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, 2021

or

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

For the transition period from                      to                     

Commission File Number: 001-32886

 ____________________________________

 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	x	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

365,580,875 shares of our $0.01 par value common stock were outstanding on October 25, 2021.

Table of Contents

PART I. Financial Information
Item 1.	Financial Statements	1
	Condensed Consolidated Balance Sheets	1
	Unaudited Condensed Consolidated Statements of 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	22
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	36
Item 4.	Controls and Procedures	37
PART II. Other Information
Item 1.	Legal Proceedings	38
Item 1A.	Risk Factors	38
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	39
Item 3.	Defaults Upon Senior Securities	39
Item 4.	Mine Safety Disclosures	39
Item 5.	Other Information	39
Item 6.	Exhibits	40
	Signature	41

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. 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.

i

“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.

ii

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, 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 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 for the year ended December 31, 2020 occur, or should underlying assumptions prove incorrect, the Company's actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by this cautionary statement.

Except as expressly stated above or otherwise required by applicable law, the Company undertakes no obligation to publicly correct or update any forward-looking statement whether as a result of new information, future events or circumstances after the date of this report, or otherwise.

iii

PART I. Financial Information

ITEM 1.    Financial Statements

Continental Resources, Inc. and Subsidiaries

Condensed Consolidated Balance Sheets

	September 30, 2021		December 31, 2020
In thousands, except par values and share data	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	693,649	$	47,470
Receivables:
Crude oil and natural gas sales	902,580		561,127
Joint interest and other	248,230		143,829
Allowance for credit losses	(2,977)		(2,462)
Receivables, net	1,147,833		702,494
Derivative assets	314		15,303
Inventories	119,285		72,157
Prepaid expenses and other	17,561		15,121
Total current assets	1,978,642		852,545
Net property and equipment, based on successful efforts method of accounting	13,475,204		13,737,292
Operating lease right-of-use assets	19,368		8,557
Derivative assets, noncurrent	1,773		—
Other noncurrent assets	31,176		34,704
Total assets	$	15,506,163	$	14,633,098
Liabilities and equity
Current liabilities:
Accounts payable trade	$	527,268	$	361,704
Revenues and royalties payable	510,986		327,029
Accrued liabilities and other	230,488		167,013
Derivative liabilities	131,616		227
Current portion of operating lease liabilities	1,895		2,588
Current portion of long-term debt	2,306		2,245
Total current liabilities	1,404,559		860,806
Long-term debt, net of current portion	4,741,729		5,530,173
Other noncurrent liabilities:
Deferred income tax liabilities, net	1,911,270		1,620,154
Asset retirement obligations, net of current portion	192,788		177,194
Derivative liabilities, noncurrent	2,172		1,584
Operating lease liabilities, net of current portion	17,326		5,839
Other noncurrent liabilities	15,253		14,623
Total other noncurrent liabilities	2,138,809		1,819,394
Commitments and contingencies (Note 8)
Equity:
Preferred stock, $0.01 par value; 25,000,000 shares authorized; no shares issued and outstanding	—		—
Common stock, $0.01 par value; 1,000,000,000 shares authorized; 365,596,400 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	1,174,755		1,205,148
Retained earnings	5,670,478		4,847,646
Total shareholders’ equity attributable to Continental Resources	6,848,889		6,056,446
Noncontrolling interests	372,177		366,279
Total equity	7,221,066		6,422,725
Total liabilities and equity	$	15,506,163	$	14,633,098

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

1

Continental Resources, Inc. and Subsidiaries

Unaudited Condensed Consolidated Statements of Operations

 

	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.

2

Continental Resources, Inc. and Subsidiaries

Unaudited Condensed Consolidated Statements of Equity

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.

3

Continental Resources, Inc. and Subsidiaries

Unaudited Condensed Consolidated Statements of Equity (Continued)

Three 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 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)	—	—		—		—		(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)	—		(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	$	—	$	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.

4

Continental Resources, Inc. and Subsidiaries

Unaudited Condensed Consolidated Statements of Cash Flows

	Nine months ended September 30,
In thousands	2021		2020
Cash flows from operating activities
Net income (loss)	$	920,270	$	(510,498)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion	1,445,129		1,286,889
Property impairments	30,991		264,976
Non-cash loss on derivatives	145,194		8,560
Stock-based compensation	44,918		48,086
Provision (benefit) for deferred income taxes	291,116		(136,127)
Dry hole costs	—		6,456
Net (gain) loss on sale of assets and other	(3,496)		5,914
(Gain) loss on extinguishment of debt	290		(64,573)
Other, net	7,465		7,811
Changes in assets and liabilities:
Accounts receivable	(444,748)		435,862
Inventories	(47,128)		21,846
Other current assets	(1,894)		1,196
Accounts payable trade	96,785		(150,645)
Revenues and royalties payable	183,050		(209,258)
Accrued liabilities and other	60,690		(80,227)
Other noncurrent assets and liabilities	21		(1,501)
Net cash provided by operating activities	2,728,653		934,767
Cash flows from investing activities
Exploration and development	(905,974)		(1,139,447)
Purchase of producing crude oil and natural gas properties	(175,441)		(23,318)
Purchase of other property and equipment	(46,948)		(21,306)
Proceeds from sale of assets	4,562		2,205
Net cash used in investing activities	(1,123,801)		(1,181,866)
Cash flows from financing activities
Credit facility borrowings	1,063,000		1,657,000
Repayment of credit facility	(1,223,000)		(1,237,000)
Redemption of Senior Notes	(630,782)		(74,032)
Proceeds from other debt	—		26,000
Repayment of other debt	(1,674)		(6,130)
Debt issuance costs	—		(237)
Contributions from noncontrolling interests	19,812		26,587
Distributions to noncontrolling interests	(16,535)		(10,814)
Repurchase of common stock	(65,256)		(126,906)
Repurchase of restricted stock for tax withholdings	(10,184)		(7,072)
Dividends paid on common stock	(94,054)		(18,460)
Net cash provided by (used in) financing activities	(958,673)		228,936
Net change in cash and cash equivalents	646,179		(18,163)
Cash and cash equivalents at beginning of period	47,470		39,400
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.

