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

~~169,959,944~~180,533,094 shares of our $0.01 par value common stock were outstanding on ~~July 31, 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.” AExploratory or development well ~~found to be incapable of producing hydrocarbons~~that does not produce crude oil and/or natural gas in ~~sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.~~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.” ~~These~~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.


	June 30, 2010		December 31, 2009		March 31, 2011		December 31, 2010
	(Unaudited)				*(Unaudited)*
	In thousands, except par values and share data				*In thousands, except par values and share data*
Assets
Current assets:
Cash and cash equivalents	$	15,232	$	14,222	$	477,440	$	7,916
Receivables:
Oil and natural gas sales		146,643		119,565
Crude oil and natural gas sales						260,570		208,211
Affiliated parties		11,274		7,823		17,038		20,156
Joint interest and other, net		148,006		55,970		282,861		254,471
Derivative assets		47,272		2,218		17,360		21,365
Inventories		39,218		26,711		52,248		38,362
Deferred and prepaid taxes		20		4,575		84,004		22,672
Prepaid expenses and other		5,624		4,944		9,724		9,173

Total current assets		413,289		236,028		1,201,245		582,326
Net property and equipment, based on successful efforts method of accounting		2,442,252		2,068,055		3,285,824		2,981,991
Debt issuance costs, net		20,725		10,844		26,342		27,468
Noncurrent derivative assets		15,353		—		49		—

Total assets	$	2,891,619	$	2,314,927	$	4,513,460	$	3,591,785


Liabilities and shareholders’ equity
Current liabilities:
Accounts payable trade	$	291,126	$	91,248	$	425,812	$	390,892
Revenues and royalties payable		79,842		66,789		174,620		133,051
Payables to affiliated parties		3,344		9,612		4,263		4,438
Accrued liabilities and other		74,366		49,601		106,357		94,829
Derivative liabilities						232,884		76,771
Current portion of asset retirement obligations		2,695		2,460		2,270		2,241

Total current liabilities		451,373		219,710		946,206		702,222
Long-term debt		609,844		523,524		896,065		925,991
Other noncurrent liabilities:
Deferred income tax liabilities		566,124		489,241		559,929		582,841
Asset retirement obligations, net of current portion		48,494		47,707		55,141		54,079
Noncurrent derivative liabilities						316,958		112,940
Other noncurrent liabilities		6,311		4,466		5,468		5,557

Total other noncurrent liabilities		620,929		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, 169,972,694 shares issued and outstanding at June 30, 2010; 169,968,471 shares issued and outstanding at December 31, 2009		1,700		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		435,271		430,283		1,102,538		439,900
Retained earnings		772,502		598,296		629,350		766,551

Total shareholders’ equity		1,209,473		1,030,279		1,733,693		1,208,155

Total liabilities and shareholders’ equity	$	2,891,619	$	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 June 30,						Six Months Ended June 30,						Three months ended March 31,
	2010			2009			2010			2009			2011			2010
	In thousands, except per share data												*In thousands, except per share data*
Revenues:
Oil and natural gas sales	$	211,204		$	141,028		$	419,263		$	226,845
Oil and natural gas sales to affiliates		8,222			5,411			17,287			12,162
Gain on mark-to-market derivative instruments		55,465			890			81,809			890
Oil and natural gas service operations		5,077			4,432			9,877			8,472
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		279,968			151,761			528,236			248,369			(36,210	)		248,268

Operating costs and expenses:
Production expenses		21,259			21,458			40,418			38,732			28,398			19,159
Production expenses to affiliates		1,089			2,580			4,531			7,732			872			3,442
Production taxes and other expenses		18,231			11,629			34,238			18,451			27,562			16,007
Exploration expenses		2,269			1,530			4,055			8,649			6,812			1,786
Oil and natural gas service operations		4,091			2,694			8,047			5,097
Crude oil and natural gas service operations														5,451			3,956
Depreciation, depletion, amortization and accretion		58,822			53,148			111,409			103,845			75,650			52,587
Property impairments		19,514			23,275			34,689			58,700			20,848			15,175
General and administrative expenses		11,494			9,351			23,343			19,635			16,347			11,849
Gain on sale of assets		(33,124	)		(85	)		(33,346	)		(221	)		(15,257	)		(222	)

Total operating costs and expenses		103,645			125,580			227,384			260,620			166,683			123,739

Income (loss) from operations		176,323			26,181			300,852			(12,251	)		(202,893	)		124,529
Other income (expense):
Interest expense		(11,903	)		(4,723	)		(20,263	)		(9,310	)		(18,971	)		(8,360	)
Other		78			301			784			448			509			706

		(11,825	)		(4,422	)		(19,479	)		(8,862	)		(18,462	)		(7,654	)

Income (loss) before income taxes		164,498			21,759			281,373			(21,113	)		(221,355	)		116,875
Provision (benefit) for income taxes		62,757			8,251			107,167			(8,008	)		(84,154	)		44,410

Net income (loss)	$	101,741		$	13,508		$	174,206		$	(13,105	)	$	(137,201	)	$	72,465

Basic net income (loss) per share	$	0.60		$	0.08		$	1.03		$	(0.08	)	$	(0.80	)	$	0.43
Diluted net income (loss) per share	$	0.60		$	0.08		$	1.03		$	(0.08	)	$	(0.80	)	$	0.43

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


	Shares outstanding		Common stock			Additional paid-in capital			Retained earnings		Total shareholders’ equity			Shares outstanding			Common stock			Additional paid-in capital			Retained earnings			Total shareholders’ equity
	In thousands, except share data													*In thousands, except share data*
Balance, January 1, 2009	169,558,129		$	1,696		$	420,054		$	526,958	$	948,708
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)	—			—			—			174,206		174,206
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)	—			—			5,970			—		5,970			—			—			3,642			—			3,642
Stock options:
Exercised (unaudited)	4,500			—			3			—		3			4,500			—			3			—			3
Restricted stock:
Issued (unaudited)	46,343			—			—			—		—			47,480			—			—			—			—
Repurchased and canceled (unaudited)	(20,911	)		—			(985	)		—		(985	)		(3,172	)		—			(207	)		—			(207	)
Forfeited (unaudited)	(25,709	)		—			—			—		—			(1,948	)		—			—			—			—

Balance, June 30, 2010 (unaudited)	169,972,694		$	1,700		$	435,271		$	772,502	$	1,209,473
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.


	Six months ended June 30,						Three months ended March 31,
	2010			2009			2011			2010
	In thousands						*In thousands*
Cash flows from operating activities:
Net income (loss)	$	174,206		$	(13,105	)	$	(137,201	)	$	72,465
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion		111,417			107,948			76,762			52,179
Property impairments		34,689			58,700			20,848			15,175
Change in fair value of derivatives		(64,714	)		(890	)		364,087			(22,052	)
Stock-based compensation		5,970			5,422			3,642			2,852
Provision (benefit) for deferred income taxes		95,500			(8,008	)		(84,154	)		40,416
Dry hole costs		409			4,992			1,504			33
Gain on sale of assets		(33,346	)		(221	)		(15,257	)		(222	)
Other, net		2,746			1,052			929			956
Changes in assets and liabilities:
Accounts receivable		(104,885	)		52,033			(77,631	)		(61,044	)
Inventories		(12,507	)		(17,948	)		(13,886	)		(363	)
Prepaid expenses and other		2,387			13,523			(513	)		4,030
Accounts payable trade		153,063			(96,873	)		3,648			69,719
Revenues and royalties payable		13,053			(19,995	)		41,569			7,574
Accrued liabilities and other		11,065			(5,577	)		11,340			8,932
Other noncurrent liabilities		1,172			1,440			(52	)		38

Net cash provided by operating activities		390,225			82,493			195,635			190,688

Cash flows from investing activities:
Exploration and development		(469,484	)		(296,099	)		(348,011	)		(156,625	)
Purchase of oil and natural gas properties		(151	)		(437	)
Purchase of crude oil and natural gas properties								—			(128	)
Purchase of other property and equipment		(14,261	)		(628	)		(29,443	)		(6,263	)
Proceeds from sale of assets		21,332			1,391			22,131			1,106

Net cash used in investing activities		(462,564	)		(295,773	)		(355,323	)		(161,910	)

Cash flows from financing activities:
Revolving credit facility borrowings		169,000			334,100			135,000			44,000
Repayment of revolving credit facility		(281,000	)		(118,500	)		(165,000	)		(72,000	)
Proceeds from issuance of 7³/8% Senior Notes Due 2020		194,210			—
Proceeds from issuance of common stock								659,736			—
Debt issuance costs		(7,876	)		(2,118	)		(21	)		(232	)
Equity issuance costs								(299	)		—
Repurchase of equity grants		(985	)		(358	)		(207	)		(113	)
Dividends to shareholders		(3	)		(7	)
Exercise of options		3			5
Exercise of stock options								3			3

Net cash provided by financing activities		73,349			213,122
Net cash provided by (used in) financing activities								629,212			(28,342	)
Net change in cash and cash equivalents		1,010			(158	)		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	$	15,232		$	5,071		$	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 primarily~~ in the North, South, and East regions of the United States. The North region consists of properties north of Kansas and west of the Mississippi river and includes North Dakota Bakken, Montana Bakken, the Red River units and the Niobrara play in Colorado and Wyoming. The South region includes Kansas and all properties south of Kansas and west of the Mississippi river including the Anadarko Woodford and Arkoma Woodford plays in Oklahoma. The East region consists of properties east of the Mississippi river including the Illinois Basin and the state of Michigan.

