UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)


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

For the quarterly period ended September 30, ~~2020~~2021


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

For the transition period from to

Commission File Number: 001-32886

____________________________________

CONTINENTAL RESOURCES, INC

(Exact name of registrant as specified in its charter)

____________________________________

Oklahoma

73-0767549

(State or other jurisdiction of incorporation or organization)

(I.R.S. Employer Identification No.)

20 N. Broadway,

Oklahoma City,

Oklahoma

73102

(Address of principal executive offices)

(Zip Code)

(405) 234-9000

(Registrant’s telephone number, including area code)

Not Applicable

(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.

Large accelerated filer

Accelerated filer

☐

Non-accelerated filer

☐

Smaller reporting company

☐

Emerging growth company

☐

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

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

~~365,234,283~~365,580,875 shares of our $0.01 par value common stock were outstanding on October ~~31, 2020.~~25, 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	5
	Notes to Unaudited Condensed Consolidated Financial Statements	6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	2422
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	3836
Item 4.	Controls and Procedures	3937

PART II. Other Information
Item 1.	Legal Proceedings	4038
Item 1A.	Risk Factors	4038
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	4139
Item 3.	Defaults Upon Senior Securities	4139
Item 4.	Mine Safety Disclosures	4139
Item 5.	Other Information	4139
Item 6.	Exhibits	4240
	Signature	4341

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, our Form 10-Qs for the quarters ended March 31, 2020 and June 30,~~ 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 have been, and may further be, exacerbated by the COVID-19 pandemic and any ~~consequent~~potential worsening of the global economic environment. New factors emerge from time to time, and it is not possible for us to predict all such factors. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date on which such statement is made. Should one or more of the risks or uncertainties described in this report or our Annual Report on Form 10-K ~~or our Form 10-Qs~~ for the ~~quarters~~year ended ~~March~~December 31, ~~2020 and June 30,~~ 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.

iviii

PART I. Financial Information

ITEM 1. Financial Statements

Continental Resources, Inc. and Subsidiaries

Condensed Consolidated Balance Sheets


		September 30, 2020		December 31, 2019			September 30, 2021		December 31, 2020
In thousands, except par values and share data	In thousands, except par values and share data	(Unaudited)				In thousands, except par values and share data	(Unaudited)
Assets	Assets					Assets
Current assets:	Current assets:					Current assets:
Cash and cash equivalents	Cash and cash equivalents	$	21,237	$	39,400	Cash and cash equivalents	$	693,649	$	47,470
Receivables:	Receivables:					Receivables:
Crude oil and natural gas sales	Crude oil and natural gas sales	475,187		726,876		Crude oil and natural gas sales	902,580		561,127

Joint interest and other	Joint interest and other	126,135		317,018		Joint interest and other	248,230		143,829
Allowance for credit losses	Allowance for credit losses	(2,220)		(2,407)		Allowance for credit losses	(2,977)		(2,462)
Receivables, net	Receivables, net	599,102		1,041,487		Receivables, net	1,147,833		702,494
Derivative assets	Derivative assets	346		0		Derivative assets	314		15,303
Inventories	Inventories	63,170		109,536		Inventories	119,285		72,157
Prepaid expenses and other	Prepaid expenses and other	15,907		16,592		Prepaid expenses and other	17,561		15,121
Total current assets	Total current assets	699,762		1,207,015		Total current assets	1,978,642		852,545
Net property and equipment, based on successful efforts method of accounting	Net property and equipment, based on successful efforts method of accounting	14,004,414		14,497,726		Net property and equipment, based on successful efforts method of accounting	13,475,204		13,737,292
Operating lease right-of-use assets	Operating lease right-of-use assets	10,396		9,128		Operating lease right-of-use assets	19,368		8,557
Derivative assets, noncurrent						Derivative assets, noncurrent	1,773		—
Other noncurrent assets	Other noncurrent assets	13,652		14,038		Other noncurrent assets	31,176		34,704
Total assets	Total assets	$	14,728,224	$	15,727,907	Total assets	$	15,506,163	$	14,633,098

Liabilities and equity	Liabilities and equity					Liabilities and equity
Current liabilities:	Current liabilities:					Current liabilities:
Accounts payable trade	Accounts payable trade	$	321,975	$	629,264	Accounts payable trade	$	527,268	$	361,704
Revenues and royalties payable	Revenues and royalties payable	260,887		470,264		Revenues and royalties payable	510,986		327,029

Accrued liabilities and other	Accrued liabilities and other	151,662		230,368		Accrued liabilities and other	230,488		167,013

Derivative liabilities	Derivative liabilities	7,086		0		Derivative liabilities	131,616		227
Current portion of operating lease liabilities	Current portion of operating lease liabilities	4,225		3,695		Current portion of operating lease liabilities	1,895		2,588
Current portion of long-term debt	Current portion of long-term debt	2,225		2,435		Current portion of long-term debt	2,306		2,245
Total current liabilities	Total current liabilities	748,060		1,336,026		Total current liabilities	1,404,559		860,806
Long-term debt, net of current portion	Long-term debt, net of current portion	5,629,133		5,324,079		Long-term debt, net of current portion	4,741,729		5,530,173
Other noncurrent liabilities:	Other noncurrent liabilities:					Other noncurrent liabilities:
Deferred income tax liabilities, net	Deferred income tax liabilities, net	1,650,998		1,787,125		Deferred income tax liabilities, net	1,911,270		1,620,154
Asset retirement obligations, net of current portion	Asset retirement obligations, net of current portion	173,762		151,774		Asset retirement obligations, net of current portion	192,788		177,194
Derivative liabilities, noncurrent	Derivative liabilities, noncurrent	1,820		0		Derivative liabilities, noncurrent	2,172		1,584
Operating lease liabilities, net of current portion	Operating lease liabilities, net of current portion	6,005		5,433		Operating lease liabilities, net of current portion	17,326		5,839
Other noncurrent liabilities	Other noncurrent liabilities	14,332		15,119		Other noncurrent liabilities	15,253		14,623
Total other noncurrent liabilities	Total other noncurrent liabilities	1,846,917		1,959,451		Total other noncurrent liabilities	2,138,809		1,819,394
Commitments and contingencies (Note 10)
Commitments and contingencies (Note 8)						Commitments and contingencies (Note 8)	0		0
Equity:	Equity:					Equity:
Preferred stock, $0.01 par value; 25,000,000 shares authorized; no shares issued and outstanding	Preferred stock, $0.01 par value; 25,000,000 shares authorized; no shares issued and outstanding	0		0		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; 365,112,162 shares issued and outstanding at September 30, 2020; 371,074,036 shares issued and outstanding at December 31, 2019		3,651		3,711
Common stock, $0.01 par value; 1,000,000,000 shares authorized; 365,596,400 shares issued and outstanding at September 30, 2021; 365,220,435 shares issued and outstanding at December 31, 2020						Common stock, $0.01 par value; 1,000,000,000 shares authorized; 365,596,400 shares issued and outstanding at September 30, 2021; 365,220,435 shares issued and outstanding at December 31, 2020	3,656		3,652
Additional paid-in capital	Additional paid-in capital	1,188,891		1,274,732		Additional paid-in capital	1,174,755		1,205,148
Retained earnings	Retained earnings	4,940,142		5,463,224		Retained earnings	5,670,478		4,847,646
Total shareholders’ equity attributable to Continental Resources	Total shareholders’ equity attributable to Continental Resources	6,132,684		6,741,667		Total shareholders’ equity attributable to Continental Resources	6,848,889		6,056,446
Noncontrolling interests	Noncontrolling interests	371,430		366,684		Noncontrolling interests	372,177		366,279
Total equity	Total equity	6,504,114		7,108,351		Total equity	7,221,066		6,422,725
Total liabilities and equity	Total liabilities and equity	$	14,728,224	$	15,727,907	Total liabilities and equity	$	15,506,163	$	14,633,098

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

Continental Resources, Inc. and Subsidiaries

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

Three months ended September 30, Nine months ended September 30,
In thousands, except per share data 2020 2019 2020 2019
Revenues:
Crude oil and natural gas sales $ 701,468 $ 1,081,400 $ 1,738,863 $ 3,328,409
Gain (loss) on derivative instruments, net (17,853) 1,195 (25,635) 53,519
Crude oil and natural gas service operations 8,755 21,602 35,602 54,886
Total revenues 692,370 1,104,197 1,748,830 3,436,814
Operating costs and expenses:
Production expenses 88,701 114,050 271,852 333,446
Production taxes 50,153 86,931 132,444 267,237
Transportation expenses 55,272 62,038 148,079 164,569
Exploration expenses 1,041 2,472 14,638 7,399
Crude oil and natural gas service operations 3,316 8,224 15,288 26,616
Depreciation, depletion, amortization and accretion 461,191 484,031 1,288,185 1,464,672
Property impairments 18,518 20,199 264,976 66,854
General and administrative expenses 45,273 46,993 129,713 141,837
Net (gain) loss on sale of assets and other 800 535 5,914 647
Total operating costs and expenses 724,265 825,473 2,271,089 2,473,277
Income (loss) from operations (31,895) 278,724 (522,259) 963,537
Other income (expense):
Interest expense (63,884) (68,090) (192,547) (204,398)
Gain (loss) on extinguishment of debt 0 (4,584) 64,573 (4,584)
Other 224 1,119 1,385 3,196
(63,660) (71,555) (126,589) (205,786)
Income (loss) before income taxes (95,555) 207,169 (648,848) 757,751
(Provision) benefit for income taxes 13,972 (49,747) 138,350 (177,386)
Net income (loss) (81,583) 157,422 (510,498) 580,365
Net loss attributable to noncontrolling interests (2,161) (740) (6,126) (1,330)
Net income (loss) attributable to Continental Resources $ (79,422) $ 158,162 $ (504,372) $ 581,695
Net income (loss) per share attributable to Continental Resources:
Basic $ (0.22) $ 0.43 $ (1.39) $ 1.56
Diluted $ (0.22) $ 0.43 $ (1.39) $ 1.56
Comprehensive income (loss):
Net income (loss) $ (81,583) $ 157,422 $ (510,498) $ 580,365
Other comprehensive income, net of tax:
Foreign currency translation adjustments 0 (18) 0 128
Total other comprehensive income, net of tax 0 (18) 0 128
Comprehensive income (loss) (81,583) 157,404 (510,498) 580,493
Comprehensive loss attributable to noncontrolling interests (2,161) (740) (6,126) (1,330)
Comprehensive income (loss) attributable to Continental Resources $ (79,422) $ 158,144 $ (504,372) $ 581,823


	Three months ended September 30,				Nine months ended September 30,
In thousands, except per share data	2021		2020		2021		2020
Revenues:
Crude oil and natural gas sales	$	1,456,181	$	701,468	$	3,986,628	$	1,738,863
Loss on derivative instruments, net	(127,110)		(17,853)		(232,795)		(25,635)
Crude oil and natural gas service operations	12,341		8,755		38,519		35,602
Total revenues	1,341,412		692,370		3,792,352		1,748,830

Operating costs and expenses:
Production expenses	103,222		88,701		292,791		271,852
Production taxes	102,398		50,153		280,667		132,444
Transportation expenses	53,969		55,272		156,670		148,079
Exploration expenses	2,534		1,041		9,470		14,638
Crude oil and natural gas service operations	4,884		3,316		15,037		15,288
Depreciation, depletion, amortization and accretion	465,357		461,191		1,446,823		1,288,185
Property impairments	7,945		18,518		30,991		264,976
General and administrative expenses	58,421		45,273		166,822		129,713
Net (gain) loss on sale of assets and other	(3,029)		800		(3,496)		5,914
Total operating costs and expenses	795,701		724,265		2,395,775		2,271,089
Income (loss) from operations	545,711		(31,895)		1,396,577		(522,259)
Other income (expense):
Interest expense	(59,894)		(63,884)		(185,796)		(192,547)
Gain (loss) on extinguishment of debt	—		—		(290)		64,573
Other	345		224		895		1,385
	(59,549)		(63,660)		(185,191)		(126,589)
Income (loss) before income taxes	486,162		(95,555)		1,211,386		(648,848)
(Provision) benefit for income taxes	(115,641)		13,972		(291,116)		138,350
Net income (loss)	370,521		(81,583)		920,270		(510,498)
Net income (loss) attributable to noncontrolling interests	1,193		(2,161)		1,975		(6,126)
Net income (loss) attributable to Continental Resources	$	369,328	$	(79,422)	$	918,295	$	(504,372)

Net income (loss) per share attributable to Continental Resources:
Basic	$	1.02	$	(0.22)	$	2.54	$	(1.39)
Diluted	$	1.01	$	(0.22)	$	2.52	$	(1.39)

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

Continental Resources, Inc. and Subsidiaries

Unaudited Condensed Consolidated Statements of Equity

Shareholders’ equity attributable to Continental Resources
In thousands, except share data Shares
outstanding Common
stock Additional
paid-in
capital Accumulated
other
comprehensive
income Treasury
stock Retained
earnings Total shareholders’ equity of Continental Resources Noncontrolling
interests Total equity
Balance at December 31, 2019 371,074,036 $ 3,711 $ 1,274,732 $ 0 $ — $ 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 $ 0 $ — $ 5,258,845 $ 6,420,362 $ 376,896 $ 6,797,258
Net income (loss) — — — — — (239,286) (239,286) (2,845) (242,131)
Change in dividends payable — — — — — 2 2 — 2
Stock-based compensation — — 15,313 — — — 15,313 — 15,313
Restricted stock:
Granted 85,514 1 — — — — 1 — 1
Repurchased and canceled (19,037) 0 (247) — — — (247) — (247)
Forfeited (39,237) (1) — — — — (1) — (1)
Contributions from noncontrolling interests — — — — — — — 4,015 4,015
Distributions to noncontrolling interests — — — — — — — (2,958) (2,958)
Balance at June 30, 2020 365,144,243 $ 3,651 $ 1,172,932 $ 0 $ — $ 5,019,561 $ 6,196,144 $ 375,108 $ 6,571,252
Net income (loss) — — — — — (79,422) (79,422) (2,161) (81,583)
Change in dividends payable — — — — — 3 3 — 3
Stock-based compensation — — 16,330 — — — 16,330 — 16,330
Restricted stock:
Granted 43,241 1 — — — — 1 — 1
Repurchased and canceled (20,873) 0 (371) — — — (371) — (371)
Forfeited (54,449) (1) — — — — (1) — (1)
Contributions from noncontrolling interests — — — — — — — 36 36
Distributions to noncontrolling interests — — — — — — — (1,553) (1,553)
Balance at September 30, 2020 365,112,162 $ 3,651 $ 1,188,891 $ 0 $ — $ 4,940,142 $ 6,132,684 $ 371,430 $ 6,504,114


Three Months Ended September 30, 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 June 30, 2021	367,563,899	$	3,676	$	1,226,223	$	—	$	5,356,189	$	6,586,088	$	369,586	$	6,955,674
Net income	—	—		—		—		369,328		369,328		1,193		370,521
Cash dividends declared ($0.15 per share)	—	—		—		—		(55,132)		(55,132)				(55,132)
Change in dividends payable	—	—		—		—		93		93		—		93
Common stock repurchased	—	—		—		(65,256)		—		(65,256)		—		(65,256)
Common stock retired	(1,916,069)	(19)		(65,237)		65,256		—		—		—		—

Stock-based compensation	—	—		14,506		—		—		14,506		—		14,506
Restricted stock:
Granted	47,701	—		—		—		—		—		—		—
Repurchased and canceled	(19,003)	—		(737)		—		—		(737)		—		(737)
Forfeited	(80,128)	(1)		—		—		—		(1)		—		(1)
Contributions from noncontrolling interests	—	—		—		—		—		—		6,788		6,788
Distributions to noncontrolling interests	—	—		—		—		—		—		(5,390)		(5,390)
Balance at September 30, 2021	365,596,400	$	3,656	$	1,174,755	$	—	$	5,670,478	$	6,848,889	$	372,177	$	7,221,066


Nine Months Ended September 30, 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	—	—		—		—		918,295		918,295		1,975		920,270
Cash dividends declared ($0.11 per share)	—	—		—		—		(40,429)		(40,429)		—		(40,429)
Cash dividends declared ($0.15 per share)	—	—		—		—		(55,132)		(55,132)		—		(55,132)
Change in dividends payable	—	—		—		—		98		98		—		98
Common stock repurchased	—	—		—		(65,256)		—		(65,256)		—		(65,256)
Common stock retired	(1,916,069)	(19)		(65,237)		65,256		—		—		—		—

Stock-based compensation	—	—		45,024		—		—		45,024		—		45,024
Restricted stock:
Granted	2,900,923	29		—		—		—		29		—		29
Repurchased and canceled	(426,255)	(4)		(10,180)		—		—		(10,184)		—		(10,184)
Forfeited	(182,634)	(2)		—		—		—		(2)		—		(2)
Contributions from noncontrolling interests	—	—		—		—		—		—		21,263		21,263
Distributions to noncontrolling interests	—	—		—		—		—		—		(17,340)		(17,340)
Balance at September 30, 2021	365,596,400	$	3,656	$	1,174,755	$	—	$	5,670,478	$	6,848,889	$	372,177	$	7,221,066

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

Continental Resources, Inc. and Subsidiaries

Unaudited Condensed Consolidated Statements of Equity (Continued)


Three Months Ended September 30, 2020																			Three Months Ended September 30, 2020
																				Shareholders’ equity attributable to Continental Resources
In thousands, except share data																			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

		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

Balance at June 30, 2020																			Balance at June 30, 2020	365,144,243	$	3,651	$	1,172,932	$	—	$	5,019,561	$	6,196,144	$	375,108	$	6,571,252
Net income (loss)	Net income (loss)	—	—		—		—		—		186,976		186,976		(483)		186,493		Net income (loss)	—	—		—		—		(79,422)		(79,422)		(2,161)		(81,583)
Other comprehensive income, net of tax		—	—		—		116		—		—		116		—		116
Change in dividends payable																			Change in dividends payable	—	—		—		—		3		3		—		3

