UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

_______________________________
FORM 10-K

_______________________________
(Mark One)
x☒ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 20172021
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)

_______________________________
Oklahoma73-0767549
(State or other jurisdiction of
incorporation or organization)
(I.R.S. Employer
Identification No.)
20 N. Broadway,Oklahoma City, OklahomaOklahoma73102
(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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post such files).    Yes  x    No  ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  x
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 filerxAccelerated filer☐
Non-accelerated filer☐Smaller reporting company☐
Large accelerated filerxAccelerated filer¨
Non-accelerated filer
¨  (Do not check if a smaller reporting company)
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. ¨
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, 20172021 was approximately $2.8$2.5 billion, based upon the closing price of $32.33$38.03 per share as reported by the New York Stock Exchange on such date.
375,215,902 364,298,349shares of our $0.01 par value common stock were outstanding on January 31, 2018.2022.


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 2018,2022, 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
PART I
Item 1.
1
General
1
Our Business StrategyStrategies
32
Our Business Strengths
32
Crude Oil and Natural Gas Operations
53
Proved Reserves
54
Developed and Undeveloped Acreage
1210
Drilling Activity
1311
Summary of Crude Oil and Natural Gas Properties and Projects
1311
Production and Price History
1614
Productive Wells
1715
Title to Properties
1716
Marketing and Major Customers
1816
Competition
1816
Regulation of the Crude Oil and Natural Gas Industry
1917
EmployeesHuman Capital
2823
Company Contact Information
2824
Item 1A.
3025
Item 1B.
4638
Item 2.
4638
Item 3.
4638
Item 4.
4638
PART II
Item 5.
4739
Item 6.
4942
Item 7.
5143
Item 7A.
7360
Item 8.
7562
Item 9.
108103
Item 9A.
108103
Item 9B.
111106
Item 9C.
106
PART III
PART III
Item 10.
111106
Item 11.
111106
Item 12.
111106
Item 13.
111106
Item 14.
111106
PART IV
Item 15.
112107





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 gas” Refers to natural gas that remains in a gaseous state in the reservoir and does not produce large quantities of liquid hydrocarbons when brought to the surface. Also may refer to gas that has been processed or treated to remove all natural gas liquids.
“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.

i


“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.

ii


“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. A significant portion of our STACK acreage is located in over-pressured portions of Blaine, Dewey and Custer counties of Oklahoma.
“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.
“step-out well” or “step outs” A well drilled beyond the proved boundaries of a field to investigate a possible extension of the field.
“three dimensional (3D) seismic” Seismic surveys using an instrument to send sound waves into the earth and collect data to help geophysicists define the underground configurations. 3D seismic provides three-dimensional pictures. We typically use 3D seismic testing to evaluate reservoir presence and/or continuity. We also use 3D seismic to identify sub-surface hazards to assist in steering, avoiding hazards and determining where to perform optimized completions.
“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. In general, unconventional plays require the application of more advanced technology and higher drilling and completion costs to produce relative to conventional plays.
“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;
competition;•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;position, dividend payments, bond repurchases, share repurchases, or income tax payments;
general•the impact of the COVID-19 (novel coronavirus) pandemic on economic conditions;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
iv



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
Item 1.    Business
General
We are an independent crude oil and natural gas company with propertiesformed 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. TheAdditionally, 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. TheOur South region includes all properties south of Nebraska and west of the Mississippi River including various plays inand includes the SCOOP (South Central Oklahoma Oil Province) and STACK (Sooner Trend Anadarko Canadian Kingfisher) areas of Oklahoma. TheOklahoma 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.
We were formedOur operations in 1967 to explore for, develop and produce crude oil and natural gas properties. Through the 1980s, our activities and growth remained focused primarily in Oklahoma. In the 1980s, we expanded our activity into the North region. The North region comprised approximately 59%55% of our crude oil and natural gas production and approximately 69%63% of our crude oil and natural gas revenues for the year ended December 31, 2017. The Company’s principal producing properties in the North region are located in the Bakken field2021. Approximately 46% of North Dakota and Montana. Approximately 50% of our estimated proved reserves as of December 31, 20172021 are located in the North region. In recent years, we have significantly expanded ourOur operations in our South region with our increased activity in the SCOOP and STACK plays. The South region comprised approximately 41%45% of our crude oil and natural gas production, 31%37% of our crude oil and natural gas revenues, and 50%54% of our estimated proved reserves as of and for the year ended December 31, 2017.2021.
We focus our exploration activities in large new or developing crude oil and natural gas plays that provide us the opportunity to acquire undeveloped acreage positions for future drilling operations.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, 2017,2021, our estimated proved reserves were 1,3311,645 MMBoe, with estimated proved developed reserves of 602representing 908 MMBoe, or 45%55%, of our total estimated proved reserves. Crude oil represents approximately 48% of our estimated proved reserves as of December 31, 2017. The standardized measure of our discounted future net cash flows totaled approximately $10.5$16.64 billion at December 31, 2017.
2021. For 2017,2021, we generated crude oil and natural gas revenues of $2.98$5.79 billion and operating cash flows of $2.08$3.97 billion. Crude oil accounted for approximately 57%49% of our total production and approximately 78%68% of our crude oil and natural gas revenues for 2017. Production2021. Our total production averaged 242,637329,647 Boe per day for 2017, a 12%2021, an increase of 10% compared to average production of 216,912 Boe per day for 2016. Average daily production for the quarter ended December 31, 2017 increased 37% to 286,985 Boe per day compared to 209,861 Boe per day for the quarter ended December 31, 2016 due to increased drilling and completion activities.2020.
The table below summarizes our total estimated proved reserves, PV-10 (non-GAAP) and net producing wells as of December 31, 2017,2021 and our average daily production for the quarter ended December 31, 2017 and the reserve-to-production index in2021 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, 2017 Average daily
production for
fourth quarter
2017
(Boe per day)		   Annualized
reserve/production
index (2)
  Proved
reserves
(MBoe)		 Percent
of total		 PV-10 (1)
(In millions)		 Net
producing
wells		 Percent
of total		 
North Region:              
Bakken field              
North Dakota Bakken 594,818
 44.7% $6,488
 1,313
 158,640
 55.3% 10.3
Montana Bakken 40,703
 3.1% 412
 263
 6,958
 2.4% 16.0
Red River units              
Cedar Hills 28,998
 2.2% 340
 130
 7,022
 2.4% 11.3
Other Red River units 2,668
 0.2% 28
 117
 2,475
 0.9% 3.0
Other 1,356
 0.1% 9
 8
 468
 0.2% 7.9
South Region:              
SCOOP 491,776
 36.9% 3,597
 260
 62,242
 21.7% 21.6
STACK 167,390
 12.6% 936
 160
 47,914
 16.7% 9.6
Other 3,286
 0.2% 23
 175
 1,266
 0.4% 7.1
Total 1,330,995
 100.0% $11,833
 2,426
 286,985
 100.0% 12.7
 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 — %$1 4 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 $1.4 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 Annualized Reserve/Production Index is the number of years that estimated proved reserves would last assuming current production continued at the same rate. This index is calculated by dividing annualized fourth quarter 2017 production into estimated proved reserve volumes as of December 31, 2017.
(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.
Business Environment and Outlook
Our industry has been significantly impacted by lower commodity prices in recent years. (2)The downward pressure on prices experienced in 2015 and 2016 showed signspresentation of easing in 2017. Commodity prices remained volatileaverage daily 2021 fourth quarter production represents production during the year, but generally increasedperiod 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 in 2017 relative to 2016 in response to improving domestic and global supply and demand fundamentals and other factors. Crude oil prices in particular showed significant signs of improvement in late 2017 and early 2018, with West Texas Intermediate crude oil benchmark prices reaching a three-year high of $66approximately 42,000 Boe per barrel in January 2018. Crude oil prices remain volatile and it is uncertain whether the increase in market prices experienced in recent months will be sustained.day based on two-stream reporting.
Continental marked its 50th anniversary in the oil and gas business in 2017. Our leadership team has significant experience with operating in challenging commodity price environments. With our portfolio of high quality assets, we are well-positioned to manage the ongoing challenges and price volatility facing our industry.
For 2018, our primary business strategies will focus on:
Balancing strong production growth with free cash flow generation;
Enhancing cash flows and return on capital employed through improvements in operating efficiencies, technical innovations, and optimized completion methods;
Continuing to exercise disciplined capital spending to maintain financial flexibility and ample liquidity; and
Improving debt metrics by further reducing outstanding debt using available operating cash flows or proceeds from asset dispositions or joint development arrangements.
Based on an expectation for higher operating cash flows in 2018 in response to improvement in crude oil prices in late 2017 and early 2018, we have increased our planned non-acquisition capital spending for 2018 to $2.3 billion compared to $2.0 billion spent in 2017, with approximately 78% of our 2018 drilling and completion budget focusing on oil-weighted areas in


the North Dakota Bakken and SCOOP Springer plays. We expect to fund our budgeted spending using cash flows from operations. We may adjust our pace of drilling and development as 2018 market conditions evolve.
For 2018, we plan to operate an average of approximately 21drilling rigs and 10completion crews for the year. We expect to spend approximately 52%of our 2018 capital expenditures budget on drilling and completion activities in North Dakota Bakken, 20%in SCOOP, and 14% in STACK. The remaining 14%of our 2018 budget will target other capital expenditures such as leasing and renewals, work-overs, and facilities. See the section below titled Summary of Crude Oil and Natural Gas Properties and Projects for further discussion of our 2018 plans.
Our Business StrategyStrategies
Despite ongoing volatility and uncertainty in commodity prices, ourOur business strategy continuesstrategies continue to be focused on increasinggenerating significant shareholder value by finding and developing crude oil and natural gas reserves at low costs that provideand attractive rates of return. The principal elements of this strategyFor 2022, our primary business strategies will include:
Growing•Continuing to exercise capital and sustaining a premier portfolio of assets focused on balancing production growth with freeoperational discipline to maximize cash flow generation. We hold a portfolio of leasehold acreage, drilling opportunitiesgeneration and uncompleted wells in certain premier U.S. resource plays with varying access to crude oil, natural gas, and natural gas liquids. We pursue opportunities to develop our existing properties as well as explore for new resource plays where significant reserves may be economically developed. Our capital programs are designed to allocate investments to projects that provide opportunities to deliver strong production growth while generating cash flows in excess of operating and capital requirements, to work down our large inventory of uncompleted wells, to convert our undeveloped acreage to acreage held by production, and to improve hydrocarbon recoveries and rates of returncompetitive returns on capital employed. While our operations have historically focused on the explorationemployed;
•Reducing outstanding debt and development of crude oil, we also allocate significant capital to natural gas areas that provide attractive rates of return.
Enhance cash flows and return on capital employed through costs reductions, operating efficiencies, technical innovations, and optimized completions. We continue to manage through the current commodity price environment by focusing on improving operating efficiencies and reducing costs. Our key operating areas are characterized by large acreage positions in select unconventional resource plays with multiple stacked geologic formations that provide repeatable drilling opportunities and resource potential. We operate a significant portion of our wells and leasehold acreage and believe the concentration of our operated assets allows us to leverage our technical expertise and manage the development of our properties to achieve cost reductions through operating efficiencies and economies of scale.
We continued to achieve efficiency gains in various aspects of our business in 2017, including additional reductions in spud-to-total depth drilling times and average days to drill horizontal laterals, which has led to reductions in drilling costs in our core areas. In addition to lowering our drilling costs, we also work to enhance cash flows through the use of optimized completion technologies that help improve recoveries and rates of return. These efforts have had a positive impact on the efficiency of our capital deployed in recent years, resulting in significant improvement in the quantity of reserves found and developed per dollar invested.
Maintaining financial flexibility andmaintaining a strong balance sheet. to enhance financial flexibility;
•Maintaining a strong balance sheet, ample liquidity,shareholder alignment by maximizing capital and financial flexibility are key components ofcorporate returns to shareholders;
•Developing our business strategy. In 2017, we reducedrecently acquired properties in the Permian Basin and Powder River Basin by applying our total debt by $226 million, or 3%, from $6.58 billion at year-end 2016 to $6.35 billion at year-end 2017. We are actively targeting further debt reduction using available cash flows from operations or proceeds from potential sales of non-strategic assetsgeologic and joint development opportunitiesoperational expertise;
•Maintaining low-cost, capital efficient operations; and will continue our focus on preserving financial flexibility and ample liquidity as we manage the risks facing our industry.
Focusing on organic growth through disciplined capital investments. Although we consider various growth opportunities, including property acquisitions, our primary focus is on organic growth through leasing and drilling•Driving continued improvement in our core areas where we can exploit our extensive inventory of repeatable drilling opportunities to achieve attractive rates of return. From January 1, 2015 through December 31, 2017, our proved reserve additions through extensionshealth, safety, and discoveries were 743 MMBoe compared with insignificant proved reserve acquisitions during that same period.environmental performance and governance programs.
Our Business Strengths
We have a number of strengths we believe will helpto allow us to successfully execute our business strategy,strategies, including the following:
Large Acreage Inventoryacreage inventory with access to both crude oil and natural gas resources. We held approximately 598,400538,400 net undeveloped acres and 1.191.40 million net developed acres under lease as of December 31, 20172021 concentrated in certaincore areas of premier U.S. resource plays. We are among the largest leaseholders in the Bakken, SCOOPplays that provide optionality and STACK plays. Being an early entrant in these plays has allowed usaccess to capture significant acreage positions in core parts of the plays.crude oil, natural gas, and natural gas liquids.


Expertise with Horizontal Drillingpad and Optimized Completion Methodsrow 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 drilling in our operating areas.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 Overoperations over a Substantial Portionsubstantial portion of Our Assetsour assets and Investmentsinvestments. As of December 31, 2017,2021, 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.industry and with operating in challenging commodity price environments. Our Chief Executive Officer,Chairman of the Board, Harold G. Hamm, began his career in the oil and gas industry in 1967. Our 9 seniorexecutive officers have an average of 3840 years of oil and gas industry experience.
Financial Position and Liquidity. Currently weWe have a revolving credit facility with lender commitments totaling $2.75$2.0 billion that matures in May 2019.October 2026. We had approximately $2.65$1.76 billion of available borrowing capacity underavailability on our credit facility at January 31, 20182022 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. Downgrades
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 credit ratingacquisitions 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 however, triggerbe 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 our credit facility’s interest ratesthe Permian Basin and commitment fees paid on unused borrowing availability under certain circumstances.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 that 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 that have been 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 following table below sets forth estimated proved crude oil and natural gas reserves information by reserve category as of December 31, 2017.2021. 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 $10.5$16.64 billion at December 31, 2017.2021. Our reserve estimates as of December 31, 20172021 are based primarily on a reserve report prepared by Ryder Scott. In preparing its report, Ryder Scott evaluated properties representing approximately 96%98% of our PV-10 and 96%98% of our total proved reserves as of December 31, 2017.2021. 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, 20172021 were determined using the 12-month unweighted arithmetic average of the first-day-of-the-month commodity prices for the period of January 20172021 through December 2017,2021, without giving effect to derivative transactions, and were held constant throughout the lives of the properties. These prices were $51.34$66.56 per Bbl for crude oil and $2.98$3.60 per MMBtu for natural gas ($47.0362.19 per Bbl for crude oil and $3.00$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)		Crude Oil
(MBbls)		Natural Gas
(MMcf)		Total
(MBoe)		PV-10 (1)
(in millions)
Proved developed producing 318,291
 1,697,926
 601,279
 $7,474.9
Proved developed producing415,861 2,853,980 891,524 $13,256.4 
Proved developed non-producing 416
 1,235
 622
 6.4
Proved developed non-producing8,292 47,167 16,154 230.5 
Proved undeveloped 322,242
 2,441,120
 729,094
 4,352.2
Proved undeveloped369,377 2,209,532 737,632 7,006.0 
Total proved reserves 640,949
 4,140,281
 1,330,995
 $11,833.5
Total proved reserves793,530 5,110,679 1,645,310 $20,492.9 
Standardized Measure (1)       $10,470.2
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 $1.4 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.

(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, 2017.2021.
 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 
  Proved Developed Proved Undeveloped
  Crude Oil
(MBbls)		 Natural Gas
(MMcf)		 Total
(MBoe)		 Crude Oil
(MBbls)		 Natural Gas
(MMcf)		 Total
(MBoe)
North Region:            
Bakken field            
North Dakota Bakken 217,776
 472,057
 296,452
 212,107
 517,562
 298,366
Montana Bakken 21,503
 38,480
 27,916
 10,385
 14,412
 12,787
Red River units            
Cedar Hills 28,321
 4,058
 28,998
 —
 —
 —
Other Red River units 2,667
 16
 2,668
 —
 —
 —
Other 110
 7,469
 1,356
 —
 —
 —
South Region:            
SCOOP 35,333
 754,820
 161,136
 84,828
 1,474,871
 330,640
STACK 12,181
 407,448
 80,089
 14,922
 434,275
 87,301
Other 816
 14,813
 3,286
 —
 —
 —
Total 318,707
 1,699,161
 601,901
 322,242
 2,441,120
 729,094
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 
  Year Ended December 31,
MBoe 2017 2016 2015
Proved reserves at beginning of year 1,274,864
 1,225,811
 1,351,091
Revisions of previous estimates (82,012) (110,474) (297,198)
Extensions, discoveries and other additions 240,206
 249,430
 253,173
Production (88,562) (79,390) (80,926)
Sales of minerals in place (15,197) (10,513) (329)
Purchases of minerals in place 1,696
 —
 —
Proved reserves at end of year 1,330,995
 1,274,864
 1,225,811
Revisions of previous estimates. Revisions represent changesfor 2021 are comprised of (i) upward price revisions of 92 MMBo and 458 Bcf (totaling 168 MMBoe) due to the significant increase in previous reserve estimates, either upward or downward,average crude oil and natural gas prices in 2021 compared to 2020 resulting from new information normally obtained from development drillingthe lifting of COVID-19 restrictions, the resumption of normal economic activity, and production history orthe resulting from a changeimprovement in economic factors, such as commodity pricessupply and differentials, operating costs, or development costs.
Given the significant volatility in commodity prices in recent years, and given the uncertainty regarding the timing, magnitude and duration of any price recovery, maintaining a strong balance sheet, ample liquidity, and financial flexibility has become an increasingly important component of our long-term business strategy. In light of our strategy to preserve financial flexibility and minimize the incurrence of new debt, we maintained a disciplined spending approach in 2017 and continued to refine our capital program to focus on areas that provide the greatest opportunities to achieve operating efficiencies and cost reductions, to convert undeveloped acreage to acreage held by production, and to improve hydrocarbon recoveries, cash flows and rates of return using optimized completions. As part of this effort, we shifted a portion of our 2017 spending away from the SCOOP and Bakken plays to areas in the emerging STACK play that offered more advantageous opportunities and rates of return in the 2017 commodity price environment. This shift in strategy coupled with our increased emphasis on balancing capital spending with cash flows altered the timing and extent of our previous development plans in certain areas and resulted indemand fundamentals, (ii) the removal of 4131 MMBo and 290155 Bcf (totaling 8957 MMBoe) of PUD reserves no longer scheduled to be developeddrilled 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 dateremoval of initial booking. These removals do not represent the elimination of recoverable hydrocarbons physicallyPUD reserves due to changes in place. In some instances the removed reserves may be developed in the future in the event of further improvement in commodity prices and an expansion of our capital expenditure budget.
Commodity prices increased on average in 2017 relative to 2016 in response to improving domestic and global supply and demand fundamentalsanticipated well densities, economics, performance, and other factors. The 12-month average first-day-of-the-month pricefactors, and (iv) downward revisions for crude oil increased 20% from $42.75 per Bbl for 2016 to $51.34 per Bbl for 2017, while the 12-month average first-day-of-the-month pricereserves of 35 MMBo and upward revisions for natural gas increased 20% from $2.49 per MMBtu for 2016 to $2.98 per MMBtu for 2017. These changes increased the economic livesreserves of


certain producing properties and caused certain previously uneconomic projects to become economic, which had a favorable impact on the Company’s proved reserve estimates, resulting in upward revisions of 29 MMBo and 78 195 Bcf (totaling 42 MMBoe) in 2017.
Additionally, changes in anticipated production performance on certain properties resulted in 59 MMBo of downward revisions to crude oil reserves and 173 Bcf of upward revisions to natural gas reserves (netting to 302 MMBoe of downward revisions) in 2017. Further,due to changes in ownership interests, operating costs, anticipated production, and other factors during the year resulted in 7 MMBo of downward revisions to crude oil reserves and 11 Bcf of upward revisions to natural gas reserves (netting to 5 MMBoe of downward revisions) in 2017.factors.
Extensions, discoveries and other additions. These are additions to our proved reserves that result from (i) extension of the proved acreage of previously discovered reservoirs through additional drilling in periods subsequent to discovery and (ii) discovery of new fields with proved reserves or of new reservoirs of proved reserves in old fields. Extensions, discoveries and other additions for each of the three years reflected in the table above were primarily due to increases in proved reserves associated with our successful drilling and completion activities in the Bakken, SCOOP and STACK areas.continual refinement of our drilling programs. Proved reserve additions from our drilling activities in the Bakken totaled 148202 MMBoe, 7341 MMBoe, and 96160 MMBoe for 2017, 20162021, 2020, and 2015,2019, respectively, while reserve additions in SCOOPOklahoma totaled 53169 MMBoe, 9750 MMBoe, and 93205 MMBoe for 2017, 20162021, 2020, and 2015, respectively. Additionally, extensions and discoveries were impacted by successful drilling and completion results in the STACK play, resulting in proved reserve additions of 39 MMBoe, 79 MMBoe and 57 MMBoe in 2017, 2016 and 2015,2019, respectively. See the subsequent section titled Summary of Crude Oil and Natural Gas Properties and Projects for a discussion of our 20172021 drilling activities. We expect a significant portion of future reserve additions will continue to come from our major development projects in the Bakken, SCOOP and STACK areas.
Sales of minerals in place. These are reductions to We had no individually significant dispositions of proved reserves resulting fromin the disposition of properties during a period. See Part II, Item 8. Notes to Consolidated Financial Statements—Note 14. Property Dispositions for further discussion of notable dispositions. We may continue to seek opportunities to sell non-strategic properties if and when we have the ability to dispose of such assets at favorable terms.past three years.
Purchases of minerals in place. These are additionsPurchases 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 resulting fromacquired in the acquisition of properties during a period.Powder River Basin totaled 26 MMBo and 46 Bcf (totaling 34 MMBoe). We have had no individually significant acquisitions of proved reserves in the past three years. However, we may participate as a buyer of properties when2020 and if we have the ability to increase our position in strategic plays at favorable terms.2019.
5

Proved Undeveloped Reserves
All of our PUD reserves at December 31, 20172021 are located in the Bakken, SCOOP, and STACK plays, our most active development areas, with those plays comprising 43%, 45%, and 12%, respectively, of our total PUD reserves at year-end 2017.areas. The following table provides information regarding changes in our PUD reserves for the year ended December 31, 2017.2021. Our PUD reserves at December 31, 20172021 include 7068 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 
  Crude Oil
(MBbls)		 Natural Gas
(MMcf)		 Total
(MBoe)
Proved undeveloped reserves at December 31, 2016 353,018
 2,419,198
 756,218
Revisions of previous estimates (73,684) (131,306) (95,569)
Extensions and discoveries 100,874
 492,468
 182,952
Sales of minerals in place (3,441) (24,870) (7,586)
Purchases of minerals in place 149
 3,009
 650
Conversion to proved developed reserves (54,674) (317,379) (107,571)
Proved undeveloped reserves at December 31, 2017 322,242
 2,441,120
 729,094
Revisions of previous estimates. During the year ended December 31, 2017,As previously discussed, in 2021 we removed 165 gross (123 net) PUD locations, which resulted in the removal of 41 MMBo and 290 Bcf (totaling 89 MMBoe) of PUD reserves, of which 31 MMBo and 66155 Bcf (totaling 4257 MMBoe) was related to our Bakken properties and 10 MMBo and 218 Bcf (totaling 46 MMBoe) was related to our SCOOP properties. These removals were due to the aforementioned refinement of our drilling program to place emphasis on areas that provide the greatest opportunities to achieve operating efficiencies and cost reductions, to convert undeveloped acreage to acreage held by production, and to improve hydrocarbon recoveries, cash flows and rates of return using optimized completions. These and other aforementioned factors altered the timing and extent of our previous development plans in certain


areas and resulted in the removal of PUD reserves no longer scheduled to be developeddrilled within five years of initial booking due to continual refinement of our drilling and development programs and reallocation of capital to areas providing the datebest opportunities to improve efficiencies, recoveries, and rates of initial booking.
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 2017 caused certain previously uneconomic projects to become economic, which2021 resulted in upward PUD reserveprice revisions of 815 MMBo and 2273 Bcf (totaling 1127 MMBoe) in 2017. Further, changes in anticipated production performance on producing properties having offsetting PUD locations resulted in 43 MMBo of downward revisions to crude oil PUD reserves and 134 Bcf of upward revisions to natural gas PUD reserves (netting to 20 MMBoe of downward revisions) in 2017.. Finally, changes in ownership interests, operating costs, anticipated production, and other factors during the year resulted in 3 MMBo of upwarddownward revisions to crudefor oil PUD reserves of 17 MMBo and 3 Bcf ofnet upward revisions tofor natural gas PUD reserves of 16 Bcf (totaling 3 MMBoea net downward revision of upward revisions)15 MMBoe) in 2017.2021.
Extensions, discoveries and discoveries. other additions. Extensions, discoveries and discoveriesother additions were primarily due to increases in PUD reserves associated with our successful drilling activity in the Bakken, SCOOPactivities and STACK areas.continual refinement of our drilling and development programs. PUD reserve additions in the Bakken totaled 86133 MMBo and 216359 Bcf (totaling 122193 MMBoe) in 2017,2021, while SCOOP PUD reserve additions in Oklahoma totaled 1324 MMBo and 193824 Bcf (totaling 45161 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 STACKPowder River Basin described above. PUD reserve additionsreserves acquired in the Permian Basin totaled 265 MMBo and 83130 Bcf (totaling 87 MMBoe) and PUD reserves acquired in the Powder River Basin totaled 12 MMBo and 21 Bcf (totaling 16 MMBoe). See the subsequent section titled Summary of Crude Oil and Natural Gas Properties and Projects for a discussion of our 2017 drilling activities in these areas.
Conversion to proved developed reserves. In 2017,2021, we developed approximately 17%24% of our PUD locations and 14%20% of our PUD reserves booked as of December 31, 20162020 through the drilling and completion of 300269 gross (146(137 net) development wells at aan aggregate capital cost of approximately $762$508 million incurred in 2017. PUD conversions in North Dakota Bakken totaled 49 MMBo and 106 Bcf (totaling 66 MMBoe) in 2017, while STACK PUD conversions totaled 4 MMBo and 130 Bcf (totaling 26 MMBoe) and SCOOP PUD conversions totaled 2 MMBo and 81 Bcf (totaling 15 MMBoe).2021.
Given the continued volatility in crude oil prices during the year, we chose not to significantly advance the development of our oil-weighted properties in the SCOOP play in 2017, instead choosing to defer development capital in that play to future periods when prices become more stable and sustainable. Additionally, we deferred certain well completion activities in North Dakota Bakken in 2017 and our inventory of DUC wells that built up in that play in 2016 was not reduced to the extent originally planned for the year. These factors adversely impacted our conversion of PUD reserves to proved developed reserves in 2017.
At December 31, 2016, we had 95 MMBoe of PUD reserves associated with 279 gross (145 net) operated and non-operated DUC locations at that date. A portion of those locations, representing 18 MMBoe of PUD reserves, were not completed in 2017 and are not reflected as having been converted to proved developed reserves during the year and continue to be reflected as PUD locations at December 31, 2017. If the year-end 2016 DUC wells had been fully completed and converted to proved developed locations in 2017, our 2017 PUD reserve conversion rate of 14%would have been 17%.
Our inventory of DUC wells classified as PUDs total 278 gross (105 net) operated and non-operated locations at December 31, 2017, representing 70 MMBoe, or 10%, of our PUD reserves. The following table summarizes 2017 activity associated with DUC wells that are classified as PUD reserves.
  DUC Wells
  Gross Net PUD Reserves
(MBoe)
DUC wells at December 31, 2016 279
 145
 95,272
Wells converted to proved developed reserves (203) (110) (75,274)
Wells added 209
 72
 51,306
Revisions (7) (2) (1,707)
DUC wells at December 31, 2017 278
 105
 69,597
Development plans. We have acquired substantial leasehold positions in the Bakken, SCOOP and STACK plays.our key operating areas. Our drilling programs to date in thoseour 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, 20172021 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 $1.0$1.2 billion in 2018 (44% of total capital budget), $1.52022, $1.9 billion in 2019,2023, $1.7 billion in 2020, $1.52024, $1.7 billion in 2021,2025, and $0.7$1.2 billion in 2022.2026. These capital expenditure projections are reflective of the current commodity price environment and have been established based on an expectation of drilling and completion costs, available cash flows, borrowing capacity, and borrowing capacity.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, 2017, including those associated with DUC wells,2021 is expected
6

to occur within five years of the date of initial booking of the PUDs. PUD reserves not expected to be developeddrilled within five years of initial booking because of changes in business strategy depressed commodity prices, or for other reasons have been removed from our reserves at December 31, 2017.2021. We had no PUD reserves at December 31, 20172021 that remain undevelopedundrilled 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, 96%98% of our PV-10 and 96%98% of our total proved reserves as of December 31, 20172021 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 3337 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 President and certain other members of seniorexecutive management.
Proved Reserve,Reserves, Standardized Measure, and PV-10 Sensitivities
Our year-end 20172021 proved reserve,reserves, Standardized Measure, and PV-10 estimates were prepared using 20172021 average first-day-of-the-month prices of $51.34$66.56 per Bbl for crude oil and $2.98$3.60 per MMBtu for natural gas ($47.0362.19 per Bbl for crude oil and $3.00$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, 20172021 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 demonstrate the impact that changing commodity prices may have on estimateddo not take into account a potential increase in our drilling activities and associated booking of additional proved reserves Standardized Measure, and PV-10that may occur at higher commodity prices and there is no assurance thesethe 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 variouscertain crude oil price scenarios, with natural gas prices being held constant at the 20172021 average first-day-of-the-month price of $2.98$3.60 per MMBtu.

7


clr-20211231_g2.jpg
8



The natural gas price sensitivities provided below show the impact on proved reserves, Standardized Measure, and PV-10 under variouscertain natural gas price scenarios, with crude oil prices being held constant at the 20172021 average first-day-of-the-month price of $51.34 $66.56per Bbl.

clr-20211231_g3.jpg

9

Developed and Undeveloped Acreage
The following table presents our total gross and net developed and undeveloped acres by region as of December 31, 2017:2021:
 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 
  Developed acres Undeveloped acres Total
  Gross Net Gross Net Gross Net
North Region:            
Bakken field            
North Dakota Bakken 951,645
 556,044
 147,513
 90,288
 1,099,158
 646,332
Montana Bakken 170,899
 137,594
 30,059
 17,601
 200,958
 155,195
Red River units 158,967
 139,418
 26,719
 13,124
 185,686
 152,542
Other 102,542
 66,399
 94,454
 68,597
 196,996
 134,996
South Region:            
SCOOP 230,799
 133,756
 260,257
 143,116
 491,056
 276,872
STACK 211,836
 118,563
 177,563
 93,846
 389,399
 212,409
Other 67,734
 32,928
 71,250
 33,067
 138,984
 65,995
East Region 449
 404
 161,935
 138,799
 162,384
 139,203
Total 1,894,871
 1,185,106
 969,750
 598,438
 2,864,621
 1,783,544

The following table sets forth the number of gross and net undeveloped acres as of December 31, 20172021 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 
10
  2018 2019 2020
  Gross Net Gross Net Gross Net
North Region:            
Bakken field            
North Dakota Bakken 20,557
 12,742
 2,890
 1,544
 29,318
 20,170
Montana Bakken 14,713
 9,489
 400
 400
 —
 —
Red River units 5,617
 3,318
 2,879
 1,365
 —
 —
Other 9,264
 5,849
 20,097
 13,877
 4,520
 1,795
South Region:            
SCOOP 75,650
 41,718
 68,307
 37,774
 51,635
 31,767
STACK 40,196
 22,346
 72,528
 38,450
 31,777
 17,782
Other 1,840
 504
 28,258
 12,251
 23,513
 11,986
East Region 6,947
 6,292
 55,347
 40,336
 11,728
 10,164
Total 174,784
 102,258
 250,706
 145,997
 152,491
 93,664




Drilling Activity
During the three years ended December 31, 2017,2021, we drilledparticipated in the drilling and completedcompletion of exploratory and development wells as set forth in the table below:
below.
 202120202019
 GrossNetGrossNetGrossNet
Exploratory wells:
Crude oil11 8.0 1 — 2 1.6 
Natural gas2 1.9 1 — 4 1.8 
Dry holes— — 1 0.9 — — 
Total exploratory wells13 9.9 3 0.9 6 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 
  2017 2016 2015
  Gross Net Gross Net Gross Net
Exploratory wells:            
Crude oil 34
 9.0
 39
 11.4
 28
 19.8
Natural gas 9
 3.1
 15
 4.2
 19
 1.4
Dry holes —
 —
 —
 —
 1
 1.0
Total exploratory wells 43
 12.1
 54
 15.6
 48
 22.2
Development wells:            
Crude oil 474
 175.4
 245
 54.7
 707
 215.5
Natural gas 91
 26.8
 66
 21.6
 142
 32.8
Dry holes —
 —
 —
 —
 —
 —
Total development wells 565
 202.2
 311
 76.3
 849
 248.3
Total wells 608
 214.3
 365
 91.9
 897
 270.5
As of December 31, 2017,2021, there were 475393 gross (179(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 20182022 in our key operating areas. Our 20182022 capital budget, has been set based on an expectationour 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, in order to minimizeunbudgeted acquisitions, actual drilling and completion results, the incurrenceavailability of new debt. If cash flows are materially impacted by a declinedrilling and completion rigs and other services and equipment, the availability of transportation and processing capacity, changes in commodity prices, we have the ability to reduceand regulatory, technological and competitive developments. We monitor our capital expenditures or utilize the availability of our revolving credit facility if needed to fund our operations. Conversely, higherspending closely based on actual and projected cash flows resulting from an increase inand may scale back our spending should commodity prices could result in increased capital expenditures.materially decrease from current levels.
The following table provides information regarding well counts and 2018 budgeted capital expenditures by operating area.
for 2022.
  2018 Plan
  Gross wells (1) Net wells (1) Capital expenditures 
(in millions) (2)
  
North Region:      
Bakken 415
 143
 $1,193
South Region:      
SCOOP 160
 44
 465
STACK and Other 181
 38
 330
Total exploration and development drilling 756
 225
 $1,988
Land     132
Capital facilities, workovers and other corporate assets     168
Seismic     12
Total 2018 capital budget, excluding acquisitions     $2,300
 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 
Seismic6 
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 2018.2022.
(2) Represents total capital expenditures for operated and non-operated wells expected to have first production in 20182022 and wells spud that will be in the process of drilling, completing or waiting on completion as of year-end 2018.2022.

11


(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 50%46% of our total proved reserves as of December 31, 20172021 and 61%55% of our average daily Boe production for the fourth quarter of 2017. Our average daily production from such properties was 175,563Boe per day for the fourth quarter of 2017, an increase of 48% from the comparable 2016 period due to increased drilling and completion activities in 2017.2021. Our principal producing properties in the North region are primarily located in the Bakken field.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 premierlargest crude oil resource plays in the United States. We are a leading producer, leasehold owner and operator in the Bakken. As of December 31, 2017,2021, we controlled one of the largest leasehold positions in the Bakken with approximately 1.31.2 million gross (801,500(771,900 net) acres under lease.
Our total Bakken production averaged 165,598175,585 Boe per day for the fourth quarter of 2017, up 58%2021, down 4% from the 20162020 fourth quarter. For the year ended December 31, 2017,2021, our average daily Bakken production increased 12% over 2016. We increased our7% compared to 2020, reflecting the impact of voluntary production curtailments in 2020 and additional drilling and well completion activities in the Bakken in 2017, particularly in the second half of the year, in response to stabilization and improvement in crude oil prices.2021. In 2017,2021, we participated in the drilling and completion of 370252 gross (145(102 net) wells in the Bakken compared to 192188 gross (38(77 net) wells completed in 2016.2020. Our 20172021 activities in the Bakken focused on ongoing multi-zone unit development of de-risked, higher rate-of-return areas in core partsareas of North Dakota and the testing of various optimized completion methods aimed at improving crude oil recoveries and rates of return.play.
Our Bakken properties represented 48%43% of our total proved reserves at December 31, 20172021 and 58%52% of our average daily Boe production for the 20172021 fourth quarter. Our total proved Bakken field reserves as of December 31, 20172021 were 636708 MMBoe, an increase of 7%39% compared to December 31, 20162020 primarily due to reserves added from our drilling program continued improvement in recoveries driven by advances in optimized completion designs, and upward reserve revisions prompted by higherimproved commodity prices in 2017.prices. Our inventory of proved undeveloped drilling locations in the Bakken totaled 1,2521,254 gross (656(701 net) wells as of December 31, 2017.2021.
For 2022, our budget for exploration and development capital expenditures in the Bakken is $800 million. In response to the stabilization and improvement in crude oil prices in late 2017 and early 20182022, we plan to increase our activities in North Dakota Bakken in 2018 relative to 2017. In 2018, we plan to investaverage approximately $1.19 billion in the play, which includes $413 million for the completionsix operated rigs and initiation of production on operated Bakken wells that were drilled but not completed as of year-end 2017. We plan to operate, on average, six rigs in North Dakota Bakken throughout 2018, an increase from four rigs as of December 31, 2017. Additionally, we plan to use, on average, six to seventwo well completion crews in North Dakotathe Bakken throughout 2018, consistent with our current activity levels.and expect to have first production on 264 gross (116 net) operated and non-operated wells during the year. Our 20182022 drilling and completion activities in the Bakken will continue to focus on core parts of North Dakota Bakkenmulti-zone unit development in areas that provide opportunities to improve capital efficiency, reduce finding and development costs, and improve recoveries and rates of return.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 50%54% of our total proved reserves as of December 31, 20172021 and 39%45% of our average daily Boe production for the fourth quarter of 2017. For the 2017 fourth quarter, our average daily production from such properties was 111,422 Boe per day, an increase of 22% from the comparable period in 2016.2021. Our principal producing properties in the South region are located in the SCOOP and STACK areas of Oklahoma.
SCOOP
The SCOOP play currently extends across Garvin, Grady, Stephens, Carter, McClain and Love counties in Oklahoma and contains crude oil and condensate-rich fairways as delineated by numerous industry wells. our recently acquired properties in the Permian Basin of Texas.
Oklahoma
We are a leading producer, leasehold owner and operator in the SCOOP play.Oklahoma. As of December 31, 2017,2021, we controlled one of the largest leasehold positions in SCOOPOklahoma with approximately 491,100801,700 gross (276,900(448,300 net)acres under lease.
12

Our SCOOP leasehold has the potential to contain hydrocarbons from a variety of conventional and unconventional reservoirs overlying and underlying the Woodford formationproperties in Oklahoma. In recent years, our drilling activities have resulted in the vertical expansion of our SCOOP Woodford position with discoveries of the SCOOP Springer and Sycamore formations, which are located directly above the Woodford formation. Located in the heart of our SCOOP acreage, our Springer and Sycamore positions supplement our Woodford leasehold and expand our resource potential and inventory in the play. 

We engaged in limited drilling and completion activities in SCOOP in 2017, choosing instead to allocate capital to other areas that offered more advantageous opportunities and rates of return. Our 2017 activities in SCOOP focused on continued vertical and horizontal expansion of the productive extent and hydrocarbon content of the play and working to determine optimum well spacing, well patterns, and completion methods for future development.


SCOOPOklahoma represented 37%41% of our total proved reserves as of December 31, 20172021 and 22%43% of our average daily Boe production for the fourth quarter of 2017.2021. Production in SCOOPOklahoma averaged 62,242146,131 Boe per day during the fourth quarter of 2017,2021, down 2% compared to the 20162020 fourth quarter. For the year ended December 31, 2017,2021, average daily production in SCOOP decreased 7%Oklahoma increased 9% compared to 2016,2020, reflecting natural declinesthe impact of voluntary production curtailments in production2020 and limitedadditional drilling and completion activities in 2017.2021. We participated in the drilling and completion of 77161 gross (20(63 net) wells in SCOOPOklahoma during 20172021 compared to 72145 gross (28(54 net) wells in 2016. Proved2020. Our proved reserves in SCOOP totaled 492 MMBoeOklahoma as of December 31, 2017,2021 totaled 679 MMBoe, an increase of 4%18% compared to December 31, 20162020 primarily due to reserves added from our drilling program continued improvement in recoveries driven by advances in optimized completion designs, and upward reserve revisions prompted by higherimproved commodity prices in 2017.prices. Our inventory of proved undeveloped drilling locations in SCOOPOklahoma totaled 336313 gross (230(170 net) wells as of December 31, 2017.2021.
For 2022, our aggregate budget for exploration and development capital expenditures in Oklahoma is $400 million. In 2018,2022, we plan to invest approximately $465 million to drill, complete and initiate production on 160 gross (44 net) operated and non-operated wells in the SCOOP play. We plan to average approximately seven operated rigs and onetwo well completion crewcrews in SCOOP throughout 2018, an increase from five rigs as of December 31, 2017.Oklahoma and expect to have first production on 117 gross (41 net) operated and non-operated wells during the year. Our 2018 drilling program2022 activities will continue to focus on expanding the known productive extent of the SCOOP Woodford, Springer and Sycamore formations, while focusing oncontinued development in areas that provide opportunities for converting undeveloped acreage to acreage held by production, increasingimprove capital efficiency, reducingreduce finding and development costs, improve recoveries and improving rates of return.return, and maximize cash flows.
STACKPermian Basin
STACK is a significant resource play locatedProved reserves associated with our Permian Basin properties acquired in the Anadarko Basin of Oklahoma characterized by stacked geologic formations with major targets in the Meramec, Osage and Woodford formations. As of December 31, 2017, we controlled one of the largest leasehold positions in STACK with approximately 389,400 gross (212,400 net) acres under lease. A significant portion of our STACK acreage is located in over-pressured portions of Blaine, Dewey and Custer counties of Oklahoma where we believe the reservoirs are typically thicker and deliver superior production rates relative to normal-pressured areas of the STACK petroleum system.
Building on early success achieved from our initial STACK drilling activities in mid-2015, we significantly increased our leasing and drilling activities in the play in 2016 and 2017. Our 2017 activities focused on pilot density drilling to expand our understanding of the productive extent and hydrocarbon content of the play and to help determine optimum well spacing, well patterns, and completion methods for future development.
Through our 2016 and 2017 activities in STACK, we have successfully tested productive zones in the play, applied optimized completions to improve recoveries, demonstrated repeatability of results, reduced drilling times, reduced well costs, and de-risked a sizeable portion of our acreage in the play. Due to the success of these efforts, STACK has become another significant growth platform for us and is expected to be an important contributor to our long-term growth. To facilitate future development of our STACK acreage, we continue to increase our water recycling and distribution capabilities in the play. Additionally, we continue to increase our access to gathering and takeaway capacity to handle crude oil and natural gas production expected from future development of the play.
Our STACK properties represented 13%late 2021 totaled 203 MMBoe, representing 12% of our total proved reserves as of December 31, 2017 and 17% of2021. Production from our average daily Boe production for the fourth quarter of 2017. Production in STACK increased to an average rate of 47,914Permian properties averaged approximately 42,000 Boe per day based on two-stream reporting during the fourth quarterour short duration of 2017, up 96% over the 2016 fourth quarter dueownership from December 21, 2021 to additional drilling and completion activity resulting from our drilling program. For the year ended December 31, 2017, average daily production in STACK grew 113% over 2016. We participated2021.
For 2022, our budget for exploration and development capital expenditures in the drilling and completion of 160 gross (49 net) wells in STACK during 2017 compared to 97 gross (26 net) wells in 2016. Proved reserves increased 4% year-over-year to 167 MMBoe as of December 31, 2017 due to reserves added from our drilling program, continued improvement in recoveries driven by advances in optimized completion designs, and upward reserve revisions prompted by higher commodity prices in 2017. Our inventory of proved undeveloped drilling locations in STACK totaled 195 gross (90 net) wells as of December 31, 2017.
Permian Basin is $400 million. In 2018,2022, we plan to investaverage approximately $317 millionfour operated rigs and one well completion crew in the play and expect to drill, complete and initiatehave first production on 18049 gross (37(46 net) operated and non-operated wells in STACK. We plan to average approximately eight operated rigs in STACK throughout 2018 compared to nine rigs as of December 31, 2017. Additionally, we plan to use, on average, three completion crews in STACK throughout 2018 compared to five crews as of December 31, 2017. Our 2018 activities will focus on delineating and de-risking our acreage, expandingduring the known productive extent of the play through the completion of new density test projects, monitoring production from optimized completions, and continued refinement of our geologic and economic models in the area.

year.

13

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, 2017, 20162021, 2020 and 20152019 in total and for each field containing 15 percent or more of our total proved reserves as of December 31, 2017 (North Dakota Bakken2021.  
 Year ended December 31,
 202120202019
Net production volumes:
Crude oil (MBbls)
North Dakota Bakken40,121 40,052 52,420 
SCOOP11,318 12,585 11,679 
Total Company58,636 58,745 72,267 
Natural gas (MMcf)
North Dakota Bakken120,517 97,532 98,186 
SCOOP179,553 136,410 111,436 
Total Company370,110 306,528 311,865 
Crude oil equivalents (MBoe)
North Dakota Bakken60,207 56,308 68,784 
SCOOP41,244 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 $50.96 
SCOOP66.46 37.88 54.92 
Total Company64.06 34.71 51.82 
Natural gas ($/Mcf)
North Dakota Bakken$4.52 $0.23 $1.28 
SCOOP5.33 1.64 2.36 
Total Company4.88 1.04 1.77 
Crude oil equivalents ($/Boe)
North Dakota Bakken$51.21 $24.24 $40.66 
SCOOP41.44 19.90 29.80 
Total Company46.24 21.47 34.56 
Average costs per Boe:
Production expenses ($/Boe)
North Dakota Bakken$4.27 $4.35 $4.28 
SCOOP1.24 1.06 1.21 
Total Company3.38 3.27 3.58 
Production taxes ($/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 SCOOP). InformationAnalysis of Financial Condition and Results of Operations—Non-GAAP Financial Measures for the STACK field is also presented.  a discussion and calculation of net sales prices, which are non-GAAP measures.
14

  Year ended December 31,
  2017 2016 2015
Net production volumes:      
Crude oil (MBbls)      
North Dakota Bakken 35,964
 31,723
 37,539
SCOOP 5,726
 6,807
 7,198
STACK 3,166
 1,552
 245
Total Company 50,536
 46,850
 53,517
Natural gas (MMcf)      
North Dakota Bakken 59,232
 50,532
 47,425
SCOOP 98,563
 102,032
 91,687
STACK 60,325
 27,983
 10,704
Total Company 228,159
 195,240
 164,454
Crude oil equivalents (MBoe)      
North Dakota Bakken 45,836
 40,145
 45,444
SCOOP 22,153
 23,813
 22,479
STACK 13,220
 6,216
 2,029
Total Company 88,562
 79,390
 80,926
Average sales prices:      
Crude oil ($/Bbl)      
North Dakota Bakken $45.21
 $34.33
 $39.76
SCOOP 47.96
 38.87
 43.98
STACK 49.68
 41.95
 41.23
Total Company 45.70
 35.51
 40.50
Natural gas ($/Mcf)      
North Dakota Bakken $2.97
 $1.05
 $2.34
SCOOP 3.26
 2.24
 2.39
STACK 2.43
 1.87
 2.06
Total Company 2.93
 1.87
 2.31
Crude oil equivalents ($/Boe)      
North Dakota Bakken $39.32
 $28.45
 $35.29
SCOOP 26.93
 20.71
 23.81
STACK 22.89
 18.88
 15.87
Total Company 33.65
 25.55
 31.48
Average costs per Boe:      
Production expenses ($/Boe)      
North Dakota Bakken $4.40
 $4.59
 $4.79
SCOOP 1.01
 1.13
 1.10
STACK 1.22
 1.00
 3.52
Total Company 3.66
 3.65
 4.30
Production taxes ($/Boe) $2.35
 $1.79
 $2.47
General and administrative expenses ($/Boe) $2.16
 $2.14
 $2.34
DD&A expense ($/Boe) $18.89
 $21.54
 $21.57


The following table sets forth information regarding our average daily production by region for the fourth quarter of 2017:2021:
 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 
  Fourth Quarter 2017 Daily Production
  Crude Oil
(Bbls per day)		 Natural Gas
(Mcf per day)		 Total
(Boe per day)
North Region:      
Bakken field      
North Dakota Bakken 124,811
 202,975
 158,640
Montana Bakken 5,497
 8,761
 6,958
Red River units      
Cedar Hills 6,830
 1,154
 7,022
Other Red River units 2,073
 2,410
 2,475
Other 82
 2,318
 468
South Region:      
SCOOP 14,551
 286,148
 62,242
STACK 13,788
 204,754
 47,914
Other 434
 4,998
 1,266
Total 168,066
 713,518
 286,985
(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, 2017.2021.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 7 5 242 148 
Red River Units267 251 — — 267 251 
South Region:
Oklahoma1,214 521 943 304 2,157 825 
Permian Basin409 318 2 1 411 319 
Other2 2 23 2 25 4 
Total7,737 3,232 975 312 8,712 3,544 
15
  Crude Oil Wells Natural Gas Wells Total Wells
  Gross     Net     Gross     Net     Gross     Net    
North Region:            
Bakken field            
North Dakota Bakken 4,083
 1,313
 —
 —
 4,083
 1,313
Montana Bakken 401
 263
 —
 —
 401
 263
Red River units           

Cedar Hills 135
 130
 —
 —
 135
 130
Other Red River units 131
 117
 —
 —
 131
 117
Other 8
 4
 18
 4
 26
 8
South Region:           
SCOOP 248
 145
 372
 115
 620
 260
STACK 172
 62
 282
 98
 454
 160
Other 139
 110
 167
 65
 306
 175
Total 5,317
 2,144
 839
 282
 6,156
 2,426

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 final 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. WeCompany landmen may also procure an acquisition title opinion from outside legal counsel on higher value properties.