~~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 ~~June 30, 2010~~March 31, 2011 and for the three ~~and six~~ month periods ended ~~June 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 ~~accounting principles generally accepted in the United States of America~~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:


*In thousands*	June 30, 2010		December 31, 2009		March 31, 2011		December 31, 2010
Tubular goods and equipment	$	18,163	$	12,044	$	23,533	$	16,306
Crude oil		21,055		14,667		28,715		22,056

	$	39,218	$	26,711	$	52,248	$	38,362

~~As of June 30, 2010, total crude~~Crude oil inventory of 473,500 barrels valued at $21.1 million consisted of approximately 284,000 barrels of line fill requirements and 189,500 barrels of temporarily stored crude oil. As of December 31, 2009, total crude oil inventory of 398,000 barrels valued at $14.7 million consisted of approximately 253,000 barrels of line fill requirements and 145,000 barrels of temporarily stored crude oil. Inventories,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 ~~computations~~ for the three ~~and six~~ months ended ~~June 30, 2010~~March 31, 2011 and ~~2009:~~2010:


	Three months ended June 30,				Six months ended June 30,					Three months ended March 31,
*In thousands, except per share data*	2010		2009		2010		2009
										2011			2010
										*In thousands, except per share data*
Income (loss) (numerator):
Net income (loss) - basic and diluted	$	101,741	$	13,508	$	174,206	$	(13,105	)	$	(137,201	)	$	72,465

Weighted average shares (denominator):
Weighted average shares - basic		168,887		168,492		168,872		168,479			171,729			168,855
Restricted shares		744		584		704		—			—			662
Employee stock options		301		422		302		—			—			303

Weighted average shares - diluted		169,932		169,498		169,878		168,479			171,729			169,820
Income (loss) per share:
Net income (loss) per share:
Basic	$	0.60	$	0.08	$	1.03	$	(0.08	)	$	(0.80	)	$	0.43
Diluted	$	0.60	$	0.08	$	1.03	$	(0.08	)	$	(0.80	)	$	0.43

The potential dilutive effect of ~~455,000~~678,000 weighted average restricted shares and ~~421,000~~103,000 weighted average stock options were not ~~considered~~included in the calculation of diluted ~~income (loss)~~net loss per share for the ~~six~~three months ended ~~June 30, 2009,~~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~~2011 presentation. On the unaudited condensed consolidated ~~balance sheet as~~statements of ~~December~~cash flows for the three months ended March 31, ~~2009,~~2010, the line item ~~“Derivative~~“Gain on sale of assets” was included in ~~“Receivables-Joint interest and other,~~“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. Transactions with this entity are not reflected as affiliate transactions in the unaudited condensed consolidated financial statements as of and for the three months ended June 30, 2010. The balance sheet at December 31, 2009 included $0.1 million from this party in “Receivables – Affiliated parties” and $6.4 million in “Payables to affiliated parties”. “Production expenses to affiliates” included $1.8 million in expenses from this party for the six months ended June 30, 2010 and $1.9 million and $4.6 million in expenses from this party for the three and six months ended June 30, 2009, respectively.

~~Net~~The following table discloses supplemental cash ~~provided by operating activities reflects~~flow information about cash paid for interest ~~payments of $15.7 million for the six months ended June 30, 2010~~ and ~~$9.8 million for the six months ended June 30, 2009. During the six months ended June 30, 2010, the Company made cash payments of $5.8 million and received $1.3 million for refunds of~~ income ~~taxes paid. During the six months ended June 30, 2009, the Company received cash payments of $1.9 million for refunds of income taxes paid. Non-cash~~taxes. Also disclosed is information about investing activities ~~include asset retirement obligations of $0.7 million and $0.6 million for the six months ended June 30, 2010 and 2009, respectively.~~that affects recognized liabilities but does not result in cash receipts or payments.

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 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 ~~six~~three months ended ~~June 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 ~~2011.~~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”, “Derivative liabilities”, and ~~“Accrued liabilities and other.”~~“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 ~~June 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 MBbls	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
July 2010 - December 2010
April 2011 - June 2011
Swaps	1,104		$	85.14														273,000				$	84.67
Collars	2,760				$	75-$78		$	76.00		$	88.75-$96.75		$	93.43		2,593,500							$	75-$80		$	79.39	$	89.00-$97.25	$	91.27
January 2011 - March 2011
July 2011 - September 2011
Swaps	225		84.55														460,000			$	85.64
Collars	1,215				$	75-$80			77.78		$	88.65-$97.25			93.10		2,622,000						��	$	75-$80		$	79.39	$	89.00-$97.25	$	91.27
April 2011 - December 2011
October 2011 - December 2011
Swaps																	644,000			$	86.25
Collars	3,713				$	75-$80			78.70		$	89.00-$97.25			92.19		2,622,000							$	75-$80		$	79.39	$	89.00-$97.25	$	91.27
January 2012 - December 2012
Swaps																	8,235,000			$	88.36
Collars																	5,332,620							$	80		$	80.00	$	93.25-$97.00	$	94.71
January 2013 - December 2013
Swaps																	5,110,000			$	88.63
Collars																	7,847,500							$	80-$95		$	85.98	$	92.30-$101.70	$	98.20

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


	Three months ended March 31,
	2011			2010
	*In thousands*
Realized gain (loss) on derivatives:
Crude oil fixed price swaps	$	(3,095	)	$	2,531
Crude oil collars		(10,247	)		—
Natural gas fixed price swaps		8,126			2,722
Natural gas basis swaps		—			(961	)
Unrealized gain (loss) on derivatives
Crude oil fixed price swaps		(165,043	)		(2,213	)
Crude oil collars		(195,088	)		(4,549	)
Natural gas fixed price swaps		(3,956	)		28,326
Natural gas basis swaps		—			488

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. Derivative contracts are carried at their fair value on the consolidated balance sheets under the captions “Derivative assets”, “Noncurrent derivative assets” and “Accrued liabilities and other.”


	June 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	$	62,625	$	—	$	62,625	$	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 ~~input~~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

value of assets and liabilities and their placement within the fair value hierarchy levels. In determining the fair value of fixed price swaps and basis swaps, due to the unavailability of relevant comparable market data for the Company’s exact contracts, a discounted cash flow method is used. 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 ~~June 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 six month periods~~months ended ~~June 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 six month periods~~months ended ~~June 30, 2010.~~March 31, 2011.


	Fair value measurements at June 30, 2010 using:							Total			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*
											*in thousands*
Derivative assets (liabilities):
Fixed price swaps	$	—	$	31,886		$	—	$	31,886		$	—	$	(233,927	)	$	—		$	(233,927	)
Basis swaps		—		(1,071	)		—		(1,071	)
Collars		—		—			31,810		31,810			—		—			(298,506	)		(298,506	)

Total	$	—	$	30,815		$	31,810	$	62,625		$	—	$	(233,927	)	$	(298,506	)	$	(532,433	)


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

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

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

Gains and losses included in earnings for the three ~~and six~~ month periods ended ~~June 30,~~March 31, 2011 and 2010 attributable to the change in unrealized gains and losses relating to derivatives held at ~~June 30,~~March 31, 2011 and 2010 are reported in ~~revenues.~~“Revenues – Gain (loss) on derivative instruments, net”.

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

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 ~~in existing fields, capital constraints,~~which management estimates will not be transferred to proved properties over the life of the lease based on experience of successful drilling and ~~amortization of new fields resulted in impairment~~the average holding period. The fair value of non-producing properties ~~of $18.8 million and $13.2 million for the three months ended June 30, 2010 and 2009, respectively and $33.0 million and $22.6 million for the six months ended June 30, 2010 and 2009, respectively.~~is calculated using significant unobservable inputs (Level 3).

As a result of changes in reserves and the ~~forward~~commodity futures price ~~strip, developed oil and gas~~strips, proved properties were reviewed for impairment at ~~June 30, 2010. The Company determined that the carrying amounts of certain fields~~March 31, 2011. No impairment provisions were not recoverable from future cash flows and, therefore, were impaired at June 30, 2010. The affected fields had a fair value of $1.0 million at June 30, 2010 resulting in $0.7 million of developed property impairmentsrecorded for the quarter ended June 30, 2010. A similar calculation at March 31, 2010 determined that the carrying amounts of certain fields were not recoverable from future cash flows and, therefore, were impaired. The affected fields at March 31, 2010 had no fair value resulting in $1.0 million of developed property impairments for the first quarter of 2010. Total pre-tax (non-cash) impairments related to developedCompany’s proved crude oil and natural gas properties for the three ~~and six~~ months ended ~~June 30, 2010~~March 31, 2011. For that period, future cash flows were ~~$0.7 million~~determined to be in excess of cost basis, therefore no impairment was necessary. Certain non-producing properties were impaired at March 31, 2011, reflecting amortization of leasehold costs. The following table sets forth the pre-tax non-cash impairments of both proved and ~~$1.7 million, respectively. Impairments of developed~~non-producing properties ~~amounted to $10.1 million and $36.1 million~~ for the ~~three and six months ended June 30, 2009, respectively. Developed~~indicated periods. Proved and non-producing property impairments are recorded under the caption “Property impairments” in the unaudited condensed consolidated statements of operations.