Stock-based compensation	Stock-based compensation	—	—		12,095		—		—		—		12,095		—		12,095		Stock-based compensation	—	—		16,330		—		—		16,330		—		16,330
Restricted stock:	Restricted stock:																		Restricted stock:
Granted	Granted	1,333,602	13		—		—		—		—		13		—		13		Granted	43,241	1		—		—		—		1		—		1
Repurchased and canceled	Repurchased and canceled	(439,419)	(4)		(20,618)		—		—		—		(20,622)		—		(20,622)		Repurchased and canceled	(20,873)	—		(371)		—		—		(371)		—		(371)
Forfeited	Forfeited	(147,074)	(1)		—		—		—		—		(1)		—		(1)		Forfeited	(54,449)	(1)		—		—		—		(1)		—		(1)
Contributions from noncontrolling interests	Contributions from noncontrolling interests	—	—		—		—		—		—		—		42,204		42,204		Contributions from noncontrolling interests	—	—		—		—		—		—		36		36
Distributions to noncontrolling interests	Distributions to noncontrolling interests	—	—		—		—		—		—		—		(3,856)		(3,856)		Distributions to noncontrolling interests	—	—		—		—		—		—		(1,553)		(1,553)
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
Net income (loss)		—	—		—		—		—		236,557		236,557		(107)		236,450
Cash dividends declared ($0.05 per share)		—	—		—		—		—		(18,747)		(18,747)		—		(18,747)
Common stock repurchased		—	—		—		—		(69,661)		—		(69,661)		—		(69,661)
Common stock retired		(1,800,000)	(18)		(69,643)		—		69,661		—		—		—		—
Other comprehensive income, net of tax		—	—		—		30		—		—		30		—		30
Stock-based compensation		—	—		12,176		—		—		—		12,176		—		12,176
Restricted stock:
Granted		59,639	1		—		—		—		—		1		—		1
Repurchased and canceled		(13,335)	(1)		(561)		—		—		—		(562)		—		(562)
Forfeited		(71,440)	(1)		—		—		—		—		(1)		—		(1)
Contributions from noncontrolling interests		—	—		—		—		—		—		—		35,118		35,118
Distributions to noncontrolling interests		—	—		—		—		—		—		—		(3,272)		(3,272)
Balance at June 30, 2019		374,943,548	$	3,749	$	1,368,272	$	561	$	—	$	5,110,921	$	6,483,503	$	346,332	$	6,829,835
Net income (loss)		—	—		—		—		—		158,162		158,162		(740)		157,422
Change in dividends payable		—	—		—		—		—		160		160		—		160
Common stock repurchased		—	—		—		—		(102,304)		—		(102,304)		—		(102,304)
Common stock retired		(3,206,553)	(32)		(102,272)		—		102,304		—		—		—		—
Other comprehensive loss, net of tax		—	—		—		(18)		—		—		(18)		—		(18)
Stock-based compensation		—	—		12,871		—		—		—		12,871		—		12,871
Restricted stock:
Granted		102,945	1		—		—		—		—		1		—		1
Repurchased and canceled		(13,353)	0		(389)		—		—		—		(389)		—		(389)
Forfeited		(96,099)	(1)		—		—		—		—		(1)		—		(1)
Contributions from noncontrolling interests		—	—		—		—		—		—		—		19,713		19,713
Distributions to noncontrolling interests		—	—		—		—		—		—		—		(3,110)		(3,110)
Balance at September 30, 2019		371,730,488	$	3,717	$	1,278,482	$	543	$	—	$	5,269,243	$	6,551,985	$	362,195	$	6,914,180
Balance at September 30, 2020																			Balance at September 30, 2020	365,112,162	$	3,651	$	1,188,891	$	—	$	4,940,142	$	6,132,684	$	371,430	$	6,504,114


Nine Months Ended September 30, 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)	—	—		—		—		(504,372)		(504,372)		(6,126)		(510,498)
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	—	—		—		—		7		7		—		7
Common stock repurchased	—	—		—		(126,906)		—		(126,906)		—		(126,906)
Common stock retired	(8,122,104)	(81)		(126,825)		126,906		—		—		—		—

Stock-based compensation	—	—		48,054		—		—		48,054		—		48,054
Restricted stock:
Granted	2,582,990	26		—		—		—		26		—		26
Repurchased and canceled	(286,256)	(2)		(7,070)		—		—		(7,072)		—		(7,072)
Forfeited	(136,504)	(3)		—		—		—		(3)		—		(3)
Contributions from noncontrolling interests	—	—		—		—		—		—		21,001		21,001
Distributions to noncontrolling interests	—	—		—		—		—		—		(10,129)		(10,129)
Balance at September 30, 2020	365,112,162	$	3,651	$	1,188,891	$	—	$	4,940,142	$	6,132,684	$	371,430	$	6,504,114

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

Continental Resources, Inc. and Subsidiaries

Unaudited Condensed Consolidated Statements of Cash Flows


		Nine months ended September 30,					Nine months ended September 30,
In thousands	In thousands	2020		2019		In thousands	2021		2020
Cash flows from operating activities	Cash flows from operating activities					Cash flows from operating activities
Net income (loss)	Net income (loss)	$	(510,498)	$	580,365	Net income (loss)	$	920,270	$	(510,498)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:	Adjustments to reconcile net income (loss) to net cash provided by operating activities:					Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion	Depreciation, depletion, amortization and accretion	1,286,889		1,465,856		Depreciation, depletion, amortization and accretion	1,445,129		1,286,889
Property impairments	Property impairments	264,976		66,854		Property impairments	30,991		264,976
Non-cash (gain) loss on derivatives		8,560		(1,303)
Non-cash loss on derivatives						Non-cash loss on derivatives	145,194		8,560
Stock-based compensation	Stock-based compensation	48,086		37,153		Stock-based compensation	44,918		48,086
Provision (benefit) for deferred income taxes	Provision (benefit) for deferred income taxes	(136,127)		177,386		Provision (benefit) for deferred income taxes	291,116		(136,127)
Dry hole costs	Dry hole costs	6,456		0		Dry hole costs	—		6,456
Net (gain) loss on sale of assets and other	Net (gain) loss on sale of assets and other	5,914		647		Net (gain) loss on sale of assets and other	(3,496)		5,914
(Gain) loss on extinguishment of debt	(Gain) loss on extinguishment of debt	(64,573)		4,584		(Gain) loss on extinguishment of debt	290		(64,573)
Other, net	Other, net	7,811		8,036		Other, net	7,465		7,811
Changes in assets and liabilities:	Changes in assets and liabilities:					Changes in assets and liabilities:
Accounts receivable	Accounts receivable	435,862		(42,269)		Accounts receivable	(444,748)		435,862
Inventories	Inventories	21,846		(21,867)		Inventories	(47,128)		21,846
Other current assets	Other current assets	1,196		(3,808)		Other current assets	(1,894)		1,196
Accounts payable trade	Accounts payable trade	(150,645)		56,624		Accounts payable trade	96,785		(150,645)
Revenues and royalties payable	Revenues and royalties payable	(209,258)		(309)		Revenues and royalties payable	183,050		(209,258)
Accrued liabilities and other	Accrued liabilities and other	(80,227)		(15,707)		Accrued liabilities and other	60,690		(80,227)
Other noncurrent assets and liabilities	Other noncurrent assets and liabilities	(1,501)		(366)		Other noncurrent assets and liabilities	21		(1,501)
Net cash provided by operating activities	Net cash provided by operating activities	934,767		2,311,876		Net cash provided by operating activities	2,728,653		934,767

Cash flows from investing activities	Cash flows from investing activities					Cash flows from investing activities
Exploration and development	Exploration and development	(1,139,447)		(2,268,594)		Exploration and development	(905,974)		(1,139,447)
Purchase of producing crude oil and natural gas properties	Purchase of producing crude oil and natural gas properties	(23,318)		(49,324)		Purchase of producing crude oil and natural gas properties	(175,441)		(23,318)
Purchase of other property and equipment	Purchase of other property and equipment	(21,306)		(22,875)		Purchase of other property and equipment	(46,948)		(21,306)
Proceeds from sale of assets	Proceeds from sale of assets	2,205		86,866		Proceeds from sale of assets	4,562		2,205
Net cash used in investing activities	Net cash used in investing activities	(1,181,866)		(2,253,927)		Net cash used in investing activities	(1,123,801)		(1,181,866)

Cash flows from financing activities	Cash flows from financing activities					Cash flows from financing activities
Credit facility borrowings	Credit facility borrowings	1,657,000		776,000		Credit facility borrowings	1,063,000		1,657,000
Repayment of credit facility	Repayment of credit facility	(1,237,000)		(476,000)		Repayment of credit facility	(1,223,000)		(1,237,000)

Redemption of Senior Notes	Redemption of Senior Notes	(74,032)		(500,000)		Redemption of Senior Notes	(630,782)		(74,032)
Premium and costs on redemption of Senior Notes		0		(4,167)

Proceeds from other debt	Proceeds from other debt	26,000		0		Proceeds from other debt	—		26,000
Repayment of other debt	Repayment of other debt	(6,130)		(1,754)		Repayment of other debt	(1,674)		(6,130)
Debt issuance costs	Debt issuance costs	(237)		0		Debt issuance costs	—		(237)
Contributions from noncontrolling interests	Contributions from noncontrolling interests	26,587		104,494		Contributions from noncontrolling interests	19,812		26,587
Distributions to noncontrolling interests	Distributions to noncontrolling interests	(10,814)		(10,493)		Distributions to noncontrolling interests	(16,535)		(10,814)
Repurchase of common stock	Repurchase of common stock	(126,906)		(171,965)		Repurchase of common stock	(65,256)		(126,906)
Repurchase of restricted stock for tax withholdings	Repurchase of restricted stock for tax withholdings	(7,072)		(21,573)		Repurchase of restricted stock for tax withholdings	(10,184)		(7,072)
Dividends paid on common stock	Dividends paid on common stock	(18,460)		0		Dividends paid on common stock	(94,054)		(18,460)
Net cash provided by (used in) financing activities	Net cash provided by (used in) financing activities	228,936		(305,458)		Net cash provided by (used in) financing activities	(958,673)		228,936
Effect of exchange rate changes on cash		0		20
Net change in cash and cash equivalents	Net change in cash and cash equivalents	(18,163)		(247,489)		Net change in cash and cash equivalents	646,179		(18,163)
Cash and cash equivalents at beginning of period	Cash and cash equivalents at beginning of period	39,400		282,749		Cash and cash equivalents at beginning of period	47,470		39,400
Cash and cash equivalents at end of period	Cash and cash equivalents at end of period	$	21,237	$	35,260	Cash and cash equivalents at end of period	$	693,649	$	21,237

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

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 55% of its crude oil and natural gas production and ~~65%~~62% of its crude oil and natural gas revenues for the nine months ended September 30, ~~2020.~~2021. The Company's principal producing properties in the North region are located in the Bakken field of North Dakota and ~~Montana.~~Montana and the Powder River Basin of Wyoming. The Company's operations in the South region comprised 45% of its crude oil and natural gas production and ~~35%~~38% of its crude oil and natural gas revenues for the nine months ended September 30, ~~2020.~~2021. The Company's principal producing properties in the South region are located in the SCOOP and STACK areas of Oklahoma.

For the nine months ended September 30, ~~2020,~~2021, crude oil accounted for ~~54%~~49% of the Company’s total production and ~~90%~~69% 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 September 30, ~~2020~~2021 and for the three and nine month periods ended September 30, ~~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 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 and nine months ended September 30, ~~2020~~2021 and ~~2019.~~2020.


		Three months ended September 30,				Nine months ended September 30,					Three months ended September 30,				Nine months ended September 30,
In thousands, except per share data	In thousands, except per share data	2020		2019		2020		2019		In thousands, except per share data	2021		2020		2021		2020
Net income (loss) attributable to Continental Resources (numerator)	Net income (loss) attributable to Continental Resources (numerator)	$	(79,422)	$	158,162	$	(504,372)	$	581,695	Net income (loss) attributable to Continental Resources (numerator)	$	369,328	$	(79,422)	$	918,295	$	(504,372)
Weighted average shares (denominator):	Weighted average shares (denominator):									Weighted average shares (denominator):
Weighted average shares - basic	Weighted average shares - basic	360,257		369,739		361,948		371,702		Weighted average shares - basic	360,563		360,257		360,899		361,948
Non-vested restricted stock (1)	Non-vested restricted stock (1)	0		937		0		1,804		Non-vested restricted stock (1)	3,685		—		3,580		—
Weighted average shares - diluted	Weighted average shares - diluted	360,257		370,676		361,948		373,506		Weighted average shares - diluted	364,248		360,257		364,479		361,948
Net income (loss) per share attributable to Continental Resources:	Net income (loss) per share attributable to Continental Resources:									Net income (loss) per share attributable to Continental Resources:
Basic	Basic	$	(0.22)	$	0.43	$	(1.39)	$	1.56	Basic	$	1.02	$	(0.22)	$	2.54	$	(1.39)
Diluted	Diluted	$	(0.22)	$	0.43	$	(1.39)	$	1.56	Diluted	$	1.01	$	(0.22)	$	2.52	$	(1.39)

(1) For the three and nine months ended September 30, 2020 the Company had a net loss and therefore the potential dilutive effect of approximately 50,000 and 609,000 weighted average non-vested restricted shares, respectively, were not included in the calculation of diluted net loss per share because to do so would have been anti-dilutive to the computations.

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—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 and nine month periods ended September 30, 2021 and 2020.

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 September 30, ~~2020~~2021 and December 31, ~~2019~~2020 consisted of the following:


In thousands	In thousands	September 30, 2020		December 31, 2019		In thousands	September 30, 2021		December 31, 2020
Tubular goods and equipment	Tubular goods and equipment	$	13,657	$	14,880	Tubular goods and equipment	$	12,017	$	13,671
Crude oil		49,513		94,656
Crude oil and natural gas						Crude oil and natural gas	107,268		58,486
Total	Total	$	63,170	$	109,536	Total	$	119,285	$	72,157

In the first quarter of 2020 the Company recognized a $24.5 million impairment to reduce its crude oil inventory to estimated net realizable value at 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 nine month period ended September 30, 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

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

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 Company adopted 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 new standard is~~did not ~~expected to~~ have a material impact on ~~the Company.~~

~~Continental Resources, Inc. and Subsidiaries~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

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.


		Nine months ended September 30,					Nine months ended September 30,
In thousands	In thousands	2020		2019		In thousands	2021		2020
Supplemental cash flow information:	Supplemental cash flow information:					Supplemental cash flow information:
Cash paid for interest	Cash paid for interest	$	178,082	$	194,087	Cash paid for interest	$	164,874	$	178,082
Cash paid for income taxes	Cash paid for income taxes	8		9		Cash paid for income taxes	3		8
Cash received for income tax refunds (1)	Cash received for income tax refunds (1)	9,485		7		Cash received for income tax refunds (1)	9		9,485
Non-cash investing activities:	Non-cash investing activities:					Non-cash investing activities:
Asset retirement obligation additions and revisions, net	Asset retirement obligation additions and revisions, net	15,733		4,313		Asset retirement obligation additions and revisions, net	9,818		15,733

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

As of September 30, ~~2020~~2021 and December 31, ~~2019,~~2020, the Company had ~~$100.1~~$194.9 million and ~~$262.7~~$128.8 million, respectively, of accrued capital expenditures included in “Net property and equipment” with an offsetting amount in “Accounts payable trade” in the condensed consolidated balance sheets.

As of September 30, ~~2020~~2021 and December 31, ~~2019,~~2020, the Company had ~~$0.1~~$1.5 million and ~~$5.6~~$0.1 million, respectively, of accrued contributions from noncontrolling interests included in "Receivables–Joint interest and other" with an offsetting amount in "Equity–Noncontrolling interests" in the condensed consolidated balance sheets.

As of September 30, ~~2020~~2021 and December 31, ~~2019,~~2020, the Company had ~~$0.8~~$1.8 million and ~~$1.5~~$1.0 million, respectively, of accrued distributions to noncontrolling interests included in "Revenues and royalties payable" with an offsetting amount in "Equity–Noncontrolling interests" in the condensed consolidated balance sheets.

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 ~~$46.9~~$45.2 million and ~~$53.0~~$46.9 million for the three months ended September 30, ~~2020~~2021 and ~~2019,~~2020, respectively, and ~~$120.8~~$129.2 million and ~~$140.7~~$120.8 million for the nine months ended September 30, ~~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.

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

Under certain arrangements, in periods of significantly depressed prices for natural gas and NGLs the contractual pricing adjustments applied by the midstream customer in a particular month may exceed the consideration to be received by the Company under the arrangement, resulting in a net payment owed by the Company to the midstream customer. In these situations, the net amounts paid or payable by the Company are reflected as a reduction of natural gas sales in the caption "Crude oil and natural gas sales" in the unaudited condensed consolidated statements of ~~comprehensive income (loss).~~operations. Such payments for operated properties, which are referred to herein as negative gas revenues, were immaterial for the three and nine months ended September 30, 2021 and totaled $2.5 million and $25.2 million ~~for operated properties~~ for the three and nine months ended September 30, 2020, respectively.

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 settlement, but does not currently take NGL volumes. When the Company elects to take volumes in kind, it pays third parties to transport the processed products it took in-kind to downstream delivery points, where it then sells to customers at prices applicable to those downstream markets. In such situations, operated revenues are recognized during the month in which control transfers to the customer at the delivery point and 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 ~~$8.4~~$8.7 million and ~~$9.0~~$8.4 million for the three months ended September 30, ~~2020~~2021 and ~~2019,~~2020, respectively, and ~~$27.3~~$27.5 million and ~~$23.9~~$27.3 million for the nine months ended September 30, ~~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.

In periods of significantly depressed prices for natural gas and NGLs the costs incurred by the outside operator in a particular month may exceed the consideration to be received by the Company, resulting in a net payment owed by the Company to the outside operator. In these situations, the net amounts paid or payable by the Company are reflected as a reduction of natural gas sales in the caption "Crude oil and natural gas sales" in the unaudited condensed consolidated statements of ~~comprehensive income (loss).~~operations. Such negative gas revenues associated with non-operated properties were immaterial for the three and nine months ended September 30, 2021 and totaled $4.7 million and $12.5 million for the three and nine months ended September 30, 2020, respectively.

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.

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

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 and nine months ended September 30, ~~2020~~2021 and ~~2019.~~2020.


		Three months ended September 30, 2020						Three months ended September 30, 2019							Three months ended September 30, 2021						Three months ended September 30, 2020
In thousands	In thousands	North Region		South Region		Total		North Region		South Region		Total		In thousands	North Region		South Region		Total		North Region		South Region		Total
Crude oil revenues:	Crude oil revenues:													Crude oil revenues:
Operated properties	Operated properties	$	346,580	$	176,585	$	523,165	$	593,729	$	210,851	$	804,580	Operated properties	$	615,514	$	214,348	$	829,862	$	346,580	$	176,585	$	523,165
Non-operated properties	Non-operated properties	91,067		9,723		100,790		172,383		12,334		184,717		Non-operated properties	159,981		12,980		172,961		91,067		9,723		100,790
Total crude oil revenues	Total crude oil revenues	437,647		186,308		623,955		766,112		223,185		989,297		Total crude oil revenues	775,495		227,328		1,002,823		437,647		186,308		623,955
Natural gas revenues:	Natural gas revenues:													Natural gas revenues:
Operated properties (1)	Operated properties (1)	2,950		67,986		70,936		10,719		71,370		82,089		Operated properties (1)	123,907		277,124		401,031		2,950		67,986		70,936
Non-operated properties (2)	Non-operated properties (2)	(2,499)		9,076		6,577		3,068		6,946		10,014		Non-operated properties (2)	31,132		21,195		52,327		(2,499)		9,076		6,577
Total natural gas revenues	Total natural gas revenues	451		77,062		77,513		13,787		78,316		92,103		Total natural gas revenues	155,039		298,319		453,358		451		77,062		77,513
Crude oil and natural gas sales	Crude oil and natural gas sales	$	438,098	$	263,370	$	701,468	$	779,899	$	301,501	$	1,081,400	Crude oil and natural gas sales	$	930,534	$	525,647	$	1,456,181	$	438,098	$	263,370	$	701,468

Timing of revenue recognition	Timing of revenue recognition													Timing of revenue recognition
Goods transferred at a point in time	Goods transferred at a point in time	$	438,098	$	263,370	$	701,468	$	779,899	$	301,501	$	1,081,400	Goods transferred at a point in time	$	930,534	$	525,647	$	1,456,181	$	438,098	$	263,370	$	701,468
Goods transferred over time	Goods transferred over time	0		0		0		0		0		0		Goods transferred over time	—		—		—		—		—		—
		$	438,098	$	263,370	$	701,468	$	779,899	$	301,501	$	1,081,400		$	930,534	$	525,647	$	1,456,181	$	438,098	$	263,370	$	701,468


		Nine months ended September 30, 2020						Nine months ended September 30, 2019							Nine months ended September 30, 2021						Nine months ended September 30, 2020
In thousands	In thousands	North Region		South Region		Total		North Region		South Region		Total		In thousands	North Region		South Region		Total		North Region		South Region		Total
Crude oil revenues:	Crude oil revenues:													Crude oil revenues:
Operated properties	Operated properties	$	891,920	$	385,836	$	1,277,756	$	1,787,776	$	523,484	$	2,311,260	Operated properties	$	1,647,079	$	591,225	$	2,238,304	$	891,920	$	385,836	$	1,277,756
Non-operated properties	Non-operated properties	252,374		26,315		278,689		558,893		35,408		594,301		Non-operated properties	478,589		41,966		520,555		252,374		26,315		278,689
Total crude oil revenues	Total crude oil revenues	1,144,294		412,151		1,556,445		2,346,669		558,892		2,905,561		Total crude oil revenues	2,125,668		633,191		2,758,859		1,144,294		412,151		1,556,445
Natural gas revenues:	Natural gas revenues:													Natural gas revenues:
Operated properties (1)	Operated properties (1)	(7,974)		179,996		172,022		83,831		290,780		374,611		Operated properties (1)	280,416		828,409		1,108,825		(7,974)		179,996		172,022
Non-operated properties (2)	Non-operated properties (2)	(5,402)		15,798		10,396		18,985		29,252		48,237		Non-operated properties (2)	64,876		54,068		118,944		(5,402)		15,798		10,396
Total natural gas revenues	Total natural gas revenues	(13,376)		195,794		182,418		102,816		320,032		422,848		Total natural gas revenues	345,292		882,477		1,227,769		(13,376)		195,794		182,418
Crude oil and natural gas sales	Crude oil and natural gas sales	$	1,130,918	$	607,945	$	1,738,863	$	2,449,485	$	878,924	$	3,328,409	Crude oil and natural gas sales	$	2,470,960	$	1,515,668	$	3,986,628	$	1,130,918	$	607,945	$	1,738,863

Timing of revenue recognition	Timing of revenue recognition													Timing of revenue recognition
Goods transferred at a point in time	Goods transferred at a point in time	$	1,130,918	$	607,945	$	1,738,863	$	2,449,485	$	878,924	$	3,328,409	Goods transferred at a point in time	$	2,470,960	$	1,515,668	$	3,986,628	$	1,130,918	$	607,945	$	1,738,863
Goods transferred over time	Goods transferred over time	0		0		0		0		0		0		Goods transferred over time	—		—		—		—		—		—
		$	1,130,918	$	607,945	$	1,738,863	$	2,449,485	$	878,924	$	3,328,409		$	2,470,960	$	1,515,668	$	3,986,628	$	1,130,918	$	607,945	$	1,738,863

(1) Operated natural gas revenues for the North region include negative gas revenues totaling $2.5 million and $25.2 million for the three and nine month periods ended September 30, 2020, respectively.

