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, or share repurchases;

~~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 consequent 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

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.

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 formed in 1967 engaged in the exploration, development, and production of crude oil and natural gas ~~primarily~~ in the North, South and East regions of the United States. Additionally, we pursue the acquisition and management of perpetually owned minerals located in ~~certain of~~ our key operating areas. The North region consists of properties north of Kansas and west of the Mississippi River and includes North Dakota Bakken, Montana Bakken, and the Red River units. The South region includes all properties south of Nebraska and west of the Mississippi River including various plays in the SCOOP and STACK areas of Oklahoma. 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 of our~~Our operations ~~is located~~ in the North region ~~with that region comprising 59%~~comprised 55% of our crude oil and natural gas production and ~~73%~~65% of our crude oil and natural gas revenues for the year ended December 31, ~~2018.~~2020. The Company’s principal producing properties in the North region are located in the Bakken field of North Dakota and Montana. Approximately ~~55%~~48% of our proved reserves as of December 31, ~~2018~~2020 are located in the North region. Our operations in the South region ~~continue to expand with our increased activity in the SCOOP and STACK plays and that region~~ comprised ~~41%~~45% of our crude oil and natural gas production, ~~27%~~35% of our crude oil and natural gas revenues, and ~~45%~~52% of our proved reserves as of and for the year ended December 31, ~~2018.~~2020.

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. 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.

As of December 31, ~~2018,~~2020, our proved reserves were ~~1,522~~1,104 MMBoe, with proved developed reserves representing~~675~~ 627 MMBoe, or ~~44%~~57%, of our total proved reserves. The standardized measure of our discounted future net cash flows totaled ~~$15.7~~$4.65 billion at December 31, ~~2018.~~2020. For ~~2018,~~2020, we generated crude oil and natural gas revenues of ~~$4.68~~$2.56 billion and operating cash flows of ~~$3.46~~$1.42 billion. Crude oil accounted for ~~56%~~53% of our total production and ~~81%~~86% of our crude oil and natural gas revenues for ~~2018.~~2020. Our total production averaged ~~298,190~~300,090 Boe per day for ~~2018,~~2020, a ~~23% increase~~decrease of 12% compared to ~~2017.~~2019.

The table below summarizes our total proved reserves, PV-10 (non-GAAP) and net producing wells as of December 31, ~~2018,~~2020, average daily production for the quarter ended December 31, ~~2018~~2020 and the reserve-to-production index in 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.


	December 31, 2018						Average daily production for fourth quarter 2018 (Boe per day)			Annualized reserve/production index (2)		December 31, 2020						Average daily production for fourth quarter 2020 (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				Proved reserves (MBoe)	Percent of total		PV-10 (1) (In millions)		Net producing wells		Percent of total
North Region:											North Region:
Bakken field											Bakken field
North Dakota Bakken	767,837	50.4	%	$	11,374	1,446	177,358	54.7	%	11.9	North Dakota Bakken	483,238	43.8	%	$	2,235	1,631	177,802	52.4	%	7.4
Montana Bakken	30,168	2.0	%	473		263	6,478	2.0	%	12.8	Montana Bakken	25,754	2.3	%	128		254	5,339	1.6	%	13.2
Red River units											Red River units
Cedar Hills	28,771	1.9	%	455		129	6,598	2.0	%	11.9	Cedar Hills	17,670	1.6	%	142		130	5,323	1.6	%	9.1
Other Red River units	3,661	0.2	%	55		114	2,446	0.8	%	4.1	Other Red River units	932	0.1	%	7		116	1,467	0.4	%	1.7
Other	31	—	%	1		2	33	—	%	2.6

South Region:											South Region:
SCOOP	459,103	30.2	%	4,742		310	67,244	20.8	%	18.7	SCOOP	478,196	43.3	%	2,139		463	107,060	31.6	%	12.2
STACK	230,175	15.1	%	1,528		205	62,947	19.4	%	10.0	STACK	97,967	8.9	%	241		299	42,281	12.4	%	6.3
Other	2,619	0.2	%	22		120	897	0.3	%	8.0	Other	5	—	%	1		2	35	—	%	0.4
Total	1,522,365	100.0	%	$	18,650	2,589	324,001	100.0	%	12.9	Total	1,103,762	100.0	%	$	4,893	2,895	339,307	100.0	%	8.9

~~(1)~~

(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 $239 million. 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 2020 production into estimated proved reserve volumes as of December 31, 2020.

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 $3.0 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 2018 production into estimated proved reserve volumes as of December 31, 2018.

Business Environment and Outlook

~~Our industry is impacted~~In March 2020, the World Health Organization declared a global pandemic related to the proliferation of COVID-19 (novel coronavirus). The ensuing economic turmoil caused by ~~volatility~~the pandemic resulted in a significant reduction in global and ~~uncertainty~~domestic demand for crude oil due to, among other things, changes in ~~commodity prices. Crude~~consumer behavior and restrictions implemented by governments to mitigate the pandemic. This demand destruction contributed to an unprecedented decline in crude oil prices, ~~showed significant signs of improvement throughout the majority of 2018,~~ with West Texas Intermediate benchmark prices reaching all-time lows in April 2020. In response to the significant reduction in crude oil ~~benchmark~~ prices, ~~rising above $75~~we began voluntarily curtailing our production in April 2020 and ultimately curtailed approximately 55% of our operated crude oil production and associated natural gas in the 2020 second quarter. Additionally, in light of the challenges facing our business and industry, we implemented cost saving initiatives and significantly reduced our operated rig and completion crew counts in order to preserve our assets and better align our capital spending with expected available cash flows, resulting in a $1.5 billion, or 56%, decrease in our non-acquisition capital spending in 2020 compared to 2019. These actions, coupled with historically low crude oil prices, resulted in a material reduction in our production, revenues, and cash flows in 2020 compared to 2019.

Crude oil prices began to stabilize in mid-2020 and generally improved in the second half of 2020 in response to the gradual lifting of COVID-19 restrictions, the resumption of economic activity, and the resulting increase in crude oil demand. In July 2020 we began to gradually restore our curtailed production and subsequently brought our remaining curtailed production back online in September 2020. As a result of our resumed production, coupled with strategic well completion activities in late 2020, our total average production improved to 339,307 Boe per ~~barrel in June and again in October before decreasing more~~day for the 2020 fourth quarter, representing a 14% increase compared to the third quarter of 2020, yet still remaining 7% lower than ~~40% in~~ the fourth quarter ~~to an 18-month low~~ of ~~$44 per barrel at year-end 2018. Crude~~2019.

Despite the gradual improvement in crude oil prices ~~have since rebounded from year-end 2018 lows, but remain volatile and unpredictable. Our leadership team has significant experience with~~in the second half of 2020, we continued our commitment to operating in ~~challenging~~a disciplined, capital efficient manner. Improved revenues from higher commodity prices coupled with our tempered spending resulted in the generation of cash flows in excess of operating and capital needs in the second half of 2020 that allowed for a $210 million net reduction in our total debt at December 31, 2020 compared to June 30, 2020. Additionally, despite production curtailments during the year, we continued to drive our per-unit production expenses lower to $3.27 per Boe for 2020 compared to $3.58 per Boe for 2019.

We remain committed to the responsible stewardship of our assets and continue to focus on maximizing cash flows, further reducing debt, delivering low-cost capital efficient operations, and generating shareholder value. The depth and quality of our asset base, the commodity optionality provided by our significant amount of acreage held by production, and our financial strength allow us to be adaptable in a variety of price environments. ~~With our portfolio of high quality assets,~~We remain flexible as we ~~are well-positioned~~monitor and adapt to ~~manage the ongoing challenges and price volatility facing our industry.~~market conditions.

For ~~2019,~~2021, our primary business strategies will focus ~~on:~~on generating shareholder value by:

~~Enhancing free cash flow generation and oil-weighted production growth;~~

Enhancing rates of return on capital employed through improvements in operating efficiencies, technical innovations, pad and row development, optimized completion methods, well productivity, and strategic mineral ownership;

•Continuing to exercise ~~disciplined~~ capital ~~spending~~and operational discipline to ~~maintain financial flexibility and ample liquidity; and~~maximize cash flow generation;

•Reducing outstanding ~~debt using available operating cash flows, proceeds from asset dispositions, or joint development arrangements.~~debt;

~~Our capital expenditures budget for 2019 is $2.6 billion compared~~•Capitalizing on commodity optionality afforded to ~~$2.8 billion spent in 2018, with the majority of~~us by our ~~2019 drilling~~crude oil and ~~completion budget focusing on oil-weighted areas in North Dakota Bakken~~natural gas assets; and SCOOP. Under the current commodity price environment, our planned capital expenditures for 2019 are expected to be funded entirely from operating cash flows. As we have done in the past, we may adjust our pace of drilling and development as 2019 market conditions evolve.

For 2019, we plan to operate an average of 25 drilling rigs and 9 completion crews for the year. We expect to spend approximately 41% of our 2019 capital expenditures budget on drilling and completion activities in the Bakken and 42% on drilling and completion activities in Oklahoma. The remaining 17% of our 2019 budget will target other capital expenditures

~~such as leasing and renewals, mineral acquisitions, work-overs, and facilities. See the section below titled~~ ~~Summary of Crude Oil and Natural Gas Properties and Projects~~ ~~for further discussion of our 2019 plans.~~•Maintaining low-cost operations.

Our Business ~~Strategy~~Strategies

Despite volatility and uncertainty in commodity prices, our business ~~strategy continues~~strategies continue to be focused on ~~increasing~~generating shareholder value by finding and developing crude oil and natural gas reserves at low costs ~~that provide~~and attractive rates of return. The principal elements of this strategy include:

Growing and sustaining aour premier portfolio of assets ~~focused on free~~in a disciplined manner to maximize cash flow ~~generation and oil-weighted production growth.~~generation. We hold a portfolio of leasehold acreage, drilling opportunities, uncompleted wells, perpetually owned minerals, ~~drilling opportunities,~~ and ~~uncompleted wells~~water infrastructure assets 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 the best opportunities to ~~deliver strong oil-weighted production growth while generating~~generate cash flows in excess of operating and capital requirements, ~~to harvest our inventory of uncompleted wells, to~~capitalize on movements in strip pricing between crude oil and natural gas, convert our undeveloped acreage to acreage held by production, harvest our inventory of uncompleted wells, and to improve hydrocarbon recoveries and rates of return on capital employed. ~~While~~We are strongly aligned with shareholders and our ~~operations have historically focused~~strategic vision is predicated on our desire to generate shareholder value through various means.

Reducing outstanding debt. Maintaining a strong balance sheet, ample liquidity, and financial flexibility are key components of our business strategy. A cornerstone of our 2021 plan is to maximize cash flow generation to pay down debt. In 2021 and beyond we will continue our focus on paying down debt and preserving financial flexibility and ample liquidity as we manage the ~~exploration and development of~~risks facing our industry.

Capitalizing on commodity optionality afforded to us by our crude oil ~~we also allocate significant capital to~~and natural gas ~~areas~~assets. We have a deep inventory of both oil and gas assets across the Bakken and Oklahoma that ~~provide attractive rates of return.~~allow us to be responsive to, and benefit from, changes in oil and gas commodity price fundamentals. This commodity optionality provides an inherent advantage to Continental. Not only do we have the ability to shift capital between our Bakken and Oklahoma assets, but within Oklahoma we have the ability to shift capital between oil-weighted or gas-weighted projects depending on which commodity has a stronger price outlook. We also have direct access to multiple premium markets from our Oklahoma assets, which allow us to pursue either oil or gas markets as prices and fundamentals warrant. For 2021, we plan to remain flexible and responsive with our drilling and completion programs to capitalize on relative movements in oil and gas prices.

~~Enhance rates of return on capital employed through operating efficiencies, technical innovations, pad~~Maintaining low-cost operations. Our culture is defined by our low cost operations and ~~row development, optimized completions, well productivity, and strategic mineral ownership.~~ in 2020 we again delivered low cost industry leadership despite the challenges facing our business. We continue to manage our business in the volatile commodity price environment by focusing on improving operating and capital efficiencies and ~~managing~~reducing costs by exploiting technical innovations, pad and row development opportunities, and other means. 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 enhance operating efficiencies and economies of scale.

~~Additionally, we capitalize on our geologic knowledge and land expertise to strategically acquire minerals in areas of future growth, thereby allowing~~ Our operational excellence has allowed us to ~~enhance cash flows~~achieve and ~~project economics through the alignment of mineral ownership with our drilling schedule. Our mineral ownership strategy serves as another avenue to enhance shareholder returns.~~maintain enviable low-cost operations.

~~Maintaining financial flexibility and a strong balance sheet~~. Maintaining a strong balance sheet, ample liquidity, and financial flexibility are key components of our business strategy. In 2018, we reduced our total debt by $585 million, or 9%, and had no outstanding borrowings on our credit facility at December 31, 2018. Additionally, we increased our cash on hand by $239 million during the year to $283 million at year-end 2018. We are actively targeting further debt reduction using available cash, operating cash flows, or proceeds from potential sales of non-strategic assets and joint development opportunities 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 in our core areas where we can exploit our extensive inventory of repeatable drilling opportunities to achieve attractive rates of return.

Our Business Strengths

We have a number of strengths ~~we believe will help~~to allow us to successfully execute our business ~~strategy,~~strategies, including the following:

Large acreage inventory with access to both crude oil and natural gas resources. We held approximately ~~525,700~~359,300 net undeveloped acres and ~~1.22~~1.23 million net developed acres under lease as of December 31, ~~2018~~2020 concentrated in certain premier U.S. resource ~~plays.~~plays that provide optionality and access to crude oil, natural gas, and natural gas liquids. We are among the largest leaseholders in the Bakken, SCOOP and STACK plays. Being an early entrant in these plays has allowed us to capture significant acreage positions in core parts of the plays.

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

Control ~~Operations Over~~operations over a ~~Substantial Portion~~substantial portion of ~~Our Assets~~our assets and ~~Investments~~investments. As of December 31, ~~2018,~~2020, we operated properties comprising ~~85%~~88% of our total proved reserves. By controlling a significant portion of our operations, we are able to more effectively manage the cost and timing of exploration and development of our properties, including the drilling and completion methods used. Additionally, we capitalize on our geologic knowledge and land expertise to strategically acquire minerals in areas of future growth, thereby allowing us to enhance cash flows and project economics through the alignment of mineral ownership with our drilling schedule. Further, we continue to grow our significant portfolio of water gathering, recycling, and disposal infrastructure assets which allow for uninterrupted flow back and recycling capabilities, supports timely completion activities, and generates additional service revenues and cash flows. Our strategies for growing our mineral ownership portfolio and water infrastructure assets serve as additional avenues to generate shareholder value.

Experienced Management Team. Our senior management team has extensive expertise in the oil and gas industry and with operating in challenging commodity price environments. Our ~~Chief~~ Executive ~~Officer,~~Chairman, Harold G. Hamm, began his career in the oil and gas industry in 1967. Our 98 executive officers have an average of 3941 years of oil and gas industry experience.

Financial Position and Liquidity. We have a credit facility with lender commitments totaling $1.5 billion that matures in April 2023. We had ~~no outstanding borrowings~~approximately $1.33 billion of borrowing availability on ~~the~~our credit facility at December 31, ~~2018~~2020 after considering outstanding borrowings and ~~continued to have no borrowings as~~letters of ~~January 31, 2019~~.credit. Our credit facility is unsecured and does not have a borrowing base requirement that is subject to periodic redetermination based on changes in commodity prices and proved reserves. Additionally, downgrades or other negative rating actions with respect to our credit rating do not trigger a reduction in our current credit facility commitments, nor do such actions trigger a security requirement or change in covenants.