Prior to the commencement of drilling operations, weCompany 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 defects,issues, if any. WeCompany landmen will not approve commencement of drilling operations until we have cured material title defects pertaining to the Company’s interest.interest are cured.
We have procured title opinions andThe Company has cured material defectstitle opinion issues as to Company interests on substantially all of ourits producing properties and believe we havebelieves it holds at least defensible title to ourits producing properties in accordance with standards generally accepted in the crude oil and natural gas industry. OurThe Company’s crude oil and natural gas properties are subject to customary royalty and leasehold burdens which do not materially interfere with the use ofCompany’s interest in the properties or affect ourthe Company’s carrying value of such properties.
Marketing and Major Customers
MostWe sell most of our operated crude oil production is sold to either crude oil refining companies or midstream marketing companies at major market centers. Other operated production not sold at major market centers is sold at the lease. 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 balance of production being primarily transported by truck. Additionally in the Bakken, a portion of our production is sold to counterparties that are connected to rail delivery systems. Where directly marketed crude oil is transported by truck it is delivered 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 or is delivered directlysystems and may choose those methods to a refinery. Wheretransport the oil they have purchased from us. We sell some operated crude oil is soldproduction at the lease the sale is complete at that point.lease. Our share of crude oil production from non-operated properties is marketed at the discretion of the operators.
The majorityWe sell most of our operated natural gas production is soldto midstream customers at our lease locations to midstream purchasers under term contracts.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 dedication. Some of our contracts allow usdedications. Under certain arrangements, we have the flexibilityright to accept, as partial payment for our sale of gas in the field, an “in-kind”take a volume of processed residue gas and/or natural gas liquids ("NGLs") in-kind at the tailgate of the midstream purchaser’scustomer's processing plant.plant in lieu of a monetary settlement for the sale of our operated natural gas production. When we electdo take volumes in kind, we pay third parties to do so,transport the residue gas volumes taken in kind to downstream delivery points, where we transport this processed gasthen sell to acustomers at prices applicable to those downstream market where it is sold.markets. Sales at thesethe downstream markets are mostly under daily and monthly interruptible packaged volumevolumes deals, shortshorter 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 gasproducts we elect to take in-kind in lieu of cashmonetary 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 marketingenvironmental stewardship strategies, policies, and efforts are monitored by our Board of crude oilDirectors’ Nominating, Environmental, Social and natural gas can be affected by factors beyondGovernance Committee (“Committee”), which is the primary Committee responsible for overseeing and managing our control, the effects of which cannot be accurately predicted. For a description of some of these factors, see Part I, Item 1A. Risk factors—Our business depends on crude oil and natural gas transportation, processing and refining facilities, most of which are owned by third parties.
For the year ended December 31, 2017, sales to BP p.l.c. and affiliates and Phillips 66 and affiliates accounted for approximately 11% and 11%, respectively,ESG initiatives in respect of our total crude oilbusiness goals. Our focus on continuous improvement in ESG performance has resulted in sustained, year-over-year decreases since 2016 in both greenhouse gas and naturalmethane intensities. From 2019 through 2020, the most recent reporting year, we achieved a 28% decrease in greenhouse gas revenues. No other purchaser accounted for more than 10% of our total crude oilintensity and natural gas revenues for 2017. The loss of any single purchaser will not have a material adverse effect on our operations, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers34% decrease in various regions.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, which can be particularly important in the areas in which we operate.ours. Those companies may be able to pay more for productive crude oil and
16

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 the significant decrease indepressed 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
OurAll of our operations are conducted onshore almost entirely 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 on us and other industry participants.requirements. These laws, regulations and other requirements often carry substantial penalties for failure to comply and may have a significant effect on the exploration, development, production or sale of crude oilour operations and natural gas andmay increase the cost of doing business and affectreduce 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 any future legislative or regulatory initiatives will affect us in a manner materially different than they wouldwill 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
Sales of crude oil and natural gas liquids (“NGLs”) or condensate in the United States are not currently subject to price controls and are made at negotiated prices. Nevertheless, the U.S. Congress could enact price controls in the future. Beginning in the 1970s, the United States regulated the exportation of petroleum and petroleum products, which restricted the markets for these commodities and affected sales prices. However, in December 2015 the U.S. Congress passed a legislative bill eliminating the export restrictions beginning in January 2016.
With regard to ourOur physical sales of crude oil and any derivative instruments relating to crude oil we are requiredsubject to comply with anti-market manipulation laws and related regulations enforced by the Federal Trade Commission (“FTC”) and the Commodity Futures Trading Commission (“CFTC”). SeeThese laws, among other things, prohibit fraudulent or deceptive conduct in connection with wholesale purchases or sales of crude oil and price manipulation in the discussion below of “Other Federal Lawscommodity and Regulations Affecting Our Industry—FTC and CFTC Market Manipulation Rules.”futures markets. If we violate the anti-market manipulation laws and regulations, we couldcan be subject to substantial penalties and related third-party damage claims by, among others, sellers, royalty owners and taxing authorities.
OurWe 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 NGLs, as well as other liquid products,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 the rules and regulations promulgated under those laws. In general, pipeline rates must be just and reasonable and must not be unduly discriminatory or confer any undue preference upon any shipper. Oil and other liquid pipeline rates are often cost-based, although some pipeline charges today are based on historical rates adjusted for inflation and other factors, and other charges may result from settlement rates agreed to by all shippers or market-based rates, which are permitted in certain circumstances. FERC or interested persons may challenge existing or changed rates or services. Intrastateintrastate crude oil and NGL pipeline transportation rates may be subject to regulation by state regulatory commissions. The basis for intrastate pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate crude oil pipeline rates, varies from state to state. As the interstate and intrastate transportation rates we pay are generally applicable to all comparable shippers, the regulation of intrastatesuch 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.
We transportFrom time to time we may sell our operated crude oil production from our North region toat market centers using primarilyin 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 combination1% improvement in the efficiency of pipelinefleets each year between 2015 and rail transportation facilities owned2025. 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 operated by third parties. Approximately 6% of such production was shipped by rail in December 2017,maintain compliance with the remainder being shipped primarily by pipeline. The U.S. Department of Transportation’s (“U.S. DOT”) Pipelinenew regulations, it is expected ship owners will either have to switch to more expensive higher quality marine fuel, install and Hazardous Materials Safety Administration (“PHMSA”) establishes safety regulations relatingutilize
17

emissions-cleaning systems, or switch to transportation of crude oil by rail and pipeline. Third party rail operators are subject to the regulatory jurisdiction of the Surface Transportation Board of the U.S. DOT, the Federal Railroad Administration (“FRA”), the U.S. Occupational Safety and Health Administration ("OSHA"), and other federal regulatory agencies. Additionally, various state and local agencies have jurisdiction over disposal of hazardous waste and regulate movement of hazardous materials if not preempted by federal law.
In 2008, the U.S. Congress passed the Rail Safety and Improvement Act, which implemented regulations governing different areas related to railroad safety. Subsequently, the FRA and PHMSA have taken several actions related to the transport of crude


oil, including but not limited to: issuing an order requiring testing, classification and handling of crude oilalternative fuels such as a hazardous material; requiring expanded hazardous material route planning for railroads to avoid populated and other sensitive areas; issuing safety advisories, alerts, emergency orders and regulatory updates; conducting special unannounced inspections; issuing rules to enhance tank car standards for certain trains carrying crude oil and ethanol; and reaching agreement with the railroad industry on a series of voluntary actions it can take to improve safety. In May 2014 the U.S. DOT issued an order requiring all railroads operating trains containing large amounts of Bakken crude oil to notify state emergency response commissions about the operation of such trains through their states. The order requires each railroad operating trains containing more than 1,000,000 gallons of Bakken crude oil, or approximately 35 tank cars, in a particular state to provide the state with notification regarding the volumes of Bakken crude oil being transported, frequencies of anticipated train traffic and the route through which Bakken crude oil will be transported.  Also in May 2014, the FRA and PHMSA issued a safety advisory to the rail industry strongly recommending the use of tank cars with the highest level of integrity in their fleet when transporting Bakken crude oil. In May 2015, PHMSA published a final rule which requires, among other things, enhanced tank car standards for new and existing tank cars, a classification and testing program for crude oil, and a requirement that older DOT-111 tank cars be retrofittedliquefied natural gas. Failure to comply with new tank car design standardsthe regulations may result in accordance withfines or shipping vessels being detained, thereby resulting in exportation capacity constraints that inhibit a specified timeline beginning as early as January 1, 2018. However, in December 2017 PHMSA announced it would initiate a rulemaking to rescind the May 2015 rule's requirements regarding electronically controlled pneumatic brakes. In August 2016, PHMSA released a final rule mandating a phase-out schedule for all DOT-111 tank cars usedthird party's ability to transport Class 3 flammable liquids between 2018 and 2029. Separately, in July 2016 PHMSA proposed a new rule to expand the applicability of comprehensivesell domestic crude oil spill response plans so that any railroad transporting a single train carrying 20 or more loaded tank cars of liquid petroleum oil in a continuous block or a single train carrying 35 or more loaded tank cars of liquid petroleum oil throughout the train mustproduction overseas, which may have a current, comprehensive, written plan. Issuancematerial impact on the markets and prices for various grades of domestic and international crude oil. The ultimate long-term impact of the final rule remains pending.IMO regulations is uncertain.
We do not own or operate pipeline or rail transportation facilities, rail cars, or rail cars; however,infrastructure used to facilitate the exportation of crude oil. However, regulations that impact the testing or raildomestic 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, which could have a material adverse effect on our financial condition, results of operations and cash flows.States. We do not expect such regulations will affect us in a materially different way than similarly situated competitors.
In June 2016 the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act (“PIPES Act”) was signed into law. The PIPES Act extends PHMSA’s safety authority through 2019 and includes provisions on advancing the safe transportation of energy commodities and other hazardous materials. The PIPES Act includes provisions aimed at increasing inspection requirements for certain underwater crude oil pipelines; improving protection of coastal areas by designating them as environmentally sensitive to pipeline failures; setting minimum safety standards for underground natural gas storage facilities, and promoting better use of data and technology to prevent damage and improve safety of pipeline systems, among other things. PHMSA published a final rule in January 2017 expanding integrity management and reporting requirements for certain hazardous liquid pipelines and gathering lines; however, implementation of the final rule was stayed following the change in U.S. Presidential Administrations. The final rule is expected to be published in the federal register during the first quarter of 2018. We do not expect such regulations will affect us in a materially different way than similarly situated competitors.
Pipeline regulations exist at the state level as well. In December 2014 the North Dakota Industrial Commission (“NDIC”) introduced rules designed to reduce the potential flammability of crude oil produced from the Bakken petroleum system (the Bakken, Three Forks, and Sanish Pool formations) before it is loaded and transported on railcars. The rules became effective in April 2015 and outline a series of standards for pressure and temperature for production facilities to follow in order to separate certain liquids and gases from the crude oil prior to transport. These rules do not affect us in a way that materially differs from our similarly situated competitors.
Regulation of sales and transportation of natural gas
In 1989,We are also required to observe the U.S. Congress enactedaforementioned anti-market manipulation laws and related regulations enforced by the Natural Gas Wellhead Decontrol Act, which removed all remaining priceFERC and non-price controls affecting wellheadCFTC in connection with physical sales of natural gas and any derivative instruments relating to natural gas. The FERC, which hasAdditionally, the authority under the Natural Gas Act (“NGA”) to regulate prices, terms, and conditions for the sale of natural gas for resale in interstate commerce, has issued blanket authorizations for all gas resellers subject to FERC regulation, except interstate pipelines, to resell natural gas at market prices. However, either the U.S. Congress or the FERC (with respect to the resale of gas in interstate commerce) could re-impose price controls in the future. 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.


The FERC regulates interstate natural gas transportation rates and service conditions under the NGANatural Gas Act and the Natural Gas Policy Act of 1978, (“NGPA”), 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. The FERC has stated open access policies are necessary to improve the competitive structure of the natural gas pipeline industrybasis and to create a regulatory framework to put natural gas sellers into more direct contractual relations with natural gas buyers by, among other things, unbundling the sale of natural gas from the sale of transportation and storage services. The FERC has issued a series of orders to implement its open access policies. As a result, the interstate pipelines’ traditional role as wholesalers of natural gas has been eliminated and replaced by a structure under which pipelines provide transportation and storage services on an open access basis to others who buy and sell natural gas. Although the FERC’s orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry. 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.
With regard to our physical salesThe gathering of natural gas, and derivative instruments relating to natural gas, we are required to observe anti-market manipulation laws and related regulations enforced by the FERC and the CFTC. See the discussion below of “Other Federal Laws and Regulations Affecting Our Industry—FTC and CFTC Market Manipulation Rules.” If we violate the anti-market manipulation laws and regulations, we could be subject to substantial penalties and related third-party damage claims by, among others, sellers, royalty owners and taxing authorities. In addition, pursuant to various FERC orders, we may be required to submit reports to the FERC for some of our operations. See the discussion below of “Other Federal Laws and Regulations Affecting Our Industry—FERC Market Transparency and Reporting Rules.”
Gathering service, 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 costs of movingpurchasers and reduce the revenues we receive for our natural gas to point of sale locations.stream. State regulation of natural gas gathering facilities generally includes various safety, environmental, and in some circumstances, equitable take requirements. Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels in the future. We cannot predict what effect, if any, such changes may have on us, but the natural gas industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes, including changes in the interpretation of existing requirements or programs to implement those requirements. We do not believe we would be affected by any such regulatory changesregulations 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 and ship natural gas on an intrastate basis 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 statutes,laws, rules, orders 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.
18

The failure to comply with thesethe above laws, rules, and regulations can result in substantial penalties. Our similarly situated competitors are generally subject to the same statutes, regulatory requirements and restrictions.


Other federal laws, and regulations affecting our industry
Dodd-Frank Wall Street Reform and Consumer Protection Act. In July 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) was enacted into law. The Dodd-Frank Act established federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The Dodd-Frank Act requires the CFTC, the SEC, and other regulators to establish rules, and regulations to implement the new legislation. Although the CFTC has issued final regulations to implement significant aspects of the legislation, others remain to be finalized or implemented and it is not possible at this time to predict when this will be accomplished. Additionally, certain aspects of the Dodd-Frank Act were repealed by the U.S. Congress in 2017.
In November 2013 and December 2016, the CFTC proposed rules establishing position limits with respect to certain futures and option contracts and equivalent swaps, subject to exceptions for certain bona fide hedging. As these new position limit rules are not yet final, the impact of these provisions on us is uncertain at this time.
Pursuant to the Dodd-Frank Act, absent an exception, mandatory clearing is now required for all market participants. The CFTC has designated certain interest rate swaps and credit default swaps for mandatory clearing. The CFTC has not yet required the clearing of any other classes of swaps, including physical commodity swaps, and the trade execution requirement does not apply to swaps not subject to a clearing mandate. Althoughas we expect to qualify for the end-user exception from the clearing requirement for our swaps entered into to hedge our commercial risks, the application of the mandatory clearing requirements to other market participants, such as swap dealers, along with changes to the markets for swaps as a result of the trade execution requirement, may change the cost and availability of the swaps we use for hedging. If any of our swaps do not qualify for the commercial end-user exception, or if the cost of entering into uncleared swaps becomes prohibitive, we may be required to clear such transactions or execute them on a derivatives contract market or swap execution facility. The ultimate effect of the proposed rules and any additional regulations on our business is uncertain.
In December 2015, the CFTC issued final rules establishing minimum margin requirements for uncleared swaps for swap dealers and major swap participants. The final rules do not impose margin requirements on commercial end users. Although we expect to qualify for the end-user exception from the margin requirements for swaps entered into to hedge our commercial risks, the application of such requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps we use for hedging. If any of our current or future swaps do not qualify for the commercial end-user exception, the posting of collateral could reduce our liquidity and cash available for capital expenditures and could reduce our ability to manage commodity price volatility and the volatility in our cash flows.
In addition to the CFTC’s swap regulations, certain foreign jurisdictions may adopt or implement laws and regulations relating to transactions in derivatives, including margin and central clearing requirements, which in each case may affect our counterparties and the derivatives markets generally. Other rules may alter the business practices of some of our counterparties and in some cases may cause them to stop transacting in or making markets in derivatives. Moreover, federal banking regulators are reevaluating the authorization under which banking entities subject to their authority may engage in physical commodities transactions.
Although we cannot predict the ultimate outcome of these rulemakings, they could result in increased costs and cash collateral requirements for the types of derivative instruments we use or otherwise limit our ability to manage our financial and commercial risks related to fluctuations in commodity prices. Additional effects of the regulations, including increased regulatory reporting and recordkeeping costs, increased regulatory capital requirements for our counterparties, and market dislocations or disruptions could have an adverse effect on our ability to hedge risks associated with our business.
Energy Policy Act of 2005. The Energy Policy Act of 2005 (“EPAct 2005”) included a comprehensive compilation of tax incentives, authorized appropriations for grants and guaranteed loans, and made significant changes to the statutory framework affecting the energy industry. For example, EPAct 2005 amended the NGA to add an anti-market manipulation provision making it unlawful for any entity to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of natural gas or the purchase or sale of transportation services subject to regulation by the FERC, in contravention of rules prescribed by the FERC. In January 2006 the FERC issued rules implementing the anti-market manipulation provision of EPAct 2005. These anti-market manipulation rules apply to natural gas pipelines and storage companies which provide interstate services, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” natural gas sales, purchases or transportation subject to FERC jurisdiction, which now includes the annual reporting requirements described further below. The EPAct 2005 also provides the FERC with the power to assess civil penalties of up to $1,000,000 per day per violation for violations of the NGA and NGPA and disgorgement of profits associated with any violation.
FERC Market Transparency and Reporting Rules. The FERC requires wholesale buyers and sellers of more than 2.2 million MMBtus of physical natural gas in the previous calendar year to report, on May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices. The FERC also requires market participants to indicate whether they report prices


to any index publishers and, if so, whether their reporting complies with the FERC’s policy statement on price reporting. Failure to comply with these reporting requirements could subject us to enhanced civil penalty liability under the EPAct 2005.
FTC and CFTC Market Manipulation Rules. Wholesale sales of petroleum are subject to provisions of the Energy Independence and Security Act of 2007 (“EISA”) and regulations by the FTC. Under the EISA, the FTC issued its Petroleum Market Manipulation Rule (the “Rule”), which became effective in November 2009. The Rule prohibits fraudulent or deceptive conduct (including false or misleading statements of material fact) in connection with wholesale purchases or sales of crude oil or refined petroleum products. Under the EISA, the FTC has authority to request a court to impose fines of up to $1,000,000 per day per violation. The CFTC has also adopted anti-market manipulation regulations prohibiting, among other things, fraud and price manipulation in the commodity and futures markets. The CFTC may assess fines of up to the greater of $1,000,000 or triple the monetary gain for violations of these anti-market manipulation regulations. Knowing or willful violations of the Commodity Exchange Act is also a felony.
Additional proposals and proceedings potentially affecting the crude oil and natural gas industry are brought before the U.S. Congress, the FERC and the courts from time to time. We cannot predict the ultimate impact these or the above laws and regulations may have on our crude oil and natural gas operations. We do not believe we will be affected in a materially different way than our similarly situated competitors.are.
Environmental regulation
General. We are subject to stringent, complex, and complexoverlapping 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 crude oil and natural gas 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 belowto a rate otherwise possible.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 U.S. Congressname of combatting climate change, President Biden has issued, and federal and state agencies frequently revise environmental laws, rules and regulations, and any changesmay 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 requirements for the crude oil and natural gas industry could have a significant impact on our operating costs.
In March 2017, President Donald Trump issued an Executive Order titled “Promoting Energy Independencecosts and Economic Growth” (the "March 2017 Executive Order") which states it is in the national interestproduction of the United States to promote clean and safe development of energy resources, while at the same time avoiding regulatory burdens that unnecessarily encumber energy production, constrain economic growth, and prevent job creation. The March 2017 Executive Order requires, among other things, the executive department and agencies to review existing regulations that potentially burden the development or use of domestically produced energy resources (with particular attention to crude oil, natural gas, coal, and nuclear energy) and suspend, revise, or rescind those regulations that unduly burden the development of such resources beyond the degree necessary to protect the public interest or otherwise comply with the law. In response to the March 2017 Executive Order, certain energy and climate-related regulations proposed or enacted under previous presidential administrations have been, or are in the process of being, reviewed, suspended, revised, or rescinded, some of which are described further below. Numerous regulations impacting the crude oil and natural gas industry are not expected to be impacted by the March 2017 Executive Order and will continue to be in effect. Additionally, undoing previously existing environmental regulations will likely involve lengthy notice-and-comment rulemaking and the resulting decisions may then be subject to litigation by opposition groups. Thus, it could take several years before existing regulations are revised or rescinded. Although further regulation of our industry may stall at the federal level under the March 2017 Executive Order, certain states have pursued additional regulation of our operations and other states may do so as well.
Environmental laws, rules and regulations. Some of the existing environmental laws, rules and regulations we are subject to include: (i) regulations by the U.S. Environmental Protection Agency (“EPA”) and various state agencies regarding approved methods of disposal for certain hazardous and nonhazardous wastes; (ii) the federal Comprehensive Environmental Response,


Compensation, and Liability Act and analogous state laws that may require the removal of previously disposed hazardous substances (including hazardous substances disposed of or released by prior owners or operators), the cleanup of property contamination (including groundwater contamination), and remedial lease restoration activities to prevent future contamination from prior operations; (iii) federal Department of Transportation safety laws and comparable state and local requirements; (iv) the federal Clean Air Act and comparable state and local requirements, which establish pollution control requirements for air emissions from our operations; (v) the federal Oil Pollution Act of 1990, which contains numerous requirements relating to the prevention of and response to oil spills into waters of the United States; (vi) the Federal Water Pollution Control Act, also known as the Clean Water Act, and analogous state laws which impose restrictions and strict controls with respect to the discharge of pollutants, including crude oil and other substances generated by our operations, into waters of the United States or state waters; (vii) the federal Resource Conservation and Recovery Act, which is the principal federal statute governing the treatment, storage and disposal of solid and hazardous wastes, and comparable state statutes; (viii) the federal Safe Drinking Water Act ("SDWA") and analogous state laws which impose requirements relating to our underground injection activities; (ix) the National Environmental Policy Act and comparable state statutes, which require government agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment; (x) the federal Endangered Species Act and comparable state statutes, which afford protections to certain plant and animal species; (xi) the federal Migratory Bird Treaty Act, which imposes certain restrictions for the protection of migratory birds; (xii) the federal Bald and Golden Eagle Protection Act, which imposes certain restrictions for the protection of bald and golden eagles; (xiii) the federal Emergency Planning and Community Right to Know Act and comparable state statutes, which require that we organize and/or disclose information about hazardous materials stored, used or produced in our operations, and (xiv) state regulations and statutes governing the handling, treatment, storage and disposal of technologically enhanced naturally occurring radioactive material.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 performanceexpansion of projects, the issuance of orders enjoining performance of some or all of our operations, and potential litigation.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 and climate change. Federal, state, and local laws, rules, and regulations have been and, mayin 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 effects the emissionconstruction or modification of carbon dioxide, methanecertain projects or facilities expected to produce or significantly increase air emissions, obtain and other identified “greenhouse gases” may have on the environment and climate worldwide, generally referredstrictly comply with stringent air permit standards or utilize specific equipment or technologies to as “climate change.”control emissions of certain pollutants. For example, in October 20152021, the EPA revisedU.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 ozone from 75 to 70 parts per billion for both the 8-hour primary and secondary standards. The EPA published a final rule in November 2017 that issued area designations with respect to ground-level ozone, for approximately 35% ofwhich was last set by the U.S. counties, including all of the counties in North Dakota and all of the counties except for Bryan County in Oklahoma, as either “attainment/unclassifiable” or “unclassifiable” and is expected to issue attainment or nonattainment designations for the remaining areas of the U.S. not addressedEPA under the November 2017 ruleObama Administration in the first half of 2018. Additionally, state2015. State implementation of thea revised NAAQS for ground-level ozone could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits, andor result in increased expenditures for pollution control equipment, the costs of which could be significant.
Regulation of greenhouse gas emissions. The EPA has also adopted regulations underthreat 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 provisionsemissions 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 federal Clean Air Actoil 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.
19

Federal regulatory initiatives have focused on establishing among other things, Prevention of Significant Deterioration (“PSD”) pre-constructionconstruction and Title V operating permit reviews for greenhouse gas emissions from certain large stationary sources. Moreover, the EPA’s source determination rule specifies that oil and gas production facilities are considered to be “adjacent” (and therefore aggregated for air permitting purposes) if they are on the same site or on sites that share equipment and are within ¼ mile of each other. This rule increases the potential for individual well facilities to be viewed collectively by the EPA as a single, large stationary source and, therefore, subject to PSD and/or Title V.  Regulations related to greenhouse gas emissions could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources.
In addition, the EPA has adopted rulessources, requiring the monitoring and annual reporting of greenhouse gas emissions from specified onshore and offshore oil and gas production sources in the United States on an annual basis, which include certain of our operations. New Source Performance Standard (“NSPS”) Subpart OOOO (“Quad O”) requires, among other things, the reduction of volatile organic compound (“VOC”) emissions from three subcategories of fractured and refractured oil and gas wells for which well completion operations are conducted: wildcat (exploratory) and delineation gas wells; low reservoir pressure non-wildcat and non-delineation gas wells; and all “other” fractured and refractured oil and gas wells. All three subcategories of wells must route flowback emissions to a gathering line or be captured and combusted using a combustion device such as a flare. However, the “other” fractured and refractured wells must use reduced emission completions or “green completions.” The rule also established specific new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other production equipment. The rule is designed to limit emissions of VOCs, sulfur dioxide, and hazardous air pollutants from a variety of sources within natural gas processing plants, oilpetroleum and natural gas production facilities,system sources, and natural gas transmission compressor stations. We have modified our operations and well equipment as needed to comply with these rules. Ongoing compliance with the rules is not expected to affect us in a way that materially differsreducing methane emissions from our similarly situated competitors.


In addition, in June 2016 the EPA finalized new regulations (NSPS Subpart OOOOa, commonly referred to as “Quad Oa”) setting methane emission standards for new and modified oil and gas production and natural gas processing and transmission facilitiesoperations 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 effortexecutive order calling on the EPA to reducerevisit federal regulations regarding methane emissions fromand establish new or more stringent standards for existing or new sources in the oil and gas sector, by up to 45% from 2012 levels by 2025 even though there was consensus atincluding the time that oiltransmission and gas producers’ compliance with Quad O had already achieved reductions in methane emissions.
However, in June 2017, the EPA proposed to stay certain portionsstorage segments. The U.S. Congress also passed, and President Biden signed into law, a revocation of the NSPS Quad Oa rules described above for a period of two years while2020 rulemaking, effectively reinstating the rules are reconsidered in2016 standards. In response to President Trump’s March 2017 Executive Order to reduce the burden of federal regulations that may hinder economic growth and energy development. The EPA has not yet published a final rule issuing the stay, and, as a result, the Quad Oa rules are currentlyBiden’s executive order, in effect but future implementation of the Quad Oa rules is uncertain at this time. As part of its reconsideration,November 2021 the EPA may issue revised rules, the timingissued a proposed rule that, if finalized, would establish Quad Ob new source and impactQuad Oc first-time existing source standards of which is uncertain.
Additional regulation with respect toperformance for methane emissions occurred in November 2016 when the U.S. Department of Interior’s Bureau of Land Management (“BLM”) published a final rule commonly referred to as the “BLM Venting and Flaring Rule.” Similar to Quad Oa, the BLM Venting and Flaring Rule imposes requirements related to methane emissions from crude oil and natural gas sources. However, in response to President Trump’s March 2017 Executive Order, in December 2017 the BLM announced it was temporarily suspending or delaying certain requirements contained in its Venting and Flaring Rule until January 2019. That suspension is now being challenged in court and future implementation and impact of the rule remains uncertain. While additional federal regulation with respect to methane emissions appears unlikely in the near future, states may nevertheless pursue rules or enforcement actions designed to reduce methane emissions. To the extent new methane emission regulations—whether it is the BLM Venting and Flaring Rule, a prospective EPA rule targeting methane emissions from existing sources, or a state agency—impose reporting obligations on, or limit emissions of greenhouse gases from, our equipment and operations they could require us to incur costs to reduce emissions associated with our operations, but the impact of these measures is not expected to be material and will not affect us in a materially different way from our similarly situated competitors.
At an international level, in December 2015 a global climate agreement was reached in Paris at the 21st Conference of Parties organized by the United Nations under the Framework Convention on Climate Change. The agreement, which goes into effect in 2020, resulted in nearly 200 countries, originally including the United States, committing to work towards limiting global warming and agreeing to a monitoring and review process of greenhouse gas emissions. The agreement includes binding and non-binding elements and did not require ratification by the U.S. Congress. In June 2017, President Trump announced the United States will withdraw from and cease implementation of the Paris climate agreement, but indicated the U.S. may re-engage in the agreement if more favorable terms can be re-negotiated. In August 2017, the U.S. State Department officially informed the United Nations of the intent of the United States to withdraw from the Paris climate agreement. The exit process provided for under the Paris agreement could take up to four years. The United States’ adherence to the exit process is uncertain and the terms on which the United States may reenter the Paris agreement or a separately negotiated agreement are unclear. Although the U.S. has ceased its participation in the Paris agreement, the agreement nonetheless may result in increased political pressure on the United States to ensure continued compliance with enforcement measures under the Clean Air Act and may spur further initiatives aimed at reducing greenhouse gasvolatile organic compound (VOC) emissions in the future.
While the U.S. Congress has from time to time considered legislation to reduce emissions of greenhouse gases, there has not been significant activity in the form of enacted legislation to reduce greenhouse gas emissions at the federal level in recent years. In the absence of such federal legislation, a number of state and regional efforts have emerged aimed at tracking and reducing greenhouse gas emissions by means of cap and trade programs that typically require major sources of greenhouse gas emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those greenhouse gases. There has also been discussion of imposing a federal carbon tax on all fossil fuel production, though such a tax appears unlikely at this time. Although it is not possible to predict how such legislation or new regulations adopted to address greenhouse gas emissions will impact our business, any future laws and regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations could require us to incur costs to reduce emissions of greenhouse gases associated with our operations. In addition, substantial limitations on greenhouse gas emissions could adversely affect the demand for the crude oil and natural gas we producesource category. This proposed rule would apply to upstream and lower the valuemidstream 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 our reserves. Finally, some scientistsaffected emission units or processes would have concluded increasing concentrationsto comply with specific standards of greenhouse gasesperformance 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 Earth’s atmosphere mayNovember 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 changes having significant physicalchange 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 increased frequencyrising sea levels, and severitytherefore are responsible for roadway and infrastructure damages, or that the companies have been aware of storms, droughts, floodsthe 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
20

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 climatic events. Ifdevelopments 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 effects from such causesrules 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 to occur, they could have an adverse effect on our exploration and production operations.misleading or deficient.
Both the EPA and the state of North Dakota pursued enforcement actions in 2016 against operators related to emissions generally and alleged noncompliance with the requirements of Quad O, Quad Oa, and relevant state regulations more specifically. One such enforcement action by the EPA against an operator resulted in a consent decree between the parties


requiring the operator to incur costs associated with a civil penalty, emissions-related mitigation projects, and implementation of a robust leak detection and repair program applicable to all of the operator’s wells in North Dakota.
Finally, the U.S. Department of Justice (“DOJ”) announced in 2016 it had partnered with the Occupational Safety and Health Administration to pursue a “Worker Endangerment Initiative” seeking to promote worker safety by pursuing not only worker safety claims in connection with worker safety incidents but also environmental claims.
Environmental protection and natural gas flaring. We strive to operate in accordance with all applicable regulatory and legal requirements and have focused on continuously improving our environmental performance; however, at times circumstances may arise that adversely affect our compliance with applicable environmental requirements. We have established internal policies, procedures and processes regarding environmental matters for all employees, contractors, and vendors. In connection with our environmental initiatives, we work to identify and manage our environmental risks and the impact of our operations and continually improve our environmental compliance. However, we cannot guarantee our efforts will always be successful.
One of our environmental initiatives is the reduction of air emissions produced from our operations, particularly with respect toincluding the flaring of natural gas from our operated well sites in the Bakken field of North Dakota. North Dakota statutes permitlaw 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 NDICNorth 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. While the NDIC ultimately determines the volume and value of any such gas flared and the applicable royalties and production taxes, the NDIC has thus far generally accepted our methods for calculating these amounts. Furthermore, the NDIC has generally accepted applications we have submitted to secure exemptions from the post-year flaring restrictions. Finally,
In addition, NDIC rules for new drilling permit applications also require the submission of gas capture plans addressing measuressetting 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. Thus far, theThe NDIC has generally accepted our gas capture plans submitted with applications for drilling permits. The deadline to comply with the requirementcurrently requires us to capture 85%91% of the natural gas produced from a field was November 1, 2016, andfield. We capture in excess of the targetNDIC requirement. If an operator is unable to attain the applicable gas capture percentage increasesgoal at maximum efficient rate, wells will be restricted in production to 88% beginning November 1, 2018200 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 91% beginning November 1, 2020.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.
For the year ended December 31, 2017, we delivered approximately 90% of our operated natural gas production in the North Dakota Bakken fieldWe seek to market, flaring approximately 10% compared to 9% in 2016 and 13% in 2015. According to data published by the NDIC, our industry as a whole flared approximately 12% of produced natural gas volumes in the North Dakota Bakken field during 2017. We are a participant in the NDIC’s Flaring Reduction Task Force and are engaged in working with other task force members and the NDIC to develop action plans for mitigatingreduce or eliminate natural gas flaring, in the state. Flared natural gas volumes frombut our operated SCOOP and STACK properties in Oklahoma are negligible given the existence of established natural gas transportation infrastructure.
There are environmental and financial risks associated with natural gas flaring, and we attempt to manage these risks on an ongoing basis. We have taken numerous actions to reduce flaring from our operated well sites, such as coordinating our well completion operations to coincide with well connections to gathering systems in order to minimize flaring; however, weefforts may not always be successful in these efforts. Our ultimate goal is to reduce natural gas flaring from our operated well sites as much as practicable. For example, in operating areas such as the Buffalo Red River units in South Dakota, the quality of the natural gas is not adequate to meet requirements for sale, so we employ processes to efficiently combust the gas in an effort to minimize impacts to the environment.or cost-effective. Our levels of flaring are and will be dependent uponimpacted by external factors such as investment from third parties in the development and continued operation of gas gathering systems, state regulations,and processing facilities and the granting of reasonable right-of-way access by land owners. For example, over the past year insufficient takeaway capacity in North Dakota has created challenges for all operators and contributed to an increase in volumes of flared gas. Increased emissions from a multi-well pad facility or centralized productionour facilities due to flaring could require ussubject our facilities to adhere to PSD or Title V permit requirements. We have filed several permits to construct major sources (i.e., facilities from which emissions of a criteria pollutant (e.g., carbon monoxide or volatile organic compounds) are expected to exceed 100 tons per year) relating to facilities where takeaway capacity is currently constrained and creating a potential to emit in excess of 100 tons per year.
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. Although we believe our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations, we cannot assure you the passage of more stringent laws or regulationsair emission permitting requirements, resulting in the future will not materially impact our financial position, results of operations or cash flows.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 increased public concern regarding an alleged potential for hydraulic fracturing to adversely affect drinking water supplies andor to induce seismic events. As a result, several federal and state agencies are studyinghave 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”("SDWA") over certain hydraulic fracturing activities involving the use of diesel fuels and published permitting guidance in February 2014 related to such activities. In May 2014,Also, the EPA has issued an Advance Notice of Proposed Rulemaking to collect data on chemicals used in hydraulic fracturing operations under Section 8 of the Toxic Substances Control Act. To date, no other action has been taken. In June 2016, the EPA finalized 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. It hasWe do not been our practice to
21

discharge wastewater to publicly owned treatment works, so the impact of this new regulation on us is not currently, and is not expected to be, material.
In Decemberlate 2016 the EPA published a final study of the potential impacts of hydraulic fracturing activities on water resources. In its report,resources in which the EPA indicated it found evidence hydraulic fracturingthat such activities can impact drinking water resources under some circumstances. The report identified certain conditions where impacts from hydraulic fracturing activities can potentially be more frequent or severe. These include water withdrawals for hydraulic fracturing in times or areas of low water availability; spills during the handling of hydraulic fracturing fluids, chemicals or produced water resulting in large volumes or high concentrations of chemicals reaching groundwater resources; injection of hydraulic fracturing fluids into wells with inadequate mechanical integrity thereby allowing gases or liquids to move to groundwater resources; injection of hydraulic fracturing fluids directly into groundwater resources; discharge of inadequately treated hydraulic fracturing wastewater to surface water; and disposal or storage of hydraulic fracturing wastewater in unlined pits thereby resulting in contamination of groundwater resources. 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 March 2015,2016, the BLM issuedunder 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. Several parties challenged the regulations and the U.S. District Court of Wyoming temporarily stayed implementation of the regulations. In June 2016, the U.S. District Court of Wyoming ruledHowever, the BLM lackedunder the statutory authority to promulgateTrump Administration published a final rule rescinding the regulations.The U.S. Department of Interior appealed the decision. In December 2017, the BLM formally rescinded its March 2015 hydraulic fracturing rules, citing unjustified administrative burdens and compliance costs arising from a reassessment performed2016 final rule in response to President Trump's March 2017 Executive Order to reduce the burden of federal regulations that may hinder economic growth and energy development. In January 2018, litigationNovember 2018. Litigation challenging the BLM's rescission of2016 final rule as well as its 2018 final rule rescinding the March 20152016 rule has been pursued by various states and industry and environmental groups. While a California federal court vacated the 2018 final rules was broughtrule in July 2020, a Wyoming federal court. As of December 31, 2017, we held approximately 65,500 net undeveloped acrescourt 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 land, representing approximately 11% of our total net undeveloped acres.lands and waters.
At the state level, severalIn addition, regulators in states in which we operate have adopted or are considering adopting legal requirements imposing more stringent permitting, disclosure and well construction requirements on hydraulic fracturing activities. Local governments also may seek to adopt ordinances within their jurisdictions regulating or prohibiting the time, place and manner of drilling activities or hydraulic fracturing activities. In certain areas of the United States, new drilling permits for hydraulic fracturing have been put on hold pending development of additional standards.
Regulators in states in which we operate are considering 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 acurtailment 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. The OCC may update this guidance to impose a larger monitoring area and more stringent requirements for notification and suspension of operations. 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.
We voluntarily participate in FracFocus, a national publicly accessible Internet-based registry developed by the Ground Water Protection Council and the Interstate Oil and Gas Compact Commission. This registry, located at www.fracfocus.org, provides


our industry with an avenue to voluntarily disclose additives used in the hydraulic fracturing process. The additives used in the hydraulic fracturing process on all wells we operate are disclosed on that website.
The adoption of any future federal, state or local laws, rules or implementing regulations imposing permitting or reporting obligations on, or otherwise limiting, hydraulic fracturing processes in areas in which we operate could make it more difficult and expensive to complete crude oil and natural gas wells in low-permeability formations, increase our costs of compliance and doing business, and delay, prevent or prohibit the development of natural resources from unconventional formations. Compliance, or the consequences of our failure to comply, could have a material adverse effect on our financial condition and results of operations. At this time it is not possible to estimate the potential impact on our business if such federal or state legislation is enacted into law.
Waste water disposal. 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 are investigatinghave investigated whether such wells have caused increased seismic activity. SomeTo address concerns regarding seismicity, some states, including states in which we operate, have delayedpursued remedies that included delaying permit approvals, mandatedmandating a reduction in injection volumes, or have shutshutting down or imposedimposing moratoria on the use of injection wells. RegulatorsMoreover, regulators in states in which we operate are consideringhave 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 has adoptedutilizes 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 initiativeslaws 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 all oil and gas producers and we do not believeexpect 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 in Oklahoma 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.
22

Employee Health and Safety. We are also subject to the requirements of the federal Occupational Safety and Health Act and comparable state statuteslaws that regulate the protection of the health and safety of workers. In addition, the OSHAU.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 statuteslaws and regulations require that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local governmental authorities and citizens.
Human Capital

Employees and Labor Relations
As of December 31, 2017,2021, we employed 1,127 people. Our future success will depend partially on1,254 people, all of which were employed in the United States, with 721 employees being located at our abilitycorporate 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 qualified personnel.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 are notalign 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 party to any collective bargaining agreementsrobust health and have not experienced any strikes or work stoppages. We considersafety 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 relations with“Brother’s Keeper” program, we encourage each of our employees to be satisfactory.a proactive participant in ensuring the safety of all of the Company’s personnel.  We utilizedeveloped 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 servicesnumber of independentrecordable 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 perform2017.

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 fieldbenefit 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 services.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
23

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 “For Investors”“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 public may read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F Street N.E., Washington, D.C. 20549. The public may obtain information about the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. We file our reports with the SEC electronically. The SEC maintains an internet website that contains reports, proxy and information statements, and other information regarding issuers thatregistrants file electronically 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.

24


Item 1A.Risk Factors
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, or 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, and rate of growth.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. For example, during 2017 the NYMEX West Texas Intermediate (“WTI”) crude oilunpredictable and Henry Hub natural gas spotcommodity prices ranged from approximately $42 to $60 per barrel and $2.45 to $3.70 per MMBtu, respectively. Commodity prices maywill likely remain volatile and unpredictable in 2018 and beyond.
We have hedged the majority of our forecasted 2018 natural gas production.future. Our future crude oil production and a portion of our future natural gas production is currently unhedged as of the time of this filing and directlyis 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;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 globalregional crude oil and natural gas exploration and production activities;
•the level of global, national, and globalregional 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 countries;nations;
the nature and extent of domestic and foreign governmental regulations and taxation, including environmental regulations;
•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;gas liquids;
•adverse weatherclimatic conditions, natural disasters, and natural disasters;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.
25

Sustained material declines in commodity prices reduce our 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 the 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 finance plannedmeet our capital expendituresexpenditure needs and commitments.
A substantial portionThe ability or willingness of our producing properties is located in limited geographic areas, making us vulnerableSaudi Arabia and other members of OPEC, and other oil exporting nations, including Russia, to risks associated with having geographically concentrated operations.
A substantial portion of our producing properties is located in the Bakken field of North Dakotaset and Montana, with that area comprising approximately 55% of ourmaintain 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 natural gas production and approximately 64% of our crude oil and natural gas revenues for the year ended December 31, 2017. Approximately 48%of our estimated proved reserves were located in the Bakken as of December 31, 2017. Additionally, in recent years we have significantly expanded our operations in Oklahoma with our increased activity in the SCOOP and STACK plays. Our properties in Oklahoma comprised approximately 41% of our crude oil and natural gas production and approximately 31% of our crude oil and natural gas revenues for the year ended December 31, 2017. Approximately 50% of our estimated proved reserves were located in Oklahoma as of December 31, 2017.
Because of this concentration in limited geographic areas, the success and profitability of our operations may be disproportionately exposed to regional factors compared to competitors having more geographically dispersed operations. These factors include, among others: (i) the pricessupply 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 natural gas produced from wellspricing. 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 regionsfuture, or utilize other actions to support and stabilize oil prices, nor can there be any assurance they will not increase production or deploy other regional supply and demand factors, including gathering, pipeline and rail transportation capacity constraints; (ii) the availability of rigs, equipment, oilfield services, supplies, and labor; (iii) the availability of processing and refining facilities; and (iv) infrastructure capacity. In addition, our operationsactions 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 Bakken field and Oklahoma may be adversely affected by severe weather events such as floods, blizzards, ice storms and tornadoes,price of oil, which can intensify competition for the items and services described above and may result in periodic shortages. The concentration of our operations in limited geographic areas also increases our exposure to changes in local laws and regulations, certain lease stipulations designed to protect wildlife, and unexpected events that may occur in the regions such as natural disasters, seismic events (which may result in third-party lawsuits), industrial accidents, labor difficulties, civil disturbances, public protests, or terrorist attacks. Any one of these events has the potential to cause producing wells to be shut-in, delay operations, decrease cash flows, increase operating and capital costs and prevent development of lease inventory before expiration. Any of the risks described above could have a material adverse effect on our business, financial condition, results of operations, and cash flows.
VolatilityOur 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;
26

•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 marketsloss 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 in global economic factorsmandates, 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 impactaffect our accessbusiness, 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 businessother technologies and financial condition.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.
United StatesRisks 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 global economiesnot 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 experienceoccur 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;
27

•political events, public protests, civil disturbances, terrorist acts or cyber attacks;
•decreases in, or extended periods of turmoillow, crude oil and volatilitynatural 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.
28

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 resulting in diminished liquidity and credit availability,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 accessfund necessary capital markets, high unemployment, unstable consumer confidence,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 diminished consumer demandwill 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 spending. In recentdevelopment 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 certain global economies have experienced periodsrepresents 37% of political uncertainty, slowing economic growth, rising interestour 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 changing economic sanctions,that vary depending upon reservoir characteristics and currency volatility. These global macroeconomic conditions may put downward pressure on commodity pricesother factors. Our future crude oil and have a negative impactnatural gas reserves and production, and therefore our cash flows and results of operations, are highly dependent on our revenues, profitability, operating cash flows, liquiditysuccess 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.condition and results of operations could be materially adversely affected.
Historically,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
29

discontinuance of development plans for properties, or higher operational costs associated with air quality compliance controls. Although we have used cash flowssome 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 operations, borrowings underthose wells until other arrangements are made for the sale or delivery of our revolving credit facilityproducts and proceeds from capital market transactionsacreage 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 asset dispositions to fund capital expenditures. Volatilityconcerns, changes in U.S.tax and global financialenergy policies, federal, state and equity markets,international regulatory developments, changes in supply and demand, equipment failures or accidents, including market disruptions, limited liquidity,pipeline and interest rate volatility, maygathering system ruptures or train derailments, and general economic conditions could negatively impact our ability to obtain needed capitalachieve 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 acceptable termsprices 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 alllower 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 costcosts of financing.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. In addition, funding our capital expenditures with additional debt will increase our leverage and doing so with equity securities may result in dilution that reduces the value of your stock.
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 2018 (excluding2022, excluding acquisitions, which are not budgeted) of which $1.99approximately $1.80 billion is allocated forto exploration and development drilling.activities. We may adjust our 20182022 capital spending plans upward or downward depending on market conditions.
Historically, Our 2022 capital budget, based on our capital expenditures have been financed with cash generated by operations, borrowings under our revolving credit facility and proceeds from the issuancecurrent expectations of debt and equity securities. Additionally, in recent years non-strategic asset


dispositions have provided a source of cash flow for use in reducing outstanding debt arising from our capital program. The actual amount and timing of future capital expenditures may differ materially from our estimates as a result of, among others, changes in commodity prices availableand costs, is expected to be funded from operating cash flows, lackflows. However, the sufficiency of access to capital, 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, and regulatory, technological and competitive developments.
Ourour cash flows from operations and access to capital areis subject to a number of variables, including but not limited to:
•the prices at which crude oil and natural gas are sold;
30

•the volume and value of our proved reserves;
•the volume of crude oil and natural gas we are able to produce and sell from existing wells; and
the prices at which crude oil and natural gas are sold;
•our ability to acquire, locate and produce new reserves;
our ability to dispose of assets or enter into joint development arrangements on satisfactory terms; and
the ability and willingness of our lenders to extend credit or of participants in the capital markets to invest in our senior notes or equity securities.
If oil and gas industry conditions weaken as a result of low commodity prices or other factors, our abilitywe may not be able to borrow may decreasegenerate sufficient cash flows and we may have limited ability to obtain the capital necessary to sustain our operations at current or planned levels. Currently, weA 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 $2.75$2.0 billion that matures in May 2019.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.
We intend to finance future capital expenditures primarily through cash flows from operations, with any cash flow deficiencies expected to be funded by borrowings under our revolving credit facility or proceeds from asset sales or joint development arrangements. However, our financing needs may require us to alter or increase our capitalization substantially through the issuance of debt or equity securities. If we issue additional debt a portion of our cash flows from operations will need to be used for the payment of interest and principal on our debt, thereby reducing our ability to use cash flows to fund working capital needs, capital expenditures and acquisitions. The issuance of additional equity securities could have a dilutive effect on the value of our common stock.
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.
Our future financial condition and results of operations will 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, develop or otherwise exploit 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.
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 curtail, delay or cancel scheduled drilling 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 train derailments;
restrictions on the use of underground injection wells for disposing of waste water from oil and gas activities;
political events, public protests, civil disturbances, terrorist acts or cyber attacks;
decreases in, or extended periods of low, crude oil and natural gas prices;
limited availability of financing with acceptable terms;
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;
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 and refining 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 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 will likely turn out to be inaccurate. Any material inaccuracies in these 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, in particular due to changes in commodity prices.
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, 2017.
In order to prepare reserve estimates, we must project production rates and the amount and timing of development expenditures. Our booked proved undeveloped reserves must be developed 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 2017, 89 MMBoe of proved undeveloped reserves were removed from our year-end reserve estimates associated with drilling locations no longer scheduled to be developed within five years from the date of initial booking.
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 but projected into the future, about matters such as crude oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.
The prices used in calculating our estimated proved reserves are calculated by determining the unweighted arithmetic average of the first-day-of-the-month commodity prices for the preceding 12 months. For the year ended December 31, 2017, average prices used to calculate our estimated proved reserves were $51.34 per Bbl for crude oil and $2.98 per MMBtu for natural gas ($47.03 per Bbl for crude oil and $3.00 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. NYMEX WTI crude oil and Henry Hub


natural gas first-day-of-the-month commodity prices for January 1, 2018 and February 1, 2018 averaged $63.11 per barrel and $3.40 per MMBtu, respectively. See Part I, Item 1. Business—Crude Oil and Natural Gas Operations—Proved Reserves—Proved Reserve, Standardized Measure, and PV-10 Sensitivities for proved reserve sensitivities under certain increasing and decreasing commodity price scenarios.
Actual future production, crude oil and natural gas 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 adjust estimates of proved reserves, potentially in material amounts, to reflect production history, results of exploration and development activities, prevailing crude oil and natural gas prices and other factors, many of which are beyond our control.
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.
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. See Part I, Item 1. Business—Crude Oil and Natural Gas Operations—Proved Reserves—Proved Reserve, Standardized Measure, and PV-10 Sensitivities for Standardized Measure and PV-10 sensitivities under certain increasing and decreasing commodity price scenarios.
Actual future net revenues from crude oil and natural gas properties will be affected by factors such as:
the actual prices we receive for sales of crude oil and natural gas;
the actual cost and timing of development and production expenditures;
the timing and amount of actual production; and
changes in governmental regulations or taxation.
The timing of both our production and our incurrence of costs in connection with the development and production of crude oil and natural gas properties will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual present value. In addition, the use of a 10% discount factor, which is required by the SEC to be used to calculate discounted future net revenues for reporting purposes, may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with our reserves or the crude oil and natural gas industry in general. Any significant variances in timing or assumptions could materially affect the estimated present value of our reserves, which in turn could have an adverse effect on the value of our assets.
We may be required to further write down the carrying values of our crude oil and natural gas properties if commodity prices decline or our development plans change.
Accounting rules require we periodically review the carrying values of our crude oil and natural gas properties for possible impairment. Proved properties are reviewed for impairment on a field-by-field basis each quarter. We use the successful efforts method of accounting whereby the estimated future cash flows expected in connection with a field are compared to the carrying amount of the field to determine if the carrying amount is recoverable. If the carrying amount of the field exceeds its estimated undiscounted future cash flows, the carrying amount of the field is reduced to its estimated fair value using a discounted cash flow model.
Based on specific market factors, prices, and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying values of our crude oil and natural gas properties. A write-down results in a non-cash charge to earnings. We have incurred impairment charges in the past and may incur additional impairment charges in the future, particularly if commodity prices decline, which could have a material adverse effect on our results of operations for the periods in which such charges are taken.


Unless we replace our crude oil and natural gas reserves, our reserves and production will decline, which could adversely affect our cash flows and results of operations.
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.
The unavailability or high cost of drilling rigs, well completion crews, water, equipment, supplies, personnel and oilfieldfield 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 historically been shortages of drilling rigs, well completion crews, equipment, supplies, personnel, or oilfieldfield 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 oilfieldfield service providers and associated equipment, supplies, and materials can fluctuate significantly, often in correlation with commodity prices or supply chain disruptions, causing periodic shortages.
Certain drillingshortages and/or higher costs. For instance, recent supply chain disruptions stemming from the COVID-19 pandemic have led to shortages of certain materials and completion costs and costs of oilfield services, equipment and materials decreasedincreased costs. While we have not yet experienced material shortages in recent yearssupply as service providers reduced their costs in response to reduced demand arising from low crude oil prices. However, inflationary pressures returned in 2017 and are expected to continue in 2018 in conjunction with the stabilization and improvement in crude oil prices in recent months.
As a result of these disruptions, if they become prolonged or expand in scope the low commodity price environment in recent years, the number of providers of services, equipment, and materials decreased in the regions where we operate. Further, increased industry drilling and completion activities in recent months prompted by improvement in crude oil prices may cause shortages or higher costs of services, equipment, and materials. Suchresulting shortages or higher costs could delay the execution of our drilling and development plans including our plans to work down our large inventory of uncompleted wells, 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 may incur substantial losses and be subject to substantial liability claims as a result of our crude oil and natural gas operations. Additionally, we may not be insured for, or our insurance may be inadequate to protect us against, these risks.
We are not insured against all risks. Losses and liabilities arising from uninsured and under-insured events could materially and adversely affect our business, financial condition or results of operations. Our crude oil and natural gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing crude oil and natural gas, including the possibility of:
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;
abnormally pressured formations;
mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse;
fires and explosions;
ruptures of pipelines or storage facilities;
loss of product or property damage occurring as a result of transfer to a rail car or train derailments;
personal injuries and death;
adverse weather conditions and natural disasters; and
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.
Any of these 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 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. The occurrence of an event not fully covered by insurance could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Prospects we decide to drill may not yield crude oil or natural gas in economically producible quantities.
Prospects we decide to drill that do not yield crude oil or natural gas in economically producible quantities may adversely affect our results of operations and financial condition. In this report, we describe some of our current prospects and plans to explore and develop those prospects. Our prospects are in various stages of evaluation, ranging from a prospect which is ready to drill to a prospect requiring substantial additional seismic data processing and interpretation. It is not possible to predict with certainty whether any particular prospect will yield crude oil or natural gas in sufficient quantities to recover drilling or completion costs or be economically producible. 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 or, if present, whether crude oil or natural gas will be present in economically producible quantities. We cannot assure you the analogies we draw from available data from other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects.
Our identified drilling locations are scheduled out over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.
Our management has specifically identified 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 uncertainties, including crude oil and natural gas prices; the availability of capital, drilling rigs, well completion crews, and transportation and processing capacity; costs; drilling results; regulatory approvals; and other factors. If future drilling results do not establish sufficient reserves to achieve an economic return, we may curtail drilling in these projects. Because of these uncertainties, we do not know if the potential drilling locations we have identified 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. In addition, 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. Low commodity prices, reduced capital spending, lack of available drilling and completion rigs and crews, and numerous other factors, many of which are beyond our control, could result in our failure to establish production on undeveloped acreage, and, 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 57% of our total net undeveloped acreage at December 31, 2017. At that date, we had leases representing 102,258 net acres expiring in 2018, 145,997 net acres expiring in 2019, and 93,664 net acres expiring in 2020. Our actual drilling activities may materially differ from those presently identified, which could adversely affect our business.
The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Our proved undeveloped reserves may not be ultimately developed or produced.
At December 31, 2017, approximately 55% of our total estimated proved reserves (by volume) were undeveloped and may not be ultimately developed or produced. 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, 2017 includes estimates of total future development costs over the next five years associated with our proved undeveloped reserves of approximately $6.4 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. In addition, under the SEC’s reserve rules, because proved undeveloped reserves may be booked only if they relate to wells scheduled to be drilled within five years of the date of booking, we may be required to remove any


proved undeveloped reserves not developed within this five-year time frame. Such removals have occurred in the past and will likely occur in the future. A removal of such reserves could adversely affect our operations. In 2017, 89 MMBoe of proved undeveloped reserves were removed from our year-end reserve estimates associated with drilling locations no longer scheduled to be developed within five years from the date of initial booking.
Our business depends on crude oil and natural gas transportation, processing, and refining 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 and refining facilities owned by third parties. The inadequacy or unavailability of capacity on these systems and facilities could result in the shut-in of producing wells, the delay or discontinuance of development plans for properties, or higher operational costs associated with air quality compliance controls. Although we have some contractual control over the transportation of our products, changes in these business relationships or failure to obtain such services on acceptable terms could adversely affect our operations. If our production becomes shut-in for any of these or other reasons, we would be unable to realize revenue from those wells until other arrangements were 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 or refining facilities due to labor disputes, maintenance, civil disturbances, public protests, terrorist attacks, cyber attacks, adverse weather, natural disasters, seismic events, 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 commitments or is hedged at lower than market prices, those commitments or financial hedges would have to be paid from borrowings absent sufficient cash flows.
Our operated crude oil and natural gas production is transported to market centers primarily using pipeline and rail transportation facilities 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. We do not currently own or operate transportation infrastructure; however, compliance with regulations that impact the transportation of crude oil or natural gas could increase our costs of doing business and limit our ability to transport and sell our production at market centers throughout the United States, the consequences of which could have a material adverse effect on our financial condition, results of operations and cash flows.
Our business depends on the availability of water and the ability to dispose of waste water from oil and gas activities. Limitations or restrictions on our ability to obtain or dispose of water may have an adverse effect on our financial condition, results of operations and cash flows.
With current technology, water is an essential component of drilling and hydraulic fracturing processes. Limitations or restrictions on our ability to secure sufficient amounts of water (including limitations resulting from natural causes such as drought), or to dispose of or recycle water after use, could adversely impact our operations. In some cases, water may need to be obtained from new sources and transported to drilling sites, resulting in increased costs. Moreover, the introduction of new environmental initiatives and regulations related to water acquisition or waste water disposal, including produced water, drilling fluids and other wastes associated with the exploration, development or production of hydrocarbons, could limit or prohibit our ability to utilize hydraulic fracturing or waste water injection wells.
In addition, concerns have been raised about the potential for seismic events to occur from the use of underground injection wells, a predominant method for disposing of waste water from oil and gas activities. Rules and regulations have been developed in Oklahoma to address these concerns by limiting or eliminating the ability to use disposal wells in certain locations or increasing the cost of disposal. We operate injection wells and utilize injection wells owned by third parties to dispose of waste water associated with our operations. Some states, including states in which we operate, have delayed permit approvals, mandated a reduction in injection volumes, or have shut down or imposed moratoria on the use of injection wells. Regulators in some states, including states in which we operate, are considering additional requirements related to seismicity. For example, in Oklahoma, the Oklahoma Corporation Commission (“OCC”) has adopted rules for operators of saltwater disposal wells in certain seismically-active areas in the Arbuckle formation of the state. These rules require disposal well operators, among other things, to 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 has adopted 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.


