e10vq

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2011

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

For the transition period from to

Commission file number: 001-14837

Quicksilver Resources Inc.

(Exact name of registrant as specified in its charter)


Delaware		75-2756163
(State or other jurisdiction of		(I.R.S. Employer Identification No.)
incorporation or organization)

801 Cherry Street, Suite 3700, Unit 19, Fort Worth, Texas		76102
(Address of principal executive offices)		(Zip Code)

(817) 665-5000
(Registrant’s telephone number, including area code)

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

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 during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No o

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. (Check one):


Large accelerated filer þ	Accelerated filer o	Non-accelerated filer o	Smaller reporting company o
		(Do not check if a smaller reporting company)

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

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date:


Title of Class		Outstanding as of July 29, 2011
Common Stock, $0.01 par value		171,117,635

DEFINITIONS

As used in this Quarterly Report unless the context otherwise requires:

“ABR” means alternate base rate

“AMT” means alternative minimum tax in the U.S.

“AOCI” means accumulated other comprehensive income

“Bbl” or “Bbls” means barrel or barrels

“Bbld” means barrel or barrels per day

“Bcf” means billion cubic feet

“Bcfd” means billion cubic feet per day

“Bcfe” means Bcf of natural gas equivalents

“Canada” means our oil and natural gas operations located in Canada

“DD&A” means Depletion, Depreciation and Accretion

“GPT” means gathering, processing and transportation expense

“MBbl” or “MBbls” means thousand barrels

“MBbld” means thousand barrels per day

“MMBbls” means million barrels

“MMBtu” means million British Thermal Units, a measure of heating value, and is approximately equal to one Mcf of natural gas

“MMBtud” means million Btu per day

“Mcf” means thousand cubic feet

“Mcfe” means Mcf natural gas equivalents, calculated as one Bbl of oil or NGLs equaling six Mcf of natural gas

“MMcf” means million cubic feet

“MMcfd” means million cubic feet per day

“MMcfe” means MMcf of natural gas equivalents

“MMcfed” means MMcfe per day

“NGL” or “NGLs” means natural gas liquids

“NYMEX” means New York Mercantile Exchange

“NYSE” means New York Stock Exchange

“OCI” means other comprehensive income

“Oil” includes crude oil and condensate

“RSU” means restricted stock unit

“Tcf” means trillion cubic feet

COMMONLY USED TERMS

Other commonly used terms and abbreviations include:

“Alliance Leasehold” means the natural gas leasehold and royalty interests acquired in the Alliance Acquisition and developed thereafter

“Barnett Shale Asset” means our operations and our assets in the Barnett Shale located in the Fort Worth Basin of North Texas

“BBEP” means BreitBurn Energy Partners L.P.

“BBEP Unit” means BBEP limited partner unit

“Crestwood” means Crestwood Holdings LLC

“Crestwood Transaction” means the sale to Crestwood of all our interests in KGS, consisting of 100% of the general partner units, including incentive distribution rights, all of our common and subordinated units and the subordinated note due from KGS

“Eni” means either or both Eni Petroleum US LLC and Eni US Operating Co. Inc., which are subsidiaries of Eni SpA

“Eni Production” means production attributable to Eni pursuant to the Eni Transaction

“Eni Transaction” means the 2009 conveyance of a 27.5% interest in our Alliance Leasehold

“FASB” means the Financial Accounting Standards Board, which promulgates accounting standards in the U.S.

“FASC” means the FASB Accounting Standards Codification, which is the single source of authoritative U.S. GAAP not promulgated by the SEC

“GAAP” means accounting principles generally accepted in the U.S.

“Gas Purchase Commitment” means the commitment pursuant to the Eni Transaction to purchase the Eni Production at a fixed price and which expired on December 31, 2010

“Greater Green River Asset” means our operations and our assets in the Greater Green River Basin located in Colorado and southern Wyoming

“HCDS” means Hill County Dry System, a gas gathering system in Hill County, Texas within the Barnett Shale

“Horn River Asset” means our operations and our assets in the Horn River Basin of Northeast British Columbia

“Horseshoe Canyon Asset” means our operations and our assets in Horseshoe Canyon, the coalbed methane fields of southern and central Alberta

“KGS” means Quicksilver Gas Services LP, a publicly-traded partnership, which we formerly owned that traded under the ticker symbol of “KGS” and subsequent to the Crestwood Transaction renamed itself Crestwood Midstream Partners LP and trades under the ticker symbol “CMLP”

“KGS Secondary Offering” means the public offering of 4,000,000 KGS common units in 2009 and the underwriters’ purchase of an additional 549,200 KGS common units in 2010

“Mercury” means Mercury Exploration Company, which is owned by members of the Darden family

“NGTL” means NOVA Gas Transmission Ltd., a subsidiary of TransCanada Pipelines Limited

“NGTL Project” means the series of contracts with NGTL for the construction of a pipeline and meter station, which will serve our Horn River Asset

“SEC” means the U.S. Securities and Exchange Commission

“Senior Secured Credit Facility” means our U.S. senior secured revolving credit facility and our Canadian senior secured revolving credit facility

“Southern Alberta Asset” means our operations and our assets in the Southern Alberta Basin of northern Wyoming and Montana, including our Cutbank field operations and assets

Forward-Looking Information

Certain statements contained in this Quarterly Report and other materials we file with the SEC, or in other written or oral statements made or to be made by us, other than statements of historical fact, are “forward-looking statements” as defined in the Private Securities Litigation Reform Act of 1995. Forward-looking statements give our current expectations or forecasts of future events. Words such as “may,” “assume,” “forecast,” “position,” “predict,” “strategy,” “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe,” “project,” “budget,” “potential,” or “continue,” and similar expressions are used to identify forward-looking statements. They can be affected by assumptions used or by known or unknown risks or uncertainties. Consequently, no forward-looking statements can be guaranteed. Actual results may vary materially. You are cautioned not to place undue reliance on any forward-looking statements. You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include:

	•		changes in general economic conditions;

	•		fluctuations in natural gas, NGL and oil prices;

	•		failure or delays in achieving expected production from exploration and development projects;

	•		uncertainties inherent in estimates of natural gas, NGL and oil reserves and predicting natural gas, NGL and oil reservoir performance;

	•		effects of hedging natural gas, NGL and oil prices;

	•		fluctuations in the value of certain of our assets and liabilities;

	•		competitive conditions in our industry;

	•		actions taken or non-performance by third parties, including suppliers, contractors, operators, processors, transporters, customers and counterparties;

	•		changes in the availability and cost of capital;

	•		delays in obtaining oilfield equipment and increases in drilling and other service costs;

	•		delays in construction of transportation pipelines and gathering and treating facilities;

	•		operating hazards, natural disasters, weather-related delays, casualty losses and other matters beyond our control;

	•		failure or inability to convert drilling licenses to leases and the exploration of our leases;

	•		the effects of existing and future laws and governmental regulations, including environmental and climate change requirements;

	•		the effects of existing or future litigation; and

	•		certain factors discussed elsewhere in this Quarterly Report.

