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 ~~with properties~~formed in 1967 engaged in the exploration, development, and production of crude oil and natural gas in the North, South and East regions of the United States. Additionally, we pursue the acquisition and management of perpetually owned minerals located in our key operating areas. 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 ~~(South Central Oklahoma Oil Province)~~ and STACK ~~(Sooner Trend Anadarko Canadian Kingfisher)~~ 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.

~~We were formed~~Our operations in ~~1967 to explore for, develop and produce crude oil and natural gas properties. Through~~ the ~~1980s, our activities and growth remained focused primarily in Oklahoma. In the 1980s, we expanded our activity into the North region. The~~ North region comprised ~~approximately 59%~~55% of our crude oil and natural gas production and ~~approximately 69%~~65% of our crude oil and natural gas revenues for the year ended December 31, ~~2017.~~2020. The Company’s principal producing properties in the North region are located in the Bakken field of North Dakota and Montana. Approximately ~~50%~~48% of our ~~estimated~~ proved reserves as of December 31, ~~2017~~2020 are located in the North region. ~~In recent years, we have significantly expanded our~~Our operations in ~~our South region with our increased activity in~~ the ~~SCOOP and STACK plays. The~~ South region comprised ~~approximately 41%~~45% of our crude oil and natural gas production, ~~31%~~35% of our crude oil and natural gas revenues, and ~~50%~~52% of our ~~estimated~~ proved reserves as of and for the year ended December 31, ~~2017.~~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, ~~2017,~~2020, our ~~estimated~~ proved reserves were ~~1,331~~1,104 MMBoe, with ~~estimated~~ proved developed reserves ~~of 602~~representing 627 MMBoe, or ~~45%~~57%, of our total ~~estimated~~ proved reserves. ~~Crude oil represents approximately 48% of our estimated proved reserves as of December 31, 2017.~~ The standardized measure of our discounted future net cash flows totaled ~~approximately $10.5~~$4.65 billion at December 31, ~~2017.~~

2020. For ~~2017,~~2020, we generated crude oil and natural gas revenues of ~~$2.98~~$2.56 billion and operating cash flows of ~~$2.08~~$1.42 billion. Crude oil accounted for ~~approximately 57%~~53% of our total production and ~~approximately 78%~~86% of our crude oil and natural gas revenues for ~~2017. Production~~2020. Our total production averaged ~~242,637~~300,090 Boe per day for ~~2017,~~2020, a decrease of 12% ~~increase~~ compared to average production of 216,912 Boe per day for 2016. Average daily production for the quarter ended December 31, 2017 increased 37% to 286,985 Boe per day compared to 209,861 Boe per day for the quarter ended December 31, 2016 due to increased drilling and completion activities.2019.

The table below summarizes our total ~~estimated~~ proved reserves, PV-10 (non-GAAP) and net producing wells as of December 31, ~~2017,~~2020, average daily production for the quarter ended December 31, ~~2017~~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, 2017						Average daily production for fourth quarter 2017 (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	594,818	44.7	%	$	6,488	1,313	158,640	55.3	%	10.3	North Dakota Bakken	483,238	43.8	%	$	2,235	1,631	177,802	52.4	%	7.4
Montana Bakken	40,703	3.1	%	412		263	6,958	2.4	%	16.0	Montana Bakken	25,754	2.3	%	128		254	5,339	1.6	%	13.2
Red River units											Red River units
Cedar Hills	28,998	2.2	%	340		130	7,022	2.4	%	11.3	Cedar Hills	17,670	1.6	%	142		130	5,323	1.6	%	9.1
Other Red River units	2,668	0.2	%	28		117	2,475	0.9	%	3.0	Other Red River units	932	0.1	%	7		116	1,467	0.4	%	1.7
Other	1,356	0.1	%	9		8	468	0.2	%	7.9

South Region:											South Region:
SCOOP	491,776	36.9	%	3,597		260	62,242	21.7	%	21.6	SCOOP	478,196	43.3	%	2,139		463	107,060	31.6	%	12.2
STACK	167,390	12.6	%	936		160	47,914	16.7	%	9.6	STACK	97,967	8.9	%	241		299	42,281	12.4	%	6.3
Other	3,286	0.2	%	23		175	1,266	0.4	%	7.1	Other	5	—	%	1		2	35	—	%	0.4
Total	1,330,995	100.0	%	$	11,833	2,426	286,985	100.0	%	12.7	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 $1.4 billion. Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of our crude oil and natural gas properties. We and others in the crude oil and natural gas industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific income tax characteristics of such entities. See ~~Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Financial Measures~~ ~~for further discussion.~~


~~(2)~~	The Annualized Reserve/Production Index is the number of years that estimated proved reserves would last assuming current production continued at the same rate. This index is calculated by dividing annualized fourth quarter 2017 production into estimated proved reserve volumes as of December 31, 2017.

Business Environment and Outlook

~~Our industry has been significantly 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 ~~lower commodity prices~~the pandemic resulted in ~~recent years. The downward pressure on prices experienced~~a significant reduction in ~~2015~~global and ~~2016 showed signs of easing~~domestic demand for crude oil due to, among other things, changes in ~~2017. Commodity prices remained volatile during~~consumer behavior and restrictions implemented by governments to mitigate the ~~year, but generally increased on average~~pandemic. This demand destruction contributed to an unprecedented decline in ~~2017 relative to 2016 in response to improving domestic and global supply and demand fundamentals and other factors. Crude~~crude oil prices, ~~in particular showed significant signs of improvement in late 2017 and early 2018,~~ with West Texas Intermediate ~~crude oil~~ benchmark prices reaching all-time lows in April 2020. 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 ~~three-year high of $66 per barrel~~$1.5 billion, or 56%, decrease in ~~January 2018.~~ 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 ~~remain volatile~~began to stabilize in mid-2020 and ~~it is uncertain whether~~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 ~~market~~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 for the 2020 fourth quarter, representing a 14% increase compared to the third quarter of 2020, yet still remaining 7% lower than the fourth quarter of 2019.

Despite the gradual improvement in crude oil prices ~~experienced in recent months will be sustained.~~

~~Continental marked its 50th anniversary~~ in the ~~oil and gas business in 2017. Our leadership team has significant experience with~~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 ~~2018,~~2021, our primary business strategies will focus ~~on:~~on generating shareholder value by:

~~Balancing strong production growth with free~~•Continuing to exercise capital and operational discipline to maximize cash flow generation;

~~Enhancing cash flows and return~~•Reducing outstanding debt;

•Capitalizing on ~~capital employed through improvements in operating efficiencies, technical innovations, and optimized completion methods;~~

~~Continuing~~commodity optionality afforded to ~~exercise disciplined capital spending to maintain financial flexibility and ample liquidity; and~~

~~Improving debt metrics~~us by ~~further reducing outstanding debt using available operating cash flows or proceeds from asset dispositions or joint development arrangements.~~

~~Based on an expectation for higher operating cash flows in 2018 in response to improvement in~~our crude oil ~~prices in late 2017~~ and ~~early 2018, we have increased our planned non-acquisition capital spending for 2018 to $2.3 billion compared to $2.0 billion spent in 2017, with approximately 78% of our 2018 drilling~~natural gas assets; and ~~completion budget focusing on oil-weighted areas in~~

~~the North Dakota Bakken and SCOOP Springer plays. We expect to fund our budgeted spending using cash flows from~~•Maintaining low-cost operations. ~~We may adjust our pace of drilling and development as 2018 market conditions evolve.~~

~~For 2018, we plan to operate an average of approximately 21drilling rigs and 10completion crews for the year. We expect to spend approximately 52%of our 2018 capital expenditures budget on drilling and completion activities in North Dakota Bakken, 20%in SCOOP, and 14% in STACK. The remaining 14%of our 2018 budget will target other capital expenditures such as leasing and renewals, work-overs, and facilities. See the section below titled~~ ~~Summary of Crude Oil and Natural Gas Properties and Projects~~ ~~for further discussion of our 2018 plans.~~

Our Business ~~Strategy~~Strategies

Despite ~~ongoing~~ 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 balancing production growth with free~~in a disciplined manner to maximize cash flow generation.We hold a portfolio of leasehold acreage, drilling opportunities, ~~and~~ uncompleted wells, perpetually owned minerals, and 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 production growth while generating~~generate cash flows in excess of operating and capital requirements, ~~to work down our large 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 cash flows~~Maintaining low-cost operations. Our culture is defined by our low cost operations and ~~return on capital employed through costs reductions, operating efficiencies, technical innovations, and optimized completions.~~ in 2020 we again delivered low cost industry leadership despite the challenges facing our business. We continue to manage ~~through~~our business in the ~~current~~volatile commodity price environment by focusing on improving operating and capital efficiencies and reducing ~~costs.~~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 ~~achieve cost reductions through~~enhance operating efficiencies and economies of scale.

~~We continued~~ Our operational excellence has allowed us to achieve ~~efficiency gains in various aspects of our business in 2017, including additional reductions in spud-to-total depth drilling times~~ and average days to drill horizontal laterals, which has led to reductions in drilling costs in our core areas. In addition to lowering our drilling costs, we also work to enhance cash flows through the use of optimized completion technologies that help improve recoveries and rates of return. These efforts have had a positive impact on the efficiency of our capital deployed in recent years, resulting in significant improvement in the quantity of reserves found and developed per dollar invested.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 2017, we reduced our total debt by $226 million, or 3%, from $6.58 billion at year-end 2016 to $6.35 billion at year-end 2017. We are actively targeting further debt reduction using available cash flows from operations or proceeds from potential sales of non-strategic 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. From January 1, 2015 through December 31, 2017, our proved reserve additions through extensions and discoveries were 743 MMBoe compared with insignificant proved reserve acquisitions during that same period.

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~~acreage inventory with access to both crude oil and natural gas resources. We held approximately ~~598,400~~359,300 net undeveloped acres and ~~1.19~~1.23 million net developed acres under lease as of December 31, ~~2017~~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 ~~Horizontal Drilling~~pad and ~~Optimized Completion Methods~~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 ~~drilling in our operating areas.~~and row development strategies. Further, we are among industry leaders in drilling long lateral lengths. We have also been among industry leaders in testing and utilizing optimized completion technologies involving various combinations of fluid types, proppant types and volumes, and stimulation stage spacing to determine optimal methods for improving recoveries and rates of return. We continually refine our drilling and completion techniques in an effort to deliver improved results across our properties.

Control ~~Operations Over~~operations over a ~~Substantial Portion~~substantial portion of ~~Our Assets~~our assets and ~~Investments~~investments. As of December 31, ~~2017,~~2020, we operated properties comprising ~~89%~~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.~~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 ~~9 senior~~8 executive officers have an average of 3841 years of oil and gas industry experience.

Financial Position and Liquidity. ~~Currently we~~We have a ~~revolving~~ credit facility with lender commitments totaling ~~$2.75~~$1.5 billion that matures in ~~May 2019.~~April 2023. We had approximately ~~$2.65~~$1.33 billion of ~~available~~ borrowing ~~capacity under~~availability on our credit facility at ~~January~~December 31, ~~2018~~2020 after considering outstanding borrowings and letters of credit.

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

Crude Oil and Natural Gas Operations

Proved Reserves

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

The ~~following~~ table below sets forth estimated proved crude oil and natural gas reserves information by reserve category as of December 31, ~~2017.~~2020. Proved reserves attributable to noncontrolling interests are not material relative to our consolidated reserves and are not separately presented herein. The standardized measure of our discounted future net cash flows totaled approximately ~~$10.5~~$4.65 billion at December 31, ~~2017.~~2020. Our reserve estimates as of December 31, ~~2017~~2020 are based primarily on a reserve report prepared by Ryder Scott. In preparing its report, Ryder Scott evaluated properties representing approximately ~~96%~~93% of our PV-10 and ~~96%~~95% of our total proved reserves as of December 31, ~~2017.~~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, ~~2017~~2020 were determined using the 12-month unweighted arithmetic average of the first-day-of-the-month commodity prices for the period of January ~~2017~~2020 through December ~~2017,~~2020, without giving effect to derivative transactions, and were held constant throughout the lives of the properties. These prices were ~~$51.34~~$39.57 per Bbl for crude oil and ~~$2.98~~$1.99 per MMBtu for natural gas ($~~47.03~~34.34 per Bbl for crude oil and ~~$3.00~~$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 318,291
1,697,926
601,279
$ 7,474.9
Proved developed non-producing 416
1,235
622
6.4
Proved undeveloped 322,242
2,441,120
729,094
4,352.2
Total proved reserves 640,949
4,140,281
1,330,995
$ 11,833.5
Standardized Measure (1) $ 10,470.2
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)~~

The following table provides additional information regarding our estimated proved crude oil and natural gas reserves by region as of December 31, ~~2017.~~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 217,776
472,057
296,452
212,107
517,562
298,366
Montana Bakken 21,503
38,480
27,916
10,385
14,412
12,787
Red River units
Cedar Hills 28,321
4,058
28,998
—
—
—
Other Red River units 2,667
16
2,668
—
—
—
Other 110
7,469
1,356
—
—
—
South Region:
SCOOP 35,333
754,820
161,136
84,828
1,474,871
330,640
STACK 12,181
407,448
80,089
14,922
434,275
87,301
Other 816
14,813
3,286
—
—
—
Total 318,707
1,699,161
601,901
322,242
2,441,120
729,094

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


	Year Ended December 31,
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 2017 2016 2015
Proved reserves at beginning of year 1,274,864
1,225,811
1,351,091
Revisions of previous estimates (82,012 ) (110,474 ) (297,198 )
Extensions, discoveries and other additions 240,206
249,430
253,173
Production (88,562 ) (79,390 ) (80,926 )
Sales of minerals in place (15,197 ) (10,513 ) (329 )
Purchases of minerals in place 1,696
—
—
Proved reserves at end of year 1,330,995
1,274,864
1,225,811

Revisions of previous estimates. Revisions represent changes in previous reserve estimates, either upward or downward, resulting from new information normally obtained from development drilling and production history or resulting from a change in economic factors, such as commodity prices and differentials, operating costs, or development costs.

~~Given the significant volatility in commodity prices in recent years, and given the uncertainty regarding the timing, magnitude and duration~~for 2020 are comprised of any price recovery, maintaining a strong balance sheet, ample liquidity, and financial flexibility has become an increasingly important component of our long-term business strategy. In light of our strategy to preserve financial flexibility and minimize the incurrence of new debt, we maintained a disciplined spending approach in 2017 and continued to refine our capital program to focus on areas that provide the greatest opportunities to achieve operating efficiencies and cost reductions, to convert undeveloped acreage to acreage held by production, and to improve hydrocarbon recoveries, cash flows and rates of return using optimized completions. As part of this effort, we shifted a portion of our 2017 spending away from the SCOOP and Bakken plays to areas in the emerging STACK play that offered more advantageous opportunities and rates of return in the 2017 commodity price environment. This shift in strategy coupled with our increased emphasis on balancing capital spending with cash flows altered the timing and extent of our previous development plans in certain areas and resulted in(i) the removal of 4150 MMBo and ~~290~~345 Bcf (totaling 89107 MMBoe) of PUD reserves no longer scheduled to be ~~developed~~drilled within five years ~~from the date~~ of initial ~~booking. These removals do not represent the elimination of recoverable hydrocarbons physically in place. In some instances the removed reserves may be developed~~booking due to a reduction in the ~~future in the event of further improvement in commodity prices and an expansion~~scope of our future drilling programs based on adverse market conditions, reduced demand, and lower prices caused by the COVID-19 pandemic and our resulting allocation of capital ~~expenditure budget.~~to areas providing the best opportunities to improve efficiencies,

~~Commodity prices increased on average in 2017 relative to 2016 in response to improving domestic~~

recoveries, and global supply and demand fundamentals and other factors. The 12-month average first-day-of-the-month price for crude oil increased 20% from $42.75 per Bbl for 2016 to $51.34 per Bbl for 2017, while the 12-month average first-day-of-the-month price for natural gas increased 20% from $2.49 per MMBtu for 2016 to $2.98 per MMBtu for 2017. These changes increased the economic livesrates of

~~certain producing properties and caused certain previously uneconomic projects to become economic, which had a favorable impact on the Company’s proved reserve estimates, resulting in upward~~ return, (ii) downward revisions of 29 MMBo and 78172 Bcf (totaling 4258 MMBoe) ~~in 2017.~~

~~Additionally,~~from the removal of PUD reserves due to changes in ~~anticipated production~~economics, performance, ~~on certain properties resulted~~and other factors, (iii) downward price revisions of 214 MMBo and 1,043 Bcf (totaling 388 MMBoe) due to the significant decrease in ~~59 MMBo of downward revisions to~~average crude oil ~~reserves~~ and ~~173 Bcf of~~natural gas prices in 2020 compared to 2019 resulting from the economic turmoil caused by the COVID-19 pandemic and other factors, and (iv) net upward revisions ~~to natural gas reserves (netting to 30 MMBoe~~ of ~~downward revisions) in 2017. Further,~~43 MMBo and 31 Bcf (totaling 48 MMBoe) due to changes in ownership interests, operating costs, anticipated production, and other ~~factors during the year resulted in 7 MMBo of downward revisions to crude oil reserves and 11 Bcf of upward revisions to natural gas reserves (netting to 5 MMBoe of downward revisions) in 2017.~~factors.

Extensions, discoveries and other additions. These are additions to our proved reserves that result from (i) extension of the proved acreage of previously discovered reservoirs through additional drilling in periods subsequent to discovery and (ii) discovery of new fields with proved reserves or of new reservoirs of proved reserves in old fields. Extensions, discoveries and other additions for each of the three years reflected in the table above were ~~primarily~~ due to ~~increases in proved reserves associated with our~~ successful drilling and completion activities and continual refinement of our drilling programs in the Bakken, SCOOP, and STACK ~~areas.~~plays. Proved reserve additions ~~from our drilling activities~~ in the Bakken totaled ~~148~~41 MMBoe, 73160 MMBoe, and 96251 MMBoe for ~~2017, 2016~~2020, 2019, and ~~2015,~~2018, respectively, while reserve additions in SCOOP totaled 5349 MMBoe, 97186 MMBoe, and 93186 MMBoe for ~~2017, 2016~~2020, 2019, and ~~2015,~~2018, respectively. Additionally, ~~extensions and discoveries were impacted by successful drilling and completion results in the STACK play, resulting in proved~~ reserve additions ~~of 39~~in STACK totaled 1 MMBoe, 7919 MMBoe, and 57128 MMBoe in ~~2017, 2016~~2020, 2019, and ~~2015,~~2018, respectively. See the subsequent section titled Summary of Crude Oil and Natural Gas Properties and Projects for a discussion of our ~~2017~~2020 drilling activities. ~~We expect a significant portion of future reserve additions will continue to come from our major development projects in the Bakken, SCOOP and STACK areas.~~

Sales of minerals in place. ~~These are reductions to~~ We had no individually significant dispositions of proved reserves ~~resulting from~~in the ~~disposition of properties during a period. See~~ ~~Part II, Item 8. Notes to Consolidated Financial Statements—Note 14. Property Dispositions~~ ~~for further discussion of notable dispositions. We may continue to seek opportunities to sell non-strategic properties if and when we have the ability to dispose of such assets at favorable terms.~~past three years.

Purchases of minerals in place. ~~These are additions to~~We had no individually significant acquisitions of proved reserves ~~resulting from the acquisition of properties during a period. We have had no significant acquisitions~~ in the past three years. ~~However, we may participate as a buyer of properties when and if we have the ability to increase our position in strategic plays at favorable terms.~~

Proved Undeveloped Reserves

All of our PUD reserves at December 31, ~~2017~~2020 are located in the Bakken, SCOOP, and STACK plays, our most active development areas, with those plays comprising ~~43%~~48%, ~~45%~~48%, and ~~12%~~4%, respectively, of our total PUD reserves at year-end ~~2017.~~2020. The following table provides information regarding changes in our PUD reserves for the year ended December 31, ~~2017.~~2020. Our PUD reserves at December 31, ~~2017~~2020 include 7098 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, 2016	353,018		2,419,198		756,218
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	(73,684	)	(131,306	)	(95,569	)	Revisions of previous estimates	(210,569)	(1,326,177)	(431,599)
Extensions and discoveries	100,874		492,468		182,952		Extensions and discoveries	37,605	271,611	82,874
Sales of minerals in place	(3,441	)	(24,870	)	(7,586	)	Sales of minerals in place	—	—	—
Purchases of minerals in place	149		3,009		650		Purchases of minerals in place	496	5,363	1,390
Conversion to proved developed reserves	(54,674	)	(317,379	)	(107,571	)	Conversion to proved developed reserves	(36,245)	(311,438)	(88,151)
Proved undeveloped reserves at December 31, 2017	322,242		2,441,120		729,094
Proved undeveloped reserves at December 31, 2020							Proved undeveloped reserves at December 31, 2020	215,069	1,567,713	476,355

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

SCOOP represented ~~37%~~43% of our total proved reserves as of December 31, ~~2017~~2020 and ~~22%~~32% of our average daily Boe production for the fourth quarter of ~~2017.~~2020. Production in SCOOP averaged ~~62,242~~107,060 Boe per day during the fourth quarter of ~~2017,~~2020, down 2%4% compared to the ~~2016~~2019 fourth quarter. For the year ended December 31, ~~2017,~~2020, average daily production in SCOOP ~~decreased 7%~~increased 16% compared to ~~2016,~~2019, reflecting ~~natural declines in production and limited~~additional drilling and completion activities in ~~2017.~~our Project SpringBoard which exceeded the impact of production curtailments in the play during the year. We participated in the drilling and completion of 77123 gross ~~(20~~(46 net) wells in SCOOP during ~~2017~~2020 compared to 72207 gross ~~(28~~(93 net) wells in ~~2016. Proved~~2019. Our total proved SCOOP field reserves ~~in SCOOP totaled 492 MMBoe~~ as of December 31, ~~2017, an increase~~2020 were 478 MMBoe, a decrease of 4%17% compared to December 31, ~~2016~~2019 primarily due to ~~reserves added from our drilling program, continued improvement in recoveries driven by advances in optimized completion designs, and upward~~downward reserve revisions prompted by ~~higher~~significantly reduced commodity prices and resulting changes in ~~2017.~~drilling plans. Our inventory of proved undeveloped drilling locations in SCOOP totaled ~~336~~262 gross ~~(230~~(164 net) wells as of December 31, ~~2017.~~

In 2018, we plan to invest approximately $465 million to drill, complete and initiate production on 160 gross (44 net) operated and non-operated wells in the SCOOP play. We plan to average approximately seven operated rigs and one completion crew in SCOOP throughout 2018, an increase from five rigs as of December 31, 2017. Our 2018 drilling program will continue to focus on expanding the known productive extent of the SCOOP Woodford, Springer and Sycamore formations, while focusing on areas that provide opportunities for converting undeveloped acreage to acreage held by production, increasing capital efficiency, reducing finding and development costs, and improving rates of return.2020.

STACK

The STACK play is ~~a significant resource play~~ located in the Anadarko Basin of Oklahoma and is characterized by stacked geologic formations with major targets in the Meramec, Osage, and Woodford formations. As of December 31, ~~2017,~~2020, we controlled one of the largest leasehold positions in STACK with approximately ~~389,400~~353,900 gross ~~(212,400~~(191,600 net) acres under lease. A significant portion of our STACK acreage is located in over-pressured portions of Blaine, Dewey and Custer counties of Oklahoma where we believe the reservoirs are typically thicker and deliver superior production rates relative to normal-pressured areas of the STACK petroleum system.

Building on early success achieved from our initial STACK drilling activities in mid-2015, we significantly increased our leasing and drilling activities in the play in 2016 and 2017. Our 2017 activities focused on pilot density drilling to expand our understanding of the productive extent and hydrocarbon content of the play and to help determine optimum well spacing, well patterns, and completion methods for future development.

Through our 2016 and 2017 activities in STACK, we have successfully tested productive zones in the play, applied optimized completions to improve recoveries, demonstrated repeatability of results, reduced drilling times, reduced well costs, and de-risked a sizeable portion of our acreage in the play. Due to the success of these efforts, STACK has become another significant growth platform for us and is expected to be an important contributor to our long-term growth. To facilitate future development of our STACK acreage, we continue to increase our water recycling and distribution capabilities in the play. Additionally, we continue to increase our access to gathering and takeaway capacity to handle crude oil and natural gas production expected from future development of the play.

Our STACK properties represented ~~13%~~9% of our total proved reserves as of December 31, ~~2017~~2020 and ~~17%~~12% of our average daily Boe production for the fourth quarter of ~~2017.~~2020. Production in STACK ~~increased to an average rate of 47,914~~averaged 42,281 Boe per day during the fourth quarter of ~~2017, up 96% over~~2020, down 18% from the ~~2016~~2019 fourth ~~quarter due to additional drilling and completion activity resulting from our drilling program.~~quarter. For the year ended December 31, ~~2017,~~2020, average daily production in STACK ~~grew 113% over 2016.~~decreased 30% compared to 2019, reflecting our reduction in drilling and completion activities and the impact of voluntary production curtailments during the year. We participated in the drilling and completion of ~~160~~22 gross ~~(49~~(8 net) wells in STACK during ~~2017~~2020 compared to 97103 gross ~~(26~~(19 net) wells in ~~2016.~~2019. Proved reserves ~~increased 4%~~in STACK decreased 46% year-over-year to ~~167~~98 MMBoe as of December 31, ~~2017~~2020 primarily due to ~~reserves added from our drilling program, continued improvement in recoveries driven by advances in optimized completion designs, and upward~~downward reserve revisions prompted by ~~higher~~significantly reduced commodity prices and resulting changes in ~~2017.~~ drilling plans. Our inventory of proved undeveloped drilling locations in STACK totaled ~~195~~25 gross ~~(90~~(9 net) wells as of December 31, ~~2017.~~2020.

For 2021, our aggregate budget for exploration and development capital expenditures in the South region is $380 million. In ~~2018,~~2021, we ~~plan~~expect to ~~invest approximately $317 million to drill, complete and initiate~~have first production on ~~180~~120 gross ~~(37~~(57 net) operated and non-operated wells in ~~STACK.~~the South region. We plan to average approximately ~~eight~~four operated rigs ~~in STACK throughout 2018 compared to nine rigs as of December 31, 2017. Additionally, we plan to use, on average, three~~and two well completion crews in ~~STACK throughout 2018 compared to five crews as of December 31, 2017.~~the South region in 2021. Our ~~2018~~2021 activities will focus on ~~delineating and de-risking our acreage, expanding the known productive extent of the play through the completion of new density test projects, monitoring production from optimized completions, and~~ continued ~~refinement of our geologic and economic models~~row development in Project SpringBoard in the ~~area.~~

SCOOP play and ongoing development in areas that provide opportunities to improve capital efficiency, reduce finding and development costs, improve recoveries and rates of return, and maximize cash flows.

Production and Price History

The following table sets forth information concerning our production results, average sales prices and production costs for the years ended December 31, ~~2017, 2016~~2020, 2019 and ~~2015~~2018 in total and for each field containing 15 percent or more of our total proved reserves as of December 31, ~~2017 (North Dakota Bakken~~2020.


