Former name, former address and former fiscal year, if changed since last report: Not applicable

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

~~180,533,094~~180,483,387 shares of our $0.01 par value common stock were outstanding on ~~May 2,~~October 31, 2011.

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

“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.

“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, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.~~gas.

“Conventional play” An area that is believed to be capable of producing crude oil and natural gas occurring in discrete accumulations in structural and stratigraphic traps.

“Developed acreage” The number of acres that are 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.~~reservoir, supplementing its natural energy. Enhanced recovery methods are ~~often~~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 differ from nearby rock.

“Horizontal drilling” A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.

“Injection well” A well into which liquids or gases are injected in order to “push” additional crude oil or natural gas out of underground reservoirs and into the wellbores of producing wells. Typically considered an enhanced recovery process.

“MBbl” One thousand barrels of crude oil, condensate or natural gas liquids.

“MMBtu” One million British thermal units. A British thermal unit 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.

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

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

“Proved developed reserves” Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

“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 that renewal is reasonably certain.

“Proved undeveloped reserves”or“PUD” Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

“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 that are produced from a crude oil or natural gas property. A royalty interest owner does not bear any of the exploration, development, or operating expenses associated with drilling and producing a crude oil or natural gas property.

“Unconventional play” An area ~~that is~~ believed to be capable of producing crude oil and/or natural gas occurring in accumulations that are regionally extensive, but require recently developed technologies to achieve profitability. These areas tend to have low permeability and may be closely associated with source rock as is the case with oil and gas shale, tight oil and gas sands and ~~coalbed~~coal-bed methane.

“Undeveloped acreage” Lease acreage on which wells have not been drilled or completed to a point that would permit the production of ~~commercial~~economically producible 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.

Certain statements and information in this report may constitute “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. All statements other than statements of historical fact included in this report are forward-looking statements. When used in this report, the words “could,” “may,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. 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. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under the headingItem 1A. Risk Factors included in this report and in our Annual Report on Form 10-K for the year ended December 31, 2010.

Without limiting the generality of the foregoing, certain statements incorporated by reference, if any, or included in this report constitute forward-looking statements.

We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for, and development, production, and sale of, crude oil and natural gas. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating crude oil and natural gas reserves and in projecting future rates of production, cash flows and access to capital, the timing of development expenditures, and the other risks described underPart II,Item 1A. Risk Factors in this report, our Annual Report on Form 10-K for the year ended December 31, 2010, registration statements filed from time to time with the SEC, 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 hereof.

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. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements to reflect events or circumstances after the date of this report.


	March 31, 2011		December 31, 2010		September 30, 2011		December 31, 2010
	*(Unaudited)*				*(Unaudited)*
	*In thousands, except par values and share data*				*In thousands, except par values and share data*
Assets
Current assets:
Cash and cash equivalents	$	477,440	$	7,916	$	42,275	$	7,916
Receivables:
Crude oil and natural gas sales		260,570		208,211		290,826		208,211
Affiliated parties		17,038		20,156		27,329		20,156
Joint interest and other, net		282,861		254,471		342,310		254,471
Derivative assets		17,360		21,365		114,323		21,365
Inventories		52,248		38,362		61,690		38,362
Deferred and prepaid taxes		84,004		22,672		1,997		22,672
Prepaid expenses and other		9,724		9,173		27,074		9,173

Total current assets		1,201,245		582,326		907,824		582,326
Net property and equipment, based on successful efforts method of accounting		3,285,824		2,981,991		4,046,235		2,981,991
Debt issuance costs, net		26,342		27,468		24,716		27,468
Noncurrent derivative assets		49		—		120,802		—

Total assets	$	4,513,460	$	3,591,785	$	5,099,577	$	3,591,785


Liabilities and shareholders’ equity
Current liabilities:
Accounts payable trade	$	425,812	$	390,892	$	526,252	$	390,892
Revenues and royalties payable		174,620		133,051		188,944		133,051
Payables to affiliated parties		4,263		4,438		8,109		4,438
Accrued liabilities and other		106,357		94,829		154,782		94,829
Derivative liabilities		232,884		76,771		—		76,771
Current portion of asset retirement obligations		2,270		2,241		2,640		2,241

Total current liabilities		946,206		702,222		880,727		702,222
Long-term debt		896,065		925,991		896,220		925,991
Other noncurrent liabilities:
Deferred income tax liabilities		559,929		582,841		843,332		582,841
Asset retirement obligations, net of current portion		55,141		54,079		56,930		54,079
Noncurrent derivative liabilities		316,958		112,940		—		112,940
Other noncurrent liabilities		5,468		5,557		3,750		5,557

Total other noncurrent liabilities		937,496		755,417		904,012		755,417
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; 180,535,512 shares issued and outstanding at March 31, 2011; 170,408,652 shares issued and outstanding at December 31, 2010		1,805		1,704
Additional paid-in-capital		1,102,538		439,900
Common stock, $0.01 par value; 500,000,000 shares authorized; 180,533,960 shares issued and outstanding at September 30, 2011; 170,408,652 shares issued and outstanding at December 31, 2010						1,805		1,704
Additional paid-in capital						1,109,126		439,900
Retained earnings		629,350		766,551		1,307,687		766,551

Total shareholders’ equity		1,733,693		1,208,155		2,418,618		1,208,155

Total liabilities and shareholders’ equity	$	4,513,460	$	3,591,785	$	5,099,577	$	3,591,785

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


	Three months ended March 31,						Three months ended September 30,						Nine months ended September 30,
	2011			2010			2011			2010			2011			2010
	*In thousands, except per share data*						*In thousands, except per share data*
Revenues:
Crude oil and natural gas sales	$	316,740		$	208,059		$	408,037		$	232,662		$	1,103,165		$	651,925
Crude oil and natural gas sales to affiliates		9,727			9,065			15,822			6,164			35,945			23,451
Gain (loss) on derivative instruments, net		(369,303	)		26,344			537,340			(24,183	)		372,490			57,626
Crude oil and natural gas service operations		6,626			4,800			7,790			4,807			24,071			14,684

Total revenues		(36,210	)		248,268			968,989			219,450			1,535,671			747,686

Operating costs and expenses:
Production expenses		28,398			19,159			35,666			23,626			95,508			64,044
Production expenses to affiliates		872			3,442			793			1,231			2,582			5,762
Production taxes and other expenses		27,562			16,007			39,262			19,517			100,315			53,755
Exploration expenses		6,812			1,786			9,814			3,530			21,660			7,585
Crude oil and natural gas service operations		5,451			3,956			6,198			4,935			19,713			12,982
Depreciation, depletion, amortization and accretion		75,650			52,587			105,085			62,918			264,236			174,327
Property impairments		20,848			15,175			26,225			14,698			66,315			49,387
General and administrative expenses		16,347			11,849			18,140			12,148			51,696			35,491
Gain on sale of assets		(15,257	)		(222	)
(Gain) loss on sale of assets								188			491			(15,387	)		(32,855	)

Total operating costs and expenses		166,683			123,739			241,371			143,094			606,638			370,478

Income (loss) from operations		(202,893	)		124,529
Income from operations								727,618			76,356			929,033			377,208
Other income (expense):
Interest expense		(18,971	)		(8,360	)		(18,981	)		(12,612	)		(56,737	)		(32,875	)
Other		509			706			994			237			2,525			1,021

		(18,462	)		(7,654	)		(17,987	)		(12,375	)		(54,212	)		(31,854	)

Income (loss) before income taxes		(221,355	)		116,875
Provision (benefit) for income taxes		(84,154	)		44,410
Income before income taxes								709,631			63,981			874,821			345,354
Provision for income taxes								270,488			24,904			333,685			132,071

Net income (loss)	$	(137,201	)	$	72,465
Net income							$	439,143		$	39,077		$	541,136		$	213,283

Basic net income (loss) per share	$	(0.80	)	$	0.43
Diluted net income (loss) per share	$	(0.80	)	$	0.43
Basic net income per share							$	2.45		$	0.23		$	3.06		$	1.26
Diluted net income per share							$	2.44		$	0.23		$	3.05		$	1.26

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


	Shares outstanding			Common stock			Additional paid-in capital			Retained earnings			Total shareholders’ equity			Shares outstanding			Common stock		Additional paid-in capital			Retained earnings		Total shareholders’ equity
	*In thousands, except share data*															*In thousands, except share data*
Balance, December 31, 2009		169,968,471		$	1,700		$	430,283		$	598,296		$	1,030,279
Net income		—			—			—			168,255			168,255
Excess tax benefit on stock-based compensation		—			—			5,230			—			5,230
Stock-based compensation		—			—			11,691			—			11,691
Stock options:
Exercised		207,220			2			255			—			257
Repurchased and canceled		(59,877	)		(1	)		(2,661	)		—			(2,662	)
Restricted stock:
Issued		449,114			4			—			—			4
Repurchased and canceled		(100,561	)		(1	)		(4,898	)		—			(4,899	)
Forfeited		(55,715	)		—			—			—			—

Balance, December 31, 2010		170,408,652		$	1,704		$	439,900		$	766,551		$	1,208,155			170,408,652		$	1,704	$	439,900		$	766,551	$	1,208,155
Net income (loss) (unaudited)		—			—			—			(137,201	)		(137,201	)
Net income (unaudited)																	—			—		—			541,136		541,136
Public offering of common stock (unaudited)		10,080,000			101			659,200			—			659,301			10,080,000			101		659,131			—		659,232
Stock-based compensation (unaudited)		—			—			3,642			—			3,642			—			—		11,742			—		11,742
Stock options:
Exercised (unaudited)		4,500			—			3			—			3			12,470			—		9			—		9
Repurchased and canceled (unaudited)																	(2,495	)		—		(150	)		—		(150	)
Restricted stock:
Issued (unaudited)		47,480			—			—			—			—			79,060			—		—			—		—
Repurchased and canceled (unaudited)		(3,172	)		—			(207	)		—			(207	)		(23,293	)		—		(1,506	)		—		(1,506	)
Forfeited (unaudited)		(1,948	)		—			—			—			—			(20,434	)		—		—			—		—

Balance, March 31, 2011 (unaudited)		180,535,512		$	1,805		$	1,102,538		$	629,350		$	1,733,693
Balance, September 30, 2011																	180,533,960		$	1,805	$	1,109,126		$	1,307,687	$	2,418,618

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


	Three months ended March 31,
	2011			2010			Nine months ended September 30,
	*In thousands*						2011			2010
Cash flows from operating activities:								*In thousands*
Net income (loss)	$	(137,201	)	$	72,465
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Net income							$	541,136		$	213,283
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion		76,762			52,179			266,281			173,321
Property impairments		20,848			15,175			66,315			49,387
Change in fair value of derivatives		364,087			(22,052	)		(403,471	)		(28,162	)
Stock-based compensation		3,642			2,852			11,742			8,596
Provision (benefit) for deferred income taxes		(84,154	)		40,416
Provision for deferred income taxes								324,354			116,165
Dry hole costs		1,504			33			3,758			1,943
Gain on sale of assets		(15,257	)		(222	)		(15,387	)		(32,855	)
Other, net		929			956			2,800			3,631
Changes in assets and liabilities:
Accounts receivable		(77,631	)		(61,044	)		(177,627	)		(192,970	)
Inventories		(13,886	)		(363	)		(23,543	)		(4,345	)
Prepaid expenses and other		(513	)		4,030			(18,937	)		2,105
Accounts payable trade		3,648			69,719			21,206			99,869
Revenues and royalties payable		41,569			7,574			55,893			28,716
Accrued liabilities and other		11,340			8,932			17,012			54,008
Other noncurrent liabilities		(52	)		38			(1,718	)		2,648

Net cash provided by operating activities		195,635			190,688			669,814			495,340

Cash flows from investing activities:
Exploration and development		(348,011	)		(156,625	)		(1,245,688	)		(719,843	)
Purchase of crude oil and natural gas properties		—			(128	)		(2,771	)		(7,319	)
Purchase of other property and equipment		(29,443	)		(6,263	)		(37,449	)		(20,453	)
Proceeds from sale of assets		22,131			1,106			22,769			38,662

Net cash used in investing activities		(355,323	)		(161,910	)		(1,263,139	)		(708,953	)

Cash flows from financing activities:
Revolving credit facility borrowings		135,000			44,000			135,000			289,000
Repayment of revolving credit facility		(165,000	)		(72,000	)		(165,000	)		(515,000	)
Proceeds from issuance of Senior Notes								—			587,210
Proceeds from issuance of common stock		659,736			—			659,736			—
Debt issuance costs		(21	)		(232	)		(37	)		(8,796	)
Equity issuance costs		(299	)		—			(368	)		(136	)
Repurchase of equity grants		(207	)		(113	)		(1,656	)		(3,658	)
Dividends to shareholders								—			(3	)
Exercise of stock options		3			3			9			251

Net cash provided by (used in) financing activities		629,212			(28,342	)
Net cash provided by financing activities								627,684			348,868
Net change in cash and cash equivalents		469,524			436			34,359			135,255
Cash and cash equivalents at beginning of period		7,916			14,222			7,916			14,222

Cash and cash equivalents at end of period	$	477,440		$	14,658		$	42,275		$	149,477

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

Continental’s principal business is crude oil and natural gas exploration, development and production with operations 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, the Red River units and the Niobrara play in Colorado and Wyoming. The South region includes Kansas and all properties south of Kansas and west of the Mississippi river including the Anadarko Woodford and Arkoma Woodford plays in Oklahoma. The East region consists of properties east of the Mississippi river including the Illinois Basin and the state of Michigan.

The consolidated financial statements include the accounts of Continental and its wholly owned subsidiaries after all significant inter-company accounts and transactions have been eliminated.

This report has been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”) applicable to interim financial information. Because this is an interim period filing presented using a condensed format, it does not include all of the disclosures required by accounting principles generally accepted in the United States (“U.S. GAAP”), although the Company believes ~~that~~ the disclosures are adequate to make the information not misleading. You should read this Form 10-Q ~~along~~together with the Company’s Annual Report on Form 10-K for the year ended December 31, 2010 (“2010 Form 10-K”), which includes a summary of the Company’s significant accounting policies and other disclosures.

The financial statements as of ~~March 31,~~September 30, 2011 and for the three and nine month periods ended ~~March 31,~~September 30, 2011 and 2010 are unaudited. The condensed consolidated balance sheet as of December 31, 2010 was derived from the audited balance sheet filed in the 2010 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 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 of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. The most significant of the estimates and assumptions that affect reported results is the estimate of the Company’s crude oil and natural gas reserves, which is used to compute depreciation, depletion, amortization and impairment on producing 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 the entire year.

Inventories are stated at the lower of cost or market and consist of the following:


In thousands	March 31, 2011		December 31, 2010		September 30, 2011		December 31, 2010
Tubular goods and equipment	$	23,533	$	16,306	$	18,973	$	16,306
Crude oil		28,715		22,056		42,717		22,056

	$	52,248	$	38,362
Total					$	61,690	$	38,362

Crude oil inventories, including line fill, are valued at the lower of cost or market using the first-in, first-out inventory method. Crude oil inventories consist of the following volumes:


In barrels	March 31, 2011		December 31, 2010		September 30, 2011		December 31, 2010
Crude oil line fill requirements		272,000		257,000		374,000		257,000
Temporarily stored crude oil		205,000		148,000		339,000		148,000

		477,000		405,000
Total						713,000		405,000

Notes to Unaudited Condensed Consolidated Financial Statements ~~– continued~~

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 and dilutive stock options, which are calculated using the treasury stock method as if the awards and options were exercised. The following is the calculation of basic and diluted weighted average shares outstanding and net income ~~(loss)~~ per share for the three and nine months ended ~~March 31,~~September 30, 2011 and 2010:

The potential dilutive effect of 678,000 weighted average restricted shares and 103,000 weighted average stock options were not included in the calculation of diluted net loss per share for the three months ended March 31, 2011 because to do so would have been anti-dilutive.