Compliance with existing or new environmental regulations and permit requirements governing the withdrawal, storage, and use of water necessary for hydraulic fracturing of wells or the disposal of waste water may increase our operating costs or may cause us to delay, curtail or discontinue our exploration and development plans, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.
We are subject to complex federal, state and local laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations 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, including those governing environmental protection, the occupational health and safety aspects of our operations, the discharge of materials into the environment, and the protection of certain plant and animal species. See Part I, Item 1. Business—Regulation of the Crude Oil and Natural Gas Industry for a description of the laws and regulations that affect us. In order to conduct operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. Environmental regulations may restrict the types, quantities and concentration of materials released into the environment in connection with drilling and production activities, limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas, and impose substantial liabilities for pollution resulting from our operations. In addition, we may experience delays in obtaining or be unable to obtain required permits, which may delay or interrupt our operations and limit our growth and revenues.
Failure to comply with laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including investigatory actions, the assessment of monetary penalties, the imposition of remedial requirements, the issuance of orders or judgments limiting or enjoining future operations and litigation. Strict liability or joint and several liability may be imposed under certain laws, 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 and other third parties for personal injury and property damage and fines or penalties for related violations of environmental laws or regulations.
Moreover, our costs of compliance with existing laws could be substantial and may increase, or unforeseen liabilities could be imposed, if existing laws and regulations are revised or reinterpreted or if new laws and regulations become applicable to our operations. If we are not able to recover the increased costs through insurance or increased revenues, our business, financial condition, results of operations and cash flows could be adversely affected.
Climate change legislation or regulations governing the emissions of “greenhouse gases” could result in increased operating costs, limitations in our ability to develop and produce reserves, and reduced demand for the crude oil, natural gas and natural gas liquids we produce.
In response to EPA findings that emissions of carbon dioxide, methane and other greenhouse gases endanger human health and the environment, the EPA has adopted regulations under existing provisions of the federal Clean Air Act establishing, among other things, Prevention of Significant Deterioration (“PSD”) pre-construction and Title V operating permit reviews for certain large stationary sources. Facilities required to obtain PSD permits for greenhouse gas emissions are also required to meet “best available control technology” standards established on a case-by-case basis. For further discussion of Title V and PSD concerns, see Part I, Item 1. Business–Regulation of the Crude Oil and Natural Gas Industry–Environmental regulation–Air emissions and climate change. Also see Part I, Item 1. Business–Regulation of the Crude Oil and Natural Gas Industry–Environmental regulation–Environmental protection and natural gas flaring. The EPA has also adopted rules requiring the monitoring and reporting of greenhouse gas emissions from specified onshore and offshore oil and gas production sources in the United States on an annual basis, which include certain of our operations. See Part I, Item 1. Business—Regulation of the Crude Oil and Natural Gas Industry—Environmental regulation—Air emissions and climate change for further discussion of the laws and regulations that affect us with respect to climate change initiatives. Regulations related to greenhouse gas emissions could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources.
Certain previously existing climate-related regulations, such as those related to the control of methane emissions, have been, or are in the process of being, reviewed, suspended, revised, or rescinded in response to President Trump's March 2017 Executive Order. Undoing previously existing regulations will likely involve lengthy notice-and-comment rulemaking and the resulting decisions may then be subject to litigation by opposition groups. Thus, it could take several years before existing regulations are revised or rescinded. Although further climate-related regulation of our industry may stall at the federal level under the March 2017 Executive Order, certain states have pursued additional regulation of our operations related to the emission of greenhouse gases and other states may do so as well. For instance, several state and regional greenhouse gas cap and trade


programs have emerged, while other states have imposed limitations on emissions of methane through equipment control and leak detection and repair requirements.
The implementation of, and compliance with, regulations that require reporting of greenhouse gases or otherwise limit emissions of greenhouse gases from our equipment and operations could require us to incur costs to monitor and report on greenhouse gas emissions, install new equipment to reduce emissions of greenhouse gases associated with our operations, or limit our ability to develop and produce our reserves. In addition, substantial limitations on greenhouse gas emissions could adversely affect the demand for the crude oil and natural gas we produce, which could lower the value of our reserves and have a material adverse effect on our business, financial condition, results of operations and cash flows.
Finally, some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods or other climatic events. If any such effects were to occur as a result of climate change or otherwise, they could have an adverse effect on our assets and operations.
Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs, additional operating restrictions or delays, and an inability to develop existing reserves or to book future reserves.
Hydraulic fracturing is an important and commonly used process in the completion of crude oil and natural gas wells in low-permeability formations. Hydraulic fracturing involves the high-pressure injection of water, sand or other proppant and additives into rock formations to stimulate crude oil and natural gas production. In recent years there has been increased public concern regarding an alleged potential for hydraulic fracturing to adversely affect drinking water supplies and to induce seismic events. As a result, several federal and state regulatory initiatives have emerged that seek to increase the regulatory burden imposed on hydraulic fracturing. See Part I, Item 1. Business—Regulation of the Crude Oil and Natural Gas Industry—Environmental regulation—Hydraulic fracturing for a description of the laws and regulations that affect us with respect to hydraulic fracturing.
States in which we operate have adopted or are considering adopting legal requirements imposing more stringent permitting, disclosure, and well construction and reclamation requirements on hydraulic fracturing activities. Local governments also may seek to adopt ordinances within their jurisdictions regulating or prohibiting the time, place and manner of drilling activities or hydraulic fracturing activities. In certain areas of the United States, new drilling permits for hydraulic fracturing have been put on hold pending development of additional standards.
The adoption of any future federal, state or local law or implementing regulation imposing permitting or reporting obligations on, or otherwise limiting, the hydraulic fracturing process, or the discovery of groundwater contamination or other adverse environmental effects directly connected to hydraulic fracturing, could make it more difficult and more expensive to complete crude oil and natural gas wells in low-permeability formations and increase our costs of compliance and doing business, as well as delay, prevent or prohibit the development of natural resources from unconventional formations. In the event regulations are adopted to prohibit or significantly limit the use of hydraulic fracturing in states in which we operate, it would have a material adverse effect on our ability to economically find and develop crude oil and natural gas reserves in our strategic plays. The inability to achieve a satisfactory economic return could cause us to curtail or discontinue our exploration and development plans, which would have a material adverse effect on our business, financial condition, results of operations and cash flows.
Proposed changes to existing laws or regulations or changes in interpretations of laws and regulations under consideration could increase our operating costs, reduce our liquidity, delay our operations or otherwise alter the way we conduct our business.
Changes to existing laws or regulations, new laws or regulations, or changes in interpretations of laws and regulations may unfavorably impact us or the infrastructure used for transporting our products. Similarly, changes in regulatory policies and priorities could result in the imposition of new obligations upon us, such as increased reporting or audits. Any of these requirements could result in increased operating costs and could have a material adverse effect on our financial condition and results of operations. If such legislation, regulations or interpretations are adopted, they could result in, among other items, additional restrictions on hydraulic fracturing of wells, restrictions on the disposal of waste water from oil and gas activities, restrictions on emissions of greenhouse gases, modification of equipment utilized in our operations, changes to the calculation of royalty payments, new safety requirements such as those involving rail transportation, and additional regulation of private energy commodity derivative and hedging activities. These and other potential laws, regulations, interpretations and other requirements could increase our operating costs, reduce our liquidity, delay our operations or otherwise alter the way we conduct our business. This, in turn, could have a material adverse effect on our financial condition, results of operations and cash flows.


Certain aspects of the newly enacted federal income tax reform legislation in the United States could adversely affect us.
On December 22, 2017, the Tax Cuts and Jobs Act (the "Tax Reform Act") was signed into law by President Trump. The Tax Reform Act represents the most significant tax policy change in the United States since 1986 and includes, among others, the following key changes to federal tax law:
Reduces the corporate tax rate from 35% to 21% and eliminates the corporate alternative minimum tax;
Limits the tax deduction for certain net operating loss (NOL) carryforwards to 80% of taxable income for a taxable year, allows NOLs generated in years after December 31, 2017 to be carried forward indefinitely, and repeals NOL carrybacks;
Limits the tax deduction for business interest expense to 30% of adjusted taxable income for a taxable year;
Allows businesses to immediately expense the cost of new investments in certain qualified depreciable assets;
Creates a territorial tax system rather than a worldwide system, which generally allows companies to repatriate future foreign source earnings without incurring additional U.S. taxes;
Subjects foreign earnings on which U.S. income tax is currently deferred to a one-time transition tax; and
Eliminates or reduces certain deductions, exclusions, and credits and adds other provisions that broaden the tax base.
Changes arising from the Tax Reform Act, which are subject to a number of important qualifications and exceptions, generally become effective for tax years beginning after December 31, 2017. Certain of the changes are permanent, while others expire at specified dates. The Tax Reform Act's provisions could have state and local tax implications. While some states automatically adopt federal tax law changes, others conform their laws with federal law on specific dates. States also may choose to decouple from the new federal tax provisions and continue to apply previous law.
Apart from the future benefits to be realized from the reduction in the corporate income tax rate from 35% to 21%, the overall long-term impact of other aspects of the Tax Reform Act is uncertain, and our business, financial condition, results of operations and cash flows could be adversely affected by certain new provisions, particularly the limitations on the tax deductibility of business interest expense and NOLs. See Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations–Legislative and Regulatory Developments–Tax Reform Legislation for a forward-looking discussion of the potential impact of the Tax Reform Act.
In previous years, legislation has been proposed to eliminate or defer certain key U.S. federal income tax deductions historically available to oil and gas exploration and production companies. Such proposed changes have included: (i) a repeal of the percentage depletion allowance for crude oil and natural gas properties; (ii) the elimination of deductions for intangible drilling and exploration and development costs; (iii) the elimination of the deduction for certain production activities; and (iv) an extension of the amortization period for certain geological and geophysical expenditures. These tax deductions currently utilized within our industry are not impacted by the Tax Reform Act. However, no prediction can be made as to whether any legislative changes will be proposed or enacted in the future that could eliminate or defer these or other tax deductions utilized within our industry.
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 to 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. Certain of 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. In addition, companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, securing long-term transportation and processing capacity, marketing hydrocarbons, attracting and retaining quality personnel, and raising additional capital, which could have a material adverse effect on our financial condition, results of operations and cash flows.
Negative public perception regarding us and/or our industry could have an adverse effect on our operations.
Negative public perception regarding us and/or our industry resulting from, among other things, concerns raised by advocacy groups about hydraulic fracturing, oil spills, induced seismicity, and greenhouse gas emissions may lead to increased regulatory scrutiny, which may, in turn, lead to new state and federal safety and environmental laws, regulations, guidelines and


enforcement interpretations. These actions may cause operational delays or restrictions, increased operating costs, additional regulatory burdens and increased risk of litigation. Moreover, governmental authorities exercise considerable discretion in the timing and scope of permit issuance and the public may engage in the permitting process, including through intervention in the courts. Negative public perception could cause the permits we need to conduct our operations to be withheld, delayed, or burdened by requirements that restrict our ability to conduct our business.
Energy conservation measures or initiatives that stimulate demand for alternative forms of energy could reduce the demand for the crude oil and natural gas we produce.
Fuel conservation measures, climate change initiatives, governmental requirements for renewable energy resources, increasing consumer demand for alternative forms of energy, and technological advances in fuel economy and energy generation devices could reduce 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.
Severe weather events and natural disasters could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Severe weather events and natural disasters such as hurricanes, tornadoes, seismic events, blizzards and ice storms affecting the areas in which we operate, including our corporate headquarters, could have a material adverse effect on our operations or the operations of third party service providers. Such events may result in significant destruction of infrastructure, businesses, and homes and could disrupt the distribution and supply of crude oil and natural gas products in the impacted region. The consequences of such events may include the evacuation of personnel; damage to and disruption of drilling rigs or transportation, processing, storage and refining facilities; 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.
Regulations under the Dodd-Frank Act regarding derivatives could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price risk and other risks associated with our business.
From time to time, we may use derivative instruments to manage commodity price risk. In 2010, the U.S. Congress adopted the Dodd-Frank Act, which, among other provisions, establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. This financial reform legislation includes provisions that require many derivative transactions previously executed over-the-counter to be executed through an exchange and be centrally cleared. In addition, this legislation calls for the imposition of position limits for swaps, including swaps involving physical commodities such as crude oil and natural gas, which have been proposed but have not been finalized. It also establishes minimum margin requirements for uncleared swaps for swap dealers and major swap participants.
If we do not qualify for an end user exemption from the Dodd-Frank requirements, the new regulations could significantly increase the cost of derivative contracts, materially alter the terms 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, impose new recordkeeping and documentation requirements, and increase our exposure to less creditworthy counterparties. Additionally, the proposed position limits may limit our ability to implement price risk management strategies if we are not able to qualify for any exemption from such limits. Further, if we do not qualify for an end user exemption, the margin requirements for uncleared swaps may require us to post collateral, which could adversely affect our available liquidity. 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. Finally, the legislation was intended, in part, to reduce the volatility of crude oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to crude oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower crude oil or natural gas prices. Any of these consequences could have a material adverse effect on our financial position, results of operations and cash flows.
The loss of senior management or technical personnel could adversely affect our operations.
We depend on the services of our senior management and technical personnel. The loss of the services of our senior management or technical personnel, including Harold G. Hamm, our Chairman and Chief Executive Officer, could have a material adverse effect on our operations. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals.


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, 2017, non-operated properties represented 18% of our estimated proved developed reserves, 6% 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 compliance with environmental, safety 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 operator 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 financial condition, results of operations and cash flows.
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, 2017, our consolidated net debt to total capitalization ratio, as defined, was 0.51 to 1.00. Our total debt would need to independently increase by approximately $5.2 billion above the existing level at December 31, 2017 (with no corresponding increase in cash or reduction in refinanced debt) to reach the maximum covenant ratio of 0.65 to 1.00. Alternatively, our total shareholders’ equity would need to independently decrease by approximately $2.8 billion below the existing level at December 31, 2017 (excluding the after-tax impact of any non-cash impairment charges) to reach the maximum covenant ratio.
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 these and other 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 of these covenants 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 adversely affect our financial condition and results of operations.
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 depend on digital technology, including information systems and related infrastructure as well as cloud applications and services, to process and record financial and operating data, analyze seismic and drilling information, conduct reservoir modeling and reserves estimation, communicate with employees and business associates, perform compliance reporting and many other activities related to our business. Our business associates, including vendors, service providers, purchasers of our production, and financial institutions, are also 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 may 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. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period.
A cyber attack involving our information systems and related infrastructure, or that of our business associates, 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 seismic data, reserves information, strategic information, or other sensitive or proprietary information could have a negative impact on our ability to compete for oil and gas resources;
data corruption or operational disruption of production-related infrastructure could result in a loss of production, or accidental discharge;
a cyber attack on a vendor or service provider could result in supply chain disruptions which could delay or halt our major development projects; and
a cyber attack on third party transportation, processing, storage or refining facilities could delay or prevent us from transporting and marketing our production, resulting in a loss of revenues.
These events 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 financial condition, results of operations or cash flows.
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. 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.
Increases in interest rates could adversely affect our business.
The U.S. Federal Reserve increased the benchmark federal funds interest rate on three separate occasions in 2017 and is forecasting additional increases in 2018 and 2019. Our business and operating results can be adversely affected by increases in interest rates, the availability, terms of and cost of capital, or downgrades or other negative rating actions with respect to our credit rating. These factors could cause our cost of doing business to increase, limit our ability to pursue acquisition opportunities, reduce cash flows used for drilling and place us at a competitive disadvantage. We require continued access to capital. A significant reduction in cash flows from operations or the availability of credit could materially and adversely affect our financial condition and results of operations.
The inability of joint interest owners, derivative counterparties, 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 ($672 million in receivables at December 31, 2017); our joint interest and other receivables ($427 million at December 31, 2017); and counterparty credit risk associated with our derivative instrument receivables ($3 million at December 31, 2017).
Joint interest receivables arise from billing the individuals and entities who own a partial interest in the wells we operate. These individuals and entities participate in our wells primarily based on their ownership in leases included in units on which we wish to drill. We can do very little to choose who participates in our wells.
We are also subject to credit risk due to concentration of our crude oil and natural gas receivables with significant customers. The two largest purchasers of our crude oil and natural gas during the year ended December 31, 2017 accounted for approximately 11% and 11%, respectively, of our total crude oil and natural gas revenues for the year. We have not generally required our counterparties to provide collateral to secure crude oil and natural gas sales receivables owed to us. Additionally, our use of derivative instruments involves the risk that our counterparties will be unable to meet their obligations.
Finally, we rely on oilfield 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 financial condition, results of operations and cash flows.
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 portion of our production. See Part II, Item 8. Notes to Consolidated Financial Statements—Note 5. Derivative Instruments for a summary of our commodity derivative positions as of December 31, 2017. We do not designate any of 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 our derivatives are recognized in current period earnings. Accordingly, our earnings may fluctuate significantly as a result of changes in commodity prices and resulting changes in the fair value of our 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, our derivative arrangements limit the benefit we would receive from increases in commodity prices. Our decision on the quantity and price at which we choose to hedge our future production, if any, 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 liquidate existing derivative positions prior to the expiration of their contractual maturities in order to monetize gain positions for the purpose of funding our capital program.
We have hedged the majority of our forecasted 2018 natural gas production. Our future crude oil production is currently unhedged and directly exposed to continued volatility in market prices, whether favorable or unfavorable.
Our Chairman and Chief Executive Officer beneficially owns approximately 76% of our outstanding common stock, giving him influence and control in corporate transactions and other matters, including a sale of our Company.
As of December 31, 2017, Harold G. Hamm, our Chairman and Chief Executive Officer, beneficially owned approximately 76% of our outstanding common shares. As a result, Mr. Hamm has 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 could cause, delay or prevent a change of control of our Company. The interests of Mr. Hamm 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 affiliated with Mr. Hamm 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 companies and us.
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 willin 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
31

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 will likelyexpect to continue to makemaking acquisitions of oil and gas properties, divest of non-strategic assets, and enter into joint development arrangements. Suitable acquisition properties, buyers of our non-strategic assets, or joint development counterparties may not be available on terms and conditions we find acceptable or not at all.
The successful acquisition of producingoil 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 costs,and operating costs and property taxes; and
potential environmental and other liabilities.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 well,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 non-strategic 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
32

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
33

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 in the Middle Eastabroad 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, and, in turn,terrorism. Any of these events could materially and adversely affect our business and results of operations.

Financial Risks

34



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.
35

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
36

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.
37

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, 2017.2021.
 
Item 2.Properties
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.
Item 3.    Legal Proceedings
See Note 10. Commitments and Contingencies–Litigation in Part II, Item 8. Financial Statements and Supplementary Data–Notes to Consolidated Financial Statements for a discussion of the legal matter involving the Company, Billy J. Strack and Daniela A. Renner, which is incorporated herein by reference.
We are involved in various legal proceedings including, but not limited to, commercial disputes, claims from royalty and surface owners, property damage claims, personal injury claims, regulatory compliance matters, disputes with tax authorities and other matters. While the outcome of these legal matters cannot be predicted with certainty, we do not expect them to have received Noticesa material effect on our financial condition, results of Violation from the North Dakota Department of Health (“NDDH”) alleging violations of the state’s air quality and water pollution control laws and rules.  We exchanged information and engaged in discussions with NDDH aimed at resolving the allegations and anticipate further discussions and exchanges.  Resolution of the allegations may result in monetary sanctions of more than $100,000.operations or cash flows.


Item 4.Mine Safety Disclosures
Item 4.    Mine Safety Disclosures
Not applicable.

38


Part II
 
Item 5.Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
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.” The following table sets forth quarterly high and low sales prices for each quarter of the previous two years. No cash dividends were declared during the previous two years.
  2017 2016
  Quarter Ended Quarter Ended
  March 31 June 30 September 30 December 31 March 31 June 30 September 30 December 31
High $53.57
 $47.87
 $40.03
 $53.55
 $31.90
 $46.01
 $52.78
 $60.30
Low $41.28
 $30.18
 $29.08
 $36.05
 $13.94
 $28.63
 $40.92
 $44.37
Cash Dividend —
 —
 —
 —
 —
 —
 —
 —
We do not anticipate paying any cash dividends on our common stock in the foreseeable future. As of January 31, 2018,February 2, 2022, the number of record holders of our common stock was 1,146. Management believes,1,269. On February 2, 2022, after inquiry, management believes that the number of beneficial owners of our common stock is approximately 64,400.79,854. On January 31, 2018,February 2, 2022, the last reported sales price of our common stock, as reported on the New York Stock Exchange, was $55.53$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 summarizes ourprovides information about purchases of our common stock during the quarter ended December 31, 2017:2021:
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 
Period Total number of
shares purchased (1)		 Average
price paid
per share (2)		 Total number of shares
purchased as part of
publicly announced
plans or programs		 Maximum number of
shares that may yet be
purchased under the
plans or programs
October 1, 2017 to October 31, 2017 234
 $38.24
 —
 —
November 1, 2017 to November 30, 2017 18,435

$44.84
 —
 —
December 1, 2017 to December 31, 2017 —

—
 —
 —
Total 18,669
 $44.76
 —
 —
(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.
(1)In connection with restricted stock grants under the Company’s 2013 Long-Term Incentive Plan (“2013 Plan”), we adopted a policy that enables employees to surrender shares to cover their tax liability. Shares indicated as having been purchased in the table above represent shares surrendered by employees to cover tax liabilities. We paid the associated taxes to the applicable taxing authorities.
(2)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, 20172021 relating to equity compensation plans:
39

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—
—
14,538,540
8,492,645
Equity Compensation Plans Not Approved by Shareholders—
—
—
 
(1)Represents the remaining shares available for issuance under the 2013 Plan.

(1)Represents the remaining shares available for issuance under the 2013 Plan.

40

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, 20122016 through December 31, 2017.2021. The graph assumes the value of the investment in our common stock and in each index was $100 on December 31, 20122016 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



Item 6.Selected Financial Data
This section presents selected consolidated financial data for the years ended December 31, 2013 through 2017. The selected financial data presented below is not intended to replace our consolidated financial statements.
The following consolidated financial data has been derived from our audited consolidated financial statements for such periods. You should read the following selected financial data in connection with Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and our consolidated financial statements and related notes included elsewhere in this report. The selected consolidated results are not necessarily indicative of results to be expected in future periods.
41
  Year Ended December 31,
  2017 2016 2015 2014 2013
Income Statement data          
In thousands, except per share data  
Crude oil and natural gas sales $2,982,966
 $2,026,958
 $2,552,531
 $4,203,022
 $3,573,431
Gain (loss) on crude oil and natural gas derivatives, net (1) 91,647
 (71,859) 91,085
 559,759
 (191,751)
Total revenues 3,120,828
 1,980,273
 2,680,167
 4,801,618
 3,421,807
Income (loss) from continuing operations (2) 789,447
 (399,679) (353,668) 977,341
 764,219
Net income (loss) (2) 789,447
 (399,679) (353,668) 977,341
 764,219
Basic net income (loss) per share:          
From continuing operations $2.13
 $(1.08) $(0.96) $2.65
 $2.08
Net income (loss) per share $2.13
 $(1.08) $(0.96) $2.65
 $2.08
Shares used in basic income (loss) per share 371,066
 370,380
 369,540
 368,829
 368,150
Diluted net income (loss) per share:          
From continuing operations $2.11
 $(1.08) $(0.96) $2.64
 $2.07
Net income (loss) per share $2.11
 $(1.08) $(0.96) $2.64
 $2.07
Shares used in diluted income (loss) per share 373,768
 370,380
 369,540
 370,758
 369,698
Production volumes          
Crude oil (MBbl) (3) 50,536
 46,850
 53,517
 44,530
 34,989
Natural gas (MMcf) 228,159
 195,240
 164,454
 114,295
 87,730
Crude oil equivalents (MBoe) 88,562
 79,390
 80,926
 63,579
 49,610
Sales volumes          
Crude oil (MBbl) (3) 50,628
 46,802
 53,664
 44,122
 34,985
Natural gas (MMcf) 228,159
 195,240
 164,454
 114,295
 87,730
Crude oil equivalents (MBoe) 88,655
 79,342
 81,073
 63,172
 49,607
Average sales prices (4)          
Crude oil ($/Bbl) $45.70
 $35.51
 $40.50
 $81.26
 $89.93
Natural gas ($/Mcf) $2.93
 $1.87
 $2.31
 $5.40
 $4.87
Crude oil equivalents ($/Boe) $33.65
 $25.55
 $31.48
 $66.53
 $72.04
Average costs per unit (4)          
Production expenses ($/Boe) $3.66
 $3.65
 $4.30
 $5.58
 $5.69
Production taxes (% of oil and gas revenues) 7.0% 7.0% 7.8% 8.2% 8.3%
DD&A ($/Boe) $18.89
 $21.54
 $21.57
 $21.51
 $19.47
General and administrative expenses ($/Boe) (5) $2.16
 $2.14
 $2.34
 $2.92
 $2.91
Proved reserves at December 31          
Crude oil (MBbl) 640,949
 643,228
 700,514
 866,360
 737,788
Natural gas (MMcf) 4,140,281
 3,789,818
 3,151,786
 2,908,386
 2,078,020
Crude oil equivalents (MBoe) 1,330,995
 1,274,864
 1,225,811
 1,351,091
 1,084,125
Other financial data (in thousands)          
Net cash provided by operating activities $2,079,106
 $1,125,919
 $1,857,101
 $3,355,715
 $2,563,295
Net cash used in investing activities $(1,808,845) $(532,965) $(3,046,247) $(4,587,399) $(3,711,011)
Net cash (used in) provided by financing activities $(243,034) $(587,773) $1,187,189
 $1,227,715
 $1,140,469
Total capital expenditures $2,035,254
 $1,110,256
 $2,564,301
 $5,015,595
 $3,841,633
Balance Sheet data at December 31 (in thousands)          
Total assets $14,199,651
 $13,811,776
 $14,919,808
 $15,076,033
 $11,841,567
Long-term debt, including current portion $6,353,691
 $6,579,916
 $7,117,788
 $5,928,878
 $4,650,889
Shareholders’ equity $5,131,203
 $4,301,996
 $4,668,900
 $4,967,844
 $3,953,118


Item 6.    Reserved


42

(1)Crude oil and natural gas derivative instruments are not designated as hedges for accounting purposes and, therefore, changes in the fair value of the instruments are shown separately from crude oil and natural gas sales. The amounts above include non-cash mark-to-market gains (losses) on crude oil and natural gas derivatives of $62.1 million, ($160.7) million, $21.5 million, $174.4 million, and ($130.2) million for the years ended December 31, 2017, 2016, 2015, 2014, and 2013, respectively. Additionally, 2014 includes $433 million of gains recognized from crude oil derivative contracts that were settled in the fourth quarter of 2014 prior to their contractual maturities initially scheduled through December 2016.
(2)
Results for 2017 reflect the remeasurement of the Company's deferred income tax assets and liabilities in response to the enactment of the Tax Cuts and Jobs Act in December 2017, which resulted in a one-time increase in net income of approximately $713.7 million ($1.92 per basic share and $1.91 per diluted share). See Part II, Item 8. Notes to Consolidated Financial Statements—Note 8. Income Taxes for further discussion. Additionally, 2017 results include a $59.6 million pre-tax loss accrual recognized in conjunction with a litigation settlement as discussed in Part II, Item 8. Notes to Consolidated Financial Statements—Note 10. Commitments and Contingencies, which resulted in an after-tax decrease in 2017 net income of $37.0 million ($0.10 per basic and diluted share).

(3)At various times, we have stored crude oil due to pipeline line fill requirements, low commodity prices, or marketing disruptions or we have sold crude oil from inventory. These actions result in differences between our produced and sold crude oil volumes.
(4)Average sales prices and average costs per unit have been computed using sales volumes and exclude any effect of derivative transactions.
(5)General and administrative (“G&A”) expenses ($/Boe) include non-cash equity compensation expenses of $0.52 per Boe, $0.61 per Boe, $0.64 per Boe, $0.86 per Boe, and $0.80 per Boe for the years ended December 31, 2017, 2016, 2015, 2014, and 2013, respectively.



ITEM 7.Management’s Discussion and Analysis of Financial Condition and Results of Operations
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 as well as the selected consolidated financial data included elsewhere in this report. Our operatingResults attributable to noncontrolling interests are not material relative to consolidated results for the periodsand are not separately presented or discussed below may not be indicative of future performance. For additional discussion of crude oil and natural gas reserve information, please see Part I, Item 1. Business—Crude Oil and Natural Gas Operations.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.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. Our operationsWe are primarily focused on explorationthe largest leaseholder and development activitiesthe largest producer in the Bakken field of North Dakota and Montana andMontana. We also have significant positions in the SCOOP and STACK areas of Oklahoma.
Business Environmentplays in Oklahoma and Outlook
Continental marked its 50th anniversaryrecently acquired positions in the oilPermian Basin of Texas and gas business in 2017. Powder River Basin of Wyoming.Our leadership team has significant experience withcommon 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 in challenging commodity price environments. Commodity prices remained volatile during the year, but generally increasedhighlights for 2021 are summarized below. Our 2021 results underscore our continued focus on average in 2017 relative to 2016. Crude oil prices in particular showed significant signs of improvement in late 2017 and early 2018, with West Texas Intermediate crude oil benchmark prices reaching a three-year high of $66 per barrel in January 2018. With our portfolio of high quality assets, we are well-positioned to manage the ongoing challenges and price volatility facing our industry.
For 2018, our primary business strategies will focus on:
Balancing strong production growth with freemaximizing cash flow generation;generation, maintaining low-cost capital efficient operations in an environmentally responsible manner, achieving consistent asset performance, and delivering capital and corporate returns to shareholders.
Enhancing cash flows and return on capital employed through improvements•Generated $1.25 billion in operating efficiencies, technical innovations, and optimized completion methods;
Continuing to exercise disciplined capital spending to maintain financial flexibility and ample liquidity; and
Improving debt metrics by further reducing outstanding debt using available operating cash flows or proceeds from asset dispositions or joint development arrangements.
Based on an expectation for higher operating cash flows in 2018, we havethe 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 planned non-acquisition capital spending for 2018quarterly fixed dividend throughout year, paying $166 million of dividends in 2021 with an additional $82 million of declared dividends to $2.3 billion compared to $2.0 billion spent in 2017, with approximately 78% of our 2018 drilling and completion budget focusing on oil-weighted areasbe paid in the North Dakotafirst 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 SCOOP Springer plays.Oklahoma. We expect to fund our budgeted spending usingenhanced cash flows from operations. We may adjustthe 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 pace of drillingoperated crude oil production and development as 2018 market conditions evolve.
2017 Highlights
Productionassociated 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.
43

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 averaged 242,637(42,000 Boe per day in 2017, an increaseon average of 12% comparedwhich 78% was oil), $29.4 million of revenues, and $14.1 million ($0.04 per basic and diluted share) of net income to 2016.our consolidated results during the period of ownership from December 21, 2021 to December 31, 2021.
Total production
 Year ended December 31,
 202120202019
Average daily production:
Crude oil (Bbl per day)160,647 160,505 197,991 
Natural gas (Mcf per day)1,014,000 837,509 854,424 
Crude oil equivalents (Boe per day)329,647 300,090 340,395 
Average net sales prices: (1)
Crude oil ($/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 fourth quarter of 2017 averaged 286,985 Boe per day, an increase of 18%periods presented.
44

  Year Ended December 31,
In thousands, except sales price data202120202019
Crude oil and natural gas sales$5,793,741 $2,555,434 $4,514,389 
Gain (loss) on derivative instruments, net(128,864)(14,658)49,083 
Crude oil and natural gas service operations54,441 45,694 68,475 
Total revenues5,719,318 2,586,470 4,631,947 
Operating costs and expenses(3,257,638)(3,140,362)(3,374,535)
Other expenses, net(275,542)(220,859)(270,250)
Income (loss) before income taxes2,186,138 (774,751)987,162 
(Provision) benefit for income taxes(519,730)169,190 (212,689)
Net income (loss)1,666,408 (605,561)774,473 
Net income (loss) attributable to noncontrolling interests5,440 (8,692)(1,168)
Net income (loss) attributable to Continental Resources$1,660,968 $(596,869)$775,641 
Diluted net income (loss) per share attributable to Continental Resources$4.56 $(1.65)$2.08 
Production volumes:
Crude oil (MBbl)58,636 58,745 72,267 
Natural gas (MMcf)370,110 306,528 311,865 
Crude oil equivalents (MBoe)120,321 109,833 124,244 
Sales volumes:
Crude oil (MBbl)58,757 58,793 72,136 
Natural gas (MMcf)370,110 306,528 311,865 
Crude oil equivalents (MBoe)120,442 109,881 124,113 
Year ended December 31, 2021 compared to the third quarteryear ended December 31, 2020
Below is a discussion of 2017 and 37% higher than the fourth quarterchanges in our results of 2016.
Average daily crude oil production increased 8% in 2017operations for 2021 compared to 2016 while average daily natural gas production increased 17%.
Crude oil represented 57%2020. A discussion of changes in our results of operations for 2020 compared to 2019 has been omitted from this Form 10-K, but may be found in Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations of our 2017 production compared to 59% for 2016. Crude oil represented 59% of our productionForm 10-K for the fourth quarter of 2017 compared to 58% foryear ended December 31, 2020 as filed with the third quarter of 2017 and 55% for the fourth quarter of 2016.SEC on February 16, 2021.


Production
The following table summarizes the changes in our average daily Boe production by major operating area for the periods presented.
 Fourth QuarterYear Ended December 31,
Boe production per day20212020% Change20212020% Change
Bakken175,585 183,141 (4 %)169,636 158,604 7 %
Oklahoma146,131 149,341 (2 %)147,249 134,506 9 %
Powder River Basin7,189 — — %5,161 — — %
Permian Basin (1)4,997 — — %1,260 — — %
All other6,266 6,825 (8 %)6,341 6,980 (9 %)
Total340,168 339,307 — %329,647 300,090 10 %
  Fourth Quarter Year Ended December 31,
Boe production per day 2017 2016 % Change 2017 2016 % Change
Bakken 165,598
 104,524
 58% 132,992
 119,200
 12%
SCOOP 62,242
 63,490
 (2%) 60,693
 65,062
 (7%)
STACK 47,914
 24,426
 96% 36,220
 16,983
 113%
All other 11,231
 17,421
 (36%) 12,732
 15,667
 (19%)
Total 286,985
 209,861
 37% 242,637
 216,912
 12%
Revenues
Crude oil and natural gas revenues totaled $2.98 billion for 2017, a 47% increase compared to 2016 driven by a 32% increase in realized commodity prices coupled with a 12% increase in total sales volumes.
Crude oil and natural gas revenues totaled $1.02 billion for the 2017 fourth quarter, a 44% increase from the 2017 third quarter and 72% higher than the 2016 fourth quarter, reflecting an increase in well completion activities and improvement in commodity prices and price realizations in late 2017. Total sales volumes for the 2017 fourth quarter increased 20% and 38% and realized commodity prices increased 20% and 25% compared to the 2017 third quarter and 2016 fourth quarter, respectively.
Proved reserves
At December 31, 2017, our proved reserves totaled 1,331 MMBoe, an increase(1)The presentation of 4% from proved reserves of 1,275 MMBoe at December 31, 2016.
Extensions and discoveries from our drilling and completion activities added 240 MMBoe of proved reserves in 2017 and upward reserve revisions due to improved commodity prices increased reserves by 42 MMBoe. These increases were partially offset by 89 MMBoe ofaverage daily 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 the respective fourth quarter and full year and net downward reserve revisions totaling 124 MMBoe resulting from changes in drilling plans and other factors.
The following table summarizesperiods. At the changes intime of closing, our proved reserves by major operating area in 2017:
  December 31, 2017 December 31, 2016 Volume change Volume
percent
change
Proved reserves by area MBoe Percent MBoe Percent 
Bakken 635,521
 48% 591,901
 46% 43,620
 7%
SCOOP 491,776
 37% 471,921
 37% 19,855
 4%
STACK 167,390
 13% 161,243
 13% 6,147
 4%
All Other 36,308
 2% 49,799
 4% (13,491) (27%)
Total 1,330,995
 100% 1,274,864
 100% 56,131
 4%
Operating cash flows
Cash flows from operating activities totaled $2.08 billion for 2017, an increase of 85% compared to $1.13 billion for 2016, reflecting an increase in sales volumes and improvement in commodity prices and price realizations in 2017.
Capital expenditures and drilling activity
Full year 2017 non-acquisition capital expenditures totaledPermian properties produced on average approximately $2.00 billion compared to $1.07 billion for 2016, reflecting our planned increase in spending for 2017 in response to improved commodity prices.
In 2017 we participated in the drilling and completion of 608 gross (214 net) wells compared to 365 gross (92 net) wells in 2016.
2017 property dispositions
In September 2017 we sold non-strategic properties in the Arkoma Woodford area of Oklahoma for cash proceeds of $65.3 million. The sale included approximately 26,000 net acres of leasehold and producing properties with production totaling


approximately 1,70042,000 Boe per day. In connection with the transaction, we recognized a pre-tax loss of $3.5 million for the year ended December 31, 2017.
In September 2017, we reached an agreement to sell non-core leasehold in the STACK play in Blaine County, Oklahoma for cash proceeds totaling $63.5 million. A portion of the transaction closed in September 2017, resulting in the receipt of proceeds amounting to $3.6 million and the recognition of a $3.3 million pre-tax gainday based on sale in the 2017 third quarter. The remainder of the transaction was completed in October 2017 at which time we received the remaining $59.9 million of proceeds and recognized an additional pre-tax gain of approximately $53.6 million, which is reflected in fourth quarter 2017 results.
In September 2017, we sold certain oil-loading facilities in Oklahoma for $7.2 million and recognized a $4.2 million pre-tax gain for the year ended December 31, 2017 associated with the transaction.
Debt and liquidity
Total debt decreased $226 million, or 3%, to $6.35 billion at December 31, 2017 compared to $6.58 billion at year-end 2016.
In December 2017 we issued $1.0 billion of 4.375% Senior Notes due 2028 (“2028 Notes”) and received total net proceeds of $990 million after deducting the initial purchasers’ fees. We used the proceeds from the offering to repay in full and terminate our $500 million term loan due November 4, 2018 and to repay a portion of the borrowings outstanding under our revolving credit facility, thereby resulting in enhanced liquidity.
At December 31, 2017, we had $43.9 million of cash and cash equivalents and $2.56 billion of borrowing availability on our credit facility after considering outstanding borrowings and letters of credit. We had $188 million of credit facility borrowings at December 31, 2017 compared to $938 million at September 30, 2017 and $905 million at December 31, 2016. At January 31, 2018, outstanding credit facility borrowings decreased further to $93 million, leaving approximately $2.65 billion of borrowing availability at that date.
Impact of income tax reform legislation
In December 2017, the Tax Cuts and Jobs Act (the "Tax Reform Act") was signed into law, which among other things reduces the federal corporate income tax rate from 35% to 21% effective January 1, 2018. In accordance with U.S. GAAP, we remeasured our deferred income tax assets and liabilities as of December 31, 2017 to reflect the reduced tax rate, which resulted in a one-time decrease in income tax expense and corresponding increase in net income of approximately $713.7 million ($1.92 per basic share and $1.91 per diluted share) recognized in the 2017 fourth quarter. See the subsequent section titled Legislative and Regulatory Developments–Tax Reform Legislation and Part II, Item 8. Notes to Consolidated Financial Statements—Note 8. Income Taxes for further discussion of the Tax Reform Act.
Litigation settlement
On February 16, 2018, we reached a settlement in connection with the case filed in November 2010 in the District Court of Blaine County by Billy J. Strack and Daniela A. Renner as trustees of certain named trusts and on behalf of other similarly situated parties against the Company. Under the settlement, if approved by the court, we will make payments and incur costs associated with the settlement of approximately $59.6 million. We have accrued a loss for such amount, which is included in “Accrued liabilities and other” on the consolidated balance sheets and “Litigation settlement” in the consolidated statements of comprehensive income (loss) as of and for the year ended December 31, 2017, which resulted in an after-tax decrease in 2017 net income of $37.0 million ($0.10 per basic and diluted share). See Part II, Item 8. Notes to Consolidated Financial Statements—Note 10. Commitments and Contingencies for further discussion.
Financial and operating highlights
We use a variety of financial and operating measures to assess our performance. Among these measures are:
Volumes of crude oil and natural gas produced;
Crude oil and natural gas price differentials relative to NYMEX benchmark prices; and
Per unit operating and administrative costs.


The following table contains financial and operating highlights for the periods presented. Average sales prices exclude any effect of derivative transactions. Per-unit expenses have been calculated using sales volumes.
  Year ended December 31,
  2017 2016 2015
Average daily production:      
Crude oil (Bbl per day) 138,455
 128,005
 146,622
Natural gas (Mcf per day) 625,093
 533,442
 450,558
Crude oil equivalents (Boe per day) 242,637
 216,912
 221,715
Average sales prices:      
Crude oil ($/Bbl) $45.70
 $35.51
 $40.50
Natural gas ($/Mcf) $2.93
 $1.87
 $2.31
Crude oil equivalents ($/Boe) $33.65
 $25.55
 $31.48
Crude oil sales price discount to NYMEX ($/Bbl) $(5.50) $(7.33) $(8.33)
Natural gas sales price discount to NYMEX ($/Mcf) $(0.16) $(0.61) $(0.34)
Production expenses ($/Boe) $3.66
 $3.65
 $4.30
Production taxes (% of oil and gas revenues) 7.0% 7.0% 7.8%
DD&A ($/Boe) $18.89
 $21.54
 $21.57
Total general and administrative expenses ($/Boe) $2.16
 $2.14
 $2.34





Results of Operations
The following table presents selected financial and operating information for the periods presented.
   Year Ended December 31,
In thousands, except sales price data 2017 2016 2015
Crude oil and natural gas sales $2,982,966
 $2,026,958
 $2,552,531
Gain (loss) on crude oil and natural gas derivatives, net 91,647
 (71,859) 91,085
Crude oil and natural gas service operations 46,215
 25,174
 36,551
Total revenues 3,120,828
 1,980,273
 2,680,167
Operating costs and expenses (1) (2,671,427) (2,267,807) (2,904,168)
Other expenses, net (2) (293,334) (344,920) (311,084)
Income (loss) before income taxes 156,067
 (632,454) (535,085)
Benefit for income taxes (3) 633,380
 232,775
 181,417
Net income (loss) $789,447
 $(399,679) $(353,668)
Diluted net income (loss) per share $2.11
 $(1.08) $(0.96)
Production volumes:      
Crude oil (MBbl) 50,536
 46,850
 53,517
Natural gas (MMcf) 228,159
 195,240
 164,454
Crude oil equivalents (MBoe) 88,562
 79,390
 80,926
Sales volumes:      
Crude oil (MBbl) 50,628
 46,802
 53,664
Natural gas (MMcf) 228,159
 195,240
 164,454
Crude oil equivalents (MBoe) 88,655
 79,342
 81,073
Average sales prices:      
Crude oil ($/Bbl) $45.70
 $35.51
 $40.50
Natural gas ($/Mcf) $2.93
 $1.87
 $2.31
Crude oil equivalents ($/Boe) $33.65
 $25.55
 $31.48
(1)Net of gain on sale of assets of $55.1 million, $304.5 million and $23.1 million for the years ended December 31, 2017, 2016 and 2015, respectively. Additionally, the year 2017 includes the aforementioned $59.6 million loss accrual recognized in conjunction with a litigation settlement.
(2)The year 2016 includes a loss on extinguishment of debt of $26.1 million related to the November 2016 redemptions of our $200 million of 7.375% Senior Notes due 2020 and $400 million of 7.125% Senior Notes due 2021.
(3)The year 2017 reflects the remeasurement of our deferred income tax assets and liabilities in response to the enactment of the Tax Reform Act in December 2017, which resulted in a one-time decrease in income tax expense via the recognition of an income tax benefit totaling approximately $713.7 million.
Year ended December 31, 2017 compared to the year ended December 31, 2016
Productiontwo-stream reporting.
The following tables reflect our production by product and region for the periods presented.
45

 Year Ended December 31, Volume
increase		 Volume
percent
increase		 Year Ended December 31,Volume increase
(decrease)		Volume
percent increase
(decrease)
 2017 2016  20212020
 Volume Percent Volume Percent  VolumePercentVolumePercent
Crude oil (MBbl) 50,536
 57% 46,850
 59% 3,686
 8%Crude oil (MBbl)58,636 49 %58,745 53 %(109)— %
Natural gas (MMcf) 228,159
 43% 195,240
 41% 32,919
 17%Natural gas (MMcf)370,110 51 %306,528 47 %63,582 21 %
Total (MBoe) 88,562
 100% 79,390
 100% 9,172
 12%Total (MBoe)120,321 100 %109,833 100 %10,488 10 %
 

 Year Ended December 31,Volume increaseVolume
percent
increase
 20212020
 MBoePercentMBoePercent
North Region66,105 55 %60,591 55 %5,514 9 %
South Region54,216 45 %49,242 45 %4,974 10 %
Total120,321 100 %109,833 100 %10,488 10 %

  Year Ended December 31, Volume
increase		 Volume
percent
increase
  2017 2016 
  MBoe Percent MBoe Percent 
North Region 52,258
 59% 48,169
 61% 4,089
 8%
South Region 36,304
 41% 31,221
 39% 5,083
 16%
Total 88,562
 100% 79,390
 100% 9,172
 12%
The 8% increaseOver the past year we increased our allocation of capital to gas-weighted projects to capitalize on improvements in crude oil production in 2017 compared to 2016 was primarily driven by a 4,241 MBbls, or 13%, increase in production from properties in North Dakota Bakken duemarket prices for natural gas and natural gas liquids. These actions contributed to an increase in well completion activities, the timing of production commencing from new pad development projects, and strong initial production results being achieved on new wells resulting from optimized completion technologies. Additionally, production from our South region properties in the STACK play increased 1,614 MBbls, or 104%, from the prior year due to additional wells being completed and producing as a result of an increase in our drilling and completion activities in that area. These increases were partially offset by decreased production from our North region properties in Montana Bakken and the Red River units due to natural declines in production coupled with reduced drilling activities over the past year. Montana Bakken crude oil production decreased 692 MBbls, or 24%, while crude oil production in the Red River units decreased 344 MBbls, or 9%, from the prior year. Additionally, crude oil production in SCOOP decreased 1,081 MBbls, or 16%, due to natural declines in production and limited drilling activities.
The 17% increase in natural gas production in 2017 compared to 2016 was driven by increased production from our properties in the STACK play due to additional wells being completed and producing subsequent to December 31, 2016. Natural gas production in STACK increased 32,342 MMcf, or 116%, over the prior year. Additionally, natural gas production in North Dakota Bakken increased 8,700 MMcf, or 17%, over the prior year in conjunction with the aforementioned increase in crude oil production. These increases were partially offset by reduced production from our SCOOP properties, which decreased 3,469 MMcf, or 3%, along with various other areas in our North and South regions due to natural declines in production and limited drilling activities. Further, natural gas production decreased 1,323 MMcf in 2017 as a result of the sale of substantially all of our Arkoma Woodford properties in September 2017.

The increase in natural gas production as a percentage of our total production from 41% in 2016and led to 43% in 2017 primarily resulted from the significanta 21% increase in STACK natural gas production duein 2021 compared to 2020. Natural gas production in Oklahoma increased 37,345 MMcf, or 18%, and natural gas production in the Bakken increased allocation of capital to that area23,122 MMcf, or 23%, over the pastprior year. Certain areasAdditionally, properties acquired in the STACK play produce a higher concentration ofPowder River Basin in March and November 2021 added 2,517 MMcf to our natural gas compared to oil-weightedproduction, while properties acquired in the Permian Basin added 614 MMcf during the short duration of our ownership of the properties in the Bakken. late 2021.
Our crude oil production grewwas flat in relative significance2021 compared to 2020 resulting from our change in allocation of capital from oil-weighted projects to gas-weighted projects over the past year and the timing of well completions. Crude oil production in the second half of 2017 as we increasedBakken was flat between years, while oil production in Oklahoma decreased 1,708 MBbls, or 12%, compared to 2020. This decrease was offset by new production added from our well completion activities2021 acquisitions. Properties acquired in North Dakota Bakkenthe Powder River Basin in responseMarch and November 2021 added 1,464 MBbls to improvedour crude oil market prices. Crude oil represented 59%production, while properties acquired in the Permian Basin added 357 MBbls during the short duration of our production forownership of the fourth quarter of 2017 compared to 55% for the fourth quarter of 2016.
In conjunction with our planned increaseproperties in capital spending for 2018, we expect our production will average between 285,000 and 300,000 Boe per day for full year 2018 compared to average daily production of 242,637 Boe per day for 2017.late 2021.
Revenues
Our revenues consist of sales of crude oil and natural gas, gains and losses resulting from changes in the fair value of our crude oil and natural gas derivative instruments, and revenues associated with crude oil and natural gas service operations.
CrudeNet crude oil and natural gas sales and related net sales prices presented below are non-GAAP measures. See the subsequent section titled Non-GAAP Financial Measures for discussion and calculation of these measures.
Net crude oil and natural gas sales. Crude Net crude oil and natural gas sales for 2017 were $2.982021 totaled $5.57 billion, a 47%136% increase fromcompared to net sales of $2.03$2.36 billion for 20162020 due to a 32% increasesignificant increases in realized commoditynet sales prices coupled with a 12% increaseand natural gas sales volumes as discussed below.
Total sales volumes for 2021 increased 10,561 MBoe, or 10%, compared to 2020, reflecting reduced sales in totalthe prior period from the previously described production curtailments in the second and third quarters of 2020 and our subsequent resumption of usual operations. For 2021, our crude oil sales volumes.volumes were flat compared to 2020, while our natural gas sales volumes increased 21% driven by our increased allocation of capital toward gas-weighted projects over the past year.
Our crude oil net sales prices averaged $45.70$64.06 per barrel for 2017,2021, an increase of 29%85% compared to $35.51$34.71 per barrel for 20162020 due to higher crude oila significant increase in market prices driven by improved supply and demand fundamentals along with improved price realizations.differentials. The differential between NYMEX West Texas Intermediate (“WTI”) calendar month crude oil prices and our realized crude oil net sales prices averaged $5.50 per barrel for 2017 compared to $7.33 for 2016. The improved differential was primarily due to improved realizations resulting from new pipeline takeaway capacity and additional markets becoming available in 2017 for Bakken production, along with the growth in our South region production which typically has lower transportation costs compared to the Bakken due to its relatively close proximity to regional refineries and the crude oil trading hub in Cushing, Oklahoma. These factors led to a continued improvement in crude oil price realizations throughout 2017. Our crude oil price differentials relative to WTI prices improved to $4.23$4.00 per barrel in 2021 compared to $5.80 per barrel in 2020. Crude oil prices for 2020 were severely impacted by adverse changes in supply and demand fundamentals from the fourth quarter.economic effects of the COVID-19 pandemic, which negatively impacted location differentials and price realizations in the 2020 period with no similar impacts in 2021.
Our natural gas net sales prices averaged $2.93$4.88 per Mcf for 2017, a 57% increase2021 compared to $1.87$1.04 per Mcf for 20162020 due to highera significant increase in market prices for natural gas and natural gas liquids (“NGLs”) and improved price realizations.differentials. The discountdifference between our realized natural gasnet sales prices and NYMEX Henry Hub calendar month natural gas prices improved from $0.61was a premium of $1.00 per Mcf for 20162021 compared to $0.16a discount of $1.10 per Mcf for 2017. The majority2020.
46

In February 2021, severe winter weather and freezing temperatures in the southern United States led to a period of ourincreased spot prices for residue natural gas production is sold atthat resulted in a significant improvement in our lease locations to midstream


purchasers with price realizations impacted byin the volume and value of NGLs that purchasers extract from our sales stream. NGL2021 first quarter compared to the prior year. Additionally, prices for natural gas liquids have increased over prior yearsignificantly in 2021 compared to 2020 levels in conjunction with increased crude oil prices and other factors, resulting in improved price realizations for our natural gas sales stream, particularly in later monthsstream. For the fourth quarter of 2017. Our realized natural gas2021, the difference between our net sales prices averaged $3.30 per Mcf in the 2017 fourth quarter, representingand NYMEX Henry Hub prices was a premium of $0.37$0.49 per Mcf over Henry Hub benchmark prices for that period.Mcf.
Total sales volumes for 2017 increased 9,313 MBoe, or 12%, compared to 2016, reflecting an increaseDerivatives. The significant improvement in our pace of drilling and completion activities in 2017. For 2017, our crude oil sales volumes increased 8% compared to 2016 while our natural gas sales volumes increased 17%.
For the 2017 fourth quarter, crude oil and natural gas revenues totaled $1,017.7 million, representing a 44% increase from 2017 third quarter revenues of $704.8 million and a 72% increase from 2016 fourth quarter revenues of $591.8 million. Revenues for the 2017 fourth quarter were favorably impacted by improved commodity prices and price realizations late in the year. Our crude oil sales prices averaged $51.16 per barrel in the 2017 fourth quarter compared to $43.27 for the 2017 third quarter and $42.23 for the 2016 fourth quarter. Our natural gas sales prices averaged $3.30 per Mcf in the 2017 fourth quarter compared to $2.74 for the 2017 third quarter and $2.70 for the 2016 fourth quarter.
New accounting rules governing the recognition and presentation of revenues went into effect on January 1, 2018. The new rules are not expected to have a material effect on the timing of our revenue recognition, but will impact our presentation of revenues and expenses. Historically, we have generally presented our revenues net of transportation costs. The new guidance will result in future revenues and transportation expenses for certain of our operated properties being reported on a gross basis, with no net effect on our results of operations, net income, or cash flows. For the 2017 fourth quarter, we had approximately $53.4 million of transportation–related charges on operated properties included in “Crude oil and natural gas sales”. The amount of future transportation expenses to be reported on a gross basis in our 2018 first quarter results is estimated to be approximately $50 million.
Derivatives. Changes in natural gas prices during 20172021 had an overall favorableunfavorable impact on the fair value of our derivatives, which resulted in positivenegative revenue adjustments of $91.6$128.9 million for the year, representing $62.1 million of non-cash gains and $29.5$149.7 million of cash losses partially offset by $20.8 million of unsettled non-cash gains. For 2020, we recognized negative revenue adjustments of $14.7 million resulting from changes in market prices that had an unfavorable impact on the fair value of our derivatives. 
Crude oil and natural gas service operations. Our crude oil and natural gas service operations consist primarily of revenues associated with water gathering, recycling, and disposal activities, which are impacted by our production volumes and the treatmenttiming and saleextent of lower quality reclaimed crude oil.our drilling and completion projects. Revenues associated with such activities increased $21.0$8.7 million, or 84%19%, from $25.2$45.7 million for 20162020 to $46.2$54.4 million for 20172021 due to an increaseincreased water handling activities resulting from increases in industry productioncompletion activities and changes in the nature, timing and extent of water handling and recycling activities between periods.production volumes compared to 2020.
Operating Costs and Expenses
Production expenses. Production expenses increased $34.9$47.6 million, or 12%13%, from $289.3to $406.9 million for 20162021 compared to $324.2$359.3 million for 20172020 primarily due to anthe previously described 10% increase in the number of producing wells and higher workover-related activities aimed at enhancing production from producing properties.total sales volumes. Production expenses on a per-Boe basis averaged $3.66 for 2017, consistent with $3.65$3.38 per Boe for 2016. Our per-unit production expenses decreased to $3.172021, consistent with $3.27 per Boe for the 2017 fourth quarter.2020.
Production taxes. Production taxes increased $65.9$211.6 million, or 46%110%, to $208.3$404.4 million in 2017for 2021 compared to $142.4$192.7 million in 2016for 2020 due to higherthe previously described increase in crude oil and natural gas revenues resulting from increasessales partially offset by a decrease in sales volumes and commodity prices over the prior year period. Production taxes are generally based on the wellhead values ofour average production and vary by state. Productiontax rate. Our production taxes as a percentage of net crude oil and natural gas revenues averaged 7.0%sales decreased to 7.3% for 2017, consistent with the 2016 average of 7.0%.
Our production tax rate increased2021 compared to 8.2% for 2020 primarily resulting from an increase in the second halfproportion of 2017 relative to the first half and averaged 7.3% for the 2017 fourth quarter. This increase primarily resulted from a significant increase in production andour revenues being generated in North Dakota from increased well completions laterOklahoma in the year,current period, which has higherlower production tax rates compared to Oklahoma. The production tax rate on new wells in North Dakota is currently 10% of crude oil revenues. The production tax rate on Oklahoma wells that commenced production after July 1, 2015 is currently 2% of crude oil and natural gas revenues for the first 36 months of production and 7% thereafter. Additionally, in 2017 new legislation was enacted in Oklahoma that increased the production tax rate from 1% to 4% and again from 4% to 7% on wells that began producing between July 1, 2011 and July 1, 2015. The new 4% tax rate on these wells went into effect on July 1, 2017, which was subsequently increased to 7% effective December 1, 2017, and contributed to an increase in our average production tax rate in the third and fourth quarters of 2017.Dakota.


