SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549



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

(Exact name of registrant as specified in its charter)

(~~405~~) (405) 234-9000

(Registrant’s telephone number, including area code)

(Former name, former address and former fiscal year, if changed since last report)

Securities registered pursuant to Section 12(b) of the Act:



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

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

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

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

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No x

~~365,152,819~~367,534,598 shares of our $0.01 par value common stock were outstanding on April ~~30, 2020~~21, 2021.

Table of Contents




PART I. Financial Information
Item 1.	Financial Statements	1
	Condensed Consolidated Balance Sheets	1
	Unaudited Condensed Consolidated Statements of ~~Comprehensive Income (Loss)~~Operations	2
	Unaudited Condensed Consolidated Statements of Equity	3
	Unaudited Condensed Consolidated Statements of Cash Flows	4
	Notes to Unaudited Condensed Consolidated Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	2019
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	3129
Item 4.	Controls and Procedures	3230

PART II. Other Information
Item 1.	Legal Proceedings	3331
Item 1A.	Risk Factors	3331
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	3532
Item 3.	Defaults Upon Senior Securities	3532
Item 4.	Mine Safety Disclosures	3532
Item 5.	Other Information	3532
Item 6.	Exhibits	3533
	Signature	3734

When we refer to “us,” “we,” “our,” “Company,” or “Continental” we are describing Continental Resources, Inc. and our subsidiaries.

Glossary of Crude Oil and Natural Gas Terms

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

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

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

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

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

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

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

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

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

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

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

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

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

“MBoe” One thousand Boe.

“Mcf” One thousand cubic feet of natural gas.

“MMBoe” One million Boe.

“MMBtu” One million British thermal units.

“MMcf” One million cubic feet of natural gas.

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

"Net crude oil and natural gas sales" Represents total crude oil and natural gas sales less total transportation expenses. Net crude oil and natural gas sales presented herein are non-GAAP measures. See Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Financial Measures for a discussion and calculation of this measure.

"Net sales price" Represents the average net wellhead sales price received by the Company for its crude oil or natural gas sales after deducting transportation expenses. ~~Amount~~Net sales price is calculated by taking revenues less transportation expenses divided by sales volumes for a period, whether for crude oil or natural gas, as applicable. Net sales prices presented herein are non-GAAP measures. See Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Financial Measures for a discussion and calculation of this measure.

“NYMEX” The New York Mercantile Exchange.

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

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

“reservoir” A porous and permeable underground formation containing a natural accumulation of producible crude oil and/or natural gas that is confined by impermeable rock or water barriers and is separate from other reservoirs.

“royalty interest” Refers to the ownership of a percentage of the resources or revenues produced from a crude oil or natural gas property. A royalty interest owner does not bear exploration, development, or operating expenses associated with drilling and producing a crude oil or natural gas property.

“SCOOP” Refers to the South Central Oklahoma Oil Province, a term used to describe properties located in the Anadarko basin of Oklahoma in which we operate. Our SCOOP acreage extends across portions of Garvin, Grady, Stephens, Carter, McClain and Love counties of Oklahoma and has the potential to contain hydrocarbons from a variety of conventional and unconventional reservoirs overlying and underlying the Woodford formation.

"STACK" Refers to Sooner Trend Anadarko Canadian Kingfisher, a term used to describe a resource play located in the Anadarko Basin of Oklahoma characterized by stacked geologic formations with major targets in the Meramec, Osage and Woodford formations. A significant portion of our STACK acreage is located in over-pressured portions of Blaine, Dewey and Custer counties of Oklahoma.

“undeveloped acreage” Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of crude oil and/or natural gas.

“unit” The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.

“working interest” The right granted to the lessee of a property to explore for and to produce and own crude oil, natural gas, or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.

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

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

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

•our strategy;

•our business and financial plans;

•our future operations;

•our crude oil and natural gas reserves and related development plans;

•technology;

•future crude oil, natural gas liquids, and natural gas prices and differentials;

•the timing and amount of future production of crude oil and natural gas and flaring activities;

•the amount, nature and timing of capital expenditures;

•estimated revenues, expenses and results of operations;

•drilling and completing of wells;

•shutting in of production and the resumption of production activities;

•competition;

•marketing of crude oil and natural gas;

•transportation of crude oil, natural gas liquids, and natural gas to markets;

•property exploitation, property acquisitions and dispositions, or joint development opportunities;

•costs of exploiting and developing our properties and conducting other operations;

•our financial position, dividend payments, bond repurchases, debt reduction plans, or share repurchases;

•the impact of the COVID-19 (novel coronavirus) pandemic on economic conditions, the demand for crude oil, the Company's operations and the operations of its customers, suppliers, and service providers;

•credit markets;

•our liquidity and access to capital;

•the impact of governmental policies, laws and regulations, as well as regulatory and legal proceedings involving us and of scheduled or potential regulatory or legal changes;

•our future operating and financial results;

•our future commodity or other hedging arrangements; and

•the ability and willingness of current or potential lenders, hedging contract counterparties, customers, and working interest owners to fulfill their obligations to us or to enter into transactions with us in the future on terms that are acceptable to us.

Forward-looking statements are based on the Company’s current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes these assumptions and expectations are reasonable, they are inherently subject to numerous business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control. No assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate or will not change over time. The risks and uncertainties that may affect the operations, performance and results of the business and forward-looking statements include, but are not limited to, those risk factors and other cautionary statements described under Part II, Item 1A. Risk Factors and elsewhere in this report, if any, our Annual Report on Form 10-K for the year ended December 31, ~~2019,~~2020, 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 ~~are,~~have been, and ~~will~~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 or our Annual Report on Form 10-K for the year ended December 31, 2020 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.

~~iii~~

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.

iii

PART I. Financial Information


~~ITEM 1.~~	~~Financial Statements~~

ITEM 1. Financial Statements

Continental Resources, Inc. and Subsidiaries

Condensed Consolidated Balance Sheets


	March 31, 2021		December 31, 2020
In thousands, except par values and share data	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	96,057	$	47,470
Receivables:
Crude oil and natural gas sales	690,619		561,127
Joint interest and other	171,465		143,829
Allowance for credit losses	(2,700)		(2,462)
Receivables, net	859,384		702,494
Derivative assets	11,275		15,303
Inventories	76,008		72,157
Prepaid expenses and other	19,097		15,121
Total current assets	1,061,821		852,545
Net property and equipment, based on successful efforts method of accounting	13,724,418		13,737,292
Operating lease right-of-use assets	22,863		8,557
Other noncurrent assets	11,825		34,704
Total assets	$	14,820,927	$	14,633,098

Liabilities and equity
Current liabilities:
Accounts payable trade	$	509,490	$	361,704
Revenues and royalties payable	501,013		327,029
Accrued liabilities and other	203,675		167,013
Derivative liabilities	10,659		227
Current portion of operating lease liabilities	5,140		2,588
Current portion of long-term debt	2,265		2,245
Total current liabilities	1,232,242		860,806
Long-term debt, net of current portion	4,971,055		5,530,173
Other noncurrent liabilities:
Deferred income tax liabilities, net	1,700,682		1,620,154
Asset retirement obligations, net of current portion	186,014		177,194
Derivative liabilities, noncurrent	1,194		1,584
Operating lease liabilities, net of current portion	17,559		5,839
Other noncurrent liabilities	14,975		14,623
Total other noncurrent liabilities	1,920,424		1,819,394
Commitments and contingencies (Note 8)			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; 367,491,013 shares issued and outstanding at March 31, 2021; 365,220,435 shares issued and outstanding at December 31, 2020	3,675		3,652
Additional paid-in capital	1,213,115		1,205,148
Retained earnings	5,107,288		4,847,646
Total shareholders’ equity attributable to Continental Resources	6,324,078		6,056,446
Noncontrolling interests	373,128		366,279
Total equity	6,697,206		6,422,725
Total liabilities and equity	$	14,820,927	$	14,633,098

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

March 31, 2020 December 31, 2019
In thousands, except par values and share data (Unaudited)
Assets
Current assets:
Cash and cash equivalents $ 517,571
$ 39,400
Receivables:
Crude oil and natural gas sales 389,203
726,876
Joint interest and other 305,519
317,018
Allowance for credit losses (2,694 ) (2,407 )
Receivables, net 692,028
1,041,487
Inventories 62,600
109,536
Prepaid expenses and other 22,973
16,592
Total current assets 1,295,172
1,207,015
Net property and equipment, based on successful efforts method of accounting 14,436,112
14,497,726
Operating lease right-of-use assets 12,684
9,128
Other noncurrent assets 12,743
14,038
Total assets $ 15,756,711
$ 15,727,907

Liabilities and equity
Current liabilities:
Accounts payable trade $ 673,669
$ 629,264
Revenues and royalties payable 239,245
470,264
Accrued liabilities and other 160,596
230,368
Current portion of operating lease liabilities 6,243
3,695
Current portion of long-term debt 2,455
2,435
Total current liabilities 1,082,208
1,336,026
Long-term debt, net of current portion 5,964,589
5,324,079
Other noncurrent liabilities:
Deferred income tax liabilities, net 1,737,112
1,787,125
Asset retirement obligations, net of current portion 156,126
151,774
Operating lease liabilities, net of current portion 6,340
5,433
Other noncurrent liabilities 13,078
15,119
Total other noncurrent liabilities 1,912,656
1,959,451
Commitments and contingencies (Note 10)

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; 365,117,003 shares issued and outstanding at March 31, 2020; 371,074,036 shares issued and outstanding at December 31, 2019 3,651
3,711
Additional paid-in capital 1,157,866
1,274,732
Retained earnings 5,258,845
5,463,224
Total shareholders’ equity attributable to Continental Resources 6,420,362
6,741,667
Noncontrolling interests 376,896
366,684
Total equity 6,797,258
7,108,351
Total liabilities and equity $ 15,756,711
$ 15,727,907

Continental Resources, Inc. and Subsidiaries

Unaudited Condensed Consolidated Statements of ~~Comprehensive Income (Loss)~~Operations


	Three months ended March 31,
In thousands, except per share data	2021		2020
Revenues:
Crude oil and natural gas sales	$	1,247,533	$	862,743
Loss on derivative instruments, net	(43,507)		0
Crude oil and natural gas service operations	11,789		18,058
Total revenues	1,215,815		880,801

Operating costs and expenses:
Production expenses	93,065		118,478
Production taxes	83,976		71,224
Transportation expenses	50,256		60,502
Exploration expenses	4,645		11,637
Crude oil and natural gas service operations	4,490		5,910
Depreciation, depletion, amortization and accretion	509,608		536,696
Property impairments	11,436		222,529
General and administrative expenses	52,848		42,911
Net (gain) loss on sale of assets and other	(207)		4,502
Total operating costs and expenses	810,117		1,074,389
Income (loss) from operations	405,698		(193,588)
Other income (expense):
Interest expense	(64,951)		(63,594)
Gain (loss) on extinguishment of debt	(196)		17,631
Other	252		532
	(64,895)		(45,431)
Income (loss) before income taxes	340,803		(239,019)
(Provision) benefit for income taxes	(80,528)		52,235
Net income (loss)	260,275		(186,784)
Net income (loss) attributable to noncontrolling interests	633		(1,120)
Net income (loss) attributable to Continental Resources	$	259,642	$	(185,664)

Net income (loss) per share attributable to Continental Resources:
Basic	$	0.72	$	(0.51)
Diluted	$	0.72	$	(0.51)

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

Three months ended March 31,
In thousands, except per share data 2020 2019
Revenues:
Crude oil and natural gas sales $ 862,743
$ 1,109,584
Loss on natural gas derivatives, net —
(1,124 )
Crude oil and natural gas service operations 18,058
15,774
Total revenues 880,801
1,124,234

Operating costs and expenses:
Production expenses 118,478
106,966
Production taxes 71,224
86,441
Transportation expenses 60,502
49,139
Exploration expenses 11,637
1,837
Crude oil and natural gas service operations 5,910
7,186
Depreciation, depletion, amortization and accretion 536,696
495,019
Property impairments 222,529
25,316
General and administrative expenses 42,911
47,617
Net (gain) loss on sale of assets and other 4,502
(252 )
Total operating costs and expenses 1,074,389
819,269
Income (loss) from operations (193,588 ) 304,965
Other income (expense):
Interest expense (63,594 ) (67,837 )
Gain on extinguishment of debt 17,631
—
Other 532
1,355

(45,431 ) (66,482 )
Income (loss) before income taxes (239,019 ) 238,483
(Provision) benefit for income taxes 52,235
(51,990 )
Net income (loss) (186,784 ) 186,493
Net loss attributable to noncontrolling interests (1,120 ) (483 )
Net income (loss) attributable to Continental Resources $ (185,664 ) $ 186,976

Net income (loss) per share attributable to Continental Resources:
Basic $ (0.51 ) $ 0.50
Diluted $ (0.51 ) $ 0.50

Comprehensive income (loss):
Net income (loss) $ (186,784 ) $ 186,493
Other comprehensive income, net of tax:
Foreign currency translation adjustments —
116
Total other comprehensive income, net of tax —
116
Comprehensive income (loss) (186,784 ) 186,609
Comprehensive loss attributable to noncontrolling interests (1,120 ) (483 )
Comprehensive income (loss) attributable to Continental Resources $ (185,664 ) $ 187,092

Continental Resources, Inc. and Subsidiaries

Unaudited Condensed Consolidated Statements of Equity


Three months ended March 31, 2021	Shareholders’ equity attributable to Continental Resources
In thousands, except share data	Shares outstanding	Common stock		Additional paid-in capital		Treasury stock		Retained earnings		Total shareholders’ equity of Continental Resources		Noncontrolling interests		Total equity
Balance at December 31, 2020	365,220,435	$	3,652	$	1,205,148	$	—	$	4,847,646	$	6,056,446	$	366,279	$	6,422,725
Net income	—	—		—		—		259,642		259,642		633		260,275

Stock-based compensation	—	—		16,900		—		—		16,900		—		16,900
Restricted stock:
Granted	2,726,442	27		—		—		—		27		—		27
Repurchased and canceled	(390,484)	(3)		(8,933)		—		—		(8,936)		—		(8,936)
Forfeited	(65,380)	(1)		—		—		—		(1)		—		(1)
Contributions from noncontrolling interests	—	—		—		—		—		—		11,463		11,463
Distributions to noncontrolling interests	—	—		—		—		—		—		(5,247)		(5,247)
Balance at March 31, 2021	367,491,013	$	3,675	$	1,213,115	$	—	$	5,107,288	$	6,324,078	$	373,128	$	6,697,206


Three months ended March 31, 2020	Shareholders’ equity attributable to Continental Resources
In thousands, except share data	Shares outstanding	Common stock		Additional paid-in capital		Treasury stock		Retained earnings		Total shareholders’ equity of Continental Resources		Noncontrolling interests		Total equity
Balance at December 31, 2019	371,074,036	$	3,711	$	1,274,732	$	—	$	5,463,224	$	6,741,667	$	366,684	$	7,108,351
Net income (loss)	��	—		—		—		(185,664)		(185,664)		(1,120)		(186,784)
Cumulative effect adjustment from adoption of ASU 2016-13	—	—		—		—		(137)		(137)		—		(137)
Cash dividends declared ($0.05 per share)	—	—		—		—		(18,580)		(18,580)		—		(18,580)
Change in dividends payable	—	—		—		—		2		2		—		2
Common stock repurchased	—	—		—		(126,906)		—		(126,906)		—		(126,906)
Common stock retired	(8,122,104)	(81)		(126,825)		126,906		—		—		—		—
Stock-based compensation	—	—		16,411		—		—		16,411		—		16,411
Restricted stock:
Granted	2,454,235	24		—		—		—		24		—		24
Repurchased and canceled	(246,346)	(2)		(6,452)		—		—		(6,454)		—		(6,454)
Forfeited	(42,818)	(1)		—		—		—		(1)		—		(1)
Contributions from noncontrolling interests	—	—		—		—		—		—		16,950		16,950
Distributions to noncontrolling interests	—	—		—		—		—		—		(5,618)		(5,618)
Balance at March 31, 2020	365,117,003	$	3,651	$	1,157,866	$	—	$	5,258,845	$	6,420,362	$	376,896	$	6,797,258

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

Three months ended March 31, 2020 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, 2019 371,074,036
$ 3,711
$ 1,274,732
$ —
$ —
$ 5,463,224
$ 6,741,667
$ 366,684
$ 7,108,351
Net income (loss) —
—
—
—
—
(185,664 ) (185,664 ) (1,120 ) (186,784 )
Cumulative effect adjustment from adoption of ASU 2016-13 —
—
—
—
—
(137 ) (137 ) —
(137 )
Cash dividends declared ($0.05 per share) —
—
—
—
—
(18,580 ) (18,580 ) —
(18,580 )
Change in dividends payable —
—
—
—
—
2
2
—
2
Common stock repurchased —
—
—
—
(126,906 ) —
(126,906 ) —
(126,906 )
Common stock retired (8,122,104 ) (81 ) (126,825 ) —
126,906
—
—
—
—
Stock-based compensation —
—
16,411
—
—
—
16,411
—
16,411
Restricted stock:
Granted 2,454,235
24
—
—
—
—
24
—
24
Repurchased and canceled (246,346 ) (2 ) (6,452 ) —
—
—
(6,454 ) —
(6,454 )
Forfeited (42,818 ) (1 ) —
—
—
—
(1 ) —
(1 )
Contributions from noncontrolling interests —
—
—
—
—
—
—
16,950
16,950
Distributions to noncontrolling interests —
—
—
—
—
—
—
(5,618 ) (5,618 )
Balance at March 31, 2020 365,117,003
$ 3,651
$ 1,157,866
$ —
$ —
$ 5,258,845
$ 6,420,362
$ 376,896
$ 6,797,258