A prior year amount has been reclassified on the condensed consolidated financial statements to conform to the 2011 presentation. On the unaudited condensed consolidated statements of cash flows for the three months ended March 31, 2010, the line item “Gain on sale of assets” was included in “Other, net” and has been shown separately in this report to conform to the 2011 presentation.

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


	Three months ended March 31,					Nine months ended September 30,
	2011		2010			2011			2010
	*In thousands*					*In thousands*
Supplemental cash flow information:
Cash paid for interest	$	15,908	$	2,263		$	69,658		$	17,218
Cash paid for income taxes	$	90	$	14		$	10,485		$	10,876
Cash received for income tax refunds	$	—	$	(1,285	)	$	(116	)	$	(1,288	)
Non-cash investing activities:
Asset retirement obligations	$	513	$	456
Asset retirement obligations, net						$	1,691		$	1,325

The Company is required to recognize 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 realized and unrealized changes in fair value onof derivative instruments in the unaudited condensed consolidated statements of ~~operations~~income under the caption “Gain (loss) on derivative instruments, net.”

The Company has utilized swap and collar derivative contracts to hedge against the variability in cash flows associated with the forecasted 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 ~~favorable~~upward price movements.

~~Notes to Unaudited Condensed Consolidated Financial Statements – continued~~

During the ~~three~~nine months ended ~~March 31,~~September 30, 2011, the Company entered into several new swap and collar derivative contracts covering a portion of its crude oil and natural gas production for 2011, 2012 and 2013. The new contracts were entered into in the ordinary course of business and the Company may enter into additional similar contracts ~~during~~in the ~~year.~~future. None of the new contracts have been designated for hedge accounting.

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 basis swap contract, which guarantees a price differential between the NYMEX prices and the Company’s physical pricing points, the Company receives a payment from the counterparty if the settled price differential is greater than the stated terms of the contract and the Company pays the counterparty if the settled price differential is less than the stated terms of the contract. 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 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.

All of the Company’s derivative contracts are carried at their fair value on 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 and subject to contractual terms which provide for net settlement are reported on a net basis on the condensed consolidated balance sheets. Substantially all of the crude oil and natural gas derivative contracts are settled based upon reported prices on the NYMEX. The estimated fair value of these contracts is based upon various factors, including closing exchange prices on the NYMEX, over-the-counter quotations, and, in the case of collars, volatility, the risk-free interest rate, and the time ~~value of options.~~to expiration. The calculation of the fair value of collars requires the use of an option-pricing model. SeeNote 5. Fair Value Measurements.

At ~~March 31,~~September 30, 2011, the Company had outstanding contracts with respect to future production as set forth in the tables below.

Notes to Unaudited Condensed Consolidated Financial Statements ~~– continued~~

The following table presents ~~information about the components of~~realized and unrealized gains and losses on derivative ~~fair value gain (loss)~~instruments for the periods presented.


	Three months ended March 31,						Three months ended September 30,						Nine months ended September 30,
	2011			2010			2011			2010			2011			2010
	*In thousands*						*In thousands*
Realized gain (loss) on derivatives:
Crude oil fixed price swaps	$	(3,095	)	$	2,531		$	(1,918	)	$	5,845		$	(9,894	)	$	13,275
Crude oil collars		(10,247	)		—			(5,364	)		825			(45,005	)		1,884
Natural gas fixed price swaps		8,126			2,722			8,395			6,373			23,918			16,628
Natural gas basis swaps		—			(961	)		—			(674	)		—			(2,323	)

Total realized gain (loss) on derivatives							$	1,113		$	12,369		$	(30,981	)	$	29,464
Unrealized gain (loss) on derivatives
Crude oil fixed price swaps		(165,043	)		(2,213	)	$	277,803		$	(17,538	)	$	199,939		$	(6,727	)
Crude oil collars		(195,088	)		(4,549	)		257,816			(28,640	)		210,300			6,445
Natural gas fixed price swaps		(3,956	)		28,326			608			9,258			(6,768	)		26,552
Natural gas basis swaps		—			488			—			368			—			1,892

Total unrealized gain (loss) on derivatives							$	536,227		$	(36,552	)	$	403,471		$	28,162

Gain (loss) on derivative instruments, net	$	(369,303	)	$	26,344		$	537,340		$	(24,183	)	$	372,490		$	57,626

The table below provides data about the fair value of derivatives that are not accounted for using hedge accounting.


	March 31, 2011								December 31, 2010								September 30, 2011						December 31, 2010
	Assets		(Liabilities)			Net			Assets		(Liabilities)			Net			Assets		(Liabilities)		Net		Assets		(Liabilities)			Net
*In thousands*	Fair Value		Fair Value			Fair Value			Fair Value		Fair Value			Fair Value			Fair Value		Fair Value		Fair Value		Fair Value		Fair Value			Fair Value
Commodity swaps and collars	$	17,409	$	(549,842	)	$	(532,433	)	$	21,365	$	(189,711	)	$	(168,346	)	$	235,125	$	—	$	235,125	$	21,365	$	(189,711	)	$	(168,346	)

The Company ~~is required to calculate~~follows Accounting Standards Codification Topic 820,Fair Value Measurements and Disclosures, which establishes a three-level valuation hierarchy for disclosure of fair value ~~based on a~~measurements. The valuation hierarchy ~~which prioritizes the inputs to valuation techniques used to measure~~categorizes assets and liabilities measured at fair value into one of three ~~levels.~~different levels depending on the observability of the inputs employed in the measurement. The ~~fair value hierarchy gives the highest priority to~~three levels are defined as follows:

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

Certain assets and liabilities are reported at fair value on a recurring ~~basis. The~~basis, including the Company’s ~~assessment~~derivative instruments. In determining the fair values of ~~the significance of~~fixed price swaps and basis swaps, a ~~particular input~~discounted cash flow method is used due to the ~~fair value measurement requires judgment, and may affect the valuation~~unavailability of ~~the fair~~

Notes to Unaudited Condensed Consolidated Financial Statements ~~– continued~~

~~value of assets and liabilities and their placement within the fair value hierarchy levels. In determining the fair value of fixed price swaps and basis swaps, due to the unavailability of~~ relevant comparable market data for the Company’s exact ~~contracts, a discounted cash flow method is used.~~contracts. The discounted cash flow method estimates future cash flows based on quoted market prices for ~~future~~forward commodity prices, observable inputs relating to basis differentials and a risk-adjusted discount rate. The fair ~~value~~values of fixed price swaps and basis ~~swap derivatives is~~swaps are calculated mainly using ~~mainly~~ significant observable inputs (Level 2). ~~The calculation~~Calculation of the fair ~~value~~values of collar contracts requires the use of an ~~option-pricing model with significant unobservable inputs (Level 3). The valuation model for~~industry-standard option ~~derivative contracts is an industry-standard~~pricing model that considers various inputs ~~including: (a)~~including quoted forward prices for commodities, ~~(b)~~ time value, ~~(c)~~ volatility factors, and ~~(d)~~ 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 for each ~~position~~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,~~September 30, 2011 and December 31, 2010. ~~There were no transfers between~~Transfers out of Level ~~1 and Level 2 of the fair value hierarchy~~3 during the three months ended ~~March 31, 2011. Further, there~~September 30, 2011 were ~~no transfers~~attributable to the Company’s ability to corroborate the volatility factors used to value its collar contracts with observable changes in ~~and/or out of~~forward commodity prices, which resulted in the Company transferring its collar contracts from Level 3 ofto Level 2 during the ~~fair value hierarchy during~~third quarter. The unrealized mark-to-market gain recognized in earnings on the collar contracts for the three months ended ~~March 31, 2011.~~September 30, 2011 amounted to $257.8 million.


	Fair value measurements at March 31, 2011 using:											Fair value measurements at September 30, 2011 using:
Description	Level 1		Level 2			Level 3			Total			Level 1		Level 2			Level 3			Total
	*in thousands*											*In thousands*
Derivative assets (liabilities):
Fixed price swaps	$	—	$	(233,927	)	$	—		$	(233,927	)	$	—	$	128,242		$	—		$	128,242
Collars		—		—			(298,506	)		(298,506	)		—		106,883			—			106,883

Total	$	—	$	(233,927	)	$	(298,506	)	$	(532,433	)	$	—	$	235,125		$	—		$	235,125

												Fair value measurements at December 31, 2010 using:
Description												Level 1		Level 2			Level 3			Total
												*In thousands*
Derivative assets (liabilities):
Fixed price swaps												$	—	$	(64,928	)	$	—		$	(64,928	)
Collars													—		—			(103,418	)		(103,418	)

Total												$	—	$	(64,928	)	$	(103,418	)	$	(168,346	)

The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the indicated periods:


	2011			2010			2011			2010
	*In thousands*						*In thousands*
Balance at January 1	$	(103,418	)	$	(3,275	)	$	(103,418	)	$	(3,275	)
Total realized or unrealized losses:
Total realized or unrealized gains (losses), net:
Included in earnings		(195,088	)		(4,549	)		(195,088	)		(4,549	)
Included in other comprehensive income		—			—			—			—
Purchases		—			—			—			—
Sales		—			—			—			—
Issuances		—			—			—			—
Settlements		—			—			—			—
Transfers into Level 3		—			—			—			—
Transfers out of Level 3		—			—			—			—

Balance at March 31	$	(298,506	)	$	(7,824	)	$	(298,506	)	$	(7,824	)
Total realized or unrealized gains (losses), net:
Included in earnings								147,573			39,634
Included in other comprehensive income								—			—
Purchases								—			—
Sales								—			—
Issuances								—			—
Settlements								—			—
Transfers into Level 3								—			—
Transfers out of Level 3								—			—

Change in unrealized losses relating to derivatives still held at March 31	$	(196,675	)	$	(4,549	)
Balance at June 30							$	(150,933	)	$	31,810
Total realized or unrealized gains (losses), net:
Included in earnings								—			(28,640	)
Included in other comprehensive income								—			—
Purchases								—			—
Sales								—			—
Issuances								—			—
Settlements								—			—
Transfers into Level 3								—			—
Transfers out of Level 3								150,933			—

Balance at September 30							$	—		$	3,170

Unrealized gains (losses) relating to derivatives still held at September 30							$	(49,102	)	$	6,631

Gains and losses included in earnings for the three and nine month periods ended ~~March 31,~~September 30, 2011 and 2010 attributable to the change in unrealized gains and losses relating to derivatives held at ~~March 31,~~September 30, 2011 and 2010 are reported in ~~“Revenues – Gain~~the unaudited condensed consolidated statements of income under the caption “Gain (loss) on derivative instruments, ~~net”.~~net.”

Certain assets and liabilities 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 and liabilities.

~~Notes to Unaudited Condensed Consolidated Financial Statements – continued~~

Asset Impairments – Proved crude oil and natural gas properties are reviewed for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such property. The estimated future cash flows expected in connection with the property are compared to the carrying amount of the property to determine if the carrying amount is recoverable. If the carrying amount of the property exceeds its estimated undiscounted future cash flows, the carrying amount of the property 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 ~~expectations for the future and includes~~ 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).

Non-producing crude oil and natural gas properties, which primarily consist of undeveloped leasehold costs and costs associated with the purchase of proved undeveloped reserves, are assessed for impairment on a property-by-property basis for individually significant balances, if any, and on an aggregate basis by prospect for individually insignificant balances. If the assessment indicates an impairment, a loss is recognized by providing a valuation allowance at the level consistent with the level at which impairment was assessed. The impairment assessment is affected by economic factors such as the results of exploration activities, commodity price outlooks, remaining lease terms, and potential shifts in business strategy employed by management. For individually insignificant non-producing properties, the amount of the impairment loss recognized is determined by amortizing the portion of the properties’ costs which management estimates will not be transferred to proved properties over the life of the lease based on experience of successful drilling and the average holding period. The impairment assessment is affected by economic factors such as the results of exploration activities, commodity price outlooks, remaining lease terms, and potential shifts in business strategy employed by management. The fair value of non-producing properties is calculated using significant unobservable inputs (Level 3).

Continental Resources, Inc. and ~~the commodity futures price strips, proved~~Subsidiaries

Proved properties were reviewed for impairment at ~~March 31,~~September 30, 2011. ~~No impairment provisions~~The Company determined the carrying amounts of certain proved properties were ~~recorded for the Company’s proved crude oil and natural gas properties for the three months ended March 31, 2011. For that period,~~not recoverable from future cash flows and, therefore, were ~~determined~~impaired. Impairments of proved properties amounted to be$7.6 million for the nine months ended September 30, 2011, all of which was recognized in ~~excess of cost basis, therefore no impairment was necessary. Certain~~the third quarter. Further, certain non-producing properties were impaired at ~~March 31,~~September 30, 2011, reflecting amortization of leasehold costs. The following table sets forth the pre-tax non-cash impairments of both proved and non-producing properties for the indicated periods. Proved and non-producing property impairments are recorded under the caption “Property impairments” in the unaudited condensed consolidated statements of ~~operations.~~income.


	Three months ended March 31,				Three months ended September 30,				Nine months ended September 30,
	2011		2010		2011		2010		2011		2010
	*In thousands*				*In thousands*
Proved property impairments	$	—	$	976	$	7,613	$	—	$	7,613	$	1,674
Non-producing property impairments		20,848		14,199		18,612		14,698		58,702		47,713

Total	$	20,848	$	15,175	$	26,225	$	14,698	$	66,315	$	49,387

Asset Retirement Obligations – The fair value of asset retirement obligations (AROs) is estimated based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding factors such ~~factors~~ as the existence of a legal obligation for an ARO, estimated probabilities, amounts and timing of settlements, the credit-adjusted risk-free rate to be used, and inflation rates. The fair values of ARO additions were ~~$0.6~~$0.7 million and ~~$0.4~~$2.4 million for the three and nine months ended ~~March 31,~~September 30, 2011, ~~and 2010,~~ respectively, which are reflected in the caption “Asset retirement obligations, net of current portion” in the condensed consolidated balance sheets. The fair values of AROs are calculated using significant unobservable inputs (Level 3).

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

~~Notes to Unaudited Condensed Consolidated Financial Statements – continued~~

The fair value of the revolving credit facility approximates its carrying value based on the borrowing rates available to the Company for bank loans with similar terms and maturities. The fair values of the 8¹/4% Senior Notes due 2019, the 7³/8% Senior Notes due 2020 and the 7¹/8% Senior Notes due 2021 are based on quoted market ~~prices.~~prices (Level 1).

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.


*In thousands*	March 31, 2011		December 31, 2010		September 30, 2011		December 31, 2010
Revolving credit facility	$	—	$	30,000	$	—	$	30,000
8¹/4% Senior Notes due 2019⁽¹⁾		297,740		297,696		297,833		297,696
7³/8% Senior Notes due 2020⁽²⁾		198,325		198,295		198,387		198,295
7¹/8% Senior Notes due 2021⁽³⁾		400,000		400,000		400,000		400,000

Total long-term debt	$	896,065	$	925,991	$	896,220	$	925,991

The Company had no debt outstanding at ~~March 31,~~September 30, 2011 on its revolving credit facility, ~~due~~which matures on July 1, 2015. At December 31, 2010, the Company had $30.0 million of outstanding borrowings on its revolving credit facility. The credit facility ~~has~~had aggregate commitments of ~~$750~~$750.0 million and a borrowing base of ~~$1.5~~$2.0 billion at September 30, 2011, subject to semi-annual redetermination. A borrowing base redetermination was completed in October 2011, whereby the lenders approved an increase in the borrowing base from $2.0 billion to $2.25 billion. The terms of the facility provide that the commitment level can be increased up to the lesser of the borrowing base then in effect or $2.5 billion. Borrowings under the facility bear interest, payable quarterly, at a rate per annum equal to the London Interbank Offered Rate (LIBOR) for one, two, three or six months, as elected by the Company, plus a margin ranging from 175 to 275 basis points, depending on the percentage of the borrowing base utilized, or the lead bank’s reference rate (prime) plus a margin ranging from 75 to 175 basis points. Borrowings are secured by the Company’s interest in at least 85% (by value) of all of its proved reserves and associated crude oil and natural gas properties.