Exploration expenses. Exploration expenses consist primarily of dry hole costs and exploratory geological and geophysical costs that are expensed as incurred. The following table shows the components of exploration expenses for the periods presented.
  Year ended December 31,
In thousands 2017 2016
Geological and geophysical costs $12,217
 $12,106
Exploratory dry hole costs 176
 4,866
Exploration expenses $12,393
 $16,972
Depreciation, depletion, amortization and accretion (“DD&A”). Total DD&A decreased $33.8 million, or 2%,amounted to $1.67$1.90 billion for 2017 compared to $1.712021, consistent with $1.88 billion for 2016 primarily due to an2020, reflecting a 10% increase in the volume of proved reserves over which costs are depleted as further discussed below,total sales volumes the impact of which was partiallynearly offset by an increasea decrease in our DD&A resulting from higher sales volumes in the current year.rate per Boe as further discussed below. The following table shows the components of our DD&A on a unit of sales basis for the periods presented.
 Year ended December 31, Year ended December 31,
$/Boe 2017 2016$/Boe20212020
Crude oil and natural gas properties $18.57
 $21.09
Crude oil and natural gas properties$15.45 $16.84 
Other equipment 0.25
 0.37
Other equipment0.22 0.19 
Asset retirement obligation accretion 0.07
 0.08
Asset retirement obligation accretion0.09 0.09 
Depreciation, depletion, amortization and accretion $18.89
 $21.54
Depreciation, depletion, amortization and accretion$15.76 $17.12 
Estimated proved reserves are a key component in our computation of DD&A expense. Proved reserves are determined using the unweighted arithmetic average of the first-day-of-the-month commodity prices for the preceding twelve months as required by SEC rules. Holding all other factors constant, if proved reserves are revised downward due to commodity price declines or other reasons, the rate at which we record DD&A expense increases. Conversely, if proved reserves are revised upward, the rate at which we record DD&A expense decreases. Upward revisions to
Our proved reserves over the past year duewere revised upward in part to an improvement2021 prompted by significant increases in first-day-of-the-month commodity prices contributed toand other factors, which resulted in a decrease in our DD&A rate for crude oil and natural gas properties in 2017the current period. As a result of these upward revisions, our DD&A rate decreased to $14.34 per Boe for the 2021 fourth quarter compared to 2016. Additionally, improvements$19.01 per Boe for the 2020 fourth quarter, the impact of which helped offset higher DD&A recognized in drilling efficiencies2021 from increased sales volumes.
NYMEX WTI crude oil and optimized completion technologies over the past year have resultedHenry 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, which are notably higher than average prices in a significant improvement in the quantity2021. If commodity prices remain at current levels for an extended period, additional upward price-related revisions of proved reserves foundmay occur in the future, which may be significant and developed per dollar invested, which also contributed to the reductioncould result in a further decrease in our DD&A rate relative to the 2021 fourth quarter. We are unable to predict the timing and amount of future reserve revisions or the impact such revisions may have on our future DD&A rate.
47

Property impairments. Property impairments decreased $239.6 million to $38.4 million for 2021 compared to $277.9 million for 2020, primarily reflecting lower proved property impairments in the current period.
Property impairments. Property impairments totaled $237.4 million for 2017, consistent with $237.3 million of impairments recognized in 2016. HigherNo proved property impairments were recognized in 20172021 as estimated future net cash flows were offset by lower non-producing property impairments as discussed below.
Proveddetermined to be in excess of cost basis due to improved commodity prices, while proved property impairments totaled $82.3$207.1 million for 2017in 2020. Additionally, impairments of unproved properties decreased $32.5 million in 2021 compared to $2.9 million for 2016. The proved property impairments recognized2020 reflecting a decrease in 2017, nearly all of which were recognized in the second quarter, were primarily concentrated in the Arkoma Woodford field for which we determined the carrying amount of the field was not recoverable from future cash flows and, therefore, was impaired at June 30, 2017.
Impairments of non-producing properties decreased $79.4 million, or 34%, to $155.0 million in 2017 compared to $234.4 million for 2016. The decrease was due to a lower balance of unamortized leasehold costs in the current year due to property dispositions and reduced land capital expenditures in recent years, along with changes in the timing and magnitude of amortization of undeveloped leasehold costs between periods resulting from changes in the Company’smanagement's estimates of undeveloped properties not expected to be developed before lease expiration.expiration in response to significantly improved commodity prices compared to the prior year. Our unamortized balance of unproved properties increased significantly in late 2021 in connection with our 2021 fourth quarter property acquisitions and now totals $1.36 billion at December 31, 2021. Accordingly, our amortized impairments of unproved property costs are expected to increase in 2022 relative to 2021 levels, the amount of which is uncertain.
General and administrative ("G&A") expenses. Total general and administrative (“G&A”)&A expenses increased $22.1$37.0 million, or 13%19%, to $191.7$233.6 million in 2017 from $169.6for 2021 compared to $196.6 million in 2016. for 2020.
Total G&A expenses include non-cash charges for equity compensation of$45.9 $63.2 million and $48.1$64.6 million for 20172021 and 2016, respectively, the decrease of which resulted from changes in the timing and magnitude of forfeitures of unvested restricted stock between periods.
2020, respectively. G&A expenses other than equity compensation included in the total G&A expense figure above totaled $145.8$170.4 million for 2017,2021, an increase of $24.3$38.4 million, or 20%29%, compared to $121.5$132.0 million for 2016. This increase was primarily2020 due to an increase in employee compensation and benefits in 2017 in response to the stabilization and improvement in commodity prices over the past year, partially offset by higher overhead recoveries from joint interest owners driven by increased drilling, completion, and production activities over the prior period.


compared to 2020.
The following table shows the components of G&A expenses on a unit of sales basis for the periods presented.
  Year ended December 31,
$/Boe20212020
General and administrative expenses$1.42 $1.20 
Non-cash equity compensation0.52 0.59 
Total general and administrative expenses$1.94 $1.79 
   Year ended December 31,
$/Boe 2017 2016
General and administrative expenses $1.64
 $1.53
Non-cash equity compensation 0.52
 0.61
Total general and administrative expenses $2.16
 $2.14
Acquisition costs. We incurred $13.9 million of expenses in connection with our December 2021 acquisition of properties in the Permian Basin, which are reflected in the caption “Acquisition costs” in the consolidated statements of comprehensive income (loss) for 2021.
Interest expense. Interest expense decreased $26.1$6.6 million, or 8%3%, to $294.5$251.6 million in 2017 from $320.6for 2021 compared to $258.2 million in 2016for 2020 due to a decrease in our annual weighted average outstanding debt primarily as a resultfrom $5.8 billion in 2020 to $5.6 billion in 2021. Our outstanding debt totaled $6.8 billion at December 31, 2021, reflecting an increase of $2.1 billion in the November 2016 redemptions of our $200 million of 7.375% 2020 Notes and $400 million of 7.125% 2021 Notes. Our weighted average outstanding long-term debt balance for 2017 was approximately $6.7 billion with a weighted average interest rate of 4.2% comparedfourth quarter due to $7.1 billion and 4.3% for 2016. The lower interest expense associated with reduced debt was partially offset by higher interest expense being incurred on our variable-rate credit facility and term loansenior note borrowings dueincurred to an increase in market interest rates in 2017.
Income Taxes. Our income before income taxes totaled $156.1 million for the year endedfund a portion of our December 31, 2017, nearly all2021 acquisition of which was generated by our operationsproperties in the United States. We provided for income taxesPermian Basin.
Gain (loss) on this amount at a combined federal and state tax rateextinguishment of 38% of pre-tax income generated in the United States and 25% of immaterial pre-tax losses generated by our operations in Canada. The application of these statutory tax rates to pre-tax earnings, combined with the impact of permanent taxable differences, valuation allowances and tax deficiencies from stock-based compensation, resulted in the recognition of $80.3 million of income tax expense for 2017.
Additionally, we remeasured our deferred income tax balances in December 2017 in response to the enactment of the Tax Reform Act, which resulted in a one-time decrease in income tax expense via the recognition of an income tax benefit totaling approximately $713.7 million. Upon combining the tax benefit from this remeasurement with the tax provision recognized on pre-tax earnings from operations, we recognized a net total income tax benefit of $633.4 million for 2017.
The remeasurement event caused a significant inconsistency in the relationship between income tax expense/benefit and pre-tax income and resulted in a negative effective tax rate for 2017.debt. See Part II, Item 8. Notes to Consolidated Financial Statements—Note 8. Income TaxesLong-Term Debt for further discussion of thisgains and other sourceslosses recognized on debt extinguishments in 2021 and tax effects2020.
Other non-operating expense. As discussed in Part II, Item 8. Notes to Consolidated Financial Statements—Note 13. Commitments and Contingencies—Pledge commitment, we recognized a $25.0 million charge to earnings upon execution of items comprising our effective tax rate for 2017. Also, see the subsequent section titled "Legislative and Regulatory Developments–Tax Reform Legislation" for a forward-looking discussion of the potential impact of the Tax Reform Act on our business.
For the year endedan irrevocable ten-year pledge commitment in December 31, 2016, we recorded an income tax benefit of $232.8 million, resulting in an effective tax rate of approximately 37% after taking into account permanent taxable differences and valuation allowances.
Year ended December 31, 2016 compared to the year ended December 31, 2015
Production
The following tables reflect our production by product and region for the periods presented.
  Year Ended December 31, Volume
increase (decrease)		 Volume
percent
increase (decrease)
  2016 2015 
  Volume Percent Volume Percent 
Crude oil (MBbl) 46,850
 59% 53,517
 66% (6,667) (12%)
Natural Gas (MMcf) 195,240
 41% 164,454
 34% 30,786
 19%
Total (MBoe) 79,390
 100% 80,926
 100% (1,536) (2%)
  Year Ended December 31, Volume
increase (decrease)		 Volume percent
increase (decrease)
  2016 2015 
  MBoe Percent MBoe Percent 
North Region 48,169
 61% 54,956
 68% (6,787) (12%)
South Region 31,221
 39% 25,970
 32% 5,251
 20%
Total 79,390
 100% 80,926
 100% (1,536) (2%)
The 12% decrease in crude oil production in 2016 compared to 2015 was driven by decreased production from our North region properties in North Dakota Bakken, Montana Bakken, and the Red River units due to natural declines in production,


reduced drilling and completion activities, and curtailment of production in those areas in 2016 resulting from low crude oil prices. Additionally, the effects of severe winter weather in North Dakota in late 2016 adversely impacted our production. North Dakota Bakken 2016 crude oil production decreased 5,816 MBbls, or 15%, and Montana Bakken production decreased 1,090 MBbls, or 28%, while production2021, which is reflected in the Red River units decreased 543 MBbls, or 13%, from the prior year. Additionally, 2016 crude oil production in SCOOP decreased 390 MBbls, or 5%, resulting from a shift in our activities to liquids-rich natural gas areas of that play offering higher rates of return and opportunities to convert undeveloped acreage to acreage held by production. These decreases were partially offset by an increase of 1,307 MBbls in crude oil production from our STACK properties due to additional wells being completed and producing as a result of a shift in our drilling and completion activities to high rate-of-return opportunities in that area.
The 19% increase in natural gas production in 2016 compared to 2015 was driven by increased production from our propertiescaption “Other income (expense)—Other” in the STACKconsolidated statements of comprehensive income (loss) for 2021.
Income Taxes. For 2021 and SCOOP plays due to additional wells being completed and producing subsequent to December 31, 2015. Natural gas production in STACK for 2016 increased 17,279 MMcf, or 161%, and SCOOP production increased 10,345 MMcf, or 11%, over the prior year. Additionally, North Dakota Bakken natural gas production for 2016 increased 3,107 MMcf, or 7%, due to an increase in gas capture from non-operated properties and resulting increase in volumes produced and delivered to market. These increases were partially offset by decreases in production from various areas in our North and South regions primarily due to natural declines in production.
The increase in natural gas production as a percentage of our total production from 34% in 2015 to 41% in 2016 primarily resulted from significant increases in STACK and SCOOP production due to a shift in our well completion activities away from the Bakken to higher rate-of-return areas in Oklahoma. Certain areas in STACK and SCOOP produce a higher concentration of natural gas compared to oil-weighted properties in the Bakken.
Revenues
Crude oil and natural gas sales. Crude oil and natural gas sales for 2016 were $2.03 billion, a 21% decrease from sales of $2.55 billion for 2015 due to decreases in commodity prices and total sales volumes.
Our crude oil sales prices averaged $35.51 per barrel for 2016, a decrease of 12% compared to $40.50 for 2015 due to lower market prices. The differential between NYMEX WTI calendar month crude oil prices and our realized crude oil prices averaged $7.33 per barrel for 2016 compared to $8.33 for 2015. The improved differential was due to increased use of pipeline transportation to move our North region crude oil to market with less dependence on more costly rail transportation, along with significant growth in our South region production which typically has lower transportation costs compared to the Bakken due to its relatively close proximity to regional refineries and the crude oil trading hub in Cushing, Oklahoma.
Our natural gas sales prices averaged $1.87 per Mcf for 2016, a 19% decrease compared to $2.31 per Mcf for 2015 due to lower market prices and the amendment of certain natural gas sales agreements in 2016. The amended contracts contributed to an increase in the discount between our realized natural gas sales prices and NYMEX Henry Hub calendar month natural gas prices from $0.34 per Mcf for 2015 to $0.61 per Mcf for 2016.
Our total sales volumes for 2016 decreased 1,731 MBoe, or 2%, compared to 2015, reflecting natural production declines coupled with our reduced pace of drilling and completion activities during the year. For 2016, our crude oil sales volumes decreased 13% compared to 2015, while our natural gas sales volumes increased 19%, reflecting the shift in our well completion activities away from oil-weighted properties in the Bakken to areas in Oklahoma with higher concentrations of natural gas.
For the 2016 fourth quarter, crude oil and natural gas revenues totaled $591.8 million, representing a 17% increase from 2016 third quarter revenues of $505.9 million and a 7% increase from 2015 fourth quarter revenues of $551.4 million. Revenues for the 2016 fourth quarter were favorably impacted by increases in crude oil, natural gas and NGL market prices late in the year. Our crude oil sales prices averaged $42.23 per barrel in the 2016 fourth quarter compared to $37.66 for the 2016 third quarter and $34.23 for the 2015 fourth quarter. Our natural gas sales prices averaged $2.70 per Mcf in the 2016 fourth quarter compared to $2.02 for the 2016 third quarter and $2.07 for the 2015 fourth quarter.
Derivatives. Changes in natural gas prices during 2016 had an overall unfavorable impact on the fair value of our derivatives, which resulted in negative revenue adjustments of $71.9 million for the year, representing $160.7 million of non-cash losses partially offset by $88.8 million of cash gains.
Crude oil and natural gas service operations. Our crude oil and natural gas service operations consist primarily of revenues associated with water gathering, recycling, and disposal activities and the treatment and sale of lower quality reclaimed crude oil. Revenues associated with such activities decreased $11.4 million, or 31%, from $36.6 million for 2015 to $25.2 million for 2016 due to a reduction in handling and treatment activities resulting from a slow down in industry production activities.


Operating Costs and Expenses
Production expenses. Production expenses decreased $59.6 million, or 17%, from $348.9 million for 2015 to $289.3 million for 2016. Production expenses on a per-Boe basis decreased to $3.65 for 2016 compared to $4.30 for 2015. These decreases primarily resulted from reduced service costs being realized in response to depressed commodity prices, increased availability and use of water gathering and recycling facilities over the prior year period, and a higher portion of our production coming from wells in Oklahoma which typically have lower operating costs compared to wells in the Bakken.
Production taxes. Production taxes decreased $58.2 million, or 29%, to $142.4 million in 2016 compared to $200.6 million in 2015 primarily due to lower crude oil and natural gas revenues resulting from decreases in commodity prices and total sales volumes over the prior year. Production taxes as a percentage of crude oil and natural gas revenues were 7.0% for 2016 compared to 7.8% for 2015, the decrease of which resulted from significant growth over the past year in our STACK and SCOOP operations and resulting increase in revenues coming from Oklahoma, which has lower production tax rates compared to North Dakota.
Exploration expenses. The following table shows the components of exploration expenses for the periods presented.
  Year ended December 31,
In thousands 2016 2015
Geological and geophysical costs $12,106
 $11,032
Exploratory dry hole costs 4,866
 8,381
Exploration expenses $16,972
 $19,413
Dry hole costs incurred in 2016 and 2015 primarily reflect costs associated with unsuccessful wells in non-core areas of our North region.
Depreciation, depletion, amortization and accretion. Total DD&A decreased $40.3 million, or 2%, to $1.71 billion for 2016 compared to $1.75 billion for 2015 primarily due to a 2% decrease in sales volumes. The following table shows the components of our DD&A on a unit of sales basis.
  Year ended December 31,
$/Boe 2016 2015
Crude oil and natural gas properties $21.09
 $21.18
Other equipment 0.37
 0.33
Asset retirement obligation accretion 0.08
 0.06
Depreciation, depletion, amortization and accretion $21.54
 $21.57
Property impairments. Total property impairments decreased $164.8 million, or 41%, to $237.3 million for 2016 compared to $402.1 million for 2015. Proved property impairments totaled $2.9 million for 2016 compared to $138.9 million for 2015. This decrease resulted from differences in the timing and severity of commodity price declines and resulting impact on fair value assessments and impairments between periods. The prolonged decrease in commodity prices in 2015 triggered significant impairments of proved properties throughout 2015. As a result of previously recognized impairments and DD&A, our proved properties were carried at values that, when compared to estimated future net cash flows, required minimal impairment during 2016.
Impairments of non-producing properties decreased $28.8 million, or 11%, in 2016 to $234.4 million, of which $34.6 million was recognized in the fourth quarter. The decrease was due to a lower balance of unamortized leasehold costs in 2016 due to property dispositions and reduced land capital expenditures, along with changes in the timing and magnitude of amortization of undeveloped leasehold costs between periods resulting from changes in the Company's estimates of undeveloped properties not expected to be developed before lease expiration.
General and administrative expenses. Total G&A expenses decreased $20.2 million, or 11%, to $169.6 million in 2016 from $189.8 million in 2015. Total G&A expenses include non-cash charges for equity compensation of $48.1 million and $51.8 million for 2016 and 2015, respectively. G&A expenses other than equity compensation included in the total G&A expense figure above totaled $121.5 million for 2016, a decrease of $16.5 million, or 12%, compared to $138.0 million for 2015.
The following table shows the components of G&A expenses on a unit of sales basis for the periods presented.


   Year ended December 31,
$/Boe 2016 2015
General and administrative expenses $1.53
 $1.70
Non-cash equity compensation 0.61
 0.64
Total general and administrative expenses $2.14
 $2.34
The decrease in G&A expenses other than equity compensation was primarily due to a reduction in employee related costs and other efforts to reduce spending in response to depressed commodity prices. The decrease in equity compensation expense was primarily due to an increase in the estimated rate of forfeitures of unvested restricted stock based on historical experience, which resulted in lower recognition of expense in 2016.
Interest expense. Interest expense increased $7.5 million, or 2%, to $320.6 million in 2016 from $313.1 million in 2015 due to
higher borrowing costs incurred on our credit facility and three-year term loan resulting from downgrades of our credit rating in February 2016 along with an increase in our weighted average outstanding long-term debt resulting from fluctuations in the level of outstanding borrowings between years. Our weighted average outstanding long-term debt balance for 2016 was approximately $7.1 billion compared to $6.9 billion or 2015.
Income Taxes. We recorded an income tax benefit for the year ended December 31, 2016 of $232.8 million compared to a benefit of $181.4 million for 2015, resulting in effective tax rates of approximately 37% and 34%, respectively, after taking into account permanent taxable differences and valuation allowances. For 2016 and 2015,2020 we provided for income taxes at a combined federal and state tax rate of 38%24.5% of pre-tax losses generated by our operationsincome/loss. We recorded an income tax provision of $519.7 million and an income tax benefit of $169.2 million for 2021 and 2020, respectively, which resulted in the United States and 25% of pre-tax losses generated by our operations in Canada. Our 2015 consolidated effective tax rate was reduced byrates of 23.8% and 21.8%, respectively, after taking into account the application of statutory tax rates, permanent taxable differences, tax effects from equity compensation, changes in valuation allowances, and other items. See Part II, Item 8. Notes to Consolidated Financial Statements—Note 11. Income Taxes for a $13.5 million valuation allowance recognized against deferredsummary of the sources and tax assets arising from $52.9 millioneffects of operating loss carryforwards generated byitems comprising our Canadian subsidiary in 2015income tax provision and resulting effective tax rates for which we do not believe we will realize a benefit.2021 and 2020.
Liquidity and Capital Resources
Our primary sources of liquidity have historically been cash flows generated from operating activities, financing provided by our revolving credit facility and the issuance of debt securities. Additionally, in recent years non-strategic asset dispositions and joint development arrangements have provided a source of cash flow for use in reducing debt and enhancing liquidity. We intendare committed to continue reducingoperating in a responsible manner to preserve financial flexibility, liquidity, and the strength of our long-term debt using available cash flows from operations and/or proceeds from additional potential sales of non-strategic assets or through joint development arrangements; however, no assurance can be given that such transactions will occur.balance sheet.
48

At DecemberJanuary 31, 2017,2022, we had $43.9 million of cash and cash equivalents and approximately $2.56$1.76 billion of borrowing availability onunder our revolving credit facility after considering outstanding borrowings of $188 million and letters of credit. At January 31, 2018, outstanding borrowings decreasedcredit, which represents a $260 million increase in availability compared to $93 million, leaving approximately $2.65 billion of borrowing availability on ouryear-end 2021. Our credit facility, at that date.which is unsecured and has no borrowing base subject to redetermination, does not mature until October 2026.
Based on our 2018planned capital expenditure budget,spending, including our pending property acquisition described below, our forecasted cash flows and projected levels of indebtedness, we expect to maintain compliance with the covenants under our revolving credit facility and senior note indentures for at least the next 12 months.indentures. Further, based on current market indications, we expect to meet in the ordinary course of business otherour contractual cash commitments to third parties pursuant to the various agreements subsequently described under the heading Contractual Obligations and in Part II, Item 8. Notes to Consolidated Financial Statements—Note 10. Commitments and ContingenciesFuture Capital Requirements, recognizing we may be required to meet such commitments even if our business plan assumptions were to change. We monitor our capital spending closely based on actual and projected cash flows and have the ability to reduce spending or dispose of assets if needed to preserve liquidity and financial flexibility if needed to fund our operations.
Cash Flows
Cash flows from operating activities
Our netNet cash provided by operating activities totaled $2.08increased $2.55 billion, and $1.13or 179%, to $3.97 billion for the years ended December 31, 2017 and 2016, respectively. The increase in operating cash flows was2021 compared to $1.42 billion for 2020 primarily due to ana $3.24 billion increase in crude oil and natural gas revenues driven by higher realizeddue to the previously described increases in commodity prices and natural gas sales volumes in the current period. This increase was partially offset by a $211.6 million increase in production taxes associated with higher crude oil and natural gas revenues and a $121.5 million increase in realized cash losses on matured commodity derivatives in the current period. Additionally, we experienced an increase in certain cash operating expenses primarily due to an increase in total sales volumes, in 2017 coupled with lower interest expenses, the effects of which were partially offset by increasesincluded a $47.6 million increase in production expenses production taxes, and general and administrative expenses and a decrease$28.3 million increase in cash gains on matured natural gas derivatives.
Crude oil prices showed signs of improvement in late 2017 and early 2018 and through February 16, 2018 are higher than average market prices for full year 2017. If crude oil prices remain at current levels, we expect our 2018 operating cash flows will be higher than 2017 levels, the extent of which is uncertain due to the unpredictable nature of commodity prices.


transportation expenses.
Cash flows used in investing activities
During the years ended December 31, 2017 and 2016, we hadNet cash flows used in investing activities totaled $4.99 billion and $1.51 billion for 2021 and 2020, respectively, the $3.48 billion increase of $1,808.8 million and $533.0 million, respectively. These totals include cash capital expenditures of $1,953.2 million and $1,164.5 million, respectively, inclusive of exploration and development drilling,which reflects our 2021 property acquisitions, and dry hole costs. Property acquisitions totaled $40.0 million and $35.9 million for the years ended December 31, 2017 and 2016, respectively. The increaseacquisition activities discussed in capital spending was driven by an increase in our capital budget and related drilling and completion activities in 2017.
The use of cash for capital expenditures in 2017 and 2016 was partially offset by proceeds received from asset dispositions, which totaled $144.4 million and $631.5 million for the years ended December 31, 2017 and 2016, respectively. See Part II, Item 8. Notes to Consolidated Financial Statements—Note 14.2. Property Dispositions for a discussion of notable dispositions.
For 2018, we currently expect our cash flows used in investing activities, exclusive of any proceeds from asset sales or joint development arrangements, will be higher than 2017 levels due to our planned increase in drillingAcquisitions and completion activity for 2018 in response to the improvement in crude oil prices in late 2017 and early 2018. Our capital expenditures for 2018 are budgeted to be $2.3 billion.Dispositions.
Cash flows from financing activities
Net cash used inprovided by financing activities for the year ended December 31, 20172021 totaled $243.0$989.1 million, primarily resulting from a reduction in total outstanding debt using available cash flows from operations and proceeds from asset dispositions. The $990 millionconsisting of $1.59 billion of net proceeds received from our December 2017 issuanceNovember 2021 issuances of 2028 Notes were usedsenior notes and $340 million of net credit facility borrowings incurred to repay in full and terminate our $500 million term loan and to repayfund a portion of our December 2021 Permian Basin acquisition. These increases were partially offset by $630.8 million of senior note redemptions during the borrowings outstanding underyear, $123.9 million of cash used to repurchase shares of our revolving credit facility, thereby resulting in no significant net change incommon stock, and $165.9 million of cash flows from financing activities related to these activities.dividends paid on common stock.
Net cash used inprovided by financing activities for the year ended December 31, 20162020 totaled $587.8$97.1 million, primarily resulting from $1.48 billion of net proceeds received from our November 2020 issuance of senior notes due 2031, $105.0 million of net credit facility borrowings, and net proceeds of $26.0 million from term loans executed during 2020. These increases were partially offset by $1.34 billion of senior note repurchases and redemptions during 2020 using available cash and proceeds from asset sales beingour issuance of 2031 Notes, $25.2 million of premiums and costs paid upon the redemptions and repurchases, $126.9 million of cash used to fund the November 2016 redemptionsrepurchase shares of our $200common stock, and $18.5 million of 7.375% Senior Notes due 2020 and $400 million of 7.125% Senior Notes due 2021.cash dividends paid on common stock.
Future Sources of Financing
Although we cannot provide any assurance, we believe funds from operating cash flows, our remaining cash balance, and availability under our revolving credit facility should be sufficient to meet our cash requirements inclusive of, but not limited to, normal operating needs, debt service obligations, plannedbudgeted capital expenditures, the pending property acquisition described below, cash payments for income taxes, and commitmentsdividend payments for at least the next 12 months and to meet our contractual cash commitments to third parties described under the heading Future Capital Requirements beyond 12 months.
Our 2018Based on current market indications, our budgeted capital expenditures budget has been established based on an expectation of availablespending plans for 2022 are expected to be funded from operating cash flows. Any deficiencies in operating cash flows with any cash flow deficienciesrelative to budgeted spending are expected to be funded by borrowings under our revolving credit facility or proceeds from asset sales or joint development arrangements.
facility. If cash flows are materially impacted by declines in commodity prices, we have the ability to reduce our capital expenditures or utilize the availability of our revolving credit facility if needed to fund our operations. operations and business plans.
We may choose to access thebanking or capital markets for additional financing or capital to fund our operations or take advantage of business opportunities that may arise. Further, we may sell additional assets or enter into strategic joint development arrangementsopportunities in order to obtain funding for our operations and capital program if such transactions can be executed on satisfactory terms. However, no assurance can be given that such transactions will occur.
49

Credit facility
We currently anticipate we will be able to generate or obtain funds sufficient to meet our short-term and long-term cash requirements. We intend to fund future capital expenditures primarily through cash flows from operations and through borrowings under our revolving credit facility, but we may also issue debt or equity securities, sell additional assets, or enter into joint development arrangements. The issuance of additional debt requires a portion of our cash flows from operations be used for the payment of interest and principal on our debt, thereby reducing our ability to use cash flows to fund working capital, capital expenditures and acquisitions. The issuance of additional equity securities could have a dilutive effect on the value of our common stock.
Revolving credit facility
Currently we have an unsecured credit facility, maturing on May 16, 2019,in October 2026, with aggregate lender commitments totaling $2.75$2.0 billion. The commitments are from a syndicate of 1712 banks and financial institutions. We believe each member of the current syndicate has the capability to fund its commitment.
As of January 31, 2018,2022, we had approximately $2.65$1.76 billion of borrowing availability on our credit facility after considering outstanding borrowings and letters of credit. Credit facility borrowings bear interest at market-based interest rates plus a margin based on the terms of the borrowing and the credit ratings assigned to our senior, unsecured, long-term indebtedness.


The commitments under our revolving credit facility are not dependent on a borrowing base calculation subject to periodic redetermination based on changes in commodity prices and proved reserves. Additionally, downgrades or other negative rating actions with respect to our credit rating woulddo not trigger a reduction in our current credit facility commitments, nor woulddo such actions trigger a security requirement or change in covenants. The weighted-average interest rate onDowngrades of our credit facility borrowings was 3.19% at December 31, 2017rating will, however, trigger increases in our credit facility's interest rates and we incur commitment fees of 0.30% per annumpaid on the daily average amount of unused borrowing availability.availability under certain circumstances.
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, or merge, consolidate or sell all or substantially all of our assets. Our credit facility also contains a requirement that we maintain a consolidated net debt to total capitalization ratio of no greater than 0.65 to 1.00. ThisSee Part II, Item 8. Notes to Consolidated Financial Statements—Note 8. Long-Term Debt for a discussion of how this ratio represents the ratio of net debt (calculated as total face value of debt plus outstanding letters ofis calculated pursuant to our 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.agreement.
We were in compliance with our revolving credit facility covenants at December 31, 20172021 and expect to maintain compliance for at least the next 12 months.compliance. At December 31, 2017,2021, our consolidated net debt to total capitalization ratio as defined in our revolving credit facility as amended, was 0.51 to 1.00.0.43. We do not believe the revolving credit facility covenants are reasonably likely to limit our ability to undertake additional debt financing to a material extent if needed to support our business. At December 31, 2017, our total debt would have needed to independently increase by approximately $5.2 billion above the existing level at that date (with no corresponding increase in cash or reduction in refinanced debt) to reach the maximum covenant ratio of 0.65 to 1.00. Alternatively, our total shareholders’ equity would have needed to independently decrease by approximately $2.8 billion (excluding the after-tax impact of any non-cash impairment charges) below the existing level at December 31, 2017 to reach the maximum covenant ratio. These independent point-in-time sensitivities do not take into account other factors that could arise to mitigate the impact of changes in debt and equity on our consolidated net debt to total capitalization ratio, such as disposing of assets or exploring alternative sources of capitalization.
Joint development agreement funding
In September 2014, we entered into an agreement with a U.S. subsidiary of SK E&S Co. Ltd (“SK”) of South Korea to jointly develop a portion of the Company’s STACK properties. Pursuant to the agreement SK will fund, or carry, 50% of our drilling and completion costs attributable to an area of mutual interest in the STACK play until approximately $270 million has been expended by SK on our behalf. As of December 31, 2017, approximately $101 million of the carry had yet to be realized and is expected to be realized through mid-2019.
Future Capital Requirements
Our material future cash requirements are summarized below. Based on current market indications, we expect to meet our contractual cash commitments to third parties as of December 31, 2021, recognizing we may be required to meet such commitments even if our business plan assumptions were to change.
Senior notes
Our debt includes outstanding senior note obligations totaling $6.2$6.36 billion at December 31, 2017. We have no near-term senior note maturities, with our earliest scheduled senior note maturity being our $2.0 billion2021, exclusive of 2022 Notes due in September 2022.interest payment obligations thereon. Our senior notes are not subject to any mandatory redemption or sinking fund requirements. The earliest scheduled senior note maturity is our $649.6 million of 2023 Notes due in April 2023. For further information on the face values, maturity dates, semi-annual interest payment dates, optional redemption periods and covenant restrictions related to our senior notes, refer to Note 8. Long-Term Debt in Part II, Item 8. Notes to Consolidated Financial Statements—Note 7. Long-Term Debt.Statements.
We were in compliance with our senior note covenants at December 31, 20172021 and expect to maintain compliance for at least the next 12 months.compliance. We do not believe the senior note covenants will materially limit our ability to undertake additional debt financing. Downgrades or other negative rating actions with respect to the credit ratings assigned to our senior unsecured debt woulddo not trigger additional senior note covenants.
ThreeCredit facility borrowings
As of January 31, 2022, we had $240 million of outstanding borrowings on our subsidiaries, Banner Pipeline Company, L.L.C., CLR Asset Holdings, LLC,credit facility, which represents a decrease of $260 million compared to $500 million outstanding at year-end 2021. Our credit facility matures in October 2026.
Transportation, gathering, and The Mineral Resources Company, whichprocessing commitments
We have no material assets or operations, fullyentered into transportation, gathering, and unconditionallyprocessing commitments to guarantee the senior notescapacity on a joint and several basis. Our other subsidiaries, the value of whose assets and operations are minor, do not guarantee the senior notes as of December 31, 2017.
Capital expenditures
We evaluate opportunities to purchase or sell crude oil and natural gas propertiespipelines and expectnatural gas processing facilities that require us to participatepay per-unit charges regardless of the amount of capacity used. Future commitments remaining as a buyer or seller of properties at various times. We seek acquisitions that utilize our technical expertise or offer opportunitiesDecember 31, 2021 under the arrangements amount to expand our existing core areas. Acquisition expenditures are not budgeted.approximately $1.31 billion. See Part II, Item 8. Notes to Consolidated Financial Statements—Note 13. Commitments and Contingencies for additional information.

Capital Expenditures

2021 Capital Spending
For the year ended December 31, 2017,2021, we invested approximately $2.0$1.54 billion in our capital program excluding $40.0 million$3.58 billion of unbudgeted acquisitions, excluding $21.3 million of mineral acquisitions attributable to Franco-Nevada, and including $79.2$114.1 million of capital costs associated with increased accruals for capital expenditures and including $2.8 million of seismic costs.as compared to December 31, 2020. Our 2021 capital expenditures budget for 2017 was $1.95 billion. Our 2017 capital
50

expenditures were allocated as follows by quarter:  quarter. See Part II, Item 8. Notes to Consolidated Financial Statements—Note 2. Property Acquisitions and Dispositions for discussion of our notable property acquisitions executed in 2021.
In millions1Q 20212Q 20213Q 20214Q 2021Total 2021
Exploration and development drilling$255.6 $216.2 $312.3 $382.6 $1,166.7 
Land costs7.5 14.5 18.5 111.1 151.6 
Mineral acquisitions attributable to Continental0.2 1.3 1.5 2.9 5.9 
Capital facilities, workovers, water infrastructure, and other corporate assets27.4 57.3 51.0 68.4 204.1 
Seismic2.7 0.2 0.4 9.2 12.5 
Capital expenditures attributable to Continental, excluding unbudgeted acquisitions$293.4 $289.5 $383.7 $574.2 $1,540.8 
Acquisitions of producing properties (1)183.3 (5.4)0.3 2,390.3 2,568.5 
Acquisitions of non-producing properties (1)24.3 18.7 3.0 967.5 1,013.5 
Total unbudgeted acquisitions207.6 13.3 3.3 3,357.8 3,582.0 
Total capital expenditures attributable to Continental501.0 302.8 387.0 3,932.0 5,122.8 
Mineral acquisitions attributable to Franco-Nevada0.9 2.8 6.0 11.6 21.3 
Total capital expenditures501.9 305.6 393.0 3,943.6 5,144.1 
In millions1Q 20172Q 20173Q 20174Q 2017Total 2017
Exploration and development drilling$329.8
$471.0
$444.7
$442.2
$1,687.7
Land costs68.8
49.8
47.7
23.0
189.3
Capital facilities, workovers and other corporate assets27.4
29.3
28.2
30.5
115.4
Seismic1.0
1.8
—
—
2.8
Capital expenditures, excluding acquisitions$427.0
$551.9
$520.6
$495.7
$1,995.2
Acquisitions of producing properties0.1
0.7
2.7
4.9
8.4
Acquisitions of non-producing properties13.3
5.1
6.8
6.4
31.6
Total acquisitions13.4
5.8
9.5
11.3
40.0
Total capital expenditures$440.4
$557.7
$530.1
$507.0
$2,035.2
(1)    Fourth quarter amounts primarily represent our December 2021 Permian Basin acquisition. See Part II, Item 8. Notes to Consolidated Financial Statements—Note 2. Property Acquisitions and Dispositions for additional information.
2022 Capital Budget
In 2022, we will remain committed to operating in a disciplined, capital-efficient manner to maximize cash flow generation and capital and corporate returns to shareholders. Our 2022 capital expenditures budget for 2018 is $2.3 billion excluding acquisitions, which is expected to be allocated as follows:reflected in the table below. Acquisition expenditures are not budgeted, with the exception of planned levels of spending for mineral acquisitions made in conjunction with our relationship with Franco-Nevada.
In millions2022 Budget
Exploration and development$1,800 
Land costs127 
Mineral acquisitions attributable to Continental (1)23 
Capital facilities, workovers, water infrastructure, and other corporate assets344 
Seismic6 
2022 capital budget attributable to Continental$2,300 
Mineral acquisitions attributable to Franco-Nevada (1)91 
Total 2022 capital budget (2)$2,391 
In millionsAmount
Exploration and development drilling$1,988
Land costs132
Capital facilities, workovers and other corporate assets168
Seismic12
Total 2018 capital budget, excluding acquisitions$2,300
(1)    Represents planned spending for mineral acquisitions by TMRC II under our relationship with Franco-Nevada Corporation. 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.

(2)    Excludes the $450 million purchase price for our pending acquisition of properties in the Powder River Basin discussed below under the caption Pending Property Acquisition.
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, access to capital, available cash flows, unbudgeted acquisitions, actual drilling and completion results, operational process improvements, the availability of drilling and completion rigs and other services and equipment, cost inflation, the availability of transportation, gathering and processing capacity, changes in commodity prices, and regulatory, technological and competitive developments. We monitor our capital spending closely based on actual and projected cash flows and may scale back our spending should commodity prices materially decrease from current levels. Conversely, an increase
51

Pending Property Acquisition
As discussed in commodity prices from current levels could resultNote 20. Subsequent Events in increased capital expenditures. Part II, Item 8. Notes to Consolidated Financial Statements, on January 24, 2022, we executed a definitive agreement to acquire oil and gas properties in the Powder River Basin for $450 million of cash, subject to customary closing price adjustments. The properties include approximately 172,000 net leasehold acres and producing properties with production totaling approximately 16,000 barrels of oil equivalent per day based on two-stream reporting. Closing of the acquisition is expected to occur in late March 2022 and remains subject to the completion of customary due diligence procedures and closing conditions.
We expect to continue participating as a buyer of properties when and if we have the ability to increase our position in strategic plays at competitiveattractive terms.
Contractual ObligationsCash Payments for Income Taxes
The following table presentsAs of February 10, 2022, the publicly available forward commodity strip prices for the remainder of 2022 averaged $83.38 per barrel for crude oil and $4.09 per Mcf for natural gas. If commodity prices remain at these levels for the year, we could potentially utilize the full amount of our federal net operating loss carryforwards and certain state net operating loss carryforwards and generate significant taxable income in 2022, which could result in us making cash payments for income taxes in the upcoming year. Because of the significant uncertainty inherent in numerous factors utilized in projecting taxable income, including future commodity prices, production levels, development activities, capital spending, profitability, and general economic conditions, we cannot predict the amount of future income tax payments with certainty, but such payments could be significant.
Dividend Declaration
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.
Delivery Commitments
We have various natural gas volume delivery commitments that are related to our North and South areas. We expect to primarily fulfill our contractual obligations with production from our proved reserves. However, we may purchase third-party volumes to satisfy our commitments. The volumes disclosed herein represent gross production associated with properties operated by us and do not reflect our net proportionate share of such amounts. Additionally, in the South region certain of our firm sales contracts for oil include delivery commitments asthat specify the delivery of a fixed and determinable quantity. We expect to primarily fulfill our contractual obligations with production from our proved reserves. As of December 31, 2017:2021, we were committed to deliver the following fixed quantities of natural gas production.
Year EndingNatural GasCrude Oil
December 31,BcfMMBo
202214613
20238413
2024733
202518—
202615—
  Payments due by period
In thousands Total Less than
1 year (2018)		 Years 2 and 3
(2019-2020)		 Years 4 and 5
(2021-2022)		 More than
5 years
Arising from arrangements on the balance sheet: 
 
 
 
 
Revolving credit facility borrowings $188,000
 $—
 $188,000
 $—
 $—
Senior Notes (1) 6,200,000
 —
 —
 2,000,000
 4,200,000
Note payable (2) 10,021
 2,286
 4,795
 2,940
 —
Interest payments (3) 2,476,202
 270,535
 569,683
 567,159
 1,068,825
Asset retirement obligations (4) 114,406
 2,612
 3,486
 —
 108,308
Arising from arrangements not on balance sheet: (5) 
 
 
 
 
Operating leases and other (6) 26,956
 11,867
 6,581
 1,300
 7,208
Drilling rig commitments (7) 103,595
 72,924
 30,671
 —
 —
Transportation and processing commitments (8) 1,429,511
 196,714
 401,656
 333,988
 497,153
Total contractual obligations $10,548,691
 $556,938
 $1,204,872
 $2,905,387
 $5,881,494
Derivative Instruments



(1)
Amounts represent scheduled maturities of our senior note obligations at December 31, 2017 and do not reflect any discount or premium at which the senior notes were issued or any debt issuance costs. See Part II, Item 8. Notes to Consolidated Financial Statements—Note 7. Long-Term Debt for a description of our senior notes.
(2)Represents future principal payments on a 10-year amortizing note payable secured by the Company’s corporate office building in Oklahoma City, Oklahoma and does not reflect any debt issuance costs. Principal and interest are payable monthly through the loan’s maturity date of February 26, 2022.
(3)
Interest payments include scheduled cash interest payments on the senior notes and note payable as well as estimated interest payments on our revolving credit facility borrowings outstanding at December 31, 2017 and assumes the actual weighted average interest rate on our credit facility borrowings of 3.19%at December 31, 2017 continues through the maturity date of the arrangement.
(4)
Amounts represent estimated discounted costs for future dismantlement and abandonment of our crude oil and natural gas properties. See Part II, Item 8. Notes to Consolidated Financial Statements—Note 1. Organization and Summary of Significant Accounting Policies for additional discussion of our asset retirement obligations.
(5)The commitment amounts included in this section primarily represent costs associated with wells operated by the Company. A portion of these costs will be borne by other interest owners. Due to variations in well ownership, our net share of these costs cannot be determined with certainty.
(6)Amounts primarily represent commitments for electric infrastructure, land and road use, office buildings and equipment, communication towers, field equipment, sponsorship agreements, and purchase obligations mainly related to software services.
(7)
Amounts represent commitments under drilling rig contracts with various terms extending to February 2020 to ensure rig availability in our key operating areas.
(8)
We have entered into transportation and processing commitments to guarantee capacity on crude oil and natural gas pipelines and natural gas processing facilities. These commitments require us to pay per-unit transportation or processing charges regardless of the amount of capacity used. We are not committed under these contracts to deliver fixed and determinable quantities of crude oil or natural gas in the future. See Part II, Item 8. Notes to Consolidated Financial Statements—Note 10. Commitments and Contingencies for additional discussion.
If the litigation settlement discussedSee Note 6. Derivative Instruments in Part II, Item 8. Notes to Consolidated Financial Statements—Note 10. CommitmentsStatements for discussion of our hedging activities, including a summary of derivative contracts in place as of December 31, 2021. Between January 1, 2022 and Contingencies isFebruary 10, 2022 we entered into additional derivative instruments as summarized in the tables below.
52

Natural gas derivatives
Weighted Average Hedge Price ($/MMBtu)
Period and Type of ContractAverage Volumes HedgedSwapsFloorCeiling
April 2022 - September 2022
Swaps - Henry Hub200,000 MMBtus/day$4.03 
April 2022 - September 2022
Collars - Henry Hub110,000 MMBtus/day$4.50 $6.00 
July 2022 - December 2022
Swaps - WAHA45,000 MMBtus/day$3.41 
October 2022 - March 2023
Collars - Henry Hub210,000 MMBtus/day$4.12 $5.52 
January 2023 - December 2023
Swaps - WAHA40,000 MMBtus/day$2.69 
April 2023 - September 2023
Swaps - Henry Hub100,000 MMBtus/day$3.25 
October 2023 - March 2024
Collars - Henry Hub100,000 MMBtus/day$3.14 $4.00 
April 2024 - December 2024
Swaps - Henry Hub100,000 MMBtus/day$3.11 
Crude oil derivatives
Period and Type of ContractAverage Volumes HedgedWeighted Average Hedge Price ($/Bbl)
March 2022 - December 2022
NYMEX Roll Swaps24,000 Bbls/day$1.10 
Share repurchase program
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. 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 and retired a cumulative total of approximately 17.0 million shares under the program at an aggregate cost of $441.1 million, leaving approximately $1.06 billion of authorized repurchasing capacity under the modified program. The timing and amount of the Company's share repurchases are subject to market conditions and management discretion. 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 court, we will make paymentsBoard of Directors at any time.
Senior note repurchases and incur costs associated with the settlement of approximately $59.6 million. The timing of payments of our obligations under the settlement is uncertain and have not been reflectedredemptions
As discussed in the contractual obligations table above.
Derivative Instruments
We may utilize derivative instruments to economically hedge against the variabilityNote 8. Long-Term Debt in cash flows associated with future sales of our production. While the use of derivative instruments limits the downside risk of adverse price movements, their use also limits future revenues from upward price movements. See Part II, Item 8. Notes to Consolidated Financial Statements—Note 5. Derivative Instruments for further discussion of the accounting applicable to our derivative instruments,Statements, in recent years we have repurchased or redeemed a summary of open contracts as of December 31, 2017, and the estimated fair valueportion of our contracts as of that date.
Between January 1, 2018 and February 16, 2018outstanding senior notes. From time to time, we entered intomay seek to execute additional natural gas derivative instruments as summarized below, representing the majorityrepurchases or redemptions of our forecasted 2018 natural gas production.senior notes for cash in open market transactions, privately negotiated transactions, or otherwise. Such repurchases or redemptions will depend on prevailing market conditions, our liquidity and prospects for future access to capital, and other factors. The hedged volumes reflected below represent an aggregation of multiple contracts that are generally expected toamounts involved in any such transactions, individually or in the aggregate, may be realized ratably over the indicated period. These derivative instruments will be settled based upon reported NYMEX Henry Hub settlement prices.material.
53
    Swaps Weighted Average Price
    
Period and Type of Contract MMBtus 
February 2018 - December 2018    
Swaps - Henry Hub 193,720,000
 $2.88




Critical Accounting Policies and Estimates
Our consolidated financial statements and related footnotes contain information that is pertinent to our management’s discussion and analysis of financial condition and results of operations. The preparation of financial statements in conformity with generally accepted accounting principles requires management to select appropriate accounting policies and to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses, and the disclosure and estimation of contingent assets and liabilities. See Part II, Item 8. Notes to Consolidated Financial Statements—Note 1. Organization and Summary of Significant Accounting Policies and Note 9. Revenuesfor descriptions of our major accounting policies. Certain of these accounting policies involve judgments and uncertainties to such an extent that there is a reasonable likelihood that materially different amounts could have been reported under different conditions or if different assumptions had been used.
In management’s opinion, the most significant reporting areas impacted by management’s judgments and estimates are crude oil and natural gas reserve estimations, revenue recognition, the choice of accounting method for crude oil and natural gas activities and derivatives, impairment of assets, income taxes and contingent liabilities. These areas are discussed below. Management’s judgments and estimates in these areas are based on information available from both internal and external sources, including engineers, geologists and historical experience in similar matters and are believed to be reasonable under the circumstances. We evaluate our estimates and assumptions on a regular basis. Actual results could differ from the estimates as additional information becomes known.
Crude Oil and Natural Gas Reserves Estimation and Standardized Measure of Future Cash Flows
Our external independent reserve engineers, Ryder Scott, and internal technical staff prepare the estimates of our crude oil and natural gas reserves and associated future net cash flows. Even though Ryder Scott and our internal technical staff are knowledgeable and follow authoritative guidelines for estimating reserves, they must make a number of subjective assumptions based on professional judgments in developing the reserve estimates. Estimates of reserves and their values, future production rates, and future costs and expenses are inherently uncertain for various reasons, including many factors beyond the Company’s control. Reserve estimates are updated by us at least semi-annually and take into account recent production levels and other technical information about each of our properties.
Crude oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be precisely measured. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Periodic revisions to theor removals of estimated reserves and future cash flows may be necessary as a result of a number of factors, including reservoir performance, new drilling, crude oil and natural gas prices, changes in costs, technological advances, new geological or geophysical data, changes in business strategies, or other economic factors. Accordingly, reserve estimates may differ significantly from the quantities of crude oil and natural gas ultimately recovered.For the years ended December 31, 2017, 2016,2021, 2020, and 2015,2019, net upward (downward) revisions of our proved reserves were revised downward from prior years’ reports bytotaled approximately 8254 MMBoe, 110(505) MMBoe, and 297(149) MMBoe, respectively. We cannot predict the amounts or timing of future reserve revisions.revisions or removals.
Estimates of proved reserves are key components of the Company’s most significant financial estimates including the computation of depreciation, depletion, amortization and impairment of proved crude oil and natural gas properties. Holding all other factors constant, if proved reserves are revised downward, the rate at which we record DD&A expense would increase, reducing net income. Conversely, if proved reserves are revised upward, the rate at which we record DD&A expense would decrease. Future revisions of reserves may be material and could significantly alter future depreciation, depletion, and amortization expense and may result in material impairments of assets.
At December 31, 2017,2021, our proved reserves totaled 1,3311,645 MMBoe as determined using 12-month average first-day-of-the-month prices of $51.34$66.56 per barrel for crude oil and $2.98$3.60 per MMBtu for natural gas. Actual future prices may be materially higher or lower than those used in our year-end estimates. NYMEX WTI crude oil and Henry Hub natural gas first-day-of-the-month commodity prices for January 1, 20182022 and February 1, 20182022 averaged $63.11$81.71 per barrel and $3.40$4.65 per MMBtu, respectively.
Holding all other factors constant, if crude oil prices used in our year-end reserve estimates were increased to $65$80 per barrel our proved reserves at December 31, 20172021 could increase by approximately 2421 MMBoe, or 2%, representing a 3% increase in proved developed producing reserves averaged with a 1% increase in PUD reserves.. If the increase in proved reserves under this oil price sensitivity existed throughout 2017,2021, our DD&A expense for 20172021 would have decreased by an estimated 3%approximately 2%.
Holding all other factors constant, if natural gas prices used in our year-end reserve estimates were increased to $4.00$4.50 per MMBtu our proved reserves at December 31, 20172021 could increase by approximately 8 MMBoe, or less than 1%, which we estimate would result in an approximate 1% decrease in DD&A expense for 2017 assuming. If the increase in proved reserves under this gas price sensitivity existed throughout the year.2021, our DD&A expense for 2021 would have decreased by approximately 1%.
54