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 $0.3~~were $0.6 million and $0.4 million for ~~both~~ the three months ended ~~June 30,~~March 31, 2011 and 2010, ~~and 2009 and was $0.7 million for both the six months ended June 30, 2010 and 2009,~~respectively, which isare 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.

   June 30, 2010    December 31, 2009
In thousands    Carrying
Amount    Fair Value    Carrying
Amount    Fair Value
Long-term debt

Revolving credit facility
   $ 114,000    $ 114,000    $ 226,000    $ 226,000
8¹/4% Senior Notes due 2019⁽¹⁾
   297,607    315,390    297,524    315,750
7³/8% Senior Notes due 2020⁽²⁾
   198,237    198,240    —      —

Total
   $ 609,844    $ 627,630    $ 523,524    $ 541,750
Notes to Unaudited Condensed Consolidated Financial Statements – continued

The fair value of the revolving credit facility approximates its carrying value based on the borrowing rates ~~currently~~ available to the Company for bank loans with similar terms and maturities. The fair ~~value~~values of the 8¹/4% Senior Notes due 2019, ~~and~~ 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 ~~these~~those instruments.


	June 30, 2010		December 31, 2009
*In thousands*					March 31, 2011		December 31, 2010
Revolving credit facility	$	114,000	$	226,000	$	—	$	30,000
8¹/4% Senior Notes due 2019⁽¹⁾		297,607		297,524		297,740		297,696
7³/8% Senior Notes due 2020⁽²⁾		198,237		—		198,325		198,295
7¹/8% Senior Notes due 2021⁽³⁾						400,000		400,000

Total long-term debt	$	609,844	$	523,524	$	896,065	$	925,991

The Company had no debt outstanding at March 31, 2011 on its revolving credit facility due July 1, 2015. At December 31, 2010, the Company ~~entered into an amended and restated~~had $30.0 million of outstanding borrowings on its revolving credit ~~agreement (the “Restated Credit Agreement”).~~facility. The ~~Restated Credit Agreement amended and restated the previous credit agreement to, among other things:~~

175 basis points. Borrowings ~~under the Restated Credit Agreement~~ are secured by anthe 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. Borrowings are subject to varying rates of interest based on the total outstanding borrowings in relation to the borrowing base and whether the loan is a Eurodollar advance, a reference rate advance or a swing line advance.

The Company had ~~$114.0~~$747.6 million of unused commitments (after considering outstanding ~~borrowings on the amended~~letters of credit) under its revolving credit facility at ~~June 30, 2010. The Company’s weighted average interest rate on this debt was 2.52% at June 30, 2010.~~

~~The Company had $634.5 million of unused commitments under the revolving credit facility at June 30, 2010~~March 31, 2011 and incurs commitment fees of 0.50% per annum of the daily average amount of unused borrowing availability. The ~~Restated Credit Agreement~~credit agreement contains certain restrictive covenants including a requirement that the Company maintain a current ratio of not less than 1.0 to 1.0 ~~(inclusive of available borrowing capacity under the Restated Credit Agreement)~~ and a ratio of total funded debt to EBITDAX of no greater than 3.75 to 1.0. As defined by the credit agreement, the current ratio represents the ratio of current assets to current liabilities, inclusive of available borrowing capacity under the credit agreement and exclusive of current balances associated with derivative contracts and asset retirement obligations. EBITDAX represents earnings before interest expense, income taxes, depreciation, depletion, amortization and accretion, property impairments, exploration expenses, unrealized derivative gains

and losses and non-cash equity compensation expense. EBITDAX is not a 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 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 ~~June 30, 2010.~~March 31, 2011.

The 8¹/4% Senior ~~Subordinated Notes due 2019 –~~ ~~On September 23, 2009, the Company issued Senior~~ Notes due 2019 (the “2019 Notes”), ~~which carry an interest rate of 8.25%~~the 7³/8% Senior Notes due 2020 (the “2020 Notes”), and ~~were sold at a discount (99.16% of par), which equates to an effective yield to maturity of approximately 8.375%. The Company received net proceeds of approximately $289.7 million after deducting~~ the ~~initial purchasers’ discounts and offering expenses. The net proceeds were used to repay a portion of~~7¹/8% Senior Notes due 2021 (the “2021 Notes”) (collectively, the ~~borrowings outstanding under the revolving credit facility.~~

~~The 2019 Notes~~“Notes”) will mature on October 1, 2019, October 1, 2020, and ~~interest~~April 1, 2021, respectively. Interest on the Notes is payable semi-annually on April 1 and October 1 of each year, ~~commencing~~with interest on the 2021 Notes having commenced on April 1, ~~2010.~~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 ~~price~~prices specified in the ~~Indenture dated September 23, 2009 (the “2009 Indenture”~~Notes’ respective indentures (together, the “Indentures”) plus accrued and unpaid interest. The Company may also redeem the ~~2019~~ Notes, in whole or in part, at athe “make-whole” redemption ~~price~~prices specified in the ~~2009 Indenture,~~Indentures plus accrued and unpaid interest at any time prior to October 1, ~~2014.~~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.

7³/8~~% Senior Subordinated~~ The Notes ~~due 2020 –~~ ~~On April 5, 2010, the Company issued $200 million of 7~~³/8~~% Senior Notes due 2020 (the “2020 Notes”). The 2020 Notes, which carry an interest rate of 7.375%, were sold at a discount (99.105% of par), which equates~~are not subject to an effective yield to maturity of approximately 7.50%. The 2020 Notes were offered and sold in a transaction exempt from the registration requirements of the Securities Act of 1933, as amended (the “Securities Act”), and were sold to qualified institutional buyers in reliance on Rule 144A of the Securities Act. The Company received net proceeds of approximately $194.2 million after deducting the initial purchasers’ discounts of approximately $1.8 million and initial purchasers’ fees of approximately $4.0 million. The net proceeds were used to repay a portion of the borrowings outstanding under the revolving credit facility.any mandatory redemption or sinking fund requirements.

The 2020 Notes will mature on October 1, 2020, and interest is payable on the 2020 Notes semi-annually on April 1 and October 1 of each year, commencing on October 1, 2010. The Company has the option to redeem all or a portion of the 2020 Notes at any time on or after October 1, 2015 at the redemption prices specified in the Indenture dated April 5, 2010 (the “2010 Indenture” and together with the 2009 Indenture, the “Indentures”) plus accrued and unpaid interest. The Company may also redeem the 2020 Notes, in whole or in part, at a “make-whole” redemption price specified in the 2010 Indenture, plus accrued and unpaid interest, at any time prior to October 1, 2015. In addition, the Company may redeem up to 35% of the 2020 Notes prior to October 1, 2013 under certain circumstances with the net cash proceeds from certain equity offerings.

In connection with the issuance and sale of the 2020 Notes, the Company entered into a registration rights agreement (the “Registration Rights Agreement”) with the initial purchasers dated April 5, 2010. Pursuant to the Registration Rights Agreement, the Company has agreed to file a registration statement with the SEC so that holders of the 2020 Notes can exchange the 2020 Notes for registered notes that have substantially identical terms as the 2020 Notes. The Company has agreed to use reasonable effort to cause the exchange to be completed within 400 days after the April 5, 2010 issuance of the 2020 Notes. The Company is required to pay additional interest if it fails to comply with its obligations to register the 2020 Notes within the specified time period, whereby the interest rate on the 2020 Notes 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 Agreement and complete the exchange of the 2020 Notes within the 400 day period.

~~The~~ Indentures ~~for the 2019 Notes and 2020 Notes (together, “the Notes”)~~ 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 ~~Notes are not subject to any sinking fund requirements. The~~Company was in compliance with these covenants at March 31, 2011. One of 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 ~~June 30, 2010,~~March 31, 2011, the Company had ~~one~~various drilling ~~contract that expires~~rig contracts with various terms extending through June 2012. These contracts were entered into in ~~August 2011. This commitment is~~the ordinary course of business to ensure rig availability to allow the Company to execute its business objectives in its key strategic plays. These drilling commitments are not recorded in the accompanying condensed consolidated balance sheets. Future commitments as of ~~June 30,~~March 31, 2011 total approximately $65 million, of which $57 million is for contracts that expire in 2011 and $8 million is for contracts that expire in 2012.