The Company had ~~$747.6~~$747.0 million of unused commitments (after considering outstanding letters of credit) under its revolving credit facility at ~~March 31,~~September 30, 2011 and incurs commitment fees of 0.50% per annum of the daily average amount of unused borrowing availability. The credit agreement contains certain restrictive covenants including a requirement that the Company maintain a current ratio of not less than 1.0 to 1.0 and a ratio of total funded debt to EBITDAX of no greater than 3.75 to 1.0. As defined by the credit agreement, the current ratio represents the ratio of current assets to current liabilities, inclusive of available borrowing capacity under the credit agreement and exclusive of current balances associated with derivative contracts and asset retirement obligations. EBITDAX represents earnings before interest expense, income taxes, depreciation, depletion, amortization and accretion, property impairments, exploration expenses, unrealized derivative gains

~~Notes to Unaudited Condensed Consolidated Financial Statements – continued~~

and losses and non-cash equity compensation expense. EBITDAX is not a measure of net income or cash flows as determined by U.S. GAAP. A reconciliation of net income to EBITDAX is provided inPart I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Non-GAAP Financial Measures. The total funded debt to EBITDAX ratio represents the sum of outstanding borrowings and letters of credit on the revolving credit facility plus the Company’s senior note obligations, divided by total EBITDAX for the most recent four quarters. The Company was in compliance with all covenants at ~~March 31,~~September 30, 2011.

The 8¹/4% Senior Notes due 2019 (the “2019 Notes”), the 7³/8% Senior Notes due 2020 (the “2020 Notes”), and the 7¹/8% Senior Notes due 2021 (the “2021 Notes”) (collectively, the “Notes”) will mature on October 1, 2019, October 1, 2020, and April 1, 2021, respectively. Interest on the Notes is payable semi-annually on April 1 and October 1 of each year, with the payment of interest on the 2021 Notes having commenced on April 1, 2011. The Company has the option to redeem all or a portion of the 2019 Notes, 2020 Notes, and 2021 Notes at any time on or after October 1, 2014, October 1, 2015, and April 1, 2016, respectively, at the redemption prices specified in the Notes’ respective indentures (together, the “Indentures”) plus accrued and unpaid interest. The Company may also redeem the Notes, in whole or in part, at the “make-whole” redemption prices specified in the Indentures plus accrued and unpaid interest at any time prior to October 1, 2014, October 1, 2015, and April 1, 2016 for the 2019 Notes, 2020 Notes, and 2021 Notes, respectively. In addition, the Company may redeem up to 35% of the 2019 Notes, 2020 Notes, and 2021 Notes prior to October 1, 2012, October 1, 2013, and April 1, 2014, respectively, under certain circumstances with the net cash proceeds from certain equity offerings. The Notes are not subject to any mandatory redemption or sinking fund requirements.

The Indentures contain certain restrictions on the Company’s ability to incur additional debt, pay dividends on common stock, make certain investments, create certain liens on assets, engage in certain transactions with affiliates, transfer or sell certain assets, consolidate or merge, or sell substantially all of the Company’s assets. These covenants are subject to a number of important exceptions and qualifications. The Company was in compliance with these covenants at ~~March 31,~~September 30, 2011. One of the Company’s subsidiaries, Banner Pipeline Company, L.L.C., which currently has no independent assets or operations, fully and unconditionally guarantees the Notes. The Company’s other subsidiary, whose assets and operations are minor, does not guarantee the Notes.

Drilling commitments – As of ~~March 31,~~September 30, 2011, the Company had ~~various~~ drilling rig contracts with various terms extending through ~~June 2012.~~August 2014. 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 key strategic plays. These drilling commitments are not recorded in the accompanying condensed consolidated balance sheets. Future commitments as of ~~March 31,~~September 30, 2011 total approximately ~~$65~~$180 million, of which ~~$57~~$49 million is ~~for contracts that expire~~expected to be incurred in 2011, $88 million in 2012, $27 million in 2013, and $8$16 million ~~is for contracts that expire~~ in ~~2012.~~2014.

Fracturing and well stimulation services ~~arrangement~~agreement – ~~In August 2010, the~~The Company ~~entered into~~has an agreement with a third party whereby the third party will provide, on a take-or-pay basis, hydraulic fracturing services and related equipment to service certain of the Company’s properties in North Dakota and Montana. The ~~arrangement~~agreement has a term of three years, beginning in October 2010, with two one-year extensions available to the Company at its discretion. Pursuant to the take-or-pay ~~arrangement,~~provisions, the Company is to pay a fixed rate per day for a minimum number of days per calendar quarter over the three-year term regardless of whether or not the services are provided. The ~~arrangement~~agreement also stipulates ~~that~~ the Company will bear the cost of certain products and materials used. ~~Fixed commitments amount to $4.9 million per quarter, or $19.5 million annually, for total future commitments of $58.5 million over the three-year term.~~ Future commitments remaining as of ~~March 31,~~September 30, 2011 amount to ~~$48.7 million.~~approximately $45 million, of which $6 million is expected to be incurred in 2011, $22 million in 2012, and $17 million in 2013. The commitments under this ~~arrangement~~agreement are not recorded in the accompanying condensed consolidated balance sheets. Since the inception of this agreement, the Company has been using the services more than the minimum number of days each quarter.

~~Delivery~~Firm transportation commitments –In 2010, the Company ~~signed~~entered into a ~~throughput and deficiency agreement with a third party crude oil pipeline company committing~~five-year firm transportation commitment to ~~ship~~guarantee capacity totaling 10,000 barrels of crude oil per day on a major pipeline in order to reduce the impact of possible production curtailments that may arise due to limited transportation capacity. The transportation commitment is for ~~five years at~~crude oil production in the Bakken field where the Company allocates a ~~tariff~~significant portion of its capital expenditures. The commitment requires the Company to pay transportation reservation charges of $1.85 per ~~barrel. The third party system is scheduled to commence operations late~~barrel, or $6.8 million annually, regardless of the amount of pipeline capacity used. Payments under the agreement began in the second quarter of ~~2011.~~2011 in conjunction with the commencement of the pipeline system’s operations. To date, production delivered to the pipeline system has exceeded the daily volumes provided in the contract. The commitments under this agreement are not recorded in the accompanying condensed consolidated balance sheets. The Company ~~will use~~is not committed under this ~~system~~contract, or any other existing contract, to ~~move some~~deliver fixed and determinable quantities of ~~its North region~~ crude oil or natural gas in the future.

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 ~~market.~~plaintiffs and other royalty interest owners from crude oil and natural gas wells located in Oklahoma. The plaintiffs 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. The action is in preliminary stages and discovery has commenced. The Company is not currently able to estimate what impact, if any, the action will have on its financial condition, results of operations or cash flows given the preliminary status of 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 Company is involved in various other legal proceedings such as commercial disputes, claims from royalty and surface owners, property damage claims, personal injury claims and similar matters. While the outcome of these legal matters cannot be predicted with certainty, the Company does not expect them to have a material adverse effect on its financial condition, results of operations or cash flows. As of September 30, 2011 and December 31, 2010, the Company has recorded a liability in the condensed consolidated balance sheets under the caption “Other noncurrent liabilities” of $2.7 million and $4.6 million, respectively, for various matters, none of which are believed to be individually significant.

Employee retirement plan – The Company maintains a defined contribution retirement plan for its employees and makes ~~discretionary~~ contributions to the plan, up to the contribution limits established by the Internal Revenue Service, based on a percentage of each eligible employee’s compensation. During 2010, contributions to the plan were 5% of eligible employees’ compensation, excluding bonuses. Effective January 1, 2011, the Company’s contributions to the plan represent 3% of eligible employees’ compensation, including bonuses, in addition to matching 50% of eligible employees’ contributions up to 6%. Expenses associated with the plan amounted to ~~$0.9~~$2.2 million and ~~$0.3~~$1.0 million for the ~~three~~nine months ended ~~March 31,~~September 30, 2011, and 2010, respectively.

~~Notes to Unaudited Condensed Consolidated Financial Statements – continued~~

Employee health claims – The Company generally self-insures employee health claims up to the first $125,000 per employee per year. Amounts paid above this level are reinsured through third-party providers. The Company generally self-insures employee workers’ compensation claims up to the first ~~$250,000~~$300,000 per employee per claim. ~~Any amounts~~Amounts paid above ~~these levels~~this level are reinsured through third-party ~~providers.~~providers up to $1 million in excess of the self-insured retention. The Company accrues for claims that have been incurred but not yet reported based on a review of claims filed versus expected claims based on claims history. The accrued liability for health and workers’ compensation claims was ~~$2.1~~$2.7 million and $1.9 million at ~~March 31,~~September 30, 2011, and December 31, 2010, respectively.

~~Litigation –~~ In November 2010, a putative 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 from crude oil and natural gas wells located in Oklahoma. The plaintiffs seek recovery of compensatory damages, interest, punitive damages and attorney fees on behalf of the putative class. The Company has responded to the petition, denied the allegations and raised a number of affirmative defenses. The action is in very preliminary stages and discovery has recently commenced. As such, the Company is not able to estimate what impact, if any, the action will have on its financial condition, results of operations or cash flows.

The Company is involved in various other legal proceedings such as commercial disputes, claims from royalty and surface owners, property damage claims, personal injury claims and similar matters. While the outcome of these legal matters cannot be predicted with certainty, the Company does not expect them to have a material adverse effect on its financial condition, results of operations or cash flows. As of March 31, 2011 and December 31, 2010, the Company has recorded a liability in “Other noncurrent liabilities” of $4.5 million and $4.6 million, respectively, for various matters, none of which are believed to be individually significant.

Environmental Risk – Due to the nature of the crude oil and natural gas business, the Company is exposed to possible environmental risks. The Company is not aware of any material environmental issues or claims.

The Company has granted stock options and restricted stock to employees and directors pursuant to the Continental Resources, Inc. 2000 Stock Option Plan (“2000 Plan”) and the Continental Resources, Inc. 2005 Long-Term Incentive Plan (“2005 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 ~~operations,~~income, is reflected in the table below for the periods presented.

Effective October 1, 2000, the Company adopted the 2000 Plan and granted stock options to certain eligible employees. These grants consisted of either incentive stock options, nonqualified stock options or a combination of both. The granted stock options vest ratably over either a three or five-year period commencing on the first anniversary of the grant date and expire ten years from the date of grant. On November 10, 2005, the 2000 Plan was terminated. As of ~~March 31,~~September 30, 2011, options covering ~~2,213,193~~2,221,163 shares had been exercised and ~~535,893~~540,868 had been canceled.

The Company’s stock option activity under the 2000 Plan for the ~~three~~nine months ended ~~March 31,~~September 30, 2011 is presented below:


	Outstanding					Exercisable						Outstanding					Exercisable
	Number of stock options			Weighted average exercise price		Number of stock options			��	Weighted average exercise price		Number of stock options			Weighted average exercise price		Number of stock options			Weighted average exercise price
Outstanding at December 31, 2010		104,970		$	0.71		104,970			$	0.71		104,970		$	0.71		104,970		$	0.71
Exercised		(4,500	)		0.71		(4,500	)			0.71		(12,470	)		0.71		(12,470	)		0.71

Outstanding at March 31, 2011		100,470			0.71		100,470				0.71
Outstanding at September 30, 2011													92,500		$	0.71		92,500		$	0.71

The intrinsic value of a stock option is the amount by which the value of the underlying stock exceeds the exercise

~~Notes to Unaudited Condensed Consolidated Financial Statements – continued~~

price of the stock option at its exercise date. The total intrinsic value of stock options exercised during the ~~three~~nine months ended ~~March 31,~~September 30, 2011 was ~~approximately $0.3~~$0.7 million. At ~~March 31,~~September 30, 2011, all stock options were exercisable and had a weighted average remaining life of ~~1.0 year~~6 months with an aggregate intrinsic value of ~~$7.1~~$4.4 million.

On October 3, 2005, the Company adopted the 2005 Plan and reserved a maximum of 5,500,000 shares of common stock that may be issued pursuant to the 2005 Plan. As of ~~March 31,~~September 30, 2011, the Company had ~~2,955,988~~2,963,015 shares of restricted stock available to grant to directors, officers and key employees under the 2005 Plan. Restricted stock is awarded in the name of the recipient and except for the right of disposal, constitutes issued and outstanding shares of the Company’s common stock for all corporate purposes during the period of restriction including the right to receive dividends, subject to forfeiture. Restricted stock grants generally vest over periods ranging from one to three years.

A summary of changes in the non-vested shares of restricted stock for the ~~three~~nine months ended ~~March 31,~~September 30, 2011 is presented below:


	Number of non-vested shares			Weighted average grant-date fair value		Number of non-vested shares			Weighted average grant-date fair value
Non-vested restricted shares at December 31, 2010		1,108,077		$	35.72		1,108,077		$	35.72
Granted		47,480			68.31		79,060			67.07
Vested		(21,036	)		29.36		(95,713	)		37.89
Forfeited		(1,948	)		35.51		(20,434	)		38.99

Non-vested restricted shares at March 31, 2011		1,132,573			37.21
Non-vested restricted shares at September 30, 2011							1,070,990		$	37.78

The fair value of restricted stock represents the average of the high and low intraday market prices 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.~~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 the restricted stock that vested during the ~~three~~nine months ended ~~March 31,~~September 30, 2011 at the vesting date was ~~$1.3~~$6.2 million. As of ~~March 31,~~September 30, 2011, there was ~~$27.4~~$20.6 million of unrecognized compensation expense related to non-vested restricted stock. ~~The~~This expense is expected to be recognized ratably over a weighted average period of ~~1.5~~1.1 years.

On March 9, 2011, the Company and certain selling shareholders completed a public offering of an aggregate of 10,000,000 shares of the Company’s common stock, including 9,170,000 shares issued and sold by the Company and 830,000 shares sold by the selling shareholders, at a price of $68.00 per share ($65.45 per share, net of the underwriting discount). The net proceeds to the Company from the offering amounted to approximately ~~$599.8~~$599.7 million after deducting the underwriting discount and offering-related expenses. The Company did not receive any proceeds from the sale of shares by the selling shareholders. In connection with the offering, the Company granted the underwriters a 30-day overallotment option to purchase up to an additional 1,500,000 shares of common stock at the public offering price, less the underwriting discount, to cover overallotments, if any.

On March 25, 2011, the Company completed the sale of an additional 910,000 shares of its common stock at a price of $68.00 per share ($65.45 per share, net of the underwriting discount) in connection with the underwriters’ partial exercise of the overallotment option granted by the Company. The Company received additional net proceeds of approximately $59.5 million, after deducting the underwriting discount, from the partial exercise of the overallotment option. The selling shareholders did not participate in the partial exercise of the overallotment option.

