CONTINENTAL RESOURCES, INC (Form: 10-Q, Received: 08/03/2020 17:18:55)

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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 June 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	x	Accelerated filer	☐
Non-accelerated filer	☐	Smaller reporting company	☐
		Emerging growth company	☐

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

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

365,129,084 shares of our $0.01 par value common stock were outstanding on July 24, 2020.

Table of Contents




PART I. Financial Information
Item 1.	Financial Statements	1
	Condensed Consolidated Balance Sheets	1
	Unaudited Condensed Consolidated Statements of Comprehensive Income (Loss)	2
	Unaudited Condensed Consolidated Statements of Equity	3
	Unaudited Condensed Consolidated Statements of Cash Flows	5
	Notes to Unaudited Condensed Consolidated Financial Statements	6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	24
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	39
Item 4.	Controls and Procedures	40

PART II. Other Information
Item 1.	Legal Proceedings	41
Item 1A.	Risk Factors	41
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	42
Item 3.	Defaults Upon Senior Securities	42
Item 4.	Mine Safety Disclosures	42
Item 5.	Other Information	42
Item 6.	Exhibits	43
	Signature	44

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-Q for the quarter ended March 31, 2020, registration statements we file from time to time with the Securities and Exchange Commission, and other announcements we make from time to time.

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

iii

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

PART I. Financial Information


ITEM 1.	Financial Statements

Continental Resources, Inc. and Subsidiaries

Condensed Consolidated Balance Sheets



	June 30, 2020			December 31, 2019
In thousands, except par values and share data	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	6,656		$	39,400
Receivables:
Crude oil and natural gas sales	176,090			726,876
Joint interest and other	151,162			317,018
Allowance for credit losses	(2,356		)	(2,407		)
Receivables, net	324,896			1,041,487
Derivative assets	9,442			—
Inventories	68,285			109,536
Prepaid expenses and other	19,111			16,592
Total current assets	428,390			1,207,015
Net property and equipment, based on successful efforts method of accounting	14,312,982			14,497,726
Operating lease right-of-use assets	11,478			9,128
Other noncurrent assets	13,508			14,038
Total assets	$	14,766,358		$	15,727,907

Liabilities and equity
Current liabilities:
Accounts payable trade	$	311,935		$	629,264
Revenues and royalties payable	158,309			470,264
Accrued liabilities and other	122,353			230,368
Derivative liabilities	10,101			—
Current portion of operating lease liabilities	5,210			3,695
Current portion of long-term debt	2,206			2,435
Total current liabilities	610,114			1,336,026
Long-term debt, net of current portion	5,740,554			5,324,079
Other noncurrent liabilities:
Deferred income tax liabilities, net	1,664,970			1,787,125
Asset retirement obligations, net of current portion	159,474			151,774
Operating lease liabilities, net of current portion	6,148			5,433
Other noncurrent liabilities	13,846			15,119
Total other noncurrent liabilities	1,844,438			1,959,451
Commitments and contingencies (Note 10)
Equity:
Preferred stock, $0.01 par value; 25,000,000 shares authorized; no shares issued and outstanding	—			—
Common stock, $0.01 par value; 1,000,000,000 shares authorized; 365,144,243 shares issued and outstanding at June 30, 2020; 371,074,036 shares issued and outstanding at December 31, 2019	3,651			3,711
Additional paid-in capital	1,172,932			1,274,732
Retained earnings	5,019,561			5,463,224
Total shareholders’ equity attributable to Continental Resources	6,196,144			6,741,667
Noncontrolling interests	375,108			366,684
Total equity	6,571,252			7,108,351
Total liabilities and equity	$	14,766,358		$	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 June 30,						Six months ended June 30,
In thousands, except per share data	2020			2019			2020			2019
Revenues:
Crude oil and natural gas sales	$	174,652		$	1,137,425		$	1,037,395		$	2,247,009
Gain (loss) on derivative instruments, net	(7,782		)	53,448			(7,782		)	52,324
Crude oil and natural gas service operations	8,789			17,509			26,847			33,284
Total revenues	175,659			1,208,382			1,056,460			2,332,617

Operating costs and expenses:
Production expenses	64,673			112,430			183,151			219,396
Production taxes	11,067			93,866			82,291			180,306
Transportation expenses	32,305			53,393			92,807			102,531
Exploration expenses	1,960			3,090			13,597			4,927
Crude oil and natural gas service operations	6,062			11,206			11,972			18,392
Depreciation, depletion, amortization and accretion	290,298			485,621			826,994			980,641
Property impairments	23,929			21,339			246,458			46,655
General and administrative expenses	41,529			47,226			84,440			94,844
Net (gain) loss on sale of assets and other	612			364			5,114			112
Total operating costs and expenses	472,435			828,535			1,546,824			1,647,804
Income (loss) from operations	(296,776		)	379,847			(490,364		)	684,813
Other income (expense):
Interest expense	(65,069		)	(68,471		)	(128,663		)	(136,308		)
Gain on extinguishment of debt	46,942			—			64,573			—
Other	629			723			1,161			2,077
	(17,498		)	(67,748		)	(62,929		)	(134,231		)
Income (loss) before income taxes	(314,274		)	312,099			(553,293		)	550,582
(Provision) benefit for income taxes	72,143			(75,649		)	124,378			(127,639		)
Net income (loss)	(242,131		)	236,450			(428,915		)	422,943
Net loss attributable to noncontrolling interests	(2,845		)	(107		)	(3,965		)	(590		)
Net income (loss) attributable to Continental Resources	$	(239,286	)	$	236,557		$	(424,950	)	$	423,533

Net income (loss) per share attributable to Continental Resources:
Basic	$	(0.66	)	$	0.63		$	(1.17	)	$	1.14
Diluted	$	(0.66	)	$	0.63		$	(1.17	)	$	1.13

Comprehensive income (loss):
Net income (loss)	$	(242,131	)	$	236,450		$	(428,915	)	$	422,943
Other comprehensive income, net of tax:
Foreign currency translation adjustments	—			30			—			146
Total other comprehensive income, net of tax	—			30			—			146
Comprehensive income (loss)	(242,131		)	236,480			(428,915		)	423,089
Comprehensive loss attributable to noncontrolling interests	(2,845		)	(107		)	(3,965		)	(590		)
Comprehensive income (loss) attributable to Continental Resources	$	(239,286	)	$	236,587		$	(424,950	)	$	423,679

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

Continental Resources, Inc. and Subsidiaries

Unaudited Condensed Consolidated Statements of Equity



Three and six months ended June 30, 2020	Shareholders’ equity attributable to Continental Resources
In thousands, except share data	Shares outstanding		Common stock			Additional paid-in capital			Accumulated other comprehensive income		Treasury stock			Retained earnings			Total shareholders’ equity of Continental Resources			Noncontrolling interests			Total equity
Balance at December 31, 2019	371,074,036		$	3,711		$	1,274,732		$	—	$	—		$	5,463,224		$	6,741,667		$	366,684		$	7,108,351
Net income (loss)	—		—			—			—		—			(185,664		)	(185,664		)	(1,120		)	(186,784		)
Cumulative effect adjustment from adoption of ASU 2016-13	—		—			—			—		—			(137		)	(137		)	—			(137		)
Cash dividends declared ($0.05 per share)	—		—			—			—		—			(18,580		)	(18,580		)	—			(18,580		)
Change in dividends payable	—		—			—			—		—			2			2			—			2
Common stock repurchased	—		—			—			—		(126,906		)	—			(126,906		)	—			(126,906		)
Common stock retired	(8,122,104	)	(81		)	(126,825		)	—		126,906			—			—			—			—
Stock-based compensation	—		—			16,411			—		—			—			16,411			—			16,411
Restricted stock:
Granted	2,454,235		24			—			—		—			—			24			—			24
Repurchased and canceled	(246,346	)	(2		)	(6,452		)	—		—			—			(6,454		)	—			(6,454		)
Forfeited	(42,818	)	(1		)	—			—		—			—			(1		)	—			(1		)
Contributions from noncontrolling interests	—		—			—			—		—			—			—			16,950			16,950
Distributions to noncontrolling interests	—		—			—			—		—			—			—			(5,618		)	(5,618		)
Balance at March 31, 2020	365,117,003		$	3,651		$	1,157,866		$	—	$	—		$	5,258,845		$	6,420,362		$	376,896		$	6,797,258
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	)	—			(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		$	—	$	—		$	5,019,561		$	6,196,144		$	375,108		$	6,571,252

