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~~September 30, 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

~~374,561,751~~ 374,530,174shares of our $0.01 par value common stock were outstanding on ~~July~~October 31, ~~2016~~.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)~~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	1718
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	3132
Item 4.	Controls and Procedures	3234

PART II. Other Information
Item 1.	Legal Proceedings	3435
Item 1A.	Risk Factors	3435
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	3435
Item 3.	Defaults Upon Senior Securities	3435
Item 4.	Mine Safety Disclosures	3435
Item 5.	Other Information	3435
Item 6.	Exhibits	3435
	Signature	3536

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

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

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

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

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

"STACK" Refers to Sooner Trend Anadarko Canadian Kingfisher, a term used to describe a resource play located in the Anadarko Basin of Oklahoma characterized by stacked geologic formations with major targets in the Meramec 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, rates of return, budgets, costs, business strategy, objectives, and cash flows, included in this report are forward-looking statements. The words “could,” “may,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project,” “budget,” “plan,” “continue,” “potential,” “guidance,” “strategy” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.

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

our strategy;

our business and financial plans;

our future operations;

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

technology;

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 believes these assumptions and expectations are reasonable, they are inherently subject to numerous business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control. No assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate or will not change over time. The risks and uncertainties that may affect the operations, performance and results of the business and forward-looking statements include, but are not limited to, those risk factors and other cautionary statements described under Part II, Item 1A. Risk Factors and elsewhere in this report, if any, our Annual Report on Form 10-K for the year ended December 31, 2015, registration statements we file from time to time with the Securities and Exchange Commission, and other announcements we make from time to time.

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

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

iii

PART I. Financial Information


ITEM 1.	Financial Statements

Continental Resources, Inc. and Subsidiaries

Condensed Consolidated Balance Sheets


	June 30, 2016			December 31, 2015			September 30, 2016			December 31, 2015
In thousands, except par values and share data	(Unaudited)						(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	16,560		$	11,463		$	19,496		$	11,463
Receivables:
Crude oil and natural gas sales	385,483			378,622			335,570			378,622
Affiliated parties	96			122			62			122
Joint interest and other, net	260,784			232,293			278,501			232,293
Derivative assets	16,693			93,922			12,587			93,922
Inventories	102,896			94,151			92,894			94,151
Prepaid expenses and other	14,700			11,766			11,765			11,766
Total current assets	797,212			822,339			750,875			822,339
Net property and equipment, based on successful efforts method of accounting	13,541,129			14,063,328			13,094,683			14,063,328
Noncurrent derivative assets	3,045			14,560			1,676			14,560
Other noncurrent assets	18,350			19,581			18,018			19,581
Total assets	$	14,359,736		$	14,919,808		$	13,865,252		$	14,919,808

Liabilities and shareholders’ equity
Current liabilities:
Accounts payable trade	$	412,851		$	553,285		$	413,278		$	553,285
Revenues and royalties payable	186,258			187,000			173,223			187,000
Payables to affiliated parties	185			69			178			69
Accrued liabilities and other	192,359			176,947			199,694			176,947
Derivative liabilities	24,227			3,583			13,780			3,583
Current portion of long-term debt	2,179			2,144			2,197			2,144
Total current liabilities	818,059			923,028			802,350			923,028
Long-term debt, net of current portion	7,149,279			7,115,644			6,830,141			7,115,644
Other noncurrent liabilities:
Deferred income tax liabilities, net	1,896,238			2,090,228			1,847,947			2,090,228
Asset retirement obligations, net of current portion	105,277			101,251			104,938			101,251
Noncurrent derivative liabilities	9,290			3,706			4,299			3,706
Other noncurrent liabilities	14,644			17,051			14,879			17,051
Total other noncurrent liabilities	2,025,449			2,212,236			1,972,063			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; 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
Common stock, $0.01 par value; 1,000,000,000 shares authorized; 374,537,423 shares issued and outstanding at September 30, 2016; 372,959,080 shares issued and outstanding at December 31, 2015							3,745			3,730
Additional paid-in capital	1,360,933			1,345,624			1,363,886			1,345,624
Accumulated other comprehensive loss	(2,903		)	(3,354		)	(2,485		)	(3,354		)
Retained earnings	3,005,173			3,322,900			2,895,552			3,322,900
Total shareholders’ equity	4,366,949			4,668,900			4,260,698			4,668,900
Total liabilities and shareholders’ equity	$	14,359,736		$	14,919,808		$	13,865,252		$	14,919,808

Continental Resources, Inc. and Subsidiaries

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


	Three months ended June 30,						Six months ended June 30,						Three months ended September 30,						Nine months ended September 30,
In thousands, except per share data	2016			2015			2016			2015			2016			2015			2016			2015
Revenues
Crude oil and natural gas sales	$	525,711		$	790,102		$	929,302		$	1,371,294		$	505,892		$	628,457		$	1,435,194		$	1,999,751
Crude oil and natural gas sales to affiliates	—			—			—			1,400			—			—			—			1,400
Gain (loss) on crude oil and natural gas derivatives, net	(82,257		)	(4,737		)	(40,145		)	28,018			15,668			46,527			(24,477		)	74,545
Crude oil and natural gas service operations	7,757			11,009			15,227			21,306			4,639			7,685			19,867			28,991
Total revenues	451,211			796,374			904,384			1,422,018			526,199			682,669			1,430,584			2,104,687

Operating costs and expenses
Production expenses	74,083			91,667			152,724			183,021			67,022			84,036			219,745			267,058
Production expenses to affiliates	—			68			—			1,654			—			—			—			1,654
Production taxes and other expenses	39,141			61,545			69,634			109,908			34,583			47,682			104,216			157,589
Exploration expenses	1,674			109			4,739			14,449			3,987			232			8,726			14,680
Crude oil and natural gas service operations	3,576			7,092			6,618			10,986			2,605			4,059			9,224			15,045
Depreciation, depletion, amortization and accretion	441,761			452,957			905,752			839,469			414,671			448,809			1,320,423			1,288,278
Property impairments	66,112			76,872			145,039			224,432			57,689			96,697			202,728			321,130
General and administrative expenses	36,246			44,190			68,654			89,571			44,389			53,798			113,043			143,368
Net gain on sale of assets and other	(100,835		)	(20,573		)	(99,127		)	(22,643		)	(5,564		)	(288		)	(104,690		)	(22,930		)
Total operating costs and expenses	561,758			713,927			1,254,033			1,450,847			619,382			735,025			1,873,415			2,185,872
Income (loss) from operations	(110,547		)	82,447			(349,649		)	(28,829		)
Loss from operations													(93,183		)	(52,356		)	(442,831		)	(81,185		)
Other income (expense):
Interest expense	(81,922		)	(78,442		)	(162,875		)	(153,505		)	(82,074		)	(79,399		)	(244,949		)	(232,904		)
Other	435			540			819			886			360			588			1,178			1,474
	(81,487		)	(77,902		)	(162,056		)	(152,619		)	(81,714		)	(78,811		)	(243,771		)	(231,430		)
Income (loss) before income taxes	(192,034		)	4,545			(511,705		)	(181,448		)
Provision (benefit) for income taxes	(72,632		)	4,142			(193,978		)	(49,880		)
Net income (loss)	$	(119,402	)	$	403		$	(317,727	)	$	(131,568	)
Basic net income (loss) per share	$	(0.32	)	$	—		$	(0.86	)	$	(0.36	)
Diluted net income (loss) per share	$	(0.32	)	$	—		$	(0.86	)	$	(0.36	)
Loss before income taxes													(174,897		)	(131,167		)	(686,602		)	(312,615		)
Benefit for income taxes													(65,276		)	(48,744		)	(259,254		)	(98,623		)
Net loss													$	(109,621	)	$	(82,423	)	$	(427,348	)	$	(213,992	)
Basic net loss per share													$	(0.30	)	$	(0.22	)	$	(1.15	)	$	(0.58	)
Diluted net loss per share													$	(0.30	)	$	(0.22	)	$	(1.15	)	$	(0.58	)

Comprehensive income (loss):
Net income (loss)	$	(119,402	)	$	403		$	(317,727	)	$	(131,568	)
Comprehensive loss:
Net loss													$	(109,621	)	$	(82,423	)	$	(427,348	)	$	(213,992	)
Other comprehensive income (loss), net of tax:
Foreign currency translation adjustments	25			625			451			(2,480		)	418			(438		)	869			(2,918		)
Total other comprehensive income (loss), net of tax	25			625			451			(2,480		)	418			(438		)	869			(2,918		)
Comprehensive income (loss)	$	(119,377	)	$	1,028		$	(317,276	)	$	(134,048	)
Comprehensive loss													$	(109,203	)	$	(82,861	)	$	(426,479	)	$	(216,910	)

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, 2015	372,959,080		$	3,730		$	1,345,624		$	(3,354	)	$	3,322,900		$	4,668,900		372,959,080		$	3,730		$	1,345,624		$	(3,354	)	$	3,322,900		$	4,668,900
Net loss (unaudited)	—		—			—			—			(317,727		)	(317,727		)	—		—			—			—			(427,348		)	(427,348		)
Other comprehensive income, net of tax (unaudited)	—		—			—			451			—			451			—		—			—			869			—			869
Stock-based compensation (unaudited)	—		—			21,041			—			—			21,041			—		—			34,259			—			—			34,259
Tax deficiency from stock-based compensation (unaudited)																		—		—			(9,460		)	—			—			(9,460		)
Restricted stock:
Granted (unaudited)	2,007,078		20			—			—			—			20			2,025,885		20			—			—			—			20
Repurchased and canceled (unaudited)	(279,019	)	(3		)	(5,732		)	—			—			(5,735		)	(296,105	)	(3		)	(6,537		)	—			—			(6,540		)
Forfeited (unaudited)	(105,835	)	(1		)	—			—			—			(1		)	(151,437	)	(2		)	—			—			—			(2		)
Balance at June 30, 2016 (unaudited)	374,581,304		$	3,746		$	1,360,933		$	(2,903	)	$	3,005,173		$	4,366,949
Balance at September 30, 2016 (unaudited)																		374,537,423		$	3,745		$	1,363,886		$	(2,485	)	$	2,895,552		$	4,260,698

Continental Resources, Inc. and Subsidiaries

Unaudited Condensed Consolidated Statements of Cash Flows


	Six months ended June 30,						Nine months ended September 30,
In thousands	2016			2015			2016			2015
Cash flows from operating activities
Net loss	$	(317,727	)	$	(131,568	)	$	(427,348	)	$	(213,992	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion	908,021			838,216			1,322,280			1,286,158
Property impairments	145,039			224,432			202,728			321,130
Non-cash loss on derivatives, net	114,972			8,599
Non-cash (gain) loss on derivatives, net							105,009			(26,011		)
Stock-based compensation	21,046			27,429			34,274			40,290
Benefit for deferred income taxes	(193,990		)	(49,890		)	(259,256		)	(98,645		)
Tax deficiency (benefit) from stock-based compensation							9,460			(13,177		)
Dry hole costs	206			8,003			233			8,183
Gain on sale of assets, net	(97,016		)	(22,643		)	(103,174		)	(22,930		)
Other, net	4,752			5,388			7,166			10,143
Changes in assets and liabilities:
Accounts receivable	(34,939		)	138,882			(2,634		)	351,309
Inventories	(8,745		)	1,938			1,257			9,137
Other current assets	(2,125		)	50,561			390			64,271
Accounts payable trade	(53,859		)	(106,174		)	(43,131		)	(178,000		)
Revenues and royalties payable	(742		)	(17,589		)	(11,102		)	(45,030		)
Accrued liabilities and other	15,347			(60,162		)	22,411			(78,947		)
Other noncurrent assets and liabilities	(2,519		)	1,390			5,325			1,603
Net cash provided by operating activities	497,721			916,812			863,888			1,415,492

Cash flows from investing activities
Exploration and development	(625,126		)	(1,972,887		)	(878,928		)	(2,598,367		)
Purchase of producing crude oil and natural gas properties	—			(557		)	(29		)	(557		)
Purchase of other property and equipment	(4,867		)	(22,449		)	(5,569		)	(31,991		)
Proceeds from sale of assets and other	112,199			32,590
Proceeds from sale of assets							334,305			33,216
Net cash used in investing activities	(517,794		)	(1,963,303		)	(550,221		)	(2,597,699		)

Cash flows from financing activities
Credit facility borrowings	638,000			1,375,000			915,000			1,780,000
Repayment of credit facility	(606,000		)	(315,000		)	(1,203,000		)	(600,000		)
Repayment of other debt	(1,064		)	(1,032		)	(1,601		)	(1,552		)
Debt issuance costs	(40		)	(2,110		)	(40		)	(2,110		)
Repurchase of restricted stock for tax withholdings	(5,735		)	(5,192		)	(6,540		)	(5,818		)
Net cash provided by financing activities	25,161			1,051,666
Tax (deficiency) benefit from stock-based compensation							(9,460		)	13,177
Net cash (used in) provided by financing activities							(305,641		)	1,183,697
Effect of exchange rate changes on cash	9			(4,098		)	7			(8,916		)
Net change in cash and cash equivalents	5,097			1,077			8,033			(7,426		)
Cash and cash equivalents at beginning of period	11,463			24,381			11,463			24,381
Cash and cash equivalents at end of period	$	16,560		$	25,458		$	19,496		$	16,955

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 all properties south of ~~Kansas~~Nebraska and west of the Mississippi River including various plays in the SCOOP (South Central Oklahoma Oil 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.

