Continental Resources Inc 10Q 2020 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

________________________________________

FORM 10-Q

________________________________________

(Mark One)


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

For the quarterly period ended September 30, 2020


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

For the transition period from to

Commission File Number: 001-32886

____________________________________

CONTINENTAL RESOURCES, INC

(Exact name of registrant as specified in its charter)

____________________________________

Oklahoma

73-0767549

(State or other jurisdiction of incorporation or organization)

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

20 N. Broadway,

Oklahoma City,

Oklahoma

73102

(Address of principal executive offices)

(Zip Code)

(405) 234-9000

(Registrant’s telephone number, including area code)

Not Applicable

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

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


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

____________________________________

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

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

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

Large accelerated filer

Accelerated filer

☐

Non-accelerated filer

☐

Smaller reporting company

☐

Emerging growth company

☐

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

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

365,234,283 shares of our $0.01 par value common stock were outstanding on October 31, 2020.

Table of Contents

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

Glossary of Crude Oil and Natural Gas Terms

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

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

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

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

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

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

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

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

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

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

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

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

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

“MBoe” One thousand Boe.

“Mcf” One thousand cubic feet of natural gas.

“MMBoe” One million Boe.

“MMBtu” One million British thermal units.

“MMcf” One million cubic feet of natural gas.

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

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

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

“NYMEX” The New York Mercantile Exchange.

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

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

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

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

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

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

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

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

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

Cautionary Statement for Purpose of “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, or share repurchases;

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

•credit markets;

•our liquidity and access to capital;

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

•our future operating and financial results;

•our future commodity or other hedging arrangements; and

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

Forward-looking statements are based on the Company’s current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes these assumptions and expectations are reasonable, they are inherently subject to numerous business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control. No assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate or will not change over time. The risks and uncertainties that may affect the operations, performance and results of the business and forward-looking statements include, but are not limited to, those risk factors and other cautionary statements described under Part II, Item 1A. Risk Factors and elsewhere in this report, if any, our Annual Report on Form 10-K for the year ended December 31, 2019, our Form 10-Qs for the quarters ended March 31, 2020 and June 30, 2020, registration statements we file from time to time with the Securities and Exchange Commission, and other announcements we make from time to time.

Many of the foregoing risks and uncertainties have been, and may further be, exacerbated by the COVID-19 pandemic and any consequent 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, our Annual Report on Form 10-K, or our Form 10-Qs for the quarters ended March 31, 2020 and June 30, 2020 occur, or should underlying assumptions prove incorrect, the Company's actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by this cautionary statement.

iii

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

PART I. Financial Information

ITEM 1. Financial Statements

Continental Resources, Inc. and Subsidiaries

Condensed Consolidated Balance Sheets


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

Joint interest and other	126,135		317,018
Allowance for credit losses	(2,220)		(2,407)
Receivables, net	599,102		1,041,487
Derivative assets	346		0
Inventories	63,170		109,536
Prepaid expenses and other	15,907		16,592
Total current assets	699,762		1,207,015
Net property and equipment, based on successful efforts method of accounting	14,004,414		14,497,726
Operating lease right-of-use assets	10,396		9,128
Other noncurrent assets	13,652		14,038
Total assets	$	14,728,224	$	15,727,907

Liabilities and equity
Current liabilities:
Accounts payable trade	$	321,975	$	629,264
Revenues and royalties payable	260,887		470,264

Accrued liabilities and other	151,662		230,368

Derivative liabilities	7,086		0
Current portion of operating lease liabilities	4,225		3,695
Current portion of long-term debt	2,225		2,435
Total current liabilities	748,060		1,336,026
Long-term debt, net of current portion	5,629,133		5,324,079
Other noncurrent liabilities:
Deferred income tax liabilities, net	1,650,998		1,787,125
Asset retirement obligations, net of current portion	173,762		151,774
Derivative liabilities, noncurrent	1,820		0
Operating lease liabilities, net of current portion	6,005		5,433
Other noncurrent liabilities	14,332		15,119
Total other noncurrent liabilities	1,846,917		1,959,451
Commitments and contingencies (Note 10)
Equity:
Preferred stock, $0.01 par value; 25,000,000 shares authorized; no shares issued and outstanding	0		0
Common stock, $0.01 par value; 1,000,000,000 shares authorized; 365,112,162 shares issued and outstanding at September 30, 2020; 371,074,036 shares issued and outstanding at December 31, 2019	3,651		3,711
Additional paid-in capital	1,188,891		1,274,732
Retained earnings	4,940,142		5,463,224
Total shareholders’ equity attributable to Continental Resources	6,132,684		6,741,667
Noncontrolling interests	371,430		366,684
Total equity	6,504,114		7,108,351
Total liabilities and equity	$	14,728,224	$	15,727,907

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

Continental Resources, Inc. and Subsidiaries

Unaudited Condensed Consolidated Statements of Comprehensive Income (Loss)


	Three months ended September 30,				Nine months ended September 30,
In thousands, except per share data	2020		2019		2020		2019
Revenues:
Crude oil and natural gas sales	$	701,468	$	1,081,400	$	1,738,863	$	3,328,409
Gain (loss) on derivative instruments, net	(17,853)		1,195		(25,635)		53,519
Crude oil and natural gas service operations	8,755		21,602		35,602		54,886
Total revenues	692,370		1,104,197		1,748,830		3,436,814

Operating costs and expenses:
Production expenses	88,701		114,050		271,852		333,446
Production taxes	50,153		86,931		132,444		267,237
Transportation expenses	55,272		62,038		148,079		164,569
Exploration expenses	1,041		2,472		14,638		7,399
Crude oil and natural gas service operations	3,316		8,224		15,288		26,616
Depreciation, depletion, amortization and accretion	461,191		484,031		1,288,185		1,464,672
Property impairments	18,518		20,199		264,976		66,854
General and administrative expenses	45,273		46,993		129,713		141,837
Net (gain) loss on sale of assets and other	800		535		5,914		647
Total operating costs and expenses	724,265		825,473		2,271,089		2,473,277
Income (loss) from operations	(31,895)		278,724		(522,259)		963,537
Other income (expense):
Interest expense	(63,884)		(68,090)		(192,547)		(204,398)
Gain (loss) on extinguishment of debt	0		(4,584)		64,573		(4,584)
Other	224		1,119		1,385		3,196
	(63,660)		(71,555)		(126,589)		(205,786)
Income (loss) before income taxes	(95,555)		207,169		(648,848)		757,751
(Provision) benefit for income taxes	13,972		(49,747)		138,350		(177,386)
Net income (loss)	(81,583)		157,422		(510,498)		580,365
Net loss attributable to noncontrolling interests	(2,161)		(740)		(6,126)		(1,330)
Net income (loss) attributable to Continental Resources	$	(79,422)	$	158,162	$	(504,372)	$	581,695

Net income (loss) per share attributable to Continental Resources:
Basic	$	(0.22)	$	0.43	$	(1.39)	$	1.56
Diluted	$	(0.22)	$	0.43	$	(1.39)	$	1.56

Comprehensive income (loss):
Net income (loss)	$	(81,583)	$	157,422	$	(510,498)	$	580,365
Other comprehensive income, net of tax:
Foreign currency translation adjustments	0		(18)		0		128
Total other comprehensive income, net of tax	0		(18)		0		128
Comprehensive income (loss)	(81,583)		157,404		(510,498)		580,493
Comprehensive loss attributable to noncontrolling interests	(2,161)		(740)		(6,126)		(1,330)
Comprehensive income (loss) attributable to Continental Resources	$	(79,422)	$	158,144	$	(504,372)	$	581,823

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

Continental Resources, Inc. and Subsidiaries

Unaudited Condensed Consolidated Statements of Equity


	Shareholders’ equity attributable to Continental Resources
In thousands, except share data	Shares outstanding	Common stock		Additional paid-in capital		Accumulated other comprehensive income		Treasury stock		Retained earnings		Total shareholders’ equity of Continental Resources		Noncontrolling interests		Total equity
Balance at December 31, 2019	371,074,036	$	3,711	$	1,274,732	$	0	$	—	$	5,463,224	$	6,741,667	$	366,684	$	7,108,351
Net income (loss)	—	—		—		—		—		(185,664)		(185,664)		(1,120)		(186,784)
Cumulative effect adjustment from adoption of ASU 2016-13	—	—		—		—		—		(137)		(137)		—		(137)
Cash dividends declared ($0.05 per share)	—	—		—		—		—		(18,580)		(18,580)		—		(18,580)
Change in dividends payable	—	—		—		—		—		2		2		—		2
Common stock repurchased	—	—		—		—		(126,906)		—		(126,906)		—		(126,906)
Common stock retired	(8,122,104)	(81)		(126,825)		—		126,906		—		—		—		—
Stock-based compensation	—	—		16,411		—		—		—		16,411		—		16,411
Restricted stock:
Granted	2,454,235	24		—		—		—		—		24		—		24
Repurchased and canceled	(246,346)	(2)		(6,452)		—		—		—		(6,454)		—		(6,454)
Forfeited	(42,818)	(1)		—		—		—		—		(1)		—		(1)
Contributions from noncontrolling interests	—	—		—		—		—		—		—		16,950		16,950
Distributions to noncontrolling interests	—	—		—		—		—		—		—		(5,618)		(5,618)
Balance at March 31, 2020	365,117,003	$	3,651	$	1,157,866	$	0	$	—	$	5,258,845	$	6,420,362	$	376,896	$	6,797,258
Net income (loss)	—	—		—		—		—		(239,286)		(239,286)		(2,845)		(242,131)
Change in dividends payable	—	—		—		—		—		2		2		—		2



