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)~~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

~~170,042,442~~180,533,094 shares of our $0.01 par value common stock were outstanding on ~~November 1, 2010.~~May 2, 2011.

When we refer to “us,” “we,” “our,” “Company,” or “Continental” we are describing Continental Resources, Inc. and/or our ~~subsidiary.~~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.~~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 or natural gas, ~~or crude oil,~~ or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

“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~~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. Enhanced recovery methods are often 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.

“~~FIFO~~~~.” (First in/First out) A cost flow assumption where the first (oldest) costs are assumed to flow out first. This means the latest (recent) costs remain on hand.~~

“Formation.” A layer of rock which has distinct characteristics that ~~differs~~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.

“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 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 gas shale, tight oil and gas sands and coalbed methane.

“Undeveloped acreage” Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of crude oil and/or natural gas.

“Unit.” The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.

“Working interest” The right granted to the lessee of a property to explore for and to produce and own crude oil, natural gas, or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.

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 ~~are based on~~ 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 heading ~~“Item~~Item 1A. Risk ~~Factors”~~Factors included in this report and in our Annual Report on Form 10-K for the year ended December 31, ~~2009.~~2010.

~~These forward-looking statements reflect management’s current belief, based on currently available information, as to the outcome and timing of future events.~~ 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 under ~~“Item~~Part II,Item 1A. Risk ~~Factors”~~Factors in this report, our Annual Report on Form 10-K for the year ended December 31, ~~2009,~~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 ~~all of which are expressly qualified by the statements in this section,~~ to reflect events or circumstances after the date of this report.


*In thousands, except par values and share data*	September 30, 2010		December 31, 2009
					March 31, 2011		December 31, 2010
					*(Unaudited)*
	(Unaudited)				*In thousands, except par values and share data*
Assets
Current assets:
Cash and cash equivalents	$	149,477	$	14,222	$	477,440	$	7,916
Receivables:
Oil and natural gas sales		162,299		119,565
Crude oil and natural gas sales						260,570		208,211
Affiliated parties		11,885		7,823		17,038		20,156
Joint interest and other, net		202,144		55,970		282,861		254,471
Derivative assets		34,849		2,218		17,360		21,365
Inventories		31,056		26,711		52,248		38,362
Deferred and prepaid taxes		15		4,575		84,004		22,672
Prepaid expenses and other		6,295		4,944		9,724		9,173

Total current assets		598,020		236,028		1,201,245		582,326
Net property and equipment, based on successful efforts method of accounting		2,703,867		2,068,055		3,285,824		2,981,991
Debt issuance costs, net		28,076		10,844		26,342		27,468
Noncurrent derivative assets		4,662		—		49		—

Total assets	$	3,334,625	$	2,314,927	$	4,513,460	$	3,591,785


Liabilities and shareholders’ equity
Current liabilities:
Accounts payable trade	$	313,348	$	91,248	$	425,812	$	390,892
Revenues and royalties payable		95,505		66,789		174,620		133,051
Payables to affiliated parties		2,804		9,612		4,263		4,438
Accrued liabilities and other		112,888		49,601		106,357		94,829
Derivative liabilities						232,884		76,771
Current portion of asset retirement obligations		2,761		2,460		2,270		2,241

Total current liabilities		527,306		219,710		946,206		702,222
Long-term debt		895,917		523,524		896,065		925,991
Other noncurrent liabilities:
Deferred income tax liabilities		593,161		489,241		559,929		582,841
Asset retirement obligations, net of current portion		49,718		47,707		55,141		54,079
Noncurrent derivative liabilities		13,438		—		316,958		112,940
Other noncurrent liabilities		6,334		4,466		5,468		5,557

Total other noncurrent liabilities		662,651		541,414		937,496		755,417
Commitments and contingencies (Note 8)
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; 170,099,358 shares issued and outstanding at September 30, 2010; 169,968,471 shares issued and outstanding at December 31, 2009		1,701		1,700
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		435,471		430,283		1,102,538		439,900
Retained earnings		811,579		598,296		629,350		766,551

Total shareholders’ equity		1,248,751		1,030,279		1,733,693		1,208,155

Total liabilities and shareholders’ equity	$	3,334,625	$	2,314,927	$	4,513,460	$	3,591,785

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


	Three months ended September 30,						Nine months ended September 30,						Three months ended March 31,
*In thousands, except per share data*	2010			2009			2010			2009
													2011			2010
													*In thousands, except per share data*
Revenues:
Oil and natural gas sales	$	232,662		$	162,465		$	651,925		$	389,310
Oil and natural gas sales to affiliates		6,164			5,907			23,451			18,069
Gain (loss) on mark-to-market derivative instruments		(24,183	)		(2,105	)		57,626			(1,215	)
Oil and natural gas service operations		4,807			3,937			14,684			12,409
Crude oil and natural gas sales													$	316,740		$	208,059
Crude oil and natural gas sales to affiliates														9,727			9,065
Gain (loss) on derivative instruments, net														(369,303	)		26,344
Crude oil and natural gas service operations														6,626			4,800

Total revenues		219,450			170,204			747,686			418,573			(36,210	)		248,268

Operating costs and expenses:
Production expenses		23,626			17,536			64,044			56,269			28,398			19,159
Production expenses to affiliates		1,231			5,183			5,762			12,914			872			3,442
Production taxes and other expenses		19,517			12,378			53,755			30,829			27,562			16,007
Exploration expenses		3,530			1,077			7,585			9,726			6,812			1,786
Oil and natural gas service operations		4,935			2,326			12,982			7,423
Crude oil and natural gas service operations														5,451			3,956
Depreciation, depletion, amortization and accretion		62,918			51,030			174,327			154,875			75,650			52,587
Property impairments		14,698			11,791			49,387			70,491			20,848			15,175
General and administrative expenses		12,148			10,049			35,491			29,684			16,347			11,849
(Gain) loss on sale of assets		491			(452	)		(32,855	)		(673	)
Gain on sale of assets														(15,257	)		(222	)

Total operating costs and expenses		143,094			110,918			370,478			371,538			166,683			123,739

Income from operations		76,356			59,286			377,208			47,035
Income (loss) from operations														(202,893	)		124,529
Other income (expense):
Interest expense		(12,612	)		(4,763	)		(32,875	)		(14,073	)		(18,971	)		(8,360	)
Other		237			194			1,021			642			509			706

		(12,375	)		(4,569	)		(31,854	)		(13,431	)		(18,462	)		(7,654	)

Income before income taxes		63,981			54,717			345,354			33,604
Provision for income taxes		24,904			19,788			132,071			11,780
Income (loss) before income taxes														(221,355	)		116,875
Provision (benefit) for income taxes														(84,154	)		44,410

Net income	$	39,077		$	34,929		$	213,283		$	21,824
Net income (loss)													$	(137,201	)	$	72,465

Basic net income per share	$	0.23		$	0.21		$	1.26		$	0.13
Diluted net income per share	$	0.23		$	0.21		$	1.26		$	0.13
Basic net income (loss) per share													$	(0.80	)	$	0.43
Diluted net income (loss) per share													$	(0.80	)	$	0.43

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


*In thousands, except share data*	Shares outstanding			Common Stock			Additional paid-in Capital			Retained earnings		Total shareholders’ Equity
Balance, January 1, 2009		169,558,129		$	1,696		$	420,054		$	526,958	$	948,708
															Shares outstanding			Common stock			Additional paid-in capital			Retained earnings			Total shareholders’ equity
															*In thousands, except share data*
Balance, December 31, 2009																169,968,471		$	1,700		$	430,283		$	598,296		$	1,030,279
Net income		—			—			—			71,338		71,338			—			—			—			168,255			168,255
Excess tax benefit on stock-based compensation																—			—			5,230			—			5,230
Stock-based compensation		—			—			11,408			—		11,408			—			—			11,691			—			11,691
Tax benefit on stock-based compensation plan		—			—			2,872			—		2,872
Stock options:
Exercised		138,010			1			244			—		245			207,220			2			255			—			257
Repurchased and canceled		(29,924	)		—			(1,223	)		—		(1,223	)		(59,877	)		(1	)		(2,661	)		—			(2,662	)
Restricted stock:
Issued		411,217			4			—			—		4			449,114			4			—			—			4
Repurchased and canceled		(83,457	)		(1	)		(3,072	)		—		(3,073	)		(100,561	)		(1	)		(4,898	)		—			(4,899	)
Forfeited		(25,504	)		—			—			—		—			(55,715	)		—			—			—			—

Balance, December 31, 2009		169,968,471		$	1,700		$	430,283		$	598,296	$	1,030,279
Net income (unaudited)		—			—			—			213,283		213,283
Balance, December 31, 2010																170,408,652		$	1,704		$	439,900		$	766,551		$	1,208,155
Net income (loss) (unaudited)																—			—			—			(137,201	)		(137,201	)
Public offering of common stock (unaudited)																10,080,000			101			659,200			—			659,301
Stock-based compensation (unaudited)		—			—			8,596			—		8,596			—			—			3,642			—			3,642
Stock options:
Exercised (unaudited)		199,250			2			249			—		251			4,500			—			3			—			3
Repurchased and canceled (unaudited)		(57,397	)		(1	)		(2,540	)				(2,541	)
Restricted stock:
Issued (unaudited)		60,667			1			—			—		1			47,480			—			—			—			—
Repurchased and canceled (unaudited)		(23,684	)		—			(1,117	)		—		(1,117	)		(3,172	)		—			(207	)		—			(207	)
Forfeited (unaudited)		(47,949	)		(1	)		—			—		(1	)		(1,948	)		—			—			—			—

Balance, September 30, 2010 (unaudited)		170,099,358		$	1,701		$	435,471		$	811,579	$	1,248,751
Balance, March 31, 2011 (unaudited)																180,535,512		$	1,805		$	1,102,538		$	629,350		$	1,733,693

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


	Nine months ended September 30,						Three months ended March 31,
*In thousands*	2010			2009
							2011			2010
							*In thousands*
Cash flows from operating activities:
Net income	$	213,283		$	21,824
Adjustments to reconcile net income to net cash provided by operating activities:
Net income (loss)							$	(137,201	)	$	72,465
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion		173,321			157,696			76,762			52,179
Property impairments		49,387			70,491			20,848			15,175
Change in fair value of derivatives		(28,162	)		1,215			364,087			(22,052	)
Stock-based compensation		8,596			8,594			3,642			2,852
Provision for deferred income taxes		116,165			11,780
Provision (benefit) for deferred income taxes								(84,154	)		40,416
Dry hole costs		1,943			5,002			1,504			33
Gain on sale of assets		(32,855	)		(673	)		(15,257	)		(222	)
Other, net		3,631			1,726			929			956
Changes in assets and liabilities:
Accounts receivable		(192,970	)		70,518			(77,631	)		(61,044	)
Inventories		(4,345	)		(13,038	)		(13,886	)		(363	)
Prepaid expenses and other		2,105			21,193			(513	)		4,030
Accounts payable trade		99,869			(115,194	)		3,648			69,719
Revenues and royalties payable		28,716			(22,465	)		41,569			7,574
Accrued liabilities and other		54,008			(4,275	)		11,340			8,932
Other noncurrent liabilities		2,648			1,601			(52	)		38

Net cash provided by operating activities		495,340			215,995			195,635			190,688

Cash flows from investing activities:
Exploration and development		(719,843	)		(372,284	)		(348,011	)		(156,625	)
Purchase of oil and natural gas properties		(7,319	)		(1,217	)
Purchase of crude oil and natural gas properties								—			(128	)
Purchase of other property and equipment		(20,453	)		(4,682	)		(29,443	)		(6,263	)
Proceeds from sale of assets		38,662			2,762			22,131			1,106

Net cash used in investing activities		(708,953	)		(375,421	)		(355,323	)		(161,910	)

Cash flows from financing activities:
Revolving credit facility borrowings		289,000			372,100			135,000			44,000
Repayment of revolving credit facility		(515,000	)		(502,500	)		(165,000	)		(72,000	)
Proceeds from issuance of Senior Notes		587,210			297,480
Proceeds from issuance of common stock								659,736			—
Debt issuance costs		(8,932	)		(9,826	)		(21	)		(232	)
Equity issuance costs								(299	)		—
Repurchase of equity grants		(3,658	)		(717	)		(207	)		(113	)
Dividends to shareholders		(3	)		(8	)
Exercise of stock options		251			141			3			3
Other debt		—			2,822

Net cash provided by financing activities		348,868			159,492
Net cash provided by (used in) financing activities								629,212			(28,342	)
Net change in cash and cash equivalents		135,255			66			469,524			436
Cash and cash equivalents at beginning of period		14,222			5,229			7,916			14,222

Cash and cash equivalents at end of period	$	149,477		$	5,295		$	477,440		$	14,658

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

~~Continental Resources, Inc.’s~~Continental’s principal business is crude oil and natural gas exploration, development and ~~production. Continental’s~~production with operations ~~are~~ 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 ~~Arkoma~~Anadarko Woodford and ~~Anadarko~~Arkoma Woodford plays in Oklahoma. The East region ~~contains~~consists of properties east of the Mississippi river including the Illinois Basin and the state of Michigan.