This list of factors is not exhaustive, and new factors may emerge or changes to these factors may occur that would impact our business. Additional information regarding these and other factors may be contained in our filings with the SEC, especially on Forms 10-K, 10-Q and 8-K. All such risk factors are difficult to predict and are subject to material uncertainties that may affect actual results and may be beyond our control. The forward-looking statements included in this Quarterly Report are made only as of the date of this Quarterly Report, and we undertake no obligation to update any of these forward-looking statements to reflect subsequent events or circumstances except to the extent required by applicable law.

All forward-looking statements are expressly qualified in their entirety by the foregoing cautionary statements.

PART I. FINANCIAL INFORMATION

ITEM 1. Condensed Consolidated Interim Financial Statements (Unaudited)

QUICKSILVER RESOURCES INC.
CONDENSED CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

In thousands, except for per share data – Unaudited


	For the Three Months Ended						For the Six Months Ended
	June 30,						June 30,
	2011			2010			2011			2010
Revenue:
Production	$	207,706		$	211,687		$	398,006		$	413,250
Sales of purchased natural gas		19,560			16,821			39,986			33,045
Other		21,180			62			22,641			4,433

Total revenue		248,446			228,570			460,633			450,728


Operating expense:
Lease operating		24,484			21,523			45,693			41,488
Gathering, processing and transportation		46,726			16,658			91,088			32,659
Production and ad valorem taxes		8,506			8,910			16,087			17,416
Costs of purchased natural gas		19,557			3,756			39,300			37,063
Other operating		23			970			183			2,224
Depletion, depreciation and accretion		54,704			50,669			107,175			97,426
Impairment		-			-			49,063			-
General and administrative		15,770			17,217			34,161			37,740

Total expense		169,770			119,703			382,750			266,016


Operating income		78,676			108,867			77,883			184,712

Income (loss) from earnings of BBEP		(26,207	)		23,168			(47,091	)		7,179
Other income - net		123,178			53,050			124,299			53,393
Interest expense		(47,552	)		(46,122	)		(93,730	)		(90,639	)


Income before income taxes		128,095			138,963			61,361			154,645

Income tax expense		(19,508	)		(48,219	)		(23,532	)		(53,301	)


Net income		108,587			90,744			37,829			101,344

Net income attributable to noncontrolling interests		-			(3,941	)		-			(6,353	)


Net income attributable to Quicksilver	$	108,587		$	86,803		$	37,829		$	94,991
Other comprehensive income (loss) net of tax:
Reclassification adjustments related to settlements of derivative contracts - net of income tax		(10,798	)		(46,089	)		(27,017	)		(72,358	)
Net change in derivative fair value - net of income tax		10,482			14,087			(6,713	)		112,693
Foreign currency translation adjustment		(1,572	)		(9,715	)		10,432			(2,755	)


Other comprehensive income (loss)		(1,888	)		(41,717	)		(23,298	)		37,580


Comprehensive income	$	106,669		$	45,086		$	14,531		$	132,571


Earnings per common share - basic	$	0.63		$	0.51		$	0.22		$	0.56

Earnings per common share - diluted	$	0.61		$	0.49		$	0.22		$	0.54

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

QUICKSILVER RESOURCES INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
In thousands, except for share data – Unaudited


	June 30,			December 31,
	2011			2010
ASSETS
Current assets
Cash	$	2		$	54,937
Accounts receivable - net of allowance for doubtful accounts		72,044			63,380
Derivative assets at fair value		62,961			89,205
Other current assets		30,569			30,650

Total current assets		165,576			238,172

Investments in equity affiliates		12,620			83,341

Property, plant and equipment - net
Oil and gas properties, full cost method (including unevaluated costs of $411,434 and $304,269, respectively)		3,003,738			2,834,645

Other property and equipment		288,215			233,200

Property, plant and equipment - net		3,291,953			3,067,845

Assets of midstream operations held for sale		27,526			27,178
Derivative assets at fair value		56,094			57,557
Other assets		35,414			38,241

	$	3,589,183		$	3,512,334


LIABILITIES AND EQUITY
Current liabilities
Current portion of long-term debt	$	147,347		$	143,478
Accounts payable		105,696			167,857
Accrued liabilities		139,161			122,904
Derivative liabilities at fair value		2,362			-
Current deferred tax liability		16,520			28,861

Total current liabilities		411,086			463,100

Long-term debt		1,834,370			1,746,716

Liabilities of midstream operations held for sale		1,465			1,431
Asset retirement obligations		58,959			56,235
Derivative liabilities at fair value		344			-
Other liabilities		28,461			28,461
Deferred income taxes		174,352			156,983
Commitments and contingencies (Note 8)
Stockholders’ equity
Preferred stock, par value $0.01, 10,000,000 shares authorized, none outstanding		-			-
Common stock, $0.01 par value, 400,000,000 shares authorized, and 176,655,595 and 175,524,816 shares issued, respectively		1,767			1,755
Paid in capital in excess of par value		725,865			714,869
Treasury stock of 5,373,482 and 5,050,450 shares, respectively		(46,288	)		(41,487	)
Accumulated other comprehensive income		106,889			130,187
Retained earnings		291,913			254,084

Total stockholders’ equity		1,080,146			1,059,408

	$	3,589,183		$	3,512,334

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

QUICKSILVER RESOURCES INC.
CONDENSED CONSOLIDATED STATEMENTS OF EQUITY
In thousands – Unaudited


	Quicksilver Resources Inc. Stockholders’ Equity
								Accumulated
			Additional					Other
	Common		Paid-in		Treasury			Comprehensive			Retained			Noncontrolling
	Stock		Capital		Stock			Income			Earnings			Interest			Total
Balances at December 31. 2009	$	1,745	$	730,265	$	(36,363	)	$	121,336		$	(180,985	)	$	60,824		$	696,822
Net income		-		-		-			-			94,991			6,353			101,344
Hedge derivative contract settlements reclassified into earnings from AOCI, net of income tax of $38,226		-		-		-			(72,358	)		-			-			(72,358	)
Net change in derivative fair value, net of income tax of $56,906		-		-		-			112,693			-			-			112,693
Currency translation adjustment		-		-		-			(2,755	)		-			-			(2,755	)
Issuance & vesting of stock compensation		8		10,187		(4,804	)		-			-			190			5,581
Stock option exercises		2		1,207		-			-			-			-			1,209
Issuance of KGS common units		-		6,746		-			-			-			4,308			11,054
Distributions paid on KGS common units		-		-		-			-			-			(8,808	)		(8,808	)