Three months ended March 30, 2019 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, 2018 376,021,575
$ 3,760
$ 1,434,823
$ 415
$ —
$ 4,706,135
$ 6,145,133
$ 276,728
$ 6,421,861
Net income (loss) —
—
—
—
—
186,976
186,976
(483 ) 186,493
Other comprehensive income, net of tax —
—
—
116
—
—
116
—
116
Stock-based compensation —
—
12,095
—
—
—
12,095
—
12,095
Restricted stock:
Granted 1,333,602
13
—
—
—
—
13
—
13
Repurchased and canceled (439,419 ) (4 ) (20,618 ) —
—
—
(20,622 ) —
(20,622 )
Forfeited (147,074 ) (1 ) —
—
—
—
(1 ) —
(1 )
Contributions from noncontrolling interests —
—
—
—
—
—
—
42,204
42,204
Distributions to noncontrolling interests —
—
—
—
—
—
—
(3,856 ) (3,856 )
Balance at March 31, 2019 376,768,684
$ 3,768
$ 1,426,300
$ 531
$ —
$ 4,893,111
$ 6,323,710
$ 314,593
$ 6,638,303

Continental Resources, Inc. and Subsidiaries

Unaudited Condensed Consolidated Statements of Cash Flows


	Three months ended March 31,
In thousands	2021		2020
Cash flows from operating activities
Net income (loss)	$	260,275	$	(186,784)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion	508,327		536,786
Property impairments	11,436		222,529
Non-cash loss on derivatives	14,070		0
Stock-based compensation	16,927		16,441
Provision (benefit) for deferred income taxes	80,528		(50,012)
Dry hole costs	0		6,259
Net (gain) loss on sale of assets and other	(207)		4,502
(Gain) loss on extinguishment of debt	196		(17,631)
Other, net	2,664		2,911
Changes in assets and liabilities:
Accounts receivable	(156,860)		344,845
Inventories	(3,851)		22,417
Other current assets	(2,336)		(4,848)
Accounts payable trade	98,521		70,084
Revenues and royalties payable	173,648		(231,990)
Accrued liabilities and other	36,149		(70,274)
Other noncurrent assets and liabilities	773		(1,417)
Net cash provided by operating activities	1,040,260		663,818

Cash flows from investing activities
Exploration and development	(258,758)		(673,191)
Purchase of producing crude oil and natural gas properties	(161,764)		(19,258)
Purchase of other property and equipment	(7,660)		(14,923)
Proceeds from sale of assets	98		633
Net cash used in investing activities	(428,084)		(706,739)

Cash flows from financing activities
Credit facility borrowings	685,000		1,130,000
Repayment of credit facility	(845,000)		(450,000)

Redemption of Senior Notes	(400,000)		(22,527)



Repayment of other debt	(552)		(603)

Contributions from noncontrolling interests	10,937		21,254
Distributions to noncontrolling interests	(4,927)		(5,212)
Repurchase of common stock	0		(126,906)
Repurchase of restricted stock for tax withholdings	(8,936)		(6,454)
Dividends paid on common stock	(111)		(18,460)
Net cash provided by (used in) financing activities	(563,589)		521,092
Net change in cash and cash equivalents	48,587		478,171
Cash and cash equivalents at beginning of period	47,470		39,400
Cash and cash equivalents at end of period	$	96,057	$	517,571

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

Three months ended March 31,
In thousands 2020 2019
Cash flows from operating activities
Net income (loss) $ (186,784 ) $ 186,493
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion 536,786
496,561
Property impairments 222,529
25,316
Non-cash loss on derivatives —
14,186
Stock-based compensation 16,441
12,107
Provision (benefit) for deferred income taxes (50,012 ) 51,990
Dry hole costs 6,259
—
Net (gain) loss on sale of assets and other 4,502
(252 )
Gain on extinguishment of debt (17,631 ) —
Other, net 2,911
3,683
Changes in assets and liabilities:
Accounts receivable 344,845
(78,027 )
Inventories 22,417
(14,742 )
Other current assets (4,848 ) (5,786 )
Accounts payable trade 70,084
24,341
Revenues and royalties payable (231,990 ) 6,282
Accrued liabilities and other (70,274 ) (563 )
Other noncurrent assets and liabilities (1,417 ) (81 )
Net cash provided by operating activities 663,818
721,508

Cash flows from investing activities
Exploration and development (673,191 ) (732,770 )
Purchase of producing crude oil and natural gas properties (19,258 ) (15,849 )
Purchase of other property and equipment (14,923 ) (4,951 )
Proceeds from sale of assets 633
499
Net cash used in investing activities (706,739 ) (753,071 )

Cash flows from financing activities
Credit facility borrowings 1,130,000
100,000
Repayment of credit facility (450,000 ) (100,000 )
Repurchase of senior notes (22,527 ) —
Repayment of other debt (603 ) (576 )
Contributions from noncontrolling interests 21,254
38,242
Distributions to noncontrolling interests (5,212 ) (3,874 )
Repurchase of common stock (126,906 ) —
Repurchase of restricted stock for tax withholdings (6,454 ) (20,622 )
Dividends paid on common stock (18,460 ) —
Net cash provided by financing activities 521,092
13,170
Effect of exchange rate changes on cash —
15
Net change in cash and cash equivalents 478,171
(18,378 )
Cash and cash equivalents at beginning of period 39,400
282,749
Cash and cash equivalents at end of period $ 517,571
$ 264,371

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

Note 1. Organization and Nature of Business

Continental Resources, Inc. (the “Company”) was formed in 1967 and is incorporated under the laws of the State of Oklahoma. The Company’s principal business is crude oil and natural gas exploration, development and production with properties primarily located in the North, South, and East regions of the United States. Additionally, the Company pursues the acquisition and management of perpetually owned minerals located in certain of its 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, Wyoming Powder River Basin, and the Red River units. The South region includes all properties south of Nebraska and west of the Mississippi River including various plays in the SCOOP and STACK areas of Oklahoma. The East region is primarily comprised of undeveloped leasehold acreage east of the Mississippi River with no significant drilling or production operations.

The Company's operations in the North region comprised ~~58%~~55% of its crude oil and natural gas production and ~~69%~~55% of its crude oil and natural gas revenues for the three months ended March 31, ~~2020.~~2021. The Company's principal producing properties in the North region are located in the Bakken field of North Dakota and Montana. The Company's operations in the South region comprised ~~42%~~45% of its crude oil and natural gas production and ~~31%~~ 45%of its crude oil and natural gas revenues for the three months ended March 31, ~~2020.~~2021. The Company's principal producing properties in the South region are located in the SCOOP and STACK areas of Oklahoma.

For the three months ended March 31, ~~2020,~~2021, crude oil accounted for ~~56%~~49% of the Company’s total production and ~~90%~~ 62%of its crude oil and natural gas revenues.

Note 2. Basis of Presentation and Significant Accounting Policies

Basis of presentation

The condensed consolidated financial statements include the accounts of the Company, its wholly-owned subsidiaries, and entities in which the Company has a controlling financial interest. Intercompany accounts and transactions have been eliminated upon consolidation. Noncontrolling interests reflected herein represent third party ownership in the net assets of consolidated subsidiaries. The portions of consolidated net income (loss) and equity attributable to the noncontrolling interests are presented separately in the Company’s financial statements.

This report has been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”) applicable to interim financial information. Because this is an interim period filing presented using a condensed format, it does not include all disclosures required by accounting principles generally accepted in the United States (“U.S. GAAP”), although the Company believes the disclosures are adequate to make the information not misleading. You should read this Quarterly Report on Form 10-Q (“Form 10-Q”) together with the Company’s Annual Report on Form 10-K for the year ended December 31, ~~2019~~2020 (“~~2019~~2020 Form 10-K”), which includes a summary of the Company’s significant accounting policies and other disclosures.

The condensed consolidated financial statements as of March 31, ~~2020~~2021 and for the three month periods ended March 31, ~~2020~~2021 and ~~2019~~2020 are unaudited. The condensed consolidated balance sheet as of December 31, ~~2019~~2020 was derived from the audited balance sheet included in the ~~2019~~2020 Form 10-K. The Company has evaluated events or transactions through the date this report on Form 10-Q was filed with the SEC in conjunction with its preparation of these condensed consolidated financial statements.

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure and estimation of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting periods. Actual results may differ from those estimates. The most significant estimates and assumptions impacting reported results are estimates of the Company’s crude oil and natural gas reserves, which are used to compute depreciation, depletion, amortization and impairment of proved crude oil and natural gas properties. In the opinion of management, all adjustments (consisting only of normal recurring adjustments) necessary for a fair presentation in accordance with U.S. GAAP have been included in these unaudited condensed consolidated financial statements. The results of operations for any interim period are not necessarily indicative of the results of operations that may be expected for any other interim period or for an entire year.

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

Earnings per share

Basic net income (loss) per share is computed by dividing net income (loss) attributable to the Company by the weighted-average number of shares outstanding for the period. In periods where the Company has net income, diluted earnings per share reflects the potential dilution of non-vested restricted stock awards, which are calculated using the treasury stock method. The

~~Continental Resources, Inc. and Subsidiaries~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

following table presents the calculation of basic and diluted weighted average shares outstanding and net income (loss) per share attributable to the Company for the three months ended March 31, 2021 and 2020.


	Three months ended March 31,
In thousands, except per share data	2021		2020
Net income (loss) attributable to Continental Resources (numerator)	$	259,642	$	(185,664)
Weighted average shares (denominator):
Weighted average shares - basic	360,789		365,403
Non-vested restricted stock (1)	1,884		0
Weighted average shares - diluted	362,673		365,403
Net income (loss) per share attributable to Continental Resources:
Basic	$	0.72	$	(0.51)
Diluted	$	0.72	$	(0.51)

(1) For the three months ended March 31, 2020 the Company had a net loss and ~~2019.~~therefore the potential dilutive effect of approximately 594,000 weighted average non-vested restricted shares were not included in the calculation of diluted net loss per share because to do so would have been anti-dilutive to the computation.

Credit risk

The Company's principal exposure to credit risk is through receivables associated with the sale of its crude oil and natural gas production and receivables associated with billings to joint interest owners. Accordingly, the Company classifies its receivables into two portfolio segments as depicted on the condensed consolidated balance sheets as "Receivables—

Three months ended March 31,
In thousands, except per share data 2020 2019
Net income (loss) attributable to Continental Resources (numerator) $ (185,664 ) $ 186,976
Weighted average shares (denominator):
Weighted average shares - basic 365,403
372,563
Non-vested restricted stock (1) —
1,911
Weighted average shares - diluted 365,403
374,474
Net income (loss) per share attributable to Continental Resources:
Basic $ (0.51 ) $ 0.50
Diluted $ (0.51 ) $ 0.50

Crude oil and natural gas sales” and "Receivables—Joint interest and other.” The Company determines its credit loss allowance for each portfolio segment by considering a number of factors, primarily including the Company’s history of credit losses with adjustment as needed to reflect current conditions, the length of time accounts are past due, whether amounts relate to operated properties or non-operated properties, the ability to recoup amounts owed through netting of production proceeds, the balance of co-owner prepayments if any, and a party's ability to pay. Historically, the Company's credit losses have been immaterial. There were no significant write-offs, recoveries, or changes in the Company's allowance for credit losses during the three month periods ended March 31, 2021 and 2020.


~~(1)~~	For the three months ended March 31, 2020 the Company had a net loss and therefore the potential dilutive effect of approximately 594,000 weighted average non-vested restricted shares were not included in the calculation of diluted net loss per share because to do so would have been anti-dilutive to the computation.

Inventories

Inventory is comprised of crude oil held in storage or as line fill in pipelines, pipeline imbalances, and tubular goods and equipment to be used in the Company's exploration and development activities. Crude oil and natural gas inventories are valued at the lower of cost or net realizable value primarily using the first-in, first-out inventory method. Tubular goods and equipment are valued primarily using a weighted average cost method applied to specific classes of inventory items.

The components of inventory as of March 31, ~~2020~~2021 and December 31, ~~2019~~2020 consisted of the following:

In thousands March 31, 2020 December 31, 2019
Tubular goods and equipment $ 15,853
$ 14,880
Crude oil 46,747
94,656
Total $ 62,600
$ 109,536


In thousands	March 31, 2021		December 31, 2020
Tubular goods and equipment	$	13,341	$	13,671
Crude oil and natural gas	62,667		58,486
Total	$	76,008	$	72,157

~~For~~In the ~~three months ended March 31,~~first quarter of 2020 the Company recognized a $24.5 million impairment to reduce its crude oil inventory to estimated net realizable value at March 31, 2020. The impairment is included in the caption “Property impairments” in the unaudited condensed consolidated statements of ~~comprehensive income (loss).~~operations for the three month period ended March 31, 2020.

Adoption of new accounting pronouncement

On January 1, ~~2020~~2021 the Company adopted Accounting Standards Update ("ASU") ~~2016-13,~~ ~~Financial Instruments~~–~~Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments. See~~ ~~Note 5. Allowance for Credit Losses~~ ~~for discussion of the adoption impact and the applicable disclosures required by the new standard.~~

~~New accounting pronouncement not yet adopted~~

~~In December 2019, the Financial Accounting Standards Board ("FASB") issued ASU~~ 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes. This standard eliminates certain exceptions to the guidance in Topic 740 related to the approach for intraperiod tax allocation, the methodology for calculating income taxes in an interim period, and the recognition of deferred tax liabilities for outside basis differences. The new guidance also clarifies certain aspects of the existing guidance, among other things. The standard is effective for interim and annual periods beginning after December 15, 2020 and shall be applied on either a prospective basis, a retrospective basis for all periods presented, or a modified retrospective basis through a cumulative-effect adjustment to retained earnings depending on which aspects of the new standard are applicable to an entity. The Company continues to evaluate the new standard and is unable to estimate its financial statement impact at this time; however, the impact is not expected to be material.

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

existing guidance, among other things. The Company adopted the standard on a prospective basis, which did not have a material impact on its financial position, results of operations, or cash flows.

Note 3. Supplemental Cash Flow Information

The following table discloses supplemental cash flow information about cash paid for interest and income tax payments and refunds. Also disclosed is information about investing activities that affects recognized assets and liabilities but does not result in cash receipts or payments.

Three months ended March 31,
In thousands 2020 2019
Supplemental cash flow information:
Cash paid for interest $ 51,111
$ 61,964
Cash paid for income taxes 8
9
Cash received for income tax refunds (1) 9,485
4
Non-cash investing activities:
Asset retirement obligation additions and revisions, net 2,508
2,570


	Three months ended March 31,
In thousands	2021		2020
Supplemental cash flow information:
Cash paid for interest	$	42,554	$	51,111
Cash paid for income taxes	0		8
Cash received for income tax refunds (1)	2		9,485
Non-cash investing activities:
Asset retirement obligation additions and revisions, net	6,802		2,508

(1) Amount received in the 2020 period primarily represents alternative minimum tax refunds.

As of March 31, ~~2020~~2021 and December 31, ~~2019,~~2020, the Company ~~had $232.2~~had $178.2 million a ~~and $262.7~~nd $128.8 million, respectively, of accrued capital expenditures included in “Net property and equipment” ~~and~~with an offsetting amount in “Accounts payable trade” in the condensed consolidated balance sheets.

As of March 31, ~~2020~~2021 and December 31, ~~2019,~~2020, the Company had ~~$1.3~~$0.6 million and ~~$5.6~~$0.1 million, respectively, of accrued contributions from noncontrolling interests included in "Receivables–Joint interest and other" ~~and~~with an offsetting amount in "Equity–Noncontrolling interests" in the condensed consolidated balance sheets.

As of March 31, ~~2020~~2021 and December 31, ~~2019,~~2020, the Company had ~~$1.9~~$1.3 million and ~~$1.5~~$1.0 million, respectively, of accrued distributions to noncontrolling interests included in "Revenues and royalties payable" ~~and~~with an offsetting amount in "Equity–Noncontrolling interests" in the condensed consolidated balance sheets.

Note 4. Revenues

Below is a discussion of the nature, timing, and presentation of revenues arising from the Company's major revenue-generating arrangements.

Operated crude oil revenues – The Company pays third parties to transport the majority of its operated crude oil production from lease locations to downstream market centers, at which time the Company's customers take title and custody of the product in exchange for prices based on the particular market where the product was delivered. Operated crude oil revenues are recognized during the month in which control transfers to the customer and it is probable the Company will collect the consideration it is entitled to receive. Crude oil sales proceeds from operated properties are generally received by the Company within one month after the month in which a sale has occurred. Operated crude oil revenues are presented separately from transportation expenses as the Company controls the operated production prior to its transfer to customers. Transportation expenses associated with the Company's operated crude oil production totaled ~~$50.4~~$40.1 millionand ~~$41.6~~$50.4 million for the three months ended March 31, ~~2020~~2021 and ~~2019,~~2020, respectively.