Stock-based compensation	—	—		15,313		—		—		—		15,313		—		15,313
Restricted stock:
Granted	85,514	1		—		—		—		—		1		—		1
Repurchased and canceled	(19,037)	0		(247)		—		—		—		(247)		—		(247)
Forfeited	(39,237)	(1)		—		—		—		—		(1)		—		(1)
Contributions from noncontrolling interests	—	—		—		—		—		—		—		4,015		4,015
Distributions to noncontrolling interests	—	—		—		—		—		—		—		(2,958)		(2,958)
Balance at June 30, 2020	365,144,243	$	3,651	$	1,172,932	$	0	$	—	$	5,019,561	$	6,196,144	$	375,108	$	6,571,252
Net income (loss)	—	—		—		—		—		(79,422)		(79,422)		(2,161)		(81,583)
Change in dividends payable	—	—		—		—		—		3		3		—		3



Stock-based compensation	—	—		16,330		—		—		—		16,330		—		16,330
Restricted stock:
Granted	43,241	1		—		—		—		—		1		—		1
Repurchased and canceled	(20,873)	0		(371)		—		—		—		(371)		—		(371)
Forfeited	(54,449)	(1)		—		—		—		—		(1)		—		(1)
Contributions from noncontrolling interests	—	—		—		—		—		—		—		36		36
Distributions to noncontrolling interests	—	—		—		—		—		—		—		(1,553)		(1,553)
Balance at September 30, 2020	365,112,162	$	3,651	$	1,188,891	$	0	$	—	$	4,940,142	$	6,132,684	$	371,430	$	6,504,114

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

Continental Resources, Inc. and Subsidiaries

Unaudited Condensed Consolidated Statements of Equity (Continued)


	Shareholders’ equity attributable to Continental Resources
In thousands, except share data	Shares outstanding	Common stock		Additional paid-in capital		Accumulated other comprehensive income		Treasury stock		Retained earnings		Total shareholders’ equity of Continental Resources		Noncontrolling interests		Total equity
Balance at December 31, 2018	376,021,575	$	3,760	$	1,434,823	$	415	$	—	$	4,706,135	$	6,145,133	$	276,728	$	6,421,861
Net income (loss)	—	—		—		—		—		186,976		186,976		(483)		186,493
Other comprehensive income, net of tax	—	—		—		116		—		—		116		—		116
Stock-based compensation	—	—		12,095		—		—		—		12,095		—		12,095
Restricted stock:
Granted	1,333,602	13		—		—		—		—		13		—		13
Repurchased and canceled	(439,419)	(4)		(20,618)		—		—		—		(20,622)		—		(20,622)
Forfeited	(147,074)	(1)		—		—		—		—		(1)		—		(1)
Contributions from noncontrolling interests	—	—		—		—		—		—		—		42,204		42,204
Distributions to noncontrolling interests	—	—		—		—		—		—		—		(3,856)		(3,856)
Balance at March 31, 2019	376,768,684	$	3,768	$	1,426,300	$	531	$	—	$	4,893,111	$	6,323,710	$	314,593	$	6,638,303
Net income (loss)	—	—		—		—		—		236,557		236,557		(107)		236,450
Cash dividends declared ($0.05 per share)	—	—		—		—		—		(18,747)		(18,747)		—		(18,747)
Common stock repurchased	—	—		—		—		(69,661)		—		(69,661)		—		(69,661)
Common stock retired	(1,800,000)	(18)		(69,643)		—		69,661		—		—		—		—
Other comprehensive income, net of tax	—	—		—		30		—		—		30		—		30
Stock-based compensation	—	—		12,176		—		—		—		12,176		—		12,176
Restricted stock:
Granted	59,639	1		—		—		—		—		1		—		1
Repurchased and canceled	(13,335)	(1)		(561)		—		—		—		(562)		—		(562)
Forfeited	(71,440)	(1)		—		—		—		—		(1)		—		(1)
Contributions from noncontrolling interests	—	—		—		—		—		—		—		35,118		35,118
Distributions to noncontrolling interests	—	—		—		—		—		—		—		(3,272)		(3,272)
Balance at June 30, 2019	374,943,548	$	3,749	$	1,368,272	$	561	$	—	$	5,110,921	$	6,483,503	$	346,332	$	6,829,835
Net income (loss)	—	—		—		—		—		158,162		158,162		(740)		157,422
Change in dividends payable	—	—		—		—		—		160		160		—		160
Common stock repurchased	—	—		—		—		(102,304)		—		(102,304)		—		(102,304)
Common stock retired	(3,206,553)	(32)		(102,272)		—		102,304		—		—		—		—
Other comprehensive loss, net of tax	—	—		—		(18)		—		—		(18)		—		(18)
Stock-based compensation	—	—		12,871		—		—		—		12,871		—		12,871
Restricted stock:
Granted	102,945	1		—		—		—		—		1		—		1
Repurchased and canceled	(13,353)	0		(389)		—		—		—		(389)		—		(389)
Forfeited	(96,099)	(1)		—		—		—		—		(1)		—		(1)
Contributions from noncontrolling interests	—	—		—		—		—		—		—		19,713		19,713
Distributions to noncontrolling interests	—	—		—		—		—		—		—		(3,110)		(3,110)
Balance at September 30, 2019	371,730,488	$	3,717	$	1,278,482	$	543	$	—	$	5,269,243	$	6,551,985	$	362,195	$	6,914,180

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

Continental Resources, Inc. and Subsidiaries

Unaudited Condensed Consolidated Statements of Cash Flows


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

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

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

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

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

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

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

Note 1. Organization and Nature of Business

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

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

For the nine months ended September 30, 2020, crude oil accounted for 54% of the Company’s total production and 90% of its crude oil and natural gas revenues.

Note 2. Basis of Presentation and Significant Accounting Policies

Basis of presentation

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

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

The condensed consolidated financial statements as of September 30, 2020 and for the three and nine month periods ended September 30, 2020 and 2019 are unaudited. The condensed consolidated balance sheet as of December 31, 2019 was derived from the audited balance sheet included in the 2019 Form 10-K. The Company has evaluated events or transactions through the date this report on Form 10-Q was filed with the SEC in conjunction with its preparation of these condensed consolidated financial statements.

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

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

Earnings per share

Basic net income (loss) per share is computed by dividing net income (loss) attributable to the Company by the weighted-average number of shares outstanding for the period. In periods where the Company has net income, diluted earnings per share reflects the potential dilution of non-vested restricted stock awards, which are calculated using the treasury stock method. The following table presents the calculation of basic and diluted weighted average shares outstanding and net income (loss) per share attributable to the Company for the three and nine months ended September 30, 2020 and 2019.


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

(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.

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 inventories are valued at the lower of cost or net realizable value primarily using the first-in, first-out inventory method. Tubular goods and equipment are valued primarily using a weighted average cost method applied to specific classes of inventory items.

The components of inventory as of September 30, 2020 and December 31, 2019 consisted of the following:


In thousands	September 30, 2020		December 31, 2019
Tubular goods and equipment	$	13,657	$	14,880
Crude oil	49,513		94,656
Total	$	63,170	$	109,536

In the first quarter of 2020 the Company recognized a $24.5 million impairment to reduce its crude oil inventory to estimated net realizable value at March 31, 2020. The impairment is included in the caption “Property impairments” in the unaudited condensed consolidated statements of comprehensive income (loss) for the nine month period ended September 30, 2020.