Crude Oil and Natural Gas Operations

Proved Reserves

Proved reserves are those quantities of crude oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates renewal is reasonably certain. In connection with the estimation of proved reserves, the term “reasonable certainty” implies a high degree of confidence ~~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 table below sets forth estimated proved crude oil and natural gas reserves information by reserve category as of December 31, ~~2018.~~2020. Proved reserves attributable to noncontrolling interests are ~~immaterial~~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 ~~$15.7~~$4.65 billion at December 31, ~~2018.~~2020. Our reserve estimates as of December 31, ~~2018~~2020 are based primarily on a reserve report prepared by Ryder Scott. In preparing its report, Ryder Scott evaluated properties representing approximately ~~98%~~93% of our PV-10 and ~~98%~~95% of our total proved reserves as of December 31, ~~2018.~~2020. 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, ~~2018~~2020 were determined using the 12-month unweighted arithmetic average of the first-day-of-the-month commodity prices for the period of January ~~2018~~2020 through December ~~2018,~~2020, without giving effect to derivative transactions, and were held constant throughout the lives of the properties. These prices were ~~$65.56~~$39.57 per Bbl for crude oil and ~~$3.10~~$1.99 per MMBtu for natural gas ($~~61.20~~34.34 per Bbl for crude oil and ~~$3.22~~$1.17 per Mcf for natural gas adjusted for location and quality differentials). These average prices are significantly lower than 2019 levels, which resulted in significant downward price-related revisions to proved reserves in 2020. Additionally, in 2020 we reduced the scope of our future drilling programs in response to the reduction in consumer demand and lower prices prompted by the COVID-19 pandemic, which resulted in the removal of PUD reserves no longer scheduled to

Crude Oil
(MBbls) Natural Gas
(MMcf) Total
(MBoe) PV-10 (1)
(in millions)
Proved developed producing 346,969
1,955,727
672,923
$ 10,248.0
Proved developed non-producing 856
8,562
2,283
23.8
Proved undeveloped 409,271
2,627,325
847,159
8,378.5
Total proved reserves 757,096
4,591,614
1,522,365
$ 18,650.3
Standardized Measure (1) $ 15,684.8
be drilled within five years of initial booking. These revisions are further discussed below and contributed to significant decreases in our proved reserves, Standardized Measure, and PV-10 in 2020 compared to 2019.

The following table summarizes our estimated proved reserves by commodity and reserve classification as of December 31, 2020.


	Crude Oil (MBbls)	Natural Gas (MMcf)	Total (MBoe)	PV-10 (1) (in millions)
Proved developed producing	271,904	2,023,293	609,119	$	3,962.5
Proved developed non-producing	10,002	49,718	18,288	110.8
Proved undeveloped	215,069	1,567,713	476,355	819.4
Total proved reserves	496,975	3,640,724	1,103,762	$	4,892.7
Standardized Measure (1)				$	4,653.6

~~(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 $3.0 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.~~

The following table provides additional information regarding our estimated proved crude oil and natural gas reserves by region as of December 31, ~~2018.~~2020.


	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	170,498	550,159	262,191	159,674	368,239	221,047
Montana Bakken	12,114	25,573	16,377	7,330	12,281	9,377
Red River units
Cedar Hills	17,670	—	17,670	—	—	—
Other Red River units	932	—	932	—	—	—

South Region:
SCOOP	69,955	1,073,955	248,947	46,263	1,097,920	229,249
STACK	10,732	423,320	81,285	1,802	89,273	16,682
Other	5	4	5	—	—	—
Total	281,906	2,073,011	627,407	215,069	1,567,713	476,355

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 237,195
588,212
335,232
300,126
794,883
432,606
Montana Bakken 20,523
40,874
27,336
2,312
3,119
2,832
Red River units
Cedar Hills 28,004
4,606
28,771
—
—
—
Other Red River units 3,659
13
3,661
—
—
—
Other 30
7
31
—
—
—
South Region:
SCOOP 45,517
785,293
176,399
89,978
1,156,355
282,705
STACK 11,932
535,356
101,158
16,855
672,968
129,016
Other 965
9,928
2,618
—
—
—
Total 347,825
1,964,289
675,206
409,271
2,627,325
847,159

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


	Year Ended December 31,
MBoe	2020	2019	2018
Proved reserves at beginning of year	1,619,265	1,522,365	1,330,995
Revisions of previous estimates	(504,874)	(148,848)	(269,253)
Extensions, discoveries and other additions	91,387	365,034	565,030
Production	(109,833)	(124,244)	(108,839)
Sales of minerals in place	—	(1,840)	(8,011)
Purchases of minerals in place	7,817	6,798	12,443
Proved reserves at end of year	1,103,762	1,619,265	1,522,365

Year Ended December 31,
MBoe 2018 2017 2016
Proved reserves at beginning of year 1,330,995
1,274,864
1,225,811
Revisions of previous estimates (269,253 ) (82,012 ) (110,474 )
Extensions, discoveries and other additions 565,030
240,206
249,430
Production (108,839 ) (88,562 ) (79,390 )
Sales of minerals in place (8,011 ) (15,197 ) (10,513 )
Purchases of minerals in place 12,443
1,696
—
Proved reserves at end of year 1,522,365
1,330,995
1,274,864

Revisions of previous estimates. Revisions for ~~2018~~2020 are comprised of (i) the removal of 7450 MMBo and ~~960~~345 Bcf (totaling ~~234~~107 MMBoe) of PUD reserves no longer scheduled to be drilled within five years of initial booking due to a reduction in the ~~continual refinement~~scope of our future drilling programs based on adverse market conditions, reduced demand, and ~~reallocation~~lower prices caused by the COVID-19 pandemic and our resulting allocation of capital to areas providing the ~~greatest~~best opportunities to improve efficiencies,

recoveries, and rates of return, (ii) downward revisions of 2129 MMBo and ~~216~~172 Bcf (totaling 5758 MMBoe) from the removal of PUD reserves due to changes in ~~anticipated well densities~~economics, performance, and other factors, (iii) ~~upward~~downward price revisions of 21214 MMBo and 311,043 Bcf (totaling 26388 MMBoe) due to ~~an increase~~the significant decrease in average crude oil and natural gas prices in ~~2018~~2020 compared to ~~2017,~~2019 resulting from the economic turmoil caused by the COVID-19 pandemic and other factors, and (iv) net ~~downward~~upward revisions of 243 MMBo and 1131 Bcf (totaling 448 MMBoe) due to changes in ownership interests, operating costs, anticipated production, ~~performance,~~ and other factors.

Extensions, discoveries and other additions. Extensions, discoveries and other additions for each of the three years reflected in the table above were due to successful drilling and completion activities and continual refinement of our drilling programs in the Bakken, SCOOP, and STACK plays. Proved reserve additions in the Bakken totaled 41 MMBoe, 160 MMBoe, and 251 MMBoe ~~148 MMBoe,~~for 2020, 2019, and ~~73 MMBoe for~~ 2018, ~~2017, and 2016,~~ respectively, while reserve additions in SCOOP totaled 49 MMBoe, 186 MMBoe, ~~53 MMBoe,~~ and 97186 MMBoe for ~~2018, 2017,~~2020, 2019, and ~~2016,~~2018, respectively. Additionally, reserve additions in STACK totaled 1 MMBoe, 19 MMBoe, and 128 MMBoe ~~39 MMBoe,~~in 2020, 2019, and ~~79 MMBoe in~~ 2018, ~~2017, and 2016,~~ respectively. See the subsequent section titled Summary of Crude Oil and Natural Gas Properties and Projects for a discussion of our ~~2018~~2020 drilling activities.

Sales of minerals in place. We had no individually significant dispositions of proved reserves in the past three years.

Purchases of minerals in place. We had no individually significant acquisitions of proved reserves in the past three years. ~~The increase in acquired reserves in 2018 compared to prior years was due to higher mineral acquisition spending.~~

Proved Undeveloped Reserves

All of our PUD reserves at December 31, ~~2018~~2020 are located in the Bakken, SCOOP, and STACK plays, our most active development areas, with those plays comprising ~~52%~~48%, ~~33%~~48%, and ~~15%~~4%, respectively, of our total PUD reserves at year-end ~~2018.~~2020. The following table provides information regarding changes in our PUD reserves for the year ended December 31, ~~2018.~~2020. Our PUD reserves at December 31, ~~2018~~2020 include 8998 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)
	Crude Oil (MBbls)		Natural Gas (MMcf)		Total (MBoe)
Proved undeveloped reserves at December 31, 2017	322,242		2,441,120		729,094
Proved undeveloped reserves at December 31, 2019							Proved undeveloped reserves at December 31, 2019	423,782	2,928,354	911,841
Revisions of previous estimates	(95,168	)	(1,229,127	)	(300,022	)	Revisions of previous estimates	(210,569)	(1,326,177)	(431,599)
Extensions and discoveries	222,122		1,612,969		490,950		Extensions and discoveries	37,605	271,611	82,874
Sales of minerals in place	(1,963	)	(24,327	)	(6,017	)	Sales of minerals in place	—	—	—
Purchases of minerals in place	2,457		33,563		8,051		Purchases of minerals in place	496	5,363	1,390
Conversion to proved developed reserves	(40,419	)	(206,873	)	(74,897	)	Conversion to proved developed reserves	(36,245)	(311,438)	(88,151)
Proved undeveloped reserves at December 31, 2018	409,271		2,627,325		847,159
Proved undeveloped reserves at December 31, 2020							Proved undeveloped reserves at December 31, 2020	215,069	1,567,713	476,355

Title to Properties

As is customary in the crude oil and natural gas industry, upon initiation of acquiring oil and gas leases covering fee mineral interests on undeveloped lands which do not have associated proved reserves, contract landmen conduct a title examination of courthouse records and production databases to determine fee mineral ownership and availability. Title, lease forms and terms are reviewed and approved by Company landmen prior to consummation.

For acquisitions from third parties, whether lands are producing crude oil and natural gas or non-producing, Company and contract landmen perform title examinations at applicable courthouses, obtain physical well site inspections, and examine the seller’s internal records (land, legal, operational, production, environmental, well, marketing and accounting) upon execution of a mutually acceptable purchase and sale agreement. Company landmen may also procure an acquisition title opinion from outside legal counsel on higher value properties.

Prior to the commencement of drilling operations, Company landmen procure an original title opinion, or supplement an existing title opinion, from outside legal counsel and perform curative work to satisfy requirements pertaining to material title defects, if any. Company landmen will not approve commencement of drilling operations until material title defects pertaining to the Company’s interest are cured.

The Company has cured material title opinion defects as to Company interests on substantially all of its producing properties and believes it holds at least defensible title to its producing properties in accordance with standards generally accepted in the crude oil and natural gas industry. The Company’s crude oil and natural gas properties are subject to customary royalty and leasehold burdens which do not materially interfere with the Company’s interest in the properties or affect the Company’s carrying value of such properties.

Marketing ~~and Major Customers~~

We sell most of our operated crude oil production to crude oil refining companies or midstream marketing companies at major market centers. In the Bakken, 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 ~~either directly to a refinery or~~ to a point on a pipeline system for further delivery. We do not transport any of our oil production prior to sale by rail, but several purchasers of our Bakken production are connected to rail delivery systems and may choose those methods to transport the oil they purchase from us. We sell some operated crude oil production at the lease. Our share of crude oil production from non-operated properties is marketed at the discretion of the operators.

We sell our operated natural gas production to midstream customers at our lease locations based on market prices in the field where the sales occur. These contracts include multi-year term agreements, many with acreage ~~dedication.~~dedications. Under certain arrangements, we have the right to take a volume of processed residue gas and/or natural gas liquids ("NGLs") in-kind at the tailgate of the midstream customer's processing plant in lieu of a monetary settlement for the sale of our operated natural gas production. We currently take certain processed residue gas volumes in kind in lieu of monetary settlement, but we do not currently take NGL volumes. When we do take volumes in kind, we pay third parties to transport the residue gas volumes taken in kind to downstream delivery points, where we then sell to customers at prices applicable to those downstream markets. Sales at the downstream markets are mostly under daily and monthly ~~interruptible~~ packaged ~~volume~~volumes deals, ~~short~~shorter term seasonal packages, and long term multi-year contracts. We continue to develop relationships and have the potential to enter into additional contracts with end-use customers, including utilities, industrial users, and liquefied natural gas exporters, for sale of products we elect to take in-kind in lieu of monetary settlement for our leasehold sales. Our share of natural gas production from non-operated properties is generally marketed at the discretion of the operators.

For the year ended December 31, 2018, sales to Valero Energy Corporation and its affiliates accounted for approximately 12% of our total crude oil and natural gas revenues. No other purchaser accounted for more than 10% of our total crude oil and natural gas revenues for 2018. 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 purchasers in various regions.

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 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 in~~depressed commodity prices in recent years, the number of providers of materials and services has decreased in the regions where we operate. 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

~~Our~~All 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 our operations and may increase the cost of doing business and reduce our profitability. In addition, because public policy changes affecting the crude oil and natural gas industry are commonplace and because laws, rules and regulations may be enacted, amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws, rules and regulations. We do not expect future legislative or regulatory initiatives will affect us materially different than they ~~would~~will affect our similarly situated competitors.

The following is a discussion of certain significant laws, rules and regulations, as amended from time to time, that may affect us in the areas in which we operate.

Regulation of sales and transportation of crude oil and natural gas liquids

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

We transport most of our operated crude oil production to market centers using a combination of trucks and pipeline transportation facilities owned and operated by third parties. The U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration establishes safety regulations relating to transportation of crude oil by pipeline. Further, our sales of crude oil are affected by the availability, terms and costs of transportation. The transportation of crude oil and natural gas liquids ("NGLs") is subject to rate and access regulation. The Federal Energy Regulatory Commission (“FERC”) regulates interstate crude oil and NGL pipeline transportation rates under the Interstate Commerce Act and the Energy Policy Act of ~~1992. In general, pipeline rates must be just~~1992, and ~~reasonable and must not be unduly discriminatory or confer any undue preference upon any shipper. Intrastate~~intrastate 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 such transportation rates will not affect us in a way that materially differs from the effect on our similarly situated competitors.

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

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 legislation eliminating the ban on crude oil exports beginning in January 2016. From time to time we may sell our operated crude oil production at market centers in the United States to third parties who then subsequently export and sell the crude oil in international markets. The International Maritime Organization ("IMO"), an agency of the United Nations, has issued regulations requiring the maritime shipping industry to gradually reduce its carbon emissions over time by mandating a 1% improvement in the efficiency of fleets each year between 2015 and 2025. In conjunction with this initiative, the IMO ~~has~~ issued regulations requiring ship owners to lower the concentration of the sulfur content used in their fuels from 3.5% to 0.5% beginning inon January 1, 2020. To achieve ~~this goal,~~and maintain compliance with the new regulations, it is expected ship owners will either have to switch to more expensive higher quality marine fuel, ~~invest in~~install and utilize emissions-cleaning systems, or switch to alternative fuels such as liquefied natural gas. ~~Third party compliance~~Failure to comply with the ~~IMO's shipping~~ regulations may result in fines or shipping vessels being detained, thereby resulting in exportation capacity constraints ~~during the period in which tanker fleets are retrofitted to meet specifications, thereby inhibiting~~that inhibit a third party's ability to transport and sell ~~our~~domestic crude oil production overseas, which may have a material impact on the markets and prices for various grades of domestic and international crude oil.

The ultimate long-term impact of the IMO regulations is uncertain.

We do not own or operate pipeline or rail transportation facilities, rail cars, or infrastructure used to facilitate the exportation of crude oil. However, regulations that impact the domestic transportation of crude oil could increase our costs of doing business

and limit our ability to transport and sell our crude oil at market centers throughout the United States. We do not expect such regulations will affect us in a materially different way than similarly situated competitors.

Regulation of sales and transportation of natural gas

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

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

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

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

Regulation of production

The production of crude oil and natural gas is regulated by a wide range of federal, state, and local laws, rules, ~~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.

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

Environmental regulation

~~General~~.General. We are subject to stringent and complex 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 ~~below~~to 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, the U.S. Congress and federal and state legislators and agencies frequently revise environmental laws, rules and regulations and ~~any~~with party control of Congress shifting in January 2021, there is potential for the Biden Administration to pursue new legislation and regulatory initiatives that revise the permitting or leasing policies pursued under the Trump Administration that could adversely affect the oil and gas industry. Moreover, President Biden has issued, and may continue to issue, executive orders in pursuit of his regulatory agenda. Any changes that result in more stringent and costly waste handling, disposal, cleanup and remediation requirements for the crude oil and natural gas industry or restrict, delay or ban oil and gas permitting or leasing on federal lands could have a significant impact on our operating costs and production of oil and gas.

Failure to comply with these and other laws, rules and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of corrective or remedial obligations or the incurrence of capital expenditures, the occurrence of restrictions, delays or cancellations in the permitting, development or ~~performance~~expansion 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 that apply to our operations.

Air emissions and climate change. Federal, state, and local laws, rules, and regulations have been and, ~~may~~in the future, will likely be enacted to address concerns about emissions of regulated air pollutants, including the potential effects of carbon dioxide, methane and other identified “greenhouse gas” emissions on the environment and climate worldwide, generally referred to as “climate change.” For example, ~~in October~~since 2015 the U.S. Environmental Protection Agency ("EPA") ~~revised~~under the Obama Administration has made revisions to the National Ambient Air Quality Standard (“NAAQS”) for ground-level ozone, ~~from 75~~making the standard stricter. Since that time, the EPA under the Trump Administration has issued attainment and nonattainment designations and, on December 31, 2020, published notice of a final action, upon conducting a periodic review of the ozone standard, electing to ~~70 parts per billion for both~~retain the ~~8-hour primary~~2015 ozone NAAQS in 2020 without revision on a going-forward basis. However, this December 2020 final action is subject to legal challenge, and ~~secondary standards.~~the NAAQS may be subject to further revision under the Biden Administration. State implementation of the revised NAAQS for ground-level ozone could result in stricter permitting requirements, a delay or ~~prohibit~~prohibition on our ability to obtain such permits, ~~and~~or result in increased expenditures for pollution control equipment, the costs of which could be significant.