Fracturing and well stimulation services arrangement – In August 2010, the Company entered into an agreement with a third party whereby the third party will provide, on a take-or-pay basis, hydraulic fracturing services and related equipment to service certain of the Company’s properties in North Dakota and Montana. The arrangement has a term of three years, beginning in October 2010, with two one-year extensions available to the Company at its discretion. Pursuant to the take-or-pay arrangement, 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 ~~$10.1~~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.~~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 six months ended June 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 $0.8~~associated with the plan amounted to $0.9 million and ~~$0.5~~$0.3 million for the ~~six~~three months ended ~~June 30,~~March 31, 2011 and 2010, respectively.

Employee health ~~claims.~~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 June 30, 2010~~March 31, 2011 and December 31, ~~2009.~~2010, respectively.

~~Litigation.~~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 ~~June 30, 2010~~March 31, 2011 and December 31, ~~2009,~~2010, the Company has ~~provided~~recorded a ~~reserve~~liability in “Other noncurrent liabilities” of $4.5 million and ~~$4.3~~$4.6 million, respectively, for various matters, none of which are believed to be individually significant.

Environmental ~~Risk.~~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 ~~general~~the caption “General and administrative ~~expense was $3.1 million~~expenses” in the unaudited condensed consolidated statements of operations, is reflected in the table below for the three months ended June 30, 2010 and $2.7 million for the three months ended June 30, 2009. The Company’s associated compensation expense included in general and administrative expense was $6.0 million for the six months ended June 30, 2010 and $5.4 million for the six months ended June 30, 2009.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 ~~June 30, 2010,~~March 31, 2011, options covering ~~2,005,973~~2,213,193 shares had been exercised and ~~478,496~~535,893 had been ~~cancelled.~~canceled.

The Company’s stock option activity under the 2000 Plan for the ~~six~~three months ended ~~June 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 ~~six~~three months ended ~~June 30, 2010~~March 31, 2011 was approximately ~~$0.2~~$0.3 million. At ~~June 30, 2010,~~March 31, 2011, all stock options were exercisable and had a weighted average remaining life of ~~0.8 years~~1.0 year with an aggregate intrinsic value of ~~$13.4~~$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 ~~June 30, 2010,~~March 31, 2011, the Company had ~~3,291,463~~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 ~~six~~three months ended ~~June 30, 2010~~March 31, 2011 is presented below:


	Number of non-vested shares		Weighted average grant-date fair value		Number of non-vested shares			Weighted average grant-date fair value
Non-vested restricted shares at December 31, 2009	1,126,821		$	26.55
Non-vested restricted shares at December 31, 2010						1,108,077		$	35.72
Granted	46,343			40.84		47,480			68.31
Vested	(84,051	)		31.07		(21,036	)		29.36
Forfeited	(25,709	)		32.00		(1,948	)		35.51

Non-vested restricted shares at June 30, 2010	1,063,404			26.68
Non-vested restricted shares at March 31, 2011						1,132,573			37.21

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 ~~six~~three months ended ~~June 30, 2010~~March 31, 2011 at ~~their~~the vesting date was ~~$3.8~~$1.3 million. As of ~~June 30, 2010,~~March 31, 2011, there was ~~$15.0~~$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 ~~1.2~~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 million,~~ of ~~which $17.7 million was received in June 2010 and the remaining $17.7 million is expected to be received during the third quarter of 2010.~~$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 ~~current~~ 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 ~~will use~~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.~~

ITEM 2.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with our historical consolidated financial statements and the notes included in our Annual Report on Form 10-K for the year ended December 31, ~~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 Anadarko Woodford and Arkoma Woodford plays in Oklahoma. The East region contains properties east of the Mississippi river including the Illinois Basin and the state of Michigan.

We focus our exploration activities in large new or developing plays that provide us the opportunity to acquire undeveloped acreage positions for future drilling operations. We have been successful in targeting large repeatable resource plays where horizontal drilling, advanced fracture stimulation and enhanced recovery technologies provide the means to economically develop and produce crude oil and natural gas reserves from unconventional formations. We derive the majority of our operating income and cash flows from the sale of crude oil and natural gas. We expect that growth in our revenues and operating income ~~and revenues~~ 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 ~~six~~three months of ~~2010,~~2011, our crude oil and natural gas production increased to ~~7,273~~4,650 MBoe ~~(40,180~~(51,663 Boe per day), up ~~562~~1,191 MBoe, or 8%34%, from the first ~~six~~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.~~field and Anadarko Woodford play in Oklahoma. Our crude oil and natural gas revenues for the first ~~six~~three months of ~~2010~~2011 increased ~~83%~~50% to ~~$436.5~~$326.5 million due to a ~~62%~~15% increase in realized commodity prices along with increased production compared to the same period in ~~2009.~~2010. Our realized price per Boe increased ~~$22.93~~$9.07 to ~~$59.92~~$71.14 for the ~~six~~three months ended ~~June 30, 2010~~March 31, 2011 compared to the ~~six~~three months ended June 30, 2009. For the six month period ended June 30, 2010, we experienced increases in production taxes and other expenses of $15.8 million, or 86%, compared to the first six months of 2009, due to an increase in 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 ~~six~~three months ended ~~June 30, 2010,~~March 31, 2011, crude oil sales volumes were 1360 MBbls ~~more~~less than crude oil production, and crude oil sales volumes were ~~251~~40 MBbls ~~less~~more than crude oil production for the same period in ~~2009.~~2010. Our cash flows from operating activities for the ~~six~~three months ended ~~June 30, 2010~~March 31, 2011 were ~~$390.2~~$195.6 million, an increase of ~~$307.7~~$4.9 million from ~~$82.5~~$190.7 million provided by our operating activities during the comparable ~~2009~~2010 period. The increase in operating cash flows was primarily due to ~~increases in revenue~~increased crude oil and natural gas revenues as a result of higher commodity ~~prices.~~prices and sales volumes. During the ~~six~~three months ended ~~June 30, 2010,~~March 31, 2011, we invested ~~$526.3~~$412.8 million (including increased accruals for capital expenditures of ~~$40.5~~$31.1 million and ~~$1.9~~$4.3 million of seismic costs) in our capital program, concentrating mainly in the North Dakota Bakken field and the ~~Arkoma 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~~2011 capital expenditures budget of ~~$1.3~~$1.75 billion will focus primarily ~~focus~~ 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. Continued strength in commodity prices may result in an increase in our actual capital expenditures during 2010; conversely, a significant decline in product prices could result in a decrease in our capital expenditures.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 ~~June 30, 2010~~March 31, 2011 compared to the three months ended ~~June 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 June 30,						Volume increase			Percent increase			Three months ended March 31,
	2010			2009								2011							2010						Volume increase				Percent increase
	Volume	Percent		Volume	Percent							Volume				Percent			Volume			Percent							Percent increase
Crude oil (MBbl)	2,877	75	%	2,517	74	%		360			14	%			3,460			74	%		2,621			76	Volume increase	%			839				32	%
Natural Gas (MMcf)	5,625	25	%	5,293	26	%		332			6	%			7,137			26	%		5,026			24	%			2,111				42	%

Total (MBoe)	3,815	100	%	3,398	100	%	417			12	%			4,650			100	%		3,459			100	%			1,191				34	%

	Three months ended June 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	3,033	80	%	2,585	76	%		448			17	%			3,660			79	%		2,707			78	%			953				35	%
South Region	675	17	%	680	20	%		(5	)		(1	)%			886			19	%		628			18	%			258				41	%
East Region	107	3	%	133	4	%	(26	)		(20	)%			104			2	%		124			4	%			(20	)			(16	)%

Total (MBoe)	3,815	100	%	3,398	100	%	417			12	%
Total														4,650			100	%		3,459			100	%			1,191				34	%

Crude oil production volumes increased ~~14%~~32% during the three months ended ~~June 30, 2010~~March 31, 2011 compared to the three months ended ~~June 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 ~~520~~850 MBbls, ~~in excess of~~a 43% increase over production for the ~~second~~first quarter of ~~2009.~~2010. Favorable drilling results ~~from drilling~~ have been the primary contributors to production growth in these areas. ~~This increase was partially offset by a decrease of 128 MBbls in the Montana Bakken due to wells shut in for repairs and natural declines.~~ Natural gas production volumes increased ~~332~~2,111 MMcf, or 6%42%, during the three months ended ~~June 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 ~~609~~635 MMcf, or 62%, for the three months ended ~~June 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. ~~These additional sales~~Natural gas production in the ~~Bakken field were partially offset by decreases in natural gas volumes of 193~~Oklahoma Woodford area increased 1,196 MMcf, or 52%, due to additional wells being completed and producing in the ~~Cedar Hills field due~~three months ended March 31, 2011 compared to the ~~conversion to water floods and 60 MMcf~~same period in ~~the South region due to natural declines.~~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 ~~June 30, 2010~~March 31, 2011 were ~~$219.4~~$326.5 million, a 50% increase from sales of ~~$146.4~~$217.1 million for the same period in ~~2009.~~2010. Our sales volumes increased ~~423~~1,090 MBoe, or ~~13%~~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 ~~$14.42~~$9.07 to ~~$57.94~~$71.14 for the three months ended ~~June 30, 2010~~March 31, 2011 from ~~$43.52~~$62.07 for the three months ended ~~June 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 ~~June 30, 2010~~March 31, 2011 was ~~$9.59~~$9.21 compared to ~~$6.02~~$7.42 for the three months ended ~~June 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 for gasoline.~~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 operations under the caption “Gain (loss) on ~~mark-to-market~~ derivative ~~instruments.~~instruments, net.”

