SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

(Exact name of registrant as specified in its charter)

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

(Registrant’s telephone number, including area code)

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

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

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. Yesx No ¨

Indicate by check mark whether the registrant has submitted electronically ~~and posted on its corporate Web site, if any,~~ every Interactive Data File required to be submitted ~~and posted~~ 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 ~~and post~~ such files). Yesx 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.

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

~~376,037,498~~374,419,853 shares of our $0.01 par value common stock were outstanding on July 31, ~~2018.~~2019.

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 ~~Statement~~Statements of ~~Shareholders’~~ Equity	3
	Unaudited Condensed Consolidated Statements of Cash Flows	45
	Notes to Unaudited Condensed Consolidated Financial Statements	56
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	2021
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	33
Item 4.	Controls and Procedures	35

PART II. Other Information
Item 1.	Legal Proceedings	36
Item 1A.	Risk Factors	36
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	36
Item 3.	Defaults Upon Senior Securities	36
Item 4.	Mine Safety Disclosures	36
Item 5.	Other Information	3637
Item 6.	Exhibits	37
	Signature	38

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

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

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

our strategy;

our business and financial plans;

our future operations;

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

technology;

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

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

the amount, nature and timing of capital expenditures;

estimated revenues, expenses and results of operations;

drilling and completing of wells;

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;~~position or dividend payments;

general economic conditions;

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, ~~2017,~~2018, registration statements we file from time to time with the Securities and Exchange Commission, and other announcements we make from time to time.

Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date on which such statement is made. Should one or more of the risks or uncertainties described in this report or our Annual Report on Form 10-K occur, or should underlying assumptions prove incorrect, the Company's actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by this cautionary statement.

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

iii

PART I. Financial Information


ITEM 1.	Financial Statements

Continental Resources, Inc. and Subsidiaries

Condensed Consolidated Balance Sheets


	June 30, 2018		December 31, 2017		June 30, 2019		December 31, 2018
In thousands, except par values and share data	(Unaudited)				(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	129,989	$	43,902	$	206,482	$	282,749
Receivables:
Crude oil and natural gas sales	671,004		671,665		650,870		644,107
Affiliated parties	58		63		206		73
Joint interest and other, net	506,301		426,585		378,009		368,235
Derivative assets	203		2,603		46,204		15,612
Inventories	115,310		97,406		110,894		88,544
Prepaid expenses and other	18,424		9,501		21,010		13,041
Total current assets	1,441,289		1,251,725		1,413,675		1,412,361
Net property and equipment, based on successful efforts method of accounting	13,339,571		12,933,789		14,387,960		13,869,800
Operating lease right-of-use assets					12,997		—
Other noncurrent assets	17,620		14,137		14,790		15,786
Total assets	$	14,798,480	$	14,199,651	$	15,829,422	$	15,297,947

Liabilities and shareholders’ equity
Liabilities and equity
Current liabilities:
Accounts payable trade	$	811,965	$	692,908	$	738,311	$	717,560
Revenues and royalties payable	380,651		374,831		339,079		400,567
Payables to affiliated parties	237		143		83		203
Accrued liabilities and other	280,199		260,074		261,609		266,819
Derivative liabilities	9,065		—
Dividends payable					18,747		—
Current portion of operating lease liabilities					8,120		—
Current portion of long-term debt	2,322		2,286		2,397		2,360
Total current liabilities	1,484,439		1,330,242		1,368,346		1,387,509
Long-term debt, net of current portion	6,164,221		6,351,405		5,767,316		5,765,989
Other noncurrent liabilities:
Deferred income tax liabilities, net	1,406,326		1,259,558		1,702,075		1,574,436
Asset retirement obligations, net of current portion	117,924		111,794		145,218		136,986
Operating lease liabilities, net of current portion					4,877		—
Other noncurrent liabilities	12,082		15,449		11,755		11,166
Total other noncurrent liabilities	1,536,332		1,386,801		1,863,925		1,722,588
Commitments and contingencies (Note 8)
Shareholders’ equity:
Commitments and contingencies (Note 9)
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; 376,030,797 shares issued and outstanding at June 30, 2018; 375,219,769 shares issued and outstanding at December 31, 2017	3,760		3,752
Common stock, $0.01 par value; 1,000,000,000 shares authorized; 374,943,548 shares issued and outstanding at June 30, 2019; 376,021,575 shares issued and outstanding at December 31, 2018					3,749		3,760
Additional paid-in capital	1,415,175		1,409,326		1,368,272		1,434,823
Accumulated other comprehensive income	325		307		561		415
Retained earnings	4,194,228		3,717,818		5,110,921		4,706,135
Total shareholders’ equity	5,613,488		5,131,203
Total liabilities and shareholders’ equity	$	14,798,480	$	14,199,651
Total shareholders’ equity attributable to Continental Resources					6,483,503		6,145,133
Noncontrolling interests					346,332		276,728
Total equity					6,829,835		6,421,861
Total liabilities and equity					$	15,829,422	$	15,297,947

Continental Resources, Inc. and Subsidiaries

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


	Three months ended June 30,						Six months ended June 30,						Three months ended June 30,						Six months ended June 30,
In thousands, except per share data	2018			2017			2018			2017			2019			2018			2019			2018
Revenues:
Crude oil and natural gas sales	$	1,137,528		$	626,548		$	2,251,380		$	1,260,398		$	1,137,425		$	1,137,528		$	2,247,009		$	2,251,380
Gain (loss) on natural gas derivatives, net	(12,685		)	28,022			(2,511		)	74,880			53,448			(12,685		)	52,324			(2,511		)
Crude oil and natural gas service operations	12,270			6,916			29,272			11,636			17,509			12,270			33,284			29,272
Total revenues	1,137,113			661,486			2,278,141			1,346,914			1,208,382			1,137,113			2,332,617			2,278,141

Operating costs and expenses:
Production expenses	90,171			82,474			183,133			155,328			112,430			90,171			219,396			183,133
Production taxes	83,595			41,965			164,175			83,198			93,866			83,595			180,306			164,175
Transportation expenses	47,254			—			96,551			—			53,393			47,254			102,531			96,551
Exploration expenses	303			3,204			2,023			8,202			3,090			303			4,927			2,023
Crude oil and natural gas service operations	7,688			4,478			12,271			7,315			11,206			7,688			18,392			12,271
Depreciation, depletion, amortization and accretion	447,200			395,770			901,578			777,926			485,621			447,200			980,641			901,578
Property impairments	29,162			123,316			62,946			174,689			21,339			29,162			46,655			62,946
General and administrative expenses	47,174			39,186			90,217			86,407			47,226			47,174			94,844			90,217
Net (gain) loss on sale of assets and other	(6,710		)	134			(6,751		)	5,669			364			(6,710		)	112			(6,751		)
Total operating costs and expenses	745,837			690,527			1,506,143			1,298,734			828,535			745,837			1,647,804			1,506,143
Income (loss) from operations	391,276			(29,041		)	771,998			48,180
Income from operations													379,847			391,276			684,813			771,998
Other income (expense):
Interest expense	(74,288		)	(72,744		)	(150,182		)	(143,916		)	(68,471		)	(74,288		)	(136,308		)	(150,182		)
Other	708			373			1,362			815			723			708			2,077			1,362
	(73,580		)	(72,371		)	(148,820		)	(143,101		)	(67,748		)	(73,580		)	(134,231		)	(148,820		)
Income (loss) before income taxes	317,696			(101,412		)	623,178			(94,921		)
(Provision) benefit for income taxes	(75,232		)	37,855			(146,768		)	31,833
Net income (loss)	$	242,464		$	(63,557	)	$	476,410		$	(63,088	)
Basic net income (loss) per share	$	0.65		$	(0.17	)	$	1.28		$	(0.17	)
Diluted net income (loss) per share	$	0.65		$	(0.17	)	$	1.27		$	(0.17	)
Income before income taxes													312,099			317,696			550,582			623,178
Provision for income taxes													(75,649		)	(75,232		)	(127,639		)	(146,768		)
Net income													236,450			242,464			422,943			476,410
Net loss attributable to noncontrolling interests													(107		)	—			(590		)	—
Net income attributable to Continental Resources													$	236,557		242,464			$	423,533		476,410

Comprehensive income (loss):
Net income (loss)	$	242,464		$	(63,557	)	$	476,410		$	(63,088	)
Net income per share attributable to Continental Resources:
Basic													$	0.63		$	0.65		$	1.14		$	1.28
Diluted													$	0.63		$	0.65		$	1.13		$	1.27

Comprehensive income:
Net income													$	236,450		$	242,464		$	422,943		$	476,410
Other comprehensive income, net of tax:
Foreign currency translation adjustments	16			189			18			327			30			16			146			18
Total other comprehensive income, net of tax	16			189			18			327			30			16			146			18
Comprehensive income (loss)	$	242,480		$	(63,368	)	$	476,428		$	(62,761	)
Comprehensive income													236,480			242,480			423,089			476,428
Comprehensive loss attributable to noncontrolling interests													(107		)	—			(590		)	—
Comprehensive income attributable to Continental Resources													$	236,587		$	242,480		$	423,679		$	476,428

Continental Resources, Inc. and Subsidiaries

Unaudited Condensed Consolidated ~~Statement~~Statements of ~~Shareholders’~~ Equity

In thousands, except share data Shares
outstanding Common
stock Additional
paid-in
capital Accumulated
other
comprehensive
income Retained
earnings Total
shareholders’
equity
Balance at December 31, 2017 375,219,769
$ 3,752
$ 1,409,326
$ 307
$ 3,717,818
$ 5,131,203
Net income (unaudited) —
—
—
—
476,410
476,410
Other comprehensive income, net of tax (unaudited) —
—
—
18
—
18
Stock-based compensation (unaudited) —
—
21,465
—
—
21,465
Restricted stock:
Granted (unaudited) 1,277,491
13
—
—
—
13
Repurchased and canceled (unaudited) (287,506 ) (3 ) (15,616 ) —
—
(15,619 )
Forfeited (unaudited) (178,957 ) (2 ) —
—
—
(2 )
Balance at June 30, 2018 (unaudited) 376,030,797
$ 3,760
$ 1,415,175
$ 325
$ 4,194,228
$ 5,613,488



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

Continental Resources, Inc. and Subsidiaries

Unaudited Condensed Consolidated Statements of Equity (Continued)



Three and six months ended June 30, 2018	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, 2017	375,219,769		$	3,752		$	1,409,326		$	307	$	—	$	3,717,818	$	5,131,203		$	—	$	5,131,203
Net income	—		—			—			—		—		233,946		233,946			—		233,946
Other comprehensive income, net of tax	—		—			—			2		—		—		2			—		2
Stock-based compensation	—		—			10,905			—		—		—		10,905			—		10,905
Restricted stock:
Granted	1,180,032		12			—			—		—		—		12			—		12
Repurchased and canceled	(276,108	)	(3		)	(14,843		)	—		—		—		(14,846		)	—		(14,846		)
Forfeited	(66,489	)	(1		)	—			—		—		—		(1		)	—		(1		)
Balance at March 31, 2018	376,057,204		$	3,760		$	1,405,388		$	309	$	—	$	3,951,764	$	5,361,221		$	—	$	5,361,221
Net income	—		—			—			—		—		242,464		242,464			—		242,464
Other comprehensive income, net of tax	—		—			—			16		—		—		16			—		16
Stock-based compensation	—		—			10,560			—		—		—		10,560			—		10,560
Restricted stock:
Granted	97,459		1			—			—		—		—		1			—		1
Repurchased and canceled	(11,398	)	—			(773		)	—		—		—		(773		)	—		(773		)
Forfeited	(112,468	)	(1		)	—			—		—		—		(1		)	—		(1		)
Balance at June 30, 2018	376,030,797		$	3,760		$	1,415,175		$	325	$	—	$	4,194,228	$	5,613,488		$	—	$	5,613,488