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

Continental Resources, Inc. and Subsidiaries

Unaudited Condensed Consolidated Statements of Equity (Continued)



Three and six months ended June 30, 2019	Shareholders’ equity attributable to Continental Resources
In thousands, except share data	Shares outstanding		Common stock			Additional paid-in capital			Accumulated other comprehensive income		Treasury stock			Retained earnings			Total shareholders’ equity of Continental Resources			Noncontrolling interests			Total equity
Balance at December 31, 2018	376,021,575		$	3,760		$	1,434,823		$	415	$	—		$	4,706,135		$	6,145,133		$	276,728		$	6,421,861
Net income (loss)	—		—			—			—		—			186,976			186,976			(483		)	186,493
Other comprehensive income, net of tax	—		—			—			116		—			—			116			—			116
Stock-based compensation	—		—			12,095			—		—			—			12,095			—			12,095
Restricted stock:
Granted	1,333,602		13			—			—		—			—			13			—			13
Repurchased and canceled	(439,419	)	(4		)	(20,618		)	—		—			—			(20,622		)	—			(20,622		)
Forfeited	(147,074	)	(1		)	—			—		—			—			(1		)	—			(1		)
Contributions from noncontrolling interests	—		—			—			—		—			—			—			42,204			42,204
Distributions to noncontrolling interests	—		—			—			—		—			—			—			(3,856		)	(3,856		)
Balance at March 31, 2019	376,768,684		$	3,768		$	1,426,300		$	531	$	—		$	4,893,111		$	6,323,710		$	314,593		$	6,638,303
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

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



	Six months ended June 30,
In thousands	2020			2019
Cash flows from operating activities
Net income (loss)	$	(428,915	)	$	422,943
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion	828,728			983,183
Property impairments	246,458			46,655
Non-cash (gain) loss on derivatives	659			(30,592		)
Stock-based compensation	31,755			24,283
Provision (benefit) for deferred income taxes	(122,155		)	127,639
Dry hole costs	6,316			—
Net (gain) loss on sale of assets and other	5,114			112
Gain on extinguishment of debt	(64,573		)	—
Other, net	5,785			4,536
Changes in assets and liabilities:
Accounts receivable	710,434			(15,144		)
Inventories	16,731			(22,438		)
Other current assets	(1,497		)	(7,150		)
Accounts payable trade	(169,762		)	38,176
Revenues and royalties payable	(311,442		)	(61,472		)
Accrued liabilities and other	(108,628		)	(5,732		)
Other noncurrent assets and liabilities	(1,438		)	(95		)
Net cash provided by operating activities	643,570			1,504,904

Cash flows from investing activities
Exploration and development	(984,430		)	(1,528,022		)
Purchase of producing crude oil and natural gas properties	(19,328		)	(20,527		)
Purchase of other property and equipment	(17,222		)	(9,848		)
Proceeds from sale of assets	2,037			652
Net cash used in investing activities	(1,018,943		)	(1,557,745		)

Cash flows from financing activities
Credit facility borrowings	1,395,000			245,000
Repayment of credit facility	(863,000		)	(245,000		)
Repurchase of senior notes	(74,032		)	—
Proceeds from other debt	26,000			—
Repayment of other debt	(5,587		)	(1,162		)
Debt issuance costs	(112		)	—
Contributions from noncontrolling interests	26,071			75,717
Distributions to noncontrolling interests	(9,644		)	(7,166		)
Repurchase of common stock	(126,906		)	(69,661		)
Repurchase of restricted stock for tax withholdings	(6,701		)	(21,184		)
Dividends paid on common stock	(18,460		)	—
Net cash provided by (used in) financing activities	342,629			(23,456		)
Effect of exchange rate changes on cash	—			30
Net change in cash and cash equivalents	(32,744		)	(76,267		)
Cash and cash equivalents at beginning of period	39,400			282,749
Cash and cash equivalents at end of period	$	6,656		$	206,482

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 54% of its crude oil and natural gas production and 67% of its crude oil and natural gas revenues for the six months ended June 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 46% of its crude oil and natural gas production and 33% of its crude oil and natural gas revenues for the six months ended June 30, 2020. The Company's principal producing properties in the South region are located in the SCOOP and STACK areas of Oklahoma.

For the six months ended June 30, 2020, crude oil accounted for 52% 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 June 30, 2020 and for the three and six month periods ended June 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.

Earnings per share

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

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

following table presents the calculation of basic and diluted weighted average shares outstanding and net income (loss) per share attributable to the Company for the three and six months ended June 30, 2020 and 2019.



	Three months ended June 30,					Six months ended June 30,
In thousands, except per share data	2020			2019		2020			2019
Net income (loss) attributable to Continental Resources (numerator)	$	(239,286	)	$	236,557	$	(424,950	)	$	423,533
Weighted average shares (denominator):
Weighted average shares - basic	360,204			372,835		362,804			372,700
Non-vested restricted stock (1)	—			1,174		—			1,857
Weighted average shares - diluted	360,204			374,009		362,804			374,557
Net income (loss) per share attributable to Continental Resources:
Basic	$	(0.66	)	$	0.63	$	(1.17	)	$	1.14
Diluted	$	(0.66	)	$	0.63	$	(1.17	)	$	1.13


(1)	For the three and six months ended June 30, 2020 the Company had a net loss and therefore the potential dilutive effect of approximately 23,000 and 243,000 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 June 30, 2020 and December 31, 2019 consisted of the following:



In thousands	June 30, 2020		December 31, 2019
Tubular goods and equipment	$	14,415	$	14,880
Crude oil	53,870		94,656
Total	$	68,285	$	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 six month period ended June 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 Company continues to evaluate the new standard and is unable to estimate its financial statement impact at this time; however, the impact is not expected to be material.

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

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.



	Six months ended June 30,
In thousands	2020		2019
Supplemental cash flow information:
Cash paid for interest	$	125,208	$	132,064
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	3,725		5,266

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

As of June 30, 2020 and December 31, 2019, the Company had $109.2 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 June 30, 2020 and December 31, 2019, the Company had $0.5 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 June 30, 2020 and December 31, 2019, the Company had $0.5 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 $23.5 million and $46.0 million for the three months ended June 30, 2020 and 2019, respectively, and $73.9 million and $87.6 million for the six months ended June 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.

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

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

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 $22.7 million for operated properties for the three and six months ended June 30, 2020.

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 $8.8 million and $7.4 million for the three months ended June 30, 2020 and 2019, respectively, and $18.9 million and $14.9 million for the six months ended June 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 $7.8 million for the three and six months ended June 30, 2020.

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 six months ended June 30, 2020 and 2019.



