UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)



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

For the quarterly period ended June 30, ~~2015~~2016



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

For the transition period from to

Commission File Number: 001-32886

CONTINENTAL RESOURCES, INC.

(Exact name of registrant as specified in its charter)



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

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

(405) 234-9000

(Registrant’s telephone number, including area code)

Not Applicable

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

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

Indicate by check mark whether the registrant has submitted electronically 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). Yes x No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting 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

~~373,104,530~~374,561,751 shares of our $0.01 par value common stock were outstanding on July 31, ~~2015~~2016.

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
	Condensed Consolidated Statement of Shareholders’ Equity	3
	Unaudited Condensed Consolidated Statements of Cash Flows	4
	Notes to Unaudited Condensed Consolidated Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	1817
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	3431
Item 4.	Controls and Procedures	3532

PART II. Other Information
Item 1.	Legal Proceedings	3634
Item 1A.	Risk Factors	3634
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	3634
Item 3.	Defaults Upon Senior Securities	3734
Item 4.	Mine Safety Disclosures	3734
Item 5.	Other Information	3734
Item 6.	Exhibits	3734
	Signature	3835

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.

“DD&A” Depreciation, depletion, amortization and accretion.

“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.

“enhanced recovery” The recovery of crude oil and natural gas through the injection of liquids or gases into the reservoir, supplementing its natural energy. Enhanced recovery methods are sometimes applied when production slows due to depletion of the natural pressure.

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

“horizontal drilling” A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled horizontally within a specified interval.

“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.

“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.

“productive well” A well found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.

“prospect” A potential geological feature or formation which geologists and geophysicists believe may contain hydrocarbons. A prospect can be in various stages of evaluation, ranging from a prospect that has been fully evaluated and is ready to drill to a prospect that will require substantial additional seismic data processing and interpretation.

“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 ~~we use~~used to describe ~~an area of crude oil and liquids-rich natural gas~~ properties located in the Anadarko basin of ~~south central~~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 and Osage formations overlying the Woodford formation. 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, ~~returns,~~rates of return, budgets, costs, business strategy, objectives, and cash ~~flow,~~flows, included in this report are forward-looking statements. The words “could,” “may,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project,” “budget,” “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 ~~strategy;~~plans;

our future operations;

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

~~our~~ technology;

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 or property acquisitions and dispositions;

costs of exploiting and developing our properties and conducting other operations;

our financial position;

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 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 ~~considers~~believes these assumptions and expectations ~~to be~~are reasonable, ~~and based on reasonable assumptions,~~ 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 ~~our~~the Company's control. No assurance can be given that such expectations will be correct or achieved or that the assumptions are ~~accurate.~~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, ~~2014,~~2015, registration statements ~~filed~~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 occur, or should underlying assumptions prove incorrect, ~~our~~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, ~~we do not intend, and disclaim any duty,~~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, 2015			December 31, 2014			June 30, 2016			December 31, 2015
In thousands, except par values and share data	(Unaudited)						(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	25,458		$	24,381		$	16,560		$	11,463
Receivables:
Crude oil and natural gas sales	545,860			552,476			385,483			378,622
Affiliated parties	96			13,360			96			122
Joint interest and other, net	450,534			567,476			260,784			232,293
Derivative assets	50,214			52,423			16,693			93,922
Inventories	100,173			102,179			102,896			94,151
Deferred and prepaid taxes	13,283			63,266
Prepaid expenses and other	14,695			14,040			14,700			11,766
Total current assets	1,200,313			1,389,601			797,212			822,339
Net property and equipment, based on successful efforts method of accounting	14,169,202			13,635,852			13,541,129			14,063,328
Noncurrent derivative assets	22,015			31,992			3,045			14,560
Other noncurrent assets	18,321			18,588			18,350			19,581
Total assets	$	15,409,851		$	15,076,033		$	14,359,736		$	14,919,808

Liabilities and shareholders’ equity
Current liabilities:
Accounts payable trade	$	776,966		$	1,263,724		$	412,851		$	553,285
Revenues and royalties payable	255,166			272,755			186,258			187,000
Payables to affiliated parties	757			7,305			185			69
Accrued liabilities and other	280,231			404,506			192,359			176,947
Derivative liabilities	339			1,645			24,227			3,583
Current portion of long-term debt	2,110			2,078			2,179			2,144
Total current liabilities	1,315,569			1,952,013			818,059			923,028
Long-term debt, net of current portion	6,988,046			5,926,800			7,149,279			7,115,644
Other noncurrent liabilities:
Deferred income tax liabilities	2,156,268			2,141,447
Deferred income tax liabilities, net							1,896,238			2,090,228
Asset retirement obligations, net of current portion	82,069			75,462			105,277			101,251
Noncurrent derivative liabilities	828			3,109			9,290			3,706
Other noncurrent liabilities	11,044			9,358			14,644			17,051
Total other noncurrent liabilities	2,250,209			2,229,376			2,025,449			2,212,236
Commitments and contingencies (Note 7)
Shareholders’ 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; 373,074,092 shares issued and outstanding at June 30, 2015; 372,005,502 shares issued and outstanding at December 31, 2014	3,731			3,720
Common stock, $0.01 par value; 1,000,000,000 shares authorized; 374,581,304 shares issued and outstanding at June 30, 2016; 372,959,080 shares issued and outstanding at December 31, 2015							3,746			3,730
Additional paid-in capital	1,310,161			1,287,941			1,360,933			1,345,624
Accumulated other comprehensive loss	(2,865		)	(385		)	(2,903		)	(3,354		)
Retained earnings	3,545,000			3,676,568			3,005,173			3,322,900
Total shareholders’ equity	4,856,027			4,967,844			4,366,949			4,668,900
Total liabilities and shareholders’ equity	$	15,409,851		$	15,076,033		$	14,359,736		$	14,919,808

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

Continental Resources, Inc. and Subsidiaries

Unaudited Condensed Consolidated Statements of Comprehensive Income (Loss)


	Three months ended June 30,						Six months ended June 30,						Three months ended June 30,						Six months ended June 30,
In thousands, except per share data	2015			2014			2015			2014			2016			2015			2016			2015
Revenues
Crude oil and natural gas sales	$	790,102		$	1,112,998		$	1,371,294		$	2,085,145		$	525,711		$	790,102		$	929,302		$	1,371,294
Crude oil and natural gas sales to affiliates	—			25,087			1,400			55,273			—			—			—			1,400
Gain (loss) on derivative instruments, net	(4,737		)	(262,524		)	28,018			(302,198		)
Gain (loss) on crude oil and natural gas derivatives, net													(82,257		)	(4,737		)	(40,145		)	28,018
Crude oil and natural gas service operations	11,009			10,534			21,306			20,370			7,757			11,009			15,227			21,306
Total revenues	796,374			886,095			1,422,018			1,858,590			451,211			796,374			904,384			1,422,018

Operating costs and expenses
Production expenses	91,667			84,236			183,021			160,211			74,083			91,667			152,724			183,021
Production expenses to affiliates	68			285			1,654			1,196			—			68			—			1,654
Production taxes and other expenses	61,545			97,025			109,908			175,327			39,141			61,545			69,634			109,908
Exploration expenses	109			11,205			14,449			16,018			1,674			109			4,739			14,449
Crude oil and natural gas service operations	7,092			5,979			10,986			14,053			3,576			7,092			6,618			10,986
Depreciation, depletion, amortization and accretion	452,957			326,871			839,469			599,732			441,761			452,957			905,752			839,469
Property impairments	76,872			79,316			224,432			137,524			66,112			76,872			145,039			224,432
General and administrative expenses	44,190			46,919			89,571			90,455			36,246			44,190			68,654			89,571
(Gain) loss on sale of assets, net	(20,573		)	(2,135		)	(22,643		)	6,363
Net gain on sale of assets and other													(100,835		)	(20,573		)	(99,127		)	(22,643		)
Total operating costs and expenses	713,927			649,701			1,450,847			1,200,879			561,758			713,927			1,254,033			1,450,847
Income (loss) from operations	82,447			236,394			(28,829		)	657,711			(110,547		)	82,447			(349,649		)	(28,829		)
Other income (expense):
Interest expense	(78,442		)	(72,841		)	(153,505		)	(135,816		)	(81,922		)	(78,442		)	(162,875		)	(153,505		)
Other	540			793			886			1,552			435			540			819			886
	(77,902		)	(72,048		)	(152,619		)	(134,264		)	(81,487		)	(77,902		)	(162,056		)	(152,619		)
Income (loss) before income taxes	4,545			164,346			(181,448		)	523,447			(192,034		)	4,545			(511,705		)	(181,448		)
Provision (benefit) for income taxes	4,142			60,808			(49,880		)	193,675			(72,632		)	4,142			(193,978		)	(49,880		)
Net income (loss)	$	403		$	103,538		$	(131,568	)	$	329,772		$	(119,402	)	$	403		$	(317,727	)	$	(131,568	)
Basic net income (loss) per share	$	—		$	0.28		$	(0.36	)	$	0.89		$	(0.32	)	$	—		$	(0.86	)	$	(0.36	)
Diluted net income (loss) per share	$	—		$	0.28		$	(0.36	)	$	0.89		$	(0.32	)	$	—		$	(0.86	)	$	(0.36	)

Comprehensive income (loss):
Net income (loss)	$	403		$	103,538		$	(131,568	)	$	329,772		$	(119,402	)	$	403		$	(317,727	)	$	(131,568	)
Other comprehensive income (loss), net of tax:
Foreign currency translation adjustments	625			—			(2,480		)	—			25			625			451			(2,480		)
Total other comprehensive income (loss), net of tax	625			—			(2,480		)	—			25			625			451			(2,480		)
Comprehensive income (loss)	$	1,028		$	103,538		$	(134,048	)	$	329,772		$	(119,377	)	$	1,028		$	(317,276	)	$	(134,048	)

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

Continental Resources, Inc. and Subsidiaries

Condensed Consolidated Statement of Shareholders’ Equity


In thousands, except share data	Shares outstanding		Common stock			Additional paid-in capital			Accumulated other comprehensive loss			Retained earnings			Total shareholders’ equity			Shares outstanding		Common stock			Additional paid-in capital			Accumulated other comprehensive loss			Retained earnings			Total shareholders’ equity
Balance at December 31, 2014	372,005,502		$	3,720		$	1,287,941		$	(385	)	$	3,676,568		$	4,967,844
Balance at December 31, 2015																		372,959,080		$	3,730		$	1,345,624		$	(3,354	)	$	3,322,900		$	4,668,900
Net loss (unaudited)	—		—			—			—			(131,568		)	(131,568		)	—		—			—			—			(317,727		)	(317,727		)
Other comprehensive loss, net of tax (unaudited)	—		—			—			(2,480		)	—			(2,480		)
Other comprehensive income, net of tax (unaudited)																		—		—			—			451			—			451
Stock-based compensation (unaudited)	—		—			27,411			—			—			27,411			—		—			21,041			—			—			21,041
Restricted stock:
Granted (unaudited)	1,338,699		13			—			—			—			13			2,007,078		20			—			—			—			20
Repurchased and canceled (unaudited)	(109,462	)	(1		)	(5,191		)	—			—			(5,192		)	(279,019	)	(3		)	(5,732		)	—			—			(5,735		)
Forfeited (unaudited)	(160,647	)	(1		)	—			—			—			(1		)	(105,835	)	(1		)	—			—			—			(1		)
Balance at June 30, 2015 (unaudited)	373,074,092		$	3,731		$	1,310,161		$	(2,865	)	$	3,545,000		$	4,856,027
Balance at June 30, 2016 (unaudited)																		374,581,304		$	3,746		$	1,360,933		$	(2,903	)	$	3,005,173		$	4,366,949

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

Continental Resources, Inc. and Subsidiaries

Unaudited Condensed Consolidated Statements of Cash Flows


	Six months ended June 30,						Six months ended June 30,
In thousands	2015			2014			2016			2015
Cash flows from operating activities
Net income (loss)	$	(131,568	)	$	329,772
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Net loss							$	(317,727	)	$	(131,568	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion	838,216			606,638			908,021			838,216
Property impairments	224,432			137,524			145,039			224,432
Non-cash (gain) loss on derivatives, net	8,599			204,791
Non-cash loss on derivatives, net							114,972			8,599
Stock-based compensation	27,429			26,017			21,046			27,429
Provision (benefit) for deferred income taxes	(49,890		)	190,571
Benefit for deferred income taxes							(193,990		)	(49,890		)
Dry hole costs	8,003			4,383			206			8,003
(Gain) loss on sale of assets, net	(22,643		)	6,363
Gain on sale of assets, net							(97,016		)	(22,643		)
Other, net	5,388			4,411			4,752			5,388
Changes in assets and liabilities:
Accounts receivable	138,882			(144,821		)	(34,939		)	138,882
Inventories	1,938			(23,519		)	(8,745		)	1,938
Other current assets	50,561			(7,938		)	(2,125		)	50,561
Accounts payable trade	(106,174		)	44,505			(53,859		)	(106,174		)
Revenues and royalties payable	(17,589		)	42,051			(742		)	(17,589		)
Accrued liabilities and other	(60,162		)	9,186			15,347			(60,162		)
Other noncurrent assets and liabilities	1,390			2,519			(2,519		)	1,390
Net cash provided by operating activities	916,812			1,432,453			497,721			916,812

Cash flows from investing activities
Exploration and development	(1,972,887		)	(2,052,870		)	(625,126		)	(1,972,887		)
Purchase of producing crude oil and natural gas properties	(557		)	(33,606		)	—			(557		)
Purchase of other property and equipment	(22,449		)	(29,829		)	(4,867		)	(22,449		)
Proceeds from sale of assets	32,590			39,018
Proceeds from sale of assets and other							112,199			32,590
Net cash used in investing activities	(1,963,303		)	(2,077,287		)	(517,794		)	(1,963,303		)

Cash flows from financing activities
Credit facility borrowings	1,375,000			1,105,000			638,000			1,375,000
Repayment of credit facility	(315,000		)	(1,380,000		)	(606,000		)	(315,000		)
Proceeds from issuance of Senior Notes	—			1,681,834
Repayment of other debt	(1,032		)	(999		)	(1,064		)	(1,032		)
Debt issuance costs	(2,110		)	(7,874		)	(40		)	(2,110		)
Repurchase of restricted stock for tax withholdings	(5,192		)	(4,646		)	(5,735		)	(5,192		)
Net cash provided by financing activities	1,051,666			1,393,315			25,161			1,051,666
Effect of exchange rate changes on cash	(4,098		)	—			9			(4,098		)
Net change in cash and cash equivalents	1,077			748,481			5,097			1,077
Cash and cash equivalents at beginning of period	24,381			28,482			11,463			24,381
Cash and cash equivalents at end of period	$	25,458		$	776,963		$	16,560		$	25,458

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

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

Note 1. Organization and Nature of Business

Continental Resources, Inc. (the “Company”) was originally formed in 1967 and is incorporated under the laws of the State of Oklahoma. The Company's principal business is crude oil and natural gas exploration, development and production with properties primarily located in the North, South, and East regions of the United States. 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 ~~Kansas and~~ all properties south of Kansas and west of the Mississippi River including various plays in the ~~South~~SCOOP (South Central Oklahoma Oil ~~Province (“SCOOP”)~~Province), STACK (Sooner Trend Anadarko Canadian Kingfisher), Northwest Cana, and Arkoma Woodford areas of Oklahoma. The East region is comprised of undeveloped leasehold acreage east of the Mississippi River with no current drilling or production operations.

~~The~~A substantial portion of the Company’s operations are ~~geographically~~ concentrated in the North region, with that region comprising ~~70%~~approximately 64% of the Company’s crude oil and natural gas production and ~~79%~~approximately 73% of its crude oil and natural gas revenues for the six months ended June 30, ~~2015.~~2016. 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 activity in the South region with its discovery ~~and announcement~~ of the SCOOP play and its increased activity in ~~Oklahoma.~~the Northwest Cana and STACK plays. The South region ~~now comprises 30%~~comprised approximately 36% of the Company's crude oil and natural gas production and ~~21%~~approximately 27% of its crude oil and natural gas revenues for the six months ended June 30, ~~2015.~~2016.

The Company has focused its operations on the exploration and development of crude oil since the 1980s. For the six months ended June 30, ~~2015,~~2016, crude oil accounted for ~~68%~~approximately 62% of the Company’s total production and ~~86%~~approximately 87% 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 and its subsidiaries, all of which are 100% ~~owned. All~~owned, after all significant intercompany accounts and transactions have been eliminated upon consolidation.

On August 18, 2014, the Company's Board of Directors declared a 2-for-1 stock split of the Company's common stock to be effected in the form of a stock dividend. The stock dividend was distributed on September 10, 2014 to shareholders of record as of September 3, 2014. Previously reported common stock and earnings per share amounts for the three and six months ended June 30, 2014 have been retroactively adjusted in the accompanying financial statements and related notes to reflect the stock split.

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, ~~2014~~2015 (“~~2014~~2015 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, ~~2015~~2016 and for the three and six month periods ended June 30, ~~2015~~2016 and ~~2014~~2015 are unaudited. The condensed consolidated balance sheet as of December 31, ~~2014~~2015 was derived from the audited balance sheet included in the ~~2014~~2015 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 of the estimates and assumptions that affect reported results are the 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.

~~Continental Resources, Inc. and Subsidiaries~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

Earnings per share

Basic and diluted net income (loss) per share is computed by dividing net income (loss) by the weighted-average number of shares outstanding for the period. ~~Diluted~~In periods where the Company has net income, ~~(loss)~~diluted earnings per share reflects

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

the potential dilution of non-vested restricted stock awards, which are calculated using the treasury stock method. The following table presents the calculation of basic and diluted weighted average shares outstanding and net income (loss) per share for the three and six months ended June 30, ~~2015~~2016 and ~~2014.~~2015.


	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	2015		2014		2015			2014		2016			2015		2016			2015
Income (loss) (numerator):
Net income (loss) - basic and diluted	$	403	$	103,538	$	(131,568	)	$	329,772	$	(119,402	)	$	403	$	(317,727	)	$	(131,568	)
Weighted average shares (denominator):
Weighted average shares - basic	369,510		368,746		369,448			368,702		370,435			369,510		370,248			369,448
Non-vested restricted stock (1)	1,363		1,588		—			1,686		—			1,363		—			—
Weighted average shares - diluted	370,873		370,334		369,448			370,388		370,435			370,873		370,248			369,448
Net income (loss) per share:
Basic	$	—	$	0.28	$	(0.36	)	$	0.89	$	(0.32	)	$	—	$	(0.86	)	$	(0.36	)
Diluted	$	—	$	0.28	$	(0.36	)	$	0.89	$	(0.32	)	$	—	$	(0.86	)	$	(0.36	)

(1)

~~The~~During the three and six months ended June 30, 2016 and the six months ended June 30, 2015, the Company had a net loss and therefore the potential dilutive effect of approximately 1,940,700, 1,486,200, and 1,472,300 weighted average restricted shares, respectively, were not included in the calculation of diluted net loss per share ~~for the six months ended June 30, 2015~~ because to do so would have been ~~anti-dilutive.~~anti-dilutive to the computations.