Adoption of new accounting pronouncement

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

New accounting pronouncement not yet adopted

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

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

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	2020		2019
Supplemental cash flow information:
Cash paid for interest	$	178,082	$	194,087
Cash paid for income taxes	8		9
Cash received for income tax refunds (1)	9,485		7
Non-cash investing activities:
Asset retirement obligation additions and revisions, net	15,733		4,313

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

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

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

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

Note 4. Revenues

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

Operated crude oil revenues – The Company pays third parties to transport the majority of its operated crude oil production from lease locations to downstream market centers, at which time the Company's customers take title and custody of the product in exchange for prices based on the particular market where the product was delivered. Operated crude oil revenues are recognized during the month in which control transfers to the customer and it is probable the Company will collect the consideration it is entitled to receive. Crude oil sales proceeds from operated properties are generally received by the Company within one month after the month in which a sale has occurred. Operated crude oil revenues are presented separately from transportation expenses as the Company controls the operated production prior to its transfer to customers. Transportation expenses associated with the Company's operated crude oil production totaled $46.9 million and $53.0 million for the three months ended September 30, 2020 and 2019, respectively, and $120.8 million and $140.7 million for the nine months ended September 30, 2020 and 2019, respectively.

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

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

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

Under certain arrangements, the Company has the right to take a volume of processed residue gas and/or NGLs in-kind at the tailgate of the midstream customer's processing plant in lieu of a monetary settlement for the sale of the Company's operated natural gas production. The Company currently takes certain processed residue gas volumes in kind in lieu of monetary settlement, but does not currently take NGL volumes. When the Company elects to take volumes in kind, it pays third parties to transport the processed products it took in-kind to downstream delivery points, where it then sells to customers at prices applicable to those downstream markets. In such situations, operated revenues are recognized during the month in which control transfers to the customer at the delivery point and it is probable the Company will collect the consideration it is entitled to receive. Operated sales proceeds are generally received by the Company within one month after the month in which a sale has occurred. In these scenarios, the Company's revenues include the pricing adjustments applied by the midstream processing entity according to the applicable contractual pricing formula, but exclude the transportation expenses the Company incurs to transport the processed products to downstream customers. Transportation expenses associated with these arrangements totaled $8.4 million and $9.0 million for the three months ended September 30, 2020 and 2019, respectively, and $27.3 million and $23.9 million for the nine months ended September 30, 2020 and 2019, respectively.

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

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

Revenues from derivative instruments – See Note 6. Derivative Instruments for discussion of the Company's accounting for its derivative instruments.

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

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

Disaggregation of crude oil and natural gas revenues

The following tables present the disaggregation of the Company's crude oil and natural gas revenues for the three and nine months ended September 30, 2020 and 2019.


	Three months ended September 30, 2020						Three months ended September 30, 2019
In thousands	North Region		South Region		Total		North Region		South Region		Total
Crude oil revenues:
Operated properties	$	346,580	$	176,585	$	523,165	$	593,729	$	210,851	$	804,580
Non-operated properties	91,067		9,723		100,790		172,383		12,334		184,717
Total crude oil revenues	437,647		186,308		623,955		766,112		223,185		989,297
Natural gas revenues:
Operated properties (1)	2,950		67,986		70,936		10,719		71,370		82,089
Non-operated properties (2)	(2,499)		9,076		6,577		3,068		6,946		10,014
Total natural gas revenues	451		77,062		77,513		13,787		78,316		92,103
Crude oil and natural gas sales	$	438,098	$	263,370	$	701,468	$	779,899	$	301,501	$	1,081,400

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




	Nine months ended September 30, 2020						Nine months ended September 30, 2019
In thousands	North Region		South Region		Total		North Region		South Region		Total
Crude oil revenues:
Operated properties	$	891,920	$	385,836	$	1,277,756	$	1,787,776	$	523,484	$	2,311,260
Non-operated properties	252,374		26,315		278,689		558,893		35,408		594,301
Total crude oil revenues	1,144,294		412,151		1,556,445		2,346,669		558,892		2,905,561
Natural gas revenues:
Operated properties (1)	(7,974)		179,996		172,022		83,831		290,780		374,611
Non-operated properties (2)	(5,402)		15,798		10,396		18,985		29,252		48,237
Total natural gas revenues	(13,376)		195,794		182,418		102,816		320,032		422,848
Crude oil and natural gas sales	$	1,130,918	$	607,945	$	1,738,863	$	2,449,485	$	878,924	$	3,328,409

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

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

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

Performance obligations

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

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

All of the Company's outstanding crude oil sales contracts at September 30, 2020 are short-term in nature with contract terms of less than one year. For such contracts, the Company has utilized the practical expedient in Accounting Standards Codification ("ASC") 606-10-50-14 exempting the Company from disclosure of the transaction price allocated to remaining performance obligations, if any, if the performance obligation is part of a contract that has an original expected duration of one year or less.

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

Contract balances

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

Revenues from previously satisfied performance obligations

To record revenues for commodity sales, at the end of each month the Company estimates the amount of production delivered and sold to customers and the prices to be received for such sales. Differences between estimated revenues and actual amounts received for all prior months are recorded in the month payment is received from the customer and are reflected in the financial statements within the caption "Crude oil and natural gas sales". Revenues recognized during the three and nine months ended September 30, 2020 and 2019 related to performance obligations satisfied in prior reporting periods were not material.

Note 5. Allowance for Credit Losses

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

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

Historically, the Company's credit losses on receivables have been immaterial. The Company’s aggregate allowance for credit losses totaled $2.2 million and $2.4 million at September 30, 2020 and December 31, 2019, which is reported as "Allowance for credit losses" in the condensed consolidated balance sheets. Aggregate credit loss expenses totaled less than $0.1 million and $1.4 million for the three months ended September 30, 2020 and 2019, respectively, and $1.4 million and $1.5 million for the nine months ended September 30, 2020 and 2019, respectively, which are included in “General and administrative expenses” in the unaudited condensed consolidated statements of comprehensive income (loss).

Receivables—Crude oil and natural gas sales

The Company's crude oil and natural gas production from operated properties is generally sold to energy marketing companies, crude oil refining companies, and natural gas gathering and processing companies. The Company monitors its credit loss exposure to these counterparties primarily by reviewing credit ratings, financial statements, and payment history. Credit terms

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

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

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

The Company’s allowance for credit losses on crude oil and natural gas sales was negligible at both September 30, 2020 and December 31, 2019. The allowance was determined by considering a number of factors, primarily including the Company’s history of credit losses with adjustment as needed to reflect current conditions, the length of time accounts are past due, whether amounts relate to operated properties or non-operated properties, and the counterparty's ability to pay. There were no significant write-offs, recoveries, or changes in the provision for credit losses on this portfolio segment during the three and nine month periods ended September 30, 2020.

Receivables—Joint interest and other

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

The Company’s allowance for credit losses on joint interest receivables totaled $2.2 million and $2.4 million at September 30, 2020 and December 31, 2019, respectively. The allowance was determined by considering a number of factors, primarily including the Company’s history of credit losses with adjustment as needed to reflect current conditions, the length of time accounts are past due, the ability to recoup amounts owed through netting of production proceeds, the balance of co-owner prepayments if any, and the co-owner's ability to pay. There were no significant write-offs, recoveries, or changes in the provision for credit losses on this portfolio segment during the three and nine month periods ended September 30, 2020.

Note 6. Derivative Instruments

From time to time the Company has entered into crude oil and natural gas swap and collar derivative contracts to economically hedge against the variability in cash flows associated with future sales of production. The Company recognizes its derivative instruments on the balance sheet as either assets or liabilities measured at fair value. The Company has not designated its derivatives as hedges for accounting purposes and, as a result, marks such derivative instruments to fair value and recognizes the changes in fair value in the unaudited condensed consolidated statements of comprehensive income (loss) under the caption "Gain (loss) on derivative instruments, net".

The Company's derivative contracts are settled based upon reported settlement prices on commodity exchanges, with crude oil derivative settlements based on NYMEX West Texas Intermediate ("WTI") pricing and natural gas derivative settlements based on NYMEX Henry Hub pricing. The estimated fair value of derivative contracts is based upon various factors, including commodity exchange prices, over-the-counter quotations, and, in the case of collars, volatility, the risk-free interest rate, and the time to expiration. The calculation of the fair value of collars requires the use of an option-pricing model. See Note 7. Fair Value Measurements.