	Three months ended June 30, 2020								Three months ended June 30, 2019
In thousands	North Region			South Region		Total			North Region		South Region		Total
Crude oil revenues:
Operated properties	$	96,410		$	30,075	$	126,485		$	608,442	$	176,086	$	784,528
Non-operated properties	28,368			3,867		32,235			207,782		12,836		220,618
Total crude oil revenues	124,778			33,942		158,720			816,224		188,922		1,005,146
Natural gas revenues:
Operated properties (1)	(22,512		)	39,704		17,192			21,650		94,712		116,362
Non-operated properties (2)	(4,622		)	3,362		(1,260		)	5,051		10,866		15,917
Total natural gas revenues	(27,134		)	43,066		15,932			26,701		105,578		132,279
Crude oil and natural gas sales	$	97,644		$	77,008	$	174,652		$	842,925	$	294,500	$	1,137,425

Timing of revenue recognition
Goods transferred at a point in time	$	97,644		$	77,008	$	174,652		$	842,925	$	294,500	$	1,137,425
Goods transferred over time	—			—		—			—		—		—
	$	97,644		$	77,008	$	174,652		$	842,925	$	294,500	$	1,137,425





	Six months ended June 30, 2020							Six months ended June 30, 2019
In thousands	North Region			South Region		Total		North Region		South Region		Total
Crude oil revenues:
Operated properties	$	545,340		$	209,251	$	754,591	$	1,194,047	$	312,633	$	1,506,680
Non-operated properties	161,307			16,592		177,899		386,510		23,074		409,584
Total crude oil revenues	706,647			225,843		932,490		1,580,557		335,707		1,916,264
Natural gas revenues:
Operated properties (1)	(10,923		)	112,010		101,087		73,111		219,410		292,521
Non-operated properties (2)	(2,903		)	6,721		3,818		15,917		22,307		38,224
Total natural gas revenues	(13,826		)	118,731		104,905		89,028		241,717		330,745
Crude oil and natural gas sales	$	692,821		$	344,574	$	1,037,395	$	1,669,585	$	577,424	$	2,247,009

Timing of revenue recognition
Goods transferred at a point in time	$	692,821		$	344,574	$	1,037,395	$	1,669,585	$	577,424	$	2,247,009
Goods transferred over time	—			—		—		—		—		—
	$	692,821		$	344,574	$	1,037,395	$	1,669,585	$	577,424	$	2,247,009

(1) Operated natural gas revenues for the North region include negative gas revenues totaling $22.7 million for both the three and six month periods ended June 30, 2020.

(2) Non-operated natural gas revenues for the North region include negative gas revenues totaling $7.8 million for both the three and six month periods ended June 30, 2020.

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 June 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 six months ended June 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 $2.4 million and $2.4 million at June 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 $0.7 million and $0.1 million for the three months ended June 30, 2020 and 2019, respectively, and $1.5 million and $0.1 million for the six months ended June 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 June 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 six month periods ended June 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 $2.3 million and $2.4 million at June 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 six month periods ended June 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 June 30, 2020 the Company had outstanding derivative contracts as set forth in the tables below.

Crude oil derivatives



		Swaps Weighted Average Price
Period and Type of Contract	Bbls	Swaps Weighted Average Price
July 2020
Swaps - WTI	2,790,000	$	35.67

Natural gas derivatives

Collars

Floors

Ceilings

Swaps Weighted Average Price

Range

Weighted Average Price

Range

Weighted Average Price

Period and Type of Contract

MMBtus

July 2020 - December 2020

Swaps - Henry Hub

17,480,000

2.63

January 2021 - March 2021

Swaps - Henry Hub

5,400,000

2.74

January 2021 - March 2021

Collars - Henry Hub

11,700,000

$2.65 - $2.70

2.67

$3.31 - $3.48

3.40

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 June 30,					Six months ended June 30,
In thousands	2020			2019		2020			2019
Cash received (paid) on derivatives:
Crude oil fixed price swaps (1)	$	(7,123	)	$	—	$	(7,123	)	$	—
Natural gas fixed price swaps	—			8,670		—			16,315
Natural gas collars	—			—		—			5,417
Cash received (paid) on derivatives, net	(7,123		)	8,670		(7,123		)	21,732
Non-cash gain (loss) on derivatives:
Crude oil fixed price swaps	(10,101		)	—		(10,101		)	—
Natural gas fixed price swaps	8,749			44,778		8,749			36,074
Natural gas collars	693			—		693			(5,482		)
Non-cash gain (loss) on derivatives, net	(659		)	44,778		(659		)	30,592
Gain (loss) on derivative instruments, net	$	(7,782	)	$	53,448	$	(7,782	)	$	52,324

(1) Represents realized losses on crude oil derivatives totaling 1,920,000 barrels at a weighted average price of $29.94 per barrel that were executed and settled during the three months ended June 30, 2020.

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,” “Noncurrent derivative assets,” “Derivative liabilities,” and “Noncurrent derivative liabilities,” 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	June 30, 2020			December 31, 2019
Commodity derivative assets:
Gross amounts of recognized assets	$	9,471		$	—
Gross amounts offset on balance sheet	(29		)	—
Net amounts of assets on balance sheet	9,442			—
Commodity derivative liabilities:
Gross amounts of recognized liabilities	(10,130		)	—
Gross amounts offset on balance sheet	29			—
Net amounts of liabilities on balance sheet	$	(10,101	)	$	—

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




In thousands	June 30, 2020			December 31, 2019
Derivative assets	$	9,442		$	—
Noncurrent derivative assets	—			—
Net amounts of assets on balance sheet	9,442			—
Derivative liabilities	(10,101		)	—
Noncurrent derivative liabilities	—			—
Net amounts of liabilities on balance sheet	(10,101		)	—
Total derivative liabilities, net	$	(659	)	$	—

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 June 30, 2020. The Company had no outstanding derivative instruments at December 31, 2019.




	Fair value measurements at June 30, 2020 using:
In thousands	Level 1		Level 2			Level 3		Total
Derivative assets (liabilities):
Swaps	$	—	$	(1,352	)	$	—	$	(1,352	)
Collars	—		693			—		693
Total	$	—	$	(659	)	$	—	$	(659	)

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 June 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 six months ended June 30, 2020 the Company determined the carrying amounts of certain proved properties were not recoverable from future cash flows and therefore were impaired. Such impairments, all of which were recognized in the 2020 first quarter, totaled $181.0 million which reflect fair value adjustments on legacy properties in the Red River Units ($166.5 million) and various non-core properties in the North and South regions ($14.5 million). The impaired properties were written down to their estimated fair value at the time of impairment of $145.6 million. Impairments for the six months ended June 30, 2020 also include a $24.5 million impairment recognized in the 2020 first quarter to reduce the Company's crude oil inventory to estimated net realizable value at the time of impairment. No proved property impairments were recognized during the three months ended June 30, 2020.

For the three and six months ended June 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 six months ended June 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 June 30,				Six months ended June 30,
In thousands	2020		2019		2020		2019
Proved property impairments	$	—	$	—	$	205,545	$	—
Unproved property impairments	23,929		21,339		40,913		46,655
Total	$	23,929	$	21,339	$	246,458	$	46,655

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.