Operated natural gas revenues – The Company sells the majority of its operated natural gas production to midstream customers at its lease locations based on market prices in the field where the sales occur. Under these arrangements, the midstream customers obtain control of the unprocessed gas stream at the lease location and the Company's revenues from each sale are determined using contractually agreed pricing formulas which contain multiple components, including the volume and Btu content of the natural gas sold, the midstream customer's proceeds from the sale of residue gas and natural gas liquids ("NGLs") at secondary downstream markets, and contractual pricing adjustments reflecting the midstream customer's estimated recoupment of its investment over time. Such revenues are recognized net of pricing adjustments applied by the midstream customer during the month in which control transfers to the customer at the delivery point and it is probable the Company will collect the consideration it is entitled to receive. Natural gas sales proceeds from operated properties are generally received by the Company within one month after the month in which a sale has occurred.

Under certain arrangements, the Company has the right to take a volume of processed residue gas and/or NGLs in-kind at the tailgate of the midstream customer's processing plant in lieu of a monetary settlement for the sale of the Company's operated natural gas production. The Company currently takes certain processed residue gas volumes in kind in lieu of monetary

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

settlement, but does not currently take NGL volumes. When the Company elects to take volumes in kind, it pays third parties to

~~Continental Resources, Inc. and Subsidiaries~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

transport the processed products it took in-kind to downstream delivery points, where it then sells to customers at prices applicable to those downstream markets. In such situations, operated revenues are recognized during the month in which control transfers to the customer at the delivery point and it is probable the Company will collect the consideration it is entitled to receive. Operated sales proceeds are generally received by the Company within one month after the month in which a sale has occurred. In these scenarios, the Company's revenues include the pricing adjustments applied by the midstream processing entity according to the applicable contractual pricing formula, but exclude the transportation expenses the Company incurs to transport the processed products to downstream customers. Transportation expenses associated with these arrangements totaled $~~10.1~~10.2 millionand ~~$7.5~~$10.1 million for the three months ended March 31, ~~2020~~2021 and ~~2019,~~2020, respectively.

Non-operated crude oil and natural gas revenues – The Company's proportionate share of production from non-operated properties is generally marketed at the discretion of the operators. For non-operated properties, the Company receives a net payment from the operator representing its proportionate share of sales proceeds which is net of costs incurred by the operator, if any. Such non-operated revenues are recognized at the net amount of proceeds to be received by the Company during the month in which production occurs and it is probable the Company will collect the consideration it is entitled to receive. Proceeds are generally received by the Company within two to three months after the month in which production occurs.

Revenues from derivative instruments – See Note 6.5. Derivative Instruments for discussion of the Company's accounting for its derivative instruments.

Revenues from service operations – Revenues from the Company's crude oil and natural gas service operations consist primarily of revenues associated with water gathering, recycling, and disposal activities and the treatment and sale of crude oil reclaimed from waste products. Revenues associated with such activities, which are derived using market-based rates or rates commensurate with industry guidelines, are recognized during the month in which services are performed, the Company has an unconditional right to receive payment, and collectability is probable. Payment is generally received by the Company within one month after the month in which services are provided.

Disaggregation of crude oil and natural gas revenues

The following tables present the disaggregation of the Company's crude oil and natural gas revenues for the three months ended March 31, ~~2020~~2021 and ~~2019.~~2020.

Three months ended March 31, 2020 Three months ended March 31, 2019
In thousands North Region South Region Total North Region South Region Total
Crude oil revenues:
Operated properties $ 448,930
$ 179,176
$ 628,106
$ 585,605
$ 136,547
$ 722,152
Non-operated properties 132,939
12,725
145,664
178,728
10,238
188,966
Total crude oil revenues 581,869
191,901
773,770
764,333
146,785
911,118
Natural gas revenues:
Operated properties 11,588
72,306
83,894
51,461
124,698
176,159
Non-operated properties 1,720
3,359
5,079
10,866
11,441
22,307
Total natural gas revenues 13,308
75,665
88,973
62,327
136,139
198,466
Crude oil and natural gas sales $ 595,177
$ 267,566
$ 862,743
$ 826,660
$ 282,924
$ 1,109,584

Timing of revenue recognition
Goods transferred at a point in time $ 595,177
$ 267,566
$ 862,743
$ 826,660
$ 282,924
$ 1,109,584
Goods transferred over time —
—
—
—
—
—
$ 595,177
$ 267,566
$ 862,743
$ 826,660
$ 282,924
$ 1,109,584


	Three months ended March 31, 2021						Three months ended March 31, 2020
In thousands	North Region		South Region		Total		North Region		South Region		Total
Crude oil revenues:
Operated properties	$	444,665	$	166,430	$	611,095	$	448,930	$	179,176	$	628,106
Non-operated properties	143,552		14,121		157,673		132,939		12,725		145,664
Total crude oil revenues	588,217		180,551		768,768		581,869		191,901		773,770
Natural gas revenues:
Operated properties	82,933		371,761		454,694		11,588		72,306		83,894
Non-operated properties	12,600		11,471		24,071		1,720		3,359		5,079
Total natural gas revenues	95,533		383,232		478,765		13,308		75,665		88,973
Crude oil and natural gas sales	$	683,750	$	563,783	$	1,247,533	$	595,177	$	267,566	$	862,743

Timing of revenue recognition
Goods transferred at a point in time	$	683,750	$	563,783	$	1,247,533	$	595,177	$	267,566	$	862,743
Goods transferred over time	0		0		0		0		0		0
	$	683,750	$	563,783	$	1,247,533	$	595,177	$	267,566	$	862,743

Performance obligations

The Company satisfies the performance obligations under its crude oil and natural gas sales contracts upon delivery of its production and related transfer of control to customers. Judgment may be required in determining the point in time when control transfers to customers. Upon delivery of production, the Company has a right to receive consideration from its customers in amounts determined by the sales contracts.

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

All of the Company's outstanding crude oil sales contracts at March 31, ~~2020~~2021 are short-term in nature with contract terms of less than one year. For such contracts, the Company has utilized the practical expedient in Accounting Standards Codification ("ASC") 606-10-50-14 exempting the Company from disclosure of the transaction price allocated to remaining performance obligations, if any, if the performance obligation is part of a contract that has an original expected duration of one year or less.

The majority of the Company's operated natural gas production is sold at lease locations to midstream customers under multi-year term contracts. For such contracts having a term greater than one year, the Company has utilized the practical expedient in ASC 606-10-50-14A which indicates an entity is not required to disclose the transaction price allocated to remaining performance obligations, if any, if variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under the Company's sales contracts, whether for crude oil or natural gas, each unit of production delivered to a customer represents a separate performance obligation; therefore, future volumes to be delivered are wholly unsatisfied at period-end and disclosure of the transaction price allocated to remaining performance obligations is not applicable.

Contract balances

Under the Company’s crude oil and natural gas sales contracts or activities that give rise to service revenues, the Company recognizes revenue after its performance obligations have been satisfied, at which point the Company has an unconditional right to receive payment. Accordingly, the Company’s commodity sales contracts and service activities generally do not give rise to contract assets or contract liabilities under ASC Topic 606. Instead, the Company's unconditional rights to receive consideration are presented as a receivable within "Receivables–Crude oil and natural gas sales" or "Receivables–Joint interest and other", as applicable, in its condensed consolidated balance sheets.

Revenues from previously satisfied performance obligations

To record revenues for commodity sales, at the end of each month the Company estimates the amount of production delivered and sold to customers and the prices to be received for such sales. Differences between estimated revenues and actual amounts received for all prior months are recorded in the month payment is received from the customer and are reflected in the financial statements within the caption "Crude oil and natural gas sales". Revenues recognized during the three months ended March 31, ~~2020~~2021 and ~~2019~~2020 related to performance obligations satisfied in prior reporting periods were not material.

~~Note 5. Allowance for Credit Losses~~

~~In June 2016, the FASB issued ASU 2016-13,~~ ~~Financial Instruments~~–~~Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments~~. This standard changes how entities measure credit losses for most financial assets and certain other instruments that are not measured at fair value through net income. The standard replaced the previously required incurred loss approach with a forward-looking expected credit loss model for accounts receivable and other financial instruments measured at amortized cost. The standard became effective for reporting periods beginning after December 15, 2019. The Company adopted the new standard on January 1, 2020 using a modified retrospective approach through a cumulative-effect adjustment to retained earnings as of the effective date. The Company's cumulative effect adjustment resulted in a $0.1 million decrease in retained earnings and corresponding decrease in receivables via the recognition of an incremental allowance for credit losses at January 1, 2020.

The Company's principal exposure to credit risk is through the sale of its crude oil and natural gas production and its receivables associated with billings to joint interest owners. Accordingly, the Company classifies its receivables into two portfolio segments as depicted on the condensed consolidated balance sheets as "Receivables—~~Crude oil and natural gas sales” and "Receivables~~—~~Joint interest and other.” Presented below are applicable disclosures required by ASU 2016-13 for each portfolio segment.~~

Historically, the Company's credit losses on receivables have been immaterial. The Company’s aggregate allowance for credit losses totaled $2.7 million and $2.4 million at March 31, 2020 and December 31, 2019, respectively, which is reported as "Allowance for credit losses" in the condensed consolidated balance sheets. Aggregate credit loss expenses totaled $0.7 million and $0.1 million for the three months ended March 31, 2020 and 2019, respectively, which is included in “General and administrative expenses” in the unaudited condensed consolidated statements of comprehensive income (loss).

~~Receivables—Crude oil and natural gas sales~~

The Company's crude oil and natural gas production from operated properties is generally sold to energy marketing companies, crude oil refining companies, and natural gas gathering and processing companies. The Company monitors its credit loss exposure to these counterparties primarily by reviewing credit ratings, financial statements, and payment history. Credit terms are extended based on an evaluation of each counterparty’s credit worthiness. The Company has not generally required its counterparties to provide collateral to secure its crude oil and natural gas sales receivables.

~~Continental Resources, Inc. and Subsidiaries~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

Receivables associated with crude oil and natural gas sales are short term in nature. Receivables from the sale of crude oil and natural gas from operated properties are generally collected within one month after the month in which a sale has occurred, while receivables associated with non-operated properties are generally collected within two to three months after the month in which production occurs.

~~The Company’s allowance for credit losses on crude oil and natural gas sales was less than $0.1 million~~at both March 31, 2020 and December 31, 2019. The allowance was determined by considering a number of factors, primarily including the Company’s history of credit losses with adjustment as needed to reflect current conditions, the length of time accounts are past due, whether amounts relate to operated properties or non-operated properties, and the counterparty's ability to pay. There were no significant write-offs, recoveries, or changes in the provision for credit losses on this portfolio segment during the three months ended March 31, 2020.

~~Receivables—Joint interest and other~~

Joint interest and other receivables primarily arise from billing the individuals and entities who own a partial interest in the wells we operate. Joint interest receivables are due within 30 days and are considered delinquent after 60 days. In order to minimize our exposure to credit risk with these counterparties we generally request prepayment of drilling costs where it is allowed by contract or state law. Such prepayments are used to offset future capital costs when billed, thereby reducing the Company's credit risk. We may have the right to place a lien on a co-owner's interest in the well, to net production proceeds against amounts owed in order to secure payment or, if necessary, foreclose on the co-owner's interest.

The Company’s allowance for credit losses on joint interest receivables totaled $2.7 million and $2.4 million at March 31, 2020 and December 31, 2019, respectively. The allowance was determined by considering a number of factors, primarily including the Company’s history of credit losses with adjustment as needed to reflect current conditions, the length of time accounts are past due, the ability to recoup amounts owed through netting of production proceeds, the balance of co-owner prepayments if any, and the co-owner's ability to pay. There were no significant write-offs, recoveries, or changes in the provision for credit losses on this portfolio segment during the three months ended March 31, 2020.

Note 6.5. Derivative Instruments

~~Natural gas derivatives~~

~~As of and for the three months ended March 31, 2019~~From time to time the Company ~~had outstanding~~enters into crude oil and natural gas swap and collar derivative contracts to economically hedge against the variability in cash flows associated with future sales of ~~natural gas~~ production. ~~Such contracts matured in 2019 and the Company had no commodity derivative contracts outstanding at December 31, 2019 and March 31, 2020.~~

The Company recognizes its derivative instruments ~~if any,~~ on the balance sheet as either assets or liabilities measured at fair value. The Company has not designated its derivatives as hedges for accounting purposes and, as a result, marks such derivative instruments to fair value and recognizes the changes in fair value in the unaudited condensed consolidated statements of operations under the caption "Loss on derivative instruments, net".

The Company's derivative contracts are settled based upon reported settlement prices on commodity exchanges, with crude oil derivative settlements based on NYMEX West Texas Intermediate ("WTI") pricing and natural gas derivative settlements based on NYMEX Henry Hub pricing. The estimated fair value of ~~derivatives~~derivative contracts is based upon various factors, including commodity exchange prices, over-the-counter quotations, and, in the case of collars, volatility, the risk-free interest rate, and the time to expiration. ~~Historically,~~The calculation of the ~~Company has not designated its derivatives as hedges for accounting purposes and, as a result, marked its derivative instruments to~~ fair value ~~and recognized~~of collars requires the ~~changes in fair value in the unaudited condensed consolidated statements~~use of ~~comprehensive income (loss) under the caption “Loss on natural gas derivatives, net”~~an option-pricing model. See Note 6. Fair Value Measurements.

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

~~Natural gas~~At March 31, 2021 the Company had outstanding derivative contracts as set forth in the tables below.


				Collars
Natural gas derivatives				Floors			Ceilings
		Swaps Weighted Average Price		Range	Weighted Average Price		Range	Weighted Average Price
Period and Type of Contract	MMBtus


April 2021 - December 2021
Swaps - Henry Hub	45,178,000	$	2.94
Collars - Henry Hub	27,450,000			$2.50 - $2.60	$	2.58	$3.06 - $3.43	$	3.24


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


April 2021 - December 2021
NYMEX Roll Swaps	8,250,000	$	0.47
April 2021 - May 2021
Swaps - WTI	1,815,000	$	54.64
Collars - WTI	1,132,000			$50.00 - $53.00	$	51.81	$55.10 - $63.05	$	59.89
January 2022 - March 2022
NYMEX Roll Swaps	675,000	$	0.50

Derivative gains and losses

Cash receipts and payments in the following table reflect the ~~gain~~gains or losses on derivative contracts which matured during the applicable period, calculated as the difference between the contract price and the ~~market~~ settlement price of matured contracts. ~~The Company's 2019 natural gas derivatives were settled based upon reported NYMEX Henry Hub settlement prices.~~ Non-cash gains and losses below represent the change in fair value of derivative instruments which continued to be held at period end ~~if any,~~ and the reversal of previously recognized non-cash gains or losses on derivative contracts that matured during the period. The Company had no outstanding commodity derivative instruments as of March 31, 2020 and for the three months then ended.


	Three months ended March 31,
In thousands	2021		2020
Cash received (paid) on derivatives:
Crude oil fixed price swaps	$	(30,033)	$	0
Crude oil collars	(4,956)		0
Crude oil NYMEX roll swaps	159		0
Natural gas fixed price swaps	2,210		0
Natural gas collars	3,183		0
Cash received (paid) on derivatives, net	(29,437)		0
Non-cash gain (loss) on derivatives:
Crude oil fixed price swaps	(8,206)		0
Crude oil collars	(2,076)		0
Crude oil NYMEX roll swaps	175		0
Natural gas fixed price swaps	6,086		0
Natural gas collars	(10,049)		0
Non-cash gain (loss) on derivatives, net	(14,070)		0
Loss on derivative instruments, net	$	(43,507)	$	0

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

Balance sheet offsetting of derivative assets and liabilities

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

The following table presents the gross amounts of recognized derivative assets and liabilities, as applicable, the amounts offset under netting arrangements with counterparties, and the resulting net amounts presented in the condensed consolidated balance sheets for the periods presented, all at fair value.

Three months ended March 31,
In thousands 2020 2019
Cash received on derivatives:
Natural gas fixed price swaps $ —
$ 7,645
Natural gas collars —
5,417
Cash received on derivatives, net —
13,062
Non-cash loss on derivatives:
Natural gas fixed price swaps —
(8,704 )
Natural gas collars —
(5,482 )
Non-cash loss on derivatives, net —
(14,186 )
Loss on natural gas derivatives, net $ —
$ (1,124 )



In thousands	March 31, 2021		December 31, 2020
Commodity derivative assets:
Gross amounts of recognized assets	$	14,362	$	15,900
Gross amounts offset on balance sheet	(3,087)		(597)
Net amounts of assets on balance sheet	11,275		15,303
Commodity derivative liabilities:
Gross amounts of recognized liabilities	(14,940)		(2,408)
Gross amounts offset on balance sheet	3,087		597
Net amounts of liabilities on balance sheet	$	(11,853)	$	(1,811)

The following table reconciles the net amounts disclosed above to the individual financial statement line items in the condensed consolidated balance sheets.



In thousands	March 31, 2021		December 31, 2020
Derivative assets	$	11,275	$	15,303
Derivative assets, noncurrent	0		0
Net amounts of assets on balance sheet	11,275		15,303
Derivative liabilities	(10,659)		(227)
Derivative liabilities, noncurrent	(1,194)		(1,584)
Net amounts of liabilities on balance sheet	(11,853)		(1,811)
Total derivative assets (liabilities), net	$	(578)	$	13,492

Note 7.6. Fair Value Measurements

The Company follows a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows:

•Level 1: Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date.