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

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


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


October 2020 - December 2020
Swaps - Henry Hub	17,480,000	$	2.58
Collars - Henry Hub	8,280,000			$2.60 - $2.80	$	2.73	$3.05 - $3.21	$	3.10
January 2021 - December 2021
Swaps - Henry Hub	23,722,000	$	2.72
Collars - Henry Hub	33,480,000			$2.60 - $3.00	$	2.72	$3.06 - $4.00	$	3.48
January 2022 - December 2022
Swaps - Henry Hub	5,475,000	$	2.44

Derivative gains and losses

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


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

Balance sheet offsetting of derivative assets and liabilities

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

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

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



In thousands	September 30, 2020		December 31, 2019
Commodity derivative assets:
Gross amounts of recognized assets	$	2,682	$	0
Gross amounts offset on balance sheet	(2,336)		0
Net amounts of assets on balance sheet	346		0
Commodity derivative liabilities:
Gross amounts of recognized liabilities	(11,242)		0
Gross amounts offset on balance sheet	2,336		0
Net amounts of liabilities on balance sheet	$	(8,906)	$	0

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, 2020		December 31, 2019
Derivative assets	$	346	$	0
Derivative assets, noncurrent	0		0
Net amounts of assets on balance sheet	346		0
Derivative liabilities	(7,086)		0
Derivative liabilities, noncurrent	(1,820)		0
Net amounts of liabilities on balance sheet	(8,906)		0
Total derivative liabilities, net	$	(8,560)	$	0

Note 7. Fair Value Measurements

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

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

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

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

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

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

Assets and Liabilities Measured at Fair Value on a Recurring Basis

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

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



	Fair value measurements at September 30, 2020 using:
In thousands	Level 1		Level 2		Level 3		Total
Derivative assets (liabilities):
Swaps	$	0	$	(8,827)	$	0	$	(8,827)
Collars	0		267		0		$	267
Total	$	0	$	(8,560)	$	0	$	(8,560)

Assets Measured at Fair Value on a Nonrecurring Basis

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

Asset impairments – Proved crude oil and natural gas properties are reviewed for impairment on a field-by-field basis each quarter. The estimated future cash flows expected in connection with the field are compared to the carrying amount of the field to determine if the carrying amount is recoverable. If the carrying amount of the field exceeds its estimated undiscounted future cash flows, the carrying amount of the field is reduced to its estimated fair value. Risk-adjusted probable and possible reserves may be taken into consideration when determining estimated future net cash flows and fair value when such reserves exist and are economically recoverable. Due to the unavailability of relevant comparable market data, a discounted cash flow method is used to determine the fair value of proved properties. Significant unobservable inputs (Level 3) utilized in the determination of discounted future net cash flows include future commodity prices adjusted for differentials, forecasted production based on decline curve analysis, estimated future operating and development costs, property ownership interests, and a 10% discount rate. At September 30, 2020, the Company's commodity price assumptions were based on forward NYMEX strip prices through year-end 2024 and were then escalated at 3% per year thereafter. Operating cost assumptions were based on current costs escalated at 3% per year beginning in 2021.

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

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

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

Certain unproved crude oil and natural gas properties were impaired during the three and nine months ended September 30, 2020 and 2019, reflecting recurring amortization of undeveloped leasehold costs on properties the Company expects will not be transferred to proved properties over the lives of the leases based on drilling plans, experience of successful drilling, and the average holding period.

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


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

Financial Instruments Not Recorded at Fair Value

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


	September 30, 2020				December 31, 2019
In thousands	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Debt:
Credit facility	$	475,000	$	475,000	$	55,000	$	55,000
Notes payable	25,137		25,600		5,351		5,400
5% Senior Notes due 2022	1,099,378		1,090,600		1,099,165		1,108,700
4.5% Senior Notes due 2023	1,443,031		1,379,900		1,491,339		1,571,400
3.8% Senior Notes due 2024	906,645		847,400		994,310		1,034,200
4.375% Senior Notes due 2028	990,345		863,500		989,661		1,063,700
4.9% Senior Notes due 2044	691,822		530,300		691,688		742,000
Total debt	$	5,631,358	$	5,212,300	$	5,326,514	$	5,580,400

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

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

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

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

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

Note 8. Long-Term Debt

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


In thousands	September 30, 2020		December 31, 2019
Credit facility	$	475,000	$	55,000
Notes payable	25,137		5,351
5% Senior Notes due 2022	1,099,378		1,099,165
4.5% Senior Notes due 2023	1,443,031		1,491,339
3.8% Senior Notes due 2024	906,645		994,310
4.375% Senior Notes due 2028	990,345		989,661
4.9% Senior Notes due 2044	691,822		691,688
Total debt	$	5,631,358	$	5,326,514
Less: Current portion of long-term debt	2,225		2,435
Long-term debt, net of current portion	$	5,629,133	$	5,324,079

Credit Facility

The Company has an unsecured credit facility, maturing on April 9, 2023, with aggregate lender commitments totaling $1.5 billion. The Company had $475 million of outstanding borrowings on its credit facility at September 30, 2020.

Credit facility borrowings bear interest at market-based interest rates plus a margin based on the terms of the borrowing and the credit ratings assigned to the Company's senior, unsecured, long-term indebtedness. The weighted-average interest rate on outstanding credit facility borrowings at September 30, 2020 was 1.9%.

The Company had approximately $1.02 billion of borrowing availability on its credit facility at September 30, 2020 after considering outstanding borrowings and letters of credit. The Company incurs commitment fees based on currently assigned credit ratings of 0.25% per annum on the daily average amount of unused borrowing availability.

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

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

Senior Notes

The following table summarizes the face values, maturity dates, semi-annual interest payment dates, and optional redemption periods related to the Company’s outstanding senior note obligations at September 30, 2020. In March and April 2020 the Company repurchased a portion of its 2023 Notes and 2024 Notes in open market transactions as further discussed below under the heading Retirement of Senior Notes.

2022 Notes (1)

2023 Notes

2024 Notes

2028 Notes

2044 Notes

Face value (in thousands)

$1,100,000

$1,449,625

$911,000

$1,000,000

$700,000

Maturity date

Sep 15, 2022

April 15, 2023

June 1, 2024

January 15, 2028

June 1, 2044

Interest payment dates

March 15, Sep 15

April 15, Oct 15

June 1, Dec 1

Jan 15, July 15

June 1, Dec 1

Make-whole redemption period (2)

—

Jan 15, 2023

Mar 1, 2024

Oct 15, 2027

Dec 1, 2043

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

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

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

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

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

2020

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

In April 2020, the Company repurchased an additional $17.0 million face value of its 2023 Notes at an aggregate cost of $9.8 million and an additional $82.0 million face value of its 2024 Notes at an aggregate cost of $43.1 million, in each case, including accrued and unpaid interest to the repurchase dates.

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

2019

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

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

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

Notes payable

In June 2020, the Company borrowed an aggregate of $26.0 million under two 10-year amortizing term loans secured by the Company’s corporate office building and its interest in parking facilities in Oklahoma City, Oklahoma. The loans mature in May 2030 and bear interest at a fixed rate of 3.50% per annum through June 9, 2025, at which time the interest rate will be reset and fixed through the maturity date. Principal and interest are payable monthly through the maturity date and, accordingly, $2.2 million is reflected as a current liability under the caption “Current portion of long-term debt” in the condensed consolidated balance sheets as of September 30, 2020 associated with the loans. A portion of the proceeds from the new loans was used to fully repay the Company's previous note payable that was set to mature in February 2022, which had a balance at pay-off of $4.4 million.

Note 9. Leases

The Company’s lease liabilities recognized on the balance sheet as a lessee totaled $10.2 million as of September 30, 2020 at discounted present value, which is comprised of the asset classes reflected in the table below. All leases recognized on the Company's balance sheet are classified as operating leases. The amounts disclosed herein primarily represent costs associated with properties operated by the Company that are presented on a gross basis and do not represent the Company's net proportionate share of such amounts. A portion of these costs have been or will be billed to other working interest owners. Once paid, the Company's share of these costs are included in property and equipment, production expenses, or general and administrative expenses, as applicable. The Company's leasing activities as a lessor are negligible.


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

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

Minimum future commitments by year for the Company's operating leases as of September 30, 2020 are presented in the table below. Such commitments are reflected at undiscounted values and are reconciled to the discounted present value recognized on the balance sheet.


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

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

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


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

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

Note 10. Commitments and Contingencies

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

Drilling rig commitments – As of September 30, 2020, the Company has drilling rig contracts with various terms extending to April 2021. Future operating day-rate commitments as of September 30, 2020 total approximately $18 million, of which $12 million is expected to be incurred in the remainder of 2020 and $6 million will be incurred in 2021. A portion of these future costs will be borne by other interest owners. Such future commitments include minimum payment obligations with a discounted present value totaling $3.7 million that are required to be recognized on the Company's balance sheet at September 30, 2020 in accordance with ASC Topic 842 as discussed in Note 9. Leases.

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

Transportation, gathering, and processing commitments – The Company has entered into transportation, gathering, and processing commitments to guarantee capacity on crude oil and natural gas pipelines and natural gas processing facilities. The commitments, which have varying terms extending as far as 2031, require the Company to pay per-unit transportation, gathering, or processing charges regardless of the amount of capacity used. Future commitments remaining as of September 30, 2020 under the arrangements amount to approximately $1.50 billion, of which $54 million is expected to be incurred in the remainder of 2020, $224 million in 2021, $256 million in 2022, $257 million in 2023, $222 million in 2024, and $489 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.