~~Continental has one wholly owned subsidiary, Banner Pipeline Company, L.L.C., which has no assets or operations.~~ The consolidated financial statements include the accounts of Continental and its wholly owned ~~subsidiary~~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 with the Company’s Annual Report on Form 10-K for the year ended December 31, ~~2009~~2010 (“~~2009~~2010 Form 10-K”), which includes a summary of the Company’s significant accounting policies and other disclosures.

The financial statements as of ~~September 30, 2010~~March 31, 2011 and for the three ~~and nine~~ month periods ended ~~September 30,~~March 31, 2011 and 2010 ~~and 2009~~ are unaudited. The ~~Condensed Consolidated Balance Sheet~~condensed consolidated balance sheet as of December 31, ~~2009~~2010 was derived from the audited balance sheet filed in the ~~2009~~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. Inventories~~market and consist of the following:

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

Basic ~~earnings~~net income (loss) per ~~common~~ share is computed by dividing net income (loss) by the weighted-average number of shares outstanding for the period. Diluted ~~earnings~~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 ~~these~~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 ~~September 30, 2010~~March 31, 2011 and ~~2009:~~2010:


	Three months ended September 30,				Nine months ended September 30,				Three months ended March 31,
*In thousands, except per share data*	2010		2009		2010		2009
Income (numerator):
Net income - basic and diluted	$	39,077	$	34,929	$	213,283	$	21,824
									2011			2010
									*In thousands, except per share data*
Income (loss) (numerator):
Net income (loss) - basic and diluted									$	(137,201	)	$	72,465

Weighted average shares (denominator):
Weighted average shares - basic		168,925		168,516		168,889		168,492		171,729			168,855
Restricted shares		740		782		719		489		—			662
Employee stock options		284		408		296		418		—			303

Weighted average shares - diluted		169,949		169,706		169,904		169,399		171,729			169,820
Net income per share:
Net income (loss) per share:
Basic	$	0.23	$	0.21	$	1.26	$	0.13	$	(0.80	)	$	0.43
Diluted	$	0.23	$	0.21	$	1.26	$	0.13	$	(0.80	)	$	0.43

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.

~~Certain~~A prior year ~~amounts have~~amount has been reclassified on the condensed consolidated financial statements to conform to the 2010 presentation. On the condensed consolidated balance sheet as of December 31, 2009, the line item “Derivative assets” was included in “Receivables – Joint interest and other, net” and has been shown separately in this report to conform to the 20102011 presentation. On the unaudited condensed consolidated ~~statement~~statements of cash flows for the ~~nine~~three months ended ~~September 30, 2009,~~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 ~~2010~~2011 presentation.

During the second quarter of 2010, the Company determined that a related party relationship, as defined by SEC rules and U.S. GAAP, did not exist with a third party entity that had been historically accounted for as a related party in the consolidated financial statements. Effective April 1, 2010, transactions with this entity are no longer reflected as affiliate transactions in the unaudited condensed consolidated financial statements. The balance sheet at December 31, 2009 includes $0.1 million from this party in “Receivables – Affiliated parties” and $6.4 million in “Payables to affiliated parties”. “Production expenses to affiliates” includes $1.8 million in expenses from this party for the nine months ended September 30, 2010, all of which was recognized in the first quarter of the year, and $1.7 million and $6.4 million in expenses from this party for the three and nine months ended September 30, 2009, respectively.

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.


	Nine months ended September 30,						Three months ended March 31,
*In thousands*	2010			2009
							2011		2010
							*In thousands*
Supplemental cash flow information:
Cash paid for interest	$	17,218		$	13,675		$	15,908	$	2,263
Cash paid for income taxes	$	10,876		$	146		$	90	$	14
Cash received for income tax refunds	$	(1,288	)	$	(22,018	)	$	—	$	(1,285	)
Non-cash investing activities
Non-cash investing activities:
Asset retirement obligations	$	1,325		$	555		$	513	$	456

The Company is required to recognize all derivative instruments on the balance sheet as either assets or liabilities measured at fair value. The Company ~~elects~~has not ~~to designate~~designated its ~~derivatives~~derivative instruments as ~~cash flow~~ 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 on derivative instruments in the unaudited condensed consolidated statements of ~~income~~operations under the caption “Gain (loss) on ~~mark-to-market~~ derivative ~~instruments.~~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 ~~may limit~~limits future revenues from favorable price movements.

During the ~~nine~~three months ended ~~September 30, 2010,~~March 31, 2011, the Company entered into several new swap and collar derivative contracts covering a portion of its crude oil and natural gas production for ~~2010,~~ 2011, 2012 and 2013. The new contracts were entered into in the ~~normal~~ordinary course of business and the Company ~~expects to~~may enter into additional similar contracts during the year. 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 ~~posted~~ 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 ~~equal to or greater than~~between the floor price and ~~equal to or less than~~ 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”, ~~“Accrued liabilities and other”~~“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 and the time value of options. The calculation of the fair value of collars requires the use of an option-pricing model. SeeNote 6.5. Fair Value Measurements.

At ~~September 30, 2010,~~March 31, 2011, the Company had outstanding contracts with respect to future production as set forth in the tables below.


Period and Type of Contract	Volume in Bbls		Swaps Weighted Average				Collars											Bbls			Swaps Weighted Average				Collars
						Floors						Ceilings								Floors							Ceilings
						Range			Weighted Average			Range			Weighted Average					Range						Weighted Average			Range		Weighted Average
October 2010 - December 2010
Swaps		1,089,000		$	83.99
Collars		1,380,000					$	75-$78		$	76.00		$	88.75-$96.75		$	93.43
January 2011 - March 2011
Swaps		284,000		83.86
Collars		2,565,000					$	75-$80			78.95		$	88.65-$97.25			91.70
April 2011 - June 2011
Swaps		91,000		81.22															273,000			$	84.67
Collars		2,593,500					$	75-$80			79.39		$	89.00-$97.25			91.27		2,593,500						$	75-$80		$	79.39	$	89.00-$97.25	$	91.27
July 2011 - September 2011
Swaps		92,000		81.22															460,000		$	85.64
Collars		2,622,000					$	75-$80			79.39		$	89.00-$97.25			91.27		2,622,000					��	$	75-$80		$	79.39	$	89.00-$97.25	$	91.27
October 2011 - December 2011
Swaps		92,000		81.22															644,000		$	86.25
Collars		2,622,000					$	75-$80			79.39		$	89.00-$97.25			91.27		2,622,000						$	75-$80		$	79.39	$	89.00-$97.25	$	91.27
January 2012 - December 2012
Swaps		1,830,000		84.57															8,235,000		$	88.36
Collars		2,745,000					$	80			80.00		$	93.25-$93.65			93.54		5,332,620						$	80		$	80.00	$	93.25-$97.00	$	94.71
January 2013 - December 2013
Swaps		1,825,000		85.90															5,110,000		$	88.63
Collars																			7,847,500						$	80-$95		$	85.98	$	92.30-$101.70	$	98.20

The following table presents information about the components of derivative fair value gain (loss) for the periods presented.


	Three months ended September 30,						Nine months ended September 30,						Three months ended March 31,
*In thousands*	2010			2009			2010			2009
													2011			2010
													*In thousands*
Realized gain (loss) on derivatives:
Crude oil fixed price swaps	$	5,845		$	—		$	13,275		$	—		$	(3,095	)	$	2,531
Crude oil collars		825			—			1,884			—			(10,247	)		—
Natural gas fixed price swaps		6,373			—			16,628			—			8,126			2,722
Natural gas basis swaps		(674	)		—			(2,323	)		—			—			(961	)
Unrealized gain (loss) on derivatives:
Unrealized gain (loss) on derivatives
Crude oil fixed price swaps		(17,538	)		—			(6,727	)		—			(165,043	)		(2,213	)
Crude oil collars		(28,640	)		—			6,445			—			(195,088	)		(4,549	)
Natural gas fixed price swaps		9,258			(1,134	)		26,552			701			(3,956	)		28,326
Natural gas basis swaps		368			(971	)		1,892			(1,916	)		—			488

Gain (loss) on mark-to-market derivative instruments	$	(24,183	)	$	(2,105	)	$	57,626		$	(1,215	)
Gain (loss) on derivative instruments, net													$	(369,303	)	$	26,344

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


	September 30, 2010							December 31, 2009								March 31, 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	$	39,511	$	(13,438	)	$	26,073	$	2,218	$	(4,307	)	$	(2,089	)	$	17,409	$	(549,842	)	$	(532,433	)	$	21,365	$	(189,711	)	$	(168,346	)

~~In January 2010, the Financial Accounting Standards Board (the “FASB”) issued ASU No. 2010-06,~~~~Fair Value Measurements and Disclosures (Topic 820)–Improving Disclosures about Fair Value Measurements~~, which requires new disclosures and clarifies existing disclosure requirements related to fair value measurements. The Company adopted the applicable provisions of this new standard on January 1, 2010 and has included the required disclosures below, as applicable.

The Company is required to calculate fair value based on a hierarchy which prioritizes the inputs to valuation techniques used to measure fair value into three levels. The fair value hierarchy gives the highest priority to unadjusted quoted market prices ~~(unadjusted)~~ in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Level 2 inputs are inputs, other than quoted prices included within Level 1, which are observable for the asset or liability, either directly or indirectly. As Level 1 inputs generally provide the most reliable evidence of fair value, the Company uses Level 1 inputs when available.

Certain assets and liabilities are reported at fair value on a recurring basis. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair

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. The discounted cash flow method estimates future cash flows based on quoted market prices for future commodity prices, observable inputs relating to basis differentials and a risk-adjusted discount rate. The fair value of fixed price swaps and basis swap derivatives is calculated using mainly significant observable inputs (Level 2). The calculation of the fair value of collar contracts requires the use of an option-pricing model with significant unobservable inputs (Level 3). The valuation model for option derivative contracts is ~~primarily~~ an industry-standard model that considers various inputs including: (a) 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. The Company’s calculation for each position is ~~then~~ compared to the counterparty valuation for reasonableness.