A substantial portion of the Company’s operations are concentrated in the North region, with that region comprising approximately ~~64%~~62% of the Company’s crude oil and natural gas production and approximately ~~73%~~71% of its crude oil and natural gas revenues for the ~~six~~nine months ended ~~June~~September 30, 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 of the SCOOP play and its increased activity in the Northwest Cana and STACK plays. The South region comprised approximately ~~36%~~38% of the Company's crude oil and natural gas production and approximately ~~27%~~29% of its crude oil and natural gas revenues for the ~~six~~nine months ended ~~June~~September 30, 2016.

The Company has focused its operations on the exploration and development of crude oil since the 1980s. For the ~~six~~nine months ended ~~June~~September 30, 2016, crude oil accounted for approximately ~~62%~~60% of the Company’s total production and approximately ~~87%~~84% 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, after all significant intercompany accounts and transactions have been eliminated upon consolidation.

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, 2015 (“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~~September 30, 2016 and for the three and ~~six~~nine month periods ended ~~June~~September 30, 2016 and 2015 are unaudited. The condensed consolidated balance sheet as of December 31, 2015 was derived from the audited balance sheet included in the 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.

Earnings per share

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

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)~~loss per share for the three and ~~six~~nine months ended ~~June~~September 30, 2016 and 2015.


	Three months ended June 30,					Six months ended June 30,						Three months ended September 30,						Nine months ended September 30,
In thousands, except per share data	2016			2015		2016			2015			2016			2015			2016			2015
Income (loss) (numerator):
Net income (loss) - basic and diluted	$	(119,402	)	$	403	$	(317,727	)	$	(131,568	)
Loss (numerator):
Net loss - basic and diluted												$	(109,621	)	$	(82,423	)	$	(427,348	)	$	(213,992	)
Weighted average shares (denominator):
Weighted average shares - basic	370,435			369,510		370,248			369,448			370,483			369,599			370,327			369,499
Non-vested restricted stock (1)	—			1,363		—			—			—			—			—			—
Weighted average shares - diluted	370,435			370,873		370,248			369,448			370,483			369,599			370,327			369,499
Net income (loss) per share:
Net loss per share:
Basic	$	(0.32	)	$	—	$	(0.86	)	$	(0.36	)	$	(0.30	)	$	(0.22	)	$	(1.15	)	$	(0.58	)
Diluted	$	(0.32	)	$	—	$	(0.86	)	$	(0.36	)	$	(0.30	)	$	(0.22	)	$	(1.15	)	$	(0.58	)

(1)

~~During~~For the three and ~~six~~nine months ended ~~June~~September 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,~~2,176,500 and ~~1,472,300~~2,083,000 weighted average non-vested restricted shares, respectively, were not included in the calculation of diluted net loss per share because to do so would have been anti-dilutive to the computations. The Company also had net losses for the three and nine months ended September 30, 2015, and therefore approximately 688,800 and 1,521,000 weighted average non-vested restricted shares, respectively, were not included in the calculation of diluted net loss per share for those periods.

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~~September 30, 2016 and December 31, 2015 consisted of the following:


In thousands	June 30, 2016		December 31, 2015		September 30, 2016		December 31, 2015
Tubular goods and equipment	$	16,245	$	15,633	$	16,080	$	15,633
Crude oil	86,651		78,518		76,814		78,518
Total	$	102,896	$	94,151	$	92,894	$	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~~$0.7 million and ~~$0.3~~$1.0 million for the three and ~~six~~nine months ended ~~June~~September 30, 2016, respectively, and ~~$1.3~~$0.9 million and ~~$12.4~~$13.3 million for the three and ~~six~~nine months ended ~~June~~September 30, 2015, respectively, against deferred tax assets associated with operating loss carryforwards generated by its Canadian subsidiary for which the Company does not expect to realize a benefit.

New accounting pronouncements not yet adopted

Leases – In February 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2016-02, Leases (Topic 842), which requires companies to recognize a right of use asset and related liability on the balance sheet for the rights and obligations arising from leases with durations greater than 12 months. The standard is effective for interim and annual reporting periods beginning after December 15, 2018 and requires adoption by application of a modified retrospective transition approach. ~~The Company is currently evaluating the impact of the new standard on its financial statements and related disclosures.~~

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

The Company continues to evaluate the impact of ASU 2016-02 and is in the process of developing systems and processes to identify, classify, and account for leases within the scope of the new guidance. Adoption of ASU 2016-02 will ultimately result in an increase in long-term assets and liabilities on the Company's balance sheet, the effect of which cannot be predicted with certainty at this time.

Stock-based compensation – In March 2016, the FASB issued ~~Accounting Standards Update~~ASU 2016-09, Compensation—Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting, which changes how companies account for certain aspects of share-based payment awards, including the accounting for income taxes, forfeitures, and statutory tax withholding requirements, as well as classification in the statement of cash flows. The standard is effective for interim and annual reporting periods beginning after December 15, 2016 and ~~shall~~will be adopted either prospectively, retrospectively or using a modified retrospective transition approach depending on the topic covered in the standard. ~~The Company~~

Under ASU 2016-09, on a prospective basis companies will no longer record excess tax benefits and deficiencies in additional paid-in capital. Instead, excess tax benefits and deficiencies will be recognized as income tax expense or benefit in the income statement. This is ~~currently evaluating~~expected to result in increased volatility in income tax expense/benefit and corresponding variations in the ~~impact~~relationship between income tax expense/benefit and pre-tax income/loss from period to period, the effect of which cannot be predicted with certainty at this time.

ASU 2016-09 also removes the requirement to delay recognition of an excess tax benefit until it reduces current taxes payable. Under the new ~~standard~~guidance, excess tax benefits will be recorded when they arise. This change is required to be applied on ~~its financial statements and related disclosures.~~ a modified retrospective basis through a cumulative effect adjustment to retained earnings upon adoption. The Company's cumulative effect adjustment is not expected to have a material impact on retained earnings upon adoption of ASU 2016-09 on January 1, 2017.

The Company expects to continue its current accounting practice of estimating forfeitures in determining the amount of stock-based compensation expense to recognize. Therefore, the adoption of ASU 2016-09 is not expected to have an impact on stock-based compensation expense to be recognized on non-vested restricted stock awards.

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 has not yet resulted in cash receipts or payments.


	Six months ended June 30,				Nine months ended September 30,
In thousands	2016		2015		2016		2015
Supplemental cash flow information:
Cash paid for interest	$	156,358	$	148,454	$	213,969	$	204,180
Cash paid for income taxes	—		27		—		27
Cash received for income tax refunds	20		50,000		174		59,117
Non-cash investing activities:
Asset retirement obligation additions and revisions, net	1,042		4,945		1,645		6,267

As of ~~June~~September 30, 2016 and December 31, 2015, the Company had ~~$196.3~~$186.2 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~~September 30, 2015 and December 31, 2014, the Company had ~~$410.3~~$315.0 million and $797.5 million, respectively, of accrued capital expenditures.

Note 4. Derivative Instruments

Crude oil and 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 future sales of 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

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

value in the unaudited condensed consolidated statements of comprehensive ~~income (loss)~~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. 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.

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 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~~September 30, 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 - ICE Brent

Period and Type of Contract	Bbls	Ceiling Price		Bbls	Ceiling Price
July 2016 - December 2016
October 2016 - December 2016
Written call options - ICE Brent (1)	736,000	$	107.70	368,000	$	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														Collars
Natural Gas - NYMEX Henry Hub	Natural Gas - NYMEX Henry Hub		Swaps Weighted Average Price				Floors				Ceilings			Natural Gas - NYMEX Henry Hub			Swaps Weighted Average Price				Floors				Ceilings
						Weighted Average Price				Weighted Average Price										Weighted Average Price				Weighted Average Price
Period and Type of Contract		MMBtus						Range				Range		MMBtus								Range				Range
July 2016 - December 2016
October 2016 - December 2016
Swaps - Henry Hub		78,110,000		$	3.00											34,870,000		$	3.09
January 2017 - December 2017
Swaps - Henry Hub		25,550,000	$	3.35											25,550,000		$	3.35
Collars - Henry Hub		65,700,000					$2.40 - $3.00	$	2.47		$2.92 - $3.88	$	3.08		65,700,000						$2.40 - $3.00	$	2.47		$2.92 - $3.88	$	3.08

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

Crude oil and natural gas derivative gains and losses

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


	Three months ended June 30,						Six months ended June 30,						Three months ended September 30,					Nine months ended September 30,
In thousands	2016			2015			2016			2015			2016		2015			2016			2015
Cash received on derivatives:
Natural gas fixed price swaps	$	38,778		$	5,551		$	77,967		$	23,942		$	5,174	$	5,142		$	83,141		$	29,084
Natural gas collars	—			7,631			—			12,675			—		6,775			—			19,450
Cash received on derivatives, net	38,778			13,182			77,967			36,617			5,174		11,917			83,141			48,534
Non-cash gain (loss) on derivatives:
Crude oil written call options	6			3			38			3,927			—		617			38			4,544
Natural gas fixed price swaps	(101,308		)	(9,296		)	(98,915		)	(2,804		)	5,298		36,257			(93,617		)	33,453
Natural gas collars	(19,733		)	(8,626		)	(19,235		)	(9,722		)	5,196		(2,264		)	(14,039		)	(11,986		)
Non-cash gain (loss) on derivatives, net	(121,035		)	(17,919		)	(118,112		)	(8,599		)	10,494		34,610			(107,618		)	26,011
Gain (loss) on crude oil and natural gas derivatives, net	$	(82,257	)	$	(4,737	)	$	(40,145	)	$	28,018		$	15,668	$	46,527		$	(24,477	)	$	74,545

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 1915 million gallons of diesel fuel over the period from ~~July~~October 2016 to December 2017 at a weighted average price of ~~$1.41~~$1.42 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)~~loss under the caption “Operating costs and expenses—Net gain on sale of assets and other.” For both the three and ~~six~~nine months ended ~~June~~September 30, 2016, the Company recognized ~~non-cash~~cash gains of ~~$4.2~~$0.1 million on its matured diesel fuel derivatives. For the three and nine months ended September 30, 2016, the Company recognized a non-cash loss of $0.5 million and ~~$3.1~~a non-cash gain of $2.6 million, respectively, ~~associated with~~on its diesel fuel derivatives.

Balance sheet offsetting of derivative assets and liabilities

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

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

The following table presents the gross amounts of recognized 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, 2016			December 31, 2015			September 30, 2016			December 31, 2015
Commodity derivative assets:
Gross amounts of recognized assets	$	37,249		$	120,385		$	25,241		$	120,385
Gross amounts offset on balance sheet	(17,511		)	(11,903		)	(10,978		)	(11,903		)
Net amounts of assets on balance sheet	19,738			108,482			14,263			108,482
Commodity derivative liabilities:
Gross amounts of recognized liabilities	(51,028		)	(19,192		)	(29,057		)	(19,192		)
Gross amounts offset on balance sheet	17,511			11,903			10,978			11,903
Net amounts of liabilities on balance sheet	$	(33,517	)	$	(7,289	)	$	(18,079	)	$	(7,289	)

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, 2016			December 31, 2015			September 30, 2016			December 31, 2015
Derivative assets	$	16,693		$	93,922		$	12,587		$	93,922
Noncurrent derivative assets	3,045			14,560			1,676			14,560
Net amounts of assets on balance sheet	19,738			108,482			14,263			108,482
Derivative liabilities	(24,227		)	(3,583		)	(13,780		)	(3,583		)
Noncurrent derivative liabilities	(9,290		)	(3,706		)	(4,299		)	(3,706		)
Net amounts of liabilities on balance sheet	(33,517		)	(7,289		)	(18,079		)	(7,289		)
Total derivative assets (liabilities), net	$	(13,779	)	$	101,193		$	(3,816	)	$	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.