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

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

The Company is involved in various other legal proceedings including, but not limited to, commercial disputes, claims from royalty and surface owners, property damage claims, personal injury claims, regulatory compliance matters, disputes with tax authorities and other matters. While the outcome of these legal matters cannot be predicted with certainty, the Company does not expect them to have a material effect on its financial condition, results of operations or cash flows. As of September 30, 2020 and December 31, 2019, the Company had recognized a liability within “Other noncurrent liabilities” of $7.5 million and $8.7 million, respectively, for various matters, none of which are believed to be individually significant.

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

Note 11. Stock-Based Compensation

The Company has granted restricted stock to employees and directors pursuant to the Continental Resources, Inc. 2013 Long-Term Incentive Plan, as amended ("2013 Plan"). The Company’s associated compensation expense, which is included in the caption “General and administrative expenses” in the unaudited condensed consolidated statements of comprehensive income (loss), was $16.4 million and $12.9 million for the three months ended September 30, 2020 and 2019, respectively, and $48.1 million and $37.2 million for the nine months ended September 30, 2020 and 2019, respectively.

In March 2019, the Company amended and restated its 2013 Plan and specified 12,983,543 shares of common stock may be issued pursuant to the amended plan. Subject to limited exceptions, the 2013 Plan allows previously issued shares to be reissued if such shares are subsequently forfeited or withheld to satisfy tax withholdings. As of September 30, 2020, the Company had 10,876,574 shares of common stock available for long-term incentive awards to employees and directors under the 2013 Plan.

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

A summary of changes in non-vested restricted shares outstanding for the nine months ended September 30, 2020 is presented below.


	Number of non-vested shares	Weighted average grant-date fair value
Non-vested restricted shares outstanding at December 31, 2019	3,461,908	$	46.82
Granted	2,582,990	27.73
Vested	(1,077,656)	45.97
Forfeited	(136,504)	36.85
Non-vested restricted shares outstanding at September 30, 2020	4,830,738	$	37.08

The grant date fair value of restricted stock represents the closing market price of the Company’s common stock on the date of grant. Compensation expense for a restricted stock grant is determined at the grant date fair value and is recognized over the vesting period as services are rendered by employees and directors. The Company estimates the number of forfeitures expected to occur in determining the amount of stock-based compensation expense to recognize. There are no post-vesting restrictions related to the Company’s restricted stock. The fair value at the vesting date of restricted stock that vested during the nine months ended September 30, 2020 was approximately $27 million. As of September 30, 2020, there was approximately $82 million of unrecognized compensation expense related to non-vested restricted stock. This expense is expected to be recognized over a weighted average period of 1.5 years.

Note 12. Shareholders' Equity

Share repurchases

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

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

The timing and amount of the Company's share repurchases are subject to market conditions and management discretion. The share repurchase program does not require the Company to repurchase a specific number of shares and may be modified, suspended, or terminated by the Board of Directors at any time.

Dividend payment

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

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

Note 13. Income Taxes

Income taxes are accounted for using the 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,
	2020			2019			2020			2019
Provision (benefit) for income taxes (in thousands)	$	(13,972)		$	49,747		$	(138,350)		$	177,386
Effective tax rate	14.6		%	24.0		%	21.3		%	23.4		%

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, 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	2020			2019			2020			2019
Income (loss) before income taxes	$	(95,555)		$	207,169		$	(648,848)		$	757,751
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	(20,067)			43,505			(136,258)			159,128
Items impacting the effective tax rate:
State and local income taxes, net of federal benefit	(2,988)			7,312			(20,896)			26,648
Equity compensation	214			92			4,685			(8,124)
Other, net	2,540			(1,162)			(90)			(266)
Valuation allowance	6,329			0			14,209			0
Provision (benefit) for income taxes	$	(13,972)		$	49,747		$	(138,350)		$	177,386
Effective tax rate	14.6		%	24.0		%	21.3		%	23.4		%

The Company reduces its deferred tax assets by a valuation allowance if, based upon the weight of available evidence, it is more-likely-than-not that the Company will not realize some portion or all of the deferred tax assets. The Company considers relevant evidence, both positive and negative, to determine the need for a valuation allowance. Information evaluated includes the Company's financial position and results of operations for the current and preceding years, the availability of deferred tax liabilities and tax carrybacks, as well as an evaluation of currently available information about future years. In the first quarter of 2020 the Company determined it was more-likely-than-not that a portion of its Oklahoma net operating loss ("NOL") carryforwards would not be able to be utilized before expiration, and a valuation allowance of approximately $4.9 million was established at March 31, 2020 for the deferred tax assets associated with such NOL carryforwards. The Company

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

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

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

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

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

The following discussion and analysis includes forward-looking statements and should be read in conjunction with the risk factors described in Part II, Item 1A. Risk Factors included in this report, if any, and in our Form 10-K for the year ended December 31, 2019 and our Form 10-Qs for the quarters ended March 31, 2020 and June 30, 2020, along with Cautionary Statement for Purpose of “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995 at the beginning of this report, for information about the risks and uncertainties that could cause our actual results to be materially different than our forward-looking statements.

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

Overview

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

Business Environment and Outlook

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

Crude oil prices began to show signs of stabilization and improvement in mid-2020 in response to the gradual lifting of COVID-19 restrictions, the resumption of economic activity, and the resulting increase in crude oil demand. In July 2020 we began to gradually restore our curtailed production and subsequently brought our remaining curtailed production back online in September. As a result, our total average production improved to 297,001 Boe per day for the 2020 third quarter, representing a 46% increase compared to the second quarter of 2020, yet still remaining 11% lower than the third quarter of 2019. Total production for the month of September 2020 averaged 339,600 Boe per day. Our production volumes are evaluated on an ongoing basis and are subject to change as market conditions evolve.

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

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

Financial and Operating Metrics

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


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

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

Three months ended September 30, 2020 compared to the three months ended September 30, 2019

Results of Operations

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


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

Production

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


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

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


	Three months ended September 30,						Volume decrease	Volume percent decrease
	2020			2019
	Volume	Percent		Volume	Percent
Crude oil (MBbl)	15,572	57	%	18,223	60	%	(2,651)	(15	%)
Natural gas (MMcf)	70,510	43	%	74,101	40	%	(3,591)	(5	%)
Total (MBoe)	27,324	100	%	30,573	100	%	(3,249)	(11	%)

	Three months ended September 30,						Volume decrease	Volume percent decrease
	2020			2019
	MBoe	Percent		MBoe	Percent
North Region	15,402	56	%	18,312	60	%	(2,910)	(16	%)
South Region	11,922	44	%	12,261	40	%	(339)	(3	%)

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

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

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

Revenues

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

Net crude oil and natural gas sales. Net crude oil and natural gas sales totaled $646.2 million for the third quarter of 2020, a 37% decrease compared to net sales of $1.02 billion for the 2019 third quarter due to significant decreases in net sales prices and sales volumes as discussed below.

Total sales volumes for the third quarter of 2020 decreased 2,793 MBoe, or 9%, compared to the 2019 third quarter, reflecting reduced sales from the previously described production curtailments that impacted the current period. For the third quarter of 2020, our crude oil sales volumes decreased 12% from the comparable 2019 period, while our natural gas sales volumes decreased 5%.

Our crude oil net sales prices averaged $35.93 per barrel in the 2020 third quarter, a decrease of 30% compared to $51.28 per barrel for the 2019 third quarter due to significantly reduced market prices. The differential between NYMEX West Texas Intermediate ("WTI") calendar month prices and our realized crude oil net sales prices improved to $5.00 per barrel for the 2020 third quarter compared to $5.15 per barrel for the 2019 third quarter.

See the subsequent section titled Future Capital Requirements–Commitments and contingencies for discussion of pending legal disputes that could impact the future operation of the Dakota Access Pipeline ("DAPL") owned by a third party that we and other operators utilize to transport Bakken crude oil production to market centers outside the basin. A restriction of DAPL's takeaway capacity could impact prices for Bakken-produced barrels and result in wider differentials relative to WTI benchmark prices in the future, the amount of which is uncertain. If transportation capacity on DAPL becomes restricted or unavailable, we have the ability to utilize other third party pipelines or rail facilities to transport our Bakken crude oil production to market, although such alternatives could be more costly.

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

Derivatives. Changes in market prices during the third quarter of 2020 had an overall unfavorable impact on the fair value of our derivatives, which resulted in negative revenue adjustments of $17.9 million for the period compared to positive revenue adjustments of $1.2 million in the comparable 2019 period.