With respect to climate change and the control of greenhouse gas emissions, ~~recent federal~~numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit existing emissions of greenhouse gases as well as to restrict or eliminate future emissions. Federal regulatory initiatives have focused on establishing construction and operating permit reviews for greenhouse gas emissions from certain large stationary sources, requiring the monitoring and annual reporting of greenhouse gas emissions from certain petroleum and natural gas system sources, and reducing methane emissions from oil and gas operations through limitations on venting and flaring and the implementation of enhanced emission leak detection and repair requirements. For example, in ~~June~~ 2016 the EPA under the Obama Administration finalized new regulations (New Source Performance Standard 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 facilities. However, in recent years following the beginning of the Trump Administration in 2017, the EPA has undertaken several measures to delay implementation of the methane standards. Recently, in September 2020, the EPA issued

its final policy and technical amendments to the 2016 final rule. The ~~U.S. Department~~policy amendments, effective September 14, 2020, notably removed the transmission and storage sector from the regulated source category and rescinded methane and volatile organic compound requirements for the remaining sources that were established by former President Obama's Administration, whereas the technical amendments, effective November 16, 2020, included changes to fugitive emissions monitoring and repair schedules for gathering and boosting compressor stations and low-production wells, recordkeeping and reporting requirements, and more. Various states and industry and environmental groups are separately challenging both the original 2016 standards and the EPA’s September 2020 final rules and on January 20, 2021, President Biden issued an executive order that, among other things, directed the EPA to reconsider the technical amendments and issue a proposed rule suspending, revising or rescinding those amendments by no later than September 2021. A reconsideration of ~~Interior’s Bureau~~the September 2020 policy amendments is expected to follow. The January 20, 2021 executive order also directed the establishment of ~~Land Management (“BLM”) finalized similar regulations in November 2016 for~~ new methane and volatile organic compound standards applicable to existing oil and gas operations, including the production, transmission, processing and storage segments. 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 for nations to limit their greenhouse gas emissions through individually-determined reduction goals every five years after 2020. While the United States withdrew from the Paris Agreement under the Trump Administration, on January 20, 2021 President Biden issued an executive order recommitting the United States to the Paris Agreement and calling for the federal ~~lands. Following~~government to begin formulating the ~~change in U.S. presidential administrations in 2016, there have been attempts~~United States’ nationally determined emissions reduction goal under the agreement. With the United States recommitting to ~~modify these regulations, and litigation concerning~~ the ~~regulations is ongoing. As a result, we cannot predict~~Paris Agreement, executive orders may be issued or federal legislation or regulatory initiatives may be adopted to achieve the ~~scope of any final methane-related regulatory requirements or the cost~~agreement’s goals, which could require us to incur increased costs to comply with such requirements. ~~Some states have also imposed similar regulations on oil and~~

In addition, increasing concern over the threat of climate change arising from greenhouse gas operations, and it is possible new methane emission standards could be proposed in the future. However, we do not expect such measures will 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 agreeingemissions has given rise to a ~~monitoring~~series of political, litigation, and ~~review process~~financial risks associated with the production and processing of hydrocarbons and emission of greenhouse gas emissions. The agreement includes binding and non-binding elements and did not require ratification by the U.S. Congress. Following the change in U.S. presidential administrations, in August 2017 the U.S. State Department officially informed the United Nations of the intent ofgases. In addition to recommitting the United States to ~~withdraw from~~ the Paris Agreement, on January 20, 2021, the Acting Secretary of the U.S. Department of the Interior issued an order, effective immediately, that suspends new crude oil and natural gas leases and drilling permits on non-Indian federal lands and waters for a period of 60 days. Building on this suspension, President Biden issued an executive order on January 27, 2021 that suspends new leasing activities for oil and gas exploration and production on non-Indian federal lands and offshore waters pending completion of a comprehensive study of federal oil and gas permitting and leasing practices that take into consideration potential climate ~~agreement.~~and other impacts associated with oil and gas activities on such lands and waters. As of December 31, 2020, we held approximately 41,800 net undeveloped acres on federal lands.

The January 20, 2021 and January 27, 2021 executive orders do not apply to existing leases and the January 27, 2021 order further directs applicable agencies to eliminate subsidies for the oil and gas sector. Legal challenges to these orders are expected, with at least one industry group already filing a lawsuit in January 2021 in Wyoming federal district court and seeking to have the moratorium on leasing declared invalid. Litigation risks are also increasing, as a number of states, municipalities and other parties have sought to bring suit against the largest oil and natural gas exploration and production companies in state or federal court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to global warming effects, such as rising sea levels, and therefore are responsible for roadway and infrastructure damages, or that the companies have been aware of the adverse effects of climate change for some time but failed to adequately disclose those impacts. There are also increasing financial risks for oil and gas producers, as stockholders and bondholders currently invested in energy companies 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 issues and some of them may elect not to provide funding for energy companies. Limitation of investments in and financings for oil and gas producers could result in reduced access to capital, higher costs of capital and the restriction, delay, or cancellation of development and production activities.

While we cannot predict the outcome of legislative or regulatory initiatives related to climate change, we anticipate that initiatives to reduce greenhouse gas emissions will continue to develop. The adoption of state or federal legislation or regulatory programs to reduce greenhouse gas emissions, including methane and carbon dioxide, could require us to incur increased operating costs, such as costs to purchase and operate emissions monitoring and control systems, to acquire emissions allowances, or comply with new regulatory or reporting requirements. ~~Any such legislation~~Additionally, political, litigation, and financial risks may result in restrictions or ~~regulatory programs could also increase~~cancellations in development and production activities, liability for infrastructure damages due to climate changes, or increases in the cost of consuming hydrocarbons and thereby ~~reduce~~reducing demand for ~~the~~ crude oil and natural gas. Moreover, the increased competitiveness of alternative energy sources (such as wind, solar, geothermal, tidal and biofuels) could reduce demand for hydrocarbons, including the oil and gas we ~~produce. Consequently, legislation~~produce, which could lead to a reduction in our revenues. Also, there is the possibility that financial institutions will be required to adopt policies that limit funding for energy companies as President Biden recently signed an executive order calling for the development of a climate finance plan and, ~~regulatory programs to reduce~~separately, the

Federal Reserve announced that it has joined the Network for Greening the Financial System, a consortium of financial regulators focused on addressing climate-related risks in the financial sector. Finally, increasing concentrations of greenhouse gas ~~emissions~~in the Earth's atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods, rising sea levels and other climatic events. Consequently, one or more of these developments could have an adverse effect on our business, financial condition, results of operations, and cash flows.

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

In addition, NDIC rules for new drilling permit applications also require the submission of gas capture plans ~~addressing measures~~setting forth plans taken by operators to capture and not flare produced gas, regardless of whether it has been or will be connected within the first year of production. The NDIC currently requires us to capture ~~88%~~91% of the natural gas produced from a ~~field,~~field. If an operator is unable to attain the applicable gas capture percentage goal at maximum efficient rate, wells will be restricted in production to 200 barrels of crude oil per day if at least 60% of the monthly volume of associated natural gas produced from the well is captured, or otherwise crude oil production from such wells is not permitted to exceed 100 barrels of crude oil per day. However, the NDIC will consider temporary exemptions from the foregoing restrictions or for other types of extenuating circumstances after notice and ~~beginning November 1, 2020~~hearing if the ~~target~~effect is a significant net increase in gas capture ~~rate increases~~within one year of the date such relief is granted. Monetary penalty provisions also apply under this regulation if an operator fails to ~~91%.~~timely file for a hearing with the NDIC upon being unable to meet such percentage goals or if the operator fails to timely implement production restrictions once below the applicable percentage goals. Ongoing compliance with the NDIC’s flaring requirements or the imposition of any additional limitations on flaring could result in increased costs and have an adverse effect on our operations.

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

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

At the federal level, the EPA has asserted federal regulatory authority pursuant to the federal Safe Drinking Water Act ("SDWA") over certain hydraulic fracturing activities involving the use of diesel fuels and published permitting guidance ~~in February 2014~~ related to such activities. ~~In June 2016,~~Also, the EPA ~~finalized~~has issued a final regulation under the Clean Water Act prohibiting discharges to publicly owned treatment works of wastewater from onshore unconventional oil and gas extraction facilities. ~~It has~~We do not ~~been our practice to~~ discharge wastewater to publicly owned treatment works, so the impact of this regulation on us is not currently, and is not expected to be, material.

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

In ~~March 2015,~~2016, the BLM ~~issued~~under the Obama Administration published final rules related to the regulation of hydraulic fracturing activities on federal lands, including requirements for chemical disclosure, well bore integrity, and handling of flowback water. However, the BLM ~~subsequently rescinded~~under the ~~rules~~Trump Administration published a final rule rescinding the 2016 final rule in ~~December 2017.~~November 2018. Litigation challenging the BLM's ~~rescission~~2016 final rule as well as its 2018 final rule rescinding the 2016 rule has been ~~filed~~pursued by ~~certain~~various states and industry and environmental ~~groups~~groups. While a California federal court vacated the 2018 final rule in July 2020, a Wyoming federal court subsequently vacated the 2016 final rule in October 2020 and, ~~remains ongoing. As of December 31, 2018, we held approximately 59,700 net undeveloped acres~~accordingly, the 2016 final rule is no

longer in effect. The Wyoming decision is expected to be appealed. Moreover, the BLM under a Biden Administration could seek to pursue regulatory initiatives that regulate hydraulic fracturing activities on federal ~~land, representing approximately 11%~~lands.

While the U.S. Congress has from time to time considered but refused to adopt federal regulation of ~~our total net undeveloped acres.~~hydraulic fracturing, there is a possibility that a Biden Administration will pursue such legislation. In addition to pursuing the revision of existing laws and regulations, President Biden has issued, and may continue to issue, additional executive orders in pursuit of his regulatory agenda with regards to limiting hydraulic fracturing.

In addition, regulators in states in which we operate have adopted ~~or 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 curtailment or even suspension of operations in the event of concurrent seismic events within a particular radius of operations of a magnitude exceeding 2.5 on the Richter scale. If seismic events exceeding the OCC guidance thresholds were to occur near our active stimulation operations on a frequent basis, they could have an adverse effect on our operations.

Waste water disposal. Underground injection wells are a predominant method for disposing of waste water from oil and gas activities. In response to seismic events near underground injection wells used for the disposal of oil and gas-related waste waters, federal and some state agencies ~~are investigating~~have investigated whether such wells have caused increased seismic activity. ~~Some~~To address concerns regarding seismicity, some states, including states in which we operate, have ~~delayed~~pursued remedies that included delaying permit approvals, ~~mandated~~mandating a reduction in injection volumes, or ~~have shut~~shutting down or ~~imposed~~imposing moratoria on the use of injection wells. ~~Regulators~~Moreover, regulators in states in which we operate ~~are considering~~have implemented additional requirements related to seismicity. For example, the OCC has adopted rules for operators of saltwater disposal wells in certain seismically-active areas in the Arbuckle formation of Oklahoma. These rules require, among other things, that

disposal well operators conduct mechanical integrity testing or make certain demonstrations of such wells’ respective depths that, depending on the depth, could require plugging the well and/or the reduction of volumes disposed in such wells. Oklahoma utilizes a “traffic light” system wherein the OCC reviews new or existing disposal wells for proximity to faults, seismicity in the area and other factors in determining whether such wells should be permitted, permitted only with special restrictions, or not permitted. At the federal level, the EPA’s current regulatory requirements for such wells do not require the consideration of seismic impacts when issuing permits. We cannot predict the EPA’s future actions in this regard.

The introduction of new environmental ~~initiatives~~laws and regulations related to the disposal of wastes associated with the exploration, development or production of hydrocarbons could limit or prohibit our ability to utilize underground injection wells. A lack of waste water disposal sites could cause us to delay, curtail or discontinue our exploration and development plans. Additionally, increased costs associated with the transportation and disposal of produced water, including the cost of complying with regulations concerning produced water disposal, may reduce our profitability. These costs are commonly incurred by oil and gas producers and we do not ~~believe~~expect the costs associated with the disposal of produced water will have a material adverse effect on our operations to any greater degree than other similarly situated competitors. In recent years, we have increased our operation and use of water recycling and distribution facilities 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. ~~Although we believe~~Historically, our ~~continued~~environmental compliance ~~with existing requirements will~~costs have not ~~have~~had a material adverse impact on our financial condition and results of ~~operations, we cannot assure you the passage of more stringent laws or regulations~~operations; however, there can be no assurance that such costs will not be material in the future or that such future compliance will not ~~materially~~have a material impact on our business, financial condition, results of operations or cash flows.

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

Human Capital

Employees and Labor Relations

As of December 31, ~~2018,~~2020, we employed ~~1,221 people. Our future success will depend partially on~~1,201 people, all of which were employed in the United States, with 716 employees being located at our ~~ability~~corporate headquarters in Oklahoma City, Oklahoma and 485 employees located in our field offices located in Oklahoma, North Dakota, South Dakota, and Montana. 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 not~~align our employee’s interests with those of our shareholders by making annual restricted stock awards to virtually all of our employees. We reward our employees for their performance in helping the Company achieve its annual business and strategic objectives through our bonus program, which is also available to virtually all of our employees. In order to ensure our compensation package remains competitive and fulfills our goal of recruiting and retaining talented employees, we consider competitive market compensation paid by other companies comparable to the Company in size, geographic location, and operations.

Safety

Safety is our highest priority and one of our core values. We promote safety with a ~~party to any collective bargaining agreements~~robust health and ~~have not experienced any strikes or work stoppages. We consider~~safety program that includes employee orientation and training, contractor management, risk assessments, hazard identification and mitigation, audits, incident reporting and investigation, and corrective/preventative action development.

Through our ~~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 ~~utilize~~developed this program to leverage and continuously improve our ability to identify and prevent reoccurrence of unsafe behaviors and conditions. This program recognizes and rewards any employee or contractor working on one of our locations who observes and reports 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 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 ~~services~~number of ~~independent~~recordable incidents per 100 full-time employees and contractors during a one year period, has decreased sequentially in each of the past three years and measured 0.40 for 2020, a 53% decrease compared to ~~perform~~2017.

Training and Development

We are committed to the training and development of our employees. We believe that supporting our employees in achieving their career and development goals is a key element of our approach to attracting and retaining top talent. We have invested in a variety of resources to support employees in achieving their career and development goals, including developing learning paths for individual contributors and leaders, creating the Continental Leadership Learning Center which offers numerous different instructor-led programs which foster employee development and acquiring 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 ~~field~~benefit programs designed to promote the health and well-being of our employees and their families. These benefits include medical, dental, and vision insurance plans; disability and life insurance plans; paid time off for holidays, vacation, sick leave, and other ~~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 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.

In response to the COVID-19 pandemic, commencing in the first quarter of 2020, we have taken, and continue to take, proactive measures to protect the health and safety of our employees. These measures have included the implementation of a voluntary testing program to provide our employees and their household members with reliable and timely test results when

public testing options were limited and restricted, maintaining social 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, suspending employee business travel, requiring employees to complete daily self-screening questionnaires, performing temperature checks, frequently and extensively disinfecting common areas, performing rigorous contact tracing protocols, 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 recognize that a diverse workforce provides the best opportunity to obtain unique perspectives, experiences, ideas, and solutions to help our business succeed. To that end, 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. Further, we forbid retaliation against any individual who reports, claims, or makes a charge of discrimination or harassment, fraud, unethical conduct, or a violation of our Company policies. To sustain and promote an inclusive culture, we 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 require all employees to complete periodic training sessions on various aspects of our Code of Business Conduct and Ethics and other corporate policies through an annual acknowledgement and certification process. We evaluate ways to enhance awareness of diversity and inclusion on an ongoing basis in an effort to continue improving our approach.

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 SEC maintains an internet website that contains reports, proxy and information statements, and other information registrants file with the SEC. The address of the SEC’s website is www.sec.gov.

Our principal executive offices are located at 20 N. Broadway, Oklahoma City, Oklahoma 73102, and our telephone number at that address is (405) 234-9000.