The following ~~table summarizes~~tables summarize the valuation of financial instruments by pricing levels that were accounted for at fair value on a recurring basis as of ~~September 30,~~March 31, 2011 and December 31, 2010. There were no transfers between Level 1 and Level 2 of the fair value hierarchy during the three ~~and nine month periods~~months ended ~~September 30, 2010.~~March 31, 2011. Further, there were no transfers in and/or out of Level 3 of the fair value hierarchy during the three ~~and nine month periods~~months ended ~~September 30, 2010.~~March 31, 2011.


*In thousands*	Fair value measurements at September 30, 2010 using:
											Fair value measurements at March 31, 2011 using:
Description	Level 1		Level 2			Level 3		Total			Level 1		Level 2			Level 3			Total
											*in thousands*
Derivative assets (liabilities):
Fixed price swaps	$	—	$	23,606		$	—	$	23,606		$	—	$	(233,927	)	$	—		$	(233,927	)
Basis swaps		—		(703	)		—		(703	)
Collars		—		—			3,170		3,170			—		—			(298,506	)		(298,506	)

Total	$	—	$	22,903		$	3,170	$	26,073		$	—	$	(233,927	)	$	(298,506	)	$	(532,433	)

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:


*In thousands*	2010
Balance at December 31, 2009	$	(3,275	)
Total realized or unrealized gains (losses):
				2011			2010
				*In thousands*
Balance at January 1				$	(103,418	)	$	(3,275	)
Total realized or unrealized losses:
Included in earnings		(4,549	)		(195,088	)		(4,549	)
Included in other comprehensive income		—			—			—
Purchases, sales, issuances and settlements, net		—
Purchases					—			—
Sales					—			—
Issuances					—			—
Settlements					—			—
Transfers into Level 3		—			—			—
Transfers out of Level 3		—			—			—

Balance at March 31, 2010	$	(7,824	)
Total realized or unrealized gains (losses):
Included in earnings		39,634
Included in other comprehensive income		—
Purchases, sales, issuances and settlements, net		—
Transfers into Level 3		—
Transfers out of Level 3		—
Balance at March 31				$	(298,506	)	$	(7,824	)

Balance at June 30, 2010	$	31,810
Total realized or unrealized gains (losses):
Included in earnings		(28,640	)
Included in other comprehensive income		—
Purchases, sales, issuances and settlements, net		—
Transfers into Level 3		—
Transfers out of Level 3		—

Balance at September 30, 2010	$	3,170

Change in unrealized gains (losses) relating to derivatives still held at September 30, 2010	$	6,631
Change in unrealized losses relating to derivatives still held at March 31				$	(196,675	)	$	(4,549	)

Gains and losses included in earnings for the three ~~and nine~~ month periods ended ~~September 30,~~March 31, 2011 and 2010 attributable to the change in unrealized gains and losses relating to derivatives held at ~~September 30,~~March 31, 2011 and 2010 are reported in ~~revenues.~~

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.~~values for those assets and liabilities.

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 ~~believes~~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 fair value of non-producing properties is calculated using significant unobservable inputs (Level 3).

As a result of changes in reserves and the ~~forward~~commodity futures price ~~strip,~~strips, proved properties were reviewed for impairment at ~~September 30, 2010.~~March 31, 2011. No impairment provisions were recorded for the Company’s proved crude oil and natural gas properties for ~~either~~ the three months ended ~~September 30, 2010 or 2009.~~March 31, 2011. For ~~those periods,~~that period, future cash flows were determined to be in excess of cost basis, therefore no impairment was necessary. Certain non-producing properties were impaired at ~~September 30, 2010,~~March 31, 2011, reflecting amortization of leasehold costs. The following table sets forth the pre-tax ~~(non-cash)~~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 ~~income.~~operations.


	Three months ended September 30,				Nine months ended September 30,				Three months ended March 31,
*In thousands*	2010		2009		2010		2009
									2011		2010
									*In thousands*
Proved property impairments	$	—	$	—	$	1,674	$	36,051	$	—	$	976
Non-producing property impairments		14,698		11,791		47,713		34,440		20,848		14,199

Total	$	14,698	$	11,791	$	49,387	$	70,491	$	20,848	$	15,175

Asset Retirement Obligations – The fair ~~values~~value of asset retirement obligations (AROs) ~~are~~is estimated based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an ~~ARO;~~ARO, estimated probabilities, amounts and timing of ~~settlements;~~settlements, the credit-adjusted risk-free rate to be ~~used;~~used, and inflation rates. The fair ~~value~~values of ARO additions ~~was~~were $0.6 million and ~~$0.3~~$0.4 million for the three months ended ~~September 30,~~March 31, 2011 and 2010, ~~and 2009, respectively, and was $1.4 million and $1.0 million for the nine months ended September 30, 2010 and 2009,~~ 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 ~~value~~values of financial instruments that are not recorded at fair value in the condensed consolidated financial statements.

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 ~~value~~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.

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*	September 30, 2010		December 31, 2009		March 31, 2011		December 31, 2010
Revolving credit facility	$	—	$	226,000	$	—	$	30,000
8¹/4% Senior Notes due 2019⁽¹⁾		297,651		297,524		297,740		297,696
7³/8% Senior Notes due 2020⁽²⁾		198,266		—		198,325		198,295
7¹/8% Senior Notes due 2021⁽³⁾		400,000		—		400,000		400,000

Total long-term debt	$	895,917	$	523,524	$	896,065	$	925,991

The Company had no debt outstanding at ~~September 30, 2010~~March 31, 2011 on its revolving credit facility due July 1, 2015. At December 31, ~~2009,~~2010, the Company had ~~$226.0~~$30.0 million ~~in long-term debt~~of outstanding borrowings on its revolving credit facility. The credit facility has aggregate commitments of $750 million and a borrowing base of ~~$1.3~~$1.5 billion, subject to semi-annual redetermination. 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 ~~its~~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 ~~our~~the Company’s interest in at least 85% (by value) of all of ~~the Company’s proven~~its proved reserves and associated crude oil and natural gas properties.

The Company had ~~$747.7~~$747.6 million of unused commitments (after considering outstanding letters of credit) under ~~the~~its revolving credit facility at ~~September 30, 2010~~March 31, 2011 and incurs commitment fees of 0.50% per annum of the daily average amount of unused borrowing availability. The credit ~~facility~~agreement contains certain restrictive covenants including a requirement that the Company maintain a current ratio of not less than 1.0 to 1.0 ~~(representing~~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 ~~less~~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)~~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 ~~ratio~~measure of net income or cash flows as determined by 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 ~~no greater than 3.75 to 1.0.~~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 ~~September 30, 2010.~~March 31, 2011.

8¹/4~~% Senior Notes due 2019~~ ~~- On September 23, 2009, the Company issued $300 million of~~The 8¹/4% Senior Notes due 2019 (the “2019 Notes”) ~~and received net proceeds of approximately $289.7 million after deducting~~, the ~~initial purchasers’ discounts and fees. The net proceeds were used to repay a portion of the borrowings then outstanding under the revolving credit facility.~~

7³/8~~% Senior Notes due 2020 -~~~~On April 5, 2010, the Company issued $200 million of~~ 7³/8% Senior Notes due 2020 (the “2020 Notes”), and ~~received net proceeds of approximately $194.2 million after deducting~~ the initial purchasers’ discounts and fees. The 2020 Notes were sold in a transaction exempt from the registration requirements of the Securities Act of 1933, as amended (the “Securities Act”), to qualified institutional buyers in reliance on Rule 144A of the Securities Act. The net proceeds were used to repay a portion of the borrowings then outstanding under the revolving credit facility.

7¹/8% Senior Notes due 2021 -~~On September 16, 2010, the Company issued $400 million of 7 1/8% Senior Notes due 2021~~ (the “2021 Notes”). The 2021 Notes were sold at par in a transaction exempt from the registration requirements of the Securities Act to qualified institutional buyers in reliance on Rule 144A of the Securities Act. The Company received net proceeds of approximately $393.0 million after deducting the initial purchasers’ fees. The net proceeds were used to repay all borrowings outstanding under the revolving credit facility and to increase cash balances to fund a portion of the Company’s 2010 capital program.

In connection with the issuance and sale of the 2020 Notes and the 2021 Notes, the Company entered into registration rights agreements (the “Registration Rights Agreements”) with the initial purchasers dated April 5, 2010 and September 16, 2010. Pursuant to the Registration Rights Agreements, the Company has agreed to file a registration statement with the SEC so that holders of the 2020 Notes and the 2021 Notes can exchange them for registered notes that have substantially identical terms as the 2020 Notes and the 2021 Notes. The Company has agreed to use reasonable efforts to cause the exchanges to be completed within 400 days after the issuance of the 2020 Notes and the 2021 Notes. The Company is required to pay additional interest if it fails to comply with its obligations to register the 2020 Notes and the 2021 Notes within the specified time period, whereby the interest rate would be increased by 1.0% per annum during the period in which a registration default is in effect. The Company expects to comply with the terms of the Registration Rights Agreements and complete the exchanges of the 2020 Notes and the 2021 Notes within the 400 day period.

~~The 2019 Notes, 2020 Notes, and 2021 notes (together,~~ (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 interest on the 2021 Notes ~~commencing~~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 athe “make-whole” redemption ~~price~~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 asat March 31, 2011. One of ~~September 30, 2010. The Notes are not subject to any mandatory redemption or sinking fund requirements. The~~the Company’s ~~sole subsidiary,~~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~~commitments –As of ~~September 30, 2010,~~March 31, 2011, the Company had various drilling rig contracts with various terms extending through June 2012. These contracts were entered into in the ~~normal~~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 ~~drilling~~ commitments as of ~~September 30, 2010 are $3.1~~March 31, 2011 total approximately $65 million, ~~for contracts that expire in 2010, $45.8~~of which $57 million is for contracts that expire in 2011 and ~~$21.4~~$8 million is for contracts that expire in 2012.

Fracturing and ~~Well Stimulation Services Arrangement~~well stimulation services arrangement – OnIn August ~~20,~~ 2010, the Company entered into an agreement with a third party towhereby 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 has a term of three years, beginning in ~~September~~October 2010, with two one-year extensions available to the Company at its discretion. Pursuant to the take-or-pay arrangement, 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 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, 2011 amount to $48.7 million. The commitments under this arrangement are not recorded in the accompanying condensed consolidated balance sheets.

Delivery commitments –In 2010, the Company signed a throughput and deficiency agreement with a third party crude oil pipeline company committing to ship 10,000 barrels 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 in the second quarter of 2011. The Company will use this system to move some of its North region crude oil to market.

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 ~~the nine months ended September 30,~~ 2010, ~~and the year ended December 31, 2009,~~ 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 ~~were $1.0~~associated with the plan amounted to $0.9 million and ~~$0.9~~$0.3 million for the ~~nine~~three months ended ~~September 30,~~March 31, 2011 and 2010, respectively.