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

Assets and Liabilities Measured at Fair Value on a Recurring Basis

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

The following tables summarize the valuation of financial instruments by pricing levels that were accounted for at fair value on a recurring basis as of ~~June~~September 30, 2016 and December 31, 2015.


	Fair value measurements at June 30, 2016 using:										Fair value measurements at September 30, 2016 using:
In thousands	Level 1		Level 2			Level 3		Total			Level 1		Level 2			Level 3		Total
Derivative assets (liabilities):
Swaps	$	—	$	8,652		$	—	$	8,652		$	—	$	13,418		$	—	$	13,418
Collars	—		(22,430		)	—		(22,430		)	—		(17,234		)	—		(17,234		)
Written call options	—		(1		)	—		(1		)	—		—			—		—
Total	$	—	$	(13,779	)	$	—	$	(13,779	)	$	—	$	(3,816	)	$	—	$	(3,816	)

	Fair value measurements at December 31, 2015 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):
Swaps	$	—	$	104,426		$	—	$	104,426		$	—	$	104,426		$	—	$	104,426
Collars	—		(3,195		)	—		(3,195		)	—		(3,195		)	—		(3,195		)
Written call options	—		(38		)	—		(38		)	—		(38		)	—		(38		)
Total	$	—	$	101,193		$	—	$	101,193		$	—	$	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 the Company's estimates of future crude oil and natural gas production, commodity prices based on commodity futures price strips adjusted for differentials, operating costs, and a risk-adjusted discount rate. The fair value of proved crude oil and natural gas properties is calculated using significant unobservable

~~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 2020 (adjusted for differentials), escalating 3% per year thereafter
Operating costs		Estimated costs for the current year, escalating 3% per year thereafter
Productive life of field		Ranging from 0 to 33 years
Discount rate		10%

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

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

~~Proved properties were reviewed for impairment at June 30, 2016 and June 30, 2015.~~ For the three and ~~six~~nine months ended ~~June~~September 30, 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,~~ 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 totaled $2.9 million for year to date 2016, all of which were recognized in the third quarter primarily for properties in a non-core area of the North region. The impaired properties were written down to their estimated fair value of approximately $0.7 million as of September 30, 2016.

Impairments of proved properties for the three and ~~six~~nine months ended ~~June~~September 30, 2015 totaled ~~$5.0~~$36.3 million and ~~$75.0~~$111.3 million, respectively, and were primarily concentrated in an emerging area with minimal production and costly reserve additions ($~~41.2~~42.5 million, including ~~$5.0~~$1.3 million in the 2015 ~~second~~third quarter), the Buffalo Red River units ($26.3 million, all in the 2015 third quarter), the Medicine Pole Hills units ($~~14.7 million)~~22.9 million, including $8.2 million in the 2015 third quarter), various legacy areas in the South region ($~~11.0 million)~~11.4 million, including $0.4 million in the 2015 third quarter), and non-Bakken areas of North Dakota and Montana ($~~8.1 million)~~8.2 million, including $0.1 million in the 2015 third quarter). The impaired properties were written down to their estimated fair value totaling approximately ~~$38.2~~$48.5 million as of ~~June~~September 30, 2015.

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

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

Three months ended June 30, Six months ended June 30,
In thousands 2016 2015 2016 2015
Proved property impairments $ —
$ 5,028
$ —
$ 75,043
Unproved property impairments 66,112
71,844
145,039
149,389
Total $ 66,112
$ 76,872
$ 145,039
$ 224,432

~~Continental Resources, Inc. and Subsidiaries~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~



	Three months ended September 30,				Nine months ended September 30,
In thousands	2016		2015		2016		2015
Proved property impairments	$	2,895	$	36,302	$	2,895	$	111,346
Unproved property impairments	54,794		60,395		199,833		209,784
Total	$	57,689	$	96,697	$	202,728	$	321,130

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, 2016				December 31, 2015				September 30, 2016				December 31, 2015
In thousands	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Debt:
Revolving credit facility	$	885,000	$	885,000	$	853,000	$	853,000	$	565,000	$	565,000	$	853,000	$	853,000
Term loan	498,556		500,000		498,274		500,000		498,710		500,000		498,274		500,000
Note payable	13,251		12,000		14,309		12,500		12,716		11,400		14,309		12,500
7.375% Senior Notes due 2020(1)	196,878		206,000		196,574		179,200		197,036		205,200		196,574		179,200
7.125% Senior Notes due 2021(1)	395,732		414,000		395,365		388,300		395,923		413,700		395,365		388,300
5% Senior Notes due 2022	1,997,004		1,940,000		1,996,831		1,480,400		1,997,095		1,970,100		1,996,831		1,480,400
4.5% Senior Notes due 2023	1,483,470		1,398,800		1,482,451		1,061,000		1,483,994		1,455,000		1,482,451		1,061,000
3.8% Senior Notes due 2024	990,443		877,500		989,932		700,300		990,702		920,000		989,932		700,300
4.9% Senior Notes due 2044	691,124		590,800		691,052		430,500		691,162		588,900		691,052		430,500
Total debt	$	7,151,458	$	6,824,100	$	7,117,788	$	5,605,200	$	6,832,338	$	6,629,300	$	7,117,788	$	5,605,200

(1) As discussed in Note 11. Subsequent Events, on October 4, 2016 the Company announced it will redeem the 7.375% Senior Notes due 2020 and the 7.125% Senior Notes due 2021 on November 10, 2016.

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

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

The fair value of 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"~~Notes”), the 3.8% Senior Notes due 2024 ("(“2024 ~~Notes"~~Notes”), and the 4.9% Senior Notes due 2044 ("(“2044 ~~Notes"~~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.

Note 6. Long-Term Debt

Long-term debt, net of unamortized discounts, premiums, and debt issuance costs totaling ~~$46.9~~$45.5 million and $49.6 million at ~~June~~September 30, 2016 and December 31, 2015, respectively, consists of the following.

In thousands June 30, 2016 December 31, 2015
Revolving credit facility $ 885,000
$ 853,000
Term loan 498,556
498,274
Note payable 13,251
14,309
7.375% Senior Notes due 2020 196,878
196,574
7.125% Senior Notes due 2021 395,732
395,365
5% Senior Notes due 2022 1,997,004
1,996,831
4.5% Senior Notes due 2023 1,483,470
1,482,451
3.8% Senior Notes due 2024 990,443
989,932
4.9% Senior Notes due 2044 691,124
691,052
Total debt $ 7,151,458
$ 7,117,788
Less: Current portion of long-term debt 2,179
2,144
Long-term debt, net of current portion $ 7,149,279
$ 7,115,644

~~Continental Resources, Inc. and Subsidiaries~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~



In thousands	September 30, 2016		December 31, 2015
Revolving credit facility	$	565,000	$	853,000
Term loan	498,710		498,274
Note payable	12,716		14,309
7.375% Senior Notes due 2020 (1)	197,036		196,574
7.125% Senior Notes due 2021 (1)	395,923		395,365
5% Senior Notes due 2022	1,997,095		1,996,831
4.5% Senior Notes due 2023	1,483,994		1,482,451
3.8% Senior Notes due 2024	990,702		989,932
4.9% Senior Notes due 2044	691,162		691,052
Total debt	$	6,832,338	$	7,117,788
Less: Current portion of long-term debt	2,197		2,144
Long-term debt, net of current portion	$	6,830,141	$	7,115,644

(1) As discussed in Note 11. Subsequent Events, on October 4, 2016 the Company announced it will redeem the 7.375% Senior Notes due 2020 and the 7.125% Senior Notes due 2021 on November 10, 2016.

Revolving Credit Facility

The Company has an unsecured revolving credit facility, maturing on May 16, 2019, with aggregate commitments totaling $2.75 billion at ~~June~~September 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 ~~$885~~$565 million and $853 million of outstanding borrowings on its revolving credit facility at ~~June~~September 30, 2016 and December 31, 2015, respectively. Borrowings bear interest at market-based interest rates plus a margin based on the terms of the borrowing and the credit ratings assigned to the Company's senior, unsecured, long-term indebtedness. The weighted-average interest rate on outstanding credit facility borrowings at ~~June~~September 30, 2016 was ~~2.2%~~2.28%.

The Company had approximately ~~$1.86~~$2.18 billion of borrowing availability on its revolving credit facility at ~~June~~September 30, 2016 and incurs commitment fees based on currently assigned credit ratings of 0.30% per annum on the daily average amount of unused borrowing 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 (calculated as total face value of debt plus outstanding letters of credit less cash and cash equivalents) divided by the sum of net debt plus total shareholders' equity plus, to the extent resulting in a reduction of total shareholders’ equity, the amount of any non-cash impairment charges incurred, net of any tax effect, after June 30, 2014. The Company was in compliance with the revolving credit facility covenants at ~~June~~September 30, 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~~September 30, 2016.

2020 Notes

2021 Notes

2022 Notes

2023 Notes

2024 Notes

2044 Notes

2020 Notes (3)

2021 Notes (3)

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)

—

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.


(3)	As discussed in Note 11. Subsequent Events, on October 4, 2016 the Company announced it will redeem these senior notes on November 10, 2016.

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

The indentures governing the Company's senior notes contain covenants that, among other things, limit the Company's ability to create liens securing certain indebtedness, enter into certain sale-leaseback transactions, 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~~September 30, 2016. ~~Two~~Three of the Company’s subsidiaries, Banner Pipeline Company, L.L.C. ~~and~~, CLR Asset Holdings, LLC, and The Mineral Resources Company, which have no material assets or operations, fully and unconditionally guarantee the senior 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 as of ~~June~~September 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~~September 30, 2016 was ~~1.95%~~2.02%.

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~~September 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 $2.2 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~~September 30, 2016.

Note 7. Commitments and Contingencies

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

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

Drilling commitments – As of ~~June~~September 30, 2016, the Company had drilling rig contracts with various terms extending to ~~year-end 2019~~February 2020 to ensure rig availability in its key operating areas. Future commitments as of ~~June~~September 30, 2016 total approximately ~~$319~~$250 million, of which ~~$97~~$49 million is expected to be incurred in the remainder of 2016, ~~$136~~$134 million in 2017, ~~$62~~$44 million in 2018, ~~and $24~~$21 million in ~~2019.~~2019, and $2 million in 2020.

Pipeline transportation commitments – The Company has entered into firm transportation commitments to guarantee pipeline access capacity on 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~~September 30, 2016 under the pipeline transportation arrangements amount to approximately ~~$893~~$849 million, of which ~~$107~~$55 million is expected to be incurred in the remainder of 2016, ~~$207~~$215 million in 2017, $208 million in 2018, $154 million in 2019, $47 million in 2020, and $170 million thereafter.

The Company’s pipeline commitments are for production primarily in the North region. The Company is not committed under these contracts to deliver fixed and determinable quantities of crude oil or natural gas in the future.

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. The Petition alleged the Company improperly deducted post-production costs from royalties paid to plaintiffs and other royalty interest owners from crude oil and natural gas wells located in Oklahoma. The plaintiffs alleged a number of claims, including breach of contract, fraud, breach of fiduciary duty, unjust enrichment, and other claims and seek recovery of compensatory damages, interest, punitive damages and attorney fees on behalf of the proposed class. 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 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 parties have continued settlement negotiations. If such negotiations are unsuccessful, the Company intends to litigate the case to its conclusion. 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~~September 30, 2016 and December 31, 2015, the Company had recorded a liability in the condensed consolidated balance sheets under the caption “Other noncurrent liabilities” of $6.1 million 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. 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),~~loss, was ~~$11.8~~$13.2 million and ~~$16.2~~$12.9 million for the three months ended ~~June~~September 30, 2016 and 2015, respectively, and ~~$21.0~~$34.3 million and ~~$27.4~~$40.3 million for the ~~six~~nine months ended ~~June~~September 30, 2016 and 2015, respectively.

In May 2013, the Company adopted the 2013 Plan and reserved 19,680,072 shares of common stock that may be issued pursuant to the plan. As of ~~June~~September 30, 2016, the Company had ~~15,177,005~~15,220,886 shares of ~~restricted~~common stock available ~~to grant~~for long-term incentive awards to employees and directors under the 2013 Plan.