5

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 62% of its crude oil and natural gas revenues for the nine months ended September 30, 2021. The Company's principal producing properties in the North region are located in the Bakken field of North Dakota and 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 38% of its crude oil and natural gas revenues for the nine months ended September 30, 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, 2021, crude oil accounted for 49% of the Company’s total production and 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, 2020 (“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, 2021 and for the three and nine month periods ended September 30, 2021 and 2020 are unaudited. The condensed consolidated balance sheet as of December 31, 2020 was derived from the audited balance sheet included in the 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.

6

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, 2021 and 2020.

	Three months ended September 30,				Nine months ended September 30,
In thousands, except per share data	2021		2020		2021		2020
Net income (loss) attributable to Continental Resources (numerator)	$	369,328	$	(79,422)	$	918,295	$	(504,372)
Weighted average shares (denominator):
Weighted average shares - basic	360,563		360,257		360,899		361,948
Non-vested restricted stock (1)	3,685		—		3,580		—
Weighted average shares - diluted	364,248		360,257		364,479		361,948
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)

(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, 2021 and December 31, 2020 consisted of the following:

In thousands	September 30, 2021		December 31, 2020
Tubular goods and equipment	$	12,017	$	13,671
Crude oil and natural gas	107,268		58,486
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 operations for the nine month period ended September 30, 2020.

Adoption of new accounting pronouncement

On January 1, 2021 the Company adopted Accounting Standards Update ("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

7

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 on a prospective basis, which did not have a material impact on its financial position, results of operations, or cash flows.

Note 3. Supplemental Cash Flow Information

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

	Nine months ended September 30,
In thousands	2021		2020
Supplemental cash flow information:
Cash paid for interest	$	164,874	$	178,082
Cash paid for income taxes	3		8
Cash received for income tax refunds (1)	9		9,485
Non-cash investing activities:
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, 2021 and December 31, 2020, the Company had $194.9 million and $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, 2021 and December 31, 2020, the Company had $1.5 million and $0.1 million, respectively, of accrued contributions from noncontrolling interests included in "Receivables–Joint interest and other" with an offsetting amount in "Equity–Noncontrolling interests" in the condensed consolidated balance sheets.

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

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

8

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 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 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 $8.7 million and $8.4 million for the three months ended September 30, 2021 and 2020, respectively, and $27.5 million and $27.3 million for the nine months ended September 30, 2021 and 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 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 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.

9

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, 2021 and 2020.

	Three months ended September 30, 2021						Three months ended September 30, 2020
In thousands	North Region		South Region		Total		North Region		South Region		Total
Crude oil revenues:
Operated properties	$	615,514	$	214,348	$	829,862	$	346,580	$	176,585	$	523,165
Non-operated properties	159,981		12,980		172,961		91,067		9,723		100,790
Total crude oil revenues	775,495		227,328		1,002,823		437,647		186,308		623,955
Natural gas revenues:
Operated properties (1)	123,907		277,124		401,031		2,950		67,986		70,936
Non-operated properties (2)	31,132		21,195		52,327		(2,499)		9,076		6,577
Total natural gas revenues	155,039		298,319		453,358		451		77,062		77,513
Crude oil and natural gas sales	$	930,534	$	525,647	$	1,456,181	$	438,098	$	263,370	$	701,468
Timing of revenue recognition
Goods transferred at a point in time	$	930,534	$	525,647	$	1,456,181	$	438,098	$	263,370	$	701,468
Goods transferred over time	—		—		—		—		—		—
	$	930,534	$	525,647	$	1,456,181	$	438,098	$	263,370	$	701,468

	Nine months ended September 30, 2021						Nine months ended September 30, 2020
In thousands	North Region		South Region		Total		North Region		South Region		Total
Crude oil revenues:
Operated properties	$	1,647,079	$	591,225	$	2,238,304	$	891,920	$	385,836	$	1,277,756
Non-operated properties	478,589		41,966		520,555		252,374		26,315		278,689
Total crude oil revenues	2,125,668		633,191		2,758,859		1,144,294		412,151		1,556,445
Natural gas revenues:
Operated properties (1)	280,416		828,409		1,108,825		(7,974)		179,996		172,022
Non-operated properties (2)	64,876		54,068		118,944		(5,402)		15,798		10,396
Total natural gas revenues	345,292		882,477		1,227,769		(13,376)		195,794		182,418
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
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	—		—		—		—		—		—
	$	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.