~~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, rate of growth, and carrying value of our properties. Crude oil and natural gas are commodities and prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for crude oil and natural gas have been volatile and unpredictable. For example, during ~~2018~~2020 the NYMEX West Texas Intermediate (“WTI”) crude oil and Henry Hub natural gas spot prices ranged from ~~approximately $44~~negative $36.98 to ~~$77~~positive $63.27 per barrel and ~~$2.49~~$1.33 to ~~$6.24~~$3.14 per MMBtu, respectively. Commodity prices will likely remain volatile and unpredictable in ~~2019~~2021 and beyond.

~~We have hedged the majority~~ A significant portion of our ~~forecasted 2019 natural gas production. Our~~ future crude oil and natural gas production is ~~currently~~ unhedged as of the time of this filing and is ~~directly~~ exposed to continued volatility in market prices, whether favorable or unfavorable.

The prices we receive for sales of our production depend on numerous factors beyond our control. These factors include, but are not limited to, the following:

•worldwide, domestic, and regional economic conditions impacting the supply of, and demand for, crude oil, natural gas, and natural gas liquids;

•the actions of the Organization of Petroleum Exporting Countries and other petroleum producing nations;

•the nature, extent, and ~~extent~~impact of domestic and foreign governmental laws, regulations, and taxation, including environmental laws and regulations governing the imposition of trade restrictions and tariffs;

•executive, regulatory or legislative actions by Congress, the Biden Administration, or states in which we operate;

•geopolitical events and conditions, including domestic political uncertainty or foreign regime changes that impact government energy policies;

•the level of global, national, and regional crude oil and natural gas exploration and production activities;

•the level of global, national, and regional crude oil and natural gas inventories, which may be impacted by economic sanctions applied to certain producing nations;

•the level and effect of speculative trading in commodity futures markets;

•the relative strength of the United States dollar compared to foreign currencies;

•the price and quantity of imports of foreign crude oil;

•the price and quantity of exports of crude oil or liquefied natural gas from the United States;

•military and political conditions in, or affecting other, crude oil-producing and natural gas-producing nations;

•localized supply and demand fundamentals;

•the cost and availability, proximity and capacity of transportation, processing, storage and refining facilities for various quantities and grades of crude oil, natural gas, and natural gas liquids;

•adverse weather 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 emission limitations or other environmental protection efforts; and

•the price and availability of alternative fuels or other energy sources.

Sustained material declines in commodity prices reduce cash flows available for capital expenditures, repayment of indebtedness and other corporate purposes; may limit our ability to borrow money or raise additional capital; and may reduce our proved reserves and the amount of crude oil and natural gas we can economically produce.

In addition to reducing our revenue, cash flows and earnings, depressed prices for crude oil and/or natural gas may adversely affect us in a variety of other ways. If commodity prices decrease substantially, some of our exploration and development projects could become uneconomic, and we may also have to make significant downward adjustments to our estimated proved reserves and our estimates of the present value of those reserves. If these price effects occur, or if our estimates of production or economic factors change, accounting rules may require us to write down the carrying value of our crude oil and/or natural gas properties.

Lower commodity prices may also lead to reductions in our drilling and completion programs, which may result in insufficient production to satisfy our transportation and processing commitments. If production is not sufficient to meet our commitments we would incur deficiency fees that would need to be paid absent any cash inflows generated from the sale of production.

Lower commodity prices may also reduce our access to capital and lead to a downgrade or other negative rating action with respect to our credit rating. A downgrade of our credit rating could negatively impact our cost of capital, increase ~~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 planned~~meet our capital ~~expenditures~~expenditure needs and commitments.

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

The Organization of Petroleum Exporting Countries ("OPEC") is an intergovernmental organization that seeks to manage the price and supply of crude oil on the global energy market. Actions taken by OPEC members, including those taken alongside other oil exporting nations such as Russia, may have a significant impact on global oil supply and pricing. For example, OPEC and certain other oil exporting nations have previously agreed to take measures, including production cuts, to support crude oil prices. However, in March 2020, members of OPEC and Russia were unable to agree on production levels and, in response, Saudi Arabia announced it would significantly increase production and cut the ~~financial markets or in global~~prices at which it sold crude oil. These actions, coupled with the economic ~~factors, including consequences resulting from international trade disputes and tariffs, could adversely~~ impact ~~our business.~~

~~United States and global economies may experience periods of volatility~~ and uncertainty from ~~time~~the COVID-19 pandemic, led to ~~time,~~a sudden and drastic decrease in crude oil prices in March 2020, which materially impacted our business, results of operations, and cash flows. It is not certain what impact current or future agreements or disagreements among these parties will have on crude oil prices, particularly in light of the significant decrease in crude oil demand resulting from the COVID-19 pandemic. There can be no assurance that OPEC members and other oil exporting nations will comply with agreed-upon production cuts, agree to further production cuts in ~~unstable consumer confidence, diminished consumer demand~~the future, or utilize other actions to support and ~~spending, diminished liquidity and credit availability, and inability~~stabilize oil prices, nor can there be any assurance they will not increase production or deploy other actions aimed at reducing oil prices. Uncertainty regarding future actions to ~~access capital markets. In recent years, certain global economies have experienced periods~~be taken by OPEC members or other oil exporting countries could lead to increased volatility in the price of political uncertainty, slowing economic growth, rising interest rates, changing economic sanctions, 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,oil, which ~~in turn~~ could have a material adverse effect on our business, financial condition, results of operations, and cash flows.

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

The ~~current administration in the United States~~COVID-19 pandemic has expressed concerns in recent years about imports from countries it perceives are engaging in unfair trade practices. In 2018, the United States government initiated tariffs on certain imported goodsnegatively impacted, and ~~has raised the possibility of imposing tariff increases on such goods or expanding the scope of tariffs~~will likely continue to include other types of imported goods. In response, certain foreign governments, most notably China, have imposed retaliatory tariffs on certain goods their countries import from the United States. These and other events, including the United Kingdom's potential withdraw from the European Union, have contributed to increased economic uncertainty and diminished expectations fornegatively impact, the global ~~economy.~~

~~Trade restrictions or~~economy which has led to, among other governmental actions related to tariffs or trade policies have impacted, and have the potential to further impact, our business and industry. For instance, in 2018 the United States government imposed import tariffs of 25% on steel products and 10% on aluminum products, as well as quantitative restrictions on imports of steel and aluminum products from various countries. The oil and gas industry in the United States utilizes significant amounts of steel in the drilling and completion of new wells and for construction of facilities, pipelines, processing plants, and refineries. The steel required to meet the needs of our industry may not be domestically available in sufficient quantities, particularly in periods of favorable commodity prices. Thus, current and future tariffs may increase the cost of materials used in various aspects of upstream, midstream, and downstream oil and gas activities which, in turn, could increase our cost of doing business. Furthermore, the tariffs and quantitative import restrictions 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 increasing levels of 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 could have negative impacts on the domestic andthings, reduced global ~~economies overall, which could result in reduced~~ demand for crude oil, disruption of global supply chains, and ~~natural gas. Any~~significant volatility and disruption of financial and commodity markets.

We began to experience material decreases in our revenues in the ~~above consequences could have a material adverse effect on~~first quarter of 2020, which negatively impacted our business, financial condition, results of operations, cash flows and ~~cash flows.~~outlook during 2020. The adverse effects of COVID-19 included or may in the future include the following:

•Historically low 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;

•Our ability to repay or refinance indebtedness, increase our credit facility commitments, borrow money, or raise capital;

•Disruptions in energy industry supply chains;

•Credit losses due to insolvency of customers, joint interest owners, and counterparties;

•Cyber incidents or information security breaches resulting in information theft, data corruption, operational disruption, and/or financial loss as a consequence of employees accessing information from remote work locations; and

•Shortages of drilling rigs, well completion crews, field services, personnel, and equipment in future periods of commodity price recovery.

The extent to which COVID-19 and depressed crude oil prices impacts our results of operations, financial position and liquidity will depend on future developments, which are uncertain and cannot be predicted, including but not limited to, the availability of effective treatments and vaccines, the ultimate duration of the pandemic, and how quickly and to what extent normal economic and operating conditions can resume. Therefore, the degree and duration of the adverse financial impact of the pandemic cannot be reasonably estimated at this time.

Our producing properties are located in limited geographic areas, making us vulnerable to risks associated with having geographically concentrated operations.

A ~~substantial~~significant portion of our producing properties is located in the Bakken field of North Dakota and Montana, with that area comprising ~~approximately 56%~~53% of our crude oil and natural gas production and ~~approximately 68%~~61% of our crude oil and natural gas revenues for the year ended December 31, ~~2018.~~2020. Approximately ~~52%~~46% of our estimated proved reserves were located in the Bakken as of December 31, ~~2018.~~2020. 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%~~45% of our crude oil and natural gas production and ~~approximately 27%~~35% of our crude oil and natural gas revenues for the year ended December 31, ~~2018.~~2020. Approximately ~~45%~~52% of our estimated proved reserves were located in Oklahoma as of December 31, ~~2018.~~2020.

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) our reliance on a limited number of pipelines to deliver our production to markets, (ii) the prices of crude oil and natural gas produced from wells in the regions and other

regional supply and demand factors, including gathering, pipeline and rail transportation capacity constraints; ~~(ii)~~(iii) the availability of rigs, completion crews, waste water disposal wells, equipment, field services, water, supplies, and labor; ~~(iii)~~(iv) the availability of processing and refining facilities; and ~~(iv)~~(v) infrastructure capacity. In addition, our operations in the Bakken field and Oklahoma may be adversely affected by severe weather events such as floods, blizzards, extreme cold, ice storms, drought, and tornadoes, 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, cyber attacks, 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.

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

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

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

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

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

•abnormal pressure or irregularities in geological formations;

•shortages of or delays in obtaining equipment or qualified personnel;

•shortages of or delays in obtaining components used in fracture stimulation processes such as water and proppants;

•delays associated with suspending our operations to accommodate nearby drilling or completion operations being conducted by other operators;

•mechanical difficulties, fires, explosions, equipment failures or accidents, including ruptures of pipelines or storage facilities, or train derailments;

•restrictions on the use of underground injection wells for disposing of waste water from oil and gas activities;

•political events, public protests, civil disturbances, terrorist acts or cyber attacks;

•decreases in, or extended periods of low, crude oil and natural gas prices;

•title problems;

•environmental hazards, such as uncontrollable flows of crude oil, natural gas, brine, well fluids, hydraulic fracturing fluids, toxic gas or other pollutants into the environment, including groundwater and shoreline contamination;

•adverse weather 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, 2020.

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

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

You should not assume the present value of future net revenues from our proved reserves is the current market value of our estimated crude oil and natural gas reserves. We base the estimated discounted future net revenues from proved reserves on the 12-month unweighted arithmetic average of the first-day-of-the-month commodity prices for the preceding twelve months. Actual future prices may be materially higher or lower than the average prices used in the calculations. In addition, the use of a 10% discount factor, which is required by the SEC to be used to calculate discounted future net revenues for reporting purposes, may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with our reserves or the crude oil and natural gas industry. For the year ended December 31, 2020, average prices used to calculate our estimated proved reserves were $39.57 per Bbl for crude oil and $1.99 per MMBtu for natural gas ($34.34 per Bbl for crude oil and $1.17 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, 2021 and February 1, 2021 averaged $51.04 per barrel and $2.53 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.

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, 2020, approximately 43% 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, 2020 includes estimates of total future development costs over the next five years associated with our proved undeveloped reserves of approximately $3.9 billion. We cannot be certain the estimated costs of the development of these reserves are accurate, development will occur as scheduled, or the results of such development will be as estimated. If we choose not to spend the capital to develop these reserves, or if we are not otherwise able to successfully develop these reserves as a result of our inability to fund necessary capital expenditures or otherwise, we will be required to remove the associated volumes from our reported proved reserves. Proved undeveloped reserves generally must be drilled within five years from the date of initial booking under SEC reserve rules. Changes in the timing of development plans that impact our ability to develop such reserves in the required time frame have resulted, and will likely in the future result, in fluctuations in reserves between periods as reserves booked in one period may need to be removed in a subsequent period. In 2020, 107 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 primarily due to a reduction in the scope of our future drilling programs based on adverse market conditions, reduced demand, and lower prices caused by the COVID-19 pandemic.

Additionally, unless production is established within the spacing units covering the undeveloped acres on which some of the locations are identified, the leases for such acreage will expire. If we are not able to renew leases before they expire, any proved undeveloped reserves associated with such leases will be removed from our proved reserves. The combined net acreage expiring in the next three years represents 50% of our total net undeveloped acreage at December 31, 2020. At that date, we had leases representing 61,293 net acres expiring in 2021, 69,609 net acres expiring in 2022, and 49,475 net acres expiring in 2023.

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

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

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

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

that impact the transportation or exportation of our production may increase our costs of doing business and inhibit a third party's ability to transport and sell our production, whether domestically or internationally, the consequences of which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

On July 6, 2020, the U.S. District Court for the District of Columbia ruled that the U.S. Army Corps of Engineers (“Corps”), which had previously issued an easement near tribal lands allowing the Dakota Access Pipeline (“DAPL”) to cross a water body, had failed to adequately consider the environmental impacts under the National Environmental Protection Act (“NEPA”) arising out of such pipeline crossing this water body, and directed the Corps to prepare a new environmental impact statement (“EIS”) as well as ordering the owners of DAPL to shut down the pipeline pending completion of the EIS. The DAPL is owned and operated by a third party and carries Bakken-produced crude oil from North Dakota to Illinois. The pipeline owner sought an emergency stay of the shut-down order from the U.S. Court of Appeals for the District of Columbia Circuit (the “Appeals Court”). On July 14, 2020, the Appeals Court issued a temporary administrative stay of such order, which has allowed the pipeline to continue operating. On January 26, 2021, the Appeals Court affirmed that part of the lower court decision vacating the Corps’ easement while it prepares a new EIS, but reversed the lower court’s order to shut down the pipeline because the lower court had not properly evaluated such a move under an applicable NEPA factoring test established under case law. As stated by the Appeals Court, the Corps is within its authority to shut down the pipeline and the Appeals Court would expect the Corps to make that decision “promptly.” On February 9, 2021, the Corps, through the Department of Justice, sought a delay of the proceedings to give lawyers time to brief the new presidential administration on the background of the DAPL matter. Accordingly, the continued operation of DAPL in the future is uncertain. The Company utilizes DAPL to transport a portion of its North region crude oil production to ultimate markets on the U.S. gulf coast. Currently, the Company is committed to transport 3,550 barrels per day on the pipeline through February 2026 and has an additional commitment to transport an incremental 26,450 barrels per day for 7 years effective upon the pending completion of a DAPL expansion project which is estimated to occur in the second half of 2021. 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 ~~$2.6~~$1.40 billion for capital expenditures attributable to us in ~~2019~~2021 of which approximately ~~$2.2~~$1.11 billion is allocated to exploration and development activities. We may adjust our ~~2019~~2021 capital spending plans upward or downward depending on market conditions. Our ~~2019~~2021 capital budget, based on our current expectations of commodity prices and costs, is expected to be funded from operating cash ~~flows and, if necessary, through borrowings under our credit facility.~~flows. However, the sufficiency of our cash flows from operations ~~and access to capital are~~is subject to a number of variables, including but not limited to:

•the prices at which crude oil and natural gas are sold;

•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

•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, we may not be able to generate sufficient cash flows and may have limited ability to obtain the capital necessary to sustain our operations at current or planned levels. A decline in cash flows from operations may require us to revise our capital program or alter or increase our capitalization substantially through the issuance of debt or equity securities.

We have a revolving credit facility with lender commitments totaling $1.5 billion that matures in April 2023. 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.

~~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, 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.

~~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 may turn out to be inaccurate. Any material inaccuracies in our reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves. The Company’s current estimates of reserves could change, potentially in material amounts, in the future due to changes in commodity prices, business strategies, and other factors.

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, 2018.~~

In order to prepare reserve estimates, we must project production rates and the amount and timing of development expenditures. Proved undeveloped reserves generally must be drilled within five years from the date of initial booking under SEC reserve rules. Changes in the timing of development plans that impact our ability to develop such reserves in the required time frame have resulted, and will likely in the future result, in fluctuations in reserves between periods as reserves booked in one period may need to be removed in a subsequent period. In 2018, 234 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.

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.

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, 2018, average prices used to calculate our estimated proved reserves were $65.56 per Bbl for crude oil and $3.10 per MMBtu for natural gas($61.20 per Bbl for crude oil and $3.22 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, 2019 and February 1, 2019 averaged $50.34 per barrel and $3.03 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.~~

~~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.~~

~~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. 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 field services could adversely affect our ability to execute our exploration and development plans within budget and on a timely basis.