The Company used ~~a portion of~~ the total net proceeds from the offering of $659.2 million to repay all amounts outstanding under its revolving credit facility and ~~expects~~ to ~~use the remaining net proceeds to accelerate the Company’s multi-year drilling program by funding~~fund a portion of its ~~increased~~ 2011 capital budget.

~~Notes to Unaudited Condensed Consolidated Financial Statements – continued~~

In March 2011, the Company assigned certain non-strategic leaseholds located in the state of Michigan to a third party for cash proceeds of $22.0 million. In connection with the transaction, the Company recognized a pre-tax gain of $15.3 ~~million.~~million which is included in the caption “(Gain) loss on sale of assets” in the unaudited condensed consolidated statements of income. The assignment involved undeveloped acreage with no proved reserves and no production or revenues.

On March 18, 2011, the Company executed an agreement to acquire ownership of 20 Broadway Associates LLC (“20 Broadway”), an entity wholly owned by the Company’s Chief Executive Officer and principal shareholder. 20 Broadway’s sole asset is an office building in Oklahoma City, Oklahoma where the Company intends to locate its corporate headquarters in 2012. The Company paid approximately $22.9 million for 20 Broadway, which is the amount the Company’s principal shareholder initially paid to acquire the office building in Oklahoma City, including the related commissions and closing costs. The transaction was approved by the Company’s Board of Directors.

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 our historical consolidated financial statements and the notes included in our Annual Report on Form 10-K for the year ended December 31, 2010. Our operating results for the periods discussed may not be indicative of future performance. The following discussion and analysis includes forward-looking statements and should be read in conjunction with ~~“Risk Factors”~~the risk factors described under ~~Part II,~~ the headingItem ~~1A of~~1A. Risk Factors included in this report and in our Annual Report on Form 10-K for the year ended December 31, 2010, along with “Cautionary Statement Regarding Forward-Looking Statements” at the beginning of this report, for information about the risks and uncertainties that could cause our actual results to be materially different than our forward-looking statements.

We are engaged in crude oil and natural gas exploration, ~~exploitation~~development and production activities 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, the Red River units and the Niobrara play in Colorado and Wyoming. The South region includes Kansas and all properties south of Kansas and west of the Mississippi river including the Anadarko Woodford and Arkoma Woodford plays in Oklahoma. The East region contains properties east of the Mississippi river including the Illinois Basin and the state of Michigan.

We focus our exploration activities in large new or developing plays that provide us the opportunity to acquire undeveloped acreage positions for future drilling operations. We have been successful in targeting large repeatable resource plays where horizontal drilling, advanced fracture stimulation and enhanced recovery technologies provide the means to economically develop and produce crude oil and natural gas reserves from unconventional formations. We derive the majority of our operating income and cash flows from the sale of crude oil and natural gas. We expect that growth in our revenues and operating income will primarily depend on product prices and our ability to increase our crude oil and natural gas production. In recent months and years, there has been significant volatility in crude oil and natural gas prices due to a variety of factors we cannot control or predict, including political and economic events, weather conditions, and competition from other energy sources. These factors impact supply and demand for crude oil and natural gas, which ~~affects~~affect crude oil and natural gas prices. In addition, the prices we realize for our crude oil and natural gas production are affected by ~~location~~price differences in ~~market prices.~~the markets where we deliver our production.

For the first ~~three~~nine months of 2011, our crude oil and natural gas production increased to ~~4,650~~15,661 MBoe ~~(51,663~~(57,365 Boe per day), up ~~1,191~~4,269 MBoe, or ~~34%~~37%, from the first ~~three~~nine months of 2010. Crude oil and natural gas production was 6,099 MBoe for the third quarter of 2011, a 24% increase over production of 4,912 MBoe for the second quarter of 2011 and a 48% increase over production of 4,119 MBoe for the third quarter of 2010. The increase in 2011 production was primarily driven by an increase in production from our properties in the North Dakota Bakken field and the Anadarko Woodford play in ~~Oklahoma.~~ Oklahoma due to the continued success of our drilling programs in those areas. Our Bakken production in North Dakota increased to 6,461 MBoe for the nine months ended September 30, 2011, an 86% increase over the comparable 2010 period. Our production in the Anadarko Woodford play totaled 1,268 MBoe in the first nine months of 2011, 598% higher than the first nine months of 2010.

Our crude oil and natural gas revenues for the first ~~three~~nine months of 2011 increased ~~50%~~69% to ~~$326.5~~$1,139.1 million due to a ~~15%~~25% increase in realized commodity prices along with increased production compared to the same period in 2010. For the 2011 third quarter, crude oil and natural gas revenues were $423.9 million, a 77% increase from the 2010 third quarter due to a 22% increase in realized commodity prices along with increased production. Our realized price per Boe increased ~~$9.07~~$14.43 to ~~$71.14~~$73.25 for the ~~three~~nine months ended ~~March 31,~~September 30, 2011 compared to the ~~three~~nine months ended ~~March~~September 30, 2010. For the 2011 third quarter, our realized price per Boe was $69.57, an increase of $12.65 compared to the 2010 third quarter.

The differential between NYMEX calendar month average crude oil prices and our realized crude oil price per barrel for the nine months ended September 30, 2011 was $7.00 compared to $8.68 for the nine months ended September 30, 2010 and $9.02 for the year ended December 31, 2010. ~~At various times, we have stored~~For the third quarter of 2011, the crude oil ~~due to pipeline line fill requirements, low commodity prices, or transportation constraints or we have sold crude oil from inventory. These actions result in differences between~~price differential was $5.62, an improvement over differentials of $6.59 for the second quarter of 2011 and $8.93 for the third quarter of 2010. A significant portion of our ~~produced and sold crude oil volumes. For the three months ended March 31, 2011, crude oil sales volumes were 60 MBbls less than~~operated crude oil production in the North region is being sold in markets other than Cushing, Oklahoma and ~~crude oil sales volumes were 40 MBbls more than crude oil production for the same period~~is priced, apart from transportation costs, at a premium to West Texas Intermediate benchmark pricing, which has resulted in ~~2010.~~ improved differentials.

Our cash flows from operating activities for the ~~three~~nine months ended ~~March 31,~~September 30, 2011 were ~~$195.6~~$669.8 million, an increase ~~of $4.9 million~~ from ~~$190.7~~$495.3 million provided by our operating activities during the comparable 2010 period. The increase in operating cash flows was primarily due to increased crude oil and natural gas revenues as a result of ~~higher~~increased commodity prices and sales ~~volumes.~~volumes, partially offset by an increase in realized losses on derivatives and higher production expenses, production taxes, and other operating expenses associated with the growth of our operations in the current year.

Our capital expenditures budget for 2011 is $2.0 billion. During the ~~three~~nine months ended ~~March 31,~~September 30, 2011, we have invested ~~$412.8~~$1,418.1 million in our capital program (including increased accruals for capital expenditures of ~~$31.1~~$117.8 million and ~~$4.3~~$14.4 million of seismic costs) ~~in our capital program,~~, concentrating mainly in the North Dakota Bakken field and the Anadarko Woodford ~~play in Oklahoma.~~

play. In ~~March~~November 2011, our Board of Directors increased our 2011 capital expenditures budget to $1.75 billion to further accelerate our drilling program and increase our acreage positions in strategic plays in the United States. Our previous 2011 capital expenditures budget was $1.36 billion. Our revised 2011approved a 2012 capital expenditures budget of $1.75 billion, a $250 million reduction from our 2011 capital budget. While our 2012 capital plan will continue to focus primarily on increased development in the North Dakota Bakken field and ~~the~~ Anadarko Woodford play, we plan to moderate our Bakken growth in ~~western Oklahoma.~~ 2012 and conserve capital while infrastructure is developed to accommodate industry growth in North Dakota.

Due to the volatility of crude oil and natural gas prices and our desire to ~~diligently~~ develop our substantial inventory of undeveloped reserves as part of our capital program, we have hedged a substantial portion of our forecasted production from our estimated proved reserves through 2013. We expect our cash flows from operations, our remaining cash balance, and the availability ~~under~~of our revolving credit facility will be sufficient to meet our capital expenditure needs for the next 12 months.

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

The following table contains financial and operating highlights for the periods presented.


	Three months ended March 31,					Three months ended September 30,				Nine months ended September 30,
	2011			2010		2011		2010		2011		2010
Average daily production:
Crude oil (Bbl per day)		38,446			29,121		47,552		33,432		42,160		31,404
Natural gas (Mcf per day)		79,297			55,839		112,423		68,057		91,231		61,948
Crude oil equivalents (Boe per day)		51,663			38,428		66,289		44,775		57,365		41,728
Average sales prices:⁽¹⁾
Crude oil ($/Bbl)	$	85.34		$	71.41	$	84.02	$	67.26	$	88.19	$	68.92
Natural gas ($/Mcf)		5.09			5.40		5.50		4.28		5.37		4.63
Crude oil equivalents ($/Boe)		71.14			62.07		69.57		56.92		73.25		58.82
Production expenses ($/Boe)⁽¹⁾		6.38			6.46		5.98		5.92		6.31		6.08
General and administrative expenses ($/Boe)^{(1) (2)}		3.56			3.39		2.98		2.90		3.32		3.09
Net income (loss) (in thousands)		(137,201	)		72,465
Diluted net income (loss) per share		(0.80	)		0.43
Net income (in thousands)							439,143		39,077		541,136		213,283
Diluted net income per share							2.44		0.23		3.05		1.26
EBITDAX (in thousands)⁽³⁾		268,655			175,583		337,754		196,917		892,040		589,962

Three months ended ~~March 31,~~September 30, 2011 compared to the three months ended ~~March 31,~~September 30, 2010

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


	Three months ended March 31,					Three months ended September 30,
	2011			2010		2011			2010
	*In thousands, except sales price data*					*In thousands, except sales price data*
Crude oil and natural gas sales	$	326,467		$	217,124	$	423,859		$	238,826
Gain (loss) on derivative instruments, net⁽¹⁾		(369,303	)		26,344		537,340			(24,183	)
Total revenues		(36,210	)		248,268		968,989			219,450
Operating costs and expenses⁽²⁾		166,683			123,739		(241,371	)		(143,094	)
Other expenses, net		18,462			7,654		(17,987	)		(12,375	)

Income (loss) before income taxes		(221,355	)		116,875
Provision (benefit) for income taxes		(84,154	)		44,410
Income before income taxes							709,631			63,981
Provision for income taxes							(270,488	)		(24,904	)

Net income (loss)	$	(137,201	)	$	72,465
Net income						$	439,143		$	39,077
Production volumes:
Crude oil (MBbl)⁽³⁾		3,460			2,621
Crude oil (MBbl)⁽²⁾							4,375			3,075
Natural gas (MMcf)		7,137			5,026		10,343			6,261
Crude oil equivalents (MBoe)		4,650			3,459		6,099			4,119
Sales volumes:
Crude oil (MBbl)⁽³⁾		3,400			2,661
Crude oil (MBbl)⁽²⁾							4,368			3,153
Natural gas (MMcf)		7,137			5,026		10,343			6,261
Crude oil equivalents (MBoe)		4,589			3,499		6,092			4,195
Average sales prices:⁽⁴⁾⁽³⁾
Crude oil ($/Bbl)	$	85.34		$	71.41	$	84.02		$	67.26
Natural gas ($/Mcf)	$	5.09		$	5.40		5.50			4.28
Crude oil equivalents ($/Boe)	$	71.14		$	62.07		69.57			56.92

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


	Three months ended March 31,																	Three months ended September 30,
	2011					2010					Volume increase			Percent increase				2011							2010							Volume increase			Percent increase
	Volume		Percent			Volume		Percent						Percent increase			Volume				Percent			Volume				Percent				Volume increase			Percent increase
Crude oil (MBbl)		3,460		74	%		2,621		76	%	Volume increase		839			32	%			4,375			72	%			3,075			75	%			1,300			42	%
Natural Gas (MMcf)		7,137		26	%		5,026		24	%		2,111			42	%			10,343			28	%			6,261			25	%			4,082			65	%

Total (MBoe)		4,650		100	%		3,459		100	%		1,191			34	%			6,099			100	%			4,119			100	%			1,980			48	%

	Three months ended March 31,										Volume increase (decrease)			Percent increase (decrease)				Three months ended September 30,														Volume increase (decrease)			Percent increase (decrease)
	2011					2010											2011							2010
	MBoe		Percent			MBoe		Percent									MBoe				Percent			MBoe				Percent
North Region		3,660		79	%		2,707		78	%			953			35	%			4,647			76	%			3,230			78	%			1,417			44	%
South Region		886		19	%		628		18	%			258			41	%			1,348			22	%			776			19	%			572			74	%
East Region		104		2	%		124		4	%		(20	)		(16	)%			104			2	%			113			3	%			(9	)		(8	%)

Total		4,650		100	%		3,459		100	%		1,191			34	%			6,099			100	%			4,119			100	%			1,980			48	%

Crude oil production volumes increased ~~32%~~42% during the three months ended ~~March 31,~~September 30, 2011 compared to the three months ended ~~March 31,~~September 30, 2010. Production increases in the North Dakota Bakken field ~~Red River units,~~ and the ~~Oklahoma~~Anadarko Woodford play contributed incremental production volumes in 2011 of ~~850~~1,165 MBbls, a ~~43%~~95% increase over production in these areas for the ~~first~~third quarter of 2010. ~~Favorable drilling results have been the primary contributors to production~~Production growth in these ~~areas.~~ areas is primarily due to increased drilling activity and higher well completions resulting from our accelerated drilling program for 2011. Additionally, production in the Cedar Hills field increased 61 MBbls, or 6%, in 2011 due to new wells being completed and enhanced recovery techniques being successfully applied in this legacy field.

Natural gas production volumes increased ~~2,111~~4,082 MMcf, or ~~42%~~65%, during the three months ended ~~March 31,~~September 30, 2011 compared to the same period in 2010. Natural gas production in the North Dakota Bakken field ~~in the North region was up 635~~increased 1,037 MMcf, or ~~62%~~100%, for the three months ended ~~March 31,~~September 30, 2011 compared to the same period in 2010 due to ~~additional~~new wells being completed and gas from existing wells being connected to natural gas ~~being connected and sold~~processing plants in North Dakota. We expect natural gas production growth in North Dakota Bakken to be further enhanced by the increased capacity of natural gas processing plants in the play, which will enable us to deliver more natural gas to market. Natural gas production in the ~~Oklahoma~~Anadarko Woodford ~~area~~play increased ~~1,196~~2,854 MMcf, or ~~52%~~427%, due to additional wells being completed and producing in the three months ended ~~March 31,~~September 30, 2011 compared to the same period in 2010.

Our total revenues are comprised of sales of crude oil and natural gas, revenues associated with crude oil and natural gas service operations, and realized and unrealized changes in the fair value of our derivative instruments. Throughout 2010 and 2011 we entered into a series of derivative instruments, including fixed price swaps and zero-cost collars, to reduce the uncertainty of future cash flows in order to underpin our capital expenditures and accelerated drilling program over the next three years. ~~The significant increase~~Changes in ~~the~~commodity futures price ~~of crude oil~~strips during the ~~three months ended March 31,~~third quarter of 2011 had ~~an adverse~~a positive impact on the fair value of our ~~derivative instruments,~~derivatives, which resulted in ~~negative~~positive revenue adjustments of ~~$369.3~~$537.3 million for the three months ended ~~March 31,~~September 30, 2011. The ~~adverse impact of the changes in our derivative instruments resulted in our total revenues being a negative $36.2~~$537.3 million ~~for the three months ended March 31, 2011. The $369.3 million negative~~positive adjustment ~~to revenue for the 2011 first quarter~~ includes ~~$5.2 million of net cash paid to our counterparties to settle derivatives and $364.1~~$536.2 million of unrealized non-cash mark-to-market ~~losses~~gains on open derivative ~~instruments. Excluding~~instruments and $1.1 million of realized gains on derivatives during the unrealized non-cash components resulting from mark-to-market changes in the fair value of our derivative instruments, our total revenues for the three months ended March 31, 2011 would have been a positive $327.9 million.quarter. The unrealized mark-to-market ~~loss~~gain relates to derivative instruments with various terms that are scheduled to be realized over the period from ~~April~~October 2011 through December 2013. Over this period, actual realized derivative settlements may differ significantly from the unrealized mark-to-market valuation at ~~March 31,~~September 30, 2011. We expect ~~that~~ our revenues will 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 crude oil and natural gas prices. While the existence of historically high commodity prices over a prolonged period could continue to have an adverse impact on the fair value of our derivative instruments and derivative settlements, such an adverse impact would be partially mitigated by increased revenues from higher realized sales prices of crude oil and natural gas at the wellhead.

