially, some of our exploration and development projects could become uneconomic, and we may also have to make significant downward adjustments to our estimated proved reserves and our estimates of the present value of those reserves. If these price effects occur, or if our estimates of production or economic factors change, accounting rules may require us to write down the carrying value of our crude oil and/or natural gas properties.
Lower commodity prices may also lead to reductions in our drilling and completion programs, which may result in insufficient production to satisfy our transportation and processing commitments. If production is not sufficient to meet our commitments we would incur deficiency fees that would need to be paid absent any cash inflows generated from the sale of production.
Lower commodity prices may also reduce our access to capital and lead to a downgrade or other negative rating action with respect to our credit rating. A downgrade of our credit rating could negatively impact our cost of capital, increase borrowing costs under our revolving credit facility, and limit our ability to access 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.
The Organization of Petroleum Exporting Countries ("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.
Our business operations, financial position, results of operations, and cash flows have been and may continue to be materially and adversely affected by the COVID-19 pandemic.
The ongoing COVID-19 pandemic has negatively impacted, and may continue to negatively impact, the global economy which has 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. The adverse effects of COVID-19 have included and may in the future include the following:
Reduced crude oil prices;
Limitations on storage and transportation capacity and an inability to market our production;
Curtailment or shutting in of production;
Delay or cessation of drilling and completion projects;
Insufficient production to satisfy transportation and processing commitments;
Impairment of assets;
Downgrades or other negative credit rating actions resulting in increased borrowing costs;
An inability to develop acreage before lease expiration;
A reduction in the volume and value of proved reserves from price declines, changes in drilling programs, and the effects of shutting in production;
Increased difficulty in our ability to repay or refinance indebtedness, increase our credit facility commitments, borrow money, or raise capital;
Disruptions in energy industry supply chains and increased rates of inflation;
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Credit losses due to insolvency of customers, joint interest owners, and counterparties;
Cyber incidents or information security breaches resulting in information theft, data corruption, operational disruption, and/or financial loss as a consequence of employees accessing information from remote work locations; and
Shortages of drilling rigs, well completion crews, field services, personnel, and equipment in future periods of commodity price recovery.
The future impact of the pandemic on global and local economies and our business will continue to depend on future developments such as the emergence of future variant strains of COVID-19, the availability and distribution of effective medical treatments and vaccines, vaccination rates, as well as government-imposed restrictions or mandates, all of which are uncertain and cannot be predicted.
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 some of our current prospects and plans to develop our 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:
abnormal pressure or irregularities in geological formations;
shortages of or delays in obtaining equipment or qualified personnel;
shortages of or delays in obtaining components used in fracture stimulation processes such as water and proppants;
delays associated with suspending our operations to accommodate nearby drilling or completion operations being conducted by other operators;
mechanical difficulties, fires, explosions, equipment failures or accidents, including ruptures of pipelines or storage facilities, or train derailments;
restrictions on the use of underground injection wells for disposing of waste water from oil and gas activities;
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political events, public protests, civil disturbances, terrorist acts or cyber attacks;
decreases in, or extended periods of low, crude oil and natural gas prices;
title problems;
environmental hazards, such as uncontrollable flows of crude oil, natural gas, brine, well fluids, hydraulic fracturing fluids, toxic gas or other pollutants into the environment, including groundwater and shoreline contamination;
adverse climatic conditions and natural disasters;
spillage or mishandling of crude oil, natural gas, brine, well fluids, hydraulic fracturing fluids, toxic gas or other pollutants by us or by third party service providers;
limitations in infrastructure, including transportation, processing, refining and exportation capacity, or markets for crude oil and natural gas; and
delays imposed by or resulting from compliance with regulatory requirements including permitting.
Any of the above risks could adversely affect our ability to conduct operations or result in substantial losses to us as a result of:
injury or loss of life;
damage to or destruction of property, natural resources and equipment;
pollution and other environmental damage;
regulatory investigations and penalties;
suspension of our operations;
repair and remediation costs; and
litigation.