10

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, 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, 2021 and 2020 related to performance obligations satisfied in prior reporting periods were not material.

Note 5. Derivative Instruments

From time to time the Company 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 operations under the caption "Loss on derivative instruments, net".

The Company's derivative contracts are settled based upon reported settlement prices on commodity exchanges, with crude oil derivative settlements based on NYMEX West Texas Intermediate ("WTI") pricing and natural gas derivative settlements based on NYMEX Henry Hub pricing. The estimated fair value of 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 6. Fair Value Measurements.

11

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

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

Natural gas derivatives
			Weighted Average Hedge Price
Period and Type of Contract	Volumes Hedged		Swaps		Sold Put		Floor		Ceiling
October 2021 - December 2021
Swaps - Henry Hub	235,000	MMBtus/day	$	3.20
Collars - Henry Hub	90,000	MMBtus/day					$	3.00	$	5.32
January 2022 - March 2022
Swaps - Henry Hub	45,000	MMBtus/day	$	3.96
Collars - Henry Hub	90,000	MMBtus/day					$	3.00	$	6.33
Three-way collars - Henry Hub	280,000	MMBtus/day			$	2.33	$	3.02	$	4.46
April 2022 - June 2022
Swaps - Henry Hub	55,000	MMBtus/day	$	4.00
July 2022 - September 2022
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 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.

12

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.

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	September 30, 2021		December 31, 2020
Commodity derivative assets:
Gross amounts of recognized assets	$	19,465	$	15,900
Gross amounts offset on balance sheet	(17,378)		(597)
Net amounts of assets on balance sheet	2,087		15,303
Commodity derivative liabilities:
Gross amounts of recognized liabilities	(151,166)		(2,408)
Gross amounts offset on balance sheet	17,378		597
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	September 30, 2021		December 31, 2020
Derivative assets	$	314	$	15,303
Derivative assets, noncurrent	1,773		—
Net amounts of assets on balance sheet	2,087		15,303
Derivative liabilities	(131,616)		(227)
Derivative liabilities, noncurrent	(2,172)		(1,584)
Net amounts of liabilities on balance sheet	(133,788)		(1,811)
Total derivative assets (liabilities), net	$	(131,701)	$	13,492

13

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

Note 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.

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, 2021 and December 31, 2020. 

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

14

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, 2021, the Company's commodity price assumptions were based on forward NYMEX strip prices through year-end 2025 and were then escalated at 3% per year thereafter. Operating cost assumptions were based on current costs escalated at 3% per year beginning in 2022.

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

For the three 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 included a $24.5 million impairment recognized in the 2020 first quarter to reduce the Company's crude oil inventory to estimated net realizable value at the time of impairment.

Certain unproved crude oil and natural gas properties were impaired during the three and nine months ended September 30, 2021 and 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 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

15

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, 2021				December 31, 2020
In thousands	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Debt:
Credit facility	$	—	$	—	$	160,000	$	160,000
Notes payable	22,923		22,500		24,590		24,700
5% Senior Notes due 2022	—		—		630,470		632,900
4.5% Senior Notes due 2023	647,789		673,600		646,943		669,900
3.8% Senior Notes due 2024	907,772		957,800		906,922		939,500
4.375% Senior Notes due 2028	991,592		1,106,500		990,746		1,024,400
5.75% Senior Notes due 2031	1,481,951		1,813,000		1,480,879		1,651,900
4.9% Senior Notes due 2044	692,008		786,800		691,868		689,600
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.

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.

16

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

Note 7. Long-Term Debt

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

In thousands	September 30, 2021		December 31, 2020
Credit facility	$	—	$	160,000
Notes payable	22,923		24,590
5% Senior Notes due 2022	—		630,470
4.5% Senior Notes due 2023	647,789		646,943
3.8% Senior Notes due 2024	907,772		906,922
4.375% Senior Notes due 2028	991,592		990,746
5.75% Senior Notes due 2031	1,481,951		1,480,879
4.9% Senior Notes due 2044	692,008		691,868
Total debt	$	4,744,035	$	5,532,418
Less: Current portion of long-term debt	2,306		2,245
Long-term debt, net of current portion	$	4,741,729	$	5,530,173

Credit Facility

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

Borrowings under the credit facility, 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 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, 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, 2021. 

	2023 Notes	2024 Notes	2028 Notes	2031 Notes	2044 Notes
Face value (in thousands)	$649,625	$911,000	$1,000,000	$1,500,000	$700,000
Maturity date	April 15, 2023	June 1, 2024	January 15, 2028	January 15, 2031	June 1, 2044
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 (1)	Jan 15, 2023	Mar 1, 2024	Oct 15, 2027	Jul 15, 2030	Dec 1, 2043

(1)At any time prior to the indicated dates, the Company 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, 2021.

17

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 $50.4 million face value of its 2023 Notes at an aggregate cost of $29.3 million and $89.0 million face value of its 2024 Notes at an aggregate cost of $46.9 million, in each case, including accrued and unpaid interest to the repurchase dates.