Employee health claims –The Company ~~self insures~~self-insures employee health claims up to the first $125,000 per ~~employee.~~employee per year. The Company ~~self insures~~self-insures employee workers’ compensation claims up to the first $250,000 per ~~employee.~~employee per claim. Any amounts paid above these ~~thresholds~~levels are reinsured through third-party providers. 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 ~~$1.3~~$2.1 million and $1.9 million at ~~both September 30, 2010~~March 31, 2011 and December 31, ~~2009.~~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 insuch as commercial disputes, claims from royalty and surface owners, property damage claims, personal injury claims and similar matters. While the ~~normal course~~outcome of ~~business, none of which, in~~these legal matters cannot be predicted with certainty, the ~~opinion of management, will individually or collectively~~Company does not expect them to have a material adverse effect on ~~the~~its financial ~~position or~~condition, results of operations ~~of the Company.~~or cash flows. As of ~~September 30, 2010~~March 31, 2011 and December 31, ~~2009,~~2010, the Company has ~~provided~~recorded a ~~reserve~~liability in “Other noncurrent liabilities” of ~~$4.6~~$4.5 million and ~~$4.3~~$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 ~~income,~~operations, 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 ~~September 30, 2010,~~March 31, 2011, options covering ~~2,200,723~~2,213,193 shares had been exercised and 535,893 had been canceled.

The Company’s stock option activity under the 2000 Plan for the ~~nine~~three months ended ~~September 30, 2010 was as follows:~~March 31, 2011 is presented below:

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

price of the stock option at its exercise date. The total intrinsic value of stock options exercised during the ~~nine~~three months ended ~~September 30, 2010~~March 31, 2011 was approximately ~~$8.5~~$0.3 million. At ~~September 30, 2010,~~March 31, 2011, all stock options were exercisable and had a weighted average remaining life of ~~1.5 years~~1.0 year with an aggregate intrinsic value of ~~$5.2~~$7.1 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 ~~September 30, 2010,~~March 31, 2011, the Company had ~~3,302,152~~2,955,988 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.

~~The Company began issuing shares of restricted common stock to employees and non-employee directors in October 2005.~~ A summary of changes in the non-vested shares of restricted stock for the ~~nine~~three months ended ~~September 30, 2010~~March 31, 2011 is presented below:

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. 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 ~~shares~~stock that vested during the ~~nine~~three months ended ~~September 30, 2010~~March 31, 2011 at ~~their~~the vesting date was ~~$4.2~~$1.3 million. As of ~~September 30, 2010,~~March 31, 2011, there was ~~$12.5~~$27.4 million of unrecognized compensation expense related to non-vested restricted ~~shares.~~stock. The expense is expected to be recognized ratably over a weighted average period of ~~1.0 year.~~1.5 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 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 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 its increased 2011 capital budget.

In ~~June 2010,~~March 2011, the Company ~~sold~~assigned certain non-strategic leaseholds located in ~~DeSoto Parish, Louisiana~~the state of Michigan to a third party ~~with an effective date of June 18, 2010. Total~~for cash proceeds ~~amounted to $35.4~~of $22.0 million. In connection with the ~~sale,~~transaction, the Company recognized a pre-tax gain of ~~$32.2~~$15.3 million. The ~~sale~~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 ~~used~~paid approximately $22.9 million for 20 Broadway, which is the ~~proceeds from~~amount the ~~sale~~Company’s principal shareholder initially paid to ~~fund a portion~~acquire the office building in Oklahoma City, including the related commissions and closing costs. The transaction was approved by the Company’s Board of ~~its 2010 capital expenditures program.~~

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, ~~2009.~~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” under Part II, Item 1A of this report, 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 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 ~~Arkoma~~Anadarko Woodford and ~~Anadarko~~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 crude oil and natural gas prices. In addition, the prices we realize for our crude oil and natural gas production are affected by location differences in market prices.

For the first ~~nine~~three months of ~~2010,~~2011, our crude oil and natural gas production increased to ~~11,392~~4,650 MBoe ~~(41,728~~(51,663 Boe per day), up ~~1,241~~1,191 MBoe, or ~~12%~~34%, from the first ~~nine~~three months of ~~2009.~~2010. The increase in ~~2010~~2011 production was primarily driven by an increase in production from our North Dakota Bakken field and ~~Oklahoma~~Anadarko Woodford ~~plays.~~play in Oklahoma. Our crude oil and natural gas revenues for the first ~~nine~~three months of ~~2010~~2011 increased ~~66%~~50% to ~~$675.4~~$326.5 million due to a ~~44%~~15% increase in realized commodity prices along with increased production compared to the same period in ~~2009.~~2010. Our realized price per Boe increased ~~$17.90~~$9.07 to ~~$58.82~~$71.14 for the ~~nine~~three months ended ~~September 30, 2010~~March 31, 2011 compared to the ~~nine~~three months ended September 30, 2009. For the nine month period ended September 30, 2010, we experienced increases in production taxes and other expenses of $22.9 million, a 74% increase compared to the first nine months of 2009, primarily due to an increase in crude oil and natural gas revenues resulting from higher commodity prices and an increase in sales volumes.March 31, 2010. At various times, we have stored crude oil due to pipeline line fill requirements, low commodity prices, or ~~because of low prices~~transportation constraints or we have sold crude oil from inventory. These actions result in differences between our produced and sold crude oil volumes. For the ~~nine~~three months ended ~~September 30, 2010,~~March 31, 2011, crude oil sales volumes were 9060 MBbls ~~more~~less than crude oil production, and crude oil sales volumes were ~~196~~40 MBbls ~~less~~more than crude oil production for the same period in ~~2009.~~2010. Our cash flows from operating activities for the ~~nine~~three months ended ~~September 30, 2010~~March 31, 2011 were ~~$495.3~~$195.6 million, an increase of ~~$279.3~~$4.9 million from ~~$216.0~~$190.7 million provided by our operating activities during the comparable ~~2009~~2010 period. The increase in operating cash flows was primarily due to increased crude oil and natural gas revenues as a result of higher commodity prices and sales volumes. During the ~~nine~~three months ended ~~September 30, 2010,~~March 31, 2011, we invested ~~$866.1~~$412.8 million (including increased accruals for capital expenditures of ~~$115.4~~$31.1 million and ~~$3.1~~$4.3 million of seismic costs) in our capital program, concentrating mainly in the North Dakota Bakken field and the ~~Arkoma Woodford and~~ Anadarko Woodford ~~plays, and the Red River units.~~play in Oklahoma.

In ~~July 2010,~~March 2011, our Board of Directors increased our ~~2010~~2011 capital expenditures budget to ~~$1.3~~$1.75 billion to further accelerate our drilling program and increase our acreage positions in strategic plays in the United States. Our previous ~~2010~~2011 capital expenditures budget was ~~$850 million.~~$1.36 billion. Our revised 2010 capital expenditures budget of $1.3 billion focuses primarily on increased development in the Bakken shale of North Dakota and Montana, the Anadarko Woodford shale in western Oklahoma, and the Niobrara shale in Colorado and Wyoming. In October 2010, our Board of Directors approved a 2011 capital expenditures budget of ~~$1.36~~$1.75 billion ~~which~~ will ~~continue to~~ focus primarily on increased development in the ~~Bakken shale of~~ North Dakota Bakken field and ~~Montana,~~ the Anadarko Woodford ~~shale~~play in western ~~Oklahoma~~Oklahoma. Due to the volatility of crude oil and ~~the Niobrara shale in Colorado~~natural gas prices and ~~Wyoming.~~our desire to diligently develop our substantial inventory of undeveloped reserves, 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 our revolving credit facility will be sufficient to meet our capital expenditure ~~needs.~~needs for the next 12 months.

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

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

Three months ended ~~September 30, 2010~~March 31, 2011 compared to the three months ended ~~September 30, 2009~~March 31, 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.


	Three months ended September 30,																	Three months ended March 31,
	2010					2009					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)		3,075		75	%		2,534		74	%	Volume increase		541			21	%			3,460			74	%			2,621			76	%			839			32	%
Natural Gas (MMcf)		6,261		25	%		5,427		26	%		834			15	%			7,137			26	%			5,026			24	%			2,111			42	%

Total (MBoe)		4,119		100	%		3,440		100	%		679			20	%			4,650			100	%			3,459			100	%			1,191			34	%

	Three months ended September 30,										Volume increase (decrease)			Percent increase (decrease)				Three months ended March 31,														Volume increase (decrease)			Percent increase (decrease)
	2010					2009											2011							2010
	MBoe		Percent			MBoe		Percent									MBoe				Percent			MBoe				Percent
North Region		3,230		78	%		2,608		76	%			622			24	%			3,660			79	%			2,707			78	%			953			35	%
South Region		776		19	%		696		20	%			80			11	%			886			19	%			628			18	%			258			41	%
East Region		113		3	%		136		4	%		(23	)		(17	)%			104			2	%			124			4	%			(20	)		(16	)%

Total (MBoe)		4,119		100	%		3,440		100	%		679			20	%
Total																			4,650			100	%			3,459			100	%			1,191			34	%

Crude oil production volumes increased ~~21%~~32% during the three months ended ~~September 30, 2010~~March 31, 2011 compared to the three months ended ~~September 30, 2009.~~March 31, 2010. Production increases in the North Dakota Bakken field, Red River units, and the Oklahoma Woodford play contributed incremental production volumes in ~~2010~~2011 of ~~659~~850 MBbls, ~~in excess of~~a 43% increase over production for the ~~third~~first quarter of ~~2009.~~2010. Favorable drilling results ~~from drilling~~ have been the primary contributors to production growth in these areas. Natural gas production volumes increased ~~834~~2,111 MMcf, or ~~15%~~42%, during the three months ended ~~September 30, 2010~~March 31, 2011 compared to the same period in ~~2009.~~2010. Natural gas production in the Bakken field in the North region was up ~~564~~635 MMcf, or 62%, for the three months ended ~~September 30, 2010~~March 31, 2011 compared to the same period in ~~2009~~2010 due to additional natural gas being connected and sold in North Dakota. Natural gas production in the Oklahoma Woodford area increased ~~617~~1,196 MMcf, or 52%, due to additional wells being completed and producing in the three months ended ~~September 30, 2010~~March 31, 2011 compared to the same period in 2009. These additional sales in the Bakken and Oklahoma Woodford plays were partially offset by decreases in natural gas volumes of 180 MMcf in the Cedar Hills field due to the conversion of producing wells to injection wells and 155 MMcf in the South region due to natural declines in a non-Woodford area.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 in the price of crude oil during the three months ended March 31, 2011 had an adverse impact on the fair value of our derivative instruments, which resulted in negative revenue adjustments of $369.3 million for the three months ended March 31, 2011. The adverse impact of the changes in our derivative instruments resulted in our total revenues being a negative $36.2 million for the three months ended March 31, 2011. The $369.3 million negative 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 million of unrealized non-cash mark-to-market losses on open derivative instruments. Excluding 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. The unrealized mark-to-market loss relates to derivative instruments with various terms that are scheduled to be realized over the period from April 2011 through December 2013. Over this period, actual realized derivative settlements may differ significantly from the unrealized mark-to-market valuation at March 31, 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 ~~September 30, 2010~~March 31, 2011 were ~~$238.8~~$326.5 million, a ~~42%~~50% increase from sales of ~~$168.4~~$217.1 million for the same period in ~~2009.~~2010. Our sales volumes increased ~~701~~1,090 MBoe, or ~~20%~~31%, over the same period in ~~2009~~2010 due to the continuing success of our ~~enhanced crude oil recovery~~drilling programs in the Bakken field and ~~drilling programs.~~Anadarko Woodford play. Our realized price per Boe increased ~~$8.73~~$9.07 to ~~$56.92~~$71.14 for the three months ended ~~September 30, 2010~~March 31, 2011 from ~~$48.19~~$62.07 for the three months ended ~~September 30, 2009.~~March 31, 2010. The differential between NYMEX calendar month average crude oil prices and our realized crude oil price per barrel for the three months ended ~~September 30, 2010~~March 31, 2011 was ~~$8.93~~$9.21 compared to ~~$9.39~~$7.42 for the three months ended ~~September 30, 2009~~March 31, 2010 and ~~$8.29~~$9.02 for the year ended December 31, ~~2009.~~2010. Factors contributing to the changing differentials included disruptions in Canadian crude oil delivery systems and other circumstances that impacted Canadian crude oil imports, ~~and~~ increases in production in the North region, ~~coupled with~~ downstream transportation capacity constraints and ~~seasonal~~ demand fluctuations.

