CONTINENTAL RESOURCES, INC - Quarter Report: 2015 March (Form 10-Q)

Large accelerated filer

Accelerated filer

Non-accelerated filer

¨ (Do not check if a smaller reporting company)

Smaller reporting company

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 March 31, 2015



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

For the transition period from to

Commission File Number: 001-32886

_______________________________

CONTINENTAL RESOURCES, INC.

(Exact name of registrant as specified in its charter)

_______________________________



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

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

(405) 234-9000

(Registrant’s telephone number, including area code)

Not Applicable

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

_______________________________

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

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

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

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

373,112,044 shares of our $0.01 par value common stock were outstanding on April 30, 2015.

Table of Contents




PART I. Financial Information
Item 1.	Financial Statements	1
	Condensed Consolidated Balance Sheets	1
	Unaudited Condensed Consolidated Statements of Comprehensive Income (Loss)	2
	Condensed Consolidated Statement of Shareholders’ Equity	3
	Unaudited Condensed Consolidated Statements of Cash Flows	4
	Notes to Unaudited Condensed Consolidated Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	17
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	29
Item 4.	Controls and Procedures	30

PART II. Other Information
Item 1.	Legal Proceedings	31
Item 1A.	Risk Factors	31
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	31
Item 3.	Defaults Upon Senior Securities	31
Item 4.	Mine Safety Disclosures	32
Item 5.	Other Information	32
Item 6.	Exhibits	32
	Signature	33

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

Glossary of Crude Oil and Natural Gas Terms

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

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

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

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

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

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

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

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

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

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

“exploratory well” A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of crude oil or natural gas in another reservoir.

“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.

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

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

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

“SCOOP” Refers to the South Central Oklahoma Oil Province, a term we use to describe an area of crude oil and liquids-rich natural gas properties located in the Anadarko basin of south central 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, statements or information concerning the Company’s future operations, performance, financial condition, production and reserves, schedules, plans, timing of development, returns, budgets, costs, business strategy, objectives, and cash flow, 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 business and financial strategy;


•	our future operations;


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


•	our technology;


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


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


•	the amount, nature and timing of capital expenditures;


•	estimated revenues, expenses and results of operations;


•	drilling and completing of wells;


•	competition;


•	marketing of crude oil and natural gas;


•	transportation of crude oil, natural gas liquids, and natural gas to markets;


•	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 results;


•	our commodity or other hedging arrangements; and


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

Forward-looking statements are based on the Company’s current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company considers these expectations to be reasonable and based on reasonable assumptions, they are inherently subject to numerous business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond our control. No assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate. The risks and uncertainties that may affect the operations, performance and results of the business and forward-looking statements include, but are not limited to, those risk factors and other cautionary statements described under Part II, Item 1A. Risk Factors and elsewhere in this report, if any, our Annual Report on Form 10-K for the year ended December 31, 2014, registration statements filed from time to time with the Securities and Exchange Commission, and other announcements we make from time to time.

Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date on which such statement is made. Should one or more of the risks or uncertainties described in this report occur, or should underlying assumptions prove incorrect, our 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 otherwise required by applicable law, we do not intend, and disclaim any duty, to 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



	March 31, 2015			December 31, 2014
In thousands, except par values and share data	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	47,645		$	24,381
Receivables:
Crude oil and natural gas sales	455,837			552,476
Affiliated parties	232			13,360
Joint interest and other, net	506,216			567,476
Derivative assets	52,392			52,423
Inventories	108,347			102,179
Deferred and prepaid taxes	13,267			63,266
Prepaid expenses and other	16,944			14,040
Total current assets	1,200,880			1,389,601
Net property and equipment, based on successful efforts method of accounting	14,111,154			13,635,852
Net debt issuance costs and other	85,811			87,625
Noncurrent derivative assets	37,419			31,992
Total assets	$	15,435,264		$	15,145,070

Liabilities and shareholders’ equity
Current liabilities:
Accounts payable trade	$	1,009,133		$	1,263,724
Revenues and royalties payable	226,912			272,755
Payables to affiliated parties	6,914			7,305
Accrued liabilities and other	355,633			404,506
Derivative liabilities	254			1,645
Current portion of long-term debt	2,093			2,078
Total current liabilities	1,600,939			1,952,013
Long-term debt, net of current portion	6,784,816			5,995,837
Other noncurrent liabilities:
Deferred income tax liabilities	2,119,281			2,141,447
Asset retirement obligations, net of current portion	78,819			75,462
Noncurrent derivative liabilities	576			3,109
Other noncurrent liabilities	9,795			9,358
Total other noncurrent liabilities	2,208,471			2,229,376
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; 500,000,000 shares authorized; 373,121,054 shares issued and outstanding at March 31, 2015; 372,005,502 shares issued and outstanding at December 31, 2014	3,731			3,720
Additional paid-in capital	1,296,200			1,287,941
Accumulated other comprehensive loss	(3,490		)	(385		)
Retained earnings	3,544,597			3,676,568
Total shareholders’ equity	4,841,038			4,967,844
Total liabilities and shareholders’ equity	$	15,435,264		$	15,145,070

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

Continental Resources, Inc. and Subsidiaries

Unaudited Condensed Consolidated Statements of Comprehensive Income (Loss)



	Three months ended March 31,
In thousands, except per share data	2015			2014
Revenues
Crude oil and natural gas sales	$	581,192		$	972,147
Crude oil and natural gas sales to affiliates	1,400			30,186
Gain (loss) on derivative instruments, net	32,755			(39,674		)
Crude oil and natural gas service operations	10,297			9,836
Total revenues	625,644			972,495

Operating costs and expenses
Production expenses	91,355			75,976
Production expenses to affiliates	1,586			910
Production taxes and other expenses	48,362			78,302
Exploration expenses	14,340			4,813
Crude oil and natural gas service operations	3,894			8,074
Depreciation, depletion, amortization and accretion	386,512			272,861
Property impairments	147,561			58,208
General and administrative expenses	45,380			43,536
(Gain) loss on sale of assets, net	(2,070		)	8,498
Total operating costs and expenses	736,920			551,178
Income (loss) from operations	(111,276		)	421,317
Other income (expense):
Interest expense	(75,063		)	(62,975		)
Other	347			759
	(74,716		)	(62,216		)
Income (loss) before income taxes	(185,992		)	359,101
Provision (benefit) for income taxes	(54,021		)	132,867
Net income (loss)	$	(131,971	)	$	226,234
Basic net income (loss) per share	$	(0.36	)	$	0.61
Diluted net income (loss) per share	$	(0.36	)	$	0.61

Comprehensive income (loss):
Net income (loss)	$	(131,971	)	$	226,234
Other comprehensive loss, net of tax:
Foreign currency translation adjustments	(3,105		)	—
Total other comprehensive loss, net of tax	(3,105		)	—
Comprehensive income (loss)	$	(135,076	)	$	226,234

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

Continental Resources, Inc. and Subsidiaries

Condensed Consolidated Statement of Shareholders’ Equity



In thousands, except share data	Shares outstanding		Common stock			Additional paid-in capital			Accumulated other comprehensive loss			Retained earnings			Total shareholders’ equity
Balance at December 31, 2014	372,005,502		$	3,720		$	1,287,941		$	(385	)	$	3,676,568		$	4,967,844
Net loss (unaudited)	—		—			—			—			(131,971		)	(131,971		)
Other comprehensive loss, net of tax (unaudited)	—		—			—			(3,105		)	—			(3,105		)
Stock-based compensation (unaudited)	—		—			11,261			—			—			11,261
Restricted stock:
Granted (unaudited)	1,233,574		12			—			—			—			12
Repurchased and canceled (unaudited)	(63,446	)	(1		)	(3,002		)	—			—			(3,003		)
Forfeited (unaudited)	(54,576	)	—			—			—			—			—
Balance at March 31, 2015 (unaudited)	373,121,054		$	3,731		$	1,296,200		$	(3,490	)	$	3,544,597		$	4,841,038

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

Continental Resources, Inc. and Subsidiaries

Unaudited Condensed Consolidated Statements of Cash Flows



	Three months ended March 31,
In thousands	2015			2014
Cash flows from operating activities
Net income (loss)	$	(131,971	)	$	226,234
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion	391,026			281,115
Property impairments	147,561			58,208
Non-cash (gain) loss on derivatives, net	(9,320		)	6,410
Stock-based compensation	11,263			11,039
Provision (benefit) for deferred income taxes	(54,026		)	131,315
Dry hole costs	8,401			—
(Gain) loss on sale of assets, net	(2,070		)	8,498
Other, net	2,261			1,754
Changes in assets and liabilities:
Accounts receivable	173,088			(53,857		)
Inventories	(6,236		)	(17,669		)
Prepaid expenses and other	48,967			(525		)
Accounts payable trade	5,185			13,854
Revenues and royalties payable	(45,844		)	34,623
Accrued liabilities and other	(17,460		)	(9,191		)
Other noncurrent assets and liabilities	1,365			(1,146		)
Net cash provided by operating activities	522,190			690,662

Cash flows from investing activities
Exploration and development	(1,267,252		)	(993,682		)
Purchase of producing crude oil and natural gas properties	(132		)	(30,278		)
Purchase of other property and equipment	(11,923		)	(30,953		)
Proceeds from sale of assets	903			35,433
Net cash used in investing activities	(1,278,404		)	(1,019,480		)

Cash flows from financing activities
Credit facility borrowings	930,000			525,000
Repayment of credit facility	(140,000		)	(170,000		)
Repayment of other debt	(515		)	(499		)
Debt issuance costs	(2,099		)	—
Repurchase of restricted stock for tax withholdings	(3,003		)	(2,630		)
Net cash provided by financing activities	784,383			351,871
Effect of exchange rate changes on cash	(4,905		)	—
Net change in cash and cash equivalents	23,264			23,053
Cash and cash equivalents at beginning of period	24,381			28,482
Cash and cash equivalents at end of period	$	47,645		$	51,535

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

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

Note 1. Organization and Nature of Business

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

The Company’s operations are geographically concentrated in the North region, with that region comprising 72% of the Company’s crude oil and natural gas production and 78% of its crude oil and natural gas revenues for the three months ended March 31, 2015. The Company's principal producing properties in the North region are located in the Bakken field of North Dakota and Montana. In recent years, the Company has significantly expanded its activity in the South region with its discovery and announcement of the SCOOP play in Oklahoma. The South region now comprises 28% of the Company's crude oil and natural gas production and 22% of its crude oil and natural gas revenues for the three months ended March 31, 2015.