The repurchased notes were canceled by the Company. The Company recognized pre-tax gains on extinguishment of debt totaling $64.6 million related to the repurchases, which included the pro-rata write-off of deferred financing costs and unamortized debt discount associated with the 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, $2.3 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, 2021 associated with the loans.

Note 8. Commitments and Contingencies

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. 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, 2021 under the arrangements amount to approximately $1.38 billion, of which $73 million is expected to be incurred in the remainder of 2021, $272 million in 2022, $272 million in 2023, $252 million in 2024, $164 million in 2025, and $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 – The Company is involved in various legal proceedings including, but not limited to, commercial disputes, claims from royalty and surface owners, property damage claims, personal injury claims, regulatory compliance matters, disputes with tax authorities and other matters. While the outcome of these legal matters cannot be predicted with certainty, the Company does not expect them to have a material effect on its financial condition, results of operations or cash flows. As of September 30, 2021 and December 31, 2020, the Company had recognized a liability within “Other noncurrent liabilities” of $7.7 million and $7.7 million, respectively, for various matters, none of which are believed to be individually significant.

18

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 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 operations, was $14.3 million and $16.4 million for the three months ended September 30, 2021 and 2020, respectively, and $44.9 million and $48.1 million for the nine months ended September 30, 2021 and 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, 2021, the Company had 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, 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, 2021 is presented below. 

	Number of non-vested shares	Weighted average grant-date fair value
Non-vested restricted shares outstanding at December 31, 2020	4,890,638	$	36.26
Granted	2,900,923	23.51
Vested	(1,615,209)	45.49
Forfeited	(182,634)	27.14
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, 2021 was approximately $40 million. As of September 30, 2021, there was approximately $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 1.6 years.

Note 10. Shareholders' Equity

2021 Share Repurchases

During the three months ended 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.

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. 

19

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

Dividend 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.

Note 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,
	2021			2020			2021			2020
Provision (benefit) for income taxes (in thousands)	$	115,641		$	(13,972)		$	291,116		$	(138,350)
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,
In thousands, except tax rates	2021			2020			2021			2020
Income (loss) before income taxes	$	486,162		$	(95,555)		$	1,211,386		$	(648,848)
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	102,094			(20,067)			254,391			(136,258)
Items impacting the effective tax rate:
State and local income taxes, net of federal benefit	17,109			(2,988)			43,559			(20,896)
Equity compensation	(11)			214			6,126			4,685
Other, net	(2,086)			2,540			(7,006)			(90)
Change in valuation allowance	(1,465)			6,329			(5,954)			14,209
Provision (benefit) for income taxes	$	115,641		$	(13,972)		$	291,116		$	(138,350)
Effective tax rate	23.8		%	14.6		%	24.0		%	21.3		%

In assessing the realizability of deferred tax assets the Company must consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The Company applies judgment to determine the weight of both positive and negative evidence in order to conclude whether a valuation allowance is necessary for its deferred tax assets. In determining whether a valuation allowance is required, the Company considers, among other factors, the Company's financial position, results of operations, projected future taxable income, reversal of existing deferred tax liabilities against deferred tax assets, and tax planning strategies. During 2020, a valuation allowance had been established for the deferred tax asset associated with a portion of the Company's Oklahoma state net operating loss carryforwards. In 2021, the Company reassessed the realizability of the deferred tax asset related to Oklahoma state net operating loss carryforwards, and based on current year activity, determined it was more likely than not that such assets would be realized. Therefore, it was determined that the previously recorded valuation allowance in 2020 should be released 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.

20

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

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.

21

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, 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, 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.

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, the SCOOP and STACK areas of 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.

Third Quarter 2021 Highlights

Financial and 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.

•Generated $1.02 billion in operating cash flows in the third quarter, bringing year-to-date operating cash flows to $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 cost operations with production expenses averaging $3.39 per Boe for the quarter.

Financial and Operating Metrics

Our operating results for 2020 were severely impacted by the economic effects from the COVID-19 pandemic on crude oil demand and prices. In response to the significant reduction in crude oil prices during 2020, we curtailed approximately 55% of our operated crude oil production and associated natural gas in the 2020 second quarter and significantly reduced our capital spending. In July 2020 we began to gradually restore our curtailed production and subsequently brought our remaining curtailed production back online in September 2020. These actions resulted in material reductions in our production, revenues, and cash flows for the 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 lifting of COVID-19 restrictions, the resumption of economic activity, and the resulting improvement in supply and demand fundamentals. The increase in commodity prices and resumption of our operations resulted in significantly improved operating results in 2021 compared to 2020 as further described below.

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.