We are not insured against all risks associated with our business. We may elect to not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented or for other reasons. In addition, pollution and environmental risks are generally not fully insurable.
Losses and liabilities arising from any of the above events could hinder our ability to conduct normal operations and could adversely affect our business, financial condition, results of operations and cash flows.
Reserve estimates depend on many assumptions that may turn out to be inaccurate. The present value of future net revenues from our proved reserves will not necessarily be the same as the current market value of our estimated crude oil and natural gas reserves. Any material inaccuracies in our reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves. The Company’s current estimates of reserves could change, potentially in material amounts, in the future due to changes in commodity prices, business strategies, and other factors. Additionally, unless we replace our crude oil and natural gas reserves, our total reserves and production will decline, which could adversely affect our cash flows and results of operations.
The process of estimating crude oil and natural gas reserves is complex and inherently imprecise. It requires interpretation of available technical data and many assumptions, including assumptions relating to current and future economic conditions, production rates, drilling and operating expenses, and commodity prices. Any significant inaccuracy in these interpretations or assumptions could materially affect our estimated quantities and 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, 2021.
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.
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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. For the year ended December 31, 2021, average prices used to calculate our estimated proved reserves were $66.56 per Bbl for crude oil and $3.60 per MMBtu for natural gas ($62.19 per Bbl for crude oil and $3.46 per Mcf for natural gas adjusted for location and quality differentials). NYMEX WTI crude oil and Henry Hub natural gas first-day-of-the-month commodity prices for January 1, 2022 and February 1, 2022 averaged $81.71 per barrel and $4.65 per MMBtu, respectively. See Part I, Item 1. Business—Crude Oil and Natural Gas Operations—Proved Reserves—Proved Reserves, Standardized Measure, and PV-10 Sensitivities for proved reserve sensitivities under certain increasing and decreasing commodity price scenarios.
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, 2021, approximately 45% 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, 2021 includes estimates of total future development costs over the next five years associated with our proved undeveloped reserves of approximately $7.7 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 will 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 will likely 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 2021, 57 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 37% of our total net undeveloped acreage at December 31, 2021. At that date, we had leases representing 83,937 net acres expiring in 2022, 62,251 net acres expiring in 2023, and 51,094 net acres expiring in 2024.
Furthermore, unless we conduct successful exploration, development and exploitation activities or acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Producing crude oil and natural gas reservoirs are generally characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future crude oil and natural gas reserves and production, and therefore our cash flows and results of operations, are highly dependent on our success in efficiently developing our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire sufficient additional reserves to replace our current and future production. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations could be materially adversely affected.
Our business depends on crude oil and natural gas transportation, processing, refining, and export facilities, most of which are owned by third parties.
The value we receive for our crude oil and natural gas production depends in part on the availability, proximity and capacity of gathering, pipeline and rail systems and processing, refining, and export facilities owned by third parties. The inadequacy or unavailability of capacity on these systems and facilities could result in the shut-in of producing wells, the delay or
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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 no later than November 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 North region crude oil production to ultimate markets on the U.S. gulf coast. Our transportation commitment on the pipeline increased from 3,550 barrels per day to 30,000 barrels per day effective August 1, 2021 in conjunction with the completion of a DAPL expansion project. This commitment 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 have budgeted $2.30 billion for capital expenditures attributable to us in 2022, excluding acquisitions, of which approximately $1.80 billion is allocated to exploration and development activities. We may adjust our 2022 capital spending plans upward or downward depending on market conditions. Our 2022 capital budget, based on our current expectations of commodity prices and costs, is expected to be funded from operating cash flows. However, the sufficiency of our cash flows from operations is subject to a number of variables, including but not limited to:
the prices at which crude oil and natural gas are sold;
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the volume of our proved reserves;
the volume of crude oil and natural gas we are able to produce and sell from existing wells; and
our ability to acquire, locate and produce new reserves;
If oil and gas industry conditions weaken as a result of low commodity prices or other factors, we may not be able to generate sufficient cash flows and may have limited ability to obtain the capital necessary to sustain our operations at current or planned levels. A decline in cash flows from operations may require us to revise our capital program or alter or increase our capitalization substantially through the issuance of debt or equity securities.