(2) Non-operated natural gas revenues for the North region include negative gas revenues totaling $4.7 million and $12.5 million for the three and nine month periods ended September 30, 2020, respectively.

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 September 30, ~~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 and nine months ended September 30, ~~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 $2.2 million and $2.4 million at September 30, 2020 and December 31, 2019, which is reported as "Allowance for credit losses" in the condensed consolidated balance sheets. Aggregate credit loss expenses totaled less than $0.1 million and $1.4 million for the three months ended September 30, 2020 and 2019, respectively, and $1.4 million and $1.5 million for the nine months ended September 30, 2020 and 2019, respectively, which are 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

~~Continental Resources, Inc. and Subsidiaries~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

are extended based on an evaluation of each counterparty’s credit worthiness. The Company has not generally required its counterparties to provide collateral to secure its crude oil and natural gas sales receivables.

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

The Company’s allowance for credit losses on crude oil and natural gas sales was negligible at both September 30, 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 and nine month periods ended September 30, 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 $2.2 million and $2.4 million at September 30, 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 and nine month periods ended September 30, 2020.

Note 6.5. Derivative Instruments

From time to time the Company ~~has entered~~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 production. The Company recognizes its derivative instruments 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 ~~comprehensive income (loss)~~operations under the caption ~~"Gain (loss)~~"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 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. The calculation of the fair value of collars requires the use of an option-pricing model. See Note 7.6. Fair Value Measurements.

1211

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

At September 30, ~~2020~~2021 the Company had outstanding derivative contracts as set forth in the tables below.


Natural gas derivatives	Natural gas derivatives				Collars						Natural gas derivatives
					Floors			Ceilings
			Swaps Weighted Average Price		Range	Weighted Average Price		Range	Weighted Average Price					Weighted Average Hedge Price
Period and Type of Contract	Period and Type of Contract	MMBtus									Period and Type of Contract	Volumes Hedged		Swaps		Sold Put		Floor		Ceiling

October 2020 - December 2020
October 2021 - December 2021											October 2021 - December 2021
Swaps - Henry Hub	Swaps - Henry Hub	17,480,000	$	2.58							Swaps - Henry Hub	235,000	MMBtus/day	$	3.20
Collars - Henry Hub	Collars - Henry Hub	8,280,000			$2.60 - $2.80	$	2.73	$3.05 - $3.21	$	3.10	Collars - Henry Hub	90,000	MMBtus/day					$	3.00	$	5.32
January 2021 - December 2021
January 2022 - March 2022											January 2022 - March 2022
Swaps - Henry Hub	Swaps - Henry Hub	23,722,000	$	2.72							Swaps - Henry Hub	45,000	MMBtus/day	$	3.96
Collars - Henry Hub	Collars - Henry Hub	33,480,000			$2.60 - $3.00	$	2.72	$3.06 - $4.00	$	3.48	Collars - Henry Hub	90,000	MMBtus/day					$	3.00	$	6.33
January 2022 - December 2022
Three-way collars - Henry Hub											Three-way collars - Henry Hub	280,000	MMBtus/day			$	2.33	$	3.02	$	4.46
April 2022 - June 2022											April 2022 - June 2022
Swaps - Henry Hub	Swaps - Henry Hub	5,475,000	$	2.44							Swaps - Henry Hub	55,000	MMBtus/day	$	4.00
July 2022 - September 2022											July 2022 - September 2022
Swaps - Henry Hub											Swaps - Henry Hub	55,000	MMBtus/day	$	4.00

Crude oil derivatives

Period and Type of Contract

Volumes Hedged

Weighted Average Hedge Price

October 2021 - December 2021

NYMEX Roll Swaps

50,000

Bbls/day

0.64

January 2022 - March 2022

NYMEX Roll Swaps

22,500

Bbls/day

0.65

Derivative gains and losses

Cash receipts and payments in the following table reflect the 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. Non-cash gains and losses below represent the change in fair value of derivative instruments which continued to be held at period end and the reversal of previously recognized non-cash gains or losses on derivative contracts that matured during the period.

Three months ended September 30, Nine months ended September 30,
In thousands 2020 2019 2020 2019
Cash received (paid) on derivatives:
Crude oil fixed price swaps $ (14,205) $ 0 $ (21,328) $ 0
Natural gas fixed price swaps 4,253 30,484 4,253 46,799
Natural gas collars 0 0 0 5,417
Cash received (paid) on derivatives, net (9,952) 30,484 (17,075) 52,216
Non-cash gain (loss) on derivatives:
Crude oil fixed price swaps 10,101 0 0 0
Natural gas fixed price swaps (17,576) (32,606) (8,827) 3,468
Natural gas collars (426) 3,317 267 (2,165)
Non-cash gain (loss) on derivatives, net (7,901) (29,289) (8,560) 1,303
Gain (loss) on derivative instruments, net $ (17,853) $ 1,195 $ (25,635) $ 53,519

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements


	Three months ended September 30,				Nine months ended September 30,
In thousands	2021		2020		2021		2020
Cash received (paid) on derivatives:
Crude oil fixed price swaps	$	—	$	(14,205)	$	(44,462)	$	(21,328)
Crude oil collars	—		—		(9,365)		—
Crude oil NYMEX roll swaps	(156)		—		966		—
Natural gas fixed price swaps	(31,361)		4,253		(27,411)		4,253
Natural gas collars	(10,563)		—		(7,329)		—
Cash received (paid) on derivatives, net	(42,080)		(9,952)		(87,601)		(17,075)
Non-cash gain (loss) on derivatives:
Crude oil fixed price swaps	—		10,101		—		—
Crude oil collars	—		—		227		—
Crude oil NYMEX roll swaps	3,506		—		180		—
Natural gas fixed price swaps	(33,947)		(17,576)		(68,503)		(8,827)
Natural gas collars	(11,411)		(426)		(29,101)		267
Natural gas three-way collars	(43,178)		—		(47,997)		—
Non-cash gain (loss) on derivatives, net	(85,030)		(7,901)		(145,194)		(8,560)
Loss on derivative instruments, net	$	(127,110)	$	(17,853)	$	(232,795)	$	(25,635)

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.

~~Continental Resources, Inc. and Subsidiaries~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

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.


In thousands	In thousands	September 30, 2020		December 31, 2019		In thousands	September 30, 2021		December 31, 2020
Commodity derivative assets:	Commodity derivative assets:					Commodity derivative assets:
Gross amounts of recognized assets	Gross amounts of recognized assets	$	2,682	$	0	Gross amounts of recognized assets	$	19,465	$	15,900
Gross amounts offset on balance sheet	Gross amounts offset on balance sheet	(2,336)		0		Gross amounts offset on balance sheet	(17,378)		(597)
Net amounts of assets on balance sheet	Net amounts of assets on balance sheet	346		0		Net amounts of assets on balance sheet	2,087		15,303
Commodity derivative liabilities:	Commodity derivative liabilities:					Commodity derivative liabilities:
Gross amounts of recognized liabilities	Gross amounts of recognized liabilities	(11,242)		0		Gross amounts of recognized liabilities	(151,166)		(2,408)
Gross amounts offset on balance sheet	Gross amounts offset on balance sheet	2,336		0		Gross amounts offset on balance sheet	17,378		597
Net amounts of liabilities on balance sheet	Net amounts of liabilities on balance sheet	$	(8,906)	$	0	Net amounts of liabilities on balance sheet	$	(133,788)	$	(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	In thousands	September 30, 2020		December 31, 2019		In thousands	September 30, 2021		December 31, 2020
Derivative assets	Derivative assets	$	346	$	0	Derivative assets	$	314	$	15,303
Derivative assets, noncurrent	Derivative assets, noncurrent	0		0		Derivative assets, noncurrent	1,773		—
Net amounts of assets on balance sheet	Net amounts of assets on balance sheet	346		0		Net amounts of assets on balance sheet	2,087		15,303
Derivative liabilities	Derivative liabilities	(7,086)		0		Derivative liabilities	(131,616)		(227)
Derivative liabilities, noncurrent	Derivative liabilities, noncurrent	(1,820)		0		Derivative liabilities, noncurrent	(2,172)		(1,584)
Net amounts of liabilities on balance sheet	Net amounts of liabilities on balance sheet	(8,906)		0		Net amounts of liabilities on balance sheet	(133,788)		(1,811)
Total derivative liabilities, net		$	(8,560)	$	0
Total derivative assets (liabilities), net						Total derivative assets (liabilities), net	$	(131,701)	$	13,492

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

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

The following table summarizes the valuation of derivative instruments by pricing levels that were accounted for at fair value on a recurring basis as of September 30, ~~2020. The Company had no outstanding derivative instruments at~~2021 and December 31, ~~2019.~~2020.


		Fair value measurements at September 30, 2020 using:									Fair value measurements at September 30, 2021 using:
In thousands	In thousands	Level 1		Level 2		Level 3		Total		In thousands	Level 1		Level 2		Level 3		Total
Derivative assets (liabilities):	Derivative assets (liabilities):									Derivative assets (liabilities):
Swaps	Swaps	$	0	$	(8,827)	$	0	$	(8,827)	Swaps	$	—	$	(66,459)	$	—	$	(66,459)
Collars	Collars	0		267		0		$	267	Collars	—		(17,425)		—		(17,425)
Three-Way Collars										Three-Way Collars	—		(47,997)		—		(47,997)
NYMEX roll swaps										NYMEX roll swaps	—		180		—		180
Total	Total	$	0	$	(8,560)	$	0	$	(8,560)	Total	$	—	$	(131,701)	$	—	$	(131,701)



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

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

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 September 30, ~~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 ~~2021.~~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 and nine months ended September 30, 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 periods.

For the three and nine months ended September 30, 2020, the Company determined the carrying amounts of certain proved properties were not recoverable from future cash flows and therefore were impaired. Impairments of proved properties amounted to $1.6 million and $182.6 million for the three and nine months ended September 30, 2020, respectively, which reflect fair value adjustments on legacy properties in the Red River Units totaling $168.1 million, including $1.6 million in the 2020 third quarter, and various non-core properties in the North and South regions totaling $14.5 million. The impaired properties were written down to their estimated fair value at the time of impairment of $145.7 million. Impairments for the nine months ended September 30, 2020 also ~~include~~included a $24.5 million impairment recognized in the 2020 first quarter ~~of 2020~~ to reduce the Company's crude oil inventory to estimated net realizable value at the time of impairment.

For the three and nine months ended September 30, 2019, estimated future net cash flows were determined to be in excess of cost basis, therefore no impairment was recorded for the Company’s proved crude oil and natural gas properties for the 2019 periods.

~~Continental Resources, Inc. and Subsidiaries~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

Certain unproved crude oil and natural gas properties were impaired during the three and nine months ended September 30, ~~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 September 30,				Nine months ended September 30,
In thousands	2021		2020		2021		2020
Proved property and inventory impairments	$	—	$	1,574	$	—	$	207,119
Unproved property impairments	7,945		16,944		30,991		57,857
Total	$	7,945	$	18,518	$	30,991	$	264,976

Three months ended September 30, Nine months ended September 30,
In thousands 2020 2019 2020 2019
Proved property impairments $ 1,574 $ 0 $ 207,119 $ 0
Unproved property impairments 16,944 20,199 57,857 66,854
Total $ 18,518 $ 20,199 $ 264,976 $ 66,854

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

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.


		September 30, 2020				December 31, 2019					September 30, 2021				December 31, 2020
In thousands	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:									Debt:
Credit facility	Credit facility	$	475,000	$	475,000	$	55,000	$	55,000	Credit facility	$	—	$	—	$	160,000	$	160,000
Notes payable	Notes payable	25,137		25,600		5,351		5,400		Notes payable	22,923		22,500		24,590		24,700
5% Senior Notes due 2022	5% Senior Notes due 2022	1,099,378		1,090,600		1,099,165		1,108,700		5% Senior Notes due 2022	—		—		630,470		632,900
4.5% Senior Notes due 2023	4.5% Senior Notes due 2023	1,443,031		1,379,900		1,491,339		1,571,400		4.5% Senior Notes due 2023	647,789		673,600		646,943		669,900
3.8% Senior Notes due 2024	3.8% Senior Notes due 2024	906,645		847,400		994,310		1,034,200		3.8% Senior Notes due 2024	907,772		957,800		906,922		939,500
4.375% Senior Notes due 2028	4.375% Senior Notes due 2028	990,345		863,500		989,661		1,063,700		4.375% Senior Notes due 2028	991,592		1,106,500		990,746		1,024,400
5.75% Senior Notes due 2031										5.75% Senior Notes due 2031	1,481,951		1,813,000		1,480,879		1,651,900
4.9% Senior Notes due 2044	4.9% Senior Notes due 2044	691,822		530,300		691,688		742,000		4.9% Senior Notes due 2044	692,008		786,800		691,868		689,600
Total debt	Total debt	$	5,631,358	$	5,212,300	$	5,326,514	$	5,580,400	Total debt	$	4,744,035	$	5,360,200	$	5,532,418	$	5,792,900

The fair value of credit facility borrowings, if any, 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 notes payable is determined using a discounted cash flow approach based on the interest rate and payment terms of the notes payable and an assumed discount rate. The fair value of notes payable is significantly influenced by the discount rate assumption, which is derived by the Company and is unobservable. Accordingly, the fair value of notes payable is classified as Level 3 in the fair value hierarchy. ~~See~~ ~~Note 8. Long-Term Debt~~ ~~for discussion of the changes in the Company's notes payable in June 2020.~~

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.

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

Note 8.7. Long-Term Debt

Long-term debt, net of unamortized discounts, premiums, and debt issuance costs totaling ~~$29.5~~$39.6 million and ~~$33.9~~$43.7 million at September 30, ~~2020~~2021 and December 31, ~~2019,~~2020, respectively, consists of the following.


In thousands	In thousands	September 30, 2020		December 31, 2019		In thousands	September 30, 2021		December 31, 2020
Credit facility	Credit facility	$	475,000	$	55,000	Credit facility	$	—	$	160,000
Notes payable	Notes payable	25,137		5,351		Notes payable	22,923		24,590
5% Senior Notes due 2022	5% Senior Notes due 2022	1,099,378		1,099,165		5% Senior Notes due 2022	—		630,470
4.5% Senior Notes due 2023	4.5% Senior Notes due 2023	1,443,031		1,491,339		4.5% Senior Notes due 2023	647,789		646,943
3.8% Senior Notes due 2024	3.8% Senior Notes due 2024	906,645		994,310		3.8% Senior Notes due 2024	907,772		906,922
4.375% Senior Notes due 2028	4.375% Senior Notes due 2028	990,345		989,661		4.375% Senior Notes due 2028	991,592		990,746
5.75% Senior Notes due 2031						5.75% Senior Notes due 2031	1,481,951		1,480,879
4.9% Senior Notes due 2044	4.9% Senior Notes due 2044	691,822		691,688		4.9% Senior Notes due 2044	692,008		691,868
Total debt	Total debt	$	5,631,358	$	5,326,514	Total debt	$	4,744,035	$	5,532,418
Less: Current portion of long-term debt	Less: Current portion of long-term debt	2,225		2,435		Less: Current portion of long-term debt	2,306		2,245
Long-term debt, net of current portion	Long-term debt, net of current portion	$	5,629,133	$	5,324,079	Long-term debt, net of current portion	$	4,741,729	$	5,530,173

Credit Facility

~~The~~At September 30, 2021, the Company ~~has~~had an unsecured credit facility, maturing on April 9, 2023, with aggregate lender commitments totaling $1.5 billion. The Company had ~~$475 million of~~no outstanding borrowings on its credit facility at September 30, ~~2020.~~2021. On October 29, 2021, the Company amended its credit facility. See Note 13. Subsequent Events for further discussion.

~~Credit~~Borrowings under the 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 September 30, 2020 was 1.9%.~~

~~The Company had approximately $1.02 billion of borrowing availability on its credit facility at September 30, 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 September 30, ~~2020.~~

~~Continental Resources, Inc. and Subsidiaries~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

2021.

Senior Notes

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 September 30, ~~2020. In March and April 2020 the Company repurchased a portion of its 2023 Notes and 2024 Notes in open market transactions as further discussed below under the heading~~ ~~Retirement of Senior Notes~~.2021.

2022 Notes (1)

2023 Notes

2024 Notes

2028 Notes

2044 Notes

2023 Notes

2024 Notes

2028 Notes

2031 Notes

2044 Notes

Face value (in thousands)

$1,100,000

$1,449,625

$911,000

$1,000,000

$700,000

Face value (in thousands)

$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

June 1, 2044

Maturity date

April 15, 2023

June 1, 2024

January 15, 2028

January 15, 2031

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

Interest payment dates

April 15, Oct 15

June 1, Dec 1

Jan 15, July 15

Jan 15, Jul 15

June 1, Dec 1

Make-whole redemption period ~~(2)~~(1)

—

Jan 15, 2023

Mar 1, 2024

Oct 15, 2027

Dec 1, 2043

Make-whole redemption period ~~(2)~~(1)

Jan 15, 2023

Mar 1, 2024

Oct 15, 2027

Jul 15, 2030

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 governing the 2022 Notes plus any accrued and unpaid interest to the date of redemption.