Derivatives. We are required to recognize all derivative instruments on the balance sheet as either assets or liabilities measured at fair value. We ~~elected~~have not ~~to designate~~designated our ~~derivatives~~derivative instruments as ~~cash flow hedges.~~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 on derivative instruments in the unaudited condensed consolidated statements of ~~income~~operations under the caption “Gain (loss) on ~~mark-to-market~~ derivative ~~instruments.~~instruments, net.”

During the three months ended ~~September 30, 2010,~~March 31, 2011, we realized losses on crude oil derivatives of $13.3 million and realized gains on natural gas derivatives of ~~$5.7~~$8.1 million. During the three months ended March 31, 2011, we reported an unrealized non-cash mark-to-market loss on crude oil derivatives of $360.1 million and an unrealized non-cash mark-to-market loss on natural gas derivatives of $4.0 million. During the three months ended March 31, 2010, we realized gains on crude oil derivatives of ~~$6.7~~$2.5 million and realized gains on natural gas derivatives of $1.8 million. During the three months ended ~~September 30,~~March 31, 2010, we reported an unrealized non-cash mark-to-market loss on crude oil derivatives of $6.8 million and an unrealized non-cash mark-to-market gain on natural gas derivatives of ~~$9.6 million and an unrealized non-cash mark-to-market loss on crude oil derivatives of $46.2~~$28.8 million. During the three months ended September 30, 2009, we had no derivative contracts related to our crude oil production and we reported unrealized non-cash mark-to-market losses from our natural gas derivatives of $2.1 million for such period.

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.


	Three months ended September 30,						Three months ended March 31,
Reclaimed crude oil sales	2010		2009		Variance		2011		2010		Variance
Average sales price ($/Bbl)	$	65.79	$	56.90	$	8.89	$	79.67	$	68.25	$	11.42
Sales volumes (barrels)		52,000		39,000		13,000		52,138		55,361		(3,223	)

Prices for reclaimed crude oil sold from our central treating units were ~~$8.89~~$11.42 per barrel higher for the three months ended ~~September 30, 2010~~March 31, 2011 than the comparable ~~2009~~2010 period, which contributed to an increase in reclaimed crude oil revenue ~~by $0.7~~of $0.5 million to ~~$3.3~~$4.7 million, contributing to an overall increase in crude oil and natural gas service operations revenue of ~~$0.9~~$1.8 million for the three months ended ~~September 30, 2010. We sold high-pressure air~~March 31, 2011. Also contributing to the increase in crude oil and natural gas service operations revenue was a $1.0 million increase in saltwater disposal income resulting from our Red River units to a third party and recorded revenues of $0.5 million for the three months ended September 30, 2009. Beginning in January 2010, we no longer sell high-pressure air to a third party.increased activity. Associated crude oil and natural gas service operations expenses increased ~~$2.6~~$1.5 million to ~~$4.9~~$5.5 million during the three months ended ~~September 30, 2010~~March 31, 2011 from ~~$2.3~~$4.0 million during the three months ended ~~September 30, 2009~~March 31, 2010 due mainly to an increase in the costs of purchasing and treating reclaimed crude oil for resale ~~compared to the same period~~and in ~~2009.~~providing saltwater disposal services.

Production Expenses and Production Taxes and Other Expenses. Production expenses increased 9%30% to ~~$24.9~~$29.3 million during the three months ended ~~September 30, 2010~~March 31, 2011 from ~~$22.7~~$22.6 million during the three months ended ~~September 30, 2009~~March 31, 2010 due primarily to higher production volumes. Production expense per Boe decreased to ~~$5.92~~$6.38 for the three months ended ~~September 30, 2010~~March 31, 2011 from ~~$6.50~~$6.46 per Boe for the three months ended ~~September 30, 2009. In the prior year, we leased compressors from a related party for approximately $400,000~~March 31, 2010. The per ~~month under an operating lease and a new agreement~~unit decrease was ~~negotiated effective February 1, 2010 resulting~~driven by longer natural production periods on certain North Dakota Bakken wells that resulted in lower artificial lifting costs, positive secondary recovery efforts in the ~~monthly lease fee being reduced~~Cedar Hills field that have resulted in lower-cost improvements in production, and the conversion of certain high pressure air injection units to ~~$50,000, lowering~~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 ~~expense per Boe for the 2010 period.~~expenses compared to 2010.

Production taxes and other expenses increased ~~$7.1~~$11.6 million, or ~~58%~~72%, to $27.6 million during the three months ended ~~September 30, 2010~~March 31, 2011 compared to the three months ended ~~September 30, 2009~~March 31, 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 include other charges for marketing, gathering, dehydration and compression fees primarily related to natural gas sales in the ~~Arkoma~~Oklahoma Woodford ~~area~~and North Dakota Bakken areas of ~~$1.1~~$2.2 million and ~~$1.5~~$1.1 million for the three months ended ~~September 30,~~March 31, 2011 and 2010, ~~and 2009,~~ respectively. Production taxes, excluding other charges, as a percentage of crude oil and natural gas sales were ~~7.7%~~7.8% for the three months ended ~~September 30, 2010~~March 31, 2011 compared to ~~6.7%~~7.0% for the three months ended ~~September 30, 2009.~~March 31, 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 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. Our overall production tax rate is expected to increase as production tax incentives we currently receive for horizontal wells reach the end of their incentive ~~period.~~periods.

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


	Three months ended September 30,				Percent increase (decrease)			Three months ended March 31,				Percent increase (decrease)
*$/Boe*	2010		2009		Percent increase (decrease)			2011		2010		Percent increase (decrease)
Production expenses	$	5.92	$	6.50		(9	)%	$	6.38	$	6.46		(1	)%
Production taxes and other expenses		4.65		3.54		31	%		6.01		4.58		31	%

Production expenses, production taxes and other expenses	$	10.57	$	10.04		5	%	$	12.39	$	11.04		12	%

Exploration Expenses. Exploration expenses consist primarily of dry hole costs and exploratory geological and geophysical costs that are expensed as incurred. Exploration expenses increased ~~$2.5~~$5.0 million in the three months ended ~~September 30, 2010~~March 31, 2011 to ~~$3.5~~$6.8 million due primarily to ~~increases~~a $1.5 million increase in dry hole expenses and a $3.3 million increase in seismic ~~expense~~expenses resulting from higher acquisitions of ~~$0.9 million and dry hole expense of $1.5 million.~~seismic data in the current year in connection with our increased capital budget for 2011.

Depreciation, Depletion, Amortization and Accretion (“DD&A”). Total DD&A increased ~~$11.9~~$23.1 million, or ~~23%~~44%, in the ~~third~~first quarter of 2011 compared to the first quarter of 2010, ~~compared to the third quarter of 2009,~~ primarily due to ~~the~~an increase in ~~production.~~production volumes. The following table shows the components of our DD&A rate per Boe.


	Three months ended September 30,				Three months ended March 31,
*$/Boe*	2010		2009		2011		2010
Crude oil and natural gas	$	14.59	$	14.22	$	16.07	$	14.62
Other equipment		0.24		0.22		0.25		0.23
Asset retirement obligation accretion		0.16		0.16		0.17		0.18

Depreciation, depletion, amortization and accretion	$	14.99	$	14.60	$	16.49	$	15.03

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 production base in the Bakken field. Our producing properties in the Bakken field typically carry a higher DD&A rate due to the existence of higher cost reserves in that field compared to other areas in which we operate.

Property Impairments. Property impairments, ~~which consisted entirely of impairments of~~both proved and non-producing, ~~properties~~increased in the three months ended March 31, 2011 by $5.6 million to $20.8 million compared to $15.2 million for the three months ended ~~September 30, 2010 and 2009,~~March 31, 2010.

Impairment of non-producing properties increased ~~$2.9~~$6.6 million during the three months ended ~~September 30, 2010~~March 31, 2011 to ~~$14.7~~$20.8 million compared to ~~$11.8~~$14.2 million for the three months ended ~~September 30, 2009~~March 31, 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 properties are amortized on a composite method based on our estimated experience of successful drilling and the average holding period.

~~We did not record any impairment provisions for proved oil and gas properties for either the three months ended September 30, 2010 or 2009.~~ 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 ~~market~~ value based on discounted cash flows. ~~For both~~We did not record any impairment provisions for proved oil and gas properties for the three months ended ~~September 30, 2010 and 2009,~~March 31, 2011. For that period, future cash flows were determined to be in excess of cost basis, ~~and~~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 2010 reflect uneconomic operating results in a non-Bakken Montana field in the North region.

General and Administrative Expenses. General and administrative expenses increased ~~$2.1~~$4.5 million to ~~$12.1~~$16.3 million during the three months ended ~~September 30, 2010~~March 31, 2011 from ~~$10.0~~$11.8 million during the comparable period in ~~2009. The majority of the increase was in personnel and office expenses.~~2010. General and administrative expenses include non-cash charges for stock-based compensation of ~~$2.6~~$3.6 million and ~~$3.2~~$2.9 million for the three months ended ~~September 30,~~March 31, 2011 and 2010, ~~and 2009,~~ respectively. General and administrative expenses excluding stock-based compensation increased ~~$2.7~~$3.8 million for the three months ended ~~September 30, 2010~~March 31, 2011 compared to the same period in ~~2009.~~2010. The increase was primarily related to an increase in personnel costs and office related expenses associated with the growth of our Company. On a volumetric basis, general and administrative expenses increased ~~$0.02~~$0.17 to ~~$2.90~~$3.56 per Boe for the three months ended ~~September 30, 2010~~March 31, 2011 compared to ~~$2.88~~$3.39 per Boe for the three months ended ~~September 30, 2009.~~March 31, 2010.

Interest Expense. Interest expense increased ~~165%,~~$10.6 million, or ~~$7.8 million,~~127%, for the three months ended ~~September 30, 2010~~March 31, 2011 compared to the three months ended ~~September 30, 2009,~~March 31, 2010 due to an increase in our outstanding debt balance ~~in the current year coupled with~~and higher rates of interest ~~being incurred~~ on our senior notes in the current year compared to lower interest rates on our credit facility borrowings in the prior year. On September 23, 2009, we issued $300 million of 8 1/4% Senior Notes due 2019. On April 5, 2010, we issued $200 million of 7 3/8% Senior Notes due 2020. On September 16, 2010, we issued $400 million of 7 1/8% Senior Notes due 2021. We recorded ~~$10.3~~$17.2 million in interest expense on the outstanding senior notes for the three months ended ~~September 30,~~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, our weighted average interest rate for the three months ended ~~September 30, 2010~~March 31, 2011 was ~~6.2%~~7.3% with a weighted average outstanding long-term debt balance of ~~$730.8~~$971.9 million ~~while for the three months ended September 30, 2009 our~~compared to a weighted average interest rate ~~was 2.82%~~of 6.1% with a weighted average outstanding long-term debt balance of ~~$581.6 million.~~$511.7 million for the same period in 2010.