Continental Resources, Inc. and Subsidiaries

Unaudited Condensed Consolidated Statements of Cash Flows


	Six months ended June 30,						Six months ended June 30,
In thousands	2018			2017			2019			2018
Cash flows from operating activities
Net income (loss)	$	476,410		$	(63,088	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Net income							$	422,943		$	476,410
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion	902,217			774,810			983,183			902,217
Property impairments	62,946			174,689			46,655			62,946
Non-cash (gain) loss on derivatives, net	11,465			(68,420		)	(30,592		)	11,465
Stock-based compensation	21,478			20,571			24,283			21,478
Provision (benefit) for deferred income taxes	146,768			(31,834		)
Dry hole costs	1			157
(Gain) loss on sale of assets, net	(6,751		)	2,859
Provision for deferred income taxes							127,639			146,768
Gain (loss) on sale of assets, net							112			(6,751		)
Other, net	7,159			5,089			4,536			7,160
Changes in assets and liabilities:
Accounts receivable	(79,043		)	(19,347		)	(15,144		)	(79,043		)
Inventories	(17,904		)	14,984			(22,438		)	(17,904		)
Other current assets	(8,138		)	(2,225		)	(7,150		)	(8,138		)
Accounts payable trade	103,710			105,441			38,176			103,710
Revenues and royalties payable	5,857			21,105			(61,472		)	5,857
Accrued liabilities and other	17,550			(17,968		)	(5,732		)	17,550
Other noncurrent assets and liabilities	(3,732		)	(251		)	(95		)	(3,732		)
Net cash provided by operating activities	1,639,993			916,572			1,504,904			1,639,993

Cash flows from investing activities
Exploration and development	(1,334,681		)	(877,115		)	(1,528,022		)	(1,334,681		)
Purchase of producing crude oil and natural gas properties	(24,097		)	(812		)	(20,527		)	(24,097		)
Purchase of other property and equipment	(12,205		)	(9,372		)	(9,848		)	(12,205		)
Proceeds from sale of assets	27,380			7,979			652			27,380
Net cash used in investing activities	(1,343,603		)	(879,320		)	(1,557,745		)	(1,343,603		)

Cash flows from financing activities
Credit facility borrowings	803,000			540,000			245,000			803,000
Repayment of credit facility	(991,000		)	(565,000		)	(245,000		)	(991,000		)
Repayment of other debt	(1,134		)	(1,099		)	(1,162		)	(1,134		)
Debt issuance costs	(5,524		)	—			—			(5,524		)
Contributions from noncontrolling interests							75,717			—
Distributions to noncontrolling interests							(7,166		)	—
Repurchase of common stock							(69,661		)	—
Repurchase of restricted stock for tax withholdings	(15,619		)	(10,620		)	(21,184		)	(15,619		)
Net cash used in financing activities	(210,277		)	(36,719		)	(23,456		)	(210,277		)
Effect of exchange rate changes on cash	(26		)	14			30			(26		)
Net change in cash and cash equivalents	86,087			547			(76,267		)	86,087
Cash and cash equivalents at beginning of period	43,902			16,643			282,749			43,902
Cash and cash equivalents at end of period	$	129,989		$	17,190		$	206,482		$	129,989

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 ~~originally~~ formed in 1967 and is incorporated under the laws of the State of Oklahoma. The ~~Company's~~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.

A ~~substantial portion~~majority of the Company’s operations are located in the North region, with that region comprising ~~59%~~62% of the Company’s crude oil and natural gas production and 74% of its crude oil and natural gas revenues for the six months ended June 30, ~~2018.~~2019. The Company's principal producing properties in the North region are located in the Bakken field of North Dakota and Montana. ~~In recent years, the Company has significantly expanded its~~The Company's operations in the South region continue to expand with its increased activity in the SCOOP and STACK ~~plays. The South~~plays and that region comprised ~~41%~~38% of the Company's crude oil and natural gas production and 26% of its crude oil and natural gas revenues for the six months ended June 30, ~~2018.~~2019.

For the six months ended June 30, ~~2018,~~2019, crude oil accounted for ~~56%~~58% of the Company’s total production and ~~82%~~85% 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 ~~its subsidiaries, all of~~entities in which ~~are 100% owned, after all significant intercompany~~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 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, ~~2017~~2018 (“~~2017~~2018 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, ~~2018~~2019 and for the three and six month periods ended June 30, ~~2018~~2019 and ~~2017~~2018 are unaudited. The condensed consolidated balance sheet as of December 31, ~~2017~~2018 was derived from the audited balance sheet included in the ~~2017~~2018 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 ~~interim~~ 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 following

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

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

~~Continental Resources, Inc. and Subsidiaries~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

and six months ended June 30, ~~2018~~2019 and ~~2017.~~2018.



	Three months ended June 30,				Six months ended June 30,
In thousands, except per share data	2019		2018		2019		2018
Net income attributable to Continental Resources (numerator)	$	236,557	$	242,464	$	423,533	$	476,410
Weighted average shares (denominator):
Weighted average shares - basic	372,835		371,921		372,700		371,733
Non-vested restricted stock	1,174		2,584		1,857		2,850
Weighted average shares - diluted	374,009		374,505		374,557		374,583
Net income per share attributable to Continental Resources:
Basic	$	0.63	$	0.65	$	1.14	$	1.28
Diluted	$	0.63	$	0.65	$	1.13	$	1.27

Three months ended June 30, Six months ended June 30,
In thousands, except per share data 2018 2017 2018 2017
Net income (loss) (numerator) $ 242,464
$ (63,557 ) $ 476,410
$ (63,088 )
Weighted average shares (denominator):
Weighted average shares - basic 371,921
371,111
371,733
370,972
Non-vested restricted stock (1) 2,584
—
2,850
—
Weighted average shares - diluted 374,505
371,111
374,583
370,972
Net income (loss) per share:
Basic $ 0.65
$ (0.17 ) $ 1.28
$ (0.17 )
Diluted $ 0.65
$ (0.17 ) $ 1.27
$ (0.17 )


~~(1)~~	For the three and six months ended June 30, 2017, the Company had a net loss and therefore the potential dilutive effect of approximately 1,933,200 and 2,546,200 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 for those periods.

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 ~~market~~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, ~~2018~~2019 and December 31, ~~2017~~2018 consisted of the following:



In thousands	June 30, 2019		December 31, 2018
Tubular goods and equipment	$	15,774	$	14,623
Crude oil	95,120		73,921
Total	$	110,894	$	88,544

In thousands June 30, 2018 December 31, 2017
Tubular goods and equipment $ 18,722
$ 14,946
Crude oil 96,588
82,460
Total $ 115,310
$ 97,406

Adoption of new accounting ~~pronouncements~~pronouncement

~~Revenue recognition and presentation~~ ~~– In May 2014,~~On January 1, 2019 the ~~Financial Accounting Standards Board ("FASB") issued~~Company adopted Accounting Standards Update ("ASU") ~~2014-09,~~ ~~Revenue from Contracts with Customers~~2016-02, Leases (Topic ~~606)~~, which supersedes nearly all previously existing revenue recognition guidance under U.S. GAAP. Subsequently, the FASB issued additional guidance to assist entities with implementation efforts, including the issuance of ASU 2016-08, ~~Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net)~~842). ~~This new guidance became effective for reporting periods beginning after December 15, 2017. The Company adopted the new revenue recognition and presentation guidance on January 1, 2018 as required.~~ See Note ~~4. Revenues~~ 8. Leasesfor discussion of the adoption impact and the applicable disclosures required by the new guidance.

New accounting ~~pronouncements~~pronouncement not yet adopted

~~Leases~~ ~~– In February 2016, the FASB issued ASU 2016-02,~~ ~~Leases (Topic 842)~~, which requires companies to recognize a right of use asset and related liability on the balance sheet for the rights and obligations arising from leases with durations greater than 12 months. The standard is effective for interim and annual reporting periods beginning after December 15, 2018. The Company plans to adopt the new standard using the simplified transition method prescribed by ASU 2018-11, ~~Leases (Topic 842): Targeted Improvements~~, whereby the Company will initially apply the new standard as of the January 1, 2019 adoption date and will recognize a cumulative-effect adjustment to the opening balance of retained earnings, if any, upon adoption in lieu of retrospectively applying the new standard to pre-adoption periods.

The Company continues to evaluate the impact of ASU 2016-02 on its financial statements, accounting policies and internal controls and is in the process of implementing systems and processes to capture, classify, and account for leases within the scope of the new guidance and to comply with the related disclosure requirements. Interpretations and application of the new guidance continue to evolve and are being monitored for applicability and impact on the Company.

~~Continental Resources, Inc. and Subsidiaries~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

Based on an initial review of the new guidance and the Company’s current commitments, the Company anticipates it will be required to recognize lease assets and liabilities related to drilling rig commitments, certain equipment rentals and leases, certain surface use agreements, and potentially other arrangements. The Company does not believe any of its firm transportation agreements will qualify as leases, but continues to evaluate such arrangements.

Based on commitments in place as of June 30, 2018, the Company currently estimates its lease assets and liabilities to be recognized under ASU 2016-02 will total approximately $100 million, the majority of which will be comprised of future cash flows associated with drilling rig commitments, which are further discussed in ~~Note 8. Commitments and Contingencies–Drilling commitments~~. This estimate may be subsequently revised based on unforeseen changes in the nature, timing, and extent of the Company's contractual arrangements from period to period, finalization of the Company's evaluation of its firm transportation agreements, or due to changes in the Company's interpretation or application of the new guidance.

~~Credit losses~~ – In June 2016 the ~~FASB~~Financial Accounting Standards Board ("FASB") issued ASU 2016-13, Financial Instruments–Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments. This standard changes how entities will measure credit losses for most financial assets and certain other instruments that are not measured at fair value through net income. The standard will replace the currently required incurred loss approach with an expected loss model for instruments measured at amortized cost. The standard is effective for interim and annual periods beginning after December 15, 2019 and shall be applied using a modified retrospective approach resulting in a cumulative effect adjustment to retained earnings upon adoption. 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. Historically, the Company's credit losses on crude oil and natural gas sales receivables and joint interest receivables have been immaterial.

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	2019		2018
Supplemental cash flow information:
Cash paid for interest	$	132,064	$	122,940
Cash paid for income taxes	9		—
Cash received for income tax refunds	7		5
Non-cash investing activities:
Asset retirement obligation additions and revisions, net	5,266		3,562

Six months ended June 30,
In thousands 2018 2017
Supplemental cash flow information:
Cash paid for interest $ 122,940
$ 138,346
Cash paid for income taxes —
2
Cash received for income tax refunds 5
148
Non-cash investing activities:
Asset retirement obligation additions and revisions, net 3,562
3,771

As of June 30, ~~2018~~2019 and December 31, ~~2017,~~2018, the Company had ~~$317.5~~$297.8 million and ~~$302.8~~$317.5 million, respectively, of accrued capital expenditures included in “Net property and equipment” and “Accounts payable trade” in the condensed consolidated balance sheets.

As of June 30, 2019 and December 31, 2018, the Company had $10.8 million and $9.3 million, respectively, of accrued contributions from noncontrolling interests included in "Receivables–Joint interest and other, net" and "Equity–Noncontrolling interests" in the condensed consolidated balance sheets.

As of June 30, 2019 and December 31, 2018, the Company had $1.3 million and $1.3 million, respectively, of accrued distributions to noncontrolling interests included in "Revenues and royalties payable" and "Equity–Noncontrolling interests" in the condensed consolidated balance sheets.

On January 1, 2019 the Company adopted ASU 2016-02 which resulted in the non-cash recognition of offsetting right-of-use assets and lease liabilities totaling approximately $19 million. No significant additional right-of-use assets and lease liabilities have been recognized subsequent to January 1, 2019. See Note 8. Leases for additional information.