Crude oil and natural gas service operations. Our crude oil and natural gas service operations consist primarily of revenues associated with water gathering, recycling, and disposal activities, which are impacted by our production volumes and the timing and extent of our drilling and completion projects. Revenues associated with such activities decreased $12.8 million, or 59%, from $21.6 million for the third quarter of 2019 to $8.8 million for the third quarter of 2020 due to reduced water handling activities resulting from our curtailment of production and limited completion projects undertaken during the current quarter. The decreased activities also resulted in a reduction in service-related expenses compared to the prior period.

Operating Costs and Expenses

Production Expenses. Production expenses decreased $25.4 million, or 22%, from $114.1 million for the third quarter of 2019 to $88.7 million for the third quarter of 2020. This decrease resulted from reduced service costs being incurred in conjunction with production curtailments and cost control efforts, operating efficiency gains, and a higher portion of our production coming from wells in Oklahoma which typically have lower operating costs compared to wells in the Bakken, all of which led to a reduction in our production expenses on a per-Boe basis to $3.19 per Boe for the 2020 third quarter compared to $3.73 per Boe for the 2019 third quarter.

Production Taxes. Production taxes decreased $36.7 million, or 42%, to $50.2 million for the third quarter of 2020 compared to $86.9 million for the third quarter of 2019 primarily due to a 35% decrease in crude oil and natural gas sales. Our production taxes as a percentage of net crude oil and natural gas sales decreased from 8.5% for the third quarter of 2019 to 7.8% for the third quarter of 2020 primarily resulting from an increase in the proportion of our revenues being generated in Oklahoma in the current period, which has lower production tax rates compared to North Dakota.

Depreciation, Depletion, Amortization and Accretion. Total DD&A decreased $22.8 million, or 5%, to $461.2 million for the third quarter of 2020 compared to $484.0 million for the third quarter of 2019 primarily due to a 9% decrease in total sales volumes. 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	2020		2019
Crude oil and natural gas	$	16.32	$	15.58
Other equipment	0.18		0.16
Asset retirement obligation accretion	0.08		0.07
Depreciation, depletion, amortization and accretion	$	16.58	$	15.81

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.

If commodity prices remain at current levels or decline further, downward revisions of our proved reserves could occur at year-end 2020, which may be significant and would result in an increase in our DD&A rate for subsequent periods. We are unable to predict the timing and amount of future reserve revisions, nor the impact such revisions may have on our future DD&A rate.

Property Impairments. Total property impairments decreased $1.7 million to $18.5 million for the third quarter of 2020 compared to $20.2 million for the third quarter of 2019. Impairments of unproved properties decreased $3.3 million reflecting a decrease in the balance of unamortized leasehold costs over the past year. Proved property impairments of $1.6 million were recognized in the third quarter of 2020 compared to no proved property impairments in the third quarter of 2019.

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

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

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

COVID-19 pandemic, partially offset by lower overhead recoveries from joint interest owners driven by reduced drilling, completion, and production activities.

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


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

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

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

Income Taxes. For the third quarters of 2020 and 2019 we provided for income taxes at a combined federal and state tax rate of 24.5% of pre-tax income/loss generated by our operations in the United States. We recorded an income tax benefit of $14.0 million for the 2020 third quarter and an income tax provision of $49.7 million for the 2019 third quarter, which resulted in effective tax rates of 14.6% and 24.0%, respectively, after taking into account statutory tax rates, permanent taxable differences, tax effects from equity compensation, valuation allowances, and other items. See Notes to Unaudited Condensed Consolidated Financial Statements–Note 13. Income Taxes for a summary of the sources and tax effects of items comprising our effective tax rates.

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

Results of Operations

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


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

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

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 9/30/2020	YTD 9/30/2019	% Change
Bakken	150,366	194,872	(23	%)
SCOOP	92,958	73,127	27	%
STACK	36,567	55,585	(34	%)
All other	7,031	8,405	(16	%)
Total	286,922	331,989	(14	%)

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


	Nine months ended September 30,						Volume decrease	Volume percent decrease
	2020			2019
	Volume	Percent		Volume	Percent
Crude oil (MBbl)	42,494	54	%	53,292	59	%	(10,798)	(20	%)
Natural gas (MMcf)	216,735	46	%	224,045	41	%	(7,310)	(3	%)
Total (MBoe)	78,617	100	%	90,633	100	%	(12,016)	(13	%)

	Nine months ended September 30,						Volume increase (decrease)	Volume percent increase (decrease)
	2020			2019
	MBoe	Percent		MBoe	Percent
North Region	43,118	55	%	55,464	61	%	(12,346)	(22	%)
South Region	35,499	45	%	35,169	39	%	330	1	%
Total	78,617	100	%	90,633	100	%	(12,016)	(13	%)

The 20% decrease in crude oil production for year to date 2020 compared to year to date 2019 was primarily driven by an 11,136 MBbls, or 27%, decrease in Bakken oil production along with a 1,032 MBbls, or 40%, decrease in STACK oil production due to the previously described production curtailments and limited drilling and completion activities undertaken during the 2020 second and third quarters. These decreases were partially offset by a 1,640 MBbls, or 22%, increase in crude oil production in SCOOP due to new well completions over the past year in our oil-weighted Project SpringBoard, which exceeded the adverse impact of production curtailments in the play.

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

Revenues

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

Total sales volumes for year to date 2020 decreased 11,814 MBoe, or 13%, compared to year to date 2019, reflecting reduced sales from the previously described production curtailments in the current period. For year to date 2020, our crude oil sales volumes decreased 20% from the comparable 2019 period, while our natural gas sales volumes decreased 3%.

Our crude oil net sales prices averaged $33.71 per barrel for year to date 2020, a decrease of 35% compared to $51.99 per barrel for year to date 2019 due to significantly reduced market prices and wider price differentials. The differential between NYMEX

WTI calendar month prices and our realized crude oil net sales prices averaged $6.03 per barrel for year to date 2020 compared to $5.01 per barrel for year to date 2019. The increased differential reflects changes in supply and demand fundamentals and economic effects from COVID-19 that impacted location differentials and price realizations in the first and second quarters of 2020 compared to the prior year.

Our natural gas net sales prices averaged $0.72 per Mcf for year to date 2020, a decrease of 60% compared to $1.78 per Mcf for year to date 2019 due to significantly reduced market prices and lower price realizations. The discount between our net sales prices and NYMEX Henry Hub calendar month prices weakened to $1.19 per Mcf for year to date 2020 compared to $0.90 per Mcf for the year to date 2019 period. NGL prices decreased in the first half of 2020 in conjunction with decreased crude oil prices and other factors, resulting in reduced price realizations for our natural gas sales stream relative to benchmark prices and contributing to the recognition of $37.7 million of negative gas revenues in the 2020 year to date period.

Derivatives. Changes in market prices during the nine months ended September 30, 2020 had an overall unfavorable impact on the fair value of our derivatives, which resulted in negative revenue adjustments of $25.6 million for the period compared to positive revenue adjustments of $53.5 million in the comparable 2019 period.

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

Operating Costs and Expenses

Production Expenses. Production expenses decreased $61.5 million, or 18%, from $333.4 million for year to date 2019 to $271.9 million for year to date 2020. This decrease resulted from reduced service costs being incurred in conjunction with production curtailments and cost control efforts, operating efficiency gains, and a higher portion of our production coming from wells in Oklahoma which typically have lower operating costs compared to wells in the Bakken, all of which led to a reduction in our production expenses on a per-Boe basis to $3.45 per Boe for year to date 2020 compared to $3.68 per Boe for the comparable 2019 period.

Production Taxes. Production taxes decreased $134.8 million, or 50%, to $132.4 million for year to date 2020 compared to $267.2 million for year to date 2019 due to a 48% decrease in crude oil and natural gas sales. Our production taxes as a percentage of net crude oil and natural gas sales averaged 8.3% for year to date 2020 compared to 8.4% for year to date 2019.

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

Depreciation, Depletion, Amortization and Accretion. Total DD&A decreased $176.5 million, or 12%, to $1.29 billion for year to date 2020 compared to $1.46 billion for the comparable 2019 period due to a 13% decrease 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	2020		2019
Crude oil and natural gas	$	16.08	$	15.95
Other equipment	0.20		0.16
Asset retirement obligation accretion	0.09		0.07
Depreciation, depletion, amortization and accretion	$	16.37	$	16.18

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

Impairments of proved oil and gas properties totaled $182.6 million for the year to date period of 2020, of which $181.0 million was recognized in the 2020 first quarter and $1.6 million was recognized in the 2020 third quarter, resulting from the significant decrease in commodity prices that indicated the carrying values for certain fields were not recoverable. The impairments were recognized on legacy properties in the Red River Units ($168.1 million) and various non-core properties in the North and South regions ($14.5 million). Additionally, in response to decreased crude oil prices we recognized a $24.5 million impairment in the

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

Impairments of unproved properties decreased $9.0 million, or 13%, to $57.9 million for year to date 2020 compared to $66.9 million for year to date 2019 primarily due to a reduction in the balance of unamortized leasehold costs over the past year.