The Company has focused its operations on the exploration and development of crude oil since the 1980s. For the three months ended March 31, 2015, crude oil accounted for 69% of the Company’s total production and 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. All significant intercompany accounts and transactions have been eliminated upon consolidation.

On August 18, 2014, the Company's Board of Directors declared a 2-for-1 stock split of the Company's common stock to be effected in the form of a stock dividend. The stock dividend was distributed on September 10, 2014 to shareholders of record as of September 3, 2014. Previously reported common stock and earnings per share amounts for the three months ended March 31, 2014 have been retroactively adjusted in the accompanying financial statements and related notes to reflect the stock split.

This report has been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”) applicable to interim financial information. Because this is an interim period filing presented using a condensed format, it does not include all disclosures required by accounting principles generally accepted in the United States (“U.S. GAAP”), although the Company believes the disclosures are adequate to make the information not misleading. You should read this Form 10-Q together with the Company’s Annual Report on Form 10-K for the year ended December 31, 2014 (“2014 Form 10-K”), which includes a summary of the Company’s significant accounting policies and other disclosures.

The condensed consolidated financial statements as of March 31, 2015 and for the three month periods ended March 31, 2015 and 2014 are unaudited. The condensed consolidated balance sheet as of December 31, 2014 was derived from the audited balance sheet included in the 2014 Form 10-K. The Company has evaluated events or transactions through the date this report on Form 10-Q was filed with the SEC in conjunction with its preparation of these condensed consolidated financial statements.

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

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

Earnings per share

Basic net income (loss) per share is computed by dividing net income (loss) by the weighted-average number of shares outstanding for the period. Diluted net income (loss) per share reflects the potential dilution of non-vested restricted stock awards, which are calculated using the treasury stock method. The following table presents the calculation of basic and diluted weighted average shares outstanding and net income (loss) per share for the three months ended March 31, 2015 and 2014.



	Three months ended March 31,
In thousands, except per share data	2015			2014
Income (loss) (numerator):
Net income (loss) - basic and diluted	$	(131,971	)	$	226,234
Weighted average shares (denominator):
Weighted average shares - basic	369,385			368,658
Non-vested restricted stock (1)	—			1,398
Weighted average shares - diluted	369,385			370,056
Net income (loss) per share:
Basic	$	(0.36	)	$	0.61
Diluted	$	(0.36	)	$	0.61


(1)	The potential dilutive effect of 925,000 weighted average restricted shares were not included in the calculation of diluted net loss per share for the three months ended March 31, 2015 because to do so would have been anti-dilutive.

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 March 31, 2015 and December 31, 2014 consisted of the following:



In thousands	March 31, 2015		December 31, 2014
Tubular goods and equipment	$	16,214	$	15,659
Crude oil	92,133		86,520
Total	$	108,347	$	102,179

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. 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 an $11.1 million valuation allowance against deferred tax assets associated with operating loss carryforwards generated by its Canadian subsidiary in the 2015 first quarter for which the Company does not expect to realize a benefit.

Affiliate transactions

The affiliate transactions reflected in the accompanying unaudited condensed consolidated statements of comprehensive income (loss) for the three months ended March 31, 2015 and 2014 include transactions between the Company and Hiland Partners, LP and its subsidiaries ("Hiland"). Hiland was controlled by the Company's principal shareholder through February 13, 2015, at which time it was sold to an unaffiliated third party. As a result of the sale, the related party relationship that existed previously between the Company and Hiland terminated as of February 13, 2015, which resulted in a reduction in affiliate transactions recognized in the Company's financial statements at March 31, 2015 and for the three months then ended.

New accounting pronouncement

On April 7, 2015, the Financial Accounting Standards Board issued Accounting Standards Update 2015-03, Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs. The new standard requires debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

amount of that debt liability, consistent with the presentation of a debt discount. Under previous guidance, debt issuance costs are required to be presented in the balance sheet as a deferred asset. The new standard does not affect the existing recognition and measurement guidance for debt issuance costs. The new standard will be effective for annual and interim periods beginning after December 15, 2015 and will be applied on a retrospective basis to all balance sheet periods presented. As of March 31, 2015, the Company's capitalized debt issuance costs subject to future reclassification under the new standard totaled $76 million, net of accumulated amortization.

Note 3. Supplemental Cash Flow Information

The following table discloses supplemental cash flow information about cash paid for interest and income tax payments and refunds. Also disclosed is information about investing activities that affects recognized assets and liabilities but does not result in cash receipts or payments.



	Three months ended March 31,
In thousands	2015			2014
Supplemental cash flow information:
Cash paid for interest	$	51,790		$	52,194
Cash paid for income taxes	6			—
Cash received for income tax refunds	50,000			5
Non-cash investing activities:
Increase (decrease) in accrued capital expenditures	(260,204		)	47,508
Asset retirement obligation additions and revisions, net	2,703			1,270

Note 4. Derivative Instruments

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

The Company may utilize swap and collar derivative contracts to economically hedge against the variability in cash flows associated with the sale of future crude oil and natural gas production. While the use of these derivative instruments limits the downside risk of adverse price movements, their use also limits future revenues from upward price movements.

With respect to a 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 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, the Company is required to make a payment to the counterparty if the settlement price for any settlement period is above the ceiling price, and neither 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 derivative contracts are settled based upon reported settlement prices on commodity exchanges, with crude oil derivative settlements based on NYMEX West Texas Intermediate (“WTI”) pricing or Inter-Continental Exchange (“ICE”) pricing for Brent crude oil and natural gas derivative settlements based on NYMEX Henry Hub pricing. The estimated fair value of derivative contracts is based upon various factors, including commodity exchange prices, over-the-counter quotations, and, in the case of collars and written call options, volatility, the risk-free interest rate, and the time to expiration. The calculation of the fair value of collars and written call options requires the use of an option-pricing model. See Note 5. Fair Value Measurements.

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

At March 31, 2015, the Company had outstanding derivative contracts with respect to future production as set forth in the tables below.



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



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



				Collars
Natural Gas - NYMEX Henry Hub		Swaps Weighted Average Price		Floors			Ceilings
					Weighted Average Price			Weighted Average Price
Period and Type of Contract	MMBtus			Range	Weighted Average Price		Range	Weighted Average Price
April 2015 - December 2015
Swaps - Henry Hub	11,000,000	$	4.16
Collars - Henry Hub	22,000,000			$3.50 - $3.75	$	3.69	$4.89 - $5.48	$	5.04
January 2016 - December 2016
Swaps - Henry Hub	63,110,000	$	3.98

(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 2014 fourth quarter. 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.

Derivative gains and losses

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

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

matured during the period.



	Three months ended March 31,
In thousands	2015			2014
Cash received (paid) on derivatives:
Crude oil fixed price swaps	$	—		$	(22,523	)
Crude oil collars	—			(584		)
Natural gas fixed price swaps	18,391			(10,157		)
Natural gas collars	5,044			—
Cash received (paid) on derivatives, net	23,435			(33,264		)
Non-cash gain (loss) on derivatives:
Crude oil fixed price swaps	—			13,690
Crude oil collars	—			5,283
Crude oil written call options	3,924			—
Natural gas fixed price swaps	6,492			(25,401		)
Natural gas collars	(1,096		)	18
Non-cash gain (loss) on derivatives, net	9,320			(6,410		)
Gain (loss) on derivative instruments, net	$	32,755		$	(39,674	)

Balance sheet offsetting of derivative assets and liabilities

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

The following table presents the gross amounts of recognized 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	March 31, 2015			December 31, 2014
Commodity derivative assets:
Gross amounts of recognized assets	$	89,811		$	84,415
Gross amounts offset on balance sheet	—			—
Net amounts of assets on balance sheet	89,811			84,415
Commodity derivative liabilities:
Gross amounts of recognized liabilities	(830		)	(4,770		)
Gross amounts offset on balance sheet	—			16
Net amounts of liabilities on balance sheet	$	(830	)	$	(4,754	)

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



In thousands	March 31, 2015			December 31, 2014
Derivative assets	$	52,392		$	52,423
Noncurrent derivative assets	37,419			31,992
Net amounts of assets on balance sheet	89,811			84,415
Derivative liabilities	(254		)	(1,645		)
Noncurrent derivative liabilities	(576		)	(3,109		)
Net amounts of liabilities on balance sheet	(830		)	(4,754		)
Total derivative assets, net	$	88,981		$	79,661

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

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.