We have a revolving credit facility with lender commitments totaling $2.0 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.
We have limited control over the activities on properties we do not operate.
Some of the properties in which we have an ownership interest are operated by other companies and involve third-party working interest owners. As of December 31, 2021, non-operated properties represented 14% of our estimated proved developed reserves, 7% of our estimated proved undeveloped reserves, and 11% 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
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marketing of oil and gas production, compliance with environmental, occupational safety and health and other regulations, or the amount of expenditures required to fund the development and operation of such properties. Moreover, we are dependent on other working interest owners on these projects to fund their contractual share of capital and operating expenditures. These limitations and our dependence on the operators and other working interest owners for these projects could cause us to incur unexpected future costs and could have a material adverse effect on our business, financial condition, results of operations and cash flows.

We may be subject to risks in connection with acquisitions, divestitures, and joint development arrangements.
As part of our business strategy, we have made and expect to continue making acquisitions of oil and gas properties, divest assets, and enter into joint development arrangements. The successful acquisition of oil and gas properties requires an assessment of several factors, including but not limited to:
reservoir modeling and evaluation of recoverable reserves;
future crude oil and natural gas prices and location and quality differentials;
the quality of the title to acquired properties;
the ability to access future drilling locations;
availability and cost of gathering, processing, and transportation facilities;
availability and cost of drilling and completion equipment and of skilled personnel;
future development and operating costs and potential environmental and other liabilities; and
regulatory, permitting and similar matters.
The accuracy of these acquisition assessments is inherently uncertain. In connection with these assessments, we perform a review, which we believe to be generally consistent with industry practices, of the subject properties. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities prior to acquisition. Inspections may not always be performed on every property, and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller of the subject properties may be unwilling or unable to provide effective contractual protection against all or part of the problems. We sometimes are not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis. Significant acquisitions and other strategic transactions may involve other risks that may impact our business, including:
diversion of our management’s attention to evaluating, negotiating and integrating significant acquisitions and strategic transactions;
the challenge and cost of integrating acquired assets and operations with our preexisting assets and operations while carrying on our ongoing business; and
the failure to realize the full benefit that we expect in estimated proved reserves, production volume, cost savings from operating synergies or other benefits anticipated from an acquisition, or to realize these benefits within the expected time frame.
As a result of our 2021 property acquisitions in the Permian Basin and Powder River Basin, the size and geographic footprint of our business has increased, and 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 these acquisitions will complement our business strategies by delivering enhanced free cash flows, corporate returns, and shareholder value, 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
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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, 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
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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 climatic events and natural disasters could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Severe climatic 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. Climate changes could result in increased frequency and severity of these climatic events, as well as chronic shifts in temperature and precipitation patterns. The consequences of such events may include the evacuation of personnel; damage to and disruption of production equipment, drilling rigs, or gathering, transportation, processing, storage, refining, and export facilities; delivery stoppages by third party vendors upon whom we rely upon for goods and services; the shut-in of production resulting from an inability to transport crude oil or natural gas products to market centers and other factors; an inability to access well sites; destruction of information and communication systems; and the disruption of administrative and management processes, any of which could hinder our ability to conduct normal operations and could adversely affect our business, financial condition, results of operations or cash flows. Our planning for normal climatic variation, 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 our consideration of changing climatic conditions and inclusion of safety factors in design is intended to reduce the uncertainties that climate change and other events may potentially introduce, our ability to mitigate the adverse impacts of these events depends in part on the effectiveness of our facilities and our disaster preparedness and response and business continuity planning, which may not have considered or be prepared for every eventuality.