Balances at June 30, 2010	$	1,755	$	748,405	$	(41,167	)	$	158,916		$	(85,994	)	$	62,867		$	844,782


Balances at December 31. 2010	$	1,755	$	714,869	$	(41,487	)	$	130,187		$	254,084		$	-		$	1,059,408
Net income		-		-		-			-			37,829			-			37,829
Hedge derivative contract settlements reclassified into earnings from AOCI, net of income tax of $12,703		-		-		-			(27,017	)		-			-			(27,017	)
Net change in derivative fair value, net of income tax of $3,924		-		-		-			(6,713	)		-			-			(6,713	)
Currency translation adjustment		-		-		-			10,432			-			-			10,432
Issuance & vesting of stock compensation		11		10,376		(4,801	)		-			-			-			5,586
Stock option exercises		1		620		-			-			-			-			621

Balances at June 30, 2011	$	1,767	$	725,865	$	(46,288	)	$	106,889		$	291,913		$	-		$	1,080,146

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

QUICKSILVER RESOURCES INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
In thousands – Unaudited


	For the Six Months Ended
	June 30,
	2011			2010
Operating activities:
Net income	$	37,829		$	101,344
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation and accretion		107,175			97,426
Impairment expense		49,063			-
Deferred income tax expense		17,667			52,243
Non-cash gain from commodity derivatives		(19,115	)		-
Non-cash gain from hedge ineffectiveness		(818	)		(27,852	)
Stock-based compensation		10,386			11,529
Non-cash interest expense		7,872			10,178
Gain on disposition of BBEP Units		(123,752	)		(35,426	)
Loss from BBEP in excess of cash distributions		60,050			826
Other		1,111			(469	)
Changes in assets and liabilities
Accounts receivable		(8,608	)		22,858
Derivative assets at fair value		-			18,682
Prepaid expenses and other assets		(4,426	)		(11,144	)
Accounts payable		(25,859	)		(20,169	)
Accrued and other liabilities		14,777			26,481

Net cash provided by operating activities		123,352			246,507


Investing activities:
Capital expenditures		(396,156	)		(356,402	)
Proceeds from sale of BBEP Units		134,423			-
Proceeds from sale of properties and equipment		3,123			864

Net cash used by investing activities		(258,610	)		(355,538	)


Financing activities:
Issuance of debt		256,445			540,032
Repayments of debt		(170,172	)		(409,613	)
Debt issuance costs paid		-			(109	)
Gas Purchase Commitment repayments		-			(16,592	)
Issuance of KGS common units - net of offering costs		-			11,054
Distributions paid on KGS common units		-			(8,808	)
Proceeds from exercise of stock options		622			1,209
Taxes paid on vesting of KGS equity compensation		-			(1,144	)
Purchase of treasury stock		(4,801	)		(4,804	)

Net cash provided by financing activities		82,094			111,225

Effect of exchange rate changes in cash		(1,771	)		(671	)

Net increase (decrease) in cash		(54,935	)		1,523
Cash at beginning of period		54,937			1,785

Cash at end of period	$	2		$	3,308

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

QUICKSILVER RESOURCES INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Unaudited

1. ACCOUNTING POLICIES AND DISCLOSURES

The accompanying condensed consolidated interim financial statements have not been audited. In management’s opinion, the accompanying condensed consolidated interim financial statements contain all adjustments necessary to fairly present our financial position as of June 30, 2011 and our results of operations and cash flows for the three and six months ended June 30, 2011 and 2010. All such adjustments are of a normal recurring nature. The results for interim periods are not necessarily indicative of annual results.

The preparation of financial statements in conformity with GAAP requires our management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expense during each reporting period. Management believes its estimates and assumptions are reasonable; however, such estimates and assumptions are subject to a number of risks and uncertainties, which may cause actual results to differ materially from management’s estimates.

Certain disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted. Accordingly, these financial statements should be read in conjunction with our consolidated financial statements and notes thereto included in our 2010 Annual Report on Form 10-K.

Recently Issued Accounting Standards

Accounting standards-setting organizations frequently issue new or revised accounting rules. We regularly review all new pronouncements to determine their impact, if any, on our financial statements. No pronouncements materially affecting our financial statements have been issued since the filing of our 2010 Annual Report on Form 10-K.

2. CRESTWOOD TRANSACTION AND MIDSTREAM OPERATIONS

In October 2010, we completed the sale of all of our interests in KGS to Crestwood. We received net proceeds of $700 million and recognized a gain of $473.2 million during the fourth quarter of 2010. We have the right to collect up to an additional $72 million in future earn-out payments in 2012 and 2013, although we have recognized no assets related to these opportunities.

Our board of directors also approved a plan for disposal of the HCDS, which is included in our midstream segment. Subsequent to our board of directors’ approval, we conducted an impairment analysis of the HCDS and recognized a charge for impairment in the third quarter of 2010.

The operating results of these midstream operations, as classified in our statement of income, are summarized below:


	For the Three			For the Six
	Months Ended			Months Ended
	June 30, 2010			June 30, 2010
	(In thousands)
Revenue from third parties	$	4,423		$	8,167
GPT expense ⁽¹⁾		(18,758	)		(35,280	)
Ad valorem taxes		1,122			2,655
Other operations		878			2,152
DD&A		6,384			12,510
General and administrative expense		617			1,745

Operating results of midstream operations		14,180			24,385
Interest and other expense		(2,308	)		(4,390	)

Results of midstream operations before income tax		11,872			19,995
Income tax expense		(4,195	)		(7,073	)

Results of midstream operations, net of income tax	$	7,677		$	12,922

Commodity Price Derivatives

As of June 30, 2011, we had price collars and swaps covering our anticipated natural gas and NGL production as follows:


	Daily Production
Production	Volume
Year	Gas		NGL
	MMcfd		MBbld

2011		190		10.5
2012		165		4.0
2013		105		-
2014-2015		65		-
2016-2021		35		-

Interest Rate Derivatives

In 2010, we executed early settlements of our interest rate swaps that were designated as fair value hedges of our senior notes due 2015 and our senior subordinated notes. We received cash of $41.5 million in the settlements, including $10.7 million for interest previously accrued and earned. At the time of the early settlements, we recorded the resulting gain as a fair value adjustment to our debt and began to recognize the deferred gain of $30.8 million as a reduction of interest expense over the lives of our senior notes due 2015 and our senior subordinated notes.