Restricted stock is awarded in the name of the recipient and constitutes issued and outstanding shares of the Company’s common stock for all corporate purposes during the period of restriction and, except as otherwise provided under the 2013 Plan or agreement relevant to a given award, includes the right to vote the restricted stock 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~~nine months ended ~~June~~September 30, 2016 is presented 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, 2015	3,249,611		$	48.20	3,249,611		$	48.20
Granted	2,007,078		21.56		2,025,885		21.81
Vested	(1,033,278	)	39.38		(1,084,804	)	39.90
Forfeited	(105,835	)	43.70		(151,437	)	41.13
Non-vested restricted shares outstanding at June 30, 2016	4,117,576		$	37.54
Non-vested restricted shares outstanding at September 30, 2016					4,039,255		$	37.46

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. 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~~nine months ended ~~June~~September 30, 2016 was approximately ~~$21.5~~$24.0 million. As of ~~June~~September 30, 2016, there was approximately ~~$81~~$67 million of unrecognized compensation expense related to non-vested restricted stock. This expense is expected to be recognized over a weighted average period of ~~1.9~~1.6 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~~nine months ended ~~June~~September 30, 2016 and 2015:


	Three months ended June 30,						Six months ended June 30,						Three months ended September 30,						Nine months ended September 30,
In thousands	2016			2015			2016			2015			2016			2015			2016			2015
Beginning accumulated other comprehensive loss, net of tax	$	(2,928	)	$	(3,490	)	$	(3,354	)	$	(385	)	$	(2,903	)	$	(2,865	)	$	(3,354	)	$	(385	)
Foreign currency translation adjustments	25			625			451			(2,480		)	418			(438		)	869			(2,918		)
Income taxes (1)	—			—			—			—			—			—			—			—
Other comprehensive income (loss), net of tax	25			625			451			(2,480		)	418			(438		)	869			(2,918		)
Ending accumulated other comprehensive loss, net of tax	$	(2,903	)	$	(2,865	)	$	(2,903	)	$	(2,865	)	$	(2,485	)	$	(3,303	)	$	(2,485	)	$	(3,303	)


(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).

Note 10. Property Dispositions

On September 30, 2016, the Company sold non-strategic properties in North Dakota and Montana to a third party for cash proceeds of $214.8 million, with no gain or loss recognized. The sale included approximately 68,000 net acres of

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

leasehold primarily in western Williams County, North Dakota, and approximately 12,000 net acres of leasehold in Roosevelt County, Montana. The sale also included producing properties with production totaling approximately 2,700 barrels of oil equivalent per day. The disposed properties represented an immaterial portion of the Company’s proved reserves.

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~~had no production or proved reserves.

~~In May~~See Note 11. Subsequent Events for discussion of an asset disposition that closed subsequent to September 30, 2016.

During the nine months ended September 30, 2015, the Company sold certain ~~undeveloped~~non-strategic properties in various areas to third parties for cash proceeds totaling $33.2 million. The proceeds primarily related to the assignment of certain non-producing leasehold acreage in Oklahoma to a third party for ~~cash proceeds of~~ $25.9 million ~~and~~in May 2015. The Company recognized a pre-tax gain on ~~the~~that transaction of $20.5 million. The ~~disposed~~assigned properties represented an immaterial portion of the Company’s total acreage.

Note 11. Subsequent ~~Event~~Events

Asset Disposition

On ~~August 2,~~October 14, 2016, the Company ~~entered into an agreement to sell~~sold approximately 30,000 net acres of non-strategic ~~producing and non-producing properties~~leasehold located in the SCOOP play in Oklahoma ~~to a third party~~ for cash proceeds ~~of $281~~totaling $295.6 million. The ~~disposition~~leasehold is ~~expected~~located primarily in the eastern portion of the SCOOP play and includes producing properties with production totaling approximately 700 barrels of oil equivalent per day. In connection with the transaction, the Company expects to ~~close~~recognize a pre-tax gain of approximately $200 million, which will be reflected in ~~October 2016.~~fourth quarter 2016 results. The disposed properties ~~to be disposed represent~~represented an immaterial portion of the Company’s proved reserves.

Senior Note Redemptions

On October 4, 2016, the Company announced it will redeem all of its outstanding 7.375% Senior Notes due 2020 (the “2020 Notes”) and 7.125% Senior Notes due 2021 (the “2021 Notes”) on November 10, 2016.

The redemption price for the 2020 Notes will be equal to 102.458% of the principal amount plus accrued and unpaid interest to the redemption date of November 10, 2016 in accordance with the terms of the 2020 Notes and the related indenture under which the 2020 Notes were issued. The aggregate principal amount of the 2020 Notes outstanding is $200 million.

The redemption price for the 2021 Notes will be equal to 103.563% of the principal amount plus accrued and unpaid interest to the redemption date of November 10, 2016 in accordance with the terms of the 2021 Notes and the related indenture under which the 2021 Notes were issued. The aggregate principal amount of the 2021 Notes outstanding is $400 million.

The aggregate of the principal amounts, redemption premiums, and accrued interest payable upon redemption of the 2020 Notes and 2021 Notes is expected to total ~~acreage, proved reserves, production, and revenues.~~approximately $624 million. The Company expects to ~~use~~fund the ~~sales~~redemptions using borrowings under its revolving credit facility. Such borrowings will serve to offset the Company's previous reduction of outstanding credit facility borrowings which used proceeds totaling approximately $630 million from asset dispositions completed in 2016 through October 31, 2016, resulting in no net increase in year to ~~reduce outstanding debt.~~date debt associated with the redemptions.

The Company expects to record a pre-tax loss on extinguishment of debt related to the redemptions of approximately $26 million, which will be reflected in fourth quarter 2016 results and includes the call premiums and write-off of deferred financing costs and unaccreted debt discounts associated with the notes.


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, 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, 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, STACK, and Northwest Cana areas of Oklahoma.

Business Environment and Outlook

Commodity prices have showed some signs of stabilization ~~and recovery~~ in ~~the second quarter of 2016,~~recent months, 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 focus on: (1) optimizing cash flows through operating efficiencies and cost reductions, (2) high-grading investments based on rates of return and opportunities to convert undeveloped acreage to acreage held by production, and (3) balancing capital spending with cash flows to minimize new borrowings and maintain ample liquidity.

2016 Highlights

Production

Production for the ~~second~~third quarter of 2016 averaged ~~219,323~~207,840 Boe per day, a decrease of 5% from the ~~first~~second quarter of 2016 and 3%9% lower than the ~~second~~third quarter of 2015. Year to date production averaged ~~225,063~~219,280 Boe per day, a ~~4% increase~~1% decrease from the comparable 2015 period.

We curtailed a portion of our Bakken production in the third quarter of 2016 due to low commodity prices, which reduced our production in August and September by approximately 12,000 Boe per day. The curtailed production was brought back online at the end of the third quarter.

North Dakota Bakken production averaged ~~114,554~~99,251 Boe per day for the third quarter of 2016, a 13% decrease from the second quarter of 2016, ~~an 11% decrease~~which resulted primarily from the ~~first quarter of 2016~~aforementioned production curtailment, and ~~10%~~20% lower than the ~~second~~third quarter of 2015. Year to date, North Dakota Bakken production averaged ~~121,861~~114,269 Boe per day, ~~a 2%~~an 8% decrease from the comparable 2015 period.

SCOOP production averaged ~~64,669~~67,462 Boe per day for the third quarter of 2016, an increase of 4% compared to the second quarter of 2016 ~~in line with~~and a decrease of 2% from the ~~first quarter of 2016 and 3% higher than the second~~third quarter of 2015. Year to date, SCOOP production averaged ~~64,642~~65,589 Boe per day, ~~a 15%~~an 8% increase over the comparable 2015 period.

~~Combined production~~Production from ~~STACK and~~ STACK/Northwest Cana averaged ~~14,610~~17,680 Boe per day for the ~~second~~third quarter of 2016, an increase of ~~31%~~21% from the ~~first~~second quarter of 2016 and ~~231%~~167% higher than the ~~second~~third quarter of 2015. Year to date, ~~combined STACK and~~ STACK/Northwest Cana production averaged ~~12,868~~14,484 Boe per day, a ~~228%~~200% increase over the comparable 2015 period.

The South region comprised ~~38%~~42% of our total production for the 2016 ~~second~~third quarter compared to ~~34%~~38% for the 2016 ~~first~~second quarter and ~~31%~~35% for the 2015 ~~second~~third quarter. The South region comprised ~~36%~~38% of our total production for year to date 2016 compared to ~~30%~~32% for the comparable 2015 period.

Revenues

Crude oil and natural gas revenues for the 2016 ~~second~~third quarter decreased ~~33%~~20% compared to the 2015 ~~second~~third quarter driven by a ~~30%~~12% decrease in realized commodity prices coupled with a 5%9% decrease in total sales volumes.

Year to date crude oil and natural gas revenues decreased ~~32%~~28% from the comparable 2015 period driven by a ~~35%~~28% decrease in realized commodity ~~prices, the effect of which was partially offset by a 4% increase in total sales volumes.~~prices.

Average crude oil sales prices for the ~~second~~third quarter and year to date periods of 2016 decreased ~~23%~~3% and ~~29%~~21%, respectively, from the comparable 2015 periods.

Crude oil sales volumes for the ~~second~~third quarter and year to date periods of 2016 decreased ~~13%~~21% and 5%10%, respectively, from the comparable 2015 periods.

Average natural gas sales prices for the ~~second~~third quarter and year to date periods of 2016 decreased ~~43%~~9% and ~~46%~~34%, respectively, from the comparable 2015 periods.

Natural gas sales volumes for the ~~second~~third quarter and year to date periods of 2016 increased 13% and ~~23%~~19%, respectively, from the comparable 2015 periods.

Capital expenditures and drilling activity

Capital expenditures excluding acquisitions totaled approximately ~~$209.4~~$238.7 million for the ~~second~~third quarter of 2016, bringing year to date 2016 non-acquisition capital expenditures to ~~$529.3~~$768.0 million compared to ~~$1.57~~$2.1 billion for year to date 2015.

For the ~~second~~third quarter of 2016 we participated in the drilling and completion of 6791 gross ~~(15~~(28 net) wells, bringing our 2016 year to date total to ~~161~~256 gross ~~(34~~(64 net) wells compared to ~~528~~734 gross ~~(184~~(235 net) wells for year to date 2015.

Our inventory of ~~drilled but~~ uncompleted ~~("DUC")~~ wells in North Dakota totaled ~~156~~173 gross ~~(126~~(133 net) operated wells at ~~June~~September 30, 2016 compared to ~~142 gross (114 net) operated wells at March 31, 2016 and~~ 135 gross (107 net) operated wells in North Dakota at December 31, 2015.

Our ~~DUC~~ inventory of uncompleted wells in Oklahoma totaled 4446 gross ~~(25~~(23 net) operated wells at ~~June~~September 30, 2016 compared to ~~42 gross (26 net) operated wells at March 31, 2016 and~~ 35 gross (25 net) operated wells in Oklahoma at December 31, 2015.

Property dispositions

In April 2016, we sold approximately 132,000 net acres of non-core undeveloped leasehold acreage located in Wyoming for $110.0 million. In connection with the transaction we recognized a pre-tax gain of approximately $96.9 million. The disposed properties had no production.

In September 2016, we sold non-strategic properties in North Dakota and Montana for $214.8 million, with no gain or loss recognized. The sale included approximately 80,000 net acres of leasehold and producing properties with production totaling approximately 2,700 Boe per day.

In October 2016, we sold non-strategic properties in the SCOOP play in Oklahoma for $295.6 million. The sale included approximately 30,000 net acres of leasehold and producing properties with production totaling approximately 700 Boe per day. In connection with the transaction, we expect to recognize a pre-tax gain of approximately $200 million, which will be reflected in fourth quarter 2016 results.

Senior note redemptions

On October 4, 2016, we announced we will redeem all of our outstanding 7.375% Senior Notes due 2020 ("2020 Notes") and 7.125% Senior Notes due 2021 ("2021 Notes") on November 10, 2016.

The redemption price for the 2020 Notes will be equal to 102.458% of the $200 million principal amount plus accrued and unpaid interest to the redemption date.

The redemption price for the 2021 Notes will be equal to 103.563% of the $400 million principal amount plus accrued and unpaid interest to the redemption date.

We expect to record a pre-tax loss on extinguishment of debt related to the redemptions of approximately $26 million, which will be reflected in fourth quarter 2016 results.