During the three months ended ~~June 30, 2010,~~March 31, 2011, we realized losses on crude oil derivatives of $13.3 million and realized gains on natural gas derivatives of ~~$6.8 million and realized gains on crude oil derivatives of $6.0~~$8.1 million. During the three months ended ~~June 30, 2010,~~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 ~~$10.0~~$4.0 million. During the three months ended March 31, 2010, we realized gains on crude oil derivatives of $2.5 million and realized gains on natural gas derivatives of $1.8 million. During the three months ended 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 ~~crude oil derivatives of $52.7 million. During the three months ended June 30, 2009, our crude oil production was unhedged and we reported non-cash unrealized mark-to-market gains from our~~natural gas derivatives of ~~$0.9 million for such period.~~$28.8 million.

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


	Three months ended March 31,
Reclaimed crude oil sales	2011		2010		Variance
Average sales price ($/Bbl)	$	79.67	$	68.25	$	11.42
Sales volumes (barrels)		52,138		55,361		(3,223	)

Prices for reclaimed crude oil sold from our central treating units were $11.42 per barrel higher for the three months ended ~~June 30, 2010~~March 31, 2011 than the comparable ~~2009 period. The price increased $20.70 per barrel~~2010 period, which ~~increased~~contributed to an increase in reclaimed crude oil ~~income by $1.6~~revenue of $0.5 million to $4.7 million, contributing to an overall increase in crude oil and natural gas service operations revenue of ~~$0.6~~$1.8 million for the three months ended ~~June 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 $0.4 million for the three months ended June 30, 2009. Beginning 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 ~~$1.4~~$1.5 million to ~~$4.1~~$5.5 million during the three months ended ~~June 30, 2010~~March 31, 2011 from ~~$2.7~~$4.0 million during the three months ended ~~June 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 ~~decreased 7%~~increased 30% to ~~$22.3~~$29.3 million during the three months ended ~~June 30, 2010~~March 31, 2011 from ~~$24.0~~$22.6 million during the three months ended ~~June 30, 2009.~~March 31, 2010 due primarily to higher production volumes. Production expense per Boe decreased to ~~$5.90~~$6.38 for the three months ended ~~June 30, 2010~~March 31, 2011 from ~~$7.14~~$6.46 per Boe for the three months ended ~~June 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 for a term of 16 months 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. Also contributing~~expenses compared to ~~the decrease was a non-recurring charge recorded in the prior year period to accrue for potential loss exposure on royalty disputes.~~2010.

Production taxes and other expenses increased ~~$6.6~~$11.6 million, or ~~57%~~72%, to $27.6 million during the three months ended ~~June 30, 2010~~March 31, 2011 compared to the three months ended ~~June 30, 2009~~March 31, 2010 as a result of higher crude oil and natural gas revenues resulting from increased ~~sales~~commodity prices and sales volumes along with the expiration of various tax incentives. Production taxes and other expenses inon the unaudited condensed consolidated statements of operations ~~includes~~include other charges for marketing, gathering, dehydration and compression fees primarily related to natural gas sales in the ~~Arkoma area~~Oklahoma Woodford and North Dakota Bakken areas of ~~$1.6~~$2.2 million and ~~$2.3~~$1.1 million for the three months ended ~~June 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 ~~7.4%~~7.8% for the three months ended ~~June 30, 2010~~March 31, 2011 compared to ~~6.4%~~7.0% for the three months ended ~~June 30, 2009.~~March 31, 2010. The increase is due to ~~oil extraction~~the expiration of various tax incentives coupled with higher taxable revenues in North Dakota, ~~realized during the three months ended June 30, 2009, no longer being applicable to wells completed in 2010, causing higher~~our most active area, which has production tax rates ~~on production from this area where we are most active.~~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 June 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	$	5.90	$	7.14	(17	)%	$	6.38	$	6.46		(1	)%
Production taxes and other expenses		4.81		3.46	39	%		6.01		4.58		31	%

Production expenses, production taxes and other expenses	$	10.71	$	10.60	1	%	$	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 ~~$0.7~~$5.0 million in the three months ended ~~June 30, 2010~~March 31, 2011 to ~~$2.3~~$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 ~~$0.5 million and dry hole expense of $0.2 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 ~~$5.7~~$23.1 million, or ~~11%~~44%, in the ~~second~~first quarter of 2011 compared to the first quarter of 2010, ~~compared to the second 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 June 30,				Three months ended March 31,
*$/Boe*	2010		2009		2011		2010
Crude oil and natural gas	$	15.12	$	15.40	$	16.07	$	14.62
Other equipment		0.24		0.23		0.25		0.23
Asset retirement obligation accretion		0.17		0.17		0.17		0.18

Depreciation, depletion, amortization and accretion	$	15.53	$	15.80	$	16.49	$	15.03

The increase in DD&A per Boe ~~decreased~~is partially ~~as a~~the result of a gradual shift in our production base from our historic production base of the ~~increase~~Red River units in ~~commodity prices used~~the Cedar Hills field to ~~calculate year-end 2009 reserve volumes as compared to~~our new production base in the ~~prices used to calculate year-end 2008 reserve volumes. Higher prices have the effect of increasing the economic life of oil and gas~~Bakken field. Our producing properties ~~which increases future reserve volumes and decreases DD&A on a volumetric basis. Additionally, our costs of adding new reserves~~ in the Bakken field ~~have been lower~~typically carry a higher DD&A rate due to the existence of higher cost reserves in ~~2010~~that field compared to ~~our historical averages, resulting~~other areas in ~~lower DD&A rates being applied to production in that area compared to the prior year.~~which we operate.

Property Impairments. Property impairments, both proved and non-producing, ~~and developed, decreased~~increased in the three months ended ~~June 30, 2010~~March 31, 2011 by ~~$3.8~~$5.6 million to ~~$19.5~~$20.8 million compared to ~~$23.3~~$15.2 million for the three months ended March 31, 2010.

Impairment of non-producing properties increased $6.6 million during the three months ended ~~June 30, 2009.~~

~~Impairment of non-producing properties increased $5.6 million during the three months ended June 30, 2010~~March 31, 2011 to ~~$18.8~~$20.8 million compared to ~~$13.2~~$14.2 million for the three months ended ~~June 30, 2009~~March 31, 2010 reflecting ~~amortization of new fields and~~ higher amortization of ~~lease~~leasehold costs ~~in our existing fields~~ resulting from ~~further defining likely drilling locations and capital constraints.~~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.

Impairment provisions for developed crude oil and natural gas properties were approximately $0.7 million for the three months ended June 30, 2010 compared to approximately $10.1 million for the three months ended June 30, 2009, a decrease of $9.4 million, or 93%. We evaluate our developed 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 developed properties in 2010 reflect uneconomic operating results in the East region, which resulted in impairments of $0.7 million for the three months ended June 30, 2010. Impairments of developed properties in 2009 reflect uneconomic drilling results primarily in our South region, which resulted in impairments of $10.0 million.

~~General and Administrative Expenses.~~ General and administrative expenses increased $2.1 million to $11.5 million during the three months ended June 30, 2010 from $9.4 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 $3.1 million and $2.7 million for the three months ended June 30, 2010 and 2009, respectively. General and administrative expenses excluding stock-based compensation increased $1.7 million for the three months ended June 30, 2010 compared to the same period in 2009. On a volumetric basis, general and administrative expenses increased $0.25 to $3.03 per Boe for the three months ended June 30, 2010 compared to $2.78 per Boe for the three months ended June 30, 2009.

~~Interest Expense.~~ Interest expense increased 152%, or $7.2 million, for the three months ended June 30, 2010 compared to the three months ended June 30, 2009, due to higher interest rates on the Notes compared to our credit facility borrowings in the prior year, along with an increase in our outstanding debt balance. On September 23, 2009, we issued $300.0 million of 2019 Notes, which carry an interest rate of 8.25% and were sold at a discount (99.16% of par), which equates to an effective yield to maturity of approximately 8.375%. On April 5, 2010, we issued $200.0 million of 7³/8% Senior Notes due 2020 (the “2020 Notes”), which carry an interest rate of 7.375% and were sold at a discount (99.105% of par), which equates to an effective yield to maturity of approximately 7.5%. We recorded $9.7 million in interest expense on the 2019 Notes and the 2020 Notes for the three months ended June 30, 2010. Including the interest on the Notes our weighted average interest rate for the three months ended June 30, 2010 was 7.1% while for the three months ended June 30, 2009 our weighted average rate was 2.72%.