The remaining $25.1 million deferral of the 2010 early settlements from all interest rate swaps will continue to be recognized as a reduction of interest expense over the life of the associated underlying debt instruments currently scheduled as follows:


(In thousands)
2011	$	2,495
2012		5,284
2013		5,735
2014		6,225
2015		4,802
2016		569

	$	25,110

Additional Fair Value Disclosures:


	Asset Derivatives				Liability Derivatives
	June 30,		December 31,		June 30,		December 31,
	2011		2010		2011		2010
	(In thousands)				(In thousands)
Derivatives designated as hedges⁽¹⁾:
Commodity contracts reported in:
Current derivative assets	$	75,084	$	97,863	$	21,107	$	8,658
Noncurrent derivative assets		47,544		63,419		1,581		5,862
Current derivative liabilities		-		-		2,362		-
Noncurrent derivative liabilities		-		-		344		-

Total derivatives designated as hedges	$	122,628	$	161,282	$	25,394	$	14,520

Derivatives not designated as hedges⁽²⁾:
Commodity contracts reported in:
Current derivative assets	$	8,984	$	-	$	-	$	-
Noncurrent derivative assets		10,131		-		-		-

Total derivatives not designated as hedges:	$	19,115	$	-	$	-	$	-


Total derivatives	$	141,743	$	161,282	$	25,394	$	14,520


⁽¹⁾		The fair value of each hedge derivative is determined using Level 2 inputs.

⁽²⁾		The fair value of each derivative not designated as a hedge is determined using Level 3 inputs.

The changes in the carrying value of our derivatives for the three and six months ended June 30, 2011 and 2010 are presented below:


	For the Three Months Ended June 30,
	2011			2010
	Cash Flow			Gas Purchase			Fair Value			Cash Flow
	Derivatives			Commitment			Derivatives			Derivatives			Total
	(In thousands)
Derivative fair value at beginning of period	$	96,203		$	(23,263	)	$	(5,030	)	$	230,718		$	202,425
Change in net amounts receivable and payable		(167	)		-			209			1,362			1,571
Net settlements reported in revenue		(15,546	)		-			-			(57,076	)		(57,076	)
Net settlements reported in interest expense		-			-			(4,267	)		-			(4,267	)
Cash settlements reported in long-term debt		-			-			(4,422	)		-			(4,422	)
Unrealized change in fair value of Gas Purchase Commitment reported in costs of purchased gas		-			17,102			-			-			17,102
Change in fair value of effective interest swaps		-			-			26,750			-			26,750
Ineffectiveness reported in other revenue		872			-			-			(2,983	)		(2,983	)
Unrealized gains reported in other revenue		19,115			-			-			-			-
Unrealized gains reported in OCI		15,872			-			-			21,373			21,373

Derivative fair value at end of period	$	116,349		$	(6,161	)	$	13,240		$	193,394		$	200,473


	For the Six Months Ended June 30,
	2011			2010
	Cash Flow			Gas Purchase			Fair Value			Cash Flow
	Derivatives			Commitment			Derivatives			Derivatives			Total
	(In thousands)
Derivative fair value at beginning of period	$	146,762		$	(6,625	)	$	4,108		$	107,881		$	105,364
Change in net amounts receivable and payable		(384	)		-			(4,788	)		(865	)		(5,653	)
Net settlements reported in revenue		(39,328	)		-			-			(81,633	)		(81,633	)
Net settlements reported in interest expense		-			-			(6,237	)		-			(6,237	)
Cash settlements reported in long-term debt		-			-			(18,682	)		-			(18,682	)
Unrealized change in fair value of Gas Purchase Commitment reported in costs of purchased gas		-			464			-			-			464
Change in fair value of effective interest swaps		-			-			38,839			-			38,839
Ineffectiveness reported in other revenue		818			-			-			(1,588	)		(1,588	)
Unrealized gains reported in other revenue		19,115			-			-			-			-
Unrealized gain (losses) reported in OCI		(10,634	)		-			-			169,599			169,599

Derivative fair value at end of period	$	116,349		$	(6,161	)	$	13,240		$	193,394		$	200,473

Gains and losses from the effective portion of derivative assets and liabilities held in AOCI expected to be reclassified into earnings during the twelve months ending June 30, 2012 would result in a gain of $40.1 million net of income taxes. Hedge derivative ineffectiveness resulted in net gains of $0.8 million and losses of $1.6 million for the six months ended June 30, 2011 and 2010, respectively.

4. INVESTMENT IN BBEP

At June 30, 2011, we owned 8.6 million BBEP Units, or 15% of BBEP, whose price closed at $19.46 per unit as of that date. Our ownership interest in BBEP was reduced in February 2011 when BBEP issued approximately 4.9 million BBEP Units. During the six months ended June 30, 2011, we have continued to reduce our ownership through the sale of approximately 7.1 million BBEP Units at a weighted average unit sales price of $18.99. We recognized a gain of $123.8 million as other income for the difference between our weighted average carrying value of $1.51 per BBEP Unit and the net sales proceeds. In July 2011, underwriters exercised their option to purchase 600,000 additional shares for proceeds of $11.4 million, which reduced our total ownership in BBEP to 13.5% at July 31, 2011.

Changes in the balance of our investment in BBEP for the six months ended June 30, 2011 were as follows:


(In thousands)
Balance at December 31, 2010	$	83,341
Equity loss in BBEP		(47,091	)
Distributions from BBEP		(12,959	)
BBEP Units sold		(10,671	)

Ending investment balance	$	12,620

We account for our investment in BBEP Units using the equity method, utilizing a one-quarter lag from BBEP’s publicly available information. Summarized estimated financial information for BBEP is as follows:


	For the Three Months Ended					For the Six Months Ended
	March 31,					March 31,
	2011			2010		2011			2010
	(In thousands)					(In thousands)
Revenue ⁽¹⁾	$	(12,704	)	$	133,166	$	5,461		$	171,429
Operating expense		73,937			69,277		153,420			142,549

Operating income (loss)		(86,641	)		63,889		(147,959	)		28,880
Interest and other ⁽²⁾		9,074			5,835		19,063			11,694
Income tax expense (benefit)		(1,002	)		144		(1,441	)		(1,030	)
Noncontrolling interests		34			71		69			90

Net income (loss) available to BBEP	$	(94,747	)	$	57,839	$	(165,650	)	$	18,126

	⁽¹⁾		For the three months ended March 31, 2011 and 2010, unrealized losses of $112.6 million and unrealized gains of $39.9 million on commodity derivatives were recognized, respectively. For the six months ended March 31, 2011 and 2010, unrealized losses of $194.9 million and $14.8 million on commodity derivatives were recognized, respectively.

	⁽²⁾		The three months ended March 31, 2011 and 2010 included unrealized gains of $1.4 million and $0.7 million, respectively, from interest rate swaps. The six months ended March 31, 2011 and 2010 included unrealized gains of $4.5 million and $2.4 million, respectively, from interest rate swaps.