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

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

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

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	2020		2019
General and administrative expenses	$	1.04	$	1.16
Non-cash equity compensation	0.61		0.41
Total general and administrative expenses	$	1.65	$	1.57

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

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

Income Taxes. For the nine months ended September 30, 2020 and 2019 we provided for income taxes at a combined federal and state tax rate of 24.5% of pre-tax income/loss generated by our operations in the United States. We recorded an income tax benefit of $138.4 million and an income tax provision of $177.4 million for the year to date periods of 2020 and 2019, respectively, which resulted in effective tax rates of 21.3% and 23.4%, respectively, after taking into account statutory tax rates, permanent taxable differences, tax effects from equity compensation, valuation allowances, and other items. See Notes to Unaudited Condensed Consolidated Financial Statements–Note 13. Income Taxes for a summary of the sources and tax effects of items comprising our effective tax rates.

Liquidity and Capital Resources

Our primary sources of liquidity have historically been cash flows generated from operating activities, financing provided by our credit facility and the issuance of debt securities. Additionally, in recent years asset dispositions and joint development arrangements have provided a source of cash flow for use in reducing debt and enhancing liquidity. In light of the challenges facing our business and industry, we remain committed to operating in a responsible manner to preserve financial flexibility, liquidity, and the strength of our balance sheet.

At October 31, 2020, we had approximately $975 million of borrowing availability under our credit facility after considering outstanding borrowings and letters of credit. Our credit facility, which is unsecured and has no borrowing base subject to redetermination, does not mature until April 2023. Further, we have no near-term senior note maturities, with our earliest scheduled maturity being our $1.1 billion of 2022 Notes due in September 2022.

Based on our planned capital spending, our forecasted cash flows and projected levels of indebtedness, we expect to maintain compliance with the covenants under our credit facility and senior note indentures. Further, based on current market indications,

we expect to meet in the ordinary course of business other contractual cash commitments to third parties as of September 30, 2020, including those described in Note 10. Commitments and Contingencies in Notes to Unaudited Condensed Consolidated Financial Statements, recognizing we may be required to meet such commitments even if our business plan assumptions were to change. We monitor our capital spending closely based on actual and projected cash flows and have the ability to reduce spending or dispose of assets if needed to preserve liquidity and financial flexibility to fund our operations.

Cash Flows

Cash flows from operating activities

Net cash provided by operating activities totaled $934.8 million and $2.31 billion for the nine months ended September 30, 2020 and 2019, respectively, reflecting a significant decrease in our operating cash flows in the second and third quarters of 2020 due to the previously described decrease in market prices and our voluntary curtailment of production which adversely impacted our 2020 operating results.

Crude oil prices stabilized and improved in the 2020 third quarter relative to historic lows reached in April 2020 and we began to gradually restore our curtailed production in July 2020. Subsequently, we fully restored our curtailed production in September 2020. As a result, our operating cash flows increased to $291.2 million for the 2020 third quarter compared to negative operating cash flows of $20.2 million for the 2020 second quarter.

Cash flows from investing activities

Net cash used in investing activities totaled $1.18 billion and $2.25 billion for the nine months ended September 30, 2020 and 2019, respectively, reflecting the significant decrease in our drilling and completion activities prompted by the decrease in crude oil prices and economic uncertainty from the COVID-19 pandemic. Our investing cash outflows have decreased sequentially throughout the nine months ended September 30, 2020, totaling $706.7 million for the first quarter, $312.2 million for the second quarter, and $162.9 million for the third quarter.

Cash flows from financing activities

Net cash provided by financing activities for the nine months ended September 30, 2020 totaled $228.9 million, primarily consisting of $420 million of net credit facility borrowings, net proceeds of $26.0 million from new term loans as described in Note 8. Long-Term Debt in Notes to Unaudited Condensed Consolidated Financial Statements, and $26.6 million of cash inflows for contributions received from Franco-Nevada Corporation for the funding of its share of mineral acquisition costs incurred by The Mineral Resources Company II ("TMRC II"). These year-to-date increases were partially offset by $126.9 million of cash used to repurchase shares of our common stock, $18.5 million of cash dividends paid on common stock, and $74.0 million of cash used to repurchase senior notes in open market transactions. For the three months ended September 30, 2020, we had net cash outflows used in financing activities totaling $113.7 million, primarily representing $112 million of net repayments on our credit facility.

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

Future Sources of Financing

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

Our capital spending plans have been adjusted to be reflective of the current commodity price environment and will be guided by our expectation of available cash flows. Any cash flow deficiencies are expected to be funded by borrowings under our credit facility. If cash flows are materially impacted by declines in commodity prices, we have the ability to reduce our capital expenditures or utilize the availability of our credit facility if needed to fund our operations and business plans. We may choose to access banking or capital markets for additional financing or capital to fund our operations or take advantage of business opportunities that may arise, although uncertainties existing in the financial markets as a result of the COVID-19 pandemic and other factors may increase the expense and difficulty of completing a bank or capital markets financing. Additionally, the terms available to the Company in connection with such a financing transaction may be less favorable than those enjoyed by the Company prior to the COVID-19 pandemic, although the degree, if any, by which such terms may change cannot be predicted

at this time. 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.

In March 2020, our corporate credit rating was downgraded by Standard & Poor's Ratings Services ("S&P") in response to weakened oil and gas industry conditions and resulting revisions made to rating agency commodity price assumptions. Such downgrade negatively impacted our cost of capital and increased our borrowing costs under our credit facility. Also in March 2020, our corporate credit ratings were reaffirmed by both Moody's Investor Services and Fitch Ratings. Such ratings are subject to ongoing review and adjustment.

Credit facility

We have an unsecured credit facility, maturing in April 2023, with aggregate lender commitments totaling $1.5 billion. The commitments are from a syndicate of 14 banks and financial institutions. We believe each member of the current syndicate has the capability to fund its commitment. As of October 31, 2020, we had $520 million of outstanding borrowings and approximately $975 million of borrowing availability on our credit facility.

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

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

We were in compliance with our credit facility covenants at September 30, 2020 and expect to maintain such compliance. At September 30, 2020, our consolidated net debt to total capitalization ratio was 0.43 to 1.00. We do not believe the credit facility covenants are reasonably likely to limit our ability to undertake additional debt financing if needed to support our business. At September 30, 2020, our total debt would have needed to independently increase by approximately $8.4 billion above the existing level at that date (with no corresponding increase in cash or reduction in refinanced debt) to reach the maximum covenant ratio of 0.65 to 1.00. Alternatively, our total shareholders' equity would have needed to independently decrease by approximately $4.5 billion (excluding the after-tax impact of any non-cash impairment charges) below the existing level at September 30, 2020 to reach the maximum covenant ratio. These independent point-in-time sensitivities do not take into account other factors that could arise to mitigate the impact of changes in debt and equity on our consolidated net debt to total capitalization ratio, such as disposing of assets or exploring alternative sources of capitalization.

Future Capital Requirements

Senior notes

Our debt includes outstanding senior note obligations totaling $5.16 billion at September 30, 2020. We have no near-term senior note maturities, with our earliest scheduled maturity being our $1.1 billion of 2022 Notes due in September 2022. Our senior notes are not subject to any mandatory redemption or sinking fund requirements. For further information on the face values, maturity dates, semi-annual interest payment dates, optional redemption periods and covenant restrictions related to our senior notes, refer to Note 8. Long-Term Debt in Notes to Unaudited Condensed Consolidated Financial Statements.

We were in compliance with our senior note covenants at September 30, 2020 and expect to maintain such compliance. We do not believe the senior note covenants will materially limit our ability to undertake additional debt financing. Downgrades or other negative rating actions with respect to the credit ratings assigned to our senior unsecured debt, such as the downgrade by S&P that occurred in March 2020, do not trigger additional senior note covenants.

Mineral acquisition relationship

In October 2018, Continental entered into a strategic relationship with Franco-Nevada Corporation to acquire oil and gas mineral interests within an area of mutual interest through a minerals subsidiary named The Mineral Resources Company II, LLC ("TMRC II"). Under the relationship, the parties have agreed to spend up to a remaining aggregate total of $154 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. Our original capital budget for 2020 was $2.65 billion, which was reduced to $1.2 billion in March 2020 in response to the significant decrease in crude oil prices resulting from the COVID-19 pandemic and other factors. We diligently evaluate and adjust our spending plans on an ongoing basis based on market conditions.