•Level 2: Observable market-based inputs or unobservable inputs corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date.

•Level 3: Unobservable inputs not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value.

A financial instrument’s categorization within the hierarchy is based upon the lowest level of input that is significant to the fair value measurement. Level 1 inputs are given the highest priority in the fair value hierarchy while Level 3 inputs are given the lowest priority. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the hierarchy. As Level 1 inputs generally provide the most reliable evidence of fair value, the Company uses Level 1 inputs when available.

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The Company's derivative instruments ~~if any,~~ are reported at fair value on a recurring basis. In determining the fair values of swap contracts, a discounted cash flow method is used due to the unavailability of relevant comparable market data for the Company’s exact contracts. The discounted cash flow method estimates future cash flows based on quoted market prices for forward commodity prices and a risk-adjusted discount rate. The fair values of swap contracts are calculated mainly using significant observable inputs (Level 2). Calculation of the fair values of collars requires the use of an industry-standard option pricing model that considers various inputs including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. These assumptions are observable in the marketplace or can be corroborated by active markets or broker quotes and are therefore designated as Level 2 within the valuation hierarchy. The Company’s calculation of fair value for each of its derivative positions is compared to the counterparty valuation for reasonableness.

~~Continental Resources, Inc. and Subsidiaries~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

The ~~Company had no outstanding commodity~~following table summarizes the valuation of derivative instruments by pricing levels that were accounted for at fair value on a recurring basis as of March 31, ~~2020~~2021 and December 31, ~~2019.~~2020.



	Fair value measurements at March 31, 2021 using:
In thousands	Level 1		Level 2		Level 3		Total
Derivative assets (liabilities):
Swaps	$	0	$	(77)	$	0	$	(77)
Collars	0		(676)		0		(676)
NYMEX roll swaps	0		$	175	0		$	175
Total	$	0	$	(578)	$	0	$	(578)



	Fair value measurements at December 31, 2020 using:
In thousands	Level 1		Level 2		Level 3		Total
Derivative assets (liabilities):
Swaps	$	0	$	2,043	$	0	$	2,043
Collars	0		11,449		0		$	11,449
Total	$	0	$	13,492	$	0	$	13,492

Assets Measured at Fair Value on a Nonrecurring Basis

Certain assets are reported at fair value on a nonrecurring basis in the condensed consolidated financial statements. The following methods and assumptions were used to estimate the fair values for those assets.

Asset impairments – Proved crude oil and natural gas properties are reviewed for impairment on a field-by-field basis each quarter. The estimated future cash flows expected in connection with the field are compared to the carrying amount of the field to determine if the carrying amount is recoverable. If the carrying amount of the field exceeds its estimated undiscounted future cash flows, the carrying amount of the field is reduced to its estimated fair value. Risk-adjusted probable and possible reserves may be taken into consideration when determining estimated future net cash flows and fair value when such reserves exist and are economically recoverable. Due to the unavailability of relevant comparable market data, a discounted cash flow method is used to determine the fair value of proved properties. Significant unobservable inputs (Level 3) utilized in the determination of discounted future net cash flows include future commodity prices adjusted for differentials, forecasted production based on decline curve analysis, estimated future operating and development costs, property ownership interests, and a 10% discount rate. At March 31, ~~2020,~~2021, the Company's commodity price assumptions were based on forward NYMEX strip prices through year-end ~~2024~~2025 and were then escalated at 3% per year thereafter. Operating cost assumptions were based on current costs escalated at 3% per year beginning in 2022.

Unobservable inputs to the Company's fair value assessments are reviewed and revised as warranted based on a number of factors, including reservoir performance, new drilling, crude oil and natural gas prices, changes in costs, technological advances, new geological or geophysical data, or other economic factors. Fair value measurements of proved properties are reviewed and approved by certain members of the Company’s management.

For the three months ended March 31, 2021, estimated future net cash flows were determined to be in excess of cost basis, and therefore no impairment was recorded for the Company's proved crude oil and natural gas properties for the 2021 period.

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

For the three months ended March 31, 2020, ~~given the significant declines in commodity prices during the quarter~~ the Company determined the carrying amounts of certain proved properties were not recoverable from future cash flows and therefore were impaired. ~~Such impairments totaled~~Impairments of proved properties amounted to $181.0 million for the three months ended March 31, 2020, which reflect fair value adjustments on legacy properties in the Red River Units ~~($166.5 million)~~totaling $166.5 million and various non-core properties in the North and South regions ~~($14.5 million).~~totaling $14.5 million. The impaired properties were written down to their estimated fair value at the time of impairment of $145.6 million. Impairments for the three months ended March 31, 2020 also include a $24.5 millionimpairment to reduce the Company's crude oil inventory to estimated net realizable value at ~~March 31, 2020.~~

~~For~~ the ~~three months ended March 31, 2019, estimated future net cash flows were determined to be in excess~~time of ~~cost basis, therefore no impairment was recorded for the Company’s proved crude oil and natural gas properties for that period.~~impairment.

Certain unproved crude oil and natural gas properties were impaired during the three months ended March 31, ~~2020~~2021 and ~~2019,~~2020, reflecting recurring amortization of undeveloped leasehold costs on properties the Company expects will not be transferred to proved properties over the lives of the leases based on drilling plans, experience of successful drilling, and the average holding period.

The following table sets forth the non-cash impairments of both proved and unproved properties for the indicated periods. Proved and unproved property impairments are recorded under the caption “Property impairments” in the unaudited condensed consolidated statements of ~~comprehensive income (loss).~~operations.

Three months ended March 31,
In thousands 2020 2019
Proved property impairments $ 205,545
$ —
Unproved property impairments 16,984
25,316
Total $ 222,529
$ 25,316

~~Continental Resources, Inc. and Subsidiaries~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~


	Three months ended March 31,
In thousands	2021		2020
Proved property and inventory impairments	$	0	$	205,545
Unproved property impairments	11,436		16,984
Total	$	11,436	$	222,529

Financial Instruments Not Recorded at Fair Value

The following table sets forth the estimated fair values of financial instruments that are not recorded at fair value in the condensed consolidated financial statements.


	March 31, 2020				December 31, 2019					March 31, 2021				December 31, 2020
In thousands	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value		In thousands	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Debt:									Debt:
Credit facility	$	735,000	$	735,000	$	55,000	$	55,000	Credit facility	$	0	$	0	$	160,000	$	160,000
Note payable	4,753		4,800		5,351		5,400
Notes payable									Notes payable	24,036		23,400		24,590		24,700
5% Senior Notes due 2022	1,099,234		692,400		1,099,165		1,108,700		5% Senior Notes due 2022	230,684		230,600		630,470		632,900
4.5% Senior Notes due 2023	1,458,753		812,200		1,491,339		1,571,400		4.5% Senior Notes due 2023	647,222		672,300		646,943		669,900
3.8% Senior Notes due 2024	987,644		507,700		994,310		1,034,200		3.8% Senior Notes due 2024	907,203		933,900		906,922		939,500
4.375% Senior Notes due 2028	989,928		463,700		989,661		1,063,700		4.375% Senior Notes due 2028	991,024		1,051,700		990,746		1,024,400
5.75% Senior Notes due 2031									5.75% Senior Notes due 2031	1,481,237		1,685,200		1,480,879		1,651,900
4.9% Senior Notes due 2044	691,732		298,600		691,688		742,000		4.9% Senior Notes due 2044	691,914		696,500		691,868		689,600
Total debt	$	5,967,044	$	3,514,400	$	5,326,514	$	5,580,400	Total debt	$	4,973,320	$	5,293,600	$	5,532,418	$	5,792,900

The fair value of credit facility borrowings approximate carrying value based on borrowing rates available to the Company for bank loans with similar terms and maturities and are classified as Level 2 in the fair value hierarchy.

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

The fair values of the 5% Senior Notes due 2022 (“2022 Notes”), the 4.5% Senior Notes due 2023 (“2023 Notes”), the 3.8% Senior Notes due 2024 (“2024 Notes”), the 4.375% Senior Notes due 2028 (“2028 Notes”), the 5.75% Senior Notes due 2031 (“2031 Notes”), and the 4.9% Senior Notes due 2044 (“2044 Notes”) are based on quoted market prices and, accordingly, are classified as Level 1 in the fair value hierarchy.

The carrying values of all classes of cash and cash equivalents, trade receivables, and trade payables are considered to be representative of their respective fair values due to the short term maturities of those instruments.

~~Note 8. Long-Term Debt~~

Long-term debt, net of unamortized discounts, premiums, and debt issuance costs totaling $32.4 million and $33.9 million at March 31, 2020 and December 31, 2019, respectively, consists of the following.

In thousands March 31, 2020 December 31, 2019
Credit facility $ 735,000
$ 55,000
Note payable 4,753
5,351
5% Senior Notes due 2022 1,099,234
1,099,165
4.5% Senior Notes due 2023 1,458,753
1,491,339
3.8% Senior Notes due 2024 987,644
994,310
4.375% Senior Notes due 2028 989,928
989,661
4.9% Senior Notes due 2044 691,732
691,688
Total debt $ 5,967,044
$ 5,326,514
Less: Current portion of long-term debt 2,455
2,435
Long-term debt, net of current portion $ 5,964,589
$ 5,324,079

~~The Company has an unsecured credit facility, maturing on~~ ~~April 9, 2023~~, with aggregate lender commitments totaling $1.5 billion. The Company had $735 million of outstanding borrowings on its credit facility at March 31, 2020. In March 2020, the Company elected to draw $500 million on its credit facility to increase its cash on hand. At March 31, 2020, the Company's cash on hand totaled $517.6 million.

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

Note 7. Long-Term Debt

Long-term debt, net of unamortized discounts, premiums, and debt issuance costs totaling $42.2 million and $43.7 million at March 31, 2021 and December 31, 2020, respectively, consists of the following.


In thousands	March 31, 2021		December 31, 2020
Credit facility	$	0	$	160,000
Notes payable	24,036		24,590
5% Senior Notes due 2022	230,684		630,470
4.5% Senior Notes due 2023	647,222		646,943
3.8% Senior Notes due 2024	907,203		906,922
4.375% Senior Notes due 2028	991,024		990,746
5.75% Senior Notes due 2031	1,481,237		1,480,879
4.9% Senior Notes due 2044	691,914		691,868
Total debt	$	4,973,320	$	5,532,418
Less: Current portion of long-term debt	2,265		2,245
Long-term debt, net of current portion	$	4,971,055	$	5,530,173

The Company has an unsecured credit facility, maturing on April 9, 2023, with aggregate lender commitments totaling $1.5 billion. The Company had 0 outstanding borrowings on its credit facility at March 31, 2021.

Credit facility borrowings, if any, bear interest at market-based interest rates plus a margin based on the terms of the borrowing and the credit ratings assigned to the Company's senior, unsecured, long-term indebtedness. ~~The weighted-average interest rate on outstanding credit facility borrowings at March 31, 2020 was 2.6%.~~

~~The Company had approximately $762 million of borrowing availability on its credit facility at March 31, 2020 after considering outstanding borrowings and letters of credit.~~ The Company incurs commitment fees based on currently assigned credit ratings of 0.25% per annum on the daily average amount of unused borrowing availability.

The credit facility contains certain restrictive covenants including a requirement that the Company maintain a consolidated net debt to total capitalization ratio of no greater than 0.65 to 1.00. This ratio represents the ratio of net debt (calculated as total face value of debt plus outstanding letters of credit less cash and cash equivalents) divided by the sum of net debt plus total shareholders' equity plus, to the extent resulting in a reduction of total shareholders’ equity, the amount of any non-cash impairment charges incurred, net of any tax effect, after June 30, 2014. The Company was in compliance with the credit facility covenants at March 31, ~~2020.~~2021.

The following table summarizes the face values, maturity dates, semi-annual interest payment dates, and optional redemption periods related to the Company’s outstanding senior note obligations at March 31, ~~2020. In March 2020~~2021.

2022 Notes

2023 Notes

2024 Notes

2028 Notes

2031 Notes

2044 Notes

Face value (in thousands)

$230,782

$649,625

$911,000

$1,000,000

$1,500,000

$700,000

Maturity date

Sep 15, 2022

April 15, 2023

June 1, 2024

January 15, 2028

January 15, 2031

June 1, 2044

Interest payment dates

Mar 15, Sep 15

April 15, Oct 15

June 1, Dec 1

Jan 15, July 15

Jan 15, Jul 15

June 1, Dec 1

Make-whole redemption period (1)

—

Jan 15, 2023

Mar 1, 2024

Oct 15, 2027

Jul 15, 2030

Dec 1, 2043

(1)At any time prior to the indicated dates, the Company ~~repurchased~~has the option to redeem all or a portion of its ~~2023 Notes~~senior notes of the applicable series at the “make-whole” redemption amounts specified in the respective senior note indentures plus any accrued and ~~2024 Notes in open market transactions as further discussed below under~~unpaid interest to the ~~heading~~ ~~Repurchase~~date of ~~Senior Notes~~.redemption. On or after the indicated dates, the Company may redeem all or a portion of its senior notes at a redemption amount equal to 100% of the principal amount of the senior notes being redeemed plus any accrued and unpaid interest to the date of redemption.

The Company’s senior notes are not subject to any mandatory redemption or sinking fund requirements.

The indentures governing the Company’s senior notes contain covenants that, among other things, limit the Company’s ability to create liens securing certain indebtedness, enter into certain sale-leaseback transactions, or consolidate, merge or transfer

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

certain assets. ~~The senior note~~These covenants are subject to a number of important exceptions and qualifications. The Company was in compliance with these covenants at March 31, ~~2020.~~2021.

~~Three~~The senior notes are obligations of Continental Resources, Inc. Additionally, three of the Company’s wholly-owned subsidiaries, Banner Pipeline Company, L.L.C., CLR Asset Holdings, LLC, and The Mineral Resources Company, ~~the value of~~ whose assets, equity, and results of operations are not material, fully and unconditionally guarantee the senior notes on a joint and several basis. The Company’s other subsidiaries, ~~the value of~~ whose assets, equity, and results of operations attributable to the Company are not material, do not guarantee the senior notes.

~~Repurchase~~Retirement of Senior Notes

In January 2021, the Company redeemed $400 million principal amount of its outstanding 2022 Notes using proceeds from lower-rate borrowings on its credit facility. The Company recorded a pre-tax loss on extinguishment of debt related to the redemption of $0.2 million, which included the pro-rata write-off of deferred financing costs and unamortized debt premium associated with the redeemed notes. The loss is reflected in the caption “Gain (loss) on extinguishment of debt” in the unaudited condensed consolidated statements of operations.

Subsequent to March 31, 2021, the Company redeemed the remaining principal balance of its 2022 Notes as discussed in Note 13. Subsequent Events.

In March 2020, the Company repurchased a portion of its 2023 Notes and 2024 Notes in open market transactions at a substantial discount to the face value of the notes, including $33.4 million face value of its 2023 Notes at an aggregate cost of $19.5 million and $7.0 million face value of its 2024 Notes at an aggregate cost of $3.8 million, in each case, including accrued and unpaid interest to the repurchase dates.

The repurchased notes were ~~subsequently~~ canceled by the Company. The Company recognized pre-tax gains on extinguishment of debt in the 2020 first quarter related to the March 2020 repurchases totaling $17.6 million, which included the pro-rata write-off of deferred financing costs and unamortized debt discount associated with the repurchased notes. ~~The gains are reflected in the caption “Gain on extinguishment of debt” in the unaudited condensed consolidated statements of comprehensive income (loss).~~

~~Continental Resources, Inc. and Subsidiaries~~

Notes ~~to Unaudited Condensed Consolidated Financial Statements~~

payable

~~Subsequent to March 31,~~In June 2020, the Company ~~repurchased and canceled additional amounts~~borrowed an aggregate of ~~its 2023 Notes and 2024 Notes. See~~ ~~Note 14. Subsequent Events~~ ~~for further information.~~

~~In February 2012, 20 Broadway Associates LLC, a wholly-owned subsidiary of the Company, borrowed $22~~$26.0 million under atwo 10-year amortizing term ~~loan~~loans secured by the Company’s corporate office building and its interest in parking facilities in Oklahoma City, Oklahoma. The ~~loan bears~~loans mature in May 2030 and bear interest at a fixed rate of ~~3.14%~~3.50% per ~~annum.~~annum through June 9, 2025, at which time the interest rate will be reset and fixed through the maturity date. Principal and interest are payable monthly through the ~~loan’s~~ maturity date of ~~February 26, 2022. Accordingly, approximately $2.5~~and, accordingly, $2.3 million is reflected as a current liability under the caption “Current portion of long-term debt” in the condensed consolidated balance sheets as of March 31, ~~2020.~~

The Company’s lease liabilities recognized on the balance sheet as a lessee totaled $12.6 million as of March 31, 2020 at discounted present value, which is comprised of the asset classes reflected in the table below. All leases recognized on the Company's balance sheet are classified as operating leases. The amounts disclosed herein primarily represent costs2021 associated with ~~properties operated by~~ the Company that are presented on a gross basis and do not reflect the Company's net proportionate share of such amounts. A portion of these costs have been or will be billed to other working interest owners. Once paid, the Company's share of these costs are included in property and equipment, production expenses, or general and administrative expenses, as applicable. The Company's leasing activities as a lessor are negligible.