	As of		As of
	March 31, 2011		December 31, 2010
	(In thousands)
Current assets	$	113,100	$	130,017
Property, plant and equipment		1,708,353		1,722,295
Other assets		49,199		77,855
Current liabilities		120,957		101,317
Long-term debt		413,240		528,116
Other non-current liabilities		141,304		91,477
Total equity		1,195,151		1,209,257

5. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment consisted of the following:


	June 30,			December 31,
	2011			2010
	(In thousands)
Oil and gas properties
Subject to depletion	$	5,027,226		$	4,805,161
Unevaluated costs		411,434			304,269
Accumulated depletion		(2,434,922	)		(2,274,785	)


Net oil and gas properties		3,003,738			2,834,645

Other plant and equipment
Pipelines and processing facilities		295,767			235,676
General properties		73,779			70,267
Accumulated depreciation		(81,331	)		(72,743	)


Net other property and equipment		288,215			233,200


Property, plant and equipment, net of accumulated depletion and depreciation	$	3,291,953		$	3,067,845

Ceiling Test Analysis

We recorded impairment expense of $49.1 million for our Canadian oil and gas properties at March 31, 2011. We computed the March 31, 2011 ceiling amount using an AECO price of $3.59 Mcf of natural gas, calculated as the unweighted average of the preceding 12-month first-day-of-the-month prices. The AECO natural gas price used to compute the ceiling amount at March 31, 2011 was 12% lower than the AECO price used in computing the ceiling amount at December 31, 2010. Our Canadian ceiling test prepared at June 30, 2011 resulted in no additional impairment of our Canadian oil and gas properties. Our U.S. ceiling tests prepared at March 31, 2011 and June 30, 2011 resulted in no impairment of our U.S. oil and gas properties.

Notes 2 and 8 to the consolidated financial statements in our 2010 Annual Report on Form 10-K contain additional information regarding our property, plant and equipment and our quarterly ceiling test analysis.

6. LONG-TERM DEBT

Long-term debt consisted of the following:


	June 30,			December 31,
	2011			2010
	(In thousands)
Senior Secured Credit Facility	$	116,640		$	21,114
Senior notes due 2015, net of unamortized discount		466,356			470,866
Senior notes due 2016, net of unamortized discount		582,514			583,605
Senior notes due 2019, net of unamortized discount		293,750			293,496
Senior subordinated notes due 2016		350,000			350,000
Convertible debentures, net of unamortized discount		147,347			143,478


Total debt		1,956,607			1,862,559
Unamortized deferred gain - terminated interest rate swaps		25,110			27,635

Current portion of long-term debt		(147,347	)		(143,478	)


Long-term debt	$	1,834,370		$	1,746,716

Senior Secured Credit Facility

The Senior Secured Credit Facility borrowing base and commitments remained at $1 billion and the aggregate letter of credit capacity was $175 million. At June 30, 2011, there was $803 million available under the facility.

Convertible Debentures

The convertible debentures due November 1, 2024 are contingently convertible into shares of our common stock. The debentures bear interest at an annual rate of 1.875% payable semi-annually on May 1 and November 1. Additionally, holders of the debentures can require us to repurchase all or a portion of their debentures on November 1, 2011, 2014 and 2019 at a price equal to the principal amount thereof plus accrued and unpaid interest. The debentures are convertible into shares of our common stock at a rate of 65.4418 shares for each $1,000 debenture, subject to adjustment. Generally, except upon the occurrence of specified events including certain changes of control, holders of the debentures are not entitled to exercise their conversion rights unless the closing price of our stock is at least $18.34 (120% of the conversion price per share) for at least 20 trading days during the period of 30 consecutive trading days ending on the last trading day of the preceding fiscal quarter. Upon conversion, we have the option to deliver any combination of our common stock and cash. Should all debentures be converted to our common stock, an additional 9,816,270 shares, subject to adjustment, would become outstanding; however, as of July 1, 2011, the debentures were not convertible based on share prices for the quarter ended June 30, 2011.

Because we may be required to repurchase these obligations at the option of the holders on November 1, 2011, we have reported them as current obligations in our June 30, 2011 and December 31, 2010 balance sheets. To the extent that the holders of these obligations do not elect to put them to us on November 1, 2011, any remaining obligations will be reclassified to long-term after that date.

At June 30, 2011 and December 31, 2010, the remaining unamortized discount on the debentures was $2.7 million and $6.5 million, respectively, resulting in a carrying value of $147.3 million and $143.5 million, respectively. The remaining discount will be accreted to face value through October 2011. For the six months ended June 30, 2011 and 2010, interest expense on our convertible debentures, recognized at an effective interest rate of 6.75%, was $5.3 million and $5.0 million, respectively, including contractual interest of $1.4 million for each period.

During June 2011, we repurchased the following senior notes in open market transactions:


	Repurchase		Face		Loss on

Instrument	Price		Value		Repurchase
	(In thousands)
Senior notes due 2015	$	5,250	$	5,000	$	250
Senior notes due 2016		2,701		2,380		321

	$	7,951	$	7,380	$	571

In July 2011, we repurchased 2015 and 2019 senior notes with a face value of $16 million and $2 million, respectively, for $19.0 million.

Summary of All Outstanding Debt

The following table summarizes significant aspects of our long-term debt at June 30, 2011:

Priority on Collateral and Structural Seniority ⁽²⁾

Highest priority

Lowest priority

Equal priority

Senior Secured

2015

2016

2019

Senior

Convertible

Credit Facility

Senior Notes

Subordinated Notes

Debentures ⁽¹⁾

Principal amount

$1.0 billion ⁽³⁾

$470 million

$597.6 million

$300.0 million

$350 million

$150 million

Scheduled maturity date ⁽⁵⁾

February 9, 2013

August 1, 2015

January 1, 2016

August 15, 2019

April 1, 2016

November 1, 2024

Interest rate on outstanding
borrowings at
June 30, 2011 ⁽⁴⁾

3.29

8.25

11.75

9.125

7.125

1.875

Base interest rate options

LIBOR, ABR or
specified ⁽⁵⁾

N/A

Financial covenants ⁽⁵⁾

- Minimum current ratio of 1.0

N/A

- Minimum EBITDA to interest expense

ratio of 2.5

Significant restrictive

- Incurrence of debt

N/A

covenants ⁽⁶⁾

- Incurrence of liens

- Payment of dividends

- Equity purchases

- Asset sales

- Affiliate transactions

- Limitations on derivatives

Optional redemption ⁽⁶⁾

Any time

August 1,

July 1,

August 15,

April 1,

November 8, 2011

2012: 103.875
2013: 101.938
2014: par

2013: 105.875
2014: 102.938
2015: par

2014: 104.563
2015: 103.042
2016: 101.521
2017: par

2011: 103.563
2012: 102.375
2013: 101.188
2014: par

and thereafter

Make-whole redemption ⁽⁶⁾

N/A

Callable prior to

N/A

August 1, 2012 at

July 1, 2013 at

August 15, 2014 at

April 1, 2011 at

make-whole call price of

Treasury + 50 bps

Change of control ⁽⁶⁾

Event of default

Put at 101% of principal plus accrued interest

Put at 100% of principal plus accrued interest

Equity clawback ⁽⁶⁾

N/A

Redeemable until
August 1, 2011 at
107.75%, plus accrued
interest for up to 35%

Redeemable until
July 1, 2012 at
111.75%, plus accrued
interest for up to 35%

Redeemable until
August 15, 2012 at
109.125%, plus accrued interest
for up to 35%

N/A

Subsidiary guarantors ⁽⁶⁾

Cowtown Pipeline
Funding, Inc.