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

A financial instrument’s categorization within the hierarchy is based upon the lowest level of input that is significant to the fair value measurement. Level 1 inputs are given the highest priority in the fair value hierarchy while Level 3 inputs are given the lowest priority. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the hierarchy. As Level 1 inputs generally provide the most reliable evidence of fair value, the Company uses Level 1 inputs when available. The Company’s policy is to recognize transfers between the hierarchy levels as of the beginning of the reporting period in which the event or change in circumstances caused the transfer.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The Company's derivative instruments are reported at fair value on a recurring basis. In determining the fair values of fixed price swaps, a discounted cash flow method is used due to the unavailability of relevant comparable market data for the Company’s exact contracts. The discounted cash flow method estimates future cash flows based on quoted market prices for forward commodity prices and a risk-adjusted discount rate. The fair values of fixed price swaps are calculated mainly using significant observable inputs (Level 2). Calculation of the fair values of collars and written call options requires the use of an industry-standard option pricing model that considers various inputs including quoted forward commodity prices, 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 March 31, 2015 and December 31, 2014.



	Fair value measurements at March 31, 2015 using:
In thousands	Level 1		Level 2			Level 3		Total
Derivative assets (liabilities):
Fixed price swaps	$	—	$	69,091		$	—	$	69,091
Collars	—		20,720			—		20,720
Written call options	—		(830		)	—		(830		)
Total	$	—	$	88,981		$	—	$	88,981

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

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

Assets Measured at Fair Value on a Nonrecurring Basis

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

Asset Impairments – Proved crude oil and natural gas properties are reviewed for impairment on a field-by-field basis each quarter. The estimated future cash flows expected in connection with the field are compared to the carrying amount of the field to determine if the carrying amount is recoverable. If the carrying amount of the field exceeds its estimated undiscounted future cash flows, the carrying amount of the field is reduced to its estimated fair value. Due to the unavailability of relevant comparable market data, a discounted cash flow method is used to determine the fair value of proved properties. The discounted cash flow method estimates future cash flows based on management’s estimates of future crude oil and natural gas production, commodity prices based on commodity futures price strips, operating and development costs, and a risk-adjusted discount rate. The fair value of proved crude oil and natural gas properties is calculated using significant unobservable inputs (Level 3). The following table sets forth quantitative information about the significant unobservable inputs used by the Company to calculate the fair value of proved crude oil and natural gas properties using a discounted cash flow method.



Unobservable Input		Assumption
Future production		Future production estimates for each property
Forward commodity prices		Forward NYMEX strip prices through 2019 (adjusted for differentials), escalating 3% per year thereafter
Operating and development costs		Estimated costs for the current year, escalating 3% per year thereafter
Productive life of field		Ranging from 0 to 50 years
Discount rate		10%

Unobservable inputs to the fair value assessment are reviewed quarterly and are revised as warranted based on a number of factors, including reservoir performance, new drilling, crude oil and natural gas prices, changes in costs, technological advances, new geological or geophysical data, or other economic factors. Fair value measurements of proved properties are reviewed and approved by certain members of the Company’s management.

Impairments of proved properties amounted to $70.0 million for the three months ended March 31, 2015 resulting from a continued decrease in commodity prices in the first quarter that indicated the carrying amounts for certain fields were not recoverable. The impairments reflect fair value adjustments primarily concentrated in an emerging area with limited production history and costly reserve additions ($36.1 million), the Medicine Pole Hills units ($14.7 million), various non-core areas in the South region ($11.1 million), and non-Bakken areas of North Dakota and Montana ($8.1 million). The impaired properties were written down to their estimated fair value totaling approximately $38.2 million at March 31, 2015.

Impairments of proved properties totaled $3.8 million for the three months ended March 31, 2014, which reflect fair value adjustments made for certain properties in a non-core area of our South region driven by uneconomic well results. The impaired properties were written down to their estimated fair value totaling approximately $1.1 million as of March 31, 2014.

Certain unproved crude oil and natural gas properties were impaired during the three months ended March 31, 2015 and 2014, reflecting recurring amortization of undeveloped leasehold costs on properties that management expects will not be transferred to proved properties over the lives of the leases based on drilling plans, experience of successful drilling, and the average holding period.

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



	Three months ended March 31,
In thousands	2015		2014
Proved property impairments	$	70,016	$	3,762
Unproved property impairments	77,545		54,446
Total	$	147,561	$	58,208

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

Financial Instruments Not Recorded at Fair Value

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



	March 31, 2015				December 31, 2014
In thousands	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Debt:
Credit facility	$	955,000	$	955,000	$	165,000	$	165,000
Note payable	15,942		14,500		16,457		14,900
7.375% Senior Notes due 2020	198,889		213,700		198,850		213,000
7.125% Senior Notes due 2021	400,000		416,300		400,000		421,000
5% Senior Notes due 2022	2,022,337		1,998,500		2,022,949		1,857,900
4.5% Senior Notes due 2023	1,500,000		1,445,000		1,500,000		1,372,800
3.8% Senior Notes due 2024	996,696		918,900		996,622		868,700
4.9% Senior Notes due 2044	698,045		625,300		698,037		572,400
Total debt	$	6,786,909	$	6,587,200	$	5,997,915	$	5,485,700

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

The fair value of the note payable is determined using a discounted cash flow approach based on the interest rate and payment terms of the note payable and an assumed discount rate. The fair value of the note payable is significantly influenced by the discount rate assumption, which is derived by the Company and is unobservable. Accordingly, the fair value of the note payable is classified as Level 3 in the fair value hierarchy.

The fair values of the 7.375% Senior Notes due 2020 (“2020 Notes”), the 7.125% Senior Notes due 2021 (“2021 Notes”), the 5% Senior Notes due 2022 (“2022 Notes”), the 4.5% Senior Notes due 2023 ("2023 Notes"), the 3.8% Senior Notes due 2024 ("2024 Notes"), and the 4.9% Senior Notes due 2044 ("2044 Notes") are based on quoted market prices and, accordingly, are classified as Level 1 in the fair value hierarchy.

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

Note 6. Long-Term Debt

Long-term debt consists of the following at March 31, 2015 and December 31, 2014:



In thousands	March 31, 2015		December 31, 2014
Credit facility	$	955,000	$	165,000
Note payable	15,942		16,457
7.375% Senior Notes due 2020 (1)	198,889		198,850
7.125% Senior Notes due 2021 (2)	400,000		400,000
5% Senior Notes due 2022 (3)	2,022,337		2,022,949
4.5% Senior Notes due 2023 (2)	1,500,000		1,500,000
3.8% Senior Notes due 2024 (4)	996,696		996,622
4.9% Senior Notes due 2044 (5)	698,045		698,037
Total debt	$	6,786,909	$	5,997,915
Less: Current portion of long-term debt	2,093		2,078
Long-term debt, net of current portion	$	6,784,816	$	5,995,837


(1)	The carrying amount is net of unamortized discounts of $1.1 million and $1.2 million at March 31, 2015 and December 31, 2014, respectively.


(2)	These notes were sold at par and are recorded at 100% of face value.


(3)	The carrying amount includes an unamortized premium of $22.3 million and $22.9 million at March 31, 2015 and December 31, 2014, respectively.

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements


(4)	The carrying amount is net of unamortized discounts of $3.3 million and $3.4 million at March 31, 2015 and December 31, 2014, respectively.


(5)	The carrying amount is net of an unamortized discount of $2.0 million at both March 31, 2015 and December 31, 2014.

Credit Facility

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

The Company had $955 million and $165 million of outstanding borrowings on its credit facility at March 31, 2015 and December 31, 2014, respectively. Borrowings bear interest at market-based interest rates plus a margin that is based on the terms of the borrowing and the credit ratings assigned to the Company's senior unsecured debt. The weighted-average interest rate on outstanding borrowings at March 31, 2015 was 1.8%.

The Company had approximately $1.54 billion of borrowing availability on its credit facility at March 31, 2015 and incurs commitment fees based on currently assigned credit ratings of 0.225% per annum of the daily average amount of unused borrowing availability.

The credit facility contains certain restrictive covenants including a requirement that the Company maintain a consolidated net debt to total capitalization ratio of no greater than 0.65 to 1.00. As of March 31, 2015, this ratio represents the ratio of net debt (total debt less cash and cash equivalents) divided by the sum of net debt plus total shareholders' equity. The Company was in compliance with this covenant at March 31, 2015. On May 4, 2015, the Company's credit facility was amended to exclude the impact of non-cash impairment charges recognized after June 30, 2014, net of any tax effect, from the determination of shareholders' equity in the calculation of the consolidated net debt to total capitalization ratio.

Senior Notes

The following table summarizes the maturity dates, semi-annual interest payment dates, and optional redemption periods related to the Company’s outstanding senior note obligations at March 31, 2015.