	Year ended December 31,
	2020		2019		2018
Net production volumes:
Crude oil (MBbls)
North Dakota Bakken	40,052		52,420		45,775
SCOOP	12,585		11,679		6,918
Total Company	58,745		72,267		61,384
Natural gas (MMcf)
North Dakota Bakken	97,532		98,186		78,448
SCOOP	136,410		111,436		99,397
Total Company	306,528		311,865		284,730
Crude oil equivalents (MBoe)
North Dakota Bakken	56,308		68,784		58,849
SCOOP	35,320		30,252		23,484
Total Company	109,833		124,244		108,839
Average net sales prices (1):
Crude oil ($/Bbl)
North Dakota Bakken	$	33.53	$	50.96	$	58.37
SCOOP	37.88		54.92		62.74
Total Company	34.71		51.82		59.19
Natural gas ($/Mcf)
North Dakota Bakken	$	0.23	$	1.28	$	3.33
SCOOP	1.64		2.36		3.41
Total Company	1.04		1.77		3.01
Crude oil equivalents ($/Boe)
North Dakota Bakken	$	24.24	$	40.66	$	49.83
SCOOP	19.90		29.80		32.88
Total Company	21.47		34.56		41.25
Average costs per Boe:
Production expenses ($/Boe)
North Dakota Bakken	$	4.35	$	4.28	$	4.40
SCOOP	1.06		1.21		1.34
Total Company	3.27		3.58		3.59
Production taxes ($/Boe)	$	1.75	$	2.88	$	3.25
General and administrative expenses ($/Boe)	$	1.79	$	1.57	$	1.69
DD&A expense ($/Boe)	$	17.12	$	16.25	$	17.09

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

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

The following table sets forth information regarding our average daily production by region for the fourth quarter of ~~2017:~~2020:


	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 2017 Daily Production
Crude Oil
(Bbls per day) Natural Gas
(Mcf per day) Total
(Boe per day)
North Region:
Bakken field
North Dakota Bakken 124,811
202,975
158,640
Montana Bakken 5,497
8,761
6,958
Red River units
Cedar Hills 6,830
1,154
7,022
Other Red River units 2,073
2,410
2,475
Other 82
2,318
468
South Region:
SCOOP 14,551
286,148
62,242
STACK 13,788
204,754
47,914
Other 434
4,998
1,266
Total 168,066
713,518
286,985

Productive Wells

Gross wells represent the number of wells in which we own a working interest and net wells represent the total of our fractional working interests owned in gross wells. The following table presents the total gross and net productive wells by region and by crude oil or natural gas completion as of December 31, ~~2017.~~2020.One or more completions in the same well bore are counted as one well.


	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

Crude Oil Wells Natural Gas Wells Total Wells
Gross Net Gross Net Gross Net
North Region:
Bakken field
North Dakota Bakken 4,083
1,313
—
—
4,083
1,313
Montana Bakken 401
263
—
—
401
263
Red River units

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

Title to Properties

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

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

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

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

Marketing ~~and Major Customers~~

~~Most~~We sell most of our operated crude oil production ~~is sold~~ to ~~either~~ crude oil refining companies or midstream marketing companies at major market centers. ~~Other operated production not sold at major market centers is sold at the lease.~~ In the Bakken, SCOOP, and STACK areas we have significant volumes of production directly connected to pipeline gathering systems, with the remaining ~~balance of~~ production ~~being~~ primarily transported by ~~truck. Additionally in the Bakken, a portion of our production is sold to counterparties that are connected to rail delivery systems. Where directly marketed crude oil is transported by~~ truck ~~it is delivered~~ to a point on a pipeline system for further delivery. We do not transport any of our oil production prior to sale by rail, but several purchasers of our Bakken production are connected to rail delivery ~~or is delivered directly~~systems and may choose those methods to ~~a refinery. Where~~transport the oil they purchase from us. We sell some operated crude oil ~~is sold~~production at the ~~lease the sale is complete at that point.~~lease. Our share of crude oil production from non-operated properties is marketed at the discretion of the operators.

~~The majority of~~We sell our operated natural gas production ~~is sold~~to midstream customers at our lease locations ~~to midstream purchasers under term contracts.~~based on market prices in the field where the sales occur. These contracts include multi-year term agreements, many with acreage ~~dedication. Some of our contracts allow us~~dedications. Under certain arrangements, we have the ~~flexibility~~right to ~~accept, as partial payment for our sale of gas in the field, an “in-kind”~~take a volume of processed residue gas and/or natural gas liquids ("NGLs") in-kind at the tailgate of the midstream ~~purchaser’s~~customer's processing ~~plant.~~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 ~~elect~~do take volumes in kind, we pay third parties to ~~do so,~~transport the residue gas volumes taken in kind to downstream delivery points, where we ~~transport this processed gas~~then sell to acustomers at prices applicable to those downstream ~~market where it is sold.~~markets. Sales at ~~these~~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 ~~gas~~products we elect to take in-kind in lieu of ~~cash~~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.

~~Our marketing of crude oil and natural gas can be affected by factors beyond our control, the effects of which cannot be accurately predicted. For a description of some of these factors, see~~ ~~Part I, Item 1A. Risk factors—Our business depends on crude oil and natural gas transportation, processing and refining facilities, most of which are owned by third parties.~~

For the year ended December 31, 2017, sales to BP p.l.c. and affiliates and Phillips 66 and affiliates accounted for approximately 11% and 11%, respectively, 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 2017. The loss of any single purchaser will not have a material adverse effect on our operations, as crude oil and natural gas are fungible products with well-established markets and numerous 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 ~~the exploration, development, production or sale of crude oil~~our operations and ~~natural gas and~~may increase the cost of doing business and ~~affect~~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 ~~any~~ future legislative or regulatory initiatives will affect us ~~in a manner~~ 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

Sales of crude oil and natural gas liquids (“NGLs”) or condensate in the United States are not currently subject to price controls and are made at negotiated prices. Nevertheless, the U.S. Congress could enact price controls in the future. Beginning in the 1970s, the United States regulated the exportation of petroleum and petroleum products, which restricted the markets for these commodities and affected sales prices. However, in December 2015 the U.S. Congress passed a legislative bill eliminating the export restrictions beginning in January 2016.

~~With regard to our~~Our physical sales of crude oil and any derivative instruments relating to crude oil we are ~~required~~subject to ~~comply with~~ anti-market manipulation laws and related regulations enforced by the Federal Trade Commission (“FTC”) and the Commodity Futures Trading Commission (“CFTC”). ~~See~~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 ~~discussion below of “Other Federal Laws~~commodity and ~~Regulations Affecting Our Industry—FTC and CFTC Market Manipulation Rules.”~~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.

~~Our~~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 ~~NGLs, as well as other liquid products,~~natural gas liquids ("NGLs") is subject to rate and access regulation. The Federal Energy Regulatory Commission (“FERC”) regulates interstate crude oil and NGL pipeline transportation rates under the Interstate Commerce Act and the Energy Policy Act of 1992, and the rules and regulations promulgated under those laws. In general, pipeline rates must be just and reasonable and must not be unduly discriminatory or confer any undue preference upon any shipper. Oil and other liquid pipeline rates are often cost-based, although some pipeline charges today are based on historical rates adjusted for inflation and other factors, and other charges may result from settlement rates agreed to by all shippers or market-based rates, which are permitted in certain circumstances. FERC or interested persons may challenge existing or changed rates or services. Intrastateintrastate crude oil and NGL pipeline transportation rates may be subject to regulation by state regulatory commissions. ~~The basis for intrastate pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate crude oil pipeline rates, varies from state to state.~~ As the interstate and intrastate transportation rates we pay are generally applicable to all comparable shippers, the regulation of ~~intrastate~~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.

~~We transport~~From time to time we may sell our operated crude oil production ~~from our North region to~~at market centers ~~using primarily~~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 ~~combination~~1% improvement in the efficiency of ~~pipeline~~fleets each year between 2015 and ~~rail transportation facilities owned~~2025. In conjunction with this initiative, the IMO issued regulations requiring ship owners to lower the concentration of the sulfur content used in their fuels from 3.5% to 0.5% beginning on January 1, 2020. To achieve and ~~operated by third parties. Approximately 6% of such production was shipped by rail in December 2017,~~maintain compliance with the ~~remainder being shipped primarily by pipeline. The U.S. Department of Transportation’s (“U.S. DOT”) Pipeline~~new regulations, it is expected ship owners will either have to switch to more expensive higher quality marine fuel, install and ~~Hazardous Materials Safety Administration (“PHMSA”) establishes safety regulations relating~~utilize emissions-cleaning systems, or switch to transportation of crude oil by rail and pipeline. Third party rail operators are subject to the regulatory jurisdiction of the Surface Transportation Board of the U.S. DOT, the Federal Railroad Administration (“FRA”), the U.S. Occupational Safety and Health Administration ("OSHA"), and other federal regulatory agencies. Additionally, various state and local agencies have jurisdiction over disposal of hazardous waste and regulate movement of hazardous materials if not preempted by federal law.

In 2008, the U.S. Congress passed the Rail Safety and Improvement Act, which implemented regulations governing different areas related to railroad safety. Subsequently, the FRA and PHMSA have taken several actions related to the transport of crude

~~oil, including but not limited to: issuing an order requiring testing, classification and handling of crude oil~~alternative fuels such as a hazardous material; requiring expanded hazardous material route planning for railroads to avoid populated and other sensitive areas; issuing safety advisories, alerts, emergency orders and regulatory updates; conducting special unannounced inspections; issuing rules to enhance tank car standards for certain trains carrying crude oil and ethanol; and reaching agreement with the railroad industry on a series of voluntary actions it can take to improve safety. In May 2014 the U.S. DOT issued an order requiring all railroads operating trains containing large amounts of Bakken crude oil to notify state emergency response commissions about the operation of such trains through their states. The order requires each railroad operating trains containing more than 1,000,000 gallons of Bakken crude oil, or approximately 35 tank cars, in a particular state to provide the state with notification regarding the volumes of Bakken crude oil being transported, frequencies of anticipated train traffic and the route through which Bakken crude oil will be transported. Also in May 2014, the FRA and PHMSA issued a safety advisory to the rail industry strongly recommending the use of tank cars with the highest level of integrity in their fleet when transporting Bakken crude oil. In May 2015, PHMSA published a final rule which requires, among other things, enhanced tank car standards for new and existing tank cars, a classification and testing program for crude oil, and a requirement that older DOT-111 tank cars be retrofittedliquefied natural gas. Failure to comply with ~~new tank car design standards~~the regulations may result in ~~accordance with~~fines or shipping vessels being detained, thereby resulting in exportation capacity constraints that inhibit a specified timeline beginning as early as January 1, 2018. However, in December 2017 PHMSA announced it would initiate a rulemaking to rescind the May 2015 rule's requirements regarding electronically controlled pneumatic brakes. In August 2016, PHMSA released a final rule mandating a phase-out schedule for all DOT-111 tank cars usedthird party's ability to transport ~~Class 3 flammable liquids between 2018~~ and ~~2029. Separately, in July 2016 PHMSA proposed a new rule to expand the applicability of comprehensive~~sell domestic crude oil spill response plans so that any railroad transporting a single train carrying 20 or more loaded tank cars of liquid petroleum oil in a continuous block or a single train carrying 35 or more loaded tank cars of liquid petroleum oil throughout the train mustproduction overseas, which may have a ~~current, comprehensive, written plan. Issuance~~material impact on the markets and prices for various grades of domestic and international crude oil. The ultimate long-term impact of the ~~final rule remains pending.~~IMO regulations is uncertain.

We do not own or operate pipeline or rail transportation facilities, rail cars, or ~~rail cars; however,~~infrastructure used to facilitate the exportation of crude oil. However, regulations that impact the ~~testing or rail~~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, which could have a material adverse effect on our financial condition, results of operations and cash flows.~~States. We do not expect such regulations will affect us in a materially different way than similarly situated competitors.

In June 2016 the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act (“PIPES Act”) was signed into law. The PIPES Act extends PHMSA’s safety authority through 2019 and includes provisions on advancing the safe transportation of energy commodities and other hazardous materials. The PIPES Act includes provisions aimed at increasing inspection requirements for certain underwater crude oil pipelines; improving protection of coastal areas by designating them as environmentally sensitive to pipeline failures; setting minimum safety standards for underground natural gas storage facilities, and promoting better use of data and technology to prevent damage and improve safety of pipeline systems, among other things. PHMSA published a final rule in January 2017 expanding integrity management and reporting requirements for certain hazardous liquid pipelines and gathering lines; however, implementation of the final rule was stayed following the change in U.S. Presidential Administrations. The final rule is expected to be published in the federal register during the first quarter of 2018. We do not expect such regulations will affect us in a materially different way than similarly situated competitors.

Pipeline regulations exist at the state level as well. In December 2014 the North Dakota Industrial Commission (“NDIC”) introduced rules designed to reduce the potential flammability of crude oil produced from the Bakken petroleum system (the Bakken, Three Forks, and Sanish Pool formations) before it is loaded and transported on railcars. The rules became effective in April 2015 and outline a series of standards for pressure and temperature for production facilities to follow in order to separate certain liquids and gases from the crude oil prior to transport. These rules do not affect us in a way that materially differs from our similarly situated competitors.

Regulation of sales and transportation of natural gas

~~In 1989,~~We are also required to observe the ~~U.S. Congress enacted~~aforementioned anti-market manipulation laws and related regulations enforced by the ~~Natural Gas Wellhead Decontrol Act, which removed all remaining price~~FERC and ~~non-price controls affecting wellhead~~CFTC in connection with physical sales of natural gas and any derivative instruments relating to natural gas. ~~The FERC, which has~~Additionally, the authority under the Natural Gas Act (“NGA”) to regulate prices, terms, and conditions for the sale of natural gas for resale in interstate commerce, has issued blanket authorizations for all gas resellers subject to FERC regulation, except interstate pipelines, to resell natural gas at market prices. However, either the U.S. Congress or the FERC (with respect to the resale of gas in interstate commerce) could re-impose price controls in the future. The U.S. Department of Energy (“U.S. DOE”) regulates the terms and conditions for the exportation and importation of natural gas (including liquefied natural gas or “LNG”). U.S. law provides for very limited regulation of exports to and imports from any country that has entered into a Free Trade Agreement (“FTA”) with the United States providing for national treatment of trade in natural gas; however, the U.S. DOE’s regulation of imports and exports from and to countries without an FTA is more comprehensive. The FERC also regulates the construction and operation of import and export facilities, including LNG terminals. Regulation of imports and exports and related facilities may materially affect natural gas markets and sales prices.

~~The~~ FERC regulates interstate natural gas transportation rates and service conditions under the ~~NGA~~Natural Gas Act and the Natural Gas Policy Act of 1978, ~~(“NGPA”),~~ which affects the marketing of natural gas we produce, as well as revenues we receive for sales of our natural gas. The FERC has endeavored to increase competition and make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory ~~basis. The FERC has stated open access policies are necessary to improve the competitive structure of the natural gas pipeline industry~~basis and to create a regulatory framework to put natural gas sellers into more direct contractual relations with natural gas buyers by, among other things, unbundling the sale of natural gas from the sale of transportation and storage services. The FERC has issued a series of orders to implement its open access policies. As a result, the interstate pipelines’ traditional role as wholesalers of natural gas has been eliminated and replaced by a structure under which pipelines provide transportation and storage services on an open access basis to others who buy and sell natural gas. Although the FERC’s orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry. We cannot provide any assurance the pro-competitive regulatory approach established by the FERC will continue. However, we do not believe any action taken by the FERC will affect us in a materially different way than similarly situated natural gas producers.

~~With regard to our physical sales~~The gathering of natural gas, and derivative instruments relating to natural gas, we are required to observe anti-market manipulation laws and related regulations enforced by the FERC and the CFTC. See the discussion below of “Other Federal Laws and Regulations Affecting Our Industry—FTC and CFTC Market Manipulation Rules.” If we violate the anti-market manipulation laws and regulations, we could be subject to substantial penalties and related third-party damage claims by, among others, sellers, royalty owners and taxing authorities. In addition, pursuant to various FERC orders, we may be required to submit reports to the FERC for some of our operations. See the discussion below of “Other Federal Laws and Regulations Affecting Our Industry—FERC Market Transparency and Reporting Rules.”

~~Gathering service,~~ which occurs upstream of jurisdictional transmission services, is generally regulated by the states. Although its policies on gathering systems have varied in the past, the FERC has reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the potential to increase costs for our ~~costs of moving~~purchasers and reduce the revenues we receive for our natural gas ~~to point of sale locations.~~stream. State regulation of natural gas gathering facilities generally includes various safety, environmental, and in some circumstances, equitable take requirements. Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels in the future. We cannot predict what effect, if any, such changes may have on us, but the natural gas industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes, including changes in the interpretation of existing requirements or programs to implement those requirements. We do not believe ~~we would be affected by any~~ such ~~regulatory changes~~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 ~~and ship natural gas on an intrastate basis~~ will not affect us in a way that materially differs from our similarly situated competitors.

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

Regulation of production

The production of crude oil and natural gas is regulated by a wide range of federal, state, and local ~~statutes,~~laws, rules, ~~orders~~ and regulations, which require, among other matters, permits for drilling operations, drilling bonds, and reports concerning operations. Each of the states where we own and operate properties have laws and regulations governing conservation, including provisions for the unitization or pooling of crude oil and natural gas properties, the establishment of maximum allowable rates of production from crude oil and natural gas wells, the regulation of well spacing, the plugging and abandonment of wells, the regulation of greenhouse gas emissions, and limitations or prohibitions on the venting or flaring of natural gas. These laws and regulations directly and indirectly limit the amount of crude oil and natural gas we can produce from our wells and the number of wells and locations we can drill, although we can and do apply for exceptions to such laws and regulations or to have reductions in well spacing. Moreover, each state generally imposes a production, severance or excise tax on the production and sale of crude oil, natural gas and natural gas liquids within its jurisdiction.

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

~~Other federal~~ laws, ~~and regulations affecting our industry~~

~~Dodd-Frank Wall Street Reform and Consumer Protection Act.~~ In July 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) was enacted into law. The Dodd-Frank Act established federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The Dodd-Frank Act requires the CFTC, the SEC, and other regulators to establish rules, and regulations to implement the new legislation. Although the CFTC has issued final regulations to implement significant aspects of the legislation, others remain to be finalized or implemented and it is not possible at this time to predict when this will be accomplished. Additionally, certain aspects of the Dodd-Frank Act were repealed by the U.S. Congress in 2017.

In November 2013 and December 2016, the CFTC proposed rules establishing position limits with respect to certain futures and option contracts and equivalent swaps, subject to exceptions for certain bona fide hedging. As these new position limit rules are not yet final, the impact of these provisions on us is uncertain at this time.

Pursuant to the Dodd-Frank Act, absent an exception, mandatory clearing is now required for all market participants. The CFTC has designated certain interest rate swaps and credit default swaps for mandatory clearing. The CFTC has not yet required the clearing of any other classes of swaps, including physical commodity swaps, and the trade execution requirement does not apply to swaps not subject to a clearing mandate. Althoughas we expect to qualify for the end-user exception from the clearing requirement for our swaps entered into to hedge our commercial risks, the application of the mandatory clearing requirements to other market participants, such as swap dealers, along with changes to the markets for swaps as a result of the trade execution requirement, may change the cost and availability of the swaps we use for hedging. If any of our swaps do not qualify for the commercial end-user exception, or if the cost of entering into uncleared swaps becomes prohibitive, we may be required to clear such transactions or execute them on a derivatives contract market or swap execution facility. The ultimate effect of the proposed rules and any additional regulations on our business is uncertain.

In December 2015, the CFTC issued final rules establishing minimum margin requirements for uncleared swaps for swap dealers and major swap participants. The final rules do not impose margin requirements on commercial end users. Although we expect to qualify for the end-user exception from the margin requirements for swaps entered into to hedge our commercial risks, the application of such requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps we use for hedging. If any of our current or future swaps do not qualify for the commercial end-user exception, the posting of collateral could reduce our liquidity and cash available for capital expenditures and could reduce our ability to manage commodity price volatility and the volatility in our cash flows.

In addition to the CFTC’s swap regulations, certain foreign jurisdictions may adopt or implement laws and regulations relating to transactions in derivatives, including margin and central clearing requirements, which in each case may affect our counterparties and the derivatives markets generally. Other rules may alter the business practices of some of our counterparties and in some cases may cause them to stop transacting in or making markets in derivatives. Moreover, federal banking regulators are reevaluating the authorization under which banking entities subject to their authority may engage in physical commodities transactions.

Although we cannot predict the ultimate outcome of these rulemakings, they could result in increased costs and cash collateral requirements for the types of derivative instruments we use or otherwise limit our ability to manage our financial and commercial risks related to fluctuations in commodity prices. Additional effects of the regulations, including increased regulatory reporting and recordkeeping costs, increased regulatory capital requirements for our counterparties, and market dislocations or disruptions could have an adverse effect on our ability to hedge risks associated with our business.

~~Energy Policy Act of 2005.~~ The Energy Policy Act of 2005 (“EPAct 2005”) included a comprehensive compilation of tax incentives, authorized appropriations for grants and guaranteed loans, and made significant changes to the statutory framework affecting the energy industry. For example, EPAct 2005 amended the NGA to add an anti-market manipulation provision making it unlawful for any entity to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of natural gas or the purchase or sale of transportation services subject to regulation by the FERC, in contravention of rules prescribed by the FERC. In January 2006 the FERC issued rules implementing the anti-market manipulation provision of EPAct 2005. These anti-market manipulation rules apply to natural gas pipelines and storage companies which provide interstate services, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” natural gas sales, purchases or transportation subject to FERC jurisdiction, which now includes the annual reporting requirements described further below. The EPAct 2005 also provides the FERC with the power to assess civil penalties of up to $1,000,000 per day per violation for violations of the NGA and NGPA and disgorgement of profits associated with any violation.

~~FERC Market Transparency and Reporting Rules.~~ The FERC requires wholesale buyers and sellers of more than 2.2 million MMBtus of physical natural gas in the previous calendar year to report, on May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices. The FERC also requires market participants to indicate whether they report prices

to any index publishers and, if so, whether their reporting complies with the FERC’s policy statement on price reporting. Failure to comply with these reporting requirements could subject us to enhanced civil penalty liability under the EPAct 2005.

~~FTC and CFTC Market Manipulation Rules~~. Wholesale sales of petroleum are subject to provisions of the Energy Independence and Security Act of 2007 (“EISA”) and regulations by the FTC. Under the EISA, the FTC issued its Petroleum Market Manipulation Rule (the “Rule”), which became effective in November 2009. The Rule prohibits fraudulent or deceptive conduct (including false or misleading statements of material fact) in connection with wholesale purchases or sales of crude oil or refined petroleum products. Under the EISA, the FTC has authority to request a court to impose fines of up to $1,000,000 per day per violation. The CFTC has also adopted anti-market manipulation regulations prohibiting, among other things, fraud and price manipulation in the commodity and futures markets. The CFTC may assess fines of up to the greater of $1,000,000 or triple the monetary gain for violations of these anti-market manipulation regulations. Knowing or willful violations of the Commodity Exchange Act is also a felony.

Additional proposals and proceedings potentially affecting the crude oil and natural gas industry are brought before the U.S. Congress, the FERC and the courts from time to time. We cannot predict the ultimate impact these or the above laws and regulations may have on our crude oil and natural gas operations. We do not believe we will be affected in a materially different way than our similarly situated competitors.are.

Environmental regulation

~~General~~.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.~~

~~In March 2017, President Donald Trump issued an Executive Order titled “Promoting Energy Independence~~costs and ~~Economic Growth” (the "March 2017 Executive Order") which states it is in the national interest~~production of the United States to promote clean and safe development of energy resources, while at the same time avoiding regulatory burdens that unnecessarily encumber energy production, constrain economic growth, and prevent job creation. The March 2017 Executive Order requires, among other things, the executive department and agencies to review existing regulations that potentially burden the development or use of domestically produced energy resources (with particular attention to crude oil, natural gas, coal, and nuclear energy) and suspend, revise, or rescind those regulations that unduly burden the development of such resources beyond the degree necessary to protect the public interest or otherwise comply with the law. In response to the March 2017 Executive Order, certain energy and climate-related regulations proposed or enacted under previous presidential administrations have been, or are in the process of being, reviewed, suspended, revised, or rescinded, some of which are described further below. Numerous regulations impacting the crude oil and ~~natural gas industry are not expected to be impacted by the March 2017 Executive Order and will continue to be in effect. Additionally,~~ undoing previously existing environmental regulations will likely involve lengthy notice-and-comment rulemaking and the resulting decisions may then be subject to litigation by opposition groups. Thus, it could take several years before existing regulations are revised or rescinded. Although further regulation of our industry may stall at the federal level under the March 2017 Executive Order, certain states have pursued additional regulation of our operations and other states may do so as well.

~~Environmental laws, rules and regulations~~. Some of the existing environmental laws, rules and regulations we are subject to include: (i) regulations by the U.S. Environmental Protection Agency (“EPA”) and various state agencies regarding approved methods of disposal for certain hazardous and nonhazardous wastes; (ii) the federal Comprehensive Environmental Response,

Compensation, and Liability Act and analogous state laws that may require the removal of previously disposed hazardous substances (including hazardous substances disposed of or released by prior owners or operators), the cleanup of property contamination (including groundwater contamination), and remedial lease restoration activities to prevent future contamination from prior operations; (iii) federal Department of Transportation safety laws and comparable state and local requirements; (iv) the federal Clean Air Act and comparable state and local requirements, which establish pollution control requirements for air emissions from our operations; (v) the federal Oil Pollution Act of 1990, which contains numerous requirements relating to the prevention of and response to oil spills into waters of the United States; (vi) the Federal Water Pollution Control Act, also known as the Clean Water Act, and analogous state laws which impose restrictions and strict controls with respect to the discharge of pollutants, including crude oil and other substances generated by our operations, into waters of the United States or state waters; (vii) the federal Resource Conservation and Recovery Act, which is the principal federal statute governing the treatment, storage and disposal of solid and hazardous wastes, and comparable state statutes; (viii) the federal Safe Drinking Water Act ("SDWA") and analogous state laws which impose requirements relating to our underground injection activities; (ix) the National Environmental Policy Act and comparable state statutes, which require government agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment; (x) the federal Endangered Species Act and comparable state statutes, which afford protections to certain plant and animal species; (xi) the federal Migratory Bird Treaty Act, which imposes certain restrictions for the protection of migratory birds; (xii) the federal Bald and Golden Eagle Protection Act, which imposes certain restrictions for the protection of bald and golden eagles; (xiii) the federal Emergency Planning and Community Right to Know Act and comparable state statutes, which require that we organize and/or disclose information about hazardous materials stored, used or produced in our operations, and (xiv) state regulations and statutes governing the handling, treatment, storage and disposal of technologically enhanced naturally occurring radioactive material.gas. Failure to comply with these and other laws, rules and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of corrective or remedial obligations or the incurrence of capital expenditures, the occurrence of restrictions, delays or cancellations in the permitting, development or ~~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 ~~the emission~~ of carbon dioxide, methane and other identified “greenhouse ~~gases” may have~~gas” emissions on the environment and climate worldwide, generally referred to as “climate change.” For example, ~~in October~~since 2015 the ~~EPA revised~~U.S. Environmental Protection Agency ("EPA") under the Obama Administration has made revisions to the National Ambient Air Quality Standard (“NAAQS”) for ground-level ozone, ~~from 75 to 70 parts per billion for both~~making the ~~8-hour primary~~standard stricter. Since that time, the EPA under the Trump Administration has issued attainment and ~~secondary standards. The EPA~~nonattainment designations and, on December 31, 2020, published notice of a final ~~rule in November 2017 that issued area designations with respect to ground-level ozone for approximately 35%~~action, upon conducting a periodic review of the ~~U.S. counties, including all of~~ozone standard, electing to retain the ~~counties~~2015 ozone NAAQS in ~~North Dakota~~2020 without revision on a going-forward basis. However, this December 2020 final action is subject to legal challenge, and ~~all of~~ the ~~counties except for Bryan County in Oklahoma, as either “attainment/unclassifiable” or “unclassifiable” and is expected~~NAAQS may be subject to ~~issue attainment or nonattainment designations for the remaining areas of the U.S. not addressed~~further revision under the ~~November 2017 rule in the first half of 2018. Additionally, state~~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. ~~The EPA has also adopted regulations under~~

With respect to climate change and the control of greenhouse gas emissions, 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 ~~provisions~~emissions of ~~the federal Clean Air Act~~greenhouse gases as well as to restrict or eliminate future emissions. Federal regulatory initiatives have focused on establishing ~~among other things, Prevention of Significant Deterioration (“PSD”) pre-construction~~construction and ~~Title V~~ operating permit reviews for greenhouse gas emissions from certain large stationary sources. Moreover, the EPA’s source determination rule specifies that oil and gas production facilities are considered to be “adjacent” (and therefore aggregated for air permitting purposes) if they are on the same site or on sites that share equipment and are within ¼ mile of each other. This rule increases the potential for individual well facilities to be viewed collectively by the EPA as a single, large stationary source and, therefore, subject to PSD and/or Title V. Regulations related to greenhouse gas emissions could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources.