	June 30, 2020				December 31, 2019
In thousands	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Debt:
Credit facility	$	587,000	$	587,000	$	55,000	$	55,000
Notes payable	25,676		26,200		5,351		5,400
5% Senior Notes due 2022	1,099,306		1,082,700		1,099,165		1,108,700
4.5% Senior Notes due 2023	1,442,434		1,393,400		1,491,339		1,571,400
3.8% Senior Notes due 2024	906,370		864,400		994,310		1,034,200
4.375% Senior Notes due 2028	990,197		882,900		989,661		1,063,700
4.9% Senior Notes due 2044	691,777		559,900		691,688		742,000
Total debt	$	5,742,760	$	5,396,500	$	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 $30.7 million and $33.9 million at June 30, 2020 and December 31, 2019, respectively, consists of the following.



In thousands	June 30, 2020		December 31, 2019
Credit facility	$	587,000	$	55,000
Notes payable	25,676		5,351
5% Senior Notes due 2022	1,099,306		1,099,165
4.5% Senior Notes due 2023	1,442,434		1,491,339
3.8% Senior Notes due 2024	906,370		994,310
4.375% Senior Notes due 2028	990,197		989,661
4.9% Senior Notes due 2044	691,777		691,688
Total debt	$	5,742,760	$	5,326,514
Less: Current portion of long-term debt	2,206		2,435
Long-term debt, net of current portion	$	5,740,554	$	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 $587 million of outstanding borrowings on its credit facility at June 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 June 30, 2020 was 2.1%.

The Company had approximately $908 million of borrowing availability on its credit facility at June 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 June 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 June 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 Repurchase 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 June 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.

Repurchase of Senior Notes

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 on extinguishment of debt” in the unaudited condensed consolidated statements of comprehensive income (loss).

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

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 June 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 $11.4 million as of June 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 reflect the Company's net proportionate share of such amounts. A portion of these costs have been or will be billed to other working interest owners. Once paid, the Company's share of these costs are included in property and equipment, production expenses, or general and administrative expenses, as applicable. The Company's leasing activities as a lessor are negligible.



In thousands	Amount
Drilling rig commitments	$	4,625
Surface use agreements	5,065
Field equipment	1,078
Other	590
Total	$	11,358

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 June 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	$	3,371
2021	2,658
2022	865
2023	812
2024	537
Thereafter	6,682
Total operating lease liabilities, at undiscounted value	$	14,925
Less: Imputed interest	(3,567		)
Total operating lease liabilities, at discounted present value	$	11,358
Less: Current portion of operating lease liabilities	(5,210		)
Operating lease liabilities, net of current portion	$	6,148

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, which are presented on a gross basis and do not reflect the Company's net proportionate share of such amounts, 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.



	Three months ended June 30,				Six months ended June 30,
In thousands, except weighted average data	2020		2019		2020			2019
Lease costs:
Operating lease costs	$	1,641	$	3,273	$	2,901		$	6,546
Variable lease costs	912		4,691		4,135			7,813
Short-term lease costs	29,460		39,517		80,808			94,678
Total lease costs	$	32,013	$	47,481	$	87,844		$	109,037

Other information:
Right-of-use assets obtained in exchange for new operating lease liabilities	$	337	$	—	$	7,339		$	—
Operating cash flows from operating leases included in lease liabilities	187		199		415			398
Weighted average remaining lease term as of June 30 (in years)					10.7			6.8
Weighted average discount rate as of June 30					4.3		%	4.7		%

Note 10. Commitments and Contingencies

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

Drilling rig commitments – As of June 30, 2020, the Company has drilling rig contracts with various terms extending to April 2021. Future operating day-rate commitments as of June 30, 2020 total approximately $27 million, of which $23 million is expected to be incurred in the remainder of 2020 and $4 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 $4.6 million that are required to be recognized on the Company's balance sheet at June 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 June 30, 2020 under the arrangements amount to approximately $1.55 billion, of which $107 million is expected to be incurred in the remainder of 2020, $226 million in 2021, $255 million in 2022, $255 million in 2023, $220 million in 2024, and $483 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. In its petition, Casillas alleges the Company breached a Purchase and Sale Agreement (“PSA”) to purchase oil and gas interests in Oklahoma for $200 million. Casillas seeks specific performance. The Company terminated the PSA due to Casillas’ breach of the agreement and denies the allegations and is vigorously defending the claims and seeking affirmative relief. The Company is not currently able to estimate what impact, if any, the ultimate resolution of the action will have on its financial condition, results of operations, or cash flows due to the preliminary status of the matter.

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 June 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 $15.3 million and $12.2 million for the three months ended June 30, 2020 and 2019, respectively, and $31.7 million and $24.3 million for the six months ended June 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 June 30, 2020, the Company had 10,844,493 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 six months ended June 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	2,539,749		27.91
Vested	(1,011,002	)	46.26
Forfeited	(82,055	)	38.21
Non-vested restricted shares outstanding at June 30, 2020	4,908,600		$	37.29

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 six months ended June 30, 2020 was approximately $25 million. As of June 30, 2020, there was approximately $100 million of unrecognized compensation expense related to non-vested restricted stock. This expense is expected to be recognized over a weighted average period of 1.7 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 months ended June 30, 2020. Through June 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 June 30,						Six months ended June 30,
	2020			2019			2020			2019
Provision (benefit) for income taxes (in thousands)	$	(72,143	)	$	75,649		$	(124,378	)	$	127,639
Effective tax rate	23.0		%	24.2		%	22.5		%	23.2		%

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 June 30,						Six months ended June 30,
In thousands, except tax rates	2020			2019			2020			2019
Income (loss) before income taxes	$	(314,274	)	$	312,099		$	(553,293	)	$	550,582
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	(65,998		)	65,541			(116,192		)	115,622
Items impacting the effective tax rate:
State and local income taxes, net of federal benefit	(10,305		)	11,538			(17,908		)	19,337
Equity compensation	585			102			4,471			(8,216		)
Other, net	560			(1,532		)	(2,629		)	896
Valuation allowance	3,015			—			7,880			—
Provision (benefit) for income taxes	$	(72,143	)	$	75,649		$	(124,378	)	$	127,639
Effective tax rate	23.0		%	24.2		%	22.5		%	23.2		%

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

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

was established at March 31, 2020 for the deferred tax assets associated with such NOL carryforwards. The Company recognized an additional valuation allowance of $3.0 million against such deferred tax assets during the three months ended June 30, 2020, bringing the cumulative valuation allowance to $7.9 million as of June 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-Q for the quarter ended March 31, 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 2020 second quarter discussed below were significantly impacted by the economic effects from the COVID-19 pandemic on crude oil demand and prices and may not be indicative of future results for the remainder of 2020. Crude oil prices have improved from historic lows in April 2020 and we have begun to restore a portion of our voluntary production curtailments initiated in the second quarter as discussed below. Accordingly, although our performance and ability to execute our business strategies continue to be impacted by the effects of COVID-19, our operating and financial results for the remainder of 2020 are expected to improve relative to the 2020 second quarter if current prices for crude oil, natural gas, and natural gas liquids are sustained or improve.

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 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. The economic turmoil resulting from COVID-19 resulted in material decreases in our production, revenues, and cash flows in the second quarter of 2020. In response to the significant reduction in crude oil prices, we voluntarily curtailed approximately 55% of our operated crude oil production and associated natural gas in the 2020 second quarter to preserve shareholder value. 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.

As a result of these actions, our total production declined to 202,815 Boe per day for the 2020 second quarter, a decrease of 44% compared to the first quarter of 2020 and 39% lower than the second quarter of 2019. Further, we reduced our non-acquisition capital spending by $460 million, or 71%, in the 2020 second quarter compared to the 2020 first quarter.