Inventories

Inventory is comprised of crude oil held in storage or as line fill in pipelines 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 primarily using the first-in, first-out inventory method. Tubular goods and equipment are valued at the lower of cost or market, with cost determined primarily using a weighted average cost method applied to specific classes of inventory items.

The components of inventory as of June 30, ~~2015~~2016 and December 31, ~~2014~~2015 consisted of the following:


In thousands	June 30, 2015		December 31, 2014		June 30, 2016		December 31, 2015
Tubular goods and equipment	$	16,690	$	15,659	$	16,245	$	15,633
Crude oil	83,483		86,520		86,651		78,518
Total	$	100,173	$	102,179	$	102,896	$	94,151

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 recorded valuation allowances of $0.2 million and $0.3 million for the three and six months ended June 30, 2016, respectively, and $1.3 million and $12.4 million for the three and six months ended June 30, 2015, respectively, against deferred tax assets associated with operating loss carryforwards generated by its Canadian subsidiary ~~in 2015~~ for which the Company does not expect to realize a benefit.

~~Affiliate transactions~~New accounting pronouncements not yet adopted

In February 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update 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 ~~affiliate transactions reflected in~~standard is effective for interim and annual reporting periods beginning after December 15, 2018 and requires adoption by application of a modified retrospective transition approach. The Company is currently evaluating the accompanying unaudited condensed consolidated statements of comprehensive income (loss) include transactions between the Company and Hiland Partners, LP and its subsidiaries ("Hiland"). Hiland was controlled by the Company's principal shareholder through February 13, 2015, at which time it was sold to an unaffiliated third party. As a resultimpact of the sale, the related party relationship that existed previously between the Company and Hiland terminated as of February 13, 2015, which resulted in a reduction in affiliate transactions recognized in the Company'snew standard on its financial statements ~~at June 30, 2015~~ and ~~for the three and six months then ended.~~related disclosures.

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

~~Adoption of new accounting pronouncement~~

In ~~April 2015,~~March 2016, the ~~Financial Accounting Standards Board~~FASB issued Accounting Standards Update ~~2015-03,~~2016-09, ~~Interest—Imputation~~Compensation—Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting, which changes how companies account for certain aspects of ~~Interest (Subtopic 835-30): Simplifying~~share-based payment awards, including the ~~Presentation of Debt Issuance Costs~~ ~~("ASU 2015-03")~~. ~~The new standard requires debt issuance costs related to a recognized term debt liability, such~~accounting for income taxes, forfeitures, and statutory tax withholding requirements, as ~~the Company's senior notes and note payable, be presented~~well as classification in the ~~balance sheet as a direct deduction from the carrying amount~~statement of ~~that term debt liability, consistent with the presentation of a debt discount. Under previous guidance, debt issuance costs were required to be presented in the balance sheet as an asset.~~cash flows. The ~~new standard does not affect the existing recognition and measurement guidance for debt issuance costs. The new~~ standard is effective for interim and annual ~~and interim~~reporting periods beginning after December 15, ~~2015, with early adoption permitted.~~

2016 and shall be adopted either prospectively, retrospectively or using a modified retrospective transition approach depending on the topic covered in the standard. The Company ~~early adopted ASU 2015-03 as of June 30, 2015 on a retrospective basis to all prior balance sheet periods presented. As a result~~is currently evaluating the impact of the ~~adoption,~~new standard on its financial statements and related disclosures. The Company expects to continue its current accounting practice of estimating forfeitures in determining the ~~Company reclassified unamortized debt issuance costs associated with its senior notes and note payable, which totaled $65.7 million and $69.0 million as~~amount of ~~June 30, 2015 and December 31, 2014, respectively, from "Other noncurrent assets"~~stock-based compensation expense to a reduction of "Long-term debt, net of current portion" on the condensed consolidated balance sheets. Adoption of ASU 2015-03 had no impact on the Company's current and previously reported shareholders' equity, results of operations, or cash flows. The December 31, 2014 carrying amounts for the Company's senior notes and note payable presented throughout this report on Form 10-Q have been adjusted to reflect the retroactive adoption of ASU 2015-03. Unamortized debt issuance costs associated with the Company's credit facility, which amounted to $8.1 million and $7.0 million as of June 30, 2015 and December 31, 2014, respectively, were not reclassified and remain reflected in "Other noncurrent assets" on the condensed consolidated balance sheets.recognize.

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~~has not ~~result~~yet resulted in cash receipts or payments.


	Six months ended June 30,					Six months ended June 30,
In thousands	2015			2014		2016		2015
Supplemental cash flow information:
Cash paid for interest	$	148,454		$	122,879	$	156,358	$	148,454
Cash paid for income taxes	27			2,012		—		27
Cash received for income tax refunds	50,000			5		20		50,000
Non-cash investing activities:
Increase (decrease) in accrued capital expenditures	(387,113		)	115,956
Asset retirement obligation additions and revisions, net	4,945			3,710		1,042		4,945

As of June 30, 2016 and December 31, 2015, the Company had $196.3 million and $282.8 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, 2015 and December 31, 2014, the Company had $410.3 million and $797.5 million, respectively, of accrued capital expenditures.

Note 4. Derivative Instruments

The Company recognizes all derivative instruments on the balance sheet as either assets or liabilities measured at fair value. The Company has not designated its derivative instruments as hedges for accounting purposesCrude oil and as a result, marks its derivative instruments to fair value and recognizes the changes in fair value in the unaudited condensed consolidated statements of comprehensive income (loss) under the caption “Gain (loss) on derivative instruments, net.”natural gas derivatives

The Company may utilize crude oil and natural gas swap and collar derivative contracts to economically hedge against the variability in cash flows associated with ~~the sale~~future sales of ~~future~~ crude oil and 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 all crude oil and natural gas derivative instruments on the balance sheet as either assets or liabilities measured at fair value. The Company has not designated its crude oil and natural gas derivative instruments 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 crude oil and natural gas derivatives, net”, which is a component of "Total revenues".

With respect to a crude oil or 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 crude oil or 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, and neither~~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~~

The Company’s crude oil and natural gas derivative contracts are settled based upon reported settlement prices on commodity exchanges, with crude oil derivative settlements based on ~~NYMEX West Texas Intermediate (“WTI”) pricing or~~ Inter-Continental Exchange (“ICE”) pricing for Brent crude oil and natural gas derivative settlements based on NYMEX Henry Hub pricing. The estimated fair value of derivative contracts is based upon various factors, including commodity exchange prices, over-the-counter quotations, and, in the case of collars and written call options, volatility, the risk-free interest rate, and the time to expiration. The calculation of the fair value of collars and written call options requires the use of an option-pricing model. See Note 5. Fair Value Measurements.

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

At June 30, ~~2015,~~2016, the Company had outstanding crude oil and natural gas derivative contracts with respect to future production as set forth in the tables below. The hedged volumes reflected below represent an aggregation of multiple derivative contracts that have varying durations and may not be realized on a ratable basis over the periods indicated.

Crude Oil - NYMEX WTI Ceilings
Weighted Average
Price
Period and Type of Contract Bbls Range
July 2015 - December 2015
Written call options - WTI (1) 2,208,000
$95.85 - $103.75 $ 98.36

Crude Oil - ICE Brent Ceilings
Weighted Average
Price
Period and Type of Contract Bbls Range
July 2015 - December 2015
Written call options - ICE Brent (1) 368,000
$ 107.40
$ 107.40
January 2016 - December 2016
Written call options - ICE Brent (1) 1,464,000
$ 107.70
$ 107.70

Collars
Natural Gas - NYMEX Henry Hub Swaps Weighted Average Price Floors Ceilings
Weighted Average Price Weighted Average Price
Period and Type of Contract MMBtus Range Range
July 2015 - December 2015
Swaps - Henry Hub 7,360,000
$ 4.16

Collars - Henry Hub 14,720,000

$3.50 - $3.75 $ 3.69
$4.89 - $5.48 $ 5.04
January 2016 - December 2016
Swaps - Henry Hub 75,930,000
$ 3.85

January 2017 - December 2017
Swaps - Henry Hub 25,550,000
$ 3.35



Crude Oil - ICE Brent

Period and Type of Contract	Bbls	Ceiling Price
July 2016 - December 2016
Written call options - ICE Brent (1)	736,000	$	107.70

(1) Written call options represent the ceiling positions remaining from the Company's previous crude oil collar contracts. The floor positions of the collars were liquidated in the fourth quarter of 2014. For these written call options, the Company is required to make a payment to the counterparty if the settlement price for any settlement period is above the ceiling price.



				Collars
Natural Gas - NYMEX Henry Hub		Swaps Weighted Average Price		Floors			Ceilings
					Weighted Average Price			Weighted Average Price
Period and Type of Contract	MMBtus			Range	Weighted Average Price		Range	Weighted Average Price
July 2016 - December 2016
Swaps - Henry Hub	78,110,000	$	3.00
January 2017 - December 2017
Swaps - Henry Hub	25,550,000	$	3.35
Collars - Henry Hub	65,700,000			$2.40 - $3.00	$	2.47	$2.92 - $3.88	$	3.08

~~Continental Resources, Inc.~~Crude oil and ~~Subsidiaries~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

~~Derivative~~natural gas derivative gains and losses

~~The following table presents cash settlements on matured derivative instruments and non-cash gains and losses on open derivative instruments for the periods presented.~~ Cash receipts and payments ~~below~~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,						Three months ended June 30,						Six months ended June 30,
In thousands	2015			2014			2015			2014			2016			2015			2016			2015
Cash received (paid) on derivatives:
Crude oil fixed price swaps	$	—		$	(50,499	)	$	—		$	(73,022	)
Crude oil collars	—			(1,453		)	—			(2,037		)
Cash received on derivatives:
Natural gas fixed price swaps	5,551			(12,191		)	23,942			(22,348		)	$	38,778		$	5,551		$	77,967		$	23,942
Natural gas collars	7,631			—			12,675			—			—			7,631			—			12,675
Cash received (paid) on derivatives, net	13,182			(64,143		)	36,617			(97,407		)
Cash received on derivatives, net													38,778			13,182			77,967			36,617
Non-cash gain (loss) on derivatives:
Crude oil fixed price swaps	—			(201,482		)	—			(187,792		)
Crude oil collars	—			(4,369		)	—			914
Crude oil written call options	3			—			3,927			—			6			3			38			3,927
Natural gas fixed price swaps	(9,296		)	7,494			(2,804		)	(17,907		)	(101,308		)	(9,296		)	(98,915		)	(2,804		)
Natural gas collars	(8,626		)	(24		)	(9,722		)	(6		)	(19,733		)	(8,626		)	(19,235		)	(9,722		)
Non-cash gain (loss) on derivatives, net	(17,919		)	(198,381		)	(8,599		)	(204,791		)	(121,035		)	(17,919		)	(118,112		)	(8,599		)
Gain (loss) on derivative instruments, net	$	(4,737	)	$	(262,524	)	$	28,018		$	(302,198	)
Gain (loss) on crude oil and natural gas derivatives, net													$	(82,257	)	$	(4,737	)	$	(40,145	)	$	28,018

Diesel fuel derivatives

In March 2016, the Company entered into diesel fuel swap derivative contracts to economically hedge against the variability in cash flows associated with future purchases of diesel fuel for use in drilling activities. The Company has hedged approximately 19 million gallons of diesel fuel over the period from July 2016 to December 2017 at a weighted average price of $1.41 per gallon. With respect to these diesel fuel swap contracts, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is greater 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 less than the swap price. The diesel fuel swap contracts are settled based upon reported NYMEX settlement prices for New York Harbor ultra-low sulfur diesel fuel.

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

The Company recognizes its diesel fuel derivative instruments on the balance sheet as either assets or liabilities measured at fair value. The estimated fair value is based upon various factors, including commodity exchange prices, over-the-counter quotations, the risk-free interest rate, and time to expiration. The Company has not designated its diesel fuel derivative instruments as hedges for accounting purposes and, as a result, marks the 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 “Operating costs and expenses—Net gain on sale of assets and other.” For the three and six months ended June 30, 2016, the Company recognized non-cash gains of $4.2 million and $3.1 million, respectively, associated with its diesel fuel derivatives.

Balance sheet offsetting of derivative assets and liabilities

~~All of the~~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”. 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 crude oil, natural gas, and diesel fuel derivative assets and liabilities, 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, 2015			December 31, 2014			June 30, 2016			December 31, 2015
Commodity derivative assets:
Gross amounts of recognized assets	$	72,275		$	84,415		$	37,249		$	120,385
Gross amounts offset on balance sheet	(46		)	—			(17,511		)	(11,903		)
Net amounts of assets on balance sheet	72,229			84,415			19,738			108,482
Commodity derivative liabilities:
Gross amounts of recognized liabilities	(1,167		)	(4,770		)	(51,028		)	(19,192		)
Gross amounts offset on balance sheet	—			16			17,511			11,903
Net amounts of liabilities on balance sheet	$	(1,167	)	$	(4,754	)	$	(33,517	)	$	(7,289	)

~~Continental Resources, Inc. and Subsidiaries~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

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


In thousands	June 30, 2015			December 31, 2014			June 30, 2016			December 31, 2015
Derivative assets	$	50,214		$	52,423		$	16,693		$	93,922
Noncurrent derivative assets	22,015			31,992			3,045			14,560
Net amounts of assets on balance sheet	72,229			84,415			19,738			108,482
Derivative liabilities	(339		)	(1,645		)	(24,227		)	(3,583		)
Noncurrent derivative liabilities	(828		)	(3,109		)	(9,290		)	(3,706		)
Net amounts of liabilities on balance sheet	(1,167		)	(4,754		)	(33,517		)	(7,289		)
Total derivative assets, net	$	71,062		$	79,661
Total derivative assets (liabilities), net							$	(13,779	)	$	101,193

Note 5. Fair Value Measurements

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

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

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

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

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

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

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 ~~fixed price swaps,~~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 ~~fixed price swaps~~swap contracts are calculated mainly using significant observable inputs (Level 2). Calculation of the fair values of collars and written call options requires the use of an industry-standard option pricing model that considers various inputs including quoted forward ~~commodity~~ 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.

~~Continental Resources, Inc. and Subsidiaries~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

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, ~~2015~~2016 and December 31, ~~2014.~~2015.


	Fair value measurements at June 30, 2015 using:										Fair value measurements at June 30, 2016 using:
In thousands	Level 1		Level 2			Level 3		Total			Level 1		Level 2			Level 3		Total
Derivative assets (liabilities):
Fixed price swaps	$	—	$	59,795		$	—	$	59,795
Swaps											$	—	$	8,652		$	—	$	8,652
Collars	—		12,094			—		12,094			—		(22,430		)	—		(22,430		)
Written call options	—		(827		)	—		(827		)	—		(1		)	—		(1		)
Total	$	—	$	71,062		$	—	$	71,062		$	—	$	(13,779	)	$	—	$	(13,779	)

	Fair value measurements at December 31, 2014 using:										Fair value measurements at December 31, 2015 using:
In thousands	Level 1		Level 2			Level 3		Total			Level 1		Level 2			Level 3		Total
Derivative assets (liabilities):
Fixed price swaps	$	—	$	62,599		$	—	$	62,599
Swaps											$	—	$	104,426		$	—	$	104,426
Collars	—		21,816			—		21,816			—		(3,195		)	—		(3,195		)
Written call options	—		(4,754		)	—		(4,754		)	—		(38		)	—		(38		)
Total	$	—	$	79,661		$	—	$	79,661		$	—	$	101,193		$	—	$	101,193

Assets Measured at Fair Value on a Nonrecurring Basis

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

Asset Impairments – Proved crude oil and natural gas properties are reviewed for impairment on a field-by-field basis each quarter. The estimated future cash flows expected in connection with the field are compared to the carrying amount of the field to determine if the carrying amount is recoverable. If the carrying amount of the field exceeds its estimated undiscounted future cash flows, the carrying amount of the field is reduced to its estimated fair value. 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 ~~management’s~~the Company's estimates of future crude oil and natural gas production, commodity prices based on commodity futures price strips adjusted for differentials, operating ~~and development~~ costs, and a risk-adjusted discount rate. The fair value of proved crude oil and natural gas properties is calculated using significant unobservable

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

inputs (Level 3). The following table sets forth quantitative information about the significant unobservable inputs used by the Company to calculate the fair value of proved crude oil and natural gas properties using a discounted cash flow method.



Unobservable Input		Assumption
Future production		Future production estimates for each property
Forward commodity prices		Forward NYMEX strip prices through ~~2019~~2020 (adjusted for differentials), escalating 3% per year thereafter
Operating ~~and development~~ costs		Estimated costs for the current year, escalating 3% per year thereafter
Productive life of field		Ranging from 0 to 5033 years
Discount rate		10%

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 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.

~~During~~Proved properties were reviewed for impairment at June 30, 2016 and June 30, 2015. For the ~~periods~~three and six months ended June 30, ~~2015~~2016, estimated future net cash flows were determined to be in excess of cost basis, therefore no impairment was recorded for the Company’s proved crude oil and natural gas properties. For the three and six months ended June 30, ~~2014,~~2015, the Company determined the carrying amounts of certain proved properties were not recoverable from future cash flows at that time and, therefore, were impaired. Impairments of proved properties ~~amounted to $5.0 million and $75.0 million~~ for the three and six months ended June 30, 2015 totaled $5.0 million and $75.0 million, respectively, ~~resulting from depressed commodity prices that indicated the carrying amounts for certain fields~~and were ~~not recoverable. The 2015 year to date impairments reflect fair value adjustments~~ primarily concentrated in an emerging area with ~~limited~~minimal production ~~history~~ and costly reserve additions ($41.2 million, including $5.0 million in the 2015 second quarter), the Medicine Pole Hills units ($14.7 million), various ~~non-core~~legacy areas in the South region ($11.0 million), and non-Bakken areas of North Dakota and Montana ($8.1 million). The impaired properties were written down to their estimated fair value totaling approximately $38.2 ~~million.~~

~~Continental Resources, Inc. and Subsidiaries~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

Impairments of proved properties totaled $27.5 million and $31.3 million for the three and six months ended June 30, 2014, respectively, which primarily reflect fair value adjustments made for certain properties in non-core areas of the South region. The impaired properties were written down to their estimated fair value totaling approximately $10.2 million as of June 30, ~~2014.~~2015.