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


In millions	1Q 2020		2Q 2020		3Q 2020		YTD 2020
Exploration and development drilling	$	544.0	$	155.8	$	120.9	$	820.7
Land costs (1)	39.9		8.9		6.1		54.9
Capital facilities, workovers and other corporate assets	63.0		25.8		22.4		111.2
Seismic	3.8		0.3		—		4.1
Capital expenditures, excluding unbudgeted acquisitions	650.7		190.8		149.4		990.9
Acquisitions of producing properties	19.3		0.1		4.0		23.4
Acquisitions of non-producing properties	10.6		—		0.1		10.7
Total unbudgeted acquisitions	29.9		0.1		4.1		34.1
Total capital expenditures	$	680.6	$	190.9	$	153.5	$	1,025.0

(1) Amount includes $24 million of mineral acquisitions made by TMRC II during the nine months ended September 30, 2020, of which $19 million was recouped from Franco-Nevada.

Commitments and contingencies

Refer to Note 10. Commitments and Contingencies in Notes to Unaudited Condensed Consolidated Financial Statements for discussion of certain future commitments and contingencies of the Company. Based on current market indications, we expect to meet in the ordinary course of business our contractual cash commitments to third parties as of September 30, 2020.

On July 6, 2020, the U.S. District Court for the District of Columbia ruled that the Dakota Access Pipeline (“DAPL”), which is owned and operated by a third party and carries Bakken-produced crude oil from North Dakota to Illinois, must shut down pending the completion of a new environmental impact statement. The pipeline owner sought an emergency stay of the shut-down order from the U.S. Court of Appeals for the District of Columbia Circuit (the "Appeals Court"). On July 14, 2020, the Appeals Court issued a temporary administrative stay of such order, which has allowed the pipeline to continue operating as of the date of this filing. The continued operation of DAPL in the future is uncertain. The Company utilizes DAPL to transport a portion of its North region crude oil production to ultimate markets on the U.S. gulf coast. Currently, the Company is committed to transport 3,550 barrels per day on the pipeline through February 2026 and has an additional commitment to transport an incremental 26,450 barrels per day for 7 years effective upon the pending completion of a DAPL expansion project which is estimated to occur in the third quarter of 2021. If transportation capacity on DAPL becomes restricted or unavailable, we have the ability to utilize other third party pipelines or rail facilities to transport our Bakken crude oil production to market, although such alternatives could be more costly. A restriction of DAPL's takeaway capacity could impact prices for Bakken-produced barrels and result in wider differentials relative to WTI benchmark prices in the future, the amount of which is uncertain.

Dividend payments

Share repurchase program

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

Senior note repurchases

As discussed in Note 8. Long-Term Debt in Notes to Unaudited Condensed Consolidated Financial Statements, in March and April 2020 we repurchased a portion of our 2023 Notes and 2024 Notes in open market transactions at a substantial discount to face value. From time to time, we may seek to execute additional repurchases of our senior notes for cash in open market transactions, privately negotiated transactions, or otherwise. Such repurchases will depend on prevailing market conditions, our liquidity and prospects for future access to capital, and other factors. The amounts involved in any such transactions, individually or in the aggregate, may be material.

Legislative and Regulatory Developments

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

Off-balance sheet arrangements

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

Critical Accounting Policies

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

New Accounting Pronouncements

See Note 2. Basis of Presentation and Significant Accounting Policies in Notes to Unaudited Condensed Consolidated Financial Statements for a discussion of the new credit loss accounting standard adopted on January 1, 2020 along with a discussion of an accounting pronouncement not yet adopted.

Non-GAAP Financial Measures

Net crude oil and natural gas sales and net sales prices

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

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

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


	Three months ended September 30, 2020						Three months ended September 30, 2019
In thousands	Crude oil		Natural gas		Total		Crude oil		Natural gas		Total
Crude oil and natural gas sales (GAAP)	$	623,955	$	77,513	$	701,468	$	989,297	$	92,103	$	1,081,400
Less: Transportation expenses	(46,890)		(8,382)		(55,272)		(53,038)		(9,000)		(62,038)
Net crude oil and natural gas sales (non-GAAP)	$	577,065	$	69,131	$	646,196	$	936,259	$	83,103	$	1,019,362
Sales volumes (MBbl/MMcf/MBoe)	16,063		70,510		27,815		18,258		74,101		30,608
Net sales price (non-GAAP)	$	35.93	$	0.98	$	23.23	$	51.28	$	1.12	$	33.30


	Nine months ended September 30, 2020						Nine months ended September 30, 2019
In thousands	Crude oil		Natural gas		Total		Crude oil		Natural gas		Total
Crude oil and natural gas sales (GAAP)	$	1,556,445	$	182,418	$	1,738,863	$	2,905,561	$	422,848	$	3,328,409
Less: Transportation expenses	(120,780)		(27,299)		(148,079)		(140,666)		(23,903)		(164,569)
Net crude oil and natural gas sales (non-GAAP)	$	1,435,665	$	155,119	$	1,590,784	$	2,764,895	$	398,945	$	3,163,840
Sales volumes (MBbl/MMcf/MBoe)	42,583		216,735		78,706		53,179		224,045		90,520
Net sales price (non-GAAP)	$	33.71	$	0.72	$	20.21	$	51.99	$	1.78	$	34.95

ITEM 3. Quantitative and Qualitative Disclosures About Market Risk

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

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

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

The fair value of our natural gas derivative instruments at September 30, 2020 was a net liability of $8.6 million. An assumed increase in the forward prices used in the September 30, 2020 valuation of our natural gas derivatives of $1.00 per MMBtu would increase our derivative liability to approximately $79 million at September 30, 2020. Conversely, an assumed decrease in forward prices of $1.00 per MMBtu would change our derivative valuation to a net asset of approximately $63 million at September 30, 2020.

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

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

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

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

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

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

We had $520 million of variable rate borrowings outstanding on our credit facility at October 31, 2020. The impact of a 0.25% increase in interest rates on this amount of debt would result in increased interest expense and reduced income before income taxes of approximately $1.3 million per year.

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

ITEM 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

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

Changes in Internal Control over Financial Reporting

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

Impact of COVID-19 on Internal Controls

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

Inherent Limitations on Controls and Procedures

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

PART II. Other Information

ITEM 1. Legal Proceedings

See Note 10. Commitments and Contingencies in Part I, Item I. Financial Statements–Notes to Unaudited Condensed Consolidated Financial Statements for a discussion of the termination of the legal matter involving the Company and Casillas Petroleum Resource Partners II, LLC that was resolved in October 2020, which is incorporated herein by reference.

ITEM 1A. Risk Factors

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

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

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

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

(b)Use of Proceeds – Not applicable.

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


Period	Total number of shares purchased	Average price paid per share		Total number of shares purchased as part of publicly announced plans or programs (1)	Maximum dollar value of shares that may yet be purchased under the plans or programs (in millions) (1)
July 1, 2020 to July 31, 2020:
Repurchases for tax withholdings (2)	985	$	17.99	—	—
Purchases by principal shareholder (3)	3,813,523	$	17.54	—	—
August 1, 2020 to August 31, 2020:
Repurchases for tax withholdings (2)	14,089	$	18.56	—	—
September 1, 2020 to September 30, 2020:
Repurchases for tax withholdings (2)	5,799	$	15.84	—	—
Purchases by principal shareholder (3)	769,235	$	12.68	—	—
Total for the quarter	4,603,631	$	16.73	—	—

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

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

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

ITEM 3. Defaults Upon Senior Securities

Not applicable.

ITEM 4. Mine Safety Disclosures

Not applicable.

ITEM 5. Other Information

Not applicable.

ITEM 6. Exhibits

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


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

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

10.1*†						Summary of Non-Employee Director Compensation approved Ju ly 30, 20 20 to be effective October 1, 2020 .

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

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

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

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

101.SCH*						Inline XBRL Taxonomy Extension Schema Document

101.CAL*						Inline XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF*						Inline XBRL Taxonomy Extension Definition Linkbase Document

101.LAB*						Inline XBRL Taxonomy Extension Label Linkbase Document

101.PRE*						Inline XBRL Taxonomy Extension Presentation Linkbase Document

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

* Filed herewith

** Furnished herewith

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

SIGNATURE

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

CONTINENTAL RESOURCES, INC.

Date:

November 5, 2020

By:

/s/ John D. Hart

John D. Hart

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

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Continental Resources Inc (CLR) 10-Q2020 Q3 Quarterly report

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