Terrorist activities could materially and adversely affect our business and results of operations.
Terrorist attacks and the threat of terrorist attacks, whether domestic or foreign attacks, as well as military or other actions taken in response to these acts, could cause instability in the global financial and energy markets. Continued hostilities abroad and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the global economy in unpredictable ways, including the disruption of energy supplies and markets, increased volatility in commodity prices or the possibility that infrastructure we rely on could be a direct target or an indirect casualty of an act of terrorism. Any of these events could materially and adversely affect our business and results of operations.
Financial Risks
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Our derivative activities could result in financial losses or reduce our earnings.
To achieve more predictable cash flows and reduce our exposure to adverse fluctuations in commodity prices, from time to time we may enter into derivative instruments for a potentially significant portion of our production. See Part II, Item 8. Notes to Consolidated Financial Statements—Note 6. Derivative Instruments for a summary of our commodity derivative positions as of December 31, 2021. Additionally, see Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Derivative Instruments for a summary of additional derivative instruments entered into subsequent to December 31, 2021. We do not designate our derivative instruments as hedges for accounting purposes and we record all derivatives on our balance sheet at fair value. Changes in the fair value of derivatives are recognized in earnings. Accordingly, our earnings may fluctuate materially as a result of changes in commodity prices and resulting changes in the fair value of any outstanding derivatives.
Derivative instruments expose us to the risk of financial loss in certain circumstances, including when:
production is less than the volume covered by the derivative instruments;
the counterparty to the derivative instrument defaults on its contractual obligations; or
there is an increase in the differential between the underlying price in the derivative instrument and actual prices received.
In addition, derivative arrangements limit the benefit we would otherwise receive from increases in commodity prices. Our decision on the quantity and price at which we choose to hedge our future production is based in part on our view of current and future market conditions and our desire to stabilize cash flows necessary for the development of our proved reserves. We may choose not to hedge future production if the pricing environment for certain time periods is deemed to be unfavorable. Additionally, we may choose to settle derivative positions prior to the expiration of their contractual maturities.
Our revolving credit facility and indentures for our senior notes contain certain covenants and restrictions that may inhibit our ability to make certain investments, incur additional indebtedness and engage in certain other transactions, which could adversely affect our ability to meet our goals.
Our revolving 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, and merge, consolidate or sell all or substantially all of our assets. Our revolving credit facility also contains a requirement that we maintain a consolidated net debt to total capitalization ratio of no greater than 0.65 to 1.00. 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, 2021, we had $500 million of outstanding borrowings on our credit facility and our consolidated net debt to total capitalization ratio, as defined, was 0.43.
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.
The covenants in our revolving credit facility and senior note indentures may restrict our ability to expand or pursue our business strategies. Our ability to comply with the provisions of our revolving credit facility or senior note indentures may be impacted by changes in economic or business conditions, results of operations, or events beyond our control. The breach of any covenant could result in a default under our revolving credit facility or senior note indentures, in which case, depending on the actions taken by the lenders or trustees thereunder or their successors or assignees, could result in all amounts outstanding thereunder, together with accrued interest, to be due and payable. If our indebtedness is accelerated, our assets may not be sufficient to repay in full such indebtedness, which would have a material adverse effect our business, financial condition, results of operations, and cash flows.
The inability of joint interest owners, significant customers, and service providers to meet their obligations to us may adversely affect our financial results.
Our principal exposure to credit risk is through the sale of our crude oil and natural gas production, which we market to energy marketing companies, crude oil refining companies, and natural gas gathering and processing companies ($1.1 billion in receivables at December 31, 2021) and our joint interest and other receivables ($279 million at December 31, 2021). 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.
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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.
Legal and Regulatory Risks
Laws, regulations, guidance, executive actions or other regulatory initiatives regarding environmental protection and occupational safety and health could increase our costs of doing business and result in operating restrictions, delays, or cancellations in the drilling and completion of crude oil and natural gas wells, which could have a material adverse effect on our business, results of operations, financial condition and cash flows.