2020 Notes

2021 Notes

2022 Notes

2023 Notes

2024 Notes

2044 Notes

Maturity date

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, Sept. 15

April 15, Oct. 15

June 1, Dec. 1

Call premium redemption period (1)

Oct 1, 2015

April 1, 2016

March 15, 2017

—

Make-whole redemption period (2)

Oct 1, 2015

April 1, 2016

March 15, 2017

Jan 15, 2023

Mar 1, 2024

Dec 1, 2043


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


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

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

The indentures governing the Company's senior notes contain covenants that, among other things, limit the Company's ability to create liens securing certain indebtedness, enter into certain sale and leaseback 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 March 31, 2015. Two of the Company’s subsidiaries, Banner Pipeline Company, L.L.C. and CLR Asset Holdings, LLC, which have no material assets or operations, fully and unconditionally guarantee the senior notes. The Company’s other subsidiaries, the value of whose assets and operations are minor, do not guarantee the senior notes.

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

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

date of February 26, 2022. Accordingly, approximately $2.1 million is reflected as a current liability under the caption “Current portion of long-term debt” in the condensed consolidated balance sheets as of March 31, 2015.

Note 7. Commitments and Contingencies

Included below is a discussion of various future commitments of the Company as of March 31, 2015. The commitments under these arrangements are not recorded in the accompanying condensed consolidated balance sheets.

Drilling commitments – As of March 31, 2015, the Company had drilling rig contracts with various terms extending through September 2018. These contracts were entered into in the ordinary course of business to ensure rig availability to allow the Company to execute its business objectives in its strategic plays. Future commitments as of March 31, 2015 total approximately $564 million, of which $186 million is expected to be incurred in the remainder of 2015, $220 million in 2016, $125 million in 2017, and $33 million in 2018.

Pipeline transportation commitments – The Company has entered into firm transportation commitments to guarantee pipeline access capacity on operational crude oil and natural gas pipelines in order to reduce the impact of possible production curtailments that may arise due to limited transportation capacity. The commitments, which have varying terms extending as far as 2025, require the Company to pay per-unit transportation charges regardless of the amount of pipeline capacity used. Future commitments remaining as of March 31, 2015 under the operational pipeline transportation arrangements amount to approximately $1.0 billion, of which $153 million is expected to be incurred in the remainder of 2015, $207 million in 2016, $201 million in 2017, $195 million in 2018, $159 million in 2019, and $109 million thereafter.

Further, the Company is a party to an additional five year firm transportation commitment for a future crude oil pipeline project being considered for development that is not yet operational. The project requires the granting of regulatory approvals and requires additional construction efforts by the counterparty before being completed. Future commitments under the non-operational arrangement total approximately $260 million at March 31, 2015. The timing of the Company’s obligations under this non-operational arrangement cannot be predicted with certainty and may not be incurred on a ratable basis over a calendar year or may not be incurred at all.

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

Fuel purchase commitment – The Company has entered into a forward purchase contract with a third party to purchase specified quantities of diesel fuel at specified prices each month over the period from January 2015 through June 2016 for use in the normal course of drilling operations. Over the contract term, the Company has committed to purchase a total of approximately 31 million gallons of diesel fuel at varying prices depending on the grade of diesel fuel purchased and the timing and location of delivery. The contract satisfies a significant portion of the Company's anticipated diesel fuel needs and provides for physical delivery to desired locations. Future commitments under the arrangement as of March 31, 2015 total approximately $75 million, of which $44 million is expected to be incurred in the remainder of 2015 and $31 million is expected to be incurred in 2016.

Litigation – In November 2010, an alleged class action was filed against the Company alleging the Company improperly deducted post-production costs from royalties paid to plaintiffs and other royalty interest owners as categorized in the petition from crude oil and natural gas wells located in Oklahoma. The plaintiffs have 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 alleged class. The Company has responded to the petition, denied the allegations and raised a number of affirmative defenses. Discovery is ongoing and information and documents continue to be exchanged. 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. The class has not been certified. Plaintiffs Amended Motion for Class Certification is presently set for evidentiary hearing on June 1, 2015. Plaintiffs have indicated that if the class is certified they may seek damages in excess of $165 million which may increase with the passage of time, a majority of which would be comprised of interest. The Company disputes plaintiffs’ claims, disputes that the case meets the requirements for a class action and is vigorously defending the case.

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

The Company is involved in various other legal proceedings including, but not limited to, commercial disputes, claims from royalty and surface owners, property damage claims, personal injury claims 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 March 31, 2015 and December 31, 2014, the Company had recorded a liability in the condensed consolidated balance sheets under the caption “Other noncurrent liabilities” of $2.9 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.

Note 8. Stock-Based Compensation

The Company has granted restricted stock to employees and directors pursuant to the Continental Resources, Inc. 2005 Long-Term Incentive Plan (“2005 Plan”) and 2013 Long-Term Incentive Plan ("2013 Plan") as discussed below. The Company’s associated compensation expense, which is included in the caption “General and administrative expenses” in the unaudited condensed consolidated statements of comprehensive income (loss), was $11.3 million and $11.0 million for the three months ended March 31, 2015 and 2014, respectively.

In May 2013, the Company adopted the 2013 Plan and reserved a maximum of 19,680,072 shares of common stock that may be issued pursuant to the plan. The 2013 Plan replaced the Company's 2005 Plan as the instrument used to grant long-term incentive awards and no further awards will be granted under the 2005 Plan. However, restricted stock awards granted under the 2005 Plan prior to the adoption of the 2013 Plan will remain outstanding in accordance with their terms. As of March 31, 2015, the Company had a maximum of 16,944,983 shares of restricted stock available to grant to officers, directors and select employees under the 2013 Plan.

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

A summary of changes in non-vested restricted shares outstanding for the three months ended March 31, 2015 is presented below:



	Number of non-vested shares		Weighted average grant-date fair value
Non-vested restricted shares outstanding at December 31, 2014	2,678,764		$	49.40
Granted	1,233,574		47.91
Vested	(180,733	)	51.28
Forfeited	(54,576	)	53.67
Non-vested restricted shares outstanding at March 31, 2015	3,677,029		$	48.74

The grant date fair value of restricted stock represents the closing market price of the Company’s common stock on the date of grant. Compensation expense for a restricted stock grant is a fixed amount determined at the grant date fair value and is recognized ratably over the vesting period as services are rendered by employees and directors. The expected life of restricted stock is based on the non-vested period that remains subsequent to the date of grant. There are no post-vesting restrictions related to the Company’s restricted stock. The fair value of restricted stock that vested during the three months ended March 31, 2015 at the vesting date was approximately $8.6 million. As of March 31, 2015, there was approximately $115 million of unrecognized compensation expense related to non-vested restricted stock. This expense is expected to be recognized ratably over a weighted average period of 1.8 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 months ended March 31, 2015:



In thousands	Three months ended March 31, 2015
Beginning accumulated other comprehensive loss, net of tax	$	(385	)
Foreign currency translation adjustments	(3,105		)
Income tax benefit (1)	—
Other comprehensive loss, net of tax	(3,105		)
Ending accumulated other comprehensive loss, net of tax	$	(3,490	)


(1)	A valuation allowance has been recognized against deferred tax assets associated with losses generated by the Company's Canadian operations, thereby resulting in zero income tax benefit on other comprehensive loss for the period.

Note 10. 2014 Property Dispositions

During the three months ended March 31, 2014, the Company sold certain non-strategic properties in Colorado, Wyoming, South Dakota and North Dakota to third parties for proceeds totaling $35.4 million. In connection with the transactions, the Company recognized pre-tax losses totaling $8.5 million. The disposed properties represented an immaterial portion of the Company’s total proved reserves, production, and revenues.


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 condensed consolidated financial statements and notes thereto included elsewhere in this report and our historical consolidated financial statements and notes included in our Annual Report on Form 10-K for the year ended December 31, 2014. Our operating results for the periods discussed below may not be indicative of future performance. The following discussion and analysis includes forward-looking statements and should be read in conjunction with the risk factors described in Part II, Item 1A. Risk Factors included in this report, if any, and in our Annual Report on Form 10-K for the year ended December 31, 2014, along with Cautionary Statement for the Purpose of the “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995 at the beginning of this report, for information about the risks and uncertainties that could cause our actual results to be materially different than our forward-looking statements.

Overview

We are an independent crude oil and natural gas company engaged in the exploration, development and production of crude oil and natural gas. We derive the majority of our operating income and cash flows from the sale of crude oil and natural gas and expect this to continue in the future. Our operations are primarily focused on exploration and development activities in the Bakken field of North Dakota and Montana and the SCOOP play in Oklahoma.

Business Environment and Outlook

The decrease in crude oil prices occurring in the latter part of 2014 continued into the first quarter of 2015. Crude oil prices have showed signs of stabilization in April 2015; however, prices remain volatile and unpredictable.

Management's plans and related capital projections for 2015 are reflective of lower commodity prices. Our 2015 capital budget has been established based on an expectation of available cash flows from operations and availability under our credit facility. We will continue to monitor our capital spending closely based on actual and projected cash flows and could scale back our 2015 spending further should commodity prices remain at current levels or decrease. Conversely, a significant improvement in crude oil prices could result in an increase in our capital expenditures.

Under the current capital plan and pricing environment, we are seeking to generally align our capital expenditures with operating cash flows by mid-2015, which we expect will slow our rate of capital spending, credit facility borrowings, and production growth compared to levels achieved in the first quarter of 2015. Accordingly, our results achieved through March 31, 2015 may not be indicative of the results to be achieved for any other interim period in 2015.