~~In addition, the EPA has adopted rules~~sources, requiring the monitoring and annual reporting of greenhouse gas emissions from ~~specified onshore~~certain petroleum and ~~offshore~~natural gas system sources, and reducing methane emissions from oil and gas ~~production sources~~operations through limitations on venting and flaring and the implementation of enhanced emission leak detection and repair requirements. For example, in 2016 the ~~United States on an annual basis, which include certain of our operations. New~~EPA under the Obama Administration finalized new regulations (New Source Performance Standard (“NSPS”) Subpart OOOO (“Quad O”) requires, among other things, the reduction of volatile organic compound (“VOC”) emissions from three subcategories of fractured and refractured oil and gas wells for which well completion operations are conducted: wildcat (exploratory) and delineation gas wells; low reservoir pressure non-wildcat and non-delineation gas wells; and all “other” fractured and refractured oil and gas wells. All three subcategories of wells must route flowback emissions to a gathering line or be captured and combusted using a combustion device such as a flare. However, the “other” fractured and refractured wells must use reduced emission completions or “green completions.” The rule also established specific new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other production equipment. The rule is designed to limit emissions of VOCs, sulfur dioxide, and hazardous air pollutants from a variety of sources within natural gas processing plants, oil and natural gas production facilities, and natural gas transmission compressor stations. We have modified our operations and well equipment as needed to comply with these rules. Ongoing compliance with the rules is not expected to affect us in a way that materially differs from our similarly situated competitors.

~~In addition, in June 2016 the EPA finalized new regulations (NSPS~~ Subpart OOOOa, commonly referred to as “Quad Oa”) setting methane emission standards for new and modified oil and gas production and natural gas processing and transmission ~~facilities~~facilities. However, in ~~an effort~~recent years following the beginning of the Trump Administration in 2017, the EPA has undertaken several measures to ~~reduce~~delay implementation of the methane ~~emissions~~standards. Recently, in September 2020, the EPA issued

its final policy and technical amendments to the 2016 final rule. The 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 the September 2020 policy amendments is expected to follow. The January 20, 2021 executive order also directed the establishment of new methane and volatile organic compound standards applicable to existing oil and gas ~~sector by up to 45% from 2012 levels by 2025 even though~~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 ~~was consensus at~~exists the ~~time that oil and gas producers’ compliance with Quad O had already achieved reductions in methane emissions.~~

However, in June 2017, the EPA proposed to stay certain portions of the NSPS Quad Oa rules described above for a period of two years while the rules are reconsidered in response to President Trump’s March 2017 Executive Order to reduce the burden of federal regulations that may hinder economic growth and energy development. The EPA has not yet published a final rule issuing the stay, and, as a result, the Quad Oa rules are currently in effect but future implementation of the Quad Oa rules is uncertain at this time. As part of its reconsideration, the EPA may issue revised rules, the timing and impact ofUnited Nations-sponsored "Paris Agreement," which is ~~uncertain.~~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 government to begin formulating the United States’ nationally determined emissions reduction goal under the agreement. With the United States recommitting to the Paris Agreement, executive orders may be issued or federal legislation or regulatory initiatives may be adopted to achieve the agreement’s goals, which could require us to incur increased costs to comply with such requirements.

~~Additional regulation~~In addition, increasing concern over the threat of climate change arising from greenhouse gas emissions has given rise to a series of political, litigation, and financial risks associated with ~~respect~~the production and processing of hydrocarbons and emission of greenhouse gases. In addition to ~~methane emissions occurred in November 2016 when~~recommitting the United States to the Paris Agreement, on January 20, 2021, the Acting Secretary of the U.S. Department of ~~Interior’s Bureau of Land Management (“BLM”) published a final rule commonly referred to as~~ the ~~“BLM Venting and Flaring Rule.” Similar to Quad Oa, the BLM Venting and Flaring Rule imposes requirements related to methane emissions from~~Interior issued an order, effective immediately, that suspends new crude oil and natural gas ~~sources. However,~~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 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 ~~response to President Trump’s March 2017 Executive Order,~~January 2021 in ~~December 2017 the BLM announced it was temporarily suspending or delaying certain requirements contained in its Venting and Flaring Rule until January 2019. That suspension is now being challenged in~~Wyoming federal district court and ~~future implementation~~seeking to have the moratorium on leasing declared invalid. Litigation risks are also increasing, as a number of states, municipalities and ~~impact~~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 ~~rule remains uncertain.~~ 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 ~~additional federal regulation with respect~~we cannot predict the outcome of legislative or regulatory initiatives related to ~~methane emissions appears unlikely in the near future, states may nevertheless pursue rules or enforcement actions designed~~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 ~~emissions. To the extent new methane emission regulations~~—~~whether it is the BLM Venting~~ and ~~Flaring Rule, a prospective EPA rule targeting methane emissions from existing sources, or a state agency~~—~~impose reporting obligations on, or limit emissions of greenhouse gases from, our equipment and operations they~~carbon dioxide, could require us to incur increased operating costs, such as costs to ~~reduce~~purchase and operate emissions ~~associated with our operations, but the impact of these measures is not expected to be material and will not affect us in a materially different way from our similarly situated competitors.~~

At an international level, in December 2015 a global climate agreement was reached in Paris at the 21st Conference of Parties organized by the United Nations under the Framework Convention on Climate Change. The agreement, which goes into effect in 2020, resulted in nearly 200 countries, originally including the United States, committing to work towards limiting global warming and agreeing to a monitoring and ~~review process of greenhouse gas emissions. The agreement includes binding~~control systems, to acquire emissions allowances, or comply with new regulatory or reporting requirements. Additionally, political, litigation, and non-binding elements and did not require ratification by the U.S. Congress. In June 2017, President Trump announced the United States will withdraw from and cease implementation of the Paris climate agreement, but indicated the U.S. may re-engage in the agreement if more favorable terms can be re-negotiated. In August 2017, the U.S. State Department officially informed the United Nations of the intent of the United States to withdraw from the Paris climate agreement. The exit process provided for under the Paris agreement could take up to four years. The United States’ adherence to the exit process is uncertain and the terms on which the United States may reenter the Paris agreement or a separately negotiated agreement are unclear. Although the U.S. has ceased its participation in the Paris agreement, the agreement nonethelessfinancial risks may result in ~~increased political pressure on the United States~~restrictions or cancellations in development and production activities, liability for infrastructure damages due to ~~ensure continued compliance with enforcement measures under the Clean Air Act and may spur further initiatives aimed at reducing greenhouse gas emissions~~climate changes, or increases in the ~~future.~~

~~While the U.S. Congress has from time to time considered legislation to reduce emissions~~cost of greenhouse gases, there has not been significant activity in the form of enacted legislation to reduce greenhouse gas emissions at the federal level in recent years. In the absence of such federal legislation, a number of stateconsuming hydrocarbons and ~~regional efforts have emerged aimed at tracking and~~thereby reducing greenhouse gas emissions by means of cap and trade programs that typically require major sources of greenhouse gas emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those greenhouse gases. There has also been discussion of imposing a federal carbon tax on all fossil fuel production, though such a tax appears unlikely at this time. Although it is not possible to predict how such legislation or new regulations adopted to address greenhouse gas emissions will impact our business, any future laws and regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations could require us to incur costs to reduce emissions of greenhouse gases associated with our operations. In addition, substantial limitations on greenhouse gas emissions could adversely affect the demand for ~~the~~ crude oil and natural gas. 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, 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, ~~lower~~separately, the ~~value~~

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

Both the EPA and the state of North Dakota pursued enforcement actions in 2016 against operators related to emissions generally and alleged noncompliance with the requirements of Quad O, Quad Oa, and relevant state regulations more specifically. One such enforcement action by the EPA against an operator resulted in a consent decree between the parties

requiring the operator to incur costs associated with a civil penalty, emissions-related mitigation projects, and implementation of a robust leak detection and repair program applicable to all of the operator’s wells in North Dakota.

Finally, the U.S. Department of Justice (“DOJ”) announced in 2016 it had partnered with the Occupational Safety and Health Administration to pursue a “Worker Endangerment Initiative” seeking to promote worker safety by pursuing not only worker safety claims in connection with worker safety incidents but also environmental claims.

Environmental protection and natural gas flaring. We strive to operate in accordance with all applicable regulatory and legal requirements and have focused on continuously improving our environmental performance; however, at times circumstances may arise that adversely affect our compliance with applicable environmental requirements. We have established internal policies, procedures and processes regarding environmental matters for all employees, contractors, and vendors. In connection with our environmental initiatives, we work to identify and manage our environmental risks and the impact of our operations and continually improve our environmental compliance. However, we cannot guarantee our efforts will always be successful.

One of our environmental initiatives is the reduction of air emissions produced from our operations, ~~particularly with respect 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 ~~NDIC~~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. While the NDIC ultimately determines the volume and value of any such gas flared and the applicable royalties and production taxes, the NDIC has thus far generally accepted our methods for calculating these amounts. Furthermore, the NDIC has generally accepted applications we have submitted to secure exemptions from the post-year flaring restrictions. Finally,

In addition, NDIC rules for new drilling permit applications also require the submission of gas capture plans ~~addressing 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. ~~Thus far, the~~The NDIC ~~has generally accepted our gas capture plans submitted with applications for drilling permits. The deadline to comply with the requirement~~currently requires us to capture ~~85%~~91% of the natural gas produced from a ~~field was November 1, 2016, and~~field. If an operator is unable to attain the ~~target~~applicable gas capture percentage ~~increases~~goal at maximum efficient rate, wells will be restricted in production to ~~88% beginning November 1, 2018~~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 ~~91% beginning November 1, 2020.~~hearing if the effect is a significant net increase in gas capture within one year of the date such relief is granted. Monetary penalty provisions also apply under this regulation if an operator fails to timely file for a hearing with the NDIC upon being unable to meet such percentage goals or if the operator fails to timely implement production restrictions once below the applicable percentage goals. Ongoing compliance with the NDIC’s flaring requirements or the imposition of any additional limitations on flaring could result in increased costs and have an adverse effect on our operations.

~~For the year ended December 31, 2017, we delivered approximately 90% of our operated natural gas production in the North Dakota Bakken field~~We continue to ~~market, flaring approximately 10% compared~~strive to 9% in 2016 and 13% in 2015. According to data published by the NDIC, our industry as a whole flared approximately 12% of produced natural gas volumes in the North Dakota Bakken field during 2017. We are a participant in the NDIC’s Flaring Reduction Task Force and are engaged in working with other task force members and the NDIC to develop action plans for mitigatingreduce natural gas flaring ~~in the state. Flared natural gas volumes from~~as much as practicable, but our ~~operated SCOOP and STACK properties in Oklahoma are negligible given the existence of established natural gas transportation infrastructure.~~

There are environmental and financial risks associated with natural gas flaring, and we attempt to manage these risks on an ongoing basis. We have taken numerous actions to reduce flaring from our operated well sites, such as coordinating our well completion operations to coincide with well connections to gathering systems in order to minimize flaring; however, weefforts may not always be successful in these efforts. Our ultimate goal is to reduce natural gas flaring from our operated well sites as much as practicable. For example, in operating areas such as the Buffalo Red River units in South Dakota, the quality of the natural gas is not adequate to meet requirements for sale, so we employ processes to efficiently combust the gas in an effort to minimize impacts to the environment.or cost-effective. Our levels of flaring are ~~and will be dependent upon~~impacted by external factors such as investment from third parties in the development and continued operation of gas gathering ~~systems, state regulations,~~and processing facilities and the granting of reasonable right-of-way access by land owners. ~~For example, over the past year insufficient takeaway capacity in North Dakota has created challenges for all operators and contributed to an increase in volumes of flared gas.~~ Increased emissions from ~~a multi-well pad facility or centralized production~~our facilities due to flaring could ~~require us~~subject our facilities to adhere to PSD or Title V permit requirements. We have filed several permits to construct major sources (i.e., facilities from which emissions of a criteria pollutant (e.g., carbon monoxide or volatile organic compounds) are expected to exceed 100 tons per year) relating to facilities where takeaway capacity is currently constrained and creating a potential to emit in excess of 100 tons per year.

We have incurred in the past, and expect to incur in the future, capital and other expenditures related to environmental compliance. Such expenditures are included within our overall capital and operating budgets and are not separately itemized. Although we believe our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations, we cannot assure you the passage of more stringent ~~laws or regulations~~air emission permitting requirements, resulting in ~~the future will not materially impact our financial position, results of operations or cash flows.~~increased compliance costs and potential construction delays.

Hydraulic fracturing. Hydraulic fracturing involves the injection of water, sand or other proppant and additives under pressure into rock formations to stimulate crude oil and natural gas production. In recent years there has been ~~increased~~ public concern regarding an alleged potential for hydraulic fracturing to adversely affect drinking water supplies ~~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”~~("SDWA") over certain hydraulic fracturing activities involving the use of diesel fuels and published permitting guidance ~~in February 2014~~ related to such activities. ~~In May 2014,~~Also, the EPA has issued an Advance Notice of Proposed Rulemaking to collect data on chemicals used in hydraulic fracturing operations under Section 8 of the Toxic Substances Control Act. To date, no other action has been taken. In June 2016, the EPA finalized a final regulation under the Clean Water Act prohibiting discharges to publicly owned treatment works of wastewater from onshore unconventional oil and gas extraction facilities. ~~It has~~We do not ~~been our practice to~~ discharge wastewater to publicly owned treatment works, so the impact of this ~~new~~ regulation on us is not currently, and is not expected to be, material.

In ~~December~~late 2016 the EPA published a final study of the potential impacts of hydraulic fracturing activities on water ~~resources. In its report,~~resources in which the EPA indicated it found evidence ~~hydraulic fracturing~~that such activities can impact drinking water resources under some circumstances. The report identified certain conditions where impacts from hydraulic fracturing activities can potentially be more frequent or severe. These include water withdrawals for hydraulic fracturing in times or areas of low water availability; spills during the handling of hydraulic fracturing fluids, chemicals or produced water resulting in large volumes or high concentrations of chemicals reaching groundwater resources; injection of hydraulic fracturing fluids into wells with inadequate mechanical integrity thereby allowing gases or liquids to move to groundwater resources; injection of hydraulic fracturing fluids directly into groundwater resources; discharge of inadequately treated hydraulic fracturing wastewater to surface water; and disposal or storage of hydraulic fracturing wastewater in unlined pits thereby resulting in contamination of groundwater resources. In its final report, the EPA indicated it was not able to calculate or estimate the national frequency of impacts on drinking water resources from hydraulic fracturing activities or fully characterize the severity of impacts. Nonetheless, the results of the EPA’s study or similar governmental reviews could spur initiatives to regulate hydraulic fracturing under the SDWA or otherwise.

In ~~March 2015,~~2016, the BLM ~~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. ~~Several parties challenged the regulations and the U.S. District Court of Wyoming temporarily stayed implementation of the regulations. In June 2016, the U.S. District Court of Wyoming ruled~~However, the BLM ~~lacked~~under the ~~statutory authority to promulgate~~Trump Administration published a final rule rescinding the ~~regulations.~~The U.S. Department of Interior appealed the decision. In December 2017, the BLM formally rescinded its March 2015 hydraulic fracturing rules, citing unjustified administrative burdens and compliance costs arising from a reassessment performed2016 final rule in ~~response to President Trump's March 2017 Executive Order to reduce the burden of federal regulations that may hinder economic growth and energy development. In January 2018, litigation~~November 2018. Litigation challenging the BLM's ~~rescission of~~2016 final rule as well as its 2018 final rule rescinding the ~~March 2015~~2016 rule has been pursued by various states and industry and environmental groups. While a California federal court vacated the 2018 final ~~rules was brought~~rule in July 2020, a Wyoming federal ~~court. As of December 31, 2017, we held approximately 65,500 net undeveloped acres~~court subsequently vacated the 2016 final rule in October 2020 and, 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.

~~At the state level, several~~In addition, regulators in states in which we operate have adopted or are considering adopting legal requirements imposing more stringent permitting, disclosure and well construction requirements on hydraulic fracturing activities. Local governments also may seek to adopt ordinances within their jurisdictions regulating or prohibiting the time, place and manner of drilling activities or hydraulic fracturing activities. In certain areas of the United States, new drilling permits for hydraulic fracturing have been put on hold pending development of additional standards.

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

We voluntarily participate in FracFocus, a national publicly accessible Internet-based registry developed by the Ground Water Protection Council and the Interstate Oil and Gas Compact Commission. This registry, located at ~~www.fracfocus.org, provides~~

our industry with an avenue to voluntarily disclose additives used in the hydraulic fracturing process. The additives used in the hydraulic fracturing process on all wells we operate are disclosed on that website.

The adoption of any future federal, state or local laws, rules or implementing regulations imposing permitting or reporting obligations on, or otherwise limiting, hydraulic fracturing processes in areas in which we operate could make it more difficult and expensive to complete crude oil and natural gas wells in low-permeability formations, increase our costs of compliance and doing business, and delay, prevent or prohibit the development of natural resources from unconventional formations. Compliance, or the consequences of our failure to comply, could have a material adverse effect on our financial condition and results of operations. At this time it is not possible to estimate the potential impact on our business if such federal or state legislation is enacted into law.

Waste water disposal. 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 ~~has adopted~~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 ~~all~~ 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. Historically, our environmental compliance costs have not had a material adverse impact on our financial condition and results of operations; however, there can be no assurance that such costs will not be material in the future or that such future compliance will not have a material impact on our business, financial condition, results of operations or cash flows.

Employee Health and Safety. We are also subject to the requirements of the federal Occupational Safety and Health Act and comparable state ~~statutes~~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 ~~statutes~~laws and regulations require ~~that~~ information be maintained about hazardous materials used or produced in operations and ~~that~~ this information be provided to employees, state and local governmental authorities and citizens.

Human Capital

Employees and Labor Relations

As of December 31, ~~2017,~~2020, we employed ~~1,127 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 public may read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F Street N.E., Washington, D.C. 20549. The public may obtain information about the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. We file our reports with the SEC electronically. The SEC maintains an internet website that contains reports, proxy and information statements, and other information ~~regarding issuers that~~registrants file ~~electronically~~ with the SEC. The address of the SEC’s website is www.sec.gov.

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


~~Item 1A.~~	~~Risk Factors~~

Item 1A. Risk Factors

You should carefully consider each of the risks described below, together with all other information contained in this report in connection with an investment in our securities. If any of the following risks develop into actual events, our business, financial condition, or results of operations, or cash flows could be materially adversely affected, the trading price of our securities could decline and you may lose all or part of your investment.

Business and Operating Risks

Substantial declines in commodity prices or extended periods of low commodity prices adversely affect our business, financial condition, results of operations and cash flows and our ability to meet our capital expenditure needs and financial commitments.

The prices we receive for sales of our crude oil and natural gas production impact our revenue, profitability, cash flows, access to capital, capital budget, ~~and~~ rate of ~~growth.~~growth, and carrying value of our properties. Crude oil and natural gas are commodities and prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for crude oil and natural gas have been volatile and unpredictable. For example, during ~~2017~~2020 the NYMEX West Texas Intermediate (“WTI”) crude oil and Henry Hub natural gas spot prices ranged from ~~approximately $42~~negative $36.98 to ~~$60~~positive $63.27 per barrel and ~~$2.45~~$1.33 to ~~$3.70~~$3.14 per MMBtu, respectively. Commodity prices ~~may~~will likely remain volatile and unpredictable in ~~2018~~2021 and beyond.

~~We have hedged the majority~~ A significant portion of our ~~forecasted 2018 natural gas production. Our~~ future crude oil and natural gas production is ~~currently~~ unhedged as of the time of this filing and ~~directly~~is exposed to continued volatility in market prices, whether favorable or unfavorable.

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

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

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

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

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

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

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

•the level of global, national, and ~~global~~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 ~~countries;~~nations;

~~the nature and extent of domestic and foreign governmental regulations and taxation, including environmental regulations;~~

•localized supply and demand fundamentals;

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

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

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

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

Lower commodity prices may also reduce our access to capital and lead to a downgrade or other negative rating

action with respect to our credit rating. A downgrade of our credit rating could negatively impact our cost of capital, increase ~~the~~ borrowing costs under our revolving credit facility, and limit our ability to access capital markets and execute aspects of our business plans. As a result, substantial declines in commodity prices or extended periods of low commodity prices may materially and adversely affect our future business, financial condition, results of operations, cash flows, liquidity and ability to ~~finance planned~~meet our capital ~~expenditures~~expenditure needs and commitments.

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

The Organization of Petroleum Exporting Countries ("OPEC") is an intergovernmental organization that seeks to manage the price and supply of crude oil on the global energy market. Actions taken by OPEC members, including those taken alongside other oil exporting nations such as Russia, may have a significant impact on global oil supply and pricing. 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 prices at which it sold crude oil. These actions, coupled with the economic impact and uncertainty from the COVID-19 pandemic, led to 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 the future, or utilize other actions to support and stabilize oil prices, nor can there be any assurance they will not increase production or deploy other actions aimed at reducing oil prices. Uncertainty regarding future actions to be taken by OPEC members or other oil exporting countries could lead to increased volatility in the price of oil, which could have a material adverse effect on our business, financial condition, results of operations, and cash flows.

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

The COVID-19 pandemic has negatively impacted, and will likely continue to negatively impact, the global economy which has led to, among other things, reduced global demand for crude oil, disruption of global supply chains, and significant volatility and disruption of financial and commodity markets.

We began to experience material decreases in our revenues in the first quarter of 2020, which negatively impacted our business, financial condition, results of operations, cash flows and 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 ~~substantial portion~~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 isare 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 55%~~53% of our crude oil and natural gas production and ~~approximately 64%~~61% of our crude oil and natural gas revenues for the year ended December 31, ~~2017.~~2020. Approximately ~~48%~~46% of our estimated proved reserves were located in the Bakken as of December 31, ~~2017.~~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 31%~~35% of our crude oil and natural gas revenues for the year ended December 31, ~~2017.~~2020. Approximately ~~50%~~52% of our estimated proved reserves were located in Oklahoma as of December 31, ~~2017.~~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, ~~oilfield~~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 ~~financial condition, results of operations and cash flows.~~

~~Volatility in the financial markets or in global economic factors could adversely impact our access to capital and business and financial condition.~~

United States and global economies may experience periods of turmoil and volatility from time to time, resulting in diminished liquidity and credit availability, inability to access capital markets, high unemployment, unstable consumer confidence, and diminished consumer demand and spending. In recent years, certain global economies have experienced periods of political uncertainty, slowing economic growth, rising interest rates, changing economic sanctions, and currency volatility. These global macroeconomic conditions may put downward pressure on commodity prices and have a negative impact on our revenues, profitability, operating cash flows, liquidity and financial condition.

Historically, we have used cash flows from operations, borrowings under our revolving credit facility and proceeds from capital market transactions and asset dispositions to fund capital expenditures. Volatility in U.S. and global financial and equity markets, including market disruptions, limited liquidity, and interest rate volatility, may negatively impact our ability to obtain needed capital on acceptable terms or at all and may increase our cost of financing.

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.

Historically, our capital expenditures have been financed with cash generated by operations, borrowings under our revolving credit facility and proceeds from the issuance of debt and equity securities. Additionally, in recent years non-strategic asset

dispositions have provided a source of cash flow for use in reducing outstanding debt arising from our capital program. The actual amount and timing of future capital expenditures may differ materially from our estimates as a result of, among others, changes in commodity prices, available cash flows, lack of access to capital, unbudgeted acquisitions, actual drilling and completion results, the availability of drilling and completion rigs and other services and equipment, the availability of transportation and processing capacity, and regulatory, technological and competitive developments.

~~Our cash flows from operations and access to capital are subject to a number of variables, including but not limited to:~~

~~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;~~

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

~~our ability to acquire, locate and produce new reserves;~~

~~our ability to dispose of assets or enter into joint development arrangements on satisfactory terms; and~~

~~the ability and willingness of our lenders to extend credit or of participants in the capital markets to invest in our senior notes or equity securities.~~

If oil and gas industry conditions weaken as a result of low commodity prices or other factors, our ability to borrow may decrease and we may have limited ability to obtain the capital necessary to sustain our operations at planned levels. Currently, we have a revolving credit facility with lender commitments totaling $2.75 billion that matures in May 2019. In the future, we may not be able to access adequate funding under our revolving credit facility if our lenders are unwilling or unable to meet their funding obligations or increase their commitments under the credit facility. Our lenders could decline to increase their commitments based on our financial condition, the financial condition of our industry or the economy as a whole or for other reasons beyond our control. Due to these and other factors, we cannot be certain that funding, if needed, will be available to the extent required or on terms we find acceptable. If operating cash flows are insufficient and we are unable to access funding or execute capital transactions when needed on acceptable terms, we may not be able to fully implement our business plans, fund our capital program and commitments, complete new property acquisitions to replace reserves, take advantage of business opportunities, respond to competitive pressures, or refinance debt obligations as they come due. Should any of the above risks occur, they could have a material adverse effect on our business, financial condition, results of operations and cash flows.

We intend to finance future capital expenditures primarily through cash flows from operations, with any cash flow deficiencies expected to be funded by borrowings under our revolving credit facility or proceeds from asset sales or joint development arrangements. However, our financing needs may require us to alter or increase our capitalization substantially through the issuance of debt or equity securities. If we issue additional debt a portion of our cash flows from operations will need to be used for the payment of interest and principal on our debt, thereby reducing our ability to use cash flows to fund working capital needs, capital expenditures and acquisitions. The issuance of additional equity securities could have a dilutive effect on the value of our common stock.

Drilling for and producing crude oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations. 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 ~~will~~ depend on the success of our exploration, development and production activities. Our crude oil and natural gas exploration and production activities are subject to numerous risks, including the risk that drilling will not result in commercially viable crude oil or natural gas production. Our decisions to purchase, explore, ~~develop~~ or ~~otherwise exploit~~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;

~~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;

•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 ~~refining~~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 ~~will likely~~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 ~~these~~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 ~~in particular~~ due to changes in commodity ~~prices.~~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, ~~2017.~~2020.

In order to prepare reserve estimates, we must project production rates and the amount and timing of development expenditures. Our booked proved undeveloped reserves must be developed within five years from the date of initial booking under SEC reserve rules. Changes in the timing of development plans that impact our ability to develop such reserves in the required time frame have resulted, and will likely in the future result, in fluctuations in reserves between periods as reserves booked in one period may need to be removed in a subsequent period. In 2017, 89 MMBoe of proved undeveloped reserves were removed from our year-end reserve estimates associated with drilling locations no longer scheduled to be developed within five years from the date of initial booking.