Note 4. Revenues

~~Adoption of new revenue recognition and disclosure guidance~~

~~In May 2014, the FASB issued ASU 2014-09,~~ ~~Revenue from Contracts with Customers (Topic 606)~~, which generally requires an entity to identify performance obligations in its contracts, estimate the amount of consideration to be received, allocate the consideration to each separate performance obligation, and recognize revenue as obligations are satisfied. Additionally, the standard requires expanded disclosures related to revenue recognition.

~~Subsequent to the issuance of ASU 2014-09, the FASB issued additional guidance to assist entities with implementation efforts, including the issuance of ASU 2016-08,~~ ~~Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net),~~ pertaining to the presentation of revenues on a gross basis (revenues presented separately from associated expenses) versus a net basis. This guidance requires an entity to record revenue on a gross basis if it controls a promised good or service before transferring it to a customer, whereas an entity records revenue on a net basis if its role is to arrange for another entity to provide the goods or services to a customer. Applying the guidance in ASU 2016-08 requires significant judgment in determining the point in time when control of products transfers to customers.

~~Continental Resources, Inc. and Subsidiaries~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

The Company adopted the new revenue recognition and presentation guidance on January 1, 2018 using a modified retrospective transition approach to all applicable contracts at the date of initial application, whereby the standard has been applied for periods commencing after December 31, 2017 and prior period results have not been adjusted to conform to current presentation. Adoption of the new guidance had no cumulative effect impact on the Company's retained earnings at January 1, 2018.

The new guidance does not have a material impact on the timing of the Company’s revenue recognition or its financial position, results of operations, net income, or cash flows, but does impact the Company's presentation of revenues and expenses under the gross-versus-net presentation guidance in ASU 2016-08. In years prior to 2018, the Company generally presented its revenues net of costs incurred to transport its production to market. Under the new guidance, revenues and transportation expenses associated with production originating from the Company’s operated properties are now reported on a gross basis as further discussed below. The changes from net to gross presentation resulted in an increase in revenues and a corresponding increase in separately reported transportation expenses, with no net effect on the Company’s results of operations, net income, or cash flows for the three and six months ended June 30, 2018.

~~The following table reflects the change in presentation of revenues and applicable expenses on the Company's 2018 results under the new and previous guidance.~~

Three months ended June 30, 2018 Six months ended June 30, 2018
In thousands New Standard Prior Presentation Change New Standard Prior Presentation Change
Revenues:
Crude oil and natural gas sales $ 1,137,528
$ 1,090,274
$ 47,254
$ 2,251,380
$ 2,154,829
$ 96,551
Loss on natural gas derivatives, net (12,685 ) (12,685 ) —
(2,511 ) (2,511 ) —
Crude oil and natural gas service operations 12,270
12,270
—
29,272
29,272
—
Total revenues $ 1,137,113
$ 1,089,859
$ 47,254
$ 2,278,141
$ 2,181,590
$ 96,551
Operating costs and expenses:

Transportation expenses $ 47,254
$ —
$ 47,254
$ 96,551
$ —
$ 96,551
Net income $ 242,464
$ 242,464
$ —
$ 476,410
$ 476,410
$ —

~~Revenue from contracts with customers~~

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 ~~and~~are presented separately from transportation expenses ~~are reported on a gross basis,~~ as the Company controls the operated production prior to its transfer to customers. Transportation expenses associated with the Company's operated crude oil production totaled $46.0 million and $40.2 million for the three months ended June 30, 2019 and 2018, respectively, and $87.6 million and $80.6 million for the ~~three and~~ six months ended June 30, 2019 and 2018, respectively.

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

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

Under certain arrangements, the Company ~~may elect~~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 ~~based on~~for the ~~customer's proceeds for~~ sale of ~~those~~the Company's operated natural gas production. The Company currently takes certain processed ~~products.~~residue gas volumes in kind in lieu of monetary settlement, but does not take NGL volumes. When the Company elects to ~~do so,~~take volumes in kind, it pays third parties to transport the processed products

~~Continental Resources, Inc. and Subsidiaries~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

~~which~~ it took in-kind to downstream delivery points, where it then sells ~~the products~~ 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$7.4 million and $7.0 million for the three months ended June 30, 2019 and 2018, respectively, and $14.9 million and $15.9 million for the ~~three and~~ six months ended June 30, 2019 and 2018, ~~respectively, comprised entirely of costs to transport processed residue gas.~~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.

~~Natural gas~~Revenues from derivative ~~revenues~~instruments – See Note 5. Derivative Instruments for discussion of the Company's accounting for its derivative instruments.

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

Disaggregation of crude oil and natural gas revenues

The following ~~table presents~~tables present the disaggregation of the Company's crude oil and natural gas revenues for the three and six months ended June 30, 2019 and 2018.



	Three months ended June 30, 2019						Three months ended June 30, 2018
In thousands	North Region		South Region		Total		North Region		South Region		Total
Crude oil revenues:
Operated properties	$	608,442	$	176,086	$	784,528	$	587,582	$	145,603	$	733,185
Non-operated properties	207,782		12,836		220,618		196,301		17,398		213,699
Total crude oil revenues	816,224		188,922		1,005,146		783,883		163,001		946,884
Natural gas revenues:
Operated properties	21,650		94,712		116,362		41,425		121,188		162,613
Non-operated properties	5,051		10,866		15,917		13,982		14,049		28,031
Total natural gas revenues	26,701		105,578		132,279		55,407		135,237		190,644
Crude oil and natural gas sales	$	842,925	$	294,500	$	1,137,425	$	839,290	$	298,238	$	1,137,528

Timing of revenue recognition
Goods transferred at a point in time	$	842,925	$	294,500	$	1,137,425	$	839,290	$	298,238	$	1,137,528
Goods transferred over time	—		—		—		—		—		—
	$	842,925	$	294,500	$	1,137,425	$	839,290	$	298,238	$	1,137,528

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

Three months ended June 30, 2018 Six months ended June 30, 2018
In thousands North Region South Region Total North Region South Region Total
Crude oil revenues:
Operated properties $ 587,582
$ 145,603
$ 733,185
$ 1,156,794
$ 284,056
$ 1,440,850
Non-operated properties 196,301
17,398
213,699
379,188
33,127
412,315
Total crude oil revenues 783,883
163,001
946,884
1,535,982
317,183
1,853,165
Natural gas revenues:
Operated properties 41,425
121,188
162,613
93,245
248,442
341,687
Non-operated properties 13,982
14,049
28,031
27,661
28,867
56,528
Total natural gas revenues 55,407
135,237
190,644
120,906
277,309
398,215
Crude oil and natural gas sales $ 839,290
$ 298,238
$ 1,137,528
$ 1,656,888
$ 594,492
$ 2,251,380

Timing of revenue recognition
Goods transferred at a point in time $ 839,290
$ 298,238
$ 1,137,528
$ 1,656,888
$ 594,492
$ 2,251,380
Goods transferred over time —
—
—
—
—
—
$ 839,290
$ 298,238
$ 1,137,528
$ 1,656,888
$ 594,492
$ 2,251,380



	Six months ended June 30, 2019						Six months ended June 30, 2018
In thousands	North Region		South Region		Total		North Region		South Region		Total
Crude oil revenues:
Operated properties	$	1,194,047	$	312,633	$	1,506,680	$	1,156,794	$	284,056	$	1,440,850
Non-operated properties	386,510		23,074		409,584		379,188		33,127		412,315
Total crude oil revenues	1,580,557		335,707		1,916,264		1,535,982		317,183		1,853,165
Natural gas revenues:
Operated properties	73,111		219,410		292,521		93,245		248,442		341,687
Non-operated properties	15,917		22,307		38,224		27,661		28,867		56,528
Total natural gas revenues	89,028		241,717		330,745		120,906		277,309		398,215
Crude oil and natural gas sales	$	1,669,585	$	577,424	$	2,247,009	$	1,656,888	$	594,492	$	2,251,380

Timing of revenue recognition
Goods transferred at a point in time	$	1,669,585	$	577,424	$	2,247,009	$	1,656,888	$	594,492	$	2,251,380
Goods transferred over time	—		—		—		—		—		—
	$	1,669,585	$	577,424	$	2,247,009	$	1,656,888	$	594,492	$	2,251,380

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. Upon delivery of production, the Company has a right to receive consideration from its customers in amounts ~~that correspond with~~determined by the ~~value of the production transferred.~~sales contracts.

All of the Company's outstanding crude oil sales contracts at June 30, ~~2018~~2019 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

~~Continental Resources, Inc. and Subsidiaries~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

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 ~~our~~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, net", 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, 2019 and 2018 related to performance obligations satisfied in prior reporting periods were not material.

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

Note 5. Derivative Instruments

Natural gas derivatives

From time to time the Company has entered into natural gas swap and collar derivative contracts to economically hedge against the variability in cash flows associated with future sales of natural gas production. ~~While the use of these derivative instruments limits the downside risk of adverse price movements, their use also limits future revenues from upward price movements.~~

The Company recognizes its ~~natural gas~~ derivative instruments on the balance sheet as either assets or liabilities measured at fair value. The Company has not designated its ~~natural gas~~ 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 natural gas derivatives, net”.

The Company's natural gas derivative contracts are settled based upon reported NYMEX Henry Hub settlement prices. The estimated fair value of derivatives is based upon various factors, including commodity exchange prices, over-the-counter quotations and, in the case of collars, volatility, the risk-free interest rate, and the time to expiration. The calculation of the fair value of collars requires the use of an option-pricing model. See Note 6. Fair Value Measurements.

With respect to a natural gas fixed price swap contract, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is less than the swap price, and the Company is required to make a payment to the counterparty if the settlement price for any settlement period is greater than the swap price. For a natural gas collar contract, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is below the floor price, and the Company is required to make a payment to the counterparty if the settlement price for any settlement period is above the ceiling price. Neither party is required to make a payment to the other party if the settlement price for any settlement period is between the floor price and the ceiling price.

~~Continental Resources, Inc. and Subsidiaries~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

At June 30, ~~2018~~2019 the Company had outstanding natural gas derivative contracts as set forth in the table below. The volumes reflected below represent an aggregation of multiple derivative contracts having similar remaining durations expected to be realized ratably over the ~~remainder of 2018.~~reflected period. At June 30, ~~2018~~2019 the Company had no outstanding crude oil derivative contracts.



		Swaps Weighted Average Price
Period and Type of Contract	MMBtus	Swaps Weighted Average Price
July 2019 - December 2019
Swaps - Henry Hub	106,168,000	$	2.80

Swaps Weighted Average Price
Period and Type of Contract MMBtus
July 2018 - December 2018
Swaps - Henry Hub 115,920,000
$ 2.88

Natural gas derivative gains and losses

Cash receipts and payments in the following table reflect the gain or loss on derivative contracts which matured during the 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 continue 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	2019		2018			2019			2018
Cash received on derivatives:
Natural gas fixed price swaps	$	8,670	$	4,758		$	16,315		$	8,954
Natural gas collars	—		—			5,417			—
Cash received on derivatives, net	8,670		4,758			21,732			8,954
Non-cash gain (loss) on derivatives:
Natural gas fixed price swaps	44,778		(17,443		)	36,074			(11,465		)
Natural gas collars	—		—			(5,482		)	—
Non-cash gain (loss) on derivatives, net	44,778		(17,443		)	30,592			(11,465		)
Gain (loss) on natural gas derivatives, net	$	53,448	$	(12,685	)	$	52,324		$	(2,511	)

Three months ended June 30, Six months ended June 30,
In thousands 2018 2017 2018 2017
Cash received (paid) on derivatives:
Natural gas fixed price swaps $ 4,758
$ 6,709
$ 8,954
$ 12,187
Natural gas collars —
(3,050 ) —
(9,456 )
Cash received (paid) on derivatives, net 4,758
3,659
8,954
2,731
Non-cash gain (loss) on derivatives:
Natural gas fixed price swaps (17,443 ) 12,520
(11,465 ) 35,416
Natural gas collars —
11,843
—
36,733
Non-cash gain (loss) on derivatives, net (17,443 ) 24,363
(11,465 ) 72,149
Gain (loss) on natural gas derivatives, net $ (12,685 ) $ 28,022
$ (2,511 ) $ 74,880

~~Diesel fuel derivatives~~

The Company previously entered into diesel fuel swap derivative contracts, all of which matured on or before December 31, 2017, to economically hedge against the variability in cash flows associated with purchases of diesel fuel for use in drilling activities. With respect to the diesel fuel swap contracts, the counterparty was required to make a payment to the Company if the settlement price for any settlement period was greater than the swap price, and the Company was required to make a payment to the counterparty if the settlement price for any settlement period was less than the swap price. The diesel fuel swap contracts were settled based upon reported NYMEX settlement prices for New York Harbor ultra-low sulfur diesel fuel.