Our crude oil and natural gas exploration and production operations are subject to stringent federal, state and local legal requirements governing environmental protection and occupational safety and health. These requirements may take the form of laws, regulations, executive actions and various other legal initiatives. See Part I, Item 1. Business—Regulation of the Crude Oil and Natural Gas Industry for a discussion of those 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, and employees and labor relations. Following is a discussion of certain significant laws, rules and regulations that affect us in these areas in which we operate. See Part I, Item 1. Business—Regulation of the Crude Oil and Natural Gas Industry for further discussion of the regulations that affect us.
Taxation of oil and gas activities—President Biden's administration is pursuing 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. The passage of such legislation or any other similar change in U.S. federal income tax law could adversely affect our business, financial condition, results of operations and cash flows.
Dodd-Frank Act derivative regulations—In 2010, the U.S. Congress adopted the Dodd-Frank Act, which, among other provisions, established federal oversight and regulation of the over-the-counter derivatives market. If we do not qualify for an end user exemption from the Dodd-Frank Act requirements, the regulations could increase the cost of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure existing derivative contracts, lead to fewer potential counterparties, and increase our exposure to less creditworthy counterparties, any of which could limit our desire and ability to implement commodity price risk management strategies. Certain other regulations, including regulations related to capital requirements, which are yet to be implemented, may have an effect that results in the reduction of the number of products and counterparties in the over-the-counter derivatives market available to us and could result in significant additional costs being passed through to us. If our use of derivatives becomes limited as a result of the regulations, our results of operations may become more volatile and our cash flows may be less predictable. Aspects of the Dodd-Frank rulemaking have been finalized in certain areas, but other areas have not been finalized or implemented and the ultimate effect of these regulations on our business remains uncertain.
Failure to comply with the above and other laws and regulations 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
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priorities, including those in response to the January 2021 change in U.S. presidential administrations and shift in control of Congress, 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.
We are involved in legal proceedings that could result in substantial liabilities.
Like other similarly-situated oil and gas companies, we are, from time to time, involved in various legal proceedings in the ordinary course of business 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. The outcome of such legal matters often cannot be predicted with certainty. We vigorously defend ourselves in all such matters. However, if our efforts to defend ourselves are not successful, it is possible the outcome of one or more such proceedings could result in substantial liability, penalties, sanctions, judgments, consent decrees, or orders requiring a change in our business practices, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. Judgments and estimates to determine accruals related to legal and other proceedings could change from period to period, and such changes could be material.

Increasing scrutiny on environmental, social, and corporate governance matters may impact our business.
Companies across all industries are facing increasing scrutiny from 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, financial condition, and/or stock price 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 stock price, our ability to recruit necessary talent, and our access to capital markets.
In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. Currently, there are no universal standards for such scores or ratings and, in fact, different standards focus, to varying degrees, on different attributes of environmental, social, and corporate governance matters. This disparity between the “standards” may result in investors focusing on inadequate or improper metrics which may lead to a misperception of a company and its ESG practices. Conversely, pressures to create more uniformity among these “standards” may result in a skewed and potentially misplaced focus on certain factors over other, equally valuable factors. For example, of the 17 United Nations Sustainability Goals, the vast majority fall within the societal component, but many sustainability “standards” provide little weight to these goals, instead emphasizing the environmental component. Nonetheless, the importance of sustainability evaluations is becoming more broadly accepted by investors and shareholders. ESG ratings are used by some investors to inform their investment and voting decisions. Additionally, certain investors use these scores to benchmark companies against their peers, and if a company is perceived as lagging, these investors may engage with companies to require improved ESG disclosure or performance. Moreover, certain members of the broader investment community may consider a company’s sustainability score as a reputational or other factor in making an investment decision. Consequently, a low sustainability score could result in exclusion of our stock from consideration by certain investment funds, engagement by investors seeking to improve such scores, and a negative perception of our operations by certain investors.