N/A

Cowtown Pipeline
Management, Inc.

Cowtown Pipeline L.P.

Cowtown Gas
Processing L.P.

Quicksilver Resources Canada Inc.

Estimated fair value ⁽⁷⁾

$116.6 million

$491.8 million

$679.8 million

$322.9 million

$341.3 million

$159.1 million


⁽¹⁾		As discussed in “Convertible Debentures” above, holders of the convertible debentures can require us to repurchase all or a part of the debentures on November 1, 2011.

⁽²⁾		The Senior Secured Credit Facility is secured by a first perfected lien on substantially all our assets including a portion of our BBEP Units. The other debt presented is based upon structural seniority and priority of payment.

⁽³⁾		The principal amount for the Senior Secured Credit Facility represents the borrowing base and commitments as of June 30, 2011.


⁽⁴⁾		Represents the weighted average borrowing rate payable to lenders and excludes effects of interest rate derivatives.

⁽⁵⁾		Amounts outstanding under the Senior Secured Credit Facility bear interest, at our election, at (i) the Adjusted Eurodollar Rate (as defined in the credit facilities) plus an applicable margin between 2.00% to 3.00%, (ii) bankers’ acceptance rate (as defined in the credit facilities) plus an applicable margin between 2.00% and 3.00%, (iii) ABR, which is the greatest of (a) the prime rate announced by JPMorgan, (b) the federal funds rate plus 0.50% and (c) the Adjusted Eurodollar Rate (as defined in the credit facilities) plus 1.0%, plus, in each case under scenario (ii), an applicable margin between 1.125% to 2.125%, or (iv) the specified rate (as defined in the credit facilities) plus an applicable margin between 2.00% to 3.00%.

⁽⁶⁾		The information presented in this table is qualified in all respects by reference to the full text of the covenants, provisions and related definitions contained in the documents governing the various components of our debt.

⁽⁷⁾		The estimated fair value is determined based on market quotations on the balance sheet date for fixed rate obligations. We consider debt with market-based interest rates to have a fair value equal to its carrying value.

Note 11 to the consolidated financial statements in our 2010 Annual Report on Form 10-K contains a more complete description of our long-term debt.

7. ASSET RETIREMENT OBLIGATIONS

The following table provides a reconciliation of the changes in the estimated asset retirement obligation for the six months ended June 30, 2011:


(In thousands)


Beginning asset retirement obligations	$	57,809
Additional liability incurred		4,091
Change in estimates		(2,716	)
Accretion expense		1,275
Asset retirement costs incurred		(1,395	)
Gain on settlement of liability		261
Currency translation adjustment		1,208


Ending asset retirement obligations		60,533
Less current portion		(1,574	)


Long-term asset retirement obligation	$	58,959

8. COMMITMENTS AND CONTINGENCIES

Contractual Obligations and Commitments

There have been no significant changes to our contractual obligations and commitments as reported in our 2010 Annual Report except for a series of contracts with NGTL and additional one-year drilling rig contracts.

In April 2011, we entered into the NGTL Project, which will serve our Horn River Asset. Under these agreements, we agreed to provide financial assurances in the form of letters of credit to NGTL during the construction phase of the project, which is expected to continue through 2014. Assuming the project is fully constructed and based on estimated costs of C$296.8 million, including taxes of C$31.8 million, we expect to provide cumulative letters of credit as follows:


	NGTL Cumulative
	Financial Assurances
	(C$ in thousands)		(US$ in thousands)
June 1, 2011 ⁽¹⁾	$	32,648	$	33,849
March 1, 2012		68,264		70,776
October 1, 2012		109,816		113,857
July 1, 2013		148,400		153,861
October 1, 2013		296,800		307,722


⁽¹⁾		A letter of credit for C$32,648 is outstanding for the NGTL Project as of June 30, 2011.

Should other companies subscribe to the project, then our financial assurances under the agreements will be reduced. If the project is terminated by NGTL, then we would be responsible for all of the costs incurred or for which NGTL is liable, and we would have the option to purchase NGTL’s rights in the project for a nominal fee. Should the project be terminated by NGTL, we are required to pay NGTL an additional C$26.4 million. No amounts have been recognized on our consolidated balance sheet as of June 30, 2011. Upon completion of the project, all construction-related guarantees will expire.

We have also entered into agreements to deliver production from our Horn River Asset to NGTL over a ten-year period. These agreements will be extended in the event NGTL has either not received 1 Tcf of gas from us and other third parties, or recovered its costs as of the end of the ten-year period. In such event, the extension will be for delivery of minimum volumes of 106 MMcfd until such time that 1 Tcf of gas is delivered.

Also under the agreements, we are required to treat the gas to meet NGTL pipeline specifications. Such treatment will require us to construct treating facilities. We will develop our plans to address the treating requirements prior to the commissioning of the assets being constructed by NGTL.

In July 2011, we entered into two additional drilling rig contracts, each with a term of one year and combined aggregate commitments of $13.0 million.

At June 30, 2011, we had $38.9 million in surety bonds issued to fulfill contractual, legal or regulatory requirements and $80.8 million in letters of credit outstanding against the Senior Secured Credit Facility, including $33.8 million for the NGTL Project and $28.9 million issued to provide credit support for surety bonds. Surety bonds and letters of credit generally have an annual renewal option.

Contingencies

On March 10, 2011, the Court denied our motions for summary judgment on Eagle’s remaining tort claims. In so doing, the Court indicated that we could move for reconsideration of those motions after the Court made a ruling as to the appropriate law to apply to those claims. The Court made its choice of law ruling on May 24, 2011, and we moved for reconsideration of our summary judgment motions on Eagle’s tort claims on June 8, 2011. The motion for reconsideration is now pending.

On March 31, 2011, the Court denied Eagle’s motion for summary judgment on our contract claims. On June 29, 2011, Eagle filed a motion for reconsideration of the Court’s order granting summary judgment in our favor on Eagle’s contract claims. That motion is now pending.

Note 14 to the consolidated financial statements in our 2010 Annual Report on Form 10-K contains a more complete description of our contractual obligations, commitments and contingencies for which there are no other significant updates during the six months ended June 30, 2011.