Certain unproved crude oil and natural gas properties were impaired during the three and six months ended June 30, ~~2015~~2016 and ~~2014,~~2015, reflecting recurring amortization of undeveloped leasehold costs on properties ~~that management~~the Company expects will not be transferred to proved properties over the lives of the leases based on drilling plans, experience of successful drilling, and the average holding period.

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


	Three months ended June 30,				Six months ended June 30,				Three months ended June 30,				Six months ended June 30,
In thousands	2015		2014		2015		2014		2016		2015		2016		2015
Proved property impairments	$	5,028	$	27,529	$	75,043	$	31,291	$	—	$	5,028	$	—	$	75,043
Unproved property impairments	71,844		51,787		149,389		106,233		66,112		71,844		145,039		149,389
Total	$	76,872	$	79,316	$	224,432	$	137,524	$	66,112	$	76,872	$	145,039	$	224,432

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

Financial Instruments Not Recorded at Fair Value

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


	June 30, 2015				December 31, 2014				June 30, 2016				December 31, 2015
In thousands	Carrying Amount		Fair Value		Carrying Amount		Fair Value		Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Debt:
Credit facility	$	1,225,000	$	1,225,000	$	165,000	$	165,000
Revolving credit facility									$	885,000	$	885,000	$	853,000	$	853,000
Term loan									498,556		500,000		498,274		500,000
Note payable	15,349		13,600		16,375		14,900		13,251		12,000		14,309		12,500
7.375% Senior Notes due 2020	196,278		211,200		195,997		213,000		196,878		206,000		196,574		179,200
7.125% Senior Notes due 2021	395,007		426,000		394,668		421,000		395,732		414,000		395,365		388,300
5% Senior Notes due 2022	1,996,664		1,970,000		1,996,507		1,857,900		1,997,004		1,940,000		1,996,831		1,480,400
4.5% Senior Notes due 2023	1,481,446		1,439,800		1,480,479		1,372,800		1,483,470		1,398,800		1,482,451		1,061,000
3.8% Senior Notes due 2024	989,431		910,800		988,940		868,700		990,443		877,500		989,932		700,300
4.9% Senior Notes due 2044	690,981		589,300		690,912		572,400		691,124		590,800		691,052		430,500
Total debt	$	6,990,156	$	6,785,700	$	5,928,878	$	5,485,700	$	7,151,458	$	6,824,100	$	7,117,788	$	5,605,200

The fair ~~value~~values of revolving credit facility borrowings ~~approximates carrying~~and the term loan approximate face value based on borrowing rates available to the Company for bank loans with similar terms and maturities and isare classified as Level 2 in the fair value hierarchy.

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 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 7.375% Senior Notes due 2020 (“2020 Notes”), the 7.125% Senior Notes due 2021 (“2021 Notes”), 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"), 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 6. Long-Term Debt

Long-term debt, net of unamortized discounts, premiums, and debt issuance costs totaling ~~$50.3~~$46.9 million and ~~$52.6~~$49.6 million at June 30, ~~2015~~2016 and December 31, ~~2014,~~2015, respectively, consists of the following. ~~See~~ ~~Note 2. Basis of Presentation and Significant Accounting Policies—Adoption of new accounting pronouncement~~ ~~for a discussion of the impact on long-term debt from the Company's June 30, 2015 adoption of ASU 2015-03.~~


In thousands	June 30, 2015		December 31, 2014		June 30, 2016		December 31, 2015
Credit facility	$	1,225,000	$	165,000
Revolving credit facility					$	885,000	$	853,000
Term loan					498,556		498,274
Note payable	15,349		16,375		13,251		14,309
7.375% Senior Notes due 2020	196,278		195,997		196,878		196,574
7.125% Senior Notes due 2021	395,007		394,668		395,732		395,365
5% Senior Notes due 2022	1,996,664		1,996,507		1,997,004		1,996,831
4.5% Senior Notes due 2023	1,481,446		1,480,479		1,483,470		1,482,451
3.8% Senior Notes due 2024	989,431		988,940		990,443		989,932
4.9% Senior Notes due 2044	690,981		690,912		691,124		691,052
Total debt	$	6,990,156	$	5,928,878	$	7,151,458	$	7,117,788
Less: Current portion of long-term debt	2,110		2,078		2,179		2,144
Long-term debt, net of current portion	$	6,988,046	$	5,926,800	$	7,149,279	$	7,115,644

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

Revolving Credit Facility

The Company has an unsecured revolving credit facility, maturing on May 16, 2019, with aggregate commitments totaling ~~$2.5~~$2.75 billion at June 30, 2016, which may be increased up to a total of $4.0 billion upon agreement between the Company and participating lenders.

The Company had ~~$1.23 billion~~$885 million and ~~$165~~$853 million of outstanding borrowings on its revolving credit facility at June 30, ~~2015~~2016 and December 31, ~~2014,~~2015, respectively. Borrowings bear interest at market-based interest rates plus a margin ~~that is~~ based on the terms of the borrowing and the credit ratings assigned to the Company's senior, unsecured, ~~debt.~~long-term indebtedness. The weighted-average interest rate on outstanding borrowings at June 30, ~~2015~~2016 was ~~1.7%~~2.2%.

The Company had approximately ~~$1.27~~$1.86 billion of borrowing availability on its revolving credit facility at June 30, ~~2015~~2016 and incurs commitment fees based on currently assigned credit ratings of ~~0.225%~~0.30% per annum on the daily average amount of unused borrowing ~~availability.~~availability under its revolving credit facility.

The revolving credit facility contains certain restrictive covenants including a requirement that the Company maintain a consolidated net debt to total capitalization ratio of no greater than 0.65 to 1.00. This ratio represents the ratio of net debt ~~(total~~(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 ~~this covenant~~the revolving credit facility covenants at June 30, ~~2015~~.2016.

~~Continental Resources, Inc. and Subsidiaries~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

Senior Notes

The following table summarizes the face values, maturity dates, semi-annual interest payment dates, and optional redemption periods related to the Company’s outstanding senior note obligations at June 30, ~~2015.~~2016.

2020 Notes

2021 Notes

2022 Notes

2023 Notes

2024 Notes

2044 Notes

2020 Notes

2021 Notes

2022 Notes

2023 Notes

2024 Notes

2044 Notes

Face value (in thousands)

$200,000

$400,000

$2,000,000

$1,500,000

$1,000,000

$700,000

$200,000

$400,000

$2,000,000

$1,500,000

$1,000,000

$700,000

Maturity date

Oct 1, 2020

April 1, 2021

Sep 15, 2022

April 15, 2023

June 1, 2024

June 1, 2044

Oct 1, 2020

April 1, 2021

Sep 15, 2022

April 15, 2023

June 1, 2024

June 1, 2044

Interest payment dates

April 1, Oct 1

March 15, Sep 15

April 15, Oct 15

June 1, Dec 1

April 1, Oct 1

March 15, Sep 15

April 15, Oct 15

June 1, Dec 1

Call premium redemption period (1)

Oct 1, 2015

April 1, 2016

March 15, 2017

—

Oct 1, 2015

April 1, 2016

March 15, 2017

—

Make-whole redemption period (2)

Oct 1, 2015

April 1, 2016

March 15, 2017

Jan 15, 2023

Mar 1, 2024

Dec 1, 2043

—

March 15, 2017

Jan 15, 2023

Mar 1, 2024

Dec 1, 2043


(1)	On or after these dates, the Company has the option to redeem all or a portion of its senior notes of the applicable series at the decreasing redemption prices specified in the respective senior note indentures (together, the “Indentures”) plus any accrued and unpaid interest to the date of redemption.


(2)	At any time prior to these dates, the Company has the option to redeem all or a portion of its senior notes of the applicable series at the “make-whole” redemption prices or amounts specified in the Indentures plus any accrued and unpaid interest to the date of redemption.

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

The indentures governing the Company's senior notes contain covenants that, among other things, limit the Company's ability to create liens securing certain indebtedness, enter into certain ~~sale and leaseback~~sale-leaseback transactions, and consolidate, merge or transfer 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, ~~2015.~~2016. Two of the Company’s subsidiaries, Banner Pipeline Company, L.L.C. and CLR Asset Holdings, LLC, which have no material assets or operations, fully and unconditionally guarantee the senior ~~notes.~~notes on a joint and several basis. The Company’s other subsidiaries, the value of whose assets and operations are minor, do not guarantee the senior ~~notes.~~notes as of June 30, 2016.

Term Loan

In November 2015, the Company borrowed $500 million under a three-year term loan agreement, the proceeds of which were used to repay a portion of the borrowings then outstanding on the Company's revolving credit facility. The term loan matures in full on November 4, 2018 and bears interest at a variable market-based interest rate plus a margin based on the

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

terms of the borrowing and the credit ratings assigned to the Company's senior, unsecured, long-term indebtedness. The interest rate on the term loan at June 30, 2016 was 1.95%.

The term loan contains certain restrictive covenants including a requirement that the Company maintain a consolidated net debt to total capitalization ratio of no greater than 0.65 to 1.0, consistent with the covenant requirement in the Company's revolving credit facility. The Company was in compliance with the term loan covenants at June 30, 2016.

Note Payable

In February 2012, 20 Broadway Associates LLC, a 100% 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. Accordingly, approximately ~~$2.1~~$2.2 million is reflected as a current liability under the caption “Current portion of long-term debt” in the condensed consolidated balance sheets as of June 30, ~~2015.~~2016.

Note 7. Commitments and Contingencies

Included below is a discussion of various future commitments of the Company as of June 30, ~~2015.~~2016. The commitments under these arrangements are not recorded in the accompanying condensed consolidated balance sheets.

Drilling commitments – As of June 30, ~~2015,~~2016, the Company had drilling rig contracts with various terms extending ~~through March 2019. These contracts were entered into in the ordinary course of business~~to year-end 2019 to ensure rig availability ~~to allow the Company to execute its business objectives~~ in its ~~strategic plays.~~key operating areas. Future commitments as of June 30, ~~2015~~2016 total approximately ~~$536~~$319 million, of which ~~$121~~$97 million is expected to be incurred in the remainder of ~~2015, $220 million in~~ 2016, ~~$129~~$136 million in 2017, ~~$61~~$62 million in 2018, and $5$24 million in 2019.

Pipeline transportation commitments – The Company has entered into firm transportation commitments to guarantee pipeline access capacity on ~~operational~~ crude oil and natural gas pipelines. The commitments, which have varying terms extending as far as 2027, require the Company to pay per-unit transportation charges regardless of the amount of pipeline capacity used. Future commitments remaining as of June 30, ~~2015~~2016 under the ~~operational~~ pipeline transportation arrangements amount to approximately ~~$1.1 billion,~~$893 million, of which ~~$104~~$107 million is expected to be incurred in the remainder of ~~2015, $213 million in~~ 2016, ~~$210~~$207 million in 2017, ~~$205~~$208 million in 2018, ~~$170~~$154 million in 2019, $47 million in 2020, and ~~$217~~$170 million thereafter.

~~Continental Resources, Inc. and Subsidiaries~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

Further, the Company was a party to a five year firm transportation commitment (the "Agreement") for a future crude oil pipeline project being considered for development that is not yet operational. The project requires the granting of regulatory approvals and requires additional construction efforts by the counterparty before being completed. The project has faced significant delays and has failed to gain the necessary permits and approvals. As a result of the persistent delays and continuous uncertainty, the Agreement’s basic assumptions and purpose have become commercially impracticable. Accordingly, in 2015 the Company provided a shipper termination notice pursuant to the Agreement and formally provided the counterparty with the Company’s termination of the Agreement in its entirety. The Company's previously disclosed commitments under the Agreement totaled approximately $260 million, which is no longer expected to be incurred.

The Company’s pipeline commitments are for production primarily in the North ~~region where the Company allocates a significant portion of its capital expenditures.~~region. The Company is not committed under these contracts to deliver fixed and determinable quantities of crude oil or natural gas in the future.

~~Fuel purchase commitment~~– The Company has entered into a forward purchase contract with a third party to purchase specified quantities of diesel fuel at specified prices each month through June 2016 for use in the normal course of drilling operations. Over the remaining contract term, the Company has committed to purchase approximately 21 million gallons of diesel fuel at varying prices depending on the grade of diesel fuel purchased and the timing and location of delivery. The contract satisfies a significant portion of the Company's anticipated diesel fuel needs and provides for physical delivery to desired locations. Future commitments under the arrangement as of June 30, 2015 total approximately $61 million, of which $30 million is expected to be incurred in the remainder of 2015 and $31 million is expected to be incurred in 2016.

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 the ~~Company alleging~~Company. The Petition alleged the Company improperly deducted post-production costs from royalties paid to plaintiffs and other royalty interest owners ~~as categorized in the Petition~~ 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 seek recovery of compensatory damages, interest, punitive damages and attorney fees on behalf of the proposed class. ~~In addition,~~On November 3, 2014, plaintiffs filed an Amended Petition that did not add any substantive claims, but sought a “hybrid class action” in which they sought certification of certain claims for injunctive relief, reserving the right to seek a further class certification on money damages in the future. Plaintiffs ~~also~~ filed an Amended Motion for Class Certification on January 9, 2015, that modified the proposed class to royalty owners in Oklahoma production from July 1, 1993, to the present (instead of 1980 to the present) and sought certification of over 45 separate “issues” for injunctive or declaratory relief, again, reserving the right to seek a further class certification of money damages in the future. The Company responded to the petition, its amendment, and the motions for class certification denying the allegations and raising a number of affirmative defenses and legal arguments to each of the claims and filings. Certain discovery was undertaken and the “hybrid” motion was briefed by plaintiffs and the Company. A hearing on the “hybrid” class certification was held on June 1st and 2nd, 2015. On June 11, 2015, the trial court certified a “hybrid” class as requested by plaintiffs. The Company has appealed the trial court’s class certification order, which will be reviewed de novo by the appellate court. The appeal briefing is complete and ready for determination by the court. An unsuccessful mediation was conducted on December 7, 2015. The Company is not currently able to estimate a reasonably possible loss or range of loss or what impact, if any, the action will 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 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. Although not currently at issue in the “hybrid” certification, plaintiffs have alleged underpayments in excess of $200 million that they may claim as damages, which may increase with the passage of time, a majority of which would be comprised of interest. The Company disputes plaintiffs’ claims, disputes that the case meets the requirements for a class action and is

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

vigorously defending the case. The Company will continue to assert its defenses to the case as certified as well as any future attempt to certify a money damages class.

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, disputes with tax authorities and other matters. While the outcome of these legal matters cannot be predicted with certainty, the Company does not expect them to have a material effect on its financial condition, results of operations or cash flows. As of both June 30, ~~2015~~2016 and December 31, ~~2014,~~2015, the Company had recorded a liability in the condensed consolidated balance sheets under the caption “Other noncurrent liabilities” of ~~$3.7~~$6.1 million ~~and $2.9 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.

~~Continental Resources, Inc. and Subsidiaries~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

Note 8. Stock-Based Compensation

The Company has granted restricted stock to employees and directors pursuant to the Continental Resources, Inc. ~~2005 Long-Term Incentive Plan (“2005 Plan”) and~~ 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 ~~$16.2~~$11.8 million and ~~$15.0~~$16.2 million for the three months ended June 30, ~~2015~~2016 and ~~2014,~~2015, respectively, and ~~$27.4~~$21.0 million and ~~$26.0~~$27.4 million for the six months ended June 30, ~~2015~~2016 and ~~2014,~~2015, respectively.

In May 2013, the Company adopted the 2013 Plan and reserved ~~a maximum of~~ 19,680,072 shares of common stock that may be issued pursuant to the plan. The 2013 Plan replaced the Company's 2005 Plan as the instrument used to grant long-term incentive awards and no further awards will be granted under the 2005 Plan. However, restricted stock awards granted under the 2005 Plan prior to the adoption of the 2013 Plan will remain outstanding in accordance with their terms. As of June 30, ~~2015,~~2016, the Company had ~~a maximum of 16,958,144~~15,177,005 shares of restricted stock available to grant to ~~officers,~~employees and directors ~~and select employees~~ under the 2013 Plan.

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

A summary of changes in non-vested restricted shares outstanding for the six months ended June 30, ~~2015~~2016 is presented ~~below:~~below.


	Number of non-vested shares		Weighted average grant-date fair value		Number of non-vested shares		Weighted average grant-date fair value
Non-vested restricted shares outstanding at December 31, 2014	2,678,764		$	49.40
Non-vested restricted shares outstanding at December 31, 2015					3,249,611		$	48.20
Granted	1,338,699		47.77		2,007,078		21.56
Vested	(360,172	)	45.95		(1,033,278	)	39.38
Forfeited	(160,647	)	52.69		(105,835	)	43.70
Non-vested restricted shares outstanding at June 30, 2015	3,496,644		$	48.98
Non-vested restricted shares outstanding at June 30, 2016					4,117,576		$	37.54

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 a fixed amount determined at the grant date fair value and is recognized ratably over the vesting period as services are rendered by employees and directors. ~~The expected life of restricted stock is based on the non-vested period that remains subsequent to the date of grant.~~ 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, ~~2015 at the vesting date~~2016 was approximately ~~$17.0~~$21.5 million. As of June 30, ~~2015,~~2016, there was approximately ~~$98~~$81 million of unrecognized compensation expense related to non-vested restricted stock. This expense is expected to be recognized ~~ratably~~ over a weighted average period of ~~1.6~~1.9 years.