Our weighted average outstanding revolving credit facility balance decreased to ~~$170.0~~$71.9 million for the three months ended ~~September 30, 2010~~March 31, 2011 compared to ~~$558.8~~$211.7 million for the three months ended ~~September 30, 2009.~~March 31, 2010. The weighted average interest rate on our revolving credit facility borrowings was ~~higher~~lower at ~~2.66%~~2.65% for the three months ended ~~September 30, 2010~~March 31, 2011 compared to ~~2.59%~~2.75% for the same period in ~~2009.~~2010. At ~~September 30, 2010,~~March 31, 2011, we had no outstanding borrowings on our revolving credit facility.

Income Taxes. We recorded an income tax ~~expense~~benefit for the three months ended ~~September 30, 2010~~March 31, 2011 of ~~$24.9~~$84.2 million compared ~~to $19.8~~with income tax expense of $44.4 million for the three months ended ~~September 30, 2009.~~March 31, 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, 2010 compared to the nine months ended September 30, 2009~~

~~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 15% during the nine months ended September 30, 2010 compared to the nine months ended September 30, 2009. Production increases in the North Dakota Bakken field, Cedar Hills field and the Oklahoma Woodford play contributed incremental volumes in 2010 of 1,625 MBbls in excess of production for the same period in 2009. Favorable results from drilling have been the primary contributors to production growth in these areas. This increase was partially offset by a decrease in the Montana Bakken of 324 MBbls due to wells shut in for repairs and natural declines. Natural gas volumes increased 668 MMcf, or 4%, during the nine months ended September 30, 2010 compared to the same period in 2009. Natural gas production in the Bakken field in the North region was up 1,742 MMcf for the nine months ended September 30, 2010 compared to the same period in 2009 due to additional natural gas being connected and sold in North Dakota. Natural gas production in the Oklahoma Woodford area increased 550 MMcf due to additional wells being completed and producing in the nine months ended September 30, 2010 compared to the same period in 2009. These additional sales in the Bakken and Oklahoma Woodford plays were partially offset by a decrease in natural gas volumes of 731 MMcf in the Red River units due to the conversion of producing wells to injection wells and the Badlands plant being down for repairs. Further, other South region natural gas volumes decreased 880 MMcf mostly due to natural declines from a non-Woodford area.

~~Crude Oil and Natural Gas Sales.~~ Crude oil and natural gas sales for the nine months ended September 30, 2010 were $675.4 million, a 66% increase from sales of $407.4 million for the same period in 2009. Our sales volumes increased 1,526 MBoe, or 15%, over the same period in 2009 due to the continuing success of our enhanced crude oil recovery and drilling programs. Our realized price per Boe increased $17.90 to $58.82 for the nine months ended September 30, 2010 from $40.92 for the nine months ended September 30, 2009. 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, 2010 was $8.68 compared to $7.91 for the nine months ended September 30, 2009 and $8.29 for the year ended December 31, 2009. Factors contributing to the changing differentials included Canadian crude oil imports and increases in production in the North region, coupled with downstream transportation capacity and seasonal demand fluctuations.

~~Derivatives.~~ We are required to recognize all derivative instruments on the balance sheet as either assets or liabilities measured at fair value. We elected not to designate our derivatives as cash flow hedges. As a result, we mark our derivative instruments to fair value and recognize the realized and unrealized changes in fair value on derivative instruments in the consolidated statements of income under the caption “Gain (loss) on mark-to-market derivative instruments.”

During the nine months ended September 30, 2010, we realized gains on natural gas derivatives of $14.3 million and realized gains on crude oil derivatives of $15.2 million. During the nine months ended September 30, 2010, we reported an unrealized non-cash mark-to-market gain on natural gas derivatives of $28.4 million and an unrealized non-cash mark-to-market loss on crude oil derivatives of $0.3 million. During the nine months ended September 30, 2009, we had no derivative contracts related to our crude oil production and we reported unrealized non-cash mark-to-market losses from our natural gas derivatives of $1.2 million for such period.

~~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 $23.85 per barrel higher for the nine months ended September 30, 2010 than the comparable 2009 period, which contributed to an increase in reclaimed crude oil revenue by $4.1 million to $12.0 million, contributing to an overall increase in crude oil and natural gas service operations revenue of $2.3 million for the nine months ended September 30, 2010. We sold high-pressure air from our Red River units to a third party and recorded revenues of $1.6 million for the nine months ended September 30, 2009. Beginning in January 2010, we no longer sell high-pressure air to a third party. Associated crude oil and natural gas service operations expenses increased $5.6 million to $13.0 million during the nine months ended September 30, 2010 from $7.4 million during the nine months ended September 30, 2009 due mainly to an increase in the costs of purchasing and treating reclaimed crude oil for resale compared to the same period in 2009.

~~Production Expenses and Production Taxes and Other Expenses~~. Production expenses increased 1% to $69.8 million during the nine months ended September 30, 2010 from $69.2 million during the nine months ended September 30, 2009 due to higher production volumes. Production expense per Boe decreased to $6.08 for the nine months ended September 30, 2010 from $6.95 per Boe for the nine months ended September 30, 2009. In the prior year, we leased compressors from a related party for approximately $400,000 per month under an operating lease and a new agreement was negotiated effective February 1, 2010 resulting in the monthly lease fee being reduced to $50,000, lowering production expense per Boe for the 2010 period. Also contributing to the decrease was a non-recurring charge recorded in the prior year period to accrue for potential loss exposure on royalty interpretations.

Production taxes and other expenses increased $22.9 million, or 74%, during the nine months ended September 30, 2010 compared to the nine months ended September 30, 2009 as a result of higher revenues resulting from increased commodity prices and sales volumes along with the expiration of various tax incentives. Production taxes and other expenses include charges for marketing, gathering, dehydration and compression fees primarily related to natural gas sales in the Arkoma Woodford area of $4.4 million and $5.4 million for the nine months ended September 30, 2010 and 2009, respectively. Production taxes, excluding other charges, as a percentage of crude oil and natural gas sales were 7.4% for the nine months ended September 30, 2010 compared to 6.4% for the nine months ended September 30, 2009. 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 oil revenues. Production taxes are 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. Our overall production tax rate is expected to increase as incentives we currently receive for horizontal wells reach the end of their incentive period.

~~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 decreased $2.1 million in the nine months ended September 30, 2010 to $7.6 million due primarily to a decrease in dry hole expense of $3.1 million, partially offset by a $1.6 million increase in seismic expenses.

~~Depreciation, Depletion, Amortization and Accretion.~~ Total DD&A increased $19.5 million, or 13%, in the first nine months of 2010 compared to the same period in 2009, primarily due to the increase in production. The following table shows the components of our DD&A rate per Boe.

DD&A per Boe decreased partially as a result of the increase in commodity prices used to calculate year-end 2009 reserve volumes as compared to the prices used to calculate year-end 2008 reserve volumes. Higher prices have the effect of increasing the economic life of oil and gas properties, which increases future reserve volumes and decreases DD&A on a volumetric basis.

~~Property Impairments.~~ Property impairments, both proved and non-producing, decreased in the nine months ended September 30, 2010 by $21.1 million to $49.4 million compared to $70.5 million during the nine months ended September 30, 2009.

Impairment of non-producing properties increased $13.3 million during the nine months ended September 30, 2010 to $47.7 million compared to $34.4 million for the nine months ended September 30, 2009 reflecting amortization of leasehold costs. Non-producing properties consist of undeveloped leasehold costs and costs associated with the purchase of certain proved undeveloped reserves. Non-producing properties are amortized on a composite method based on our estimated experience of successful drilling and the average holding period.

Impairment provisions for proved crude oil and natural gas properties were approximately $1.7 million for the nine months ended September 30, 2010 compared to approximately $36.1 million for the nine months ended September 30, 2009, a decrease of $34.4 million, or 95%. 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 market value based on discounted cash flows. Impairments of proved properties in 2010 reflect uneconomic operating results in the East region and a non-Bakken Montana field in the North region, which resulted in impairments of $1.7 million for the nine months ended September 30, 2010. Impairments of proved properties in 2009 reflect uneconomic drilling results in the first half of 2009 in our South region, which resulted in impairments of $24.1 million. The remaining 2009 impairments were the result of decreases in reserves and prices.

~~General and Administrative Expenses.~~ General and administrative expenses increased $5.8 million to $35.5 million during the nine months ended September 30, 2010 from $29.7 million during the comparable period in 2009. The majority of the increase was in personnel and office expenses. General and administrative expenses include non-cash charges for stock-based compensation of $8.6 million for both the nine months ended September 30, 2010 and 2009. On a volumetric basis, general and administrative expenses increased $0.11 to $3.09 per Boe for the nine months ended September 30, 2010 compared to $2.98 per Boe for the nine months ended September 30, 2009.

~~Interest Expense.~~ Interest expense increased 134%, or $18.8 million, for the nine months ended September 30, 2010 compared to the nine months ended September 30, 2009, due to an increase in our outstanding debt balance in the current year coupled with higher rates of interest being incurred on our senior notes in the current year compared to interest rates on our credit facility borrowings in the prior year. On September 23, 2009, we issued $300 million of 8¹/4~~% Senior Notes due 2019. On April 5, 2010, we issued $200 million of 7~~³/8~~% Senior Notes due 2020. On September 16, 2010, we issued $400 million of 7~~¹/8% Senior Notes due 2021. We recorded $26.6 million in interest expense on the outstanding senior notes for the nine months ended September 30, 2010. Including the interest on the senior notes, our weighted average interest rate for the nine months ended September 30, 2010 was 6.64% with a weighted average outstanding balance of $612.1 million compared to a weighted average interest rate of 2.98% and a weighted average outstanding balance of $558.8 million for the nine months ended September 30, 2009.

Our average revolving credit facility balance decreased to $161.2 million for the nine months ended September 30, 2010 compared to $550.7 million for the nine months ended September 30, 2009. The weighted average interest rate on our revolving credit facility borrowings was lower at 2.66% for the nine months ended September 30, 2010 compared to 2.90% for the same period in 2009. At September 30, 2010, we had no outstanding borrowings on our revolving credit facility.

~~Income Taxes.~~ We recorded income tax expense for the nine months ended September 30, 2010 of $132.1 million compared to $11.8 million for the nine months ended September 30, 2009. 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 ~~senior notes.~~debt and equity securities. During the first ~~nine~~three months of ~~2010,~~2011, our ~~crude oil prices were $19.11~~average realized sales price was $9.07 per ~~barrel~~Boe higher than the first ~~nine~~three months of ~~2009, and we have seen our natural gas~~2010. The increase in realized commodity prices ~~for the first nine months of 2010 increase 62% compared to the first nine months of 2009. The increased prices of crude oil and natural gas~~ in the current year, coupled with our 31% increase in sales volumes, resulted in improved cash flows from operations and better liquidity. Further, our liquidity has improved at March 31, 2011 as we have more borrowing availability on our revolving credit facility as a result of refinancing 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 ~~September 30, 2010,~~March 31, 2011, we had approximately ~~$149.5~~$477.4 million of cash and cash equivalents and approximately ~~$747.7~~$747.6 million ~~(after considering outstanding letters of credit)~~ of net available liquidity under our revolving credit ~~facility.~~facility (after considering outstanding letters of credit).

Our net cash provided by operating activities was ~~$495.3~~$195.6 million and ~~$216.0~~$190.7 million for the ~~nine~~three months ended ~~September 30,~~March 31, 2011 and 2010, ~~and 2009,~~ 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 in the current period.