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Risks Related to our Corporate Structure
Our Chairman of the Board and members of his family beneficially own approximately 82% of our outstanding common stock, giving them influence and control in corporate transactions and other matters, including a sale of our Company.
As of December 31, 2021, Harold G. Hamm, our Chairman of the Board, and members of his family, beneficially owned approximately 82% of our outstanding common shares. As a result, Mr. Hamm and his family have control over our Company and will continue to be able to control the election of our directors, determine our corporate and management policies and determine, without the consent of our other shareholders, the outcome of certain corporate transactions or other matters submitted to our shareholders for approval, including potential mergers or acquisitions, asset sales and other significant corporate transactions. Therefore, Mr. Hamm and his family could cause, delay or prevent a change of control of our Company. The interests of Mr. Hamm and his family may not coincide with the interests of other holders of our common stock.
We have historically entered into, and may enter into, transactions from time to time with companies or persons affiliated with Mr. Hamm and his family, if, after an independent review by our Audit Committee or by the independent members of our Board of Directors, it is determined such transactions are in the Company’s best interests and are on terms no less favorable to us than could be achieved with an unaffiliated third party. These transactions may result in conflicts of interest between Mr. Hamm’s affiliated parties and us.

Item 1B.    Unresolved Staff Comments
There were no unresolved Securities and Exchange Commission staff comments at December 31, 2021.
 
Item 2.    Properties
The information required by Item 2 is contained in Part I, Item 1. Business—Crude Oil and Natural Gas Operations and Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Delivery Commitments and is incorporated herein by reference.

Item 3.    Legal Proceedings
We are involved in various legal proceedings including, but not limited to, commercial disputes, claims from royalty and surface owners, property damage claims, personal injury claims, regulatory compliance matters, disputes with tax authorities and other matters. While the outcome of these legal matters cannot be predicted with certainty, we do not expect them to have a material effect on our financial condition, results of operations or cash flows.

Item 4.    Mine Safety Disclosures
Not applicable.
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Part II
 
Item 5.    Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Our common stock is listed on the New York Stock Exchange and trades under the symbol “CLR.” As of February 2, 2022, the number of record holders of our common stock was 1,269. On February 2, 2022, after inquiry, management believes that the number of beneficial owners of our common stock is 79,854. On February 2, 2022, the last reported sales price of our common stock, as reported on the New York Stock Exchange, was $55.08 per share.
In May 2019, our Board of Directors approved the initiation of a dividend payment program. On February 9, 2022, the Company declared a quarterly cash dividend of $0.23 per share on its outstanding common stock, which will be paid on March 4, 2022 to shareholders of record as of February 22, 2022. The Company intends to continue paying a quarterly dividend; however, any payment of future dividends will be at the discretion of our Board of Directors and will depend on, among other things, our future earnings, financial condition, cash flows, capital requirements, levels of indebtedness, prevailing business conditions and other considerations our Board of Directors may deem relevant.
The following table provides information about purchases of our common stock during the quarter ended December 31, 2021:
PeriodTotal number of shares purchasedAverage price paid per shareTotal 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, 2021 to October 31, 2021
Repurchases for tax withholdings (2)11,288 $52.13 — $— 
November 1, 2021 to November 30, 2021
Repurchases for tax withholdings (2)41,154 $49.36 — $— 
Share repurchase program (1)1,102,682 $46.30 1,102,682 $566.5 
Purchases by principal shareholder (3)108,500 $47.69 — $— 
December 1, 2021 to December 31, 2021
Share repurchase program (1)179,820 $42.33 179,820 $558.9 
Purchases by principal shareholder (3)367,020 $43.82 — $— 
Total for the quarter1,810,464 $45.59 1,282,502 
(1)In May 2019 our Board of Directors approved the initiation of a share repurchase program to acquire up to $1 billion of our common stock beginning in June 2019 at times and levels deemed appropriate by management. The program was announced on June 3, 2019 and does not have a set expiration date. As of December 31, 2021, the total dollar value of shares that may yet be purchased under the original program totaled $558.9 million. On February 8, 2022, our Board of Directors approved an increase in the size of the share repurchase program to $1.5 billion, inclusive of cumulative amounts repurchased to date. As of the date of this filing, we have repurchased a cumulative $441.1 million of our common stock. Accordingly, the total dollar value of shares that may yet be purchased now totals approximately $1.06 billion under the modified program. The share repurchase program does not require the Company to repurchase a specific number of shares and may be modified, suspended, or terminated by the Board of Directors at any time.