The Company recognized its diesel fuel derivatives on the balance sheet as either assets or liabilities measured at fair value. The estimated fair value was based upon various factors, including commodity exchange prices, over-the-counter quotations, the risk-free interest rate, and time to expiration. The Company did not designate its diesel fuel derivatives as hedges for accounting purposes and, as a result, marked the derivative instruments to fair value and recognized the changes in fair value in the unaudited condensed consolidated statements of comprehensive income (loss) under the caption “Operating costs and expenses—~~Net (gain) loss on sale of assets and other.”~~

Cash receipts in the following table reflect gains on diesel fuel derivatives which matured during the 2017 period, calculated as the difference between the contract price and the market settlement price of matured contracts. Non-cash losses below represent the change in fair value of diesel fuel derivatives held at June 30, 2017 and the reversal of previously recognized non-cash gains or losses on derivative contracts that matured during the three and six months ended June 30, 2017.

Three months ended June 30, Six months ended June 30,
In thousands 2018 2017 2018 2017
Cash received on diesel fuel derivatives $ —
$ 185
$ —
$ 919
Non-cash loss on diesel fuel derivatives —
(1,098 ) —
(3,729 )
Loss on diesel fuel derivatives, net $ —
$ (913 ) $ —
$ (2,810 )

~~Continental Resources, Inc. and Subsidiaries~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

Balance sheet offsetting of derivative assets and liabilities

The Company’s derivative contracts are recorded at fair value in the condensed consolidated balance sheets under the captions “Derivative assets”, “Noncurrent derivative assets”, “Derivative liabilities”, and “Noncurrent derivative liabilities”, as

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

applicable. Derivative assets and liabilities with the same counterparty that are subject to contractual terms which provide for net settlement are reported on a net basis in the condensed consolidated balance sheets.

The following table presents the gross amounts of recognized natural gas ~~and diesel fuel~~ 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, 2018			December 31, 2017		June 30, 2019		December 31, 2018
Commodity derivative assets:
Gross amounts of recognized assets	$	885		$	2,603	$	46,204	$	16,789
Gross amounts offset on balance sheet	(682		)	—		—		(1,177		)
Net amounts of assets on balance sheet	203			2,603		46,204		15,612
Commodity derivative liabilities:
Gross amounts of recognized liabilities	(9,747		)	—		—		(1,177		)
Gross amounts offset on balance sheet	682			—		—		1,177
Net amounts of liabilities on balance sheet	$	(9,065	)	$	—	$	—	$	—

Note 6. Fair Value Measurements

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

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. The Company’s

~~Continental Resources, Inc. and Subsidiaries~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

policy is to recognize transfers between the hierarchy levels as of the beginning of the reporting period in which the event or change in circumstances caused the transfer.

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 tables summarize the valuation of financial instruments by pricing levels that were accounted for at fair value on a recurring basis as of June 30, ~~2018~~2019 and December 31, ~~2017.~~2018.

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~~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. The discounted cash flow method estimates future cash flows based on the ~~Company's~~Company’s estimates of future crude oil and natural gas production, commodity prices based on commodity futures price strips adjusted for differentials, operating costs, and a risk-adjusted discount rate. The fair value of proved crude oil and natural gas properties is calculated using significant unobservable inputs (Level 3). The following table sets forth quantitative information about the significant unobservable inputs used by the Company at June 30, 2019 to calculate the fair value of proved crude oil and natural gas properties using a discounted cash flow method.

~~Continental Resources, Inc. and Subsidiaries~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

Unobservable inputs to the fair value assessment are reviewed quarterly and are revised as warranted based on a number of factors, including reservoir performance, new drilling, crude oil and natural gas prices, changes in costs, technological

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

advances, new geological or geophysical data, or other economic factors. Fair value measurements of proved properties are reviewed and approved by certain members of the Company’s management.

For the three and six months ended June 30, 2019 and 2018, 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 those periods.

For the three and six months ended June 30, 2017, the Company determined the carrying amounts of certain proved properties were not recoverable from future cash flows, and therefore, were impaired. Impairments of proved properties totaled $81.5 million and $82.3 million for the three and six months ended June 30, 2017, respectively. The 2017 impairments reflected fair value adjustments primarily concentrated in the Arkoma Woodford field ($81.2 million, all in the second quarter of 2017) and various non-core areas in the North and South regions ($1.1 million, including $0.3 million in the second quarter of 2017). The impaired properties were written down to their estimated fair value at the time of impairment of approximately $72 million.

Certain unproved crude oil and natural gas properties were impaired during the three and six months ended June 30, ~~2018~~2019 and ~~2017,~~2018, 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).~~income.



	Three months ended June 30,				Six months ended June 30,
In thousands	2019		2018		2019		2018
Proved property impairments	$	—	$	—	$	—	$	—
Unproved property impairments	21,339		29,162		46,655		62,946
Total	$	21,339	$	29,162	$	46,655	$	62,946

Three months ended June 30, Six months ended June 30,
In thousands 2018 2017 2018 2017
Proved property impairments $ —
$ 81,469
$ —
$ 82,340
Unproved property impairments 29,162
41,847
62,946
92,349
Total $ 29,162
$ 123,316
$ 62,946
$ 174,689

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.

~~(1) As discussed in~~ ~~Note 12. Subsequent Events, on July 12, 2018 the Company announced it will redeem $400 million, or 20%, of its outstanding $2.0 billion of 5% Senior Notes due 2022 on August 16, 2018.~~

The fair value of revolving credit facility borrowings at December 31, 2017 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.



	June 30, 2019				December 31, 2018
In thousands	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Debt:
Credit facility	$	—	$	—	$	—	$	—
Note payable	6,535		6,600		7,700		7,700
5% Senior Notes due 2022	1,598,590		1,613,800		1,598,404		1,590,900
4.5% Senior Notes due 2023	1,490,126		1,572,800		1,488,960		1,476,300
3.8% Senior Notes due 2024	993,724		1,028,400		993,151		947,200
4.375% Senior Notes due 2028	989,137		1,052,900		988,617		942,800
4.9% Senior Notes due 2044	691,601		738,300		691,517		618,800
Total debt	$	5,769,713	$	6,012,800	$	5,768,349	$	5,583,700

The fair value of the note payable is determined using a discounted cash flow approach based on the interest rate and payment terms of the note payable and an assumed discount rate. The fair value of the note payable is significantly influenced

~~Continental Resources, Inc. and Subsidiaries~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

by the discount rate assumption, which is derived by the Company and is unobservable. Accordingly, the fair value of the note payable is classified as Level 3 in the fair value hierarchy.

The fair values of the 5% Senior Notes due 2022 (“2022 Notes”), the 4.5% Senior Notes due 2023 (“2023 Notes”), the 3.8% Senior Notes due 2024 (“2024 Notes”), the 4.375% Senior Notes due 2028 (“2028 Notes”), 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 7. Long-Term Debt

Long-term debt, net of unamortized discounts, premiums, and debt issuance costs totaling ~~$42.3~~$36.9 million and ~~$44.3~~$39.4 million at June 30, ~~2018~~2019 and December 31, ~~2017,~~2018, respectively, consists of the following.



In thousands	June 30, 2019		December 31, 2018
Credit facility	$	—	$	—
Note payable	6,535		7,700
5% Senior Notes due 2022	1,598,590		1,598,404
4.5% Senior Notes due 2023	1,490,126		1,488,960
3.8% Senior Notes due 2024	993,724		993,151
4.375% Senior Notes due 2028	989,137		988,617
4.9% Senior Notes due 2044	691,601		691,517
Total debt	$	5,769,713	$	5,768,349
Less: Current portion of long-term debt	2,397		2,360
Long-term debt, net of current portion	$	5,767,316	$	5,765,989

In thousands June 30, 2018 December 31, 2017
Revolving credit facility $ —
$ 188,000
Note payable 8,845
9,974
5% Senior Notes due 2022 (1) 1,997,782
1,997,576
4.5% Senior Notes due 2023 1,487,803
1,486,690
3.8% Senior Notes due 2024 992,588
992,036
4.375% Senior Notes due 2028 988,090
988,061
4.9% Senior Notes due 2044 691,435
691,354
Total debt $ 6,166,543
$ 6,353,691
Less: Current portion of long-term debt 2,322
2,286
Long-term debt, net of current portion $ 6,164,221
$ 6,351,405

~~Revolving~~ Credit Facility

~~On April 9, 2018, the~~The Company ~~entered into a new~~has an unsecured ~~revolving~~ credit facility, maturing on April 9, 2023, with aggregate lender commitments totaling $1.5 billion, which may be increased up to a total of $4.0 billion upon agreement between the Company and participating lenders. In connection with the execution of the new credit facility, the Company terminated its then-existing $2.75 billion credit facility that was due to mature in May 2019.$1.50 billion. The Company had no outstanding borrowings on its credit facility at June 30, 2019 and December 31, 2018.

Borrowings under the credit facility, if any, bear interest at market-based interest rates plus a margin based on the terms of the borrowing and the credit ratings assigned to the Company's senior, unsecured, long-term indebtedness. The Company incurs commitment fees based on currently assigned credit ratings of 0.20% per annum on the daily average amount of unused borrowing ~~availability under its credit facility.~~availability.

The ~~Company's new~~ credit facility ~~retains substantially the same~~contains certain restrictive covenants ~~as the previous credit facility,~~ 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, ~~2018.~~

~~Continental Resources, Inc. and Subsidiaries~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

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, ~~2018.~~2019.

The Company has the option to redeem all or a portion of its remaining 2022 Notes at the decreasing redemption prices specified in the indenture related to the 2022 Notes plus any accrued and unpaid interest to the date of redemption. ~~See~~ ~~Note 12. Subsequent Events~~.

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

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

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

certain assets. The senior note covenants are subject to a number of important exceptions and qualifications. The Company was in compliance with these covenants at June 30, ~~2018.~~ 2019.

Three of the Company’s wholly-owned subsidiaries, Banner Pipeline Company, L.L.C., CLR Asset Holdings, LLC, and The Mineral Resources Company, ~~which have no material~~the value of whose assets, orequity, and results of operations are minor, fully and unconditionally guarantee the senior notes on a joint and several basis. The Company’s other subsidiaries, the value of whose assets, equity, and results of operations attributable to the Company are minor, do not guarantee the senior notes.

In February 2012, 20 Broadway Associates LLC, a ~~100% owned~~wholly-owned subsidiary of the Company, borrowed $22 million under a 10-year amortizing term loan secured by the Company’s corporate office building in Oklahoma City, Oklahoma. The loan bears interest at a fixed rate of 3.14% per annum. Principal and interest are payable monthly through the loan’s maturity date of February 26, ~~2022.~~2022. Accordingly, approximately ~~$2.3~~$2.4 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, ~~2018.~~2019.