Crude oil prices have shown signs of stabilization and improvement in June and July in response to the gradual lifting of restrictions and resumption of economic activity and ongoing restoration of crude oil demand, with West Texas Intermediate crude oil benchmark prices averaging approximately $40 per barrel in July 2020. As a result, in July we began to partially restore our curtailed production and plan to continue restoring production as improved supply and demand fundamentals continue to benefit oil prices. Accordingly, we expect to see production growth in the second half of the year relative to 2020 second quarter levels. Our production volumes are evaluated on an ongoing basis and are subject to change as market conditions evolve.

We continue to actively evaluate the impact of COVID-19 on our operations, financial condition, suppliers, industry, and workforce. We are committed to the responsible stewardship of our assets and, in light of economic uncertainty from the pandemic, we will continue to preserve shareholder value and focus on protecting the strength of our balance sheet, preserving financial flexibility and liquidity, delivering capital efficient operations and cost savings, and conserving the development of our assets.

Our leadership team has significant experience with operating in challenging commodity price environments. The depth and quality of our asset base, the optionality provided by our predominant amount of acreage held by production, and our financial

strength allow us to be adaptable in a variety of price environments. We will 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 June 30,						Six months ended June 30,
	2020			2019			2020			2019
Average daily production:
Crude oil (Bbl per day)	95,174			193,586			147,922			193,753
Natural gas (Mcf per day)	645,846			826,969			803,434			828,422
Crude oil equivalents (Boe per day)	202,815			331,414			281,828			331,823
Average net sales prices (1):
Crude oil ($/Bbl)	$	16.35		$	54.66		$	32.37		$	52.36
Natural gas ($/Mcf)	$	0.12		$	1.66		$	0.59		$	2.11
Crude oil equivalents ($/Boe)	$	7.88		$	36.03		$	18.56		$	35.79
Crude oil net sales price discount to NYMEX ($/Bbl)	$	(7.54	)	$	(5.11	)	$	(6.66	)	$	(4.94	)
Natural gas net sales price discount to NYMEX ($/Mcf)	$	(1.58	)	$	(0.98	)	$	(1.26	)	$	(0.79	)
Production expenses ($/Boe)	$	3.58		$	3.74		$	3.60		$	3.66
Production taxes (% of net crude oil and natural gas sales)	7.8		%	8.7		%	8.7		%	8.4		%
Depreciation, depletion, amortization and accretion ($/Boe)	$	16.07		$	16.14		$	16.25		$	16.37
Total general and administrative expenses ($/Boe)	$	2.30		$	1.57		$	1.66		$	1.58


(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 June 30, 2020 compared to the three months ended June 30, 2019

Results of Operations

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



	Three months ended June 30,
In thousands	2020			2019
Crude oil and natural gas sales	$	174,652		$	1,137,425
Gain (loss) on derivative instruments, net	(7,782		)	53,448
Crude oil and natural gas service operations	8,789			17,509
Total revenues	175,659			1,208,382
Operating costs and expenses	(472,435		)	(828,535		)
Other expenses, net (1)	(17,498		)	(67,748		)
Income (loss) before income taxes	(314,274		)	312,099
(Provision) benefit for income taxes	72,143			(75,649		)
Net income (loss)	(242,131		)	236,450
Net loss attributable to noncontrolling interests	(2,845		)	(107		)
Net income (loss) attributable to Continental Resources	$	(239,286	)	$	236,557
Production volumes:
Crude oil (MBbl)	8,661			17,616
Natural gas (MMcf)	58,772			75,254
Crude oil equivalents (MBoe)	18,456			30,159
Sales volumes:
Crude oil (MBbl)	8,270			17,549
Natural gas (MMcf)	58,772			75,254
Crude oil equivalents (MBoe)	18,065			30,091

(1) Net of gain on extinguishment of debt of $46.9 million for the three months ended June 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 second quarter period.



Boe production per day	2Q 2020	2Q 2019	% Change
Bakken	88,822	194,014	(54	%)
SCOOP	72,296	71,471	1	%
STACK	34,756	57,209	(39	%)
All other	6,941	8,720	(20	%)
Total	202,815	331,414	(39	%)

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



	Three months ended June 30,						Volume decrease		Volume percent decrease
	2020			2019
	Volume	Percent		Volume	Percent
Crude oil (MBbl)	8,661	47	%	17,616	58	%	(8,955	)	(51	%)
Natural gas (MMcf)	58,772	53	%	75,254	42	%	(16,482	)	(22	%)
Total (MBoe)	18,456	100	%	30,159	100	%	(11,703	)	(39	%)

	Three months ended June 30,						Volume decrease		Volume percent decrease
	2020			2019
	MBoe	Percent		MBoe	Percent
North Region	8,711	47	%	18,440	61	%	(9,729	)	(53	%)
South Region	9,745	53	%	11,719	39	%	(1,974	)	(17	%)
Total	18,456	100	%	30,159	100	%	(11,703	)	(39	%)

The 51% decrease in crude oil production for the 2020 second quarter was driven by the previously described production curtailments implemented during the quarter coupled with minimal drilling and completion activities, which led to a 7,802 MBbls, or 58%, decrease in Bakken crude oil production, a 526 MBbls, or 22%, decrease in SCOOP crude oil production, and a 509 MBbls, or 59%, decrease in STACK crude oil production.

Our production curtailments and minimal drilling and completion activities also impacted our natural gas production, leading to a 22% decrease in natural gas production for the 2020 second quarter compared to the 2019 second quarter. Natural gas production in the Bakken decreased 10,626 MMcf, or 43%, and natural gas production in STACK decreased 9,205 MMcf, or 35%, from the prior year second quarter. These decreases were partially offset by a 3,607 MMcf, or 15%, increase in SCOOP natural gas production.

Revenues

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

Net crude oil and natural gas sales. Net crude oil and natural gas sales totaled $142.3 million for the second quarter of 2020, an 87% decrease compared to net sales of $1.08 billion for the 2019 second quarter due to significant decreases in net sales prices and sales volumes as discussed below.

Total sales volumes for the second quarter of 2020 decreased 12,026 MBoe, or 40%, compared to the 2019 second quarter, reflecting reduced sales from the previously described production curtailments in the current period. For the second quarter of 2020, our crude oil sales volumes decreased 53% from the comparable 2019 period, while our natural gas sales volumes decreased 22%.

Our crude oil net sales prices averaged $16.35 per barrel in the 2020 second quarter, a decrease of 70% compared to $54.66 per barrel for the 2019 second quarter due to significantly reduced market prices and wider price differentials. The differential between NYMEX West Texas Intermediate ("WTI") calendar month prices and our realized crude oil net sales prices averaged $7.54 per barrel for the 2020 second quarter compared to $5.11 per barrel for the 2019 second quarter. The increased differential reflects changes in supply and demand fundamentals and economic effects from COVID-19 that impacted location differentials and price realizations compared to the prior year period.

See the subsequent section titled Future Capital Requirements–Commitments and contingencies for discussion of recent developments that may impact the 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. The restriction of DAPL's takeaway capacity may have an impact on prices for Bakken-produced barrels and result in wider differentials relative to WTI benchmark prices in the future, the amount of which is uncertain. If transportation capacity on DAPL becomes restricted or unavailable, we have the ability to utilize other third party pipelines or rail facilities to transport our Bakken crude oil production to market, although such alternatives may be more costly.