Our average revolving credit facility balance decreased to $98.7 million for the three months ended June 30, 2010 compared to $612.6 million for the three months ended June 30, 2009, and the weighted average interest rate on our revolving credit facility was lower at 2.43% for the three months ended June 30, 2010 compared to 2.72% for the same period in 2009. At June 30, 2010, our outstanding revolving credit facility balance was $114.0 million with a weighted average interest rate of 2.52%.

~~Income Taxes.~~ We recorded income tax expense for the three months ended June 30, 2010 of $62.8 million compared to $8.3 million for the three months ended June 30, 2009. We provide taxes at a combined federal and state tax rate of approximately 38% after taking into account permanent taxable differences.

~~Six months ended June 30, 2010 compared to the six months ended June 30, 2009~~

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

~~(1)~~

~~Net of gain on sale of assets of $33.3 million and $0.2 million for the six months ended June 30, 2010 and 2009, respectively.~~

~~(2)~~

~~Average prices have been calculated using sales volumes and excluding any effect of derivative transactions.~~

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

Crude oil production volumes increased 12% during the six months ended June 30, 2010 compared to the six months ended June 30, 2009. Production increases in the North Dakota Bakken field, Cedar Hills field and the Oklahoma Woodford contributed incremental volumes in 2010 of 941 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 234 MBbls due to wells shut in for repairs and natural declines. Natural gas volumes decreased 166 MMcf, or 2%, during the six months ended June 30, 2010 compared to the same period in 2009. Natural gas production in the Bakken field in the North region was up 1,178 MMcf for the six months ended June 30, 2010 compared to the same period in 2009 due to additional natural gas being connected and sold in North Dakota. These additional sales in North Dakota were offset by a decrease in natural gas volumes of 548 MMcf in the Red River units due to the conversion to water floods and the Badlands plant being down for repairs. Further, the South region natural gas volumes decreased 791 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 six months ended June 30, 2010 were $436.5 million, an 83% increase from sales of $239.0 million for the same period in 2009. Our sales volumes increased 825 MBoe, or 13%, 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 $22.93 to $59.92 for the six months ended June 30, 2010 from $36.99 for the six months ended June 30, 2009. The differential between NYMEX calendar month average crude oil prices and our realized crude oil price per barrel for the six months ended June 30, 2010 was $8.54 compared to $7.08 for the six months ended June 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 for gasoline.

~~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 statements of operations under the caption “Gain on mark-to-market derivative instruments.”

During the six months ended June 30, 2010, we realized gains on natural gas derivatives of $8.6 million and realized gains on crude oil derivatives of $8.5 million. During the six months ended June 30, 2010, we reported an unrealized non-cash mark-to-market gain on natural gas derivatives of $18.8 million and an unrealized non-cash mark-to-market gain on crude oil derivatives of $45.9 million. During the six months ended June 30, 2009, our crude oil production was unhedged and we reported non-cash unrealized mark-to-market gains from our gas derivatives of $0.9 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. Prices for reclaimed crude oil sold from our central treating units were higher for the six months ended June 30, 2010 than the comparable 2009 period. The price increased $29.05 per barrel which increased reclaimed crude oil income by $3.4 million, contributing to an overall increase in crude oil and natural gas service operations revenue of $1.4 million for the six months ended June 30, 2010. We sold high-pressure air from our Red River units to a third party and recorded revenues of $1.1 million for the six months ended June 30, 2009. Beginning January 2010, we no longer sell high-pressure air to a third party. Associated crude oil and natural gas service operations expenses increased $2.9 million to $8.0

million during the six months ended June 30, 2010 from $5.1 million during the six months ended June 30, 2009 due mainly to an increase in the costs of purchasing and treating crude oil for resale compared to the same period in 2009.

~~Production Expenses and Production Taxes and Other Expenses~~. Production expenses decreased 3% to $44.9 million during the six months ended June 30, 2010 from $46.5 million during the six months ended June 30, 2009. Production expenses per Boe decreased to $6.17 for the six months ended June 30, 2010 from $7.19 per Boe for the six months ended June 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 for a term of 16 months 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 disputes.

Production taxes and other expenses increased $15.8 million, or 86%, during the six months ended June 30, 2010 compared to the six months ended June 30, 2009 as a result of higher revenues resulting from increased sales prices and the expiration of various tax incentives. Production taxes and other expenses in 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 area of $2.9 million and $3.5 million for the six months ended June 30, 2010 and 2009, respectively. Production taxes, excluding other charges, as a percentage of crude oil and natural gas sales were 7.2% for the six months ended June 30, 2010 compared to 6.3% for the six months ended June 30, 2009. The increase is due to oil extraction tax incentives in North Dakota realized during the six months ended June 30, 2009, no longer being applicable to wells completed in 2010, causing higher tax rates on production from this area where we are most active. 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 $4.6 million in the six months ended June 30, 2010 to $4.1 million due primarily to a decrease in dry hole expense of $4.6 million.

~~Depreciation, Depletion, Amortization and Accretion.~~Total DD&A increased $7.6 million, or 7%, in the first six 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. Additionally, our costs of adding new reserves in the Bakken field have been lower in 2010 compared to our historical averages, resulting in lower DD&A rates being applied to production in that area compared to the prior year.

~~Property Impairments.~~ Property impairments, non-producing and developed, decreased in the six months ended June 30, 2010 by $24.0 million to $34.7 million compared to $58.7 million during the six months ended June 30, 2009.

Impairment of non-producing properties increased $10.4 million during the six months ended June 30, 2010 to $33.0 million compared to $22.6 million for the six months ended June 30, 2009 reflecting amortization of new fields and higher amortization of lease costs in our existing fields resulting from further defining likely drilling locations and capital constraints. 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 developed crude oil and natural gas properties were approximately $1.7 million for the six months ended June 30, 2010 compared to approximately $36.1 million for the six months ended June 30, 2009, a decrease of $34.4 million, or 95%. We evaluate our developed 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. We did not record any impairment provisions for proved oil and gas properties for the three months ended March 31, 2011. For that period, future cash flows were determined to be in excess of cost basis, therefore no impairment was necessary. Impairment provisions for proved crude oil and natural gas properties were $1.0 million for the three months ended March 31, 2010. Impairments of ~~developed~~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 six months ended June 30, 2010. Impairments of developed properties in 2009 reflect uneconomic drilling results in three single well fields completed in the first half of 2009 in our South region, which resulted in impairments of $24.8 million. The remaining 2009 impairments were $4.1 million in the East region and $7.2 in the North region due to decreases in reserves and prices.region.

General and Administrative Expenses. General and administrative expenses increased ~~$3.7~~$4.5 million to ~~$23.3~~$16.3 million during the ~~six~~three months ended ~~June 30, 2010~~March 31, 2011 from ~~$19.6~~$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 ~~$6.0~~$3.6 million and ~~$5.4~~$2.9 million for the ~~six~~three months ended ~~June 30,~~March 31, 2011 and 2010, ~~and 2009,~~ respectively. General and administrative expenses excluding stock-based compensation increased ~~$3.1~~$3.8 million for the ~~six~~three months ended ~~June 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 ~~$0.16~~$0.17 to ~~$3.20~~$3.56 per Boe for the ~~six~~three months ended ~~June 30, 2010~~March 31, 2011 compared to ~~$3.04~~$3.39 per Boe for the ~~six~~three months ended ~~June 30, 2009.~~March 31, 2010.

Interest Expense. Interest expense increased ~~118%,~~$10.6 million, or ~~$11.0 million,~~127%, for the ~~six~~three months ended ~~June 30, 2010~~March 31, 2011 compared to the ~~six~~three months ended ~~June 30, 2009,~~March 31, 2010 due to an increase in our outstanding debt balance and higher rates of interest on our senior notes in the current year compared to lower interest rates on ~~the Notes compared to~~ our ~~revolving~~ credit facility borrowings in the prior year, along with higher debt balances. The 2019 Notes were issued on September 23, 2009 in an aggregate principal amount of $300.0 million and carry an interest rate of 8.25%. They were sold at a discount (99.16% of par), which equates to an effective yield to maturity of approximately 8.375%. The 2020 Notes were issued on April 5, 2010 in an aggregate principal amount of $200.0 million and carry an interest rate of 7.375%. They were sold at a discount (99.105% of par), which equates to an effective yield to maturity of approximately 7.5%.year. We recorded ~~$15.9~~$17.2 million in interest expense on the ~~Notes~~outstanding senior notes for the ~~six~~three months ended ~~June 30,~~March 31, 2011 compared with $6.3 million for the same period in 2010. Including the interest on both the ~~Notes,~~senior notes and revolving credit facility borrowings, our weighted average interest rate for the ~~six~~three months ended ~~June 30, 2010~~March 31, 2011 was ~~6.83%~~7.3% with a weighted average outstanding long-term debt balance of $971.9 million compared to ~~3.07%~~a weighted average interest rate of 6.1% with a weighted average outstanding long-term debt balance of $511.7 million for the ~~six months ended June 30, 2009.~~same period in 2010.