Crude Oil and Natural Gas Sales. Crude oil and natural gas sales for the three months ended ~~March 31,~~September 30, 2011 were ~~$326.5~~$423.9 million, a ~~50%~~77% increase from sales of ~~$217.1~~$238.8 million for the same period in 2010. Our sales volumes increased ~~1,090~~1,897 MBoe, or ~~31%~~45%, over the same period in 2010 due to the continuing success of our drilling programs in the North Dakota Bakken field and Anadarko Woodford play. Our realized price per Boe increased ~~$9.07~~$12.65 to ~~$71.14~~$69.57 for the three months ended ~~March 31,~~September 30, 2011 from ~~$62.07~~$56.92 for the three months ended ~~March 31,~~September 30, 2010. The differential between NYMEX calendar month average crude oil prices and our realized crude oil price per barrel for the three months ended ~~March 31,~~September 30, 2011 was ~~$9.21~~$5.62 compared to ~~$7.42~~$8.93 for the three months ended ~~March 31,~~September 30, 2010 and $9.02 for the year ended December 31, 2010. ~~Factors contributing to the changing differentials included disruptions in Canadian~~A significant portion of our operated crude oil ~~delivery systems and other circumstances that impacted Canadian crude oil imports, increases in~~ production in the North region ~~downstream~~is being sold in markets other than Cushing, Oklahoma and is priced, apart from transportation ~~capacity constraints and demand fluctuations.~~costs, at a premium to West Texas Intermediate benchmark pricing, which has resulted in improved differentials.

Derivatives. We are required to recognize all derivative instruments on the balance sheet as either assets or liabilities measured at fair value. We have not designated our derivative instruments as hedges for accounting purposes. As a result, we mark our derivative instruments to fair value and recognize the realized and unrealized changes in fair value onof derivative instruments in the unaudited condensed consolidated statements of ~~operations~~income under the caption “Gain (loss) on derivative instruments, ~~net.”~~net”, which is a component of total revenues.

During the three months ended ~~March 31,~~September 30, 2011, we realized losses on crude oil derivatives of ~~$13.3~~$7.3 million and realized gains on natural gas derivatives of ~~$8.1~~$8.4 million. During the three months ended ~~March 31,~~September 30, 2011, we reported an unrealized non-cash mark-to-market ~~loss~~gains on crude oil derivatives of ~~$360.1~~$535.6 million and ~~an unrealized non-cash mark-to-market loss on~~ natural gas derivatives of ~~$4.0~~$0.6 million. During the three months ended ~~March 31,~~September 30, 2010, we realized gains on crude oil derivatives of ~~$2.5~~$6.7 million and ~~realized gains on~~ natural gas derivatives of ~~$1.8~~$5.7 million. During the three months ended ~~March 31,~~September 30, 2010, we reported an unrealized non-cash mark-to-market loss on crude oil derivatives of ~~$6.8~~$46.2 million and an unrealized non-cash mark-to-market gain on natural gas derivatives of ~~$28.8~~$9.6 million.

Crude Oil and Natural Gas Service Operations. Our crude oil and natural gas service operations consist primarily of the treatment and sale of lower quality crude oil, or reclaimed crude oil. The table below shows the volumes and prices for the sale of reclaimed crude oil for the periods presented.

Prices for reclaimed crude oil sold from our central treating units were $15.45 per barrel higher for the three months ended September 30, 2011 than the comparable 2010 period, which contributed to an increase in reclaimed crude oil revenue of $2.4 million to $5.8 million and contributed to an overall increase in crude oil and natural gas service operations revenue of $3.0 million for the three months ended September 30, 2011. Also contributing to the increase in crude oil and natural gas service operations revenue was a $0.3 million increase in saltwater disposal income resulting from increased activity. Associated crude oil and natural gas service operations expenses increased $1.3 million to $6.2 million during the three months ended September 30, 2011 from $4.9 million during the three months ended September 30, 2010 due mainly to an increase in the costs of purchasing and treating reclaimed crude oil for resale and in providing saltwater disposal services.

Production Expenses and Production Taxes and Other Expenses. Production expenses increased 47% to $36.5 million during the three months ended September 30, 2011 from $24.9 million during the three months ended September 30, 2010. This increase is primarily the result of higher production volumes from an increase in the number of producing wells. Production expense per Boe was $5.98 for the three months ended September 30, 2011 compared to $5.92 per Boe for the three months ended September 30, 2010.

Production taxes and other expenses increased $19.7 million, or 101%, to $39.3 million during the three months ended September 30, 2011 compared to the three months ended September 30, 2010 as a result of higher crude oil and natural gas revenues resulting from increased commodity prices and sales volumes along with the expiration of various tax incentives. Production taxes and other expenses in the unaudited condensed consolidated statements of income include other charges for marketing, gathering, dehydration and compression fees primarily related to natural gas sales in the Oklahoma Woodford and North Dakota Bakken areas of $5.2 million and $1.1 million for the three months ended September 30, 2011 and 2010, respectively. The increase in other charges is primarily due to the significant increase in natural gas sales volumes in the current period. Production taxes, excluding other charges, as a percentage of crude oil and natural gas revenues were 8.0% for the three months ended September 30, 2011 compared to 7.7% for the three months ended September 30, 2010. The increase is due to the expiration of various tax incentives coupled with higher taxable revenues in North Dakota, our most active area, which has production tax rates of up to 11.5% of crude oil revenues. Production taxes are generally based on the wellhead values of production and vary by state. Additionally, 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 activities such as horizontal drilling and enhanced recovery projects. In Montana and Oklahoma, new horizontal wells qualify for a tax incentive and are taxed at a lower rate during their initial months of production. After the incentive period expires, the tax rate increases to the statutory rate. Our overall production tax rate is expected to further increase as we continue to expand our operations in North Dakota and as production tax incentives we currently receive for horizontal wells reach the end of their incentive periods.

On a unit of sales basis, production expenses and production taxes and other expenses were as follows:

Exploration Expenses. Exploration expenses consist primarily of dry hole costs and exploratory geological and geophysical costs that are expensed as incurred. Exploration expenses increased $6.3 million in the three months ended September 30, 2011 to $9.8 million due primarily to a $7.0 million increase in seismic expenses resulting from higher acquisitions of seismic data in the current year in connection with our increased capital budget for 2011. This increase was partially offset by a $1.1 million decrease in dry hole expenses.

Depreciation, Depletion, Amortization and Accretion (“DD&A”). Total DD&A increased $42.2 million, or 67%, in the third quarter of 2011 compared to the third quarter of 2010, primarily due to a 48% increase in production volumes. The following table shows the components of our DD&A on a unit of sales basis.

The increase in DD&A per Boe is partially the result of a gradual shift in our production base from our historic base of the Red River units in the Cedar Hills field to newer production bases in the Bakken and Oklahoma Woodford plays. The producing properties in our newer areas typically carry higher DD&A rates due to the higher costs of developing reserves in those areas compared to our older, more mature properties.

Property Impairments. Property impairments increased in the three months ended September 30, 2011 by $11.5 million to $26.2 million compared to $14.7 million for the three months ended September 30, 2010.

Impairments of non-producing properties increased $3.9 million during the three months ended September 30, 2011 to $18.6 million compared to $14.7 million for the three months ended September 30, 2010, reflecting higher amortization of leasehold costs resulting from a larger base of amortizable costs. Non-producing properties consist of undeveloped leasehold costs and costs associated with the purchase of certain proved undeveloped reserves. Individually insignificant non-producing properties are amortized on an aggregate basis based on our estimated experience of successful drilling and the average holding period. We currently have no individually significant non-producing properties that are assessed for impairment on a property-by property basis.

Impairment provisions for proved crude oil and natural gas properties were $7.6 million for the three months ended September 30, 2011. We evaluate proved crude oil and natural gas properties for impairment by comparing their cost basis to the estimated future cash flows on a field basis. If the cost basis is in excess of estimated future cash flows, then we impair it based on an estimate of fair value based on discounted cash flows. Impairments of proved properties in 2011 primarily reflect uneconomic operating results for the first well drilled on our acreage in the Niobrara play in Colorado. No impairment provisions for proved properties were recognized for the three months ended September 30, 2010. For the 2010 period, future cash flows were determined to be in excess of cost basis, therefore no impairment was necessary.

General and Administrative Expenses. General and administrative expenses increased $6.0 million to $18.1 million during the three months ended September 30, 2011 from $12.1 million during the comparable period in 2010. On a volumetric basis, general and administrative expenses increased $0.08 to $2.98 per Boe for the three months ended September 30, 2011 compared to $2.90 per Boe for the three months ended September 30, 2010. General and administrative expenses include non-cash charges for stock-based compensation of $4.2 million and $2.6 million for the three months ended September 30, 2011 and 2010, respectively. General and administrative expenses excluding stock-based compensation increased $4.4 million for the three months ended September 30, 2011 compared to the same period in 2010. The increase was primarily related to an increase in personnel costs and office-related expenses associated with the growth of our Company. Over the past year, our Company has grown from having 470 total employees in September 2010 to 578 total employees in September 2011, a 23% increase. In March 2011, we announced plans to relocate our corporate headquarters from Enid, Oklahoma to Oklahoma City, Oklahoma. The move is a key element of our growth strategy of tripling our production and reserves between 2009 and 2014 and is expected to be completed during 2012. For the three months ended September 30, 2011, we have recognized approximately $1.1 million of costs in general and administrative expenses associated with the relocation. We currently expect to incur approximately $15 million to $25 million of costs in conjunction with the relocation, with the majority of such costs expected to be incurred in the second and third quarters of 2012.

Interest Expense. Interest expense increased $6.4 million, or 50%, for the three months ended September 30, 2011 compared to the three months ended September 30, 2010 due to increases in our weighted average outstanding long-term debt balance and our weighted average interest rate. Our weighted average interest rate for the three months ended September 30, 2011 was 7.6% with a weighted average outstanding long-term debt balance of $900.0 million compared to a weighted average interest rate of 6.2% with a weighted average outstanding long-term debt balance of $730.8 million for the same period in 2010. In September 2010, we issued $400 million of 7¹/8% Senior Notes and used a portion of the net proceeds to repay credit facility borrowings that carried lower interest rates.

We had no outstanding borrowings on our revolving credit facility as of September 30, 2011 or during the three months then ended, while our weighted average outstanding revolving credit facility balance amounted to $170.0 million for the three months ended September 30, 2010.

Income Taxes. We recorded income tax expense for the three months ended September 30, 2011 of $270.5 million compared to $24.9 million for the three months ended September 30, 2010. We provide for income taxes at a combined federal and state tax rate of approximately 38% after taking into account permanent taxable differences.

Nine months ended September 30, 2011 compared to the nine months ended September 30, 2010

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

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

Crude oil production volumes increased 34% during the nine months ended September 30, 2011 compared to the nine months ended September 30, 2010. Production increases in the North Dakota Bakken field and the Anadarko Woodford play contributed incremental production volumes in 2011 of 2,720 MBbls, an 88% increase over production in these areas for the same period in 2010. Production growth in these areas is primarily due to increased drilling activity and higher well completions resulting from our accelerated drilling program for 2011, which have offset the reduced production resulting from the abnormal rainfall and flooding experienced in North Dakota during the second quarter of 2011. Additionally, production in the Cedar Hills field increased 120 MBbls, or 4%, in 2011 due to new wells being completed and enhanced recovery techniques being successfully applied in this legacy field.

Natural gas production volumes increased 7,994 MMcf, or 47%, during the nine months ended September 30, 2011 compared to the same period in 2010. Natural gas production in the North Dakota Bakken field was up 2,186 MMcf, or 83%, for the nine months ended September 30, 2011 compared to the same period in 2010 due to new wells being completed and gas from existing wells being connected to natural gas processing plants in North Dakota. We expect natural gas production growth in North Dakota Bakken to be further enhanced by the increased capacity of natural gas processing plants in the play, which will enable us to deliver more natural gas to market. Natural gas production in the Anadarko Woodford play increased 5,171 MMcf, or 321%, due to additional wells being completed and producing in the nine months ended September 30, 2011 compared to the same period in 2010. Further, natural gas production increased 614 MMcf in non-Woodford areas of our South region due to the completion of new wells during the period.

Crude Oil and Natural Gas Sales. Crude oil and natural gas sales for the nine months ended September 30, 2011 were $1,139.1 million, a 69% increase from sales of $675.4 million for the same period in 2010. Our sales volumes increased 4,069 MBoe, or 35%, over the same period in 2010 due to the continuing success of our drilling programs in the North Dakota Bakken field and Anadarko Woodford play. Our realized price per Boe increased $14.43 to $73.25 for the nine months ended September 30, 2011 from $58.82 for the nine months ended September 30, 2010. The differential between NYMEX calendar month average crude oil prices and our realized crude oil price per barrel for the nine months ended September 30, 2011 was $7.00 compared to $8.68 for the nine months ended September 30, 2010 and $9.02 for the year ended December 31, 2010. A significant portion of our operated crude oil production in the North region is being sold in markets other than Cushing, Oklahoma and is priced, apart from transportation costs, at a premium to West Texas Intermediate benchmark pricing, which has resulted in improved differentials.

Derivatives. We are required to recognize all derivative instruments on the balance sheet as either assets or liabilities measured at fair value. We have not designated our derivative instruments as hedges for accounting purposes. As a result, we mark our derivative instruments to fair value and recognize the realized and unrealized changes in fair value of derivative instruments in the unaudited condensed consolidated statements of income under the caption “Gain (loss) on derivative instruments, net”, which is a component of total revenues.

During the nine months ended September 30, 2011, we realized losses on crude oil derivatives of $54.9 million and realized gains on natural gas derivatives of $23.9 million. During the nine months ended September 30, 2011, we reported an unrealized non-cash mark-to-market gain on crude oil derivatives of $410.2 million and an unrealized non-cash mark-to-market loss on natural gas derivatives of $6.7 million. During the nine months ended September 30, 2010, we realized gains on crude oil derivatives of $15.2 million and natural gas derivatives of $14.3 million. During the nine months ended September 30, 2010, we reported an unrealized non-cash mark-to-market loss on crude oil derivatives of $0.3 million and an unrealized non-cash mark-to-market gain on natural gas derivatives of $28.4 million.