Our natural gas net sales prices averaged $0.12 per Mcf for the 2020 second quarter, a decrease of 93% compared to $1.66 per Mcf for the 2019 second quarter due to significantly reduced market prices and lower price realizations. The discount between our net sales prices and NYMEX Henry Hub calendar month natural gas prices weakened to $1.58 per Mcf for the 2020 second quarter compared to $0.98 per Mcf for the 2019 second quarter. We sell the majority of our operated natural gas production to

midstream customers at lease locations based on market prices in the field where the sales occur. The field markets are impacted by residue gas and natural gas liquids ("NGLs") prices at secondary, downstream markets. NGL prices in 2020 have decreased significantly compared to 2019 levels 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. As a result of the significant decrease in 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 $30.5 million for the 2020 second quarter, with immaterial amounts in prior periods, 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.

NGL prices have improved from recent lows in conjunction with increased crude oil prices and other factors, which has resulted in improved price realizations for our natural gas sales stream. If prices remain at current levels or improve, while we may recognize additional negative gas revenues in the second half of 2020, we would not expect such amounts to be of a similar magnitude as the negative gas revenues recognized in the 2020 second quarter.

Derivatives. Changes in crude oil prices during the second quarter of 2020 had an overall unfavorable impact on the fair value of our derivatives, which resulted in negative revenue adjustments of $7.8 million for the period compared to positive revenue adjustments of $53.4 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 and the treatment and sale of crude oil reclaimed from waste products. Revenues associated with such activities decreased $8.7 million, or 50%, from $17.5 million for the second quarter of 2019 to $8.8 million for the second quarter of 2020 due to a decrease in the magnitude of water handling and recycling activities resulting from our curtailment of production activities 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 $47.7 million, or 42%, from $112.4 million for the second quarter of 2019 to $64.7 million for the second quarter of 2020 due to the previously described production curtailments and associated 40% decrease in sales volumes. Production expenses on a per-Boe basis averaged $3.58 for the 2020 second quarter, improved from $3.74 per Boe recognized for the 2019 second quarter. We expect our total production expenses to increase in the second half of 2020 relative to second quarter levels as we begin to resume production on curtailed wells, the amount of which is uncertain.

Production Taxes. Production taxes decreased $82.8 million, or 88%, to $11.1 million for the second quarter of 2020 compared to $93.9 million for the second quarter of 2019 primarily due to an 85% decrease in crude oil and natural gas sales. Our production taxes as a percentage of net crude oil and natural gas sales decreased from 8.7% for the second quarter of 2019 to 7.8% for the second 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 $195.3 million, or 40%, to $290.3 million for the second quarter of 2020 compared to $485.6 million for the second quarter of 2019 due to a 40% 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 June 30,
$/Boe	2020		2019
Crude oil and natural gas	$	15.65	$	15.91
Other equipment	0.30		0.16
Asset retirement obligation accretion	0.12		0.07
Depreciation, depletion, amortization and accretion	$	16.07	$	16.14

DD&A expenses associated with other equipment and asset retirement obligations increased on a per-Boe basis in 2020 due to the 40% decrease in total sales volumes with no corresponding decrease in DD&A, as DD&A for such assets is recognized on a ratable basis over defined periods irrespective of current production levels.

Property Impairments. Property impairments increased $2.6 million to $23.9 million for the second quarter of 2020 compared to $21.3 million for the second quarter of 2019, reflecting an increase in the amortization of undeveloped leasehold costs from

changes in the Company’s estimates of properties not expected to be developed before lease expiration in response to significantly reduced commodity prices. There were no proved property impairments recognized in the second quarter periods of 2020 and 2019.

General and Administrative Expenses. Total G&A expenses decreased $5.7 million, or 12%, to $41.5 million for the second quarter of 2020 compared to $47.2 million for the second quarter of 2019.

Total G&A expenses include non-cash charges for equity compensation of $15.3 million and $12.2 million for the second 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 second quarter that resulted in lower equity compensation expense for that period.

G&A expenses other than equity compensation totaled $26.2 million for the 2020 second quarter, a decrease of $8.8 million, or 25%, compared to $35.0 million for the 2019 second 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 June 30,
$/Boe	2020		2019
General and administrative expenses	$	1.45	$	1.17
Non-cash equity compensation	0.85		0.40
Total general and administrative expenses	$	2.30	$	1.57

The increase in G&A expenses on a per-Boe basis in 2020 was driven by the 40% decrease in total sales volumes from the previously described production curtailments with no similar reduction in G&A expenses, as certain G&A expenses continue to be incurred in the absence of production.

Interest Expense. Interest expense decreased $3.4 million, or 5%, to $65.1 million for the second quarter of 2020 compared to $68.5 million for the second 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. The decrease in interest expense from lower average interest rates was partially offset by an increase in total outstanding debt as a consequence of the COVID-19 pandemic that led to reduced cash flows and higher credit facility borrowings in recent months. Our weighted average outstanding debt balance for the 2020 second quarter was approximately $6.1 billion with a weighted average interest rate of 4.2% compared to averages of $5.8 billion and 4.5% for the 2019 second quarter.

Income Taxes. For the second 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 $72.1 million for the 2020 second quarter and an income tax provision of $75.6 million for the 2019 second quarter, which resulted in effective tax rates of 23.0% and 24.2%, 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.

Six months ended June 30, 2020 compared to the six months ended June 30, 2019

Results of Operations

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



	Six months ended June 30,
In thousands	2020			2019
Crude oil and natural gas sales	$	1,037,395		$	2,247,009
Gain (loss) on derivative instruments, net	(7,782		)	52,324
Crude oil and natural gas service operations	26,847			33,284
Total revenues	1,056,460			2,332,617
Operating costs and expenses	(1,546,824		)	(1,647,804		)
Other expenses, net (1)	(62,929		)	(134,231		)
Income (loss) before income taxes	(553,293		)	550,582
(Provision) benefit for income taxes	124,378			(127,639		)
Net income (loss)	(428,915		)	422,943
Net loss attributable to noncontrolling interests	(3,965		)	(590		)
Net income (loss) attributable to Continental Resources	$	(424,950	)	$	423,533
Production volumes:
Crude oil (MBbl)	26,922			35,069
Natural gas (MMcf)	146,225			149,944
Crude oil equivalents (MBoe)	51,293			60,060
Sales volumes:
Crude oil (MBbl)	26,521			34,922
Natural gas (MMcf)	146,225			149,944
Crude oil equivalents (MBoe)	50,891			59,912

(1) Net of gain on extinguishment of debt of $64.6 million for the six months ended June 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 6/30/2020	YTD 6/30/2019	% Change
Bakken	145,162	196,704	(26	%)
SCOOP	90,057	69,576	29	%
STACK	39,455	56,863	(31	%)
All other	7,154	8,680	(18	%)
Total	281,828	331,823	(15	%)

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



	Six months ended June 30,						Volume decrease		Volume percent decrease
	2020			2019
	Volume	Percent		Volume	Percent
Crude oil (MBbl)	26,922	52	%	35,069	58	%	(8,147	)	(23	%)
Natural gas (MMcf)	146,225	48	%	149,944	42	%	(3,719	)	(2	%)
Total (MBoe)	51,293	100	%	60,060	100	%	(8,767	)	(15	%)

	Six months ended June 30,						Volume increase (decrease)		Volume percent increase (decrease)
	2020			2019
	MBoe	Percent		MBoe	Percent
North Region	27,715	54	%	37,151	62	%	(9,436	)	(25	%)
South Region	23,578	46	%	22,909	38	%	669		3	%
Total	51,293	100	%	60,060	100	%	(8,767	)	(15	%)

The 23% decrease in crude oil production for year to date 2020 was primarily driven by an 8,530 MBbls, or 31%, decrease in Bakken oil production along with a 589 MBbls, or 36%, decrease in STACK oil production due to the previously described production curtailments and minimal drilling and completion activities undertaken during the 2020 second quarter. These decreases were partially offset by a 1,146 MBbls, or 26%, 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 in the 2020 second quarter.