In thousands Amount
Drilling rig commitments $ 6,048
Surface use agreements 5,091
Field equipment 1,105
Other 339
Total $ 12,583

loans.

~~Drilling rig commitments reflected above represent minimum payment obligations expected to be incurred on enforceable commitments with durations in excess of one year at the inception of the lease.~~

Minimum future commitments by year for the Company's operating leases as of March 31, 2020 are presented in the table below. Such commitments are reflected at undiscounted values and are reconciled to the discounted present value recognized on the balance sheet.

~~Continental Resources, Inc. and Subsidiaries~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

Additional information for the Company's operating leases is presented below. Lease costs are reflected at gross amounts and primarily represent costs incurred for drilling rigs, most of which are short term contracts that are not recognized as right-of-use assets and lease liabilities on the balance sheet. Variable lease costs primarily represent differences between minimum payment obligations and actual operating day-rate charges incurred by the Company for its long term drilling rig contracts. Short-term lease costs primarily represent operating day-rate charges for drilling rig contracts with durations of one year or less and month-to-month field equipment rentals.

In thousands, except weighted average data Three months ended March 31, 2020
Lease costs:
Operating lease costs $ 1,260
Variable lease costs 3,223
Short-term lease costs 51,348
Total lease costs $ 55,831

Other information:
Right-of-use assets obtained in exchange for new operating lease liabilities $ 7,002
Operating cash flows from operating leases included in lease liabilities 228
Weighted average remaining lease term as of March 31, 2020 (in years) 9.8
Weighted average discount rate as of March 31, 2020 4.1 %

Note ~~10.~~8. Commitments and Contingencies

Included below is a discussion of certain future commitments ~~and contingencies~~ of the Company as of March 31, ~~2020.~~2021.

Drilling rig commitments – As of March 31, ~~2020,~~2021, the Company has drilling rig contracts with various terms extending to ~~April~~November 2021. Future operating day-rate commitments as of March 31, ~~2020~~2021 total approximately ~~$36~~$8 million, of which ~~$33 million is expected to~~will be incurred in the remainder of ~~2020 and $3 million will be incurred in~~ 2021. A portion of these future costs will be borne by other interest owners. Such future commitments include minimum payment obligations with a discounted present value totaling $6.0 million that are required to be recognized on the Company's balance sheet at March 31, 2020 in accordance with ASC Topic 842 as discussed in ~~Note 9. Leases~~.

~~Other lease commitments –~~ ~~The Company has various other lease commitments primarily associated with surface use agreements and field equipment. See~~ ~~Note 9. Leases~~ ~~for additional information.~~

Transportation, gathering, and processing commitments – The Company has entered into transportation, gathering, and processing commitments to guarantee capacity on crude oil and natural gas pipelines and natural gas processing facilities. The commitments, which have varying terms extending as far as 2031, require the Company to pay per-unit transportation, gathering, or processing charges regardless of the amount of capacity used. Future commitments remaining as of March 31, ~~2020~~2021 under the arrangements amount to approximately ~~$2.11~~$1.46 billion, of which ~~$210~~$192 million is expected to be incurred in the remainder of ~~2020, $326 million in~~ 2021, ~~$329~~$272 million in 2022, ~~$331~~$272 million in 2023, ~~$298~~$234 million in 2024, $143 million in 2025, and ~~$615~~$346 million thereafter. A portion of these future costs will be borne by other interest owners. The Company is not committed under the above contracts to deliver fixed and determinable quantities of crude oil or natural gas in the future. These commitments do not qualify as leases under ASC Topic 842 and are not recognized on the Company's balance sheet.

Senior note redemption – On March 22, 2021, the Company announced its intention to redeem the remaining outstanding principal balance of its 2022 Notes subsequent to March 31, 2021. See Note 13. Subsequent Events for further discussion.

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

Litigation – The Company is involved in various legal proceedings including, but not limited to, commercial disputes, claims from royalty and surface owners, property damage claims, personal injury claims, regulatory compliance matters, disputes with tax authorities and other matters. While the outcome of these legal matters cannot be predicted with certainty, the Company does not expect them to have a material effect on its financial condition, results of operations or cash flows. As of March 31, ~~2020~~2021 and December 31, ~~2019,~~2020, the Company had recognized a liability within “Other noncurrent liabilities” of ~~$7.5~~$7.7 million and~~$8.7~~ $7.7 million, respectively, for various matters, none of which are believed to be individually significant. ~~See~~ ~~Note 14. Subsequent Events~~ ~~for discussion of a new legal matter involving the Company that was initiated subsequent to March 31, 2020.~~

Environmental risk – Due to the nature of the crude oil and natural gas business, the Company is exposed to possible environmental risks. The Company is not aware of any material environmental issues or claims.

~~Continental Resources, Inc. and Subsidiaries~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

Note ~~11.~~9. Stock-Based Compensation

The Company has granted restricted stock to employees and directors pursuant to the Continental Resources, Inc. 2013 Long-Term Incentive Plan, as amended ("2013 Plan"). The Company’s associated compensation expense, which is included in the caption “General and administrative expenses” in the unaudited condensed consolidated statements of ~~comprehensive income (loss),~~operations, was ~~$16.4~~$16.9 million and ~~$12.1~~$16.4 million for the three months ended March 31, ~~2020~~2021 and ~~2019,~~2020, respectively.

In March 2019, the Company amended and restated its 2013 Plan and ~~reserved~~specified 12,983,543 shares of common stock ~~that~~ may be issued pursuant to the amended plan. ~~The~~Subject to limited exceptions, the 2013 Plan allows previously issued shares to be reissued if such shares are subsequently forfeited ~~after issuance.~~or withheld to satisfy tax withholdings. As of March 31, ~~2020,~~2021, the Company had ~~10,871,733~~8,497,723 shares of common stock available for long-term incentive awards to employees and directors under the 2013 Plan.

Restricted stock is awarded in the name of the recipient and constitutes issued and outstanding shares of the Company’s common stock for all corporate purposes during the period of restriction and, except as otherwise provided under the 2013 Plan or agreement relevant to a given award, includes the right to vote the restricted stock and to receive dividends if any, subject to forfeiture. Restricted stock grants generally vest over periods ranging from 1 to 3 years.

A summary of changes in non-vested restricted shares outstanding for the three months ended March 31, ~~2020~~2021 is presented below.

Number of
non-vested
shares Weighted average
grant-date
fair value
Non-vested restricted shares outstanding at December 31, 2019 3,461,908
$ 46.82
Granted 2,454,235
28.41
Vested (925,568 ) 46.19
Forfeited (42,818 ) 39.88
Non-vested restricted shares outstanding at March 31, 2020 4,947,757
$ 37.87


	Number of non-vested shares	Weighted average grant-date fair value
Non-vested restricted shares outstanding at December 31, 2020	4,890,638	$	36.26
Granted	2,726,442	22.99
Vested	(1,278,334)	46.54
Forfeited	(65,380)	27.80
Non-vested restricted shares outstanding at March 31, 2021	6,273,366	$	28.49

The grant date fair value of restricted stock represents the closing market price of the Company’s common stock on the date of grant. Compensation expense for a restricted stock grant is determined at the grant date fair value and is recognized over the vesting period as services are rendered by employees and directors. The Company estimates the number of forfeitures expected to occur in determining the amount of stock-based compensation expense to recognize. There are no post-vesting restrictions related to the Company’s restricted stock. The fair value at the vesting date of restricted stock that vested during the three months ended March 31, ~~2020~~2021 was approximately ~~$24~~$29 million. As of March 31, ~~2020,~~2021, there was approximately ~~$117~~$111 million of unrecognized compensation expense related to non-vested restricted stock. This expense is expected to be recognized over a weighted average period of ~~1.9~~2.0 years.

Note ~~12.~~10. Shareholders' Equity

~~For~~During the three months ended March 31, 2020, the Company repurchased and retired approximately 8.1 million shares of its common stock at an aggregate cost of $126.9 million. ~~Through~~No share repurchases have been made subsequent to March 31, ~~2020, the~~2020. The Company ~~had~~has repurchased and retired a cumulative total of approximately 13.8 million shares at an aggregate cost of $317.1 million since the inception of its $1 billion share repurchase program in June 2019.

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.

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

On January 27, 2020 the Company declared a quarterly cash dividend of $0.05 per share on its outstanding common stock, which amounted to $18.4 million and was paid on February 21, 2020 to shareholders of record as of February 7, 2020.

~~To preserve cash in response to the significant reduction in crude oil prices and economic turmoil resulting from the COVID-19 pandemic, in April 2020 the Company’s quarterly~~See Note 13. Subsequent Events for discussion of a dividend ~~was suspended~~declaration made by the ~~Board of Directors until further notice.~~Company subsequent to March 31, 2021.

~~Continental Resources, Inc. and Subsidiaries~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

Note ~~13.~~11. Income Taxes

Income taxes are accounted for using the asset and liability method under which deferred income taxes are recognized for the future tax effects of temporary differences between financial statement carrying amounts and the tax basis of existing assets and liabilities using the enacted statutory tax rates in effect at period-end. The effect on deferred taxes for a change in tax rates is recognized in income in the period that includes the enactment date. The Company’s policy is to recognize penalties and interest related to unrecognized tax benefits, if any, in income tax expense.

The Company's provision (benefit) for income taxes and resulting effective tax rates were as follows for the periods presented.

Three months ended March 31,
2020 2019
Provision (benefit) for income taxes (in thousands) $ (52,235 ) $ 51,990
Effective tax rate 21.9 % 21.8 %

The Company computes its quarterly income tax provision (benefit) under the effective tax rate method based on applying an anticipated annual effective tax rate to year-to-date pre-tax income (loss), except for discrete items. Income taxes for discrete items are computed and recorded in the period in which the specific transaction occurs.

The Company's effective tax rate differs from the United States federal statutory tax rate due to the effect of state income taxes, equity compensation, changes in valuation allowances, and other tax items as reflected in the table below.

Three months ended March 31,
In thousands, except tax rates 2020 2019
Income (loss) before income taxes $ (239,019 ) $ 238,483
U.S. federal statutory tax rate 21.0 % 21.0 %
Expected income tax provision (benefit) based on U.S. federal statutory tax rate (50,194 ) 50,081
Items impacting the effective tax rate:
State and local income taxes, net of federal benefit (7,603 ) 7,798
Equity compensation 3,886
(8,318 )
Other, net (3,189 ) 2,429
Valuation allowance 4,865
—
Provision (benefit) for income taxes $ (52,235 ) $ 51,990
Effective tax rate 21.9 % 21.8 %

~~The Company reduces its~~


	Three months ended March 31,
In thousands, except tax rates	2021			2020
Income (loss) before income taxes	$	340,803		$	(239,019)
U.S. federal statutory tax rate	21.0		%	21.0		%
Expected income tax provision (benefit) based on U.S. federal statutory tax rate	71,569			(50,194)
Items impacting the effective tax rate:
State and local income taxes, net of federal benefit	12,895			(7,603)
Equity compensation	5,990			3,886
Other, net	(5,031)			(3,189)
Change in valuation allowance	(4,895)			4,865
Provision (benefit) for income taxes	$	80,528		$	(52,235)
Effective tax rate	23.6		%	21.9		%

In assessing the realizability of deferred tax assets ~~by a valuation allowance if, based upon~~ the ~~weight of available evidence,~~Company must consider whether it is ~~more-likely-than-not~~more likely than not that ~~the Company will not realize~~ some portion or all of the deferred tax ~~assets.~~assets will not be realized. The Company ~~considers relevant evidence,~~applies judgment to determine the weight of both positive and negative evidence in order to ~~determine the need for~~conclude whether a valuation ~~allowance. Information evaluated includes~~allowance is necessary for its deferred tax assets. In determining whether a valuation allowance is required, the Company considers, among other factors, the Company's financial position, ~~and~~ results of operations, ~~for the current and preceding years, the availability~~projected future taxable income, reversal of existing deferred tax liabilities against deferred tax assets, and tax carrybacks, as well as an evaluation of currently available information about future years. The Company determined it was more-likely-than-not that a portion of its Oklahoma NOL carryforwards would not be able to be utilized before expiration, andplanning strategies. During 2020, a valuation allowance of ~~approximately $4.9~~$14.5 million ~~was~~had been established for the deferred tax ~~assets~~asset associated with a portion of the Company's Oklahoma state net operating loss carryforwards. In the first quarter of 2021, the Company reassessed the realizability of the deferred tax asset related to Oklahoma state net operating loss carryforwards and determined it was more likely than not that such ~~NOL carryforwards.~~assets would be realized. Therefore, it was determined that the previously recorded valuation allowance in 2020 should be released throughout 2021, with $4.9 million of the release being recognized during the first quarter of 2021.

The Company will continue to evaluate both the positive and negative evidence on a quarterly basis in determining the need for a valuation allowance with respect to its deferred tax assets. Changes in positive and negative evidence, including differences between estimated and actual results, could result in changes in the valuation of our deferred tax assets that could have a

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

material impact on our consolidated financial statements. Changes in existing tax laws could also affect actual tax results and the realization of deferred tax assets over time.

Note 12. Property Acquisition

On March 4, 2021, the Company acquired undeveloped leasehold and producing properties in the Powder River Basin of Wyoming for $206.6 million, consisting of a $21.5 million escrow deposit paid in December 2020 upon execution of a definitive purchase agreement and a $185.1 million payment made at closing in March 2021. The acquisition included approximately 130,000 net acres and producing properties with production totaling approximately 7,200 net barrels of oil equivalent per day at the time of closing. The $21.5 million escrow deposit paid in December 2020 is included in the caption "Other noncurrent assets" on the Company's balance sheet at December 31, 2020, which was subsequently reclassified to "Net property and equipment" on the closing date. The Company recognized approximately $4.9 million of asset retirement obligations and $12.4 million of right-of-use assets and corresponding lease liabilities as of March 31, 2021 associated with the acquired properties.

Note ~~14.~~13. Subsequent Events

~~In March 2020, the World Health Organization declared a global pandemic related to the proliferation~~Full redemption of ~~COVID-19 (novel coronavirus).~~ The adverse economic effects of the COVID-19 pandemic continue to evolve as of the filing of this report. The catastrophe caused by the COVID-19 pandemic has materially decreased global and domestic demand for crude oil based on changes in consumer behavior and restrictions implemented by governments to mitigate the pandemic. This destruction of2022 Notes

~~Continental Resources, Inc. and Subsidiaries~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

~~demand has led to an unprecedented decline in crude oil prices. In response to these developments,~~On April 22, 2021, the Company ~~began shutting in production in April 2020 and currently has approximately 70%~~redeemed the remaining $230.8 million principal amount of its operated crude oil production and associated natural gas shut-in. The duration and extent of our production shut-ins are being evaluated on an ongoing basis and are subject to change as market conditions evolve. Given the uncertain duration of the catastrophe caused by the COVID-19 pandemic and the potential for a longer-term impact on consumer behaviors, the Company is not able to estima~~te the effects of the pandemic~~outstanding 2022 Notes using proceeds from lower-rate borrowings on its ~~results~~credit facility.

Dividend declaration

On April 27, 2021, the Company's Board of ~~operations, financial condition, or cash flows for~~Directors approved the ~~remainder~~reinstatement of ~~2020. Nevertheless,~~ a ~~near term material negative impact~~quarterly dividend of $0.11 per share on the Company's ~~production, revenues, cash flows, and earnings is certain~~outstanding common stock, payable on May 24, 2021 to ~~occur for the second quarter~~shareholders of ~~2020.~~record as of May 10, 2021.

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. In its petition Casillas alleges the Company breached a Purchase and Sale Agreement (“PSA”) to purchase oil and gas interests in Oklahoma for $200 million. Casillas seeks specific performance. The Company terminated the PSA due to Casillas’ breach of the agreement and denies the allegations and will vigorously defend the claims. The Company will also seek affirmative relief. The Company is not currently able to estimate what impact, if any, the ultimate resolution of the action will have on its financial condition, results of operations, or cash flows due to the preliminary status of the matter.

In April 2020, the Company repurchased and canceled an additional $17.0 million face value of its 2023 Notes at an aggregate cost of $9.8 million and an additional $82.0 million face value of its 2024 Notes at an aggregate cost of $43.1 million, in each case, including accrued and unpaid interest to the repurchase dates. The Company estimates it will recognize pre-tax gains on extinguishment of debt related to the April 2020 repurchases totaling $47.0 million, which include the pro-rata write-off of deferred financing costs and unamortized debt discount associated with the notes. The reduction in debt and associated extinguishment gains from the April 2020 repurchases will be reflected in the Company's second quarter 2020 results.

ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with the unaudited condensed consolidated financial statements and notes thereto included elsewhere in this report and our historical consolidated financial statements and notes included in our Form 10-K for the year ended December 31, ~~2019.~~

As a result of the catastrophic impact from the COVID-19 pandemic on global and domestic demand for crude oil, our operating results for the first quarter of 2020 discussed below are not indicative of the Company’s expected results for the remainder of 2020. While a material negative impact is expected for the second quarter of 2020, given the uncertainty around the progression of the pandemic, it is difficult to predict the extent to which it will continue to have a significant impact on the Company’s performance during the remainder of 2020 and beyond.