Credit facility and liquidity

At ~~June~~September 30, 2016, we had ~~$16.6~~$19.5 million of cash and cash equivalents and approximately ~~$1.86~~$2.18 billion of borrowing availability on our credit facility after considering outstanding borrowings and letters of credit. We had ~~$885~~$565 million of outstanding borrowings on our credit facility at ~~June~~September 30, 2016 compared to $885 million at June 30, 2016, $940 million at March 31, 2016 and $853 million at December 31, 2015. At ~~July~~October 31, 2016, outstanding credit facility borrowings ~~totaled $820 million.~~were$295 million with approximately $2.45 billion of borrowing availability. The decrease in outstanding borrowings in October reflects the use of proceeds from our October 2016 SCOOP asset disposition to reduce outstanding debt.

~~Property disposition~~

~~In April~~We expect to borrow approximately $624 million under our credit facility on or around November 10, 2016 ~~we sold approximately 132,000 net acres~~to fund the redemptions of ~~non-core undeveloped leasehold acreage located in Wyoming~~our 2020 Notes and 2021 Notes. Such borrowings will serve to ~~a third party for cash proceeds of $110.0 million. The proceeds were used to pay down a portion~~offset our previous reduction of outstanding credit facility borrowings ~~on our revolving credit facility. In connection~~which used proceeds totaling approximately $630 million from asset dispositions completed in 2016 through October 31, 2016, resulting in no net increase in year to date debt associated with the ~~transaction we recognized a pre-tax gain of approximately $96.9 million.~~

redemptions.

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.

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 September 30,						Nine months ended September 30,
	2016			2015			2016			2015			2016			2015			2016			2015
Average daily production:
Crude oil (Bbl per day)	133,044			149,897			139,756			146,722			116,277			147,472			131,873			146,975
Natural gas (Mcf per day)	517,677			459,898			511,837			420,123			549,374			484,834			524,441			441,930
Crude oil equivalents (Boe per day)	219,323			226,547			225,063			216,742			207,840			228,278			219,280			220,630
Average sales prices:
Crude oil ($/Bbl)	$	38.38		$	49.84		$	31.76		$	44.46		$	37.66		$	38.95		$	33.51		$	42.60
Natural gas ($/Mcf)	$	1.31		$	2.31		$	1.33		$	2.48		$	2.02		$	2.23		$	1.57		$	2.39
Crude oil equivalents ($/Boe)	$	26.36		$	37.82		$	22.73		$	34.93		$	26.42		$	29.90		$	23.91		$	33.18
Crude oil sales price discount to NYMEX ($/Bbl)	$	(7.21	)	$	(8.18	)	$	(7.51	)	$	(9.05	)	$	(7.27	)	$	(7.54	)	$	(7.44	)	$	(8.54	)
Natural gas sales price discount to NYMEX ($/Mcf)	$	(0.65	)	$	(0.33	)	$	(0.69	)	$	(0.31	)	$	(0.80	)	$	(0.54	)	$	(0.73	)	$	(0.39	)
Production expenses ($/Boe)	$	3.72		$	4.39		$	3.74		$	4.70		$	3.50		$	4.00		$	3.66		$	4.45
Production taxes (% of oil and gas revenues)	7.4		%	7.8		%	7.5		%	8.0		%	6.8		%	7.6		%	7.3		%	7.8		%
DD&A ($/Boe)	$	22.15		$	21.68		$	22.16		$	21.36		$	21.66		$	21.36		$	22.00		$	21.36
Total general and administrative expenses ($/Boe) (1)	$	1.82		$	2.11		$	1.68		$	2.28		$	2.32		$	2.56		$	1.88		$	2.38
Net income (loss) (in thousands)	$	(119,402	)	$	403		$	(317,727	)	$	(131,568	)
Diluted net income (loss) per share	$	(0.32	)	$	—		$	(0.86	)	$	(0.36	)
Net loss (in thousands)													$	(109,621	)	$	(82,423	)	$	(427,348	)	$	(213,992	)
Diluted net loss per share													$	(0.30	)	$	(0.22	)	$	(1.15	)	$	(0.58	)


(1)	Represents cash general and administrative expenses per Boe and non-cash equity compensation expenses per Boe. See Operating Costs and Expenses—General and Administrative Expenses below for the quarter and year to date periods for additional discussion of these components.

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

Results of Operations

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

Three months ended June 30,
In thousands, except sales price data 2016 2015
Crude oil and natural gas sales $ 525,711
$ 790,102
Loss on crude oil and natural gas derivatives, net (82,257 ) (4,737 )
Crude oil and natural gas service operations 7,757
11,009
Total revenues 451,211
796,374
Operating costs and expenses (1) (561,758 ) (713,927 )
Other expenses, net (81,487 ) (77,902 )
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) 12,107
13,641
Natural gas (MMcf) 47,109
41,851
Crude oil equivalents (MBoe) 19,958
20,616
Sales volumes:

Crude oil (MBbl) 12,090
13,917
Natural gas (MMcf) 47,109
41,851
Crude oil equivalents (MBoe) 19,941
20,892
Average sales prices:

Crude oil ($/Bbl) $ 38.38
$ 49.84
Natural gas ($/Mcf) 1.31
2.31
Crude oil equivalents ($/Boe) 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.~~



	Three months ended September 30,
In thousands, except sales price data	2016			2015
Crude oil and natural gas sales	$	505,892		$	628,457
Gain on crude oil and natural gas derivatives, net	15,668			46,527
Crude oil and natural gas service operations	4,639			7,685
Total revenues	526,199			682,669
Operating costs and expenses	(619,382		)	(735,025		)
Other expenses, net	(81,714		)	(78,811		)
Loss before income taxes	(174,897		)	(131,167		)
Benefit for income taxes	65,276			48,744
Net loss	$	(109,621	)	$	(82,423	)
Production volumes:
Crude oil (MBbl)	10,698			13,567
Natural gas (MMcf)	50,542			44,605
Crude oil equivalents (MBoe)	19,121			21,002
Sales volumes:
Crude oil (MBbl)	10,724			13,582
Natural gas (MMcf)	50,542			44,605
Crude oil equivalents (MBoe)	19,148			21,016
Average sales prices:
Crude oil ($/Bbl)	$	37.66		$	38.95
Natural gas ($/Mcf)	2.02			2.23
Crude oil equivalents ($/Boe)	26.42			29.90

Production

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


	Three months ended June 30,						Volume increase (decrease)		Volume percent increase (decrease)		Three months ended September 30,						Volume increase (decrease)		Volume percent increase (decrease)
	2016			2015							2016			2015
	Volume	Percent		Volume	Percent						Volume	Percent		Volume	Percent
Crude oil (MBbl)	12,107	61	%	13,641	66	%	(1,534	)	(11	%)	10,698	56	%	13,567	65	%	(2,869	)	(21	%)
Natural gas (MMcf)	47,109	39	%	41,851	34	%	5,258		13	%	50,542	44	%	44,605	35	%	5,937		13	%
Total (MBoe)	19,958	100	%	20,616	100	%	(658	)	(3	%)	19,121	100	%	21,002	100	%	(1,881	)	(9	%)

	Three months ended June 30,						Volume increase (decrease)		Volume percent increase (decrease)		Three months ended September 30,						Volume increase (decrease)		Volume percent increase (decrease)
	2016			2015							2016			2015
	MBoe	Percent		MBoe	Percent						MBoe	Percent		MBoe	Percent
North Region	12,448	62	%	14,150	69	%	(1,702	)	(12	%)	11,003	58	%	13,681	65	%	(2,678	)	(20	%)
South Region	7,510	38	%	6,466	31	%	1,044		16	%	8,118	42	%	7,321	35	%	797		11	%
Total	19,958	100	%	20,616	100	%	(658	)	(3	%)	19,121	100	%	21,002	100	%	(1,881	)	(9	%)

The ~~11%~~21% decrease in crude oil production for the ~~second~~third quarter was driven by decreased production from our North region properties in North Dakota Bakken, Montana Bakken, and the Red River units due to ~~a combination of~~ natural declines in production ~~and reduced drilling and completion activities~~coupled with a curtailment of production in ~~those areas.~~the 2016 third quarter resulting from low crude oil prices. North Dakota Bakken crude oil production decreased ~~1,377~~2,278 MBbls, or ~~14%~~24%, and Montana Bakken production decreased ~~242~~273 MBbls, or ~~24%~~29%, while production in the Red River units decreased ~~145~~135 MBbls, or 13%, over the prior year ~~second~~third quarter. Additionally, crude oil production in SCOOP decreased 454 MBbls, or 22%, resulting from a shift in our activities to liquids-rich natural gas areas of that play offering higher rates of return and opportunities to convert undeveloped acreage to acreage held by production. These decreases were partially offset by an increase of ~~281~~

292 MBbls in crude oil production from our STACK/Northwest Cana

properties due to additional wells being completed and producing ~~resulting from~~as a result of a shift in our ~~well~~drilling and completion activities ~~away from the Bakken~~ to ~~higher~~high rate-of-return ~~areas~~opportunities in ~~Oklahoma.~~that area.

The 13% increase in natural gas production for the ~~second~~third quarter was driven by increased production from our properties in the STACK, Northwest Cana and SCOOP plays due to additional wells being completed and producing subsequent to ~~June~~September 30, 2015. Natural gas production in STACK/Northwest Cana increased ~~3,881~~4,350 MMcf, or ~~173%~~135%, and SCOOP production increased ~~1,042~~1,802 MMcf, or 4%7%, over the prior year ~~second~~third quarter. Additionally, North Dakota Bakken natural gas production increased ~~990~~248 MMcf, or 8%2%, 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.

The increase in natural gas production as a percentage of our total production from ~~34%~~35% in the ~~second~~third quarter of 2015 to ~~39%~~44% in the ~~second~~third quarter of 2016 primarily resulted from significant increases in STACK, Northwest Cana and SCOOP production over the past year due to ~~the aforementioned~~a 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 2016, we expect to continue focusing our well completion activities on our Oklahoma properties. Accordingly, we expect our natural gas production may increase to approximately 40% of our total production for the full year of 2016. As crude oil prices recover, we expect to increase our completion activities in the Bakken and shift our production back to a higher proportion of crude oil.

Revenues

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

Crude Oil and Natural Gas Sales. Crude oil and natural gas sales for the ~~second~~third quarter of 2016 were ~~$525.7~~$505.9 million, a ~~33%~~20% decrease from sales of ~~$790.1~~$628.5 million for the 2015 ~~second~~third quarter due to decreases in commodity prices and total sales volumes.

Our crude oil sales prices averaged ~~$38.38~~$37.66 per barrel in the 2016 ~~second~~third quarter, a decrease of ~~23%~~3% compared to ~~$49.84~~$38.95 for the 2015 ~~second~~third quarter due to lower crude oil market prices. The differential between NYMEX West Texas Intermediate ("WTI") calendar month crude oil prices and our realized crude oil prices averaged ~~$7.21~~$7.27 per barrel for the 2016 ~~second~~third quarter compared to ~~$8.18~~$7.54 for the 2015 ~~second~~third quarter. The improved differential was due to increased use of pipeline transportation to move our North region crude oil to market with less dependence on more costly rail transportation, along with ~~significant growth in~~an increased proportion of our total production coming from the 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 natural gas sales prices averaged ~~$1.31~~$2.02 per Mcf for the 2016 ~~second~~third quarter, a ~~43%~~9% decrease compared to ~~$2.31~~$2.23 per Mcf for the 2015 ~~second~~third quarter due primarily to ~~lower market prices for natural gas and natural gas liquids (“NGLs”) along with~~ the amendment of certain natural gas sales agreements in 2016. The amended contracts contributed to an increase in the discount between our realized natural gas sales prices and NYMEX Henry Hub calendar month natural gas prices from $0.54 per Mcf for the 2015 third quarter to $0.80 per Mcf for the 2016 third quarter. The majority of our natural gas production is sold at our lease locations to midstream purchasers with price realizations impacted by the volume and value of ~~NGLs~~natural gas liquids ("NGLs") that purchasers 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 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. NGL prices remained depressed in the 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. 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 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 2016 revenues and differentials.

For the ~~second~~third quarter of 2016, our crude oil sales volumes decreased ~~13%~~21% 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 areas in Oklahoma with higher concentrations of liquids-rich natural gas.

Derivatives. Changes in natural gas prices during the ~~second~~third quarter of 2016 had ~~an unfavorable~~a favorable impact on the fair value of our natural gas derivatives, which resulted in ~~negative~~positive revenue adjustments of ~~$82.3~~$15.7 million for the period, representing ~~$121.0~~$10.5 million of non-cash ~~losses~~gains on derivatives ~~partially offset by $38.7~~and $5.2 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 natural gas prices.