In February 2016 the FASB issued ASU 2016-02, Leases (Topic 842), which requires companies to recognize a right-of-use asset and related liability on the balance sheet for the rights and obligations arising from leases with durations greater than twelve months. The standard became effective for interim and annual reporting periods beginning after December 15, 2018. The Company adopted the new standard on January 1, 2019 on a prospective basis using the simplified transition method prescribed by ASU 2018-11, Leases (Topic 842): Targeted Improvements. Offsetting right-of-use assets and lease liabilities recognized by the Company on the January 1, 2019 adoption date totaled approximately $19 million, representing minimum payment obligations associated with drilling rig commitments, surface use agreements, equipment, and other leases with contractual durations in excess of one year. No cumulative-effect adjustment to retained earnings was recognized upon adoption of the new standard.

The Company has elected to account for lease and non-lease components in its contracts as a single lease component for all asset classes. Additionally, the Company has elected not to apply the recognition requirements of ASC Topic 842 to leases with durations of twelve months or less and has elected to use hindsight in determining the lease term for all leases. The Company's leasing activities as a lessor are negligible.

Presented below are disclosures required by the new lease standard. 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 lease liabilities recognized on the balance sheet as a lessee totaled $13.0 million as of June 30, 2019 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.



In thousands	Amount
Drilling rig commitments	$	7,570
Surface use agreements	3,753
Field equipment	1,311
Other	363
Total	$	12,997

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.

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

Minimum future commitments by year for the Company's operating leases as of June 30, 2019 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.

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



In thousands, except weighted average data	Three months ended June 30, 2019		Six months ended June 30, 2019
Lease costs:
Operating lease costs	$	3,273	$	6,546
Variable lease costs	4,691		7,813
Short-term lease costs	39,517		94,678
Total lease costs	$	47,481	$	109,037

Other information:
Operating cash flows from operating leases included in lease liabilities	$	199	$	398
Weighted average remaining lease term as of June 30, 2019 (in years)			6.8
Weighted average discount rate as of June 30, 2019			4.7		%

Note 8.9. Commitments and Contingencies

Included below is a discussion of ~~various~~certain future commitments and contingencies of the Company as of June 30, ~~2018. The~~2019.

Drilling rig commitments ~~under these arrangements are not recorded in the accompanying condensed consolidated balance sheets.~~

~~Drilling commitments~~ – As of June 30, ~~2018,~~2019, the Company has drilling rig contracts with various terms extending to ~~June 2021~~May 2020 to ensure rig availability in its key operating areas. Future operating day-rate commitments as of June 30, ~~2018~~2019 total approximately ~~$97~~$67 million, of which ~~$42~~$56 million is expected to be incurred in the remainder of ~~2018, $41~~2019 and $11 million in 2020. 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 $7.6 million that are required to be recognized on the Company's balance sheet at June 30, 2019 ~~$10 million~~ in ~~2020,~~accordance with ASC Topic 842 as discussed in Note 8. Leases.

Other lease commitments – The Company has various other lease commitments primarily associated with surface use agreements and ~~$4 million in 2021.~~field equipment. See Note 8. 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 2028, 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, ~~2018~~ 2019

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

under the arrangements amount to approximately ~~$1.36~~$2.28 billion, of which ~~$112~~$131 million is expected to be incurred in the remainder of ~~2018,$225 million in~~ 2019, ~~$194~~$282 million in 2020, ~~$175~~$327 million in 2021, ~~$168~~$323 million in 2022, $325 million in 2023, and ~~$487~~$889 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.

Dividend declaration – See Note 11. Shareholders' Equity for discussion of the Company's dividend payment obligation as of June 30, 2019.

Litigation – In November 2010, a putative class action was filed in the District Court of Blaine County, Oklahoma by Billy J. Strack and Daniela A. Renner as trustees of certain named trusts and on behalf of other similarly situated parties against

~~Continental Resources, Inc. and Subsidiaries~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

the Company. The Petition, as amended, alleged the Company improperly deducted post-production costs from royalties paid to plaintiffs and other royalty interest owners from crude oil and natural gas wells located in Oklahoma. The plaintiffs alleged a number of claims, including breach of contract, fraud, breach of fiduciary duty, unjust enrichment, and other claims and sought recovery of compensatory damages, interest, punitive damages and attorney fees on behalf of the proposed class. The Company denied all allegations and denied that the case was properly brought as a class action. On June 11, 2015, the trial court certified a “hybrid” class requested by plaintiffs over the objections of the Company. The Company appealed the trial court’s class certification order. On February 8, 2017, the Oklahoma Court of Civil Appeals reversed the trial court’s ruling on certification and remanded the case for further proceedings. The plaintiffs filed a Petition for Rehearing which was denied by the Oklahoma Court of Civil Appeals. Plaintiffs then filed a Petition for Writ of Certiorari on May 23, 2017 to the Oklahoma Supreme Court, which was denied on October 2, 2017. On October 10, 2017, Plaintiffs filed with the trial court a “Second Amended and Renewed Motion for Class Action Certification and Request that the Court to Set a Briefing Schedule Related to Class Certification.” During the litigation the Company was not able to estimate a reasonably possible loss or range of loss or what impact, if any, the ultimate resolution of the action would have on its financial condition, results of operations or cash flows due to the preliminary status of the matter, the complexity and number of legal and factual issues presented by the matter and uncertainties with respect to, among other things, the nature of the claims and defenses, the existence and the potential size of the class, the scope and types of the properties and agreements involved, the production years involved, and the ultimate potential outcome of the matter. The Company further disclosed that it was reasonably possible one or more events could occur in the near term that could impact the Company’s ability to estimate the potential effect of this matter if any, on its financial condition, results of operations or cash flows. During the litigation the Company also disclosed plaintiffs alleged underpayments in excess of $200 million as damages, which may increase with the passage of time, a majority of which would be comprised of interest. After certification of the case as a class action was reversed the parties continued settlement negotiations. Due to the uncertainty of and burdens of litigation, onin February ~~16,~~ 2018 the Company reached a settlement in connection with this ~~matter.~~matter, which was subsequently approved by the District Court of Garfield County, Oklahoma in June 2018. Under the settlement, the Company initially expected to make payments and incur costs associated with the settlement of approximately $59.6 million. ~~The Company~~ and accrued a loss for such amount at December 31, ~~2017, which was subsequently increased~~2017. In the third quarter of 2018, the Company made payments totaling $45.8 million to ~~$61.7~~satisfy the majority of its obligations under the settlement. The Company's remaining loss accrual for this matter totals $15.7 million at June 30, ~~2018 to reflect~~2019, representing additional settlement obligations ~~resulting from~~expected to be substantially satisfied in the ~~passage~~third quarter of ~~time. Such~~2019. The accrual for this matter is included in “Accrued liabilities and other” on the condensed consolidated balance sheets. On April 3, 2018, the District Court of Garfield County, Oklahoma preliminarily approved the settlement and set certain dates applicable to the settlement including the timing and content of Notice, Opt-out, and Objections to Class Members. The Fairness Hearing was held on June 11, 2018. On June 12, 2018, the court entered an order formally approving the settlement. The order approving the settlement is not subject to appeal. On June 20, 2018, the court entered an order approving Plaintiff Counsels’ request for Attorney Fees and Expenses. The deadline for an appeal of the order approving Attorney Fees and Expenses is August 13, 2018. In accordance with the settlement terms, the Company expects to make payments totaling approximately $50 million in the third quarter of 2018 and expects to satisfy the remainder of its settlement obligations in 2019.

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. In addition to the accrued loss on the matter described above, as of June 30, ~~2018~~2019 and December 31, ~~2017~~2018 the Company had recorded a liability in the condensed consolidated balance sheets under the caption “Other noncurrent liabilities” of ~~$4.7~~$5.7 million and ~~$7.6~~$4.7 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 9.10. Stock-Based Compensation

The Company has granted restricted stock to employees and directors pursuant to the Continental Resources, Inc. 2013 Long-Term Incentive Plan ("2013 Plan") as discussed below. 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 ~~$10.6~~$12.2 million and ~~$9.1~~$10.6 million for the three months ended June 30, ~~2018~~2019 and ~~2017,~~2018, respectively, and ~~$21.5~~$24.3 million and ~~$20.6~~$21.5 million for the six months ended June 30, ~~2018~~2019 and ~~2017,~~2018, respectively.

In May 2013, the Company adopted the 2013 Plan and reserved 19,680,072 shares of common stock that may be issued pursuant to the plan. As of June 30, ~~2018,~~2019, the Company had ~~13,727,512~~13,014,761 shares of common stock available for long-term incentive awards to employees and directors under the 2013 Plan.

~~Continental Resources, Inc. and Subsidiaries~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

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 under the Company's dividend payment program discussed in Note 11. Shareholders' Equity, subject to forfeiture. Restricted stock grants generally vest over periods ranging from ~~one~~1 to ~~three~~3 years.

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

A summary of changes in non-vested restricted shares outstanding for the six months ended June 30, ~~2018~~2019 is presented below.

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, ~~2018~~2019 was approximately ~~$57.0~~$77 million. As of June 30, ~~2018,~~2019, there was approximately ~~$94~~$95 million of unrecognized compensation expense related to non-vested restricted stock. This expense is expected to be recognized over a weighted average period of ~~1.5~~1.7 years.

Note ~~10. Accumulated Other Comprehensive Income (Loss)~~11. Shareholders' Equity

~~Adjustments resulting~~Share repurchase program

In May 2019 the Company's Board of Directors approved the initiation of a share repurchase program to acquire up to $1 billion of the Company's common stock beginning in June 2019 and expected to continue through 2020. As of June 30, 2019, the Company had repurchased and retired 1,800,000 shares under the program at an aggregate cost of $69.7 million.

Under the program, the Company may repurchase shares from time to time at management's discretion in accordance with applicable securities laws, including through open market transactions, privately negotiated transactions or any combination thereof. In addition, shares may also be repurchased pursuant to a trading plan meeting the ~~process~~requirements of ~~translating foreign functional currency financial statements into U.S. dollars~~Rule 10b5-1 under the Securities Exchange Act of 1934. The timing and amount of repurchases are subject to market conditions. 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 declaration

In May 2019 the Company's Board of Directors approved the initiation of a dividend payment program and on June 3, 2019 the Company announced a quarterly cash dividend of $0.05 per share on the Company's outstanding common stock, payable on November 21, 2019 to shareholders of record on November 7, 2019. At June 30, 2019 the Company recognized an $18.7 million liability associated with its dividend declaration which is included in ~~“Accumulated other comprehensive income (loss)” within shareholders’ equity~~"Dividends payable" and "Equity–Retained Earnings" in the condensed consolidated balance sheets and “Other comprehensive income, net of tax” in the unaudited condensed consolidated statements of comprehensive income (loss). The following table summarizes the change in accumulated other comprehensive income (loss) for the three and six months ended June 30, 2018 and 2017:

Three months ended June 30, Six months ended June 30,
In thousands 2018 2017 2018 2017
Beginning accumulated other comprehensive income (loss), net of tax $ 309
$ (122 ) $ 307
$ (260 )
Foreign currency translation adjustments 16
189
18
327
Income taxes (1) —
—
—
—
Other comprehensive income, net of tax 16
189
18
327
Ending accumulated other comprehensive income, net of tax $ 325
$ 67
$ 325
$ 67

Note ~~11.~~12. 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. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized.

The Company's ~~(provision) benefit~~provision for income taxes ~~totaled ($75.2) million~~ and ~~$37.9 million~~resulting effective tax rates were as follows for the ~~three months ended June 30, 2018 and 2017, respectively. The Company's (provision) benefit for income taxes totaled ($146.8) million and~~periods presented.



	Three months ended June 30,						Six months ended June 30,
	2019			2018			2019			2018
Provision for income taxes (in thousands)	$	75,649		$	75,232		$	127,639		$	146,768
Effective tax rate	24.2		%	23.7		%	23.2		%	23.6		%

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

~~$31.8 million~~The Company computes its quarterly income tax provision under the effective tax rate method based on applying an anticipated annual effective tax rate to year-to-date pre-tax income, except for discrete items. Income taxes for discrete items are computed and recorded in the ~~six months ended June 30, 2018 and 2017, respectively. These amounts differ~~period in which the specific transaction occurs.