~~(2)~~At any time prior to the indicated dates, the Company has the option to redeem all or a portion of its senior notes of the applicable series at the “make-whole” redemption amounts specified in the respective senior note indentures plus any accrued and unpaid interest to the date of redemption. On or after the indicated dates, the Company may redeem all or a portion of its senior notes at a redemption amount equal to 100% of the principal amount of the senior notes being redeemed plus any accrued and unpaid interest to the date of redemption.

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

The indentures governing the Company’s senior notes contain covenants that, among other things, limit the Company’s ability to create liens securing certain indebtedness, enter into certain sale-leaseback transactions, or consolidate, merge or transfer certain assets. These covenants are subject to a number of important exceptions and qualifications. The Company was in compliance with these covenants at September 30, ~~2020.~~2021.

~~Three~~

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

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, 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, whose assets, equity, and results of operations attributable to the Company are not material, do not guarantee the senior notes.

Retirement of Senior Notes

2021

In January 2021, the Company redeemed $400.0 million principal amount of its outstanding 2022 Notes and subsequently redeemed the remaining $230.8 million principal amount of its 2022 Notes in April 2021. The Company recognized pre-tax losses on extinguishment of debt totaling $0.3 million related to the redemptions, which included the pro-rata write-off of deferred financing costs and unamortized debt premium associated with the redeemed notes. The losses are reflected in the caption “Gain (loss) on extinguishment of debt” in the unaudited condensed consolidated statements of operations.

2020

In March and April 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~~$50.4 million face value of its 2023 Notes at an aggregate cost of ~~$19.5~~$29.3 million and ~~$7.0~~$89.0 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.~~

In April 2020, the Company repurchased 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$46.9 million, in each case, including accrued and unpaid interest to the repurchase dates.

The repurchased notes were canceled by the Company. The Company recognized pre-tax gains on extinguishment of debt ~~in the 2020 first quarter~~totaling $64.6 million related to the ~~March 2020~~ repurchases, ~~totaling $17.6 million and additional pre-tax gains on extinguishment of debt in the 2020 second quarter related to the April 2020 repurchases totaling $47.0 million,~~ which included the pro-rata write-off of deferred financing costs and unamortized debt discount associated with the ~~notes. The gains are reflected in the caption “Gain (loss) on extinguishment of debt” in the unaudited condensed consolidated statements of comprehensive income (loss).~~

~~2019~~

In September 2019, the Company redeemed $500 million of its previously outstanding $1.6 billion of 2022 Notes. The redemption price was equal to 100.833% of the principal amount called for redemption plus accrued and unpaid interest to the redemption date. The aggregate of the principal amount, redemption premium, and accrued interest paid upon redemption was~~$516.5 million. The Company recorded a pre-tax loss on extinguishment of debt related to the redemption of $4.6 million,~~

~~Continental Resources, Inc. and Subsidiaries~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

~~which included the redemption premium and pro-rata write-off of deferred financing costs and unamortized debt premium associated with the~~repurchased notes.

Notes payable

In June 2020, the Company borrowed an aggregate of $26.0 million under two 10-year amortizing term loans secured by the Company’s corporate office building and its interest in parking facilities in Oklahoma City, Oklahoma. The loans mature in May 2030 and bear interest at a fixed rate of 3.50% per 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 maturity date and, accordingly, ~~$2.2~~$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 September 30, ~~2020~~2021 associated with the loans. ~~A portion of the proceeds from the new loans was used to fully repay the Company's previous note payable that was set to mature in February 2022, which had a balance at pay-off of $4.4 million.~~

~~Note 9. Leases~~

The Company’s lease liabilities recognized on the balance sheet as a lessee totaled $10.2 million as of September 30, 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 costs associated with properties operated by the Company that are presented on a gross basis and do not represent the Company's net proportionate share of such amounts. A portion of these costs have been or will be billed to other working interest owners. Once paid, the Company's share of these costs are included in property and equipment, production expenses, or general and administrative expenses, as applicable. The Company's leasing activities as a lessor are negligible.


~~In thousands~~	~~Amount~~
~~Drilling rig commitments~~	$	~~3,661~~
~~Surface use agreements~~	~~4,998~~
~~Field equipment~~	~~1,026~~
~~Other~~	~~545~~
~~Total~~	$	~~10,230~~

~~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 September 30, 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.

In thousands Amount
Remainder of 2020 $ 1,872
2021 2,914
2022 868
2023 814
2024 540
Thereafter 6,707
Total operating lease liabilities, at undiscounted value $ 13,715
Less: Imputed interest (3,485)
Total operating lease liabilities, at discounted present value $ 10,230
Less: Current portion of operating lease liabilities (4,225)
Operating lease liabilities, net of current portion $ 6,005

~~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 primarily represent costs incurred for drilling rigs, most of which are short term contracts that are not recognized as right-of-use assets and lease liabilities on the balance sheet. Variable lease costs primarily represent differences between minimum payment obligations and actual operating day-rate charges incurred by the Company for its long term drilling rig contracts. Short-term lease costs primarily represent operating day-rate charges for drilling rig contracts with durations of one year or less and month-to-month field equipment rentals.~~A portion of such lease costs are borne by other interest owners.~~

Three months ended September 30, Nine months ended September 30,
In thousands, except weighted average data 2020 2019 2020 2019
Lease costs:
Operating lease costs $ 1,636 $ 2,784 $ 4,537 $ 9,330
Variable lease costs 55 3,820 4,190 11,633
Short-term lease costs 13,863 47,956 94,671 142,634
Total lease costs $ 15,554 $ 54,560 $ 103,398 $ 163,597
Other information:
Right-of-use assets obtained in exchange for new operating lease liabilities $ 38 $ 615 $ 7,377 $ 615
Operating cash flows from operating leases included in lease liabilities 259 202 674 600
Weighted average remaining lease term as of September 30 (in years) 11.4 9.2
Weighted average discount rate as of September 30 4.4 % 4.8 %

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

~~Included below is a discussion of certain future commitments and contingencies of the Company as of September 30, 2020.~~

~~Drilling rig commitments –~~ As of September 30, 2020, the Company has drilling rig contracts with various terms extending to April 2021. Future operating day-rate commitments as of September 30, 2020 total approximately $18 million, of which $12 million is expected to be incurred in the remainder of 2020 and $6 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 $3.7 million that are required to be recognized on the Company's balance sheet at September 30, 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~~Certain of 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 September 30, ~~2020~~2021 under the arrangements amount to approximately ~~$1.50~~$1.38 billion, of which ~~$54~~$73 million is expected to be incurred in the remainder of ~~2020, $224 million in~~ 2021, ~~$256~~$272 million in 2022, ~~$257~~$272 million in 2023, ~~$222~~$252 million in 2024, $164 million in 2025, and ~~$489~~$353 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.

Pending property acquisitions – The Company is in the process of executing various property acquisitions to increase its position in multiple strategic plays, which we expect will result in cash outlays of up to approximately $375 million in the fourth quarter of 2021 if completed. The acquisitions remain subject to the completion of customary due diligence procedures and satisfaction of closing conditions. Additionally, see Note 13. Subsequent Events for discussion of a definitive acquisition agreement executed by the Company subsequent to September 30, 2021.

Litigation – On April 15, 2020, Casillas Petroleum Resource Partners II, LLC filed a petition against the Company in the District Court of Tulsa County, State of Oklahoma alleging the Company breached a Purchase and Sale Agreement (“PSA”) to purchase oil and gas interests in Oklahoma for $200 million. The Company asserted the PSA was terminated due to Casillas’ breach of the PSA and denied the allegations. On October 16, 2020, the parties entered into a settlement agreement to amend and supplement the terms of the PSA, close on the transaction contemplated by the PSA for a negotiated amount, and settle all disputes involved in the litigation or that could have been raised in the litigation. The parties subsequently dismissed their respective claims in the litigation.

~~Continental Resources, Inc. and Subsidiaries~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

The Company is involved in various ~~other~~ legal proceedings including, but not limited to, commercial disputes, claims from royalty and surface owners, property damage claims, personal injury claims, regulatory compliance matters, disputes with tax authorities and other matters. While the outcome of these legal matters cannot be predicted with certainty, the Company does not expect them to have a material effect on its financial condition, results of operations or cash flows. As of September 30, ~~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.

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

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.

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~~$14.3 million and ~~$12.9~~$16.4 million for the three months ended September 30, ~~2020~~2021 and ~~2019,~~2020, respectively, and ~~$48.1~~$44.9 million and ~~$37.2~~$48.1 million for the nine months ended September 30, ~~2020~~2021 and ~~2019,~~2020, respectively.

In March 2019, the Company amended and restated its 2013 Plan and specified 12,983,543 shares of common stock may be issued pursuant to the amended plan. Subject to limited exceptions, the 2013 Plan allows previously issued shares to be reissued if such shares are subsequently forfeited or withheld to satisfy tax withholdings. As of September 30, ~~2020,~~2021, the Company had ~~10,876,574~~8,476,267 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 nine months ended September 30, ~~2020~~2021 is presented below.


		Number of non-vested shares	Weighted average grant-date fair value			Number of non-vested shares	Weighted average grant-date fair value
Non-vested restricted shares outstanding at December 31, 2019		3,461,908	$	46.82
Non-vested restricted shares outstanding at December 31, 2020					Non-vested restricted shares outstanding at December 31, 2020	4,890,638	$	36.26
Granted	Granted	2,582,990	27.73		Granted	2,900,923	23.51
Vested	Vested	(1,077,656)	45.97		Vested	(1,615,209)	45.49
Forfeited	Forfeited	(136,504)	36.85		Forfeited	(182,634)	27.14
Non-vested restricted shares outstanding at September 30, 2020		4,830,738	$	37.08
Non-vested restricted shares outstanding at September 30, 2021					Non-vested restricted shares outstanding at September 30, 2021	5,993,718	$	27.88

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 nine months ended September 30, ~~2020~~2021 was approximately ~~$27~~$40 million. As of September 30, ~~2020,~~2021, there was approximately ~~$82~~$81 million of unrecognized compensation expense related to non-vested restricted stock. This expense is expected to be recognized over a weighted average period of ~~1.5~~1.6 years.

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

2021 Share ~~repurchases~~Repurchases

During the three months ended ~~March~~September 30, 2021, the Company repurchased and retired approximately 1.9 million shares of its common stock at an aggregate cost of $65.3 million. The Company has repurchased and retired a cumulative total of approximately 15.7 million shares at an aggregate cost of $382.4 million since the inception of its $1 billion share repurchase program in June 2019.

2020 Share Repurchases

During the nine months ended September 31, 2020, the Company repurchased and retired approximately 8.1 million shares of its common stock at an aggregate cost of $126.9 million. No share repurchases were made during the three month periods ended June 30, 2020 and September 30, 2020. Through September 30, 2020, the Company had repurchased and retired a cumulative total of approximately 13.8 million shares at an aggregate cost of $317.1 million since the inception of its $1 billion share repurchase program in June 2019.

~~Continental Resources, Inc. and Subsidiaries~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

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

Dividend ~~payment~~Payments

On July 30, 2021, the Company declared a quarterly cash dividend of $0.15 per share on its outstanding common stock, which amounted to $54.1 million and was paid on August 20, 2021 to shareholders of record as of August 10, 2021.

On April 27, 2021, the Company declared a quarterly cash dividend of $0.11 per share on its outstanding common stock, which amounted to $40 million and was paid on May 24, 2021 to shareholders of record as of May 10, 2021.

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 uncertainty resulting from the COVID-19 pandemic, in April 2020 the Company’s quarterly dividend was suspended by the Board of Directors until further notice.

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 September 30,						Nine months ended September 30,							Three months ended September 30,						Nine months ended September 30,
		2020			2019			2020			2019				2021			2020			2021			2020
Provision (benefit) for income taxes (in thousands)	Provision (benefit) for income taxes (in thousands)	$	(13,972)		$	49,747		$	(138,350)		$	177,386		Provision (benefit) for income taxes (in thousands)	$	115,641		$	(13,972)		$	291,116		$	(138,350)
Effective tax rate	Effective tax rate	14.6		%	24.0		%	21.3		%	23.4		%	Effective tax rate	23.8		%	14.6		%	24.0		%	21.3		%

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 September 30,						Nine months ended September 30,							Three months ended September 30,						Nine months ended September 30,
In thousands, except tax rates	In thousands, except tax rates	2020			2019			2020			2019			In thousands, except tax rates	2021			2020			2021			2020
Income (loss) before income taxes	Income (loss) before income taxes	$	(95,555)		$	207,169		$	(648,848)		$	757,751		Income (loss) before income taxes	$	486,162		$	(95,555)		$	1,211,386		$	(648,848)
U.S. federal statutory tax rate	U.S. federal statutory tax rate	21.0		%	21.0		%	21.0		%	21.0		%	U.S. federal statutory tax rate	21.0		%	21.0		%	21.0		%	21.0		%
Expected income tax provision (benefit) based on U.S. federal statutory tax rate	Expected income tax provision (benefit) based on U.S. federal statutory tax rate	(20,067)			43,505			(136,258)			159,128			Expected income tax provision (benefit) based on U.S. federal statutory tax rate	102,094			(20,067)			254,391			(136,258)
Items impacting the effective tax rate:	Items impacting the effective tax rate:													Items impacting the effective tax rate:
State and local income taxes, net of federal benefit	State and local income taxes, net of federal benefit	(2,988)			7,312			(20,896)			26,648			State and local income taxes, net of federal benefit	17,109			(2,988)			43,559			(20,896)
Equity compensation	Equity compensation	214			92			4,685			(8,124)			Equity compensation	(11)			214			6,126			4,685
Other, net	Other, net	2,540			(1,162)			(90)			(266)			Other, net	(2,086)			2,540			(7,006)			(90)
Valuation allowance		6,329			0			14,209			0
Change in valuation allowance														Change in valuation allowance	(1,465)			6,329			(5,954)			14,209
Provision (benefit) for income taxes	Provision (benefit) for income taxes	$	(13,972)		$	49,747		$	(138,350)		$	177,386		Provision (benefit) for income taxes	$	115,641		$	(13,972)		$	291,116		$	(138,350)
Effective tax rate	Effective tax rate	14.6		%	24.0		%	21.3		%	23.4		%	Effective tax rate	23.8		%	14.6		%	24.0		%	21.3		%

~~The Company reduces its~~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. In the first quarter of~~planning strategies. During 2020, ~~the Company determined it was more-likely-than-not that a portion of its Oklahoma net operating loss ("NOL") carryforwards would not be able to be utilized before expiration, and~~ a valuation allowance ~~of approximately $4.9 million was~~had been established ~~at March 31, 2020~~ for the deferred tax ~~assets~~asset associated with a portion of the Company's Oklahoma state net operating loss carryforwards. In 2021, the Company reassessed the realizability of the deferred tax asset related to Oklahoma state net operating loss carryforwards, and based on current year activity, determined it was more likely than not that such ~~NOL carryforwards. The Company~~assets would be realized. Therefore, it was determined that the previously recorded valuation allowance in 2020 should be released throughout 2021, with $1.5 million and $5.9 million of release being recognized during the three and nine months ended September 30, 2021, respectively.

2220

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

recognized additional valuation allowances of $3.0 million and $6.3 million against such deferred tax assets during the three month periods ended June 30, 2020 and September 30, 2020, respectively, bringing the cumulative valuation allowance to $14.2 million as of September 30, 2020.

The Company will continue to evaluate both the positive and negative evidence on a quarterly basis in determining the need for a valuation allowance with respect to its deferred tax assets. Changes in positive and negative evidence, including differences between estimated and actual results, could result in changes in the valuation of our deferred tax assets that could have a material impact on our consolidated financial statements. Changes in existing tax laws could also affect actual tax results and the realization of deferred tax assets over time.

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 associated with the acquired properties.

Note 13. Subsequent Events

Credit Facility Amendment

On October 29, 2021, the Company amended its credit facility to increase the aggregate commitments from $1.5 billion to $1.7 billion and extend the maturity date from April 2023 to October 2026. The amended credit facility provides for benchmark replacement mechanics to address the transition from LIBOR, while all other terms, conditions, and covenants remain substantially unchanged.

Acquisition Agreement

On November 1, 2021, the Company executed a definitive agreement to acquire oil and gas properties and related assets in the Permian Basin of Texas from certain subsidiaries of Pioneer Natural Resources Company (“Pioneer”) for $3.25 billion of cash, subject to customary closing price adjustments. The properties include approximately 92,000 net leasehold acres, approximately 50,000 net royalty acres in the same area normalized to a 1/8th royalty, production totaling approximately 55,000 net barrels of oil equivalent per day (~70% oil) based on historical 3-stream reporting and including anticipated volumes from in-progress wells expected to be completed in first quarter 2022, and extensive water infrastructure. On the execution date the Company paid Pioneer a deposit of $325 million. Closing of the acquisition is expected to occur in December 2021 and remains subject to the completion of customary due diligence procedures and closing conditions, including the satisfaction of certain regulatory approvals. The Company expects to fund the acquisition through a combination of funding sources, including the use of cash on hand, utilization of credit facility borrowing capacity, and the issuance of debt securities and/or bank term loan facilities.

Dividend Declaration

On November 1, 2021, the Company declared a quarterly cash dividend of $0.20 per share on its outstanding common stock, which will be paid on November 26, 2021 to shareholders of record as of November 15, 2021.

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.~~2020.

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 and our Form 10-Qs for the quarters ended March 31, 2020 and June 30,~~ 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 operating results for the three and nine month periods ended September 30, 2020 discussed below were impacted by the economic effects from the COVID-19 pandemic on crude oil demand and prices and may not be indicative of future results. Given the economic uncertainty from the pandemic and ongoing volatility in commodity prices, it is difficult to predict the extent to which the pandemic or other factors will have on the Company’s performance during the remainder of 2020 and beyond.

Overview

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

~~Business Environment~~Third Quarter 2021 Highlights

Financial and ~~Outlook~~operating highlights for the third quarter of 2021 are summarized below. Our 2021 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~~•Generated $1.02 billion in operating cash flows in the third quarter, bringing year-to-date operating cash flows to ~~historically~~$2.73 billion;

•Third quarter operating cash flows exceeded net cash used in investing activities by $663 million, with cash on hand increasing to $694 million at September 30, 2021;

•Increased quarterly fixed dividend to $0.15 per share of common stock which was paid on August 20, 2021;

•Repurchased 1.9 million shares of common stock during the third quarter under our resumed share repurchase program at an aggregate cost of $65.3 million; and

•Continued to maintain low ~~levels in April~~cost operations with production expenses averaging $3.39 per Boe for the quarter.

Financial and Operating Metrics

Our operating results for 2020 ~~due primarily to reduced global and domestic demand for crude oil caused~~were severely impacted by the ~~impact of~~economic effects from the COVID-19 pandemic on crude oil demand and ~~resulting changes in consumer behavior and restrictions implemented by governments to mitigate the pandemic.~~prices. In response to the significant reduction in crude oil prices during 2020, we ~~began to voluntarily curtail our production beginning in April and ultimately~~ curtailed approximately 55% of our operated crude oil production and associated natural gas in the 2020 second ~~quarter. Additionally, we implemented cost saving initiatives~~quarter and significantly reduced our ~~operated rig and completion crew counts in order to preserve our assets and better align our~~ capital ~~spending with expected available cash flows.~~

Crude oil prices began to show signs of stabilization and improvement in mid-2020 in response to the gradual lifting of COVID-19 restrictions, the resumption of economic activity, and the resulting increase in crude oil demand.spending. In July 2020 we began to gradually restore our curtailed production and subsequently brought our remaining curtailed production back online in ~~September. As a result,~~September 2020. These actions resulted in material reductions in our ~~total average~~ production, ~~improved to 297,001 Boe per day~~revenues, and cash flows for the ~~2020 third quarter, representing a 46% increase~~nine months ended September 30, 2020.