(2)Amounts represent shares surrendered by employees to cover tax liabilities in connection with the vesting of restricted stock granted under the Company's 2013 Long-Term Incentive Plan. We paid the associated taxes to the applicable taxing authorities. The price paid per share was the closing price of our common stock on the date the restrictions lapsed on such shares.
(3)Represents shares of our common stock purchased in open market transactions by Harold G. Hamm, our Chairman of the Board and principal shareholder.
Equity Compensation Plan Information
The following table sets forth the information as of December 31, 2021 relating to equity compensation plans: 
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Number of Shares
to be Issued Upon
Exercise of
Outstanding
Options
Weighted-Average
Exercise Price of
Outstanding Options
Remaining Shares
Available for Future
Issuance Under Equity
Compensation Plans (1)
Equity Compensation Plans Approved by Shareholders— — 8,492,645
Equity Compensation Plans Not Approved by Shareholders— — — 
 
(1)Represents the remaining shares available for issuance under the 2013 Plan.
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Performance Graph
The following graph compares our common stock performance with the performance of the Standard & Poor’s 500 Stock Index (“S&P 500 Index”) and the Dow Jones US Oil and Gas Index (“Dow Jones US O&G Index”) for the period of December 31, 2016 through December 31, 2021. The graph assumes the value of the investment in our common stock and in each index was $100 on December 31, 2016 and that any dividends were reinvested. The stock performance shown on the graph below is not indicative of future price performance.
The information provided in this section is being furnished to, and not filed with, the SEC. As such, this information is neither subject to Regulation 14A or 14C nor to the liabilities of Section 18 of the Securities Exchange Act of 1934, as amended.
clr-20211231_g4.jpg

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Item 6.    Reserved

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ITEM 7.    Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis should be read in conjunction with our consolidated financial statements and notes included elsewhere in this report. Results attributable to noncontrolling interests are not material relative to consolidated results and are not separately presented or discussed below.
The following discussion and analysis includes forward-looking statements and should be read in conjunction with Part I, Item 1A. Risk Factors in this report, along with Cautionary Statement for the Purpose of the “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995 at the beginning of this report, for information about the risks and uncertainties that could cause our actual results to be materially different than our forward-looking statements.
Overview
We are an independent crude oil and natural gas company engaged in the exploration, development, management, and production of crude oil and natural gas and associated products. Additionally, we pursue the acquisition and management of perpetually owned minerals located in our key operating areas. We derive the majority of our operating income and cash flows from the sale of crude oil and natural gas and expect this to continue in the future. We are the largest leaseholder and the largest producer in the Bakken field of North Dakota and Montana. We also have significant positions in the SCOOP and STACK plays in Oklahoma and recently acquired positions in the Permian Basin of Texas and Powder River Basin of Wyoming. Our common stock trades on the New York Stock Exchange under the symbol “CLR” and our corporate internet website is www.clr.com.
2021 Highlights
Financial and operating highlights for 2021 are summarized below. Our 2021 results underscore our continued focus on maximizing cash flow generation, maintaining low-cost capital efficient operations in an environmentally responsible manner, achieving consistent asset performance, and delivering capital and corporate returns to shareholders.