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

2015 Highlights

Significant highlights for the first quarter of 2015 include:

Production

Production for the first quarter of 2015 averaged 206,829 Boe per day, an increase of 7% from the fourth quarter of 2014 and 36% higher than the first quarter of 2014.

North Dakota Bakken production averaged 120,957 Boe per day for the first quarter of 2015, a 5% increase over the fourth quarter of 2014 and 44% higher than the first quarter of 2014.

SCOOP production averaged 49,882 Boe per day for the first quarter of 2015, a 23% increase over the fourth quarter of 2014 and 70% higher than the first quarter of 2014.

SCOOP comprised 24% of our total production for the 2015 first quarter compared to 21% for the 2014 fourth quarter and 19% for the 2014 first quarter.

Revenues

Crude oil and natural gas revenues for the 2015 first quarter decreased 42% compared to the 2014 first quarter driven by a 58% decrease in realized commodity prices, the effect of which was partially offset by a 38% increase in total sales volumes.

Average crude oil sales prices decreased 57% compared to the 2014 first quarter, partially offset by a 38% increase in crude oil sales volumes.

Average natural gas sales prices decreased 62% compared to the 2014 first quarter, partially offset by a 37% increase in natural gas sales volumes.

Crude oil represented 84% and 82% of our total crude oil and natural gas revenues for the first quarters of 2015 and 2014, respectively.

Proved property impairments

Continued decreases in commodity prices in the first quarter of 2015 adversely impacted the recoverability of capitalized costs in certain operating areas and contributed to the recognition of non-cash impairment charges for proved properties totaling $70.0 million for the 2015 first quarter. The 2015 impairments were primarily concentrated in non-core areas of our North and South regions.

Capital expenditures and drilling activity

We invested approximately $983.8 million in our capital program in the first quarter of 2015, excluding $36.8 million of unbudgeted acquisitions. For the first quarter of 2015, we participated in the completion of 277 gross (106 net) wells, including 191 gross (60 net) in North Dakota Bakken and 74 gross (36 net) in SCOOP. As of March 31, 2015, we operated 28 rigs on our properties, down from 49 operated rigs at December 31, 2014.

Credit facility and liquidity

In February 2015, aggregate commitments on our credit facility were increased from $1.75 billion to $2.5 billion to provide additional liquidity if needed to maintain our growth strategy, take advantage of business opportunities, and fund our capital program and commitments. We had $1.54 billion of borrowing availability on our credit facility at March 31, 2015 after considering outstanding borrowings and letters of credit.

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,


•	Per unit operating and administrative costs, and


•	EBITDAX (a non-GAAP financial measure).

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 March 31,
	2015			2014
Average daily production:
Crude oil (Bbl per day)	143,511			106,398
Natural gas (Mcf per day)	379,906			276,439
Crude oil equivalents (Boe per day)	206,829			152,471
Average sales prices:
Crude oil ($/Bbl)	$	38.56		$	89.73
Natural gas ($/Mcf)	$	2.70		$	7.06
Crude oil equivalents ($/Boe)	$	31.65		$	75.03
Crude oil sales price differential to NYMEX ($/Bbl)	$	(10.01	)	$	(8.98	)
Natural gas sales price premium (differential) to NYMEX ($/Mcf)	$	(0.28	)	$	2.14
Production expenses ($/Boe)	$	5.05		$	5.76
Production taxes (% of oil and gas revenues)	8.2		%	7.7		%
DD&A ($/Boe)	$	21.00		$	20.43
General and administrative expenses ($/Boe)	$	1.85		$	2.43
Non-cash equity compensation ($/Boe)	$	0.61		$	0.83
Net income (loss) (in thousands)	$	(131,971	)	$	226,234
Diluted net income (loss) per share	$	(0.36	)	$	0.61
EBITDAX (in thousands) (1)	$	439,427		$	775,407

(1)

We define EBITDAX as earnings before interest expense, income taxes, depreciation, depletion, amortization and accretion, property impairments, exploration expenses, non-cash gains and losses resulting from the requirements of accounting for derivatives, non-cash equity compensation expense, and losses on extinguishment of debt. EBITDAX is not a measure of net income or operating cash flows as determined by U.S. GAAP. Reconciliations of net income and operating cash flows to EBITDAX are provided subsequently under the heading Non-GAAP Financial Measures.

Three months ended March 31, 2015 compared to the three months ended March 31, 2014

Results of Operations

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



	Three months ended March 31,
In thousands, except sales price data	2015			2014
Crude oil and natural gas sales	$	582,592		$	1,002,333
Gain (loss) on derivative instruments, net	32,755			(39,674		)
Crude oil and natural gas service operations	10,297			9,836
Total revenues	625,644			972,495
Operating costs and expenses	(736,920		)	(551,178		)
Other expenses, net	(74,716		)	(62,216		)
Income (loss) before income taxes	(185,992		)	359,101
(Provision) benefit for income taxes	54,021			(132,867		)
Net income (loss)	$	(131,971	)	$	226,234
Production volumes:
Crude oil (MBbl)	12,916			9,576
Natural gas (MMcf)	34,192			24,879
Crude oil equivalents (MBoe)	18,615			13,722
Sales volumes:
Crude oil (MBbl)	12,711			9,213
Natural gas (MMcf)	34,192			24,879
Crude oil equivalents (MBoe)	18,409			13,359
Average sales prices:
Crude oil ($/Bbl)	$	38.56		$	89.73
Natural gas ($/Mcf)	2.70			7.06
Crude oil equivalents ($/Boe)	31.65			75.03

Production

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



	Three months ended March 31,						Volume increase	Volume percent increase
	2015			2014
	Volume	Percent		Volume	Percent
Crude oil (MBbl)	12,916	69	%	9,576	70	%	3,340	35	%
Natural gas (MMcf)	34,192	31	%	24,879	30	%	9,313	37	%
Total (MBoe)	18,615	100	%	13,722	100	%	4,893	36	%

	Three months ended March 31,						Volume increase	Volume percent increase
	2015			2014
	MBoe	Percent		MBoe	Percent
North Region	13,426	72	%	10,118	74	%	3,308	33	%
South Region	5,189	28	%	3,604	26	%	1,585	44	%
Total	18,615	100	%	13,722	100	%	4,893	36	%

The 35% increase in crude oil production for the first quarter was driven by increased production from our properties in the Bakken field and SCOOP play. Production in the Bakken field increased 2,663 MBbls, or 35%, over the prior year first quarter, while SCOOP production increased 788 MBbls, or 115%. Production growth in these areas was primarily due to additional drilling and completion activity resulting from our drilling program. These increases were partially offset by a decrease in production from our properties in the Red River units and non-core areas of our North region totaling 124 MBbls, or 10%, compared to the prior year first quarter due to a combination of natural declines in production and reduced drilling activity in those areas.

The 37% increase in natural gas production for the first quarter was driven by increased production from our properties in the Bakken field and SCOOP play due to additional wells being completed and producing in first quarter 2015. Natural gas production in the Bakken field increased 4,586 MMcf, or 63%, over the prior year first quarter, while SCOOP production increased 6,353 MMcf, or 54%. These increases were partially offset by decreases in production from various areas in our North and South regions, primarily in Northwest Cana and Arkoma, due to natural declines in production.

Our 36% year-over-year growth in total production achieved through March 31, 2015 is not expected to be sustained for the full year of 2015. Our planned reduction in capital spending for 2015 will have a more significant impact on our year-over-year production growth beginning in the second quarter. For the full year of 2015, our planned drilling activity is projected to yield 16% to 20% production growth compared to 2014.

Revenues

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

Crude Oil and Natural Gas Sales. Crude oil and natural gas sales for the first quarter of 2015 were $582.6 million, a 42% decrease from sales of $1,002.3 million for the same period in 2014. Revenues for the 2015 first quarter were adversely impacted by decreased commodity prices and increased crude oil inventory levels as discussed below.

Our crude oil sales prices averaged $38.56 per barrel in the 2015 first quarter compared to $89.73 for the 2014 first quarter and $61.53 for the 2014 fourth quarter. The decrease in crude oil prices in late 2014 continued into the 2015 first quarter, resulting in significantly lower realized sales prices.

Our average natural gas sales price for the 2015 first quarter decreased to $2.70 per Mcf compared to $7.06 for the 2014 first quarter and $4.36 for the 2014 fourth quarter due to lower market prices for natural gas and natural gas liquids ("NGLs"). The difference between our realized natural gas sales prices over NYMEX Henry Hub calendar month natural gas prices was a differential of $0.28 per Mcf for the 2015 first quarter compared to premiums of $2.14 for the 2014 first quarter and $0.35 for the 2014 fourth quarter. NGL prices decreased in the 2015 first quarter in conjunction with the continued decrease in crude oil prices, which reduced the value of our natural gas sales stream and unfavorably impacted the difference between our realized prices and Henry Hub benchmark pricing.

Crude oil, natural gas and NGL prices remain volatile and we are unable to predict the impact future price changes may have on our full year 2015 revenues.

Our sales volumes increased 5,050 MBoe, or 38%, over the comparable period in 2014 primarily due to an increase in producing wells due to the success of our drilling programs in the Bakken field and SCOOP play. 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. An increase in crude oil line fill requirements and higher in-transit barrels on new pipeline systems contributed to an increase in crude oil inventories in 2015. This caused crude oil sales volumes to be lower than crude oil production by 205 MBbls for the first quarter of 2015.