In the regions in which we operate, there have ~~historically~~ been shortages of drilling rigs, well completion crews, equipment, personnel, field services, and supplies, including key components used in fracture stimulation processes such as water and proppants, as well as high costs associated with these critical components of our operations. With current technology, water is an essential component of drilling and hydraulic fracturing processes. The availability of water sources and disposal facilities is becoming increasingly competitive, constrained, subject to social and regulatory scrutiny, and impacted by third-party supply chains over which we may have limited control. Limitations or restrictions on our ability to secure, transport, and use sufficient amounts of water, including limitations resulting from natural causes such as drought, could adversely impact our operations. In some cases, water may need to be obtained from new sources and transported to drilling or completion sites, resulting in increased costs.

The demand for qualified and experienced field service providers and associated equipment, supplies, and materials can fluctuate significantly, often in correlation with commodity prices, causing periodic shortages and/or higher costs. Such shortages or higher costs could delay the execution of our drilling and development plans or cause us to incur expenditures not provided for in our capital budget or to not achieve the rates of return we are targeting for our development program, all of which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

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

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

We ~~may incur substantial losses~~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 ~~be subject to substantial liability claims as a result~~involve third-party working interest owners. As of December 31, 2020, non-operated properties represented 14% of our ~~crude~~estimated proved developed reserves, 10% of our estimated proved undeveloped reserves, and 12% of our estimated total proved reserves. We have limited ability to influence or control the operations or future development of non-operated properties, including the marketing of oil and ~~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 associated~~production, compliance with ~~our business. Losses~~environmental, occupational safety and liabilities arising from uninsured and under-insured events could materially and adversely affect our business, financial condition or results of operations. Our activities are subject to all of the operating risks associated with drilling for and producing crude oil and natural gas, including the possibility of:

~~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~~health and other ~~environmental damage;~~

~~regulatory investigations~~regulations, or the amount of expenditures required to fund the development and ~~penalties;~~

~~suspension~~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 ~~operations;~~

~~repair~~dependence on the operators and ~~remediation costs;~~other working interest owners for these projects could cause us to incur unexpected future 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~~We may be subject to ~~drill may not produce crude oil or natural gas~~risks in ~~expected quantities.~~connection with acquisitions, divestitures, and joint development arrangements.

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. In this report, we describe someAs part of our ~~current prospects~~business strategy, we have made and ~~plans~~will likely continue to ~~develop our key operating areas. It is not possible to predict with certainty whether any particular prospect will produce crude~~make acquisitions of oil ~~or natural~~and gas ~~in sufficient quantities to recover drilling~~properties, divest assets, and ~~completion costs, achieve desired recoveries and rates of return, or be economically producible.~~enter into joint development arrangements. The ~~use of seismic data and other technologies and the study~~successful acquisition of producing ~~fields in the same area will~~properties requires an assessment of several factors, including but 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.limited to:

~~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.~~•recoverable reserves;

~~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;~~ prices and location and quality differentials;

•the ~~availability~~quality of ~~capital, drilling rigs, well completion crews,~~the title to acquired properties;

•future development costs, operating costs and ~~transportation~~property taxes; and ~~processing capacity; costs; drilling results; regulatory approvals;~~

•potential environmental 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~~liabilities.

The accuracy of these ~~uncertainties,~~acquisition assessments is inherently uncertain. In connection with these assessments, we ~~do not know if our potential drilling locations will ever~~perform a review, which we believe to 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 somegenerally consistent with industry practices, of the ~~locations~~subject properties. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities prior to acquisition. Inspections may not always be performed on every property, and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the ~~leases for such acreage will expire. Low commodity prices, reduced capital spending, lack~~seller of ~~available drilling and completion rigs and crews and numerous other factors, many~~the subject properties may be unwilling or unable to provide effective contractual protection against all or part of ~~which are beyond our control, could result in our failure to establish production on undeveloped acreage, and, if we~~the problems. We sometimes are not ~~able~~entitled 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 60% of our total net undeveloped acreage at December 31, 2018. At that date, we had leases representing 136,174 net acres expiring in 2019, 107,840 net acres expiring in 2020,contractual indemnification for environmental liabilities and ~~69,345 net acres expiring in 2021. Our actual drilling activities may materially differ from those presently identified, which could adversely affect our business.~~acquire properties on an “as is” basis.

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, 2018, approximately 56% 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, 2018 includes estimates of total future development costs over the next five years associated with our proved undeveloped reserves of approximately $9.2 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 generally 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 may occur in the future. A removal of such reserves could adversely affect our operations. In 2018, 234 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.~~

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

The value we receive for our crude oil and natural gas production depends in part on the availability, proximity and capacity of gathering, pipeline and rail systems and processing, refining, and export facilities owned by third parties. The inadequacy or unavailability of capacity on these systems and facilities could result in the shut-in of producing wells, the delay or discontinuance of development plans for properties, or higher operational costs associated with air quality compliance controls. Although we have some contractual control over the transportation of our products, changes in these business relationships or failure to obtain such services on acceptable terms could adversely affect our operations. If our production becomes shut-in for any of these or other reasons, we 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, refining, or export facilities due to labor disputes, maintenance, civil disturbances, international trade disputes, 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 or processing commitments or is hedged at lower than market prices, those commitments or financial hedges would have to be paid from borrowings in the absence of sufficient operating cash flows.

Our operated crude oil and natural gas production is ultimately transported to downstream market centers in the United States primarily using transportation facilities and equipment owned and operated by third parties. See ~~Part I, Item 1. Business—Regulation of the Crude Oil and Natural Gas Industry~~ ~~for a discussion of regulations impacting the transportation of crude oil and natural gas. From~~ time to time we may sell ~~our operated crude oil production at market centers in the United States to third parties who then subsequently export and sell the crude oil in international markets. We do not currently own~~ or ~~operate infrastructure used to facilitate the transportation and exportation~~otherwise dispose of ~~crude oil; however, third party compliance with regulations that impact the transportation or exportation~~certain assets as a result of an evaluation of our ~~production~~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 ~~increase our costs~~result in fewer potential bidders, unsuccessful sales efforts, and a higher risk that buyers may seek to terminate a transaction prior to closing. The occurrence of ~~doing business and inhibit a third party's ability to transport and sell our production, whether domestically or internationally,~~any of the ~~consequences of which~~matters described above could have ~~a material~~an adverse ~~effect~~impact on our business, financial condition, results of operations and cash flows.

~~Our business depends on~~Volatility in the ~~availability of water and the ability to dispose of waste water from oil and gas activities. Limitations~~financial markets 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 limitationsin global economic conditions, including consequences resulting from ~~natural causes such as drought), or to dispose of or recycle water after use,~~domestic political uncertainty, geopolitical events, international trade disputes and tariffs, and health epidemics could adversely impact our ~~operations. In some cases, water~~business.

United States and global economies may ~~need~~experience periods of volatility and uncertainty from time to ~~be obtained from new sources and transported to drilling or completion sites,~~time, resulting in ~~increased costs. Moreover, the introduction of new environmental initiatives~~unstable consumer confidence, diminished consumer demand and ~~regulations related~~spending, diminished liquidity and credit availability, and inability 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.

access capital markets. In ~~addition, concerns have been raised in~~ recent years, ~~about~~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 ~~potential for seismic events to occur from the use of underground injection wells, a predominant method for disposing of waste water from oil~~availability 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~~materials used in our ~~operations. Some states, including states~~industry, which 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, have imposed or are considering additional requirements related to seismicity. See ~~Part I, Item 1. Business—Regulation of the Crude Oil and Natural Gas Industry—Environmental regulation—Waste water disposal~~ ~~for further discussion of regulations that affect us.~~

Compliance with existing or new environmental laws, 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, whichturn 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.

~~We are subject~~Trade restrictions or other governmental actions related to ~~complex federal, state~~tariffs or trade policies have impacted, and ~~local laws~~have the potential to further impact, our business and ~~regulations that could adversely affect~~industry by increasing the cost ~~manner~~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 ~~feasibility~~cessation of ~~conducting our operations~~drilling and completion efforts or ~~expose us~~the postponement or cancellation of new pipeline transportation projects the U.S. industry is relying on to ~~significant liabilities.~~

~~Our~~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 exploration and production operations are subject to complex and stringent federal, state and local laws and regulations, including those governing environmental protection, occupational health and safety, the discharge of materials into the environment, and the protection of certain plant and animal species. See ~~Part I, Item 1. Business—Regulation~~gas. Any 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 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. Strict liability or joint and several liability may be imposed under certain laws, whichabove consequences 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, 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 laws or regulations, 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 laws and regulations 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, restrictions on transportation of production, new safety requirements, 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.

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. 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. 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. 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 status of such regulations. Undoing previously existing regulations has and likely will continue to involve lengthy notice-and-comment rulemaking, and the resulting decisions have been and likely will continue to be subject to litigation by opposition groups. Thus, the scope and impact of existing and potential future regulations remains substantially uncertain with respect to the implementation of climate-related public policies. However, given the long-term trend towards increasing regulation, future federal greenhouse gas regulations of the oil and gas industry remain possible, and certain states have separately imposed their own regulations on emissions from oil and gas production activities and other states may do so as well.

The implementation of, and compliance with, laws and 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. Moreover, activists concerned about the potential effects of climate change have directed their attention at sources of funding for energy companies, which has and may yet result in financial institutions, funds, and other sources of capital restricting or eliminating their investment in crude oil and natural gas activities. 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 laws and regulations 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 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 proposed and enacted laws and regulations have emerged which could 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 laws and regulations 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.

Future legislation may impose new taxes on crude oil or natural gas activities, including eliminating or reducing certain federal income tax deductions currently available with respect to crude oil and natural gas exploration and development.

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 were not impacted by the Tax Cuts and Jobs Act signed into law in the United States in December 2017. 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. Any such changes could adversely affect our business, financial condition, results of operations and cash flows.

~~We are involved in legal proceedings that~~A cyber incident could result in ~~substantial liabilities.~~information theft, data corruption, operational disruption, and/or financial loss.

~~Like~~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 ~~similarly-situated oil~~activities. The availability and ~~gas companies, we~~integrity of these systems are ~~from time~~essential for us to ~~time, involved~~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 ~~various legal proceedings~~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 of our systems and those of our business associates, may remain undetected for an extended period.

A cyber attack involving our information systems and related infrastructure, and/or that of our business associates, could disrupt our business and negatively impact our operations in ~~the ordinary course~~a variety of ~~business~~ways, including but not limited to ~~commercial disputes, claims~~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 ~~royalty and surface owners, property damage claims, personal injury claims, regulatory compliance matters, disputes with tax authorities, and other matters. The outcome~~remedial actions, loss 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 onebusiness, or ~~more such proceedings could result in substantial~~potential 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~~or cash flows. ~~Judgments~~

While the Company has established cyber security systems and ~~estimates~~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 ~~determine accruals related~~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 ~~other proceedings could change from period~~compliance matters which may impose significant costs that are likely to ~~period, and such changes could be material.~~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. ~~In addition, our competitors may be able~~Our inability to ~~offer better compensation packages to attract and retain qualified personnel than we are able to offer. We may not be able to~~effectively 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, whichthis environment 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 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 or a reduction in demand for our products. 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 or third party service providers need to conduct 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, floods, blizzards, extreme cold, drought, 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 regions.~~ The consequences of such events may include the evacuation of personnel; damage to and disruption of drilling rigs or transportation, processing, storage, refining, and export 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.

Terrorist activities could materially and adversely affect our business and results of operations.

Terrorist attacks and the threat of terrorist attacks, whether domestic or foreign attacks, as well as military or other actions taken in response to these acts, could cause instability in the global financial and energy markets. Continued hostilities abroad and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the global economy in unpredictable ways, including the disruption of energy supplies and markets, increased volatility in commodity prices or the possibility that infrastructure we rely on could be a direct target or an indirect casualty of an act of terrorism. Any of these events could materially and adversely affect our business and results of operations.

~~Regulations under the Dodd-Frank Act regarding derivatives~~Financial Risks

Our derivative activities could ~~have an~~result in financial losses or reduce our earnings.

To achieve more predictable cash flows and reduce our exposure to adverse ~~effect on our ability to use derivative instruments to reduce the effect of~~fluctuations in commodity ~~price risk and other risks associated with our business.~~

~~From~~prices, from time to time we may ~~use~~enter into derivative instruments for a potentially significant portion of our production. See Part II, Item 8. Notes to ~~manage~~Consolidated Financial Statements—Note 5. Derivative Instruments for a summary of our commodity ~~price risk. In 2010, the U.S. Congress adopted the Dodd-Frank Act, which, among other provisions, established federal oversight~~derivative positions as of December 31, 2020. Additionally, see Part II, Item 7. Management’s Discussion and ~~regulation~~Analysis of ~~the over-the-counter derivatives market~~Financial Condition and ~~required the Commodity Futures Trading Commission~~Results of Operations—Derivative Instruments for a summary of additional derivative instruments entered into subsequent to ~~promulgate a range of rules and regulations applicable to derivative transactions. If we~~December 31, 2020. We do not ~~qualify~~designate our derivative instruments as hedges for ~~an end user exemption from~~accounting purposes and we record all derivatives on our balance sheet at fair value. Changes in the ~~Dodd-Frank Act requirements, the new regulations could increase the cost of derivative contracts, reduce the availability~~fair value of derivatives ~~to protect against risks we encounter, reduce~~are recognized in earnings. Accordingly, 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. If our use of derivatives becomes limitedearnings may fluctuate materially as a result of changes in commodity prices and resulting changes in the ~~regulations,~~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 ~~results~~future production is based in part on our view of ~~operations may become more volatile~~current and future market conditions and our desire to stabilize cash flows ~~may be less predictable. While certain Dodd-Frank Act regulations are already in effect, certain aspects~~necessary for the development of ~~the rulemaking have been repealed or have not been finalized and the ultimate effect of the regulations on~~ our ~~business remains uncertain.~~

~~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, 2018, non-operated properties represented 19% of our estimated proved developed reserves, 12% of our estimated proved undeveloped reserves, and 15% of our estimated total proved reserves. We ~~have limited ability~~may choose not to ~~influence or control~~hedge future production if the ~~operations or future development~~pricing environment for certain time periods is deemed to be unfavorable. Additionally, we may choose to liquidate derivative positions prior to the expiration of non-operated properties, including the marketing of oil and gas production, 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~~maturities in order to monetize gain positions for the purpose of funding our capital ~~and operating expenditures. These limitations and our dependence on the operators and~~program or 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.~~opportunities.

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, ~~2018,~~2020, we had no$160 million of outstanding borrowings on our credit facility and our consolidated net debt to total capitalization ratio, as defined, was ~~0.43~~0.42 to 1.00. Our total debt would need to independently increase by approximately $8.1 billion above the existing level at December 31, 2018 (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 $4.3 billion below the existing level at December 31, 2018 (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 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.

~~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. In addition, certain cyber incidents, such as surveillance of our systems and those of our business associates, may remain undetected for an extended period.

unauthorized access to or theft of seismic data, reserves information, strategic information, or other sensitive or proprietary information owned by us or by third parties could have a negative impact on our ability to compete for oil and gas resources;

~~data corruption, communication interruption, or other operational disruption during drilling activities could result in failure to reach the intended target or a drilling incident;~~

~~data corruption or operational disruption of production-related infrastructure could result in a loss of production or accidental discharge;~~

a cyber attack on third party transportation, processing, storage, refining, or export facilities could delay or prevent us from transporting and marketing our production, resulting in a loss of revenues;

~~a cyber attack on a vendor or service provider could result in supply chain disruptions which could delay or halt our major development projects;~~

a cyber attack involving commodity exchanges or financial institutions could slow or halt commodities trading, thus preventing us from marketing our production or engaging in hedging activities, resulting in a loss of revenues;

~~corruption of our financial or operating data could result in events of non-compliance which could lead to regulatory fines or penalties; and~~

~~a cyber attack could result in unauthorized access to and release of personal or confidential information maintained by the Company.~~

Any of the above 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 business, financial condition, results of operations or cash flows.

The Company has established cyber security systems and controls intended to monitor threats, identify incidents and assess their impact, protect information, and mitigate data loss. The Company has also established disclosure controls and procedures in tandem with incident response protocols, including regular assessment of threats and incidents by a security oversight committee comprised of members of senior management and information technology personnel. These systems, controls, and procedures are intended to provide information about cyber security incidents so that such information can be timely processed and reported to the appropriate personnel; however, these systems, controls, and procedures may not identify all risks and threats we face, or may fail to protect data or mitigate the adverse effects of data loss. Our senior management makes materiality assessments and disclosure decisions and has implemented procedures to prohibit insider trading on the basis of material nonpublic information about cyber incidents; however, we cannot guarantee all of these efforts will be effective. Although we maintain systems, controls, and procedures to address cyber security risks, such measures cannot eliminate cyber

~~security threats and incidents, and there remains a risk that we will experience a cyber breach, attack, or data loss incident and suffer adverse effects.~~

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.