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

Note 9. Accumulated Other Comprehensive Loss

Adjustments resulting from the process of translating foreign functional currency financial statements into U.S. dollars are included in "Accumulated other comprehensive loss" within shareholders’ equity on the condensed consolidated balance sheets. The following table summarizes the change in accumulated other comprehensive loss for the three and six months ended June 30, 2016 and 2015:


							Three months ended June 30,						Six months ended June 30,
In thousands	Three months ended June 30, 2015			Six months ended June 30, 2015			2016			2015			2016			2015
Beginning accumulated other comprehensive loss, net of tax	$	(3,490	)	$	(385	)	$	(2,928	)	$	(3,490	)	$	(3,354	)	$	(385	)
Foreign currency translation adjustments	625			(2,480		)	25			625			451			(2,480		)
Income tax (expense) benefit (1)	—			—
Income taxes (1)							—			—			—			—
Other comprehensive income (loss), net of tax	625			(2,480		)	25			625			451			(2,480		)
Ending accumulated other comprehensive loss, net of tax	$	(2,865	)	$	(2,865	)	$	(2,903	)	$	(2,865	)	$	(2,903	)	$	(2,865	)


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

Note 10. Property Dispositions

In April 2016, the Company sold approximately 132,000 net acres of undeveloped leasehold acreage located in Wyoming to a third party for cash proceeds of $110.0 million. The proceeds were used to pay down a portion of outstanding borrowings on the Company's revolving credit facility. In connection with the transaction, the Company recognized a pre-tax gain of $96.9 million. The disposed properties represented an immaterial portion of the Company’s total acreage and included no production or proved reserves.

In May 2015, the Company ~~assigned~~sold certain ~~non-producing~~undeveloped leasehold acreage in Oklahoma to a third party for cash proceeds of $25.9 million and recognized a pre-tax gain on the transaction of $20.5 million. The ~~assigned properties represented an immaterial portion of the Company’s leasehold acreage.~~

During the six months ended June 30, 2014, the Company sold certain non-strategic properties in various areas to third parties for proceeds totaling $39.0 million. In connection with the transactions, the Company recognized pre-tax losses totaling $6.4 million. The disposed properties represented an immaterial portion of the Company’s total acreage.

Note 11. Subsequent Event

On August 2, 2016, the Company entered into an agreement to sell non-strategic producing and non-producing properties in the SCOOP play in Oklahoma to a third party for cash proceeds of $281 million. The disposition is expected to close in October 2016. The properties to be disposed represent an immaterial portion of the Company’s total acreage, proved reserves, production, and revenues. The Company expects to use the sales proceeds to reduce outstanding debt.


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

The following discussion and analysis should be read in conjunction with the unaudited condensed consolidated financial statements and notes thereto included elsewhere in this report and our historical consolidated financial statements and notes included in our Annual Report on Form 10-K for the year ended December 31, ~~2014~~2015. 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, ~~2014~~2015, along with Cautionary Statement for the Purpose of the “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995 at the beginning of this report, for information about the risks and uncertainties that could cause our actual results to be materially different than our forward-looking statements.

Overview

We are an independent crude oil and natural gas company engaged in the exploration, development and production of crude oil and natural gas. 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, ~~play in~~STACK, and Northwest Cana areas of Oklahoma.

Business Environment and Outlook

Commodity prices ~~have remained depressed through June 30, 2015~~showed some signs of stabilization and recovery in the second quarter of 2016, but still remain volatile and unpredictable due to domestic and global supply and demand factors. In light of the challenges facing our industry, our primary business strategies for 2016 continue to ~~be volatile~~focus on: (1) optimizing cash flows through operating efficiencies and ~~unpredictable. Management's plans and related capital projections for the remainder of 2015 are reflective of the depressed commodity price environment. Our 2015 capital budget has been established~~cost reductions, (2) high-grading investments based on ~~an expectation~~rates of ~~available~~return and opportunities to convert undeveloped acreage to acreage held by production, and (3) balancing capital spending with cash flows ~~from operations and availability under our credit facility. We will continue~~ to monitor our capital spending closely based on actual and projected cash flows and could scale back our remaining 2015 spending should commodity prices remain at current levels or decrease. Conversely, a significant improvement in crude oil prices could result in an increase in our capital expenditures.

Under our current capital plan, we are seeking to generally align our capital expenditures with operating cash flows for the remainder of 2015, which we expect will slow our rate of capital spending, credit facilityminimize new borrowings and production growth in the third and fourth quarters compared to levels achieved through June 30, 2015. Accordingly, our results achieved through June 30, 2015 may not be indicative of the results to be achieved for the remainder of 2015.maintain ample liquidity.

Management believes we are positioned to withstand the current weakness in commodity prices and remains confident in the Company's underlying financial strength to manage the challenges presented in this price environment. We believe the depth and quality of our asset base coupled with our financial strength allow us to be adaptable in a variety of price environments. We will continue to manage through this downturn focusing on operating efficiencies, reducing costs, and maintaining our financial strength.

~~2015~~2016 Highlights

Production

Production for the second quarter of ~~2015~~2016 averaged ~~226,547~~219,323 Boe per day, ~~an increase~~a decrease of ~~10%~~5% from the first quarter of ~~2015~~2016 and ~~35% higher~~3% lower than the second quarter of ~~2014.~~2015. Year to date production averaged ~~216,742~~225,063 Boe per day, a ~~35%~~4% increase ~~over~~from the comparable ~~2014~~2015 period.

North Dakota Bakken production averaged ~~127,872~~114,554 Boe per day for the second quarter of ~~2015, a 6% increase over~~2016, an 11% decrease from the first quarter of ~~2015~~2016 and ~~35% higher~~10% lower than the second quarter of ~~2014.~~2015. Year to date, North Dakota Bakken production averaged ~~124,434~~121,861 Boe per day, a ~~39% increase over~~2% decrease from the comparable ~~2014~~2015 period.

SCOOP production averaged ~~62,546~~64,669 Boe per day for the second quarter of ~~2015, a 25% increase over~~2016, in line with the first quarter of ~~2015~~2016 and ~~83%~~3% higher than the second quarter of ~~2014.~~2015. Year to date, SCOOP production averaged ~~56,249~~64,642 Boe per day, a ~~77%~~15% increase over the comparable ~~2014~~2015 period.

~~SCOOP~~Combined production from STACK and Northwest Cana averaged 14,610 Boe per day for the second quarter of 2016, an increase of 31% from the first quarter of 2016 and 231% higher than the second quarter of 2015. Year to date, combined STACK and Northwest Cana production averaged 12,868 Boe per day, a 228% increase over the comparable 2015 period.

The South region comprised ~~28%~~38% of our total production for the ~~2015~~2016 second quarter compared to ~~24%~~34% for the 2016 first quarter and 31% for the 2015 ~~first quarter and 20% for the 2014~~ second quarter. ~~SCOOP~~The South region comprised ~~26%~~36% of our total production for year to date ~~2015~~2016 compared to ~~20%~~30% for the comparable ~~2014~~2015 period.

Revenues

Crude oil and natural gas revenues for the ~~2015~~2016 second quarter decreased ~~31%~~33% compared to the ~~2014~~2015 second quarter driven by a ~~49%~~30% decrease in realized commodity prices coupled with a 5% decrease in total sales volumes.

Year to date crude oil and natural gas revenues decreased 32% from the comparable 2015 period driven by a 35% decrease in realized commodity prices, the effect of which was partially offset by a ~~36% increase in total sales volumes.~~

~~Year to date crude oil and natural gas revenues decreased 36% from the comparable 2014 period driven by a 53% decrease in realized commodity prices, the effect of which was partially offset by a 37%~~4% increase in total sales volumes.

Average crude oil sales prices for the second quarter and year to date periods of ~~2015~~2016 decreased ~~46%~~23% and ~~51%~~29%, respectively, from the comparable ~~2014~~2015 periods.

Crude oil sales volumes for the second quarter and year to date periods of ~~2015 increased 30%~~2016 decreased 13% and ~~34%~~5%, respectively, from the comparable ~~2014~~2015 periods.

Average natural gas sales prices for the second quarter and year to date periods of ~~2015~~2016 decreased ~~57%~~43% and ~~60%~~46%, respectively, from the comparable ~~2014~~2015 periods.

Natural gas sales volumes for the second quarter and year to date periods of ~~2015~~2016 increased ~~49%~~13% and ~~43%~~23%, respectively, from the comparable ~~2014~~2015 periods.

~~Proved property impairments~~

Depressed commodity prices and downward revisions to proved reserves in the second quarter of 2015 adversely impacted the recoverability of capitalized costs in certain operating areas and contributed to the recognition of non-cash impairment charges for proved properties totaling $5.0 million for the second quarter, bringing year to date proved property impairments to $75.0 million through June 30, 2015. These impairments were primarily concentrated in non-core areas of our North and South regions.

Capital expenditures and drilling activity

~~We invested~~Capital expenditures excluding acquisitions totaled approximately ~~$585.5~~$209.4 million ~~in our capital program in~~for the second quarter of ~~2015, excluding $6.4 million of unbudgeted acquisitions,~~2016, bringing ~~our~~ year to date 2016 non-acquisition capital expenditures to $529.3 million compared to $1.57 billion ~~through June 30,~~for year to date 2015.

For the second quarter ~~and year to date periods~~ of ~~2015~~2016 we participated in the drilling and completion of ~~the following number~~67 gross (15 net) wells, bringing our 2016 year to date total to 161 gross (34 net) wells compared to 528 gross (184 net) wells for year to date 2015.

Our inventory of drilled but uncompleted ("DUC") wells ~~by area:~~

Three months ended June 30, 2015 Six months ended June 30, 2015
Gross Net Gross Net
North Dakota Bakken 158
56
367
116
Montana Bakken 1
—
9
6
SCOOP 55
18
131
54
Northwest Cana 5
2
5
2
Other 4
—
16
6
Total wells 223
76
528
184

~~As of~~in North Dakota totaled 156 gross (126 net) operated wells at June 30, ~~2015, we~~2016 compared to 142 gross (114 net) operated ~~27 rigs on our properties, down from 49~~wells at March 31, 2016 and 135 gross (107 net) operated ~~rigs~~wells at December 31, ~~2014.~~2015.

Our DUC inventory in Oklahoma totaled 44 gross (25 net) operated wells at June 30, 2016 compared to 42 gross (26 net) operated wells at March 31, 2016 and 35 gross (25 net) operated wells at December 31, 2015.

Credit facility and liquidity

At June 30, ~~2015,~~2016, we had ~~$25.5~~$16.6 million of cash and cash equivalents and ~~$1.27~~approximately $1.86 billion of borrowing availability on our credit facility after considering outstanding borrowings and letters of credit. We had ~~$1.23 billion~~$885 million of outstanding borrowings on our credit facility at June 30, ~~2015~~2016 compared to ~~$955~~$940 million at March 31, ~~2015~~2016 and ~~$165~~$853 million at December 31, ~~2014.~~2015. At July 31, ~~2015,~~2016, outstanding credit facility borrowings totaled $820 million.

Property disposition

In April 2016, we ~~continued~~sold approximately 132,000 net acres of non-core undeveloped leasehold acreage located in Wyoming to ~~have $1.23 billion~~a third party for cash proceeds of $110.0 million. The proceeds were used to pay down a portion of outstanding borrowings ~~and $1.27 billion of borrowing availability~~ on our revolving credit facility.

~~Credit facility borrowings, net~~ In connection with the transaction we recognized a pre-tax gain of repayments, totaled $270 million for the 2015 second quarter compared to $790 million for the 2015 first quarter, the decrease of which resulted from higher crude oil market prices compared to the first quarter and a reduced level of capital expenditures from our efforts to align capital expenditures with operating cash flows in the second quarter.approximately $96.9 million.

Financial and operating highlights

We use a variety of financial and operating measures to assess our performance. Among these measures are:

Volumes of crude oil and natural gas produced,

Crude oil and natural gas prices realized, and

Per unit operating and administrative ~~costs, and~~

~~EBITDAX (a non-GAAP financial measure).~~costs.

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


	Three months ended June 30,						Six months ended June 30,						Three months ended June 30,						Six months ended June 30,
	2015			2014			2015			2014			2016			2015			2016			2015
Average daily production:
Crude oil (Bbl per day)	149,897			116,441			146,722			111,447			133,044			149,897			139,756			146,722
Natural gas (Mcf per day)	459,898			309,074			420,123			292,847			517,677			459,898			511,837			420,123
Crude oil equivalents (Boe per day)	226,547			167,953			216,742			160,255			219,323			226,547			225,063			216,742
Average sales prices:
Crude oil ($/Bbl)	$	49.84		$	92.31		$	44.46		$	91.12		$	38.38		$	49.84		$	31.76		$	44.46
Natural gas ($/Mcf)	$	2.31		$	5.43		$	2.48		$	6.20		$	1.31		$	2.31		$	1.33		$	2.48
Crude oil equivalents ($/Boe)	$	37.82		$	74.09		$	34.93		$	74.53		$	26.36		$	37.82		$	22.73		$	34.93
Crude oil sales price differential to NYMEX ($/Bbl)	$	(8.18	)	$	(10.69	)	$	(9.05	)	$	(9.90	)
Natural gas sales price premium (differential) to NYMEX ($/Mcf)	$	(0.33	)	$	0.76		$	(0.31	)	$	1.41
Crude oil sales price discount to NYMEX ($/Bbl)													$	(7.21	)	$	(8.18	)	$	(7.51	)	$	(9.05	)
Natural gas sales price discount to NYMEX ($/Mcf)													$	(0.65	)	$	(0.33	)	$	(0.69	)	$	(0.31	)
Production expenses ($/Boe)	$	4.39		$	5.50		$	4.70		$	5.62		$	3.72		$	4.39		$	3.74		$	4.70
Production taxes (% of oil and gas revenues)	7.8		%	8.3		%	8.0		%	8.0		%	7.4		%	7.8		%	7.5		%	8.0		%
DD&A ($/Boe)	$	21.68		$	21.28		$	21.36		$	20.88		$	22.15		$	21.68		$	22.16		$	21.36
General and administrative expenses ($/Boe) (1)	$	1.34		$	2.08		$	1.58		$	2.24
Non-cash equity compensation ($/Boe)	$	0.77		$	0.98		$	0.70		$	0.91
Total general and administrative expenses ($/Boe) (1)													$	1.82		$	2.11		$	1.68		$	2.28
Net income (loss) (in thousands)	$	403		$	103,538		$	(131,568	)	$	329,772		$	(119,402	)	$	403		$	(317,727	)	$	(131,568	)
Diluted net income (loss) per share	$	—		$	0.28		$	(0.36	)	$	0.89		$	(0.32	)	$	—		$	(0.86	)	$	(0.36	)
EBITDAX (in thousands) (2)	$	647,009		$	867,938		$	1,086,435		$	1,643,345


(1)	~~Excludes~~ Represents cash general and administrative expenses per Boe and non-cash equity compensation ~~expense.~~

~~(2)~~

expenses per Boe. See ~~We define EBITDAX as earnings before interest expense, income taxes, depreciation, depletion, amortization~~Operating Costs and ~~accretion, property impairments, exploration expenses, non-cash gains~~Expenses—General and ~~losses resulting from~~Administrative Expenses below for the ~~requirements~~quarter and year to date periods for additional discussion of accounting for derivatives, non-cash equity compensation expense, and losses on extinguishment of debt. EBITDAX is not a measure of net income or operating cash flows as determined by U.S. GAAP. Reconciliations of net income and operating cash flows to EBITDAX are provided below under the heading ~~Non-GAAP Financial Measures~~.these components.

Three months ended June 30, ~~2015~~2016 compared to the three months ended June 30, ~~2014~~2015

Results of Operations

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


	Three months ended June 30,						Three months ended June 30,
In thousands, except sales price data	2015			2014			2016			2015
Crude oil and natural gas sales	$	790,102		$	1,138,085		$	525,711		$	790,102
Loss on derivative instruments, net	(4,737		)	(262,524		)
Loss on crude oil and natural gas derivatives, net							(82,257		)	(4,737		)
Crude oil and natural gas service operations	11,009			10,534			7,757			11,009
Total revenues	796,374			886,095			451,211			796,374
Operating costs and expenses(1)	(713,927		)	(649,701		)	(561,758		)	(713,927		)
Other expenses, net	(77,902		)	(72,048		)	(81,487		)	(77,902		)
Income before income taxes	4,545			164,346
Provision for income taxes	(4,142		)	(60,808		)
Net income	$	403		$	103,538
Income (loss) before income taxes							(192,034		)	4,545
(Provision) benefit for income taxes							72,632			(4,142		)
Net income (loss)							$	(119,402	)	$	403
Production volumes:
Crude oil (MBbl)	13,641			10,596			12,107			13,641
Natural gas (MMcf)	41,851			28,126			47,109			41,851
Crude oil equivalents (MBoe)	20,616			15,284			19,958			20,616
Sales volumes:
Crude oil (MBbl)	13,917			10,674			12,090			13,917
Natural gas (MMcf)	41,851			28,126			47,109			41,851
Crude oil equivalents (MBoe)	20,892			15,362			19,941			20,892
Average sales prices:
Crude oil ($/Bbl)	$	49.84		$	92.31		$	38.38		$	49.84
Natural gas ($/Mcf)	2.31			5.43			1.31			2.31
Crude oil equivalents ($/Boe)	37.82			74.09			26.36			37.82

(1) Net of gain on sale of assets of $96.9 million and $20.5 million for the three months ended June 30, 2016 and 2015, respectively.

Production

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


	Three months ended June 30,						Volume increase	Volume percent increase		Three months ended June 30,						Volume increase (decrease)		Volume percent increase (decrease)
	2015			2014						2016			2015
	Volume	Percent		Volume	Percent					Volume	Percent		Volume	Percent
Crude oil (MBbl)	13,641	66	%	10,596	69	%	3,045	29	%	12,107	61	%	13,641	66	%	(1,534	)	(11	%)
Natural gas (MMcf)	41,851	34	%	28,126	31	%	13,725	49	%	47,109	39	%	41,851	34	%	5,258		13	%
Total (MBoe)	20,616	100	%	15,284	100	%	5,332	35	%	19,958	100	%	20,616	100	%	(658	)	(3	%)

	Three months ended June 30,						Volume increase	Volume percent increase		Three months ended June 30,						Volume increase (decrease)		Volume percent increase (decrease)
	2015			2014						2016			2015
	MBoe	Percent		MBoe	Percent					MBoe	Percent		MBoe	Percent
North Region	14,150	69	%	11,253	74	%	2,897	26	%	12,448	62	%	14,150	69	%	(1,702	)	(12	%)
South Region	6,466	31	%	4,031	26	%	2,435	60	%	7,510	38	%	6,466	31	%	1,044		16	%
Total	20,616	100	%	15,284	100	%	5,332	35	%	19,958	100	%	20,616	100	%	(658	)	(3	%)

The ~~29% increase~~11% decrease in crude oil production for the second quarter was driven by ~~increased~~decreased production from our properties in ~~the~~North Dakota Bakken, ~~field~~Montana Bakken and SCOOP play. Production in the Bakken field increased 2,172 MBbls, or 26%, over the prior year second quarter, while SCOOP production increased 959 MBbls, or 118%. Production growth in these areas was primarily due to additional drilling and completion activity resulting from our drilling program. These increases were partially offset by a decrease in production from our properties in the Red River units ~~totaling 124 MBbls, or 10%, compared to the prior year second quarter~~ due to a combination of natural declines in production and reduced drilling ~~activity.~~and completion activities in those areas. North Dakota Bakken crude oil production decreased 1,377 MBbls, or 14%, and Montana Bakken production decreased 242 MBbls, or 24%, while production in the Red River units decreased 145 MBbls, or 13%, over the prior year second quarter. These decreases were partially offset by an increase of 281

MBbls in crude oil production from our STACK/Northwest Cana properties due to additional wells being completed and producing resulting from a shift in our well completion activities away from the Bakken to higher rate-of-return areas in Oklahoma.