Derivatives. Changes in commodity prices during the first quarter of 2015 had a favorable impact on the fair value of our derivatives, which resulted in positive revenue adjustments of $32.8 million for the period. Our revenues may continue to be significantly impacted, either positively or negatively, by changes in the fair value of our derivative instruments as a result of volatility in commodity prices.

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



	Three months ended March 31,
In thousands	2015		2014
Cash received (paid) on derivatives:
Crude oil derivatives	$	—	$	(23,107	)
Natural gas derivatives	23,435		(10,157		)
Cash received (paid) on derivatives, net	23,435		(33,264		)
Non-cash gain (loss) on derivatives:
Crude oil derivatives	3,924		18,973
Natural gas derivatives	5,396		(25,383		)
Non-cash gain (loss) on derivatives, net	9,320		(6,410		)
Gain (loss) on derivative instruments, net	$	32,755	$	(39,674	)

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

Operating Costs and Expenses

Production Expenses. Production expenses increased 21% to $92.9 million for the first quarter of 2015 from $76.9 million for the first quarter of 2014. This increase was primarily the result of an increase in the number of producing wells and resulting 36% increase in production volumes over the prior year period.

Production expense per Boe decreased to $5.05 for the 2015 first quarter compared to $5.76 for the 2014 first quarter. This per-Boe decrease resulted from curtailed spending and reduced service costs being realized in response to depressed commodity prices, a higher portion of our production coming from natural gas wells in the SCOOP area which typically have lower operating costs compared to other areas, and a significant increase in production volumes from new well completions during the 2015 first quarter.

Production Taxes and Other Expenses. Production taxes and other expenses decreased $29.9 million, or 38%, to $48.4 million for the first quarter of 2015 compared to $78.3 million for the first quarter of 2014 primarily as a result of lower crude oil and natural gas revenues resulting from the significant decrease in commodity prices over the prior year period. Production taxes as a percentage of crude oil and natural gas revenues were 8.2% for the first quarter of 2015 compared to 7.7% for the first quarter of 2014, the difference of which resulted from changes in the mix of crude oil and natural gas sales volumes and values and the proportion of taxable revenues coming from North Dakota and Oklahoma between periods.

Production taxes are generally based on the wellhead values of production and vary by state. Some states offer exemptions or reduced production tax rates for wells that produce less than a certain quantity of crude oil or natural gas and to encourage certain activities, such as horizontal drilling and enhanced recovery projects. In Montana and Oklahoma, certain horizontal wells are taxed at a lower rate during their initial months of production which subsequently increases after a specified period of time or when specified production volumes are achieved.

At March 31, 2015, North Dakota has a crude oil tax structure based on a 5% production tax and a 6.5% oil extraction tax for a combined tax of 11.5% of crude oil revenues. Currently, the 6.5% oil extraction tax has a series of built-in triggers that reduce or eliminate the tax depending on various commodity price and production circumstances. For instance, North Dakota law provides that if the average WTI oil price for a full calendar month falls below $57.50 per barrel, a reduced oil extraction tax rate of 2% becomes effective for wells having first production after the price trigger date. Beginning with the month of January 2015 and continuing for the full first quarter, WTI oil prices, on average, were below the $57.50 per barrel price trigger. Accordingly, our North Dakota wells having first production on or after February 1, 2015 qualify for a reduced 2% oil extraction tax, subject to production, value and time limitations. The reduced tax rate realized on applicable wells did not have a significant impact on our production tax expenses for the 2015 first quarter. North Dakota's crude oil tax structure and related incentives have been impacted by new legislation enacted in April 2015 as described below.

Additionally in North Dakota, if the average WTI oil price falls below a certain threshold ($55.09 per barrel for 2015) for five consecutive months, then the 6.5% oil extraction tax is reduced to 0% or 4% depending on the completion date and age of a well. The reduced tax rates revert back to 6.5% under varying circumstances tied to WTI oil price increases, production and value limitations, and the passage of time. WTI oil prices, on average, fell below the $55.09 price trigger for the month of January 2015 and the monthly average has remained below that level for four consecutive months through April 30, 2015. If the monthly average WTI price remains below $55.09 per barrel for May 2015, a significant number of our wells in North Dakota will qualify for a reduced tax rate, which could have a significant impact on our production tax expenses. We are unable to estimate with certainty the impact this potential tax rate reduction, if realized, may have on our future operating results. This tax incentive has been impacted by the new legislation described below.

On April 29, 2015, new legislation (House Bill 1476) was signed into law in North Dakota that eliminates the price-based oil extraction tax incentives described above and sets a lower oil extraction tax rate. The new law removes the above tax incentives effective January 1, 2016. New wells completed prior to that date will remain eligible for the above tax incentives through January 1, 2016. Additionally, the new law permanently reduces the oil extraction tax from 6.5% to 5% effective January 1, 2016, resulting in a total tax of 10% on crude oil revenues when combined with the 5% production tax which was not changed by the new law. Under the new law, the oil extraction tax will increase from 5% to 6%, for a total tax rate of 11%, if the average WTI oil price is above $90 per barrel (indexed for inflation) for three consecutive months. The oil extraction tax will revert back to 5% if the average WTI oil price falls below $90 per barrel for three consecutive months. We are unable to estimate with certainty the impact this new law will have on our future operating results.

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 March 31,
In thousands	2015		2014
Geological and geophysical costs	$	5,939	$	4,813
Exploratory dry hole costs	8,401		—
Exploration expenses	$	14,340	$	4,813

Dry hole costs incurred in the first quarter of 2015 primarily reflect costs associated with an unsuccessful well in a prospect in our North region that is in the early stages of exploration.

Depreciation, Depletion, Amortization and Accretion (“DD&A”). Total DD&A increased $113.6 million, or 42%, to $386.5 million for the first quarter of 2015 compared to $272.9 million for the first quarter of 2014 primarily due to a 38% increase in 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 March 31,
$/Boe	2015		2014
Crude oil and natural gas	$	20.59	$	20.08
Other equipment	0.35		0.29
Asset retirement obligation accretion	0.06		0.06
Depreciation, depletion, amortization and accretion	$	21.00	$	20.43

Property Impairments. Total property impairments increased $89.4 million, or 154%, to $147.6 million for the first quarter of 2015 compared to $58.2 million for the 2014 first quarter due primarily to write-downs resulting from the continued decrease in commodity prices in the 2015 first quarter which adversely impacted the recoverability of capitalized costs in certain operating areas.

Impairments of proved properties totaled $70.0 million for the first quarter of 2015 compared to $3.8 million for the first quarter of 2014, the increase of which resulted from the continued decrease in commodity prices in the 2015 first quarter that indicated the carrying amounts for certain fields were not recoverable. The 2015 impairments were primarily concentrated in an emerging area with limited production history and costly reserve additions ($36.1 million), the Medicine Pole Hills units ($14.7 million), various non-core areas in the South region ($11.1 million), and non-Bakken areas of North Dakota and Montana ($8.1 million).

Impairments of non-producing properties increased $23.1 million for the first quarter of 2015 to $77.5 million compared to $54.4 million for the first quarter of 2014. The increase was primarily due to higher rates of amortization being applied to undeveloped leasehold costs resulting from changes in management’s estimates of undeveloped properties not expected to be developed before lease expiration, particularly in response to the significant decrease in commodity prices in recent months which has altered our drilling plans.

General and Administrative ("G&A") Expenses. G&A expenses increased $1.9 million, or 4%, to $45.4 million for the first quarter of 2015 from $43.5 million for the 2014 first quarter primarily due to an increase in personnel costs and office-related expenses associated with our growth. G&A expenses include non-cash charges for equity compensation of $11.3 million and $11.0 million for the first quarters of 2015 and 2014, respectively.

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



	Three months ended March 31,
$/Boe	2015		2014
General and administrative expenses	$	1.85	$	2.43
Non-cash equity compensation	0.61		0.83
Total general and administrative expenses	$	2.46	$	3.26

The decrease in G&A expenses on a per-Boe basis in 2015 was driven by curtailed spending and smaller increases in personnel costs compared to the prior year in response to depressed commodity prices, coupled with a significant increase in sales volumes from new well completions during the 2015 first quarter.

The decrease in equity compensation expense on a per-Boe basis in 2015 was primarily due to an increase in the estimated rate of forfeitures of unvested restricted stock based on historical experience, which resulted in a reduction of compensation expense recognized in the 2015 first quarter of approximately $3 million.

Interest Expense. Interest expense increased $12.1 million, or 19%, to $75.1 million for the first quarter of 2015 compared to $63.0 million for the first quarter of 2014 due to an increase in our weighted average outstanding long-term debt obligations. Our weighted average outstanding long-term debt balance for the 2015 first quarter was approximately $6.4 billion with a weighted average interest rate of 4.6% compared to averages of $4.9 billion and 5.0% for the 2014 first quarter. The increase in outstanding debt resulted from borrowings incurred subsequent to March 31, 2014 to fund our 2014 and 2015 capital programs.

Income Taxes. We recorded an income tax benefit for the first quarter of 2015 of $54.0 million compared to income tax expense of $132.9 million for the first quarter of 2014, resulting in effective tax rates of approximately 29% and 37%, respectively, after taking into account permanent taxable differences and valuation allowances. Our 2015 effective tax rate was reduced by an $11.1 million valuation allowance recognized against deferred tax assets associated with operating loss carryforwards generated by our Canadian subsidiary in the 2015 first quarter for which we do not believe we will realize a benefit.