22

	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, 2021 compared to the three months ended September 30, 2020

Results of Operations

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

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

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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 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 increase (decrease)	Volume percent increase (decrease)
	2021			2020
	Volume	Percent		Volume	Percent
Crude oil (MBbl)	14,458	47	%	15,572	57	%	(1,114)	(7	%)
Natural gas (MMcf)	96,188	53	%	70,510	43	%	25,678	36	%
Total (MBoe)	30,489	100	%	27,324	100	%	3,165	12	%
	Three months ended September 30,						Volume increase	Volume percent increase
	2021			2020
	MBoe	Percent		MBoe	Percent
North Region	16,455	54	%	15,402	56	%	1,053	7	%
South Region	14,034	46	%	11,922	44	%	2,112	18	%
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 7% decrease in crude oil production for the 2021 third quarter compared to the 2020 third quarter was driven by our change in allocation of capital from oil-weighted projects to gas-weighted projects over the past year and the timing of well completions, which led to a 788 MBbls, or 22%, decrease in SCOOP crude oil production, a 511 MBbls, or 5%, decrease in Bakken crude oil production, and a 120 MBbls, or 23%, decrease in STACK crude oil production compared to the 2020 third quarter. Properties acquired in the Powder River Basin of Wyoming in March 2021 added 346 MBbls to our 2021 third quarter crude oil 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 $1.40 billion for the third quarter of 2021, a 117% increase compared to net sales of $646.2 million for the 2020 third quarter due to significant increases in net sales prices and total sales volumes as discussed below.

Total sales volumes for the third quarter of 2021 increased 2,620 MBoe, or 9%, compared to the 2020 third quarter, reflecting reduced sales in the prior year period due to the previously described production curtailments in the 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 10% driven by our increased allocation of capital toward gas-weighted projects over the past year.

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Our crude oil net sales prices averaged $66.48 per barrel in the 2021 third quarter compared to $35.93 per barrel for the 2020 third quarter due to a significant increase in market 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 averaged $4.09 per barrel for the 2021 third quarter compared to $5.00 per barrel for the 2020 third quarter. Crude oil prices in the 2020 third quarter were impacted by adverse changes in supply and demand fundamentals from the economic effects of the COVID-19 pandemic, which negatively impacted location differentials and price realizations in the 2020 third 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 due to a significant increase in market prices and improved price differentials. The difference between our net sales prices and NYMEX Henry Hub calendar month natural gas prices 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. 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. NGL prices have increased significantly in 2021 compared to 2020 levels in conjunction with increased crude oil prices and other factors, resulting in significantly improved price realizations for our natural gas sales stream relative to benchmark prices.

Derivatives. The significant improvement in commodity prices during the third quarter of 2021 had an overall unfavorable impact on the fair value of our derivatives, which resulted in negative revenue adjustments of $127.1 million for the period, representing $42.1 million of cash losses and $85.0 million of unsettled non-cash losses, compared to negative revenue adjustments totaling $17.9 million in the 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 increased $3.6 million, or 41%, from $8.8 million for the third quarter of 2020 to $12.3 million for the third quarter of 2021 due to increased water handling activities resulting from the previously described increase in completion activities and production volumes compared to the 2020 third quarter.

Operating Costs and Expenses

Production Expenses. Production expenses increased $14.5 million, or 16%, to $103.2 million for the third quarter of 2021 compared to $88.7 million for the third quarter of 2020 primarily due to the previously described 9% increase in total 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.

Production Taxes. Production taxes increased $52.2 million to $102.4 million for the third quarter of 2021 compared to $50.2 million for the third quarter of 2020 due to the previously described increase in crude oil and natural gas 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 to 7.3% for the third quarter of 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 increased $4.2 million, or 1%, to $465.4 million for the third quarter of 2021 compared to $461.2 million for the third quarter of 2020 primarily due to the previously described 9% increase in total sales 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,
$/Boe	2021		2020
Crude oil and natural gas	$	14.98	$	16.32
Other equipment	0.22		0.18
Asset retirement obligation accretion	0.09		0.08
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.

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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 for an extended period, additional upward price-related revisions of proved reserves may occur in the future, which may be significant and could result in a further decrease in our DD&A rate. We are unable to predict the timing and amount of future reserve revisions or the impact such revisions may have on our future DD&A rate.

Property Impairments. Total property impairments decreased $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, primarily reflecting a decrease in the amortization of undeveloped leasehold costs 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 prior year. There were no proved property impairments recognized in the third quarter of 2021 compared to $1.6 million recognized in the third quarter of 2020.

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

Total G&A expenses include non-cash charges for equity compensation of $14.3 million and $16.4 million for the third quarters of 2021 and 2020, 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. This increase was primarily due to an increase in employee benefits partially offset by higher overhead recoveries from joint interest owners driven by increased drilling, completion, and production 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	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 $4.0 million, or 6%, to $59.9 million for the third quarter of 2021 compared to $63.9 million for the third quarter of 2020 due to a decrease in our total outstanding debt. Our weighted average outstanding debt balance was $4.8 billion for the third quarter of 2021 compared to $5.8 billion for the third quarter of 2020.

Income Taxes. For the third quarters of 2021 and 2020 we provided for income taxes at a combined federal and state tax rate of 24.5% of our pre-tax income/loss. We recorded an income tax provision of $115.6 million for the 2021 third quarter and an income tax benefit of $14.0 million for the 2020 third quarter, which resulted in effective tax rates of 23.8% and 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 11. Income Taxes for a summary of the sources and tax effects of items comprising our effective tax rates.