~~Increases in interest rates could adversely affect our business.~~

The U.S. Federal Reserve increased the benchmark federal funds interest rate on four separate occasions in 2018 and is forecasting additional increases in 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, disposition, or joint development opportunities, reduce cash flows used for drilling and completion activities, and place us at a competitive disadvantage. 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.

Financial regulators are working to transition away from the London Interbank Offered Rate (“LIBOR”) as a reference rate for financial contracts by the end of 2021 and to develop benchmarks to replace LIBOR. Certain types of borrowings under our revolving credit facility, which matures in April 2023, are derived from the LIBOR reference rate. Our revolving credit agreement includes general provisions governing the establishment of an alternate rate of interest to the LIBOR-based rate that gives consideration to the then prevailing market convention for determining a rate of interest for comparable syndicated loans. At this time, the impact on the Company's borrowing costs, if any, under an alternative reference rate scenario is uncertain.

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 ($~~644~~561 million in receivables at December 31, ~~2018);~~2020) and our joint interest and other receivables ($~~368~~144 million at December 31, ~~2018); and counterparty credit risk associated with our derivative instrument receivables ($16 million at December 31, 2018)~~2020). These counterparties may experience insolvency or liquidity issues and may not be able to meet their obligations and liabilities owed to us, particularly during a period of depressed commodity prices. Defaults by these counterparties could adversely impact our financial condition and results of operations.

Additionally, we rely on field service companies and midstream companies for services associated with the drilling and completion of wells and for certain midstream services. A worsening of the commodity price environment may result in a material adverse impact on the liquidity and financial position of the parties with whom we do business, resulting in delays in payment of, or non-payment of, amounts owed to us, delays in operations, loss of access to equipment and facilities and similar impacts. These events could have an adverse impact on our business, financial condition, results of operations and cash flows.

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 ~~derivative activities~~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 new leasing and permitting on federal lands and waters; elimination of subsidies for the oil and gas sector; 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—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. With President Biden taking office and the control of Congress shifting in January 2021, there is an increased risk of the enactment of legislation that alters, eliminates, or defers these or other tax deductions utilized within our industry, which could adversely affect our business, financial ~~losses or~~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 ~~earnings.~~

~~To achieve more predictable cash flows~~ability to monetize or restructure existing derivative contracts, lead to fewer potential counterparties, and ~~reduce~~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 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 ~~fluctuations~~effect on our financial condition, results of operations and cash flows.

Climate change activism, 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.

Climate change activism, fuel conservation measures, governmental requirements for renewable energy resources, increasing consumer demand for alternative forms of energy, and technological advances in ~~commodity prices,~~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. See Part I, Item 1. Business—Regulation of the Crude Oil and Natural Gas Industry for further discussion relating to climate change and emission of greenhouse gases, climate change activism, energy conservation measures or initiatives that stimulate demand for alternative forms of energy. 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 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 attention to environmental, social, and corporate governance matters may impact our business.

Companies across all industries are facing increasing scrutiny from stakeholders related to their environmental, social, and corporate governance (“ESG”) practices. These 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 ~~enter into derivative instruments~~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 ~~a potentially significant 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, 2018. We do not designate any of our derivative instruments as hedges for accounting purposes~~hydrocarbon products, reduced profits, increased investigations and ~~we record all derivatives~~litigation, and negative impacts on our ~~balance sheet at fair value. Changes in the fair value of~~stock price, our ~~derivatives are recognized in current period earnings. Accordingly,~~ability to recruit necessary talent, and our ~~earnings may fluctuate materially as a result of changes in commodity prices and resulting changes in the fair value of our derivatives.~~

~~Derivative instruments expose us~~access 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.~~

capital markets.

In addition, ~~our derivative arrangements limit~~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 ~~benefit we would otherwise receive from increases~~“standards” may result in ~~commodity prices. Our decision~~investors focusing on inadequate or improper metrics which may lead to a misperception of a company and its ESG practices. Nonetheless, the ~~quantity~~importance of sustainability evaluations is becoming more broadly accepted by investors and ~~price at which we choose~~shareholders. ESG ratings are used by some investors to ~~hedge our future production,~~inform their investment and voting decisions. Additionally, certain investors use these scores to benchmark companies against their peers, and if ~~any,~~a company is ~~based~~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 ~~part on our view of current and future market conditions and our desire to stabilize cash flows necessary for the development~~making an investment decision. Consequently, a low sustainability score could result in exclusion of our ~~proved reserves. We may choose not~~stock from consideration by certain investment funds, engagement by investors seeking 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~~improve such scores and a negative perception of our ~~forecasted 2019 natural gas production. Our future crude oil production is currently unhedged and directly exposed~~operations by certain investors.

Risks Related to ~~continued volatility in market prices, whether favorable or unfavorable.~~our Corporate Structure

Our ~~Chairman and Chief~~ Executive ~~Officer~~Chairman beneficially owns approximately ~~76%~~81% 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, ~~2018,~~2020, Harold G. Hamm, our ~~Chairman and Chief~~ Executive ~~Officer,~~Chairman, beneficially owned approximately~~76%~~ 81% 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 or persons 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 parties and us.

~~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 likely continue to make acquisitions of oil and gas properties, divest of assets, and enter into joint development arrangements. Suitable acquisition properties, buyers of our assets, or joint development counterparties may not be available on terms and conditions we find acceptable or not at all.

~~The successful acquisition of producing properties requires an assessment of several factors, including but not limited to:~~

~~recoverable reserves;~~

~~future crude oil and natural gas prices and location and quality differentials;~~

~~the quality of the title to acquired properties;~~

~~future development costs, operating costs and property taxes; and~~

~~potential environmental and other liabilities.~~

The accuracy of these acquisition assessments is inherently uncertain. In connection with these assessments, we perform a review, which we believe to be generally consistent with industry practices, of the subject properties. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities prior to acquisition. Inspections may not always be performed on every property, and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller of the subject properties may be unwilling or unable to provide effective contractual protection against all or part of the problems. We sometimes are not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis.

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

~~Terrorist activities could materially and adversely affect our business and results of operations.~~

Item 1B. Unresolved Staff Comments

There were no unresolved Securities and Exchange Commission staff comments at December 31, ~~2018.~~2020.


~~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.~~	~~Legal Proceedings~~

~~See~~ ~~Note 11. Commitments~~Item 3. Legal Proceedings

On April 15, 2020, Casillas Petroleum Resource Partners II, LLC filed a petition against the Company in the District Court of Tulsa County, State of Oklahoma alleging the Company breached a Purchase and ~~Contingencies–Litigation~~Sale Agreement (“PSA”) to purchase oil and gas interests in ~~Part II, Item 8. Financial Statements~~Oklahoma for $200 million. The Company asserted the PSA was terminated due to Casillas’ breach of the PSA and ~~Supplementary Data–Notes~~denied the allegations. On October 16, 2020, the parties entered into a settlement agreement to ~~Consolidated Financial Statements~~amend and supplement the terms of the PSA, close on the transaction contemplated by the PSA for a ~~discussion of~~negotiated amount, and settle all disputes involved in the ~~legal matter involving~~litigation or that could have been raised in the ~~Company, Billy J. Strack and Daniela A. Renner, which is incorporated herein by reference.~~litigation. The parties subsequently dismissed their respective claims in the litigation.


~~Item 4.~~	~~Mine Safety Disclosures~~

Item 4. Mine Safety Disclosures

Not applicable.

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.” As of January ~~31, 2019,~~29, 2021, the number of record holders of our common stock was ~~1,234. Management believes,~~1,223. On January 29, 2021, after inquiry, management believes that the number of beneficial owners of our common stock is ~~approximately 71,370.~~55,192. On January ~~31, 2019,~~29, 2021, the last reported sales price of our common stock, as reported on the New York Stock Exchange, was ~~$46.17~~$19.69 per share.

In May 2019, our Board of Directors approved the initiation of a dividend payment program and on June 3, 2019 the Company announced its first quarterly cash dividend of $0.05 per share, which was paid on November 21, 2019. On January 27, 2020 our Board of Directors approved a cash dividend of $0.05 per share for the first quarter of 2020, which was paid on February 21, 2020. To preserve cash in response to the significant reduction in crude oil prices and economic uncertainty resulting from the COVID-19 pandemic, in April 2020 the Company's quarterly dividend was suspended by the Board of Directors. 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 our~~provides information about purchases of our common stock during the quarter ended December 31, ~~2018:~~2020:

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, 2018 to October 31, 2018 785
$ 52.68
—
—
November 1, 2018 to November 30, 2018 11,389

$ 48.00
—
—
December 1, 2018 to December 31, 2018 —

—
—
—
Total 12,174
$ 48.30
—
—


Period	Total number of shares purchased	Average price paid per share		Total number of shares purchased as part of publicly announced plans or programs (1)	Maximum dollar value of shares that may yet be purchased under the plans or programs (in millions) (1)
October 1, 2020 to October 31, 2020
Repurchases for tax withholdings (2)	9,292	$	12.40	—	—
November 1, 2020 to November 30, 2020
Repurchases for tax withholdings (2)	11,297	$	14.06	—	—
December 1, 2020 to December 31, 2020
Repurchases for tax withholdings (2)	—	$	—	—	—
Total for the quarter	20,589	$	—	—	—

~~(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.~~

(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. The share repurchase program may be modified, suspended, or terminated by our Board of Directors at any time. No share repurchases were made by the Company under the program during the three months ended December 31, 2020. The total dollar value of shares that may yet be purchased under the program totaled $682.9 million as of December 31, 2020.

(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.

Equity Compensation Plan Information

The following table sets forth the information as of December 31, ~~2018~~2020 relating to equity compensation plans:



	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	—	—	~~13,736,734~~	10,768,301
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.

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, ~~2013~~2015 through December 31, ~~2018.~~2020. The graph assumes the value of the investment in our common stock and in each index was $100 on December 31, ~~2013~~2015 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.


~~Item 6.~~	~~Selected Financial Data~~

Item 6. Selected Financial Data

This section presents selected consolidated financial data for the years ended December 31, ~~2014~~2016 through ~~2018.~~2020. The selected financial data presented below is not intended to replace our consolidated financial statements.

The following 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. Operating and financial results attributable to noncontrolling interests are ~~immaterial~~not material relative to the Company's consolidated results and are not separately presented below.

Year Ended December 31,
2018 2017 2016 2015 2014
Income Statement data
In thousands, except per share data
Crude oil and natural gas sales (1) $ 4,678,722
$ 2,982,966
$ 2,026,958
$ 2,552,531
$ 4,203,022
Gain (loss) on crude oil and natural gas derivatives, net (2) (23,930 ) 91,647
(71,859 ) 91,085
559,759
Total revenues 4,709,586
3,120,828
1,980,273
2,680,167
4,801,618
Net income (loss) (3) 989,700
789,447
(399,679 ) (353,668 ) 977,341
Net income (loss) attributable to Continental Resources (3)(4) 988,317
789,447
(399,679 ) (353,668 ) 977,341
Net income (loss) per share attributable to Continental Resources: (3)(4)
Basic $ 2.66
$ 2.13
$ (1.08 ) $ (0.96 ) $ 2.65
Diluted $ 2.64
$ 2.11
$ (1.08 ) $ (0.96 ) $ 2.64
Production volumes
Crude oil (MBbl) 61,384
50,536
46,850
53,517
44,530
Natural gas (MMcf) 284,730
228,159
195,240
164,454
114,295
Crude oil equivalents (MBoe) 108,839
88,562
79,390
80,926
63,579
Average costs per unit
Production expenses ($/Boe) $ 3.59
$ 3.66
$ 3.65
$ 4.30
$ 5.58
Production taxes (% of net oil and gas revenues) 7.9 % 7.0 % 7.0 % 7.8 % 8.2 %
DD&A ($/Boe) $ 17.09
$ 18.89
$ 21.54
$ 21.57
$ 21.51
General and administrative expenses ($/Boe) $ 1.69
$ 2.16
$ 2.14
$ 2.34
$ 2.92
Proved reserves at December 31
Crude oil (MBbl) 757,096
640,949
643,228
700,514
866,360
Natural gas (MMcf) 4,591,614
4,140,281
3,789,818
3,151,786
2,908,386
Crude oil equivalents (MBoe) 1,522,365
1,330,995
1,274,864
1,225,811
1,351,091
Other financial data (in thousands)
Net cash provided by operating activities $ 3,456,008
$ 2,079,106
$ 1,125,919
$ 1,857,101
$ 3,355,715
Net cash used in investing activities $ (2,860,172 ) $ (1,808,845 ) $ (532,965 ) $ (3,046,247 ) $ (4,587,399 )
Net cash (used in) provided by financing activities $ (356,934 ) $ (243,034 ) $ (587,773 ) $ 1,187,189
$ 1,227,715
Total capital expenditures $ 2,928,746
$ 2,035,254
$ 1,110,256
$ 2,564,301
$ 5,015,595
Balance Sheet data at December 31 (in thousands)
Total assets $ 15,297,947
$ 14,199,651
$ 13,811,776
$ 14,919,808
$ 15,076,033
Long-term debt, including current portion $ 5,768,349
$ 6,353,691
$ 6,579,916
$ 7,117,788
$ 5,928,878
Total equity $ 6,421,861
$ 5,131,203
$ 4,301,996
$ 4,668,900
$ 4,967,844

~~(1)~~

In years prior to 2018, we generally presented our revenues net of costs incurred to transport our production to market. For 2018, crude oil and natural gas sales are presented gross of certain transportation expenses as a result of our January 1, 2018 adoption of new revenue recognition and presentation rules as discussed in ~~Part II, Item 8. Notes to Consolidated Financial Statements—Note 8. Revenues.~~ We adopted the new rules using a modified retrospective transition approach whereby the rules were prospectively applied beginning January 1, 2018 and prior period results have not been adjusted to conform to the current presentation. The change in presentation resulted in an increase in revenues and a corresponding increase in separately reported transportation expenses, with no net effect on our results of operations, net income, or cash flows for 2018.

~~(2)~~

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 year 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.

~~(3)~~

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 9. Income~~


	Year Ended December 31,
	2020			2019			2018			2017			2016
Income Statement data
In thousands, except per share data
Crude oil and natural gas sales (1)	$	2,555,434		$	4,514,389		$	4,678,722		$	2,982,966		$	2,026,958
Gain (loss) on derivative instruments, net	(14,658)			49,083			(23,930)			91,647			(71,859)
Total revenues	2,586,470			4,631,947			4,709,586			3,120,828			1,980,273
Net income (loss) (2)	(605,561)			774,473			989,700			789,447			(399,679)
Net income (loss) attributable to Continental Resources (2)(3)	(596,869)			775,641			988,317			789,447			(399,679)
Net income (loss) per share attributable to Continental Resources: (2)(3)
Basic	$	(1.65)		$	2.09		$	2.66		$	2.13		$	(1.08)
Diluted	$	(1.65)		$	2.08		$	2.64		$	2.11		$	(1.08)
Cash dividends per common share	$	0.05		$	0.05		—			—			—
Production volumes
Crude oil (MBbl)	58,745			72,267			61,384			50,536			46,850
Natural gas (MMcf)	306,528			311,865			284,730			228,159			195,240
Crude oil equivalents (MBoe)	109,833			124,244			108,839			88,562			79,390
Average costs per unit
Production expenses ($/Boe)	$	3.27		$	3.58		$	3.59		$	3.66		$	3.65
Production taxes (% of net oil and gas revenues)	8.2		%	8.3		%	7.9		%	7.0		%	7.0		%
DD&A ($/Boe)	$	17.12		$	16.25		$	17.09		$	18.89		$	21.54
General and administrative expenses ($/Boe)	$	1.79		$	1.57		$	1.69		$	2.16		$	2.14
Proved reserves at December 31
Crude oil (MBbl)	496,975			760,187			757,096			640,949			643,228
Natural gas (MMcf)	3,640,724			5,154,471			4,591,614			4,140,281			3,789,818
Crude oil equivalents (MBoe)	1,103,762			1,619,265			1,522,365			1,330,995			1,274,864
Other financial data (in thousands)
Net cash provided by operating activities	$	1,422,304		$	3,115,688		$	3,456,008		$	2,079,106		$	1,125,919
Net cash used in investing activities	$	(1,511,358)		$	(2,771,956)		$	(2,860,172)		$	(1,808,845)		$	(532,965)
Net cash (used in) provided by financing activities	$	97,124		$	(587,108)		$	(356,934)		$	(243,034)		$	(587,773)
Total capital expenditures	$	1,363,034		$	2,809,192		$	2,928,746		$	2,035,254		$	1,110,256
Balance Sheet data at December 31 (in thousands)
Total assets	$	14,633,098		$	15,727,907		$	15,297,947		$	14,199,651		$	13,811,776
Long-term debt, including current portion	$	5,532,418		$	5,326,514		$	5,768,349		$	6,353,691		$	6,579,916
Total equity	$	6,422,725		$	7,108,351		$	6,421,861		$	5,131,203		$	4,301,996

(1)In years prior to 2018, we generally presented our revenues net of costs incurred to transport our production to market. For 2020, 2019, and 2018, crude oil and natural gas sales are presented gross of certain transportation expenses as a result of our January 1, 2018 adoption of ASU 2014-09, Revenue from Contracts with Customers (Topic 606). We adopted the new rules using a modified retrospective transition approach whereby the rules were prospectively applied beginning January 1, 2018 and prior period results were not adjusted to conform to the current presentation. The change in presentation resulted in an increase in revenues and a corresponding increase in separately reported transportation expenses, with no net effect on our results of operations, net income, or cash flows.