The ~~49%~~13% increase in natural gas production for the second quarter was driven by increased production from our properties in the ~~Bakken field~~STACK, Northwest Cana and SCOOP ~~play~~plays due to additional wells being completed and producing ~~and gas from existing wells being connected to natural gas processing plants~~ subsequent to June 30, ~~2014.~~2015. Natural gas production in ~~the Bakken field~~STACK/Northwest Cana increased ~~4,663~~3,881 MMcf, or ~~55%~~173%, and SCOOP production increased 1,042 MMcf, or 4%, over the prior year second ~~quarter, while SCOOP~~quarter. Additionally, North Dakota Bakken natural gas production increased ~~9,690~~990 MMcf, or ~~70%.~~8%, due to an increase in gas capture from non-operated properties and resulting increase in volumes produced and delivered to market. These increases were partially offset by decreases in production from various areas in our North and South regions primarily due to natural declines in production.

~~Our 35% quarter-over-quarter growth~~The increase in natural gas production as a percentage of our total production ~~is not expected~~from 34% in the second quarter of 2015 to ~~be sustained for~~39% in the second quarter of 2016 primarily resulted from significant increases in STACK, Northwest Cana and SCOOP production over the past year due to the aforementioned shift in our well completion activities away from the Bakken to higher rate-of-return areas in Oklahoma. Our properties in STACK, Northwest Cana and SCOOP typically produce a higher concentration of liquids-rich natural gas compared to oil-weighted properties in the Bakken. For the remainder of ~~2015. Our ongoing reduction in capital spending for 2015 is expected~~2016, we expect to ~~have a more significant impact~~continue focusing our well completion activities on our ~~year-over-year production growth in the third and fourth quarters and~~Oklahoma properties. Accordingly, we expect our natural gas production may increase to approximately 40% of our total production for the ~~second half~~full year of ~~2015 will generally be flat compared~~2016. As crude oil prices recover, we expect to increase our completion activities in the Bakken and shift our production ~~for the first half~~back to a higher proportion of ~~2015.~~crude oil.

Revenues

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

Crude Oil and Natural Gas Sales. Crude oil and natural gas sales for the second quarter of ~~2015~~2016 were ~~$790.1~~$525.7 million, a ~~31%~~33% decrease from sales of ~~$1,138.1~~$790.1 million for the ~~same period in 2014 primarily~~2015 second quarter due to ~~a significant decrease~~decreases in commodity ~~prices.~~prices and sales volumes.

Our crude oil sales prices averaged ~~$49.84~~$38.38 per barrel in the ~~2015~~2016 second quarter, a decrease of 23% compared to ~~$92.31~~$49.84 for ~~the 2014 second quarter. Market prices for crude oil remained depressed in~~ the 2015 second quarter ~~resulting in significantly~~due to lower ~~realized sales prices compared to the prior year.~~crude oil market prices. The differential between NYMEX ~~WTI~~West Texas Intermediate ("WTI") calendar month ~~average~~ crude oil prices and our realized crude oil ~~price~~prices averaged $7.21 per barrel ~~was~~for the 2016 second quarter compared to $8.18 for the 2015 ~~second quarter compared to $10.69 for the 2014~~ second quarter. The improved differential was due ~~in part~~ to increased ~~availability and~~ use of pipeline transportation to move our North region crude oil to market with less dependence on more costly rail ~~transportation.~~transportation, along with significant growth in our South region production which typically has lower transportation costs compared to the Bakken due to its relatively close proximity to regional refineries and the crude oil trading hub in Cushing, Oklahoma.

Our ~~average~~ natural gas sales ~~price~~prices averaged $1.31 per Mcf for the ~~2015~~2016 second quarter, ~~decreased~~a 43% decrease compared to $2.31 per Mcf ~~compared to $5.43~~ for the ~~2014~~2015 second quarter due to lower market prices for natural gas and natural gas liquids ~~("NGLs"~~(“NGLs”)~~. Our~~ along with the amendment of certain natural gas sales agreements in 2016. The majority of our natural gas production is ~~primarily~~ sold at ~~the wellhead~~our lease locations to midstream purchasers with price realizations ~~being~~ impacted by the volume and value of NGLs that purchasers ~~retrieve~~extract from our sales stream. The difference between our realized natural gas sales prices and NYMEX Henry Hub calendar month natural gas prices was a ~~differential~~discount of $0.65 per Mcf for the 2016 second quarter compared to a discount of $0.33 per Mcf for the 2015 second ~~quarter compared to a premium of $0.76 for the 2014 second~~ quarter. NGL prices remained depressed in the ~~2015~~2016 second quarter in conjunction with low crude oil prices, which, along with our amended natural gas sales agreements, reduced the value of our natural gas sales stream and unfavorably impacted the difference between our realized prices and Henry Hub benchmark pricing.

~~Crude oil,~~ If NGL prices do not recover from current levels, the prices we receive for the sale of our natural gas stream for the remainder of 2016 may continue to be lower than Henry Hub benchmark prices.

Commodity prices showed some signs of stabilization and ~~NGL prices~~recovery in the second quarter of 2016, but still remain volatile and we are unable to predict the impact future price changes may have on our full year ~~2015~~2016 revenues and differentials.

~~Our sales volumes for~~For the second quarter of ~~2015 increased 5,530 MBoe, or 36%, over the comparable period in 2014 primarily due to an increase in producing wells due to the success of~~2016, our drilling programs in the Bakken field and SCOOP play. At various times we have stored crude oil due to pipeline line fill requirements, low commodity prices, or marketing disruptions or we have sold crude oil from inventory. These actions result in differences between produced and sold crude oil volumes. Operating efficiencies achieved during the second quarter on new third party pipeline systems provided for improved transportation of our crude oil to market, which resulted in the sale of crude oil previously stored in inventory at March 31, 2015 and caused crude oil sales volumes decreased 13% from the comparable 2015 period, while our natural gas sales volumes increased 13%, reflecting the shift in our well completion activities away from oil-weighted properties in the Bakken to beareas in Oklahoma with higher ~~than crude oil production by 276 MBbls for the second quarter~~concentrations of ~~2015.~~liquids-rich natural gas.

Derivatives. Changes in ~~commodity~~natural gas prices during the second quarter of ~~2015~~2016 had ~~a negative~~an unfavorable impact on the fair value of our natural gas derivatives, which resulted in negative revenue adjustments of ~~$4.7~~$82.3 million for the ~~period.~~period, representing $121.0 million of non-cash losses on derivatives partially offset by $38.7 million of cash gains. Our revenues may continue to be significantly impacted, either positively or negatively, by changes in the fair value of our derivative instruments as a result of volatility in ~~commodity~~natural gas prices.

~~The following table presents cash settlements on matured derivative instruments and non-cash gains and losses on open derivative instruments for the periods presented.~~

Three months ended June 30,
In thousands 2015
2014
Cash received (paid) on derivatives:
Crude oil derivatives $ —
$ (51,952 )
Natural gas derivatives 13,182
(12,191 )
Cash received (paid) on derivatives, net 13,182
(64,143 )
Non-cash gain (loss) on derivatives:
Crude oil derivatives 3
(205,851 )
Natural gas derivatives (17,922 ) 7,470
Non-cash gain (loss) on derivatives, net (17,919 ) (198,381 )
Gain (loss) on derivative instruments, net $ (4,737 ) $ (262,524 )

Operating Costs and Expenses

Production Expenses. Production expenses ~~increased 9% to~~decreased $17.6 million, or 19%, from $91.7 million for the second quarter of 2015 ~~from $84.5~~to $74.1 million for the second quarter of ~~2014. This increase was primarily~~2016. Production expenses on a per-Boe basis decreased to $3.72 for the ~~result of an increase in the number of producing wells and resulting 36% increase in sales volumes over the prior year period.~~

~~Production expense per Boe decreased~~2016 second quarter compared to $4.39 for the 2015 second ~~quarter compared to $5.50 for the 2014 second~~ quarter. ~~This per-Boe decrease~~These decreases primarily resulted from curtailed spending and reduced service costs being realized in response to depressed commodity prices, increased availability and use of water gathering and recycling facilities over the prior year period, and a higher portion of our production coming from natural gas wells in ~~the SCOOP area~~Oklahoma which typically have lower operating costs compared to ~~other areas, and a 36% increase~~crude oil wells in ~~sales volumes from new well completions.~~the Bakken.

Production Taxes and Other Expenses. Production taxes and other expenses decreased ~~$35.5~~$22.4 million, or ~~37%~~36%, to $39.1 million for the second quarter of 2016 compared to $61.5 million for the second quarter of 2015 ~~compared to $97.0 million for the second quarter of 2014~~ primarily due to lower crude oil and natural gas revenues resulting from ~~the significant decrease~~decreases in commodity prices over the prior year period.Production taxes as a percentage of crude oil and natural gas revenues were 7.8% for the second quarter of 2015 compared to 8.3% for the second quarter of 2014, the difference of which resulted from changes in the mix of crude oil and natural gas sales volumes and values and the proportion of taxable revenues coming from North Dakota and Oklahoma between periods.

Production taxes are generally based on the wellhead values of production and vary by state. ~~Some states offer exemptions or reduced~~Production taxes as a percentage of crude oil and natural gas revenues were 7.4% for the second quarter of 2016 compared to 7.8% for the second quarter of 2015, the decrease of which resulted from significant growth over the past year in our STACK, Northwest Cana and SCOOP operations and resulting increase in revenues coming from Oklahoma, which has lower production tax rates compared to North Dakota. We expect our average production tax rate for ~~wells~~the remainder of 2016 will continue to trend lower than 2015 levels as our operations in Oklahoma continue to grow in significance and given the passing of legislation in North Dakota in 2015 that ~~produce less than a certain quantity~~decreased the combined production tax rate from 11.5% to 10.0% of crude oil or natural gas and to encourage certain activities, such as horizontal drilling and enhanced recovery projects. In Montana and Oklahoma, certain horizontal wells are taxed at a lower rate during their initial months of production which subsequently increases after a specified period of time or when specified production volumes are achieved.

~~Through June 30, 2015,~~ revenues from new wells in Oklahoma were taxed at 1% for the first 48 months of production, after which the tax rate increases to 7%. Effective July 1, 2015, the tax rate on new Oklahoma wells spud after that date was changed to 2% for the first 36 months of production and 7% thereafter.

At June 30, 2015, North Dakota had a crude oil tax structure based on a 5% production tax and a 6.5% oil extraction tax for a combined tax of 11.5% of crude oil revenues. In April 2015, new legislation was signed into law in North Dakota ~~that eliminated the then-existing price-based oil extraction tax incentives and set a lower oil extraction tax rate. The new law reduces the oil extraction tax from 6.5% to 5%~~ effective January 1, 2016, resulting in a total tax of 10% on crude oil revenues when combined with the 5% production tax which was not changed by the new law. Under the new law, the oil extraction tax will increase from 5% to 6%, for a total tax rate of 11%, if the average WTI oil price is above $90 per barrel (indexed for inflation) for three consecutive months. The oil extraction tax will revert back to 5% if the average WTI oil price falls below $90 per barrel for three consecutive months.2016.

Exploration Expenses. Exploration expenses consist primarily of dry hole costs and exploratory geological and geophysical costs that are expensed as incurred. The following table shows the components of exploration expenses for the periods presented.


	Three months ended June 30,				Three months ended June 30,
In thousands	2015		2014		2016		2015
Geological and geophysical costs	$	109	$	6,732	$	1,468	$	109
Exploratory dry hole costs	—		4,473		206		—
Exploration expenses	$	109	$	11,205	$	1,674	$	109

The ~~decrease~~increase in geological and geophysical expenses in the 2016 second quarter ~~of 2015~~ was due to changes in the timing and amount of costs incurred by the Company and ~~recouped from~~billed to joint interest ~~partners~~owners between periods.

Depreciation, Depletion, Amortization and Accretion (“DD&A”). Total DD&A ~~increased $126.1~~decreased $11.2 million, or ~~39%~~2%, to $441.8 million for the second quarter of 2016 compared to $453.0 million for the second quarter of 2015 ~~compared to $326.9 million for the second quarter of 2014~~ primarily due to a ~~36% increase~~5% decrease in total sales volumes. The following table shows the components of our DD&A on a unit of sales basis for the periods presented.


	Three months ended June 30,				Three months ended June 30,
$/Boe	2015		2014		2016		2015
Crude oil and natural gas	$	21.32	$	20.93	$	21.69	$	21.32
Other equipment	0.31		0.30		0.38		0.31
Asset retirement obligation accretion	0.05		0.05		0.08		0.05
Depreciation, depletion, amortization and accretion	$	21.68	$	21.28	$	22.15	$	21.68

Estimated proved reserves are a key component in our computation of DD&A expense. Holding all other factors constant, if proved reserves are revised downward, the rate at which we record DD&A expense would increase. ~~The~~Downward revisions of proved reserves in 2016 prompted by depressed commodity prices contributed to an increase in our DD&A rate for crude oil and natural gas properties in the ~~current period resulted from downward revisions~~second quarter of ~~proved reserves in 2015 prompted by depressed commodity prices.~~

2016 compared to the prior year period. If commodity prices ~~remain at current levels or~~ decline further, additional downward revisions of proved reserves may occur in the future, which may be significant and ~~could~~would result in ~~a further~~an increase in our DD&A ~~rate in the second half of 2015.~~rate. We are unable to predict the timing and amount of future reserve revisions ~~nor~~or the impact such revisions may have on our future DD&A rate.

Property Impairments. Total property impairments decreased ~~$2.4~~$10.8 million, or 3%14%, to $66.1 million for the 2016 second quarter compared to $76.9 million for the ~~second quarter of~~ 2015 ~~compared to $79.3 million for the 2014~~ second quarter.

~~Impairments of~~There were no proved ~~properties totaled $5.0 million for~~property impairments recognized in the second quarter of ~~2015~~2016 compared to ~~$27.5~~$5.0 million ~~for~~of such impairments in the second quarter of ~~2014. The 2015 second quarter impairments reflect~~2015. This decrease resulted from differences in the timing and severity of commodity price declines and resulting impact on fair value ~~adjustments prompted by depressed~~assessments and impairments between periods. As a result of the impairments and DD&A recognized to date coupled with an improvement in commodity prices in ~~an emerging area with limited production history~~June 2016, our proved properties are carried at values that did not exceed estimated future net cash flows at June 30, 2016 and ~~costly reserve additions.~~required no impairment during the 2016 second quarter.

Estimated ~~proved~~ reserves are a key component in assessing proved properties for impairment. If commodity prices ~~remain at current levels or~~ decline further, downward revisions of ~~proved~~ reserves may be significant in the future and could result in ~~additional~~ impairments of proved properties in the ~~second half~~remainder of ~~2015.~~2016. We are unable to predict the timing and amount of future reserve revisions ~~nor~~or the impact such revisions may have on future impairments, if any.

Impairments of non-producing properties ~~increased $20.0~~decreased $5.7 million, or 8%, to $66.1 million for the 2016 second quarter ~~of 2015~~compared to $71.8 million ~~compared to $51.8 million~~ for the 2015 second ~~quarter of 2014.~~quarter. The ~~increase~~decrease was ~~primarily~~ due to ~~higher rates~~a lower balance of unamortized leasehold costs in the current year due in part to reduced land capital expenditures along with changes in the timing and magnitude of amortization ~~being applied to~~of undeveloped leasehold costs between periods resulting from changes in ~~management’s~~the Company's estimates of undeveloped properties not expected to be developed before lease expiration, particularly in response to decreased commodity prices which have altered our drilling plans. Our rates of amortization may continue to increase in future periods if commodity prices remain at current levels or decline further and additional changes are made to drilling plans.expiration.

General and Administrative ("G&A") Expenses. Total G&A expenses decreased ~~$2.7~~$7.9 million, or 6%18%, to ~~$44.2~~$36.2 million for the second quarter of ~~2015~~2016 from ~~$46.9~~$44.2 million for ~~the 2014~~ second ~~quarter.~~quarter of 2015. Total G&A expenses include non-cash charges for equity compensation of ~~$16.2~~$11.8 million and ~~$15.0~~$16.2 million for the second quarters of 2016 and 2015, ~~and 2014,~~ respectively. G&A expenses other than equity compensation totaled $24.4 million for the 2016 second quarter, a decrease of $3.6 million, or 13%, compared to the 2015 second quarter.

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


	Three months ended June 30,				Three months ended June 30,
$/Boe	2015		2014		2016		2015
General and administrative expenses	$	1.34	$	2.08	$	1.22	$	1.34
Non-cash equity compensation	0.77		0.98		0.60		0.77
Total general and administrative expenses	$	2.11	$	3.06	$	1.82	$	2.11

The decrease in G&A expenses onother than equity compensation was primarily due to a ~~per-Boe basis~~reduction in ~~2015 was driven by curtailed~~employee related costs and other efforts to reduce spending ~~deferral of hiring, and smaller increases in personnel costs compared to the prior year~~ in response to depressed commodity ~~prices, coupled with a 36% increase in sales volumes from new well completions.~~

prices. The decrease in equity compensation expense ~~on a per-Boe basis~~ was primarily due to ~~the~~an increase in ~~sales volumes from new well completions with no comparable increase~~the estimated rate of forfeitures of unvested restricted stock based on historical experience, which resulted in ~~equity compensation expense.~~lower recognition of expense in 2016.

Interest Expense. Interest expense increased ~~$5.6~~$3.5 million, or 8%4%, to $81.9 million for the second quarter of 2016 compared to $78.4 million for the second quarter of 2015 ~~compared to $72.8 million for the second quarter of 2014~~ due to an increase in our weighted average outstanding long-term debt ~~obligations.~~obligations and higher borrowing costs incurred on our credit facility and three-year term loan resulting from downgrades of our credit rating in February 2016. Our weighted average outstanding long-term debt balance for the ~~2015~~2016 second quarter was approximately ~~$7.1~~$7.3 billion with a weighted average interest rate of 4.3% compared to averages of ~~$5.6~~$7.1 billion and ~~5.0%~~4.3% for the ~~2014~~2015 second quarter. The increase in outstanding debt resulted from borrowings incurred subsequent to June 30, ~~2014~~2015 to fund our ~~2014 and 2015~~ capital ~~programs.~~spending.