Our DD&A calculations for oil and gas properties are performed on a field basis and revisions to proved reserves will not necessarily be applied ratably across all fields and may not be applied to some fields at all. Further, reserve revisions in


significant fields may individually affect our DD&A rate. As a result, the impact on DD&A expense from revisions in reserves cannot be predicted with certainty and may result in changes in expense that are greater or less than the underlying changes in reserves.
See Part I, Item 1. Business—Crude Oil and Natural Gas Operations—Proved Reserves—Proved Reserve,Reserves, Standardized Measure, and PV-10 Sensitivities for additional proved reserve sensitivities under certain increasing and decreasing commodity price scenarios for crude oil and natural gas.
Revenue Recognition
We derive substantially all of our revenues from the sale of crude oil and natural gas. CrudeSee Part II, Item 8. Notes to Consolidated Financial Statements—Note 9. Revenues for discussion of our accounting policies governing the recognition and presentation of revenues.
Operated crude oil and natural gas revenues are recognized induring the month the product is deliveredin which control transfers to the purchasercustomer and title transfers. Weit is probable the Company will collect the consideration it is entitled to receive. For non-operated properties, the Company's proportionate share of production is generally receive payment from onemarketed at the discretion of the operators. Non-operated revenues are recognized by the Company during the month in which production occurs and it is probable the Company will collect the consideration it is entitled to three months after the sale has occurred. receive.
At the end of each month, to record revenuerevenues we estimate the amount of production delivered and sold to purchaserscustomers and the prices at which they were sold. Variances between estimated revenues and actual amounts received for all prior months are recorded in the month payment is received and are reflected in our financial statements as crude oil and natural gas sales. These variances have historically not been material.
New accounting rules governingFor the recognitionsale of crude oil and presentation ofnatural gas, we evaluate whether we are the principal, and report revenues went into effect on January 1, 2018. See Part II, Item 8. Notes to Consolidated Financial Statements—Note 1. Organizationa gross basis (revenues presented separately from associated expenses), or an agent, and Summary of Significant Accounting Policies–New accounting pronouncements not yet adopted at December 31, 2017–Revenue recognition and presentation for discussionreport revenues on a net basis. In this assessment, we consider if we obtain control of the expected impactproducts before they are transferred to the customer as well as other indicators. Judgment may be required in determining the point in time when control of the new rules on our future financial statements.products transfers to customers.
Successful Efforts Method of Accounting
Our business is subject to accounting rules that are unique to the crude oil and natural gas industry. Two generally accepted methods of accounting for oil and gas activities are available—the successful efforts method and the full cost method. The most significant differences between these two methods are the treatment of exploration costs and the manner in which the carrying value of oil and gas properties are amortized and evaluated for impairment. We use the successful efforts method of accounting for our oil and gas properties. See Part II, Item 8. Notes to Consolidated Financial Statements—Note 1. Organization and Summary of Significant Accounting Policies for further discussion of the accounting policies applicable to the successful efforts method of accounting.
Derivative Activities
WeFrom time to time we may utilize derivative contracts to hedge against the variability in cash flows associated with the forecasted sale of future crude oil and natural gas production and forecasted purchases of diesel fuel for use in drilling activities.other purposes. We have elected not to designate any of our price risk management activities as cash flow hedges. As a result, we mark our derivative instruments to fair value and recognize the changes in fair value in current earnings.
In determining the amounts to be recorded for our openoutstanding derivative contracts, we are required to estimate the fair value of the derivatives. We use an independent third party to provide our derivative valuations. The third party’s valuation models for derivative contracts are industry-standard models that consider various inputs including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. The fair value calculations for collars requires the use of an option-pricing model. The estimated future prices are compared to the prices fixed by the derivative agreements and the resulting estimated future cash inflows or outflows over the lives of the derivatives are discounted to calculate the fair value of the derivative contracts. These pricing and discounting variables are sensitive to market volatility as well as changes in future price forecasts and interest rates. See Part II, Item 7A. Quantitative and Qualitative Disclosures About Market Risk for a discussion of the sensitivity of natural gas derivative fair value calculations to changes in forward natural gas prices.
We validate our derivative valuations through management review and by comparison to our counterparties’ valuations for reasonableness. Differences between our fair value calculations and counterparty valuations have historically not been material.
55

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


Proved crude oil and natural gas properties are reviewed for impairment on a field-by-field basis. If the carrying amount of a field exceeds its estimated undiscounted future cash flows, the carrying amount of the field is reduced to its estimated fair value using a discounted cash flow model. For producing properties, the impairment evaluations involve a significant amount of judgment since the results are based on estimated future events, such as future sales prices for crude oil and natural gas, future costs to produce those products, estimates of future crude oil and natural gas reserves to be recovered and the timing thereof, the economic and regulatory climates and other factors. The need to test a field for impairment may result from significant declines in sales prices or downward revisions toor removals of crude oil and natural gas reserves. Estimates of anticipated sales prices and recoverable reserves are highly judgmental and are subject to material revision in future periods.
Impairment provisionsNo impairments were recognized for producingour proved crude oil and natural gas properties totaled $82.3 million for 2017.the year ended December 31, 2021 as estimated future net cash flows were determined to be in excess of cost basis. Commodity price assumptions used for the year-end December 31, 20172021 impairment calculations were based on publicly available average annual forward commodity strip prices through year-end 20222026 and were then escalated at 3% per year thereafter. Holding all other factors constant, as forward commodity prices decrease, our probability for recognizing producing property impairments may increase, or the magnitude of impairments to be recognized may increase. Conversely, as forward commodity prices increase, our probability for recognizing producing property impairments may decrease, or the magnitude of impairments to be recognized may decrease or be eliminated. As of December 31, 2017,2021, the publicly available forward commodity strip prices for the year 20222026 used in our fourth quarter impairment calculations averaged $51.65$58.42 per barrel for crude oil and $2.89$3.03 per Mcf for natural gas. If forward commodity prices materially decrease from current levels for an extended period, additional impairments of producing properties may be recognized in the future. Because of the uncertainty inherent in the numerous factors utilized in determining the fair value of producing properties, we cannot predict the timing and amount of future impairment charges, if any.
Impairment losses for non-producingunproved properties which primarily consist of undeveloped leasehold costs and costs associated with the purchase of certain proved undeveloped reserves, are generally recognized by amortizing the portion of the properties’ costs which management estimates will not be transferred to proved properties over the lives of the leases based on drilling plans, experience of successful drilling, and the average holding period. The impairment assessments are affected by economic factors such as the results of exploration activities, commodity price outlooks, anticipated drilling programs, remaining lease terms, and potential shifts in business strategy employed by management. The estimated timing and rate of successful drilling is highly judgmental and is subject to material revision in future periods as better information becomes available.
Income Taxes
We make certain estimatesIncome taxes are accounted for using the asset and judgments in determining ourliability method. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income tax expense for financial reporting purposes. These estimates and judgments occur in the calculation of certainyears in which those differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities that arise from differencesof a change in the timing and recognition of revenue and expense for tax and financial reporting purposes. Our federal and staterates is recognized in income tax returns are generally not prepared or filed before the consolidated financial statements are prepared; therefore, we estimate the tax basis of our assets and liabilities at the end of each period as well as the effects of tax rate changes, tax credits and net operating loss carryforwards. Adjustments related to these estimates are recorded in our tax provision in the period in which we file our income tax returns. Further, we must assessthat includes the likelihood we will be able to recover or utilize our deferred tax assets. If recovery is not likely, we must record a valuation allowance against suchenactment date.
In assessing the realizability of deferred tax assets, for the amount we would not expect to recover, which would result in an increase to our income tax expense. As of December 31, 2017, we believe all deferred tax assets, net of valuation allowances, reflected in our consolidated balance sheets will ultimately be utilized. Wemanagement must consider future taxable income in making such assessments. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly related to prevailing crude oil and natural gas prices). If our estimates and judgments change regarding our ability to utilize our deferred tax assets, our tax provision could increase in the period it is determined thatwhether it is more likely than not that some portion or all of the deferred tax assets will not be realized. We apply judgment to determine the weight of both positive and negative evidence in order to conclude whether a valuation allowance is necessary for our deferred tax assets. In determining whether a valuation allowance is required, we consider, among other factors, our financial position, results of operations, projected future taxable income, reversal of existing deferred tax liabilities against deferred tax assets, and tax planning strategies. Significant judgment is involved in this determination as we are required to make assumptions about future commodity prices, projected production, development activities, profitability of future business strategies and forecasted economics in the oil and gas industry. Additionally, changes in the effective tax rate resulting from changes in tax law and our level of earnings may limit utilization of deferred tax assets and may affect the valuation of deferred tax balances in the future. Changes in judgment regarding future realization of deferred tax assets may result in a reversal of all or a portion of the valuation allowance.
We believe our net deferred tax assets will ultimately be realized. During 2020, a $14.5 million valuation allowance was established for the deferred tax asset will not be utilized.
Our effective tax rate is subject to variability from period to period asassociated with a result of factors other than changes in federal and state tax rates and/or changes in tax laws which can affect tax-paying companies. Our effective tax rate is affected by permanent taxable differences, valuation allowances, and changes in the allocation of property, payroll, and revenues between states in which we own property as rates vary from state to state. Due to the sizeportion of our grossOklahoma state net operating loss carryforwards. In 2021, we reassessed the realizability of the deferred tax balances, a small change in our estimated future tax rate can have a material effectasset related to Oklahoma state net operating loss carryforwards, and based on current period earnings.year activity, determined it was more likely than not that such assets would be realized. Therefore, it was determined that the previously recorded valuation allowance in 2020 should be released in 2021. We will continue to evaluate both the

56


positive and negative evidence on a quarterly basis in determining the need for a valuation allowance with respect to our deferred tax assets.
Contingent Liabilities
A provision for legal, environmental and other contingencies is charged to expense when a loss is probable and the loss or range of loss can be reasonably estimated. Determining when liabilities and expenses should be recorded for these contingencies and the appropriate amounts of accruals is subject to an estimation process that requires subjective judgment of management. In certain cases, management’s judgment is based on the advice and opinions of legal counsel and other advisers, the interpretation of laws and regulations which can be interpreted differently by regulators and/or courts of law, the experience of the Company and other companies dealing with similar matters, and management’s decision on how it intends to respond to a particular matter; for example, a decision to contest it vigorously or a decision to seek a negotiated settlement. Actual losses can differ from estimates for various reasons, including differing interpretations of laws and opinions and assessments on the amount of damages. We closely monitor known and potential legal, environmental and other contingencies and make our best estimate of when or if to record liabilities and losses for matters based on available information.
Off-Balance Sheet Arrangements
Currently, we do not have any off-balance sheet arrangements with unconsolidated entities to enhance liquidity and capital resources.
New Accounting PronouncementsPronouncement
See Part II, Item 8. Notes to Consolidated Financial Statements—Note 1. Organization and Summary of Significant Accounting PoliciesPolicies—Adoption of new accounting pronouncement for a discussion of the new income tax accounting standard adopted on January 1, 2021, which did not have a material impact upon adoptionon our financial position, results of new accounting pronouncements in 2017 along with a discussion of accounting pronouncements not yet adopted.operations, or cash flows.
Legislative and Regulatory Developments
The crude oil and natural gas industry in the United States is subject to various types of regulation at the federal, state and local levels. In January 2021, President Biden issued executive orders that, among other things, establish new greenhouse gas emission standards for the oil and gas sector. Additionally, the Biden 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, as well as other tax policy changes including a proposed increase in the U.S. corporate income tax rate, among other things. These changes, if enacted, could have a material adverse effect on our results of operations and cash flows. President Biden may continue to issue additional executive orders in pursuit of his regulatory agenda and there is the potential for the revision of existing laws and regulations or the adoption of new legislation that could adversely affect the oil and gas industry. See Part I, Item 1. Business—Regulation of the Crude Oil and Natural Gas Industry for afurther discussion of significant laws and regulations that have been enacted or are currently being considered by regulatory bodies that may affect us in the areas in which we operate.
Tax Reform Legislation
On December 22, 2017, the Tax Reform Act was signed into law, which represents the most significant tax policy change in the United States since 1986. Below is a summary of key changes included in the new law that are most relevant to our business. Changes arising from the Tax Reform Act, which are subject to a number of important qualifications and exceptions not included in the summary below, generally become effective for tax years beginning after December 31, 2017. The following discussion should be read in conjunction with Part II, Item 8. Notes to Consolidated Financial Statements—Note 8. Income Taxes.
Reduction in corporate tax rate—the Tax Reform Act reduces the corporate tax rate from 35% to 21%, effective for tax years beginning after December 31, 2017. In recent years, we have provided for income taxes at a combined federal and state tax rate of 38% of pre-tax income and losses generated by our operations in the United States, representing 35% for federal income taxes and 3% for state income taxes. For 2018, under the new tax law we expect to provide for income taxes at a combined federal and state tax rate of approximately 24%. The new lower federal tax rate is expected to have a significant favorable impact on our U.S. GAAP net income in future periods.
Repeal of alternative minimum tax—the Tax Reform Act repeals the corporate alternative minimum tax (“AMT”), effective for tax years beginning after December 31, 2017. Further, the new law allows an entity to claim portions of any unused AMT credits over the next four years to offset its regular tax liability. An entity with unused AMT credits as of December 31, 2017 can first use those credits to offset its regular tax for 2017, and can then claim up to 50% of the remaining AMT credits in 2018, 2019, and 2020, with all remaining AMT credits refundable in 2021. This law change is expected to have a favorable impact on the Company relative to previous AMT rules. Our unused AMT credits totaled $7.8 million at December 31, 2017, which we believe are realizable and will be pursued for refund.
Net operating loss deduction limitation—the Tax Reform Act limits the amount entities are able to deduct for federal net operating loss ("NOL") carryforwards generated in tax years beginning after December 31, 2017 to 80% of taxable income for a respective year. The law also generally repeals an entity's ability to carry back future NOLs to prior periods. These adverse rule changes are mitigated by a law change that now allows any NOLs generated in taxable years beginning after December 31, 2017 to be carried forward indefinitely. NOLs arising before January 1, 2018 may still be carried back two years and are subject to their existing carryforward expiration periods. These new law changes, when considered in the aggregate, are not expected to have a significant adverse impact on our ability to fully utilize current and future federal NOL carryforwards.


As of December 31, 2017, we had federal NOL carryforwards of $2.39 billion which begin expiring in 2033. Deferred tax assets reflected in our consolidated balance sheet related to these NOL carryforwards totaled $604.4 million at December 31, 2017. In response to the tax law changes, we reassessed the realizability of these deferred tax assets, taking into consideration how the new laws impact future taxable income, if any, that is expected to be offset by our NOLs. We believe our available NOLs at December 31, 2017 will ultimately be utilized prior to expiration and, as a result, no valuation allowance on our NOL deferred tax assets is necessary as of December 31, 2017.
Interest expense deduction limitation—the Tax Reform Act limits the deduction for business interest expense to 30% of adjusted taxable income for tax years beginning after December 31, 2017. Before January 1, 2022, the calculation of adjusted taxable income is similar to taxable earnings before interest, taxes, depreciation, and amortization (EBITDA). After January 1, 2022, that calculation is equivalent to taxable earnings before interest and taxes (EBIT). These adverse changes are mitigated by a law change that now allows any disallowed interest expense to be carried forward indefinitely. Based on our current tax planning strategies, these changes are not expected to have a significant adverse impact on our ability to deduct interest expenses for at least the next five years.
Acceleration of bonus depreciation—under the Tax Reform Act, entities are able to claim bonus depreciation to accelerate the expensing of the cost of certain qualified property acquired and placed into service after September 27, 2017 and before January 1, 2023. For the first five-year period (2018 through 2022), companies can deduct 100% of the cost of qualified property compared to a 50% allowance under previous law. During the period starting in 2023, the additional bonus depreciation is gradually phased out by 20% each year through 2027. This law change is expected to have a favorable impact on the Company as it has the potential to reduce or eliminate future taxable income or increase NOLs for utilization in future periods.
Executive compensation deduction limitation—for tax years beginning after December 31, 2017, the Tax Reform Act limits an entity's ability to deduct compensation in excess of $1 million for certain employees regardless of the character of those payments. Further, the new law expands the number of individuals whose compensation is subject to the $1 million limitation and expands the types of equity awards to be included in the calculations. These changes will limit our ability to deduct future executive compensation expenses, the impact of which is uncertain but is not expected to be significant to our business.
Impact on foreign operations—the Tax Reform Act introduces new rules that significantly change fundamental aspects of the taxation of foreign earnings of U.S. entities. Notably, the new law subjects unrepatriated foreign earnings to a mandatory one-time transition tax on post-1986 earnings at a rate of 15.5% for foreign earnings held in the form of cash and certain liquid assets and at a rate of 8% for all other foreign earnings. Our foreign operations are immaterial and have not generated taxable income historically and are not expected to generate significant taxable income in the future. Additionally, we have no significant cash or liquid assets held in foreign countries. Accordingly, the foreign tax law changes in the Tax Reform Act are not expected to have a significant impact on our business.
In addition to the changes described above, the Tax Reform Act includes a multitude of other provisions that broaden the tax base and eliminate or reduce other deductions, exclusions, and credits, none of which are expected to individually have a significant impact on our business.
The Tax Reform Act is generally expected to have an overall favorable impact on our business primarily due to expected benefits from the reduced corporate tax rate. The new laws are not expected to adversely impact our liquidity or the amount of cash payments we make for income taxes for at least the next five years.
Inflation
Certain drilling and completion costs and costs of oilfield services, equipment, and materials decreased in recent years as service providers reduced their costs in response to reduced demand arising from historically low crude oil prices. However, inflationary pressures returned in 20172021 and are expected to continue in 20182022 in conjunction with the stabilization andsignificant improvement in crude oilcommodity prices over the past year in response to the lifting of COVID-19 restrictions, the resumption of normal economic activity, and the resulting improvement in supply and demand fundamentals. Additionally, recent months. As a resultsupply chain disruptions stemming from the COVID-19 pandemic have led to shortages of the low commodity price environment in recent years, the number of providers of services,certain materials and equipment and materials decreasedresulting increases in the regions where we operate.material and labor costs. If these supply chain disruptions persist or worsen, and commodity prices show signs of sustained recovery andcontinue to remain at attractive levels that stimulate increased industry drilling and completion activities increase,activity, we may face shortages of service providers, equipment, and materials. Such shortages could result in increased competition which may lead to further increases in costs.


Non-GAAP Financial Measures
Net crude oil and natural gas sales and net sales prices
Revenues and transportation expenses associated with production from our operated properties are reported separately as discussed in Part II, Item 8. Notes to Consolidated Financial Statements—Note 9. Revenues. For non-operated properties, we receive a net payment from the operator for our share of sales proceeds which is net of costs incurred by the operator, if any. Such non-operated revenues are recognized at the net amount of proceeds received. As a result, the separate presentation of revenues and transportation expenses from our operated properties differs from the net presentation from non-operated properties. This impacts the comparability of certain operating metrics, such as per-unit sales prices, when such metrics are prepared in accordance with U.S. GAAP using gross presentation for some revenues and net presentation for others.
57

In order to provide metrics prepared in a manner consistent with how management assesses the Company's operating results and to achieve comparability between operated and non-operated revenues, we have presented crude oil and natural gas sales net of transportation expenses in Management’s Discussion and Analysis of Financial Condition and Results of Operations, which we refer to as "net crude oil and natural gas sales," a non-GAAP measure. Average sales prices calculated using net crude oil and natural gas sales are referred to as "net sales prices," a non-GAAP measure, and are calculated by taking revenues less transportation expenses divided by sales volumes, whether for crude oil or natural gas, as applicable. Management believes presenting our revenues and sales prices net of transportation expenses is useful because it normalizes the presentation differences between operated and non-operated revenues and allows for a useful comparison of net realized prices to NYMEX benchmark prices on a Company-wide basis.
The following table presents a reconciliation of total Company crude oil and natural gas sales (GAAP) to net crude oil and natural gas sales and related net sales prices (non-GAAP) for 2021, 2020, and 2019.
Total CompanyYear Ended December 31, 2021Year Ended December 31, 2020Year Ended December 31, 2019
In thousandsCrude oilNatural gasTotalCrude oilNatural gasTotalCrude oilNatural gasTotal
Crude oil and natural gas sales (GAAP)$3,949,294 $1,844,447 $5,793,741 $2,199,976 $355,458 $2,555,434 $3,929,994 $584,395 $4,514,389 
Less: Transportation expenses(185,130)(39,859)(224,989)(158,989)(37,703)(196,692)(191,998)(33,651)(225,649)
Net crude oil and natural gas sales (non-GAAP)$3,764,164 $1,804,588 $5,568,752 $2,040,987 $317,755 $2,358,742 $3,737,996 $550,744 $4,288,740 
Sales volumes (MBbl/MMcf/MBoe)58,757 370,110 120,442 58,793 306,528 109,881 72,136 311,865 124,113 
Net sales price (non-GAAP)$64.06 $4.88 $46.24 $34.71 $1.04 $21.47 $51.82 $1.77 $34.56 
The following tables present reconciliations of crude oil and natural gas sales (GAAP) to net crude oil and natural gas sales and related net sales prices (non-GAAP) for North Dakota Bakken and SCOOP for 2021, 2020, and 2019 as presented in Part I, Item 1. Business—Crude Oil and Natural Gas Operations—Production and Price History.
North Dakota BakkenYear Ended December 31, 2021Year Ended December 31, 2020Year Ended December 31, 2019
In thousandsCrude oilNatural gasTotalCrude oilNatural gasTotalCrude oilNatural gasTotal
Crude oil and natural gas sales (GAAP)$2,695,738 $549,932 $3,245,670 $1,469,450 $24,714 $1,494,164 $2,826,136 $128,426 $2,954,562 
Less: Transportation expenses(154,359)(4,831)(159,190)(127,036)(2,580)(129,616)(157,076)(2,530)(159,606)
Net crude oil and natural gas sales (non-GAAP)$2,541,379 $545,101 $3,086,480 $1,342,414 $22,134 $1,364,548 $2,669,060 $125,896 $2,794,956 
Sales volumes (MBbl/MMcf/MBoe)40,186 120,517 60,272 40,040 97,532 56,295 52,374 98,186 68,738 
Net sales price (non-GAAP)$63.24 $4.52 $51.21 $33.53 $0.23 $24.24 $50.96 $1.28 $40.66 
SCOOPYear Ended December 31, 2021Year Ended December 31, 2020Year Ended December 31, 2019
In thousandsCrude oilNatural gasTotalCrude oilNatural gasTotalCrude oilNatural gasTotal
Crude oil and natural gas sales (GAAP)$756,596 $980,323 $1,736,919 $486,076 $246,125 $732,201 $640,097 $277,230 $917,327 
Less: Transportation expenses(2,854)(23,808)(26,662)(5,275)(21,909)(27,184)(3,539)(14,795)(18,334)
Net crude oil and natural gas sales (non-GAAP)$753,742 $956,515 $1,710,257 $480,801 $224,216 $705,017 $636,558 $262,435 $898,993 
Sales volumes (MBbl/MMcf/MBoe)11,341 179,553 41,267 12,694 136,410 35,429 11,592 111,436 30,164 
Net sales price (non-GAAP)$66.46 $5.33 $41.44 $37.88 $1.64 $19.90 $54.92 $2.36 $29.80 
58

PV-10
Our PV-10 value, a non-GAAP financial measure, is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable financial measure computed using U.S. GAAP. PV-10 generally differs from Standardized Measure because it does not include the effects of income taxes on future net revenues. At December 31, 2017,2021, our PV-10 totaled approximately $11.83$20.49 billion. The standardized measure of our discounted future net cash flows was approximately $10.47$16.64 billion at December 31, 2017,2021, representing a $1.36$3.86 billion difference from PV-10 due to the effect of deducting estimated future income taxes in arriving at Standardized Measure. We believe the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to proved reserves held by companies without regard to the specific income tax characteristics of such entities and is a useful measure of evaluating the relative monetary significance of our crude oil and natural gas properties. Investors may utilize PV-10 as a basis for comparing the relative size and value of our proved reserves to other companies. PV-10 should not be considered as a substitute for, or more meaningful than, the Standardized Measure as determined in accordance with U.S. GAAP. Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of our crude oil and natural gas properties.

59


Item 7A.Quantitative and Qualitative Disclosures About Market Risk
Item 7A.    Quantitative and Qualitative Disclosures About Market Risk
General. We are exposed to a variety of market risks including commodity price risk, credit risk, and interest rate risk. We seek to address these risks through a program of risk management which may include the use of derivative instruments.
Commodity Price Risk. Our primary market risk exposure is in the prices we receive from sales of our crude oil and natural gas production.gas. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our natural gas production. PricingPrices for crude oil and natural gas hashave been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside of our control, including volatility in the differences between product prices at sales points and the applicable index prices. Based on our average daily production for the quarter ended December 31, 2017,2021, and excluding any effect of our derivative instruments in place, our annual revenue would increase or decrease by approximately $613$608 million for each $10.00 per barrel change in crude oil prices at December 31, 2021 and $260$380 million for each $1.00 per Mcf change in natural gas prices.prices at December 31, 2021.
To reduce price risk caused by market fluctuations in crude oil and natural gas prices, from time to time we may economically hedge a portion of our anticipated crude oil and natural gas production as part of our risk management program. In addition, we may utilize basis contracts to hedge the differential between derivative contract index prices and those of our physical pricing points. Reducing our exposure to price volatility helps secure funds to be used for our capital program.program and for general corporate purposes. Our decision on the quantity and price at which we choose to hedge our production is based in part on our view of current and future market conditions. We may choose not to hedge future production if the price environment for certain time periods is deemed to be unfavorable. Additionally, we may choose to liquidatesettle existing derivative positions prior to the expiration of their contractual maturities in order to monetize gain positions for the purpose of funding our capital program.maturities. While hedging, if utilized, limitsmay limit the downside risk of adverse price movements, it also limitsmay limit future revenues from upward price movements. We have hedged the majority
The fair value of our forecasted 2018derivative instruments at December 31, 2021 was a net asset of $34.3 million, which is comprised of a $33.3 million net asset associated with our natural gas production. Our futurederivatives and a $1.0 million net asset associated with our crude oil production is currently unhedged and directly exposedderivatives. The following table shows how a hypothetical +/- 10% change in the underlying forward prices used to continued volatility in market prices, whether favorable or unfavorable.
Changes in natural gas prices during the year ended December 31, 2017 had an overall favorable impact oncalculate the fair value of our derivative instruments. Forderivatives would impact the year endedfair value estimates as of December 31, 2017, we recognized cash gains on natural gas derivatives of $29.6 million and non-cash mark-to-market gains on natural gas derivatives of $62.1 million.2021.
Hypothetical Fair Value
In thousandsChange in Forward PriceAsset (Liability)
Crude Oil-10%$1,273
Crude Oil+10%$641
Natural Gas-10%$99,641
Natural Gas+10%($33,074)
The fair value of our natural gas derivative instruments at December 31, 2017 was a net asset of $2.6 million. An assumed increase in the forward prices used in the year-end valuation of our natural gas derivatives of $1.00 per MMBtu would change our natural gas derivative valuation to a net liability of approximately $2 million at December 31, 2017. Conversely, an assumed decrease in forward prices of $1.00 per MMBtu would increase our natural gas derivative asset to approximately $7 million at December 31, 2017. Changes in the fair value of our natural gas derivatives from the above price sensitivities would produce a corresponding change in our total revenues.
See Part II, Item 8. Notes to Consolidated Financial Statements—Note 5. Derivative Instruments for further discussion of our hedging activities, including a summary of derivative contracts in place as of December 31, 2017.
Credit Risk. We monitor our risk of loss due to non-performance by counterparties of their contractual obligations. Our principal exposure to credit risk is through the sale of our crude oil and natural gas production, which we market to energy marketing companies, crude oil refining companies, and natural gas gathering and processing companies ($672 million1.1 billion in receivables at December 31, 2017);2021) and our joint interest and other receivables ($427279 million at December 31, 2017); and counterparty credit risk associated with our derivative instrument receivables ($3 million at December 31, 2017)2021).
We monitor our exposure to counterparties on crude oil and natural gas sales primarily by reviewing credit ratings, financial statements and payment history. We extend credit terms based on our evaluation of each counterparty’s credit worthiness. We have not generally required our counterparties to provide collateral to secure crude oil and natural gas sales receivables owed to us. Historically, our credit losses on crude oil and natural gas sales receivables have been immaterial.
Joint interest receivables arise from billing the individuals and entities who own a partial interest in the wells we operate. These individuals and entities participate in our wells primarily based on their ownership in leases included in units on which we wish to drill. We can do very little to choose who participates in our wells. In order to minimize our exposure to this credit risk we generally request prepayment of drilling costs where it is allowed by contract or state law. For such prepayments, a liability is recorded and subsequently reduced as the associated work is performed. This liability was $35$19 million at December 31, 2017,2021, which will be used to offset future capital costs when billed. In this manner, we reduce credit risk. We may have the right to place a lien on a co-owner’s interest in the well, to redirectnet production proceeds against amounts owed in order to secure payment or, if necessary, foreclose on the interest. Historically, our credit losses on joint interest receivables have been immaterial.

60


Our use of derivative instruments involves the risk that our counterparties will be unable to meet their commitments under the arrangements. We manage this risk by using multiple counterparties who we consider to be financially strong in order to minimize our exposure to credit risk with any individual counterparty.
Interest Rate Risk. Our exposure to changes in interest rates relates primarily to any variable-rate borrowings we may have outstanding from time to time under our revolving credit facility. Such borrowings bear interest at market-based interest rates plus a margin based on the terms of the borrowing and the credit ratings assigned to our senior, unsecured, long-term indebtedness. All of our other long-term indebtedness is fixed rate and does not expose us to the risk of cash flow loss due to changes in market interest rates.
We had $240 million of variable rate borrowings outstanding on our credit facility at January 31, 2022. The impact of a 0.25% increase in interest rates on this amount of debt would result in increased interest expense and reduced income before income taxes of approximately $0.6 million per year.
We manage our interest rate exposure by monitoring both the effects of market changes in interest rates and the proportion of our debt portfolio that is variable-rate versus fixed-rate debt. We may utilize interest rate derivatives to alter interest rate exposure in an attempt to reduce interest rate expense related to existing debt issues. Interest rate derivatives may be used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio. We currently have no interest rate derivatives.
We had $93 million of variable rate borrowings outstanding on our revolving credit facility at January 31, 2018. The impact of a 0.25% increase in interest rates on this amount of debt would result in increased interest expense and reduced net income of approximately $0.2 million per year.
The following table presents our debt maturities and the weighted average interest rates by expected maturity date as of December 31, 2017:2021:
In thousands20222023202420252026ThereafterTotal
Fixed rate debt:
Senior Notes:
Principal amount (1)$— $649,625 $911,000 $— $800,000 $4,000,000 $6,360,625 
Weighted-average interest rate— 4.5%3.8%— 2.3 %4.7 %4.2 %
Notes payable:
Principal amount (1)$2,326 $2,410 $2,495 $2,587 $2,681 $9,952 $22,451 
Interest rate3.5 %3.5 %3.5 %3.5 %3.5 %3.5 %3.5 %
Variable rate debt:
Credit facility:
Principal amount$— $— $— $— $500,000 $— $500,000 
Weighted-average interest rate— — — — 1.6 %— 1.6 %
(1)Amounts represent scheduled maturities and do not reflect any discount or premium at which the notes were issued or any debt issuance costs.
61
In thousands 2018 2019 2020 2021 2022 Thereafter Total
Fixed rate debt: 
 
 
 
 
 
 
Senior Notes: 
 
 
 
 
 
 
Principal amount (1) $—
 $—
 $—
 $—
 $2,000,000
 $4,200,000
 $6,200,000
Weighted-average interest rate —
 —
 —
 —
 5.0% 4.4% 4.6%
Note payable: 
 
 
 
 
 
 
Principal amount $2,286
 $2,360
 $2,435
 $2,515
 $425
 $—
 $10,021
Interest rate 3.1% 3.1% 3.1% 3.1% 3.1% —
 3.1%
Variable rate debt: 
 
 
 
 
 
 
Revolving credit facility: 
 
 
 
 
 
 
Principal amount $—
 $188,000
 $—
 $—
 $—
 $—
 $188,000
Weighted-average interest rate —
 3.2% —
 —
 —
 —
 3.2%
(1)Amounts do not reflect any discount or premium at which the senior notes were issued.




Item 8.
Item 8.    Financial Statements and Supplementary Data




Index to Consolidated Financial Statements
(PCAOB ID Number 248)
7663
7766
7867
7968
8070
8171

62


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


Board of Directors and Shareholders
Continental Resources, Inc.


Opinion on the financial statements
We have audited the accompanying consolidated balance sheets of Continental Resources, Inc. (an Oklahoma corporation) and subsidiaries (the “Company”) as of December 31, 20172021 and 2016,2020, the related consolidated statements of comprehensive income (loss), shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2017,2021, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 20172021 and 2016,2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017,2021, in conformity with accounting principles generally accepted in the United States of America.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Company’s internal control over financial reporting as of December 31, 2017,2021, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), and our report datedFebruary 21, 2018 14, 2022expressed an unqualified opinion.
Basis for opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence supportingregarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical audit matter
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
•Estimation of proved crude oil and natural gas reserves as it relates to the recognition of depletion expense, proved and unproved crude oil and natural gas reserves used in the assessment and measurement of impairment of proved crude oil and natural gas properties, and recording of the fair value of crude oil and natural gas properties in the Permian Basin Acquisition and Powder River Basin Acquisitions (herein referred to as “the crude oil and natural gas reserves”)
    As described in Note 1 to the consolidated financial statements, the Company accounts for its crude oil and natural gas properties using the successful efforts method of accounting, which requires management to make estimates of proved crude oil and natural gas reserve volumes and future cash flows to record depletion expense
63

and proved and unproved crude oil and natural gas reserves to assess its crude oil and natural gas properties for impairment. Additionally, as described in Note 2 to the consolidated financial statements, the Company acquired significant oil and natural gas properties through asset acquisitions and a business combination. Crude oil and natural gas reserves are a significant input to the determination of the acquisition date fair value of crude oil and natural gas properties acquired by the Company in asset acquisitions and business combinations. To estimate the crude oil and natural gas reserves and future cash flows, management makes significant estimates and assumptions including forecasting the production decline rate of producing crude oil and natural gas properties and forecasting the timing and volume of production associated with the Company’s development plan for proved undeveloped properties and unproved properties. In addition, the estimation of the crude oil and natural gas reserves is also impacted by management’s judgments and estimates regarding the financial performance of wells associated with the crude oil and natural gas reserves to determine if wells are expected with reasonable certainty to be economical under the appropriate pricing assumptions required in the estimation of depletion expense and impairment assessments / measurements. We identified the estimation of proved crude oil and natural gas reserves as it relates to the recognition of depletion expense and proved and unproved crude oil and natural gas reserves for the assessment / measurement of impairment of crude oil and natural gas properties as a critical audit matter.
    The principal considerations for our determination that the estimation of proved crude oil and natural gas reserves as it relates to the recognition of depletion expense and proved and unproved crude oil and natural gas reserves for the assessment / measurement of impairment of crude oil and natural gas properties and the recording of oil and natural gas properties values in the Permian Basin Acquisition and Powder River Basin Acquisitions is a critical audit matter is that relatively minor changes in certain inputs and assumptions, which require a high degree of subjectivity, necessary to estimate the volume and future cash flows of the Company’s crude oil and natural gas reserves could have a significant impact on the measurement of depletion expense or assessment / measurement of impairment expense and the acquisition date values of crude oil and natural gas properties.
    Our audit procedures related to the estimation of proved crude oil and natural gas reserves as it relates to the recognition of depletion expense and proved and unproved crude oil and natural gas reserves for the assessment and measurement of impairment and the amount of crude oil and natural gas properties recorded from acquisitions and business combinations included the following, among others.
•Tested the design and operating effectiveness of controls relating to management’s estimation of proved crude oil and natural gas reserves for the purpose of estimating depletion expense and proved and unproved crude oil and natural gas reserves for assessing / measuring the Company’s proved crude oil and gas properties for impairment and acquisitions and business combinations.
•Assessed the independence, objectivity, and professional qualifications of the Company’s reservoir engineer specialists, made inquiries of these specialists (internal and external) regarding the process followed and judgments used to make significant estimates, including but not limited to crude oil and natural gas reserve volumes, decline rates, and economically recoverable crude oil and natural gas reserves and reviewed the reserve estimates prepared by the Company’s specialists.
•To the extent key inputs and assumptions used to determine crude oil and natural gas reserve volumes and other cash flow inputs and assumptions are derived from the Company’s accounting records, including, but not limited to: historical pricing differentials, operating costs, estimated capital costs, discount rates, and ownership interests, we tested management’s process for determining the assumptions, including examining underlying support on a sample basis. Specifically, our audit procedures involved testing management’s assumptions by:

◦Compared the estimated pricing differentials used in the reserve report to realized prices related to revenue transactions recorded in the current year and examined contractual support for the pricing differentials
◦Evaluated the models used to estimate the operating costs at year-end and compared to historical operating costs
64

◦Compared the estimates of future capital expenditures in the reserve reports to management’s forecasts and amounts expended for recently drilled and completed wells
◦Evaluated the working and net revenue interests used in the reserve report by inspecting land and division order records
◦Evaluated the Company’s evidence supporting the amount of proved undeveloped properties reflected in the reserve report by examining historical conversion rates and support for the Company’s ability to fund and intent to develop the proved undeveloped properties
◦Applied analytical procedures to the reserve report by comparing to historical actual results and to the prior year reserve report
◦Evaluated the reasonableness of the Company’s classification of reserves as proved or unproved
◦Evaluated the reasonableness of risk-adjustment factors applied to unproved crude oil and natural gas reserves that were taken into consideration to determine estimated future net cash flows used to evaluate proved property impairment and for acquisitions and business combinations
◦As it relates to the recording of the acquisition date values of crude oil and natural gas properties in acquisitions and a business combination, we utilized internal valuation specialists with specialized skills and knowledge to assist with evaluating certain assumptions, such as risk-adjustment factors and the valuation of unproved oil and gas properties on per net acre basis, as compared to industry surveys and publicly available market data

/s/ GRANT THORNTON LLP


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


Oklahoma City, Oklahoma
February 21, 201814, 2022






65

Continental Resources, Inc. and Subsidiaries
Consolidated Balance Sheets

  December 31,
In thousands, except par values and share data 2017 2016
Assets    
Current assets:    
Cash and cash equivalents $43,902
 $16,643
Receivables:    
Crude oil and natural gas sales 671,665
 404,750
Affiliated parties 63
 99
Joint interest and other, net 426,585
 364,850
Derivative assets 2,603
 4,061
Inventories 97,406
 111,987
Prepaid expenses and other 9,501
 10,843
Total current assets 1,251,725
 913,233
Net property and equipment, based on successful efforts method of accounting 12,933,789
 12,881,227
Other noncurrent assets 14,137
 17,316
Total assets $14,199,651
 $13,811,776
     
Liabilities and shareholders’ equity    
Current liabilities:    
Accounts payable trade $692,908
 $476,342
Revenues and royalties payable 374,831
 217,425
Payables to affiliated parties 143
 148
Accrued liabilities and other 260,074
 176,770
Derivative liabilities —
 59,489
Current portion of long-term debt 2,286
 2,219
Total current liabilities 1,330,242
 932,393
Long-term debt, net of current portion 6,351,405
 6,577,697
Other noncurrent liabilities:    
Deferred income tax liabilities, net 1,259,558
 1,890,305
Asset retirement obligations, net of current portion 111,794
 94,436
Other noncurrent liabilities 15,449
 14,949
Total other noncurrent liabilities 1,386,801
 1,999,690
Commitments and contingencies (Note 10) 
 
Shareholders’ equity:    
Preferred stock, $0.01 par value; 25,000,000 shares authorized; no shares issued and outstanding —
 —
Common stock, $0.01 par value; 1,000,000,000 shares authorized;    
375,219,769 shares issued and outstanding at December 31, 2017;    
374,492,357 shares issued and outstanding at December 31, 2016 3,752
 3,745
Additional paid-in capital 1,409,326
 1,375,290
Accumulated other comprehensive income (loss) 307
 (260)
Retained earnings 3,717,818
 2,923,221
Total shareholders’ equity 5,131,203
 4,301,996
Total liabilities and shareholders’ equity $14,199,651
 $13,811,776

 December 31,
In thousands, except par values and share data20212020
Assets
Current assets:
Cash and cash equivalents$20,868 $47,470 
Receivables:
Crude oil and natural gas sales1,122,415 561,127 
Joint interest and other278,753 143,829 
Allowance for credit losses(2,814)(2,462)
Receivables, net1,398,354 702,494 
Derivative assets22,334 15,303 
Inventories105,568 72,157 
Prepaid expenses and other17,266 15,121 
Total current assets1,564,390 852,545 
Net property and equipment, based on successful efforts method of accounting16,975,465 13,737,292 
Derivative assets, noncurrent13,188 — 
Operating lease right-of-use assets16,370 8,557 
Other noncurrent assets21,698 34,704 
Total assets$18,591,111 $14,633,098 
Liabilities and equity
Current liabilities:
Accounts payable trade$582,317 $361,704 
Revenues and royalties payable627,171 327,029 
Accrued liabilities and other285,740 167,013 
Derivative liabilities899 227 
Current portion of operating lease liabilities1,674 2,588 
Current portion of long-term debt2,326 2,245 
Total current liabilities1,500,127 860,806 
Long-term debt, net of current portion6,826,566 5,530,173 
Other noncurrent liabilities:
Deferred income tax liabilities, net2,139,884 1,620,154 
Asset retirement obligations, net of current portion215,701 177,194 
Derivative liabilities, noncurrent318 1,584 
Operating lease liabilities, net of current portion13,800 5,839 
Other noncurrent liabilities38,390 14,623 
Total other noncurrent liabilities2,408,093 1,819,394 
Commitments and contingencies (Note 13)00
Equity:
Preferred stock, $0.01 par value; 25,000,000 shares authorized; no shares issued and outstanding— — 
Common stock, $0.01 par value; 1,000,000,000 shares authorized;
364,297,520 shares issued and outstanding at December 31, 2021;
365,220,435 shares issued and outstanding at December 31, 2020;3,643 3,652 
Additional paid-in capital1,131,602 1,205,148 
Retained earnings6,340,211 4,847,646 
Total shareholders’ equity attributable to Continental Resources7,475,456 6,056,446 
Noncontrolling interests380,869 366,279 
Total equity7,856,325 6,422,725 
Total liabilities and equity$18,591,111 $14,633,098 

The accompanying notes are an integral part of these consolidated financial statements.
66

Continental Resources, Inc. and Subsidiaries
Consolidated Statements of Comprehensive Income (Loss)
 
 Year Ended December 31,
In thousands, except per share data202120202019
Revenues:
Crude oil and natural gas sales$5,793,741 $2,555,434 $4,514,389 
Gain (loss) on derivative instruments, net(128,864)(14,658)49,083 
Crude oil and natural gas service operations54,441 45,694 68,475 
Total revenues5,719,318 2,586,470 4,631,947 
Operating costs and expenses:
Production expenses406,906 359,267 444,649 
Production taxes404,362 192,718 357,988 
Transportation expenses224,989 196,692 225,649 
Exploration expenses21,047 17,732 14,667 
Crude oil and natural gas service operations21,480 18,294 33,230 
Depreciation, depletion, amortization and accretion1,898,082 1,880,959 2,017,383 
Property impairments38,370 277,941 86,202 
Acquisition costs13,920 — — 
General and administrative expenses233,628 196,572 195,302 
Net (gain) loss on sale of assets and other(5,146)187 (535)
Total operating costs and expenses3,257,638 3,140,362 3,374,535 
Income (loss) from operations2,461,680 (553,892)1,257,412 
Other income (expense):
Interest expense(251,598)(258,240)(269,379)
Gain (loss) on extinguishment of debt(290)35,719 (4,584)
Other(23,654)1,662 3,713 
(275,542)(220,859)(270,250)
Income (loss) before income taxes2,186,138 (774,751)987,162 
(Provision) benefit for income taxes(519,730)169,190 (212,689)
Net income (loss)1,666,408 (605,561)774,473 
Net income (loss) attributable to noncontrolling interests5,440 (8,692)(1,168)
Net income (loss) attributable to Continental Resources$1,660,968 $(596,869)$775,641 
Net income (loss) per share attributable to Continental Resources:
Basic$4.61 $(1.65)$2.09 
Diluted$4.56 $(1.65)$2.08 
Comprehensive income (loss):
Net income (loss)$1,666,408 $(605,561)$774,473 
Other comprehensive income (loss), net of tax:
Foreign currency translation adjustments— — 140 
Release of cumulative translation adjustments— — (555)
Total other comprehensive income (loss), net of tax— — (415)
Comprehensive income (loss)1,666,408 (605,561)774,058 
Comprehensive income (loss) attributable to noncontrolling interests5,440 (8,692)(1,168)
Comprehensive income (loss) attributable to Continental Resources$1,660,968 $(596,869)$775,226 
The accompanying notes are an integral part of these consolidated financial statements.
67
  Year Ended December 31,
In thousands, except per share data 2017 2016 2015
Revenues:      
Crude oil and natural gas sales $2,982,966
 $2,026,958
 $2,551,131
Crude oil and natural gas sales to affiliates —
 —
 1,400
Gain (loss) on crude oil and natural gas derivatives, net 91,647
 (71,859) 91,085
Crude oil and natural gas service operations 46,215
 25,174
 36,551
Total revenues 3,120,828
 1,980,273
 2,680,167
       
Operating costs and expenses:      
Production expenses 324,214
 289,289
 347,243
Production expenses to affiliates —
 —
 1,654
Production taxes 208,278
 142,388
 200,637
Exploration expenses 12,393
 16,972
 19,413
Crude oil and natural gas service operations 16,880
 11,386
 17,337
Depreciation, depletion, amortization and accretion 1,674,901
 1,708,744
 1,749,056
Property impairments 237,370
 237,292
 402,131
General and administrative expenses 191,706
 169,580
 189,846
Litigation settlement 59,600
 —
 —
Net gain on sale of assets and other (53,915) (307,844) (23,149)
Total operating costs and expenses 2,671,427
 2,267,807
 2,904,168
Income (loss) from operations 449,401
 (287,534) (224,001)
Other income (expense):      
Interest expense (294,495) (320,562) (313,079)
Loss on extinguishment of debt (554) (26,055) —
Other 1,715
 1,697
 1,995
  (293,334) (344,920) (311,084)
Income (loss) before income taxes 156,067
 (632,454) (535,085)
Benefit for income taxes 633,380
 232,775
 181,417
Net income (loss) $789,447
 $(399,679) $(353,668)
Basic net income (loss) per share $2.13
 $(1.08) $(0.96)
Diluted net income (loss) per share $2.11
 $(1.08) $(0.96)
       
Comprehensive income (loss):      
Net income (loss) $789,447
 $(399,679) $(353,668)
Other comprehensive income (loss), net of tax:      
Foreign currency translation adjustments 567
 3,094
 (2,969)
Total other comprehensive income (loss), net of tax 567
 3,094
 (2,969)
Comprehensive income (loss) $790,014
 $(396,585) $(356,637)


Continental Resources, Inc. and Subsidiaries
Consolidated Statements of Shareholders’ Equity

Shareholders’ equity attributable to Continental Resources
In thousands, except share dataShares
outstanding		Common
stock		Additional
paid-in
capital		Accumulated
other
comprehensive
income		Treasury
stock		Retained
earnings		Total shareholders’ equity of Continental ResourcesNoncontrolling
interests		Total
equity
Balance at December 31, 2018376,021,575 $3,760 $1,434,823 $415 $— $4,706,135 $6,145,133 $276,728 $6,421,861 
Net income (loss)— — — — — 775,641 775,641 (1,168)774,473 
Cash dividends declared— — — — — (18,747)(18,747)— (18,747)
Change in dividends payable— — — — — 195 195 — 195 
Common stock repurchased— — — — (190,239)— (190,239)— (190,239)
Common stock retired(5,646,553)(56)(190,183)— 190,239 — — — — 
Other comprehensive loss, net of tax— — — (415)— — (415)— (415)
Stock-based compensation— — 52,030 — — — 52,030 — 52,030 
Restricted stock:
Granted1,526,825 15 — — — — 15 — 15 
Repurchased and canceled(477,789)(5)(21,938)— — — (21,943)— (21,943)
Forfeited(350,022)(3)— — — — (3)— (3)
Contributions from noncontrolling interests— — — — — — — 105,528 105,528 
Distributions to noncontrolling interests— — — — — — — (14,404)(14,404)
Balance at December 31, 2019371,074,036 $3,711 $1,274,732 $— $— $5,463,224 $6,741,667 $366,684 $7,108,351 
Net loss— — — — — (596,869)(596,869)(8,692)(605,561)
Cumulative effect adjustment from adoption of ASU 2016-13— — — — — (137)(137)— (137)
Cash dividends declared— — — — — (18,580)(18,580)— (18,580)
Change in dividends payable— — — — — 8 8 — 8 
Common stock repurchased— — — — (126,906)— (126,906)— (126,906)
Common stock retired(8,122,104)(81)(126,825)— 126,906 — — — — 
Stock-based compensation— — 64,585 — — — 64,585 — 64,585 
Restricted stock:
Granted2,738,625 27 — — — — 27 — 27 
Repurchased and canceled(306,845)(3)(7,344)— — (7,347)— (7,347)
Forfeited(163,277)(2)— — — — (2)— (2)
Contributions from noncontrolling interests— — — — — — — 21,557 21,557 
Distributions to noncontrolling interests— — — — — — — (13,270)(13,270)
Balance at December 31, 2020365,220,435 $3,652 $1,205,148 $— $— $4,847,646 $6,056,446 $366,279 $6,422,725 
Net income— — — — — 1,660,968 1,660,968 5,440 1,666,408 
Cash dividends declared— — — — — (168,536)(168,536)— (168,536)
Change in dividends payable— — — — — 133 133 — 133 
Common stock repurchased— — — — (123,924)— (123,924)— (123,924)
Common stock retired(3,198,571)(32)(123,892)— 123,924 — — — — 
Stock-based compensation— — 63,145 — — — 63,145 — 63,145 
The accompanying notes are an integral part of these consolidated financial statements.
68
Continental Resources, Inc. and Subsidiaries
Consolidated Statements of Equity

In thousands, except share data 
Shares
outstanding
 
Common
stock
 
Additional
paid-in
capital
 
Accumulated
other
comprehensive
income (loss)
 
Retained
earnings
 
Total
shareholders’
equity
Balance at December 31, 2014 372,005,502
 $3,720
 $1,287,941
 $(385) $3,676,568
 $4,967,844
Net loss —
 —
 —
 —
 (353,668) (353,668)
Other comprehensive loss, net of tax —
 —
 —
 (2,969) —
 (2,969)
Stock-based compensation —
 —
 51,817
 —
 —
 51,817
Tax benefit from stock-based compensation —
 —
 13,177
 —
 —
 13,177
Restricted stock:            
Granted 1,462,534
 15
 —
 —
 —
 15
Repurchased and canceled (172,786) (2) (7,311) —
 —
 (7,313)
Forfeited (336,170) (3) —
 —
 —
 (3)
Balance at December 31, 2015 372,959,080
 $3,730
 $1,345,624
 $(3,354) $3,322,900
 $4,668,900
Net loss —
 —
 —
 —
 (399,679) (399,679)
Other comprehensive income, net of tax —
 —
 —
 3,094
 —
 3,094
Stock-based compensation —
 —
 48,084
 —
 —
 48,084
Tax deficiency from stock-based compensation —
 —
 (9,828) —
 —
 (9,828)
Restricted stock:            
Granted 2,064,508
 20
 —
 —
 —
 20
Repurchased and canceled (337,981) (3) (8,590) —
 —
 (8,593)
Forfeited (193,250) (2) —
 —
 —
 (2)
Balance at December 31, 2016 374,492,357
 $3,745
 $1,375,290
 $(260) $2,923,221
 $4,301,996
Cumulative effect adjustment from adoption of ASU 2016-09 (see Note 1) —
 —
 —
 —
 5,150
 5,150
Net income —
 —
 —
 —
 789,447
 789,447
Other comprehensive income, net of tax —
 —
 —
 567
 —
 567
Stock-based compensation —
 —
 45,854
 —
 —
 45,854
Restricted stock:            
Granted 1,585,870
 16
 —
 —
 —
 16
Repurchased and canceled (259,729) (3) (11,818) —
 —
 (11,821)
Forfeited (598,729) (6) —
 —
 —
 (6)
Balance at December 31, 2017 375,219,769
 $3,752
 $1,409,326
 $307
 $3,717,818
 $5,131,203

Restricted stock:
Granted3,050,491 31 — — — — 31 — 31 
Repurchased and canceled(478,697)(5)(12,799)— — (12,804)— (12,804)
Forfeited(296,138)(3)— — — — (3)— (3)
Contributions from noncontrolling interests— — — — — — — 33,086 33,086 
Distributions to noncontrolling interests— — — — — — — (23,936)(23,936)
Balance at December 31, 2021364,297,520 $3,643 $1,131,602 $— $— $6,340,211 $7,475,456 $380,869 $7,856,325 

The accompanying notes are an integral part of these consolidated financial statements.
69

Continental Resources, Inc. and Subsidiaries
Consolidated Statements of Cash Flows
 Year Ended December 31,
In thousands202120202019
Cash flows from operating activities:
Net income (loss)$1,666,408 $(605,561)$774,473 
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depreciation, depletion, amortization and accretion1,893,106 1,882,458 2,019,704 
Property impairments38,370 277,941 86,202 
Non-cash (gain) loss on derivatives, net(20,814)(13,492)15,612 
Stock-based compensation63,173 64,613 52,044 
Provision (benefit) for deferred income taxes519,730 (166,971)212,689 
Net (gain) loss on sale of assets and other(5,146)187 (535)
(Gain) loss on extinguishment of debt290 (35,719)4,584 
Other, net35,614 16,970 10,408 
Changes in assets and liabilities:
Accounts receivable(694,981)332,128 (33,619)
Inventories(33,411)12,859 (21,204)
Other current assets(2,144)1,471 (4,459)
Accounts payable trade106,367 (133,977)(36,359)
Revenues and royalties payable298,552 (143,260)69,195 
Accrued liabilities and other109,540 (66,071)(36,467)
Other noncurrent assets and liabilities(803)(1,272)3,420 
Net cash provided by operating activities3,973,851 1,422,304 3,115,688 
Cash flows from investing activities:
Exploration and development(2,382,413)(1,408,149)(2,783,149)
Purchase of producing crude oil and natural gas properties(2,548,575)(81,994)(51,558)
Purchase of other property and equipment(66,598)(23,994)(25,983)
Proceeds from sale of assets8,041 2,779 88,734 
Net cash used in investing activities(4,989,545)(1,511,358)(2,771,956)
Cash flows from financing activities:
Credit facility borrowings1,663,000 2,052,000 1,216,000 
Repayment of credit facility(1,323,000)(1,947,000)(1,161,000)
Proceeds from issuance of Senior Notes1,587,776 1,485,000 — 
Redemption and repurchase of Senior Notes(630,782)(1,343,250)(500,000)
Premium and costs on redemption of Senior Notes— (25,173)(4,167)
Proceeds from other debt— 26,000 — 
Repayment of other debt(2,243)(6,679)(2,352)
Debt issuance costs(12,082)(4,368)— 
Contributions from noncontrolling interests31,493 27,116 109,137 
Distributions to noncontrolling interests(22,447)(13,809)(14,164)
Repurchase of common stock(123,924)(126,906)(190,239)
Repurchase of restricted stock for tax withholdings(12,804)(7,347)(21,943)
Dividends paid on common stock(165,895)(18,460)(18,380)
Net cash provided by (used in) financing activities989,092 97,124 (587,108)
Effect of exchange rate changes on cash— — 27 
Net change in cash and cash equivalents(26,602)8,070 (243,349)
Cash and cash equivalents at beginning of period47,470 39,400 282,749 
Cash and cash equivalents at end of period$20,868 $47,470 $39,400 
The accompanying notes are an integral part of these consolidated financial statements.
70
  Year Ended December 31,
In thousands 2017 2016 2015
Cash flows from operating activities:      
Net income (loss) $789,447
 $(399,679) $(353,668)
Adjustments to reconcile net income (loss) to cash provided by operating activities:      
Depreciation, depletion, amortization and accretion 1,670,838
 1,709,567
 1,746,454
Property impairments 237,370
 237,292
 402,131
Non-cash (gain) loss on derivatives, net (58,031) 156,621
 (21,532)
Stock-based compensation 45,868
 48,098
 51,834
Tax benefit from US tax reform legislation (713,655) —
 —
Provision (benefit) for deferred income taxes from operations 88,056
 (209,836) (181,441)
Tax deficiency (benefit) from stock-based compensation —
 9,828
 (13,177)
Dry hole costs 176
 4,866
 8,381
Litigation settlement 59,600
 —
 —
Gain on sale of assets, net (55,124) (304,489) (23,149)
Loss on extinguishment of debt 554
 26,055
 —
Other, net 12,592
 9,812
 12,646
Changes in assets and liabilities:      
Accounts receivable (329,811) (158,383) 524,973
Inventories 14,517
 (17,836) 7,997
Other current assets 1,038
 968
 65,493
Accounts payable trade 137,339
 (14,404) (201,434)
Revenues and royalties payable 158,982
 30,455
 (85,754)
Accrued liabilities and other 21,368
 (883) (84,056)
Other noncurrent assets and liabilities (2,018) (2,133) 1,403
Net cash provided by operating activities 2,079,106
 1,125,919
 1,857,101
       
Cash flows from investing activities:      
Exploration and development (1,931,942) (1,154,131) (3,042,747)
Purchase of producing crude oil and natural gas properties (8,446) (5,008) (557)
Purchase of other property and equipment (12,810) (5,375) (36,951)
Proceeds from sale of assets 144,353
 631,549
 34,008
Net cash used in investing activities (1,808,845) (532,965) (3,046,247)
       
Cash flows from financing activities:      
Credit facility borrowings 1,302,000
 1,691,000
 2,001,000
Repayment of credit facility (2,019,000) (1,639,000) (1,313,000)
Proceeds from issuance of Senior Notes 990,000
 —
 —
Redemption of Senior Notes —
 (600,000) —
Premium on redemption of Senior Notes —
 (19,168) —
Proceeds from other debt —
 —
 500,000
Repayment of other debt (502,214) (2,144) (2,078)
Debt issuance costs (1,999) (40) (4,597)
Repurchase of restricted stock for tax withholdings (11,821) (8,593) (7,313)
Tax (deficiency) benefit from stock-based compensation —
 (9,828) 13,177
Net cash (used in) provided by financing activities (243,034) (587,773) 1,187,189
Effect of exchange rate changes on cash 32
 (1) (10,961)
Net change in cash and cash equivalents 27,259
 5,180
 (12,918)
Cash and cash equivalents at beginning of period 16,643
 11,463
 24,381
Cash and cash equivalents at end of period $43,902
 $16,643
 $11,463


Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements

Note 1. Organization and Summary of Significant Accounting Policies
Description of the Company
Continental Resources, Inc. (the “Company”) was originally formed in 1967 and is incorporated under the laws of the State of Oklahoma. The Company’s principal business is crude oil and natural gas exploration, development, management, and production with properties primarily located in the North, South, and East regions of the United States. Additionally, the Company pursues the acquisition and management of perpetually owned minerals located in its key operating areas.
In 2021 the Company executed strategic acquisitions to expand its operations into the Permian Basin of Texas and the Powder River Basin of Wyoming. See Note 2. Property Acquisitions and Dispositions for additional information on the acquisitions. The Company's 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. The South region includes all properties south of Nebraska and west of the Mississippi River including various plays inand includes the SCOOP (South Central Oklahoma Oil Province) and STACK (Sooner Trend Anadarko Canadian Kingfisher) areas of Oklahoma.Oklahoma and the Permian Basin of Texas. The East region is primarily comprised of undeveloped leasehold acreage east of the Mississippi River with no significant drilling or production operations.
A substantial portion For financial reporting purposes, the Company has one reportable segment due to the similar nature of its business, which is the Company’s operations is located in the North region, with that region comprising approximately59%exploration, development, and production of the Company’s crude oil and natural gas production and approximately 69% of its crude oil and natural gas revenues for the year ended December 31, 2017. The Company’s principal producing properties in the North region are located in the Bakken field of North Dakota and Montana. As of December 31, 2017, approximately 50% of the Company’s estimated proved reserves were located in the North region. In recent years, the Company has significantly expanded its operations in the South region with its increased activity in the SCOOP and STACK plays. The South region comprised approximately 41% of the Company’s crude oil and natural gas production, 31% of its crude oil and natural gas revenues, and 50% of its estimated proved reserves as of and for the year ended December 31, 2017.
For the year ended December 31, 2017, crude oil accounted for approximately 57% of the Company’s total production and approximately 78% of its crude oil and natural gas revenues. Crude oil represents approximately 48% of the Company’s estimated proved reserves as of December 31, 2017.United States.
Basis of presentation of consolidated financial statements
The consolidated financial statements include the accounts of the Company, its wholly-owned subsidiaries, and its subsidiaries, all ofentities in which are 100% owned, after all significant intercompanythe Company has a controlling financial interest. Intercompany accounts and transactions have been eliminated upon consolidation. Noncontrolling interests reflected herein represent third party ownership in the net assets of consolidated subsidiaries. The portions of consolidated net income (loss) and equity attributable to the noncontrolling interests are presented separately in the Company’s financial statements.
Use of estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States (“U.S. GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure and estimation of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting periods. Actual results may differ from those estimates. The most significant estimates and assumptions impacting reported results are estimates of the Company’s crude oil and natural gas reserves, which are used to compute depreciation, depletion, amortization and impairment of proved crude oil and natural gas properties.
Revenue recognition
Crude oil and natural gas sales result from interests owned by the Company in crude oil and natural gas properties. Sales of crude oil and natural gas produced from crude oil and natural gas operations are recognized when the product is delivered to the purchaser and title transfers to the purchaser. Payment is generally received one to three months after the sale has occurred. The Company uses the sales method of accounting for natural gas imbalances in those circumstances where it has under-produced or over-produced its ownership percentage in a property. Under this method, a receivable or payable is recognized only to the extent an imbalance cannot be recouped from the reserves in the underlying properties. The Company’s aggregate imbalance positions at December 31, 2017 and 2016 were not material.
New accounting rules governing the recognition and presentation of revenues went into effect on January 1, 2018. See the subsequent section titled "New accounting pronouncements not yet adopted at December 31, 2017–Revenue recognition and presentation" for discussion of the expected impact of the new rules on the Company's future financial statements.