~~Taxes~~ (2)Results for ~~further discussion. Additionally,~~ 2017 include 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).

(3)Excludes results ~~include a $59.6 million pre-tax loss accrual recognized in conjunction with a litigation settlement as discussed in~~ attributable to noncontrolling interests. See Part II, Item 8. Notes to Consolidated Financial Statements—Note ~~11. Commitments~~16. Noncontrolling Interests for a discussion of the arrangements that give rise to the separate presentation of results attributable to Continental and ~~Contingencies, which resulted~~noncontrolling interests in ~~an after-tax decrease in 2017 net income of $37.0 million ($0.10 per basic and diluted share).~~


~~(4)~~	~~Excludes results attributable to noncontrolling interests. See~~ ~~Part II, Item 8. Notes to Consolidated Financial Statements—Note 15. Noncontrolling Interests~~ ~~for a discussion of new arrangements executed in 2018 that gave rise to the separate presentation of results attributable to Continental and noncontrolling interests in our financial statements.~~

our financial statements.


~~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 operating results for the periods discussed below may not be indicative of future performance.~~ Results attributable to noncontrolling interests are ~~immaterial~~not material relative to consolidated results and are not separately presented or discussed below.

~~For additional discussion of crude oil and natural gas reserve information, please see~~ ~~Part I, Item 1. Business—Crude Oil and Natural Gas Operations.~~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.

Our operating results for 2020 discussed below were impacted by the economic effects from the COVID-19 pandemic on crude oil demand and prices and may not be indicative of future results. Given the economic uncertainty from the pandemic and ongoing volatility in commodity prices, it is difficult to predict the extent to which the pandemic or other factors will have on the Company’s performance in 2021 and beyond.

Overview

We are an independent crude oil and natural gas company engaged in the exploration, development and production of crude oil and natural gas. Additionally, we pursue the acquisition and management of perpetually owned minerals located in ~~certain of~~ our key operating areas. We derive the majority of our operating income and cash flows from the sale of crude oil and natural gas and expect this to continue in the future. Our operations are primarily focused on exploration and development activities in the Bakken field of North Dakota and Montana and the SCOOP and STACK areas of Oklahoma. Our common stock trades on the New York Stock Exchange under the symbol “CLR” and our corporate internet website is www.clr.com.

~~2018 Highlights~~

~~Production~~Business Environment and Outlook

Crude oil prices decreased to historically low levels in April 2020 due primarily to reduced global and domestic demand for crude oil caused by the impact of the COVID-19 pandemic and resulting changes in consumer behavior and restrictions implemented by governments to mitigate the pandemic. In response to the significant reduction in crude oil prices, we began voluntarily curtailing our production in April 2020 and ultimately curtailed approximately 55% of our operated crude oil production and associated natural gas in the 2020 second quarter. Additionally, in light of the challenges facing our business and industry, we implemented cost saving initiatives and significantly reduced our operated rig and completion crew counts in order to preserve our assets and better align our capital spending with expected available cash flows, resulting in a $1.5 billion, or 56%, decrease in our non-acquisition capital spending in 2020 compared to 2019. These actions, coupled with historically low crude oil prices, resulted in a material reduction in our production, ~~averaged 298,190~~revenues, and cash flows in 2020 compared to 2019.

Crude oil prices began to stabilize in mid-2020 and generally improved in the second half of 2020 in response to the gradual lifting of COVID-19 restrictions, the resumption of economic activity, and the resulting increase in crude oil demand. In July 2020 we began to gradually restore our curtailed production and subsequently brought our remaining curtailed production back online in September 2020. As a result of our resumed production, coupled with strategic well completion activities in late 2020, our total average production improved to 339,307 Boe per day ~~in 2018, an increase of 23% compared to 2017.~~

~~Total production~~ for the 2020 fourth quarter, ~~of 2018 averaged 324,001 Boe per day, an~~representing a 14% increase ~~of 9%~~ compared to the third quarter of ~~2018 and 13% higher~~2020, yet still remaining 7% lower than the fourth quarter of ~~2017.~~2019.

~~Average daily~~Despite the gradual improvement in crude oil ~~production increased 21%~~prices in ~~2018 compared~~the second half of 2020, we continued our commitment to ~~2017 while average daily natural gas production increased 25%.~~

~~The following table summarizes~~operating in a disciplined, capital efficient manner. Improved revenues from higher commodity prices coupled with our tempered spending resulted in the ~~changes~~generation of cash flows in excess of operating and capital needs in the second half of 2020 that allowed for a $210 million net reduction in our ~~average daily Boe production by major operating area for the periods presented.~~

Fourth Quarter Year Ended December 31,
Boe production per day 2018 2017 % Change 2018 2017 % Change
Bakken 183,836
165,598
11 % 167,800
132,992
26 %
SCOOP 67,244
62,242
8 % 64,339
60,693
6 %
STACK 62,947
47,914
31 % 56,055
36,220
55 %
All other 9,974
11,231
(11 %) 9,996
12,732
(21 %)
Total 324,001
286,985
13 % 298,190
242,637
23 %

~~Proved reserves~~

~~At December 31, 2018, our proved reserves totaled 1,522 MMBoe, an increase of 14%from proved reserves of 1,331 MMBoe~~total debt at December 31, ~~2017.~~

~~Extensions, discoveries and other additions from our drilling and completion activities added 565 MMBoe of proved reserves in 2018 and upward reserve revisions due~~2020 compared to ~~improved commodity prices increased reserves by 26 MMBoe. These increases were partially offset by 109 MMBoe of~~June 30, 2020. Additionally, despite production curtailments during the year, ~~and net downward reserve revisions and removals totaling 295 MMBoe resulting from changes in drilling plans and other factors.~~

~~The following table summarizes the changes in~~we continued to drive our ~~proved reserves by major operating area in 2018:~~

December 31, 2018 December 31, 2017 Volume change Volume
percent
change
Proved reserves by area MBoe Percent MBoe Percent
Bakken 798,005
52 % 635,521
48 % 162,484
26 %
SCOOP 459,103
30 % 491,776
37 % (32,673 ) (7 %)
STACK 230,175
15 % 167,390
13 % 62,785
38 %
All Other 35,082
3 % 36,308
2 % (1,226 ) (3 %)
Total 1,522,365
100 % 1,330,995
100 % 191,370
14 %

~~Operating cash flows~~

~~Net cash inflows from operating activities totaled $3.46 billion~~per-unit production expenses lower to $3.27 per Boe for ~~2018, an increase of 66%~~2020 compared to ~~$2.08 billion~~$3.58 per Boe for 2017, reflecting higher commodity prices and sales volumes. Net cash inflows from operating activities exceeded net cash outflows from investing activities by $596 million for 2018, allowing for further debt reduction during2019.

We remain committed to the ~~year.~~

~~Debt and liquidity~~

~~Total debt decreased $585 million, or 9%, in 2018, reflecting the repayment of all previously outstanding credit facility borrowings at year-end 2017 along with the $400 million partial redemption~~responsible stewardship of our ~~$2.0 billion~~assets and continue to focus on maximizing cash flows, further reducing debt, delivering low-cost capital efficient operations, and generating shareholder value. The depth and quality of ~~5% Senior Notes due 2022~~our asset base, the commodity optionality provided by our significant amount of acreage held by production, and our financial strength allow us to be adaptable in ~~August 2018.~~

~~At December 31, 2018,~~a variety of price environments. We remain flexible as we ~~had $283 million of cash~~monitor and ~~cash equivalents~~adapt to market conditions. See the subsequent section titled Liquidity and $1.5 billion of borrowing availability on our credit facility. We had no outstanding credit facility borrowings at December 31, 2018 and continued to have no outstanding borrowings as of January 31, 2019.

~~Strategic mineral relationship~~

In October 2018 we entered into a strategic relationship with Franco-Nevada Corporation to acquire oil and gas mineral interests in the SCOOP and STACK plays through a newly-formed minerals subsidiary. At closing, Franco-Nevada paid $214.8 million to Continental for an interest in the minerals subsidiary and for funding of its share of certain mineral acquisition costs, and has subsequently made additional funding contributions. 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 the minerals subsidiary based upon performance relative to predetermined production targets. See ~~Part II, Item 8. Notes to Consolidated Financial Statements—Note 15. Noncontrolling Interests~~Capital Resources for additional ~~information.~~discussion of our financial condition.

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.~~

Operating Metrics

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.


	Year ended December 31,
	2020			2019			2018
Average daily production:
Crude oil (Bbl per day)	160,505			197,991			168,177
Natural gas (Mcf per day)	837,509			854,424			780,083
Crude oil equivalents (Boe per day)	300,090			340,395			298,190
Average net sales prices: (1)
Crude oil ($/Bbl)	$	34.71		$	51.82		$	59.19
Natural gas ($/Mcf)	$	1.04		$	1.77		$	3.01
Crude oil equivalents ($/Boe)	$	21.47		$	34.56		$	41.25
Crude oil net sales price discount to NYMEX ($/Bbl)	$	(5.80)		$	(5.15)		$	(5.27)
Natural gas net sales price discount to NYMEX ($/Mcf)	$	(1.10)		$	(0.86)		$	(0.09)
Production expenses ($/Boe)	$	3.27		$	3.58		$	3.59
Production taxes (% of net crude oil and natural gas sales)	8.2		%	8.3		%	7.9		%
DD&A ($/Boe)	$	17.12		$	16.25		$	17.09
Total general and administrative expenses ($/Boe)	$	1.79		$	1.57		$	1.69

Year ended December 31,
2018 2017 2016
Average daily production:
Crude oil (Bbl per day) 168,177
138,455
128,005
Natural gas (Mcf per day) 780,083
625,093
533,442
Crude oil equivalents (Boe per day) 298,190
242,637
216,912
Average net sales prices: (1)
Crude oil ($/Bbl) $ 59.19
$ 45.70
$ 35.51
Natural gas ($/Mcf) $ 3.01
$ 2.93
$ 1.87
Crude oil equivalents ($/Boe) $ 41.25
$ 33.65
$ 25.55
Crude oil net sales price discount to NYMEX ($/Bbl) $ (5.27 ) $ (5.50 ) $ (7.33 )
Natural gas net sales price discount to NYMEX ($/Mcf) $ (0.09 ) $ (0.16 ) $ (0.61 )
Production expenses ($/Boe) $ 3.59
$ 3.66
$ 3.65
Production taxes (% of net crude oil and natural gas sales) 7.9 % 7.0 % 7.0 %
DD&A ($/Boe) $ 17.09
$ 18.89
$ 21.54
Total general and administrative expenses ($/Boe) $ 1.69
$ 2.16
$ 2.14


~~(1)~~	~~See the subsequent section titled~~ ~~Non-GAAP Financial Measures~~ ~~for a discussion and calculation of net sales prices, which are non-GAAP measures for 2018.~~

(1) See the subsequent section titled Non-GAAP Financial Measures for a discussion and calculation of net sales prices, which are non-GAAP measures.

Results of Operations

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

Year Ended December 31,
In thousands, except sales price data 2018 2017 2016
Crude oil and natural gas sales (1) $ 4,678,722
$ 2,982,966
$ 2,026,958
Gain (loss) on crude oil and natural gas derivatives, net (23,930 ) 91,647
(71,859 )
Crude oil and natural gas service operations 54,794
46,215
25,174
Total revenues 4,709,586
3,120,828
1,980,273
Operating costs and expenses (2) (3,115,866 ) (2,671,427 ) (2,267,807 )
Other expenses, net (3) (296,918 ) (293,334 ) (344,920 )
Income (loss) before income taxes 1,296,802
156,067
(632,454 )
(Provision) benefit for income taxes (4) (307,102 ) 633,380
232,775
Net income (loss) 989,700
789,447
(399,679 )
Net income attributable to noncontrolling interests 1,383
—
—
Net income (loss) attributable to Continental Resources $ 988,317
$ 789,447
$ (399,679 )
Diluted net income (loss) per share attributable to Continental Resources $ 2.64
$ 2.11
$ (1.08 )
Production volumes:
Crude oil (MBbl) 61,384
50,536
46,850
Natural gas (MMcf) 284,730
228,159
195,240
Crude oil equivalents (MBoe) 108,839
88,562
79,390
Sales volumes:
Crude oil (MBbl) 61,332
50,628
46,802
Natural gas (MMcf) 284,730
228,159
195,240
Crude oil equivalents (MBoe) 108,787
88,655
79,342

~~(1)~~

In years prior to 2018, we generally presented our revenues net of costs incurred to transport our production to market. For 2018, crude oil and natural gas sales are presented gross of certain transportation expenses as a result of our January 1, 2018 adoption of new revenue recognition and presentation rules (ASU 2016-08) as discussed in ~~Part II, Item 8. Notes to Consolidated Financial Statements—Note 8. Revenues.~~ We adopted the new rules using a modified retrospective transition approach whereby the rules were prospectively applied beginning January 1, 2018 and prior period results have not been adjusted to conform to the current presentation. The change in presentation resulted in an increase in revenues and a corresponding increase in separately reported transportation expenses, with no net effect on our results of operations, net income, or cash flows for 2018.

~~(2)~~

Net of gain on sale of assets of $16.7 million, $55.1 million, and $304.5 million for 2018, 2017, and 2016, respectively. The year 2018 includes $191.6 million of transportation expenses that are presented gross of crude oil and natural gas sales as a result of our aforementioned adoption of ASU 2016-08 on January 1, 2018. ~~The year 2017 includes a $59.6 million loss accrual recognized in conjunction with the litigation settlement described in~~ ~~Part II, Item 8. Notes to Consolidated Financial Statements—Note 11. Commitments and Contingencies—Litigation.~~


~~(3)~~	~~Includes losses on extinguishment of debt of $7.1 million, $0.6 million, and $26.1 million for 2018, 2017, and 2016, respectively.~~


~~(4)~~	The year 2017 reflects the remeasurement of our 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 decrease in income tax expense via the recognition of an income tax benefit totaling $713.7 million.


	Year Ended December 31,
In thousands, except sales price data	2020		2019		2018
Crude oil and natural gas sales	$	2,555,434	$	4,514,389	$	4,678,722
Gain (loss) on derivative instruments, net	(14,658)		49,083		(23,930)
Crude oil and natural gas service operations	45,694		68,475		54,794
Total revenues	2,586,470		4,631,947		4,709,586
Operating costs and expenses	(3,140,362)		(3,374,535)		(3,115,866)
Other expenses, net	(220,859)		(270,250)		(296,918)
Income (loss) before income taxes	(774,751)		987,162		1,296,802
(Provision) benefit for income taxes	169,190		(212,689)		(307,102)
Net income (loss)	(605,561)		774,473		989,700
Net income (loss) attributable to noncontrolling interests	(8,692)		(1,168)		1,383
Net income (loss) attributable to Continental Resources	$	(596,869)	$	775,641	$	988,317
Diluted net income (loss) per share attributable to Continental Resources	$	(1.65)	$	2.08	$	2.64
Production volumes:
Crude oil (MBbl)	58,745		72,267		61,384
Natural gas (MMcf)	306,528		311,865		284,730
Crude oil equivalents (MBoe)	109,833		124,244		108,839
Sales volumes:
Crude oil (MBbl)	58,793		72,136		61,332
Natural gas (MMcf)	306,528		311,865		284,730
Crude oil equivalents (MBoe)	109,881		124,113		108,787

Year ended December 31, ~~2018~~2020 compared to the year ended December 31, ~~2017~~2019

Below is a discussion of changes in our results of operations for 2020 compared to 2019. A discussion of changes in our results of operations for 2019 compared to 2018 has been omitted from this Form 10-K, but may be found in Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations of our Form 10-K for the year ended December 31, 2019 as filed with the SEC on February 26, 2020.