Income Taxes. We recorded an income tax ~~expense~~benefit for the second quarter of ~~2015~~2016 of ~~$4.1~~$72.6 million compared to ~~$60.8~~income tax expense of $4.1 million for the second quarter of ~~2014,~~2015, resulting in effective tax rates of approximately ~~91%~~38% and ~~37%~~91%, respectively, after taking into account permanent taxable differences and valuation allowances. For the ~~2015~~ second ~~quarter,~~quarters of 2016 and 2015, we provided for income taxes at a combined federal and state tax rate of 38% of pre-tax income (loss) generated by our operations in the United States. Our effective tax rate for the 2015 second quarter ~~effective tax rate~~ was increased by a $1.3 million valuation allowance recognized against deferred tax assets associated with $6.4 million of operating loss carryforwards generated by our Canadian subsidiary in the 2015 second quarter for which we do not believe we will realize a benefit.

Six months ended June 30, ~~2015~~2016 compared to the six months ended June 30, ~~2014~~2015

Results of Operations

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


	Six months ended June 30,						Six months ended June 30,
In thousands, except sales price data	2015			2014			2016			2015
Crude oil and natural gas sales	$	1,372,694		$	2,140,418		$	929,302		$	1,372,694
Gain (loss) on derivative instruments, net	28,018			(302,198		)
Gain (loss) on crude oil and natural gas derivatives, net							(40,145		)	28,018
Crude oil and natural gas service operations	21,306			20,370			15,227			21,306
Total revenues	1,422,018			1,858,590			904,384			1,422,018
Operating costs and expenses(1)	(1,450,847		)	(1,200,879		)	(1,254,033		)	(1,450,847		)
Other expenses, net	(152,619		)	(134,264		)	(162,056		)	(152,619		)
Income (loss) before income taxes	(181,448		)	523,447
(Provision) benefit for income taxes	49,880			(193,675		)
Net income (loss)	$	(131,568	)	$	329,772
Loss before income taxes							(511,705		)	(181,448		)
Benefit for income taxes							193,978			49,880
Net loss							$	(317,727	)	$	(131,568	)
Production volumes:
Crude oil (MBbl)	26,557			20,172			25,436			26,557
Natural gas (MMcf)	76,043			53,005			93,154			76,043
Crude oil equivalents (MBoe)	39,231			29,006			40,961			39,231
Sales volumes:
Crude oil (MBbl)	26,628			19,887			25,356			26,628
Natural gas (MMcf)	76,043			53,005			93,154			76,043
Crude oil equivalents (MBoe)	39,301			28,721			40,882			39,301
Average sales prices:
Crude oil ($/Bbl)	$	44.46		$	91.12		$	31.76		$	44.46
Natural gas ($/Mcf)	2.48			6.20			1.33			2.48
Crude oil equivalents ($/Boe)	34.93			74.53			22.73			34.93

(1) Net of gain on sale of assets of $97.0 million and $22.6 million for the six months ended June 30, 2016 and 2015, respectively.

Production

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


	Six months ended June 30,						Volume increase	Volume percent increase		Six months ended June 30,						Volume increase (decrease)		Volume percent increase (decrease)
	2015			2014						2016			2015
	Volume	Percent		Volume	Percent					Volume	Percent		Volume	Percent
Crude oil (MBbl)	26,557	68	%	20,172	70	%	6,385	32	%	25,436	62	%	26,557	68	%	(1,121	)	(4	%)
Natural gas (MMcf)	76,043	32	%	53,005	30	%	23,038	43	%	93,154	38	%	76,043	32	%	17,111		23	%
Total (MBoe)	39,231	100	%	29,006	100	%	10,225	35	%	40,961	100	%	39,231	100	%	1,730		4	%

	Six months ended June 30,						Volume increase	Volume percent increase		Six months ended June 30,						Volume increase (decrease)		Volume percent increase (decrease)
	2015			2014						2016			2015
	MBoe	Percent		MBoe	Percent					MBoe	Percent		MBoe	Percent
North Region	27,576	70	%	21,371	74	%	6,205	29	%	26,240	64	%	27,576	70	%	(1,336	)	(5	%)
South Region	11,655	30	%	7,635	26	%	4,020	53	%	14,721	36	%	11,655	30	%	3,066		26	%
Total	39,231	100	%	29,006	100	%	10,225	35	%	40,961	100	%	39,231	100	%	1,730		4	%

The ~~32% increase~~4% decrease in crude oil production for year to date ~~2015~~2016 was driven by ~~increased~~decreased production from our properties in ~~the~~North Dakota Bakken, ~~field~~Montana Bakken and SCOOP play. Production in the Bakken field increased 4,836 MBbls, or 30%, over the prior year period, while SCOOP production increased 1,746 MBbls, or 116%. Production growth in these areas was primarily due to additional drilling and completion activity resulting from our drilling program. These increases were partially offset by a decrease in production from our properties in the Red River units ~~totaling 235 MBbls, or 10%, compared to the prior year~~ due to a combination of natural declines in production and reduced drilling ~~activity.~~and completion activities in those areas. North Dakota Bakken crude oil production decreased 1,001 MBbls, or 5%, and Montana Bakken production decreased 607 MBbls, or 28%, while production in the Red River units decreased 275 MBbls, or 13%, over the prior year period. These decreases were partially offset by increases in production from our properties

in the STACK/Northwest Cana and SCOOP plays which increased 503 MBbls and 378 MBbls, respectively,due to additional wells being completed and producing resulting from a shift in our well completion activities away from the Bakken to higher rate-of-return areas in Oklahoma.

The ~~43%~~23% increase in natural gas production for year to date ~~2015~~2016 was driven by increased production from our properties in the ~~Bakken field~~STACK/Northwest Cana and SCOOP ~~play~~plays due to additional wells being completed and producing ~~and gas from existing wells being connected to natural gas processing plants~~ subsequent to June 30, ~~2014.~~2015. Natural gas production in ~~the Bakken field~~STACK/Northwest Cana increased ~~9,249~~6,771 MMcf, or ~~59%~~173%, and SCOOP production increased 7,236 MMcf, or 17%, over the prior year ~~while SCOOP~~period. Additionally, North Dakota Bakken production increased ~~16,043~~3,942 MMcf, or ~~63%.~~17%, due to an increase in gas capture from non-operated properties and resulting increase in volumes produced and delivered to market. These increases were partially offset by decreases in production from various areas in our North and South regions primarily due to natural declines in production.

Our ~~35% year-over-year~~reduction in capital spending and deferral of certain well completion activities has adversely impacted our rate of production and our 4% growth in total production realized for year to date 2016 compared to year to date 2015 is not expected to be sustained for the remainder of ~~2015. Our ongoing reduction in capital spending for 2015 is expected to have a more significant impact on our year-over-year production growth in the third and fourth quarters and we~~2016. We expect our rate of production to slow for the ~~second half~~remainder of ~~2015 will generally be flat~~2016 and may average between 210,000 and 220,000 Boe per day for the full year of 2016 compared to average daily production of 221,715 Boe per day for ~~the first half of~~full year 2015.

Revenues

Crude Oil and Natural Gas Sales. Crude oil and natural gas sales for year to date ~~2015~~2016 were ~~$1.37 billion,~~$929.3 million, a ~~36%~~32% decrease from sales of ~~$2.14~~$1.37 billion for the same period in ~~2014 primarily~~2015 due to a significant decrease in commodity ~~prices.~~prices partially offset by an increase in total sales volumes.

Our crude oil sales prices averaged ~~$44.46~~$31.76 per barrel for year to date ~~2015~~2016, a decrease of 29% compared to ~~$91.12~~$44.46 for year to date ~~2014. Market prices for~~2015 due to lower crude oil ~~have remained depressed in the first half of 2015, resulting in significantly lower realized sales prices compared to the prior year.~~market prices. The differential between NYMEX WTI calendar month average crude oil prices and our realized crude oil price per barrel for year to date ~~2015~~2016 was ~~$9.05~~$7.51 per barrel compared to ~~$9.90~~$9.05 for year to date ~~2014.~~2015. The improved differential was due ~~in part~~ to increased ~~availability and~~ use of pipeline transportation ~~in the current year~~ to move our North region crude oil to market with less dependence on more costly rail ~~transportation.~~transportation, along with significant growth in our South region production which typically has lower transportation costs compared to the Bakken due to its relatively close proximity to regional refineries and the crude oil trading hub in Cushing, Oklahoma.

Our ~~average~~ natural gas sales ~~price~~prices averaged $1.33 per Mcf for year to date ~~2015 decreased~~2016, a 46% decrease compared to $2.48 ~~per Mcf compared to $6.20~~ for year to date ~~2014~~2015 due to lower market prices for natural gas and ~~NGLs. Our~~NGLs along with the amendment of certain natural gas ~~production is primarily sold at the wellhead with price realizations being impacted by the volume and value of NGLs that purchasers retrieve from our~~ sales ~~stream.~~agreements in 2016. The difference between our realized natural gas sales prices and NYMEX Henry Hub calendar month natural gas prices was a ~~differential~~discount of ~~$0.31~~$0.69 per Mcf for year to date ~~2015~~2016 compared to a ~~premium~~discount of ~~$1.41~~$0.31 per Mcf for the comparable ~~2014~~2015 period. NGL prices in the first half of ~~2015 have~~2016 remained depressed in conjunction with low crude oil prices, which, ~~has~~along with our amended natural gas sales agreements, reduced the value of our natural gas sales stream and unfavorably impacted the difference between our realized prices and Henry Hub benchmark pricing.

~~Crude oil,~~ If NGL prices do not recover from current levels, the prices we receive for the sale of our natural gas ~~and NGL prices remain volatile and we are unable~~stream for the remainder of 2016 may continue to ~~predict the impact future price changes may have on~~be lower than Henry Hub benchmark prices.

For year to date 2016, our ~~full year 2015 revenues and differentials.~~

~~Our~~crude oil sales volumes decreased 5% from the comparable 2015 period, while our natural gas sales volumes increased 23%, reflecting the shift in our well completion activities away from oil-weighted properties in the Bakken to areas in Oklahoma with higher concentrations of liquids-rich natural gas.

At various times we have stored crude oil due to pipeline line fill requirements, low commodity prices, or marketing disruptions or we have sold crude oil from inventory. These actions result in differences between produced and sold crude oil volumes and caused crude oil sales volumes to be lower than crude oil production by 80 MBbls for year to date ~~2015 increased 10,580 MBoe, or 37%, over the comparable period in 2014 primarily due to an increase in producing wells due to the success of our drilling programs in the Bakken field and SCOOP play.~~2016.

Derivatives. Changes in ~~commodity~~natural gas prices during the six months ended June 30, ~~2015~~2016 had ~~a favorable~~an unfavorable impact on the fair value of our natural gas derivatives, which resulted in ~~positive~~negative revenue adjustments of ~~$28.0~~$40.1 million for the ~~period. The following table presents cash settlements on matured derivative instruments and~~period, representing $118.1 million of non-cash ~~gains and~~ losses on ~~open derivative instruments for the periods presented.~~derivatives partially offset by $78.0 million of cash gains.

Six months ended June 30,
In thousands 2015 2014
Cash received (paid) on derivatives:
Crude oil derivatives $ —
$ (75,059 )
Natural gas derivatives 36,617
(22,348 )
Cash received (paid) on derivatives, net 36,617
(97,407 )
Non-cash gain (loss) on derivatives:
Crude oil derivatives 3,927
(186,878 )
Natural gas derivatives (12,526 ) (17,913 )
Non-cash gain (loss) on derivatives, net (8,599 ) (204,791 )
Gain (loss) on derivative instruments, net $ 28,018
$ (302,198 )

~~Crude Oil and Natural Gas Service Operations~~. Revenues from our service operations primarily consist of income generated from water transportation, water recycling activities, and the sale of reclaimed crude oil. The increase in operating income generated by our service operations in the first six months of 2015 over the first six months of 2014 was driven by the expansion of Company-owned water recycling facilities in the SCOOP area.

Operating Costs and Expenses

Production Expenses. Production expenses ~~increased 14% to~~decreased $32.0 million, or 17%, from $184.7 million for year to date 2015 ~~from $161.4~~to $152.7 million ~~during the comparable 2014 period. This increase was primarily the result of an increase in the number of producing wells and resulting 37% increase in sales volumes over the prior year period.~~

~~Production expense per Boe decreased to $4.70~~ for year to date ~~2015 compared~~2016. Production expenses on a per-Boe basis decreased to ~~$5.62~~$3.74 for year to date ~~2014. This per Boe decrease~~2016 compared to $4.70 for the comparable 2015 period. These decreases primarily resulted from curtailed spending and reduced service costs being realized in response to depressed commodity prices, increased availability and use of water gathering and recycling facilities over the prior year period, and a higher portion of our production coming from natural gas wells in ~~the SCOOP area~~Oklahoma which typically have lower operating costs compared to ~~other areas, and a 37% increase~~crude oil wells in ~~sales volumes from new well completions.~~the Bakken.

Production Taxes and Other Expenses. Production taxes and other expenses decreased ~~$65.4~~$40.3 million, or 37%, to $69.6 million for year to date 2016 compared to $109.9 million for year to date 2015 ~~compared to $175.3 million for year to date 2014~~ primarily due to lower crude oil and natural gas revenues resulting from ~~the significant decrease~~decreases in commodity prices over the prior year period. Production taxes as a percentage of crude oil and natural gas revenues were 7.5% for year to date 2016 compared to 8.0% for ~~both~~ year to date 2015, the decrease of which resulted from significant growth over the past year in our STACK, Northwest Cana and ~~year~~SCOOP operations and resulting increase in revenues coming from Oklahoma, which has lower production tax rates compared to ~~date 2014.~~North Dakota. We expect our average production tax rate for the remainder of 2016 will continue to trend lower than 2015 levels as our operations in Oklahoma continue to grow in significance and given the passing of legislation in North Dakota in 2015 that decreased the combined production tax rate from 11.5% to 10.0% of crude oil revenues in North Dakota effective January 1, 2016.

Exploration Expenses. The following table shows the components of exploration expenses for the periods presented.


	Six months ended June 30,				Six months ended June 30,
In thousands	2015		2014		2016		2015
Geological and geophysical costs	$	6,446	$	11,635	$	4,533	$	6,446
Exploratory dry hole costs	8,003		4,383		206		8,003
Exploration expenses	$	14,449	$	16,018	$	4,739	$	14,449

The decrease in geological and geophysical expenses in ~~2015~~2016 was due to changes in the timing and amount of costs incurred by the Company and ~~recouped from~~billed to joint interest ~~partners~~owners between periods.

Dry hole costs incurred in 2015 primarily reflect costs associated with an unsuccessful well in a prospect in our North ~~region that is~~region. There have been no significant dry hole costs incurred in ~~the early stages of exploration.~~2016.

Depreciation, Depletion, Amortization and Accretion. Total DD&A increased ~~$239.8~~$66.3 million, or ~~40%~~8%, to ~~$839.5~~$905.8 million for year to date ~~2015~~2016 compared to ~~$599.7~~$839.5 million for the comparable period in ~~2014~~2015 primarily due to a ~~37%~~4% increase in total sales volumes. The following table shows the components of our DD&A on a unit of sales basis.


	Six months ended June 30,				Six months ended June 30,
$/Boe	2015		2014		2016		2015
Crude oil and natural gas	$	20.98	$	20.53	$	21.71	$	20.98
Other equipment	0.32		0.29		0.37		0.32
Asset retirement obligation accretion	0.06		0.06		0.08		0.06
Depreciation, depletion, amortization and accretion	$	21.36	$	20.88	$	22.16	$	21.36

The increase in our DD&A rate for crude oil and natural gas properties in the current period resulted from downward revisions of proved reserves at year-end 2015 and in ~~2015~~2016 prompted by depressed commodity prices. If commodity prices ~~remain at current levels or~~ decline further, additional downward revisions of proved reserves may occur in the future, which may be significant and ~~could~~would result in ~~a further~~an increase in our DD&A ~~rate in the second half of 2015.~~rate. We are unable to predict the timing and amount of future reserve revisions ~~nor~~or the impact such revisions may have on our future DD&A rate.

Property Impairments. Total property impairments ~~increased $86.9~~decreased $79.4 million, or ~~63%~~35%, to $145.0 million for year to date 2016 compared to $224.4 million for year to date 2015 ~~compared~~primarily due to ~~$137.5 million~~a decrease in proved property impairments. There were no proved property impairments recognized for year to date ~~2014.~~

~~Impairments~~2016 compared to $75.0 million of ~~proved properties increased $43.7 million~~such impairments for year to date ~~2015 to $75.0 million compared to $31.3 million for year to date 2014 due to higher write-downs~~2015. This decrease resulted from differences in the timing and severity of commodity price declines and resulting ~~from depressed~~impact on fair value assessments and impairments between periods. The prolonged decrease in commodity prices in 2015 triggered significant impairments of proved properties throughout 2015. As a result of the impairments and DD&A recognized to date coupled with an improvement in commodity prices in June 2016, our proved properties are carried at values that ~~adversely impacted~~did not exceed estimated future net cash flows at June 30, 2016 and required no impairment during the recoverability of capitalized costs in certain operating areas. The 2015 impairments were primarily concentrated in an emerging area with limited production history and costly reserve additions ($41.2 million, including $5.0 million in the second quarter), the Medicine Pole Hills units ($14.7 million), various non-core areas in the South region ($11.0 million), and non-Bakken areas of North Dakota and Montana ($8.1 million).six month period.

If commodity prices ~~remain at current levels or~~ decline further, downward revisions of ~~proved~~ reserves may be significant in the future and could result in ~~additional~~ impairments of proved properties in the ~~second half~~remainder of ~~2015.~~2016. We are unable to predict the timing and amount of future reserve revisions ~~nor~~or the impact such revisions may have on future impairments, if any.

Impairments of non-producing properties increased $43.2 million for year to date 2015 to $149.4 million compared to $106.2 million for year to date 2014. The increase was primarily due to higher rates of amortization being applied to undeveloped leasehold costs resulting from changes in management’s estimates of undeveloped properties not expected to be developed before lease expiration, particularly in response to decreased commodity prices which have altered our drilling plans. Our rates of amortization may continue to increase in future periods if commodity prices remain at current levels or decline further and additional changes are made to drilling plans.