Liquidity and Capital Resources

Our primary sources of liquidity have been cash flows generated from operating activities, financing provided by our credit facility and the issuance of debt and equity securities. In February 2015, the aggregate lender commitments on our credit facility were increased from $1.75 billion to $2.5 billion to provide additional liquidity if needed to maintain our growth strategy, take advantage of business opportunities, and fund our capital program and commitments. At March 31, 2015, we had $47.6 million of cash and cash equivalents and $1.54 billion of borrowing availability on our credit facility after considering outstanding borrowings and letters of credit. We had $955 million of outstanding borrowings on our credit facility at March 31, 2015, which subsequently increased to $1.18 billion as of April 30, 2015 as a result of additional borrowings incurred to fund a portion of our 2015 drilling program. At April 30, 2015, we had $1.32 billion of borrowing availability on our credit facility after considering outstanding borrowings and letters of credit at that date.

Based on our planned capital expenditures, our forecasted operating cash flows and projected levels of indebtedness, we expect to maintain compliance with the covenants under our credit facility and senior note indentures for at least the next 12 months. Further, we expect to meet in the ordinary course of business other contractual cash commitments to third parties as of March 31, 2015, including those described in Note 7. Commitments and Contingencies in Notes to Unaudited Condensed Consolidated Financial Statements, recognizing we may be required to meet such commitments even if our business plan assumptions were to change.

Cash Flows

Cash flows from operating activities

Our net cash provided by operating activities was $522.2 million and $690.7 million for the three months ended March 31, 2015 and 2014, respectively. The decrease in operating cash flows was primarily due to lower crude oil and natural gas revenues driven by lower realized commodity prices along with increases in production expenses, general and administrative expenses, interest expense and other expenses associated with the growth of our Company and an increase in producing well count over the past year, all partially offset by an increase in cash gains on matured derivatives.

If the currently depressed crude oil pricing environment persists or worsens, we expect our operating cash flows for the remainder of 2015 will continue to be lower than 2014 levels.

Cash flows used in investing activities

During the three months ended March 31, 2015 and 2014, we had cash flows used in investing activities (excluding proceeds from asset sales) of $1,279.3 million and $1,054.9 million, respectively, related to our capital program, inclusive of dry hole costs and property acquisitions. Cash acquisition capital expenditures totaled $36.8 million and $66.4 million for the three months ended March 31, 2015 and 2014, respectively. Cash capital expenditures excluding acquisitions totaled $1,242.5 million and $988.5 million for the three months ended March 31, 2015 and 2014, respectively. First quarter 2015 cash capital expenditures were significantly impacted by the payment of amounts owed in connection with our 2014 drilling program and associated decrease in accruals for capital expenditures and the completion of wells that were in the process of drilling or waiting on completion at December 31, 2014.

Cash flows from financing activities

Net cash provided by financing activities for the three months ended March 31, 2015 and 2014 was $784.4 million and $351.9 million, respectively, primarily resulting from $790 million and $355 million, respectively, of net borrowings being incurred on our credit facility during those periods to fund a portion of our capital programs. Our 2015 first quarter operating cash flows were adversely impacted by decreased commodity prices, leading to a $790 million net increase in credit facility borrowings incurred during the quarter for the payment of amounts owed in connection with our 2014 drilling program and to fund a portion of our 2015 drilling program.

Our levels of capital expenditures and credit facility borrowings incurred through March 31, 2015 are not expected to be continued at the same rate for the full year of 2015. Under our current capital plan and pricing environment, we are seeking to generally align our capital expenditures with operating cash flows by mid-2015 which we expect will result in a reduction in quarterly capital spending and credit facility borrowings from levels incurred in the 2015 first quarter.

Future Sources of Financing

Although we cannot provide any assurance, we believe funds from operating cash flows, our remaining cash balance and availability under our credit facility, including our ability to increase our borrowing capacity thereunder, should be sufficient to meet our cash requirements inclusive of, but not limited to, normal operating needs, debt service obligations, planned capital expenditures, and commitments for the next 12 months. Our 2015 capital expenditures budget is reflective of the significant decrease in commodity prices in recent months and has been established based on an expectation of available cash flows from operations and availability under our credit facility. If operating cash flows are materially impacted by a further decline in commodity prices, we have the ability to reduce our capital expenditures or utilize the availability on our 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.

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

Credit facility

We have an unsecured credit facility, maturing on May 16, 2019, with aggregate lender commitments totaling $2.5 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 15 banks and financial institutions. We believe each member of the current syndicate has the capability to fund its commitment. As of April 30, 2015, we had $1.18 billion of outstanding borrowings and $1.32 billion of borrowing availability on our credit facility after considering outstanding borrowings and letters of credit.

The commitments under our credit facility are not dependent on a borrowing base calculation subject to periodic redetermination based on changes in commodity prices and proved reserves. Additionally, a downgrade or other negative rating action with respect to our credit rating will not trigger a reduction in our current credit facility commitments, nor will such action trigger a security requirement or change in covenants.

Our credit facility contains restrictive covenants that may limit our ability to, among other things, incur additional indebtedness, incur liens, engage in sale and leaseback transactions, 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. Effective May 4, 2015, this ratio represents the ratio of net debt (total debt 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.

On May 4, 2015, our credit facility was amended to add the language described in the paragraph above that has the effect of excluding the impact of non-cash impairment charges recognized after June 30, 2014 from the determination of shareholders' equity in the calculation of the consolidated net debt to total capitalization ratio. This amendment is filed as Exhibit 10.2 to this report on Form 10-Q. The amendment is documented in Amendment No. 1 dated May 4, 2015 (“Amendment No. 1”) among the Company, as borrower, and its subsidiaries Banner Pipeline Company, L.L.C. and CLR Asset Holdings, LLC, as guarantors (referred to collectively as the “Subsidiaries”), the lenders party to Amendment No. 1 and MUFG Union Bank, N.A. (“MUFG”), as Administrative Agent. Amendment No. 1 amends the unsecured Revolving Credit Agreement dated May 16, 2014 among the Company, as borrower, the Subsidiaries, as guarantors, MUFG, as Administrative Agent, Bank of America, N.A., Compass Bank and The Royal Bank of Scotland plc, as Co-Syndication Agents, Citibank, N.A., JPMorgan

Chase Bank, N.A., U.S. Bank National Association and Wells Fargo Bank, N.A., as Co-Documentation Agents and the other lenders named therein.

The amended ratio definition described above did not have an impact on our covenant compliance at March 31, 2015. Prior to and after the amendment we were in compliance with our credit facility covenants and expect to maintain compliance for at least the next 12 months. At March 31, 2015, our consolidated net debt to total capitalization ratio, as originally defined in the credit facility prior to amendment, was 0.58 to 1.00. If the amended ratio definition that became effective May 4, 2015 was used, our consolidated net debt to total capitalization ratio would have been 0.56 to 1.00 as of March 31, 2015.

We do not believe the credit facility covenants are reasonably likely to limit our ability to undertake additional debt or equity financing to a material extent. At March 31, 2015, our total debt would have needed to independently increase by approximately $3.0 billion, or 45%, above existing levels at that date (with no corresponding increase in cash or reduction in refinanced debt) to reach the maximum covenant ratio of 0.65 to 1.00 using the amended definition of consolidated net debt to total capitalization. Alternatively, our total shareholders' equity would have needed to independently decrease by approximately $1.6 billion, or 31%, below existing levels at March 31, 2015 to reach the maximum covenant ratio using the amended ratio definition. These independent point-in-time sensitivities do not take into account other factors that could arise to mitigate the impact of changes in debt and equity on our consolidated net debt to total capitalization ratio, such as disposing of assets or exploring alternative sources of capitalization.

Future Capital Requirements

Senior notes

Our long-term debt includes outstanding senior note obligations totaling $5.8 billion at March 31, 2015. We have no near-term senior note maturities, with our earliest scheduled maturity being our $200 million of 2020 Notes due in October 2020. Our senior notes are not subject to any mandatory redemption or sinking fund requirements. For further information on the 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 March 31, 2015 and expect to maintain compliance for at least the next 12 months. We do not believe the senior note covenants will materially limit our ability to undertake additional debt or equity financing. A downgrade or other negative rating action with respect to the credit ratings assigned to our senior unsecured debt does not trigger additional senior note covenants that are more restrictive than the existing covenants at March 31, 2015.

Two of our subsidiaries, Banner Pipeline Company, L.L.C. and CLR Asset Holdings, LLC, which have no material assets or operations, fully and unconditionally guarantee the senior notes. Our other subsidiaries, the value of whose assets and operations are minor, do not guarantee the senior notes.