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

The prices used in calculating our estimated proved reserves are calculated by determining the unweighted arithmetic average of the first-day-of-the-month commodity prices for the preceding 12 months. For the year ended December 31, 2017, average prices used to calculate our estimated proved reserves were $51.34 per Bbl for crude oil and $2.98 per MMBtu for natural gas ($47.03 per Bbl for crude oil and $3.00 per Mcf for natural gas adjusted for location and quality differentials). Actual future prices may be materially higher or lower than those used in our year-end estimates. NYMEX WTI crude oil and Henry Hub

~~natural gas first-day-of-the-month commodity prices for January 1, 2018 and February 1, 2018 averaged $63.11 per barrel and $3.40 per MMBtu, respectively. See~~ ~~Part I, Item 1. Business—Crude Oil and Natural Gas Operations—Proved Reserves—Proved Reserve, Standardized Measure, and PV-10 Sensitivities~~ ~~for proved reserve sensitivities under certain increasing and decreasing commodity price scenarios.~~

Actual future production, crude oil and natural gas 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, ~~many~~some of which are beyond our control.

~~The present value of future net revenues from our proved reserves will not necessarily be the same as the current market value of our estimated crude oil and natural gas reserves.~~

You should not assume the present value of future net revenues from our proved reserves is the current market value of our estimated crude oil and natural gas reserves. We base the estimated discounted future net revenues from proved reserves on the 12-month unweighted arithmetic average of the first-day-of-the-month commodity prices for the preceding twelve months. Actual future prices may be materially higher or lower than the average prices used in the calculations. ~~See~~ ~~Part I, Item 1. Business—Crude Oil and Natural Gas Operations—Proved Reserves—Proved Reserve, Standardized Measure, and PV-10 Sensitivities~~ ~~for Standardized Measure and PV-10 sensitivities under certain increasing and decreasing commodity price scenarios.~~

~~Actual future net revenues from crude oil and natural gas properties will be affected by factors such as:~~

~~the actual prices we receive for sales of crude oil and natural gas;~~

~~the actual cost and timing of development and production expenditures;~~

~~the timing and amount of actual production; and~~

~~changes in governmental regulations or taxation.~~

The timing of both our production and our incurrence of costs in connection with the development and production of crude oil and natural gas properties will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual present value. In addition, the use of a 10% discount factor, which is required by the SEC to be used to calculate discounted future net revenues for reporting purposes, may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with our reserves or the crude oil and natural gas ~~industry in general. Any~~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 ~~variances in timing or~~capital expenditures and successful drilling operations. Our reserve estimates assume we can and will make these expenditures and conduct these operations successfully. These assumptions ~~could materially affect~~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 ~~present value~~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 ~~reserves, which in turn could have an adverse effect on the value of our assets.~~

~~We may~~inability to fund necessary capital expenditures or otherwise, we will be required to ~~further write down~~remove the ~~carrying values~~associated volumes from our reported proved reserves. Proved undeveloped reserves generally must be drilled within five years from the date of ~~our crude oil and natural gas properties if commodity prices decline or our development plans change.~~

~~Accounting rules require we periodically review~~initial booking under SEC reserve rules. Changes in 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~~timing of development plans ~~production data, economics and other factors, we may be required~~that impact our ability 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~~develop such reserves in the ~~past~~required time frame have resulted, and ~~may incur additional impairment charges~~will likely in the future ~~particularly if commodity~~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 ~~decline,~~caused by the COVID-19 pandemic.

Additionally, unless production is established within the spacing units covering the undeveloped acres on which ~~could have a material adverse effect on~~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 ~~results~~proved reserves. The combined net acreage expiring in the next three years represents 50% of ~~operations for the periods~~our total net undeveloped acreage at December 31, 2020. At that date, we had leases representing 61,293 net acres expiring in ~~which such charges are taken.~~2021, 69,609 net acres expiring in 2022, and 49,475 net acres expiring in 2023.

~~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~~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.

The unavailability or high cost of drilling rigs, well completion crews, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute our exploration and development plans within budget and on a timely basis.

In the regions in which we operate, there have historically been shortages of drilling rigs, well completion crews, equipment, supplies, personnel or oilfield services, 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. The demand for qualified and experienced oilfield service providers and associated equipment, supplies, and materials can fluctuate significantly, often in correlation with commodity prices, causing periodic shortages.

As a result of the low commodity price environment in recent years, the number of providers of services, equipment, and materials decreased in the regions where we operate. Further, increased industry drilling and completion activities in recent months prompted by improvement in crude oil prices may cause shortages or higher costs of services, equipment, and materials. Such shortages or higher costs could delay the execution of our drilling and development plans, including our plans to work down our large inventory of uncompleted wells, or cause us to incur expenditures not provided for in our capital budget or to not achieve the rates of return we are targeting for our development program, all of which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

We may incur substantial losses and be subject to substantial liability claims as a result of our crude oil and natural gas operations. Additionally, we may not be insured for, or our insurance may be inadequate to protect us against, these risks.

We are not insured against all risks. Losses and liabilities arising from uninsured and under-insured events could materially and adversely affect our business, financial condition or results of operations. Our crude oil and natural gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing crude oil and natural gas, including the possibility of:

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

~~abnormally pressured formations;~~

~~mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse;~~

~~fires and explosions;~~

~~ruptures of pipelines or storage facilities;~~

~~loss of product or property damage occurring as a result of transfer to a rail car or train derailments;~~

~~personal injuries and death;~~

~~adverse weather conditions and natural disasters; and~~

~~spillage or mishandling of crude oil, natural gas, brine, well fluids, hydraulic fracturing fluids, toxic gas or other pollutants by us or by third party service providers.~~

~~Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to us as a result of:~~

~~injury or loss of life;~~

~~damage to or destruction of property, natural resources and equipment;~~

~~pollution and other environmental damage;~~

~~regulatory investigations and penalties;~~

~~suspension of our operations;~~

~~repair and remediation costs; and~~

~~litigation.~~

We may elect to not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented or for other reasons. In addition, pollution and environmental risks are generally not fully insurable. The occurrence of an event not fully covered by insurance could have a material adverse effect on our business, financial condition, results of operations and cash flows.

~~Prospects we decide to drill may not yield crude oil or natural gas in economically producible quantities.~~

Prospects we decide to drill that do not yield crude oil or natural gas in economically producible quantities may adversely affect our results of operations and financial condition. In this report, we describe some of our current prospects and plans to explore and develop those prospects. Our prospects are in various stages of evaluation, ranging from a prospect which is ready to drill to a prospect requiring substantial additional seismic data processing and interpretation. It is not possible to predict with certainty whether any particular prospect will yield crude oil or natural gas in sufficient quantities to recover drilling or completion costs or be economically producible. The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether crude oil or natural gas will be present or, if present, whether crude oil or natural gas will be present in economically producible quantities. We cannot assure you the analogies we draw from available data from other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects.

~~Our identified drilling locations are scheduled out over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.~~

Our management has specifically identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. Our ability to drill and develop these locations is subject to a number of uncertainties, including crude oil and natural gas prices; the availability of capital, drilling rigs, well completion crews, and transportation and processing capacity; costs; drilling results; regulatory approvals; and other factors. If future drilling results do not establish sufficient reserves to achieve an economic return, we may curtail drilling in these projects. Because of these uncertainties, we do not know if the potential drilling locations we have identified will ever be drilled or if we will be able to produce crude oil or natural gas from these or any other potential drilling locations in sufficient quantities to achieve an economic return. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the locations are identified, the leases for such acreage will expire. Low commodity prices, reduced capital spending, lack of available drilling and completion rigs and crews, and numerous other factors, many of which are beyond our control, could result in our failure to establish production on undeveloped acreage, and, if we are not able to renew leases before they expire, any proved undeveloped reserves associated with such leases will be removed from our proved reserves. The combined net acreage expiring in the next three years represents 57% of our total net undeveloped acreage at December 31, 2017. At that date, we had leases representing 102,258 net acres expiring in 2018, 145,997 net acres expiring in 2019, and 93,664 net acres expiring in 2020. Our actual drilling activities may materially differ from those presently identified, which could adversely affect our business.

The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Our proved undeveloped reserves may not be ultimately developed or produced.

At December 31, 2017, approximately 55% of our total estimated proved reserves (by volume) were undeveloped and may not be ultimately developed or produced. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling operations. Our reserve estimates assume we can and will make these expenditures and conduct these operations successfully. These assumptions may not prove to be accurate. Our reserve report at December 31, 2017 includes estimates of total future development costs over the next five years associated with our proved undeveloped reserves of approximately $6.4 billion. We cannot be certain the estimated costs of the development of these reserves are accurate, development will occur as scheduled, or the results of such development will be as estimated. If we choose not to spend the capital to develop these reserves, or if we are not otherwise able to successfully develop these reserves as a result of our inability to fund necessary capital expenditures or otherwise, we will be required to remove the associated volumes from our reported proved reserves. In addition, under the SEC’s reserve rules, because proved undeveloped reserves may be booked only if they relate to wells scheduled to be drilled within five years of the date of booking, we may be required to remove any

proved undeveloped reserves not developed within this five-year time frame. Such removals have occurred in the past and will likely occur in the future. A removal of such reserves could adversely affect our operations. In 2017, 89 MMBoe of proved undeveloped reserves were removed from our year-end reserve estimates associated with drilling locations no longer scheduled to be developed within five years from the date of initial booking.

Our business depends on crude oil and natural gas transportation, processing, refining, and ~~refining~~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 ~~refining~~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~~will be unable to realize revenue from those wells until other arrangements ~~were~~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 ~~refining~~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 ~~absent~~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 ~~pipeline~~transportation facilities and ~~rail transportation facilities~~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 ~~infrastructure;~~and exportation of crude oil; however, third party compliance with regulations

that impact the transportation or exportation of ~~crude oil or natural gas could~~our production may increase our costs of doing business and ~~limit our~~inhibit a third party's ability to transport and sell our production, ~~at market centers throughout the United States,~~whether domestically or internationally, the consequences of which could have a material adverse effect on our ~~financial condition, results of operations and cash flows.~~

~~Our~~ business, depends on the availability of water and the ability to dispose of waste water from oil and gas activities. Limitations or restrictions on our ability to obtain or dispose of water may have an adverse effect on our financial condition, results of operations and cash flows.

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.

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 $1.40 billion for capital expenditures attributable to us in 2021 of which approximately $1.11 billion is allocated to exploration and development activities. We may adjust our 2021 capital spending plans upward or downward depending on market conditions. Our 2021 capital budget, based on our current expectations of commodity prices and costs, is expected to be funded from operating cash flows. However, the sufficiency of our cash flows from operations is subject to a number of variables, including but not limited to:

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

•the volume of our proved reserves;

•the volume of crude oil and natural gas we are able to produce and sell from existing wells; and

•our ability to acquire, locate and produce new reserves;

If oil and gas industry conditions weaken as a result of low commodity prices or other factors, we may not be able to generate sufficient cash flows and may have limited ability to obtain the capital necessary to sustain our operations at current or planned levels. A decline in cash flows from operations may require us to revise our capital program or alter or increase our capitalization substantially through the issuance of debt or equity securities.

We have a revolving credit facility with lender commitments totaling $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.

The unavailability or high cost of drilling rigs, well completion crews, water, equipment, supplies, personnel and field services could adversely affect our ability to execute our exploration and development plans within budget and on a timely basis.

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

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 ~~introduction~~execution of ~~new environmental initiatives~~our drilling and ~~regulations related to water acquisition~~development plans or waste water disposal, including produced water, drilling fluids and other wastes associated with the exploration, development or production of hydrocarbons, could limit or prohibit our ability to utilize hydraulic fracturing or waste water injection wells.

In addition, concerns have been raised about the potential for seismic events to occur from the use of underground injection wells, a predominant method for disposing of waste water from oil and gas activities. Rules and regulations have been developed in Oklahoma to address these concerns by limiting or eliminating the ability to use disposal wells in certain locations or increasing the cost of disposal. We operate injection wells and utilize injection wells owned by third parties to dispose of waste water associated with our operations. Some states, including states in which we operate, have delayed permit approvals, mandated a reduction in injection volumes, or have shut down or imposed moratoria on the use of injection wells. Regulators in some states, including states in which we operate, are considering additional requirements related to seismicity. For example, in Oklahoma, the Oklahoma Corporation Commission (“OCC”) has adopted rules for operators of saltwater disposal wells in certain seismically-active areas in the Arbuckle formation of the state. These rules require disposal well operators, among other things, to conduct mechanical integrity testing or make certain demonstrations of such wells’ respective depths that, depending on the depth, could require plugging the well and/or the reduction of volumes disposed in such wells. Oklahoma has adopted a “traffic light” system wherein the OCC reviews new or existing disposal wells for proximity to faults, seismicity in the area and other factors in determining whether such wells should be permitted, permitted only with special restrictions, or not permitted.

Compliance with existing or new environmental regulations and permit requirements governing the withdrawal, storage, and use of water necessary for hydraulic fracturing of wells or the disposal of waste water may increase our operating costs or may cause us to ~~delay, curtail~~incur expenditures not provided for in our capital budget or ~~discontinue~~to not achieve the rates of return we are targeting for our ~~exploration and~~ development ~~plans,~~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 ~~subject~~uncertain, and the value of our undeveloped acreage will decline if drilling results are unsuccessful.

While our costs to ~~complex federal, state~~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 ~~local laws~~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 ~~regulations that could adversely affect~~operating wells in these areas may be higher than initially expected, and the ~~cost, manner~~value of our undeveloped acreage in the emerging areas may decline if drilling results are unsuccessful.

We have limited control over the activities on properties we do not operate.

Some of the properties in which we have an ownership interest are operated by other companies and involve third-party working interest owners. As of December 31, 2020, non-operated properties represented 14% of our 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 ~~feasibility of conducting our~~control the operations or ~~expose us to significant liabilities.~~

~~Our crude~~future development of non-operated properties, including the marketing of oil and ~~natural~~ gas ~~exploration~~production, compliance with environmental, occupational safety and ~~production operations are subject to complex and stringent federal, state and local laws and regulations, including those governing environmental protection, the occupational~~ health and ~~safety aspects~~other regulations, or the amount of expenditures required to fund the development and operation of such properties. Moreover, we are dependent on other working interest owners on these projects to fund their contractual share of capital and operating expenditures. These limitations and our ~~operations,~~dependence on the ~~discharge of materials into the environment, and the protection of certain plant and animal species. See~~ ~~Part I, Item 1. Business—Regulation of the Crude Oil and Natural Gas Industry~~ for a description of the laws and regulations that affect us. In order to conduct operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. Environmental regulations may restrict the types, quantities and concentration of materials released into the environment in connection with drilling and production activities, limit or prohibit drilling activities on certain lands lying within wilderness, wetlandsoperators and other ~~protected areas, and impose substantial liabilities~~working interest owners for pollution resulting from our operations. In addition, we may experience delays in obtaining or be unable to obtain required permits, which may delay or interrupt our operations and limit our growth and revenues.

Failure to comply with laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including investigatory actions, the assessment of monetary penalties, the imposition of remedial requirements, the issuance of orders or judgments limiting or enjoining future operations and litigation. Strict liability or joint and several liability may be imposed under certain laws, whichthese projects 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~~incur unexpected future costs and could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage and fines or penalties for related violations of environmental laws or regulations.

Moreover, our costs of compliance with existing laws could be substantial and may increase, or unforeseen liabilities could be imposed, if existing laws and regulations are revised or reinterpreted or if new laws and regulations become applicable to our operations. If we are not able to recover the increased costs through insurance or increased revenues, our business, financial condition, results of operations and cash flows could be adversely affected.

Climate change legislation or regulations governing the emissions of “greenhouse gases” could result in increased operating costs, limitations in our ability to develop and produce reserves, and reduced demand for the crude oil, natural gas and natural gas liquids we produce.

In response to EPA findings that emissions of carbon dioxide, methane and other greenhouse gases endanger human health and the environment, the EPA has adopted regulations under existing provisions of the federal Clean Air Act establishing, among other things, Prevention of Significant Deterioration (“PSD”) pre-construction and Title V operating permit reviews for certain large stationary sources. Facilities required to obtain PSD permits for greenhouse gas emissions are also required to meet “best available control technology” standards established on a case-by-case basis. For further discussion of Title V and PSD concerns, see ~~Part I, Item 1. Business–Regulation of the Crude Oil and Natural Gas Industry–Environmental regulation–Air emissions and climate change. Also see~~ ~~Part I, Item 1. Business–Regulation of the Crude Oil and Natural Gas Industry–Environmental regulation–Environmental protection and natural gas flaring~~. The EPA has also adopted rules requiring the monitoring and reporting of greenhouse gas emissions from specified onshore and offshore oil and gas production sources in the United States on an annual basis, which include certain of our operations. See ~~Part I, Item 1. Business—Regulation of the Crude Oil and Natural Gas Industry—Environmental regulation—Air emissions and climate change~~ for further discussion of the laws and regulations that affect us with respect to climate change initiatives. Regulations related to greenhouse gas emissions could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources.

Certain previously existing climate-related regulations, such as those related to the control of methane emissions, have been, or are in the process of being, reviewed, suspended, revised, or rescinded in response to President Trump's March 2017 Executive Order. Undoing previously existing regulations will likely involve lengthy notice-and-comment rulemaking and the resulting decisions may then be subject to litigation by opposition groups. Thus, it could take several years before existing regulations are revised or rescinded. Although further climate-related regulation of our industry may stall at the federal level under the March 2017 Executive Order, ~~certain states have pursued additional regulation of our operations~~ ~~related to the emission of greenhouse gases~~ ~~and other states may do so as well. For instance, several state and regional greenhouse gas cap and trade~~

~~programs have emerged, while other states have imposed limitations on emissions of methane through equipment control and leak detection and repair requirements.~~

The implementation of, and compliance with, regulations that require reporting of greenhouse gases or otherwise limit emissions of greenhouse gases from our equipment and operations could require us to incur costs to monitor and report on greenhouse gas emissions, install new equipment to reduce emissions of greenhouse gases associated with our operations, or limit our ability to develop and produce our reserves. In addition, substantial limitations on greenhouse gas emissions could adversely affect the demand for the crude oil and natural gas we produce, which could lower the value of our reserves and have a material adverse effect on our business, financial condition, results of operations and cash flows.

~~Finally, some scientists~~We may be subject to risks in connection with acquisitions, divestitures, and joint development arrangements.

As part of our business strategy, we have ~~concluded that increasing concentrations~~made and will likely continue to make acquisitions of ~~greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency~~oil 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~~gas properties, divest assets, and ~~operations.~~enter into joint development arrangements. The successful acquisition of producing properties requires an assessment of several factors, including but not limited to:

Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs, additional operating restrictions or delays, and an inability to develop existing reserves or to book future reserves.•recoverable reserves;

~~Hydraulic fracturing is an important and commonly used process in the completion of~~•future crude oil and natural gas ~~wells~~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 ~~low-permeability formations. Hydraulic fracturing involves~~reducing debt and enhancing liquidity. Such divestitures have inherent risks, including possible delays in closing, the ~~high-pressure injection~~risk of ~~water, sand~~lower-than-expected sales proceeds for the disposed assets, and potential post-closing adjustments and claims for indemnification. Additionally, volatility and unpredictability in commodity prices may result in fewer potential bidders, unsuccessful sales efforts, and a higher risk that buyers may seek to terminate a transaction prior to closing. The occurrence of any of the matters described above could have an adverse impact on our business, financial condition, results of operations and cash flows.

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

United States and global economies may experience periods of volatility and uncertainty from time to ~~stimulate crude oil~~time, resulting in unstable consumer confidence, diminished consumer demand and ~~natural gas production.~~spending, diminished liquidity and credit availability, and inability to access capital markets. In recent years, ~~there has been increased public concern regarding an alleged potential for hydraulic fracturing to adversely affect drinking water supplies~~certain global economies have experienced periods of political uncertainty, slowing economic growth, rising interest rates, changing economic sanctions, health-related concerns, and ~~to induce seismic events. As a result, several federal and state regulatory initiatives have emerged that seek to increase the regulatory burden imposed on hydraulic fracturing. See~~ ~~Part I, Item 1. Business—Regulation of the Crude Oil and Natural Gas Industry—Environmental regulation—Hydraulic fracturing~~ ~~for a description of the laws and regulations that affect us with respect to hydraulic fracturing.~~

States in which we operate have adopted or are considering adopting legal requirements imposing more stringent permitting, disclosure, and well construction and reclamation requirements on hydraulic fracturing activities. Local governments alsocurrency volatility. These global macroeconomic conditions 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~~negative impact on ~~our ability to economically find~~commodity prices and ~~develop crude oil~~the availability and ~~natural gas reserves~~cost of materials used in our ~~strategic plays. The inability to achieve a satisfactory economic return~~industry, which in turn could ~~cause us to curtail or discontinue our exploration and development plans, which would~~ have a material adverse effect on our business, financial condition, results of operations and cash flows.

~~Proposed changes~~In recent years, the United States government has initiated new tariffs on certain imported goods and has imposed increases to certain existing ~~laws or regulations or~~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 ~~interpretations~~regulations, fiscal policy, social programs, domestic and foreign relations, and government energy policies, which could pose a potential threat to domestic and global economic growth.

Trade restrictions or other governmental actions related to tariffs or trade policies have impacted, and have the potential to further impact, our business and industry by increasing the cost of ~~laws~~materials used in various aspects of upstream, midstream, and ~~regulations under consideration could increase our operating costs, reduce our liquidity,~~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 ~~our operations~~ or ~~otherwise alter the way we conduct our business.~~

~~Changes to existing laws or regulations, new laws or regulations, or changes in interpretations~~cessation of ~~laws~~drilling and ~~regulations may unfavorably impact us~~completion efforts or the ~~infrastructure used for transporting our products. Similarly, changes~~postponement or cancellation of new pipeline transportation projects the U.S. industry is relying on to transport its onshore production to market, as well as endangering U.S. liquefied natural gas export projects resulting in ~~regulatory policies~~negative impacts on natural gas production. Additionally, trade and/or tariff disputes have impacted, and ~~priorities~~have the potential to further impact, domestic and global economies overall, which could result in ~~the imposition of new obligations upon us, such as increased reporting or audits.~~reduced demand for crude oil and natural gas. Any of ~~these requirements could result in increased operating costs and~~the above consequences could have a material adverse effect on our financial condition and results of operations. If such legislation, regulations or interpretations are adopted, they could result in, among other items, additional restrictions on hydraulic fracturing of wells, restrictions on the disposal of waste water from oil and gas activities, restrictions on emissions of greenhouse gases, modification of equipment utilized in our operations, changes to the calculation of royalty payments, new safety requirements such as those involving rail transportation, and additional regulation of private energy commodity derivative and hedging activities. These and other potential laws, regulations, interpretations and other requirements could increase our operating costs, reduce our liquidity, delay our operations or otherwise alter the way we conduct our business. This, in turn, could have a material adverse effect on our financial condition, results of operations and cash flows.

~~Certain aspects of the newly enacted federal income tax reform legislation in the United States could adversely affect us.~~

On December 22, 2017, the Tax Cuts and Jobs Act (the "Tax Reform Act") was signed into law by President Trump. The Tax Reform Act represents the most significant tax policy change in the United States since 1986 and includes, among others, the following key changes to federal tax law:

~~Reduces the corporate tax rate from 35% to 21% and eliminates the corporate alternative minimum tax;~~

Limits the tax deduction for certain net operating loss (NOL) carryforwards to 80% of taxable income for a taxable year, allows NOLs generated in years after December 31, 2017 to be carried forward indefinitely, and repeals NOL carrybacks;

~~Limits the tax deduction for business interest expense to 30% of adjusted taxable income for a taxable year;~~

~~Allows businesses to immediately expense the cost of new investments in certain qualified depreciable assets;~~

~~Creates a territorial tax system rather than a worldwide system, which generally allows companies to repatriate future foreign source earnings without incurring additional U.S. taxes;~~

~~Subjects foreign earnings on which U.S. income tax is currently deferred to a one-time transition tax; and~~

~~Eliminates or reduces certain deductions, exclusions, and credits and adds other provisions that broaden the tax base.~~

Changes arising from the Tax Reform Act, which are subject to a number of important qualifications and exceptions, generally become effective for tax years beginning after December 31, 2017. Certain of the changes are permanent, while others expire at specified dates. The Tax Reform Act's provisions could have state and local tax implications. While some states automatically adopt federal tax law changes, others conform their laws with federal law on specific dates. States also may choose to decouple from the new federal tax provisions and continue to apply previous law.

~~Apart from the future benefits to be realized from the reduction in the corporate income tax rate from 35% to 21%, the overall long-term impact of other aspects of the Tax Reform Act is uncertain, and~~ our business, financial condition, results of operations and cash ~~flows~~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.

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 a variety of ways, including but not limited to unauthorized access to, or theft of, sensitive or proprietary information and data corruption or operational disruption that adversely ~~affected by certain new provisions, particularly the limitations~~affects our ability to carry on ~~the tax deductibility~~our business. Any such event could damage our reputation and lead to financial losses from remedial actions, loss of business, ~~interest expense~~or potential liability, which could have a material adverse effect on our business, financial condition, results of operations or cash flows.

While the Company has established cyber security systems and ~~NOLs. See~~ ~~Part II, Item 7. Management’s Discussion~~controls, disclosure controls and ~~Analysis~~procedures and incident response protocols, these systems, controls, procedures and protocols may not identify all risks and threats we face, or may fail to protect data or mitigate the adverse effects of ~~Financial Condition and Results of Operations–Legislative and Regulatory Developments–Tax Reform Legislation~~ ~~for a forward-looking discussion of the potential impact of the Tax Reform Act.~~

~~In previous years, legislation has been proposed~~data loss. To our knowledge we have not experienced any material losses relating to eliminate or defer certain key U.S. federal income tax deductions historically available to oil and gas exploration and production companies. Such proposed changes have included: (i) a repeal of the percentage depletion allowance for crude oil and natural gas properties; (ii) the elimination of deductions for intangible drilling and exploration and development costs; (iii) the elimination of the deduction for certain production activities; and (iv) an extension of the amortization period for certain geological and geophysical expenditures. These tax deductions currently utilized within our industry are not impacted by the Tax Reform Act. However, no predictioncyber attacks; however, there can be ~~made as to whether any legislative changes~~no assurance that we will ~~be proposed or enacted~~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 ~~could eliminate or defer these or other tax deductions utilized within our industry.~~are likely to increase over time.

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

Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, securing long-term transportation and processing capacity, marketing crude oil and natural gas, and securing trained personnel. Also, there is substantial competition for capital available for investment in the crude oil and natural gas industry. ~~Certain of our~~Our competitors may possess and employ financial, technical and personnel resources greater than ours. Those companies may be able to pay more for productive crude oil and natural gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. ~~In addition, companies may be able~~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 raised by advocacy groups about hydraulic fracturing, oil spills, induced seismicity, and greenhouse gas emissions may lead to increased regulatory scrutiny, which may, in turn, lead to new state and federal safety and environmental laws, regulations, guidelines and

enforcement interpretations. These actions may cause operational delays or restrictions, increased operating costs, additional regulatory burdens and increased risk of litigation. Moreover, governmental authorities exercise considerable discretion in the timing and scope of permit issuance and the public may engage in the permitting process, including through intervention in the courts. Negative public perception could cause the permits we need to conduct our operations to be withheld, delayed, or burdened by requirements that restrict our ability to conduct our business.

~~Energy conservation measures or initiatives that stimulate demand for alternative forms of energy could reduce the demand for the crude oil and natural gas we produce.~~

Fuel conservation measures, climate change initiatives, governmental requirements for renewable energy resources, increasing consumer demand for alternative forms of energy, and technological advances in fuel economy and energy generation devices could reduce demand for the crude oil and natural gas we produce. The potential impact of changing demand for crude oil and natural gas services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows.