Crude oil and natural gas prices have increased significantly in 2021 compared to 2020 levels in response to the ~~second quarter~~lifting of ~~2020, yet still remaining 11% lower than~~COVID-19 restrictions, the ~~third quarter~~resumption of ~~2019. Total production for~~economic activity, and the ~~month~~resulting improvement in supply and demand fundamentals. The increase in commodity prices and resumption of ~~September 2020 averaged 339,600 Boe per day. Our production volumes are evaluated on an ongoing basis and are subject to change as market conditions evolve.~~

~~In the third quarter of 2020, we continued~~ our ~~commitment to~~operations resulted in significantly improved operating results in a disciplined, capital efficient manner. Our non-acquisition capital spending continued to trend lower during the 2020 third quarter and totaled $149.4 million, a 22% sequential decrease from our 2020 second quarter spending. This was significantly lower than our 2020 third quarter operating cash flows which totaled $291.2 million, thus allowing for a $112 million reduction in our outstanding debt during the quarter. Additionally, despite production curtailments, we continued to drive our per-unit production expenses lower to $3.19 per Boe for the 2020 third quarter2021 compared to ~~$3.58 per Boe for the~~ 2020 ~~second quarter and $3.73 per Boe for the 2019 third quarter.~~

~~We remain committed to the responsible stewardship of our assets and continue to focus on maximizing free cash flows,~~as further reducing debt, delivering low-cost capital efficient operations, and generating sustainable shareholder value. The depth and quality of our asset base, the commodity optionality provided by our predominant amount of acreage held by production, and our financial strength allow us to be adaptable in a variety of price environments. We remain flexible as we monitor and adapt to market conditions. See the subsequent section titled ~~Liquidity and Capital Resources~~ ~~for additional discussion of our financial condition.~~

~~Financial and Operating Metrics~~described below.

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 September 30, Nine months ended September 30,
2020 2019 2020 2019
Average daily production:
Crude oil (Bbl per day) 169,265 198,074 155,088 195,209
Natural gas (Mcf per day) 766,416 805,446 791,005 820,679
Crude oil equivalents (Boe per day) 297,001 332,315 286,922 331,989
Average net sales prices (1):
Crude oil ($/Bbl) $ 35.93 $ 51.28 $ 33.71 $ 51.99
Natural gas ($/Mcf) $ 0.98 $ 1.12 $ 0.72 $ 1.78
Crude oil equivalents ($/Boe) $ 23.23 $ 33.30 $ 20.21 $ 34.95
Crude oil net sales price discount to NYMEX ($/Bbl) $ (5.00) $ (5.15) $ (6.03) $ (5.01)
Natural gas net sales price discount to NYMEX ($/Mcf) $ (1.05) $ (1.11) $ (1.19) $ (0.90)
Production expenses ($/Boe) $ 3.19 $ 3.73 $ 3.45 $ 3.68
Production taxes (% of net crude oil and natural gas sales) 7.8 % 8.5 % 8.3 % 8.4 %
Depreciation, depletion, amortization and accretion ($/Boe) $ 16.58 $ 15.81 $ 16.37 $ 16.18
Total general and administrative expenses ($/Boe) $ 1.63 $ 1.54 $ 1.65 $ 1.57


	Three months ended September 30,						Nine months ended September 30,
	2021			2020			2021			2020
Average daily production:
Crude oil (Bbl per day)	157,153			169,265			158,609			155,088
Natural gas (Mcf per day)	1,045,521			766,416			1,004,954			791,005
Crude oil equivalents (Boe per day)	331,407			297,001			326,102			286,922
Average net sales prices (1):
Crude oil ($/Bbl)	$	66.48		$	35.93		$	60.79		$	33.71
Natural gas ($/Mcf)	$	4.62		$	0.98		$	4.38		$	0.72
Crude oil equivalents ($/Boe)	$	46.07		$	23.23		$	43.04		$	20.21
Crude oil net sales price discount to NYMEX ($/Bbl)	$	(4.09)		$	(5.00)		$	(4.13)		$	(6.03)
Natural gas net sales price premium (discount) to NYMEX ($/Mcf)	$	0.62		$	(1.05)		$	1.17		$	(1.19)
Production expenses ($/Boe)	$	3.39		$	3.19		$	3.29		$	3.45
Production taxes (% of net crude oil and natural gas sales)	7.3		%	7.8		%	7.3		%	8.3		%
Depreciation, depletion, amortization and accretion ($/Boe)	$	15.29		$	16.58		$	16.26		$	16.37
Total general and administrative expenses ($/Boe)	$	1.92		$	1.63		$	1.87		$	1.65

(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 September 30, ~~2020~~2021 compared to the three months ended September 30, ~~2019~~2020

Results of Operations

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


		Three months ended September 30,					Three months ended September 30,
In thousands	In thousands	2020		2019		In thousands	2021		2020
Crude oil and natural gas sales	Crude oil and natural gas sales	$	701,468	$	1,081,400	Crude oil and natural gas sales	$	1,456,181	$	701,468
Gain (loss) on derivative instruments, net		(17,853)		1,195
Loss on derivative instruments, net						Loss on derivative instruments, net	(127,110)		(17,853)
Crude oil and natural gas service operations	Crude oil and natural gas service operations	8,755		21,602		Crude oil and natural gas service operations	12,341		8,755
Total revenues	Total revenues	692,370		1,104,197		Total revenues	1,341,412		692,370
Operating costs and expenses	Operating costs and expenses	(724,265)		(825,473)		Operating costs and expenses	(795,701)		(724,265)
Other expenses, net	Other expenses, net	(63,660)		(71,555)		Other expenses, net	(59,549)		(63,660)
Income (loss) before income taxes	Income (loss) before income taxes	(95,555)		207,169		Income (loss) before income taxes	486,162		(95,555)
(Provision) benefit for income taxes	(Provision) benefit for income taxes	13,972		(49,747)		(Provision) benefit for income taxes	(115,641)		13,972
Net income (loss)	Net income (loss)	(81,583)		157,422		Net income (loss)	370,521		(81,583)
Net loss attributable to noncontrolling interests		(2,161)		(740)
Net income (loss) attributable to noncontrolling interests						Net income (loss) attributable to noncontrolling interests	1,193		(2,161)
Net income (loss) attributable to Continental Resources	Net income (loss) attributable to Continental Resources	$	(79,422)	$	158,162	Net income (loss) attributable to Continental Resources	$	369,328	$	(79,422)
Production volumes:	Production volumes:					Production volumes:
Crude oil (MBbl)	Crude oil (MBbl)	15,572		18,223		Crude oil (MBbl)	14,458		15,572
Natural gas (MMcf)	Natural gas (MMcf)	70,510		74,101		Natural gas (MMcf)	96,188		70,510
Crude oil equivalents (MBoe)	Crude oil equivalents (MBoe)	27,324		30,573		Crude oil equivalents (MBoe)	30,489		27,324
Sales volumes:	Sales volumes:					Sales volumes:
Crude oil (MBbl)	Crude oil (MBbl)	16,063		18,258		Crude oil (MBbl)	14,404		16,063
Natural gas (MMcf)	Natural gas (MMcf)	70,510		74,101		Natural gas (MMcf)	96,188		70,510
Crude oil equivalents (MBoe)	Crude oil equivalents (MBoe)	27,815		30,608		Crude oil equivalents (MBoe)	30,435		27,815

Production

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

Boe production per day 3Q 2020 3Q 2019 % Change
Bakken 160,661 191,268 (16 %)
SCOOP 98,697 80,115 23 %
STACK 30,853 53,070 (42 %)
All other 6,790 7,862 (14 %)
Total 297,001 332,315 (11 %)


Boe production per day	3Q 2021	3Q 2020	% Change
Bakken	167,604	160,661	4	%
SCOOP	119,678	98,697	21	%
STACK	32,844	30,853	6	%
Powder River Basin	4,937	—	—
All other	6,344	6,790	(7	%)
Total	331,407	297,001	12	%

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


		Three months ended September 30,						Volume decrease	Volume percent decrease			Three months ended September 30,						Volume increase (decrease)	Volume percent increase (decrease)
		2020			2019							2021			2020
		Volume	Percent		Volume	Percent						Volume	Percent		Volume	Percent
Crude oil (MBbl)	Crude oil (MBbl)	15,572	57	%	18,223	60	%	(2,651)	(15	%)	Crude oil (MBbl)	14,458	47	%	15,572	57	%	(1,114)	(7	%)
Natural gas (MMcf)	Natural gas (MMcf)	70,510	43	%	74,101	40	%	(3,591)	(5	%)	Natural gas (MMcf)	96,188	53	%	70,510	43	%	25,678	36	%
Total (MBoe)	Total (MBoe)	27,324	100	%	30,573	100	%	(3,249)	(11	%)	Total (MBoe)	30,489	100	%	27,324	100	%	3,165	12	%

		Three months ended September 30,						Volume decrease	Volume percent decrease			Three months ended September 30,						Volume increase	Volume percent increase
		2020			2019							2021			2020
		MBoe	Percent		MBoe	Percent						MBoe	Percent		MBoe	Percent
North Region	North Region	15,402	56	%	18,312	60	%	(2,910)	(16	%)	North Region	16,455	54	%	15,402	56	%	1,053	7	%
South Region	South Region	11,922	44	%	12,261	40	%	(339)	(3	%)	South Region	14,034	46	%	11,922	44	%	2,112	18	%

Total	Total	27,324	100	%	30,573	100	%	(3,249)	(11	%)	Total	30,489	100	%	27,324	100	%	3,165	12	%

Over the past year we increased our allocation of capital to gas-weighted projects to capitalize on improvements in market prices for natural gas and natural gas liquids. These actions contributed to an increase in our natural gas production as a percentage of total production and led to a 36% increase in natural gas production for the 2021 third quarter compared to the 2020 third quarter. Natural gas production in SCOOP increased 16,312 MMcf, or 50%, and natural gas production in the Bakken increased 6,899 MMcf, or 29%, over the prior year third quarter. Additionally, properties acquired in the Powder River Basin in March 2021 added 652 MMcf to our 2021 third quarter natural gas production.

The ~~15%~~7% decrease in crude oil production for the ~~2020~~2021 third quarter compared to the ~~2019~~2020 third quarter was driven by ~~production curtailments initiated during~~our change in allocation of capital from oil-weighted projects to gas-weighted projects over the ~~2020 second quarter that continued into~~past year and the ~~third quarter coupled with limited drilling and completion activities,~~timing of well completions, which led to a ~~2,606~~788 MBbls, or ~~19%~~22%, decrease in SCOOP crude oil production, a 511 MBbls, or 5%, decrease in Bakken crude oil production, and a ~~442~~120 MBbls, or ~~46%~~23%, decrease in STACK crude oil ~~production. These decreases were partially offset by a 495 MBbls, or 16%, increase in SCOOP crude oil~~ production ~~due~~compared to ~~new well completions over the past year in our oil-weighted Project SpringBoard, which exceeded the adverse impact of production curtailments in the play in~~ the 2020 third quarter.

~~Our production curtailments and limited drilling and completion activities also impacted~~ Properties acquired in the Powder River Basin of Wyoming in March 2021 added 346 MBbls to our ~~natural gas production, leading to a 5% decrease in natural gas production for the 2020~~2021 third quarter compared to the 2019 third quarter. Natural gas production in the Bakken decreased 1,260 MMcf, or 5%, and natural gas production in STACK decreased 9,612 MMcf, or 41%, from the prior year third quarter. These decreases were partially offset by a 7,290 MMcf, or 29%, increase in SCOOP natural gas production in conjunction with the previously described increase in SCOOPcrude oil ~~production over the prior year period.~~production.

Revenues

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 ~~$646.2 million~~$1.40 billion for the third quarter of ~~2020,~~2021, a ~~37% decrease~~117% increase compared to net sales of ~~$1.02 billion~~$646.2 million for the ~~2019~~2020 third quarter due to significant ~~decreases~~increases in net sales prices and total sales volumes as discussed below.

Total sales volumes for the third quarter of ~~2020 decreased 2,793~~2021 increased 2,620 MBoe, or 9%, compared to the ~~2019~~2020 third quarter, reflecting reduced sales ~~from~~in the prior year period due to the previously described production curtailments ~~that impacted~~in the ~~current period.~~second and third quarters of 2020 and our subsequent resumption of usual operations. For the third quarter of 2021, our natural gas sales volumes increased 36% compared to the 2020 third quarter while our crude oil sales volumes decreased ~~12% from~~10% driven by our increased allocation of capital toward gas-weighted projects over the ~~comparable 2019 period, while our natural gas sales volumes decreased 5%.~~past year.

Our crude oil net sales prices averaged ~~$35.93~~$66.48 per barrel in the ~~2020~~2021 third quarter ~~a decrease of 30%~~ compared to ~~$51.28~~$35.93 per barrel for the ~~2019~~2020 third quarter due to ~~significantly reduced~~a significant increase in market ~~prices.~~prices from improved supply and demand fundamentals along with improved price differentials. The differential between NYMEX West Texas Intermediate ("WTI") calendar month prices and our realized crude oil net sales prices ~~improved~~averaged $4.09 per barrel for the 2021 third quarter compared to $5.00 per barrel for the 2020 third ~~quarter compared to $5.15 per barrel for the 2019 third~~ quarter.

~~See the subsequent section titled~~ ~~Future Capital Requirements–Commitments and contingencies~~ for discussion of pending legal disputes that could impact the future operation of the Dakota Access Pipeline ("DAPL") owned by a third party that we and other operators utilize to transport Bakken crude Crude oil ~~production to market centers outside the basin. A restriction of DAPL's takeaway capacity could impact prices for Bakken-produced barrels and result in wider differentials relative to WTI benchmark~~ prices in the ~~future,~~2020 third quarter were impacted by adverse changes in supply and demand fundamentals from the ~~amount~~economic effects of the COVID-19 pandemic, which ~~is uncertain. If transportation capacity on DAPL becomes restricted or unavailable, we have~~negatively impacted location differentials and price realizations in the ~~ability to utilize other~~2020 third ~~party pipelines or rail facilities to transport our Bakken crude oil production to market, although such alternatives could be more costly.~~quarter with no similar impacts in the 2021 third quarter.

Our natural gas net sales prices averaged $4.62 per Mcf for the 2021 third quarter compared to $0.98 per Mcf for the 2020 third quarter ~~a decrease of 13% compared to $1.12 per Mcf for the 2019 third quarter~~ due to ~~significantly reduced~~a significant increase in market ~~prices.~~prices and improved price differentials. The ~~discount~~difference between our net sales prices and NYMEX Henry Hub calendar month natural gas prices ~~improved~~was a premium of $0.62 per Mcf for the 2021 third quarter compared to a discount of $1.05 per Mcf for the 2020 ~~third quarter compared to $1.11 per Mcf for the 2019~~ third quarter. We sell the majority of our operated natural gas production to midstream customers at lease locations based on market prices in the field where the sales occur. The field markets are impacted by residue gas and natural gas liquids ("NGLs") prices at secondary, downstream markets. ~~As a result of reduced residue gas and~~ NGL prices ~~under certain of our arrangements on operated properties, the contractual pricing adjustments applied by midstream customers exceeded the sales consideration we were entitled~~have increased significantly in 2021 compared to ~~receive,~~2020 levels in conjunction with increased crude oil prices and other factors, resulting in a net payment owed by us to the customers. Additionally, in some instances on non-operated properties, the costs incurred by the outside operator exceeded the consideration we were entitled to receive, resulting in a net payment owed by us to the outside operator. The net amounts paid or payable under these arrangements on operated and non-operated properties totaled $7.2 millionsignificantly improved price realizations for ~~the 2020 third quarter, and are reflected as a reduction of~~our natural gas ~~revenues and net~~ sales stream relative to benchmark prices. ~~Nearly all of such amounts are associated with our North region natural gas production.~~

Derivatives. ~~Changes~~The significant improvement in ~~market~~commodity prices during the third quarter of ~~2020~~2021 had an overall unfavorable impact on the fair value of our derivatives, which resulted in negative revenue adjustments of ~~$17.9~~$127.1 million for the period, representing $42.1 million of cash losses and $85.0 million of unsettled non-cash losses, compared to ~~positive~~negative revenue adjustments ~~of $1.2~~totaling $17.9 million in the ~~comparable 2019 period.~~2020 third quarter.

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 $12.8~~increased $3.6 million, or ~~59%~~41%, from ~~$21.6 million for the third quarter of 2019 to~~ $8.8 million for the third quarter of 2020 to $12.3 million for the third quarter of 2021 due to ~~reduced~~increased water handling activities resulting from ~~our curtailment of~~the previously described increase in completion activities and production ~~and limited completion projects undertaken during the current quarter. The decreased activities also resulted in a reduction in service-related expenses~~volumes compared to the ~~prior period.~~ 2020 third quarter.

Operating Costs and Expenses

Production Expenses. Production expenses ~~decreased $25.4~~increased $14.5 million, or ~~22%~~16%, ~~from $114.1~~to $103.2 million for the third quarter of ~~2019~~2021 compared to $88.7 million for the third quarter of ~~2020. This decrease resulted from reduced service costs being incurred~~2020 primarily due to the previously described 9% increase in conjunction with production curtailments and 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 Bakken, all of which led to a reduction in our productiontotal sales volumes. Production expenses on a per-Boe basis averaged $3.39 per Boe for the 2021 third quarter compared to $3.19 per Boe for the 2020 third ~~quarter compared to $3.73 per Boe for the 2019 third~~ quarter.

Production Taxes. Production taxes ~~decreased $36.7~~increased $52.2 million ~~or 42%,~~to $102.4 million for the third quarter of 2021 compared to $50.2 million for the third quarter of 2020 ~~compared to $86.9 million for the third quarter of 2019 primarily~~ due to ~~a 35% decrease~~the previously described 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 decreased ~~from 8.5%~~to 7.3% for the third quarter of ~~2019~~2021 compared to 7.8% for the third quarter of 2020 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 North Dakota.

Depreciation, Depletion, Amortization and Accretion. Total DD&A ~~decreased $22.8~~increased $4.2 million, or 5%1%, to $465.4 million for the third quarter of 2021 compared to $461.2 million for the third quarter of 2020 ~~compared to $484.0 million for the third quarter of 2019~~ primarily due to athe previously described 9% ~~decrease~~increase in total sales ~~volumes.~~volumes, the impact of which was partially offset by a decrease 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.


		Three months ended September 30,					Three months ended September 30,
$/Boe	$/Boe	2020		2019		$/Boe	2021		2020
Crude oil and natural gas	Crude oil and natural gas	$	16.32	$	15.58	Crude oil and natural gas	$	14.98	$	16.32
Other equipment	Other equipment	0.18		0.16		Other equipment	0.22		0.18
Asset retirement obligation accretion	Asset retirement obligation accretion	0.08		0.07		Asset retirement obligation accretion	0.09		0.08
Depreciation, depletion, amortization and accretion	Depreciation, depletion, amortization and accretion	$	16.58	$	15.81	Depreciation, depletion, amortization and accretion	$	15.29	$	16.58

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

Our proved reserves were revised upward in mid-2021 prompted by significant increases in first-day-of-the-month commodity prices and other factors, which resulted in a decrease in our DD&A rate for crude oil and natural gas properties in the third quarter of 2021 compared to the third quarter of 2020. If commodity prices remain at current elevated levels ~~or decline further, downward~~for an extended period, additional upward price-related revisions of ~~our~~ proved reserves ~~could~~may occur ~~at year-end 2020,~~in the future, which may be significant and ~~would~~could result in ~~an increase~~a further decrease in our DD&A ~~rate for subsequent periods.~~rate. 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. Total property impairments decreased ~~$1.7~~$10.6 million, or 57%, to $7.9 million for the third quarter of 2021 compared to $18.5 million for the third quarter of 2020, ~~compared to $20.2 million for the third quarter of 2019. Impairments of unproved properties decreased $3.3 million~~primarily reflecting a decrease in the ~~balance~~amortization of ~~unamortized~~undeveloped leasehold costs ~~over~~from changes in management's estimates of properties not expected to be developed before lease expiration in response to significantly improved commodity prices compared to the ~~past~~prior year. ~~Proved~~There were no proved property impairments ~~of $1.6 million were~~ recognized in the third quarter of ~~2020~~2021 compared to ~~no proved property impairments~~$1.6 million recognized in the third quarter of ~~2019.~~2020.