The following discussion and analysis includes forward-looking statements and should be read in conjunction with the risk factors described in Part II, Item 1A. Risk Factors included in this report, if any, and in our Form 10-K for the year ended December 31, ~~2019,~~2020, 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 crude oil and natural gas production and revenues for the first quarter of 2021 were impacted by severe winter weather and freezing temperatures in the southern United States in February 2021 as further discussed below and may not be indicative of future results.

We are an independent crude oil and natural gas company engaged in the exploration, development and production of crude oil and natural gas. Additionally, we pursue the acquisition and management of perpetually owned minerals located in certain of our key operating areas. We derive the majority of our operating income and cash flows from the sale of crude oil and natural gas and expect this to continue in the future. Our operations are primarily focused on exploration and development activities in the Bakken field of North Dakota and Montana, the Powder River Basin of Wyoming, 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~~First Quarter 2021 Highlights

Financial and ~~Outlook~~operating highlights for the first quarter of 2021 are summarized below. Our first quarter results underscore our continued focus on maximizing cash flow generation, reducing debt, maintaining low-cost capital efficient operations, achieving consistent asset performance, and delivering shareholder capital returns.

~~Crude oil prices decreased significantly~~•Generated $1.04 billion in ~~March~~cash flows from operations, a 57% increase over the 2020 first quarter;

•Reduced outstanding debt by $560 million, or 10%, in the first quarter;

•Continued to maintain low cost operations, with production expenses averaging $3.35 per Boe for the quarter;

•Completed acquisition of Powder River Basin properties in Wyoming for $207 million, adding 130,000 net acres and ~~continued to decrease~~production of approximately 7,200 Boe per day as of the closing date; and

•Reinstated quarterly dividend in April ~~2020 to historically low levels. This decline is attributable to a number~~2021 at $0.11 per share of factors, most notably the reduced global and domestic demand for crude oil caused by the impact of the COVID-19 pandemic and resulting changes in consumer behavior and restrictions implemented by governments to mitigate the pandemic. Additionally, in March 2020 the alliance between the Organization of Petroleum Exporting Countries ("OPEC") and Russia on production cuts broke down as both sides were unable to reach an agreement on how much to restrict production in order to stabilize crude oil prices. As a result, Saudi Arabia subsequently announced it would significantly increase production and cut the prices at which it sells crude oil. These actions, coupled with the economic impact and uncertainty from COVID-19, resulted in simultaneous supply and demand shocks that triggered a sudden and drastic decrease in crude oil prices in March 2020. In April 2020, the alliance between OPEC and Russia reached an agreement to reduce production and will reconvene in June 2020 to determine whether further reductions are necessary. It is uncertain what impact these production cuts, along with production cuts in the United States and elsewhere, will have on crude oil prices and whether such cuts will be sufficient to offset the demand destruction caused by the COVID-19 pandemic. Given the significant uncertainty around the timing and path of recovery from the pandemic, we have withdrawn our financial and operational guidance for 2020.

Company management is actively evaluating the impact of COVID-19 on its operations, financial condition, suppliers, industry, and workforce. In light of the challenges facing our business and industry, we have acted to implement cost saving initiatives in order to preserve financial flexibility, liquidity, and the strength of our balance sheet. We have significantly reduced our capital spending and continue to diligently evaluate and adjust our spending plans on an ongoing basis based on market conditions. As of April 30, 2020, we have reduced our operated rig count by 70% since the beginning of the year. Further, we currently have zero completion crews running in the Bakken and plan to average one completion crew in the South for the remainder of 2020. We are committed to the responsible stewardship of our assets and, with minimal long-term service or supply contracts in place, have the ability to reduce our spending in response to changes in market conditions to preserve our assets and better align our spending with expected available cash flows.

In response to the significant reduction in crude oil prices and expectations for crude oil transportation and storage limitations, we began shutting in production in April and currently have approximately 70% of our operated crude oil production and associated natural gas shut-in. The duration and extent of our production shut-ins are being evaluated on an ongoing basis and are subject to change as market conditions evolve. Other operators are also shutting in production, which will adversely impact production originating from our non-operated properties. These actions, coupled with historically low crude oil prices, are expected to result in a material reduction in our revenues and cash flows, the amount of which is uncertain due to ongoing

volatility in commodity prices and uncertainty regarding the extent and duration of production shut-ins. The duration and magnitude of the effects from the COVID-19 pandemic are unknown and we are unable to predict with certainty when production shut-ins and other business impacts may end.

Our leadership team has significant experience with operating in challenging commodity price environments. The depth and quality of our asset base, the optionality provided by our predominant amount of acreage held by production, and our financial strength allow uscommon stock to be adaptable in a variety of price environments. We will remain flexible as we monitor and adapt to market conditions and plan to be well-positioned when market conditions improve. See the subsequent section titled ~~Liquidity and Capital Resources~~ ~~for additional discussion of our financial condition.~~paid on May 24, 2021.

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

Three months ended March 31,
2020 2019
Average daily production:
Crude oil (Bbl per day) 200,671
193,921
Natural gas (Mcf per day) 961,022
829,891
Crude oil equivalents (Boe per day) 360,841
332,236
Average net sales prices (1):

Crude oil ($/Bbl) $ 39.64
$ 50.05
Natural gas ($/Mcf) $ 0.90
$ 2.56
Crude oil equivalents ($/Boe) $ 24.44
$ 35.56
Crude oil net sales price discount to NYMEX ($/Bbl) $ (6.26 ) $ (4.77 )
Natural gas net sales price discount to NYMEX ($/Mcf) $ (1.05 ) $ (0.60 )
Production expenses ($/Boe) $ 3.61
$ 3.59
Production taxes (% of net crude oil and natural gas sales) 8.9 % 8.2 %
Depreciation, depletion, amortization and accretion ($/Boe) $ 16.35
$ 16.60
Total general and administrative expenses ($/Boe) $ 1.31
$ 1.60


	Three months ended March 31,
	2021			2020
Average daily production:
Crude oil (Bbl per day)	151,852			200,671
Natural gas (Mcf per day)	936,540			961,022
Crude oil equivalents (Boe per day)	307,942			360,841
Average net sales prices (1):
Crude oil ($/Bbl)	$	53.09		$	39.64
Natural gas ($/Mcf)	$	5.56		$	0.90
Crude oil equivalents ($/Boe)	$	43.11		$	24.44
Crude oil net sales price discount to NYMEX ($/Bbl)	$	(4.52)		$	(6.26)
Natural gas net sales price premium (discount) to NYMEX ($/Mcf)	$	2.87		$	(1.05)
Production expenses ($/Boe)	$	3.35		$	3.61
Production taxes (% of net crude oil and natural gas sales)	7.0		%	8.9		%
Depreciation, depletion, amortization and accretion ($/Boe)	$	18.35		$	16.35
Total general and administrative expenses ($/Boe)	$	1.90		$	1.31

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

Three months ended March 31, ~~2020~~2021 compared to the three months ended March 31, ~~2019~~2020

Results of Operations

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

The following table summarizes the changes in our average daily Boe production by major operating area for the first quarter period.

In mid-February 2021, severe winter weather and freezing temperatures in the southern United States impacted our operations in Oklahoma, resulting in the curtailment of a portion of our production, delays in drilling and completion of wells, and other operational constraints, which adversely impacted our first quarter 2021 production by approximately 6,000 Boe per day (60% of which was crude oil). We have restored our curtailed production and estimate our production for the second quarter of 2021 will average between 160,000 and 165,000 barrels of oil per day and between 920,000 and 940,000 Mcf of natural gas per day.

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

The ~~increase~~25% decrease in crude oil production for the 2021 first quarter compared to the 2020 first quarter was ~~primarily~~ driven by reduced drilling and completion activities over the past year in response to the economic turmoil from the COVID-19 pandemic coupled with the previously described weather-related production curtailments in February 2021, which led to a ~~1,672~~3,514 MBbls, or ~~83%, increase in SCOOP production due to new well completions in our oil-weighted Project SpringBoard. This increase was partially offset by a 729 MBbls, or 5%~~27%, decrease in Bakken crude oil production, ~~due~~a 985 MBbls, or 27%, decrease in SCOOP crude oil production, and a 183 MBbls, or 27%, decrease in STACK crude oil production compared to variations in the timing of new well completions and well ownership changes between periods. First quarter 2019 production in the Bakken benefitted from initial production on large pad projects and additional production from increased ownership interests with no amounts of a similar magnitude in the 2020 first quarter.

The ~~increase~~February 2021 production curtailments and limited drilling and completion activities over the past year also impacted our natural gas production, leading to a 4% decrease in natural gas production for the 2021 first quarter compared to the 2020 first ~~quarter was driven by a 12,302 MMcf, or 50%, increase in SCOOP~~quarter. Natural gas production in ~~conjunction with~~ the ~~aforementioned increase~~Bakken decreased 2,222 MMcf, or 7%, and natural gas production in ~~SCOOP crude oil production over~~STACK decreased 3,351 MMcf, or 17%, from the prior year first quarter. Additionally, natural gas production from the Bakken play increased 6,705 MMcf, or 28%, due to an increase in gas capture and resulting increase in volumes delivered to market compared to the prior period. These ~~increases~~decreases were partially offset by a ~~5,924~~2,115 MMcf, or ~~23%~~6%, ~~decrease~~increase in ~~STACK~~SCOOP natural gas production.

In the second quarter of 2020 we shifted our rigs to gas-weighted areas in Oklahoma to capitalize on improvements in market prices for natural gas. These actions contributed to an increase in our natural gas production ~~from natural declines and limited natural gas drilling activities~~as a percentage of total production in the ~~play.~~

~~Our level of production achieved in~~2021 first quarter compared to the 2020 first ~~quarter is not indicative~~quarter. Based on drilling and completion plans, we project our production will become more oil-weighted in the second half of ~~results expected for the remainder of 2020 due~~2021 compared to the ~~aforementioned shut-in of our production. Other operators are also shutting in production. The duration and magnitude~~first half of the ~~economic effects from COVID-19 are unknown and we are unable to predict with certainty when the production shut-ins and other business impacts may end.~~year.

Net crude oil and natural gas sales and related net sales prices presented below are non-GAAP measures. See the subsequent section titled Non-GAAP Financial Measures for a discussion and calculation of these measures.

Net crude oil and natural gas sales. Net crude oil and natural gas sales totaled ~~$802.2 million~~$1.20 billion for the first quarter of ~~2020,~~2021, a ~~24% decrease~~49% increase compared to net sales of ~~$1.06 billion~~$802.2 million for the ~~2019~~2020 first quarter due to a significant ~~decrease~~increases in net sales prices partially offset by ~~higher~~decreases in sales volumes as discussed below.

Total sales volumes for the first quarter of ~~2020 increased 3,005~~2021 decreased 5,052 MBoe, or ~~10%~~15%, compared to the ~~2019~~2020 first quarter, reflecting ~~new well completions~~the impact of reduced drilling and completion activities over the past ~~year.~~year in response to economic turmoil from the COVID-19

pandemic and the previously described production curtailments in February 2021. For the first quarter of ~~2020,~~2021, our crude oil sales volumes ~~increased 5% from~~decreased 25% compared to the ~~comparable 2019 period,~~2020 first quarter, while our natural gas sales volumes ~~increased 17%~~decreased 4%.

Our crude oil net sales prices averaged ~~$39.64~~$53.09 per barrel in the ~~2020~~2021 first quarter, ~~a decrease~~an increase of ~~21%~~34% compared to ~~$50.05~~$39.64 per barrel for the ~~2019~~2020 first quarter due to ~~lower~~an increase in market prices and ~~wider~~improved price differentials. The differential between NYMEX West Texas Intermediate ("WTI") calendar month prices and our realized crude oil net sales prices averaged $4.52 per barrel for the 2021 first quarter compared to $6.26 per barrel for the 2020 first ~~quarter compared to $4.77 per barrel for the 2019 first~~ quarter. The ~~increased~~2020 first quarter price differential ~~reflects~~was impacted by adverse changes in supply and demand fundamentals ~~and~~from the early economic effects ~~from~~of COVID-19 and ~~OPEC~~ actions taken by the Organization of Petroleum Exporting Countries and Russia that negatively impacted location differentials and price realizations ~~compared to~~in the prior year ~~period.~~first quarter.

Our natural gas net sales prices averaged $5.56 per Mcf for the 2021 first quarter compared to $0.90 per Mcf for the 2020 first quarter ~~a decrease of 65% compared to $2.56 per Mcf for the 2019 first quarter~~ due to ~~lower~~an increase in market prices and ~~reduced~~improved price ~~realizations.~~differentials. The ~~discount~~difference between our net sales prices and NYMEX Henry Hub calendar month natural gas prices ~~weakened~~was a premium of $2.87 per Mcf for the 2021 first quarter compared to a discount of $1.05 per Mcf for the 2020 first ~~quarter compared~~quarter. The effects of the previously described winter storm in February 2021 led to ~~$0.60 per Mcf~~a period of increased spot prices for ~~the 2019 first quarter. We sell the majority of our operated~~residue natural gas ~~production to midstream customers at lease locations based on market prices~~that resulted in a significant improvement in our price realizations in the ~~field where the sales occur. The field markets are impacted by~~

~~residue gas~~2021 first quarter relative to benchmark prices and prior periods. Additionally, prices for natural gas liquids ~~("NGLs") prices at secondary, downstream markets. NGL prices in 2020~~ have ~~decreased significantly~~increased compared to ~~2019~~first quarter 2020 levels in conjunction with ~~decreased~~increased crude oil prices and other factors, resulting in ~~reduced~~improved price realizations for our natural gas sales ~~stream relative~~stream. For the remainder of 2021 we project our natural gas net sales prices will be a discount to Henry Hub benchmark ~~prices.~~prices of between zero and $0.50 per Mcf.

Derivatives. Changes in market prices during the first quarter of 2021 had an overall unfavorable impact on the fair value of our derivatives, which resulted in negative revenue adjustments of $43.5 million for the period, representing $29.4 million of cash losses and $14.1 million of unsettled non-cash losses. We had no outstanding derivative instruments during the first quarter of 2020.

Crude oil and natural gas service operations. Our crude oil and natural gas service operations consist primarily of revenues associated with water gathering, recycling, and disposal activities, which are impacted by our production volumes and the timing and extent of our drilling and completion projects. Revenues associated with such activities decreased $6.3 million, or 35%, from $18.1 million for the first quarter of 2020 ~~are not indicative of results expected~~to $11.8 million for the ~~remainder~~first quarter of ~~2020~~2021 due to ~~the significant decline~~reduced water handling activities resulting from a decrease in ~~crude oil prices beginning in March~~production and ~~the aforementioned shut-in of production. We expect these factors will have a significant adverse impact on future revenues in 2020; however, we are unable to estimate such impact due~~reduced completion activities compared to the ~~uncertain duration and magnitude of~~2020 first quarter. The decreased activities also resulted in a reduction in service-related expenses compared to the ~~effects of the COVID-19 pandemic and ongoing volatility in commodity prices.~~prior period.

Operating Costs and Expenses

Production Expenses. Production expenses ~~increased $11.5~~decreased $25.4 million, or ~~11%~~21%, from ~~$107.0 million for the first quarter of 2019 to~~ $118.5 million for the first quarter of 2020 ~~primarily due~~ to ~~an increase~~$93.1 million for the first quarter of 2021. This decrease resulted from reduced service costs being incurred in conjunction with lower sales volumes, cost control efforts, operating efficiency gains, and a higher portion of our production coming from wells in Oklahoma which typically have lower operating costs compared to wells in the ~~number~~Bakken, all of ~~producing wells and related 10% increase~~which led to a decrease in ~~sales volumes. Production~~our production expenses on a per-Boe basis ~~averaged~~to $3.35 per Boe for the 2021 first quarter compared to $3.61 per Boe for the 2020 first ~~quarter, consistent with $3.59 per Boe recognized for the 2019 first~~ quarter.

We are unable to estimate what impact the aforementioned production shut-ins will have on our production expenses for the remainder of 2020. The expected decrease in our production volumes may not result in a corresponding decrease in production expenses as certain operating costs are fixed in nature and may continue to be incurred in the absence of production. Additionally, we cannot estimate the timing or magnitude of expenses that will be incurred to restart some or all of our shut-in wells.

Production Taxes. Production taxes ~~decreased $15.2~~increased $12.8 million, or 18%, to $84.0 million for the first quarter of 2021 compared to $71.2 million for the first quarter of 2020 ~~compared to $86.4 million for the first quarter of 2019 primarily~~ due to a ~~22% decrease~~45% increase in crude oil and natural gas ~~sales.~~sales partially offset by a decrease in our average production tax rate. Our production taxes as a percentage of net crude oil and natural gas sales ~~increased~~decreased from ~~8.2% for the first quarter of 2019 to~~ 8.9% for the first quarter of 2020 ~~primarily resulting from the aforementioned increase in natural gas production volumes in North Dakota Bakken compared~~ to the prior period. Natural gas production taxes in North Dakota are based on a per-Mcf rate applied to the quantity of volumes produced rather than being derived from the wellhead value of sales, which resulted in higher natural gas production taxes from increased North Dakota production despite lower revenues, thereby increasing our average production tax rate. Our production taxes for the 2020 second quarter are expected to be lower than the 2020 first quarter due to an expected decline in production and revenues as discussed above, the impact of which is uncertain.