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

Severe weather events and natural disasters such as hurricanes, tornadoes, seismic events, 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 region.~~ The consequences of such events may include the evacuation of personnel; damage to and disruption of drilling rigs or transportation, processing, storage, refining, and ~~refining~~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.

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

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

Financial Risks

Our derivative activities could 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, establishes 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 ~~entities, such as us, that participate in that market. This financial reform legislation includes provisions that require many~~Results of Operations—Derivative Instruments for a summary of additional derivative ~~transactions previously executed over-the-counter~~instruments entered into subsequent to be executed through an exchange and be centrally cleared. In addition, this legislation calls for the imposition of position limits for swaps, including swaps involving physical commodities such as crude oil and natural gas, which have been proposed but have not been finalized. It also establishes minimum margin requirements for uncleared swaps for swap dealers and major swap participants.

~~If we~~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 requirements, the new regulations could significantly increase the cost of derivative contracts, materially alter the terms 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, impose new recordkeeping and documentation requirements, and increase our exposure to less creditworthy counterparties. Additionally, the proposed position limitsearnings may limit our ability to implement price risk management strategies if we are not able to qualify for any exemption from such limits. Further, if we do not qualify for an end user exemption, the margin requirements for uncleared swaps may require us to post collateral, which could adversely affect our available liquidity. If our use of derivatives becomes limitedfluctuate 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. Finally,~~necessary for the ~~legislation was intended, in part, to reduce the volatility~~development of crude oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to crude oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower crude oil or natural gas prices. Any of these consequences could have a material adverse effect on our ~~financial position, results of operations and cash flows.~~

~~The loss of senior management or technical personnel could adversely affect our operations.~~

We depend on the services of our senior management and technical personnel. The loss of the services of our senior management or technical personnel, including Harold G. Hamm, our Chairman and Chief Executive Officer, could have a material adverse effect on our operations. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals.

~~We have limited control over the activities on properties we do not operate.~~

Some of the properties in which we have an ownership interest are operated by other companies and involve third-party working interest owners. As of December 31, 2017, non-operated properties represented 18% of our estimated proved developed reserves, 6% of our estimated proved undeveloped reserves, and 11% of our estimated total proved reserves. We ~~have limited ability~~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 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 operator 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 financial condition, results of operations and cash flows.~~business 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, ~~2017,~~2020, we had $160 million of outstanding borrowings on our credit facility and our consolidated net debt to total capitalization ratio, as defined, was ~~0.51~~0.42 to 1.00. Our total debt would need to independently increase by approximately $5.2 billion above the existing level at December 31, 2017 (with no corresponding increase in cash or reduction in refinanced debt) to reach the maximum covenant ratio of 0.65 to 1.00. Alternatively, our total shareholders’ equity would need to independently decrease by approximately $2.8 billion below the existing level at December 31, 2017 (excluding the after-tax impact of any non-cash impairment charges) to reach the maximum covenant ratio.

The indentures governing our senior notes contain covenants that, among other things, limit our ability to create liens securing certain indebtedness, enter into certain sale and leaseback transactions, and consolidate, merge or transfer certain assets.

The covenants in our revolving credit facility and senior note indentures may restrict our ability to expand or pursue our business strategies. Our ability to comply with ~~these and other~~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 ~~of these covenants~~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 ~~adversely affect our financial condition and results of operations.~~

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

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

As dependence on digital technologies has increased, cyber incidents, including deliberate attacks or unintentional events, have also increased. Our technologies, systems, networks, and those of our business associates have been and may continue to be the target of cyber attacks or information security breaches, which could lead to disruptions in critical systems, unauthorized release or theft of confidential or protected information, corruption of data or other disruptions of our business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period.

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

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

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

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

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

~~These events could damage our reputation and lead to financial losses from remedial actions, loss of business, or potential liability, which could~~ have a material adverse effect on our business, financial condition, results of operations, orand cash flows.

To our knowledge we have not experienced any material losses relating to cyber attacks; however, there can be no assurance that we will not suffer material losses in the future. As cyber threats continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any information security vulnerabilities.

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

The U.S. Federal Reserve increased the benchmark federal funds interest rate on three separate occasions in 2017 and is forecasting additional increases in 2018 and 2019. Our business and operating results can be adversely affected by increases in interest rates, the availability, terms of and cost of capital, or downgrades or other negative rating actions with respect to our credit rating. These factors could cause our cost of doing business to increase, limit our ability to pursue acquisition opportunities, reduce cash flows used for drilling and place us at a competitive disadvantage. We require continued access to capital. A significant reduction in cash flows from operations or the availability of credit could materially and adversely affect our financial condition and results of operations.

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

Our principal exposure to credit risk is through the sale of our crude oil and natural gas production, which we market to energy marketing companies, crude oil refining companies, and natural gas gathering and processing companies ($~~672~~561 million in receivables at December 31, ~~2017);~~2020) and our joint interest and other receivables ($~~427~~144 million at December 31, ~~2017);~~2020). These counterparties may experience insolvency or liquidity issues and ~~counterparty credit risk associated with our derivative instrument receivables ($3 million at December 31, 2017).~~

We are also subject to credit risk due to concentration of our crude oil and natural gas receivables with significant customers. The two largest purchasers of our crude oil and natural gas during the year ended December 31, 2017 accounted for approximately 11% and 11%, respectively, of our total crude oil and natural gas revenues for the year. We havemay not generally required our counterparties to provide collateral to secure crude oil and natural gas sales receivables owed to us. Additionally, our use of derivative instruments involves the risk that our counterparties will be ~~unable~~able to meet their ~~obligations.~~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.

~~Finally,~~

Additionally, we rely on ~~oilfield~~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 portion of our production. See~~ ~~Part II, Item 8. Notes to Consolidated Financial Statements—Note 5. Derivative Instruments~~ ~~for a summary of our commodity derivative positions as of December 31, 2017. We do not designate any of our derivative instruments as hedges for accounting purposes~~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 significantly 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 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 2018 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, ~~2017,~~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 ~~companies~~parties and us.

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

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

~~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 non-strategic assets, and enter into joint development arrangements. Suitable acquisition properties, buyers of our non-strategic assets, or joint development counterparties may not be available on terms and conditions we find acceptable or not at all.

~~The successful acquisition of 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.~~

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 non-strategic assets as a result of an evaluation of our asset portfolio or to provide cash flow for use in reducing debt and enhancing liquidity. Such divestitures have inherent risks, including possible delays in closing, the risk of lower-than-expected sales proceeds for the disposed assets, and potential post-closing adjustments and claims for indemnification. Additionally, volatility and unpredictability in commodity prices may result in fewer potential bidders, unsuccessful sales efforts, and a higher risk that buyers may seek to terminate a transaction prior to closing.

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

Terrorist attacks and the threat of terrorist attacks, whether domestic or foreign attacks, as well as military or other actions taken in response to these acts, could cause instability in the global financial and energy markets. Continued hostilities in the Middle East and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the global economy in unpredictable ways, including the disruption of energy supplies and markets, increased volatility in commodity prices or the possibility that infrastructure we rely on could be a direct target or an indirect casualty of an act of terrorism, and, in turn, 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, ~~2017.~~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 10. 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.

We have received Notices of Violation from the North Dakota Department of Health (“NDDH”) alleging violations of the state’s air quality and water pollution control laws and rules. We exchanged information and engaged in discussions with NDDH aimed at resolving the allegations and anticipate further discussions and exchanges. Resolution of the allegations may result in monetary sanctions of more than $100,000.


~~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.” ~~The following table sets forth quarterly high and low sales prices for each quarter of the previous two years. No cash dividends were declared during the previous two years.~~

2017 2016
Quarter Ended Quarter Ended
March 31 June 30 September 30 December 31 March 31 June 30 September 30 December 31
High $ 53.57
$ 47.87
$ 40.03
$ 53.55
$ 31.90
$ 46.01
$ 52.78
$ 60.30
Low $ 41.28
$ 30.18
$ 29.08
$ 36.05
$ 13.94
$ 28.63
$ 40.92
$ 44.37
Cash Dividend —
—
—
—
—
—
—
—

~~We do not anticipate paying any cash dividends on our common stock in the foreseeable future.~~ As of January ~~31, 2018,~~29, 2021, the number of record holders of our common stock was ~~1,146. Management believes,~~1,223. On January 29, 2021, after inquiry, management believes that the number of beneficial owners of our common stock is ~~approximately 64,400.~~55,192. On January ~~31, 2018,~~29, 2021, the last reported sales price of our common stock, as reported on the New York Stock Exchange, was ~~$55.53~~$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, ~~2017:~~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, 2017 to October 31, 2017 234
$ 38.24
—
—
November 1, 2017 to November 30, 2017 18,435

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

—
—
—
Total 18,669
$ 44.76
—
—


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, ~~2017~~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	—	—	~~14,538,540~~	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, ~~2012~~2015 through December 31, ~~2017.~~2020. The graph assumes the value of the investment in our common stock and in each index was $100 on December 31, ~~2012~~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, ~~2013~~2016 through ~~2017.~~2020. The selected financial data presented below is not intended to replace our consolidated financial statements.

The following ~~consolidated~~ financial data has been derived from our audited consolidated financial statements for such periods. You should read the following selected financial data in connection with Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and our consolidated financial statements and related notes included elsewhere in this report. The selected consolidated results are not necessarily indicative of results to be expected in future periods. Operating and financial results attributable to noncontrolling interests are not material relative to the Company's consolidated results and are not separately presented below.


	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.

(2)Results for 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 attributable to noncontrolling interests. See Part II, Item 8. Notes to Consolidated Financial Statements—Note 16. Noncontrolling Interests for a discussion of the arrangements that give rise to the separate presentation of results attributable to Continental and noncontrolling interests in our financial statements.

Year Ended December 31,
2017 2016 2015 2014 2013
Income Statement data
In thousands, except per share data
Crude oil and natural gas sales $ 2,982,966
$ 2,026,958
$ 2,552,531
$ 4,203,022
$ 3,573,431
Gain (loss) on crude oil and natural gas derivatives, net (1) 91,647
(71,859 ) 91,085
559,759
(191,751 )
Total revenues 3,120,828
1,980,273
2,680,167
4,801,618
3,421,807
Income (loss) from continuing operations (2) 789,447
(399,679 ) (353,668 ) 977,341
764,219
Net income (loss) (2) 789,447
(399,679 ) (353,668 ) 977,341
764,219
Basic net income (loss) per share:
From continuing operations $ 2.13
$ (1.08 ) $ (0.96 ) $ 2.65
$ 2.08
Net income (loss) per share $ 2.13
$ (1.08 ) $ (0.96 ) $ 2.65
$ 2.08
Shares used in basic income (loss) per share 371,066
370,380
369,540
368,829
368,150
Diluted net income (loss) per share:
From continuing operations $ 2.11
$ (1.08 ) $ (0.96 ) $ 2.64
$ 2.07
Net income (loss) per share $ 2.11
$ (1.08 ) $ (0.96 ) $ 2.64
$ 2.07
Shares used in diluted income (loss) per share 373,768
370,380
369,540
370,758
369,698
Production volumes
Crude oil (MBbl) (3) 50,536
46,850
53,517
44,530
34,989
Natural gas (MMcf) 228,159
195,240
164,454
114,295
87,730
Crude oil equivalents (MBoe) 88,562
79,390
80,926
63,579
49,610
Sales volumes
Crude oil (MBbl) (3) 50,628
46,802
53,664
44,122
34,985
Natural gas (MMcf) 228,159
195,240
164,454
114,295
87,730
Crude oil equivalents (MBoe) 88,655
79,342
81,073
63,172
49,607
Average sales prices (4)
Crude oil ($/Bbl) $ 45.70
$ 35.51
$ 40.50
$ 81.26
$ 89.93
Natural gas ($/Mcf) $ 2.93
$ 1.87
$ 2.31
$ 5.40
$ 4.87
Crude oil equivalents ($/Boe) $ 33.65
$ 25.55
$ 31.48
$ 66.53
$ 72.04
Average costs per unit (4)
Production expenses ($/Boe) $ 3.66
$ 3.65
$ 4.30
$ 5.58
$ 5.69
Production taxes (% of oil and gas revenues) 7.0 % 7.0 % 7.8 % 8.2 % 8.3 %
DD&A ($/Boe) $ 18.89
$ 21.54
$ 21.57
$ 21.51
$ 19.47
General and administrative expenses ($/Boe) (5) $ 2.16
$ 2.14
$ 2.34
$ 2.92
$ 2.91
Proved reserves at December 31
Crude oil (MBbl) 640,949
643,228
700,514
866,360
737,788
Natural gas (MMcf) 4,140,281
3,789,818
3,151,786
2,908,386
2,078,020
Crude oil equivalents (MBoe) 1,330,995
1,274,864
1,225,811
1,351,091
1,084,125
Other financial data (in thousands)
Net cash provided by operating activities $ 2,079,106
$ 1,125,919
$ 1,857,101
$ 3,355,715
$ 2,563,295
Net cash used in investing activities $ (1,808,845 ) $ (532,965 ) $ (3,046,247 ) $ (4,587,399 ) $ (3,711,011 )
Net cash (used in) provided by financing activities $ (243,034 ) $ (587,773 ) $ 1,187,189
$ 1,227,715
$ 1,140,469
Total capital expenditures $ 2,035,254
$ 1,110,256
$ 2,564,301
$ 5,015,595
$ 3,841,633
Balance Sheet data at December 31 (in thousands)
Total assets $ 14,199,651
$ 13,811,776
$ 14,919,808
$ 15,076,033
$ 11,841,567
Long-term debt, including current portion $ 6,353,691
$ 6,579,916
$ 7,117,788
$ 5,928,878
$ 4,650,889
Shareholders’ equity $ 5,131,203
$ 4,301,996
$ 4,668,900
$ 4,967,844
$ 3,953,118

~~(1)~~

Crude oil and natural gas derivative instruments are not designated as hedges for accounting purposes and, therefore, changes in the fair value of the instruments are shown separately from crude oil and natural gas sales. The amounts above include non-cash mark-to-market gains (losses) on crude oil and natural gas derivatives of $62.1 million, ($160.7) million, $21.5 million, $174.4 million, and ($130.2) million for the years ended December 31, 2017, 2016, 2015, 2014, and 2013, respectively. Additionally, 2014 includes $433 million of gains recognized from crude oil derivative contracts that were settled in the fourth quarter of 2014 prior to their contractual maturities initially scheduled through December 2016.

~~(2)~~

Results for 2017 reflect the remeasurement of the Company's deferred income tax assets and liabilities in response to the enactment of the Tax Cuts and Jobs Act in December 2017, which resulted in a one-time increase in net income of approximately $713.7 million ($1.92 per basic share and $1.91 per diluted share). See ~~Part II, Item 8. Notes to Consolidated Financial Statements—Note 8. Income Taxes for further discussion. Additionally, 2017 results include a $59.6 million pre-tax loss accrual recognized in conjunction with a litigation settlement as discussed in~~ ~~Part II, Item 8. Notes to Consolidated Financial Statements—Note 10. Commitments and Contingencies, which resulted in an after-tax decrease in 2017 net income of $37.0 million ($0.10 per basic and diluted share).~~


~~(3)~~	At various times, we have stored crude oil due to pipeline line fill requirements, low commodity prices, or marketing disruptions or we have sold crude oil from inventory. These actions result in differences between our produced and sold crude oil volumes.


~~(4)~~	~~Average sales prices and average costs per unit have been computed using sales volumes and exclude any effect of derivative transactions.~~


~~(5)~~	General and administrative (“G&A”) expenses ($/Boe) include non-cash equity compensation expenses of $0.52 per Boe, $0.61 per Boe, $0.64 per Boe, $0.86 per Boe, and $0.80 per Boe for the years ended December 31, 2017, 2016, 2015, 2014, and 2013, respectively.


~~ITEM 7.~~	~~Management’s Discussion and Analysis of Financial Condition and Results of Operations~~

ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with our consolidated financial statements and notes, as well as the selected consolidated financial data included elsewhere in this report. ~~Our operating~~Results attributable to noncontrolling interests are not material relative to consolidated results ~~for the periods~~and are not separately presented or discussed ~~below may not be indicative of future performance. For additional discussion of crude oil and natural gas reserve information, please see~~ ~~Part I, Item 1. Business—Crude Oil and Natural Gas Operations.~~below.

The following discussion and analysis includes forward-looking statements and should be read in conjunction with Part I, Item 1A. Risk Factors in this report, along with Cautionary Statement for the Purpose of the “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995 at the beginning of this report, for information about the risks and uncertainties that could cause our actual results to be materially different than our forward-looking statements.

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 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.

Business Environment and Outlook

Continental marked its 50th anniversary in the oil and gas business in 2017. Our leadership team has significant experience with operating in challenging commodity price environments. Commodity prices remained volatile during the year, but generally increased on average in 2017 relative to 2016. Crude oil prices decreased to historically low levels in ~~particular showed significant signs of improvement in late 2017~~April 2020 due primarily to reduced global and ~~early 2018, with West Texas Intermediate~~domestic demand for crude oil ~~benchmark~~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, ~~reaching a three-year high~~we began voluntarily curtailing our production in April 2020 and ultimately curtailed approximately 55% of ~~$66 per barrel~~our operated crude oil production and associated natural gas in ~~January 2018. With our portfolio~~the 2020 second quarter. Additionally, in light of ~~high quality assets, we are well-positioned to manage~~ the ~~ongoing~~ challenges ~~and price volatility~~ facing our ~~industry.~~

~~For 2018,~~business and industry, we implemented cost saving initiatives and significantly reduced our ~~primary business strategies will focus on:~~

~~Balancing strong production growth~~operated rig and completion crew counts in order to preserve our assets and better align our capital spending with ~~free cash flow generation;~~

~~Enhancing~~expected available cash flows, ~~and return on capital employed through improvements~~resulting in ~~operating efficiencies, technical innovations, and optimized completion methods;~~

~~Continuing to exercise disciplined~~a $1.5 billion, or 56%, decrease in our non-acquisition capital spending in 2020 compared to ~~maintain financial flexibility~~2019. These actions, coupled with historically low crude oil prices, resulted in a material reduction in our production, revenues, and ~~ample liquidity; and~~

~~Improving debt metrics by further reducing outstanding debt using available operating cash flows or proceeds from asset dispositions or joint development arrangements.~~

~~Based on an expectation for higher operating~~ cash flows in ~~2018, we have increased our planned non-acquisition capital spending for 2018 to $2.3 billion~~2020 compared to $2.0 billion spent in 2017, with approximately 78% of our 2018 drilling and completion budget focusing on oil-weighted areas in the North Dakota Bakken and SCOOP Springer plays. We expect to fund our budgeted spending using cash flows from operations. We may adjust our pace of drilling and development as 2018 market conditions evolve.

~~2017 Highlights~~

~~Production~~2019.

Crude oil prices began to stabilize in mid-2020 and ~~natural gas~~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 ~~averaged 242,637~~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 2017, an increase of 12% compared to 2016.~~

~~Total production~~ for the 2020 fourth quarter, ~~of 2017 averaged 286,985 Boe per day, an~~representing a 14% increase ~~of 18%~~ compared to the third quarter of ~~2017 and 37% higher~~2020, yet still remaining 7% lower than the fourth quarter of ~~2016.~~2019.

~~Average daily~~Despite the gradual improvement in crude oil ~~production increased 8%~~prices in ~~2017~~the second half of 2020, we continued our commitment to operating in 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 ~~2016 while average daily natural gas~~June 30, 2020. Additionally, despite production ~~increased 17%.~~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.

~~Crude oil represented 57%~~We remain committed to the responsible stewardship of our ~~2017~~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. We remain flexible as we monitor and adapt to market conditions. See the subsequent section titled Liquidity and Capital Resources for additional discussion of our financial condition.

Financial and 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

(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	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, 2020 compared to ~~59%~~the year ended December 31, 2019

Below is a discussion of changes in our results of operations for ~~2016. Crude oil represented 59%~~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 ~~production~~Form 10-K for the ~~fourth quarter of 2017 compared to 58% for~~year ended December 31, 2019 as filed with the ~~third quarter of 2017 and 55% for the fourth quarter of 2016.~~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 2017 2016 % Change 2017 2016 % Change
Bakken 165,598
104,524
58 % 132,992
119,200
12 %
SCOOP 62,242
63,490
(2 %) 60,693
65,062
(7 %)
STACK 47,914
24,426
96 % 36,220
16,983
113 %
All other 11,231
17,421
(36 %) 12,732
15,667
(19 %)
Total 286,985
209,861
37 % 242,637
216,912
12 %

~~Revenues~~

Crude oil and natural gas revenues totaled $2.98 billion for 2017, a 47% increase compared to 2016 driven by a 32% increase in realized commodity prices coupled with a 12% increase in total sales volumes.

Crude oil and natural gas revenues totaled $1.02 billion for the 2017 fourth quarter, a 44% increase from the 2017 third quarter and 72% higher than the 2016 fourth quarter, reflecting an increase in well completion activities and improvement in commodity prices and price realizations in late 2017. Total sales volumes for the 2017 fourth quarter increased 20% and 38% and realized commodity prices increased 20% and 25% compared to the 2017 third quarter and 2016 fourth quarter, respectively.

~~Proved reserves~~

~~At December 31, 2017, our proved reserves totaled 1,331 MMBoe, an increase of 4% from proved reserves of 1,275 MMBoe at December 31, 2016.~~

Extensions and discoveries from our drilling and completion activities added 240 MMBoe of proved reserves in 2017 and upward reserve revisions due to improved commodity prices increased reserves by 42 MMBoe. These increases were partially offset by 89 MMBoe of production during the year and net downward reserve revisions totaling 124 MMBoe resulting from changes in drilling plans and other factors.

~~The following table summarizes the changes in our proved reserves by major operating area in 2017:~~

December 31, 2017 December 31, 2016 Volume change Volume
percent
change
Proved reserves by area MBoe Percent MBoe Percent
Bakken 635,521
48 % 591,901
46 % 43,620
7 %
SCOOP 491,776
37 % 471,921
37 % 19,855
4 %
STACK 167,390
13 % 161,243
13 % 6,147
4 %
All Other 36,308
2 % 49,799
4 % (13,491 ) (27 %)
Total 1,330,995
100 % 1,274,864
100 % 56,131
4 %

~~Operating cash flows~~

Cash flows from operating activities totaled $2.08 billion for 2017, an increase of 85% compared to $1.13 billion for 2016, reflecting an increase in sales volumes and improvement in commodity prices and price realizations in 2017.

~~Capital expenditures and drilling activity~~

Full year 2017 non-acquisition capital expenditures totaled approximately $2.00 billion compared to $1.07 billion for 2016, reflecting our planned increase in spending for 2017 in response to improved commodity prices.

~~In 2017 we participated in the drilling and completion of 608 gross (214 net) wells compared to 365 gross (92 net) wells in 2016.~~

~~2017 property dispositions~~

In September 2017 we sold non-strategic properties in the Arkoma Woodford area of Oklahoma for cash proceeds of $65.3 million. The sale included approximately 26,000 net acres of leasehold and producing properties with production totaling

~~approximately 1,700 Boe per day. In connection with the transaction, we recognized a pre-tax loss of $3.5 million for the year ended December 31, 2017.~~

In September 2017, we reached an agreement to sell non-core leasehold in the STACK play in Blaine County, Oklahoma for cash proceeds totaling $63.5 million. A portion of the transaction closed in September 2017, resulting in the receipt of proceeds amounting to $3.6 million and the recognition of a $3.3 million pre-tax gain on sale in the 2017 third quarter. The remainder of the transaction was completed in October 2017 at which time we received the remaining $59.9 million of proceeds and recognized an additional pre-tax gain of approximately $53.6 million, which is reflected in fourth quarter 2017 results.

~~In September 2017, we sold certain oil-loading facilities in Oklahoma for $7.2 million and recognized a $4.2 million pre-tax gain for the year ended December 31, 2017 associated with the transaction.~~

~~Debt and liquidity~~

~~Total debt decreased $226 million, or 3%, to $6.35 billion at December 31, 2017 compared to $6.58 billion at year-end 2016.~~

In December 2017 we issued $1.0 billion of 4.375% Senior Notes due 2028 (“2028 Notes”) and received total net proceeds of $990 million after deducting the initial purchasers’ fees. We used the proceeds from the offering to repay in full and terminate our $500 million term loan due November 4, 2018 and to repay a portion of the borrowings outstanding under our revolving credit facility, thereby resulting in enhanced liquidity.

At December 31, 2017, we had $43.9 million of cash and cash equivalents and $2.56 billion of borrowing availability on our credit facility after considering outstanding borrowings and letters of credit. We had $188 million of credit facility borrowings at December 31, 2017 compared to $938 million at September 30, 2017 and $905 million at December 31, 2016. At January 31, 2018, outstanding credit facility borrowings decreased further to $93 million, leaving approximately $2.65 billion of borrowing availability at that date.

~~Impact of income tax reform legislation~~

In December 2017, the Tax Cuts and Jobs Act (the "Tax Reform Act") was signed into law, which among other things reduces the federal corporate income tax rate from 35% to 21% effective January 1, 2018. In accordance with U.S. GAAP, we remeasured our deferred income tax assets and liabilities as of December 31, 2017 to reflect the reduced tax rate, which resulted in a one-time decrease in income tax expense and corresponding increase in net income of approximately $713.7 million ($1.92 per basic share and $1.91 per diluted share) recognized in the 2017 fourth quarter. See the subsequent section titled ~~Legislative and Regulatory Developments–Tax Reform Legislation~~ ~~and~~ ~~Part II, Item 8. Notes to Consolidated Financial Statements—Note 8. Income Taxes~~ ~~for further discussion of the Tax Reform Act.~~

~~Litigation settlement~~

On February 16, 2018, we reached a settlement in connection with the case filed in November 2010 in the District Court of Blaine County by Billy J. Strack and Daniela A. Renner as trustees of certain named trusts and on behalf of other similarly situated parties against the Company. Under the settlement, if approved by the court, we will make payments and incur costs associated with the settlement of approximately $59.6 million. We have accrued a loss for such amount, which is included in “Accrued liabilities and other” on the consolidated balance sheets and “Litigation settlement” in the consolidated statements of comprehensive income (loss) as of and for the year ended December 31, 2017, which resulted in an after-tax decrease in 2017 net income of $37.0 million ($0.10 per basic and diluted share). See ~~Part II, Item 8. Notes to Consolidated Financial Statements—Note 10. Commitments and Contingencies~~ ~~for further discussion.~~

~~Financial and operating highlights~~

~~We use a variety of financial and operating measures to assess our performance. Among these measures are:~~

~~Volumes of crude oil and natural gas produced;~~

~~Crude oil and natural gas price differentials relative to NYMEX benchmark prices; and~~

~~Per unit operating and administrative costs.~~

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

Year ended December 31,
2017 2016 2015
Average daily production:
Crude oil (Bbl per day) 138,455
128,005
146,622
Natural gas (Mcf per day) 625,093
533,442
450,558
Crude oil equivalents (Boe per day) 242,637
216,912
221,715
Average sales prices:
Crude oil ($/Bbl) $ 45.70
$ 35.51
$ 40.50
Natural gas ($/Mcf) $ 2.93
$ 1.87
$ 2.31
Crude oil equivalents ($/Boe) $ 33.65
$ 25.55
$ 31.48
Crude oil sales price discount to NYMEX ($/Bbl) $ (5.50 ) $ (7.33 ) $ (8.33 )
Natural gas sales price discount to NYMEX ($/Mcf) $ (0.16 ) $ (0.61 ) $ (0.34 )
Production expenses ($/Boe) $ 3.66
$ 3.65
$ 4.30
Production taxes (% of oil and gas revenues) 7.0 % 7.0 % 7.8 %
DD&A ($/Boe) $ 18.89
$ 21.54
$ 21.57
Total general and administrative expenses ($/Boe) $ 2.16
$ 2.14
$ 2.34

~~Results of Operations~~

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

Year Ended December 31,
In thousands, except sales price data 2017 2016 2015
Crude oil and natural gas sales $ 2,982,966
$ 2,026,958
$ 2,552,531
Gain (loss) on crude oil and natural gas derivatives, net 91,647
(71,859 ) 91,085
Crude oil and natural gas service operations 46,215
25,174
36,551
Total revenues 3,120,828
1,980,273
2,680,167
Operating costs and expenses (1) (2,671,427 ) (2,267,807 ) (2,904,168 )
Other expenses, net (2) (293,334 ) (344,920 ) (311,084 )
Income (loss) before income taxes 156,067
(632,454 ) (535,085 )
Benefit for income taxes (3) 633,380
232,775
181,417
Net income (loss) $ 789,447
$ (399,679 ) $ (353,668 )
Diluted net income (loss) per share $ 2.11
$ (1.08 ) $ (0.96 )
Production volumes:
Crude oil (MBbl) 50,536
46,850
53,517
Natural gas (MMcf) 228,159
195,240
164,454
Crude oil equivalents (MBoe) 88,562
79,390
80,926
Sales volumes:
Crude oil (MBbl) 50,628
46,802
53,664
Natural gas (MMcf) 228,159
195,240
164,454
Crude oil equivalents (MBoe) 88,655
79,342
81,073
Average sales prices:
Crude oil ($/Bbl) $ 45.70
$ 35.51
$ 40.50
Natural gas ($/Mcf) $ 2.93
$ 1.87
$ 2.31
Crude oil equivalents ($/Boe) $ 33.65
$ 25.55
$ 31.48


~~(1)~~	Net of gain on sale of assets of $55.1 million, $304.5 million and $23.1 million for the years ended December 31, 2017, 2016 and 2015, respectively. Additionally, the year 2017 includes the aforementioned $59.6 million loss accrual recognized in conjunction with a litigation settlement.