General and Administrative Expenses. Total G&A expenses ~~decreased $1.7~~increased $13.1 million, or 4%29%, to $58.4 million for the third quarter of 2021 compared to $45.3 million for the third quarter of ~~2020 compared to $47.0 million for the third quarter of 2019.~~2020.

Total G&A expenses include non-cash charges for equity compensation of ~~$16.4~~$14.3 million and ~~$12.9~~$16.4 million for the third quarters of 2021 and 2020, and 2019, respectively, the increase of which was due to additional grants of restricted stock awards coupled with higher forfeitures of unvested restricted stock in the 2019 third quarter that resulted in lower equity compensation expense for that period.

respectively. G&A expenses other than equity compensation totaled $44.1 million for the 2021 third quarter, an increase of $15.2 million, or 53%, compared to $28.9 million for the 2020 third ~~quarter, a decrease of $5.2 million, or 15%, compared to $34.1 million for the 2019 third~~ quarter. This ~~decrease~~increase was primarily due to ~~a reduction~~an increase in employee benefits ~~and other efforts to reduce spending in response to significantly reduced commodity prices and economic turmoil from the~~

~~COVID-19 pandemic,~~ partially offset by ~~lower~~higher overhead recoveries from joint interest owners driven by ~~reduced~~increased drilling, completion, and production ~~activities.~~activities compared to the 2020 third quarter.

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

Three months ended September 30,
$/Boe 2020 2019
General and administrative expenses $ 1.04 $ 1.12
Non-cash equity compensation 0.59 0.42
Total general and administrative expenses $ 1.63 $ 1.54

The increase in equity compensation expenses on a per-Boe basis in 2020 was driven by a 9% decrease in total sales volumes with no similar reduction in equity compensation expenses, as such expenses continue to be recognized irrespective of sales volumes.


	Three months ended September 30,
$/Boe	2021		2020
General and administrative expenses	$	1.45	$	1.04
Non-cash equity compensation	0.47		0.59
Total general and administrative expenses	$	1.92	$	1.63

Interest Expense. Interest expense decreased ~~$4.2~~$4.0 million, or 6%, to $59.9 million for the third quarter of 2021 compared to $63.9 million for the third quarter of 2020 ~~compared to $68.1 million for the third quarter of 2019~~ due to a decrease in our ~~weighted average interest rate from changes in the mix of~~total outstanding ~~debt between periods driven by the redemption or repurchase of senior notes over the past year using available cash and lower-rate credit facility borrowings.~~debt. Our weighted average outstanding debt balance was $4.8 billion for the ~~2020~~ third quarter ~~was approximately~~of 2021 compared to $5.8 billion ~~with a weighted average interest rate of 4.2% compared to averages of $5.8 billion and 4.5%~~ for the ~~2019~~ third ~~quarter.~~quarter of 2020.

Income Taxes. For the third 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 $115.6 million for the ~~United States. We recorded~~2021 third quarter and an income tax benefit of $14.0 million for the 2020 third quarter, ~~and an income tax provision of $49.7 million for the 2019 third quarter,~~ which resulted in effective tax rates of ~~14.6%~~23.8% and ~~24.0%~~14.6%, 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.

Nine months ended September 30, ~~2020~~2021 compared to the nine months ended September 30, ~~2019~~2020

Results of Operations

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

Nine months ended September 30,
In thousands 2020 2019
Crude oil and natural gas sales $ 1,738,863 $ 3,328,409
Gain (loss) on derivative instruments, net (25,635) 53,519
Crude oil and natural gas service operations 35,602 54,886
Total revenues 1,748,830 3,436,814
Operating costs and expenses (2,271,089) (2,473,277)
Other expenses, net (1) (126,589) (205,786)
Income (loss) before income taxes (648,848) 757,751
(Provision) benefit for income taxes 138,350 (177,386)
Net income (loss) (510,498) 580,365
Net loss attributable to noncontrolling interests (6,126) (1,330)
Net income (loss) attributable to Continental Resources $ (504,372) $ 581,695
Production volumes:
Crude oil (MBbl) 42,494 53,292
Natural gas (MMcf) 216,735 224,045
Crude oil equivalents (MBoe) 78,617 90,633
Sales volumes:
Crude oil (MBbl) 42,583 53,179
Natural gas (MMcf) 216,735 224,045
Crude oil equivalents (MBoe) 78,706 90,520

~~(1) Net of gain on extinguishment of debt of $64.6 million for the nine months ended September 30, 2020. See~~ ~~Notes to Unaudited Condensed Consolidated Financial Statements–Note 8. Long-Term Debt~~ ~~for further discussion.~~


	Nine months ended September 30,
In thousands	2021		2020
Crude oil and natural gas sales	$	3,986,628	$	1,738,863
Loss on derivative instruments, net	(232,795)		(25,635)
Crude oil and natural gas service operations	38,519		35,602
Total revenues	3,792,352		1,748,830
Operating costs and expenses	(2,395,775)		(2,271,089)
Other expenses, net	(185,191)		(126,589)
Income (loss) before income taxes	1,211,386		(648,848)
(Provision) benefit for income taxes	(291,116)		138,350
Net income (loss)	920,270		(510,498)
Net income (loss) attributable to noncontrolling interests	1,975		(6,126)
Net income (loss) attributable to Continental Resources	$	918,295	$	(504,372)
Production volumes:
Crude oil (MBbl)	43,300		42,494
Natural gas (MMcf)	274,352		216,735
Crude oil equivalents (MBoe)	89,026		78,617
Sales volumes:
Crude oil (MBbl)	43,257		42,583
Natural gas (MMcf)	274,352		216,735
Crude oil equivalents (MBoe)	88,982		78,706

Production

The following table summarizes the changes in our average daily Boe production by major operating area for the year to date period.


Boe production per day	Boe production per day	YTD 9/30/2020	YTD 9/30/2019	% Change		Boe production per day	YTD 9/30/2021	YTD 9/30/2020	% Change
Bakken	Bakken	150,366	194,872	(23	%)	Bakken	167,632	150,366	11	%
SCOOP	SCOOP	92,958	73,127	27	%	SCOOP	112,572	92,958	21	%
STACK	STACK	36,567	55,585	(34	%)	STACK	35,054	36,567	(4	%)
Powder River Basin						Powder River Basin	4,477	—	—
All other	All other	7,031	8,405	(16	%)	All other	6,367	7,031	(9	%)
Total	Total	286,922	331,989	(14	%)	Total	326,102	286,922	14	%

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


		Nine months ended September 30,						Volume decrease	Volume percent decrease			Nine months ended September 30,						Volume increase	Volume percent increase
		2020			2019							2021			2020
		Volume	Percent		Volume	Percent						Volume	Percent		Volume	Percent
Crude oil (MBbl)	Crude oil (MBbl)	42,494	54	%	53,292	59	%	(10,798)	(20	%)	Crude oil (MBbl)	43,300	49	%	42,494	54	%	806	2	%
Natural gas (MMcf)	Natural gas (MMcf)	216,735	46	%	224,045	41	%	(7,310)	(3	%)	Natural gas (MMcf)	274,352	51	%	216,735	46	%	57,617	27	%
Total (MBoe)	Total (MBoe)	78,617	100	%	90,633	100	%	(12,016)	(13	%)	Total (MBoe)	89,026	100	%	78,617	100	%	10,409	13	%

		Nine months ended September 30,						Volume increase (decrease)	Volume percent increase (decrease)			Nine months ended September 30,						Volume increase	Volume percent increase
		2020			2019							2021			2020
		MBoe	Percent		MBoe	Percent						MBoe	Percent		MBoe	Percent
North Region	North Region	43,118	55	%	55,464	61	%	(12,346)	(22	%)	North Region	48,718	55	%	43,118	55	%	5,600	13	%
South Region	South Region	35,499	45	%	35,169	39	%	330	1	%	South Region	40,307	45	%	35,499	45	%	4,808	14	%
Total	Total	78,617	100	%	90,633	100	%	(12,016)	(13	%)	Total	89,025	100	%	78,617	100	%	10,408	13	%

The ~~20% decrease~~previously described increase in our allocation of capital to gas-weighted projects over the past year contributed to an increase in our natural gas production as a percentage of total production and led to a 27% increase in natural gas production for year to date 2021 compared to year to date 2020. Natural gas production in SCOOP increased 35,624 MMcf, or 37%, and natural gas production in the Bakken increased 21,839 MMcf, or 32%, over the prior year period. Additionally, properties acquired in the Powder River Basin in March 2021 added 1,697 MMcf to our 2021 year to date natural gas production.

The 2% increase in crude oil production for year to date ~~2020~~2021 compared to year to date ~~2019~~2020 was primarily driven by ~~an 11,136~~a 923 MBbls, or ~~27%~~3%, increase in Bakken crude oil production and 939 MBbls of production added from properties acquired in the Powder River Basin of Wyoming in March 2021. These increases were partially offset by a 676 MBbls, or 7%, decrease in ~~Bakken~~SCOOP crude oil production ~~along with~~and a ~~1,032~~195 MBbls, or ~~40%~~13%, decrease in STACK crude oil production due to the previously described ~~production curtailments and limited drilling and completion activities undertaken during the 2020 second and third quarters. These decreases were partially offset by a 1,640 MBbls, or 22%,~~ increase in ~~crude oil production in SCOOP due~~our allocation of capital to ~~new well completions~~gas-weighted projects over the past ~~year in our oil-weighted Project SpringBoard, which exceeded the adverse impact of production curtailments in the play.~~

Our production curtailments and limited drilling and completion activities in the 2020 second and third quarters also impacted our year to date natural gas production, leading to a 24,740 MMcf, or 33%, decrease in STACK gas production and a 5,180 MMcf, or 7%, decrease in Bakken gas production over the prior year period. These decreases were partially offset by a 23,199 MMcf, or 31%, increase in SCOOP gas production in conjunction with the previously described increase in SCOOP oil production over the prior year period.year.

Revenues

Net crude oil and natural gas sales. Net crude oil and natural gas sales for year to date ~~2020~~2021 totaled ~~$1.59~~$3.83 billion, ~~a decrease~~an increase of ~~50%~~141% compared to net sales of ~~$3.16~~$1.59 billion for the comparable ~~2019~~2020 period due to significant ~~decreases~~increases in net sales prices and sales volumes as discussed below.

Total sales volumes for year to date ~~2020 decreased 11,814~~2021 increased 10,276 MBoe, or 13%, compared to year to date ~~2019,~~2020, reflecting reduced sales in the prior period from the previously described production curtailments in the ~~current period.~~second and third quarters of 2020 and our subsequent resumption of usual operations. For year to date ~~2020,~~2021, our crude oil sales volumes ~~decreased 20%~~increased 2% from the comparable ~~2019~~2020 period, while our natural gas sales volumes ~~decreased 3%.~~increased 27%, driven by our increased allocation of capital toward gas-weighted projects over the past year.

Our crude oil net sales prices averaged $60.79 per barrel for year to date 2021, an increase of 80% compared to $33.71 per barrel for year to date 2020 ~~a decrease of 35% compared to $51.99 per barrel for year to date 2019~~ due to ~~significantly reduced~~a significant increase in market prices from improved supply and ~~wider~~demand fundamentals along with improved price differentials. The differential between NYMEX

WTI calendar month prices and our realized crude oil net sales prices averaged $4.13 per barrel for year to date 2021 compared to $6.03 per barrel for year to date ~~2020 compared to $5.01 per barrel~~2020. Crude oil prices for year to date ~~2019. The increased differential reflects~~2020 were severely impacted by adverse changes in supply and demand fundamentals ~~and~~from the economic effects ~~from~~of the COVID-19 ~~that~~pandemic, which negatively impacted location differentials and price realizations in the ~~first and second quarters of~~ 2020 ~~compared to the prior year.~~period with no similar impacts in 2021.

Our natural gas net sales prices averaged $4.38 per Mcf for year to date 2021 compared to $0.72 per Mcf for year to date 2020 ~~a decrease of 60% compared to $1.78 per Mcf for year to date 2019~~ due to ~~significantly reduced~~a significant increase in market prices and ~~lower~~improved price ~~realizations.~~differentials. The ~~discount~~difference between our net sales prices and NYMEX Henry Hub calendar month natural gas prices ~~weakened to $1.19~~was a premium of $1.17 per Mcf for year to date ~~2020~~2021 compared to ~~$0.90~~a discount of $1.19 per Mcf for the year to date ~~2019~~2020 period. ~~NGL prices decreased~~In February 2021, severe winter weather and freezing temperatures in the southern United States led to a period of increased spot prices for residue natural gas that resulted in a significant improvement in our price realizations in the 2021 first ~~half of~~quarter relative to benchmark prices and prior periods. Additionally, prices for natural gas liquids have increased significantly in 2021 compared to 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 to benchmark prices and contributing to the recognition of $37.7 million of negative gas revenues in the 2020 year to date period.~~stream.

Derivatives. ~~Changes~~The significant improvement in ~~market~~commodity prices during the nine months ended September 30, ~~2020~~2021 had an overall unfavorable impact on the fair value of our derivatives, which resulted in negative revenue adjustments of ~~$25.6~~$232.8 million for the period, representing $87.6 million of cash losses and $145.2 million of unsettled non-cash losses, compared to ~~positive~~negative revenue adjustments of ~~$53.5~~$25.6 million in the comparable ~~2019 period.~~

~~Crude oil and natural gas service operations.~~ ~~Revenues associated with our crude oil and natural gas service operations decreased $19.3 million, or 35%, from $54.9 million for year to date 2019 to $35.6 million for year to date~~ 2020 due to reduced water handling activities resulting from our curtailment of production and reduced completion activities in the second and third quarters of 2020. The decreased activities also resulted in a reduction in service-related expenses compared to the prior period.

Operating Costs and Expenses

Production Expenses. Production expenses ~~decreased $61.5~~increased $20.9 million, or ~~18%~~8%, ~~from $333.4~~to $292.8 million for year to date ~~2019~~2021 compared to $271.9 million for year to date ~~2020. This decrease resulted from reduced service costs being incurred~~2020 primarily due to the previously described 13% increase in conjunction with production curtailments and 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 Bakken, all of which led to a reduction in our productiontotal sales volumes. Production expenses on a per-Boe basis averaged $3.29 per Boe for year to date 2021 compared to $3.45 per Boe for year to date ~~2020 compared to $3.68 per Boe for the comparable 2019 period.~~2020.

Production Taxes. Production taxes ~~decreased $134.8~~increased $148.3 million, or ~~50%~~112%, to $280.7 million for year to date 2021 compared to $132.4 million for year to date 2020 ~~compared to $267.2 million for year to date 2019~~ due to ~~a 48% decrease~~the previously described 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 ~~averaged~~decreased to 7.3% for year to date 2021 compared to 8.3% for year to date 2020 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 ~~8.4% for year to date 2019.~~North Dakota.

Exploration expenses. Exploration expenses, which consist primarily of exploratory geological and geophysical costs and dry hole costs that are expensed as incurred, ~~increased $7.2~~decreased $5.1 million to $9.5 million for year to date 2021 compared to $14.6 million for year to date ~~2020 compared to $7.4 million for year to date 2019 due to changes in the timing and extent of our exploration-related activities compared to the prior year period.~~2020. The 2020 period includes $6.3 million of dry hole costs recognized in the 2020 first quarter associated with an unsuccessful exploratory well with no comparable dry hole costs incurred in the ~~prior year~~2021 period.

Depreciation, Depletion, Amortization and Accretion. Total DD&A ~~decreased $176.5~~increased $158.6 million, or 12%, to ~~$1.29~~$1.45 billion for year to date ~~2020~~2021 compared to ~~$1.46~~$1.29 billion for the comparable ~~2019~~2020 period primarily due to athe previously described 13% ~~decrease~~increase in total sales volumes. The following table shows the components of our DD&A on a unit of sales basis for the periods presented.


		Nine months ended September 30,					Nine months ended September 30,
$/Boe	$/Boe	2020		2019		$/Boe	2021		2020
Crude oil and natural gas	Crude oil and natural gas	$	16.08	$	15.95	Crude oil and natural gas	$	15.95	$	16.08
Other equipment	Other equipment	0.20		0.16		Other equipment	0.22		0.20
Asset retirement obligation accretion	Asset retirement obligation accretion	0.09		0.07		Asset retirement obligation accretion	0.09		0.09
Depreciation, depletion, amortization and accretion	Depreciation, depletion, amortization and accretion	$	16.37	$	16.18	Depreciation, depletion, amortization and accretion	$	16.26	$	16.37

Property Impairments. Total property impairments ~~increased $198.1~~decreased $234.0 million to ~~$265.0~~$31.0 million for the year to date period of ~~2020~~2021 compared to ~~$66.9 million for the year to date period of 2019 primarily reflecting higher proved property impairments as described below.~~

Impairments of proved oil and gas properties totaled $182.6 million for the year to date period of 2020, of which $181.0 million was recognized in the 2020 first quarter and $1.6 million was recognized in the 2020 third quarter, resulting from the significant decrease in commodity prices that indicated the carrying values for certain fields were not recoverable. The impairments were recognized on legacy properties in the Red River Units ($168.1 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 million impairment in the

~~2020 first quarter to reduce the value of our crude oil inventory to estimated net realizable value. There were no proved property impairments recognized during the year to date period of 2019.~~

~~Impairments of unproved properties decreased $9.0 million, or 13%, to $57.9~~$265.0 million for year to date 2020 ~~compared~~primarily reflecting lower proved property impairments in the current period. No proved property impairments were recognized for year to ~~$66.9~~date 2021 as estimated future net cash flows were determined to be in excess of cost basis due to improved commodity prices, while proved property impairments totaled $207.1 million in the comparable 2020 period. Additionally, impairments of unproved properties decreased $26.9 million for year to date ~~2019 primarily due~~2021 compared to year to date 2020 reflecting a ~~reduction~~decrease in the ~~balance~~amortization of ~~unamortized~~undeveloped leasehold costs ~~over~~from changes in management's estimates of properties not expected to be developed before lease expiration in response to significantly improved commodity prices compared to the ~~past~~prior year.

General and Administrative Expenses. Total G&A expenses ~~decreased $12.1~~increased $37.1 million, or 9%29%, to $166.8 million for year to date 2021 compared to $129.7 million for year to date ~~2020 compared to $141.8 million for year to date 2019.~~2020.

Total G&A expenses include non-cash charges for equity compensation of ~~$48.1~~$44.9 million and ~~$37.2~~$48.1 million for the year to date periods of 2021 and 2020, and 2019, respectively, the increase of which was due to additional grants of restricted stock awards coupled with higher forfeitures of unvested restricted stock in 2019 that resulted in lower equity compensation expense for that period.

respectively. G&A expenses other than equity compensation totaled ~~$81.6~~$121.9 million for year to date ~~2020, a decrease~~2021, an increase of ~~$23.0~~$40.3 million, or ~~22%~~49%, compared to ~~$104.6~~$81.6 million for the comparable ~~2019 period. This decrease was primarily~~2020 period due to ~~a reduction~~an increase in employee benefits and other efforts to reduce spending in response to significantly reduced commodity prices and economic turmoil from the COVID-19 pandemic, partially offset by lower overhead recoveries from joint interest owners driven by reduced drilling, completion, and production activities.benefits.