Operating Costs and Expenses

Production Expenses. Production expenses decreased ~~$17.6~~$17.0 million, or ~~19%~~20%, from ~~$91.7~~$84.0 million for the ~~second~~third quarter of 2015 to ~~$74.1~~$67.0 million for the ~~second~~third quarter of 2016. Production expenses on a per-Boe basis decreased to ~~$3.72~~$3.50 for the 2016 ~~second~~third quarter compared to ~~$4.39~~$4.00 for the 2015 ~~second~~third quarter. 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 Oklahoma which typically have lower operating costs compared to ~~crude oil~~ wells in the Bakken.

Production Taxes and Other Expenses. Production taxes and other expenses decreased ~~$22.4~~$13.1 million, or ~~36%~~27%, to ~~$39.1~~$34.6 million for the ~~second~~third quarter of 2016 compared to ~~$61.5~~$47.7 million for the ~~second~~third quarter of 2015 primarily due to lower crude oil and natural gas revenues resulting from decreases in commodity prices and total sales volumes over the prior year period.

Production taxes are generally based on the wellhead values of production and vary by state. Production taxes as a percentage of crude oil and natural gas revenues were ~~7.4%~~6.8% for the ~~second~~third quarter of 2016 compared to ~~7.8%~~7.6% for the ~~second~~third 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 the remainder of 2016 will continue to trend lower than 2015 levels as our operations in Oklahoma continue to grow in relative 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~~on crude oil revenues ~~in North Dakota~~ effective January 1, 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 September 30,
In thousands	2016		2015		2016		2015
Geological and geophysical costs	$	1,468	$	109	$	3,960	$	52
Exploratory dry hole costs	206		—		27		180
Exploration expenses	$	1,674	$	109	$	3,987	$	232

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

Depreciation, Depletion, Amortization and Accretion (“DD&A”). Total DD&A decreased ~~$11.2~~$34.1 million, or 2%8%, to ~~$441.8~~$414.7 million for the ~~second~~third quarter of 2016 compared to ~~$453.0~~$448.8 million for the ~~second~~third quarter of 2015 primarily due to a 5%9% decrease in total sales volumes. The following table shows the components of our DD&A on a unit of sales basis for the periods presented.


	Three months ended June 30,				Three months ended September 30,
$/Boe	2016		2015		2016		2015
Crude oil and natural gas	$	21.69	$	21.32	$	21.20	$	20.98
Other equipment	0.38		0.31		0.38		0.32
Asset retirement obligation accretion	0.08		0.05		0.08		0.06
Depreciation, depletion, amortization and accretion	$	22.15	$	21.68	$	21.66	$	21.36

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. 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 second quarter of 2016 compared to the prior year period. If commodity prices decline, ~~further, additional~~ downward revisions of proved reserves may occur in the future, which may be significant and would result in an increase in our DD&A rate. We are unable to predict the timing and amount of future reserve revisions or the impact such revisions may have on our future DD&A rate.

Property Impairments. Total property impairments decreased ~~$10.8~~$39.0 million, or ~~14%~~40%, to ~~$66.1~~$57.7 million for the 2016 ~~second~~third quarter compared to ~~$76.9~~$96.7 million for the 2015 ~~second quarter.There were no~~third quarter primarily due to a decrease in proved property impairments. Proved property impairments ~~recognized in~~totaled $2.9 million for the ~~second~~2016 third quarter ~~of 2016~~ compared to ~~$5.0~~$36.3 million ~~of such impairments in~~for the ~~second~~third quarter of 2015. This decrease resulted from differences in the timing and severity of commodity price declines and resulting impact on fair value 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 June 2016,~~ our proved properties are carried at values that, ~~did not exceed~~when compared to estimated future net cash flows, ~~at June 30, 2016 and~~ required nominimal impairment ~~during~~for the 2016 ~~second~~third quarter.

Estimated reserves are a key component in assessing proved properties for impairment. If commodity prices decline, ~~further,~~ downward revisions of reserves may be significant in the future and could result in additional impairments of proved ~~properties in the remainder of 2016.~~properties. We are unable to predict the timing and amount of future reserve revisions or the impact such revisions may have on future impairments, if any.

Impairments of non-producing properties decreased ~~$5.7~~$5.6 million, or 8%9%, to ~~$66.1~~$54.8 million for the 2016 ~~second~~third quarter compared to ~~$71.8~~$60.4 million for the 2015 ~~second~~third quarter. The decrease was due to 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 of undeveloped leasehold costs between periods resulting from changes in the Company's estimates of undeveloped properties not expected to be developed before lease expiration.

General and Administrative ("G&A") Expenses. Total G&A expenses decreased ~~$7.9~~$9.4 million, or ~~18%~~17%, to ~~$36.2~~$44.4 million for the ~~second~~third quarter of 2016 from ~~$44.2~~$53.8 million for ~~second~~third quarter of 2015. Total G&A expenses include non-cash charges for equity compensation of ~~$11.8~~$13.2 million and ~~$16.2~~$12.9 million for the ~~second~~third quarters of 2016 and 2015, respectively. G&A expenses

other than equity compensation included in the total G&A expense figure above totaled ~~$24.4~~$31.2 million for the 2016 ~~second~~third quarter, a decrease of ~~$3.6~~$9.7 million, or ~~13%~~24%, compared to the 2015 ~~second quarter.~~third quarter primarily due to a reduction in employee related costs and other efforts to reduce spending in response to depressed commodity prices.

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

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

The decrease in G&A expenses other than equity compensation was primarily due to a reduction in employee related costs and other efforts to reduce spending in response to depressed commodity prices. The decrease in equity compensation expense 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 2016.



	Three months ended September 30,
$/Boe	2016		2015
General and administrative expenses	$	1.63	$	1.95
Non-cash equity compensation	0.69		0.61
Total general and administrative expenses	$	2.32	$	2.56

Interest Expense. Interest expense increased ~~$3.5~~$2.7 million, or 4%3%, to ~~$81.9~~$82.1 million for the ~~second~~third quarter of 2016 compared to ~~$78.4~~$79.4 million for the ~~second~~third quarter of 2015 due to ~~an increase in our weighted average outstanding long-term debt 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 2016 ~~second~~third quarter was approximately ~~$7.3~~$7.1 billion with a weighted average interest rate of ~~4.3% compared to averages of $7.1 billion and 4.3% for~~4.4%, consistent with the 2015 ~~second~~third quarter. The ~~increase in outstanding debt resulted from borrowings incurred subsequent to June 30, 2015 to fund~~2016 third quarter includes approximately $11 million of interest expense associated with our ~~capital spending.~~2020 Notes and 2021 Notes that will be redeemed on November 10, 2016.

Income Taxes. We recorded an income tax benefit for the ~~second~~third quarter of 2016 of ~~$72.6~~$65.3 million compared to ~~income tax expense~~a benefit of ~~$4.1~~$48.7 million for the ~~second~~third quarter of 2015, resulting in effective tax rates of approximately ~~38% and 91%, respectively,~~37% for both periods after taking into account permanent taxable differences and valuation allowances. For the ~~second~~third 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)~~losses generated by our operations in the United ~~States.~~States and 25% of pre-tax losses generated by our operations in Canada. Our consolidated effective tax ~~rate~~rates for the third quarter periods were reduced as a result of valuation allowances totaling $0.7 million for the 2016 third quarter and $0.9 million for the 2015 ~~second~~third quarter ~~was increased by a $1.3 million valuation allowance~~being recognized against deferred tax assets ~~associated with $6.4 million of~~arising from 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~~Nine months ended ~~June~~September 30, 2016 compared to the ~~six~~nine months ended ~~June~~September 30, 2015

Results of Operations

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


	Six months ended June 30,						Nine months ended September 30,
In thousands, except sales price data	2016			2015			2016			2015
Crude oil and natural gas sales	$	929,302		$	1,372,694		$	1,435,194		$	2,001,151
Gain (loss) on crude oil and natural gas derivatives, net	(40,145		)	28,018			(24,477		)	74,545
Crude oil and natural gas service operations	15,227			21,306			19,867			28,991
Total revenues	904,384			1,422,018			1,430,584			2,104,687
Operating costs and expenses (1)	(1,254,033		)	(1,450,847		)	(1,873,415		)	(2,185,872		)
Other expenses, net	(162,056		)	(152,619		)	(243,771		)	(231,430		)
Loss before income taxes	(511,705		)	(181,448		)	(686,602		)	(312,615		)
Benefit for income taxes	193,978			49,880			259,254			98,623
Net loss	$	(317,727	)	$	(131,568	)	$	(427,348	)	$	(213,992	)
Production volumes:
Crude oil (MBbl)	25,436			26,557			36,133			40,124
Natural gas (MMcf)	93,154			76,043			143,697			120,647
Crude oil equivalents (MBoe)	40,961			39,231			60,083			60,232
Sales volumes:
Crude oil (MBbl)	25,356			26,628			36,080			40,210
Natural gas (MMcf)	93,154			76,043			143,697			120,647
Crude oil equivalents (MBoe)	40,882			39,301			60,029			60,318
Average sales prices:
Crude oil ($/Bbl)	$	31.76		$	44.46		$	33.51		$	42.60
Natural gas ($/Mcf)	1.33			2.48			1.57			2.39
Crude oil equivalents ($/Boe)	22.73			34.93			23.91			33.18

(1) Net of gain on sale of assets of ~~$97.0~~$103.2 million and ~~$22.6~~$22.9 million for the ~~six~~nine months ended ~~June~~September 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 (decrease)		Volume percent increase (decrease)		Nine months ended September 30,						Volume increase (decrease)		Volume percent increase (decrease)
	2016			2015							2016			2015
	Volume	Percent		Volume	Percent						Volume	Percent		Volume	Percent
Crude oil (MBbl)	25,436	62	%	26,557	68	%	(1,121	)	(4	%)	36,133	60	%	40,124	67	%	(3,991	)	(10	%)
Natural gas (MMcf)	93,154	38	%	76,043	32	%	17,111		23	%	143,697	40	%	120,647	33	%	23,050		19	%
Total (MBoe)	40,961	100	%	39,231	100	%	1,730		4	%	60,083	100	%	60,232	100	%	(149	)	—	%

	Six months ended June 30,						Volume increase (decrease)		Volume percent increase (decrease)		Nine months ended September 30,						Volume increase (decrease)		Volume percent increase (decrease)
	2016			2015							2016			2015
	MBoe	Percent		MBoe	Percent						MBoe	Percent		MBoe	Percent
North Region	26,240	64	%	27,576	70	%	(1,336	)	(5	%)	37,243	62	%	41,257	68	%	(4,014	)	(10	%)
South Region	14,721	36	%	11,655	30	%	3,066		26	%	22,840	38	%	18,975	32	%	3,865		20	%
Total	40,961	100	%	39,231	100	%	1,730		4	%	60,083	100	%	60,232	100	%	(149	)	—	%

The 4%10% decrease in crude oil production for year to date 2016 was driven primarily by decreased production from our North region properties in North Dakota Bakken, Montana Bakken and the Red River units due to ~~a combination of~~ natural declines in production ~~and reduced drilling and completion activities~~coupled with a curtailment of production in ~~those areas.~~the 2016 third quarter resulting from low crude oil prices. North Dakota Bakken crude oil production decreased ~~1,001~~3,279 MBbls, or 5%12%, and Montana Bakken production decreased ~~607~~880 MBbls, or 28%, while production in the Red River units decreased ~~275~~410 MBbls, or 13%, over the prior year period. Additionally, crude oil

production in SCOOP decreased 76 MBbls, or 1%, resulting from a shift in our activities to liquids-rich natural gas areas of that play offering higher rates of return and opportunities to convert undeveloped acreage to acreage held by production. These decreases were partially offset by ~~increases~~an increase of 795 MBbls in crude oil production from our ~~properties~~

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

The ~~23%~~19% increase in natural gas production for year to date 2016 was driven by increased production from our properties in the ~~STACK/~~STACK, Northwest Cana, and SCOOP plays due to additional wells being completed and producing subsequent to ~~June~~September 30, 2015. Natural gas production in STACK/Northwest Cana increased ~~6,771~~11,121 MMcf, or ~~173%~~156%, and SCOOP production increased ~~7,236~~9,038 MMcf, or ~~17%~~13%, over the prior year period. Additionally, North Dakota Bakken production increased ~~3,942~~4,190 MMcf, or ~~17%~~12%, 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 reduction in capital spending and deferral of certain well completion activities throughout 2016 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 2016.~~production. We expect our rate of production to ~~slow for the remainder of 2016 and may~~ average between ~~210,000~~215,000 and 220,000 Boe per day for the full year of 2016 compared to average daily production of 221,715 Boe per day for full year 2015.