~~(2)~~	The year 2016 includes a loss on extinguishment of debt of $26.1 million related to the November 2016 redemptions of our $200 million of 7.375% Senior Notes due 2020 and $400 million of 7.125% Senior Notes due 2021.


~~(3)~~	The year 2017 reflects the remeasurement of our deferred income tax assets and liabilities in response to the enactment of the Tax Reform Act in December 2017, which resulted in a one-time decrease in income tax expense via the recognition of an income tax benefit totaling approximately $713.7 million.

~~Year ended December 31, 2017 compared to the year ended December 31, 2016~~

~~Production~~


	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
	2017			2016							2020			2019
	Volume	Percent		Volume	Percent						Volume	Percent		Volume	Percent
Crude oil (MBbl)	50,536	57	%	46,850	59	%	3,686	8	%	Crude oil (MBbl)	58,745	53	%	72,267	58	%	(13,522)	(19	%)
Natural gas (MMcf)	228,159	43	%	195,240	41	%	32,919	17	%	Natural gas (MMcf)	306,528	47	%	311,865	42	%	(5,337)	(2	%)
Total (MBoe)	88,562	100	%	79,390	100	%	9,172	12	%	Total (MBoe)	109,833	100	%	124,244	100	%	(14,411)	(12	%)


	Year Ended December 31,						Volume increase	Volume percent increase			Year Ended December 31,						Volume decrease	Volume percent decrease
	2017			2016							2020			2019
	MBoe	Percent		MBoe	Percent						MBoe	Percent		MBoe	Percent
North Region	52,258	59	%	48,169	61	%	4,089	8	%	North Region	60,591	55	%	74,028	60	%	(13,437)	(18	%)
South Region	36,304	41	%	31,221	39	%	5,083	16	%	South Region	49,242	45	%	50,216	40	%	(974)	(2	%)
Total	88,562	100	%	79,390	100	%	9,172	12	%	Total	109,833	100	%	124,244	100	%	(14,411)	(12	%)

In millions Amount
Exploration and development drilling $ 1,988
Land costs 132
Capital facilities, workovers and other corporate assets 168
Seismic 12
Total 2018 capital budget, excluding acquisitions $ 2,300

Our drilling and completion activities and the actual amount and timing of our capital expenditures may differ materially from our budget as a result of, among other things, ~~access to capital,~~ available cash flows, unbudgeted acquisitions, actual drilling and completion results, operational process improvements, the availability of drilling and completion rigs and other services and equipment, the availability of transportation, gathering and processing capacity, changes in commodity prices, and regulatory, technological and competitive developments. We monitor our capital spending closely based on actual and projected cash flows and may scale back our spending should commodity prices decrease from current levels. Conversely, an increase in commodity prices from current levels could result in increased capital expenditures. We expect to continue participating as a buyer of properties when and if we have the ability to increase our position in strategic plays at competitive terms.

Contractual Obligations

The following table presents our contractual obligations and commitments as of December 31, ~~2017:~~2020.


	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

Payments due by period
In thousands Total Less than
1 year (2018) Years 2 and 3
(2019-2020) Years 4 and 5
(2021-2022) More than
5 years
Arising from arrangements on the balance sheet:

Revolving credit facility borrowings $ 188,000
$ —
$ 188,000
$ —
$ —
Senior Notes (1) 6,200,000
—
—
2,000,000
4,200,000
Note payable (2) 10,021
2,286
4,795
2,940
—
Interest payments (3) 2,476,202
270,535
569,683
567,159
1,068,825
Asset retirement obligations (4) 114,406
2,612
3,486
—
108,308
Arising from arrangements not on balance sheet: (5)

Operating leases and other (6) 26,956
11,867
6,581
1,300
7,208
Drilling rig commitments (7) 103,595
72,924
30,671
—
—
Transportation and processing commitments (8) 1,429,511
196,714
401,656
333,988
497,153
Total contractual obligations $ 10,548,691
$ 556,938
$ 1,204,872
$ 2,905,387
$ 5,881,494
(1)On January 5, 2021, we redeemed $400 million principal amount of our outstanding 2022 Notes using proceeds from borrowings on our credit facility. Such activity is not reflected in the table above.

(2)Amounts represent scheduled maturities of our senior note obligations at December 31, 2020 and do not reflect any discount or premium at which the senior notes were issued or any debt issuance costs.

(3)Represents future principal payments on two 10-year amortizing notes payable secured by the Company’s corporate office building and its interest in parking facilities in Oklahoma City, Oklahoma and does not reflect any debt issuance costs. Principal and interest are payable monthly through the loans' maturity dates in May 2030.


~~(1)~~	Amounts represent scheduled maturities of our senior note obligations at December 31, 2017 and do not reflect any discount or premium at which the senior notes were issued or any debt issuance costs. See ~~Part II, Item 8. Notes to Consolidated Financial Statements—Note 7. Long-Term Debt~~ ~~for a description of our senior notes.~~


~~(2)~~	Represents future principal payments on a 10-year amortizing note payable secured by the Company’s corporate office building in Oklahoma City, Oklahoma and does not reflect any debt issuance costs. Principal and interest are payable monthly through the loan’s maturity date of February 26, 2022.


~~(3)~~	(4)Interest payments include scheduled cash interest payments on the senior notes and note payable as well as estimated interest payments on our revolving credit facility borrowings outstanding at December 31, 2017 and assumes the actual weighted average interest rate on our credit facility borrowings of 3.19%~~at December 31, 2017 continues through the maturity date of the arrangement.~~


~~(4)~~	~~Amounts represent estimated discounted costs for future dismantlement and abandonment of our crude oil and natural gas properties. See~~ ~~Part II, Item 8. Notes to Consolidated Financial Statements—Note 1. Organization and Summary of Significant Accounting Policies~~ ~~for additional discussion of our asset retirement obligations.~~


~~(5)~~	The commitment amounts included in this section primarily represent costs associated with wells operated by the Company. A portion of these costs will be borne by other interest owners. Due to variations in well ownership, our net share of these costs cannot be determined with certainty.


~~(6)~~	Amounts primarily represent commitments for electric infrastructure, land and road use, office buildings and equipment, communication towers, field equipment, sponsorship agreements, and purchase obligations mainly related to software services.


~~(7)~~	~~Amounts represent commitments under drilling rig contracts with various terms extending to~~ ~~February 2020~~ ~~to ensure rig availability in our key operating areas.~~

~~(8)~~

We have entered into transportation and processing commitments to guarantee capacity on crude oil and natural gas pipelines and natural gas processing facilities. These commitments require us to pay per-unit transportation or processing charges regardless of the amount of capacity used. We are not committed under these contracts to deliver fixed and determinable quantities of crude oil or natural gas in the future. See ~~Part II, Item 8. Notes to Consolidated Financial Statements—Note 10. Commitments and Contingencies~~ ~~for additional discussion.~~

If the ~~litigation settlement discussed in~~ senior notes and notes payable, as well as estimated interest payments and commitment fees on unused borrowing availability under our credit facility assuming the $1.33 billion of availability as of December 31, 2020 continues through the April 2023 maturity date of the facility.

(5)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 ~~10. Commitments~~1. Organization and ~~Contingencies~~ ~~is approved by the court, we will make payments and incur costs associated with the settlement~~Summary of ~~approximately $59.6 million. The timing of payments~~Significant Accounting Policies for additional discussion of our asset retirement obligations.

(6)Amounts primarily represent commitments for electric infrastructure, surface use agreements, office buildings and equipment, communication towers, field equipment,and purchase obligations mainly related to software services. 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. These amounts include minimum payment obligations on enforceable commitments with durations in excess of one year with a discounted present value totaling $6.4 million that qualify as leases and were recognized on our balance sheet at December 31, 2020 in accordance with ASC Topic 842.

(7)Amounts represent operating day-rate commitments under drilling rig contracts with various terms extending toMay 2021. A portion of these costs will be borne by other interest owners, the ~~settlement~~amount of which cannot be determined with certainty. These amounts include minimum payment obligations with a discounted present value totaling $2.0 million that qualify as leases and were recognized on our balance sheet at December 31, 2020in accordance with ASC Topic 842.

(8)We have entered into transportation and processing commitments to guarantee capacity on crude oil and natural gas pipelines and natural gas processing facilities. These commitments require us to pay per-unit transportation or processing charges regardless of the amount of capacity used. We are not committed under these contracts to deliver fixed and determinable quantities of crude oil or natural gas in the future. A portion of these costs will be borne by other interest owners, the amount of which cannot be determined with certainty. These commitments do not qualify as leases under ASC Topic 842 and are not recognized on our balance sheet.

On December 31, 2020, we executed a definitive agreement to acquire undeveloped leasehold and producing properties in the Powder River Basin of Wyoming for $215 million of cash. Closing of the acquisition is ~~uncertain~~scheduled to occur on or around March 4, 2021. This pending acquisition remains subject to the completion of customary due diligence procedures and ~~have~~closing conditions and is not ~~been~~ reflected in the table above.

Delivery Commitments

We have various natural gas volume delivery commitments that are related to our North and South areas. We expect to primarily fulfill our contractual obligations ~~table above.~~with production from our proved reserves. However, we may purchase third-party volumes to satisfy our commitments. The volumes disclosed herein represent gross production associated with properties operated by us and do not reflect our net proportionate share of such amounts. As of December 31, 2020, we were committed to deliver the following fixed quantities of natural gas production.


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

Derivative Instruments

~~We may utilize derivative instruments to economically hedge against the variability~~See Note 5. Derivative Instruments in cash flows associated with future sales of our production. While the use of derivative instruments limits the downside risk of adverse price movements, their use also limits future revenues from upward price movements. See Part II, Item 8. Notes to Consolidated Financial ~~Statements—Note 5. Derivative Instruments~~Statements for ~~further discussion of the accounting applicable to our derivative instruments,~~ a summary of ~~open contracts~~derivative instruments in place as of December 31, ~~2017, and the estimated fair value of our contracts as of that date.~~

2020. Between January 1, ~~2018~~2021 and February ~~16, 2018~~12, 2021 we entered into additional ~~natural gas~~ derivative instruments as summarized ~~below, representing the majority of our forecasted 2018 natural gas production.~~below. The hedged volumes reflected below represent an aggregation of multiple ~~contracts that are generally expected to be realized ratably over the indicated period. These~~contracts. The crude oil derivative instruments will be settled based ~~upon reported~~on NYMEX West Texas Intermediate pricing and natural gas derivative instruments will be settled based on NYMEX Henry Hub ~~settlement prices.~~pricing.

Natural gas derivatives

Swaps Weighted Average Price

Period and Type of Contract

MMBtus

April 2021 - December 2021

Swaps - Henry Hub

64,120,000

2.88


				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

Dividend payments

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.

Swaps Weighted Average Price

Period and Type of Contract MMBtus
February 2018 - December 2018
Swaps - Henry Hub 193,720,000
$ 2.88
Share repurchase program

In May 2019 our Board of Directors approved the initiation of a share repurchase program to acquire up to $1 billion of our common stock beginning in June 2019. Through December 31, 2020, we had repurchased and retired a cumulative total of approximately 13.8 million shares at an aggregate cost of $317.1 million since the inception of the program. The timing and amount of the Company's share repurchases are subject to market conditions and management discretion. The share repurchase program does not require the Company to repurchase a specific number of shares and may be modified, suspended, or terminated by the Board of Directors at any time. To preserve cash in the current environment, we do not expect to engage in significant share repurchase activity in the near term.

Senior note repurchases

As discussed in Note 7. Long-Term Debt and Note 21. Subsequent Event in Part II, Item 8. Notes to Consolidated Financial Statements, in 2020 and early 2021 we repurchased a portion of our outstanding senior notes. From time to time we may seek to execute additional repurchases of our senior notes for cash in open market transactions, privately negotiated transactions, or otherwise. Such repurchases will depend on prevailing market conditions, our liquidity and prospects for future access to capital, and other factors. The amounts involved in any such transactions, individually or in the aggregate, may be material.

Critical Accounting Policies and Estimates

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

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

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

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

Crude oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be precisely measured. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Periodic revisions ~~to the~~or removals of estimated reserves and future cash flows may be necessary as a result of a number of factors, including reservoir performance, new drilling, crude oil and natural gas prices, changes in costs, technological advances, new geological or geophysical data, changes in business strategies, or other economic factors. Accordingly, reserve estimates may differ significantly from the quantities of crude oil and natural gas ultimately recovered.For the years ended December 31, ~~2017, 2016,~~2020, 2019, and ~~2015,~~2018, net downward revisions and removals of our proved reserves ~~were revised downward from prior years’ reports by~~totaled approximately 82505 MMBoe, ~~110~~149 MMBoe, and ~~297~~269 MMBoe, respectively. We cannot predict the amounts or timing of future reserve ~~revisions.~~revisions or removals.

Estimates of proved reserves are key components of the Company’s most significant financial estimates including the computation of depreciation, depletion, amortization and impairment of proved crude oil and natural gas properties. Holding all other factors constant, if proved reserves are revised downward, the rate at which we record DD&A expense would increase, reducing net income. Conversely, if proved reserves are revised upward, the rate at which we record DD&A expense would

decrease. Future revisions of reserves may be material and could significantly alter future depreciation, depletion, and amortization expense and may result in material impairments of assets.

At December 31, ~~2017,~~2020, our proved reserves totaled ~~1,331~~1,104 MMBoe as determined using 12-month average first-day-of-the-month prices of ~~$51.34~~$39.57 per barrel for crude oil and ~~$2.98~~$1.99 per MMBtu for natural gas. Actual future prices may be materially higher or lower than those used in our year-end estimates. NYMEX WTI crude oil and Henry Hub natural gas first-day-of-the-month commodity prices for January 1, ~~2018~~2021 and February 1, ~~2018~~2021 averaged ~~$63.11~~$51.04 per barrel and ~~$3.40~~$2.53 per MMBtu, respectively.

Holding all other factors constant, if crude oil prices used in our year-end reserve estimates were increased to ~~$65~~$50 per barrel our proved reserves at December 31, ~~2017~~2020 could increase by approximately 2452 MMBoe, or 5%, representing a 7% increase in proved developed producing reserves averaged with a 2% increase in PUD reserves. If the increase in proved reserves under this oil price sensitivity existed throughout 2020, our DD&A expense for 2020 would have decreased by an estimated 7%.

Holding all other factors constant, if natural gas prices used in our year-end reserve estimates were increased to $2.50 per MMBtu our proved reserves at December 31, 2020 could increase by approximately 21 MMBoe, or 2%, representing a 3% increase in proved developed producing reserves averaged with a 1% increase in PUD reserves. If the increase in proved reserves under this gas price sensitivity existed throughout ~~2017,~~2020, our DD&A expense for ~~2017~~2020 would have decreased by an estimated 3%.

Holding all other factors constant, if natural gas prices used in our year-end reserve estimates were increased to $4.00 per MMBtu our proved reserves at December 31, 2017 could increase by approximately 8 MMBoe, or 1%, which we estimate would result in an approximate 1% decrease in DD&A expense for 2017 assuming the increase in proved reserves under this price sensitivity existed throughout the year.

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

significant fields may individually affect our DD&A rate. As a result, the impact on DD&A expense from revisions in reserves cannot be predicted with certainty and may result in changes in expense that are greater or less than the underlying changes in reserves.

See Part I, Item 1. Business—Crude Oil and Natural Gas Operations—Proved Reserves—Proved Reserve, Standardized Measure, and PV-10 Sensitivities for additional proved reserve sensitivities under certain increasing and decreasing commodity price scenarios for crude oil and natural gas.

Revenue Recognition

We derive substantially all of our revenues from the sale of crude oil and natural gas. ~~Crude~~See Part II, Item 8. Notes to Consolidated Financial Statements—Note 8. Revenues for discussion of our accounting policies governing the recognition and presentation of revenues.

Operated crude oil and natural gas revenues are recognized induring the month ~~the product is delivered~~in which control transfers to the ~~purchaser~~customer and ~~title transfers. We~~it is probable the Company will collect the consideration it is entitled to receive. For non-operated properties, the Company's proportionate share of production is generally ~~receive payment from one~~marketed at the discretion of the operators. Non-operated revenues are recognized by the Company during the month in which production occurs and it is probable the Company will collect the consideration it is entitled to ~~three months after the sale has occurred.~~ receive.

At the end of each month, to record ~~revenue~~revenues we estimate the amount of production delivered and sold to ~~purchasers~~customers and the prices at which they were sold. Variances between estimated revenues and actual amounts received for all prior months are recorded in the month payment is received and are reflected in our financial statements as crude oil and natural gas sales. These variances have historically not been material.

~~New accounting rules governing~~For the ~~recognition~~sale of crude oil and ~~presentation of~~natural gas, we evaluate whether we are the principal, and report revenues ~~went into effect~~ on ~~January 1, 2018. See~~ ~~Part II, Item 8. Notes to Consolidated Financial Statements—Note 1. Organization~~a gross basis (revenues presented separately from associated expenses), or an agent, and ~~Summary of Significant Accounting Policies–New accounting pronouncements not yet adopted at December 31, 2017–Revenue recognition and presentation~~ ~~for discussion~~report revenues on a net basis. In this assessment, we consider if we obtain control of the ~~expected impact~~products before they are transferred to the customer as well as other indicators. Judgment may be required in determining the point in time when control of ~~the new rules on our future financial statements.~~products transfers to customers.

Successful Efforts Method of Accounting

Our business is subject to accounting rules that are unique to the crude oil and natural gas industry. Two generally accepted methods of accounting for oil and gas activities are available—the successful efforts method and the full cost method. The most significant differences between these two methods are the treatment of exploration costs and the manner in which the carrying value of oil and gas properties are amortized and evaluated for impairment. We use the successful efforts method of accounting for our oil and gas properties. See Part II, Item 8. Notes to Consolidated Financial Statements—Note 1. Organization and Summary of Significant Accounting Policies for further discussion of the accounting policies applicable to the successful efforts method of accounting.

Derivative Activities

WeFrom time to time we may utilize derivative contracts to hedge against the variability in cash flows associated with the forecasted sale of future crude oil and natural gas production and ~~forecasted purchases of diesel fuel~~ for ~~use in drilling activities.~~other purposes. We have elected not to designate any of our price risk management activities as cash flow hedges. As a result, we mark our derivative instruments to fair value and recognize the changes in fair value in current earnings.

In determining the amounts to be recorded for ~~our open~~outstanding derivative contracts, we are required to estimate the fair value of the derivatives. We use an independent third party to provide our derivative valuations. The third party’s valuation models for derivative contracts are industry-standard models that consider various inputs including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. The fair value calculations for collars requires the use of an option-pricing model. The estimated future prices are compared to the prices fixed by the derivative agreements and the resulting estimated future cash inflows or outflows over the lives of the derivatives are discounted to calculate the fair value of the derivative contracts. These pricing and discounting variables are sensitive to market volatility as well as changes in future price forecasts and interest rates. ~~See~~ ~~Part II, Item 7A. Quantitative and Qualitative Disclosures About Market Risk~~ ~~for a discussion of the sensitivity of natural gas derivative fair value calculations to changes in forward natural gas prices.~~

We validate our derivative valuations through management review and by comparison to our counterparties’ valuations for reasonableness. Differences between our fair value calculations and counterparty valuations have historically not been material.

Impairment of Assets

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

Proved crude oil and natural gas properties are reviewed for impairment on a field-by-field basis. If the carrying amount of a field exceeds its estimated undiscounted future cash flows, the carrying amount of the field is reduced to its estimated fair value using a discounted cash flow model. For producing properties, the impairment evaluations involve a significant amount of judgment since the results are based on estimated future events, such as future sales prices for crude oil and natural gas, future costs to produce those products, estimates of future crude oil and natural gas reserves to be recovered and the timing thereof, the economic and regulatory climates and other factors. The need to test a field for impairment may result from significant declines in sales prices or downward revisions toor removals of crude oil and natural gas reserves. Estimates of anticipated sales prices and recoverable reserves are highly judgmental and are subject to material revision in future periods.

Impairment provisions for ~~producing~~proved properties totaled ~~$82.3~~$207.1 million for ~~2017.~~2020. Commodity price assumptions used for the year-end December 31, ~~2017~~2020 impairment calculations were based on publicly available average annual forward commodity strip prices through year-end ~~2022~~2025 and were then escalated at 3% per year thereafter. Holding all other factors constant, as forward commodity prices decrease, our probability for recognizing producing property impairments may increase, or the magnitude of impairments to be recognized may increase. Conversely, as forward commodity prices increase, our probability for recognizing producing property impairments may decrease, or the magnitude of impairments to be recognized may decrease or be eliminated. As of December 31, ~~2017,~~2020, the publicly available forward commodity strip prices for the year ~~2022~~2025 used in our fourth quarter impairment calculations averaged ~~$51.65~~$44.82 per barrel for crude oil and ~~$2.89~~$2.52 per Mcf for natural gas. If forward commodity prices materially decrease from current levels for an extended period, additional impairments of producing properties may be recognized in the future. Because of the uncertainty inherent in the numerous factors utilized in determining the fair value of producing properties, we cannot predict the timing and amount of future impairment charges, if any.

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

Income Taxes

~~We make certain estimates~~Income taxes are accounted for using the asset and ~~judgments in determining our~~liability method. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income ~~tax expense for financial reporting purposes. These estimates and judgments occur~~ in the ~~calculation of certain~~years in which those differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities ~~that arise from differences~~of a change in ~~the timing and recognition of revenue and expense for~~ tax ~~and financial reporting purposes. Our federal and state~~rates is recognized in income tax returns are generally not prepared or filed before the consolidated financial statements are prepared; therefore, we estimate the tax basis of our assets and liabilities at the end of each period as well as the effects of tax rate changes, tax credits and net operating loss carryforwards. Adjustments related to these estimates are recorded in our tax provision in the period ~~in which we file our income tax returns. Further, we must assess~~that includes the ~~likelihood we will be able to recover or utilize our deferred tax assets. If recovery is not likely, we must record a valuation allowance against such~~enactment date.

In assessing the realizability of deferred tax assets, for the amount we would not expect to recover, which would result in an increase to our income tax expense. As of December 31, 2017, we believe all deferred tax assets, net of valuation allowances, reflected in our consolidated balance sheets will ultimately be utilized. Wemanagement must consider future taxable income in making such assessments. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly related to prevailing crude oil and natural gas prices). If our estimates and judgments change regarding our ability to utilize our deferred tax assets, our tax provision could increase in the period it is determined thatwhether it is more likely than not that some portion or all of the deferred tax assets will not be realized. We apply judgment to determine the weight of both positive and negative evidence in order to conclude whether a valuation allowance is necessary for our deferred tax assets. In determining whether a valuation allowance is required for our deferred tax asset ~~will not be utilized.~~

~~Our~~balances, we consider, among other factors, current financial position, results of operations, projected future taxable income, reversal of existing deferred tax liabilities against deferred tax assets, whether the carryforward period is so brief that it would limit realization of the tax benefit, and tax planning strategies. Significant judgment is involved in this determination as we are required to make assumptions about future commodity prices, projected production, development activities, profitability of future business strategies and forecasted economics in the oil and gas industry. Additionally, changes in the effective tax rate ~~is subject to variability~~resulting from ~~period to period as a result of factors other than changes in federal and state tax rates and/or~~ changes in tax ~~laws which can~~law and our level of earnings may limit utilization of deferred tax assets and may affect ~~tax-paying companies. Our effective tax rate is affected by permanent taxable differences,~~the valuation ~~allowances, and changes in the allocation~~ of ~~property, payroll, and revenues between states in which we own property as rates vary from state to state. Due to the size of our gross~~ deferred tax balances in the future. Changes in judgment regarding future realization of deferred tax assets may result in a ~~small change~~reversal of all or a portion of the valuation allowance.

We believe our net deferred tax assets, after valuation allowances, will ultimately be realized. We will continue to evaluate both the positive and negative evidence on a quarterly basis in determining the need for additional valuation allowances with respect to our ~~estimated future~~deferred tax ~~rate can have~~assets.In 2020, we determined it was more likely than not that a ~~material effect on current period earnings.~~

portion of our Oklahoma net operating loss carryforward would not be utilized before expiration, and a valuation allowance of $14.5 million was established during the year for the deferred tax asset associated with such net operating loss carryforward.

Contingent Liabilities

A provision for legal, environmental and other contingencies is charged to expense when a loss is probable and the loss or range of loss can be reasonably estimated. Determining when liabilities and expenses should be recorded for these contingencies and the appropriate amounts of accruals is subject to an estimation process that requires subjective judgment of management. In certain cases, management’s judgment is based on the advice and opinions of legal counsel and other advisers, the interpretation of laws and regulations which can be interpreted differently by regulators and/or courts of law, the experience of the Company and other companies dealing with similar matters, and management’s decision on how it intends to respond to a particular matter; for example, a decision to contest it vigorously or a decision to seek a negotiated settlement. Actual losses can differ from estimates for various reasons, including differing interpretations of laws and opinions and assessments on the amount of damages. We closely monitor known and potential legal, environmental and other contingencies and make our best estimate of when or if to record liabilities and losses for matters based on available information.

Off-Balance Sheet Arrangements

Currently, we do not have any off-balance sheet arrangements with unconsolidated entities to enhance liquidity and capital resources.