The Company's effective tax rate differs from ~~the amounts computed by applying~~ the United States ~~statutory~~ federal ~~income~~statutory tax rate due to ~~net~~the effect of state income ~~before income taxes. The sources~~taxes, equity compensation, and other tax ~~effects of the differences are~~items as reflected in the table ~~below:~~below.



	Three months ended June 30,						Six months ended June 30,
In thousands, except tax rates	2019			2018			2019			2018
Income before income taxes	$	312,099		$	317,696		$	550,582		$	623,178
U.S. federal statutory tax rate	21.0		%	21.0		%	21.0		%	21.0		%
Expected income tax provision based on U.S. federal statutory tax rate	65,541			66,716			115,622			130,867
Items impacting the effective tax rate:
State and local income taxes, net of federal benefit	11,538			9,531			19,337			18,695
Equity compensation	102			(359		)	(8,216		)	(1,868		)
Other, net	(1,532		)	(656		)	896			(926		)
Provision for income taxes	$	75,649		$	75,232		$	127,639		$	146,768
Effective tax rate	24.2		%	23.7		%	23.2		%	23.6		%

Three months ended June 30, Six months ended June 30,
$ in thousands 2018 Tax rate % 2017 Tax rate % 2018 Tax rate % 2017 Tax rate %
Expected income tax (provision) benefit based on US statutory tax rate (1) $ (66,716 ) 21 % $ 35,494
35 % $ (130,867 ) 21 % $ 33,222
35 %
State income taxes, net of federal benefit (9,531 ) 3 % 3,043
3 % (18,695 ) 3 % 2,848
3 %
Tax benefit (deficiency) from stock-based compensation 359
— % (473 ) (1 %) 1,868
— % (3,773 ) (4 %)
Canadian valuation allowance (2) (78 ) — % (112 ) — % (148 ) — % (257 ) — %
Other, net 734
— % (97 ) — % 1,074
— % (207 ) — %
(Provision) benefit for income taxes $ (75,232 ) 24 % $ 37,855
37 % $ (146,768 ) 24 % $ 31,833
34 %

Note ~~12.~~13. Subsequent ~~Events~~

~~Partial redemption of senior notes~~Event

On July ~~12, 2018,~~18, 2019 the Company ~~announced it will redeem $400 million, or 20%,~~sold certain water gathering, recycling, and disposal assets in the STACK play for proceeds of ~~its outstanding $2.0 billion of 5% Senior Notes due 2022 on August 16, 2018.~~$85.3 million. The ~~redemption price will be equal to 101.667%~~disposed assets represented an immaterial portion of the ~~principal amount called for redemption plus accrued~~Company’s assets and ~~unpaid interest to the redemption date in accordance with the terms of the 2022 Notes and the related indenture under which the 2022 Notes were issued.~~

The aggregate of the principal amount, redemption premium, and accrued interest payable upon partial redemption of the 2022 Notes is expected to total approximately $415 million. The Company expects to record a pre-tax loss on extinguishment of debt related to the partial redemption of approximately $7 million, which will be reflected in third quarter 2018operating results.

~~Formation of strategic relationship~~

On August 6, 2018, the Company executed definitive documents to form a strategic relationship with Franco-Nevada, subject to customary closing conditions, to acquire minerals in the SCOOP and STACK plays, primarily in areas operated by the Company. In accordance with the deal terms, Franco-Nevada has agreed to pay approximately $220 million for a stake in a newly-formed minerals subsidiary. The Company expects to receive the proceeds at closing in the fourth quarter of 2018. The amount to be received by the Company is subject to adjustment under the terms of the transaction documents.

In addition, the parties have also committed, subject to satisfaction of agreed upon development thresholds, to spend up to a combined $125 million per year over the next three years to acquire additional minerals through the newly-formed subsidiary. With a carry component on capital acquisition costs, the Company is to fund 20% of future mineral acquisitions. The Company will be entitled to receive between 25% and 50% of total revenues generated by the minerals subsidiary based upon performance relative to certain predetermined targets.

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 ~~Annual Report on~~ Form 10-K for the year ended December 31, ~~2017.~~2018. Our operating results for the periods discussed below may not be indicative of future performance. 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 ~~Annual Report on~~ Form 10-K for the year ended December 31, ~~2017,~~2018, along with Cautionary Statement for the Purpose of the “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995 at the beginning of this report, for information about the risks and uncertainties that could cause our actual results to be materially different than our forward-looking statements.

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.

Second Quarter 2019 Highlights

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

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, 2019 compared to the three months ended June 30, 2018

Results of Operations

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

The following table summarizes the changes in our average daily Boe production by major operating area for the periods presented.

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

The 23% increase in crude oil production for the 2019 second quarter was primarily driven by a 2,454 MBbls, or 22%, increase in Bakken production due to additional wells being completed. Additionally, crude oil production from the SCOOP play increased 786 MBbls, or 48%, from the prior year second quarter due to new well completions in our oil-weighted Project SpringBoard, while crude oil production in the STACK play increased 99 MBbls, or 12%, from new well completions. These increases were partially offset by decreased crude oil production from various other areas due to natural declines in production.

The 9% increase in natural gas production for the 2019 second quarter was driven by a 4,874 MMcf, or 25%, increase in Bakken gas production in conjunction with the aforementioned increase in Bakken crude oil production over the prior year second quarter. Additionally, natural gas production in the STACK play increased 2,401 MMcf, or 10%, due to additional wells being completed. These increases were partially offset by reduced production from various other areas due to natural declines in production.

Our revenues consist of sales of crude oil and natural gas, gains and losses resulting from changes in the fair value of our natural gas derivative instruments, and revenues associated with crude oil and natural gas service operations.

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

Net crude oil and natural gas sales. Net crude oil and natural gas sales totaled $1.08 billion for the second quarter of 2019,consistent with net sales of $1.09 billion for the 2018 second quarterdue to offsetting changes in sales volumes and net sales prices as discussed below.

Total sales volumes for the second quarter of 2019 increased 4,228 MBoe, or 16%, compared to the 2018 second quarter, reflecting an increase in drilling and completion activities over the past year. For the second quarter of 2019, our crude oil sales volumes increased 23% from the comparable 2018 period, while our natural gas sales volumes increased 9%.

Our crude oil net sales prices averaged $54.66 per barrel in the 2019 second quarter, a decrease of 14% compared to $63.35 per barrel for the 2018 second quarter primarily due to lower crude oil market prices. The differential between NYMEX West Texas Intermediate ("WTI") calendar month prices and our realized crude oil net sales prices averaged $5.11 per barrel for the 2019 second quarter compared to $4.55 per barrel for the 2018 second quarter, reflecting changes in supply and demand fundamentals over the past year that created volatility in our price realizations between periods.

Our natural gas net sales prices averaged $1.66 per Mcf for the 2019 second quarter, a decrease of 37% compared to $2.65 per Mcf for the 2018 second quarter. The discount between our net sales prices and NYMEX Henry Hub calendar month prices weakened by $0.83 per Mcf compared to the 2018 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 2019 have decreased significantly compared to 2018 second quarter 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.

Derivatives. Changes in natural gas market prices during the second quarter of 2019 had a favorable impact on the fair value of our natural gas derivatives, which resulted in positive revenue adjustments of $53.4 million in the current period compared to negative revenue adjustments of $12.7 million in the comparable 2018 period.

Crude oil and natural gas service operations. Revenues associated with our crude oil and natural gas service operations increased $5.2 million, or 43%, from $12.3 million for the 2018 second quarter to $17.5 million for the 2019 second quarter due to an increase in the magnitude of water handling and recycling activities compared to the prior period. The increased activities also resulted in higher service-related expenses compared to the prior period.

Operating Costs and Expenses

Production Expenses. Production expenses increased $22.2 million, or 25%, from $90.2 million for the second quarter of 2018 to $112.4 million for the second quarter of 2019 primarily due to an increase in the number of producing wells and related 16% increase in sales volumes. Production expenses on a per-Boe basis averaged $3.74 for the 2019 second quarter compared to $3.49 per Boe recognized for the 2018 second quarter.

Production Taxes. Production taxes increased $10.3 million, or 12%, to $93.9 million for the second quarter of 2019 compared to $83.6 million for the second quarter of 2018, despite flat revenues, due in part to an increase in the proportion of our production and revenues being generated in North Dakota over the past year from increased oil-weighted drilling and completion activities. North Dakota has higher crude oil production tax rates compared to Oklahoma. Additionally, production

taxes for natural gas revenues in North Dakota are based on a per-unit rate applied to the quantity of volumes sold whereas in Oklahoma such production taxes are based on a percentage applied to the wellhead value of sales. These factors caused our production taxes as a percentage of net crude oil and natural gas sales to increase from 7.7% for the second quarter of 2018 to 8.7% for the second quarter of 2019. Additionally, in March 2018 new legislation was enacted in Oklahoma that increased the state's production tax rate, effective July 1, 2018, from 2% to 5% for the first 36 months of production for wells commencing production after July 1, 2015, which also contributed to the increase in our average production tax rate compared to the prior year second quarter.

Depreciation, Depletion, Amortization and Accretion. Total DD&A increased $38.4 million, or 9%, to $485.6 million for thesecond quarter of 2019 compared to $447.2 million for the second quarter of 2018 due to an increase in total sales volumes, the impact of which was partially offset by a reduction in our DD&A rate per Boe as further discussed below. The following table shows the components of our DD&A on a unit of sales basis for the periods presented.

The reduction in our DD&A rate for crude oil and natural gas properties resulted from an increase in proved developed reserves over which costs are depleted, along with improvements in drilling efficiencies and completion methods that have resulted in an increase in the quantity of proved reserves found and developed per dollar invested.

Property Impairments. There were no proved property impairments recognized in the second quarter periods of 2019 and 2018. Impairments of unproved properties decreased $7.9 million, or 27%, to $21.3 million for the 2019 second quarter compared to $29.2 million for the 2018 second quarter due to a reduction in the balance of unamortized leasehold costs over the past year.

General and Administrative Expenses. G&A expenses totaled $47.2 million for the second quarter of 2019, consistent with $47.2 million for the second quarter of 2018. Total G&A expenses include non-cash charges for equity compensation of $12.2 million and $10.6 million for the second quarters of 2019 and 2018, respectively. G&A expenses other than equity compensation included in the total G&A expense figure above totaled $35.0 million for the 2019 second quarter, a decrease of$1.6 million, or 4%, compared to $36.6 million for the 2018 second quarter due to higher overhead recoveries from joint interest owners driven by increased drilling and completion activities.

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

The decrease in total G&A expenses on a per-Boe basis was driven by a 16% increase in total sales volumes from new well completions with no comparable increase in G&A expenses.

Interest Expense. Interest expense decreased $5.8 million, or 8%, to $68.5 million for the second quarter of 2019 compared to $74.3 million for the second quarter of 2018 due to a decrease in total outstanding debt. Our weighted average outstanding debt balance was $5.8 billion for the 2019 second quarter compared to $6.3 billion for the 2018 second quarter.

Income Taxes. For the second quarters of 2019 and 2018 we provided for income taxes at a combined federal and state tax rate of 24.5% and 24.0%, respectively, of pre-tax income generated by our operations in the United States. We recorded income tax provisions of $75.6 million and $75.2 million for the second quarters of 2019 and 2018, respectively, which resulted in effective tax rates of 24.2% and 23.7%, respectively, after taking into account statutory tax rates, permanent taxable differences, tax effects from equity compensation, and other items. See Notes to Unaudited Condensed Consolidated Financial Statements–Note ~~4. Revenues,~~ ~~we adopted new revenue recognition~~12. Income Taxes for a summary of the sources and ~~presentation rules on January 1, 2018. The new rules did not have a material impact on~~tax effects of items comprising our effective tax rates.