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


		Nine months ended September 30,					Nine months ended September 30,
$/Boe	$/Boe	2020		2019		$/Boe	2021		2020
General and administrative expenses	General and administrative expenses	$	1.04	$	1.16	General and administrative expenses	$	1.37	$	1.04
Non-cash equity compensation	Non-cash equity compensation	0.61		0.41		Non-cash equity compensation	0.50		0.61
Total general and administrative expenses	Total general and administrative expenses	$	1.65	$	1.57	Total general and administrative expenses	$	1.87	$	1.65

The increase in equity compensation expenses on a per-Boe basis in 2020 was driven by a 13% decrease in total sales volumes with no similar reduction in equity compensation expenses, as such expenses continue to be recognized irrespective of sales volumes.

Interest Expense. Interest expense decreased ~~$11.9~~$6.8 million, or 6%4%, to ~~$192.5~~$185.8 million for year to date ~~2020~~2021 compared to ~~$204.4~~$192.5 million for the comparable ~~2019~~2020 period ~~primarily~~ due to a decrease in our ~~weighted average interest rate from changes in the mix of~~total outstanding ~~debt between periods driven by the redemption or repurchase of senior notes over the past year using available cash and lower-rate credit facility borrowings.~~debt. Our weighted average outstanding debt balance for year to date ~~2020~~2021 was ~~$5.8~~$5.1 billion ~~with a weighted average interest rate of 4.3%~~ compared to ~~averages of~~ $5.8 billion ~~and 4.5%~~ for year to date ~~2019.~~2020.

Income Taxes. For the nine months ended September 30, ~~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 $291.1 million for the ~~United States. We recorded~~year to date period of 2021 and an income tax benefit of $138.4 million ~~and an income tax provision of $177.4 million~~ for ~~the~~ year to date ~~periods of~~ 2020, ~~and 2019, respectively,~~ which resulted in effective tax rates of ~~21.3%~~24.0% and ~~23.4%~~21.3%, 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 remain~~We are committed to operating in a ~~responsible~~ manner to preserve financial flexibility, liquidity, and the strength of our balance sheet.

On October 29, 2021, we amended our credit facility to increase aggregate commitments from $1.5 billion to $1.7 billion, extend the maturity date from April 2023 to October 2026, and provide for benchmark replacement mechanics to address the transition from LIBOR, with all other terms, conditions, and covenants remaining substantially unchanged. At October 31, ~~2020,~~2021, we had ~~approximately $975 million~~no outstanding borrowings and $1.7 billion of borrowing availability under our credit ~~facility after considering outstanding borrowings and letters of credit.~~facility. Our amended credit facility ~~which is~~remains unsecured and has no borrowing base subject to ~~redetermination, does not mature until April 2023.~~redetermination. Further, 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.

As discussed in Note 13. Subsequent Events in Notes to Unaudited Condensed Consolidated Financial Statements, on November 1, 2021 we executed a definitive agreement to acquire oil and gas properties and related assets in the Permian Basin of Texas from certain subsidiaries of Pioneer Natural Resources Company for $3.25 billion of cash, subject to customary closing price adjustments. Additionally, we are in the process of executing various other property acquisitions to increase our position in multiple strategic plays, which we expect will result in cash outlays of up to approximately $375 million. Closing of these acquisitions is expected to occur in the 2021 fourth quarter and remain subject to the completion of customary due diligence procedures and closing conditions, including the satisfaction of certain regulatory approvals. We expect to fund the above acquisitions through a combination of funding sources, including the use of cash on hand, utilization of credit facility borrowing capacity, and the issuance of debt securities and/or bank term loan facilities.

Based on our planned capital spending, including our pending property acquisitions described herein, 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~~our contractual cash commitments to third parties as of September 30, ~~2020,~~2021, including those described in Note ~~10.~~8. Commitments and Contingenciesand Note 13. Subsequent Events 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

Cash flows from operating activities

Net cash provided by operating activities ~~totaled $934.8 million and $2.31~~increased $1.79 billion, or 192%, to $2.73 billion for the ~~nine months ended September 30,~~year to date period of 2021 compared to $935 million for year to date 2020 primarily due to a $2.2 billion increase in crude oil and ~~2019, respectively, reflecting a significant decrease in our operating cash flows in the second and third quarters of 2020~~natural gas revenues due to the previously described ~~decrease~~increases in ~~market~~commodity prices and ~~our voluntary curtailment of production which adversely impacted our 2020 operating results.~~

~~Crude oil prices stabilized and improved~~sales volumes in the ~~2020 third quarter relative to historic lows reached~~current period. This increase was partially offset by a $148.2 million increase in ~~April 2020~~production taxes associated with higher crude oil and ~~we began to gradually restore our curtailed production~~natural gas revenues and a $70.5 million increase in ~~July 2020. Subsequently, we fully restored our curtailed production~~realized cash losses on matured commodity derivatives in ~~September 2020. As a result, our operating cash flows increased to $291.2 million for~~ the ~~2020 third quarter compared to negative operating cash flows of $20.2 million for the 2020 second quarter.~~current period.

Cash flows from investing activities

Net cash used in investing activities ~~totaled $1.18 billion and $2.25~~decreased $58 million, or 5%, to $1.12 billion for the ~~nine months ended September 30,~~year to date period of 2021 compared to $1.18 billion for year to date 2020, reflecting our focus on maintaining capital spending discipline to maximize cash flow generation for debt reduction. Our cash flows used in investing activities for 2021 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 between $1.5 billion and 2019, respectively, reflecting the significant decrease in our drilling and completion activities prompted by the decrease in crude oil prices and economic uncertainty from the COVID-19 pandemic. Our investing cash outflows have decreased sequentially throughout the nine months ended September 30, 2020, totaling $706.7 million$1.6 billion compared to $1.2 billion of non-acquisition capital spending for ~~the first quarter, $312.2 million for the second quarter, and $162.9 million for the third quarter.~~full year 2020.

Cash flows from financing activities

Net cash used in financing activities for the year to date period of 2021 totaled $958.7 million, primarily consisting of $630.8 million of cash used to redeem the remaining balance of our 2022 Notes, $160 million of net repayments on our credit facility, $94.1 million of cash dividends paid on common stock, and $65.3 million of cash used to repurchase shares of our common stock.

Net cash provided by financing activities for the ~~nine months ended September 30,~~year to date period of 2020 totaled $228.9 million, primarily consisting of $420 million of net credit facility borrowings and net proceeds of $26.0 million from ~~new~~ term loans as described in Note 8.7. Long-Term Debt in Notes to Unaudited Condensed Consolidated Financial Statements~~and~~$26.6 million of cash inflows for contributions received from Franco-Nevada Corporation for the funding of its share of mineral acquisition costs incurred by The Mineral Resources Company II ("TMRC II"). These year-to-date increases were, partially offset by $126.9 million of cash used to repurchase shares of our common stock, $18.5 million of cash dividends paid on our common stock, and $74.0 million of cash used to repurchase senior notes in open market transactions. For the three months ended September 30, 2020, we had net cash outflows used in financing activities totaling $113.7 million, primarily representing $112 million of net repayments on our credit facility.

Net cash used in financing activities for the nine months ended September 30, 2019 totaled $305.5 million, which partly represents cash used to fund our partial redemption of 2022 Notes in September 2019. We funded the redemption using a combination of available cash and lower-rate borrowings under our credit facility. Additionally, $172.0 million of cash was used to repurchase shares of our common stock under our share repurchase program initiated in June 2019. These 2019 year-to-date cash outflows were partially offset by $104.5 million of cash inflows for contributions received from Franco-Nevada Corporation for the funding of its share of mineral acquisition costs incurred by TMRC II.

Future Sources of Financing

Although we cannot provide any assurance, we believe funds from operating cash flows, our 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~~budgeted capital expenditures, and ~~commitments~~dividend payments for at least the next 12 months.

~~Our~~Based on current market indications, our budgeted capital spending plans ~~have been adjusted~~are expected to be ~~reflective of the current commodity price environment and will be guided by our expectation of available~~funded from operating cash flows. Any deficiencies in operating cash ~~flow deficiencies~~flows relative to budgeted spending are expected to be funded by borrowings under our credit facility. If cash flows are materially impacted by declines in commodity prices, we have the ability to reduce our capital expenditures or utilize the availability of our 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~~arise. For instance, as previously described we plan to issue debt securities and/or execute bank term loan facilities in the ~~financial markets as~~2021 fourth quarter to fund a ~~result~~portion of the COVID-19 pandemic and other factors 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 may 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.~~our pending property acquisitions. 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.

Credit facility

In March 2020, our corporate credit rating was downgraded by Standard & Poor's Ratings Services ("S&P") in response to weakened oil and gas industry conditions and resulting revisions made to rating agency commodity price assumptions. Such downgrade negatively impacted our cost of capital and increased our borrowing costs underOn October 29, 2021, we amended our credit ~~facility. Also in March 2020, our corporate credit ratings were reaffirmed by both Moody's Investor Services~~facility to increase aggregate commitments from $1.5 billion to $1.7 billion and ~~Fitch Ratings. Such ratings are subject~~extend the maturity date from April 2023 to ~~ongoing review and adjustment.~~

~~Credit facility~~

~~We have an unsecured~~October 2026. The amount available under the credit facility ~~maturing~~can be increased by up to an additional $2.3 billion in ~~April 2023, with aggregate lender commitments totaling $1.5 billion.~~the future upon the agreement of the Company and participating lenders. The commitments are from a syndicate of 1412 banks and financial institutions. We believe each member of the current syndicate has the capability to fund its commitment. As of October 31, ~~2020,~~2021, we had ~~$520 million of~~no outstanding borrowings ~~and approximately $975 million of borrowing availability~~ on our credit facility.

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 September 30, ~~2020~~2021 and expect to maintain such compliance. At September 30, ~~2020,~~2021, our consolidated net debt to total capitalization ratio was ~~0.43~~0.33 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 September 30, 2020, our total debt would have needed to independently increase by approximately $8.4 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 $4.5 billion (excluding the after-tax impact of any non-cash impairment charges) below the existing level at September 30, 2020 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

Senior notes

Our debt includes outstanding senior note obligations totaling ~~$5.16~~$4.76 billion at September 30, ~~2020.~~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 September 30, ~~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 through a minerals subsidiary named The Mineral Resources Company II, LLC ("TMRC II"). Under the relationship, the parties have agreed to spend up to a remaining aggregate total of ~~$154~~$127 million to acquire mineral interests. Continental agreed 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 2021.

Capital expenditures

We remain committed to operating in a disciplined, capital-efficient ~~manner.~~manner to maximize cash flow generation. Our ~~original~~non-acquisition capital ~~budget~~expenditures are expected to total between $1.5 billion and $1.6 billion for ~~2020 was $2.65 billion, which was reduced to $1.2 billion~~2021. Acquisition expenditures are not budgeted, with the exception of planned levels of spending for mineral acquisitions made in ~~March 2020 in response to the significant decrease in crude oil prices resulting from the COVID-19 pandemic and other factors. We diligently evaluate and adjust~~conjunction with our ~~spending plans on an ongoing basis based on market conditions.~~relationship with Franco-Nevada.

For the nine months ended September 30, ~~2020,~~2021, we invested ~~$990.9~~$966.6 million in our capital program excluding ~~$34.1~~$224.2 million of unbudgeted acquisitions and ~~excluding $162.6~~including $66.0 million of capital costs associated with ~~reduced~~increased accruals for capital expenditures as compared to December 31, 2019. In light of the challenges facing our business and industry we have significantly reduced our drilling and completion activities in order to preserve our assets and better align our spending with expected available cash flows. As a result of these actions, our non-acquisition capital spending was reduced by 71% in the 2020 second quarter relative to the 2020 first quarter, and was reduced another 22% in the 2020 third quarter.2020. Our ~~2020~~2021 year to date capital expenditures were allocated as shown in the table below.


In millions	In millions	1Q 2020		2Q 2020		3Q 2020		YTD 2020		In millions	1Q 2021		2Q 2021		3Q 2021		YTD 2021
Exploration and development drilling	Exploration and development drilling	$	544.0	$	155.8	$	120.9	$	820.7	Exploration and development drilling	$	255.6	$	216.2	$	312.3	$	784.1
Land costs ~~(1)~~	Land costs ~~(1)~~	39.9		8.9		6.1		54.9		Land costs ~~(1)~~	7.5		14.5		18.5		40.5
Capital facilities, workovers and other corporate assets		63.0		25.8		22.4		111.2
Mineral acquisitions attributable to Continental										Mineral acquisitions attributable to Continental	0.2		1.3		1.5		3.0
Capital facilities, workovers, water infrastructure, and other corporate assets										Capital facilities, workovers, water infrastructure, and other corporate assets	27.4		57.3		51.0		135.7
Seismic	Seismic	3.8		0.3		—		4.1		Seismic	2.7		0.2		0.4		3.3
Capital expenditures, excluding unbudgeted acquisitions		650.7		190.8		149.4		990.9
Acquisitions of producing properties		19.3		0.1		4.0		23.4
Capital expenditures attributable to Continental, excluding unbudgeted acquisitions										Capital expenditures attributable to Continental, excluding unbudgeted acquisitions	293.4		289.5		383.7		966.6
Acquisitions of producing properties (1)										Acquisitions of producing properties (1)	183.3		(5.4)		0.3		178.2
Acquisitions of non-producing properties	Acquisitions of non-producing properties	10.6		—		0.1		10.7		Acquisitions of non-producing properties	24.3		18.7		3.0		46.0
Total unbudgeted acquisitions	Total unbudgeted acquisitions	29.9		0.1		4.1		34.1		Total unbudgeted acquisitions	207.6		13.3		3.3		224.2
Total capital expenditures attributable to Continental										Total capital expenditures attributable to Continental	$	501.0	$	302.8	$	387.0	$	1,190.8
Mineral acquisitions attributable to Franco-Nevada										Mineral acquisitions attributable to Franco-Nevada	0.9		2.8		6.0		9.7
Total capital expenditures	Total capital expenditures	$	680.6	$	190.9	$	153.5	$	1,025.0	Total capital expenditures	$	501.9	$	305.6	$	393.0	$	1,200.5

(1) ~~Amount includes $24~~The adjustment of $5.4 million in the second quarter of ~~mineral~~2021 represents customary purchase price adjustments related to our March 2021 acquisition of undeveloped leasehold and producing properties in the Powder River Basin of Wyoming.

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, ~~made by TMRC II during~~actual drilling and completion results, the ~~nine months ended September 30, 2020,~~availability of ~~which $19 million was recouped~~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 ~~Franco-Nevada.~~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. See "Commitments and contingencies" below for a discussion of pending property acquisitions that are expected to close in the 2021 fourth quarter.

Commitments and contingencies

Refer to Note ~~10.~~8. Commitments and Contingenciesand Note 13. Subsequent Events in Notes to Unaudited Condensed Consolidated Financial Statements for discussion of certain future commitments ~~and contingencies~~ of the Company. ~~Based on current market indications,~~

Pending Property Acquisitions

On November 1, 2021, we executed a definitive agreement to acquire oil and gas properties and related assets in the Permian Basin of Texas for $3.25 billion of cash, subject to customary closing price adjustments. Additionally, we are in the process of executing various other property acquisitions to increase our position in multiple strategic plays, which we expect will result in cash outlays of up to ~~meet~~approximately $375 million. Closing of these acquisitions is expected to occur in the ~~ordinary course~~2021 fourth quarter and remain subject to the completion of ~~business our contractual cash commitments~~customary due diligence procedures and closing conditions, including the satisfaction of certain regulatory approvals. There can be no assurance that all of the conditions to ~~third parties as~~closing the acquisitions will be satisfied.

Dakota Access Pipeline

The U.S. Army Corps of ~~September 30, 2020.~~

~~On July 6, 2020, the U.S. District Court for the District of Columbia ruled that~~Engineers (“Corps”) is currently conducting a court-ordered environmental review to determine whether the Dakota Access Pipeline (“DAPL”), poses a threat to the drinking water supply of the Standing Rock Sioux Reservation. DAPL currently remains in operation while the Corps conducts the review, which is ~~owned and operated by a third party and carries Bakken-produced crude oil from North Dakota~~estimated to ~~Illinois,~~be completed no later than September 2022. Once completed, the Corps will determine whether DAPL is safe to operate or must be shut down pending the completion of a new environmental impact statement. The pipeline owner sought an emergency stay of the shut-down order from the U.S. Court of Appeals for the District of Columbia Circuit (the "Appeals Court"). On July 14, 2020, the Appeals Court issued a temporary administrative stay of such order, which has allowed the pipeline to continue operating as of the date of this filing. The continued operation of DAPL in the future is uncertain. down.

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,~~Our transportation commitment on the ~~Company is committed to transport~~pipeline increased from 3,550 barrels per day ~~on the pipeline through February 2026 and has an additional commitment~~ to ~~transport an incremental 26,450~~30,000 barrels per day ~~for 7 years~~ effective ~~upon~~August 1, 2021 in conjunction with the ~~pending~~ completion of a DAPL expansion ~~project~~project. This commitment will continue through February 2026 at which ~~is estimated~~time the commitment decreases to ~~occur in the third quarter of 2021.~~ 26,450 barrels per day through July 2028.

If transportation capacity on DAPL becomes restricted or unavailable, we have the ability to utilize other third party pipelines or rail facilities to transport our Bakken crude oil production to market, although such alternatives ~~could~~may be more costly. A restriction of ~~DAPL's~~DAPL’s takeaway capacity ~~could~~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.

Dividend declaration

Derivative Instruments

The fair value of our derivative instruments at September 30, 2021 was a net liability of $131.7 million, which is expected to be realized and paid on a generally ratable basis through March 2022 assuming forward commodity prices existing as of September 30, 2021 remain in place. See Note 5. Derivative Instruments for further discussion of our hedging activities, including a summary of derivative contracts in place as of September 30, 2021.

~~Dividend payments~~

~~To preserve cash in response~~The company entered into additional derivative contracts subsequent to the significant reduction in crude oil prices and economic uncertainty resulting from the COVID-19 pandemic, in April 2020 the Company’s quarterly dividend was suspended by the Board of Directors until further notice.

~~Share repurchase program~~

~~In May 2019 our Board of Directors approved the initiation of a share repurchase program to acquire up to $1 billion of our common stock beginning in June 2019. Through~~ September 30, 2020, we had repurchased and retired a cumulative total of approximately 13.8 million shares at an aggregate cost of $317.1 million since the inception of the program. The timing and amount of the Company's share repurchases are subject to market conditions and management discretion. The share repurchase program does not require the Company to repurchase a specific number of shares and may be modified, suspended, or terminated by the Board of Directors at any time. To preserve cash2021 as set forth in the ~~current environment, we do not expect to engage in significant share repurchase activity in the near term.~~tables below.