Revenues

Crude Oil and Natural Gas Sales. Crude oil and natural gas sales for year to date 2016 were ~~$929.3 million,~~$1.44 billion, a ~~32%~~28% decrease from sales of ~~$1.37~~$2.00 billion for the same period in 2015 due to ~~a significant decrease~~decreases in commodity prices ~~partially offset by an increase in~~and total sales volumes.

Our crude oil sales prices averaged ~~$31.76~~$33.51 per barrel for year to date 2016, a decrease of ~~29%~~21% compared to ~~$44.46~~$42.60 for year to date 2015 due to lower crude oil 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 2016 was ~~$7.51~~$7.44 per barrel compared to ~~$9.05~~$8.54 for year to date 2015. The improved differential was due to increased use of pipeline transportation to move our North region crude oil to market with less dependence on more costly rail 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 natural gas sales prices averaged ~~$1.33~~$1.57 per Mcf for year to date 2016, a ~~46%~~34% decrease compared to ~~$2.48~~$2.39 for year to date 2015 due primarily to ~~lower market prices for natural gas and NGLs along with~~ the amendment of certain natural gas sales agreements in 2016. The ~~difference~~amended contracts contributed to an increase in the discount between our realized natural gas sales prices and NYMEX Henry Hub calendar month natural gas prices ~~was a discount of $0.69~~from $0.39 per Mcf for year to date ~~2016 compared~~2015 to ~~a discount of $0.31~~$0.73 per Mcf for the comparable 2015 period. NGL prices in the first half of 2016 remained depressed in conjunction with low crude oil prices, which, along with our amended natural gas sales agreements, reduced the valueyear to date 2016. The majority of our natural gas production is sold at our lease locations to midstream purchasers with price realizations impacted by the volume and value of NGLs that purchasers extract from our sales stream and unfavorably impacted the difference between our realized prices and Henry Hub benchmark pricing. 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. stream.

For year to date 2016, our crude oil sales volumes decreased 5%10% from the comparable 2015 period, while our natural gas sales volumes increased ~~23%~~19%, 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 8053 MBbls for year to date 2016.

Derivatives. Changes in natural gas prices during the ~~six~~nine months ended ~~June~~September 30, 2016 had an unfavorable impact on the fair value of our natural gas derivatives, which resulted in negative revenue adjustments of ~~$40.1~~$24.5 million for the period, representing ~~$118.1~~$107.6 million of non-cash losses on derivatives partially offset by ~~$78.0~~$83.1 million of cash gains.

Operating Costs and Expenses

Production Expenses. Production expenses decreased ~~$32.0~~$49.0 million, or ~~17%~~18%, from ~~$184.7~~$268.7 million for year to date 2015 to ~~$152.7~~$219.7 million for year to date 2016. Production expenses on a per-Boe basis decreased to ~~$3.74~~$3.66 for year to date 2016 compared to ~~$4.70~~$4.45 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 Oklahoma which typically have lower operating costs compared to ~~crude oil~~ wells in the Bakken.

Production Taxes and Other Expenses. Production taxes and other expenses decreased ~~$40.3~~$53.4 million, or ~~37%~~34%, to ~~$69.6~~$104.2 million for year to date 2016 compared to ~~$109.9~~$157.6 million for year to date 2015 primarily due to lower crude oil and natural gas revenues resulting primarily from decreases in commodity prices over the prior year period. Production taxes as a

percentage of crude oil and natural gas revenues were ~~7.5%~~7.3% for year to date 2016 compared to ~~8.0%~~7.8% for year to date 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 the remainder of 2016 will continue to trend lower than 2015 levels as our operations in Oklahoma continue to grow in relative 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~~on 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,				Nine months ended September 30,
In thousands	2016		2015		2016		2015
Geological and geophysical costs	$	4,533	$	6,446	$	8,493	$	6,497
Exploratory dry hole costs	206		8,003		233		8,183
Exploration expenses	$	4,739	$	14,449	$	8,726	$	14,680

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

Dry hole costs incurred in 2015 primarily reflect costs associated with an unsuccessful well in a prospect in our North region. There have been no significant dry hole costs incurred in 2016.

Depreciation, Depletion, Amortization and Accretion. Total DD&A increased ~~$66.3~~$32.1 million, or 8%2%, to ~~$905.8 million~~$1.32 billion for year to date 2016 compared to ~~$839.5 million~~$1.29 billion for the comparable period in 2015 primarily due to ~~a 4%~~an increase in ~~total sales volumes.~~our DD&A rate between periods resulting from downward revisions of proved reserves at year-end 2015 and in 2016 prompted by depressed commodity prices. The following table shows the components of our DD&A on a unit of sales basis.


	Six months ended June 30,				Nine months ended September 30,
$/Boe	2016		2015		2016		2015
Crude oil and natural gas	$	21.71	$	20.98	$	21.55	$	20.98
Other equipment	0.37		0.32		0.37		0.32
Asset retirement obligation accretion	0.08		0.06		0.08		0.06
Depreciation, depletion, amortization and accretion	$	22.16	$	21.36	$	22.00	$	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 2016 prompted by depressed commodity prices. If commodity prices decline, ~~further,~~ additional downward revisions of proved reserves may occur in the future, which may be significant and would result in ana further increase in our DD&A rate. We are unable to predict the timing and amount of future reserve revisions or the impact such revisions may have on our future DD&A rate.

Property Impairments. Total property impairments decreased ~~$79.4~~$118.4 million, or ~~35%~~37%, to ~~$145.0~~$202.7 million for year to date 2016 compared to ~~$224.4~~$321.1 million for year to date 2015 primarily due to a decrease in proved property impairments. ~~There were no proved~~Proved property impairments ~~recognized~~totaled $2.9 million for year to date 2016 compared to ~~$75.0~~$111.3 million ~~of such impairments~~ for year to date 2015. This decrease resulted from differences in the timing and severity of commodity price declines and resulting 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, ~~did not exceed~~when compared to estimated future net cash flows, ~~at June 30, 2016 and~~ required nominimal impairment during the ~~six month period.~~nine months ended September 30, 2016.

If commodity prices decline, ~~further,~~ downward revisions of reserves may be significant in the future and could result in additional impairments of proved ~~properties in the remainder of 2016.~~properties. We are unable to predict the timing and amount of future reserve revisions or the impact such revisions may have on future impairments, if any.

Impairments of non-producing properties decreased $10.0 million, or 5%, to $199.8 million for year to date 2016 compared to $209.8 million for year to date 2015. The decrease was due to 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 of undeveloped leasehold costs between periods resulting from changes in the Company's estimates of undeveloped properties not expected to be developed before lease expiration.

General and Administrative Expenses. Total G&A expenses decreased ~~$20.9~~$30.4 million, or ~~23%~~21%, to ~~$68.7~~$113.0 million for year to date 2016 from ~~$89.6~~$143.4 million for the comparable period in 2015. Total G&A expenses include non-cash charges for equity compensation of ~~$21.0~~$34.3 million and ~~$27.4~~$40.3 million for year to date 2016 and year to date 2015, respectively. G&A

expenses other than equity compensation included in the total G&A expense figure above totaled ~~$47.7~~$78.7 million for year to date 2016, a decrease of ~~$14.5~~$24.4 million, or ~~23%~~24%, 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,				Nine months ended September 30,
$/Boe	2016		2015		2016		2015
General and administrative expenses	$	1.16	$	1.58	$	1.31	$	1.71
Non-cash equity compensation	0.52		0.70		0.57		0.67
Total general and administrative expenses	$	1.68	$	2.28	$	1.88	$	2.38

Interest Expense. Year to date interest expense increased ~~$9.4~~$12.0 million, or 6%5%, to ~~$162.9~~$244.9 million compared to ~~$153.5~~$232.9 million for the comparable 2015 period due to an increase in our weighted average outstanding long-term debt ~~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.~~obligations. Our weighted average outstanding long-term debt balance for year to date 2016 was approximately $7.2 billion with a weighted average interest rate of 4.3% compared to averages of ~~$6.7~~$6.8 billion and ~~4.5%~~4.4% for the comparable period in 2015. The increase in outstanding debt resulted from borrowings incurred subsequent to ~~June~~September 30, 2015 to fund our capital spending. We plan to redeem our 2020 Notes and 2021 Notes on November 10, 2016, which is expected to reduce our future interest expense by approximately $44 million annually, assuming no other changes in outstanding debt.

Income Taxes. We recorded an income tax benefit for the ~~six~~nine months ended ~~June~~September 30, 2016 of ~~$194.0~~$259.3 million compared to a benefit of ~~$49.9~~$98.6 million for the prior year period, resulting in effective tax rates of approximately 38% and ~~27%~~32%, 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.~~States and 25% of pre-tax losses generated by our operations in Canada. Our 2015 consolidated effective tax rate was reduced byas a ~~$12.4~~result of a $13.3 million valuation allowance being recognized against deferred tax assets ~~associated with $50.2~~arising from $52 million of operating loss carryforwards generated by our Canadian subsidiary infor the ~~first half of~~nine months ended September 30, 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. Additionally, in 2016 non-strategic asset dispositions have provided a significant source of cash flow that was used to reduce outstanding debt and enhance liquidity. At ~~June~~September 30, 2016, we had ~~$16.6~~$19.5 million of cash and cash equivalents and approximately ~~$1.86~~$2.18 billion of borrowing availability on our revolving credit facility after considering outstanding borrowings of $565 million 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~~October 31, 2016, outstanding borrowings totaled ~~$820~~$295 millionwith approximately ~~$1.93~~$2.45 billion of borrowing availability on our credit facility after considering outstanding borrowings and letters of credit. The decrease in outstanding borrowings in October reflects the reduction of debt using proceeds from our October sale of SCOOP properties for $295.6 million. We expect to borrow approximately $624 million under our credit facility on or around November 10, 2016 to fund the redemptions of our 2020 Notes and 2021 Notes. Such borrowings will serve to offset our previous reduction of outstanding credit facility borrowings which used proceeds totaling approximately $630 million from asset dispositions completed in 2016 through October 31, 2016, resulting in no net increase in year to date debt associated with the redemptions. See Note 10. Property Dispositions and Note 11. Subsequent Events in Notes to Unaudited Condensed Consolidated Financial Statements for additional discussion of our asset dispositions and pending senior note redemptions.

Based on our 2016 capital expenditure budget, our forecasted 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~~September 30, 2016, including those described in Note 7. Commitments and Contingencies and Note 11. Subsequent Eventsin 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 ~~$497.7~~$863.9 million and ~~$916.8 million~~$1.42 billion for the ~~six~~nine months ended ~~June~~September 30, 2016 and 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, partially offset by lower production expenses, production taxes, and general and administrative expenses and an increase in cash gains on matured natural gas derivatives.

IfGiven the current commodity price environment, ~~existing in the second quarter of 2016 persists or worsens and our rate of production continues to slow,~~ we expect our operating cash flows for the remainder of 2016 will continue to be lower than 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~~nine months ended ~~June~~September 30, 2016 and 2015, we had cash flows used in investing activities ~~(excluding proceeds from asset sales)~~ of ~~$630.0~~$884.5 million and ~~$2.0~~$2.63 billion, respectively, related to our capital program, inclusive of exploration and development drilling, property acquisitions, and dry hole ~~costs and property acquisitions.~~costs. Property acquisitions totaled ~~$14.3~~$22.6 million and $43.2 million for the ~~six~~nine months ended ~~June~~September 30, 2016 and 2015, respectively. The decrease in capital spending was driven by a decrease in our capital budget and related drilling activity for 2016. Our cash capital expenditures for 2016 include the payment of amounts owed at December 31, 2015 in connection with our 2015 drilling program and associated ~~$86.5~~$96.6 million decrease in accruals for capital expenditures for the ~~six~~nine months ended ~~June~~September 30, 2016.

The use of cash for capital expenditures ~~during the six months ended June 30,~~in 2016 and 2015 was partially offset by ~~$112.2 million of~~ proceeds received from asset dispositions, ~~primarily related~~which totaled $334.3 million and $33.2 million for the nine months ended September 30, 2016 and 2015, respectively. See Note 10. Property Dispositions in Notes to ~~the April 2016 sale of non-core undeveloped leasehold acreage in Wyoming for proceeds of $110.0 million.~~Unaudited Condensed Consolidated Financial Statements.