81
Table of Contents
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements


Cash and cash equivalents
The Company considers all highly liquid investments with original maturities of three months or less to be cash equivalents. The Company maintains its cash and cash equivalents in accounts that may not be federally insured. As of December 31, 2017,2021, the Company had cash deposits in excess of federally insured amounts of approximately $42.5$19.4 million.The Company has not experienced any losses in such accounts and believes it is not exposed to significant credit risk in this area.
Accounts receivable
The Company operates exclusively in crude oil and natural gas exploration and production related activities. Receivables arising from crude oil and natural gas sales and joint interest receivables are generally unsecured. Accounts receivable are due within 30 days and are considered delinquent after 60 days. The Company determines its allowance for doubtful accounts by considering a number of factors, including the length of time accounts are past due, the Company’s history of losses, and the customer or working interest owner’s ability to pay. The Company writes off specific receivables when they become noncollectable and any payments subsequently received on those receivables are credited to the allowance for doubtful accounts.credit losses. Write-offs of noncollectable receivables have historically not been material. The Company’s allowance for doubtful accountscredit losses totaled $2.2$2.8 million and $3.0$2.5 million as of December 31, 20172021 and 2016, respectively, which is included in “Receivables—Joint interest and other, net” on the consolidated balance sheets.2020, respectively. See Note 10. Allowance for Credit Losses for additional information.
Concentration of credit risk
The Company is subject to credit risk resulting from the concentration of its crude oil and natural gas receivables with several significant purchasers. For the year ended December 31, 2017,2021, sales to the Company’s two largest purchaserspurchaser accounted for approximately 11% and 11%, respectively,10% of the Company’s total crude oil and natural gas sales. No other purchaser accounted for more than 10% of the Company’s total crude oil and natural gas sales for 2017.2021. The Company generally does not require collateral and does not believe the loss of any single purchaser would materially impact its operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers in various regions.
71
Table of Contents
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements

Inventories
Inventory is comprised of crude oil held in storage or as line fill in pipelines, pipeline imbalances, and tubular goods and equipment to be used in the Company’s exploration and development activities. Crude oil inventories are valued at the lower of cost or marketnet realizable value primarily using the first-in, first-out inventory method. Tubular goods and equipment are valued primarily using a weighted average cost method applied to specific classes of inventory items.
The components of inventory as of December 31, 20172021 and 20162020 consisted of the following:
December 31,
In thousands20212020
Tubular goods and equipment$12,506 $13,671 
Crude oil93,062 58,486 
Total$105,568 $72,157 
  December 31,
In thousands 2017 2016
Tubular goods and equipment $14,946
 $15,243
Crude oil 82,460
 96,744
Total $97,406
 $111,987
In the first quarter of 2020 the Company recognized a $24.5 million impairment to reduce its crude oil inventory to estimated net realizable value at the time of impairment. The impairment is included in the caption “Property impairments” in the consolidated statements of comprehensive income (loss) for the year ended December 31, 2020.
Crude oil and natural gas properties
The Company uses the successful efforts method of accounting for crude oil and natural gas properties whereby costs incurred to acquire mineral interests in crude oil and natural gas properties, to drill and equip exploratory wells that find proved reserves, to drill and equip development wells, and expenditures for enhanced recovery operations are capitalized. Geological and geophysical costs, seismic costs incurred for exploratory projects, lease rentals and costs associated with unsuccessful exploratory wells or projects are expensed as incurred. Costs of seismic studies that are utilized in development drilling within an area of proved reserves are capitalized as development costs. To the extent a seismic project covers areas of both developmental and exploratory drilling, those seismic costs are proportionately allocated between capitalized development costs and exploration expense. Maintenance repairs and costs of injectionrepairs are expensed as incurred, except that the costs of replacements or renewals that expand capacity or improve production are capitalized.incurred.
Under the successful efforts method of accounting, the Company capitalizes exploratory drilling costs on the balance sheet pending determination of whether the well has found proved reserves in economically producible quantities. The Company capitalizes costs associated with the acquisition or construction of support equipment and facilities with the drilling and development costs to which they relate. If proved reserves are found by an exploratory well, the associated capitalized costs

82
Table of Contents
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements


become part of well equipment and facilities. However, if proved reserves are not found, the capitalized costs associated with the well are expensed, net of any salvage value.
Production expenses are those costs incurred by the Company to operate and maintain its crude oil and natural gas properties and associated equipment and facilities. Production expenses include but are not limited to labor costs to operate the Company’s properties, repairs and maintenance, certain waste water disposal costs, utility costs, certain workover-related costs, and materials and supplies utilized in the Company’s operations.
Service property and equipment
Service property and equipment consist primarily of automobiles and aircraft; machinery and equipment; gathering and recycling systems; storage tanks; office and computer equipment, software, furniture and fixtures; and buildings and improvements. Major renewals and replacements are capitalized and stated at cost, while maintenance and repairs are expensed as incurred.
Depreciation and amortization of service property and equipment are provided in amounts sufficient to expense the cost of depreciable assets to operations over their estimated useful lives using the straight-line method. The estimated useful lives of service property and equipment are as follows:
72
Table of Contents
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements

Service property and equipment
Useful Lives

In Years
Automobiles and aircraft5-10
Machinery and equipment6-106-20
Gathering and recycling systems15-30
Storage tanks10-30
Office and computer equipment, software, furniture and fixtures3-25
Buildings and improvements4-40
Depreciation, depletion and amortization
Depreciation, depletion and amortization of capitalized drilling and development costs of producing crude oil and natural gas properties, including related support equipment and facilities, are computed using the unit-of-production method on a field basis based on total estimated proved developed reserves. Amortization of producing leaseholds is based on the unit-of-production method using total estimated proved reserves. In arriving at rates under the unit-of-production method, the quantities of recoverable crude oil and natural gas reserves are established based on estimates made by the Company’s internal geologists and engineers and external independent reserve engineers. Upon sale or retirement of properties, the cost and related accumulated depreciation, depletion and amortization are eliminated from the accounts and the resulting gain or loss, if any, is recognized. UnitSales of productionproved properties constituting a part of an amortization base are accounted for as normal retirements with no gain or loss recognized if doing so does not significantly affect the unit-of-production amortization rate. Unit-of-production rates are revised whenever there is an indication of a need, but at least in conjunction with semi-annual reserve reports. Revisions are accounted for prospectively as changes in accounting estimates.
Asset retirement obligations
The Company accounts for its asset retirement obligations by recording the fair value of a liability for an asset retirement obligation in the period in which a legal obligation is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Subsequently, the capitalized asset retirement costs are charged to expense through the depreciation, depletion and amortization of crude oil and natural gas properties and the liability is accreted to the expected future abandonment cost ratably over the related asset’s life.

83
Table of Contents
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements


The Company’s primary asset retirement obligations relate to future plugging and abandonment costs and related disposal of facilities on its crude oil and natural gas properties. The following table summarizes the changes in the Company’s future abandonment liabilities from January 1, 20152019 through December 31, 2017:2021:
In thousands202120202019
Asset retirement obligations at January 1$179,676 $153,673 $141,360 
Accretion expense11,125 9,393 8,443 
Revisions (1)(1,291)10,743 (1,762)
Plus: Additions for new assets (2)32,351 7,048 8,392 
Less: Plugging costs and sold assets(2,037)(1,181)(2,760)
Total asset retirement obligations at December 31$219,824 $179,676 $153,673 
Less: Current portion of asset retirement obligations at December 31 (3)4,123 2,482 1,899 
Non-current portion of asset retirement obligations at December 31$215,701 $177,194 $151,774 
In thousands 2017 2016 2015
Asset retirement obligations at January 1 $96,178
 $102,909
 $76,708
Accretion expense 5,886
 6,086
 4,740
Revisions (1) 7,801
 (12,755) 15,068
Plus: Additions for new assets 6,884
 2,692
 7,404
Less: Plugging costs and sold assets (2,343) (2,754) (1,011)
Total asset retirement obligations at December 31 $114,406
 $96,178
 $102,909
Less: Current portion of asset retirement obligations at December 31 (2) 2,612
 1,742
 1,658
Non-current portion of asset retirement obligations at December 31 $111,794
 $94,436
 $101,251
(1)     Revisions primarily represent changes in the present value of liabilities resulting from changes in estimated costs and economic lives of producing properties.
(1)Revisions primarily represent changes in the present value of liabilities resulting from changes in estimated costs and economic lives of producing properties.
(2)Balance is included in the caption “Accrued liabilities and other” in the consolidated balance sheets.
(2)    Balance for 2021 includes $21.4 million of asset retirement obligations recognized in conjunction with the 2021 property acquisitions discussed in Note 2. Property Acquisitions and Dispositions.
(3)    Balance is included in the caption “Accrued liabilities and other” in the consolidated balance sheets.
As of December 31, 20172021 and 2016,2020, net property and equipment on the consolidated balance sheets included $40.3$72.8 million and $34.0$56.1 million, respectively, of net asset retirement costs.
Asset impairment
73
Table of Contents
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements

Proved crude oil and natural gas properties are reviewed for impairment on a field-by-field basis each quarter. The estimated future cash flows expected in connection with the field are compared to the carrying amount of the field to determine if the carrying amount is recoverable. If the carrying amount of the field exceeds its estimated undiscounted future cash flows, the carrying amount of the field is reduced to its estimated fair value.
Non-producing crude oil and natural gas properties primarily consist of undeveloped leasehold costs and costs associated with the purchase of certain proved undeveloped reserves. Impairment losses for non-producingunproved properties are generally recognized by amortizing the portion of the properties’ costs which management estimates will not be transferred to proved properties over the lives of the leases based on drilling plans, experience of successful drilling, and the average holding period. The Company’s impairment assessments are affected by economic factors such as the results of exploration activities, commodity price outlooks, anticipated drilling programs, remaining lease terms, and potential shifts in business strategy employed by management.
Debt issuance costs
Costs incurred in connection with the execution of the Company’s notenotes payable and revolving credit facility and any amendments thereto are capitalized and amortized over the terms of the arrangements on a straight-line basis, the use of which approximates the effective interest method. Costs incurred upon the issuances of the Company’s various senior notes (collectively, the “Notes”) were capitalized and are being amortized over the terms of the Notes using the effective interest method.
The Company had aggregate capitalized costs of $58.2$60.6 million and $55.9$45.8 million (net of accumulated amortization of $65.9$36.9 million and $56.8$30.5 million) relating to its long-term debt at December 31, 20172021 and 2016,2020, respectively. The increase in 2021 resulted from the capitalization of costs incurred in connection with the amendment of the Company’s credit facility and the issuance of new senior notes as discussed in Note 8. Long-Term Debt.
Unamortized capitalized costs associated with the Company’s Notes and note payable totaled $55.0$50.9 millionand $50.4$42.5 million at December 31, 20172021 and 2016,2020, respectively, and are reflected as a reduction of “Long-term debt, net of current portion” on the consolidated balance sheets. The increase in 2017 resulted from the capitalization of costs incurred in connection with the Company’s issuance of 4.375% Senior Notes due 2028 as discussed in Note 7. Long-Term Debt. 
Unamortized capitalized costs associated with the Company’s revolving credit facility totaled $3.2$9.7 millionand $5.5$3.3 million at December 31, 20172021 and 2016,2020, respectively, and are reflected in “Other noncurrent assets” on the consolidated balance sheets.
For the years ended December 31, 2017, 20162021, 2020 and 2015,2019, the Company recognized amortization expense associated with capitalized debt issuance costs of $9.1$7.2 million, $9.8$7.8 million and $8.9$8.3 million, respectively, which are reflected in “Interest expense” on the consolidated statements of comprehensive income (loss).

84
Table of Contents
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements


Derivative instruments
The Company recognizes its derivative instruments on the balance sheet as either assets or liabilities measured at fair value with such amounts classified as current or long-term based on contractual settlement dates. The accounting for the changes in fair value of a derivative depends on the intended use of the derivative and resulting designation. The Company has not designated its derivative instruments as hedges for accounting purposes and, as a result, marks its derivative instruments to fair value and recognizes the changes in fair value in the consolidated statements of comprehensive income (loss). Gains and losses on crude oil and natural gas derivatives are reflected in under the caption “Gain“Gain (loss) on crude oil and natural gas derivatives, net.derivative instruments, net.” Gains and losses on diesel fuel derivatives are reflected in the caption “Operating costs and expenses—Net gain on sale of assets and other.”See Note 6. Derivative Instruments for additional information.
Fair value of financial instruments
The Company’s financial instruments consist primarily of cash, trade receivables, trade payables, derivative instruments and long-term debt. See Note 6.7. Fair Value Measurements for a discussion of the methods used to determine fair value for the Company’s financial instruments and the quantification of fair value for its derivatives and long-term debt obligations at December 31, 20172021 and 2016.2020.
Income taxes
Income taxes are accounted for using the asset and liability method under which deferred income taxes are recognized for the future tax effects of temporary differences between financial statement carrying amounts and the tax basis of existing assets and liabilities using the enacted statutory tax rates in effect at year-end.period-end. The effect on deferred taxes for a change in tax rates is recognized in income in the period that includes the enactment date. On December 22, 2017, the Tax Cuts and Jobs Act (the "Tax Reform Act") was signed into law, which among other things reduces the federal corporate income tax rate from 35% to 21% effective January 1, 2018. In accordance with U.S. GAAP, the Company remeasured its deferred income tax assets and liabilities as of December 31, 2017 to reflect the reduced tax rate. See Note 8. Income Taxes for further discussion of the Tax Reform Act and its impact on the Company's financial statements as of and for the year ended December 31, 2017.
The Company’s policy is to recognize penalties and interest related to unrecognized tax benefits, if any, in income tax expense. A

The Company establishes a valuation allowance for deferred tax assets is recorded whenif it believes it is more likely than not that the benefit from thesome or all of its deferred tax assetassets will not be realized. The Company recordedSignificant judgment is applied in evaluating the need for and the magnitude of appropriate valuation allowances of $0.4 million, $1.0 million, and $13.5 million for the years ended December 31, 2017, 2016, and 2015, respectively, against deferred tax assets associated with operating loss carryforwards generated by its Canadian subsidiaryassets. See Note 11. Income Taxes for which the Company does not expectadditional information.
74
Table of Contents
Continental Resources, Inc. and Subsidiaries
Notes to realize a benefit.Consolidated Financial Statements

Earnings per share attributable to Continental Resources
Basic net income (loss) per share is computed by dividing net income (loss) attributable to the Company by the weighted-average number of shares outstanding for the period. In periods where the Company has net income, diluted earnings per share reflects the potential dilution of non-vested restricted stock awards, which are calculated using the treasury stock method. The following table presents the calculation of basic and diluted weighted average shares outstanding and net income (loss) per share attributable to the Company for the years ended December 31, 2017, 20162021, 2020 and 2015.
2019.
 Year ended December 31,Year ended December 31,
In thousands, except per share data 2017 2016 2015In thousands, except per share data202120202019
Net income (loss) (numerator) (1) $789,447
 $(399,679) $(353,668)
Net income (loss) attributable to Continental Resources (numerator)Net income (loss) attributable to Continental Resources (numerator)$1,660,968 $(596,869)$775,641 
Weighted average shares (denominator):      Weighted average shares (denominator):
Weighted average shares - basic 371,066
 370,380
 369,540
Weighted average shares - basic360,434 361,538 370,699 
Non-vested restricted stock (2) 2,702
 —
 —
Non-vested restricted stock (1)Non-vested restricted stock (1)4,019 — 1,839 
Weighted average shares - diluted 373,768
 370,380
 369,540
Weighted average shares - diluted364,453 361,538 372,538 
Net income (loss) per share: (1)      
Net income (loss) per share attributable to Continental Resources:Net income (loss) per share attributable to Continental Resources:
Basic $2.13
 $(1.08) $(0.96)Basic$4.61 $(1.65)$2.09 
Diluted $2.11
 $(1.08) $(0.96)Diluted$4.56 $(1.65)$2.08 

85
Table(1)    For the year ended December 31, 2020, the Company had a net loss and therefore the potential dilutive effect of Contents
Continental Resources, Inc. and Subsidiaries
Notesapproximately 934,000 weighted average non-vested restricted shares were not included in the calculation of diluted net loss per share because to Consolidated Financial Statementsdo so would have been anti-dilutive to the computation.


(1)
The Company’s remeasurement of its deferred income tax assets and liabilities in response to the enactment of the Tax Reform Act in December 2017 resulted in a one-time decrease in income tax expense and corresponding increase in net income of approximately $713.7 million ($1.92 per basic share and $1.91 per diluted share) for the year ended December 31, 2017. See Note 8. Income Taxes for further discussion. Additionally, 2017 results include a $59.6 million pre-tax loss accrual recognized in conjunction with a litigation settlement as discussed in Note 10. Commitments and Contingencies, which resulted in an after-tax decrease in 2017 net income of $37.0 million ($0.10 per basic and diluted share).
(2)For the years ended December 31, 2016 and 2015, the Company had a net loss and therefore the potential dilutive effect of approximately 2,303,000 and 1,567,000 weighted average non-vested restricted shares, respectively, were not included in the calculation of diluted net loss per share because to do so would have been anti-dilutive to the computations.
Foreign currency translation
In 2014, the Company initiated exploratory drilling activitiesoperations in Canada through a 100%-ownedwholly-owned Canadian subsidiary. The Company’s operations in Canada are currently immaterial.were immaterial and were sold in the fourth quarter of 2019. See Note 11. Income Taxes and Note 2. Property Acquisitions and Dispositions for further discussion. The Company has designated the Canadian dollar as the functional currency for its Canadian operations. Adjustments resulting from the process of translating foreign functional currency financial statements into U.S. dollars arewere included in “Accumulated other comprehensive income (loss)”income” within shareholders’ equity on the consolidated balance sheets.
Adoptionsheets and “Other comprehensive income (loss), net of new accounting pronouncements
Stock-based compensation – In March 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016-09, Compensation—Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting, which changes how companies account for certain aspects of share-based payment awards, including the accounting for income taxes, forfeitures, and statutory tax withholding requirements, as well as classification in the statement of cash flows. The Company adopted the new standard on January 1, 2017 as required. The impact of adoption is described below.
ASU 2016-09 removes the requirement to delay recognition of an excess tax benefit until it reduces current taxes payable. An excess tax benefit (tax deficiency) arises when stock-based compensation expense recognized in an entity’s tax return exceeds (is less than) the expense recognized in an entity’s financial statements. Under the new standard, effective January 1, 2017 excess tax benefits are recorded when they arise. This change was required to be applied on a modified retrospective basis by recording a cumulative effect adjustment to opening retained earnings upon adoption to account for previously unrecognized excess tax benefits. The Company’s cumulative effect adjustment recorded under the new standard resulted in a $5.2 million increase in retained earnings and corresponding decrease in deferred income tax liabilities at January 1, 2017.
Additionally, under ASU 2016-09 companies no longer record excess tax benefits and deficiencies in additional paid-in capital. Instead, excess tax benefits and deficiencies are recognized as income tax benefit or expense in the income statement, effective January 1, 2017 on a prospective basis. This is expected to result in increased volatility in income tax expense/benefit and corresponding variations in the relationship between income tax expense/benefit and pre-tax income/loss from period to period. The Company recognized $3.9 million ($0.01 per basic and diluted share) of tax deficiencies from stock-based compensation as income tax expense for the year ended December 31, 2017 under the new standard, which is reflected in “Benefit for income taxes”tax” in the consolidated statements of comprehensive income (loss).
Adoption of new accounting pronouncement
On January 1, 2021 the Company adopted ASU 2016-09 also removed2019-12, Income Taxes (Topic 740): Simplifying the requirement that entities present excess tax benefits and deficiencies as offsetting cash flows from financing and operating activitiesAccounting for Income Taxes. This standard eliminated certain exceptions to the guidance in the statement of cash flows. Instead, ASU 2016-09 requires cash flowsTopic 740 related to excessthe approach for intraperiod tax benefitsallocation, the methodology for calculating income taxes in an interim period, and deficiencies be classified as operating activities in the same manner asrecognition of deferred tax liabilities for outside basis differences. The new guidance also clarified certain aspects of the existing guidance, among other cash flows related to income taxes.things. The Company has elected to apply this guidanceadopted the standard on a prospective basis. Accordingly, the cash flow presentation of excess tax benefits and deficiencies in periods prior to January 1, 2017 has not been adjusted to conform to current period presentation.
The Company has elected to continue its historical accounting practice of estimating forfeitures in determining the amount of stock-based compensation expense to recognize. Therefore, the adoption of ASU 2016-09 doesbasis, which did not have ana material impact on the amountits financial position, results of stock-based compensation expense to be recognized by the Company on non-vested restricted stock awards.
Business combinations – In January 2017, the FASB issued ASU 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business, which changes the definition of a business to assist entities with evaluating when a set of transferred assets and activities is deemed to be a business. Determining whether a transferred set constitutes a business is important because the accounting for a business combination differs from that of an asset acquisition. The definition of a business also affects the accounting for dispositions. Under the new standard, when substantially all of the fair value of assets acquired is

operations, or cash flows.
86
75
Table of Contents
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements



Note 2. Property Acquisitions and Dispositions
concentrated2021
Permian Basin Acquisition
On December 21, 2021, the Company acquired oil and gas assets and properties from certain subsidiaries of Pioneer Natural Resources Company pursuant to a purchase and sale agreement in which the Company purchased: (a) 100% of the issued and outstanding limited liability company interests of Jagged Peak Energy LLC, which in turn owns 100% of the issued and outstanding limited liability company interests of Parsley SoDe Water LLC; and (b) certain oil and gas assets and properties in the Permian Basin of Texas (collectively, the “Pioneer Acquisition”). The properties included approximately 92,000 net leasehold acres, approximately 50,000 net royalty acres in the same area normalized to a single asset, or1/8th royalty, production totaling approximately 42,000 net barrels of oil equivalent per day (78% oil) based on two-stream reporting at the time of closing, and extensive water infrastructure.
The purchase price paid to the sellers was approximately $3.06 billion in cash, representing a group of similar assets,$3.25 billion purchase price less customary closing adjustments made pursuant to the assets acquired would not represent a business and business combination accounting would not be required. The new standard may result in more transactions being accounted for as asset acquisitions rather than business combinations. The standard is effective for interim and annual periods beginning after December 15, 2017 and shall be applied prospectively.agreement. The Company early adopted ASU 2017-01 asfunded the purchase price through a combination of January 1, 2017, which had no significant impactcash on the Company’s financial statements ashand, utilization of credit facility borrowing capacity, and for the year ended December 31, 2017.
New accounting pronouncements not yet adopted at December 31, 2017
Revenue recognition and presentation – In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606), which generally requires an entity to identify performance obligations in its contracts, estimate the amount of consideration to be received in the transaction price, allocate the transaction price to each separate performance obligation, and recognize revenue as obligations are satisfied. Additionally, the standard requires expanded disclosures related to revenue recognition.
Subsequent to the issuance of ASU 2014-09, the FASB issued various clarifications and interpretive guidance to assist entities with implementation efforts, including guidance pertaining to the presentation of revenues on a gross basis (revenues presented separately from associated expenses) versus a net basis. Under this guidance, an entity generally shall record revenue on a gross basis if it controls a promised good or service before transferring it to a customer, whereas an entity shall record revenue on a net basis if its role is to arrangesenior notes as further discussed in Note 8. Long-Term Debt.
The Pioneer Acquisition was accounted for another entity to provide the goods or services to a customer. Significant judgment may be required in some circumstances to determine whether gross or net presentation is appropriate.
ASU 2014-09 and related interpretive guidance is effective for interim and annual periods beginning after December 15, 2017 and allows for either full retrospective adoption, meaning the standard is applied to all periods presented in the financial statements, or modified retrospective adoption, meaning the standard is applied only to the most current period presented. The Company adopted the standard on January 1, 2018 using the modified retrospective approach,acquisition method under ASC Topic 805, Business Combinations, which had no cumulative effect impact on retained earnings upon adoption. The standard is not expectedrequires all assets acquired and liabilities assumed to be recorded at fair value at the acquisition date. Provisional fair value measurements have a material effect on the timing of the Company’s revenue recognition or its financial position, results of operations, net income, or cash flows, but will impact the Company’s revenue-related disclosures and internal controls over financial reporting beginning January 1, 2018. Additionally, the standard will impact the Company's future presentation of revenues and expenses under the gross-versus-net presentation guidance. Historically,been made by the Company has generally presented its revenues net of transportation costs. The new guidance will result in future revenues and associated transportation expenses for certain of the Company’s operated properties being reported on a gross basis beginning January 1, 2018. The changes from net to gross presentation will result in an increase in revenues and a corresponding increase in separately reported transportation expenses, with no net effect on the Company’s results of operations, net income, or cash flows. For the year ended December 31, 2017, the Company had approximately $201.5 million of transportation–related charges on operated properties included in “Crude oil and natural gas sales” on the consolidated statements of comprehensive income (loss). This amount is not necessarily indicative of amounts to be expected in future periods. The Company is not able to estimate the impact on the presentation of its future revenues and expenses under the new guidance due to uncertainties with respect to future sales volumes, service costs, locations of producing properties, sales destinations, transportation methods utilized, and changes in the nature, timing, and extent of its arrangements from period to period.
Leases – In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which requires companies to recognize a right of use asset and related liability on the balance sheet for the rights and obligations arising from leases with durations greater than 12 months. The standard is effective for interim and annual reporting periods beginning after December 15, 2018 and requires adoption by application of a modified retrospective transition approach.
The Company continues to evaluate the impact of ASU 2016-02 on its financial statements, accounting policies and internal controls and is in the process of developing systems and processes to identify, classify, and account for leases within the scope of the new guidance and to comply with the related disclosure requirements. Standard setting guidance and interpretations continue to evolve and are being monitored for applicability and impact to the Company’s business and industry. Based on an initial review of the new guidance and the Company’s current commitments, the Company anticipates it may be required to recognize leaseacquired assets and liabilities, relatedand adjustments to drilling rig commitments, certainthose measurements may be made in subsequent periods (up to one year from the acquisition date) as additional information necessary to complete the fair value analysis is obtained.
The following table summarizes the provisional fair values assigned to assets acquired and liabilities assumed as of the acquisition date (presented in millions). Certain studies necessary to complete the purchase price allocation are still under evaluation, including, but not limited to, the valuation of service properties and equipment, rentalsinventory, and leases, certain surface use agreements, and potentially certain firm transportation agreements, as well as other arrangements,lease liabilities. The Company will finalize the effectpurchase price allocation during the twelve-month period following the acquisition date, during which time the value of which cannot be estimated at this time.
Credit losses – In June 2016, the FASB issued ASU 2016-13, Financial Instruments–Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments. This standard changes how entities will measure credit losses for most financial assets and certain other instrumentsliabilities presented below may be revised if necessary.

In millionsAs of December 21, 2021
Receivables$3 
Proved crude oil and natural gas properties2,396 
Unproved crude oil and natural gas properties693 
Service properties, equipment and other6 
Operating lease right-of-use assets2 
Total assets acquired$3,100 
Revenues and royalties payable$14 
Accrued liabilities and other8 
Operating lease liabilities2 
Asset retirement obligations16 
Total liabilities assumed$40 
Net assets acquired$3,060 

The fair values of proved and unproved properties acquired were measured using discounted cash flow valuation techniques based on inputs that are not measured atobservable in the market and, as such, are considered Level 3 fair value through net income. The standard will replace the currently required incurred loss approach with an expected loss modelmeasurements. Significant unobservable inputs included future commodity prices adjusted for instruments measured at amortized cost. The standard

differentials, projections of estimated quantities of recoverable reserves, forecasted production based on decline curve analysis, estimated timing and amount of future operating and development costs, and a weighted average cost of capital.
87
76
Table of Contents
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements



For income tax purposes, the Pioneer Acquisition will be treated as an asset purchase such that the tax basis in the assets and liabilities will generally reflect the allocated fair value at closing. Therefore, the Company does not anticipate a material tax consequence for deferred income taxes related to the Pioneer Acquisition.
is effective for interimThe Pioneer Acquisition contributed $29.4 million of revenues and annual periods beginning after$14.1 million ($0.04 per basic and diluted share)of net income to the Company's consolidated results during the period of ownership from December 15, 2019 and shall be applied using a modified retrospective approach resulting in a cumulative effect adjustment21, 2021 to retained earnings upon adoption.December 31, 2021, excluding transaction expenses. The Company continuesincurred $13.9 million of expenses in connection with the transaction which are reflected in the caption “Acquisition costs” in the consolidated statements of comprehensive income (loss) for the year ended December 31, 2021.
The table below summarizes the Company's pro forma results as if the Pioneer Acquisition and associated increase in debt described in Note 8. Long-Term Debt had been completed on January 1, 2020 and were combined with the Company's historical results. The following pro forma information is unaudited, is provided for informational purposes only, and does not represent actual results that would have occurred if the Pioneer Acquisition was completed on January 1, 2020, nor are they indicative of future results.
Year Ended December 31,
In millions20212020
Pro forma combined total revenues$6,657 $3,174 
Pro forma combined net income (loss) attributable to Continental$2,097 $(481)

Powder River Basin Acquisitions
In March 2021, the Company acquired undeveloped leasehold and producing properties in the Powder River Basin of Wyoming for $206.6 million, consisting of a $21.5 million escrow deposit paid in December 2020 upon execution of a definitive purchase agreement and a $185.1 million payment made at closing in March 2021. The acquisition was accounted for as an asset acquisition under ASC Topic 805 and included approximately 130,000 net acres and producing properties with production totaling approximately 7,200 net barrels of oil equivalent per day at the time of closing. Of the purchase price, $183 million was allocated to evaluateproved properties and $24 million was allocated to unproved properties. The $21.5 million escrow deposit paid in December 2020 is included in the new standardcaption "Other noncurrent assets" on the Company's balance sheet at December 31, 2020, which was subsequently reclassified to "Net property and is unableequipment" on the closing date. The Company recognized approximately $4.9 million of asset retirement obligations and $8.2 million of right-of-use assets and corresponding lease liabilities associated with the acquired properties.
In November 2021, the Company acquired undeveloped leasehold and producing properties in the Powder River Basin for $246.8 million. The acquisition was accounted for as an asset acquisition under ASC Topic 805 and included approximately 72,000 net acres and immaterial amounts of production. Of the purchase price, $27 million was allocated to estimateproved properties and $220 million was allocated to unproved properties. The Company recognized approximately $0.5 million of asset retirement obligations and an immaterial amount of right-of-use assets and corresponding lease liabilities associated with the acquired properties.
2020
In October 2020, the Company acquired undeveloped leasehold and producing properties in the SCOOP play for $162.8 million. The acquisition included approximately 19,500 net acres and immaterial amounts of production.
2019
In November 2019, the Company sold its financial statement impact at this time. Historically,Canadian subsidiary and related operations for cash proceeds of $1.7 million and recognized a $1.0 million pre-tax gain on the sale. The Company designated the Canadian dollar as the functional currency for its Canadian operations and, with the sale of the Canadian subsidiary, $0.5 million of cumulative translation adjustments included in "Accumulated other comprehensive income" on the consolidated balance sheets were released and included in the determination of the gain on sale. The disposed subsidiary and properties represented an immaterial portion of the Company’s credit losses on crude oilassets and natural gas sales receivablesoperating results.
In July 2019, the Company sold certain water gathering, recycling, and joint interest receivables have been immaterial.disposal assets in the STACK play for proceeds of $85.3 million, with no gain or loss recognized. The sale represented an immaterial portion of the Company’s assets and operating results.
77
Table of Contents
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements

Note 2.3. Supplemental Cash Flow Information
The following table discloses supplemental cash flow information about cash paid for interest and income tax payments and refunds. Also disclosed is information about investing activities that affects recognized assets and liabilities but does not result in cash receipts or payments.
 Year ended December 31,
In thousands202120202019
Supplemental cash flow information:
Cash paid for interest$214,727 $256,633 $267,421 
Cash paid for income taxes3 4 229 
Cash received for income tax refunds (1)58 9,600 107 
Non-cash investing activities:
Asset retirement obligation additions and revisions, net31,060 17,791 6,630 
  Year ended December 31,
In thousands 2017 2016 2015
Supplemental cash flow information:      
Cash paid for interest $281,058
 $316,116
 $301,743
Cash paid for income taxes 2
 2
 30
Cash received for income tax refunds 257
 174
 61,403
Non-cash investing activities:      
Asset retirement obligation additions and revisions, net 14,685
 (10,063) 22,472

(1) Amount received in 2020 primarily represents alternative minimum tax refunds.
As of December 31, 20172021 and 2016,2020, the Company had $302.8$242.9 million and $223.6$128.8 million, respectively, of accrued capital expenditures included in “Net property and equipment” andwith an offsetting amount in “Accounts payable trade” in the consolidated balance sheets.

As of December 31, 2021 and 2020, the Company had $1.7 million and $0.1 million, respectively, of accrued contributions from noncontrolling interests included in "Receivables–Joint interest and other" with an offsetting amount in "Equity–Noncontrolling interests" in the condensed consolidated balance sheets.
As of December 31, 2021 and 2020, the Company had $2.5 million and $1.0 million, respectively, of accrued distributions to noncontrolling interests included in "Revenues and royalties payable" with an offsetting amount in "Equity–Noncontrolling interests" in the condensed consolidated balance sheets.
As of December 31, 2021, the Company recognized approximately $21.4 million of asset retirement obligations and $10.0 million of right-of-use assets and corresponding lease liabilities associated with the 2021 property acquisitions discussed in Note 2. Property Acquisitions and Dispositions.

Note 3.4. Net Property and Equipment
Net property and equipment includes the following at December 31, 20172021 and 2016. 2020. See Note 2. Property Acquisitions and Dispositions for discussion of certain acquisitions executed in 2021 that contributed to the increase in net property and equipment in 2021.
December 31,
In thousands20212020
Proved crude oil and natural gas properties$31,613,656 $27,726,954 
Unproved crude oil and natural gas properties1,358,673 368,256 
Service properties, equipment and other484,989 414,066 
Total property and equipment33,457,318 28,509,276 
Accumulated depreciation, depletion and amortization(16,481,853)(14,771,984)
Net property and equipment$16,975,465 $13,737,292 

78
  December 31,
In thousands 2017 2016
Proved crude oil and natural gas properties $21,362,199
 $19,802,395
Unproved crude oil and natural gas properties 365,413
 429,562
Service properties, equipment and other 290,111
 301,788
Total property and equipment 22,017,723
 20,533,745
Accumulated depreciation, depletion and amortization (9,083,934) (7,652,518)
Net property and equipment $12,933,789
 $12,881,227
Table of Contents
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements

Note 4.5. Accrued Liabilities and Other
Accrued liabilities and other includes the following at December 31, 20172021 and 2016:2020:
December 31,
In thousands20212020
Prepaid advances from joint interest owners$18,964 $25,209 
Accrued compensation82,844 47,985 
Accrued production taxes, ad valorem taxes and other non-income taxes90,597 40,818 
Accrued interest75,983 50,009 
Current portion of asset retirement obligations4,123 2,482 
Other13,229 510 
Accrued liabilities and other$285,740 $167,013 
  December 31,
In thousands 2017 2016
Prepaid advances from joint interest owners $34,511
 $57,861
Accrued compensation 65,308
 38,046
Accrued production taxes, ad valorem taxes and other non-income taxes 40,611
 22,053
Accrued interest 55,282
 52,657
Accrued litigation settlement (see Note 10) 59,600
 —
Current portion of asset retirement obligations 2,612
 1,742
Other 2,150
 4,411
Accrued liabilities and other $260,074
 $176,770

88
Table of Contents
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements


Note 5.6. Derivative Instruments
Crude oil and natural gas derivatives
TheFrom time to time the Company may utilize crude oil and natural gas swap and collarenters into derivative contracts to economically hedge against the variability in cash flows associated with future sales of crude oil and natural gas production. While the use of these derivative instruments limits the downside risk of adverse price movements, their use also limits future revenues from upward price movements.
The Company recognizes all derivative instruments on the balance sheet as either assets or liabilities measured at fair value. The Company has not designated its crude oil and natural gas derivative instruments as hedges for accounting purposes and, as a result, marks such derivative instruments to fair value and recognizes the changes in fair value in the consolidated statements of comprehensive income (loss) under the caption “Gain (loss) on crude oil and natural gas derivatives, net.”
The estimated fair value of derivative contracts is based upon various factors, including commodity exchange prices, over-the-counter quotations, and, in the case of collars and written call options, volatility, the risk-free interest rate, and the time to expiration. The calculation of the fair value of collars and written call options requires the use of an option-pricing model. See Note 6. Fair Value Measurements.
With respect to a crude oil or natural gas fixed price swap contract, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is less than the swap price, and the Company is required to make a payment to the counterparty if the settlement price for any settlement period is greater than the swap price. For a crude oil or natural gas collar contract, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is below the floor price and the Company is required to make a payment to the counterparty if the settlement price for any settlement period is above the ceiling price. Neither party is required to make a payment to the other party if the settlement price for any settlement period is between the floor price and the ceiling price.
At December 31, 2017, the Company had outstanding natural gas derivative contracts as set forth in the table below. The volumes reflected below represent an aggregation of multiple derivative contracts having similar remaining durations expected to be realized ratably over the indicated 2018 period. At December 31, 2017 the Company had no outstanding crude oil derivative contracts.
Period and Type of Contract MMBtus Swaps Weighted Average Price 
January 2018 - March 2018     
Swaps - Henry Hub 6,300,000
 $3.28
 
Crude oil and natural gas derivative gains and losses
Cash receipts and payments in the following table reflect the gain or loss on derivative contracts which matured during the period, calculated as the difference between the contract price and the market settlement price of matured contracts. Non-cash gains and losses below represent the change in fair value of derivative instruments which continue to be held at period end, if any, and the reversal of previously recognized non-cash gains or losses on derivative contracts that matured during the period.

89
Table of Contents
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements


  Year ended December 31,
In thousands 2017 2016 2015
Cash received (paid) on derivatives:      
Natural gas fixed price swaps $40,095
 $88,823
 $39,670
Natural gas collars (10,539) —
 29,883
Cash received on derivatives, net 29,556
 88,823
 69,553
Non-cash gain (loss) on derivatives:      
Crude oil written call options —
 38
 4,715
Natural gas fixed price swaps 18,960
 (120,784) 41,828
Natural gas collars 43,131
 (39,936) (25,011)
Non-cash gain (loss) on derivatives, net 62,091
 (160,682) 21,532
Gain (loss) on crude oil and natural gas derivatives, net $91,647
 $(71,859) $91,085

Diesel fuel derivatives
The Company previously entered into diesel fuel swap derivative contracts, all of which matured on or before December 31, 2017, to economically hedge against the variability in cash flows associated with future purchases of diesel fuel for use in drilling activities. With respect to the diesel fuel swap contracts, the counterparty was required to make a payment to the Company if the settlement price for any settlement period was greater than the swap price, and the Company was required to make a payment to the counterparty if the settlement price for any settlement period was less than the swap price. The diesel fuel swap contracts were settled based upon reported NYMEX settlement prices for New York Harbor ultra-low sulfur diesel fuel.
The Company recognized its diesel fuel derivative instruments on the balance sheet as either assets or liabilities measured at fair value. The estimated fair value wasis based upon various factors, including commodity exchange prices, over-the-counter quotations, and, in the case of collars, volatility, the risk-free interest rate, and the time to expiration. The Company did not designate its diesel fuel derivative instruments as hedges for accounting purposes and, as a result, markedcalculation of the derivative instruments to fair value and recognizedof collars requires the changes in fair valueuse of an option-pricing model. See Note 7. Fair Value Measurements.

At December 31, 2021 the Company had outstanding derivative contracts as set forth in the consolidated statementstables below.
Natural gas derivativesWeighted Average Hedge Price ($/MMBtu)
Period and Type of ContractAverage Volumes HedgedBasis SwapsSwapsSold PutFloorCeiling
January 2022 - December 2023
Basis Swaps - NGPL TXOK75,000 MMBtus/day$(0.17)
January 2022 - March 2022
Collars - Henry Hub90,000 MMBtus/day$3.00 $6.33 
Three-way collars - Henry Hub280,000 MMBtus/day$2.33 $3.02 $4.46 
Swaps - Henry Hub45,000 MMBtus/day$3.86 
April 2022 - September 2022
Swaps - Henry Hub190,000 MMBtus/day$4.02 
October 2022 - December 2022
Collars - Henry Hub150,000 MMBtus/day$3.54 $5.34 
Three-way collars - Henry Hub50,000 MMBtus/day$3.00 $4.07 $5.00 
Swaps - Henry Hub50,000 MMBtus/day$4.20 
January 2023 - December 2023
Collars - Henry Hub62,500 MMBtus/day$3.41 $4.87 
Three-way collars - Henry Hub12,500 MMBtus/day$3.00 $4.32 $5.00 
Swaps - Henry Hub175,000 MMBtus/day$3.38 
January 2024 - December 2024
Swaps - Henry Hub125,000 MMBtus/day$3.12 
Collars - Henry Hub25,000 MMBtus/day$3.10 $4.18 
January 2025 - December 2025
Swaps - Henry Hub10,000 MMBtus/day$3.08 
79
Table of comprehensive income (loss) under the caption “Operating costsContents
Continental Resources, Inc. and expenses—Net gain on sale of assetsSubsidiaries
Notes to Consolidated Financial Statements



Crude oil derivatives
Period and Type of ContractAverage Volumes HedgedWeighted Average Hedge Price ($/Bbl)
January 2022 - March 2022
NYMEX Roll Swaps32,500 Bbls/day$0.71 
April 2022 - June 2022
NYMEX Roll Swaps15,000 Bbls/day$0.85 
July 2022 - December 2022
NYMEX Roll Swaps7,500 Bbls/day$0.90 
Derivative gains and other.”losses
Cash receipts and payments in the following table reflect the gains or losses on diesel fuel derivativesderivative contracts which matured during the applicable period, calculated as the difference between the contract price and the market settlement price of matured contracts. The Company's derivative contracts are settled based upon reported settlement prices on commodity exchanges, with crude oil derivative settlements based on NYMEX West Texas Intermediate ("WTI") pricing and natural gas derivative settlements based primarily on NYMEX Henry Hub pricing. Non-cash gains and losses below represent the change in fair value of diesel fuel derivativesderivative instruments which continued to be held at period end if any, and the reversal of previously recognized non-cash gains or losses on derivative contracts that matured during the period.
  Year ended December 31,
In thousands 2017 2016
Cash received on diesel fuel derivatives $2,845
 $699
Non-cash gain (loss) on diesel fuel derivatives (4,060) 4,060
Gain (loss) on diesel fuel derivatives, net $(1,215) $4,759
 Year ended December 31,
In thousands202120202019
Cash received (paid) on derivatives:
Crude oil fixed price swaps$(44,463)$(31,179)$— 
Crude oil collars(9,365)— — 
Crude oil NYMEX roll swaps(163)— — 
Natural gas fixed price swaps(84,141)1,071 58,836 
Natural gas collars(11,546)1,958 5,859 
Cash received (paid) on derivatives, net(149,678)(28,150)64,695 
Non-cash gain (loss) on derivatives:
Crude oil collars227 (227)— 
Crude oil NYMEX roll swaps957 — — 
Natural gas fixed price swaps25,565 2,043 (10,130)
Natural gas basis swaps(177)— — 
Natural gas collars(7,690)11,676 (5,482)
Natural gas three-way collars1,932 — — 
Non-cash gain (loss) on derivatives, net20,814 13,492 (15,612)
Gain (loss) on derivative instruments, net$(128,864)$(14,658)$49,083 


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

9080
Table of Contents
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements



The following table presents the gross amounts of recognized crude oil, natural gas, and diesel fuel derivative assets and liabilities, as applicable, the amounts offset under netting arrangements with counterparties, and the resulting net amounts presented in the consolidated balance sheets for the periods presented,at December 31, 2021, all at fair value.
December 31,
In thousands20212020
Commodity derivative assets:
Gross amounts of recognized assets$42,903 $15,900 
Gross amounts offset on balance sheet(7,381)(597)
Net amounts of assets on balance sheet35,522 15,303 
Commodity derivative liabilities:
Gross amounts of recognized liabilities(8,598)(2,408)
Gross amounts offset on balance sheet7,381 597 
Net amounts of liabilities on balance sheet$(1,217)$(1,811)
  December 31,
In thousands 2017 2016
Commodity derivative assets:    
Gross amounts of recognized assets $2,603
 $4,061
Gross amounts offset on balance sheet —
 —
Net amounts of assets on balance sheet 2,603
 4,061
Commodity derivative liabilities:    
Gross amounts of recognized liabilities —
 (59,489)
Gross amounts offset on balance sheet —
 —
Net amounts of liabilities on balance sheet $—
 $(59,489)
The following table reconciles the net amounts disclosed above to the individual financial statement line items in the consolidated balance sheets.
December 31,
In thousands20212020
Derivative assets$22,334 $15,303 
Derivative assets, noncurrent13,188 — 
Net amounts of assets on balance sheet35,522 15,303 
Derivative liabilities(899)(227)
Derivative liabilities, noncurrent(318)(1,584)
Net amounts of liabilities on balance sheet(1,217)(1,811)
Total derivative assets, net$34,305 $13,492 
  December 31,
In thousands 2017 2016
Derivative assets $2,603
 $4,061
Noncurrent derivative assets —
 —
Net amounts of assets on balance sheet 2,603
 4,061
Derivative liabilities —
 (59,489)
Noncurrent derivative liabilities —
 —
Net amounts of liabilities on balance sheet —
 (59,489)
Total derivative assets (liabilities), net $2,603
 $(55,428)
Note 6.7. Fair Value Measurements
The Company follows a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows:
•Level 1: Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date.
•Level 2: Observable market-based inputs or unobservable inputs corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date.
•Level 3: Unobservable inputs not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value.
A financial instrument’s categorization within the hierarchy is based upon the lowest level of input that is significant to the fair value measurement. Level 1 inputs are given the highest priority in the fair value hierarchy while Level 3 inputs are given the lowest priority. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the hierarchy. As Level 1 inputs generally provide the most reliable evidence of fair value, the Company uses Level 1 inputs when available. The Company’s policy is to recognize transfers between the hierarchy levels as of the beginning of the reporting period in which the event or change in circumstances caused the transfer.