Production

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


	Fourth Quarter				Year Ended December 31,
Boe production per day	2020	2019	% Change		2020	2019	% Change
Bakken	183,141	194,156	(6	%)	158,604	194,691	(19	%)
SCOOP	107,060	111,829	(4	%)	96,503	82,882	16	%
STACK	42,281	51,628	(18	%)	38,003	54,587	(30	%)
All other	6,825	7,728	(12	%)	6,980	8,235	(15	%)
Total	339,307	365,341	(7	%)	300,090	340,395	(12	%)

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


	Year Ended December 31,						Volume increase	Volume percent increase			Year Ended December 31,						Volume decrease	Volume percent decrease
	2018			2017							2020			2019
	Volume	Percent		Volume	Percent						Volume	Percent		Volume	Percent
Crude oil (MBbl)	61,384	56	%	50,536	57	%	10,848	21	%	Crude oil (MBbl)	58,745	53	%	72,267	58	%	(13,522)	(19	%)
Natural gas (MMcf)	284,730	44	%	228,159	43	%	56,571	25	%	Natural gas (MMcf)	306,528	47	%	311,865	42	%	(5,337)	(2	%)
Total (MBoe)	108,839	100	%	88,562	100	%	20,277	23	%	Total (MBoe)	109,833	100	%	124,244	100	%	(14,411)	(12	%)



Title of each class	Trading symbol(s)	Name of each exchange on which registered
Common Stock, $0.01 par value	CLR	New York Stock Exchange



PART I
~~PART I~~
Item 1.	Business		1
		General		1
		Our Business ~~Strategy~~Strategies		3
		Our Business Strengths		3
		Crude Oil and Natural Gas Operations		54
		Proved Reserves		54
		Developed and Undeveloped Acreage		1110
		Drilling Activity		1211
		Summary of Crude Oil and Natural Gas Properties and Projects		1211
		Production and Price History		1514
		Productive Wells		1615
		Title to Properties		1716
		Marketing ~~and Major Customers~~		1716
		Competition		1716
		Regulation of the Crude Oil and Natural Gas Industry		1817
		~~Employees~~Human Capital		2223
		Company Contact Information		2224
Item 1A.		Risk Factors		2325
Item 1B.		Unresolved Staff Comments		38
Item 2.		Properties		38
Item 3.		Legal Proceedings		38
Item 4.		Mine Safety Disclosures		38

PART II
Item 5.		Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		39
Item 6.		Selected Financial Data		41
Item 7.		Management’s Discussion and Analysis of Financial Condition and Results of Operations		4342
Item 7A.		Quantitative and Qualitative Disclosures About Market Risk		6459
Item 8.		Financial Statements and Supplementary Data		6661
Item 9.		Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		~~101~~100
Item 9A.		Controls and Procedures		~~101~~100
Item 9B.		Other Information		~~104~~103

PART III
Item 10.		Directors, Executive Officers and Corporate Governance		~~104~~103
Item 11.		Executive Compensation		~~104~~103
Item 12.		Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		~~104~~103
Item 13.		Certain Relationships and Related Transactions, and Director Independence		~~104~~103
Item 14.		Principal Accountant Fees and Services		~~104~~103

PART IV
Item 15.		Exhibits and Financial Statement Schedules		~~105~~104


	Developed acres		Undeveloped acres		Total
	Gross	Net	Gross	Net	Gross	Net
North Region:
Bakken field
North Dakota Bakken	949,852	563,260	105,095	61,248	1,054,947	624,508
Montana Bakken	170,412	136,153	33,795	25,789	204,207	161,942
Red River units	155,249	138,064	19,455	10,112	174,704	148,176
Other	80,326	54,095	29,569	25,725	109,895	79,820
South Region:
SCOOP	276,618	166,327	183,840	107,459	460,458	273,786
STACK	265,736	146,078	88,139	45,489	353,875	191,567
Other	34,247	20,790	28,940	12,364	63,187	33,154
East Region	734	670	77,547	71,159	78,281	71,829
Total	1,933,174	1,225,437	566,380	359,345	2,499,554	1,584,782



	Developed acres		Undeveloped acres		Total
	Gross	Net	Gross	Net	Gross	Net
North Region:
Bakken field
North Dakota Bakken	950,649	558,662	136,740	85,817	1,087,389	644,479
Montana Bakken	171,663	137,622	17,866	10,134	189,529	147,756
Red River units	158,077	139,796	20,462	9,821	178,539	149,617
Other	88,615	62,330	70,095	58,471	158,710	120,801
South Region:
SCOOP	257,866	152,607	194,483	103,027	452,349	255,634
STACK	254,539	139,036	153,320	89,602	407,859	228,638
Other	61,744	28,971	70,748	33,380	132,492	62,351
East Region	943	848	158,613	135,490	159,556	136,338
Total	1,944,096	1,219,872	822,327	525,742	2,766,423	1,745,614


	2021		2022		2023
	Gross	Net	Gross	Net	Gross	Net
North Region:
Bakken field
North Dakota Bakken	34,287	23,193	31,849	19,034	4,160	2,143
Montana Bakken	1,480	1,480	12,182	10,311	5,697	5,580
Other	—	—	—	—	17,847	17,847
South Region:
SCOOP	36,475	16,265	35,631	22,773	26,068	12,927
STACK	31,465	19,241	11,541	7,696	4,259	3,114
Other	4,889	744	8,987	6,063	2,942	2,592
East Region	969	370	4,856	3,732	5,968	5,272
Total	109,565	61,293	105,046	69,609	66,941	49,475



x☒			ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934



¨☐			TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934



	2019 Plan
	Gross wells (1)	Net wells (1)	Capital expenditures (in millions) (2)
	Gross wells (1)	Net wells (1)	Capital expenditures (in millions) (2)
Bakken	437	148	$	1,063
Oklahoma	228	109	1,102
Total exploration and development	665	257	$	2,165
Land (3)			205
Capital facilities, workovers and other corporate assets			228
Seismic			2
Total 2019 capital budget			$	2,600


	2021 Plan
	Gross wells (1)	Net wells (1)	Capital expenditures (in millions) (2)

North Region	229	94	$	732
South Region	120	57	380
Total exploration and development	349	151	$	1,112
Land			85
Mineral acquisitions attributable to Continental (3)			13
Capital facilities, workovers, water infrastructure, and other			186
Seismic			4
2021 capital budget attributable to Continental			$	1,400
Mineral acquisitions attributable to Franco-Nevada (3)			52
Total 2021 capital budget			$	1,452


~~(3)~~	~~Includes $125 million of planned spending for mineral acquisitions under our new relationship with Franco-Nevada Corporation described in~~ ~~Part II, Item 8. Notes to Consolidated Financial Statements—Note 15. Noncontrolling Interests. With a carry structure in place, Continental will recoup $100 million, or 80%, of such acquisition spending from Franco-Nevada.~~


~~(1)~~	~~See~~ ~~Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Financial Measures~~ ~~for a discussion and calculation of net sales prices, which are non-GAAP measures for 2018.~~


	Fourth Quarter 2020 Daily Production
	Crude Oil (Bbls per day)	Natural Gas (Mcf per day)	Total (Boe per day)
North Region:
Bakken field
North Dakota Bakken	122,291	333,070	177,802
Montana Bakken	4,137	7,209	5,339
Red River units
Cedar Hills	5,323	—	5,323
Other Red River units	1,464	17	1,467

South Region:
SCOOP	36,415	423,871	107,060
STACK	6,995	211,715	42,281
Other	14	129	35
Total	176,639	976,011	339,307



	Fourth Quarter 2018 Daily Production
	Crude Oil (Bbls per day)	Natural Gas (Mcf per day)	Total (Boe per day)
North Region:
Bakken field
North Dakota Bakken	139,338	228,124	177,358
Montana Bakken	4,998	8,881	6,478
Red River units
Cedar Hills	6,389	1,255	6,598
Other Red River units	2,048	2,385	2,446
Other	33	—	33
South Region:
SCOOP	21,332	275,471	67,244
STACK	12,402	303,272	62,947
Other	394	3,014	897
Total	186,934	822,402	324,001


	Crude Oil Wells		Natural Gas Wells		Total Wells
	Gross	Net	Gross	Net	Gross	Net
North Region:
Bakken field
North Dakota Bakken	4,708	1,631	—	—	4,708	1,631
Montana Bakken	394	254	—	—	394	254
Red River units
Cedar Hills	136	130	—	—	136	130
Other Red River units	130	116	—	—	130	116

South Region:
SCOOP	620	316	488	147	1,108	463
STACK	416	157	436	142	852	299
Other	1	1	22	1	23	2
Total	6,405	2,605	946	290	7,351	2,895



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, 2018 to October 31, 2018	785	$	52.68	—	—
November 1, 2018 to November 30, 2018	11,389	$	48.00	—	—
December 1, 2018 to December 31, 2018	—	—		—	—
Total	12,174	$	48.30	—	—



	December 31, 2018			December 31, 2017			Volume change		Volume percent change
Proved reserves by area	MBoe	Percent		MBoe	Percent		Volume change		Volume percent change
Bakken	798,005	52	%	635,521	48	%	162,484		26	%
SCOOP	459,103	30	%	491,776	37	%	(32,673	)	(7	%)
STACK	230,175	15	%	167,390	13	%	62,785		38	%
All Other	35,082	3	%	36,308	2	%	(1,226	)	(3	%)
Total	1,522,365	100	%	1,330,995	100	%	191,370		14	%



	Year ended December 31,
In thousands	2018		2017
Geological and geophysical costs	$	7,495	$	12,217
Exploratory dry hole costs	147		176
Exploration expenses	$	7,642	$	12,393


	Year ended December 31,
$/Boe	2020		2019
Crude oil and natural gas properties	$	16.84	$	16.03
Other equipment	0.19		0.15
Asset retirement obligation accretion	0.09		0.07
Depreciation, depletion, amortization and accretion	$	17.12	$	16.25


In millions	1Q 2020		2Q 2020		3Q 2020		4Q 2020		Total 2020
Exploration and development	$	544.0	$	155.8	$	120.9	$	151.0	$	971.7
Land costs (1)	39.9		8.9		6.1		3.5		58.4
Capital facilities, workovers and other corporate assets	63.0		25.8		22.4		13.5		124.7
Seismic	3.8		0.3		—		0.1		4.2
Capital expenditures, excluding acquisitions	$	650.7	$	190.8	$	149.4	$	168.1	$	1,159.0
Acquisitions of producing properties	19.3		0.1		4.0		37.1		60.5
Acquisitions of non-producing properties	10.6		—		0.1		132.8		143.5
Total acquisitions (2)	29.9		0.1		4.1		169.9		204.0
Total capital expenditures	$	680.6	$	190.9	$	153.5	$	338.0	$	1,363.0



In millions	1Q 2018		2Q 2018		3Q 2018		4Q 2018		Total 2018
Exploration and development	$	496.3	$	627.9	$	633.5	$	611.0	$	2,368.7
Land costs (1)	67.0		44.9		105.5		59.0		276.4
Capital facilities, workovers and other corporate assets	33.0		41.4		51.8		72.6		198.8
Seismic	—		—		—		—		—
Capital expenditures, excluding acquisitions	$	596.3	$	714.2	$	790.8	$	742.6	$	2,843.9
Acquisitions of producing properties	2.6		21.5		1.4		6.1		31.6
Acquisitions of non-producing properties (1)	28.0		21.6		2.0		1.6		53.2
Total acquisitions	30.6		43.1		3.4		7.7		84.8
Total capital expenditures	$	626.9	$	757.3	$	794.2	$	750.3	$	2,928.7


~~(1)~~	These captions include costs incurred during 2018 to acquire minerals, which, along with minerals acquired prior to 2018, were contributed to our newly-formed subsidiary TMRC II in October 2018 as part of the transaction with Franco-Nevada.



In millions	2019 Budget
Exploration and development	$	2,165
Land costs (1)	205
Capital facilities, workovers and other corporate assets	228
Seismic	2
Total 2019 capital budget	$	2,600


~~(1)~~In millions	~~Includes $125 million of planned spending for mineral~~2021 Budget
Exploration and development	$	1,112
Land costs	85
Mineral acquisitions ~~by TMRC II. With a carry structure in place,~~attributable to Continental ~~will recoup $100 million, or 80%, of such spending from Franco-Nevada.~~(1)	13
Capital facilities, workovers, water infrastructure, and other corporate assets	186
Seismic	4
2021 capital budget attributable to Continental	$	1,400
Mineral acquisitions attributable to Franco-Nevada (1)	52
Total 2021 capital budget (2)	$	1,452


	Payments due by period
In thousands	Total		Less than 1 year (2021)		Years 2 and 3 (2022-2023)		Years 4 and 5 (2024-2025)		More than 5 years
Credit facility borrowings (1)	$	160,000	$	—	$	160,000	$	—	$	—
Senior Notes (1)(2)	5,391,407		—		1,280,407		911,000		3,200,000
Notes payable (3)	24,696		2,245		4,736		5,082		12,633
Interest payments and commitment fees (4)	2,316,057		266,929		482,793		346,997		1,219,338
Asset retirement obligations (5)	179,676		2,482		22,760		1,141		153,293
Operating leases and other (6)	33,236		15,514		7,536		1,428		8,758
Drilling rig commitments (7)	14,099		14,099		—		—		—
Transportation and processing commitments (8)	1,450,873		226,804		513,243		364,819		346,007
Total contractual obligations	$	9,570,044	$	528,073	$	2,471,475	$	1,630,467	$	4,940,029


~~(1)~~	~~Amounts represent scheduled maturities of our senior note obligations at December 31, 2018 and do not reflect any discount or premium at which the senior notes were issued or any debt issuance costs.~~


~~(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 commitment fees on unused borrowing availability under our credit facility assuming the $1.5 billion of availability as of December 31, 2018 continues through the April 2023 maturity date of the facility.


~~(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)~~	~~See~~ ~~Part II, Item 8. Notes to Consolidated Financial Statements—Note 11. Commitments and Contingencies—Litigation~~ ~~for discussion of this litigation settlement obligation.~~


~~(6)~~	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.


Year Ending						Natural Gas
December 31,						Bcf
2021						107
2022						37
2023						34
2024						34
2025						18
2026						15


				Collars
Crude oil derivatives		Swaps Weighted Average Price		Floors			Ceilings
Period and Type of Contract	Bbls			Range	Weighted Average Price		Range	Weighted Average Price


March 2021 - December 2021
NYMEX Roll Swaps	6,885,000	$	0.39
January 2021- May 2021
Swaps - WTI	5,310,000	$	52.50
March 2021 - April 2021
Collars - WTI	915,000			$45.00 - $50.00	$	47.46	$53.80 - $55.10	$	54.44



		Swaps Weighted Average Price

Period and Type of Contract	MMBtus
April 2019 - December 2019
Swaps - Henry Hub	63,250,000	$	2.83


Total Company	Year Ended December 31, 2020						Year Ended December 31, 2019						Year Ended December 31, 2018
In thousands	Crude oil		Natural gas		Total		Crude oil		Natural gas		Total		Crude oil		Natural gas		Total
Crude oil and natural gas sales (GAAP)	$	2,199,976	$	355,458	$	2,555,434	$	3,929,994	$	584,395	$	4,514,389	$	3,792,594	$	886,128	$	4,678,722
Less: Transportation expenses	(158,989)		(37,703)		(196,692)		(191,998)		(33,651)		(225,649)		(162,312)		(29,275)		(191,587)
Net crude oil and natural gas sales (non-GAAP)	$	2,040,987	$	317,755	$	2,358,742	$	3,737,996	$	550,744	$	4,288,740	$	3,630,282	$	856,853	$	4,487,135
Sales volumes (MBbl/MMcf/MBoe)	58,793		306,528		109,881		72,136		311,865		124,113		61,332		284,730		108,787
Net sales price (non-GAAP)	$	34.71	$	1.04	$	21.47	$	51.82	$	1.77	$	34.56	$	59.19	$	3.01	$	41.25



Total Company	Fourth Quarter 2018									Year Ended December 31, 2018
In thousands	Crude oil			Natural gas			Total			Crude oil			Natural gas			Total
Crude oil and natural gas sales (GAAP)	$	900,872		$	253,232		$	1,154,104		$	3,792,594		$	886,128		$	4,678,722
Less: Transportation expenses	(42,373		)	(6,655		)	(49,028		)	(162,312		)	(29,275		)	(191,587		)
Net crude oil and natural gas sales (non-GAAP for 2018)	$	858,499		$	246,577		$	1,105,076		$	3,630,282		$	856,853		$	4,487,135
Sales volumes (MBbl/MMcf/MBoe)	17,149			75,661			29,759			61,332			284,730			108,787
Net sales price (non-GAAP for 2018)	$	50.06		$	3.26		$	37.13		$	59.19		$	3.01		$	41.25