General and Administrative Expenses. Total G&A expenses decreased ~~$0.9~~$20.9 million, or 1%23%, to ~~$89.6~~$68.7 million for year to date ~~2015~~2016 from ~~$90.5~~$89.6 million for the comparable period in ~~2014.~~2015. Total G&A expenses include non-cash charges for equity compensation of ~~$27.4~~$21.0 million and ~~$26.0~~$27.4 million for year to date ~~2015~~2016 and year to date ~~2014,~~2015, respectively. G&A expenses other than equity compensation totaled $47.7 million for year to date 2016, a decrease of $14.5 million, or 23%, compared to the comparable 2015 period.

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


	Six months ended June 30,				Six months ended June 30,
$/Boe	2015		2014		2016		2015
General and administrative expenses	$	1.58	$	2.24	$	1.16	$	1.58
Non-cash equity compensation	0.70		0.91		0.52		0.70
Total general and administrative expenses	$	2.28	$	3.15	$	1.68	$	2.28

The decrease in G&A expenses onother than equity compensation was primarily due to a ~~per-Boe basis~~reduction in ~~2015 was driven by curtailed~~employee related costs and other efforts to reduce spending ~~deferral of hiring, and smaller increases in personnel costs compared to the prior year~~ in response to depressed commodity ~~prices, coupled with a 37% increase in sales volumes from new well completions.~~

prices. The decrease in equity compensation expense ~~on a per-Boe basis~~ was primarily due to an increase in the estimated rate of forfeitures of unvested restricted stock based on historical experience, which resulted in lower recognition of expense in ~~2015, coupled with the increase in sales volumes from new well completions with no comparable increase in equity compensation expense.~~2016.

Interest Expense. Year to date interest expense increased ~~$17.7~~$9.4 million, or ~~13%~~6%, to ~~$153.5~~$162.9 million compared to ~~$135.8~~$153.5 million for the comparable ~~2014~~2015 period due to an increase in our weighted average outstanding long-term debt ~~obligations.~~obligations and higher borrowing costs incurred on our credit facility and three-year term loan resulting from downgrades of our credit rating in February 2016. Our weighted average outstanding long-term debt balance for year to date ~~2015~~2016 was approximately ~~$6.7~~$7.2 billion with a weighted average interest rate of ~~4.5%~~4.3% compared to averages of ~~$5.3~~$6.7 billion and ~~5.0%~~4.5% for the comparable period in ~~2014.~~2015. The increase in outstanding debt resulted from borrowings incurred subsequent to June 30, ~~2014~~2015 to fund our ~~2014 and 2015~~ capital ~~programs.~~spending.

Income Taxes. We recorded an income tax benefit for the six months ended June 30, ~~2015~~2016 of ~~$49.9~~$194.0 million compared to ~~income tax expense~~a benefit of ~~$193.7~~$49.9 million for the prior year period, resulting in effective tax rates of approximately ~~27%~~38% and ~~37%~~27%, respectively, after taking into account permanent taxable differences and valuation allowances. For year to date 2016 and 2015, we provided for income taxes at a combined federal and state tax rate of 38% of pre-tax losses generated by our operations in the United States. Our 2015 effective tax rate was reduced by a $12.4 million valuation allowance recognized against deferred tax assets associated with $50.2 million of operating loss carryforwards generated by our Canadian subsidiary in the first half of 2015 for which we do not believe we will realize a benefit.

Liquidity and Capital Resources

Our primary sources of liquidity have historically been cash flows generated from operating activities, financing provided by our revolving credit facility and the issuance of debt and equity securities. At June 30, ~~2015,~~2016, we had ~~$25.5~~$16.6 million of cash and cash equivalents and ~~$1.27~~approximately $1.86 billion of borrowing availability on our revolving credit facility after considering outstanding borrowings and letters of credit. We are focused on balancing our 2016 capital spending with cash flows in order to minimize new borrowings and maintain ample liquidity. At July 31, 2016, outstanding borrowings totaled $820 million with approximately $1.93 billion of borrowing availability on our credit facility after considering ~~$1.23 billion of~~ outstanding borrowings and letters of credit. ~~At July 31, 2015, we continued to have $1.23 billion of outstanding borrowings and $1.27 billion of borrowing availability on our credit facility.~~

Based on our ~~planned~~2016 capital ~~expenditures,~~expenditure budget, our forecasted ~~operating~~ cash flows and projected levels of indebtedness, we expect to maintain compliance with the covenants under our revolving credit facility, three-year term loan, 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, ~~2015,~~2016, including those described in Note 7. 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.

Cash Flows

Cash flows from operating activities

Our net cash provided by operating activities was ~~$916.8~~$497.7 million and ~~$1,432.5~~$916.8 million for the six months ended June 30, ~~2015~~2016 and ~~2014,~~2015, respectively. The decrease in operating cash flows was primarily due to lower crude oil and natural gas revenues driven by lower realized commodity prices, ~~along with increases in production expenses and interest expense associated with the growth of our Company and an increase in producing well count over the past year, all~~ partially offset by lower production expenses, production taxes, and general and administrative expenses and an increase in cash gains on matured natural gas derivatives.

If the commodity ~~prices remain at current levels~~price environment existing in the second quarter of 2016 persists or ~~decline further,~~worsens and our rate of production continues to slow, we expect our operating cash flows for the remainder of ~~2015~~2016 will continue to be lower than ~~2014 levels.~~2015 levels, the extent of which is uncertain due to the unpredictable nature of commodity prices.

Cash flows used in investing activities

During the six months ended June 30, ~~2015~~2016 and ~~2014,~~2015, we had cash flows used in investing activities (excluding proceeds from asset sales) of ~~$1,995.9~~$630.0 million and ~~$2,116.3 million,~~$2.0 billion, respectively, related to our capital program, inclusive of dry hole costs and property acquisitions. ~~Cash acquisition capital expenditures~~Property acquisitions totaled ~~$43.2~~$14.3 million and ~~$107.6~~$43.2 million for the six months ended June 30, 2016 and 2015, respectively. The decrease in capital spending was driven by a decrease in our capital budget and ~~2014, respectively. Cash capital expenditures excluding acquisitions totaled $1,952.7 million and $2,008.7 million~~related drilling activity for ~~the six months ended June 30, 2015 and 2014, respectively.~~2016. Our cash capital expenditures for ~~2015~~2016 include the payment of amounts owed at December 31, ~~2014~~2015 in connection with our ~~2014~~2015 drilling program and associated ~~$387.1~~$86.5 million decrease in accruals for capital expenditures for the six months ended June 30, ~~2015.~~2016.

The use of cash for capital expenditures ~~in 2015 and 2014 was partially offset by proceeds received from asset dispositions, which totaled $32.6 million and $39.0 million for~~during the six months ended June 30, 2016 was partially offset by $112.2 million of proceeds received from asset dispositions primarily related to the April 2016 sale of non-core undeveloped leasehold acreage in Wyoming for proceeds of $110.0 million.

We expect our capital spending for the remainder of 2016 will continue to be lower than 2015 ~~and 2014, respectively.~~levels due to the significant decrease in our budgeted capital spending to $920 million for 2016, a reduction of 63% compared to $2.5 billion of capital spending in 2015.

Cash flows from financing activities

Net cash provided by financing activities for the six months ended June 30, ~~2015~~2016 was ~~$1,051.7~~$25.2 million primarily resulting from net borrowings ~~incurred~~of $32 million on our revolving credit facility during the period. ~~Our 2015 operating cash flows were adversely impacted by decreased commodity prices, leading to a $1,060 million~~The net increase in borrowings was comprised of $87 million of net borrowings in the 2016 first quarter partially offset by $55 million of net repayments in the 2016 second quarter. The second quarter net repayments resulted from a $110.0 million reduction of credit facility debt using proceeds from the sale of undeveloped leasehold acreage in Wyoming in April 2016, partially offset by additional borrowings ~~incurred for~~during the ~~payment of amounts owed in connection with our 2014 drilling program and to fund a portion of our 2015 drilling program.~~quarter.

Net cash provided by financing activities for the six months ended June 30, ~~2014~~2015 was ~~$1,393.3 million~~$1.05 billion primarily resulting from ~~the receipt of $1.68~~$1.06 billion of net ~~proceeds from the issuances of $1.0 billion of 3.8% Senior Notes due 2024 and $700 million of 4.9% Senior Notes due 2044 in May 2014, partially offset by net repayments of $275 million~~borrowings on our ~~credit facility.~~

~~Our levels of capital expenditures and~~revolving credit facility ~~borrowings incurred through June 30, 2015 are not expected to be continued at the same rate for the remainder of 2015. Under our current capital plan, we~~during that period.

We are seeking to generally ~~align~~balance our 2016 capital expenditures with ~~operating~~ cash flows ~~for the remainder of 2015 which we expect will result in reduced capital spending and credit facility~~to minimize new borrowings in ~~the third and fourth quarters compared to levels incurred through year to date June 30, 2015.~~2016.

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 revolving credit facility ~~including our ability to increase our borrowing capacity thereunder,~~ should be sufficient to meet our cash requirements inclusive of, but not limited to, normal operating needs, debt service obligations, planned capital expenditures, and commitments for at least the next 12 months.

Our 2016 capital expenditures budget ~~for the remainder of 2015 is reflective of the depressed commodity price environment and~~ has been established based on an expectation of available cash flows, ~~from operations and availability~~with any cash flow deficiencies expected to be funded by borrowings under our revolving credit facility. If ~~operating~~ cash flows are materially impacted by ~~a further decline~~declines in commodity prices, we have the ability to reduce our capital expenditures or utilize the availability onof our revolving credit facility if needed to fund our operations. We may choose to access the capital markets for additional financing or capital to take advantage of business opportunities that may arise if such financing can be arranged on favorable terms. Additionally, we may choose to sell assets or enter into strategic joint development opportunities in order to obtain funding for our operations and capital program.

We currently anticipate we will be able to generate or obtain funds sufficient to meet our short-term and long-term cash requirements. We intend to ~~finance~~fund future capital expenditures primarily through cash flows from operations and through borrowings under our revolving credit facility, but we may also issue debt or equity securities or sell assets. The issuance of additional debt requires a portion of our cash flows from operations be used for the payment of interest and principal on our debt, thereby reducing our ability to use cash flows to fund working capital, capital expenditures and acquisitions. The issuance of additional equity securities could have a dilutive effect on the value of our common stock.

~~Credit~~Revolving credit facility

We have an unsecured revolving credit facility, maturing on May 16, 2019, with aggregate lender commitments totaling ~~$2.5~~$2.75 billion, which may be increased up to a total of $4.0 billion upon agreement between the Company and participating lenders. The commitments are from a syndicate of 1517 banks and financial institutions. We believe each member of the current syndicate has the capability to fund its commitment. As of July 31, ~~2015,~~2016, we had ~~$1.23~~approximately $1.93 billion ~~of outstanding borrowings and $1.27 billion~~of borrowing availability on our credit facility after considering outstanding borrowings and letters of credit. Borrowings bear interest at market-based interest rates plus a margin based on the terms of the borrowing and the credit ratings assigned to our senior, unsecured, long-term indebtedness.

The commitments under our revolving credit facility are not dependent on a borrowing base calculation subject to periodic redetermination based on changes in commodity prices and proved reserves. Additionally, ~~a downgrade~~downgrades or other negative rating ~~action~~actions with respect to our credit rating, ~~will~~such as the downgrades by Standard & Poor's Ratings Services ("S&P") and Moody's Investor Services, Inc. ("Moody's") that occurred in February 2016 in response to weakened oil and gas industry conditions, do not trigger a reduction in our current credit facility commitments, nor ~~will~~do such ~~action~~actions trigger a security requirement or change in covenants. The downgrades of our credit rating did, however, trigger a 0.250% increase in our credit facility's interest rate and a 0.075% increase in the rate of commitment fees paid on unused borrowing availability under our credit facility.

Our revolving 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, and 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. This ratio represents the ratio of net debt ~~(total~~(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.

We were in compliance with our revolving credit facility covenants at June 30, ~~2015~~2016 and expect to maintain compliance for at least the next 12 months. At June 30, ~~2015,~~2016, our consolidated net debt to total capitalization ratio, as defined in our revolving credit facility as amended, was ~~0.57~~0.59 to 1.00. WeAs we continue to focus on balancing our 2016 capital spending with cash flows to minimize new borrowings, we do not believe the revolving credit facility covenants are reasonably likely to limit our ability to undertake additional debt ~~or equity~~ financing to a material ~~extent.~~extent if needed to support our business. At June 30, ~~2015,~~2016, our total debt would have needed to independently increase by approximately ~~$2.9~~$2.2 billion, or ~~41%~~31%, above existing levels at that date (with no corresponding increase in cash or reduction in refinanced debt) to reach the maximum covenant ratio of 0.65 to 1.00. Alternatively, our total shareholders' equity would have needed to independently decrease by approximately ~~$1.5~~$1.2 billion (excluding the after-tax impact of any non-cash impairment charges), or ~~29%,~~27% below existing levels at June 30, ~~2015~~2016 to reach the maximum covenant ratio. These independent point-in-time sensitivities do not take into account other factors that could arise to mitigate the impact of changes in debt and equity on our consolidated net debt to total capitalization ratio, such as disposing of assets or exploring alternative sources of capitalization.

Joint development agreement funding

In September 2014, we entered into an agreement with a U.S. subsidiary of SK E&S Co. Ltd ("SK") of South Korea to jointly develop a significant portion of the Company's Northwest Cana natural gas properties. Pursuant to the agreement SK will fund, or carry, 50% of our drilling and completion costs attributable to an area of mutual interest within our Northwest Cana properties until approximately $270 million has been expended by SK on our behalf. As of June 30, 2016, approximately $175 million of the carry to be expended by SK on our behalf had yet to be realized and is expected to be realized through 2019.

Proceeds from pending sale of assets

On August 2, 2016, we entered into an agreement to sell non-strategic producing and non-producing properties in the SCOOP play in Oklahoma to a third party for cash proceeds of $281 million. The disposition is expected to close in October 2016. We expect to use the sales proceeds to reduce outstanding debt.

Future Capital Requirements

Senior notes

Our long-term debt includes outstanding senior note obligations totaling $5.8 billion at June 30, ~~2015.~~2016. We have no near-term senior note maturities, with our earliest scheduled maturity being our $200 million of 2020 Notes due in October 2020. 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 6. Long-Term Debt in Notes to Unaudited Condensed Consolidated Financial Statements.

We were in compliance with our senior note covenants at June 30, ~~2015~~2016 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 ~~or equity~~ financing. ~~A downgrade~~Downgrades or other negative rating ~~action~~actions with respect to the credit ratings assigned to our senior unsecured debt, ~~does~~such as the downgrades by S&P and Moody's that occurred in February 2016, do not trigger additional senior note ~~covenants that are more restrictive than the existing covenants at June 30, 2015.~~covenants.

Two of our subsidiaries, Banner Pipeline Company, L.L.C. and CLR Asset Holdings, LLC, which have no material assets or operations, fully and unconditionally guarantee the senior ~~notes.~~notes on a joint and several basis. Our other subsidiaries, the value of whose assets and operations are minor, do not guarantee the senior ~~notes.~~notes as of June 30, 2016.

Term loan

We have a $500 million unsecured term loan that matures in full in November 2018 and bears interest at variable 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. Downgrades or other negative rating actions with respect to our credit rating, such as the S&P and Moody's downgrades that occurred in February 2016, do not trigger a security requirement or change in covenants for the term loan. The February 2016 downgrades of our credit rating did, however, trigger a 0.125% increase in our term loan's interest rate. The interest rate on the term loan was 1.95% at June 30, 2016.

Capital expenditures

We evaluate opportunities to purchase or sell crude oil and natural gas properties and expect to participate as a buyer or seller of properties at various times. We seek acquisitions that utilize our technical expertise or offer opportunities to expand our existing core areas. Acquisition expenditures are not budgeted.

Our capital expenditures budget for ~~2015~~2016 is ~~$2.7 billion~~$920 million excluding acquisitions, which is expected to be allocated as follows:


In millions	Amount		Amount
Exploration and development drilling	$	2,370	$	784
Land costs	180		78
Capital facilities, workovers and other corporate assets	138		55
Seismic	12		3
Total 2015 capital budget, excluding acquisitions	$	2,700
Total 2016 capital budget, excluding acquisitions			$	920

~~During~~For the six months ended June 30, ~~2015,~~2016, we ~~participated in the completion of 528 gross (184 net) wells and~~ invested approximately ~~$1,569.3~~$529.3 million in our capital program, excluding ~~$43.2~~$14.3 million of unbudgeted acquisitions, excluding ~~$387.1~~$86.5 million of capital costs associated with decreased accruals for capital expenditures, and including ~~$3.8~~$0.1 million of seismic costs. Our ~~2015~~2016 year to date capital expenditures were allocated as follows by quarter:


In millions	1Q 2015		2Q 2015		YTD 2015		1Q 2016		2Q 2016		YTD 2016
Exploration and development drilling	$	914.2	$	518.3	$	1,432.5	$	290.0	$	179.6	$	469.6
Land costs	27.1		19.9		47.0		19.9		18.8		38.7
Capital facilities, workovers and other corporate assets	40.9		45.1		86.0		9.9		11.0		20.9
Seismic	1.6		2.2		3.8		0.1		—		0.1
Capital expenditures, excluding acquisitions	983.8		585.5		1,569.3		319.9		209.4		529.3
Acquisitions of producing properties	0.1		0.4		0.5		—		—		—
Acquisitions of non-producing properties	36.7		6.0		42.7		4.4		9.9		14.3
Total acquisitions	36.8		6.4		43.2		4.4		9.9		14.3
Total capital expenditures	$	1,020.6	$	591.9	$	1,612.5	$	324.3	$	219.3	$	543.6

Our 2015 capital program is focused primarily on development drilling in the North Dakota Bakken and SCOOP plays, focusing on core areas of the plays that have the greatest potential to improve recoveries and rates of return.

Our ~~year to date~~non-acquisition capital ~~expenditures incurred through June 30, 2015 are slightly below~~spending budget ~~at mid-year. If our current rate of spending continues, our capital expenditures may be as much as $150 million below our full year 2015 budget of $2.7 billion by year-end.~~

~~Our 2015 capital program~~for 2016 has been ~~established~~set based on an expectation of available cash flows ~~from operations~~ and ~~availability~~is designed to target capital expenditures and cash flows being relatively balanced for 2016 at an assumed average WTI benchmark crude oil price of approximately $37 per barrel for the year, with any cash flow deficiencies being funded by borrowings under our revolving credit facility. Over the six months ended June 30, 2016, WTI crude oil benchmark prices have averaged approximately $40 per barrel.