~~Exploration expenses. Exploration expenses, which consist primarily of exploratory geological and geophysical costs and dry hole costs that are expensed as incurred, increased $9.8 million to $11.6 million~~7.0% for the first quarter of ~~2020~~2021 primarily resulting from an increase in the proportion of our revenues being generated in Oklahoma in the current period, which has lower production tax rates compared to $1.8 million for the first quarter of 2019 due to changes in the timing and extent of our exploration-related activities compared to the prior year period. The 2020 first quarter includes $6.3 million of dry hole costs associated with an unsuccessful exploratory well with no comparable dry hole costs incurred in the prior year period.North Dakota.

Depreciation, Depletion, Amortization and Accretion. Total DD&A ~~increased $41.7~~decreased $27.1 million, or 8%5%, to $509.6 million for the first quarter of 2021 compared to $536.7 million for the first quarter of 2020 ~~compared to $495.0 million for the first quarter of 2019~~ primarily due to a ~~10% increase~~15% decrease in total sales ~~volumes.~~volumes, the impact of which was partially offset by an increase in our DD&A rate per Boe as further discussed below. The following table shows the components of our DD&A on a unit of sales basis for the periods presented.

Estimated proved reserves are a key component in our computation of DD&A expense. Proved reserves are determined using the unweighted arithmetic average of the first-day-of-the-month commodity prices for the preceding twelve months as required by SEC rules. Holding all other factors constant, if proved reserves are revised downward due to commodity price declines or ~~for~~ other reasons, the rate at which we record DD&A expense increases. Conversely, if proved reserves are revised upward, the rate at which we record DD&A expense decreases.

IfDownward revisions of proved reserves at year-end 2020 prompted by a significant decrease in average commodity prices ~~remain at current levels or decline further, downward revisions of our proved reserves are expected to occur later in 2020, which may be significant~~ and ~~would result~~other factors resulted in an increase in our DD&A rate for ~~subsequent periods as~~crude oil and natural gas properties in the first quarter of 2021 compared to the ~~2020~~first quarter of 2020.

NYMEX WTI crude oil and Henry Hub natural gas first-day-of-the-month commodity prices in 2021 have been higher than average prices for the full year of 2020. If commodity prices remain at current levels for an extended period, upward price-related revisions of proved reserves may occur in the future, which may be significant and could result in a decrease in our DD&A rate relative to the 2021 first quarter. We are unable to predict the timing and amount of future reserve revisions ~~nor~~or the impact such revisions may have on our future DD&A rate.

Property Impairments. ~~Property~~Total property impairments ~~increased $197.2~~decreased $211.1 million to $11.4 million for the first quarter of 2021 compared to $222.5 million for the first quarter of 2020, ~~compared to $25.3 million for the first quarter of 2019,~~primarily reflecting ~~higher~~lower proved property impairments in the current period. No proved property impairments were recognized in the 2021 first quarter as ~~described below.~~

~~Impairments~~estimated future net cash flows were determined to be in excess of cost basis due to improved commodity prices, while proved ~~oil and gas~~property impairments totaled $205.5 million in the 2020 first quarter. Additionally, impairments of unproved properties ~~totaled $181.0~~decreased $5.5 million ~~for~~in the 2021 first quarter compared to the 2020 first quarter, ~~which resulted from the significant decrease~~reflecting changes in commodity prices during the 2020 first quarter that indicated the carrying values for certain fields were not recoverable. The impairments were recognized on legacy properties in the Red River Units ($166.5 million) and various non-core properties in the North and South regions ($14.5 million). Additionally, in response to decreased crude oil prices we recognized a $24.5 millionimpairment in the 2020 first quarter to reduce the value of our crude oil inventory to estimated net realizable value at March 31, 2020. There were no proved property impairments recognized in the first quarter of 2019.

Commodity price assumptions used for the March 31, 2020 impairment calculations were based on publicly available average annual forward commodity strip prices through year-end 2024 and were then escalated at 3% per year thereafter. At March 31, 2020, strip prices averaged $38.15 per barrel for crude oil and $2.35 per Mcf for natural gas over the period from the present through year-end 2024. Further, at March 31, 2020 the strip prices for the individual year of 2024 averaged $43.17 per barrel and $2.44 per Mcf. If forward commodity prices materially decrease from these levels for an extended period, additional impairments of proved properties may be recognized in the future. Because of the uncertainty inherent in the numerous factors utilized in determining fair value, we cannot predict the timing and amount of future impairment charges, if any.

~~Impairments~~management's estimates of unproved properties ~~decreased $8.3 million, or 33%,~~not expected to ~~$17.0 million for the 2020 first quarter compared~~be transferred to~~$25.3 million for the 2019 first quarter due to a reduction in the balance of unamortized leasehold costs~~ proved properties over the ~~past year.~~ lives of the leases.

General and Administrative Expenses. Total G&A expenses ~~decreased $4.7~~increased $9.9 million, or ~~10%~~23%, to $52.8 million for the first quarter of 2021 compared to $42.9 million for the first quarter of ~~2020 compared to $47.6 million for the first quarter of 2019.~~ 2020.

Total G&A expenses include non-cash charges for equity compensation of ~~$16.4 million and $12.1~~$16.9 million for the first ~~quarters~~quarter of ~~2020 and 2019, respectively.~~2021, consistent with $16.4 million for the first quarter of 2020. G&A expenses other than equity compensation totaled $35.9 million for the 2021 first quarter, an increase of $9.4 million, or 35%, compared to $26.5 million for the 2020 first ~~quarter, a decrease of $9.0 million, or 25%,~~quarter. This increase was primarily due to an increase in employee benefits coupled with lower overhead recoveries from joint interest owners driven by reduced drilling, completion, and production activities compared to ~~$35.5 million for~~ the ~~2019~~2020 first quarter.

The following table shows the components of G&A expenses on a unit of sales basis for the periods presented.

The decrease in G&A expenses other than equity compensation in 2020 was primarily due to a reduction in employee benefits and other efforts to reduce spending in response to significantly reduced commodity prices and economic turmoil from the COVID-19 pandemic. This decrease, coupled with the 10% increase in our sales volumes, resulted in lower G&A expenses on a per-Boe basis compared to the prior year period.

The increase in equity compensation expense in 2020 was due to additional grants of restricted stock awards coupled with higher forfeitures of unvested restricted stock in the 2019 first quarter that resulted in lower equity compensation expense for that period.

~~Net (gain) loss on sale of assets and other~~. In the first quarter of 2020, we paid a deposit and transaction fees totaling $5.3 million associated with a potential property acquisition that was terminated by the Company. Such amounts were expensed and are included in the caption "Net (gain) loss on sale of assets and other."


	Three months ended March 31,
$/Boe	2021		2020
General and administrative expenses	$	1.29	$	0.81
Non-cash equity compensation	0.61		0.50
Total general and administrative expenses	$	1.90	$	1.31

Interest Expense. Interest expense ~~decreased $4.2~~totaled $65.0 million ~~or 6%, to~~for the first quarter of 2021, consistent with $63.6 million for the first quarter of ~~2020 compared~~2020. We reduced our outstanding debt by $560 million during the 2021 first quarter and expect our interest expense for the remaining quarterly periods of 2021 to ~~$67.8 million for~~be lower than the first quarter ~~of 2019 due to a decrease in total outstanding debt. Our weighted average outstanding debt balance was $5.5 billion for the 2020~~amount. The 2021 first quarter ~~compared to $5.8 billion for the 2019 first quarter. We expect our average outstanding debt balance to increase for the 2020 second quarter relative to the 2020 first quarter as a consequence~~includes $3.2 million of ~~the COVID-19 pandemic that has led to reduced cash flows and higher credit facility borrowings. This increase is expected to result in higher~~ interest expense ~~the amount~~associated with our 2022 Notes that were redeemed as discussed in Note 7. Long-Term Debt and ~~duration of which are uncertain. Our total debt amounted~~Note 13. Subsequent Events in Notes to ~~$6.07 billion at April 30, 2020 with a weighted average interest rate of 4.2%.~~Unaudited Condensed Consolidated Financial Statements.

Income Taxes. For the first quarters of ~~2020~~2021 and ~~2019~~2020 we provided for income taxes at a combined federal and state tax rate of 24.5% of our pre-tax income/~~loss generated by our operations in~~loss. We recorded an income tax provision of $80.5 million for the ~~United States. We recorded~~2021 first quarter and an income tax benefit of $52.2 million for the 2020 first quarter, ~~and an income tax provision of $52.0 million for the 2019 first quarter,~~ which resulted in effective tax rates of ~~21.9%~~23.6% and ~~21.8%~~21.9%, respectively, after taking into account statutory tax rates, permanent taxable differences, tax effects from equity compensation, changes in valuation allowances, and other items. See Notes to Unaudited Condensed Consolidated

Financial Statements–Note ~~13.~~11. Income Taxes for a summary of the sources and tax effects of items comprising our effective tax rates.

Liquidity and Capital Resources

Our primary sources of liquidity have historically been cash flows generated from operating activities, financing provided by our credit facility and the issuance of debt securities. Additionally, ~~in recent years~~ asset dispositions and joint development arrangements have provided a source of cash flow for use in reducing debt and enhancing liquidity.In light of the challenges facing our business and industry, we ~~will~~ remain committed to operating in a responsible manner to preserve financial flexibility, liquidity, and the strength of our balance sheet. We intend to continue reducing our long-term debt using available cash flows from operations and/or proceeds from potential sales of assets or through joint development arrangements; however, no assurance can be given that such transactions will occur.

Based on our planned capital spending, our forecasted cash flows and projected levels of indebtedness, we expect to maintain compliance with the covenants under our credit facility and senior note indentures. Further, based on current market indications, we expect to meet in the ordinary course of business other contractual cash commitments to third parties as of March 31, ~~2020,~~2021, including those described in Note ~~10.~~8. Commitments and Contingencies in Notes to Unaudited Condensed Consolidated Financial Statements, recognizing we may be required to meet such commitments even if our business plan assumptions were to change. We monitor our capital spending closely based on actual and projected cash flows and have the ability to reduce spending or dispose of assets if needed to preserve liquidity and financial flexibility to fund our operations.

Cash flows ~~provided by~~from operating activities

Net cash provided by operating activities ~~totaled $663.8~~increased $376 million, ~~and $721.5~~or 57%, to $1.04 billion for the first quarter of 2021 compared to $664 million for the ~~three months ended March 31,~~first quarter of 2020 ~~and 2019, respectively. The decrease in operating cash flows was~~ primarily due to a ~~decrease~~$385 million increase in crude oil and natural gas revenues due to the previously described increases in commodity prices ~~coupled with increases~~ in ~~production expenses and transportation expenses from higher sales volumes and lower cash gains on matured natural gas derivatives. The reduced cash flows from these factors were~~the current period. This increase was partially offset by ~~lower production taxes and interest expenses~~a $29 million increase in realized cash losses on matured commodity derivatives in the 2021 first quarter compared to the ~~2019 period.~~2020 first quarter.

~~Our~~Based on current market indications, we expect our operating cash flows for the remainder of 2021 will continue to be higher than 2020 levels, as our 2020 results were significantly impacted by the economic effects from the COVID-19 pandemic on crude oil demand and prices which led to material reductions in our production, revenues, and operating cash flows in 2020.

Cash flows from investing activities

Net cash used in investing activities decreased $279 million, or 39%, to $428 million for the first quarter of 2021 compared to $707 million for the first quarter of 2020, ~~are not indicative of results expected~~reflecting our focus on maintaining capital spending discipline to maximize cash flow generation for ~~the remainder of 2020 due to an expected decline in production and revenues as discussed above. We expect these factors will have a significant adverse impact on future~~debt reduction. Our cash flows in 2020; however, we are unable to estimate such impact due to the uncertain duration of the effects of the COVID-19 pandemic, ongoing volatility in commodity prices, and uncertainty regarding the extent and duration of production shut-ins.

~~Cash~~ flows used in investing activities for the 2021 first quarter include $185.1 million paid in March 2021 to acquire properties in the Powder River Basin of Wyoming as discussed in Notes to Unaudited Condensed Consolidated Financial Statements–Note 12. Property Acquisition. Our non-acquisition capital expenditures for full year 2021 are budgeted to be $1.4 billion compared to $1.2 billion of non-acquisition capital spending for full year 2020.

Cash flows from financing activities

Net cash used in ~~investing~~financing activities totaled $706.7 million and $753.1 million for the three months ended March 31, 2020 and 2019, respectively. The decrease in spending resulted from changes in the timing of our allocation of annual capital spending between periods, along with spending reductions initiated toward the end of the 2020 first quarter in response to decreased crude oil prices and economic uncertainty from the COVID-19 pandemic. Our level of capital spending for the first quarter of ~~2020 is not expected~~2021 totaled $564 million, primarily consisting of $400 million of cash used to redeem a portion of our 2022 Notes in January 2021 and $160 million of net repayments on our credit facility. We intend to continue ~~due to the aforementioned decrease~~reducing our long-term debt in ~~our drilling~~2021 and completion activities. Other operators have scaled back their capital spending as well, resulting in reduced spending on our non-operated properties. As a result of these actions, we expect our non-acquisition capital expenditures to trend down significantly for the remainder of 2020.

~~Cash flows provided by financing activities~~beyond.

Net cash provided by financing activities for the ~~three months ended March 31,~~first quarter of 2020 totaled ~~$521.1~~$521 million, driven by $680 million of net borrowings incurred on our credit facility ~~of $680 million and $21.3 million of~~to increase cash ~~inflows for contributions received~~on hand during 2020 due to economic uncertainties from ~~Franco-Nevada Corporation for~~ the ~~funding of its share of mineral acquisition costs incurred by The Mineral Resources Company II, LLC as described below under the heading "Mineral acquisition relationship." These cash inflows were~~COVID-19 pandemic, which was partially offset by ~~$126.9~~$127 million of cash used to repurchase shares of our common stock, ~~$18.5~~$19 million of cash dividends paid on common stock, and ~~$22.5~~$23 million of cash used to repurchase senior notes in open market transactions.

In March 2020, we elected to draw $500 million on our credit facility to increase our cash on hand. At March 31, 2020, our cash on hand totaled $517.6 million. Given this amount of available cash and our reduction in capital spending, our amount of incremental credit facility borrowings incurred in the 2020 first quarter is not expected to recur in the second quarter.

Net cash provided by financing activities for the three months ended March 31, 2019 totaled $13.2 million, which included $38.2 million of contributions received from Franco-Nevada Corporation for the funding of its share of mineral acquisition costs incurred by The Mineral Resources Company II. Partially offsetting these cash inflows was $20.6 million of cash paid to taxing authorities to satisfy tax withholdings associated with restricted stock awards that vested during the period.

Future Sources of Financing

Although we cannot provide any assurance, we believe funds from operating cash flows ~~our remaining cash balance,~~ and availability under our credit facility should be sufficient to meet our cash requirements inclusive of, but not limited to, normal operating needs, debt service obligations, planned capital expenditures, dividend payments, and commitments for at least the next 12 months.

~~Our~~Based on current market indications, our 2021 capital spending ~~plans for the remainder of 2020 have been adjusted~~plan is expected to be ~~reflective of the adverse commodity price environment and will be guided by our expectation of available~~funded from operating cash flows. Any cash flow deficiencies are expected to be funded by borrowings under our credit facility. If cash flows are materially impacted by ~~further~~ declines in commodity prices, we have the ability to reduce our capital expenditures or utilize the availability of our credit facility if needed to fund our operations and business plans. We may choose to access banking or capital markets for additional financing or capital to fund our operations or take advantage of business opportunities that may arise, although uncertainties existing in the financial markets as a result of the COVID-19 pandemic may increase the expense and difficulty of completing a bank or capital markets financing. Additionally, the terms available to the Company in connection with such a financing transaction will likely be less favorable than those enjoyed by the Company prior to the COVID-19 pandemic, although the degree, if any, by which such terms may change cannot be predicted at this time.arise. Further, we may sell assets or enter into strategic joint development opportunities in order to obtain funding if such transactions can be executed on satisfactory terms. However, no assurance can be given that such transactions will occur.

We have an unsecured credit facility, maturing in April 2023, with aggregate lender commitments totaling $1.5 billion. The commitments are from a syndicate of 14 banks and financial institutions. We believe each member of the current syndicate has the capability to fund its commitment.

As of ~~April 30, 2020,~~March 31, 2021, we had ~~$935 million of~~no outstanding borrowings ~~and approximately $562 million of borrowing availability~~ on our credit facility. ~~In March 2020, we elected to draw $500 million on our credit facility to increase our cash on hand. At April 30, 2020, our estimated cash on hand totaled approximately $500 million.~~

The commitments under our credit facility are not dependent on a borrowing base calculation subject to periodic redetermination based on changes in commodity prices and proved reserves. Additionally, downgrades or other negative rating actions with respect to our credit rating ~~such as the downgrade by S&P that occurred in March 2020 in response to weakened oil and gas industry conditions,~~ do not trigger a reduction in our current credit facility commitments, nor do such actions trigger a security requirement or change in covenants. ~~The downgrade~~Downgrades of our credit rating ~~did,~~will, however, trigger ~~a 0.25% increase~~increases in our credit facility's interest ~~rate~~rates and ~~prompted a 0.05% increase in the rate of~~ commitment fees paid on unused borrowing ~~availability.~~availability under certain circumstances.