91
81
Table of Contents
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements



Assets and liabilities measuredLiabilities Measured at fair valueFair Value on a recurring basisRecurring Basis
The Company’s derivative instruments are reported at fair value on a recurring basis. In determining the fair values of swap contracts, a discounted cash flow method is used due to the unavailability of relevant comparable market data for the Company’s exact contracts. The discounted cash flow method estimates future cash flows based on quoted market prices for forward commodity prices and a risk-adjusted discount rate. The fair values of swap contracts are calculated mainly using significant observable inputs (Level 2). Calculation of the fair values of collars requires the use of an industry-standard option pricing model that considers various inputs including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. These assumptions are observable in the marketplace or can be corroborated by active markets or broker quotes and are therefore designated as Level 2 within the valuation hierarchy. The Company’s calculation of fair value for each of its derivative positions is compared to the counterparty valuation for reasonableness.
The following tables summarize the valuation of financialderivative instruments by pricing levels that were accounted for at fair value on a recurring basis as of December 31, 20172021 and 2016.2020.
 Fair value measurements at December 31, 2017 using:  Fair value measurements at December 31, 2021 using: 
In thousands Level 1 Level 2 Level 3 TotalIn thousandsLevel 1Level 2Level 3Total
Derivative assets:  
Swaps $—
 $2,603
 $—
 $2,603
Derivative assets (liabilities):Derivative assets (liabilities):
Fixed price swapsFixed price swaps$— $27,608 $— $27,608 
Basis swapsBasis swaps— (177)— (177)
CollarsCollars— 3,986 — 3,986 
Three-way collarsThree-way collars— 1,931 — 1,931 
NYMEX roll swapsNYMEX roll swaps— 957 — 957 
Total $—
 $2,603
 $—
 $2,603
Total$— $34,305 $— $34,305 
 
Fair value measurements at December 31, 2020 using: 
In thousandsLevel 1Level 2Level 3Total
Derivative assets (liabilities):
Swaps— $2,043 — 2,043 
Collars— 11,449 — 11,449 
Total$— $13,492 $— $13,492 
  Fair value measurements at December 31, 2016 using:  
In thousands Level 1 Level 2 Level 3 Total
Derivative liabilities:  
Swaps $—
 $(12,297) $—
 $(12,297)
Collars —
 (43,131) —
 (43,131)
Total $—
 $(55,428) $—
 $(55,428)

Assets measuredMeasured at fair valueFair Value on a nonrecurring basisNonrecurring Basis
Certain assets are reported at fair value on a nonrecurring basis in the consolidated financial statements. The following methods and assumptions were used to estimate the fair values for those assets.
Asset impairments – Proved crude oil and natural gas properties are reviewed for impairment on a field-by-field basis each quarter. The estimated future cash flows expected in connection with the field are compared to the carrying amount of the field to determine if the carrying amount is recoverable. If the carrying amount of the field exceeds its estimated undiscounted future cash flows, the carrying amount of the field is reduced to its estimated fair value. Risk-adjusted probable and possible reserves may be taken into consideration when determining estimated future net cash flows and fair value when such reserves exist and are economically recoverable. Due to the unavailability of relevant comparable market data, a discounted cash flow method is used to determine the fair value of proved properties. TheSignificant unobservable inputs (Level 3) utilized in the determination of discounted cash flow method estimates future net cash flows based on the Company’s estimates ofinclude future crude oil and natural gas production, commodity prices based on commodity futures price strips adjusted for differentials, forecasted production based on decline curve analysis, estimated future operating and development costs, property ownership interests, and a risk-adjusted10% discount rate. The fair value of proved crude oil and natural gas properties is calculated using significant unobservable inputs (Level 3). The following table sets forth quantitative information about the significant unobservable inputs used by the Company atAt December 31, 2017 to calculate2021, the fair value of proved crude oilCompany's commodity price assumptions were based on forward NYMEX strip prices through year-end 2026 and natural gas properties using a discounted cash flow method.
Unobservable InputAssumption
Future productionFuture production estimates for each property
Forward commodity pricesForward NYMEX strip prices through 2022 (adjusted for differentials), escalating 3% per year thereafter
Operating costsEstimated costs for the current year, escalating 3% per year thereafter
Productive life of fieldRanging from 1 to 38 years
Discount rate10%

92
Table of Contents
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements


were then escalated at 3% per year thereafter. Operating cost assumptions were based on current costs escalated at 3% per year beginning in 2023.
Unobservable inputs to the Company's fair value assessmentassessments are reviewed quarterly and are revised as warranted based on a number of factors, including reservoir performance, new drilling, crude oil and natural gas prices, changes in costs, technological advances, new geological or geophysical data, or other economic factors. Fair value measurements of proved properties are reviewed and approved by certain members of the Company’s management.
82
Table of Contents
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements

For the year ended December 31, 2017,2021, estimated future net cash flows were determined to be in excess of cost basis, and therefore no impairment was recorded for the Company's proved crude oil and natural gas properties in 2021.
For the years ended December 31, 2020 and 2019, the Company determined the carrying amounts of certain proved properties were not recoverable from future cash flows, and therefore, were impaired. Impairments of proved properties amounted to $82.3Such impairments totaled $207.1 million and $3.7 million for 2017,2020 and 2019, respectively, which reflectfor 2020 reflected fair value adjustments on legacy properties in the Arkoma Woodford field ($81.2 million)Red River Units totaling $168.1 million and various non-core areasproperties in the North and South regions ($1.1 million).totaling $14.5 million. The impaired properties were written down to their estimated fair value at the time of impairment of approximately $72$145.7 million. Impairments for 2020 also include a $24.5 million impairment recognized in the first quarter of 2020 to reduce the Company's crude oil inventory to estimated net realizable value at the time of impairment. Proved property impairments recognized in 2019 reflected write-offs of various non-core properties in the North and South regions.
Certain unproved crude oil and natural gas properties were impaired during the years ended December 31, 2017, 2016,2021, 2020, and 2015,2019, reflecting recurring amortization of undeveloped leasehold costs on properties the Company expects will not be transferred to proved properties over the lives of the leases based on drilling plans, experience of successful drilling, and the average holding period.
The following table sets forth the non-cash impairments of both proved and unproved properties for the indicated periods. Proved and unproved property impairments are recorded under the caption “Property impairments” in the consolidated statements of comprehensive income (loss).
 Year ended December 31, Year ended December 31,
In thousands 2017 2016 2015In thousands202120202019
Proved property impairments $82,340
 $2,895
 $138,878
Proved property and inventory impairmentsProved property and inventory impairments$— $207,119 $3,745 
Unproved property impairments 155,030
 234,397
 263,253
Unproved property impairments38,370 70,822 82,457 
Total $237,370
 $237,292
 $402,131
Total$38,370 $277,941 $86,202 
Financial instruments not recordedInstruments Not Recorded at fair valueFair Value
The following table sets forth the estimated fair values of financial instruments that are not recorded at fair value in the consolidated financial statements.
  December 31, 2017 December 31, 2016
In thousands Carrying Amount Fair Value Carrying Amount Fair Value
Debt:        
Revolving credit facility (1) $188,000
 $188,000
 $905,000
 $905,000
Term loan (1) —
 —
 498,865
 500,000
Note payable 9,974
 9,900
 12,176
 10,200
5% Senior Notes due 2022 1,997,576
 2,040,000
 1,997,188
 2,020,400
4.5% Senior Notes due 2023 1,486,690
 1,526,800
 1,484,524
 1,474,800
3.8% Senior Notes due 2024 992,036
 988,800
 990,964
 929,400
4.375% Senior Notes due 2028 (1) 988,061
 987,200
 —
 —
4.9% Senior Notes due 2044 691,354
 679,900
 691,199
 607,600
Total debt $6,353,691
 $6,420,600
 $6,579,916
 $6,447,400
(1) In December 2017, the Company issued $1.0 billion of 4.375% Senior Notes due 2028 and used the proceeds therefrom to repay in full and terminate its term loan and to repay a portion See Note 8. Long-Term Debt for discussion of the borrowingschanges in the Company's outstanding under its revolving credit facility. See Note 7. Long-Term Debt for further discussion.debt during the year ended December 31, 2021.
 December 31, 2021December 31, 2020
In thousandsCarrying AmountEstimated Fair ValueCarrying AmountEstimated Fair Value
Debt:
Credit facility$500,000 $500,000 $160,000 $160,000 
Notes payable22,356 22,000 24,590 24,700 
5% Senior Notes due 2022— — 630,470 632,900 
4.5% Senior Notes due 2023648,078 670,200 646,943 669,900 
3.8% Senior Notes due 2024908,061 950,000 906,922 939,500 
2.268% Senior Notes due 2026792,621 795,200 — — 
4.375% Senior Notes due 2028991,880 1,082,100 990,746 1,024,400 
5.75% Senior Notes due 20311,482,319 1,769,600 1,480,879 1,651,900 
2.875% Senior Notes due 2032791,521 780,500 — — 
4.9% Senior Notes due 2044692,056 781,500 691,868 689,600 
Total debt$6,828,892 $7,351,100 $5,532,418 $5,792,900 
The fair valuesvalue of revolving credit facility borrowings and the term loan approximate carrying value based on borrowing rates available to the Company for bank loans with similar terms and maturities and are classified as Level 2 in the fair value hierarchy.

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

9383
Table of Contents
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements



The fair values of the 5% Senior Notes due 2022 (“2022 Notes”), the 4.5% Senior Notes due 2023 (“2023 Notes”), the 3.8% Senior Notes due 2024 (“2024 Notes”), the 4.375% Senior Notes due 2028 (“2028 Notes”), and the 4.9% Senior Notes due 2044 (“2044 Notes”)Company's senior notes are based on quoted market prices and, accordingly, are classified as Level 1 in the fair value hierarchy.
The carrying values of all classes of cash and cash equivalents, trade receivables, and trade payables are considered to be representative of their respective fair values due to the short term maturities of those instruments.
Note 7.8. Long-Term Debt
Long-term debt, net of unamortized discounts, premiums, and debt issuance costs totaling $44.3$54.2 million and $37.3$43.7 million at December 31, 20172021 and 2016,2020, respectively, consists of the following.
December 31,
In thousands20212020
Credit facility$500,000 $160,000 
Notes payable22,356 24,590 
5% Senior Notes due 2022— 630,470 
4.5% Senior Notes due 2023648,078 646,943 
3.8% Senior Notes due 2024908,061 906,922 
2.268% Senior Notes due 2026792,621 — 
4.375% Senior Notes due 2028991,880 990,746 
5.75% Senior Notes due 20311,482,319 1,480,879 
2.875% Senior Notes due 2032791,521 — 
4.9% Senior Notes due 2044692,056 691,868 
Total debt6,828,892 5,532,418 
Less: Current portion of long-term debt2,326 2,245 
Long-term debt, net of current portion$6,826,566 $5,530,173 
  December 31,
In thousands 2017 2016
Revolving credit facility $188,000
 $905,000
Term loan —
 498,865
Note payable 9,974
 12,176
5% Senior Notes due 2022 1,997,576
 1,997,188
4.5% Senior Notes due 2023 1,486,690
 1,484,524
3.8% Senior Notes due 2024 992,036
 990,964
4.375% Senior Notes due 2028 988,061
 —
4.9% Senior Notes due 2044 691,354
 691,199
Total debt 6,353,691
 6,579,916
Less: Current portion of long-term debt 2,286
 2,219
Long-term debt, net of current portion $6,351,405
 $6,577,697
Credit Facility
RevolvingOn October 29, 2021, the Company replaced its credit facility which resulted in an increase in aggregate commitments from $1.5 billion to $1.7 billion and an extension of the maturity date from April 2023 to October 2026. On November 22, 2021, the Company incrementally increased the amount of aggregate credit facility commitments from $1.7 billion to $2.0 billion. The new credit facility provides for benchmark replacement mechanics to address the transition from LIBOR, while all other terms, conditions, and covenants remain substantially unchanged from the prior credit facility. The Company's credit facility is unsecured and has no borrowing base requirement subject to redetermination.
The Company has an unsecured revolvinghad $500 million of outstanding borrowings on its credit facility maturing on May 16, 2019, with aggregate commitments totaling $2.75 billion at December 31, 2017.2021, which were incurred to fund a portion of the Company's December 2021 acquisition of properties in the Permian Basin of Texas as discussed in Note 2. Property Acquisitions and Dispositions.Credit facility borrowings bear interest at market-based interest rates plus a margin based on the terms of the borrowing and the credit ratings assigned to the Company’sCompany's senior, unsecured, long-term indebtedness. The weighted-average interest rate on outstanding credit facility borrowings at December 31, 20172021 was 3.19%1.6%.
The Company had approximately $2.56$1.50 billion of borrowing availability on its revolving credit facility at December 31, 20172021 after considering outstanding borrowings and letters of credit. The Company incurs commitment fees based on currently assigned credit ratings of 0.30%0.20% per annum on the daily average amount of unused borrowing availability under its revolving credit facility.availability.
The revolving credit facility contains certain restrictive covenants including a requirement that the Company maintain a consolidated net debt to total capitalization ratio of no greater than 0.65 to 1.00. This ratio represents the ratio of net debt (calculated as total face value of debt plus outstanding letters of credit less cash and cash equivalents) divided by the sum of net debt plus total shareholders’ equity plus, to the extent resulting in a reduction of total shareholders’ equity, the amount of any non-cash impairment charges incurred, net of any tax effect, after June 30, 2014. The Company was in compliance with the revolving credit facility covenants at December 31, 2017.
Senior notes
In December 2017, the Company issued $1.0 billion of 4.375% Senior Notes due 2028 and received total net proceeds of $990 million after deducting the initial purchasers' fees. The 2028 Notes were sold at par in a private placement transaction exempt from the registration requirements of the Securities Act to qualified institutional buyers in reliance on Rule 144A of the Securities Act. The Company used the net proceeds from the offering to repay in full and terminate its $500 million term loan and to repay a portion of the borrowings outstanding under its revolving credit facility.
In connection with the issuance of the 2028 Notes, the Company entered into a registration rights agreement with the initial purchasers dated December 8, 2017 to allow holders of the unregistered 2028 Notes to exchange them for registered notes that have substantially identical terms. The Company agreed to use reasonable efforts to cause the exchange to be completed within 400 days after the issuance of the 2028 Notes. The Company is required to pay additional interest if it fails to comply with its obligations to register the 2028 Notes within the specified time period, whereby the interest rate would be increased by

2021.
94
84
Table of Contents
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements



Senior Notes
1.0% per annum duringIn November 2021 the periodCompany issued $800 million of 2.268% Senior Notes due 2026 ("2026 Notes") and $800 million of 2.875% Senior Notes due 2032 ("2032 Notes") and received combined total net proceeds from the offerings of $1.59 billionafter deducting the initial purchasers' fees and original issuance discount. The 2026 Notes were sold at par and the 2032 Notes were sold at 99.922% of par in which aprivate placement transactions exempt from the registration default is in effect.requirements of the Securities Act to eligible purchasers. The Company expectsused the net proceeds from the offerings to comply withfinance a portion of its December 2021 acquisition of properties in the terms of the registration rights agreementPermian Basin as discussed in Note 2. Property Acquisitions and complete the exchange of the 2028 Notes within the 400 day period.Dispositions.
The following table summarizes the face values, maturity dates, semi-annual interest payment dates, and optional redemption periods related to the Company’s outstanding senior note obligations at December 31, 2017.2021.
2023 Notes2024 Notes2026 Notes2028 Notes2031 Notes2032 Notes2044 Notes
Face value (in thousands)$649,625$911,000$800,000$1,000,000$1,500,000$800,000$700,000
Maturity dateApril 15, 2023June 1, 2024November 15, 2026January 15, 2028January 15, 2031April 1, 2032June 1, 2044
Interest payment datesApril 15, Oct 15June 1, Dec 1May 15, Nov 15Jan 15, July 15Jan 15,
Jul 15		April 1, Oct 1June 1, Dec 1
Make-whole redemption period (1)Jan 15, 2023Mar 1, 2024Nov 15, 2023Oct 15, 2027Jul 15, 2030January 1. 2032Dec 1, 2043
   2022 Notes (1)  2023 Notes  2024 Notes 2028 Notes 2044 Notes
Face value (in thousands) $2,000,000 $1,500,000 $1,000,000 $1,000,000 $700,000
Maturity date  Sep 15, 2022  April 15, 2023  June 1, 2024 January 15, 2028 June 1, 2044
Interest payment dates  March 15,  Sep 15  April 15, Oct 15  June 1, Dec 1 Jan 15, July 15 June 1, Dec 1
Make-whole redemption period (2)  —  Jan 15, 2023  Mar 1, 2024 Oct 15, 2027 Dec 1, 2043
(1)At any time prior to the indicated dates, the Company has the option to redeem all or a portion of its senior notes of the applicable series at the “make-whole” redemption amounts specified in the respective senior note indentures plus any accrued and unpaid interest to the date of redemption. On or after the indicated dates, the Company may redeem all or a portion of its senior notes at a redemption amount equal to 100% of the principal amount of the senior notes being redeemed plus any accrued and unpaid interest to the date of redemption.
(1)The Company has the option to redeem all or a portion of its 2022 Notes at the decreasing redemption prices specified in the indenture related to the 2022 Notes plus any accrued and unpaid interest to the date of redemption.
(2)At any time prior to the indicated dates, the Company has the option to redeem all or a portion of its senior notes of the applicable series at the “make-whole” redemption prices or amounts specified in the respective senior note indentures plus any accrued and unpaid interest to the date of redemption. On or after these dates, the Company may redeem all or a portion of its senior notes at a redemption price equal to 100% of the principal amount of the senior notes being redeemed plus any accrued and unpaid interest to the date of redemption.
The Company’s senior notes are not subject to any mandatory redemption or sinking fund requirements.
The indentures governing the Company’s senior notes contain covenants that, among other things, limit the Company’s ability to create liens securing certain indebtedness, enter into certain sale-leaseback transactions, or consolidate, merge or transfer certain assets. The senior noteThese covenants are subject to a number of important exceptions and qualifications. The Company was in compliance with these covenants at December 31, 2017. Three2021.
The senior notes are obligations of Continental Resources, Inc. Additionally, as of December 31, 2021 three of the Company’s wholly-owned consolidated subsidiaries, Banner Pipeline Company, L.L.C., CLR Asset Holdings, LLC, and The Mineral Resources Company, which have nowhose assets, equity, and results of operations are not material, assets or operations, fully and unconditionally guarantee the senior notes on a joint and several basis. The Company plans to designate Jagged Peak Energy LLC and Parsley SoDe Water LLC, its recently acquired consolidated subsidiaries discussed in Note 2. Property Acquisitions and Dispositions, as restricted subsidiaries under the Company’s senior note indentures. As a result, such entities will fully and unconditionally guarantee the senior notes on a joint and several basis along with the Company’s other subsidiary guarantors. The Company’s other subsidiaries the value ofexisting at December 31, 2021, whose assets, equity, and results of operations attributable to the Company are minor,not material, do not guarantee the senior notes.
2016 RedemptionsRetirement of Senior Notes
2021
In November 2016,January 2021, the Company redeemed its then outstanding 7.375% Senior Notes due 2020 (“2020 Notes”) and 7.125% Senior Notes due 2021 (“2021 Notes”). The redemption price for the 2020 Notes was equal to 102.458% of the $200$400.0 million principal amount plus accrued and unpaid interest to the redemption date in accordance with the terms of the 2020its outstanding 2022 Notes and related indenture. The redemption price forsubsequently redeemed the 2021 Notes was equal to 103.563% of the $400remaining $230.8 million principal amount plus accrued and unpaid interest to the redemption dateof its 2022 Notes in accordance with the terms of the 2021 Notes and related indenture. The aggregate of the principal amounts, redemption premiums, and accrued interest paid upon redemption of the 2020 Notes and 2021 Notes was $623.9 million. The Company funded the redemptions using borrowings under its revolving credit facility.
April 2021. The Company recognized a pre-tax losslosses on extinguishment of debt totaling $26.1$0.3 million related to the redemptions, which included the call premiums andpro-rata write-off of deferred financing costs and unaccretedunamortized debt discountspremium associated with the notes and isredeemed notes. The losses are reflected underin the caption “Loss“Gain (loss) on extinguishment of debt” in the consolidated statements of comprehensive income (loss) for.
2020
In March and April 2020, the year ended December 31, 2016.Company repurchased a portion of its 2023 Notes and 2024 Notes in open market transactions at a substantial discount to the face value of the notes, including $50.4 million face value of its 2023 Notes at an aggregate cost of $29.3 million and $89.0 million face value of its 2024 Notes at an aggregate cost of $46.9 million, in each case, including accrued and unpaid interest to the repurchase dates. The Company recognized pre-tax gains on extinguishment of debt totaling
Term loan
85
Table of Contents
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements

$64.6 million related to the repurchases, which included the pro-rata write-off of deferred financing costs and unamortized debt discount associated with the notes.
In November 2015,2020, the Company borrowed $500repurchased $469.2 million under a three-year term loan agreement which was scheduled to mature on November 4, 2018. In December 2017, the Company repaid in fullof its 2022 Notes and terminated the term loan$800.0 million of its 2023 Notes using a portion of the proceeds from its November 2020 issuance of 2028$1.5 billion of 5.75% Senior Notes as described above.due 2031. For the 2022 Notes, the purchase price was equal to 100.250% of the principal amount repurchased plus accrued and unpaid interest to the repurchase date. The aggregate of the principal amount, premium, and accrued interest paid upon repurchase of the 2022 Notes was $475.0 million. For the 2023 Notes, the purchase price was equal to 103.000% of the principal amount repurchased plus accrued and unpaid interest to the repurchase date. The aggregate of the principal amount, premium, and accrued interest paid upon repurchase of the 2023 Notes was $828.0 million. The Company recognizedrecorded pre-tax losses on extinguishment of debt related to these repurchases totaling $28.9 million, which included the premium and pro-rata write-off of deferred financing costs and unamortized debt premium associated with the notes.
2019
In September 2019, the Company redeemed $500 million of its previously outstanding $1.6 billion of 2022 Notes. The redemption price was equal to 100.833% of the principal amount called for redemption plus accrued and unpaid interest to the redemption date. The aggregate of the principal amount, redemption premium, and accrued interest paid upon redemption was $516.5 million. The Company recorded a pre-tax loss on extinguishment of $0.6 milliondebt related to the termination, representingredemption of $4.6 million, which included the redemption premium and pro-rata write-off of deferred financing costs and unamortized debt premium associated with the term loan.notes.
NoteNotes payable
In February 2012, 20 Broadway Associates LLC, a 100% owned subsidiary ofJune 2020, the Company borrowed $22an aggregate of $26.0 million under atwo 10-year amortizing term loanloans secured by the Company’s corporate office building and its interest in parking facilities in Oklahoma City, Oklahoma. The loan bearsloans mature in May 2030 and bear interest at a fixed rate of 3.14%3.50% per annum.annum through June 9, 2025, at which time the interest rate will be reset and fixed through the maturity date. Principal and interest are payable monthly through the loan’s maturity date of February 26, 2022. Accordingly, approximatelyand, accordingly, $2.3 million is reflected as a current liability under the caption “Current portion of long-term debt” in the consolidated balance sheets as of December 31, 2017.2021 associated with the loans. A portion of the proceeds from the new loans was used to fully repay the Company's previous note payable that was set to mature in February 2022, which had a balance at pay-off of $4.4 million.

Note 9. Revenues
Below is a discussion of the nature, timing, and presentation of revenues arising from the Company's major revenue-generating arrangements.
Operated crude oil revenues – The Company pays third parties to transport the majority of its operated crude oil production from lease locations to downstream market centers, at which time the Company's customers take title and custody of the product in exchange for prices based on the particular market where the product was delivered. Operated crude oil revenues are recognized during the month in which control transfers to the customer and it is probable the Company will collect the consideration it is entitled to receive. Crude oil sales proceeds from operated properties are generally received by the Company within one month after the month in which a sale has occurred. Operated crude oil revenues are presented separately from transportation expenses, as the Company controls the operated production prior to its transfer to customers. Transportation expenses associated with the Company's operated crude oil production totaled $185.1 million, $159.0 million, and $192.0 million for the years ended December 31, 2021, 2020, and 2019, respectively.
Operated natural gas revenues – The Company sells the majority of its operated natural gas production to midstream customers at its lease locations based on market prices in the field where the sales occur. Under these arrangements, the midstream customers obtain control of the unprocessed gas stream at the lease location and the Company's revenues from each sale are determined using contractually agreed pricing formulas which contain multiple components, including the volume and Btu content of the natural gas sold, the midstream customer's proceeds from the sale of residue gas and natural gas liquids ("NGLs") at secondary downstream markets, and contractual pricing adjustments reflecting the midstream customer's estimated recoupment of its investment over time. Such revenues are recognized net of pricing adjustments applied by the midstream customer during the month in which control transfers to the customer at the delivery point and it is probable the Company will collect the consideration it is entitled to receive. Natural gas sales proceeds from operated properties are generally received by the Company within one month after the month in which a sale has occurred.
Under certain arrangements, in periods of significantly depressed prices for natural gas and NGLs the contractual pricing adjustments applied by the midstream customer in a particular month may exceed the consideration to be received by the Company under the arrangement, resulting in a net payment owed by the Company to the midstream customer. In these
95
86
Table of Contents
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements



Note 8. Income Taxes
On December 22, 2017,situations, the Tax Reform Act was signed into law. The new legislation contains several key changes to U.S. corporate tax laws that are expected to impactnet amounts paid or payable by the Company includingare reflected as a reduction of natural gas sales in the corporatecaption "Crude oil and natural gas sales" in the consolidated statements of comprehensive income tax rate from 35%(loss). Such payments, which are referred to 21%, effective January 1, 2018. The new legislation also includesherein as negative gas revenues, were immaterial for 2021 and 2019 and totaled $25.6 million for operated properties for 2020.
Under certain arrangements, the Company has the right to take a varietyvolume of other changes such asprocessed residue gas and/or NGLs in-kind at the repealtailgate of the alternative minimum tax,midstream customer's processing plant in lieu of a monetary settlement for the introductionsale of new limitations on the tax deductibility of net operating losses, interest expenses,Company's operated natural gas production. When the Company elects to take volumes in kind, it pays third parties to transport the processed products it took in-kind to downstream delivery points, where it then sells to customers at prices applicable to those downstream markets. In such situations, operated revenues are recognized during the month in which control transfers to the customer at the delivery point and executive compensationit is probable the Company will collect the consideration it is entitled to receive. Operated sales proceeds are generally received by the Company within one month after the month in which a sale has occurred. In these scenarios, the Company's revenues include the pricing adjustments applied by the midstream processing entity according to the applicable contractual pricing formula, but exclude the transportation expenses the acceleration of expensing of certain qualified property,Company incurs to transport the processed products to downstream customers. Transportation expenses associated with these arrangements totaled $39.9 million, $37.7 million, and the introduction of new laws governing taxation of foreign earnings of U.S. entities, among others.
U.S. GAAP (Accounting Standards Codification Topic 740, Income Taxes) requires entities to recognize the effect of tax law changes in the reporting period that includes the enactment date. The income tax accounting effect of a change in tax law includes, for example, remeasuring deferred tax assets and liabilities at a new tax rate and evaluating whether a valuation allowance is needed for deferred tax assets. In response to the enactment of the Tax Reform Act, the Securities and Exchange Commission issued guidance in Staff Accounting Bulletin No. 118 ("SAB 118") to assist entities in applying ASC 740 to the new tax law. SAB 118 allows entities to record estimated provisional amounts during a measurement period in circumstances where an entity does not have the necessary information in reasonable detail to complete its accounting for a tax law change under ASC 740 prior to the issuance of its financial statements.
In accordance with ASC 740, the Company remeasured its deferred tax assets and liabilities as of December 31, 2017 to reflect the reduction in the corporate tax rate from 35% to 21%. This remeasurement resulted in a $713.7$33.7 million decrease in net deferred income tax liabilities and corresponding decrease in income tax expense as of and for the year ended December 31, 2017, which is reflected in the tables below. The Company also reassessed the realizability of its deferred tax assets, taking into consideration how the new tax law impacts future taxable income, and has recorded such assets at realizable value at December 31, 2017. The Company's accounting for the effects of the tax rate change on its deferred tax balances as well as other relevant aspects of the Tax Reform Act is complete and no provisional amounts have been recorded as allowed under SAB 118.
The items comprising the Company's benefit for income taxes are as follows for the periods presented:
  Year ended December 31,
In thousands 2017 2016 2015
Current income tax (provision) benefit:      
United States federal (1) $7,781
 $22,941
 $—
Various states —
 (2) (24)
Total current income tax (provision) benefit 7,781
 22,939
 (24)
Deferred income tax (provision) benefit:      
United States federal - taxation on operations (81,054) 182,422
 140,578
United States federal - effect of US tax reform 713,655
 —
 —
Various states (7,002) 27,414
 40,863
Total deferred income tax benefit 625,599
 209,836
 181,441
Benefit for income taxes $633,380
 $232,775
 $181,417
(1) The current federal income tax benefits for the years ended December 31, 20172021, 2020, and 2016 represent alternative minimum tax refunds.2019, respectively.

Non-operated crude oil and natural gas revenues – The Company's proportionate share of production from non-operated properties is generally marketed at the discretion of the operators. For non-operated properties, the Company receives a net payment from the operator representing its proportionate share of sales proceeds which is net of costs incurred by the operator, if any. Such non-operated revenues are recognized at the net amount of proceeds to be received by the Company during the month in which production occurs and it is probable the Company will collect the consideration it is entitled to receive. Proceeds are generally received by the Company within two to three months after the month in which production occurs.
In periods of significantly depressed prices for natural gas and NGLs the costs incurred by the outside operator in a particular month may exceed the consideration to be received by the Company, resulting in a net payment owed by the Company to the outside operator. In these situations, the net amounts paid or payable by the Company are reflected as a reduction of natural gas sales in the caption "Crude oil and natural gas sales" in the consolidated statements of comprehensive income (loss). Such negative gas revenues associated with non-operated properties were immaterial for 2021 and 2019 and totaled $17.3 million for 2020.
Revenues from derivative instruments – See Note 6. Derivative Instruments for discussion of the Company's accounting for its derivative instruments.
Revenues from service operations – Revenues from the Company's crude oil and natural gas service operations consist primarily of revenues associated with water gathering, recycling, and disposal activities and the treatment and sale of crude oil reclaimed from waste products. Revenues associated with such activities, which are derived using market-based rates or rates commensurate with industry guidelines, are recognized during the month in which services are performed, the Company has an unconditional right to receive payment, and collectability is probable. Payment is generally received by the Company within one month after the month in which services are provided.
96
87
Table of Contents
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements



Disaggregation of crude oil and natural gas revenues
The benefitfollowing table presents the disaggregation of the Company's crude oil and natural gas revenues for the periods presented.
Year ended December 31,
202120202019
In thousandsNorth RegionSouth RegionTotalNorth RegionSouth RegionTotalNorth RegionSouth RegionTotal
Crude oil revenues:
Operated properties$2,392,465 $838,129 $3,230,594 $1,264,149 $537,961 $1,802,110 $2,365,574 $786,652 $3,152,226 
Non-operated properties656,727 61,973 718,700 362,952 34,914 397,866 727,068 50,700 777,768 
Total crude oil revenues3,049,192 900,102 3,949,294 1,627,101 572,875 2,199,976 3,092,642 837,352 3,929,994 
Natural gas revenues:
Operated properties (1)460,376 1,186,937 1,647,313 28,086 301,486 329,572 109,668 411,464 521,132 
Non-operated properties (2)115,420 81,714 197,134 720 25,166 25,886 25,188 38,075 63,263 
Total natural gas revenues575,796 1,268,651 1,844,447 28,806 326,652 355,458 134,856 449,539 584,395 
Crude oil and natural gas sales$3,624,988 $2,168,753 $5,793,741 $1,655,907 $899,527 $2,555,434 $3,227,498 $1,286,891 $4,514,389 
Timing of revenue recognition
Goods transferred at a point in time$3,624,988 $2,168,753 $5,793,741 $1,655,907 $899,527 $2,555,434 $3,227,498 $1,286,891 $4,514,389 
Goods transferred over time— — — — — — — — — 
$3,624,988 $2,168,753 $5,793,741 $1,655,907 $899,527 $2,555,434 $3,227,498 $1,286,891 $4,514,389 
(1) Operated natural gas revenues for the North region include negative gas revenues totaling $25.6 million for the year ended December 31, 2020.
(2) Non-operated natural gas revenues for the North region include negative gas revenues totaling $17.3 million for the year ended December 31, 2020.

Performance obligations
The Company satisfies the performance obligations under its crude oil and natural gas sales contracts upon delivery of its production and related transfer of control to customers. Judgment may be required in determining the point in time when control transfers to customers. Upon delivery of production, the Company has a right to receive consideration from its customers in amounts determined by the sales contracts.
The Company's outstanding crude oil sales contracts at December 31, 2021 are primarily short-term in nature with contract terms of less than one year. For such contracts, the Company has utilized the practical expedient in Accounting Standards Codification ("ASC") 606-10-50-14 exempting the Company from disclosure of the transaction price allocated to remaining performance obligations, if any, if the performance obligation is part of a contract that has an original expected duration of one year or less.
The majority of the Company's operated natural gas production is sold at lease locations to midstream customers under multi-year term contracts. For such contracts having a term greater than one year, the Company has utilized the practical expedient in ASC 606-10-50-14A which indicates an entity is not required to disclose the transaction price allocated to remaining performance obligations, if any, if variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under the Company’s sales contracts, whether for crude oil or natural gas, each unit of production delivered to a customer represents a separate performance obligation; therefore, future volumes to be delivered are wholly unsatisfied at period-end and disclosure of the transaction price allocated to remaining performance obligations is not applicable.
88
Table of Contents
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements

Contract balances
Under the Company’s crude oil and natural gas sales contracts or activities that give rise to service revenues, the Company recognizes revenue after its performance obligations have been satisfied, at which point the Company has an unconditional right to receive payment. Accordingly, the Company’s commodity sales contracts and service activities generally do not give rise to contract assets or contract liabilities under ASC Topic 606. Instead, the Company's unconditional rights to receive consideration are presented as a receivable within "Receivables–Crude oil and natural gas sales" or "Receivables–Joint interest and other," as applicable, in its consolidated balance sheets.
Revenues from previously satisfied performance obligations
To record revenues for commodity sales, at the end of each month the Company estimates the amount of production delivered and sold to customers and the prices to be received for such sales. Differences between estimated revenues and actual amounts received for all prior months are recorded in the month payment is received from the customer and are reflected in the financial statements within the caption "Crude oil and natural gas sales". Revenues recognized during the years ended December 31, 2021, 2020, and 2019 related to performance obligations satisfied in prior reporting periods were not material.
Note 10. Allowance for Credit Losses
The Company's principal exposure to credit risk is through the sale of its crude oil and natural gas production and its receivables associated with billings to joint interest owners. Accordingly, the Company classifies its receivables into two portfolio segments as depicted on the consolidated balance sheets as "Receivables—Crude oil and natural gas sales” and "Receivables—Joint interest and other.”

Historically, the Company's credit losses on receivables have been immaterial. The Company’s aggregate allowance for credit losses totaled $2.8 million and $2.5 million at December 31, 2021 and 2020, respectively, which is reported as "Allowance for credit losses" in the consolidated balance sheets. Aggregate credit loss expenses totaled $0.8 million, $1.8 million, and $1.6 million for the years ended December 31, 2021, 2020, and 2019, respectively, which are included in “General and administrative expenses” in the consolidated statements of comprehensive income (loss).
Receivables—Crude oil and natural gas sales
The Company's crude oil and natural gas production from operated properties is generally sold to energy marketing companies, crude oil refining companies, and natural gas gathering and processing companies. The Company monitors its credit loss exposure to these counterparties primarily by reviewing credit ratings, financial statements, and payment history. Credit terms are extended based on an evaluation of each counterparty’s credit worthiness. The Company has not generally required its counterparties to provide collateral to secure its crude oil and natural gas sales receivables.
Receivables associated with crude oil and natural gas sales are short term in nature. Receivables from the sale of crude oil and natural gas from operated properties are generally collected within one month after the month in which a sale has occurred, while receivables associated with non-operated properties are generally collected within two to three months after the month in which production occurs.
The Company’s allowance for credit losses on crude oil and natural gas sales was negligible at both December 31, 2021 and December 31, 2020. The allowance was determined by considering a number of factors, primarily including the Company’s history of credit losses with adjustment as needed to reflect current conditions, the length of time accounts are past due, whether amounts relate to operated properties or non-operated properties, and the counterparty's ability to pay. There were no significant write-offs, recoveries, or changes in the provision for credit losses on this portfolio segment during the years ended December 31, 2021, 2020, and 2019.
Receivables—Joint interest and other
Joint interest and other receivables primarily arise from billing the individuals and entities who own a partial interest in the wells we operate. Joint interest receivables are due within 30 days and are considered delinquent after 60 days. In order to minimize our exposure to credit risk with these counterparties we generally request prepayment of drilling costs where it is allowed by contract or state law. Such prepayments are used to offset future capital costs when billed, thereby reducing the Company's credit risk. We may have the right to place a lien on a co-owner's interest in the well, to net production proceeds against amounts owed in order to secure payment or, if necessary, foreclose on the co-owner's interest.
89
Table of Contents
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements

The Company’s allowance for credit losses on joint interest receivables totaled $2.8 million and $2.5 million at December 31, 2021 and 2020, respectively. The allowance was determined by considering a number of factors, primarily including the Company’s history of credit losses with adjustment as needed to reflect current conditions, the length of time accounts are past due, the ability to recoup amounts owed through netting of production proceeds, the balance of co-owner prepayments if any, and the co-owner's ability to pay. There were no significant write-offs, recoveries, or changes in the provision for credit losses on this portfolio segment during the years ended December 31, 2021, 2020, and 2019.
Note 11. Income Taxes
The items comprising the Company's provision (benefit) for income taxes are as follows for the periods presented:
 Year ended December 31,
In thousands202120202019
Current income tax provision (benefit):
United States federal$— $(2,248)$— 
Various states— 29 — 
Total current income tax provision (benefit)— (2,219)— 
Deferred income tax provision (benefit):
United States federal467,051 (148,828)191,328 
Various states52,679 (18,143)21,361 
Total deferred income tax provision (benefit)519,730 (166,971)212,689 
Provision (benefit) for income taxes$519,730 $(169,190)$212,689 
Effective tax rate23.8 %21.8 %21.5 %
The Company's effective tax rate differs from the amount computed by applying the United States federal statutory federaltax rate due to the effect of state income taxes, equity compensation, changes in valuation allowances, and other tax items as reflected in the table below.
 Year ended December 31,
In thousands, except tax rates202120202019
Income (loss) before income taxes$2,186,138 $(774,751)$987,162 
U.S. federal statutory tax rate21.0 %21.0 %21.0 %
Expected income tax provision (benefit) based on U.S. federal statutory tax rate459,089 (162,698)207,304 
Items impacting the effective tax rate:
State and local income taxes, net of federal benefit77,979 (24,808)31,967 
Tax (benefit) deficiency from stock-based compensation5,869 4,927 (7,971)
Sale of Canadian subsidiary and assets— — (16,860)
Other, net(8,733)(1,085)(1,751)
Change in valuation allowance(14,474)14,474 — 
Provision (benefit) for income taxes$519,730 $(169,190)$212,689 
Effective tax rate23.8 %21.8 %21.5 %
90
Table of Contents
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements

In assessing the realizability of deferred tax assets the Company must consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The Company applies judgment to determine the weight of both positive and negative evidence in order to conclude whether a valuation allowance is necessary for its deferred tax assets. In determining whether a valuation allowance is required, the Company considers, among other factors, the Company's financial position, results of operations, projected future taxable income, reversal of existing deferred tax liabilities against deferred tax assets, and tax planning strategies. During 2020, a $14.5 million valuation allowance was established for the deferred tax asset associated with a portion of the Company's Oklahoma state net operating loss carryforwards. In 2021, the Company reassessed the realizability of the deferred tax asset related to Oklahoma state net operating loss carryforwards, and based on current year activity, determined it was more likely than not that such assets would be realized. Therefore, it was determined that the previously recorded valuation allowance in 2020 should be released in 2021.
The Company will continue to evaluate both the positive and negative evidence on a quarterly basis in determining the need for a valuation allowance with respect to its deferred tax assets. Changes in positive and negative evidence, including differences between estimated and actual results, could result in changes in the valuation of our deferred tax assets that could have a material impact on our consolidated financial statements. Changes in existing tax laws could also affect actual tax results and the realization of deferred tax assets over time.
In 2019, the Company sold its Canadian subsidiary and associated properties. Prior to the sale, the Company had recognized cumulative valuation allowances totaling $19.6 million against deferred tax assets associated with operating loss carryforwards generated by the Canadian subsidiary for which the Company did not expect to realize a benefit. In conjunction with the sale, the deferred tax assets, deferred tax liabilities, and cumulative valuation allowance related to the Canadian subsidiary were removed, and an income tax ratebenefit of $16.9 million was recorded related to income (loss) before income taxes. The sources and tax effectsthe resulting capital loss on the sale of the difference are as follows:stock.
  Year ended December 31,
  2017 2016 2015
In thousands, except rates Amount Rate Amount Rate Amount Rate
             
Expected income tax (provision) benefit based on US statutory tax rate of 35% $(54,623) 35.0% $221,359
 35.0% $187,280
 35.0%
State income taxes, net of federal benefit (4,682) 3.0% 18,829
 3.0% 16,219
 3.0%
Effect of US tax reform legislation 713,655
 (457.3%) —
 —% —
 —%
Tax deficiency from stock-based compensation (1) (3,932) 2.5% —
 —% —
 —%
Canadian valuation allowance (2) (404) 0.3% (1,044) (0.2%) (13,503) (2.5%)
Effect of differing statutory tax rate in Canada (194) 0.1% (481) (0.1%) (5,239) (1.0%)
Non-deductible compensation (13,813) 8.9% (3,471) (0.5%) (1,488) (0.3%)
Other, net (2,627) 1.7% (2,417) (0.4%) (1,852) (0.3%)
Benefit for income taxes $633,380
 (405.8%) $232,775
 36.8% $181,417
 33.9%
(1)
The Company recognized $3.9 million of tax deficiencies from stock-based compensation as income tax expense for the year ended December 31, 2017 in accordance with ASU 2016-09 as discussed in Note 1. Organization and Summary of Significant Accounting Policies–Adoption of new accounting pronouncements.
(2)Represents valuation allowances recognized against all deferred tax assets associated with operating loss carryforwards generated by the Company's Canadian operations during the respective periods for which the Company does not expect to realize a benefit.
The components of the Company’s deferred tax assets and deferred tax liabilities as of December 31, 20172021 and 20162020 are reflected in the table below.
 December 31,
In thousands20212020
Deferred tax assets
United States net operating loss carryforwards$365,602 $579,781 
Equity compensation12,751 12,900 
Other29,421 10,691 
Total deferred tax assets407,774 603,372 
Valuation allowance— (14,474)
Total deferred tax assets, net of valuation allowance407,774 588,898 
Deferred tax liabilities
Property and equipment(2,536,938)(2,204,378)
Other(10,720)(4,674)
Total deferred tax liabilities(2,547,658)(2,209,052)
Deferred income tax liabilities, net$(2,139,884)$(1,620,154)
  December 31,
In thousands 2017 2016
Deferred tax assets    
United States net operating loss carryforwards $604,423
 $478,975
Canadian net operating loss carryforwards 19,341
 18,936
Alternative minimum tax carryforwards 7,781
 16,663
Equity compensation 12,962
 32,924
Non-cash losses on derivatives —
 21,064
Other 21,885
 11,466
Total deferred tax assets 666,392
 580,028
Canadian valuation allowance (19,341) (18,936)
Total deferred tax assets, net of valuation allowance 647,051
 561,092
Deferred tax liabilities    
Property and equipment (1,903,451) (2,448,450)
Other (3,158) (2,947)
Total deferred tax liabilities (1,906,609) (2,451,397)
Deferred income tax liabilities, net $(1,259,558) $(1,890,305)
As of December 31, 2017,2021, the Company had federal and state net operating loss carryforwards of $2.39$1.17 billion and $3.40$3.63 billion, respectively. TheApproximately $283 million of the Company's federal net operating loss carryforward will begin expiringcarryforwards were generated in 2033.tax years prior to 2018 and expire in 2037, with the remaining $887 million having an indefinite life. The Company’s net operating loss carryforward in Oklahoma totaled $2.17$3.07 billion at December 31, 2017,2021, of which will begin to expire in 2027.$1.96 billion expires between 2030 and 2037, and the remaining $1.11 billion has an indefinite life. The Company’s net operating loss carryforward in North Dakota totaled $1.07 billion$457 million at December 31, 2017, which will begin to expire in 2033.The Company2021 and has alternative minimum tax credit carryforwards of $7.8 million that are refundable by 2021.an indefinite life. Any available

97
Table of Contents
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements


statutory depletion carryforwards will be recognized when realized. The Company files income tax returns in the U.S. federal U.S.and state and Canadian jurisdictions. With few exceptions, the Company is no longer subject to U.S. federal or state and local income tax examinations by tax authorities for years prior to 2014.2018.
Note 12. Leases
The Company recorded valuation allowances of $0.4 million, $1.0Company’s lease liabilities recognized on the balance sheet as a lessee totaled $15.5 million and $13.5 million against Canadian deferred tax assets for the years ended December 31, 2017, 2016 and 2015, respectively. The Company's cumulative valuation allowance was $19.3$8.4 million as of December 31, 2017. Our Canadian subsidiary has generated operating loss carryforwards for2021 and 2020, respectively, at discounted present value, which we do not believe we will realize a benefit. The amountis comprised of deferred tax assets considered realizable, however, could change if our subsidiary generates taxable income.
Note 9. Lease Commitments
The Company’s operating lease obligations primarily represent leases for land and road use, office buildings and equipment, communication towers, and field equipment. Lease payments associated with operating leases for the years ended December 31, 2017, 2016 and 2015 were $1.9 million, $4.4 million and $9.6 million, respectively, a portion of which was capitalized and/or billed to other interest owners. At December 31, 2017, the minimum future rental commitments under operating leases having lease terms in excess of one year areasset classes reflected in the table below. New accounting rules will go into effect for reporting periods beginning after December 15, 2018 that will impactAll leases recognized on the Company's accountingbalance sheet are classified as operating leases. The amounts disclosed
91
Table of Contents
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements

herein primarily represent costs associated with properties operated by the Company that are presented on a gross basis and do not represent the Company's net proportionate share of such amounts. A portion of these costs have been or will be billed to other working interest owners. Once paid, the Company's share of these costs are included in property and equipment, production expenses, or general and administrative expenses, as applicable.
The Company accounts for lease and non-lease components in its contracts as a single lease component for all asset classes. Additionally, the Company does not apply the recognition requirements of ASC Topic 842 to leases with durations of twelve months or less and uses hindsight in determining the lease term for all leases. See Note 1. Organization and SummaryThe Company's leasing activities as a lessor are negligible.
December 31,
In thousands20212020
Drilling rig commitments$— $2,025 
Surface use agreements12,354 4,928 
Field equipment2,095 928 
Other1,025 546 
Total$15,474 $8,427 
Minimum future commitments by year for the Company's operating leases as of Significant Accounting Policies–New accounting pronouncements not yet adopted at December 31, 2017–Leases2021 are presented in the table below. Such commitments are reflected at undiscounted values and are reconciled to the discounted present value recognized on the balance sheet.
In thousandsAmount
2022$2,369 
20232,263 
20241,831 
20251,295 
20261,258 
Thereafter13,084 
Total operating lease liabilities, at undiscounted value$22,100 
Less: Imputed interest(6,626)
Total operating lease liabilities, at discounted present value$15,474 
Less: Current portion of operating lease liabilities(1,674)
Operating lease liabilities, net of current portion$13,800 
Additional information for further discussion.the Company's operating leases is presented below. Lease costs primarily represent costs incurred for drilling rigs, most of which are short term contracts that are not recognized as right-of-use assets and lease liabilities on the balance sheet. Variable lease costs primarily represent differences between minimum payment obligations and actual operating day-rate charges incurred by the Company for its long term drilling rig contracts. Short-term lease costs primarily represent operating day-rate charges for drilling rig contracts with durations of one year or less and month-to-month field equipment rentals.A portion of such lease costs are borne by other interest owners.
92
Table of Contents
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements

In thousands Total amount
2018 $1,656
2019 958
2020 817
2021 645
2022 620
Thereafter 7,208
Total obligations $11,904
Year ended December 31,
In thousands, except weighted average data202120202019
Lease costs:
Operating lease costs$6,653 $6,444 $11,130 
Variable lease costs3,271 4,956 11,930 
Short-term lease costs77,551 107,984 176,586 
Total lease costs$87,475 $119,384 $199,646 
Other information:
Right-of-use assets obtained in exchange for new operating lease liabilities (1)$10,481 $7,377 $1,208 
Operating cash flows from operating leases included in lease liabilities1,731 890 804 
Weighted average remaining lease term as of December 31 (in years)14.413.211.5
Weighted average discount rate as of December 315.0 %4.8 %4.9 %
(1)     Balance for 2021 primarily represents $10.0 million of right-of-use assets and corresponding lease liabilities recognized in connection with the Company's property acquisitions discussed in Note 2. Property Acquisitions and Dispositions.
Note 10.13. Commitments and Contingencies
Included below is a discussion of various future commitments of the Company as of December 31, 2017. The commitments under these arrangements are not recorded in the accompanying consolidated balance sheets.
Drilling commitments – As of December 31, 2017, the Company has drilling rig contracts with various terms extending toFebruary 2020 to ensure rig availability in its key operating areas. Future commitments as of December 31, 2017 total approximately $104 million, of which $73 million is expected to be incurred in 2018, $30 million in 2019 and $1 million in 2020. A portion of these future costs will be borne by other interest owners.
Transportation, gathering, and processing commitments – The Company has entered into transportation, gathering, and processing commitments to guarantee capacity on crude oil and natural gas pipelines and natural gas processing facilities. The commitments, which have varying terms extending as far as 2028,2031, require the Company to pay per-unit transportation, gathering, or processing charges regardless of the amount of capacity used. Future commitments remaining as of December 31, 20172021 under the arrangements amount to approximately $1.43$1.31 billion, of which $197$275 million is expected to be incurred in 2018, $2162022, $270 million in 2019, $1862023, $251 million in 2020, $1682024, $164 million in 2021, $1662025, $139 million in 2022,2026, and $497$214 million thereafter. A portion of these future costs will be borne by other interest owners. The Company is not committed under the above contracts to deliver fixed and determinable quantities of crude oil or natural gas in the future.
Litigation – In November 2010, a putative class action was filed in the District Court of Blaine County, Oklahoma by Billy J. Strack These commitments do not qualify as leases under ASC Topic 842 and Daniela A. Renner as trustees of certain named trusts andare not recognized on behalf of other similarly situated parties against the Company. The Petition, as amended, alleged the Company improperly deducted post-production costs from royalties paid to plaintiffs and other royalty interest owners from crude oil and natural gas wells located in Oklahoma. The plaintiffs alleged a number of claims, including breach of contract, fraud, breach of fiduciary duty, unjust enrichment, and other claims and sought recovery of compensatory damages, interest, punitive damages and attorney fees on behalf of the proposed class. The Company denied all allegations and denied that the case was properly brought as a class action. On June 11, 2015, the trial court certified a “hybrid” class requested by plaintiffs over the objections of the Company. The Company appealed the trial court’s class certification order. On February 8, 2017, the Oklahoma Court of Civil Appeals reversed the trial court’s ruling on certification

98
Table of Contents
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements


and remanded the case for further proceedings. The plaintiffs filed a Petition for Rehearing which was denied by the Oklahoma Court of Civil Appeals. Plaintiffs then filed a Petition for Writ of Certiorari on May 23, 2017 to the Oklahoma Supreme Court, which was denied on October 2, 2017. On October 10, 2017, Plaintiffs filed with the trial court a “Second Amended and Renewed Motion for Class Action Certification and Request that the Court to Set a Briefing Schedule Related to Class Certification.” During the litigation the Company was not able to estimate a reasonably possible loss or range of loss or what impact, if any, the ultimate resolution of the action would have on its financial condition, results of operations or cash flows due to the preliminary status of the matter, the complexity and number of legal and factual issues presented by the matter and uncertainties with respect to, among other things, the nature of the claims and defenses, the existence and the potential size of the class, the scope and types of the properties and agreements involved, the production years involved, and the ultimate potential outcome of the matter. The Company further disclosed that it was reasonably possible one or more events could occur in the near term that could impact the Company’s ability to estimate the potential effect of this matter if any, on its financial condition, results of operations or cash flows. During the litigation the Company also disclosed plaintiffs alleged underpayments in excess of $200 million as damages, which may increase with the passage of time, a majority of which would be comprised of interest. After certification of the case as a class action was reversed the parties continued settlement negotiations. Due to the uncertainty of and burdens of litigation, on February 16, 2018, the Company reached a settlement in connection with this matter. Under the settlement, if approved by the court, the Company will make payments and incur costs associated with the settlement of approximately $59.6 million.balance sheet.
Lease commitments – The Company has accruedvarious lease commitments primarily associated with surface use agreements and field equipment. See Note 12. Leases for additional information.
Pledge commitment– The Company entered into a loss$25.0 million ten-year irrevocable pledge agreement with Oklahoma State University in December 2021. The pledge agreement provides for such amount,ten equal payments of $2.5 million to be paid annually on or before December 31 of each year until the pledge is paid in full on December 31, 2030. In connection with the pledge, the Company recognized a $25.0 million charge to earnings which is includedreflected in “Accrued liabilities and other” on the consolidated balance sheets and “Litigation settlement”caption “Other income (expense)—Other” in the consolidated statements of comprehensive income (loss) as of and for the year ended December 31, 2017. The District Court2021.
Pending property acquisition – See Note 20. Subsequent Events for discussion of Garfield County, Oklahoma must approvea definitive acquisition agreement executed by the settlement.Company subsequent to December 31, 2021.
Litigation –The Company is involved in various other legal proceedings including, but not limited to, commercial disputes, claims from royalty and surface owners, property damage claims, personal injury claims, regulatory compliance matters, disputes with tax authorities and other matters. While the outcome of these legal matters cannot be predicted with certainty, the Company does not expect them to have a material effect on its financial condition, results of operations or cash flows. As of December 31, 20172021 and 2016,2020, the Company had recordedrecognized a liability in the consolidated balance sheets under the captionwithin “Other noncurrent liabilities” of $7.6$7.9 million and $6.5$7.7 million, respectively, for various matters, none of which are believed to be individually significant.
Environmental risk – Due to the nature of the crude oil and natural gas business, the Company is exposed to possible environmental risks. The Company is not aware of any material environmental issues or claims.
93
Table of Contents
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements

Note 11.14. Related Party Transactions
The Company historically sold a portion of its natural gas production to Hiland Partners, LP and its subsidiaries (“Hiland”). Hiland was controlled by the Company's principal shareholder through February 13, 2015, at which time it was sold to an unaffiliated third party. As a result of the sale, the prior related party relationship between the Company and Hiland terminated as of February 13, 2015. For the year ended December 31, 2015, sales to Hiland amounted to $1.4 million, net of transportation and processing costs, which is included in the caption “Crude oil and natural gas sales to affiliates” in the consolidated statements of comprehensive income (loss).
The Company capitalized costs of $0.1 million and $2.6 million in 2016 and 2015, respectively, associated with drilling rig services and demobilization of a drilling rig provided by an affiliate. Hiland historically provided field services such as compression, purchases of residue fuel gas and reclaimed crude oil, and reimbursements of generator rentals and fuel. Production and other expenses attributable to these transactions with Hiland prior to its sale were $1.7 million for the year ended December 31, 2015. The total amount paid to these affiliates, a portion of which was billed to other interest owners, was $0.1 million and $7.7 million for the years ended December 31, 2016 and 2015, respectively. No amounts were due to these affiliates at December 31, 2017 and 2016 related to the transactions.
Certain officers of the Company own or control entities that own working and royalty interests in wells operated by the Company. The Company paid revenues to these affiliates, including royalties, of $0.5 million, $0.4 million, $0.2 million, and $0.7$0.4 million and received payments from these affiliates of $0.3$0.1 million, $0.3 million, and $0.5$0.3 million during the years ended December 31, 2017, 2016,2021, 2020, and 2015,2019, respectively, relating to the operations of the respective properties. At December 31, 20172021 and 2016,2020, approximately $58,000$39,000 and $90,000$18,000, respectively, was due from these affiliates respectively,relating to these transactions, which is included in “Receivables—Joint interest and other” on the consolidated balance sheets. At December 31, 2021 and 2020, approximately $48,000$37,000 and $45,000$18,000, respectively, was due to these affiliates respectively, relating to these transactions.transactions, which is included in “Revenues and royalties payable” on the consolidated balance sheets.
The Company allows certain affiliates to use its corporate aircraft and crews and has used the aircraft of those same affiliates from time to time in order to facilitate efficient transportation of Company personnel. The rates charged between the parties vary by type of aircraft used. In 2016, the Company also purchased an existing prepaid maintenance account from an affiliate for use in major engine overhaul to be applied as needed for corporate aircrafts. For usage during 2017, 2016,2021, 2020, and 2015,2019, the