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

Results of Operations

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

	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	YTD 9/30/2021	YTD 9/30/2020	% Change
Bakken	167,632	150,366	11	%
SCOOP	112,572	92,958	21	%
STACK	35,054	36,567	(4	%)
Powder River Basin	4,477	—	—
All other	6,367	7,031	(9	%)
Total	326,102	286,922	14	%

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

	Nine months ended September 30,						Volume increase	Volume percent increase
	2021			2020
	Volume	Percent		Volume	Percent
Crude oil (MBbl)	43,300	49	%	42,494	54	%	806	2	%
Natural gas (MMcf)	274,352	51	%	216,735	46	%	57,617	27	%
Total (MBoe)	89,026	100	%	78,617	100	%	10,409	13	%
	Nine months ended September 30,						Volume increase	Volume percent increase
	2021			2020
	MBoe	Percent		MBoe	Percent
North Region	48,718	55	%	43,118	55	%	5,600	13	%
South Region	40,307	45	%	35,499	45	%	4,808	14	%
Total	89,025	100	%	78,617	100	%	10,408	13	%

The 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 2021 compared to year to date 2020 was primarily driven by a 923 MBbls, or 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 SCOOP crude oil production and a 195 MBbls, or 13%, decrease in STACK crude oil production due to the previously described increase in our allocation of capital to gas-weighted projects over the past year.

Revenues

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

Total sales volumes for year to date 2021 increased 10,276 MBoe, or 13%, compared to year to date 2020, reflecting reduced sales in the prior period from the previously described production curtailments in the second and third quarters of 2020 and our subsequent resumption of usual operations. For year to date 2021, our crude oil sales volumes increased 2% from the comparable 2020 period, while our natural gas sales volumes 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 due to a significant increase in market prices from improved supply and 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. Crude oil prices for year to date 2020 were severely impacted by adverse changes in supply and demand fundamentals from the economic effects of the COVID-19 pandemic, which negatively impacted location differentials and price realizations in the 2020 period with no similar impacts in 2021.

Our natural gas net sales prices averaged $4.38 per Mcf for year to date 2021 compared to $0.72 per Mcf for year to date 2020 due to a significant increase in market prices and improved price differentials. The difference between our net sales prices and NYMEX Henry Hub calendar month natural gas prices was a premium of $1.17 per Mcf for year to date 2021 compared to a discount of $1.19 per Mcf for the year to date 2020 period. 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 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 increased crude oil prices and other factors, resulting in improved price realizations for our natural gas sales stream.

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

Operating Costs and Expenses

Production Expenses. Production expenses increased $20.9 million, or 8%, to $292.8 million for year to date 2021 compared to $271.9 million for year to date 2020 primarily due to the previously described 13% increase in total 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.

Production Taxes. Production taxes increased $148.3 million, or 112%, to $280.7 million for year to date 2021 compared to $132.4 million for year to date 2020 due to the previously described increase in crude oil and natural gas 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 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 North Dakota.

Exploration expenses. Exploration expenses, which consist primarily of exploratory geological and geophysical costs and dry hole costs that are expensed as incurred, decreased $5.1 million to $9.5 million for year to date 2021 compared to $14.6 million for year to date 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 2021 period.

Depreciation, Depletion, Amortization and Accretion. Total DD&A increased $158.6 million, or 12%, to $1.45 billion for year to date 2021 compared to $1.29 billion for the comparable 2020 period primarily due to the previously described 13% 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,
$/Boe	2021		2020
Crude oil and natural gas	$	15.95	$	16.08
Other equipment	0.22		0.20
Asset retirement obligation accretion	0.09		0.09
Depreciation, depletion, amortization and accretion	$	16.26	$	16.37

Property Impairments. Total property impairments decreased $234.0 million to $31.0 million for the year to date period of 2021 compared to $265.0 million for year to date 2020 primarily reflecting lower proved property impairments in the current period. No proved property impairments were recognized for year to 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 2021 compared to year to date 2020 reflecting a decrease in the amortization of undeveloped leasehold costs 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 prior year.

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

Total G&A expenses include non-cash charges for equity compensation of $44.9 million and $48.1 million for the year to date periods of 2021 and 2020, respectively. G&A expenses other than equity compensation totaled $121.9 million for year to date 2021, an increase of $40.3 million, or 49%, compared to $81.6 million for the comparable 2020 period due to an increase in employee 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,
$/Boe	2021		2020
General and administrative expenses	$	1.37	$	1.04
Non-cash equity compensation	0.50		0.61
Total general and administrative expenses	$	1.87	$	1.65

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Interest Expense. Interest expense decreased $6.8 million, or 4%, to $185.8 million for year to date 2021 compared to $192.5 million for the comparable 2020 period due to a decrease in our total outstanding debt. Our weighted average outstanding debt balance for year to date 2021 was $5.1 billion compared to $5.8 billion for year to date 2020.