	Three months ended March 31,							Nine months ended September 30,
Reclaimed crude oil sales	2011		2010		Variance			2011		2010		Increase
Average sales price ($/Bbl)	$	79.67	$	68.25	$	11.42		$	92.63	$	74.29	$	18.34
Sales volumes (barrels)		52,138		55,361		(3,223	)		192,000		167,000		25,000

Prices for reclaimed crude oil sold from our central treating units were ~~$11.42~~$18.34 per barrel higher for the ~~three~~nine months ended ~~March 31,~~September 30, 2011 than the comparable 2010 period, which contributed to an increase in reclaimed crude oil revenue of ~~$0.5~~$5.8 million to ~~$4.7~~$17.8 million ~~contributing~~and contributed to an overall increase in crude oil and natural gas service operations revenue of ~~$1.8~~$9.4 million for the ~~three~~nine months ended ~~March 31,~~September 30, 2011. Also contributing to the increase in crude oil and natural gas service operations revenue was a ~~$1.0~~$2.8 million increase in saltwater disposal income resulting from increased activity. Associated crude oil and natural gas service operations expenses increased ~~$1.5~~$6.7 million to ~~$5.5~~$19.7 million during the ~~three~~nine months ended ~~March 31,~~September 30, 2011 from ~~$4.0~~$13.0 million during the ~~three~~nine months ended ~~March 31,~~September 30, 2010 due mainly to an increase in the costs of purchasing and treating reclaimed crude oil for resale and in providing saltwater disposal services.

Production Expenses and Production Taxes and Other Expenses. Production expenses increased ~~30%~~41% to ~~$29.3~~$98.1 million during the ~~three~~nine months ended ~~March 31,~~September 30, 2011 from ~~$22.6~~$69.8 million during the ~~three~~nine months ended ~~March 31, 2010 due~~September 30, 2010. This increase is primarily tothe result of higher production ~~volumes.~~volumes from an increase in the number of producing wells. Production ~~expense~~expenses per Boe ~~decreased~~increased to ~~$6.38~~$6.31 for the ~~three~~nine months ended ~~March 31,~~September 30, 2011 from ~~$6.46~~$6.08 per Boe for the ~~three~~nine months ended ~~March 31,~~September 30, 2010. The ~~per unit decrease~~per-unit increase was ~~driven by longer natural production periods on certain~~primarily due to increases in well site and road maintenance costs and saltwater disposal costs in the second quarter, all resulting from abnormal rainfall and flooding in North Dakota ~~Bakken wells that resulted~~ in ~~lower artificial lifting~~April and May 2011. Also contributing to the per-unit increase were higher workover expenditures from increased activity as well as general inflationary pressure on the costs ~~positive secondary recovery efforts in the Cedar Hills field that have resulted in lower-cost improvements in production,~~of oilfield services and the conversion of certain high pressure air injection units to less costly waterflood units. We plan to convert some waterflood units to high pressure air injection units on certain fields during 2011, which may result in increased production expenses compared to 2010.equipment.

Production taxes and other expenses increased ~~$11.6~~$46.6 million, or ~~72%~~87%, to ~~$27.6~~$100.3 million during the ~~three~~nine months ended ~~March 31,~~September 30, 2011 compared to the ~~three~~nine months ended ~~March 31,~~September 30, 2010 as a result of higher crude oil and natural gas revenues resulting from increased commodity prices and sales volumes along with the expiration of various tax incentives. Production taxes and other expenses on the unaudited condensed consolidated statements of ~~operations~~income include other charges for marketing, gathering,

dehydration and compression fees primarily related to natural gas sales in the Oklahoma Woodford and North Dakota Bakken areas of ~~$2.2~~$10.0 million and ~~$1.1~~$3.9 million for the ~~three~~nine months ended ~~March 31,~~September 30, 2011 and 2010, respectively. The increase in other charges is primarily due to the significant increase in natural gas sales volumes in the current year. Production taxes, excluding other charges, as a percentage of crude oil and natural gas ~~sales~~revenues were ~~7.8%~~7.9% for the ~~three~~nine months ended ~~March 31,~~September 30, 2011 compared to ~~7.0%~~7.4% for the ~~three~~nine months ended ~~March 31,~~September 30, 2010. The increase is due to the expiration of various tax incentives coupled with higher taxable revenues in North Dakota, our most active area, which has production tax rates of up to 11.5% of crude oil revenues. Production taxes are generally based on the wellhead values of production and vary by state. Additionally, 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, new horizontal wells qualify for a tax incentive and are taxed at a lower rate during their initial months of production. After the incentive period expires, the tax rate increases to the statutory ~~rates.~~rate. Our overall production tax rate is expected to further increase as we continue to expand our operations in North Dakota and as production tax incentives we currently receive for horizontal wells reach the end of their incentive periods.

On a unit of sales basis, production expenses and production taxes and other expenses were as follows:


	Three months ended March 31,				Percent increase (decrease)			Nine months ended September 30,
*$/Boe*	2011		2010		Percent increase (decrease)			2011		2010
Production expenses	$	6.38	$	6.46		(1	)%	$	6.31	$	6.08
Production taxes and other expenses		6.01		4.58		31	%		6.45		4.68

Production expenses, production taxes and other expenses	$	12.39	$	11.04		12	%	$	12.76	$	10.76

Exploration Expenses. Exploration expenses consist primarily of dry hole costs and exploratory geological and geophysical costs that are expensed as incurred. Exploration expenses increased ~~$5.0~~$14.1 million in the ~~three~~nine months ended ~~March 31,~~September 30, 2011 to ~~$6.8~~$21.7 million due primarily to a ~~$1.5~~$1.8 million increase in dry hole expenses and ~~a $3.3~~an $11.3 million increase in seismic expenses resulting from higher acquisitions of seismic data in the current year in connection with our increased capital budget for 2011.

Depreciation, Depletion, Amortization and ~~Accretion (“DD&A”).~~Accretion. Total DD&A increased ~~$23.1~~$89.9 million, or ~~44%~~52%, in the first ~~quarter~~nine months of 2011 compared to the first ~~quarter~~nine months of 2010 primarily due to ana 37% increase in production volumes. The following table shows the components of our DD&A ~~rate per Boe.~~on a unit of sales basis.


	Three months ended March 31,				Nine months ended September 30,
*$/Boe*	2011		2010		2011		2010
Crude oil and natural gas	$	16.07	$	14.62	$	16.55	$	14.78
Other equipment		0.25		0.23		0.29		0.24
Asset retirement obligation accretion		0.17		0.18		0.15		0.17

Depreciation, depletion, amortization and accretion	$	16.49	$	15.03	$	16.99	$	15.19

The increase in DD&A per Boe is partially the result of a gradual shift in our production base from our historic ~~production~~ base of the Red River units in the Cedar Hills field to ~~our new~~newer production ~~base~~bases in the Bakken ~~field. Our~~and Oklahoma Woodford plays. The producing properties in ~~the Bakken field~~our newer areas typically carry a higher DD&A ~~rate~~rates due to the ~~existence of~~ higher cost of developing reserves in ~~that field~~those areas compared to ~~other areas in which we operate.~~our older, more mature properties.

Property Impairments. Property impairments ~~both proved and non-producing,~~ increased in the ~~three~~nine months ended ~~March 31,~~September 30, 2011 by ~~$5.6~~$16.9 million to ~~$20.8~~$66.3 million compared to ~~$15.2~~$49.4 million for the ~~three~~nine months ended ~~March 31,~~September 30, 2010.

~~Impairment~~Impairments of non-producing properties increased ~~$6.6~~$11.0 million during the ~~three~~nine months ended ~~March 31,~~September 30, 2011 to ~~$20.8~~$58.7 million compared to ~~$14.2~~$47.7 million for the ~~three~~nine months ended ~~March 31,~~September 30, 2010, reflecting higher amortization of leasehold costs resulting from a larger base of amortizable costs. Non-producing properties consist of undeveloped leasehold costs and costs associated with the purchase of certain proved undeveloped reserves. ~~Non-producing~~Individually insignificant non-producing properties are amortized on ~~a composite method~~an aggregate basis based on our estimated experience of successful drilling and the average holding period. We currently have no individually significant non-producing properties that are assessed for impairment on a property-by-property basis.

Impairment provisions for proved crude oil and natural gas properties were $7.6 million for the nine months ended September 30, 2011 compared to $1.7 million for the same period in 2010. We evaluate ~~our~~ proved crude oil and natural gas properties for impairment by comparing their cost basis to the estimated future cash flows on a field basis. If the cost basis is in excess of estimated future cash flows, then we impair it based on an estimate of fair value based on discounted cash flows. We did not record any impairment provisions for proved oil and gas properties for the three months ended March 31, 2011. For that period, future cash flows were determined to be in excess of cost basis, therefore no impairment was necessary. Impairment provisions for proved crude oil and natural gas properties were $1.0 million for the three months ended March 31, 2010. Impairments of proved properties in 2011 primarily reflect uneconomic operating results for the first well drilled on our acreage in the Niobrara play in Colorado. Impairments in 2010 reflect uneconomic operating results in the East region and a non-Bakken Montana field in the North region.

General and Administrative Expenses. General and administrative expenses increased ~~$4.5~~$16.2 million to ~~$16.3~~$51.7 million during the ~~three~~nine months ended ~~March 31,~~September 30, 2011 from ~~$11.8~~$35.5 million during the comparable period in 2010. On a volumetric basis, general and administrative expenses increased $0.23 to $3.32 per Boe for the nine months ended September 30, 2011 compared to $3.09 per Boe for the nine months ended September 30, 2010. General and administrative expenses include non-cash charges for stock-based compensation of ~~$3.6~~$11.7 million and ~~$2.9~~$8.6 million for the ~~three~~nine months ended ~~March 31,~~September 30, 2011 and 2010, respectively. General and administrative expenses excluding stock-based compensation increased ~~$3.8~~$13.1 million for the ~~three~~nine months ended ~~March 31,~~September 30, 2011 compared to the same period in 2010. The increase was primarily related to an increase in personnel costs and ~~office related~~office-related expenses associated with the growth of our Company. OnOver the past year, our Company has grown from having 470 total employees in September 2010 to 578 total employees in September 2011, a ~~volumetric basis,~~23% increase. In March 2011, we announced plans to relocate our corporate headquarters from Enid, Oklahoma to Oklahoma City, Oklahoma. The move is a key element of our growth strategy of tripling our production and reserves between 2009 and 2014 and is expected to be completed during 2012. For the nine months ended September 30, 2011, we have recognized approximately $1.5 million of costs in general and administrative expenses ~~increased $0.17~~associated with the relocation. We currently expect to ~~$3.56 per Boe for~~incur approximately $15 million to $25 million of costs in conjunction with the ~~three months ended March 31, 2011 compared~~relocation, with the majority of such costs expected to ~~$3.39 per Boe for~~be incurred in the ~~three months ended March 31, 2010.~~second and third quarters of 2012.

Interest Expense. Interest expense increased ~~$10.6~~$23.9 million, or ~~127%~~73%, for the ~~three~~nine months ended ~~March 31,~~September 30, 2011 compared to the ~~three months ended March 31,~~same period in 2010 due to ~~an increase~~increases in our weighted average outstanding long-term debt balance and ~~higher rates of~~our weighted average interest on our senior notes in the current year compared to lower interest rates on our credit facility borrowings in the prior year. We recorded $17.2 million in interest expense on the outstanding senior notes for the three months ended March 31, 2011 compared with $6.3 million for the same period in 2010. Including the interest on both the senior notes and revolving credit facility borrowings, ourrate. Our weighted average interest rate for the ~~three~~nine months ended ~~March 31,~~September 30, 2011 was ~~7.3%~~7.4% with a weighted average outstanding long-term debt balance of ~~$971.9~~$923.7 million compared to a weighted average interest rate of ~~6.1%~~6.6% with a weighted average outstanding long-term debt balance of ~~$511.7~~$612.1 million for the same period in 2010. We issued $200 million of 7³/8% Senior Notes in April 2010 and $400 million of 7¹/8% Senior Notes in September 2010, the net proceeds of which were used to repay credit facility borrowings that carried lower interest rates.

Our weighted average outstanding revolving credit facility balance decreased to ~~$71.9~~$23.7 million for the ~~three~~nine months ended ~~March 31,~~September 30, 2011 compared to ~~$211.7~~$161.2 million for the ~~three~~nine months ended ~~March 31,~~September 30, 2010. The weighted average interest rate on our revolving credit facility borrowings was ~~lower at~~ 2.65% for the ~~three~~nine months ended ~~March 31,~~September 30, 2011 compared to ~~2.75%~~2.66% for the same period in 2010. At ~~March 31,~~September 30, 2011, we had no outstanding borrowings on our revolving credit facility.

Income Taxes. We recorded ~~an income tax benefit for the three months ended March 31, 2011 of $84.2 million compared with~~ income tax expense for the nine months ended September 30, 2011 of ~~$44.4~~$333.7 million compared to $132.1 million for the ~~three~~nine months ended ~~March 31,~~September 30, 2010. We provide for income taxes at a combined federal and state tax rate of approximately 38% after taking into account permanent taxable differences.

Our primary sources of liquidity have been cash flows generated from operating activities, financing provided by our revolving credit facility and the issuance of debt and equity securities. During the first ~~three~~nine months of 2011, our average realized sales price was ~~$9.07~~$14.43 per Boe higher than the first ~~three~~nine months of 2010. The increase in realized commodity prices in the current year, coupled with our ~~31%~~35% increase in sales volumes for the first nine months of 2011 compared to the same period in 2010, resulted in improved cash flows from operations and better liquidity. Further, our liquidity has improved ~~at March 31,~~in 2011 as we have more borrowing availability on our revolving credit facility as a result of ~~refinancing~~repaying our credit facility borrowings through the issuance and sale of common stock in March 2011 as discussed below under the headingSale of Common Stock.

At ~~March 31,~~September 30, 2011, we had ~~approximately $477.4~~$42.3 million of cash and cash equivalents and ~~approximately $747.6~~$747.0 million of net available liquidity under our revolving credit facility ~~(after~~after considering outstanding letters of ~~credit).~~credit.

Our net cash provided by operating activities was ~~$195.6~~$669.8 million and ~~$190.7~~$495.3 million for the ~~three~~nine months ended ~~March 31,~~September 30, 2011 and 2010, respectively. The increase in operating cash flows was primarily due to higher crude oil and natural gas revenues as a result of higher commodity prices and sales volumes, partially offset by an increase in realized losses on derivatives and increases in production expenses, production taxes, and other operating expenses associated with the growth of our operations in the current ~~period.~~year.

During the ~~three~~nine months ended ~~March 31,~~September 30, 2011 and 2010, we had cash flows used in investing activities (excluding asset sales) of ~~$377.5~~$1,285.9 million and ~~$163.0~~$747.6 million, respectively, related to our capital program, inclusive of dry hole costs. The increase in ~~our~~ cash flows used in investing activities in 2011 was due to the continued acceleration of our drilling program, primarily in the North Dakota Bakken field and the Anadarko Woodford play in Oklahoma.

Net cash provided by financing activities for the ~~three~~nine months ended ~~March 31,~~September 30, 2011 was ~~$629.2~~$627.7 million and was ~~mainly~~ the result of the issuance and sale of an aggregate 10,080,000 shares of our common stock in March 2011 for total net proceeds of ~~approximately $659.3~~$659.4 million, after deducting underwriting discounts and offering-related expenses, ~~along with borrowings~~reduced by a net repayment of $30 million on ~~our credit facility, partially offset by amounts repaid under~~ our credit facility. Net cash ~~used in~~provided by financing activities of ~~$28.3~~$348.9 million for the ~~three~~nine months ended ~~March 31,~~September 30, 2010 was mainly the result of ~~amounts repaid under~~receiving $587.2 million of net proceeds from the issuances of the 2020 Notes in April 2010 and the 2021 Notes in September 2010, reduced by net repayments of $226 million on our credit facility.

We believe ~~that~~ funds from operating cash flows, our remaining cash balance, and our revolving credit facility should be sufficient to meet our cash requirements inclusive of, but not limited to, normal operating needs, debt service obligations, planned capital expenditures, and commitments and contingencies for the next 12 months.