During the ~~nine~~three months ended ~~September 30,~~March 31, 2011 and 2010, ~~and 2009,~~ we had cash flows used in investing activities (excluding asset sales) of ~~$747.6~~$377.5 million and ~~$378.2~~$163.0 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 ~~current year~~continued acceleration of our drilling program, primarily in the North Dakota Bakken field and ~~Arkoma~~the Anadarko Woodford ~~plays.~~play in Oklahoma.

Net cash provided by financing activities for the ~~nine~~three months ended ~~September 30, 2010~~March 31, 2011 was ~~$348.9~~$629.2 million and was mainly the result of the issuance and sale of ~~the $200~~an aggregate 10,080,000 shares of our common stock in March 2011 for total net proceeds of approximately $659.3 million, ~~of 2020 Notes in April 2010~~after deducting underwriting discounts and ~~the issuance of the $400 million of 2021 Notes in September 2010~~offering-related expenses, along with borrowings on our credit facility, partially offset by amounts repaid under our credit facility. Net cash ~~provided by~~used in financing activities of ~~$159.5~~$28.3 million for the ~~nine~~three months ended ~~September 30, 2009~~March 31, 2010 was mainly the result of ~~amounts received from the issuance of the $300 million of 2019 Notes in September 2009 along with borrowings on our credit facility, partially offset by~~ amounts repaid under 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 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 may also include the issuance of debt or equity securities or the sale of assets. ~~Furthermore, the~~The issuance of additional debt may require that 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 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 million, a portion of which was used to repay all amounts outstanding under our revolving credit facility. The remaining net proceeds, the remaining 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.

~~On June 30, 2010, we entered into~~We have an ~~amended and restated revolving credit agreement. The restated credit agreement amended and restated our previous credit agreement to, among other things:~~

~~Our amended credit facility is backed by~~2015, are from a syndicate of 14 ~~banks.~~banks and financial institutions. We believe that each member of the current syndicate ~~of banks~~ has the capability to fund ~~up to their commitments.~~its commitment. If one or more ~~banks should not be able to~~lenders cannot fund ~~their~~its commitment, we ~~may~~would not have the full availability of the $750 million commitment.

We had no outstanding borrowings under our credit facility at ~~September 30, 2010~~March 31, 2011 and ~~$226.0~~$30.0 million outstanding at December 31, ~~2009.~~2010. As of ~~September 30, 2010,~~March 31, 2011, we had ~~$747.7~~$747.6 million of borrowing availability under our credit facility (after considering outstanding letters of credit). ~~On September 16, 2010,~~As previously discussed, we issued ~~$400 million~~and sold an aggregate 10,080,000 shares of ~~the 2021 Notes~~our common stock in March 2011 and received total net proceeds of approximately ~~$393.0~~$659.3 million after deducting ~~initial purchasers’ fees.~~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 ~~$182~~$155 million. ~~Prior to payoff, weighted average outstanding borrowings under our credit facility amounted to $170.0 million during the third quarter of 2010.~~ As of ~~November 1, 2010,~~May 2, 2011, we ~~continue~~continued to have no outstanding borrowings and ~~$747.7~~$747.6 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, 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 ~~fourth~~second quarter of ~~2010.~~2011. 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.

Our credit agreement contains certain restrictive covenants including a requirement that we maintain a current ratio of not less than 1.0 to 1.0 (representing current assets less current liabilities inclusive of available borrowing capacity under the credit agreement and exclusive of current balances associated with derivative contracts and asset retirement obligations) and a ratio of total funded debt to EBITDAX of no greater than 3.75 to 1.0. We were in compliance with all covenants at September 30, 2010 and we expect to maintain compliance for at least the next 12 months. We do not believe the restrictive covenants will materially limit our ability to undertake additional debt or equity financing.

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.

On September 23, 2009, we issued $300 million of 8 1/4% Senior Notes due 2019 and received net proceeds of approximately $289.7 million after deducting the initial purchasers’ discounts and fees. On April 5, 2010, we issued $200 million of 7 3/8% Senior Notes due 2020 and received net proceeds of approximately $194.2 million after deducting the initial purchasers’ discounts and fees. The net proceeds from these offerings were used to repay a portion of the borrowings then outstanding under our revolving credit facility that were incurred to fund capital expenditures. On September 16, 2010, we issued $400 million of 7 1/8% Senior Notes due 2021 and received net proceeds of approximately $393.0 million after deducting initial purchasers’ fees. The net proceeds were used to repay the remaining borrowings outstanding under the revolving credit facility that were incurred to fund capital expenditures and to increase cash balances to fund a portion of our 2010 capital program.

The 2019 Notes, 2020 Notes, and 2021 Notes (together, 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 interest on the 2021 Notes commencing on April 1, 2011. We have 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. We may also redeem the Notes, in whole or in part, at a “make-whole” redemption price 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, we 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. Currently, we have no plans or intentions of exercising an early redemption option on the Notes. The Notes are not subject to any mandatory redemption or sinking fund requirements.

The Indentures contain certain restrictions on our ability to incur additional debt, pay dividends on our 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 our assets. These covenants are subject to a number of important exceptions and qualifications. We were in compliance with these covenants as of September 30, 2010 and expect to maintain compliance for at least the next 12 months. We do not believe the restrictive covenants will materially limit our ability to undertake additional debt or equity financing. Our subsidiary, which currently has no independent assets or operations, fully and unconditionally guarantees the Notes.

On July 16, 2010, we filed a shelf registration statement on Form S-3 pursuant to which we may offer from time to time one or more series of debt or equity securities. We may issue additional long-term debt and equity securities from time to time when market conditions are favorable and when the need arises. The nature, amounts, terms, and timing of such financing arrangements, and the related impact on our financial position, results of operations, and liquidity are currently indeterminable. The issuance of additional equity securities could have a dilutive effect on the value of our common stock.

As part of our risk management program, we hedge a portion of our anticipated future crude oil and natural gas production ~~for the next 12-42 months~~ 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 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 ~~these~~ hedging arrangements limits the downside risk of adverse price movements, their use also ~~may limit~~limits future revenues from favorable price movements. ~~The use~~Substantially all of our hedging transactions ~~also involves~~are settled based upon reported settlement prices on the ~~risk that~~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 ~~counterparties will be unable~~accounting applicable to ~~meet~~our derivative instruments, a listing of open contracts at March 31, 2011 and the ~~financial terms of such transactions. Our derivative contracts are with multiple counterparties to minimize our exposure to credit risk with any individual counterparty.~~

During the nine months ended September 30, 2010, we realized gains on crude oil and natural gas derivatives of $29.4 million and reported an unrealized non-cash mark-to-market gain on derivatives of $28.2 million. Theestimated fair value of ~~our derivative instruments at September 30, 2010 was a net asset~~those contracts as of ~~$26.1 million.~~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.

During the first ~~nine~~three months of ~~2010,~~2011, we participated in the completion of ~~233~~92 gross ~~(80.2~~(31.1 net) wells and invested a total of ~~$866.1~~$412.8 million (including increases in accruals for capital expenditures of ~~$115.4~~$31.1 million and ~~$3.1~~$4.3 million of seismic costs) in our capital program as shown in the following table.

The revised 2010 capital expenditures budget of $1.3 billion primarily focuses on increased development in the Bakken shale of North Dakota and Montana, the Anadarko Woodford shale in western Oklahoma and the Niobrara shale in Colorado and Wyoming.


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

Total	$	412.8

~~In October 2010, our Board of Directors approved a~~Our 2011 capital expenditures budget of ~~$1.36 billion. Our 2011 planned capital expenditures are expected to be allocated as follows:~~

~~The 2011 capital expenditures budget of $1.36~~$1.75 billion will ~~continue to~~ focus primarily on increased development in the ~~Bakken shale of~~ North Dakota Bakken field and ~~Montana,~~ the Anadarko Woodford ~~shale~~play in western ~~Oklahoma and the Niobrara shale in Colorado and Wyoming.~~Oklahoma.

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 ~~2010 and~~ 2011 capital ~~budgets.~~budget. 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 ~~September 30, 2010,~~March 31, 2011, we had various drilling rig contracts with various terms extending through June 2012. These contracts were entered into in the ~~normal~~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 ~~September 30, 2010 are $3.1~~March 31, 2011 total approximately $65 million, ~~for contracts that expire in 2010, $45.8~~of which $57 million is for contracts that expire in 2011 and ~~$21.4~~$8 million is for contracts that expire in 2012.

OnIn August ~~20,~~ 2010, we entered into an agreement with a third party towhereby 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 has a term of three years, beginning in ~~September~~October 2010, with two one-year extensions available to us at our discretion. Pursuant to the take-or-pay arrangement, 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, 2011 amount to $48.7 million. The commitments under this arrangement are not recorded in the accompanying condensed consolidated balance sheets.

In 2010, the Company signed a throughput and deficiency agreement with a third party crude oil pipeline company committing to ship 10,000 barrels 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 in the second quarter of 2011. The Company will use this system to move some of its North region crude oil to market.

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.

On 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 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 restructuring costs or liabilities have been incurred or recognized as of March 31, 2011. We are not currently able to reasonably estimate the costs to be incurred in 2011 or 2012 in connection with the relocation, but we do not expect such costs to have a material adverse effect on our financial condition, results of operations or cash flows.

There has been no change in our critical accounting policies from those disclosed in our Form 10-K for the year ended December 31, ~~2009.~~2010.

Various accounting standards and interpretations have been issued with effective dates in 2011. We have evaluated the recently issued accounting pronouncements that are effective in 2011 and believe that none of them will have a material effect on our financial position, results of operations or cash flows when adopted.

Further, we are closely monitoring the joint standard-setting efforts of the Financial Accounting Standards Board and the International Accounting Standards Board. 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 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 ~~September 30, 2010.~~March 31, 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, to be due and payable. If the indebtedness under our revolving credit facility 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 isprovides a reconciliation of our net income to ~~EBITDAX.~~EBITDAX for the periods presented.


	Three months ended September 30,				Nine months ended September 30,					Three months ended March 31,
*in thousands*	2010		2009		2010			2009
Net income	$	39,077	$	34,929	$	213,283		$	21,824
										2011			2010
										*in thousands*
Net income (loss)										$	(137,201	)	$	72,465
Interest expense		12,612		4,763		32,875			14,073		18,971			8,360
Provision for income taxes		24,904		19,788		132,071			11,780
Provision (benefit) for income taxes											(84,154	)		44,410
Depreciation, depletion, amortization and accretion		62,918		51,030		174,327			154,875		75,650			52,587
Property impairments		14,698		11,791		49,387			70,491		20,848			15,175
Exploration expenses		3,530		1,077		7,585			9,726		6,812			1,786
Unrealized derivative (gain) loss		36,552		2,105		(28,162	)		1,215
Unrealized losses (gains) on derivatives											364,087			(22,052	)
Non-cash equity compensation		2,626		3,172		8,596			8,594		3,642			2,852

EBITDAX	$	196,917	$	128,655	$	589,962		$	292,578	$	268,655		$	175,583

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 ~~and crude oil~~ 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 ~~price.~~prices. Based on our average daily production for the ~~nine~~three months ended ~~September 30, 2010,~~March 31, 2011, and excluding any effect of our derivative instruments in place, our annual revenue would increase or decrease by approximately ~~$114.6~~$140.3 million for each $10.00 per barrel change in crude oil prices and ~~$22.6~~$28.9 million for each $1.00 per ~~MMBtu~~Mcf change in natural gas prices.