99
Table of Contents
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements


Company charged affiliates approximately $19,400, $9,500,$11,300, $8,100, and $9,600,$17,600, respectively, for use of its corporate aircraft crews, fuel, and reimbursement of expenses and received approximately $18,600, $6,800,$5,000, $9,500, and $33,000$18,900 from affiliates in 2017, 2016,2021, 2020, and 2015, respectively.2019, respectively, in connection with such items. The Company was charged approximately $460,000, $292,000,$117,000, $120,000, and $236,000,$303,000, respectively, by affiliates for use of their aircraft and reimbursement of expenses during 2017, 2016 (including the prepayment),2021, 2020, and 20152019 and paid $368,000, $195,000,$84,000, $158,000, and $221,000$426,000 to the affiliates in 2017, 2016,2021, 2020, and 2015,2019, respectively. At December 31, 2017 and 2016,2021, approximately $4,200 and $3,400$6,300 was due from an affiliate respectively,relating to these transactions, which is included in “Receivables—Joint interest and other” on the consolidated balance sheets. At December 31, 2021, approximately $92,000 and $97,000$33,000 was due to an affiliate respectively, relating to these transactions.
The Company incurred costs for various field projects that had been ongoing with an entity that became an affiliate oftransactions, which is included in “Accounts payable trade” on the Company in the third quarter of 2014. During the fourth quarter of 2015,consolidated balance sheets. No amounts were due to or from the affiliate relationship terminated. The total amount invoiced and capitalized for 2015 associated with the projects was $8.8 million. The total amount paid, a portion of which was billed to other interest owners, was $9.2 million for 2015.at December 31, 2020.
Note 12.15. Stock-Based Compensation
On January 1, 2017, the Company adopted ASU 2016-09, Compensation—Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting. See Note 1. Organization and Summary of Significant Accounting Policies—Adoption of new accounting pronouncements for a discussion of the impact of adoption.
The Company has granted restricted stock to employees and directors pursuant to the Continental Resources, Inc. 2013 Long-Term Incentive Plan, as amended (“2013 Plan”) as discussed below.. The Company’s associated compensation expense, which is included in the caption “General and administrative expenses” in the consolidated statements of comprehensive income (loss), was $45.9$63.2 million, $48.1$64.6 million, and $51.8$52.0 million for the years ended December 31, 2017, 20162021, 2020, and 2015,2019, respectively.
In May 2013,March 2019, the Company adopted theamended and restated its 2013 Plan and reserved 19,680,072specified 12,983,543 shares of common stock that may be issued pursuant to the amended plan. Subject to limited exceptions, the 2013 Plan allows previously issued shares to be reissued if such shares are subsequently forfeited or withheld to satisfy tax withholdings. As of December 31, 2017,2021, the Company had 14,538,5408,492,645 shares of common stock available for long-term incentive awards to employees and directors under the 2013 Plan.
Restricted stock is awarded in the name of the recipient and constitutes issued and outstanding shares of the Company’s common stock for all corporate purposes during the period of restriction and, except as otherwise provided under the 2013 Plan or agreement relevant to a given award, includes the right to vote the restricted stock and to receive dividends, subject to forfeiture. Restricted stock grants generally vest over periods ranging from one1 to three3 years.
94
Table of Contents
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements

A summary of changes in non-vested restricted shares from December 31, 20142018 to December 31, 20172021 is presented below.
Number of
non-vested
shares		Weighted
average
grant-date
fair value
 Number of
non-vested
shares		 Weighted
average
grant-date
fair value
Non-vested restricted shares at December 31, 2014 2,678,764
 $49.40
Non-vested restricted shares at December 31, 2018Non-vested restricted shares at December 31, 20184,022,409 $38.44 
Granted 1,462,534
 46.65
Granted1,526,825 43.21 
Vested (555,517) 48.07
Vested(1,737,304)24.19 
Forfeited (336,170) 51.23
Forfeited(350,022)47.13 
Non-vested restricted shares at December 31, 2015 3,249,611
 $48.20
Non-vested restricted shares at December 31, 2019Non-vested restricted shares at December 31, 20193,461,908 $46.82 
Granted 2,064,508
 22.36
Granted2,738,625 26.93 
Vested (1,207,235) 41.27
Vested(1,146,618)45.78 
Forfeited (193,250) 39.79
Forfeited(163,277)36.69 
Non-vested restricted shares at December 31, 2016 3,913,634
 $37.12
Non-vested restricted shares at December 31, 2020Non-vested restricted shares at December 31, 20204,890,638 $36.26 
Granted 1,585,870
 44.58
Granted3,050,491 24.73 
Vested (874,665) 57.36
Vested(1,750,483)44.36 
Forfeited (598,729) 37.34
Forfeited(296,138)26.61 
Non-vested restricted shares at December 31, 2017 4,026,110
 $35.63
Non-vested restricted shares at December 31, 2021Non-vested restricted shares at December 31, 20215,894,508 $28.38 
The grant date fair value of restricted stock represents the closing market price of the Company’s common stock on the date of grant. Compensation expense for a restricted stock grant is determined at the grant date fair value and is recognized over the vesting period as services are rendered by employees and directors. The Company estimates the number of forfeitures expected to occur in determining the amount of stock-based compensation expense to recognize. There are no post-vesting restrictions

100
Table of Contents
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements


related to the Company’s restricted stock. The fair value at the vesting date of restricted stock that vested during 2017, 20162021, 2020, and 20152019 was $39.8approximately $46.7 million, $30.0$27.5 million, and $23.6$79.7 million, respectively. As of December 31, 2017,2021, there was approximately $58$70 million of unrecognized compensation expense related to non-vested restricted stock. This expense is expected to be recognized over a weighted average period of 1.21.4 years.
Note 13. 16. Shareholders' Equity Attributable to Continental Resources
Share Repurchases
In May 2019 the Company's Board of Directors approved the initiation of a share repurchase program to acquire up to $1 billion of the Company's common stock beginning in June 2019. See Note 20. Subsequent Events for discussion of an increase in the authorized amount of the Company's share repurchase program made subsequent to December 31, 2021. As of December 31, 2021, the Company has repurchased and retired a cumulative total of approximately 17.0 million shares under the program at an aggregate cost of $441.1 million as reflected in the table below by year.
Number of
shares		Aggregate cost (in thousands)
2019 Share Repurchases5,646,553 $190,239 
2020 Share Repurchases8,122,104 126,906 
2021 Share Repurchases3,198,571 123,924 
Total16,967,228 $441,069 
The timing and amount of the Company's share repurchases are subject to market conditions and management discretion. 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. 
Dividend Payments
95
Table of Contents
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements

The following table summarizes the dividends paid by the Company on its outstanding common stock for the years ended December 31, 2021, 2020, and 2019.
Amount (in thousands)Dividend per share
Year Ended December 31, 2019
Fourth quarter$18,747 $0.05 
Total$18,747 
Year Ended December 31, 2020
First quarter$18,580 $0.05 
Total$18,580 
Year Ended December 31, 2021
Second quarter$40,429 $0.11 
Third quarter55,132 $0.15 
Fourth quarter72,975 $0.20 
Total$168,536 
Accumulated Other Comprehensive Income (Loss)other comprehensive income
Adjustments resulting from the process of translating foreign functional currency financial statements into U.S. dollars are included in “Accumulated other comprehensive income (loss)”income” within shareholders’ equity attributable to Continental Resources on the consolidated balance sheets and “Other comprehensive income (loss), net of tax” in the consolidated statements of comprehensive income (loss). The following table summarizes the change in accumulated other comprehensive income (loss) for the years ended December 31, 2017, 2016, and 2015:
  Year ended December 31,
In thousands 2017 2016 2015
Beginning accumulated other comprehensive loss, net of tax $(260) $(3,354) $(385)
Foreign currency translation adjustments 567
 3,094
 (2,969)
Income taxes (1) —
 —
 —
Other comprehensive income (loss), net of tax 567
 3,094
 (2,969)
Ending accumulated other comprehensive income (loss), net of tax $307
 $(260) $(3,354)
(1)A valuation allowance has been recognized against all deferred tax assets associated with losses generated by the Company’s Canadian operations, thereby resulting in no income taxes on other comprehensive income (loss).
Note 14. Property Dispositions
2017
In September 2017, the Company sold non-strategic properties in the Arkoma Woodford area for cash proceeds of $65.3 million. The sale included approximately 26,000 net acres of leasehold in Atoka, Coal, Hughes, and Pittsburg Counties of Oklahoma and producing properties with production totaling approximately 1,700 barrels of oil equivalent per day. In connection with the transaction, the Company recognized a pre-tax loss of $3.5 million for the year ended December 31, 2017. The disposed properties represented an immaterial portion2019.
In thousands2019
Beginning accumulated other comprehensive income, net of tax$415 
Foreign currency translation adjustments140 
Release of cumulative translation adjustments (1)(555)
Income taxes (2)— 
Other comprehensive income (loss), net of tax(415)
Ending accumulated other comprehensive income, net of tax$— 
(1)     In conjunction with the Company’s proved reserves.sale of its Canadian operations in 2019, the cumulative translation adjustments were released. See Note 2. Property Acquisitions and Dispositions for further information.
In September 2017,(2)     A valuation allowance had been recognized against all deferred tax assets associated with losses generated by the Company reached an agreement to sell non-core leasehold in the STACK play in Blaine County, Oklahoma for cash proceeds totaling $63.5 million. A portion of the transaction closed in September 2017,Company’s Canadian operations, thereby resulting in the receipt of proceeds amounting to $3.6 million and the recognition of a $3.3 million pre-tax gainno income taxes on sale in the 2017 third quarter. The remainder of the transaction was completed in October 2017 at which time the Company received the remaining $59.9 million of proceeds and recognized an additional pre-tax gain of approximately $53.6 million, which is reflected in fourth quarter 2017 results. The disposed properties represented an immaterial portion of the Company’s production and proved reserves.other comprehensive income.
In September 2017, the Company sold certain oil-loading facilities in Oklahoma for $7.2 million and recognized a $4.2 million pre-tax gain for the year ended December 31, 2017 associated with the transaction.
2016Note 17. Noncontrolling Interests
Strategic mineral relationship
In October 2016, the2018, Continental entered into a strategic relationship with Franco-Nevada Corporation to acquire oil and gas mineral interests within an area of mutual interest through a minerals subsidiary named The Mineral Resources Company sold approximately 30,000 net acresII, LLC (“TMRC II”). At closing in October 2018, Continental contributed most of non-strategic leaseholdits previously acquired mineral interests to TMRC II in exchange for a 50.1% ownership interest in the SCOOP playentity and Franco-Nevada paid $214.8 million to Continental for a 49.9% ownership interest in OklahomaTMRC II and for cash proceeds totaling $295.6 million. The leasehold was located primarilyfunding of its share of certain mineral acquisition costs. Under the arrangement, Continental is to fund 20% of future mineral acquisitions and will be entitled to receive between 25% and 50% of total revenues generated by TMRC II based upon performance relative to certain predetermined production targets.
Continental holds a controlling financial interest in TMRC II and manages its operations. Accordingly, Continental consolidates the easternfinancial results of the entity and presents the portion of the SCOOP playTMRC II’s results attributable to Franco-Nevada as a noncontrolling interest in its consolidated financial statements. Periodically, Franco-Nevada makes capital contributions to, and included producing properties with production totaling approximately 700 barrels of oil equivalent per day. In connection withreceives revenue distributions from, TMRC II and the transaction, the Company recognized a pre-tax gain of $201.0 million. The disposed properties represented an immaterial portion of the Company’s proved reserves.Continental’s consolidated net assets attributable to Franco-Nevada totaled $369.8 million and $355.1 million at December 31, 2021 and 2020, respectively.
In September 2016, the Company sold non-strategic properties in North Dakota and Montana for cash proceeds totaling $214.8 million, with no gain or loss recognized. The sale included approximately 68,000 net acres of leasehold primarily in western Williams County, North Dakota, and approximately 12,000 net acres of leasehold in Roosevelt County, Montana. The sale also included producing properties with production totaling approximately 2,700 barrels of oil equivalent per day. The disposed properties represented an immaterial portion of the Company’s proved reserves.

Joint ownership arrangement
101
96
Table of Contents
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements



In April 2016,Continental maintains an arrangement with a third party to jointly own parking facilities adjacent to the Company sold approximately 132,000companies’ corporate office buildings. The activities of the parking facilities, which are immaterial to Continental, are managed through an entity named SFPG, LLC (“SFPG”). Continental holds a controlling financial interest in SFPG and manages its operations. Accordingly, Continental consolidates the financial results of the entity and includes the results attributable to the third party within noncontrolling interests in Continental’s financial statements. The portion of Continental’s consolidated net acres of undeveloped leasehold acreageassets attributable to the third party's ownership interest in Wyoming for cash proceeds totaling $110.0 million. In connection with the transaction, the Company recognized a pre-tax gain of $96.9 million. The disposed properties had no production or proved reserves.
2015
During the year endedSFPG totaled $11.1 million and $11.2 million at December 31, 2015, the Company sold certain non-strategic properties in various areas for cash proceeds totaling $34.0 million. The proceeds primarily related to the disposition of certain non-producing leasehold acreage in Oklahoma for $25.9 million in May 2015. The Company recognized a pre-tax gain on the transaction of $20.5 million. The disposed properties represented an immaterial portion of the Company’s leasehold acreage.2021 and 2020, respectively.
Note 15.18. Crude Oil and Natural Gas Property Information
The tables reflected below represent consolidated figures for the Company and its subsidiaries. In 2014, the Company initiated exploratory drilling activitiesoperations in Canada. Through December 31, 2017, those drilling activitiesCanada which were sold in the fourth quarter of 2019. The Company's Canadian operations have not had a material impact on the Company’s totalhistorical capital expenditures, production, and revenues. Accordingly, the results of operations, costs incurred, and capitalized costs associated with the Canadian operations have not been shown separately from the consolidated figures in the tables below. Additionally, results attributable to noncontrolling interests are not material relative to the Company's consolidated results and are not separately presented below.
The following table sets forth the Company’s consolidated results of operations from crude oil and natural gas producing activities for the years ended December 31, 2017, 20162021, 2020 and 2015.2019.
Year ended December 31,
In thousands202120202019
Crude oil and natural gas sales$5,793,741 $2,555,434 $4,514,389 
Production expenses(406,906)(359,267)(444,649)
Production taxes(404,362)(192,718)(357,988)
Transportation expenses(224,989)(196,692)(225,649)
Exploration expenses(21,047)(17,732)(14,667)
Depreciation, depletion, amortization and accretion(1,872,075)(1,859,893)(1,997,854)
Property impairments(38,370)(277,941)(86,202)
Income tax (provision) benefit (1)(690,902)83,427 (323,025)
Results from crude oil and natural gas producing activities$2,135,090 $(265,382)$1,064,355 

 Year ended December 31,
In thousands 2017 2016 2015
Crude oil and natural gas sales $2,982,966
 $2,026,958
 $2,552,531
Production expenses (324,214) (289,289) (348,897)
Production taxes (208,278) (142,388) (200,637)
Exploration expenses (12,393) (16,972) (19,413)
Depreciation, depletion, amortization and accretion (1,652,180) (1,679,485) (1,722,336)
Property impairments (237,370) (237,292) (402,131)
Income tax benefit (1) 504,475
 126,794
 33,680
Results from crude oil and natural gas producing activities $1,053,006
 $(211,674) $(107,203)
(1)    Income taxes reflect the application of a combined federal and state tax rate of 24.5% on pre-tax income/loss generated by our operations in the United States. Additionally, the 2019 period includes the $16.9 million income tax benefit recognized upon the Company's sale of its Canadian operations during that year.
(1)
Income taxes reflect the application of a combined federal and state tax rate of 38% on pre-tax income and losses generated by operations in the United States. Additionally, the 2017 period includes a $713.7 million income tax benefit recognized upon the Company’s remeasurement of its deferred income tax assets and liabilities in response to the enactment of the Tax Reform Act in December 2017. See Note 8. Income Taxes for further discussion.
Costs incurred in crude oil and natural gas activities
Costs incurred, both capitalized and expensed, in connection with the Company’s consolidated crude oil and natural gas acquisition, exploration and development activities for the years ended December 31, 2017, 20162021, 2020 and 20152019 are presented below:below. See Note 2. Property Acquisitions and Dispositions for discussion of notable property acquisitions executed in 2021 that gave rise to the significant increase in costs incurred and aggregate capitalized costs in the current year.
 Year ended December 31, Year ended December 31,
In thousands 2017 2016 2015In thousands202120202019
Property acquisition costs:      Property acquisition costs:
Proved $8,446
 $5,008
 $557
Proved$2,580,271 $60,494 $51,558 
Unproved 220,875
 149,962
 168,492
Unproved1,197,507 201,919 312,680 
Total property acquisition costs 229,321
 154,970
 169,049
Total property acquisition costs3,777,778 262,413 364,238 
Exploration Costs 123,461
 182,355
 241,523
Exploration Costs171,549 48,282 50,143 
Development Costs 1,695,954
 767,148
 2,148,530
Development Costs1,174,828 1,053,532 2,388,582 
Total $2,048,736
 $1,104,473
 $2,559,102
Total$5,124,155 $1,364,227 $2,802,963 
Costs incurred above include asset retirement costs and revisions thereto of $15.3$31.1 million, ($9.6)$18.1 million and $22.8$6.7 million for the years ended December 31, 2017, 20162021, 2020 and 2015,2019, respectively.

10297
Table of Contents
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements



Aggregate capitalized costs
Aggregate capitalized costs relating to the Company’s consolidated crude oil and natural gas producing activities and related accumulated depreciation, depletion and amortization as of December 31, 20172021 and 20162020 are as follows:
 December 31, December 31,
In thousands 2017 2016In thousands20212020
Proved crude oil and natural gas properties $21,362,199
 $19,802,395
Proved crude oil and natural gas properties$31,613,656 $27,726,954 
Unproved crude oil and natural gas properties 365,413
 429,562
Unproved crude oil and natural gas properties1,358,673 368,256 
Total 21,727,612
 20,231,957
Total32,972,329 28,095,210 
Less accumulated depreciation, depletion and amortization (8,971,935) (7,553,255)Less accumulated depreciation, depletion and amortization(16,310,054)(14,622,376)
Net capitalized costs $12,755,677
 $12,678,702
Net capitalized costs$16,662,275 $13,472,834 
Under the successful efforts method of accounting, the costs of drilling an exploratory well are capitalized pending determination of whether proved reserves can be attributed to the discovery. When initial drilling and completion operations are complete, management attempts to determine whether the well has discovered crude oil and natural gas reserves and, if so, whether those reserves can be classified as proved reserves. Often, the determination of whether proved reserves can be recorded under SEC guidelines cannot be made when drilling is completed. In those situations where management believes that economically producible hydrocarbons have not been discovered, the exploratory drilling costs are reflected on the consolidated statements of comprehensive income (loss) as dry hole costs, a component of “Exploration expenses”.expenses.” Where sufficient hydrocarbons have been discovered to justify further exploration or appraisal activities, exploratory drilling costs are deferred under the caption “Net property and equipment” on the consolidated balance sheets pending the outcome of those activities.
On at least a quarterly basis, operating and financial management review the status of all deferred exploratory drilling costs in light of ongoing exploration activities—in particular, whether the Company is making sufficient progress in its ongoing exploration and appraisal efforts. If management determines that future appraisal drilling or development activities are not likely to occur, any associated exploratory well costs are expensed in that period of determination.
The following table presents the amount of capitalized exploratory drillingwell costs pending evaluation at December 31 for each of the last three years and changes in those amounts during the years then ended:
 Year ended December 31, Year ended December 31,
In thousands 2017 2016 2015In thousands202120202019
Balance at January 1 $34,852
 $59,397
 $93,421
Balance at January 1$32,737 $6,257 $3,959 
Additions to capitalized exploratory well costs pending determination of proved reserves 79,451
 123,980
 132,806
Additions to capitalized exploratory well costs pending determination of proved reserves122,068 32,880 28,280 
Reclassification to proved crude oil and natural gas properties based on the determination of proved reserves (81,035) (141,941) (160,779)Reclassification to proved crude oil and natural gas properties based on the determination of proved reserves(117,131)(72)(23,200)
Capitalized exploratory well costs charged to expense (1,912) (6,584) (6,051)Capitalized exploratory well costs charged to expense(1)(6,328)(2,782)
Balance at December 31 $31,356
 $34,852
 $59,397
Balance at December 31$37,673 $32,737 $6,257 
Number of gross wells 37
 54
 73
Number of gross wells17 16 11 
As of December 31, 2017,2021, the Company had no significant exploratory drillingwell costs that were suspended one year beyond the completion of drilling.
Note 16.19. Supplemental Crude Oil and Natural Gas Information (Unaudited)
The table below shows estimates of proved reserves prepared by the Company’s internal technical staff and independent external reserve engineers in accordance with SEC definitions. Ryder Scott Company, L.P. prepared reserve estimates for properties comprising approximately 96%98%, 99%95%, and 98%91% of the Company's total proved reserves as of December 31, 2017, 2016,2021, 2020, and 2015,2019, respectively. Remaining reserve estimates were prepared by the Company’s internal technical staff. All proved reserves stated herein are located in the United States. No proved reserves have been included for the Company’s Canadian operations as of December 31, 2017, 2016,for the periods presented. Proved reserves attributable to noncontrolling interests are not material relative to the Company's consolidated reserves and 2015.are not separately presented in the tables below.
Proved reserves are estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be economically producible in future periods from known reservoirs under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate

10398
Table of Contents
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements



expire, unless evidence indicates renewal is reasonably certain. There are numerous uncertainties inherent in estimating quantities of proved crude oil and natural gas reserves. Crude oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be precisely measured, and estimates of engineers other than the Company’s might differ materially from the estimates set forth herein. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Periodic revisions to theor removals of estimated reserves and future cash flows may be necessary as a result of a number of factors, including reservoir performance, new drilling, crude oil and natural gas prices, changes in costs, technological advances, new geological or geophysical data, changes in business strategies, or other economic factors. Accordingly, reserve estimates may differ significantly from the quantities of crude oil and natural gas ultimately recovered.
Reserves at December 31, 2017, 20162021, 2020, and 20152019 were computed using the 12-month unweighted average of the first-day-of-the-month commodity prices as required by SEC rules.
Natural gas imbalance receivables and payables for each of the three years ended December 31, 2017, 20162021, 2020, and 20152019 were not material and have not been included in the reserve estimates.
Proved crude oil and natural gas reserves
Changes in proved reserves were as follows for the periods presented:
Crude Oil
(MBbls)		Natural Gas
(MMcf)		Total
(MBoe)
Proved reserves as of December 31, 2018757,096 4,591,614 1,522,365 
Revisions of previous estimates(88,307)(363,239)(148,848)
Extensions, discoveries and other additions162,710 1,213,947 365,034 
Production(72,267)(311,865)(124,244)
Sales of minerals in place(803)(6,224)(1,840)
Purchases of minerals in place1,758 30,238 6,798 
Proved reserves as of December 31, 2019760,187 5,154,471 1,619,265 
Revisions of previous estimates(249,845)(1,530,174)(504,874)
Extensions, discoveries and other additions42,106 295,686 91,387 
Production(58,745)(306,528)(109,833)
Sales of minerals in place— — — 
Purchases of minerals in place3,272 27,269 7,817 
Proved reserves as of December 31, 2020496,975 3,640,724 1,103,762 
Revisions of previous estimates14,574 233,966 53,569 
Extensions, discoveries and other additions165,268 1,235,022 371,105 
Production(58,636)(370,110)(120,321)
Sales of minerals in place(70)(469)(148)
Purchases of minerals in place175,419 371,546 237,343 
Proved reserves as of December 31, 2021793,530 5,110,679 1,645,310 
  Crude Oil
(MBbls)		 Natural Gas
(MMcf)		 Total
(MBoe)
Proved reserves as of December 31, 2014 866,360
 2,908,386
 1,351,091
Revisions of previous estimates (246,840) (302,143) (297,198)
Extensions, discoveries and other additions 134,764
 710,453
 253,173
Production (53,517) (164,454) (80,926)
Sales of minerals in place (253) (456) (329)
Purchases of minerals in place —
 —
 —
Proved reserves as of December 31, 2015 700,514
 3,151,786
 1,225,811
Revisions of previous estimates (99,966) (63,057) (110,474)
Extensions, discoveries and other additions 97,587
 911,062
 249,430
Production (46,850) (195,240) (79,390)
Sales of minerals in place (8,057) (14,733) (10,513)
Purchases of minerals in place —
 —
 —
Proved reserves as of December 31, 2016 643,228
 3,789,818
 1,274,864
Revisions of previous estimates (77,779) (25,390) (82,012)
Extensions, discoveries and other additions 129,895
 661,867
 240,206
Production (50,536) (228,159) (88,562)
Sales of minerals in place (4,365) (64,989) (15,197)
Purchases of minerals in place 506
 7,134
 1,696
Proved reserves as of December 31, 2017 640,949
 4,140,281
 1,330,995
Revisions of previous estimates. Revisions represent changesfor 2021 are comprised of (i) upward price revisions of 92 MMBo and 458 Bcf (totaling 168 MMBoe) due to the significant increase in previous reserve estimates, either upward or downward,average crude oil and natural gas prices in 2021 compared to 2020 resulting from new information normally obtained from development drillingthe lifting of COVID-19 restrictions, the resumption of normal economic activity, and production history orthe resulting from a changeimprovement in economic factors, such as commodity pricessupply and differentials, operating costs or development costs.
In 2017, the Company continued to refine its capital program to focus on areas that provide the greatest opportunities to achieve operating efficiencies and cost reductions, to convert undeveloped acreage to acreage held by production, and to improve hydrocarbon recoveries, cash flows and rates of return using optimized completions. As part of this effort, the Company shifted a portion of its 2017 spending away from the SCOOP and Bakken plays to areas in the emerging STACK play that offered more advantageous opportunities and rates of return in the 2017 commodity price environment. This shift in strategy coupled with the Company's increased emphasis on balancing capital spending with cash flows altered the timing and extent of previous development plans in certain areas and resulted indemand fundamentals, (ii) the removal of 4131 MMBo and 290155 Bcf (totaling 8957 MMBoe) of PUD reserves no longer scheduled to be developeddrilled within five years of initial booking due 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 dateremoval of initial booking.

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.
104
99
Table of Contents
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements



CommodityRevisions for 2020 are comprised of (i) the removal of 50 MMBo and 345 Bcf (totaling 107 MMBoe) of PUD reserves no longer scheduled to be drilled within five years of initial booking due to a reduction in the scope of future drilling programs based on adverse market conditions, reduced demand, and lower prices increased on average in 2017 relativecaused by the COVID-19 pandemic and our resulting allocation of capital to 2016 in responseareas providing the best opportunities to improving domesticimprove efficiencies, recoveries, and global supply and demand fundamentals and other factors. The 12-month average first-day-of-the-month price for crude oil increased 20% from $42.75 per Bbl for 2016 to $51.34 per Bbl for 2017, while the 12-month average first-day-of-the-month price for natural gas increased 20% from $2.49 per MMBtu for 2016 to $2.98 per MMBtu for 2017. These changes increased the economic livesrates of certain producing properties and caused certain previously uneconomic projects to become economic, which had a favorable impact on the Company’s proved reserve estimates, resulting in upwardreturn, (ii) downward revisions of 29 MMBo and 78172 Bcf (totaling 4258 MMBoe) in 2017.
Additionally,from the removal of PUD reserves due to changes in anticipated productioneconomics, performance, on certain properties resultedand other factors, (iii) downward price revisions of 214 MMBo and 1,043 Bcf (totaling 388 MMBoe) due to a significant decrease in 59 MMBo of downward revisions toaverage crude oil reserves and 173 Bcf ofnatural gas prices in 2020 compared to 2019 resulting from the economic turmoil caused by the COVID-19 pandemic and other factors, and (iv) net upward revisions to natural gasfor oil reserves (nettingof 43 MMBo and 31 Bcf (totaling 48 MMBoe) due to 30 MMBoe of downward revisions) in 2017. Further, changes in ownership interests, operating costs, anticipated production, and other factors.
Revisions for 2019 are comprised of (i) the removal of 17 MMBo and 108 Bcf (totaling 35 MMBoe) of PUD reserves no longer scheduled to be drilled within five years of initial booking due to continual refinement of the Company's drilling programs and reallocation of capital to areas providing the greatest opportunities to improve efficiencies, recoveries, and rates of return, (ii) downward revisions of 38 MMBo and 278 Bcf (totaling 85 MMBoe) from the removal of PUD reserves due to changes in economics, performance, and other factors, during the year resulted(iii) downward price revisions of 24 MMBo and 118 Bcf (totaling 43 MMBoe) due to a decrease in 7 MMBo ofaverage crude oil and natural gas prices in 2019 compared to 2018, and (iv) net downward revisions to crudefor oil reserves of 9 MMBo and 11 Bcf ofnet upward revisions tofor natural gas reserves of 139 Bcf (netting to 514 MMBoe of downwardupward revisions) due to changes in 2017.ownership interests, operating costs, anticipated production, and other factors.
Extensions, discoveries and other additions.These are additions to proved reserves resulting from (1) extension of the proved acreage of previously discovered reservoirs through additional drilling in periods subsequent to discovery and (2) discovery of new fields with proved reserves or of new reservoirs of proved reserves in old fields.
Extensions, discoveries and other additions for each of the three years reflected in the table above were primarily due to increases in proved reserves associated with our successful drilling and completion activities in the Bakken, SCOOP, and STACK plays. Provedcontinual refinement of our drilling programs. For 2021, proved reserve additions in the Bakken totaled 106140 MMBo and 253375 Bcf (totaling 148202 MMBoe) and proved reserve additions in SCOOPOklahoma totaled 1625 MMBo and 224860 Bcf (totaling 53169 MMBoe) for the year ended December 31, 2017. Additionally, 2017 extensions and discoveries were impacted by successful drilling and completion results in the STACK play, resulting in proved reserve additions of 8 MMBo and 185 Bcf (totaling 39 MMBoe) in 2017..
Sales of minerals in place. These are reductions to proved reserves resulting from the disposition of properties during a period. See Note 14. Property Dispositions for a discussion of notable dispositions.
Purchases of minerals in place. These are additions to proved reserves resulting from the acquisition of properties during a period. There were no individually significant acquisitionsdispositions of proved reserves in the three years reflected in the table above.
Purchases of minerals in place. Purchases for 2021 primarily represent acquisitions of proved reserves in the Permian Basin and Powder River Basin as discussed in Note 2. Property Acquisitions and Dispositions. Proved reserves acquired in the Permian Basin in 2021 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). There were no individually significant acquisitions of proved reserves in 2019 or 2020.
The following reserve information sets forth the estimated quantities of proved developed and proved undeveloped crude oil and natural gas reserves of the Company as of December 31, 2017, 20162021, 2020 and 2015:2019:
 December 31,
 202120202019
Proved Developed Reserves
Crude oil (MBbl)424,153 281,906 336,405 
Natural Gas (MMcf)2,901,147 2,073,011 2,226,117 
Total (MBoe)907,678 627,407 707,424 
Proved Undeveloped Reserves
Crude oil (MBbl)369,377 215,069 423,782 
Natural Gas (MMcf)2,209,532 1,567,713 2,928,354 
Total (MBoe)737,632 476,355 911,841 
Total Proved Reserves
Crude oil (MBbl)793,530 496,975 760,187 
Natural Gas (MMcf)5,110,679 3,640,724 5,154,471 
Total (MBoe)1,645,310 1,103,762 1,619,265 
  December 31,
  2017 2016 2015
Proved Developed Reserves      
Crude oil (MBbl) 318,707
 290,210
 326,798
Natural Gas (MMcf) 1,699,161
 1,370,620
 1,190,343
Total (MBoe) 601,901
 518,646
 525,188
Proved Undeveloped Reserves      
Crude oil (MBbl) 322,242
 353,018
 373,716
Natural Gas (MMcf) 2,441,120
 2,419,198
 1,961,443
Total (MBoe) 729,094
 756,218
 700,623
Total Proved Reserves      
Crude oil (MBbl) 640,949
 643,228
 700,514
Natural Gas (MMcf) 4,140,281
 3,789,818
 3,151,786
Total (MBoe) 1,330,995
 1,274,864
 1,225,811
Proved developed reserves are reserves expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are reserves expected to be recovered from new wells on undrilled acreage or from existing wells that require relatively major capital expenditures to recover.recover, including most wells where drilling has occurred but the wells have not been completed. Natural gas is converted to barrels of crude oil equivalent using a conversion factor of six thousand cubic feet per barrel of crude oil based on the average equivalent energy content of natural gas compared to crude oil.

105
100
Table of Contents
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements



Standardized measure of discounted future net cash flows relating to proved crude oil and natural gas reserves
The standardized measure of discounted future net cash flows presented in the following table was computed using the 12-month unweighted average of the first-day-of-the-month commodity prices, the costs in effect at December 31 of each year and a 10% discount factor. The Company cautions that actual future net cash flows may vary considerably from these estimates. Although the Company’s estimates of total proved reserves, development costs and production rates were based on the best available information, the development and production of the crude oil and natural gas reserves may not occur in the periods assumed. Actual prices realized, costs incurred and production quantities may vary significantly from those used. Therefore, the estimated future net cash flow computations should not be considered to represent the Company’s estimate of the expected revenues or the current value of existing proved reserves.
The following table sets forth the standardized measure of discounted future net cash flows attributable to the Company’s proved crude oil and natural gas reserves as of December 31, 2017, 20162021, 2020, and 2015.2019. Discounted future net cash flows attributable to noncontrolling interests are not material relative to the Company's consolidated amounts and are not separately presented below.
 December 31,
In thousands202120202019
Future cash inflows$67,034,046 $21,334,235 $49,893,470 
Future production costs(18,837,000)(7,750,834)(15,309,672)
Future development and abandonment costs(7,751,678)(3,950,752)(10,033,887)
Future income taxes (1)(7,862,849)(724,569)(3,351,657)
Future net cash flows32,582,519 8,908,080 21,198,254 
10% annual discount for estimated timing of cash flows(15,946,126)(4,254,515)(10,736,613)
Standardized measure of discounted future net cash flows$16,636,393 $4,653,565 $10,461,641 
  December 31,
In thousands 2017 2016 2015
Future cash inflows $42,574,897
 $31,008,587
 $36,551,672
Future production costs (11,159,362) (9,175,410) (10,869,493)
Future development and abandonment costs (6,487,097) (6,452,647) (6,935,958)
Future income taxes (1) (3,488,755) (3,018,839) (3,717,612)
Future net cash flows 21,439,683
 12,361,691
 15,028,609
10% annual discount for estimated timing of cash flows (10,969,506) (6,851,468) (8,552,325)
Standardized measure of discounted future net cash flows $10,470,177
 $5,510,223
 $6,476,284
(1)Estimated future income taxes were calculated by applying existing statutory tax rates, including any known future changes, to the estimated pre-tax net cash flows related to proved crude oil and natural gas reserves, giving effect to any permanent taxable differences and tax credits, less the tax basis of the properties involved. The U.S. federal statutory tax rate utilized in estimating future income taxes was 21% at December 31, 2021, 2020, and 2019.
(1)Estimated future income taxes were calculated by applying existing statutory tax rates, including any known future changes, to the estimated pre-tax net cash flows related to proved crude oil and natural gas reserves, giving effect to any permanent taxable differences and tax credits, less the tax basis of the properties involved. The U.S. federal statutory tax rate utilized in estimating future income taxes was 21% at December 31, 2017 and 35% at December 31, 2016 and 2015.
The weighted average crude oil price (adjusted for location and quality differentials) utilized in the computation of future cash inflows was $47.03, $35.57,$62.19, $34.34, and $41.63$51.95 per barrel at December 31, 2017, 20162021, 2020, and 2015,2019, respectively. The weighted average natural gas price (adjusted for location and quality differentials) utilized in the computation of future cash inflows was $3.00, $2.14,$3.46, $1.17, and $2.35$2.02 per Mcf at December 31, 2017, 20162021, 2020, and 2015,2019, respectively. Future cash flows are reduced by estimated future costs to develop and produce the proved reserves, as well as certain abandonment costs, based on year-end cost estimates assuming continuation of existing economic conditions. The expected tax benefits to be realized from the utilization of net operating loss carryforwards and tax credits are used in the computation of future income tax cash flows.
101
Table of Contents
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements

The changes in the aggregate standardized measure of discounted future net cash flows attributable to the Company’s proved crude oil and natural gas reserves are presented below for each of the past three years.
 December 31,
 In thousands202120202019
Standardized measure of discounted future net cash flows at January 1$4,653,565 $10,461,641 $15,684,817 
Extensions, discoveries and improved recoveries, less related costs2,985,056 187,981 1,649,322 
Revisions of previous quantity estimates816,674 (2,952,489)(1,564,503)
Changes in estimated future development and abandonment costs706,168 4,760,286 1,401,513 
Purchases (sales) of minerals in place, net3,408,365 53,742 49,330 
Net change in prices and production costs9,396,945 (6,912,031)(6,591,347)
Accretion of discount489,273 1,183,993 1,865,034 
Sales of crude oil and natural gas produced, net of production costs(4,757,483)(1,806,758)(3,486,103)
Development costs incurred during the period683,212 863,101 1,557,121 
Change in timing of estimated future production and other1,871,903 (2,325,024)(1,690,779)
Change in income taxes(3,617,285)1,139,123 1,587,236 
Net change11,982,828 (5,808,076)(5,223,176)
Standardized measure of discounted future net cash flows at December 31$16,636,393 $4,653,565 $10,461,641 
  December 31,
 In thousands 2017 2016 2015
Standardized measure of discounted future net cash flows at January 1 $5,510,223
 $6,476,284
 $18,433,034
Extensions, discoveries and improved recoveries, less related costs 1,462,629
 786,587
 1,091,283
Revisions of previous quantity estimates (1,004,355) (794,785) (2,156,028)
Changes in estimated future development and abandonment costs 743,657
 1,651,218
 5,008,731
Sales of minerals in place, net (41,077) (90,390) (7,768)
Net change in prices and production costs 3,808,116
 (2,003,163) (16,111,142)
Accretion of discount 665,507
 798,597
 1,843,303
Sales of crude oil and natural gas produced, net of production costs (2,450,474) (1,595,281) (2,002,997)
Development costs incurred during the period 1,045,875
 454,983
 1,394,584
Change in timing of estimated future production and other 948,519
 (538,665) (3,844,259)
Change in income taxes (218,443) 364,838
 2,827,543
Net change 4,959,954
 (966,061) (11,956,750)
Standardized measure of discounted future net cash flows at December 31 $10,470,177
 $5,510,223
 $6,476,284

106
Table of Contents
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements


Note 17. Quarterly Financial Data (Unaudited)20. Subsequent Events
Acquisition Agreement
On January 24, 2022, the Company executed a definitive agreement to acquire oil and gas properties in the Powder River Basin for $450 million of cash, subject to customary closing price adjustments. The Company’s unauditedproperties include approximately 172,000 net leasehold acres and producing properties with production totaling approximately 16,000 barrels of oil equivalent per day based on two-stream reporting. Closing of the acquisition is expected to occur in late March 2022 and remains subject to the completion of customary due diligence procedures and closing conditions.
Increase in Share Repurchase Program

On February 8, 2022, the Company's Board of Directors approved an increase in the size of the Company's existing share repurchase program from $1.0 billion to $1.5 billion, inclusive of cumulative amounts repurchased to date. As of the date of this filing, the Company has repurchased a cumulative $441.1 million of its common stock, leaving approximately $1.06 billion of authorized repurchasing capacity 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.
Dividend Declaration
On February 9, 2022, the Company declared a quarterly financial data for 2017 and 2016 is summarized below. 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.

102
  Quarter ended
In thousands, except per share data March 31     June 30     September 30     December 31    
2017        
Total revenues (1) $685,427
 $661,486
 $726,743
 $1,047,172
Gain on crude oil and natural gas derivatives, net (1) $46,858
 $28,022
 $8,602
 $8,165
Property impairments (2) $51,372
 $123,316
 $35,130
 $27,552
Litigation settlement (3) $—
 $—
 $—
 $59,600
Gain (loss) on sale of assets, net (4) $(3,638) $780
 $3,562
 $54,420
Income (loss) from operations $77,221
 $(29,041) $91,753
 $309,468
Net income (loss) (5) $469
 $(63,557) $10,621
 $841,914
Net income (loss) per share:        
Basic $—
 $(0.17) $0.03
 $2.27
Diluted $—
 $(0.17) $0.03
 $2.25
2016        
Total revenues (1) $453,174
 $451,211
 $526,199
 $549,689
Gain (loss) on crude oil and natural gas derivatives, net (1) $42,112
 $(82,257) $15,668
 $(47,382)
Property impairments (2) $78,927
 $66,112
 $57,689
 $34,564
Gain on sale of assets, net (4) $109
 $96,907
 $6,158
 $201,315
Income (loss) from operations $(239,103) $(110,547) $(93,183) $155,299
Loss on extinguishment of debt (6) $—
 $—
 $—
 $26,055
Net income (loss) $(198,326) $(119,402) $(109,621) $27,670
Net income (loss) per share:        
Basic $(0.54) $(0.32) $(0.30) $0.07
Diluted $(0.54) $(0.32) $(0.30) $0.07
(1)Gains and losses on crude oil and natural gas derivative instruments are reflected in “Total revenues” on both the consolidated statements of comprehensive income (loss) and this table of unaudited quarterly financial data. Crude oil and natural gas derivative gains and losses have been shown separately to illustrate the fluctuations in revenues that are attributable to the Company’s derivative instruments. Commodity price fluctuations each quarter can result in significant swings in mark-to-market gains and losses, which affects comparability between periods.
(2)Property impairments have been shown separately to illustrate the impact on quarterly results attributable to write downs of the Company’s assets. Commodity price fluctuations each quarter can result in significant changes in estimated future cash flows and resulting impairments, which affects comparability between periods.
(3)
Fourth quarter 2017 results include a $59.6 million pre-tax loss accrual recognized in conjunction with a litigation settlement as discussed in Note 10. Commitments and Contingencies, which resulted in an after-tax decrease in net income of $37.0 million ($0.10 per basic and diluted share).

(4)
Gains on asset sales have been shown separately to illustrate the impact on quarterly results attributable to asset dispositions, which differ in significance from period to period and affect comparability. See Note 14. Property Dispositions for a discussion of notable dispositions.
(5)
Fourth quarter 2017 results reflect the remeasurement of the Company's deferred income tax assets and liabilities in response to the enactment of the Tax Reform Act in December 2017, which resulted in a one-time decrease in income tax expense and corresponding increase in net income of approximately $713.7 million ($1.92 per basic share and $1.91 per diluted share). See Note 8. Income Taxes for further discussion.
(6)
See Note 7. Long-Term Debt for discussion of the loss recognized by the Company upon the redemption of its 2020 Notes and 2021 Notes in the 2016 fourth quarter.




Item 9.Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Item 9.    Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
There have been no changes in accountants or any disagreements with accountants.


Item 9A.Controls and Procedures
Item 9A.    Controls and Procedures
Evaluation of Disclosure Controls and Procedures
As of the end of the period covered by this report, an evaluation of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) was performed under the supervision and with the participation of the Company’s management, including its Chief Executive Officer and Chief Financial Officer. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded the Company’s disclosure controls and procedures were effective as of December 31, 20172021 to ensure information required to be disclosed in the reports it files and submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and information required to be disclosed under the Exchange Act is accumulated and communicated to the Company’s management, including its Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.


Changes in Internal Control over Financial Reporting
As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, of our internal control over financial reporting to determine whether any changes occurred during the fourth quarter of 20172021 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. Based on that evaluation, there were no changes in our internal control over financial reporting or in other factors during the fourth quarter of 20172021 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
 

103


Management’s Report on Internal Control Over Financial Reporting


MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING


Our Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our consolidated financial statements for external purposes in accordance with generally accepted accounting principles. Under the supervision and with the participation of our Company’s management, including the Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
Our internal control over financial reporting includes those policies and procedures that: (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of our consolidated financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our consolidated financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Based on our evaluation under the framework in Internal Control—Integrated Framework (2013), the management of our Company concluded that our internal control over financial reporting was effective as of December 31, 2017.2021.
The effectiveness of our internal control over financial reporting as of December 31, 20172021 has been audited by Grant Thornton LLP, an independent registered public accounting firm, as stated in their report that follows.




/s/ Harold G. HammWilliam B. Berry
Chairman of the BoardPresident and Chief Executive Officer


/s/ John D. Hart
Senior Vice President, Chief Financial Officer and TreasurerExecutive Vice President of Strategic Planning


February 21, 2018

14, 2022

104

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


Board of Directors and Shareholders
Continental Resources, Inc.


Opinion on internal control over financial reporting
We have audited the internal control over financial reporting of Continental Resources, Inc. (an Oklahoma corporation) and subsidiaries (the “Company”) as of December 31, 2017,2021, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017,2021, based on criteria established in the 2013 Internal Control—Integrated Framework issued by COSO.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated financial statements of the Company as of and for the year ended December 31, 2017,2021, and our report dated February 21, 2018 14, 2022expressed an unqualified opinion on those financial statements.
Basis for opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control overOver Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and limitations of internal control over financial reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.


/s/ GRANT THORNTON LLP


Oklahoma City, Oklahoma
February 21, 2018

14, 2022

105

Item 9B.Other Information
Item 9B.    Other Information
None.

Item 9C.    Disclosure Regarding Foreign Jurisdictions that Prevent Inspections
None.

PART III
 
Item 10.Directors, Executive Officers and Corporate Governance
Item 10.    Directors, Executive Officers and Corporate Governance
Information as to Item 10 will be set forth in the Proxy Statement for the Annual Meeting of Shareholders to be held in May 20182022 (the “Annual Meeting”) and is incorporated herein by reference.
 
Item 11.Executive Compensation
Item 11.    Executive Compensation
Information as to Item 11 will be set forth in the Proxy Statement for the Annual Meeting and is incorporated herein by reference.
 
Item 12.Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Item 12.    Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Information required by Item 201(d) of Regulation S-K with respect to securities authorized for issuance under equity compensation plans is disclosed in Part II, Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities—Equity Compensation Plan Information and is incorporated herein by reference. Other applicable information required as to Item 12 will be set forth in the Proxy Statement for the Annual Meeting and is incorporated herein by reference.
 
Item 13.Certain Relationships and Related Transactions, and Director Independence
Item 13.    Certain Relationships and Related Transactions, and Director Independence
Information as to Item 13 will be set forth in the Proxy Statement for the Annual Meeting and is incorporated herein by reference.
 
Item 14.Principal Accountant Fees and Services
Item 14.    Principal Accountant Fees and Services
Information as to Item 14 will be set forth in the Proxy Statement for the Annual Meeting and is incorporated herein by reference.

106


PART IV
 
Item 15.Exhibits and Financial Statement Schedules
Item 15.    Exhibits and Financial Statement Schedules
(1) Financial Statements
The consolidated financial statements of Continental Resources, Inc. and Subsidiaries and the Report of Independent Registered Public Accounting Firm are included in Part II, Item 8 of this report. Reference is made to the accompanying Index to Consolidated Financial Statements.
(2) Financial Statement Schedules
All financial statement schedules have been omitted because they are not applicable or the required information is presented in the financial statements or the notes thereto.
(3) Index to Exhibits
The exhibits required to be filed or furnished pursuant to Item 601 of Regulation S-K are set forth below.
2.1
3.1
3.2***3.2
4.1
4.2
4.3
4.4
4.44.5
4.54.6
Indenture dated as of May 19, 2014 among Continental Resources, Inc., Banner Pipeline Company, L.L.C., CLR Asset Holdings, LLC and Wilmington Trust, National Association, as trustee, filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K (Commission File No. 001-32886) filed May 22, 2014 and incorporated herein by reference.
4.6***4.7
Registration Rights Agreement dated as of August 13, 2012 among Continental Resources, Inc., the Revocable Inter Vivos Trust of Harold G. Hamm, and Jeffrey B. Hume.
4.7
Indenture dated as of December 8, 2017 among Continental Resources, Inc., Banner Pipeline Company, L.L.C., CLR Asset Holdings, LLC, The Mineral Resources Company and Wilmington Trust, National Association, as trustee, filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K (Commission File No. 001-32886) filed December 12, 2017 and incorporated herein by reference.
107

4.8
10.1†4.9
10.1†


10.2†
10.3†
Continental Resources, Inc. 2013 Long-Term Incentive Plan included as Appendix A to the Company’s Definitive Proxy Statement on Schedule 14A (Commission File No. 001-32886) filed April 10, 2013 and incorporated herein by reference.
10.4†
Form of Employee Restricted Stock Award Agreement under the Continental Resources, Inc. 2013 Long-Term Incentive Plan filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K (Commission File No. 001-32886) filed May 24, 2013 and incorporated herein by reference.
10.5†
Form of Non-Employee Director Restricted Stock Award Agreement under the Continental Resources, Inc. 2013 Long-Term Incentive Plan filed as Exhibit 10.3 to the Company’s Current Report on Form 8-K (Commission File No. 001-32886) filed May 24, 2013 and incorporated herein by reference.
10.6†
Continental Resources, Inc. Deferred Compensation Plan filed as Exhibit 10.110.2 to the Company’s Current Report on Form 8-K10-Q for the quarter ended September 30, 2018 (Commission File No. 001-32886) filed September 26, 2013October 29, 2018 and incorporated herein by reference.
10.7†10.4†
10.810.5†
10.9†
Second Amendment to the Continental Resources, Inc. Deferred Compensation Plan adopted and effective as of May 23, 2014 filed as Exhibit 10.15 to the Company’s Registration Statement on Form S-4 (Commission File No. 333-196944) filed June 20, 2014 and incorporated herein by reference.
10.1010.6
10.11†
Summary of Non-Employee Director Compensation Approved as of May 19, 2016 to be effective July 1, 2016 filed as Exhibit 10.1 to the Company’s Form 10-Q for the quarter ended June 30, 2016 (Commission File No. 001-32886) filed August 3, 2016 and incorporated herein by reference.
10.12†
Description of cash bonus plan approved as of March 20, 2017 filed as Exhibit 10.1 to the Company’s Form 10-Q for the quarter ended March 31, 2017 (Commission File No. 001-32886) filed May 3, 2017 and incorporated herein by reference.
10.13
Purchase Agreement dated as of December  4, 2017 among Continental Resources, Inc.,its subsidiaries Banner Pipeline Company L.L.C., CLR Asset Holdings, LLC and The Mineral Resources Company as guarantors, MUFG Union Bank, N.A., as Administrative Agent, MUFG Union Bank, N.A., BofA Securities, Inc., Mizuho Bank, Ltd., TD Securities (USA) LLC, U.S. Bank National Association, Royal Bank of Canada, Wells Fargo Securities, LLC, and Merrill Lynch, Pierce, Fenner & Smith Incorporated,Truist Securities, Inc. as Joint Lead Arrangers and Joint Bookrunners, and the representative of the several initial purchasers,other lenders named therein filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K (Commission File No. 001-32886) filed December 5, 2017November 3, 2021 and incorporated herein by reference.
21*10.7†
10.8†
10.9†
10.10†
10.11†
10.12†
21*
23.1*
108

23.2*
31.1*
31.2*


32**
99*
101.INS**Inline XBRL Instance Document - the Inline XBRL Instance Document does not appear in the Interactive Data file because its XBRL tags are embedded within the Inline XBRL document
101.SCH**Inline XBRL Taxonomy Extension Schema Document
101.CAL**Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF**Inline XBRL Taxonomy Extension Definition Linkbase Document
101.LAB**Inline XBRL Taxonomy Extension Label Linkbase Document
101.PRE**Inline XBRL Taxonomy Extension Presentation Linkbase Document

*104Filed herewithCover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)
**Furnished herewith
***Re-filed herewith pursuant to Item 10(d) of Regulation S-K.
†Management contracts or compensatory plans or arrangements filed pursuant to Item 601(b)(10)(iii) of Regulation S-K.


*    Filed herewith
**    Furnished herewith
†    Management contracts or compensatory plans or arrangements filed pursuant to Item 601(b)(10)(iii) of Regulation S-K.
109

Signatures
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Continental Resources, Inc. has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
 
CONTINENTAL RESOURCES, INC.
By:
/S/    HAROLD G. HAMMWILLIAM B. BERRY
Name:Harold G. HammWilliam B. Berry
Title:Chairman of the BoardPresident and Chief Executive Officer
Date:February 21, 201814, 2022
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of Continental Resources, Inc. and in the capacities and on the dates indicated.
 
SignatureTitleDate
/s/    HAROLD G. HAMMChairman of the Board and DirectorFebruary 14, 2022
Harold G. Hamm
SignatureTitleDate

/s/    HAROLD G. HAMM
WILLIAM B. BERRY
Chairman of the Board and
President, Chief Executive Officer,
and Director
(principal executive officer)
February 21, 201814, 2022
Harold G. HammWilliam B. Berry


/s/    JOHN D. HART
SeniorChief Financial Officer and Executive Vice President Chief Financial
Officer and Treasurer
of Strategic Planning
(principal financial and accounting officer)
February 21, 201814, 2022
John D. Hart
/s/    WILLIAM B. BERRYSHELLY LAMBERTZExecutive Vice President, Chief Culture and Administrative Officer and DirectorFebruary 21, 201814, 2022
William B. BerryShelly Lambertz
/s/    JAMES L. GALLOGLYDirectorFebruary 21, 2018
James L. Gallogly
/s/    LON MCCAINDirectorFebruary 21, 201814, 2022
Lon McCain
/s/    JOHN T. MCNABB IIDirectorFebruary 21, 201814, 2022
John T. McNabb II
/s/    MARK E. MONROEDirectorFebruary 21, 201814, 2022
Mark E. Monroe
/s/    TIMOTHY G. TAYLORDirectorFebruary 14, 2022
Timothy G. Taylor