Capital expenditures

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

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



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

During the three months ended March 31, 2015, we participated in the completion of 277 gross (106 net) wells and invested approximately $983.8 million in our capital program, excluding $36.8 million of unbudgeted acquisitions, excluding $260.2 million of capital costs associated with decreased accruals for capital expenditures, and including $1.6 million of seismic costs. Our 2015 year-to-date capital expenditures were allocated as follows:



In millions	Amount
Exploration and development drilling	$	914.2
Land costs	27.1
Capital facilities, workovers and other corporate assets	40.9
Seismic	1.6
Capital expenditures, excluding acquisitions	983.8
Acquisitions of producing properties	0.1
Acquisitions of non-producing properties	36.7
Total acquisitions	36.8
Total capital expenditures	$	1,020.6

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

Our 2015 capital program has been established based on an expectation of available cash flows from operations and availability under our credit facility. The actual amount and timing of our capital expenditures may differ materially from our budget as a result of, among other things, access to capital, available cash flows, unbudgeted acquisitions, actual drilling results, the availability of drilling rigs and other services and equipment, the availability of transportation capacity, changes in commodity prices, and regulatory, technological and competitive developments. A further decline in commodity prices could cause us to further curtail our actual capital expenditures. Conversely, an increase in commodity prices could result in increased capital expenditures. We expect to continue participating as a buyer of properties when and if we have the ability to increase our position in strategic plays at competitive terms.

Commitments

Refer to Note 7. Commitments and Contingencies in Notes to Unaudited Condensed Consolidated Financial Statements for a discussion of certain future commitments of the Company as of March 31, 2015. We believe our cash flows from operations, our remaining cash balance, and amounts available under our credit facility, including our ability to increase our borrowing capacity thereunder, will be sufficient to satisfy our commitments.

Off-balance sheet arrangements

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

Critical Accounting Policies

There have been no changes in our critical accounting policies from those disclosed in our Form 10-K for the year ended December 31, 2014.

Recent Accounting Pronouncements Not Yet Adopted

Refer to Note 2. Basis of Presentation and Significant Accounting Policies in Notes to Unaudited Condensed Consolidated Financial Statements for a discussion of recent accounting pronouncements not yet adopted as of March 31, 2015.

Non-GAAP Financial Measures

We use a variety of financial and operational measures to assess our performance. Among these measures is EBITDAX. We define EBITDAX as earnings before interest expense, income taxes, depreciation, depletion, amortization and accretion, property impairments, exploration expenses, non-cash gains and losses resulting from the requirements of accounting

for derivatives, non-cash equity compensation expense, and losses on extinguishment of debt. EBITDAX is not a measure of net income or operating cash flows as determined by U.S. GAAP.

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

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

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



	Three months ended March 31,
In thousands	2015			2014
Net income (loss)	$	(131,971	)	$	226,234
Interest expense	75,063			62,975
Provision (benefit) for income taxes	(54,021		)	132,867
Depreciation, depletion, amortization and accretion	386,512			272,861
Property impairments	147,561			58,208
Exploration expenses	14,340			4,813
Impact from derivative instruments:
Total (gain) loss on derivatives, net	(32,755		)	39,674
Cash received (paid) on derivatives, net	23,435			(33,264		)
Non-cash (gain) loss on derivatives, net	(9,320		)	6,410
Non-cash equity compensation	11,263			11,039
EBITDAX	$	439,427		$	775,407

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



	Three months ended March 31,
In thousands	2015			2014
Net cash provided by operating activities	$	522,190		$	690,662
Current income tax provision	5			1,552
Interest expense	75,063			62,975
Exploration expenses, excluding dry hole costs	5,939			4,813
Gain (loss) on sale of assets, net	2,070			(8,498		)
Other, net	(6,775		)	(10,008		)
Changes in assets and liabilities	(159,065		)	33,911
EBITDAX	$	439,427		$	775,407


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, interest rate risk and foreign currency exchange risk. We seek to address these risks through a program of risk management which may include the use of derivative instruments.

Commodity Price Risk. Our primary market risk exposure is in the pricing applicable to 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 three months ended March 31, 2015, and excluding any effect of our derivative instruments in place, our annual revenue would increase or decrease by approximately $524 million for each $10.00 per barrel change in crude oil prices and $139 million for each $1.00 per Mcf change in natural gas prices.

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

Changes in commodity prices during the three months ended March 31, 2015 had an overall favorable impact on the fair value of our derivative instruments. For the three months ended March 31, 2015, we recognized cash gains on derivatives of $23.4 million and reported a non-cash mark-to-market gain on derivatives of $9.3 million.

The fair value of our crude oil derivative instruments at March 31, 2015 was a net liability of $0.8 million. An assumed increase in the forward prices used in the March 31, 2015 valuation of our crude oil derivatives of $10.00 per barrel would increase our crude oil derivative liability to approximately $2.6 million at March 31, 2015. Conversely, an assumed decrease in forward prices of $10.00 per barrel would decrease our crude oil derivative liability to approximately $0.3 million at March 31, 2015.

The fair value of our natural gas derivative instruments at March 31, 2015 was a net asset of $89.8 million. An assumed increase in the forward prices used in the March 31, 2015 valuation of our natural gas derivatives of $1.00 per MMBtu would decrease our natural gas derivative asset to approximately $3.5 million at March 31, 2015. Conversely, an assumed decrease in forward prices of $1.00 per MMBtu would increase our natural gas derivative asset to approximately $181.0 million at March 31, 2015.

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 ($456 million in receivables at March 31, 2015), our joint interest receivables ($506 million at March 31, 2015), and counterparty credit risk associated with our derivative instrument receivables ($90 million at March 31, 2015).

We monitor our exposure to counterparties on crude oil and natural gas sales primarily by reviewing credit ratings, financial statements and payment history. We extend credit terms based on our evaluation of each counterparty’s credit worthiness. We have not generally required our counterparties to provide collateral to support 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 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 $107 million at March 31, 2015, 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 credit facility. We manage our interest rate exposure by monitoring both the effects of market changes in interest rates and the proportion of our debt portfolio that is variable-rate versus fixed-rate debt. We may utilize interest rate derivatives to alter interest rate exposure in an attempt to reduce interest rate expense related to existing debt issues. Interest rate derivatives may be used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio. We currently have no interest rate derivatives.

We had $1.18 billion of outstanding borrowings on our credit facility at April 30, 2015 with a weighted average interest rate of 1.7%. The impact of a 1% increase in interest rates on this amount of debt would result in increased interest expense of approximately $11.8 million per year and a $7.3 million decrease in net income per year.

Foreign Currency Exchange Risk. The assets, liabilities, revenues, expenses and cash flows associated with our Canadian subsidiary are based on the U.S. dollar equivalent of such amounts measured in the Canadian dollar functional currency. Assets and liabilities of the Canadian subsidiary are translated to U.S. dollars using the applicable exchange rate as of the end of a reporting period. Revenues, expenses and cash flows are translated using an average exchange rate during the reporting period. A 10% change in the Canadian-to-U.S. dollar exchange rate would not materially impact our March 31, 2015 balance sheet.

ITEM 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As of the end of the period covered by this report, an evaluation of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) was performed under the supervision and with the participation of the Company’s management, including its Chief Executive Officer and Chief Financial Officer. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of March 31, 2015 to ensure that information required to be disclosed in the reports it files and submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that information required to be disclosed under the Exchange Act is accumulated and communicated to the Company’s management, including its Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control over Financial Reporting

During the three months ended March 31, 2015, 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

During the three months ended March 31, 2015 there have been no material changes with respect to the legal proceedings previously disclosed in our 2014 Form 10-K that was filed with the SEC on February 24, 2015. See Note 7. Commitments and Contingencies in Notes to Unaudited Condensed Consolidated Financial Statements included elsewhere in this report.


ITEM 1A.	Risk Factors

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

There have been no material changes in our risk factors from those disclosed in our 2014 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 March 31, 2015:



Period	Total number of shares purchased		Average price paid per share			Total number of shares purchased as part of publicly announced plans or programs	Maximum number of shares that may yet be purchased under the plans or programs (3)
January 1, 2015 to January 31, 2015	254	(1)	$	44.63	(1)	—	—
February 1, 2015 to February 28, 2015	62,883	(1)	$	47.36	(1)	—	—
March 1, 2015 to March 31, 2015	139,930	(2)	$	42.97	(2)	—	—
Total	203,067		$	44.33		—	—

(1)

In connection with restricted stock grants under the Company's 2005 Long-Term Incentive Plan ("2005 Plan") and 2013 Long-Term Incentive Plan ("2013 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. The price paid per share was the closing price of our common stock on the date the restrictions lapsed on such shares. We paid the associated taxes to the Internal Revenue Service.


(2)	Of this amount, 309 shares represent shares surrendered by employees to cover tax liabilities at an average price per share of $42.76. Additionally, the amount includes 139,621 shares of our common stock purchased by Harold G. Hamm, our Chairman of the Board, Chief Executive Officer, and principal shareholder in open-market transactions at an average price per share of $42.97.


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


ITEM 3.	Defaults Upon Senior Securities

Not applicable.


ITEM 4.	Mine Safety Disclosures

Not applicable.

ITEM 5. Other Information

Not applicable.


ITEM 6.	Exhibits

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

SIGNATURE

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



		CONTINENTAL RESOURCES, INC.

Date:	May 6, 2015	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	Third Amended and Restated Certificate of Incorporation of Continental Resources, Inc. filed February 24, 2012 as Exhibit 3.1 to the Company’s 2011 Form 10-K (Commission File No. 001-32886) 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*†	Description of Cash Bonus Plan approved as of March 20, 2015.

10.2*	Amendment No. 1 dated May 4, 2015 to the Revolving Credit Agreement dated as of May 16, 2014 among Continental Resources, Inc., as borrower, Banner Pipeline Company L.L.C. and CLR Asset Holdings, LLC, as guarantors, the lenders party thereto, and MUFG Union Bank, N.A., as Administrative Agent.

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.