9. QUICKSILVER STOCKHOLDERS’ EQUITY

Common Stock, Preferred Stock and Treasury Stock

We are authorized to issue 400 million shares of common stock with a $0.01 par value per share and 10 million shares of preferred stock with a $0.01 par value per share. At June 30, 2011 and December 31, 2010, we had 171.3 million and 170.5 million shares of common stock outstanding, respectively.

Note 16 to the consolidated financial statements in our 2010 Annual Report on Form 10-K contains additional information about our equity-based compensation plan.

Stock Options

Options to purchase shares of common stock were granted in 2011 with an estimated fair value of $7.6 million. The following summarizes the values from and assumptions for the Black-Scholes option pricing model for stock options issued during the six months ended June 30, 2011:


		2011
Wtd avg grant date fair value		$9.16
Wtd avg grant date		Jan 3, 2011
Wtd avg risk-free interest rate		2.38%
Expected life (in years)		6.0
Wtd avg volatility		66.8%
Expected dividends		-

The following table summarizes our stock option activity for the six months ended June 30, 2011:


				Wtd Avg		Wtd Avg		Aggregate
				Exercise		Remaining		Intrinsic
	Shares			Price		Contractual Life		Value
						(In years)		(In thousands)
Outstanding at January 1, 2011		3,348,642		$	11.10
Granted		834,970			14.88
Exercised		(100,149	)		6.21
Cancelled		(176,636	)		13.71

Outstanding at June 30, 2011		3,906,827		$	11.91		7.9	$	17,079

Exercisable at June 30, 2011		1,949,505		$	11.62		7.2	$	11,450

We estimate that a total of 3.8 million stock options will become vested including those options already exercisable. Compensation expense related to stock options of $3.5 million was recognized for each of the six months ended June 30, 2011 and 2010. Cash received from the exercise of stock options totaled $0.6 million for the six months ended June 30, 2011. The total intrinsic value of those options exercised was $0.8 million.

Restricted Stock

The following table summarizes our restricted stock and stock unit activity for the six months ended June 30, 2011:


	Payable in shares					Payable in cash
				Wtd Avg					Wtd Avg
				Grant Date					Grant Date
	Shares			Fair Value		Shares			Fair Value

Outstanding at January 1, 2011		2,329,089		$	11.27		372,633		$	10.31
Granted		1,144,724			14.85		214,515			14.88
Vested		(1,090,230	)		12.07		(137,463	)		9.50
Cancelled		(114,094	)		11.98		(48,693	)		13.25

Outstanding at June 30, 2011		2,269,489		$	12.66		400,992		$	13.11

As of December 31, 2010, the unrecognized compensation cost related to outstanding unvested restricted stock was $13.9 million, which is expected to be recognized in expense through December 2013. Grants of restricted stock and RSUs during the six months ended June 30, 2011 had an estimated grant date fair value of $17.0 million. The fair value of RSUs settled in cash was $5.9 million at June 30, 2011. For the six months ended June 30, 2011 and 2010, compensation expense of $6.8 million and $6.7 million, respectively, was recognized. The total fair value of shares vested during the six months ended June 30, 2011 was $13.2 million.

10. EARNINGS PER SHARE

The following is a reconciliation of the numerator and denominator used for the computation of basic and diluted net income per common share:


	For the Three Months Ended						For the Six Months Ended
	June 30,						June 30,
	2011			2010			2011			2010
	(In thousands, except per share data)

Net income attributable to Quicksilver	$	108,587		$	86,803		$	37,829		$	94,991

Basic income allocable to participating securities ⁽¹⁾		(1,331	)		(1,179	)		(454	)		(1,264	)

Basic net income attributable to Quicksilver	$	107,256		$	85,624		$	37,375		$	93,727
Impact of assumed conversions – interest on 1.875% convertible debentures, net of income taxes		1,880			1,787			-			3,552

Income available to stockholders assuming conversion of convertible debentures	$	109,136		$	87,411		$	37,375		$	97,279


Weighted average common shares – basic		168,984			167,976			168,928			167,915

Effect of dilutive securities ⁽²⁾:
Share-based compensation awards		868			766			858			814
Contingently convertible debentures		9,816			9,816			-			9,816

Weighted average common shares – diluted		179,668			178,558			169,786			178,545


Earnings per common share - basic	$	0.63		$	0.51		$	0.22		$	0.56

Earnings per common share - diluted	$	0.61		$	0.49		$	0.22		$	0.54

	⁽¹⁾		Restricted share awards that contain nonforfeitable rights to dividends are participating securities and, therefore, are included in computing earnings using the two-class method. Participating securities, however, do not participate in undistributed net losses.

	⁽²⁾		For the six months ended June 30, 2011, the effects of 9.8 million shares associated with our contingently convertible debt were antidilutive, and excluded from the diluted share calculations. For the three and six

months ended June, 2011, stock options and unvested restricted stock units representing 1.9 million shares were antidilutive and, therefore, excluded from the diluted share calculations. For the three and six months ended June 30, 2010, the effects of unvested restricted stock units representing 1.3 million shares were antidilutive and, therefore, excluded from the diluted share calculations.

11. CONDENSED CONSOLIDATING FINANCIAL INFORMATION

Note 18 to the consolidated financial statements in our 2010 Annual Report on Form 10-K contains a more complete description of our guarantor, non-guarantor, restricted and unrestricted subsidiaries. After completing the Crestwood Transaction during the fourth quarter of 2010, we no longer have any unrestricted subsidiaries except for two newly created subsidiaries that held no material assets or liability as of June 30, 2011.

The following tables present financial information about Quicksilver and our restricted subsidiaries for the three- and six-month periods covered by the consolidated financial statements.

Condensed Consolidating Balance Sheets


	June 30, 2011
			Restricted		Restricted					Quicksilver
	Quicksilver		Guarantor		Non-Guarantor		Consolidating			Resources Inc.
	Resources Inc.		Subsidiaries		Subsidiaries		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets	$	226,504	$	87,167	$	45,540	$	(193,635	)	$	165,576
Property and equipment		2,597,280		67,637		627,036		-			3,291,953
Assets of midstream operations		-		27,526		-		-			27,526
Investment in subsidiaries (equity method)		276,769		-		-		(264,149	)		12,620
Other assets		328,042		-		7,086		(243,620	)		91,508

Total assets	$	3,428,595	$	182,330	$	679,662	$	(701,404	)	$	3,589,183


LIABILITIES AND EQUITY
Current liabilities	$	469,626	$	107,061	$	28,034	$	(193,635	)	$	411,086
Long-term liabilities		1,878,823		20,373		440,910		(243,620	)		2,096,486
Liabilities of midstream operations		-		1,465		-		-			1,465
Stockholders’ equity		1,080,146		53,431		210,718		(264,149	)		1,080,146