Income Taxes. For the nine months ended September 30, 2021 and 2020 we provided for income taxes at a combined federal and state tax rate of 24.5% of our pre-tax income/loss. We recorded an income tax provision of $291.1 million for the year to date period of 2021 and an income tax benefit of $138.4 million for year to date 2020, which resulted in effective tax rates of 24.0% and 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 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, asset dispositions and joint development arrangements have provided a source of cash flow for use in reducing debt and enhancing liquidity. We are committed to operating in a 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, 2021, we had no outstanding borrowings and $1.7 billion of borrowing availability under our credit facility. Our amended credit facility remains unsecured and has no borrowing base subject to redetermination. Further, we have no near-term senior note maturities, with our earliest scheduled maturity being our $649.6 million of 2023 Notes due in 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 our contractual cash commitments to third parties as of September 30, 2021, including those described in Note 8. Commitments and Contingencies and 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 increased $1.79 billion, or 192%, to $2.73 billion for the 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 natural gas revenues due to the previously described increases in commodity prices and sales volumes in the current period. This increase was partially offset by a $148.2 million increase in production taxes associated with higher crude oil and natural gas revenues and a $70.5 million increase in realized cash losses on matured commodity derivatives in the current period.

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Cash flows from investing activities

Net cash used in investing activities decreased $58 million, or 5%, to $1.12 billion for the 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 $1.6 billion compared to $1.2 billion of non-acquisition capital spending for 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 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 term loans as described in Note 7. Long-Term Debt in Notes to Unaudited Condensed Consolidated Financial Statements, 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.

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 normal operating needs, debt service obligations, budgeted capital expenditures, and dividend payments for at least the next 12 months.    

Based on current market indications, our budgeted capital spending plans are expected to be funded from operating cash flows. Any deficiencies in operating cash 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. For instance, as previously described we plan to issue debt securities and/or execute bank term loan facilities in the 2021 fourth quarter to fund a portion of 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

On October 29, 2021, we amended our credit facility to increase aggregate commitments from $1.5 billion to $1.7 billion and extend the maturity date from April 2023 to October 2026. The amount available under the credit facility can be increased by up to an additional $2.3 billion in the future upon the agreement of the Company and participating lenders. The commitments are from a syndicate of 12 banks and financial institutions. We believe each member of the current syndicate has the capability to fund its commitment. As of October 31, 2021, we had no outstanding borrowings 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 do not trigger a reduction in our current credit facility commitments, nor do such actions trigger a security requirement or change in covenants. Downgrades of our credit rating will, however, trigger increases in our credit facility's interest rates and commitment fees paid on unused borrowing availability under certain circumstances.

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 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, 2021 and expect to maintain such compliance. At September 30, 2021, our consolidated net debt to total capitalization ratio was 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.

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Future Capital Requirements

Senior notes

Our debt includes outstanding senior note obligations totaling $4.76 billion at September 30, 2021. We have no near-term senior note maturities, with our earliest scheduled maturity being our $649.6 million of 2023 Notes due in 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 7. Long-Term Debt in Notes to Unaudited Condensed Consolidated Financial Statements.

We were in compliance with our senior note covenants at September 30, 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 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 $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 to maximize cash flow generation. Our non-acquisition capital expenditures are expected to total between $1.5 billion and $1.6 billion for 2021. Acquisition expenditures are not budgeted, with the exception of planned levels of spending for mineral acquisitions made in conjunction with our relationship with Franco-Nevada.

For the nine months ended September 30, 2021, we invested $966.6 million in our capital program excluding $224.2 million of unbudgeted acquisitions and including $66.0 million of capital costs associated with increased accruals for capital expenditures as compared to December 31, 2020. Our 2021 year to date capital expenditures were allocated as shown in the table below.

In millions	1Q 2021		2Q 2021		3Q 2021		YTD 2021
Exploration and development drilling	$	255.6	$	216.2	$	312.3	$	784.1
Land costs	7.5		14.5		18.5		40.5
Mineral acquisitions attributable to Continental	0.2		1.3		1.5		3.0
Capital facilities, workovers, water infrastructure, and other corporate assets	27.4		57.3		51.0		135.7
Seismic	2.7		0.2		0.4		3.3
Capital expenditures attributable to Continental, excluding unbudgeted acquisitions	293.4		289.5		383.7		966.6
Acquisitions of producing properties (1)	183.3		(5.4)		0.3		178.2
Acquisitions of non-producing properties	24.3		18.7		3.0		46.0
Total unbudgeted acquisitions	207.6		13.3		3.3		224.2
Total capital expenditures attributable to Continental	$	501.0	$	302.8	$	387.0	$	1,190.8
Mineral acquisitions attributable to Franco-Nevada	0.9		2.8		6.0		9.7
Total capital expenditures	$	501.9	$	305.6	$	393.0	$	1,200.5

(1) The adjustment of $5.4 million in the second quarter of 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, actual drilling and completion results, the availability of drilling and completion rigs and other services and equipment, the availability of transportation and processing capacity, changes in commodity prices, and regulatory, technological and competitive developments. We monitor our capital spending closely based on actual and projected cash flows and may scale back our spending should commodity

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prices decrease from current levels. Conversely, an increase in commodity prices from current levels could result in increased capital expenditures. We expect to continue participating as a buyer of properties when and if we have the ability to increase our position in strategic plays at competitive terms. 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 8. Commitments and Contingencies and Note 13. Subsequent Events in Notes to Unaudited Condensed Consolidated Financial Statements for discussion of certain future commitments of the Company.

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 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. There can be no assurance that all of the conditions to closing the acquisitions will be satisfied.