Based on our planned production growth and ~~the existence of~~ derivative contracts we have in place to limit the downside risk of adverse price movements associated with the forecasted sale of future production, we currently anticipate ~~that~~ we will be able to generate or obtain funds sufficient to meet our short-term and long-term cash requirements. We intend to finance ~~our~~ future capital expenditures primarily through cash flows from operations and through borrowings under our revolving credit facility, but we may also ~~include the issuance of~~issue debt or equity securities or ~~the sale of~~sell assets. The issuance of additional debt ~~may require that~~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.

On March 9, 2011, we and certain selling shareholders completed a public offering of an aggregate of 10,000,000 shares of ~~our~~ common stock, including 9,170,000 shares issued and sold by us and 830,000 shares sold by the selling

shareholders, at a price of $68.00 per share ($65.45 per share, net of the underwriting discount). Our net proceeds from the offering amounted to approximately ~~$599.8~~$599.7 million after deducting the underwriting discount and offering-related expenses. We did not receive any proceeds from the sale of shares by the selling shareholders. In connection with the offering, we granted the underwriters a 30-day overallotment option to purchase up to an additional 1,500,000 shares of common stock at the public offering price, less the underwriting discount, to cover overallotments, if any.

On March 25, 2011, we completed the sale of an additional 910,000 shares of ~~our~~ common stock at a price of $68.00 per share ($65.45 per share, net of the underwriting discount) in connection with the underwriters’ partial exercise of the overallotment option. We received additional net proceeds of approximately $59.5 million, after deducting the underwriting discount, from the partial exercise of the overallotment option. The selling shareholders did not participate in the partial exercise of the overallotment option.

After deducting underwriting discounts and offering-related expenses, we received total net proceeds from the offering of ~~approximately $659.3~~$659.2 million, a portion of which was used to repay all amounts then outstanding under our revolving credit facility. The remaining net proceeds ~~the remaining~~were used to fund a portion of ~~which is reflected in “Cash and cash equivalents” in the condensed consolidated balance sheet at March 31, 2011, are expected to be used to accelerate~~ our ~~multi-year drilling program by funding our increased~~ 2011 capital budget.

We have ~~an existing~~a revolving credit facility with aggregate lender commitments totaling ~~$750~~$750.0 million and a current borrowing base of ~~$1.5~~$2.25 billion, subject to semi-annual redetermination. The most recent borrowing base redetermination was completed in October 2011, whereby the lenders approved an increase in the borrowing base from $2.0 billion to $2.25 billion. The aggregate commitment level may be increased at our option from time to time (provided no default exists) up to the lesser of $2.5 billion or the borrowing base then in effect. Borrowings under the facility bear interest, payable quarterly, at a rate per annum equal to the London Interbank Offered Rate (LIBOR) for one, two, three or six months, as elected by ~~the Company,~~us, plus a margin ranging from 175 to 275 basis points, depending on the percentage of the borrowing base utilized, or the lead bank’s reference rate (prime) plus a margin ranging from 75 to 175 basis points.

The commitments under our credit facility, which matures on July 1, 2015, are from a syndicate of 14 banks and financial institutions. We believe ~~that~~ each member of the current syndicate has the capability to fund its commitment. If one or more lenders cannot fund its commitment, we would not have the full availability of the ~~$750~~$750.0 million commitment.

We had no outstanding borrowings ~~under~~on our credit facility at ~~March 31,~~September 30, 2011 and $30.0 million outstanding at December 31, 2010. As of ~~March 31,~~September 30, 2011, we had ~~$747.6~~$747.0 million of borrowing availability under our credit facility (after considering outstanding letters of credit). As previously discussed, we issued and sold an aggregate 10,080,000 shares of our common stock in March 2011 and received total net proceeds of ~~approximately $659.3~~$659.2 million after deducting underwriting discounts and offering-related expenses. The net proceeds were used to repay all borrowings then outstanding under our credit facility, which had a balance prior to payoff of ~~$155 million.~~$155.0 million, with the remaining net proceeds being used to fund a portion of our 2011 capital budget. As of ~~May 2,~~October 31, 2011, we ~~continued to have no~~had $130.0 million of outstanding borrowings and ~~$747.6~~$617.2 million of borrowing availability under our credit facility.

Our credit facility contains restrictive covenants that may limit our ability to, among other things, incur additional indebtedness, sell assets, make loans to others, make investments, enter into mergers, change material contracts, incur liens and engage in certain other transactions without the prior consent of the lenders. Our credit agreement also contains requirements that we maintain a current ratio of not less than 1.0 to 1.0 and a ratio of total funded debt to EBITDAX of no greater than 3.75 to 1.0. As defined by our credit agreement, the current ratio represents our ratio of current assets to current liabilities, inclusive of available borrowing capacity under the credit agreement and exclusive of current balances associated with derivative contracts and asset retirement obligations. EBITDAX represents earnings before interest expense, income taxes, depreciation, depletion, amortization and accretion, property impairments, exploration expenses, unrealized derivative gains and losses and non-cash equity compensation expense. EBITDAX is not a measure of net income or cash flows as determined by U.S. GAAP. A reconciliation of net income to EBITDAX is provided subsequently under the captionNon-GAAP Financial Measures. The total funded debt to EBITDAX ratio represents the sum of outstanding borrowings and letters of credit under our revolving credit facility plus our senior note obligations, divided by total EBITDAX for the most recent four quarters. We were in compliance with these covenants at ~~March 31,~~September 30, 2011 and we expect to maintain compliance for at least the next 12 months. We do not believe the restrictive covenants ~~will limit, or~~ are reasonably likely to limit our ability to undertake additional debt or equity financing to a material extent.

In the future, we may not be able to access adequate funding under our credit facility as a result of (i) a decrease in our borrowing base due to the outcome of a subsequent borrowing base redetermination, or (ii) an unwillingness or inability

on the part of our lending counterparties to meet their funding obligations. We expect the next borrowing base redetermination to occur in the second quarter of ~~2011.~~2012. Declines in commodity prices could result in a determination to lower the borrowing base in the future and, in such case, we could be required to repay any indebtedness in excess of the borrowing base.

If we are unable to access funding when needed on acceptable terms, we may not be able to fully implement our business plans, complete new property acquisitions to replace our reserves, take advantage of business opportunities, respond to competitive pressures, or refinance our debt obligations as they come due, any of which could have a material adverse effect on our operations and financial results.

As part of our risk management program, we hedge a portion of our anticipated future crude oil and natural gas production to achieve more predictable cash flows and to reduce our exposure to fluctuations in crude oil and natural gas prices. Reducing our exposure to price volatility helps ensure ~~that we have~~ adequate funds are available for our capital program. Our decision on the quantity and price at which we choose to hedge our future production is based in part on our view of current and future market conditions and our desire to have the cash flows needed to fund the development of our inventory of undeveloped crude oil and natural gas reserves in conjunction with our growth strategy. While the use of hedging arrangements limits the downside risk of adverse price movements, their use also limits future revenues from ~~favorable~~upward price movements. Substantially all of our hedging transactions are settled based upon reported settlement prices on the NYMEX.

We have hedged a significant portion of our forecasted production through 2013. Please seeNote 4. Derivative InstrumentsinNotes to Unaudited Condensed Consolidated Financial Statements for further discussion of the accounting applicable to our derivative instruments, a ~~listing~~summary of open contracts at ~~March 31,~~September 30, 2011 and the estimated fair value of those contracts as of that date.

We evaluate opportunities to purchase or sell crude oil and natural gas properties and could 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.

~~In March~~Our capital expenditure budget for 2011 ~~our Board of Directors increased our 2011 capital expenditures budget to $1.75~~is $2.0 billion, ~~to further accelerate our drilling program and to increase our acreage positions in strategic resource plays. Our previous 2011 capital expenditures budget was $1.36 billion.~~

~~Our 2011 planned capital expenditures are~~which is expected to be allocated as follows:


	Amount		Amount
	*in millions*		*in millions*
Exploration and development drilling	$	1,521.5	$	1,735
Land costs		114.1		165
Capital facilities, workovers and re-completions		91.8		53
Buildings, vehicles, computers and other equipment				32
Seismic		15.0		15
Vehicles, computers and other equipment		7.6

Total	$	1,750.0	$	2,000

During the first ~~three~~nine months of 2011, we participated in the completion of 92361 gross ~~(31.1~~(124.6 net) wells and invested a total of ~~$412.8~~$1,418.1 million in our capital program (including increases in accruals for capital expenditures of ~~$31.1~~$117.8 million and ~~$4.3~~$14.4 million of seismic costs) ~~in our capital program~~ as shown in the following table.


	Amount		Amount
	*in millions*		*in millions*
Exploration and development drilling	$	327.8	$	1,169.7
Land costs		44.4		156.3
Capital facilities, workovers and re-completions		5.4		37.5
Buildings, vehicles, computers and other equipment		29.4		37.4
Acquisition of producing properties		—
Acquisitions of producing properties				2.8
Seismic		4.3		14.4
Dry holes		1.5

Total	$	412.8	$	1,418.1

Our 2011 capital ~~expenditures budget of $1.75 billion will focus~~program is focused primarily on increased development in the North Dakota Bakken field and the Anadarko Woodford play in western Oklahoma.

In November 2011, our Board of Directors approved a 2012 capital expenditures budget of $1.75 billion. Our 2012 planned capital expenditures are expected to be allocated as follows:

The 2012 capital plan will continue to focus primarily on increased development in the North Dakota Bakken field and Anadarko Woodford play. We plan to moderate our Bakken growth in 2012 and conserve capital while infrastructure is developed to accommodate industry growth in North Dakota, resulting in a decrease in our 2012 capital budget compared to 2011.

Although we cannot provide any assurance, assuming successful implementation of our strategy, including the future development of our proved reserves and realization of our cash flows as anticipated, we believe ~~that~~ our remaining cash balance, cash flows from operations and available borrowing capacity under our revolving credit facility will be sufficient to fund our 2011 and 2012 capital ~~budget.~~budgets. The actual amount and timing of our capital expenditures may differ materially from our estimates as a result of, among other things, available cash flows, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments.

As of ~~March 31,~~September 30, 2011, we had ~~various~~ drilling rig contracts with various terms extending through ~~June 2012.~~August 2014. These contracts were entered into in the ordinary course of business to ensure rig availability to allow us to execute our business objectives in our key strategic plays. These drilling commitments are not recorded in the accompanying condensed consolidated balance sheets. Future drilling commitments as of ~~March 31,~~September 30, 2011 total approximately ~~$65~~$180 million, of which ~~$57~~$49 million is ~~for contracts that expire~~expected to be incurred in 2011, $88 million in 2012, $27 million in 2013, and $8$16 million isin 2014. We expect to continue to enter into additional drilling rig contracts to help mitigate the risk of experiencing equipment shortages and rising costs that could delay our drilling projects or cause us to incur expenditures not provided for ~~contracts that expire~~ in ~~2012.~~our capital budget.

~~In August 2010, we entered into~~We have an agreement with a third party whereby the third party will provide, on a take-or-pay basis, hydraulic fracturing services and related equipment to service certain of our properties in North Dakota and Montana. The ~~arrangement~~agreement has a term of three years, beginning in October 2010, with two one-year extensions available ~~to us~~ at our discretion. Pursuant to the take-or-pay ~~arrangement,~~provisions, we will pay a fixed rate per day for a minimum number of days per calendar quarter over the three-year term regardless of whether or not the services are provided. ~~Fixed commitments amount to $4.9 million per quarter, or $19.5 million annually, for total future commitments of $58.5 million over the three-year term.~~ Future commitments remaining at ~~March 31,~~September 30, 2011 amount to ~~$48.7 million.~~approximately $45 million, of which $6 million is expected to be incurred in 2011, $22 million in 2012, and $17 million in 2013. The commitments under this ~~arrangement~~agreement are not recorded in the accompanying condensed consolidated balance sheets. Since the inception of this agreement, we have been using the services more than the minimum number of days each quarter.

In, 2010, we entered into a five-year firm transportation commitment to guarantee capacity totaling 10,000 barrels of crude oil per day on a major pipeline in order to reduce the impact of possible production curtailments that may arise due to limited transportation capacity. The transportation commitment is for crude oil production in the Bakken field where we allocate a significant portion of our capital expenditures. The commitment requires us to pay transportation reservation charges of $1.85 per barrel, or $6.8 million annually, regardless of the amount of pipeline capacity used. Payments under the agreement began in the second quarter of 2011 in conjunction with the commencement of the pipeline system’s operations. To date, production delivered to the pipeline system has exceeded the daily volumes provided in the contract. The commitments under this agreement are not recorded in the accompanying condensed consolidated balance sheets.

~~In 2010, the Company signed a throughput~~We are not committed under any existing contracts to deliver fixed and ~~deficiency agreement with a third party crude oil pipeline company committing to ship 10,000 barrels~~determinable quantities of crude oil ~~per day for five years at a tariff of $1.85 per barrel. The third party system is scheduled to commence operations late~~or natural gas in the ~~second quarter of 2011. The Company will use this system to move some of its North region crude oil to market.~~future.

We believe ~~that~~ our cash flows from operations, our remaining cash balance, and available borrowing capacity under our revolving credit facility will be sufficient to satisfy the above commitments.

OnIn March ~~21,~~ 2011, we announced plans to relocate our corporate headquarters from Enid, Oklahoma to Oklahoma City, Oklahoma. The move is a key element of our growth strategy of tripling our production and reserves between 2009 and 2014. The relocation is expected to provide more convenient access to our operations across the country, to our business partners and to an expanded pool of technical talent. The transition is expected to be completed during 2012. ~~In connection~~We currently estimate we may incur approximately $15 million to $25 million of costs in conjunction with our relocation. These costs will be incurred over the next 15 months through the end of 2012, with the relocation, we acquired an office building in Oklahoma City, Oklahoma in March 2011 for approximately $22.9 million to serve as our new headquarters. Currently, the relocation is in the preliminary stages and no significant restructuringmajority of such costs ~~or liabilities have been incurred or recognized as of March 31, 2011. We are not currently able to reasonably estimate the costs~~expected to be incurred in ~~2011 or 2012~~the second and third quarters of 2012. Over the next 15 months, we generally expect to recognize the majority of relocation costs in ~~connection with the relocation, but we do not expect such costs to have a material adverse effect on~~ our financial ~~condition, results~~statements when incurred. As of ~~operations or cash flows.~~September 30, 2011, we have recognized approximately $1.5 million of costs associated with our relocation efforts, which are included in the caption “General and administrative expenses” in the unaudited condensed consolidated statements of income.

There has been no change in our critical accounting policies from those disclosed in our Form 10-K for the year ended December 31, 2010.

~~Various accounting standards~~In May 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2011-04,Fair Value Measurement (Topic 820)–Amendments to Achieve Common Fair Value Measurement and ~~interpretations have been issued~~Disclosure Requirements in U.S. GAAP and IFRSs.The amendments in ASU No. 2011-04 are the result of the work by the FASB and the International Accounting Standards Board to develop common global requirements for measuring fair value and for disclosing information about fair value measurements to improve the comparability of financial statements prepared in accordance with U.S. GAAP and IFRS. Many of the amendments in ASU No. 2011-04 offer clarification to existing guidance and are not intended to result in significant changes in the application of the fair value measurement guidance of U.S. GAAP. The new standard is effective ~~dates in 2011. We have evaluated~~for the ~~recently issued accounting pronouncements that are effective in~~first interim or annual reporting period beginning after December 15, 2011 and ~~believe that none~~is required to be applied prospectively. We will adopt the requirements of ~~them~~ASU No. 2011-04 on January 1, 2012, which will require additional disclosures and is not expected to have a material effect on our financial position, results of operations or cash ~~flows when adopted.~~flows.