We expect our capital spending for the remainder of 2016 will continue to be lower than 2015 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.~~spending.

Cash flows from financing activities

Net cash ~~provided by~~used in financing activities for the ~~six~~nine months ended ~~June~~September 30, 2016 was ~~$25.2~~$305.6 million primarily resulting from net ~~borrowings~~repayments of ~~$32~~$288 million on our revolving credit facility during the period. 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~~the reduction of credit facility debt using proceeds totaling $334.3 million from ~~the sale of undeveloped leasehold acreage in Wyoming in April~~2016 asset dispositions completed through September 30, 2016, partially offset by ~~additional~~ borrowings ~~during the quarter.~~incurred to fund operations and debt interest payments.

Net cash provided by financing activities for the ~~six~~nine months ended ~~June~~September 30, 2015 was ~~$1.05~~$1.18 billion primarily resulting from ~~$1.06 billion of~~ net borrowings on our revolving credit facility during that ~~period.~~period to fund operations.

We are seeking to generally balance our 2016 capital expenditures with cash flows to minimize new ~~borrowings in 2016.~~borrowings.

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 should be sufficient to meet our cash requirements inclusive of, but not limited to, normal operating needs, pending senior note redemptions, debt service obligations, planned capital expenditures, and commitments for at least the next 12 months.

Our 2016 capital expenditures budget has been established based on an expectation of available cash flows, with any cash flow deficiencies expected to be funded by borrowings under our revolving credit facility. If cash flows are materially impacted by declines in commodity prices, we have the ability to reduce our capital expenditures or utilize the availability of our 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,~~Further, we may choose to sell additional 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 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 additional 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.

Revolving credit facility

We have an unsecured revolving credit facility, maturing on May 16, 2019, with aggregate lender commitments totaling $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 17 banks and financial institutions. We believe each member of the current syndicate has the capability to fund its commitment.

As of ~~July~~October 31, 2016, we had approximately ~~$1.93~~$2.45 billionof borrowing availability on our credit facility after considering outstanding borrowings, ~~and~~ letters of ~~credit. Borrowings~~credit, and the repayment of credit facility borrowings using the $295.6 million of proceeds from our October 2016 sale of SCOOP properties. We expect to borrow approximately $624 million under our credit facility on or around November 10, 2016 to fund the redemptions of our 2020 Notes and 2021 Notes, which will result in an equivalent decrease in borrowing availability. See Note 11. Subsequent Events in Notes to Unaudited Condensed Consolidated Financial Statements for additional discussion. Our credit facility borrowings bear interest at market-based interest rates plus a margin based on the terms of the borrowing and the credit ratings assigned to 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, downgrades or other negative rating actions with respect to our credit rating, 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 do such 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 (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~~September 30, 2016 and expect to maintain compliance for at least the next 12 months. At ~~June~~September 30, 2016, our consolidated net debt to total capitalization ratio, as defined in our revolving credit facility as amended, was ~~0.59~~0.58 to 1.00. As 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 financing to a material extent if needed to support our business. At ~~June~~September 30, 2016, our total debt would have needed to independently increase by approximately ~~$2.2~~$2.4 billion ~~or 31%,~~ above the existing ~~levels~~level at that date (with no corresponding increase in cash or reduction in refinanced debt) to reach the maximum covenant ratio of 0.65 to 1.00. Alternatively, our total shareholders' equity would have needed to independently decrease by approximately ~~$1.2~~$1.3 billion (excluding the after-tax impact of any non-cash impairment charges)~~, or 27%~~ below the existing ~~levels~~level at ~~June~~September 30, 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~~September 30, 2016, approximately ~~$175~~$162 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~~September 30, ~~2016. We have no near-term senior note maturities, with~~2016, inclusive of the 2020 Notes and 2021 Notes to be redeemed on November 10, 2016 as discussed below. Excluding the pending redemptions of our 2020 Notes and 2021 Notes, the earliest scheduled maturity ~~being~~of our ~~$200 million~~senior notes is the $2.0 billion of ~~2020~~2022 Notes due in ~~October 2020.~~September 2022. Our senior notes are not subject to any mandatory redemption or sinking fund requirements. For further information on the face values, maturity dates, semi-annual interest payment dates, optional redemption periods and covenant restrictions related to our senior notes, refer to Note 6. Long-Term Debt in Notes to Unaudited Condensed Consolidated Financial Statements.

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

~~Two~~Three of our subsidiaries, Banner Pipeline Company, L.L.C. ~~and~~, CLR Asset Holdings, LLC, and The Mineral Resources Company, which have no material assets or operations, fully and unconditionally guarantee the senior 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 as of ~~June~~September 30, 2016.

Senior note redemptions

In October 2016, we announced we will redeem all of our outstanding 7.375% Senior Notes due 2020 and 7.125% Senior Notes due 2021 on November 10, 2016. Refer to Note 11. Subsequent Events in Notes to Unaudited Condensed Consolidated Financial Statements for additional discussion. We expect to fund the redemptions using borrowings under our revolving credit facility. Such borrowings will serve to offset our previous reduction of outstanding credit facility borrowings which used proceeds totaling approximately $630 million from asset dispositions completed in 2016 through October 31, 2016, resulting in no net increase in year to date debt associated with the redemptions.

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%~~2.02% at ~~June~~September 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~~We plan to increase our well completion activities in the 2016 fourth quarter relative to our previous plan. Additionally, we have experienced an increase in our average working interest in operated and non-operated wells across certain of our plays in recent months. As a result, we have increased our 2016 non-acquisition capital expenditures budget ~~for 2016 is~~from $920 million ~~excluding acquisitions,~~to a new budget of approximately $1.1 billion, which is expected to be allocated as follows:


In millions	Amount		Amount
Exploration and development drilling	$	784	$	939
Land costs	78		93
Capital facilities, workovers and other corporate assets	55		63
Seismic	3		5
Total 2016 capital budget, excluding acquisitions	$	920	$	1,100

For the ~~six~~nine months ended ~~June~~September 30, 2016, we invested approximately ~~$529.3~~$768.0 million in our capital program, excluding ~~$14.3~~$22.6 million of unbudgeted acquisitions, excluding ~~$86.5~~$96.6 million of capital costs associated with decreased accruals for capital expenditures, and including ~~$0.1~~$2.7 million of seismic costs. Our 2016 year to date capital expenditures were allocated as follows by quarter:


In millions	1Q 2016		2Q 2016		YTD 2016		1Q 2016		2Q 2016		3Q 2016		YTD 2016
Exploration and development drilling	$	290.0	$	179.6	$	469.6	$	290.0	$	179.6	$	198.0	$	667.6
Land costs	19.9		18.8		38.7		19.9		18.8		21.1		59.8
Capital facilities, workovers and other corporate assets	9.9		11.0		20.9		9.9		11.0		17.0		37.9
Seismic	0.1		—		0.1		0.1		—		2.6		2.7
Capital expenditures, excluding acquisitions	319.9		209.4		529.3		319.9		209.4		238.7		768.0
Acquisitions of producing properties	—		—		—		—		—		—		—
Acquisitions of non-producing properties	4.4		9.9		14.3		4.4		9.9		8.3		22.6
Total acquisitions	4.4		9.9		14.3		4.4		9.9		8.3		22.6
Total capital expenditures	$	324.3	$	219.3	$	543.6	$	324.3	$	219.3	$	247.0	$	790.6

Our non-acquisition capital spending budget for 2016 has been set based on an expectation of available cash flows and 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 and completion rigs and other services and equipment, the availability of transportation capacity, changes in commodity prices, and regulatory, technological and competitive developments. We monitor our capital spending closely based on actual and projected cash flows and may ~~continue to~~ scale back our spending should commodity prices decrease from current levels. Conversely, an increase in commodity prices from current levels could result in ~~increased~~a further increase in 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~~September 30, 2016. We believe our cash flows from operations, our remaining cash balance, and amounts available under our revolving credit facility 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.

Critical Accounting Policies

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


ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk

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

Commodity Price Risk. Our primary market risk exposure is in the prices we receive from sales of our crude oil and natural gas production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our natural gas production. Pricing for crude oil and natural gas has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside of our control, including volatility in the differences between product prices at sales points and the applicable index prices. Based on our average daily production for the ~~six~~nine months ended ~~June~~September 30, 2016, and excluding any effect of our derivative instruments in place, our annual revenue would increase or decrease by approximately ~~$510~~$481 million for each $10.00 per barrel change in crude oil prices at ~~June~~September 30, 2016 and ~~$187~~$191 million for each $1.00 per Mcf change in natural gas prices at ~~June~~September 30, 2016.

To reduce price risk caused by market fluctuations in crude oil and natural gas prices, from time to time we may economically hedge a portion of our anticipated crude oil and natural gas production as part of our risk management program. In addition, we may utilize basis contracts to hedge the differential between derivative contract index prices and those of our

physical pricing points. Reducing our exposure to price volatility helps secure funds for our capital program. Our decision on the quantity and price at which we choose to hedge our production is based in part on our view of current and future market conditions. We may choose not to hedge future production if the price environment for certain time periods is deemed to be unfavorable. Additionally, we may choose to liquidate existing derivative positions prior to the expiration of their contractual maturities in order to monetize gain positions for the purpose of funding our capital program. While hedging, if utilized, limits the downside risk of adverse price movements, it also limits future revenues from upward price movements. Our crude oil production and sales for 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 natural gas prices during the ~~six~~nine months ended ~~June~~September 30, 2016 had an overall unfavorable impact on the fair value of our derivative instruments. For the ~~six~~nine months ended ~~June~~September 30, 2016, we recognized cash gains on natural gas derivatives of ~~$78.0~~$83.1 million which were more than offset by non-cash mark-to-market losses on natural gas derivatives of ~~$118.1~~$107.6 million.

The fair value of our natural gas derivative instruments at ~~June~~September 30, 2016 was a net liability of ~~$16.9~~$6.4 million. An assumed increase in the forward prices used in the ~~June~~September 30, 2016 valuation of our natural gas derivatives of $1.00 per MMBtu would increase our natural gas derivative liability to approximately ~~$161~~$106 million at ~~June~~September 30, 2016. Conversely, an assumed decrease in forward prices of $1.00 per MMBtu would change our natural gas derivative valuation to a net asset of approximately ~~$120~~$86 million at ~~June~~September 30, 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 ($~~385~~336 millionin receivables at ~~June~~September 30, 2016), our joint interest receivables ($~~261~~279 millionat ~~June~~September 30, 2016), and counterparty credit risk associated with our derivative instrument receivables ($2014 million at ~~June~~September 30, 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 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 ~~$85~~$72 million at ~~June~~September 30, 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 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 an aggregate of ~~$1.32 billion~~$795 million of variable rate borrowings outstanding on our revolving credit facility and three-year term loan at ~~July~~October 31, 2016. The impact of a 0.25% increase in interest rates on this amount of debt would result in increased interest expense of approximately ~~$3.3~~$2.0 million per year and a ~~$2.0~~$1.2 million decrease in net income per year.

ITEM 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

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

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

Changes in Internal Control over Financial Reporting

During the three months ended ~~June~~September 30, 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

See Note 7. Commitments and Contingencies–Litigation in Part I, Item I. Financial Statements–Notes to Unaudited Condensed Consolidated Financial Statements for a discussion of the legal matter involving the Company, Billy J. Strack and Daniela A. 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 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 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 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~~September 30, 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
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
—
—



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
July 1, 2016 to July 31, 2016	3,213	$	45.73	—	—
August 1, 2016 to August 31, 2016	13,546	$	47.48	—	—
September 1, 2016 to September 30, 2016	327	$	44.29	—	—
Total	17,086	$	47.09	—	—


(1)	In connection with restricted stock grants under the Company's 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 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.


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 3,~~November 2, 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	Conformed version of Third Amended and Restated Certificate of Incorporation of Continental Resources, Inc. as amended by amendment filed on June 15, 2015 filed as Exhibit 3.1 to the Company’s Form 10-Q for the quarterly period ended June 30, 2015 (Commission File No. 001-32886) filed August 5, 2015 and incorporated herein by reference.

3.2	Third Amended and Restated Bylaws of Continental Resources, Inc. filed as Exhibit 3.1 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*†~~	~~Summary of Non-Employee Director Compensation Approved as of May 19, 2016 to be effective July 1, 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


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

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