New Accounting Pronouncements

See Part II, Item 8. Notes to Consolidated Financial Statements—Note ~~1. Organization and Summary of Significant Accounting Policies~~9. Allowance for Credit Losses for a discussion of the ~~impact upon adoption of~~ new credit loss accounting ~~pronouncements in 2017 along with a discussion of accounting pronouncements not yet adopted.~~standard adopted on January 1, 2020.

Legislative and Regulatory Developments

The crude oil and natural gas industry in the United States is subject to various types of regulation at the federal, state and local levels. See Part I, Item 1. Business—Regulation of the Crude Oil and Natural Gas Industry for a discussion of significant laws and regulations that have been enacted or are currently being considered by regulatory bodies that may affect us in the areas in which we operate.

~~Tax Reform Legislation~~

~~On December 22, 2017,~~ In particular, in January 2021 President Biden issued executive orders that, among other things, suspend new permitting and leasing activities for oil and gas exploration and production on federal lands and establish new greenhouse gas emission standards for the ~~Tax Reform Act was signed into law, which represents the most significant tax policy change~~oil and gas sector. President Biden may continue to issue additional executive orders in ~~the United States since 1986. Below~~pursuit of his regulatory agenda and, with control of Congress shifting in January 2021, there is a summary of key changes included in the new law that are most relevant to our business. Changes arising from the Tax Reform Act, which are subject to a number of important qualifications and exceptions not included in the summary below, generally become effective for tax years beginning after December 31, 2017. The following discussion should be read in conjunction with ~~Part II, Item 8. Notes to Consolidated Financial Statements—Note 8. Income Taxes.~~

~~Reduction in corporate tax rate—~~the Tax Reform Act reduces the corporate tax rate from 35% to 21%, effective for tax years beginning after December 31, 2017. In recent years, we have provided for income taxes at a combined federal and state tax rate of 38% of pre-tax income and losses generated by our operations in the United States, representing 35% for federal income taxes and 3% for state income taxes. For 2018, under the new tax law we expect to provide for income taxes at a combined federal and state tax rate of approximately 24%. The new lower federal tax rate is expected to have a significant favorable impact on our U.S. GAAP net income in future periods.

~~Repeal of alternative minimum tax—~~the Tax Reform Act repeals the corporate alternative minimum tax (“AMT”), effective for tax years beginning after December 31, 2017. Further, the new law allows an entity to claim portions of any unused AMT credits over the next four years to offset its regular tax liability. An entity with unused AMT credits as of December 31, 2017 can first use those credits to offset its regular tax for 2017, and can then claim up to 50% of the remaining AMT credits in 2018, 2019, and 2020, with all remaining AMT credits refundable in 2021. This law change is expected to have a favorable impact on the Company relative to previous AMT rules. Our unused AMT credits totaled $7.8 million at December 31, 2017, which we believe are realizable and will be pursued for refund.

~~Net operating loss deduction limitation—~~the Tax Reform Act limits the amount entities are able to deduct for federal net operating loss ("NOL") carryforwards generated in tax years beginning after December 31, 2017 to 80% of taxable income for a respective year. The law also generally repeals an entity's ability to carry back future NOLs to prior periods. These adverse rule changes are mitigated by a law change that now allows any NOLs generated in taxable years beginning after December 31, 2017 to be carried forward indefinitely. NOLs arising before January 1, 2018 may still be carried back two years and are subject to their existing carryforward expiration periods. These new law changes, when considered in the aggregate, are not expected to have a significant adverse impact on our ability to fully utilize current and future federal NOL carryforwards.

As of December 31, 2017, we had federal NOL carryforwards of $2.39 billion which begin expiring in 2033. Deferred tax assets reflected in our consolidated balance sheet related to these NOL carryforwards totaled $604.4 million at December 31, 2017. In response to the tax law changes, we reassessed the realizability of these deferred tax assets, taking into consideration how the new laws impact future taxable income, if any, that is expected to be offset by our NOLs. We believe our available NOLs at December 31, 2017 will ultimately be utilized prior to expiration and, as a result, no valuation allowance on our NOL deferred tax assets is necessary as of December 31, 2017.

~~Interest expense deduction limitation—~~the Tax Reform Act limits the deduction for business interest expense to 30% of adjusted taxable income for tax years beginning after December 31, 2017. Before January 1, 2022, the calculation of adjusted taxable income is similar to taxable earnings before interest, taxes, depreciation, and amortization (EBITDA). After January 1, 2022, that calculation is equivalent to taxable earnings before interest and taxes (EBIT). These adverse changes are mitigated by a law change that now allows any disallowed interest expense to be carried forward indefinitely. Based on our current tax planning strategies, these changes are not expected to have a significant adverse impact on our ability to deduct interest expenses for at least the next five years.

~~Acceleration of bonus depreciation—~~under the Tax Reform Act, entities are able to claim bonus depreciation to accelerate the expensing of the cost of certain qualified property acquired and placed into service after September 27, 2017 and before January 1, 2023. For the first five-year period (2018 through 2022), companies can deduct 100% of the cost of qualified property compared to a 50% allowance under previous law. During the period starting in 2023, the additional bonus depreciation is gradually phased out by 20% each year through 2027. This law change is expected to have a favorable impact on the Company as it has the potential ~~to reduce or eliminate future taxable income or increase NOLs~~ for ~~utilization in future periods.~~

~~Executive compensation deduction limitation—for tax years beginning after December 31, 2017,~~ the ~~Tax Reform Act limits an entity's ability to deduct compensation in excess~~revision of ~~$1 million for certain employees regardless of the character of those payments. Further, the new law expands the number of individuals whose compensation is subject to the $1 million limitation~~existing laws and expands the types of equity awards to be included in the calculations. These changes will limit our ability to deduct future executive compensation expenses, the impact of which is uncertain but is not expected to be significant to our business.

~~Impact on foreign operations—~~the Tax Reform Act introduces new rules that significantly change fundamental aspects of the taxation of foreign earnings of U.S. entities. Notably, the new law subjects unrepatriated foreign earnings to a mandatory one-time transition tax on post-1986 earnings at a rate of 15.5% for foreign earnings held in the form of cash and certain liquid assets and at a rate of 8% for all other foreign earnings. Our foreign operations are immaterial and have not generated taxable income historically and are not expected to generate significant taxable income in the future. Additionally, we have no significant cash or liquid assets held in foreign countries. Accordingly, the foreign tax law changes in the Tax Reform Act are not expected to have a significant impact on our business.

In addition to the changes described above, the Tax Reform Act includes a multitude of other provisions that broaden the tax base and eliminate or reduce other deductions, exclusions, and credits, none of which are expected to individually have a significant impact on our business.

The Tax Reform Act is generally expected to have an overall favorable impact on our business primarily due to expected benefits from the reduced corporate tax rate. The new laws are not expected to adversely impact our liquidityregulations or the ~~amount~~adoption of ~~cash payments we make for income taxes for at least~~new legislation that could adversely affect the ~~next five years.~~oil and gas industry.

Inflation

Certain drilling and completion costs and costs of oilfield services, equipment, and materials decreased in recent years as service providers reduced their costs in response to reduced demand arising from low crude oil prices. However, inflationary pressures returned in 2017 and are expected to continue in 2018 in conjunction with the stabilization and improvement in crude oil prices in recent months. As a result of the low commodity price environment in recent years, the number of providers of services, equipment, and materials have decreased in the regions where we operate. If commodity prices show signs of diminished volatility and sustained recovery, ~~and~~ industry drilling and completion activities are likely to increase and we may face shortages of service providers, equipment, and materials. Such shortages could result in increased competition which may lead to ~~further~~ increases in costs.

Non-GAAP Financial Measures

Net crude oil and natural gas sales and net sales prices

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

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

The following table presents a reconciliation of total Company crude oil and natural gas sales (GAAP) to net crude oil and natural gas sales and related net sales prices (non-GAAP) for 2020, 2019, and 2018.


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

The following tables present reconciliations of crude oil and natural gas sales (GAAP) to net crude oil and natural gas sales and related net sales prices (non-GAAP) for North Dakota Bakken and SCOOP for 2020, 2019, and 2018 as presented in Part I, Item 1. Business—Crude Oil and Natural Gas Operations—Production and Price History.


North Dakota Bakken	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)	$	1,469,450	$	24,714	$	1,494,164	$	2,826,136	$	128,426	$	2,954,562	$	2,797,771	$	263,388	$	3,061,159
Less: Transportation expenses	(127,036)		(2,580)		(129,616)		(157,076)		(2,530)		(159,606)		(128,287)		(2,291)		(130,578)
Net crude oil and natural gas sales (non-GAAP)	$	1,342,414	$	22,134	$	1,364,548	$	2,669,060	$	125,896	$	2,794,956	$	2,669,484	$	261,097	$	2,930,581
Sales volumes (MBbl/MMcf/MBoe)	40,040		97,532		56,295		52,374		98,186		68,738		45,735		78,448		58,810
Net sales price (non-GAAP)	$	33.53	$	0.23	$	24.24	$	50.96	$	1.28	$	40.66	$	58.37	$	3.33	$	49.83


SCOOP	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)	$	486,076	$	246,125	$	732,201	$	640,097	$	277,230	$	917,327	$	435,798	$	351,021	$	786,819
Less: Transportation expenses	(5,275)		(21,909)		(27,184)		(3,539)		(14,795)		(18,334)		(4,039)		(11,741)		(15,780)
Net crude oil and natural gas sales (non-GAAP)	$	480,801	$	224,216	$	705,017	$	636,558	$	262,435	$	898,993	$	431,759	$	339,280	$	771,039
Sales volumes (MBbl/MMcf/MBoe)	12,694		136,410		35,429		11,592		111,436		30,164		6,882		99,397		23,447
Net sales price (non-GAAP)	$	37.88	$	1.64	$	19.90	$	54.92	$	2.36	$	29.80	$	62.74	$	3.41	$	32.88

PV-10

Our PV-10 value, a non-GAAP financial measure, is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable financial measure computed using U.S. GAAP. PV-10 generally differs from Standardized Measure because it does not include the effects of income taxes on future net revenues. At December 31, ~~2017,~~2020, our PV-10 totaled approximately ~~$11.83~~$4.89 billion. The standardized measure of our discounted future net cash flows was approximately ~~$10.47~~$4.65 billion at December 31, ~~2017,~~2020, representing a ~~$1.36 billion~~$239 million difference from PV-10 due to the effect of deducting estimated future income taxes in arriving at Standardized Measure. We believe the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to proved reserves held by companies without regard to the specific income tax characteristics of such entities and is a useful measure of evaluating the relative monetary significance of our crude oil and natural gas properties. Investors may utilize PV-10 as a basis for comparing the relative size and value of our proved reserves to other companies. PV-10 should not be considered as a substitute for, or more meaningful than, the Standardized Measure as determined in accordance with U.S. GAAP. Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of our crude oil and natural gas properties.


~~Item 7A.~~	~~Quantitative and Qualitative Disclosures About Market Risk~~

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

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

Commodity Price Risk. Our primary market risk exposure is in the prices we receive from sales of our crude oil and natural ~~gas production.~~gas. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our natural gas production. ~~Pricing~~Prices for crude oil and natural gas ~~has~~have been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside of our control, including volatility in the differences between product prices at sales points and the applicable index prices. Based on our average daily production for the quarter ended December 31, ~~2017,~~2020, and excluding any effect of our derivative instruments in place, our annual revenue would increase or decrease by approximately ~~$613~~$645 million for each $10.00 per barrel change in crude oil prices at December 31, 2020 and ~~$260~~$356 million for each $1.00 per Mcf change in natural gas ~~prices.~~prices at December 31, 2020.

To reduce price risk caused by market fluctuations in crude oil and natural gas prices, from time to time we may economically hedge a portion of our anticipated crude oil and natural gas production as part of our risk management program. In addition, we may utilize basis contracts to hedge the differential between derivative contract index prices and those of our physical pricing points. Reducing our exposure to price volatility helps secure funds to be used for our capital program. Our decision on the quantity and price at which we choose to hedge our production is based in part on our view of current and future market conditions. We may choose not to hedge future production if the price environment for certain time periods is deemed to be unfavorable. Additionally, we may choose to 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. While hedging, if utilized, ~~limits~~may limit the downside risk of adverse price movements, it also ~~limits~~may limit future revenues from upward price movements. We have hedged the majority of our forecasted 2018 natural gas production. Our future crude oil production is currently unhedged and directly exposed to continued volatility in market prices, whether favorable or unfavorable.

Changes in natural gas prices during the year ended December 31, 2017 had an overall favorable impact on the fair value of our derivative instruments. For the year ended December 31, 2017, we recognized cash gains on natural gas derivatives of $29.6 million and non-cash mark-to-market gains on natural gas derivatives of $62.1 million.

The fair value of our natural gas derivative instruments at December 31, ~~2017~~2020 was a net asset of ~~$2.6~~$13.7 million. An assumed increase in the forward prices used in the ~~year-end~~December 31, 2020 valuation of our natural gas derivatives of $1.00 per MMBtu would change our ~~natural gas~~ derivative valuation to a net liability of approximately $2$27 million at December 31, ~~2017.~~2020. Conversely, an assumed decrease in forward prices of $1.00 per MMBtu would increase our ~~natural gas~~ derivative asset to approximately $7$63 million at December 31, ~~2017.~~ 2020.

Changes in the fair value of our ~~natural gas~~ derivatives from the above price sensitivities would produce a corresponding change in our total revenues.

~~See~~ ~~Part II, Item 8. Notes to Consolidated Financial Statements—Note 5. Derivative Instruments~~ ~~for further discussion of our hedging activities, including a summary of derivative contracts in place as of December 31, 2017.~~

Credit Risk. We monitor our risk of loss due to non-performance by counterparties of their contractual obligations. Our principal exposure to credit risk is through the sale of our crude oil and natural gas production, which we market to energy marketing companies, crude oil refining companies, and natural gas gathering and processing companies ($~~672~~561 million in receivables at December 31, ~~2017);~~2020) and our joint interest and other receivables ($~~427~~144 million at December 31, ~~2017); and counterparty credit risk associated with our derivative instrument receivables ($3 million at December 31, 2017)~~2020).

We monitor our exposure to counterparties on crude oil and natural gas sales primarily by reviewing credit ratings, financial statements and payment history. We extend credit terms based on our evaluation of each counterparty’s credit worthiness. We have not generally required our counterparties to provide collateral to secure crude oil and natural gas sales receivables owed to us. Historically, our credit losses on crude oil and natural gas sales receivables have been ~~immaterial.~~immaterial; however, we could experience increased exposure to credit losses in the future, which may be material, if the adverse economic effects of the COVID-19 pandemic persist for an extended period.

Joint interest receivables arise from billing the individuals and entities who own a partial interest in the wells we operate. These individuals and entities participate in our wells primarily based on their ownership in leases included in units on which we wish to drill. We can do very little to choose who participates in our wells. In order to minimize our exposure to this credit risk we generally request prepayment of drilling costs where it is allowed by contract or state law. For such prepayments, a liability is recorded and subsequently reduced as the associated work is performed. This liability was ~~$35~~$25 million at December 31, ~~2017,~~2020, which will be used to offset future capital costs when billed. In this manner, we reduce credit risk. We may have the right to place a lien on a co-owner’s interest in the well to redirect production proceeds in order to secure payment or, if necessary, foreclose on the interest. Historically, our credit losses on joint interest receivables have been ~~immaterial.~~

~~Our use of derivative instruments involves the risk that our counterparties will be unable to meet their commitments under the arrangements. We manage this risk by using multiple counterparties who~~immaterial; however, we ~~consider to be financially strong in order to minimize our~~could experience increased exposure to credit ~~risk with any individual counterparty.~~losses in the future, which may be material, if the adverse economic effects of the COVID-19 pandemic persist for an extended period.

Interest Rate Risk. Our exposure to changes in interest rates relates primarily to any variable-rate borrowings we may have outstanding from time to time under our ~~revolving~~ credit facility. Such borrowings bear interest at market-based interest rates plus a margin based on the terms of the borrowing and the credit ratings assigned to our senior, unsecured, long-term indebtedness. In March 2020, our corporate credit rating was downgraded by S&P in response to weakened oil and gas industry conditions and

resulting revisions made to rating agency commodity price assumptions. The downgrade caused the interest rate on our credit facility borrowings to increase by 0.25% and also prompted a 0.05% increase in the rate of commitment fees paid on unused borrowing availability. All of our other long-term indebtedness is fixed rate and does not expose us to the risk of cash flow loss due to changes in market interest rates.

We had $360 million of variable rate borrowings outstanding on our credit facility at January 31, 2021. The impact of a 0.25% increase in interest rates on this amount of debt would result in increased interest expense and reduced income before income taxes of approximately $0.9 million per year.

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

We had $93 million of variable rate borrowings outstanding on our revolving credit facility at January 31, 2018. The impact of a 0.25% increase in interest rates on this amount of debt would result in increased interest expense and reduced net income of approximately $0.2 million per year.

The following table presents our debt maturities and the weighted average interest rates by expected maturity date as of December 31, ~~2017:~~2020:


In thousands	2021			2022			2023			2024			2025			Thereafter			Total
Fixed rate debt:
Senior Notes:
Principal amount (1)(2)	$	—		$	630,782		$	649,625		$	911,000		$	—		$	3,200,000		$	5,391,407
Weighted-average interest rate	—			5.0%			4.5%			3.8		%	—		%	5.1		%	4.8		%
Notes payable:
Principal amount (1)	$	2,245		$	2,326		$	2,410		$	2,495		$	2,587		$	12,633		$	24,696
Interest rate	3.5		%	3.5		%	3.5		%	3.5		%	3.5		%	3.5		%	3.5		%
Variable rate debt:
Credit facility:
Principal amount (2)	$	—		$	—		$	160,000		$	—		$	—		$	—		$	160,000
Weighted-average interest rate	—			—			1.9		%	—			—			—			1.9		%

(1)Amounts represent scheduled maturities and do not reflect any discount or premium at which the notes were issued or any debt issuance costs.

(2)On January 5, 2021, we redeemed $400 million principal amount of our outstanding 2022 Notes using proceeds from borrowings on our credit facility. Such activity is not reflected in the table above.

In thousands 2018 2019 2020 2021 2022 Thereafter Total
Fixed rate debt:

Senior Notes:

Principal amount (1) $ —
$ —
$ —
$ —
$ 2,000,000
$ 4,200,000
$ 6,200,000
Weighted-average interest rate —
—
—
—
5.0 % 4.4 % 4.6 %
Note payable:

Principal amount $ 2,286
$ 2,360
$ 2,435
$ 2,515
$ 425
$ —
$ 10,021
Interest rate 3.1 % 3.1 % 3.1 % 3.1 % 3.1 % —
3.1 %
Variable rate debt:

Revolving credit facility:

Principal amount $ —
$ 188,000
$ —
$ —
$ —
$ —
$ 188,000
Weighted-average interest rate —
3.2 % —
—
—
—
3.2 %


~~(1)~~	~~Amounts do not reflect any discount or premium at which the senior notes were issued.~~


~~Item 8.~~	Item 8. Financial Statements and Supplementary Data

Index to Consolidated Financial Statements



Report of Independent Registered Public Accounting Firm			7662
Consolidated Balance Sheets as of December 31, ~~2017~~2020 and ~~2016~~2019			7764
Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, ~~2017, 2016~~2020, 2019 and ~~2015~~2018			7865
Consolidated Statements of ~~Shareholders’~~ Equity for the Years Ended December 31, ~~2017, 2016~~2020, 2019 and ~~2015~~2018			7966
Consolidated Statements of Cash Flows for the Years Ended December 31, ~~2017, 2016~~2020, 2019 and ~~2015~~2018			8068
Notes to Consolidated Financial Statements			8169

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Shareholders

Continental Resources, Inc.

Opinion on the financial statements

We have audited the accompanying consolidated balance sheets of Continental Resources, Inc. (an Oklahoma corporation) and subsidiaries (the “Company”) as of December 31, ~~2017~~2020 and ~~2016,~~2019, the related consolidated statements of comprehensive income (loss), ~~shareholders’~~ equity, and cash flows for each of the three years in the period ended December 31, ~~2017,~~2020, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, ~~2017~~2020 and ~~2016,~~2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, ~~2017,~~2020, in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Company’s internal control over financial reporting as of December 31, ~~2017,~~2020, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), and our report dated February ~~21, 2018~~16, 2021 expressed an unqualified opinion.

Basis for opinion

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

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence ~~supporting~~regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical audit matter

The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

•Estimation of proved crude oil and natural gas reserves as it relates to the recognition of depletion expense and of proved and unproved crude oil and natural gas reserves for the assessment / measurement of impairment of proved crude oil and natural gas properties (herein referred to as “the crude oil and natural gas reserves”)

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

of proved crude oil and natural gas reserves as it relates to the recognition of depletion expense and proved and unproved crude oil and natural gas reserves for the assessment / measurement of impairment of crude oil and natural gas properties as a critical audit matter.

The principal considerations for our determination that the estimation of proved crude oil and natural gas reserves as it relates to the recognition of depletion expense and proved and unproved crude oil and natural gas reserves for the assessment / measurement of impairment of crude oil and natural gas properties is a critical audit matter is that relatively minor changes in certain inputs and assumptions, which require a high degree of subjectivity, necessary to estimate the volume and future cash flows of the Company’s crude oil and natural gas reserves could have a significant impact on the measurement of depletion expense or assessment / measurement of impairment expense.

Our audit procedures related to the estimation of proved crude oil and natural gas reserves as it relates to the recognition of depletion expense and proved and unproved crude oil and natural gas reserves for the assessment / measurement of impairment included the following, among others.

•Tested the design and operating effectiveness of controls relating to management’s estimation of proved crude oil and natural gas reserves for the purpose of estimating depletion expense and proved and unproved crude oil and natural gas reserves for assessing / measuring the Company’s proved crude oil and gas properties for impairment.

•Assessed the independence, objectivity, and professional qualifications of the Company’s reservoir engineer specialists, made inquiries of these specialists (internal and external) regarding the process followed and judgments used to make significant estimates, including but not limited to crude oil and natural gas reserve volumes, decline rates, and economically recoverable crude oil and natural gas reserves and reviewed the reserve estimates prepared by the Company’s specialists.

•To the extent key inputs and assumptions used to determine crude oil and natural gas reserve volumes and other cash flow inputs and assumptions are derived from the Company’s accounting records, including, but not limited to: historical pricing differentials, operating costs, estimated capital costs, discount rates, and ownership interests, we tested management’s process for determining the assumptions, including examining underlying support on a sample basis. Specifically, our audit procedures involved testing management’s assumptions by:

◦Compared the estimated pricing differentials used in the reserve report to realized prices related to revenue transactions recorded in the current year and examined contractual support for the pricing differentials

◦Evaluated the models used to estimate the operating costs at year-end and compared to historical operating costs

◦Compared the estimates of future capital expenditures in the reserve reports to management’s forecasts and amounts expended for recently drilled and completed wells

◦Evaluated the working and net revenue interests used in the reserve report by inspecting land and division order records

◦Evaluated the Company’s evidence supporting the amount of proved undeveloped properties reflected in the reserve report by examining historical conversion rates and support for the Company’s ability to fund and intent to develop the proved undeveloped properties

◦Applied analytical procedures to the reserve report by comparing to historical actual results and to the prior year reserve report

◦Evaluated the reasonableness of the Company’s classification of reserves as proved or unproved; and

◦Evaluated the reasonableness of risk-adjustment factors applied to unproved crude oil and natural gas reserves that were taken into consideration to determine estimated future net cash flows used to evaluate proved property impairment.

/s/ GRANT THORNTON LLP

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

Oklahoma City, Oklahoma

February ~~21, 2018~~16, 2021

Continental Resources, Inc. and Subsidiaries

Consolidated Balance Sheets

December 31,
In thousands, except par values and share data 2017 2016
Assets
Current assets:
Cash and cash equivalents $ 43,902
$ 16,643
Receivables:
Crude oil and natural gas sales 671,665
404,750
Affiliated parties 63
99
Joint interest and other, net 426,585
364,850
Derivative assets 2,603
4,061
Inventories 97,406
111,987
Prepaid expenses and other 9,501
10,843
Total current assets 1,251,725
913,233
Net property and equipment, based on successful efforts method of accounting 12,933,789
12,881,227
Other noncurrent assets 14,137
17,316
Total assets $ 14,199,651
$ 13,811,776

Liabilities and shareholders’ equity
Current liabilities:
Accounts payable trade $ 692,908
$ 476,342
Revenues and royalties payable 374,831
217,425
Payables to affiliated parties 143
148
Accrued liabilities and other 260,074
176,770
Derivative liabilities —
59,489
Current portion of long-term debt 2,286
2,219
Total current liabilities 1,330,242
932,393
Long-term debt, net of current portion 6,351,405
6,577,697
Other noncurrent liabilities:
Deferred income tax liabilities, net 1,259,558
1,890,305
Asset retirement obligations, net of current portion 111,794
94,436
Other noncurrent liabilities 15,449
14,949
Total other noncurrent liabilities 1,386,801
1,999,690
Commitments and contingencies (Note 10)

Shareholders’ equity:
Preferred stock, $0.01 par value; 25,000,000 shares authorized; no shares issued and outstanding —
—
Common stock, $0.01 par value; 1,000,000,000 shares authorized;
375,219,769 shares issued and outstanding at December 31, 2017;
374,492,357 shares issued and outstanding at December 31, 2016 3,752
3,745
Additional paid-in capital 1,409,326
1,375,290
Accumulated other comprehensive income (loss) 307
(260 )
Retained earnings 3,717,818
2,923,221
Total shareholders’ equity 5,131,203
4,301,996
Total liabilities and shareholders’ equity $ 14,199,651
$ 13,811,776


	December 31,
In thousands, except par values and share data	2020		2019
Assets
Current assets:
Cash and cash equivalents	$	47,470	$	39,400
Receivables:
Crude oil and natural gas sales	561,127		726,876
Joint interest and other	143,829		317,018
Allowance for credit losses	(2,462)		(2,407)
Receivables, net	702,494		1,041,487
Derivative assets	15,303		0
Inventories	72,157		109,536
Prepaid expenses and other	15,121		16,592
Total current assets	852,545		1,207,015
Net property and equipment, based on successful efforts method of accounting	13,737,292		14,497,726
Operating lease right-of-use assets	8,557		9,128
Other noncurrent assets	34,704		14,038
Total assets	$	14,633,098	$	15,727,907

Liabilities and equity
Current liabilities:
Accounts payable trade	$	361,704	$	629,264
Revenues and royalties payable	327,029		470,264
Accrued liabilities and other	167,013		230,368
Derivative liabilities	227		0
Current portion of operating lease liabilities	2,588		3,695
Current portion of long-term debt	2,245		2,435
Total current liabilities	860,806		1,336,026
Long-term debt, net of current portion	5,530,173		5,324,079
Other noncurrent liabilities:
Deferred income tax liabilities, net	1,620,154		1,787,125
Asset retirement obligations, net of current portion	177,194		151,774
Derivative liabilities, noncurrent	1,584		0
Operating lease liabilities, net of current portion	5,839		5,433
Other noncurrent liabilities	14,623		15,119
Total other noncurrent liabilities	1,819,394		1,959,451
Commitments and contingencies (Note 12)	0		0
Equity:
Preferred stock, $0.01 par value; 25,000,000 shares authorized; no shares issued and outstanding	0		0
Common stock, $0.01 par value; 1,000,000,000 shares authorized;
365,220,435 shares issued and outstanding at December 31, 2020;
371,074,036 shares issued and outstanding at December 31, 2019;	3,652		3,711
Additional paid-in capital	1,205,148		1,274,732

Retained earnings	4,847,646		5,463,224
Total shareholders’ equity attributable to Continental Resources	6,056,446		6,741,667
Noncontrolling interests	366,279		366,684
Total equity	6,422,725		7,108,351
Total liabilities and equity	$	14,633,098	$	15,727,907