Our production curtailments and minimal drilling and completion activities in the 2020 second quarter also impacted our year to date natural gas production, leading to a 15,128 MMcf, or 29%, decrease in STACK gas production and a 3,920 MMcf, or 8%, decrease in Bakken gas production over the prior year period. These decreases were nearly offset by a 15,909 MMcf, or 33%, 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 $944.6 million, a decrease of 56% compared to net sales of $2.14 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 9,021 MBoe, or 15%, 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 24% from the comparable 2019 period, while our natural gas sales volumes decreased 2%.

Our crude oil net sales prices averaged $32.37 per barrel for year to date 2020, a decrease of 38% compared to $52.36 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 $6.66 per barrel for year to date 2020 compared to $4.94 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 compared to the prior year period.

Our natural gas net sales prices averaged $0.59 per Mcf for year to date 2020, a decrease of 72% compared to $2.11 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 $1.26 per Mcf for year to date 2020 compared to $0.79 per Mcf for the year to date 2019 period. NGL prices have decreased significantly over prior year levels in conjunction with decreased crude oil prices and other factors, resulting in reduced price realizations in 2020 for our natural gas sales stream relative to benchmark prices and leading to the previously described recognition of $30.5 million of negative gas revenues in the 2020 second quarter.

Derivatives. Changes in crude oil market prices during the six months ended June 30, 2020 had an overall unfavorable impact on the fair value of our derivatives, which resulted in negative revenue adjustments of $7.8 million for the period compared to positive revenue adjustments of $52.3 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 $6.5 million, or 19%, from $33.3 million for year to date 2019 to $26.8 million for year to date 2020 due to a

decrease in the magnitude of water handling and recycling activities resulting from our curtailment of production activities in the 2020 second 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 $36.2 million, or 17%, from $219.4 million for year to date 2019 to $183.2 million for year to date 2020 due to the previously described production curtailments and associated 15% decrease in sales volumes. Production expenses on a per-Boe basis averaged $3.60 for year to date 2020, improved from $3.66 per Boe recognized for the comparable 2019 period.

Production Taxes. Production taxes decreased $98.0 million, or 54%, to $82.3 million for year to date 2020 compared to $180.3 million for year to date 2019 due to a 54% decrease in crude oil and natural gas sales. Our production taxes as a percentage of net crude oil and natural gas sales averaged 8.7% 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 $8.7 million to $13.6 million for year to date 2020 compared to $4.9 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 $153.6 million, or 16%, to $827.0 million for year to date 2020 compared to $980.6 million for the comparable 2019 period due to a 15% 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.



	Six months ended June 30,
$/Boe	2020		2019
Crude oil and natural gas	$	15.95	$	16.14
Other equipment	0.21		0.16
Asset retirement obligation accretion	0.09		0.07
Depreciation, depletion, amortization and accretion	$	16.25	$	16.37

Property Impairments. Property impairments increased $199.8 million to $246.5 million for the year to date period of 2020 compared to $46.7 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 $181.0 million for the year to date period of 2020, all of which were recognized in the 2020 first 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 ($166.5 million) and various non-core properties in the North and South regions ($14.5 million). Additionally, in response to decreased crude oil prices we recognized a $24.5 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 $5.8 million, or 12%, to $40.9 million for year to date 2020 compared to $46.7 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 $10.4 million, or 11%, to $84.4 million for year to date 2020 compared to $94.8 million for year to date 2019.

Total G&A expenses include non-cash charges for equity compensation of $31.7 million and $24.3 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 $52.7 million for year to date 2020, a decrease of $17.8 million, or 25%, compared to $70.5 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.



	Six months ended June 30,
$/Boe	2020		2019
General and administrative expenses	$	1.04	$	1.18
Non-cash equity compensation	0.62		0.40
Total general and administrative expenses	$	1.66	$	1.58

Net (gain) loss on sale of assets and other. For the six months ended June 30, 2020 we paid a deposit and transaction fees totaling $5.7 million associated with a potential property acquisition that was terminated by the Company. Such amounts were expensed and are included in the caption "Net (gain) loss on sale of assets and other."

Interest Expense. Interest expense decreased $7.6 million, or 6%, to $128.7 million for year to date 2020 compared to $136.3 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 six months ended June 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 $124.4 million and an income tax provision of $127.6 million for the year to date periods of 2020 and 2019, respectively, which resulted in effective tax rates of 22.5% and 23.2%, 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 will remain committed to operating in a responsible manner to preserve financial flexibility, liquidity, and the strength of our balance sheet.

At July 31, 2020, we had approximately $848 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 June 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 $643.6 million and $1.50 billion for the six months ended June 30, 2020 and 2019, respectively, reflecting a significant decrease in our 2020 second quarter cash flows due to the previously described decrease in crude oil prices and our voluntary curtailment of production during the quarter. As a result of these factors, we generated negative operating cash flows of $20.2 million in the 2020 second quarter compared to $663.8 million of positive operating cash flows in the 2020 first quarter.

WTI crude oil prices have improved from historic lows reached in April 2020 and averaged approximately $40 per barrel in July 2020. If crude oil prices remain at current levels or further improve and we continue to restore our curtailed production, our operating cash flows are expected to improve in the second half of 2020 relative to second quarter levels, the amount of which cannot be estimated.

Cash flows from investing activities

Net cash used in investing activities totaled $1.02 billion and $1.56 billion for the six months ended June 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. As a result of our reduced activities, our investing cash outflows decreased significantly from $706.7 million in the 2020 first quarter to $312.2 million in the 2020 second quarter.

Cash flows from financing activities

Net cash provided by financing activities for the six months ended June 30, 2020 totaled $342.6 million, comprised of $521.1 million of net financing cash inflows for the 2020 first quarter partially offset by $178.5 million in net financing cash outflows for the 2020 second quarter, the change of which was primarily driven by credit facility borrowing and repayment activities. Net credit facility borrowings totaled $532 million for year to date 2020, representing net borrowings of $680 million in the first quarter offset by subsequent net repayments of $148 million in the second quarter. These net credit facility borrowings for year to date 2020 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.

Net cash used in financing activities for the six months ended June 30, 2019 totaled $23.5 million, which primarily represents $69.7 million of cash used to repurchase shares of our common stock and $21.2 million of cash paid to taxing authorities to satisfy tax withholdings associated with restricted stock awards that vested during the period, partially offset by $75.7 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.

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 for the remainder of 2020 have been adjusted to be reflective of the adverse 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 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 July 31, 2020, we had $647 million of outstanding borrowings and approximately $848 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 June 30, 2020 and expect to maintain such compliance. At June 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 June 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 June 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 June 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 June 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 in the SCOOP and STACK plays through a minerals subsidiary named The Mineral Resources Company II, LLC ("TMRC II"). Under the relationship, the parties have committed, subject to satisfaction of agreed upon acreage development thresholds, to spend a remaining aggregate total of approximately $154 million through year-end 2021 to acquire mineral interests. Continental is to fund 20% of future mineral acquisitions and will be entitled to receive between 25% and 50% of total revenues generated by TMRC II based upon performance relative to predetermined production targets, while Franco-Nevada will fund 80% of future acquisitions and will be entitled to receive between 50% and 75% of TMRC II's revenues. Based upon production targets achieved to date, Continental is currently earning 50% of TMRC II's revenues and such allocation is expected to continue through at least year-end 2020. The timing and amount of future mineral acquisitions and resulting achievement of production targets are expected to be adversely impacted by Continental's previously described reduction in 2020 capital spending, which may impact the allocation of revenues between Continental and Franco-Nevada in periods beyond 2020, the extent of which cannot be estimated.