Our credit facility contains restrictive covenants that may limit our ability to, among other things, incur additional indebtedness, incur liens, engage in sale and leaseback transactions, or merge, consolidate or sell all or substantially all of our assets. Our credit facility also contains a requirement that we maintain a consolidated net debt to total capitalization ratio of no greater than 0.65 to 1.00. See Notes to Unaudited Condensed Consolidated Financial Statements–Note ~~8. Long Term~~7. Long-Term Debt for a discussion of how this ratio is calculated pursuant to our credit agreement.

We were in compliance with our credit facility covenants at March 31, ~~2020~~2021 and expect to maintain such compliance. At March 31, ~~2020,~~2021, our consolidated net debt to total capitalization ratio was ~~0.41~~0.39 to 1.00. We do not believe the credit facility covenants are reasonably likely to limit our ability to undertake additional debt financing if needed to support our business. At March 31, ~~2020,~~2021, our total debt would have needed to independently increase by approximately ~~$8.9~~$9.5 billion above the existing level at that date (with no corresponding increase in cash or reduction in refinanced debt) to reach the maximum covenant ratio of 0.65 to 1.00. Alternatively, our total shareholders' equity would have needed to independently decrease by approximately ~~$4.8~~$5.1 billion (excluding the after-tax impact of any non-cash impairment charges) below the existing level at March 31, ~~2020~~2021 to reach the

maximum covenant ratio. These independent point-in-time sensitivities do not take into account other factors that could arise to mitigate the impact of changes in debt and equity on our consolidated net debt to total capitalization ratio, such as disposing of assets or exploring alternative sources of capitalization.

Future Capital Requirements

In April 2021, we redeemed the remaining $230.8 million principal amount of our outstanding 2022 Notes using proceeds from lower-rate credit facility borrowings. Our ~~debt includes~~ outstanding senior note obligations ~~totaling $5.3~~now total $4.76 billion ~~at March 31, 2020.~~as of April 28, 2021. We have no near-term senior note maturities, with our earliest scheduled maturity being our ~~$1.1 billion~~$649.6 million of ~~2022~~2023 Notes due in ~~September 2022.~~April 2023. Our senior notes are not subject to any mandatory redemption or sinking fund requirements. For further information on the face values, maturity dates, semi-annual interest payment dates, optional redemption periods and covenant restrictions related to our senior notes, refer to Note 8.7. Long-Term Debt in Notes to Unaudited Condensed Consolidated Financial Statements.

We were in compliance with our senior note covenants at March 31, ~~2020~~2021 and expect to maintain such compliance. We do not believe the senior note covenants will materially limit our ability to undertake additional debt financing. Downgrades or other negative rating actions with respect to the credit ratings assigned to our senior unsecured debt ~~such as the downgrade by S&P that occurred in March 2020,~~ do not trigger additional senior note covenants.

Mineral acquisition relationship

In October 2018, Continental entered into a strategic relationship with Franco-Nevada Corporation to acquire oil and gas mineral interests within an area of mutual interest ~~in the SCOOP and STACK plays~~ through a minerals subsidiary named The Mineral Resources Company II, LLC ("TMRC II"). Under the relationship, the parties have ~~committed, subject~~agreed to ~~satisfaction of agreed upon acreage development thresholds,~~spend up to ~~spend~~ a remaining aggregate total of ~~approximately $157~~$139 million ~~through year-end 2021~~ to acquire mineral interests. Continental isagreed to fund 20% of future mineral acquisitions and will be entitled to receive between 25% and 50% of total revenues generated by TMRC II based upon performance relative to predetermined production targets, while Franco-Nevada will fund 80% of future acquisitions and will be entitled to receive between 50% and 75% of TMRC II's revenues. Based upon production targets achieved to date, Continental is currently earning 50% of TMRC II's revenues and such allocation is expected to continue through at least year-end 2020. The timing and amount of future mineral acquisitions and resulting achievement of production targets are expected to be adversely impacted by Continental's aforementioned reduction in 2020 capital spending, which may impact the allocation of revenues between Continental and Franco-Nevada in periods beyond 2020, the extent of which cannot be estimated.2021.

Capital expenditures

We remain committed to operating in a disciplined, capital-efficient manner to maximize cash flow generation. Our capital expenditures budget for 2021 is $1.4 billion, which is expected to be allocated as reflected in ~~light~~the table below. Based on current expectations of commodity prices and costs, our 2021 capital budget is expected to be funded from operating cash flows. Acquisition expenditures are not budgeted, with the exception of planned levels of spending for mineral acquisitions made in conjunction with our relationship with Franco-Nevada.


In 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

(1) Represents planned spending for mineral acquisitions by TMRC II under our relationship with Franco-Nevada. Continental holds a controlling financial interest in TMRC II and therefore consolidates the financial results and capital expenditures of the current weakness and volatility in commodity prices. Our original capital budget for 2020 was $2.65 billion, which was reduced to $1.2 billion in March 2020 in response to the significant decrease in crude oil prices resulting from the COVID-19 pandemic and OPEC actions.~~We are diligently evaluating and adjusting our spending plans on an ongoing basis based on market conditions.~~entity. With ~~minimal long-term service or supply contracts~~a carry structure in place, ~~we have~~Continental will fund 20% of 2021 planned spending, or $13 million, and Franco-Nevada will fund the ~~ability~~remaining 80%, or $52 million.

(2) Excludes our March 2021 acquisition of properties in the Powder River Basin of Wyoming discussed in Notes to ~~reduce our spending in response to changes in market conditions to preserve our assets and better align our spending with expected available cash flows.~~Unaudited Condensed Consolidated Financial Statements–Note 12. Property Acquisition.

For the three months ended March 31, ~~2020,~~2021, we invested ~~$650.7~~$293.4 million in our capital program excluding ~~$29.9~~$207.6 million of unbudgeted acquisitions and ~~excluding $30.5~~including $49.4 million of capital costs associated with ~~reduced~~increased accruals for capital expenditures as compared to December 31, ~~2019.~~2020. Our ~~pace of spending in the first quarter is not expected~~2021 year to ~~continue into subsequent quarters of 2020 given the significant decrease in our planned spending as discussed above. Our 2020 first quarter~~date capital expenditures were allocated as shown in the table below.

Our drilling and completion activities and the actual amount and timing of our capital expenditures may differ materially from our budget as a result of, among other things, available cash flows, unbudgeted acquisitions, actual drilling and completion results, the availability of drilling and completion rigs and other services and equipment, the availability of transportation and

processing capacity, changes in commodity prices, and regulatory, technological and competitive developments. We monitor our capital spending closely based on actual and projected cash flows and may scale back our spending should commodity prices 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.

Commitments and contingencies

Refer to Note ~~10.~~8. Commitments and Contingencies ~~and~~ ~~Note 14. Subsequent Events~~ in Notes to Unaudited Condensed Consolidated Financial Statementsfor discussion of certain future commitments ~~and contingencies~~ of the Company. Based on current market indications, we expect to meet in the ordinary course of business our contractual cash commitments to third parties as of March 31, ~~2020.~~2021.

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 the Standing Rock Sioux 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 stay, followed by an August 5, 2020 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 action under an applicable NEPA factoring test established under case law. On April 23, 2021, the Appeals Court denied the pipeline owner’s request for rehearing. The Corps is currently conducting the court-ordered environmental review. Once this review is finished, which completion is anticipated by no later than early 2022, the Corps will determine whether the pipeline is safe to operate or must be permanently shut down. On April 9, 2021, the Biden Administration announced that the Corps will not take immediate action to shut down the DAPL while it conducts the environmental review. U.S. District Judge James Boasberg, who is set to rule on the Standing Rock Sioux Tribe's request for an injunction shutting down the DAPL while the environmental review is being conducted, granted a 10-day continuance following the Biden Administration’s announcement on April 9, 2021 and may render a decision as early as May 2021.

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.



In thousands	Amount
Remainder of 2020	$	4,954
2021	2,574
2022	782
2023	729
2024	456
Thereafter	6,676
Total operating lease liabilities, at undiscounted value	$	16,171
Less: Imputed interest	(3,588		)
Total operating lease liabilities, at discounted present value	$	12,583
Less: Current portion of operating lease liabilities	(6,243		)
Operating lease liabilities, net of current portion	$	6,340


Boe production per day	1Q 2020	1Q 2019	% Change		Boe production per day	1Q 2021	1Q 2020	% Change
Bakken	201,502	199,423	1	%	Bakken	160,577	201,502	(20	%)
SCOOP	107,817	67,659	59	%	SCOOP	101,984	107,817	(5	%)
STACK	44,155	56,513	(22	%)	STACK	36,402	44,155	(18	%)
All other	7,367	8,641	(15	%)	All other	8,979	7,367	22	%
Total	360,841	332,236	9	%	Total	307,942	360,841	(15	%)


	Three months ended March 31,						Volume increase	Volume percent increase			Three months ended March 31,						Volume decrease	Volume percent decrease
	2020			2019							2021			2020
	Volume	Percent		Volume	Percent						Volume	Percent		Volume	Percent
Crude oil (MBbl)	18,261	56	%	17,453	58	%	808	5	%	Crude oil (MBbl)	13,667	49	%	18,261	56	%	(4,594)	(25	%)
Natural gas (MMcf)	87,453	44	%	74,690	42	%	12,763	17	%	Natural gas (MMcf)	84,289	51	%	87,453	44	%	(3,164)	(4	%)
Total (MBoe)	32,836	100	%	29,901	100	%	2,935	10	%	Total (MBoe)	27,715	100	%	32,836	100	%	(5,121)	(16	%)

	Three months ended March 31,						Volume increase	Volume percent increase			Three months ended March 31,						Volume decrease	Volume percent decrease
	2020			2019							2021			2020
	MBoe	Percent		MBoe	Percent						MBoe	Percent		MBoe	Percent
North Region	19,003	58	%	18,711	63	%	292	2	%	North Region	15,259	55	%	19,003	58	%	(3,744)	(20	%)
South Region	13,833	42	%	11,190	37	%	2,643	24	%	South Region	12,456	45	%	13,833	42	%	(1,377)	(10	%)

Total	32,836	100	%	29,901	100	%	2,935	10	%	Total	27,715	100	%	32,836	100	%	(5,121)	(16	%)



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



Three months ended March 30, 2019	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, 2018	376,021,575		$	3,760		$	1,434,823		$	415	$	—	$	4,706,135	$	6,145,133		$	276,728		$	6,421,861
Net income (loss)	—		—			—			—		—		186,976		186,976			(483		)	186,493
Other comprehensive income, net of tax	—		—			—			116		—		—		116			—			116
Stock-based compensation	—		—			12,095			—		—		—		12,095			—			12,095
Restricted stock:
Granted	1,333,602		13			—			—		—		—		13			—			13
Repurchased and canceled	(439,419	)	(4		)	(20,618		)	—		—		—		(20,622		)	—			(20,622		)
Forfeited	(147,074	)	(1		)	—			—		—		—		(1		)	—			(1		)
Contributions from noncontrolling interests	—		—			—			—		—		—		—			42,204			42,204
Distributions to noncontrolling interests	—		—			—			—		—		—		—			(3,856		)	(3,856		)
Balance at March 31, 2019	376,768,684		$	3,768		$	1,426,300		$	531	$	—	$	4,893,111	$	6,323,710		$	314,593		$	6,638,303



	Three months ended March 31, 2020						Three months ended March 31, 2019
In thousands	North Region		South Region		Total		North Region		South Region		Total
Crude oil revenues:
Operated properties	$	448,930	$	179,176	$	628,106	$	585,605	$	136,547	$	722,152
Non-operated properties	132,939		12,725		145,664		178,728		10,238		188,966
Total crude oil revenues	581,869		191,901		773,770		764,333		146,785		911,118
Natural gas revenues:
Operated properties	11,588		72,306		83,894		51,461		124,698		176,159
Non-operated properties	1,720		3,359		5,079		10,866		11,441		22,307
Total natural gas revenues	13,308		75,665		88,973		62,327		136,139		198,466
Crude oil and natural gas sales	$	595,177	$	267,566	$	862,743	$	826,660	$	282,924	$	1,109,584

Timing of revenue recognition
Goods transferred at a point in time	$	595,177	$	267,566	$	862,743	$	826,660	$	282,924	$	1,109,584
Goods transferred over time	—		—		—		—		—		—
	$	595,177	$	267,566	$	862,743	$	826,660	$	282,924	$	1,109,584



	2022 Notes (1)	2023 Notes	2024 Notes	2028 Notes	2044 Notes
Face value (in thousands)	$1,100,000	$1,466,625	$993,000	$1,000,000	$700,000
Maturity date	Sep 15, 2022	April 15, 2023	June 1, 2024	January 15, 2028	June 1, 2044
Interest payment dates	March 15, Sep 15	April 15, Oct 15	June 1, Dec 1	Jan 15, July 15	June 1, Dec 1
Make-whole redemption period (2)	—	Jan 15, 2023	Mar 1, 2024	Oct 15, 2027	Dec 1, 2043


~~(1)~~	The Company has the option to redeem all or a portion of its remaining 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.



In thousands	Amount
Drilling rig commitments	$	6,048
Surface use agreements	5,091
Field equipment	1,105
Other	339
Total	$	12,583



In thousands, except weighted average data	Three months ended March 31, 2020
Lease costs:
Operating lease costs	$	1,260
Variable lease costs	3,223
Short-term lease costs	51,348
Total lease costs	$	55,831

Other information:
Right-of-use assets obtained in exchange for new operating lease liabilities	$	7,002
Operating cash flows from operating leases included in lease liabilities	228
Weighted average remaining lease term as of March 31, 2020 (in years)	9.8
Weighted average discount rate as of March 31, 2020	4.1		%


~~ITEM 2.~~	~~Management’s Discussion and Analysis of Financial Condition and Results of Operations~~



In millions	1Q 2020
Exploration and development drilling	$	544.0
Land costs (1)	39.9
Capital facilities, workovers and other corporate assets	63.0
Seismic	3.8
Capital expenditures, excluding unbudgeted acquisitions	650.7
Acquisitions of producing properties	19.3
Acquisitions of non-producing properties	10.6
Total unbudgeted acquisitions	29.9
Total capital expenditures	$	680.6


~~(1)~~In millions	~~Amount includes $21 million~~1Q 2021
Exploration and development drilling	$	255.6
Land costs	7.5
Mineral acquisitions attributable to Continental	0.2
Capital facilities, workovers, water infrastructure, and other corporate assets	27.4
Seismic	2.7
Capital expenditures attributable to Continental, excluding unbudgeted acquisitions	293.4
Acquisitions of ~~mineral~~producing properties	183.3
Acquisitions of non-producing properties	24.3
Total unbudgeted acquisitions ~~made by TMRC II during the three months ended March 31, 2020, of which $16 million was recouped from Franco-Nevada.~~	207.6
Total capital expenditures attributable to Continental	$	501.0
Mineral acquisitions attributable to Franco-Nevada	0.9
Total capital expenditures	$	501.9


		Hypothetical Fair Value
In thousands	Change in Forward Price	Asset (Liability)
Crude Oil	-10%	$4,889
Crude Oil	+10%	($26,418)
Natural Gas	-10%	$24,298
Natural Gas	+10%	($3,891)


~~ITEM 2.~~	~~Unregistered Sales of Equity Securities and Use of Proceeds~~


~~(a)~~	~~Recent Sales of Unregistered Securities – Not applicable.~~


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)
January 1, 2021 to January 31, 2021:
Repurchases for tax withholdings (2)	15,189	$	19.19	—	—
February 1, 2021 to February 28, 2021:
Repurchases for tax withholdings (2)	374,313	$	23.02	—	—
March 1, 2021 to March 31, 2021:
Repurchases for tax withholdings (2)	982	$	29.29	—	—
Total for the quarter	390,484	$	22.89	—	—


~~(2)~~	Amounts represent shares surrendered by employees to cover tax liabilities in connection with the vesting of restricted stock granted under the Company's 2013 Long-Term Incentive Plan. We paid the associated taxes to the applicable taxing authorities. The price paid per share was the closing price of our common stock on the date the restrictions lapsed on such shares.



3.1						Conformed version of Third Amended and Restated Certificate of Incorporation of Continental Resources, Inc. as amended by ~~amendment~~amendments filed on June 15, 2015 and May 21, 2020 filed as Exhibit 3.1 to the ~~Company’s~~Company's Form 10-Q for the quarterly period ended June 30, ~~2015~~2020 (Commission File No. 001-32886) filed August ~~5, 2015~~3, 2020 and incorporated herein by reference.

3.2						Third Amended and Restated Bylaws of Continental Resources, Inc. filed as Exhibit 3.2 to the Company’s Form 10-K for the year ended December 31, 2017 (Commission File No. 001-32886) filed February 21, 2018 and incorporated herein by reference.

31.110.1†						Description of cash bonus plan as of March 16, 2021.

31.1*						Certification of the Company’s Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (15 U.S.C. Section 7241).

31.2*						Certification of the Company’s Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (15 U.S.C. Section 7241).

32**						Certification of the Company’s Chief Executive Officer and Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350).

101.INS*						Inline XBRL Instance Document - the Inline XBRL Instance Document does not appear in the Interactive Data file because its XBRL tags are embedded within the Inline XBRL document

101.SCH*						Inline XBRL Taxonomy Extension Schema Document

101.CAL*						Inline XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF*						Inline XBRL Taxonomy Extension Definition Linkbase Document

101.LAB*						Inline XBRL Taxonomy Extension Label Linkbase Document

101.PRE*						Inline XBRL Taxonomy Extension Presentation Linkbase Document

104						Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)