Six months ended June 30, 2019 compared to the ~~timing of our revenue recognition or our financial position, results of operations, net income, or cash flows for the three and~~ six months ended June 30, 2018 ~~but did~~

Results of Operations

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

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

The 21% increase in crude oil production for year to date 2019 was primarily driven by a 4,973 MBbls, or 22%, increase in Bakken production due to additional wells being completed. Additionally, crude oil production from the SCOOP play increased 1,331 MBbls, or 43%, from the prior year period due to new well completions in our oil-weighted Project SpringBoard. These increases were partially offset by decreased crude oil production from various other areas due to natural declines in production.

The 10% increase in natural gas production for year to date 2019 was primarily driven by a 10,319 MMcf, or 27%, increase in Bakken gas production in conjunction with the aforementioned increase in Bakken crude oil production over the prior year period. Additionally, natural gas production in the STACK play increased 5,671 MMcf, or 12%, due to additional wells being completed. These increases were partially offset by reduced production from various other areas due to natural declines in production.

Net crude oil and natural gas sales. Net crude oil and natural gas sales for year to date 2019 totaled $2.14 billion, consistent with net sales of $2.15 billion for the comparable 2018 period due to offsetting changes in sales volumes and net sales prices as discussed below.

Total sales volumes for year to date 2019 increased 8,245 MBoe, or 16%, compared to year to date 2018, reflecting an increase in drilling and completion activities over the past year. For year to date 2019, our crude oil sales volumes increased 20% from the comparable 2018 period, while our natural gas sales volumes increased 10%.

Our crude oil net sales prices averaged $52.36 per barrel for year to date 2019, a decrease of 14% compared to $61.14 per barrel for year to date 2018 primarily due to lower crude oil market prices. The differential between NYMEX WTI calendar month prices and our realized crude oil net sales prices averaged $4.94 per barrel for year to date 2019 compared to $4.22 per barrel for year to date 2018, reflecting changes in supply and demand fundamentals over the past year that created volatility in our price realizations between periods.

Our natural gas net sales prices averaged $2.11 per Mcf for year to date 2019, a decrease of 25% compared to $2.81 per Mcf for year to date 2018. The discount between our net sales prices and NYMEX Henry Hub calendar month prices weakened by $0.71 per Mcf compared to the year to date 2018 period. As discussed above, 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 2019 for our natural gas sales stream relative to benchmark prices.

Derivatives. Changes in natural gas market prices during the six months ended June 30, 2019 had a favorable impact on the ~~presentation~~fair value of our natural gas derivatives, which resulted in positive revenue adjustments of $52.3 million for the period compared to negative revenue adjustments of $2.5 million in the comparable 2018 period.

Crude oil and natural gas service operations. Revenues associated with our crude oil and natural gas ~~revenues.~~service operations increased $4.0 million, or 14%, from $29.3 million for year to date 2018 to $33.3 million for year to date 2019 due to an increase in the magnitude of water handling and recycling activities compared to the prior period. The increased activities also resulted in higher service-related expenses compared to the prior period.

Operating Costs and Expenses

Production Expenses. Production expenses increased $36.3 million, or 20%, from $183.1 million for year to date 2018 to $219.4 million for year to date 2019 primarily due to an increase in the number of producing wells and related 16% increase in sales volumes. Production expenses on a per-Boe basis averaged $3.66 for year to date 2019 compared to $3.54 per Boe recognized for the comparable 2018 period.

Production Taxes. Production taxes increased $16.1 million, or 10%, to $180.3 million for year to date 2019 compared to $164.2 million for year to date 2018, despite flat revenues, due to the aforementioned increase in proportion of our production and revenues being generated in North Dakota over the past year, which has a per-unit natural gas production tax rate assessed on volumes sold and a higher crude oil production tax rate compared to Oklahoma, and the legislation enacted in Oklahoma in 2018 as discussed above that increased the production tax rate on certain producing wells. As a result of these factors, our production taxes as a percentage of net crude oil and natural gas sales increased from 7.6% for year to date 2018 to 8.4% for year to date 2019.

Depreciation, Depletion, Amortization and Accretion. Total DD&A increased $79.0 million, or 9%, to $980.6 million for year to date 2019 compared to $901.6 million for the comparable 2018 period due to an increase in total sales volumes, the impact of which was partially offset by the aforementioned reduction in our DD&A rate per Boe in 2019. The following table shows the components of our DD&A on a unit of sales basis for the periods presented.

Property Impairments. There were no proved property impairments recognized during the year to date periods of 2019 and 2018. Impairments of unproved properties decreased $16.2 million, or 26%, to $46.7 million for year to date 2019 compared to $62.9 million for year to date 2018 due to a reduction in the balance of unamortized leasehold costs over the past year.

General and Administrative Expenses. Total G&A expenses increased $4.6 million, or 5%, from $90.2 million for year to date 2018 to $94.8 million for year to date 2019. Total G&A expenses include non-cash charges for equity compensation of $24.3 million and $21.5 million for the year to date periods of 2019 and 2018, respectively. G&A expenses other than equity compensation included in the total G&A expense figure above totaled $70.5 million for year to date 2019, an increase of $1.8 million, or 3%, compared to $68.7 million for the comparable 2018 period. We ~~adopted~~have incurred higher personnel-related costs in 2019 associated with the ~~new rules using a modified retrospective transition approach whereby changes~~growth in our operations over the past year; however, the increased costs have been ~~applied~~mitigated by higher overhead recoveries from joint interest owners driven by increased drilling and completion activities.

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

The decrease in G&A expenses on a per-Boe basis was driven by a 16% increase in total sales volumes from new well completions with no comparable increase in G&A expenses.

Interest Expense. Interest expense decreased $13.9 million, or 9%, to $136.3 million for year to date 2019 compared to $150.2 million for the comparable 2018 period due to a decrease in total outstanding debt. Our weighted average outstanding debt balance for year to date 2019 was $5.8 billion compared to $6.3 billion for year to date 2018.

Income Taxes. For the six months ended June 30, 2019 and 2018 we provided for income taxes at a combined federal and state tax rate of 24.5% and 24.0%, respectively, of pre-tax income generated by our operations in the United States. We recorded income tax provisions of $127.6 million and $146.8 million for the year to date periods of 2019 and 2018, respectively, which resulted in effective tax rates of 23.2% and 23.6%, respectively, after ~~December 31, 2017~~taking into account statutory tax rates, permanent taxable differences, tax effects from equity compensation, and ~~prior~~other items. See Notes to Unaudited Condensed Consolidated Financial Statements–Note 12. Income Taxes for a summary of the sources and tax effects of items comprising our effective tax rates for the six months ended June 30, 2019 and 2018.

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. We intend to continue reducing our long-term debt using available cash flows from operations and/or proceeds from additional potential sales of assets or through joint development arrangements; however, no assurance can be given that such transactions will occur.

Based on our planned capital spending, our forecasted cash flows and projected levels of indebtedness, we expect to maintain compliance with the covenants under our credit facility and senior note indentures for at least the next 12 months. Further, we expect to meet in the ordinary course of business other contractual cash commitments to third parties as of June 30, 2019, including those described in Note 9. 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 to preserve liquidity and financial flexibility if needed to fund our operations.

Cash flows provided by operating activities

Net cash provided by operating activities totaled $1.50 billion and $1.64 billion for the six months ended June 30, 2019 and 2018, respectively. The decrease in operating cash flows was primarily due to the aforementioned decrease in crude oil and natural gas commodity prices, increase in production expenses, and increase in production taxes. The reduced cash flows from these factors were partially offset by lower interest expenses and higher cash gains on matured natural gas derivatives compared to the 2018 period.

Cash flows used in investing activities

Net cash used in investing activities totaled $1.56 billion and $1.34 billion for the six months ended June 30, 2019 and 2018, respectively. The increase in spending resulted from changes in the timing of our annual capital spending between periods. Our capital expenditures budget for full year 2019 is $2.6 billion compared to $2.8 billion spent in 2018.

Cash flows used in financing activities

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 under our share repurchase program initiated in June 2019 and $21.2 million of cash paid to taxing authorities to satisfy tax withholdings associated with restricted stock awards that vested during the period, ~~results have~~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, LLC as described below under the heading "Mineral acquisition relationship."

Net cash used in financing activities for the six months ended June 30, 2018 totaled $210.3 million primarily resulting from $188 million of net repayments on our credit facility during the period.

Future Sources of Financing

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

Under the current commodity price environment, our planned capital expenditures for 2019 are expected to be funded entirely from operating cash flows. Additionally, we expect to generate cash flows in excess of operating and capital needs, which we plan to apply toward dividend payments, share repurchases, and further reduction of debt in the future.

We currently anticipate we will be able to generate or obtain funds sufficient to meet our short-term and long-term cash requirements. 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 the capital markets for additional financing or capital to take advantage of business opportunities that may arise. Further, we may sell assets or enter into strategic joint development opportunities in order to obtain funding if such transactions can be executed on satisfactory terms.

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, 2019 we had no outstanding borrowings and approximately $1.5 billion 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 would not trigger a reduction in our current credit facility commitments, nor would such actions trigger a security requirement or change in covenants. Downgrades of our credit rating will, however, trigger increases in our credit facility’s interest rates and commitment fees paid on unused borrowing availability under certain circumstances.

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

We were in compliance with our credit facility covenants at June 30, 2019 and expect to maintain compliance for at least the next 12 months. At June 30, 2019, our consolidated net debt to total capitalization ratio was 0.42 to 1.00. We do not believe the credit facility covenants are reasonably likely to limit our ability to undertake additional debt financing to a material extent if needed to support our business.

Asset disposition proceeds

On July 18, 2019 we sold certain water gathering, recycling, and disposal assets in the STACK play for proceeds of $85.3 million which will be used for general corporate purposes. The disposed assets represented an immaterial portion of the Company’s assets and operating results.

Future Capital Requirements

Our debt includes outstanding senior note obligations totaling $5.8 billion at June 30, 2019. Our senior notes are not subject to any mandatory redemption or sinking fund requirements. For further information on the face values, maturity dates, semi-annual interest payment dates, optional redemption periods and covenant restrictions related to our senior notes, refer to Note 7. Long-Term Debt in Notes to Unaudited Condensed Consolidated Financial Statements.

In 2018, we redeemed $400 million of our $2.0 billion of 5% Senior Notes due 2022. We plan to further redeem our 2022 Notes in the future prior to their maturity.

We were in compliance with our senior note covenants at June 30, 2019 and expect to maintain compliance for at least the next 12 months. 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 would 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 $213 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 will continue for the remainder of 2019.

Capital expenditures

Our capital expenditures budget for 2019 is $2.6 billion, which is expected to be allocated as reflected below. Acquisition expenditures are not budgeted, with the exception of planned levels of spending for mineral acquisitions made in conjunction with our relationship with Franco-Nevada.

For the six months ended June 30, 2019, we invested $1.44 billion in our capital program excluding $100.3 million of unbudgeted acquisitions and excluding $19.7 million of capital costs associated with decreased accruals for capital expenditures. Our 2019 year to date capital expenditures were allocated as shown in the table below.

Our year-to-date capital expenditures reflect an accelerated pace of development due to improved cycle times and efficiency gains which resulted in more net wells being spud and completed than budgeted while using the same number of rigs and completion crews. Our pace of capital spending slowed in the second quarter relative to the first quarter and is expected to continuing slowing in the second half of 2019 in conjunction with a planned decrease in rigs and stimulation crews.

Our drilling and completion activities and the actual amount and timing of our capital expenditures may differ materially from our budget as a result of, among other things, available cash flows, unbudgeted acquisitions, actual drilling and completion results, operational process improvements, the availability of drilling and completion rigs and other services and equipment, the availability of transportation, gathering and processing capacity, changes in commodity prices, and regulatory, technological and competitive developments. We monitor our capital spending closely based on actual and projected cash flows and may scale back our spending should commodity prices decrease from current levels. Conversely, an increase in commodity prices from current levels could result in increased capital expenditures. We expect to continue participating as a buyer of properties when and if we have the ability to increase our position in strategic plays at competitive terms.