Capital expenditures

We remain committed to operating in a disciplined, capital-efficient manner in light of ongoing economic uncertainty and volatility in commodity prices. Our original capital budget for 2020 was $2.65 billion, which was reduced to $1.2 billion in March 2020 in response to the significant decrease in crude oil prices resulting from the COVID-19 pandemic and actions by

the Organization of Petroleum Exporting Countries. We diligently evaluate and adjust our spending plans on an ongoing basis based on market conditions.

For the six months ended June 30, 2020, we invested $841.5 million in our capital program excluding $30.0 million of unbudgeted acquisitions and excluding $153.5 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 significantly reduced our drilling and completion activities beginning in March 2020 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 $460 million, or 71%, in the 2020 second quarter compared to the 2020 first quarter. Our 2020 year to date capital expenditures were allocated as shown in the table below. We expect our capital spending to continue declining in the second half of the year.



In millions	1Q 2020		2Q 2020		YTD 2020
Exploration and development drilling	$	544.0	$	155.8	$	699.8
Land costs (1)	39.9		8.9		48.8
Capital facilities, workovers and other corporate assets	63.0		25.8		88.8
Seismic	3.8		0.3		4.1
Capital expenditures, excluding unbudgeted acquisitions	650.7		190.8		841.5
Acquisitions of producing properties	19.3		0.1		19.4
Acquisitions of non-producing properties	10.6		—		10.6
Total unbudgeted acquisitions	29.9		0.1		30.0
Total capital expenditures	$	680.6	$	190.9	$	871.5


(1)	Amount includes $23 million of mineral acquisitions made by TMRC II during the six months ended June 30, 2020, of which $18 million was recouped from Franco-Nevada.

Commitments and contingencies

Refer to Note 10. Commitments and Contingencies 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 June 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 mid-2021. If transportation capacity on DAPL becomes restricted or unavailable, we have the ability to utilize other third party pipelines or rail facilities to transport our Bakken crude oil production to market, although such alternatives may be more costly. The restriction of DAPL's takeaway capacity may have an impact on prices for Bakken-produced barrels and result in wider differentials relative to WTI benchmark prices in the future, the amount of which is uncertain.

Dividend 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 June 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 six months ended June 30, 2020 and 2019.



	Three months ended June 30, 2020									Three months ended June 30, 2019
In thousands	Crude oil			Natural gas			Total			Crude oil			Natural gas			Total
Crude oil and natural gas sales (GAAP)	$	158,720		$	15,932		$	174,652		$	1,005,146		$	132,279		$	1,137,425
Less: Transportation expenses	(23,518		)	(8,787		)	(32,305		)	(45,981		)	(7,412		)	(53,393		)
Net crude oil and natural gas sales (non-GAAP)	$	135,202		$	7,145		$	142,347		$	959,165		$	124,867		$	1,084,032
Sales volumes (MBbl/MMcf/MBoe)	8,270			58,772			18,065			17,549			75,254			30,091
Net sales price (non-GAAP)	$	16.35		$	0.12		$	7.88		$	54.66		$	1.66		$	36.03



	Six months ended June 30, 2020									Six months ended June 30, 2019
In thousands	Crude oil			Natural gas			Total			Crude oil			Natural gas			Total
Crude oil and natural gas sales (GAAP)	$	932,490		$	104,905		$	1,037,395		$	1,916,264		$	330,745		$	2,247,009
Less: Transportation expenses	(73,890		)	(18,917		)	(92,807		)	(87,628		)	(14,903		)	(102,531		)
Net crude oil and natural gas sales (non-GAAP)	$	858,600		$	85,988		$	944,588		$	1,828,636		$	315,842		$	2,144,478
Sales volumes (MBbl/MMcf/MBoe)	26,521			146,225			50,891			34,922			149,944			59,912
Net sales price (non-GAAP)	$	32.37		$	0.59		$	18.56		$	52.36		$	2.11		$	35.79

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 our crude oil and natural gas production. 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 six months ended June 30, 2020, and excluding the effect of derivative instruments in place, if any, our annual revenue would increase or decrease by approximately $540 million for each $10.00 per barrel change in crude oil prices at June 30, 2020 and $293 million for each $1.00 per Mcf change in natural gas prices at June 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 crude oil derivative instruments at June 30, 2020 was a net liability of $10.1 million. An assumed increase in the forward prices used in the June 30, 2020 valuation of our crude oil derivatives of $10.00 per barrel would increase our crude oil derivative liability to approximately $38 million at June 30, 2020. Conversely, an assumed decrease in forward prices of $10.00 per barrel would change our crude oil derivative valuation to a net asset of approximately $18 million at June 30, 2020.

The fair value of our natural gas derivative instruments at June 30, 2020 was a net asset of $9.4 million. An assumed increase in the forward prices used in the June 30, 2020 valuation of our natural gas derivatives of $1.00 per MMBtu would change our natural gas derivative valuation to a net liability of approximately $20 million at June 30, 2020. Conversely, an assumed decrease in forward prices of $1.00 per MMBtu would increase our natural gas derivative asset to approximately $40 million at June 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 ($176 million in receivables at June 30, 2020), and our joint interest and other receivables ($151 million at June 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 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 $32 million at June 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 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 $647 million of variable rate borrowings outstanding on our credit facility at July 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 $1.6 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 June 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 June 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 legal matter involving the Company and Casillas Petroleum Resource Partners II, LLC, 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 June 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)
April 1, 2020 to April 30, 2020:	—	—		—	—
May 1, 2020 to May 31, 2020:
Repurchases for tax withholdings (2)	19,037	$	12.96	—	—
June 1, 2020 to June 30, 2020:
Purchases by principal shareholder (3)	6,738,015	$	16.50	—	—
Total for the quarter	6,757,052	$	16.49	—	—

(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 June 30, 2020. The dollar value of shares that may yet be purchased under the program totaled $682.9 million as of June 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.

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

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

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

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

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

101.SCH*		Inline XBRL Taxonomy Extension Schema Document

101.CAL*		Inline XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF*		Inline XBRL Taxonomy Extension Definition Linkbase Document

101.LAB*		Inline XBRL Taxonomy Extension Label Linkbase Document

101.PRE*		Inline XBRL Taxonomy Extension Presentation Linkbase Document

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


*	Filed herewith


**	Furnished herewith

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:	August 3, 2020	By:	/s/ John D. Hart
			John D. Hart
			Sr. Vice President, Chief Financial Officer and Treasurer (Duly Authorized Officer and Principal Financial Officer)


1.	I have reviewed this report on Form 10-Q for the period ended June 30, 2020 of Continental Resources, Inc. (“Registrant”);


2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;


3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the Registrant as of, and for, the periods presented in this report;


4.	The Registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the Registrant and have:


(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the Registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


(c)	Evaluated the effectiveness of the Registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


(d)	Disclosed in this report any change in the Registrant’s internal control over financial reporting that occurred during the Registrant’s most recent fiscal quarter (the Registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the Registrant’s internal control over financial reporting; and


(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the Registrant’s ability to record, process, summarize and report financial information; and


(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the Registrant’s internal control over financial reporting.



/s/ William B. Berry		/s/ John D. Hart
William B. Berry		John D. Hart
Chief Executive Officer		Sr. Vice President, Chief Financial Officer and Treasurer
August 3, 2020		August 3, 2020