Our weighted average outstanding revolving credit facility balance decreased to ~~$157.3~~$71.9 million for the ~~six~~three months ended ~~June 30, 2010~~March 31, 2011 compared to ~~$546.6~~$211.7 million for the ~~six~~three months ended ~~June 30, 2009, and the~~March 31, 2010. The weighted average interest rate on our revolving credit facility borrowings was lower at 2.65% for the ~~six~~three months ended ~~June 30, 2010~~March 31, 2011 compared to ~~3.07%~~2.75% for the same period in ~~2009.~~2010. At ~~June 30, 2010,~~March 31, 2011, we had no outstanding borrowings on our ~~outstanding~~ revolving credit ~~facility balance was $114.0 million with a weighted average interest rate of 2.52%.~~facility.

Income Taxes. We recorded an income tax benefit for the three months ended March 31, 2011 of $84.2 million compared with income tax expense ~~for the six months ended June 30, 2010~~ of ~~$107.2 million compared to a benefit of $8.0~~$44.4 million for the ~~six~~three months ended ~~June 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.

Our primary sources of liquidity have been cash flows generated from operating activities, financing provided by our revolving credit facility and the issuance of ~~bonds.~~debt and equity securities. During the first ~~six~~three months of ~~2010, crude oil prices were $22.93~~2011, our average realized sales price was $9.07 per Boe higher than the first ~~six~~three months of ~~2009, and we have seen natural gas~~2010. The increase in realized commodity prices ~~for~~in the ~~first six months of 2010~~current year, coupled with our 31% increase ~~73% compared to the first six months of 2009. Since crude oil accounts for more than 75% of our production, the price increase~~in sales volumes, resulted in improved cash flows from operations and better liquidity.

~~On June 30, 2010,~~ Further, our liquidity has improved at March 31, 2011 as we ~~entered into an amended and restated revolving credit agreement (the “Restated Credit Agreement”). The Restated Credit Agreement amended and restated~~have more borrowing availability on our ~~previous credit agreement to, among other things:~~

~~Maintain aggregate commitments~~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 March 31, 2011, we had approximately $477.4 million of cash and cash equivalents and approximately $747.6 million of net available liquidity under our revolving credit facility (after considering outstanding letters of ~~$750~~credit).

Cash Flows

Cash Flows from Operating Activities

Our net cash provided by operating activities was $195.6 million ~~which may be increased at~~and $190.7 million for the three months ended March 31, 2011 and 2010, respectively. The increase in operating cash flows was primarily due to higher crude oil and natural gas revenues as a result of higher commodity prices and sales volumes in the current period.

Cash Flows from Investing Activities

During the three months ended March 31, 2011 and 2010, we had cash flows used in investing activities (excluding asset sales) of $377.5 million and $163.0 million, respectively, related to our ~~option from time to time (provided there exists no default) up~~capital program, inclusive of dry hole costs. The increase in our cash flows used in investing activities in 2011 was due to the ~~lesser~~continued acceleration of ~~$2.5 billion or~~our drilling program, primarily in the ~~borrowing base then~~North Dakota Bakken field and the Anadarko Woodford play in ~~effect;~~Oklahoma.

Our amended revolving credit facility is backed by a syndicate of 14 banks. We believe that the current syndicate of banks has the capability to fund up to their commitments. If one or more banks should not be able to fund their commitment, we may not have the full availability of the $750.0 million commitment.

~~On September 23, 2009, we issued $300.0 million of the 2019 Notes and received~~for total net proceeds of approximately ~~$289.7 million~~

after deducting initial purchasers’ discounts and other expenses and after giving effect to the discount at which the 2019 Notes were issued. The net proceeds were used to repay a portion of the borrowings outstanding under our revolving credit facility. On April 5, 2010, we issued $200.0 million of the 2020 Notes and received net proceeds of approximately $194.2$659.3 million, after deducting ~~initial purchasers’~~underwriting discounts and ~~other~~offering-related expenses, ~~and after giving effect to the discount at which the 2020 Notes were issued. The net proceeds from the 2020 Notes were used to repay a portion of the~~along with borrowings ~~outstanding~~on our credit facility, partially offset by amounts repaid under our ~~revolving~~ credit facility. AsNet cash used in financing activities of ~~June 30, 2010, we had $634.5~~$28.3 million ~~of borrowing availability under our revolving credit facility. As of July~~for the three months ended March 31, 2010 ~~we had $544.5 million~~was mainly the result of ~~borrowing availability~~amounts repaid under our ~~revolving~~ credit facility.

~~In June 2010, we sold certain non-strategic leaseholds located in DeSoto Parish, Louisiana to a third party with an effective date~~Future Sources of June 18, 2010. Total cash proceeds amounted to $35.4 million, of which $17.7 million was received in June 2010 and the remaining $17.7 million is expected to be received during the third quarter of 2010. In connection with the sale, we recognized a pre-tax gain of $32.2 million. The sale involved undeveloped acreage with no proved reserves and no current production or revenues. We will use the proceeds from the sale to fund a portion of our 2010 capital expenditures program.Financing

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.

WeBased 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; however, our financing needs~~facility, but may ~~require us to alter or increase our capitalization substantially through~~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.

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

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

We had no outstanding borrowings under our credit facility at March 31, 2011 and $30.0 million outstanding at December 31, 2010. As of March 31, 2011, we had $747.6 million of borrowing availability under our credit facility (after considering outstanding letters of credit). As previously discussed, we issued and sold an aggregate 10,080,000 shares of our common stock in March 2011 and received total net proceeds of approximately $659.3 million after deducting underwriting discounts and offering-related expenses. The net proceeds were used to repay all borrowings then outstanding under our credit facility, which had a balance prior to payoff of $155 million. As of May 2, 2011, we continued to have no outstanding borrowings and $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 ~~revolving~~ credit facility as a result of (i) a decrease in our borrowing base due to the outcome of a subsequent borrowing base redetermination, or (ii) an unwillingness or inability

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

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

Our net cash provided by operating activities was $390.2 million and $82.5 million for the six months ended June 30, 2010 and 2009, respectively. The increase in operating cash flows was mainly due to increases in revenue as a result of higher commodity prices.

During the six months ended June 30, 2010 and 2009, we had cash flows used in investing activities (excluding asset sales) of $483.9 million and $297.2 million, respectively, related to our capital program, inclusive of dry hole costs. The increase in our cash flows used in investing activities was primarily due to the accelerationAs part of our ~~drilling~~risk management program, ~~primarily in the North Dakota Bakken and Arkoma Woodford plays.~~

Net cash provided by financing activities for the six months ended June 30, 2010 was $73.3 million and was mainly the result of the issuance of the 2020 Notes along with borrowings on our revolving credit facility, partially offset by amounts repaid under our revolving credit facility. Net cash provided by financing activities of $213.1 million for the six months ended June 30, 2009 was mainly the result of amounts borrowed under our revolving credit facility to fund capital expenditures. On April 5, 2010, we ~~issued $200.0 million of 7~~³/8~~% Senior Notes due 2020 and received net proceeds of approximately $194.2 million, which were used to repay a portion of the borrowings outstanding under our revolving credit facility.~~

We had $114.0 million and $226.0 million outstanding under our revolving credit facility at June 30, 2010 and December 31, 2009, respectively. We used the net proceeds of $194.2 million from our April 5, 2010 issuance of the 2020 Notes to repayhedge a portion of our ~~outstanding revolving credit facility borrowings. As~~anticipated future crude oil and natural gas production to achieve more predictable cash flows and to reduce our exposure to fluctuations in crude oil and natural gas prices. Reducing our exposure to price volatility helps ensure that we have adequate funds 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 ~~July 31, 2010, we had $204.0 million of outstanding borrowings under~~current and future market conditions and our revolving credit facility. The amended and restated revolving credit facility that was entered into on June 30, 2010, has an aggregate commitment level of $750 million and a borrowing base of $1.3 billion that is subjectdesire to ~~semi-annual redetermination. We expect the next borrowing base redetermination to occur in the fourth quarter of 2010. The terms of the revolving credit facility~~

~~provide for the commitment level to be increased at our option from time to time (provided no default exists) up to the lesser of $2.5 billion or the current borrowing base.~~

On September 23, 2009, we issued $300 million of the 2019 Notes. The 2019 Notes, which carry an interest rate of 8.25%, were sold at a discount (99.16% of par), which equates to an effective yield to maturity of approximately 8.375%. We 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 outstanding under our revolving credit facility.