To partially reduce price risk caused by these market fluctuations, we periodically hedge ~~crude oil and natural gas prices through the utilization of derivatives, including zero-cost collars and fixed price contracts.~~

~~During the nine months ended September 30, 2010, we entered into several new swap and collar derivative contracts covering~~ 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 months ended March 31, 2011, we realized a net loss on crude oil and natural gas derivatives of $5.2 million and reported an unrealized non-cash mark-to-market loss on derivatives of $364.1 million. The fair value of our derivative instruments at March 31, 2011 was a net liability of $532.4 million. An assumed increase in the forward commodity prices used in the March 31, 2011 valuation of our derivative instruments of $10.00 per barrel for crude oil and $1.00 per MMBtu for natural gas would increase our net derivative liability to approximately $892 million at March 31, 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 our net derivative liability to approximately $188 million at March 31, 2011.

Throughout 2010 and 2011 ~~2012 and 2013. The new contracts were~~we entered into ~~in the normal course of business and we expect to enter into additional similar contracts during the year. None of the new contracts have been designated for hedge accounting. See~~~~Note 5 – Derivative Contracts~~ in~~Notes to Unaudited Condensed Consolidated Financial Statements for additional information regarding our swap and collar derivative contracts.~~

On July 21, 2010, President Obama signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act, which, among other things, establishes federal oversight and regulation of the over-the-counter derivatives market and the entities that participate in that market. Significant regulations are required to be promulgated by the SEC and the Commodity Futures Trading Commission within 360 days from the date of enactment to implement the new legislation. The new legislation, to the extent applicable to us or our derivative counterparties, may result in increased costs and cash collateral requirements for the typesa series of derivative instruments, ~~we use~~including fixed price swaps and zero-cost collars, to ~~hedge~~reduce the uncertainty of future cash flows in order to underpin our capital expenditures and ~~otherwise manage~~accelerated drilling program over the next three years. The significant increase in the price of crude oil during the three months ended March 31, 2011 had an adverse impact on the fair value of our ~~financial and commercial risks related~~derivative instruments, which resulted in the recognition of a $364.1 million unrealized mark-to-market loss on derivative instruments at March 31, 2011. The unrealized mark-to-market loss relates to ~~fluctuations in~~derivative instruments with various terms that are scheduled to be realized over the period from April 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, 2011. While the existence of historically high commodity prices ~~and~~over a prolonged period could continue to have an adverse ~~effect~~impact on the fair value of our ~~ability to hedge risks associated with our business. Many~~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 key concepts and processes under the Dodd-Frank Act are not defined and must be delineated by rules and regulations to be adopted by the applicable regulatory agencies. As a consequence, it is not possible at this time to predict the effects that the Dodd-Frank Act or the resulting rules and regulations may have on our hedging activities.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 ($~~166.3~~266.6 million in receivables at ~~September 30, 2010)~~March 31, 2011), our joint interest receivables ($~~210.0~~293.9 million at ~~September 30, 2010)~~March 31, 2011), and counterparty credit risk associated with our derivative ~~instruments.~~instrument receivables ($17.4 million at March 31, 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 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 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 ~~$54.8 million and $13.5~~$57.6 million at ~~September 30, 2010 and December~~March 31, ~~2009, respectively,~~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 variable-rate borrowings outstanding 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 ~~are exposed to changes in interest rates as a result of our credit facility. We~~ had no ~~revolving credit facility debt~~ outstanding borrowings under our revolving credit facility at ~~November 1, 2010.~~March 31, 2011 or May 2, 2011.

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~~Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) were effective as of ~~September 30, 2010.~~March 31, 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 September 30, 2010, we implemented a new Company-wide enterprise resource planning software system, SAP, to replace our previous system. The new SAP system became operational on July 1, 2010. The system implementation was undertaken to enhance our accounting and reporting procedures, provide more standardized and efficient business processes, and provide flexibility to adapt to the planned future growth of our Company. In conjunction with the SAP implementation, the Company modified the design, operation and documentation of its internal controls over financial reporting in the business processes impacted by the new system. Management believes these changes will maintain and strengthen our overall internal controls.

~~Except as described above,~~March 31, 2011, there were no ~~other~~ 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 occurred during our most recent fiscal quarter~~ 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.

~~From time~~During the three months ended March 31, 2011, there have been no material changes with respect to ~~time, we are a party to litigation or other~~the legal proceedings ~~that we consider to be a part of the ordinary course of~~previously disclosed in our business. We are currently involved in various legal proceedings which we do not expect to have, individually or in the aggregate, a material adverse effect on our financial condition or results of operations.2010 Form 10-K. SeeNote 8.7. Commitments and ContingenciesinNotes to Unaudited Condensed Consolidated Financial Statements. of this Form 10-Q.

~~Except as set forth below, there~~There have been no material changes in our risk factors from those disclosed in our ~~Annual Report on~~2010 Form 10-K ~~for the year ended December 31, 2009~~ that was filed with the SEC on February ~~26, 2010.~~25, 2011.

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 ~~2009~~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 ~~2009~~2010 Form 10-K are not the only risks facing our ~~company.~~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.

The recent adoption of derivatives legislation by the United States Congress could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price risk and other risks associated with our business.

We use derivative instruments to manage our commodity price risk. The United States Congress recently adopted the Dodd-Frank Wall Street Reform and Consumer Protection Act (HR 4173), which, among other provisions, establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The new legislation was signed into law by President Obama on July 21, 2010 and requires the Commodities Futures Trading Commission (the “CFTC”) and the SEC to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. The CFTC has also proposed regulations to set position limits for certain futures and option contracts in the major energy markets, although it is not possible at this time to predict whether or when the CFTC will adopt those rules or include comparable provisions in its rulemaking under the new legislation. The financial reform legislation may also require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our derivative activities, although the application of those provisions to us is uncertain at this time. The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty.

The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral, which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable. Finally, the legislation was intended, in part, to reduce the volatility of crude oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to crude oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our consolidated financial position, results of operations and 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 ~~September 30, 2010:~~March 31, 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	57
	Condensed Consolidated Balance Sheets	57
	Unaudited Condensed Consolidated Statements of ~~Income~~Operations	68
	Condensed Consolidated Statements of Shareholders’ Equity	79
	Unaudited Condensed Consolidated Statements of Cash Flows	810
	Notes to Unaudited Condensed Consolidated Financial Statements	911
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	1922
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	3133
Item 4.	Controls and Procedures	3234

PART II. Other Information
Item 1.	Legal Proceedings	3334
Item 1A.	Risk Factors	3334
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	3334
Item 3.	Defaults Upon Senior Securities	3435
Item 4.	(Removed and Reserved)	3435
Item 5.	Other Information	3435
Item 6.	Exhibits	35
	Signature	36


*In barrels*	September 30, 2010		December 31, 2009
Crude oil line fill requirements		229,000		253,000
Temporarily stored crude oil		75,000		145,000

		304,000		398,000


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

		477,000		405,000


In thousands	March 31, 2011		December 31, 2010
Tubular goods and equipment	$	23,533	$	16,306
Crude oil		28,715		22,056

	$	52,248	$	38,362


Period and Type of Contract	MMBtu		Swaps Weighted Average
October 2010 - December 2010
Swaps		3,778,000	$	6.09
January 2011 - December 2011
Swaps		11,862,500		6.36


Period and Type of Contract	MMBtus		Swaps Weighted Average
April 2011 - June 2011
Swaps		6,597,500	$	5.44
July 2011 - September 2011
Swaps		6,900,000	$	5.42
October 2011 - December 2011
Swaps		7,222,000	$	5.40
January 2012 - December 2012
Swaps		3,660,000	$	5.07


	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	)


	Outstanding					Exercisable
	Number of options			Weighted average exercise price		Number of options			Weighted average exercise price
Outstanding at December 31, 2009		312,190		$	1.06		312,190		$	1.06
Exercised		(199,250	)		1.26		(199,250	)		1.26

Outstanding at September 30, 2010		112,940			0.71		112,940			0.71


	Outstanding					Exercisable
	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
Exercised		(4,500	)		0.71		(4,500	)			0.71

Outstanding at March 31, 2011		100,470			0.71		100,470				0.71


	Number of non-vested shares			Weighted average grant- date fair value
Non-vested restricted shares at December 31, 2009		1,126,821		$	26.55
Granted		60,667			42.42
Vested		(92,273	)		30.92
Forfeited		(47,949	)		30.92

Non-vested restricted shares at September 30, 2010		1,047,266			26.88


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

Non-vested restricted shares at March 31, 2011		1,132,573			37.21


	Three months ended September 30,
*In thousands, except price data*	2010			2009
Crude oil and natural gas sales	$	238,826		$	168,372
Gain (loss) on mark-to-market derivative instruments		(24,183	)		(2,105	)
Total revenues		219,450			170,204
Operating costs and expenses⁽¹⁾		143,094			110,918
Other expenses, net		12,375			4,569

Income before income taxes		63,981			54,717
Provision for income taxes		24,904			19,788

Net income	$	39,077		$	34,929
Production Volumes:
Crude oil (MBbl)		3,075			2,534
Natural gas (MMcf)		6,261			5,427
Crude oil equivalents (MBoe)		4,119			3,440
Sales Volumes:
Crude oil (MBbl)		3,153			2,589
Natural gas (MMcf)		6,261			5,427
Crude oil equivalents (MBoe)		4,195			3,494
Average Prices:⁽²⁾
Crude oil ($/Bbl)	$	67.26		$	58.78
Natural gas ($/Mcf)	$	4.28		$	2.98
Crude oil equivalents ($/Boe)	$	56.92		$	48.19


Period	(a) Total number of shares purchased ⁽¹⁾		(b) Average price paid per share⁽²⁾		(c ) Total number of shares purchased as part of publicly announced plans or programs		(d) Maximum number of shares that may yet be purchased under the plans or program ⁽³⁾
July 1, 2010 to July 31, 2010		750	$	43.57		—		—
August 1, 2010 to August 31, 2010		2,023	$	47.62		—		—
September 1, 2010 to September 30, 2010		57,397	$	44.26		—		—

Total		60,170	$	44.36		—		—


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		—		—


	~~Continental Resources, Inc.~~CONTINENTAL RESOURCES, INC.

Date: ~~November~~May 5, ~~2010~~2011	By:	/s/ John D. Hart
		John D. Hart
		Sr. Vice President, Chief Financial Officer and Treasurer (Duly Authorized Officer and Principal Financial Officer)


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. ~~001-328861)~~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. ~~001-328861)~~001-32886) filed May 22, 2007 and incorporated herein by reference.

~~4.1~~		Indenture dated as of September 16, 2010 among Continental Resources, Inc., Banner Pipeline Company, L.L.C. and Wilmington Trust FSB, as trustee, filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K (Commission File No. 001-32886) filed September 17, 2010 and incorporated herein by reference.

~~4.2~~		Registration Rights Agreement dated as of September 16, 2010 among Continental Resources, Inc., Banner Pipeline Company, L.L.C. and the Initial Purchasers named therein, filed as Exhibit 4.2 to the Company’s Current Report on Form 8-K (Commission File No. 001-32886) filed September 17, 2010 and incorporated herein by reference.

10.1		~~Purchase Agreement~~Assignment of Membership Interest dated ~~as of September 13, 2010 among~~March 18, 2011 between Harold Hamm and Continental Resources, Inc.~~, Banner Pipeline Company, L.L.C. and the Initial Purchasers named therein,~~ filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K (Commission File No. 001-32886) filed ~~September 14, 2010~~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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