The actual amount and timing of our capital expenditures may differ materially from our budget as a result of, among other things, access to capital, available cash flows, unbudgeted acquisitions, actual drilling results, the availability of drilling rigs and other services and equipment, the availability of transportation capacity, changes in commodity prices, and regulatory, technological and competitive developments. We ~~will continue to~~ monitor our capital spending closely based on actual and projected cash flows and ~~could~~may continue to scale back our ~~remaining 2015~~ spending should commodity prices ~~remain at~~decrease from current ~~levels or decrease.~~levels. Conversely, an increase in commodity prices 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

Refer to Note 7. Commitments and Contingencies in Notes to Unaudited Condensed Consolidated Financial Statements for a discussion of certain future commitments of the Company as of June 30, ~~2015.~~2016. We believe our cash flows from operations, our remaining cash balance, and amounts available under our revolving credit facility ~~including our ability to increase our borrowing capacity thereunder,~~ will be sufficient to satisfy our commitments.

Off-balance sheet arrangements

Currently, we do not have any off-balance sheet arrangements with unconsolidated entities to enhance liquidity and capital resources. ~~However, as is customary in the crude oil and natural gas industry, we have various contractual commitments not reflected in the consolidated balance sheets as shown in~~ ~~Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Contractual Obligations~~ ~~in our 2014 Form 10-K.~~

Critical Accounting Policies

There have been no changes in our critical accounting policies from those disclosed in our ~~2014~~2015 Form 10-K.

~~Non-GAAP Financial Measures~~

We use a variety of financial and operational measures to assess our performance. Among these measures is EBITDAX. We define EBITDAX as earnings before interest expense, income taxes, depreciation, depletion, amortization and accretion, property impairments, exploration expenses, non-cash gains and losses resulting from the requirements of accounting for derivatives, non-cash equity compensation expense, and losses on extinguishment of debt. EBITDAX is not a measure of net income or operating cash flows as determined by U.S. GAAP.

Management believes EBITDAX is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. Further, we believe EBITDAX is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet future debt service requirements, if any. We exclude the items listed above from net income and operating cash flows in arriving at EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired.

EBITDAX should not be considered as an alternative to, or more meaningful than, net income or operating cash flows as determined in accordance with U.S. GAAP or as an indicator of a company’s operating performance or liquidity. Certain items excluded from EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of EBITDAX. Our computations of EBITDAX may not be comparable to other similarly titled measures of other companies.

~~The following table provides a reconciliation of our net income (loss) to EBITDAX for the periods presented.~~

Three months ended June 30, Six months ended June 30,
In thousands
2015 2014 2015 2014
Net income (loss) $ 403
$ 103,538
$ (131,568 ) $ 329,772
Interest expense 78,442
72,841
153,505
135,816
Provision (benefit) for income taxes 4,142
60,808
(49,880 ) 193,675
Depreciation, depletion, amortization and accretion 452,957
326,871
839,469
599,732
Property impairments 76,872
79,316
224,432
137,524
Exploration expenses 109
11,205
14,449
16,018
Impact from derivative instruments:
Total (gain) loss on derivatives, net 4,737
262,524
(28,018 ) 302,198
Cash received (paid) on derivatives, net 13,182
(64,143 ) 36,617
(97,407 )
Non-cash (gain) loss on derivatives, net 17,919
198,381
8,599
204,791
Non-cash equity compensation 16,165
14,978
27,429
26,017
EBITDAX $ 647,009
$ 867,938
$ 1,086,435
$ 1,643,345

~~The following table provides a reconciliation of our net cash provided by operating activities to EBITDAX for the periods presented.~~

Six months ended June 30,
In thousands 2015 2014
Net cash provided by operating activities $ 916,812
$ 1,432,453
Current income tax provision 10
3,104
Interest expense 153,505
135,816
Exploration expenses, excluding dry hole costs 6,446
11,635
Gain (loss) on sale of assets, net 22,643
(6,363 )
Other, net (4,135 ) (11,317 )
Changes in assets and liabilities (8,846 ) 78,017
EBITDAX $ 1,086,435
$ 1,643,345


ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk

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

Commodity Price Risk. Our primary market risk exposure is in the ~~pricing applicable to~~prices we receive from sales of our crude oil and natural gas production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our natural gas production. Pricing for crude oil and natural gas has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside of our control, including volatility in the differences between product prices at sales points and the applicable index prices. Based on our average daily production for the six months ended June 30, ~~2015,~~2016, and excluding any effect of our derivative instruments in place, our annual revenue would increase or decrease by approximately ~~$536~~$510 million for each $10.00 per barrel change in crude oil prices at June 30, 2016 and ~~$153~~$187 million for each $1.00 per Mcf change in natural gas ~~prices.~~prices at June 30, 2016.

To reduce price risk caused by ~~these~~ market fluctuations in crude oil and natural gas prices, from time to time we may economically hedge a portion of our anticipated crude oil and natural gas production as part of our risk management program. In addition, we may utilize basis contracts to hedge the differential between derivative contract index prices and those of our physical pricing points. Reducing our exposure to price volatility helps secure funds ~~to be used~~ for our capital program. Our decision on the quantity and price at which we choose to hedge our production is based in part on our view of current and future market conditions. We may choose not to hedge future production if the price environment for certain time periods is deemed to be unfavorable. Additionally, we may choose to liquidate existing derivative positions prior to the expiration of their contractual maturities in order to monetize ~~favorable~~ gain positions for the purpose of funding our capital program. While hedging, if utilized, limits the downside risk of adverse price movements, it also limits future revenues from upward price movements. Our crude oil production and sales for ~~2015~~the remainder of 2016 and beyond are currently unhedged and directly exposed to continued volatility in crude oil market prices, whether favorable or unfavorable.

Changes in ~~commodity~~natural gas prices during the six months ended June 30, ~~2015~~2016 had an overall ~~favorable~~unfavorable impact on the fair value of our derivative instruments. For the six months ended June 30, ~~2015,~~2016, we recognized cash gains on natural gas derivatives of ~~$36.6~~$78.0 million ~~partially~~which were more than offset by a non-cash mark-to-market ~~loss~~losses on natural gas derivatives of ~~$8.6~~$118.1 million.

The fair value of our ~~crude oil~~natural gas derivative instruments at June 30, ~~2015~~2016 was a net liability of ~~$0.8~~$16.9 million. An assumed increase in the forward prices used in the June 30, 2015 valuation of our crude oil derivatives of $10.00 per barrel would increase our crude oil derivative liability to approximately $2.3 million at June 30, 2015. Conversely, an assumed decrease in forward prices of $10.00 per barrel would decrease our crude oil derivative liability to approximately $0.3 million at June 30, 2015.

~~The fair value of our natural gas derivative instruments at June 30, 2015 was a net asset of $71.9 million. An assumed increase in the forward prices used in the June 30, 2015~~2016 valuation of our natural gas derivatives of $1.00 per MMBtu would ~~change~~increase our natural gas derivative ~~valuation~~liability to ~~a net liability of~~ approximately ~~$43.0~~$161 million at June 30, ~~2015.~~2016. Conversely, an assumed decrease in forward prices of $1.00 per MMBtu would ~~increase~~change our natural gas derivative valuation to a net asset toof approximately ~~$190.4~~$120 million at June 30, ~~2015.~~2016.

Credit Risk. We monitor our risk of loss due to non-performance by counterparties of their contractual obligations. Our principal exposure to credit risk is through the sale of our crude oil and natural gas production, which we market to energy marketing companies, crude oil refining companies, and natural gas gathering and processing companies ($~~546~~385 millionin receivables at June 30, ~~2015)~~2016), our joint interest receivables ($~~451~~261 millionat June 30, ~~2015)~~2016), and counterparty credit risk associated with our derivative instrument receivables ($7220 million at June 30, ~~2015)~~2016).

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

Joint interest receivables arise from billing the individuals and entities who own a partial interest in the wells we operate. These individuals and entities participate in our wells primarily based on their ownership in leases included in units on which we wish to drill. We can do very little to choose who participates in our wells. In order to minimize our exposure to this credit risk we generally request prepayment of drilling costs where it is allowed by contract or state law. For such prepayments, a liability is recorded and subsequently reduced as the associated work is performed. This liability was ~~$86~~$85 million at June 30, ~~2015,~~2016, which will be used to offset future capital costs when billed. In this manner, we reduce credit risk. We may have the right

to place a lien on our co-owners interest in the well to redirect production proceeds in order to secure payment or, if necessary, foreclose on the interest. Historically, our credit losses on joint interest receivables have been immaterial.

Our use of derivative instruments involves the risk that our counterparties will be unable to meet their commitments under the arrangements. We manage this risk by using multiple counterparties who we consider to be financially strong in order to minimize our exposure to credit risk with any individual counterparty.

Interest Rate Risk. Our exposure to changes in interest rates relates primarily to any variable-rate borrowings we may have outstanding from time to time under our revolving credit ~~facility.~~ facility and three-year term loan. Such borrowings bear interest at market-based interest rates plus a margin based on the terms of the borrowing and the credit ratings assigned to our senior, unsecured, long-term indebtedness. In February 2016, our corporate credit rating was downgraded by S&P and Moody's in response to weakened oil and gas industry conditions and resulting revisions made to rating agency commodity price assumptions. These downgrades caused the interest rates on our revolving credit facility borrowings and three-year term loan to increase by 0.250% and 0.125%, respectively. All of our other long-term indebtedness is fixed rate and does not expose us to the risk of cash flow loss due to changes in market interest rates.

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

We had ~~$1.23~~an aggregate of $1.32 billion of variable rate borrowings outstanding ~~borrowings~~ on our revolving credit facility and three-year term loan at July 31, ~~2015 with a weighted average interest rate of 1.7%.~~2016. The impact of a 1%0.25% increase in interest rates on this amount of debt would result in increased interest expense of approximately ~~$12.3~~$3.3 million per year and a ~~$7.6~~$2.0 million decrease in net income per year.

~~Foreign Currency Exchange Risk.~~The assets, liabilities, revenues, expenses and cash flows associated with our Canadian subsidiary are based on the U.S. dollar equivalent of such amounts measured in the Canadian dollar functional currency. Assets and liabilities of the Canadian subsidiary are translated to U.S. dollars using the applicable exchange rate as of the end of a reporting period. Revenues, expenses and cash flows are translated using an average exchange rate during the reporting period. A 10% change in the Canadian-to-U.S. dollar exchange rate would not materially impact our June 30, 2015 balance sheet.

ITEM 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As of the end of the period covered by this report, an evaluation of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) was performed under the supervision and with the participation of the Company’s management, including its Chief Executive Officer and Chief Financial Officer. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded ~~that~~ the Company’s disclosure controls and procedures were effective as of June 30, ~~2015~~2016 to ensure ~~that~~ information required to be disclosed in the reports it files and submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and ~~that~~ information required to

be disclosed under the Exchange Act is accumulated and communicated to the Company’s management, including its Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control over Financial Reporting

During the three months ended June 30, ~~2015,~~2016, there were no changes in our internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Inherent Limitations on Controls and Procedures

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

PART II. Other Information


ITEM 1.	Legal Proceedings

~~In November 2010,~~See Note 7. Commitments and Contingencies–Litigation in Part I, Item I. Financial Statements–Notes to Unaudited Condensed Consolidated Financial Statements for a ~~putative class action was filed in~~discussion of the ~~District Court of Blaine County, Oklahoma by~~legal matter involving the Company, Billy J. Strack and Daniela A. Renner as trustees of certain named trusts and on behalf of other similarly situated parties against the Company alleging the Company improperly deducted post-production costs from royalties paid to plaintiffs and other royalty interest owners as categorized in the Petition 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 seek recovery of compensatory damages, interest, punitive damages and attorney fees on behalf of the proposed class. In addition, plaintiffs filed an Amended Petition that did not add any substantive claims, but sought a “hybrid class action” in which they sought certification of certain claims for injunctive relief, reserving the right to seek a further class certification on money damages in the future. Plaintiffs also filed an Amended Motion for Class Certification that modified the proposed class to royalty owners in Oklahoma production from July 1, 1993, to the present (instead of 1980 to the present) and sought certification of over 45 separate “issues” for injunctive or declaratory relief, again, reserving the right to seek a further class certification of money damages in the future. The Company responded to the petition, its amendment, and the motions for class certification denying the allegations and raising a number of affirmative defenses to each of the claims and filings. Certain discovery was undertaken and the “hybrid” motion was briefed by plaintiffs and the Company. A hearing on the “hybrid” class certification was held on June 1st and 2nd, 2015. On June 11, 2015, the trial court certified a “hybrid” class as requested by plaintiffs. The Company appealed the trial court’s class certification order, which will be reviewed ~~de novo~~ by the appellate court. The Company is not currently able to estimate a reasonably possible loss or range of loss or what impact, if any, the action will 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 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. Although not currently at issue in the “hybrid” certification, plaintiffs have alleged underpayments in excess of $200 million that they may claim as damages, which may increase with the passage of time, a majority of which would be comprised of interest. The Company disputes plaintiffs’ claims, disputes that the case meets the requirements for a class action and is vigorously defending the case. The Company will continue to assert its defenses to the case as certified as well as any future attempt to certify a money damages class.Renner.


ITEM 1A.	Risk Factors

In addition to the information set forth in this Form 10-Q, you should carefully consider the risk factors discussed in Part I, Item 1A. Risk Factors in our ~~2014~~2015 Form 10-K, which could materially affect our business, financial condition or future results. The risks described in this Form 10-Q, if any, and in our ~~2014~~2015 Form 10-K are not the only risks facing our Company. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results.

There have been no material changes in our risk factors from those disclosed in our ~~2014~~2015 Form 10-K.


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


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


(b)	Use of Proceeds – Not applicable.

(c)Purchases of Equity Securities by the Issuer and Affiliated Purchasers – The following table provides information about purchases of shares of our common stock during the three months ended June 30, ~~2015:~~2016:

Period Total number of shares purchased (1) Average price paid per share (2) 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 (3)
April 1, 2015 to April 30, 2015 6,855
$ 49.96
—
—
May 1, 2015 to May 31, 2015 32,514
47.46
—
—
June 1, 2015 to June 30, 2015 6,647
45.82
—
—
Total 46,016
$ 47.59
—
—



Period	Total number of shares purchased (1)	Average price paid per share (2)		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, 2016 to April 30, 2016	—	—		—	—
May 1, 2016 to May 31, 2016	14,913	$	40.16	—	—
June 1, 2016 to June 30, 2016	1,102	44.50		—	—
Total	16,015	$	40.46	—	—

(1)

In connection with restricted stock grants under the Company's ~~2005 Long-Term Incentive Plan and~~ 2013 Long-Term Incentive Plan, we adopted a policy that enables employees to surrender shares to cover their tax liability. Shares indicated as having been purchased in the table above represent shares surrendered by employees to cover tax liabilities. We paid the associated taxes to the ~~Internal Revenue Service.~~applicable taxing authorities.


(2)	The price paid per share was the closing price of our common stock on the date the restrictions lapsed on such shares.


~~(3)~~	We are unable to determine at this time the total amount of securities or approximate dollar value of securities that could potentially be surrendered to us pursuant to our policy that enables employees to surrender shares to cover their tax liability associated with the vesting of restrictions on shares.


ITEM 3.	Defaults Upon Senior Securities

Not applicable.


ITEM 4.	Mine Safety Disclosures

Not applicable.

ITEM 5. Other Information

Not applicable.


ITEM 6.	Exhibits

The exhibits required to be filed pursuant to Item 601 of Regulation S-K are set forth in the Index to Exhibits accompanying this report and are incorporated herein by reference.

SIGNATURE

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



		CONTINENTAL RESOURCES, INC.

Date:	August ~~5, 2015~~3, 2016	By:	/s/ John D. Hart
			John D. Hart
			Sr. Vice President, Chief Financial Officer and Treasurer (Duly Authorized Officer and Principal Financial Officer)

Index to Exhibits



~~3.1*‡~~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.~~ 2015filed 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 3.1 to the Company’s Current Report on Form 8-K (Commission File No. 001-32886) filed November 6, 2012 and incorporated herein by reference.

~~10.1~~	Amendment No. 1 dated May 4, 2015 to the Revolving Credit Agreement dated as of May 16, 2014 among Continental Resources, Inc., as borrower, Banner Pipeline Company L.L.C. and CLR Asset Holdings, LLC, as guarantors, the lenders party thereto, and MUFG Union Bank, N.A., as Administrative Agent, filed as Exhibit 10.2 to the Company's Form 10-Q for the quarter ended March 31, 2015 (Commission File No. 001-32886) filed May 6, 2015 and incorporated herein by reference.

10.210.1†	Summary of Non-Employee Director Compensation Approved as of May 19, ~~2015~~2016 to be effective July 1, ~~2015.~~2016.

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

101.SCH**	XBRL Taxonomy Extension Schema Document

101.CAL**	XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF**	XBRL Taxonomy Extension Definition Linkbase Document

101.LAB**	XBRL Taxonomy Extension Label Linkbase Document

101.PRE**	XBRL Taxonomy Extension Presentation Linkbase Document


*	Filed herewith


**	Furnished herewith

‡

This exhibit is being filed pursuant to Item 601(b)(3)(i) of Regulation S-K which requires a conformed version of our charter reflecting all amendments in one document. The exhibit reflects our Third Amended and Restated Certificate of Incorporation as filed with the Oklahoma Secretary of State on May 17, 2007 revised for the amendment filed on June 15, 2015, which changed the first sentence of Article Four by increasing the total number of authorized shares from 525,000,000 to 1,025,000,000 and the total authorized common shares from 500,000,000 to 1,000,000,000 as approved by shareholders on May 19, 2015.


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



Crude Oil - NYMEX WTI		Ceilings
			Weighted Average Price
Period and Type of Contract	Bbls	Range	Weighted Average Price
July 2015 - December 2015
Written call options - WTI (1)	2,208,000	$95.85 - $103.75	$	98.36



	Three months ended June 30, 2015		Six months ended June 30, 2015
	Gross	Net	Gross	Net
North Dakota Bakken	158	56	367	116
Montana Bakken	1	—	9	6
SCOOP	55	18	131	54
Northwest Cana	5	2	5	2
Other	4	—	16	6
Total wells	223	76	528	184

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