~~Further, we are~~We continue to closely ~~monitoring~~monitor the joint standard-setting efforts of the ~~Financial Accounting Standards Board~~FASB and the ~~International Accounting Standards Board.~~IASB. There are a ~~large~~ number of pending accounting standards ~~that are~~ being targeted for completion in 2011 and beyond, including, but not limited to, standards relating to revenue recognition, accounting for leases, ~~fair value measurements,~~ accounting for financial instruments, balance sheet offsetting, disclosure of loss contingencies and financial statement presentation. Because these pending standards have not yet been finalized, at this time we are not able to determine the potential future impact ~~that~~ these standards will have, if any, on our financial position, results of operations or cash flows.

EBITDAX represents earnings before interest expense, income taxes, depreciation, depletion, amortization and accretion, property impairments, exploration expenses, unrealized derivative gains and losses, and non-cash equity compensation expense. EBITDAX is not a measure of net income or cash flows as determined by U.S. GAAP. Management believes EBITDAX is useful because it allows ~~them~~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. We exclude the items listed above from net income 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 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. We believe ~~that~~ 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. Our revolving credit facility requires that we maintain a total funded debt to EBITDAX ratio of no greater than 3.75 to 1.0 on a rolling four-quarter basis. This ratio represents the sum of outstanding borrowings and letters of credit under our revolving credit facility plus our senior note obligations, divided by total EBITDAX for the most recent four quarters. We were in compliance with this covenant at ~~March 31,~~September 30, 2011. A violation of this covenant in the future could result in a default under our revolving credit facility. In the event of such default, the lenders under our revolving credit facility could elect to terminate their commitments thereunder, cease making further loans, and could declare all outstanding amounts, ~~together with accrued interest,~~if any, to be due and payable. If ~~the indebtedness~~we had any outstanding borrowings under our ~~revolving~~ credit facility and such indebtedness were to be accelerated, our assets may not be sufficient to repay in full such indebtedness. Our revolving credit facility defines EBITDAX consistently with the definition of EBITDAX utilized and presented by us. The following table provides a reconciliation of our net income to EBITDAX for the periods presented.


	Three months ended March 31,						Three months ended September 30,					Nine months ended September 30,
	2011			2010
	*in thousands*
Net income (loss)	$	(137,201	)	$	72,465
*in thousands*							2011			2010		2011			2010
Net income							$	439,143		$	39,077	$	541,136		$	213,283
Interest expense		18,971			8,360			18,981			12,612		56,737			32,875
Provision (benefit) for income taxes		(84,154	)		44,410
Provision for income taxes								270,488			24,904		333,685			132,071
Depreciation, depletion, amortization and accretion		75,650			52,587			105,085			62,918		264,236			174,327
Property impairments		20,848			15,175			26,225			14,698		66,315			49,387
Exploration expenses		6,812			1,786			9,814			3,530		21,660			7,585
Unrealized losses (gains) on derivatives		364,087			(22,052	)
Unrealized (gains) losses on derivatives								(536,227	)		36,552		(403,471	)		(28,162	)
Non-cash equity compensation		3,642			2,852			4,245			2,626		11,742			8,596

EBITDAX	$	268,655		$	175,583		$	337,754		$	196,917	$	892,040		$	589,962

General.We are exposed to a variety of market risks including commodity price risk, credit risk and interest rate risk. We 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 U.S. natural gas production. Pricing for crude oil and natural gas production 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~~nine months ended ~~March 31,~~September 30, 2011, and excluding any effect of our derivative instruments in place, our annual revenue would increase or decrease by approximately ~~$140.3~~$154 million for each $10.00 per barrel change in crude oil prices and ~~$28.9~~$33 million for each $1.00 per Mcf change in natural gas prices. To partially reduce price risk caused by these market fluctuations, we periodically hedge a portion of our anticipated crude oil and natural gas production as part of our risk management program and to provide greater certainty in our ~~internally generated~~ cash flows to support our capital expenditure program.

For the ~~three~~nine months ended ~~March 31,~~September 30, 2011, we realized a net loss on crude oil and natural gas derivatives of ~~$5.2~~$31.0 million and reported an unrealized non-cash mark-to-market ~~loss~~gain on derivatives of ~~$364.1~~$403.5 million. The fair value of our derivative instruments at ~~March 31,~~September 30, 2011 was a net ~~liability~~asset of ~~$532.4~~$235.1 million. An assumed increase in the forward commodity prices used in the ~~March 31,~~September 30, 2011 valuation of our derivative instruments of $10.00 per barrel for crude oil and $1.00 per MMBtu for natural gas would ~~increase~~change our derivative valuation to a net ~~derivative~~ liability toof approximately ~~$892~~$55 million at ~~March 31,~~September 30, 2011. Conversely, an assumed decrease in forward commodity prices of $10.00 per barrel for crude oil and $1.00 per MMBtu for natural gas would ~~decrease~~increase our net derivative ~~liability~~asset to approximately ~~$188~~$522 million at ~~March 31,~~September 30, 2011.

Throughout 2010 and 2011 we entered into a series of derivative instruments, including fixed price swaps and zero-cost collars, to reduce the uncertainty of future cash flows in order to underpin our capital expenditures and our accelerated drilling program ~~over the next three years. The significant increase~~through 2013. Changes in ~~the~~commodity futures price ~~of crude oil~~strips during the ~~three~~nine months ended ~~March 31,~~September 30, 2011 had an ~~adverse~~overall positive impact on the fair value of our derivative instruments, which resulted in the recognition of a ~~$364.1~~$403.5 million unrealized mark-to-market ~~loss~~gain on derivative instruments ~~at March 31,~~for the first nine months of 2011. The unrealized mark-to-market ~~loss~~gain relates to derivative instruments with various terms that are scheduled to be realized over the period from ~~April~~October 2011 through December 2013. Over this period, actual realized derivative settlements may differ significantly, either positively or negatively, from the unrealized mark-to-market valuation at ~~March 31,~~September 30, 2011. While the existence of historically high commodity prices over a prolonged period could continue to have an adverse impact on the fair value of our derivative instruments and derivative settlements, such an adverse impact would be partially mitigated by increased cash flows from higher realized sales prices of crude oil and natural gas at the wellhead.

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, refineries and affiliates ($~~266.6~~301.6 million in receivables at ~~March 31,~~September 30, 2011), our joint interest receivables ($~~293.9~~358.9 million at ~~March 31,~~September 30, 2011), and counterparty credit risk associated with our derivative instrument receivables ($~~17.4~~235.1 million at ~~March 31,~~September 30, 2011).

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 entities ~~who~~which own a partial interest in the wells we operate. These 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 ~~$57.6~~$74.2 million at ~~March 31,~~September 30, 2011, which will be used to offset future capital costs when billed. In this manner, we reduce credit risk. We also 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. Currently, ~~all of~~ our derivative contracts are with parties that are lenders (or affiliates of lenders) under our revolving credit agreement.

Interest Rate Risk. Our exposure to changes in interest rates relates primarily to any variable-rate borrowings we may have outstanding from time to time under our revolving credit facility. 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 no$130.0 million of outstanding borrowings under our revolving credit facility at ~~March~~October 31, 2011. The impact of a 1% increase in interest rates on this amount of debt would result in increased interest expense of approximately $1.3 million per year and a $0.8 million decrease in net income per year. Our revolving credit facility matures on July 1, 2015 and the weighted average interest rate at October 31, 2011 ~~or May 2, 2011.~~was 2.1%.

Based on management’s evaluation, under the supervision and with the participation of our principal executive officer and principal financial officer, as of the end of the period covered by this report, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures (which are defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) were effective as of ~~March 31,~~September 30, 2011. Disclosure controls and procedures include, without limitation, controls and procedures designed to provide reasonable assurance that the information required to be disclosed by us in the reports we file or submit under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and ~~our~~ Chief Financial Officer, to allow timely decisions regarding required disclosures and is recorded, processed, summarized and reported within the time period in the rules and forms of the SEC.

During the quarter ended ~~March 31,~~September 30, 2011, 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.

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.

During the ~~three~~nine months ended ~~March 31,~~September 30, 2011, there have been no material changes with respect to the legal proceedings previously disclosed in our 2010 Form ~~10-K.~~10-K that was filed with the SEC on February 25, 2011. SeeNote 7. Commitments and ContingenciesinNotes to Unaudited Condensed Consolidated Financial Statements of this Form 10-Q.

~~There~~Except as set forth below, there have been no material changes in our risk factors from those disclosed in our 2010 Form ~~10-K that was filed with the SEC on February 25, 2011.~~10-K.

In addition to the information set forth in this Form 10-Q, you should carefully consider the factors discussed inPart I, Item 1A. Risk Factors in our 2010 Form 10-K, which could materially affect our business, financial condition or future results. The risks described in this Form 10-Q and in our 2010 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.

Our business depends on crude oil and natural gas transportation facilities, most of which are owned by third parties, and on the availability of rail transportation.

The marketability of our crude oil and natural gas production depends in part on the availability, proximity and capacity of pipeline and rail systems owned by third parties. The unavailability of, or lack of, available capacity on these systems and facilities could result in the shut-in of producing wells or the delay, or discontinuance of, development plans for properties. Although we have some contractual control over the transportation of our product, material changes in these business relationships could materially affect our operations. Federal and state regulation of crude oil and natural gas production and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines and rail systems, labor disputes in the rail industry and general economic conditions could adversely affect our ability to produce, gather and transport crude oil and natural gas.

As a result of pipeline constraints and the continuous increase in Williston Basin production, we are transporting approximately 40% of the crude oil production from our North Region by rail. At October 31, 2011, eleven unions representing approximately 92,000 railway workers were unable to reach agreement on a new labor contract with more than 30 railroads. On October 6, 2011, President Obama appointed a Presidential Emergency Board to oversee contract talks, which effectively extends the period during which no job action is allowed for sixty days from that date or until early December 2011. In the event the relevant parties are unable to reach an agreement, a strike may occur in early December 2011.

The disruption of third-party pipelines or rail transportation facilities due to labor disputes, maintenance and/or weather could negatively impact our ability to market and deliver our products. We have no control over when or if such pipeline or rail facilities will be restored or what prices will be charged. A significant shut-in of production in connection with any of the aforementioned items could materially affect us due to a lack of cash flows, and if a substantial portion of the impacted production is hedged at lower than market prices, those financial hedges would have to be paid from borrowings absent sufficient cash flows.

The following table provides information about purchases of equity securities that are registered by us pursuant to Section 12 of the Exchange Act during the quarter ended ~~March 31,~~September 30, 2011:

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.

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.


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

302 N. Independence, Suite 1500, Enid, Oklahoma		73701
(Address of principal executive offices)		(Zip Code)


PART I. Financial Information
Item 1.	Financial Statements	71
	Condensed Consolidated Balance Sheets	71
	Unaudited Condensed Consolidated Statements of ~~Operations~~Income	82
	Condensed Consolidated Statements of Shareholders’ Equity	93
	Unaudited Condensed Consolidated Statements of Cash Flows	104
	Notes to Unaudited Condensed Consolidated Financial Statements	115
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	2216
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	3332
Item 4.	Controls and Procedures	3433

PART II. Other Information
Item 1.	Legal Proceedings	34
Item 1A.	Risk Factors	34
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	34
Item 3.	Defaults Upon Senior Securities	35
Item 4.	(Removed and Reserved)	35
Item 5.	Other Information	35	��
Item 6.	Exhibits	35
	Signature	36


Crude Oil					Collars
Period and Type of Contract	Bbls		Swaps Weighted Average		Floors				Ceilings
Period and Type of Contract	Bbls		Swaps Weighted Average		Range		Weighted Average		Range		Weighted Average
October 2011 - December 2011
Swaps		644,000	$	86.25
Collars		2,622,000			$	75.00-$80.00	$	79.39	$	89.00-$97.25	$	91.27
January 2012 - December 2012
Swaps		9,150,000	$	90.17
Collars		5,332,620			$	80.00	$	80.00	$	93.25-$97.00	$	94.71
January 2013 - December 2013
Swaps		5,110,000	$	88.63
Collars		8,760,000			$	80.00-$95.00	$	86.92	$	92.30-$110.33	$	99.46


Period and Type of Contract	Bbls		Swaps Weighted Average			Collars
						Floors				Ceilings
						Range		Weighted Average		Range		Weighted Average
April 2011 - June 2011
Swaps		273,000	$	84.67
Collars		2,593,500				$	75-$80	$	79.39	$	89.00-$97.25	$	91.27
July 2011 - September 2011
Swaps		460,000	$	85.64
Collars		2,622,000			��	$	75-$80	$	79.39	$	89.00-$97.25	$	91.27
October 2011 - December 2011
Swaps		644,000	$	86.25
Collars		2,622,000				$	75-$80	$	79.39	$	89.00-$97.25	$	91.27
January 2012 - December 2012
Swaps		8,235,000	$	88.36
Collars		5,332,620				$	80	$	80.00	$	93.25-$97.00	$	94.71
January 2013 - December 2013
Swaps		5,110,000	$	88.63
Collars		7,847,500				$	80-$95	$	85.98	$	92.30-$101.70	$	98.20


Natural Gas Period and Type of Contract	MMBtus		Swaps Weighted Average
October 2011 - December 2011
Swaps		7,222,000	$	5.40
January 2012 - December 2012
Swaps		3,660,000	$	5.07


Period	Total number of shares purchased⁽¹⁾		Average price paid per share ⁽²⁾		Total number of shares purchased as part of publicly announced plans or programs		Maximum number of shares that may yet be purchased under the plans or program ⁽³⁾
January 1, 2011 to January 31, 2011		1,016	$	57.40		—		—
February 1, 2011 to February 28, 2011		842	$	66.65		—		—
March 1, 2011 to March 31, 2011		1,314	$	70.91		—		—

Total		3,172	$	65.45		—		—


Period	Total number of shares purchased⁽¹⁾		Average price paid per share⁽²⁾		Total number of shares purchased as part of publicly announced plans or programs		Maximum number of shares that may yet be purchased under the plans or program⁽³⁾
July 1, 2011 to July 31, 2011		711	$	65.12		—		—
August 1, 2011 to August 31, 2011		6,429	$	64.04		—		—
September 1, 2011 to September 30, 2011		—	$	—		—		—

Total		7,140	$	64.15		—		—


~~1.1~~		Underwriting Agreement dated March 3, 2011 among Continental Resources, Inc., the Selling Shareholders and Merrill Lynch, Pierce, Fenner & Smith Incorporated and J.P. Morgan Securities LLC, as representatives of the underwriters named therein, filed as Exhibit 1.1 to the Company’s Current Report on Form 8-K (Commission File No. 001-32886) filed March 9, 2011 and incorporated herein by reference.

3.1		Third Amended and Restated Certificate of Incorporation 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 May 22, 2007 and incorporated herein by reference.

3.2		Second Amended and Restated Bylaws of Continental Resources, Inc. filed as Exhibit 3.2 to the Company’s Current Report on Form 8-K (Commission File No. 001-32886) filed May 22, 2007 and incorporated herein by reference.

~~10.1~~		Assignment of Membership Interest dated March 18, 2011 between Harold Hamm and Continental Resources, Inc. filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K (Commission File No. 001-32886) filed March 23, 2011 and incorporated herein by reference.

~~10.2*†~~		~~Summary of Non-Employee Director Compensation as of March 31, 2011.~~

21*		~~Subsidiaries of Continental Resources, Inc.~~

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

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