Natural gas derivatives
			Weighted Average Hedge Price
Period and Type of Contract	Volumes Hedged		Swaps		Sold Put		Floor		Ceiling
April 2022 - September 2022
Swaps - Henry Hub	85,000	MMBtus/day	$	4.07
October 2022 - December 2022
Three-way collars - Henry Hub	50,000	MMBtus/day			$	3.00	$	4.07	$	5.00
January 2023 - December 2023
Swaps - Henry Hub	50,000	MMBtus/day	$	3.39
January 2023 - March 2023
Three-way collars - Henry Hub	50,000	MMBtus/day			$	3.00	$	4.32	$	5.00


Crude oil derivatives

Period and Type of Contract	Volumes Hedged		Weighted Average Hedge Price


January 2022 - March 2022
NYMEX Roll Swaps	10,000	Bbls/day	$	0.85
April 2022 - June 2022
NYMEX Roll Swaps	15,000	Bbls/day	$	0.85
July 2022 - December 2022
NYMEX Roll Swaps	7,500	Bbls/day	$	0.90

Senior note ~~repurchases~~redemptions

As discussed in Note 8.7. Long-Term Debt in ~~Notes to Unaudited Condensed Consolidated Financial Statements~~, in ~~March and April 2020~~2021 we ~~repurchased a portion~~redeemed the remaining principal amount of our ~~2023 Notes and 2024 Notes in open market transactions at a substantial discount to face value.~~outstanding 2022 Notes. From time to time, we may seek to execute additional redemptions or repurchases of our senior notes for cash in open market transactions, privately negotiated transactions, or otherwise. Such redemptions or repurchases will depend on prevailing market conditions, our liquidity and prospects for future access to capital, and other factors. The amounts involved in any such transactions, individually or in the aggregate, may be material.

~~Legislative and Regulatory Developments~~

On March 27, 2020, the Coronavirus Aid, Relief, and Economic Security Act ("CARES Act") was signed into law, which is aimed at supporting the U.S. economy and providing emergency assistance to individuals, families, and businesses affected by the COVID-19 pandemic. In particular, key income tax-related provisions of the CARES Act include (1) elimination of the 80% of taxable income limitation by allowing entities to utilize 100% of net operating losses ("NOLs") to offset taxable income in 2018, 2019, or 2020, (2) allowing NOLs originating in 2018, 2019, or 2020 to be carried back to each of the preceding five years to generate a refund, (3) increasing the net interest expense deduction limit from 30% to 50% of adjusted taxable income for tax years beginning in 2019 and 2020, and (4) allowing taxpayers with alternative minimum tax credits to claim a refund in 2020 for the entire amount of the credit instead of recovering the credit through refunds over a period of years. The CARES Act is not expected to have a material impact on our business.

Off-balance sheet arrangements

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

Critical Accounting Policies

There have been no changes in our critical accounting policies from those disclosed in our ~~2019~~2020 Form 10-K.

New Accounting Pronouncements

See Note 2. Basis of Presentation and Significant Accounting Policies in Notes to Unaudited Condensed Consolidated Financial Statements for a discussion of the new ~~credit loss~~income tax accounting standard adopted on January 1, 2021, which did not have a material impact on our financial position, results of operations, or cash flows.

Legislative and Regulatory Developments

The crude oil and natural gas industry in the United States is subject to various types of regulation at the federal, state and local levels. In January 2021 President Biden issued executive orders that, among other things, establish new greenhouse gas emission standards for the oil and gas sector. President Biden may continue to issue additional executive orders in pursuit of his regulatory agenda and, with control of Congress shifting in January 2021, there is the potential for the revision of existing laws and regulations or the adoption of new legislation that could adversely affect the oil and gas industry, including those pertaining to the taxation of oil and gas exploration and production activities. See Part I, Item 1. Business—Regulation of the Crude Oil and Natural Gas Industry in our Form 10-K for the year ended December 31, 2020 ~~along with~~for a discussion of ~~an accounting pronouncement not yet adopted.~~significant laws and regulations that have been enacted or are currently being considered by regulatory bodies that may affect us in the areas in which we operate.

Non-GAAP Financial Measures

Net crude oil and natural gas sales and net sales prices

Revenues and transportation expenses associated with production from our operated properties are reported separately as discussed in Notes to Unaudited Condensed Consolidated Financial Statements–Note 4. Revenues. For non-operated properties, we receive a net payment from the operator for our share of sales proceeds which is net of costs incurred by the operator, if any. Such non-operated revenues are recognized at the net amount of proceeds received. As a result, the separate presentation of revenues and transportation expenses from our operated properties differs from the net presentation from non-operated properties. This impacts the comparability of certain operating metrics, such as per-unit sales prices, when such metrics are prepared in accordance with U.S. GAAP using gross presentation for some revenues and net presentation for others.

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

The following tables present a reconciliation of crude oil and natural gas sales (GAAP) to net crude oil and natural gas sales and related net sales prices (non-GAAP) for the three and nine months ended September 30, ~~2020~~2021 and ~~2019.~~2020.


		Three months ended September 30, 2020						Three months ended September 30, 2019							Three months ended September 30, 2021						Three months ended September 30, 2020
In thousands	In thousands	Crude oil		Natural gas		Total		Crude oil		Natural gas		Total		In thousands	Crude oil		Natural gas		Total		Crude oil		Natural gas		Total
Crude oil and natural gas sales (GAAP)	Crude oil and natural gas sales (GAAP)	$	623,955	$	77,513	$	701,468	$	989,297	$	92,103	$	1,081,400	Crude oil and natural gas sales (GAAP)	$	1,002,823	$	453,358	$	1,456,181	$	623,955	$	77,513	$	701,468
Less: Transportation expenses	Less: Transportation expenses	(46,890)		(8,382)		(55,272)		(53,038)		(9,000)		(62,038)		Less: Transportation expenses	(45,241)		(8,728)		(53,969)		(46,890)		(8,382)		(55,272)
Net crude oil and natural gas sales (non-GAAP)	Net crude oil and natural gas sales (non-GAAP)	$	577,065	$	69,131	$	646,196	$	936,259	$	83,103	$	1,019,362	Net crude oil and natural gas sales (non-GAAP)	$	957,582	$	444,630	$	1,402,212	$	577,065	$	69,131	$	646,196
Sales volumes (MBbl/MMcf/MBoe)	Sales volumes (MBbl/MMcf/MBoe)	16,063		70,510		27,815		18,258		74,101		30,608		Sales volumes (MBbl/MMcf/MBoe)	14,404		96,188		30,435		16,063		70,510		27,815
Net sales price (non-GAAP)	Net sales price (non-GAAP)	$	35.93	$	0.98	$	23.23	$	51.28	$	1.12	$	33.30	Net sales price (non-GAAP)	$	66.48	$	4.62	$	46.07	$	35.93	$	0.98	$	23.23


		Nine months ended September 30, 2020						Nine months ended September 30, 2019							Nine months ended September 30, 2021						Nine months ended September 30, 2020
In thousands	In thousands	Crude oil		Natural gas		Total		Crude oil		Natural gas		Total		In thousands	Crude oil		Natural gas		Total		Crude oil		Natural gas		Total
Crude oil and natural gas sales (GAAP)	Crude oil and natural gas sales (GAAP)	$	1,556,445	$	182,418	$	1,738,863	$	2,905,561	$	422,848	$	3,328,409	Crude oil and natural gas sales (GAAP)	$	2,758,859	$	1,227,769	$	3,986,628	$	1,556,445	$	182,418	$	1,738,863
Less: Transportation expenses	Less: Transportation expenses	(120,780)		(27,299)		(148,079)		(140,666)		(23,903)		(164,569)		Less: Transportation expenses	(129,218)		(27,452)		(156,670)		(120,780)		(27,299)		(148,079)
Net crude oil and natural gas sales (non-GAAP)	Net crude oil and natural gas sales (non-GAAP)	$	1,435,665	$	155,119	$	1,590,784	$	2,764,895	$	398,945	$	3,163,840	Net crude oil and natural gas sales (non-GAAP)	$	2,629,641	$	1,200,317	$	3,829,958	$	1,435,665	$	155,119	$	1,590,784
Sales volumes (MBbl/MMcf/MBoe)	Sales volumes (MBbl/MMcf/MBoe)	42,583		216,735		78,706		53,179		224,045		90,520		Sales volumes (MBbl/MMcf/MBoe)	43,257		274,352		88,982		42,583		216,735		78,706
Net sales price (non-GAAP)	Net sales price (non-GAAP)	$	33.71	$	0.72	$	20.21	$	51.99	$	1.78	$	34.95	Net sales price (non-GAAP)	$	60.79	$	4.38	$	43.04	$	33.71	$	0.72	$	20.21

3735

ITEM 3. Quantitative and Qualitative Disclosures About Market Risk

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

Commodity Price Risk. Our primary market risk exposure is in the prices we receive from sales of crude oil and natural gas. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our natural gas production. Pricing for crude oil and natural gas has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside of our control, including ~~volatility in the~~ differences between product prices at sales points and the applicable index prices. Based on our average daily production for the nine months ended September 30, ~~2020,~~2021, and excluding the effect of derivative instruments in place, ~~if any,~~ our annual revenue would increase or decrease by approximately ~~$566~~$579 million for each $10.00 per barrel change in crude oil prices at September 30, ~~2020~~2021 and ~~$289~~$367 million for each $1.00 per Mcf change in natural gas prices at September 30, ~~2020.~~2021.

To reduce price risk caused by market fluctuations in crude oil and natural gas prices, from time to time we may economically hedge a portion of our anticipated crude oil and natural gas production as part of our risk management program. In addition, we may utilize basis contracts to hedge the differential between derivative contract index prices and those of our physical pricing points. Reducing our exposure to price volatility helps secure funds to be used for our capital ~~program.~~program and general corporate purposes. Our decision on the quantity and price at which we choose to hedge our production is based in part on our view of current and future market conditions. We may choose not to hedge future production if the price environment for certain time periods is deemed to be unfavorable. Additionally, we may choose to ~~liquidate~~settle existing derivative positions prior to the expiration of their contractual ~~maturities in order to monetize gain positions for the purpose of funding our capital program.~~maturities. While hedging, if utilized, limits the downside risk of adverse price movements, it also limits future revenues from upward price movements.

The fair value of our ~~natural gas~~ derivative instruments at September 30, ~~2020~~2021 was a net liability of ~~$8.6 million. An assumed increase in the forward prices used in the September 30, 2020 valuation~~$131.7 million, which is comprised of a $131.9 million net liability associated with our natural gas derivatives partially offset by a $0.2 million net asset associated with our crude oil derivatives. The following table shows how a hypothetical +/- 10% change in the underlying forward prices used to calculate the fair value of ~~$1.00 per MMBtu~~our derivatives would ~~increase our derivative liability to approximately $79 million at~~impact the fair value estimates as of September 30, ~~2020. Conversely, an assumed decrease in forward prices of $1.00 per MMBtu would change our derivative valuation to a net asset of approximately $63 million at September 30, 2020.~~2021.


		Hypothetical Fair Value
In thousands	Change in Forward Price	Asset (Liability)
Crude Oil	-10%	$530
Crude Oil	+10%	($171)
Natural Gas	-10%	($100,583)
Natural Gas	+10%	($164,669)

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

Credit Risk. We monitor our risk of loss due to non-performance by counterparties of their contractual obligations. Our principal exposure to credit risk is through the sale of our crude oil and natural gas production, which we market to energy marketing companies, crude oil refining companies, and natural gas gathering and processing companies ($~~475~~903 million in receivables at September 30, ~~2020)~~2021), and our joint interest and other receivables ($~~126~~248 million at September 30, ~~2020)~~2021).

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

Joint interest receivables arise from billing the individuals and entities who own a partial interest in the wells we operate. These individuals and entities participate in our wells primarily based on their ownership in leases included in units on which we wish to drill. We can do very little to choose who participates in our wells. In order to minimize our exposure to this credit risk we generally request prepayment of drilling costs where it is allowed by contract or state law. For such prepayments, a liability is recorded and subsequently reduced as the associated work is performed. This liability was ~~$26~~$19 million at September 30, ~~2020,~~2021, which will be used to offset future capital costs when billed. In this manner, we reduce credit risk. We may have the right to place a lien on a co-owner's interest in the well, to net production proceeds against amounts owed in order to secure payment or, if necessary, foreclose on the ~~co-owner's~~ interest. Historically, our credit losses on joint interest receivables have been immaterial; however, we could experience increased exposure to credit losses in the future, which may be material, if the adverse economic effects of the COVID-19 pandemic persist for an extended period.immaterial.

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

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

We had ~~$520 million of variable rate~~no outstanding borrowings ~~outstanding~~ on our credit facility at October 31, ~~2020. The impact of a 0.25% increase in interest rates on this amount of debt would result in increased interest expense and reduced income before income taxes of approximately $1.3 million per year.~~2021.

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

ITEM 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As of the end of the period covered by this report, an evaluation of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) was performed under the supervision and with the participation of the Company’s management, including its Chief Executive Officer and Chief Financial Officer. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded the Company’s disclosure controls and procedures were effective as of September 30, ~~2020~~2021 to ensure information required to be disclosed in the reports it files and submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and information required to be disclosed under the Exchange Act is accumulated and communicated to the Company’s management, including its Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control over Financial Reporting

During the three months ended September 30, ~~2020,~~2021, there were no changes in our internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

~~Impact of COVID-19 on Internal Controls~~

In an effort to protect the health and safety of our employees from the COVID-19 pandemic, we have taken proactive measures to adopt social distancing policies, including limiting the number of employees attending meetings, reducing the number of people at our sites, and suspending employee business travel. These actions have not had a material adverse effect on our ability to maintain our operations, financial reporting systems, internal control over financial reporting, and disclosure controls and procedures.

Inherent Limitations on Controls and Procedures

A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risks that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Accordingly, even an effective system of internal control will provide only reasonable assurance that the objectives of the internal control system are met.

3937

PART II. Other Information

ITEM 1. Legal Proceedings

~~See~~ ~~Note 10. Commitments~~We are involved in various legal proceedings including, but not limited to, commercial disputes, claims from royalty and ~~Contingencies~~ in ~~Part I, Item I. Financial Statements–Notes~~surface owners, property damage claims, personal injury claims, regulatory compliance matters, disputes with tax authorities and other matters. While the outcome of these legal matters cannot be predicted with certainty, we do not expect them to ~~Unaudited Condensed Consolidated Financial Statements~~ ~~for~~have a ~~discussion~~material effect on our financial condition, results of ~~the termination of the legal matter involving the Company and Casillas Petroleum Resource Partners II, LLC that was resolved in October 2020, which is incorporated herein by reference.~~operations or cash flows.

ITEM 1A. Risk Factors

In addition to the information set forth in this Form 10-Q, you should carefully consider the risk factors discussed in Part ~~II, Item 1A. Risk Factors~~ ~~in our Form 10-Q for the quarter ended March 31, 2020 and~~ ~~Part~~ I, Item 1A. Risk Factors in our ~~2019~~2020 Form 10-K, which could materially affect our business, financial condition or future results. The risks described in this Form 10-Q, ~~our Form 10-Q for the quarter ended March 31, 2020,~~if any, and in our ~~2019~~2020 Form 10-K are not the only risks facing our Company. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results.

There have been no material changes in our risk factors from those disclosed in our ~~2019~~2020 Form ~~10-K, other than those contained in our Form 10-Q for the quarter ended March 31, 2020.~~10-K.

4038

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

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

(b)Use of Proceeds – Not applicable.

(c)Purchases of Equity Securities by the Issuer and Affiliated Purchasers – The table below provides information about purchases of shares of our common stock during the three months ended September 30, ~~2020.~~2021.


Period	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)	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)
July 1, 2020 to July 31, 2020:
July 1, 2021 to July 31, 2021:							July 1, 2021 to July 31, 2021:
Repurchases for tax withholdings (2)	Repurchases for tax withholdings (2)	985	$	17.99	—	—	Repurchases for tax withholdings (2)	4,636	$	35.18	—	—
Purchases by principal shareholder (3)		3,813,523	$	17.54	—	—
August 1, 2020 to August 31, 2020:
August 1, 2021 to August 31, 2021:							August 1, 2021 to August 31, 2021:
Repurchases for tax withholdings (2)	Repurchases for tax withholdings (2)	14,089	$	18.56	—	—	Repurchases for tax withholdings (2)	8,166	$	36.61	—	—
September 1, 2020 to September 30, 2020:
Share repurchase program (1)							Share repurchase program (1)	1,916,069	$	34.06	1,916,069	$	617.6
September 1, 2021 to September 30, 2021:							September 1, 2021 to September 30, 2021:
Repurchases for tax withholdings (2)	Repurchases for tax withholdings (2)	5,799	$	15.84	—	—	Repurchases for tax withholdings (2)	6,201	$	44.25	—	—
Purchases by principal shareholder (3)	Purchases by principal shareholder (3)	769,235	$	12.68	—	—	Purchases by principal shareholder (3)	261,709	$	41.99	—	—
Total for the quarter	Total for the quarter	4,603,631	$	16.73	—	—	Total for the quarter	2,196,781	$	35.04	1,916,069

(1)In May 2019 our Board of Directors approved the initiation of a share repurchase program to acquire up to $1 billion of our common stock beginning in June 2019 at times and levels deemed appropriate by management. The program was announced on June 3, 2019 and does not have a set expiration date. The share repurchase program may be modified, suspended, or terminated by our Board of Directors at any time. No share repurchases were made by the Company under the program during the three months ended September 30, 2020. The dollar value of shares that may yet be purchased under the program totaled $682.9 million as of September 30, 2020.

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

(3)Represents shares of our common stock purchased in open market transactions by Harold G. Hamm, our ~~Executive~~ Chairman of the Board and principal shareholder.

ITEM 3. Defaults Upon Senior Securities

Not applicable.

ITEM 4. Mine Safety Disclosures

Not applicable.

ITEM 5. Other Information

Not applicable.

4139

ITEM 6. Exhibits

The exhibits required to be filed pursuant to Item 601 of Regulation S-K are set forth below.


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

~~10.1*†~~						~~Summary of Non-Employee Director Compensation approved~~ Ju ~~ly 30, 2020 to be effective October 1, 2020~~.

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)

* Filed herewith

** Furnished herewith

~~† Management contract or compensatory plan or arrangement filed pursuant to Item 601(b)(10)(iii) of Regulation S-K.~~

4240

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

CONTINENTAL RESOURCES, INC.

Date:

November ~~5, 2020~~3, 2021

By:

/s/ John D. Hart

John D. Hart

Sr. Vice President, Chief Financial Officer and ~~Treasurer~~Chief Strategy Officer
(Duly Authorized Officer and Principal Financial Officer)

4341


In thousands	Amount
Remainder of 2020	$	1,872
2021	2,914
2022	868
2023	814
2024	540
Thereafter	6,707
Total operating lease liabilities, at undiscounted value	$	13,715
Less: Imputed interest	(3,485)
Total operating lease liabilities, at discounted present value	$	10,230
Less: Current portion of operating lease liabilities	(4,225)
Operating lease liabilities, net of current portion	$	6,005


	Three months ended September 30,				Nine months ended September 30,
In thousands, except weighted average data	2020		2019		2020			2019
Lease costs:
Operating lease costs	$	1,636	$	2,784	$	4,537		$	9,330
Variable lease costs	55		3,820		4,190			11,633
Short-term lease costs	13,863		47,956		94,671			142,634
Total lease costs	$	15,554	$	54,560	$	103,398		$	163,597

Other information:
Right-of-use assets obtained in exchange for new operating lease liabilities	$	38	$	615	$	7,377		$	615
Operating cash flows from operating leases included in lease liabilities	259		202		674			600
Weighted average remaining lease term as of September 30 (in years)					11.4			9.2
Weighted average discount rate as of September 30					4.4		%	4.8		%


Boe production per day	3Q 2020	3Q 2019	% Change
Bakken	160,661	191,268	(16	%)
SCOOP	98,697	80,115	23	%
STACK	30,853	53,070	(42	%)
All other	6,790	7,862	(14	%)
Total	297,001	332,315	(11	%)