Generated $1.25 billion in operating cash flows in the fourth quarter, bringing year-to-date operating cash flows to a Company record $3.97 billion;
Completed strategic acquisitions to expand our operations into the Permian Basin for cash consideration of $3.06 billion and the Powder River Basin for cash consideration totaling $453 million;
Sequentially increased our quarterly fixed dividend throughout year, paying $166 million of dividends in 2021 with an additional $82 million of declared dividends to be paid in the first quarter of 2022;
Repurchased 3.2 million shares of common stock in 2021 under our share repurchase program at an aggregate cost of $124 million; and
Continued to maintain low cost operations with production expenses averaging $3.38 per Boe for 2021.
With our acquisitions in the Permian Basin and Powder River Basin in 2021 we now have substantial strategic positions in four leading basins in the United States, providing our Company and shareholders with enhanced geologic and geographic diversity and commodity optionality. We believe these transactions will be accretive on financial metrics and will complement our existing deep portfolio of assets in the Bakken and Oklahoma. We expect enhanced cash flows from the acquisitions will provide continued support for additional returns to shareholders via debt reduction, dividend increases, share repurchases, and increased returns on capital employed. See Part I, Item 1. Business—Acquisition Activities and Part II, Item 8. Notes to Consolidated Financial Statements—Note 2. Property Acquisitions and Dispositions for additional information on the acquisitions.
Financial and Operating Metrics
Our operating results for 2020 were severely impacted by the economic effects from the COVID-19 pandemic on crude oil demand and prices. In response to the significant reduction in crude oil prices during 2020, we curtailed approximately 55% of our operated crude oil production and associated natural gas in the 2020 second quarter and significantly reduced our capital spending. In July 2020 we began to gradually restore our curtailed production and subsequently brought our remaining curtailed production back online in September 2020. These actions resulted in material reductions in our production, revenues, and cash flows for 2020.
Crude oil and natural gas prices have increased significantly in 2021 compared to 2020 levels in response to the lifting of COVID-19 restrictions, the resumption of normal economic activity, and the resulting improvement in supply and demand fundamentals. The increase in commodity prices and resumption of our operations resulted in significantly improved operating results in 2021 compared to 2020 as further described below.
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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 previously described Permian Basin acquisition closed on December 21, 2021 and thus had a limited impact on fourth quarter and full year 2021 operating results given our short duration of ownership. The acquired Permian assets contributed 460 MBoe of production (42,000 Boe per day on average of which 78% was oil), $29.4 million of revenues, and $14.1 million ($0.04 per basic and diluted share) of net income to our consolidated results during the period of ownership from December 21, 2021 to December 31, 2021.
 Year ended December 31,
 202120202019
Average daily production:
Crude oil (Bbl per day)160,647 160,505 197,991 
Natural gas (Mcf per day)1,014,000 837,509 854,424 
Crude oil equivalents (Boe per day)329,647 300,090 340,395 
Average net sales prices: (1)
Crude oil ($/Bbl)$64.06 $34.71 $51.82 
Natural gas ($/Mcf)$4.88 $1.04 $1.77 
Crude oil equivalents ($/Boe)$46.24 $21.47 $34.56 
Crude oil net sales price discount to NYMEX ($/Bbl)$(4.00)$(5.80)$(5.15)
Natural gas net sales price premium (discount) to NYMEX ($/Mcf)$1.00 $(1.10)$(0.86)
Production expenses ($/Boe)$3.38 $3.27 $3.58 
Production taxes (% of net crude oil and natural gas sales)7.3 %8.2 %8.3 %
DD&A ($/Boe) $15.76 $17.12 $16.25 
Total general and administrative expenses ($/Boe)$1.94 $1.79 $1.57 
(1)     See the subsequent section titled Non-GAAP Financial Measures for a discussion and calculation of net sales prices, which are non-GAAP measures.
Results of Operations
The following table presents selected financial and operating information for the periods presented.
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  Year Ended December 31,