Commitments and contingencies

Refer to Note 9. Commitments and Contingencies in Notes to Unaudited Condensed Consolidated Financial Statements for discussion of certain future commitments and contingencies of the Company as of June 30, 2019. We believe our cash flows from operations, our remaining cash balance, and amounts available under our credit facility will be sufficient to satisfy such commitments and contingencies.



Oklahoma					73-0767549
(State or other jurisdiction of incorporation or organization)					(I.R.S. Employer Identification No.)

	20 N. Broadway,	Oklahoma City,	Oklahoma	73102		~~73102~~
	(Address of principal executive offices)				(Zip Code)



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



Large accelerated filer	x	Accelerated filer		¨
			☐
Non-accelerated filer	¨ ~~(Do not check if a smaller reporting company)~~ ☐	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. ¨



Unobservable Input		Assumption
Future production		Future production estimates for each property
Forward commodity prices		Forward NYMEX strip prices through ~~2022~~2023 (adjusted for differentials), escalating 3% per year thereafter
Operating costs		Estimated costs for the current year, escalating 3% per year thereafter
Productive life of ~~field~~properties		~~Ranging from 1~~Up to 3850 years
Discount rate		10%



	2022 Notes (1)	2023 Notes	2024 Notes	2028 Notes	2044 Notes
Face value (in thousands)	$1,600,000	$1,500,000	$1,000,000	$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



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



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



	Fair value measurements at June 30, 2019 using:
In thousands	Level 1		Level 2		Level 3		Total
Derivative assets:
Swaps	$	—	$	46,204	$	—	$	46,204
Total	$	—	$	46,204	$	—	$	46,204

	Fair value measurements at December 31, 2018 using:
In thousands	Level 1		Level 2		Level 3		Total
Derivative assets:
Swaps	$	—	$	10,130	$	—	$	10,130
Collars	—		5,482		—		5,482
Total	$	—	$	15,612	$	—	$	15,612



	Fair value measurements at June 30, 2018 using:
In thousands	Level 1		Level 2			Level 3		Total
Derivative liabilities:
Swaps	$	—	$	(8,862	)	$	—	$	(8,862	)
Total	$	—	$	(8,862	)	$	—	$	(8,862	)

	Fair value measurements at December 31, 2017 using:
In thousands	Level 1		Level 2			Level 3		Total
Derivative assets:
Swaps	$	—	$	2,603		$	—	$	2,603
Total	$	—	$	2,603		$	—	$	2,603



In thousands	Amount
Remainder of 2019	$	6,546
2020	2,300
2021	706
2022	691
2023	624
Thereafter	4,872
Total operating lease liabilities, at undiscounted value	$	15,739
Less: Imputed interest	(2,742		)
Total operating lease liabilities, at discounted present value	$	12,997
Less: Current portion of operating lease liabilities	(8,120		)
Operating lease liabilities, net of current portion	$	4,877



	Number of non-vested shares		Weighted average grant-date fair value
Non-vested restricted shares outstanding at December 31, 2018	4,022,409		$	38.44
Granted	1,393,241		44.31
Vested	(1,648,254	)	22.95
Forfeited	(218,514	)	47.45
Non-vested restricted shares outstanding at June 30, 2019	3,548,882		$	47.38


~~(1)~~	A valuation allowance has been recognized against all deferred tax assets associated with losses generated by the Company's Canadian operations, thereby resulting in no income taxes on other comprehensive income.



	Three months ended June 30,										Six months ended June 30,
$ in thousands	2018			Tax rate %		2017			Tax rate %		2018			Tax rate %		2017			Tax rate %
Expected income tax (provision) benefit based on US statutory tax rate (1)	$	(66,716	)	21	%	$	35,494		35	%	$	(130,867	)	21	%	$	33,222		35	%
State income taxes, net of federal benefit	(9,531		)	3	%	3,043			3	%	(18,695		)	3	%	2,848			3	%
Tax benefit (deficiency) from stock-based compensation	359			—	%	(473		)	(1	%)	1,868			—	%	(3,773		)	(4	%)
Canadian valuation allowance (2)	(78		)	—	%	(112		)	—	%	(148		)	—	%	(257		)	—	%
Other, net	734			—	%	(97		)	—	%	1,074			—	%	(207		)	—	%
(Provision) benefit for income taxes	$	(75,232	)	24	%	$	37,855		37	%	$	(146,768	)	24	%	$	31,833		34	%


~~(1)~~	~~In December 2017 the Tax Cuts and Jobs Act was signed into law, which among other things reduced the U.S. federal corporate income tax rate from 35% to 21% effective January 1, 2018.~~


~~(2)~~	Represents valuation allowances recognized against all deferred tax assets associated with operating loss carryforwards generated by the Company's Canadian operations during the respective periods for which the Company does not expect to realize a benefit.



Boe production per day	2Q 2019	2Q 2018	% Change from 2Q 2018		1Q 2019	% Change from 1Q 2019
Bakken	194,014	158,119	23	%	199,423	(3	%)
SCOOP	71,471	64,786	10	%	67,659	6	%
STACK	57,209	51,722	11	%	56,513	1	%
All other	8,720	9,432	(8	%)	8,641	1	%
Total	331,414	284,059	17	%	332,236	—	%



	Three months ended June 30,						Volume increase	Volume percent increase
	2019			2018
	Volume	Percent		Volume	Percent
Crude oil (MBbl)	17,616	58	%	14,298	55	%	3,318	23	%
Natural gas (MMcf)	75,254	42	%	69,310	45	%	5,944	9	%
Total (MBoe)	30,159	100	%	25,849	100	%	4,310	17	%

	Three months ended June 30,						Volume increase	Volume percent increase
	2019			2018
	MBoe	Percent		MBoe	Percent
North Region	18,440	61	%	15,177	59	%	3,263	21	%
South Region	11,719	39	%	10,672	41	%	1,047	10	%
Total	30,159	100	%	25,849	100	%	4,310	17	%



	Three months ended June 30,
$/Boe	2019		2018
Crude oil and natural gas	$	15.91	$	17.03
Other equipment	0.16		0.20
Asset retirement obligation accretion	0.07		0.06
Depreciation, depletion, amortization and accretion	$	16.14	$	17.29



In millions	2019 Budget
Exploration and development	$	2,165
Land costs (1)	205
Capital facilities, workovers and other corporate assets	228
Seismic	2
Total 2019 capital budget	$	2,600


(1)	Represents the initial budget which includes $125 million of planned spending for mineral acquisitions by TMRC II. To capitalize on favorable market conditions, in July 2019 the Company and Franco-Nevada agreed to increase the planned spending to $150 million for 2019. With a carry structure in place, Continental will recoup 80% of such spending from Franco-Nevada.


(1)	Year-to-date amount includes $95 million of mineral acquisitions made by TMRC II during the six months ended June 30, 2019, of which $76 million was recouped from Franco-Nevada.



	Three months ended June 30, 2018									Three months ended June 30, 2017
In thousands	Crude oil			Natural gas			Total			Crude oil		Natural gas		Total
Crude oil and natural gas sales (GAAP)	$	946,884		$	190,644		$	1,137,528		$	481,898	$	144,650	$	626,548
Less: Transportation expenses	(40,217		)	(7,037		)	(47,254		)	—		—		—
Net crude oil and natural gas sales (non-GAAP for 2018)	$	906,667		$	183,607		$	1,090,274		$	481,898	$	144,650	$	626,548
Sales volumes (MBbl/MMcf/MBoe)	14,311			69,310			25,863			11,499		55,054		20,674
Net sales price (non-GAAP for 2018)	$	63.35		$	2.65		$	42.16		$	41.91	$	2.63	$	30.31



	Six months ended June 30, 2018									Six months ended June 30, 2017
In thousands	Crude oil			Natural gas			Total			Crude oil		Natural gas		Total
Crude oil and natural gas sales (GAAP)	$	1,853,165		$	398,215		$	2,251,380		$	962,539	$	297,859	$	1,260,398
Less: Transportation expenses	(80,603		)	(15,948		)	(96,551		)	—		—		—
Net crude oil and natural gas sales (non-GAAP for 2018)	$	1,772,562		$	382,267		$	2,154,829		$	962,539	$	297,859	$	1,260,398
Sales volumes (MBbl/MMcf/MBoe)	28,993			136,040			51,667			22,253		106,114		39,938
Net sales price (non-GAAP for 2018)	$	61.14		$	2.81		$	41.71		$	43.26	$	2.81	$	31.56



Boe production per day	2Q 2018	2Q 2017	% Change from 2Q 2017		1Q 2018	% Change from 1Q 2018
Bakken	158,119	119,861	32	%	161,356	(2	%)
SCOOP	64,786	61,107	6	%	62,012	4	%
STACK	51,722	31,934	62	%	53,361	(3	%)
All other	9,432	13,311	(29	%)	10,681	(12	%)
Total	284,059	226,213	26	%	287,410	(1	%)


~~(1)~~	~~See the previous section titled~~ ~~Change in presentation of revenues~~ ~~for a discussion and calculation of net sales prices, which are non-GAAP measures for the three and six months ended June 30, 2018.~~


~~ITEM 3.~~	~~Quantitative and Qualitative Disclosures About Market Risk~~


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



Period	Total number of shares purchased (1)		Average price paid per share			Total number of shares purchased as part of publicly announced plans or programs	Maximum number of shares that may yet be purchased under the plans or programs
April 1, 2018 to April 30, 2018	462		$	58.94		—	—
May 1, 2018 to May 31, 2018	146,393	(2)	$	65.51	(2)	—	—
June 1, 2018 to June 30, 2018	543		$	65.62		—	—
Total	147,398		$	65.49		—	—



Period	Total number of shares purchased	Average price paid per share		Total number of shares purchased as part of publicly announced plans or programs (3)	Maximum dollar value of shares that may yet be purchased under the plans or programs (in millions) (3)
April 1, 2019 to April 30, 2019	—	—		—	—
May 1, 2019 to May 31, 2019:
Repurchases for tax withholdings (1)	13,335	$	42.02	—	—
Purchases by principal shareholder (2)	93,000	$	42.71	—	—
June 1, 2019 to June 30, 2019:
Purchases by principal shareholder (2)	38,600	$	38.76	—	—
Share repurchase program (3)	1,800,000	$	38.70	1,800,000	$	930.3
Total for the quarter	1,944,935	$	38.92	1,800,000


~~(2)~~	~~Of this amount, 10,393 shares represent shares surrendered by employees to cover tax liabilities at an average price per share of $68.30.~~ The price paid per share was the closing price of our common stock on the date the restrictions lapsed on such shares. ~~Additionally, the amount includes 136,000~~


(2)	Amounts represent shares of our common stock purchased by Harold G. Hamm, our Chairman of the Board, Chief Executive Officer, and principal shareholder in open-market ~~transactions~~transactions.



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

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

~~10.1*†~~		~~Summary of Non-Employee Director Compensation Approved as of May 16, 2018.~~

~~10.2***†~~		~~Form of Employee Restricted Stock Award Agreement under the Continental Resources, Inc. 2013 Long-Term Incentive Plan.~~

~~10.3***†~~		~~Form of Non-Employee Director Restricted Stock Award Agreement under the Continental Resources, Inc. 2013 Long-Term Incentive Plan.~~

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**		XBRL Instance Document - the 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


~~***~~	~~Re-filed herewith pursuant to Item 10(d) of Regulation S-K.~~


†	~~Management contracts or compensatory plans or arrangements filed pursuant to Item 601(b)(10)(iii) of Regulation S-K.~~



		CONTINENTAL RESOURCES, INC.

Date:	August ~~7, 2018~~5, 2019	By:	/s/ John D. Hart
			John D. Hart
			Sr. Vice President, Chief Financial Officer and Treasurer (Duly Authorized Officer and Principal Financial Officer)