Dakota Access Pipeline

The U.S. Army Corps of 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 estimated to be completed no later than September 2022. Once completed, the Corps will determine whether DAPL is safe to operate or must be shut 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. Our transportation commitment on the pipeline increased from 3,550 barrels per day to 30,000 barrels per day effective August 1, 2021 in conjunction with the completion of a DAPL expansion project. This commitment will continue through February 2026 at which time the commitment decreases to 26,450 barrels per day through July 2028.

If transportation capacity on DAPL becomes restricted or unavailable, we have the ability to utilize other third party pipelines or rail facilities to transport our Bakken crude oil production to market, although such alternatives may be more costly. A restriction of DAPL’s takeaway capacity may have an impact on prices for Bakken-produced barrels and result in wider differentials relative to WTI benchmark prices in the future, the amount of which is uncertain.

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.

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.

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The company entered into additional derivative contracts subsequent to September 30, 2021 as set forth in the 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 redemptions

As discussed in Note 7. Long-Term Debt, in 2021 we redeemed the remaining principal amount of our 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.

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 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 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.

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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 for a discussion of significant laws and regulations that have been enacted or are currently being considered by regulatory bodies that may affect us in the areas in which we operate.

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, 2021 and 2020.

	Three months ended September 30, 2021						Three months ended September 30, 2020
In thousands	Crude oil		Natural gas		Total		Crude oil		Natural gas		Total
Crude oil and natural gas sales (GAAP)	$	1,002,823	$	453,358	$	1,456,181	$	623,955	$	77,513	$	701,468
Less: Transportation expenses	(45,241)		(8,728)		(53,969)		(46,890)		(8,382)		(55,272)
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)	14,404		96,188		30,435		16,063		70,510		27,815
Net sales price (non-GAAP)	$	66.48	$	4.62	$	46.07	$	35.93	$	0.98	$	23.23

	Nine months ended September 30, 2021						Nine months ended September 30, 2020
In thousands	Crude oil		Natural gas		Total		Crude oil		Natural gas		Total
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	(129,218)		(27,452)		(156,670)		(120,780)		(27,299)		(148,079)
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)	43,257		274,352		88,982		42,583		216,735		78,706
Net sales price (non-GAAP)	$	60.79	$	4.38	$	43.04	$	33.71	$	0.72	$	20.21

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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 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, 2021, and excluding the effect of derivative instruments in place, our annual revenue would increase or decrease by approximately $579 million for each $10.00 per barrel change in crude oil prices at September 30, 2021 and $367 million for each $1.00 per Mcf change in natural gas prices at September 30, 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 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 settle existing derivative positions prior to the expiration of their contractual 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 derivative instruments at September 30, 2021 was a net liability of $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 our derivatives would impact the fair value estimates as of September 30, 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 ($903 million in receivables at September 30, 2021), and our joint interest and other receivables ($248 million at September 30, 2021).

We monitor our exposure to counterparties on crude oil and natural gas sales primarily by reviewing credit ratings, financial statements and payment history. We extend credit terms based on our evaluation of each counterparty’s credit worthiness. We have not generally required our counterparties to provide collateral to secure crude oil and natural gas sales receivables owed to us. Historically, our credit losses on crude oil and natural gas sales receivables have been immaterial.

Joint interest receivables arise from billing the individuals and entities who own a partial interest in the wells we operate. These individuals and entities participate in our wells primarily based on their ownership in leases included in units on which we wish to drill. We can do very little to choose who participates in our wells. In order to minimize our exposure to this credit risk we generally request prepayment of drilling costs where it is allowed by contract or state law. For such prepayments, a liability is recorded and subsequently reduced as the associated work is performed. This liability was $19 million at September 30, 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 interest. Historically, our credit losses on joint interest receivables have been immaterial.

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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. 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 no outstanding borrowings on our credit facility at October 31, 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, 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, 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.

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.

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PART II. Other Information

ITEM 1.    Legal Proceedings

We are involved in various legal proceedings including, but not limited to, commercial disputes, claims from royalty and surface owners, property damage claims, personal injury claims, regulatory compliance matters, disputes with tax authorities and other matters. While the outcome of these legal matters cannot be predicted with certainty, we do not expect them to have a material effect on our financial condition, results of 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 I, Item 1A. Risk Factors in our 2020 Form 10-K, which could materially affect our business, financial condition or future results. The risks described in this Form 10-Q, if any, and in our 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 2020 Form 10-K. 

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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, 2021.

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, 2021 to July 31, 2021:
Repurchases for tax withholdings (2)	4,636	$	35.18	—	—
August 1, 2021 to August 31, 2021:
Repurchases for tax withholdings (2)	8,166	$	36.61	—	—
Share repurchase program (1)	1,916,069	$	34.06	1,916,069	$	617.6
September 1, 2021 to September 30, 2021:
Repurchases for tax withholdings (2)	6,201	$	44.25	—	—
Purchases by principal shareholder (3)	261,709	$	41.99	—	—
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. 

(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 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.

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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.
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

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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 3, 2021	By:	/s/ John D. Hart
			John D. Hart
			Sr. Vice President, Chief Financial Officer and Chief Strategy Officer (Duly Authorized Officer and Principal Financial Officer)

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