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

Continental Resources, Inc. and Subsidiaries

Consolidated Statements of Comprehensive Income (Loss)


	Year Ended December 31,
In thousands, except per share data	2020		2019		2018
Revenues:
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:
Production expenses	359,267		444,649		390,423
Production taxes	192,718		357,988		353,140
Transportation expenses	196,692		225,649		191,587
Exploration expenses	17,732		14,667		7,642
Crude oil and natural gas service operations	18,294		33,230		21,639
Depreciation, depletion, amortization and accretion	1,880,959		2,017,383		1,859,327
Property impairments	277,941		86,202		125,210
General and administrative expenses	196,572		195,302		183,569

Net (gain) loss on sale of assets and other	187		(535)		(16,671)
Total operating costs and expenses	3,140,362		3,374,535		3,115,866
Income (loss) from operations	(553,892)		1,257,412		1,593,720
Other income (expense):
Interest expense	(258,240)		(269,379)		(293,032)
Gain (loss) on extinguishment of debt	35,719		(4,584)		(7,133)
Other	1,662		3,713		3,247
	(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

Net income (loss) per share attributable to Continental Resources:
Basic	$	(1.65)	$	2.09	$	2.66
Diluted	$	(1.65)	$	2.08	$	2.64

Comprehensive income (loss):
Net income (loss)	$	(605,561)	$	774,473	$	989,700
Other comprehensive income (loss), net of tax:
Foreign currency translation adjustments	0		140		108
Release of cumulative translation adjustments	0		(555)		0
Total other comprehensive income (loss), net of tax	0		(415)		108
Comprehensive income (loss)	(605,561)		774,058		989,808
Comprehensive income (loss) attributable to noncontrolling interests	(8,692)		(1,168)		1,383
Comprehensive income (loss) attributable to Continental Resources	$	(596,869)	$	775,226	$	988,425

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

Year Ended December 31,
In thousands, except per share data 2017 2016 2015
Revenues:
Crude oil and natural gas sales $ 2,982,966
$ 2,026,958
$ 2,551,131
Crude oil and natural gas sales to affiliates —
—
1,400
Gain (loss) on crude oil and natural gas derivatives, net 91,647
(71,859 ) 91,085
Crude oil and natural gas service operations 46,215
25,174
36,551
Total revenues 3,120,828
1,980,273
2,680,167

Operating costs and expenses:
Production expenses 324,214
289,289
347,243
Production expenses to affiliates —
—
1,654
Production taxes 208,278
142,388
200,637
Exploration expenses 12,393
16,972
19,413
Crude oil and natural gas service operations 16,880
11,386
17,337
Depreciation, depletion, amortization and accretion 1,674,901
1,708,744
1,749,056
Property impairments 237,370
237,292
402,131
General and administrative expenses 191,706
169,580
189,846
Litigation settlement 59,600
—
—
Net gain on sale of assets and other (53,915 ) (307,844 ) (23,149 )
Total operating costs and expenses 2,671,427
2,267,807
2,904,168
Income (loss) from operations 449,401
(287,534 ) (224,001 )
Other income (expense):
Interest expense (294,495 ) (320,562 ) (313,079 )
Loss on extinguishment of debt (554 ) (26,055 ) —
Other 1,715
1,697
1,995
(293,334 ) (344,920 ) (311,084 )
Income (loss) before income taxes 156,067
(632,454 ) (535,085 )
Benefit for income taxes 633,380
232,775
181,417
Net income (loss) $ 789,447
$ (399,679 ) $ (353,668 )
Basic net income (loss) per share $ 2.13
$ (1.08 ) $ (0.96 )
Diluted net income (loss) per share $ 2.11
$ (1.08 ) $ (0.96 )

Comprehensive income (loss):
Net income (loss) $ 789,447
$ (399,679 ) $ (353,668 )
Other comprehensive income (loss), net of tax:
Foreign currency translation adjustments 567
3,094
(2,969 )
Total other comprehensive income (loss), net of tax 567
3,094
(2,969 )
Comprehensive income (loss) $ 790,014
$ (396,585 ) $ (356,637 )

Continental Resources, Inc. and Subsidiaries

Consolidated Statements of ~~Shareholders’~~ Equity


	Shareholders’ equity attributable to Continental Resources
In thousands, except share data	Shares outstanding	Common stock		Additional paid-in capital		Accumulated other comprehensive income		Treasury stock		Retained earnings		Total shareholders’ equity of Continental Resources		Noncontrolling interests		Total equity
Balance at December 31, 2017	375,219,769	$	3,752	$	1,409,326	$	307	$	—	$	3,717,818	$	5,131,203	$	0	$	5,131,203
Net Income	—	—		—		—		—		988,317		988,317		1,383		989,700
Other comprehensive income, net of tax	—	—		—		108		—		—		108		—		108
Equity transaction costs (see Note 16)	—	—		(4,838)		—		—		—		(4,838)		—		(4,838)
Stock-based compensation	—	—		47,223		—		—		—		47,223		—		47,223
Restricted stock:
Granted	1,390,914	14		0		—		—		—		14		—		14
Repurchased and canceled	(310,822)	(3)		(16,888)		—		—		—		(16,891)		—		(16,891)
Forfeited	(278,286)	(3)		—		—		—		—		(3)		—		(3)
Contributions from noncontrolling interests	—	—		—		—		—		—		—		277,238		277,238
Distributions to noncontrolling interests	—	—		—		—		—		—		—		(1,893)		(1,893)
Balance at December 31, 2018	376,021,575	$	3,760	$	1,434,823	$	415	$	—	$	4,706,135	$	6,145,133	$	276,728	$	6,421,861
Net income (loss)	—	—		—		—		—		775,641		775,641		(1,168)		774,473
Cash dividends declared ($0.05 per share)	—	—		—		—		—		(18,747)		(18,747)		—		(18,747)
Change in dividends payable	—	—		—		—		—		195		195		—		195
Common stock repurchased	—	—		—		—		(190,239)		—		(190,239)		—		(190,239)
Common stock retired	(5,646,553)	(56)		(190,183)		—		190,239		—		—		—		—
Other comprehensive loss, net of tax	—	—		—		(415)		—		—		(415)		—		(415)
Stock-based compensation	—	—		52,030		—		—		—		52,030		—		52,030
Restricted stock:
Granted	1,526,825	15		0		—		—		—		15		—		15
Repurchased and canceled	(477,789)	(5)		(21,938)		—		—				(21,943)		—		(21,943)
Forfeited	(350,022)	(3)		—		—		—		—		(3)		—		(3)
Contributions from noncontrolling interests	—	—		—		—		—		—		—		105,528		105,528
Distributions to noncontrolling interests	—	—		—		—		—		—		—		(14,404)		(14,404)
Balance at December 31, 2019	371,074,036	$	3,711	$	1,274,732	$	0	$	—	$	5,463,224	$	6,741,667	$	366,684	$	7,108,351
Net income (loss)	—	—		—		—		—		(596,869)		(596,869)		(8,692)		(605,561)
Cumulative effect adjustment from adoption of ASU 2016-13 (see Note 9)	—	—		—		—		—		(137)		(137)		—		(137)
Cash dividends declared ($0.05 per share)	—	—		—		—		—		(18,580)		(18,580)		—		(18,580)
Change in dividends payable	—	—		—		—		—		8		8		—		8
Common stock repurchased	—	—		—		—		(126,906)		—		(126,906)		—		(126,906)
Common stock retired	(8,122,104)	(81)		(126,825)		—		126,906		—		—		—		—
Stock-based compensation	—	—		64,585		—		—		—		64,585		—		64,585
Restricted stock:
Granted	2,738,625	27		0		—		—		—		27		—		27

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

Continental Resources, Inc. and Subsidiaries

Consolidated Statements of Equity

In thousands, except share data
Shares
outstanding

Common
stock

Additional
paid-in
capital

Accumulated
other
comprehensive
income (loss)

Retained
earnings

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


Repurchased and canceled	(306,845)	(3)		(7,344)		—		—				(7,347)		—		(7,347)
Forfeited	(163,277)	(2)		—		—		—		—		(2)		—		(2)
Contributions from noncontrolling interests	—	—		—		—		—		—		—		21,557		21,557
Distributions to noncontrolling interests	—	—		—		—		—		—		—		(13,270)		(13,270)
Balance at December 31, 2020	365,220,435	$	3,652	$	1,205,148	$	0	$	—	$	4,847,646	$	6,056,446	$	366,279	$	6,422,725

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

Continental Resources, Inc. and Subsidiaries

Consolidated Statements of Cash Flows


	Year Ended December 31,
In thousands	2020		2019		2018
Cash flows from operating activities:
Net income (loss)	$	(605,561)	$	774,473	$	989,700
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depreciation, depletion, amortization and accretion	1,882,458		2,019,704		1,859,118
Property impairments	277,941		86,202		125,210
Non-cash (gain) loss on derivatives, net	(13,492)		15,612		(13,009)
Stock-based compensation	64,613		52,044		47,236
Provision (benefit) for deferred income taxes	(166,971)		212,689		314,878
Net (gain) loss on sale of assets and other	187		(535)		(16,671)
(Gain) loss on extinguishment of debt	(35,719)		4,584		7,133
Other, net	16,970		10,408		16,705
Changes in assets and liabilities:
Accounts receivable	332,128		(33,619)		94,765
Inventories	12,859		(21,204)		7,735
Other current assets	1,471		(4,459)		(3,539)
Accounts payable trade	(133,977)		(36,359)		9,274
Revenues and royalties payable	(143,260)		69,195		24,010
Accrued liabilities and other	(66,071)		(36,467)		(4,162)
Other noncurrent assets and liabilities	(1,272)		3,420		(2,375)
Net cash provided by operating activities	1,422,304		3,115,688		3,456,008

Cash flows from investing activities:
Exploration and development	(1,408,149)		(2,783,149)		(2,840,880)
Purchase of producing crude oil and natural gas properties	(81,994)		(51,558)		(31,579)
Purchase of other property and equipment	(23,994)		(25,983)		(42,171)
Proceeds from sale of assets	2,779		88,734		54,458
Net cash used in investing activities	(1,511,358)		(2,771,956)		(2,860,172)

Cash flows from financing activities:
Credit facility borrowings	2,052,000		1,216,000		2,024,000
Repayment of credit facility	(1,947,000)		(1,161,000)		(2,212,000)
Proceeds from issuance of Senior Notes	1,485,000		0		0
Redemption and repurchase of Senior Notes	(1,343,250)		(500,000)		(400,000)
Premium and costs on redemption of Senior Notes	(25,173)		(4,167)		(6,700)
Proceeds from other debt	26,000		0		0
Repayment of other debt	(6,679)		(2,352)		(2,286)
Debt issuance costs	(4,368)		0		(5,535)
Equity transaction costs	0		0		(4,838)
Contributions from noncontrolling interests	27,116		109,137		267,920
Distributions to noncontrolling interests	(13,809)		(14,164)		(604)
Repurchase of common stock	(126,906)		(190,239)		0
Repurchase of restricted stock for tax withholdings	(7,347)		(21,943)		(16,891)
Dividends paid on common stock	(18,460)		(18,380)		0
Net cash provided by (used in) financing activities	97,124		(587,108)		(356,934)
Effect of exchange rate changes on cash	0		27		(55)
Net change in cash and cash equivalents	8,070		(243,349)		238,847
Cash and cash equivalents at beginning of period	39,400		282,749		43,902
Cash and cash equivalents at end of period	$	47,470	$	39,400	$	282,749

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

Year Ended December 31,
In thousands 2017 2016 2015
Cash flows from operating activities:
Net income (loss) $ 789,447
$ (399,679 ) $ (353,668 )
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depreciation, depletion, amortization and accretion 1,670,838
1,709,567
1,746,454
Property impairments 237,370
237,292
402,131
Non-cash (gain) loss on derivatives, net (58,031 ) 156,621
(21,532 )
Stock-based compensation 45,868
48,098
51,834
Tax benefit from US tax reform legislation (713,655 ) —
—
Provision (benefit) for deferred income taxes from operations 88,056
(209,836 ) (181,441 )
Tax deficiency (benefit) from stock-based compensation —
9,828
(13,177 )
Dry hole costs 176
4,866
8,381
Litigation settlement 59,600
—
—
Gain on sale of assets, net (55,124 ) (304,489 ) (23,149 )
Loss on extinguishment of debt 554
26,055
—
Other, net 12,592
9,812
12,646
Changes in assets and liabilities:
Accounts receivable (329,811 ) (158,383 ) 524,973
Inventories 14,517
(17,836 ) 7,997
Other current assets 1,038
968
65,493
Accounts payable trade 137,339
(14,404 ) (201,434 )
Revenues and royalties payable 158,982
30,455
(85,754 )
Accrued liabilities and other 21,368
(883 ) (84,056 )
Other noncurrent assets and liabilities (2,018 ) (2,133 ) 1,403
Net cash provided by operating activities 2,079,106
1,125,919
1,857,101

Cash flows from investing activities:
Exploration and development (1,931,942 ) (1,154,131 ) (3,042,747 )
Purchase of producing crude oil and natural gas properties (8,446 ) (5,008 ) (557 )
Purchase of other property and equipment (12,810 ) (5,375 ) (36,951 )
Proceeds from sale of assets 144,353
631,549
34,008
Net cash used in investing activities (1,808,845 ) (532,965 ) (3,046,247 )

Cash flows from financing activities:
Credit facility borrowings 1,302,000
1,691,000
2,001,000
Repayment of credit facility (2,019,000 ) (1,639,000 ) (1,313,000 )
Proceeds from issuance of Senior Notes 990,000
—
—
Redemption of Senior Notes —
(600,000 ) —
Premium on redemption of Senior Notes —
(19,168 ) —
Proceeds from other debt —
—
500,000
Repayment of other debt (502,214 ) (2,144 ) (2,078 )
Debt issuance costs (1,999 ) (40 ) (4,597 )
Repurchase of restricted stock for tax withholdings (11,821 ) (8,593 ) (7,313 )
Tax (deficiency) benefit from stock-based compensation —
(9,828 ) 13,177
Net cash (used in) provided by financing activities (243,034 ) (587,773 ) 1,187,189
Effect of exchange rate changes on cash 32
(1 ) (10,961 )
Net change in cash and cash equivalents 27,259
5,180
(12,918 )
Cash and cash equivalents at beginning of period 16,643
11,463
24,381
Cash and cash equivalents at end of period $ 43,902
$ 16,643
$ 11,463

Continental Resources, Inc. and Subsidiaries

Notes to Consolidated Financial Statements



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		1210
		Drilling Activity		1311
		Summary of Crude Oil and Natural Gas Properties and Projects		1311
		Production and Price History		1614
		Productive Wells		1715
		Title to Properties		1716
		Marketing ~~and Major Customers~~		1816
		Competition		1816
		Regulation of the Crude Oil and Natural Gas Industry		1917
		~~Employees~~Human Capital		2823
		Company Contact Information		2824
Item 1A.		Risk Factors		3025
Item 1B.		Unresolved Staff Comments		4638
Item 2.		Properties		4638
Item 3.		Legal Proceedings		4638
Item 4.		Mine Safety Disclosures		4638

PART II
Item 5.		Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		4739
Item 6.		Selected Financial Data		4941
Item 7.		Management’s Discussion and Analysis of Financial Condition and Results of Operations		5142
Item 7A.		Quantitative and Qualitative Disclosures About Market Risk		7359
Item 8.		Financial Statements and Supplementary Data		7561
Item 9.		Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		~~108~~100
Item 9A.		Controls and Procedures		~~108~~100
Item 9B.		Other Information		~~111~~103

PART III
Item 10.		Directors, Executive Officers and Corporate Governance		~~111~~103
Item 11.		Executive Compensation		~~111~~103
Item 12.		Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		~~111~~103
Item 13.		Certain Relationships and Related Transactions, and Director Independence		~~111~~103
Item 14.		Principal Accountant Fees and Services		~~111~~103

PART IV
Item 15.		Exhibits and Financial Statement Schedules		~~112~~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	951,645	556,044	147,513	90,288	1,099,158	646,332
Montana Bakken	170,899	137,594	30,059	17,601	200,958	155,195
Red River units	158,967	139,418	26,719	13,124	185,686	152,542
Other	102,542	66,399	94,454	68,597	196,996	134,996
South Region:
SCOOP	230,799	133,756	260,257	143,116	491,056	276,872
STACK	211,836	118,563	177,563	93,846	389,399	212,409
Other	67,734	32,928	71,250	33,067	138,984	65,995
East Region	449	404	161,935	138,799	162,384	139,203
Total	1,894,871	1,185,106	969,750	598,438	2,864,621	1,783,544


	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



	DUC Wells
	Gross		Net		PUD Reserves (MBoe)
DUC wells at December 31, 2016	279		145		95,272
Wells converted to proved developed reserves	(203	)	(110	)	(75,274	)
Wells added	209		72		51,306
Revisions	(7	)	(2	)	(1,707	)
DUC wells at December 31, 2017	278		105		69,597


	2017		2016		2015			2020		2019		2018
	Gross	Net	Gross	Net	Gross	Net		Gross	Net	Gross	Net	Gross	Net
Exploratory wells:							Exploratory wells:
Crude oil	34	9.0	39	11.4	28	19.8	Crude oil	1	—	2	1.6	4	1.0
Natural gas	9	3.1	15	4.2	19	1.4	Natural gas	1	—	4	1.8	9	4.6
Dry holes	—	—	—	—	1	1.0	Dry holes	1	0.9	—	—	—	—
Total exploratory wells	43	12.1	54	15.6	48	22.2	Total exploratory wells	3	0.9	6	3.4	13	5.6
Development wells:							Development wells:
Crude oil	474	175.4	245	54.7	707	215.5	Crude oil	300	115.5	615	222.9	636	213.7
Natural gas	91	26.8	66	21.6	142	32.8	Natural gas	31	15.9	68	9.7	151	39.1
Dry holes	—	—	—	—	—	—	Dry holes	—	—	—	—	—	—
Total development wells	565	202.2	311	76.3	849	248.3	Total development wells	331	131.4	683	232.6	787	252.8
Total wells	608	214.3	365	91.9	897	270.5	Total wells	334	132.3	689	236.0	800	258.4



	2018 Plan
	Gross wells (1)	Net wells (1)	Capital expenditures (in millions) (2)
	Gross wells (1)	Net wells (1)	Capital expenditures (in millions) (2)
North Region:
Bakken	415	143	$	1,193
South Region:
SCOOP	160	44	465
STACK and Other	181	38	330
Total exploration and development drilling	756	225	$	1,988
Land			132
Capital facilities, workovers and other corporate assets			168
Seismic			12
Total 2018 capital budget, excluding acquisitions			$	2,300


	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



	Fourth Quarter 2017 Daily Production
	Crude Oil (Bbls per day)	Natural Gas (Mcf per day)	Total (Boe per day)
North Region:
Bakken field
North Dakota Bakken	124,811	202,975	158,640
Montana Bakken	5,497	8,761	6,958
Red River units
Cedar Hills	6,830	1,154	7,022
Other Red River units	2,073	2,410	2,475
Other	82	2,318	468
South Region:
SCOOP	14,551	286,148	62,242
STACK	13,788	204,754	47,914
Other	434	4,998	1,266
Total	168,066	713,518	286,985



	2017								2016
	Quarter Ended								Quarter Ended
	March 31		June 30		September 30		December 31		March 31		June 30		September 30		December 31
High	$	53.57	$	47.87	$	40.03	$	53.55	$	31.90	$	46.01	$	52.78	$	60.30
Low	$	41.28	$	30.18	$	29.08	$	36.05	$	13.94	$	28.63	$	40.92	$	44.37
Cash Dividend	—		—		—		—		—		—		—		—



Period	Total number of shares purchased (1)	Average price paid per share (2)		Total number of shares purchased as part of publicly announced plans or programs	Maximum number of shares that may yet be purchased under the plans or programs
October 1, 2017 to October 31, 2017	234	$	38.24	—	—
November 1, 2017 to November 30, 2017	18,435	$	44.84	—	—
December 1, 2017 to December 31, 2017	—	—		—	—
Total	18,669	$	44.76	—	—



	December 31, 2017			December 31, 2016			Volume change		Volume percent change
Proved reserves by area	MBoe	Percent		MBoe	Percent		Volume change		Volume percent change
Bakken	635,521	48	%	591,901	46	%	43,620		7	%
SCOOP	491,776	37	%	471,921	37	%	19,855		4	%
STACK	167,390	13	%	161,243	13	%	6,147		4	%
All Other	36,308	2	%	49,799	4	%	(13,491	)	(27	%)
Total	1,330,995	100	%	1,274,864	100	%	56,131		4	%



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


	Year ended December 31,					Year ended December 31,
$/Boe	2017		2016		$/Boe	2020		2019
Crude oil and natural gas properties	$	18.57	$	21.09	Crude oil and natural gas properties	$	16.84	$	16.03
Other equipment	0.25		0.37		Other equipment	0.19		0.15
Asset retirement obligation accretion	0.07		0.08		Asset retirement obligation accretion	0.09		0.07
Depreciation, depletion, amortization and accretion	$	18.89	$	21.54	Depreciation, depletion, amortization and accretion	$	17.12	$	16.25



	Year Ended December 31,						Volume increase (decrease)		Volume percent increase (decrease)
	2016			2015
	Volume	Percent		Volume	Percent
Crude oil (MBbl)	46,850	59	%	53,517	66	%	(6,667	)	(12	%)
Natural Gas (MMcf)	195,240	41	%	164,454	34	%	30,786		19	%
Total (MBoe)	79,390	100	%	80,926	100	%	(1,536	)	(2	%)



	Year Ended December 31,						Volume increase (decrease)		Volume percent increase (decrease)
	2016			2015
	MBoe	Percent		MBoe	Percent
North Region	48,169	61	%	54,956	68	%	(6,787	)	(12	%)
South Region	31,221	39	%	25,970	32	%	5,251		20	%
Total	79,390	100	%	80,926	100	%	(1,536	)	(2	%)


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 2017		2Q 2017		3Q 2017		4Q 2017		Total 2017
Exploration and development drilling	$	329.8	$	471.0	$	444.7	$	442.2	$	1,687.7
Land costs	68.8		49.8		47.7		23.0		189.3
Capital facilities, workovers and other corporate assets	27.4		29.3		28.2		30.5		115.4
Seismic	1.0		1.8		—		—		2.8
Capital expenditures, excluding acquisitions	$	427.0	$	551.9	$	520.6	$	495.7	$	1,995.2
Acquisitions of producing properties	0.1		0.7		2.7		4.9		8.4
Acquisitions of non-producing properties	13.3		5.1		6.8		6.4		31.6
Total acquisitions	13.4		5.8		9.5		11.3		40.0
Total capital expenditures	$	440.4	$	557.7	$	530.1	$	507.0	$	2,035.2


In millions	2021 Budget
Exploration and development	$	1,112
Land costs	85
Mineral acquisitions attributable to Continental (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



In millions	Amount
Exploration and development drilling	$	1,988
Land costs	132
Capital facilities, workovers and other corporate assets	168
Seismic	12
Total 2018 capital budget, excluding acquisitions	$	2,300



Service property and equipment			Useful Lives In Years
Automobiles and aircraft			5-10
Machinery and equipment			6-10
Gathering and recycling systems			15-30
Storage tanks			10-30
Office and computer equipment, software, furniture and fixtures			3-25
Buildings and improvements			4-40


~~(1)~~	~~Revisions primarily represent changes in the present value of liabilities resulting from changes in estimated costs and economic lives of producing properties.~~


~~(2)~~	~~Balance is included in the caption “Accrued liabilities and other” in the consolidated balance sheets.~~


~~(2)~~	For the years ended December 31, 2016 and 2015, the Company had a net loss and therefore the potential dilutive effect of approximately 2,303,000 and 1,567,000 weighted average non-vested restricted shares, respectively, were not included in the calculation of diluted net loss per share because to do so would have been anti-dilutive to the computations.



	Fair value measurements at December 31, 2017 using:
In thousands	Level 1		Level 2		Level 3		Total
Derivative assets:
Swaps	$	—	$	2,603	$	—	$	2,603
Total	$	—	$	2,603	$	—	$	2,603



~~Unobservable Input~~		~~Assumption~~
~~Future production~~		~~Future production estimates for each property~~
~~Forward commodity prices~~		~~Forward NYMEX strip prices through 2022 (adjusted for differentials), escalating 3% per year thereafter~~
~~Operating costs~~		~~Estimated costs for the current year, escalating 3% per year thereafter~~
~~Productive life of field~~		~~Ranging from 1 to 38 years~~
~~Discount rate~~		~~10%~~


	December 31, 2020				December 31, 2019
In thousands	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Debt:
Credit facility	$	160,000	$	160,000	$	55,000	$	55,000
Notes payable	24,590		24,700		5,351		5,400
5% Senior Notes due 2022	630,470		632,900		1,099,165		1,108,700
4.5% Senior Notes due 2023	646,943		669,900		1,491,339		1,571,400
3.8% Senior Notes due 2024	906,922		939,500		994,310		1,034,200
4.375% Senior Notes due 2028	990,746		1,024,400		989,661		1,063,700
5.75% Senior Notes due 2031	1,480,879		1,651,900		0		0
4.9% Senior Notes due 2044	691,868		689,600		691,688		742,000
Total debt	$	5,532,418	$	5,792,900	$	5,326,514	$	5,580,400


~~(1)~~	The Company has the option to redeem all or a portion of its 2022 Notes at the decreasing redemption prices specified in the indenture related to the 2022 Notes plus any accrued and unpaid interest to the date of redemption.


	Year ended December 31,
In thousands, except tax rates	2020			2019			2018

Income (loss) before income taxes	$	(774,751)		$	987,162		$	1,296,802
U.S. federal statutory tax rate	21.0		%	21.0		%	21.0		%
Expected income tax provision (benefit) based on U.S. federal statutory tax rate	(162,698)			207,304			272,328
Items impacting the effective tax rate:
State and local income taxes, net of federal benefit	(24,808)			31,967			45,920
Tax (benefit) deficiency from stock-based compensation	4,927			(7,971)			(259)
Sale of Canadian subsidiary and assets	0			(16,860)			0
Other, net	(1,085)			(1,751)			(10,887)
Valuation allowance	14,474			0			0
Provision (benefit) for income taxes	$	(169,190)		$	212,689		$	307,102
Effective tax rate	21.8		%	21.5		%	23.7		%


~~(1)~~	~~The Company recognized $3.9 million of tax deficiencies from stock-based compensation as income tax expense for the year ended December 31, 2017 in accordance with ASU 2016-09 as discussed in~~ ~~Note 1. Organization and Summary of Significant Accounting Policies–Adoption of new accounting pronouncements~~.


~~(2)~~	Represents valuation allowances recognized against all deferred tax assets associated with operating loss carryforwards generated by the Company's Canadian operations during the respective periods for which the Company does not expect to realize a benefit.


In thousands	Amount
Drilling rig commitments	$	2,025
Surface use agreements	4,928
Field equipment	928
Other	546
Total	$	8,427


	Year ended December 31,
In thousands, except weighted average data	2020			2019
Lease costs:
Operating lease costs	$	6,444		$	11,130
Variable lease costs	4,956			11,930
Short-term lease costs	107,984			176,586
Total lease costs	$	119,384		$	199,646

Other information:
Right-of-use assets obtained in exchange for new operating lease liabilities	$	7,377		$	1,208
Operating cash flows from operating leases included in lease liabilities	890			804
Weighted average remaining lease term as of December 31 (in years)	13.2			11.5
Weighted average discount rate as of December 31	4.8		%	4.9		%