~~The 2019 Notes will mature on October 1, 2019, and interest is payable semi-annually on April 1 and October 1 of each year, commencing April 1, 2010. We~~ have the ~~option~~cash flows needed to ~~redeem all or a portion~~fund the development of ~~the 2019 Notes at any time on or after October 1, 2014 at the redemption price specified~~our inventory of undeveloped crude oil and natural gas reserves in the Indenture dated September 23, 2009 (the “2009 Indenture”) plus accrued and unpaid interest. We may also redeem the 2019 Notes, in whole or in part, at a “make-whole” redemption price specified in the 2009 Indenture, plus accrued and unpaid interest, at any time prior to October 1, 2014. In addition, we may redeem up to 35% of the 2019 Notes prior to October 1, 2012 under certain circumstances with the net cash proceeds from certain equity offerings. The 2009 Indenture contains certain restrictions on our ability to incur additional debt, pay dividends on our common stock, make investments, create liens on our assets, engage in transactionsconjunction with our ~~affiliates, transfer or sell assets, consolidate or merge, or sell substantially~~growth strategy. While the use of hedging arrangements limits the downside risk of adverse price movements, their use also limits future revenues from favorable price movements. Substantially all of our ~~assets. These covenants~~hedging transactions are ~~subject~~settled based upon reported settlement prices on the NYMEX.

We have hedged a significant portion of our forecasted production through 2013. Please seeNote 4. Derivative InstrumentsinNotes to Unaudited Condensed Consolidated Financial Statements for further discussion of the accounting applicable to our derivative instruments, a ~~number~~listing of ~~important exceptions~~open contracts at March 31, 2011 and ~~qualifications. We were in compliance with these covenants~~the estimated fair value of those contracts as of June 30, 2010. The 2019 Notes are not subject to any sinking fund requirements. Our subsidiary, which currently has no independent assets or operations, fully and unconditionally guarantees this debt.

~~On April 5, 2010, we issued $200 million of 7~~ ³Future Capital Requirements/8% Senior Notes due 2020. The 2020 Notes, which carry an interest rate of 7.375%, were sold at a discount (99.105% of par), which equates to an effective yield to maturity of approximately 7.5%. We received net proceeds of approximately $194.2 million after deducting the initial purchasers’ discounts and fees. The net proceeds were used to repay a portion of the borrowings outstanding under our revolving credit facility.

The 2020 Notes will mature on October 1, 2020, and interest is payable semi-annually on April 1 and October 1 of each year, commencing on October 1, 2010. We have the option to redeem all or a portion of the 2020 Notes at any time on or after October 1, 2015 at the redemption prices specified in the Indenture dated April 5, 2010 (the “2010 Indenture”) plus accrued and unpaid interest. We may also redeem the 2020 Notes, in whole or in part, at a “make-whole” redemption price specified in the 2010 Indenture, plus accrued and unpaid interest, at any time prior to October 1, 2015. In addition, we may redeem up to 35% of the 2020 Notes prior to October 1, 2013 under certain circumstances with the net cash proceeds from certain equity offerings. The 2010 Indenture contains certain restrictions on our ability to incur additional debt, pay dividends on our common stock, make certain investments, create certain liens on our assets, engage in certain transactions with our 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 June 30, 2010. The 2020 Notes are not subject to any sinking fund requirements. Our sole subsidiary, which currently has no independent assets or operations, fully and unconditionally guarantees this debt.

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.

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 ~~six~~three months ended ~~June 30, 2010,~~March 31, 2011, and excluding any effect of our derivative instruments in place, our annual revenue would increase or decrease by approximately ~~$110.9~~$140.3 million for each $10.00 per barrel change in crude oil prices and ~~$21.5~~$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 six months ended June 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 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 the recognition of a $364.1 million unrealized mark-to-market loss on derivative instruments at March 31, 2011. The ~~new contracts were entered into in~~unrealized mark-to-market loss relates to derivative instruments with various terms that are scheduled to be realized over the ~~normal course~~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 ~~business~~historically high commodity prices over a prolonged period could continue to have an adverse impact on the fair value of our derivative instruments and ~~we expect to enter into additional similar contracts during~~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 ~~year. None of the new contracts have been designated for hedge accounting. See~~ ~~Part I, Item 1. Financial Statements, Note 5 – Derivative Contracts~~ ~~for additional information regarding our swap and collar derivative contracts.~~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 ($~~151.5~~266.6 million in receivables at ~~June 30, 2010) and~~March 31, 2011), our joint interest receivables ($~~154.5~~293.9 million at ~~June 30, 2010)~~March 31, 2011), and counterparty credit risk associated with our derivative 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 $57.6 million at March 31, 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 ~~long-term debt obligations.~~variable-rate borrowings outstanding under our revolving credit facility. We manage our interest rate exposure by ~~limiting our variable-rate debt to a certain percentage of total capitalization and by~~ monitoring both the effects of market changes in interest ~~rates.~~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 ~~are~~may be used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio. We ~~are exposed to changes in~~currently have no interest ~~rates as a result of our credit facility.~~rate derivatives. We had ~~revolving credit facility debt of $204.0 million~~no outstanding borrowings under our revolving credit facility at ~~July~~March 31, 2010. The impact of a 1% increase in interest rates on this amount of debt would increase interest expense by approximately $2.0 million per year. Our revolving credit facility debt matures on July 1, 2015 and the weighted-average interest rate at July 31, 2010 was 2.29%.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 ~~June 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 ~~June 30, 2010,~~March 31, 2011, there were no changes in our internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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

~~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.

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

In addition to the ~~other~~ 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 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 ~~June 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)


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


Period and Type of Contract	MMMBtus	Swaps Weighted Average
July 2010 - December 2010
Swaps	7,556	$	6.09
January 2011 - December 2011
Swaps	11,863		6.36


*In thousands*	2010
Balance at December 31, 2009	$	(3,275	)
Total realized or unrealized gains (losses):
Included in earnings		(4,549	)
Included in other comprehensive income		—
Purchases, sales, issuances and settlements, net		—
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 June 30, 2010	$	31,810

Change in unrealized gains (losses) relating to derivatives still held at June 30, 2010	$	35,271


PART I. Financial Information
Item 1.		Financial Statements	6	7
		Condensed Consolidated Balance Sheets	6	7
		Unaudited Condensed Consolidated Statements of Operations	7	8
		Condensed Consolidated Statements of Shareholders’ Equity	8	9
		Unaudited Condensed Consolidated Statements of Cash Flows	9	10
		Notes to Unaudited Condensed Consolidated Financial Statements	10	11
Item 2.		Management’s Discussion and Analysis of Financial Condition and Results of Operations	18	22
Item 3.		Quantitative and Qualitative Disclosures About Market Risk	28	33
Item 4.		Controls and Procedures	29	34

PART II. Other Information
Item 1.		Legal Proceedings	30	34
Item 1A.		Risk Factors	30	34
Item 2.		Unregistered Sales of Equity Securities and Use of Proceeds	30	34
Item 3.		Defaults Upon Senior Securities	30	35
Item 4.		(Removed and Reserved)	30	35
Item 5.		Other Information	30	35
Item 6.		Exhibits	31
	35
		Signature	32	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


	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	(4,500	)		0.71	(4,500	)		0.71

Outstanding at June 30, 2010	307,690			1.06	307,690			1.06


	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


	Three months ended June 30,
*In thousands, except price data*	2010		2009
Crude oil and natural gas sales	$	219,426	$	146,439
Gain on mark-to-market derivative instruments		55,465		890
Total revenues		279,968		151,761
Operating costs and expenses⁽¹⁾		103,645		125,580
Other expenses, net		11,825		4,422

Income before income taxes		164,498		21,759
Provision for income taxes		62,757		8,251

Net income	$	101,741	$	13,508
Production Volumes:
Crude oil (MBbl)		2,877		2,517
Natural gas (MMcf)		5,625		5,293
Crude oil equivalents (MBoe)		3,815		3,398
Sales Volumes:
Crude oil (MBbl)		2,849		2,482
Natural gas (MMcf)		5,625		5,293
Crude oil equivalents (MBoe)		3,788		3,365
Average Prices:⁽²⁾
Crude oil ($/Bbl)	$	68.44	$	53.44
Natural gas ($/Mcf)	$	4.33	$	2.60
Crude oil equivalents ($/Boe)	$	57.94	$	43.52


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

Total	$	1,750.0


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⁾
April 1, 2010 to April 30, 2010	4,865	$	45.38	—	—
May 1, 2010 to May 31, 2010	4,673	$	47.35	—	—
June 1, 2010 to June 30, 2010	8,683	$	49.25	—	—

Total	18,221	$	47.73	—	—


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: ~~August 6, 2010~~May 5, 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 April 5, 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 April 7, 2010 and incorporated herein by reference.

~~4.2~~		Registration Rights Agreement dated as of April 5, 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 April 7, 2010 and incorporated herein by reference.

10.1		~~Purchase Agreement~~Assignment of Membership Interest dated ~~as of~~ March ~~30, 2010 among~~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 ~~April 5, 2010~~March 23, 2011 and incorporated herein by reference.

~~10.2~~10.2*†		~~Seventh Amended and Restated Credit Agreement dated June 30, 2010 among~~Summary of Non-Employee Director Compensation as of March 31, 2011.

21*		Subsidiaries of Continental Resources, Inc. as borrower, Union Bank, N.A. as administrative agent, as issuing lender and as swing line lender, and the other lenders party thereto, filed as Exhibit 10.1 to the Company’s current report on Form 8-K (Commission File No. 001-32886) filed July 7, 2010 and incorporated herein by reference.

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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