Total liabilities and equity	$	3,428,595	$	182,330	$	679,662	$	(701,404	)	$	3,589,183


	December 31, 2010
			Restricted		Restricted					Quicksilver
	Quicksilver		Guarantor		Non-Guarantor		Consolidating			Resources Inc.
	Resources Inc.		Subsidiaries		Subsidiaries		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets	$	295,697	$	86,582	$	49,424	$	(193,531	)	$	238,172
Property and equipment		2,417,680		68,390		581,775		-			3,067,845
Assets of midstream operations		-		27,178		-		-			27,178
Investment in subsidiaries (equity method)		367,845		-		-		(284,504	)		83,341
Other assets		339,227		-		191		(243,620	)		95,798

Total assets	$	3,420,449	$	182,150	$	631,390	$	(721,655	)	$	3,512,334


LIABILITIES AND EQUITY
Current liabilities	$	496,631	$	106,627	$	53,373	$	(193,531	)	$	463,100
Long-term liabilities		1,864,410		20,346		347,259		(243,620	)		1,988,395
Liabilities of midstream operations		-		1,431		-		-			1,431
Stockholders’ equity		1,059,408		53,746		230,758		(284,504	)		1,059,408

Total liabilities and equity	$	3,420,449	$	182,150	$	631,390	$	(721,655	)	$	3,512,334

Condensed Consolidating Statements of Income


	For the Three Months Ended June 30, 2011
				Restricted			Restricted						Quicksilver
	Quicksilver			Guarantor			Non-Guarantor			Consolidating			Resources Inc.
	Resources Inc.			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenue	$	202,788		$	1,222		$	45,383		$	(947	)	$	248,446
Operating expenses		142,389			782			27,546			(947	)		169,770
Equity in net earnings of subsidiaries		11,855			-			-			(11,855	)		-

Operating income		72,254			440			17,837			(11,855	)		78,676
Loss from earnings of BBEP		(26,207	)		-			-			-			(26,207	)
Interest expense and other		77,085			-			(1,459	)		-			75,626
Income tax expense		(14,545	)		(154	)		(4,809	)		-			(19,508	)

Net income	$	108,587		$	286		$	11,569		$	(11,855	)	$	108,587


	For the Three Months Ended June 30, 2010
				Restricted			Restricted			Restricted			Quicksilver			Unrestricted						Quicksilver
	Quicksilver			Guarantor			Non-Guarantor			Subsidiary			and Restricted			Non-Guarantor			Consolidating			Resources Inc.
	Resources Inc.			Subsidiaries			Subsidiaries			Eliminations			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenue	$	195,394		$	1,566		$	28,700		$	(629	)	$	225,031		$	27,194		$	(23,655	)	$	228,570
Operating expenses		103,657			2,470			23,797			(629	)		129,295			14,063			(23,655	)		119,703
Equity in net earnings of subsidiaries		5,544			6,172			-			(5,544	)		6,172			-			(6,172	)		-

Operating income		97,281			5,268			4,903			(5,544	)		101,908			13,131			(6,172	)		108,867
Income from earnings of BBEP		23,168			-			-			-			23,168			-			-			23,168
Interest expense and other		11,658			-			(1,785	)		-			9,873			(2,945	)		-			6,928
Income tax expense		(45,304	)		(1,843	)		(999	)		-			(48,146	)		(73	)		-			(48,219	)

Net income	$	86,803		$	3,425		$	2,119		$	(5,544	)	$	86,803		$	10,113		$	(6,172	)	$	90,744
Net income attributable to noncontrolling interests		-			-			-			-			-			(3,941	)		-			(3,941	)

Net income attributable to Quicksilver	$	86,803		$	3,425		$	2,119		$	(5,544	)	$	86,803		$	6,172		$	(6,172	)	$	86,803


	For the Six Months Ended June 30, 2011
				Restricted			Restricted						Quicksilver
	Quicksilver			Guarantor			Non-Guarantor			Consolidating			Resources Inc.
	Resources Inc.			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenue	$	382,359		$	2,489		$	77,724		$	(1,939	)	$	460,633
Operating expenses		279,559			2,804			102,326			(1,939	)		382,750
Equity in net earnings of subsidiaries		(21,954	)		-			-			21,954			-

Operating income (loss)		80,847			(315	)		(24,602	)		21,954			77,883
Loss from earnings of BBEP		(47,091	)		-			-			-			(47,091	)
Interest expense and other		33,815			-			(3,246	)		-			30,569
Income tax (expense) benefit		(29,741	)		109			6,100			-			(23,532	)

Net income (loss)	$	37,829		$	(206	)	$	(21,748	)	$	21,954		$	37,829


	For the Six Months Ended June 30, 2010
				Restricted			Restricted			Restricted			Quicksilver			Unrestricted						Quicksilver
	Quicksilver			Guarantor			Non-Guarantor			Subsidiary			and Restricted			Non-Guarantor			Consolidating			Resources Inc.
	Resources Inc.			Subsidiaries			Subsidiaries			Eliminations			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenue	$	377,894		$	3,211		$	64,549		$	(1,325	)	$	444,329		$	51,933		$	(45,534	)	$	450,728
Operating expenses		231,498			4,353			47,142			(1,325	)		281,668			29,882			(45,534	)		266,016
Equity in net earnings of subsidiaries		16,146			9,949			-			(16,146	)		9,949			-			(9,949	)		-

Operating income		162,542			8,807			17,407			(16,146	)		172,610			22,051			(9,949	)		184,712
Income from earnings of BBEP		7,179			-			-			-			7,179			-			-			7,179
Interest expense and other		(28,401	)		-			(3,222	)		-			(31,623	)		(5,623	)		-			(37,246	)
Income tax expense benefit		(46,329	)		(3,082	)		(3,764	)		-			(53,175	)		(126	)		-			(53,301	)

Net income	$	94,991		$	5,725		$	10,421		$	(16,146	)	$	94,991		$	16,302		$	(9,949	)	$	101,344
Net income attributable to noncontrolling interests		-			-			-			-			-			(6,353	)		-			(6,353	)

Net income attributable to Quicksilver	$	94,991		$	5,725		$	10,421		$	(16,146	)	$	94,991		$	9,949		$	(9,949	)	$	94,991

Condensed Consolidating Statements of Cash Flows


	For the Six Months Ended June 30, 2011
				Restricted			Restricted					Quicksilver
	Quicksilver			Guarantor			Non-Guarantor			Consolidating		Resources Inc.
	Resources Inc.			Subsidiaries			Subsidiaries			Eliminations		Consolidated
	(In thousands)
Net cash flow provided by operations	$	96,029		$	1,137		$	26,186		$	-	$	123,352
Capital expenditures		(275,753	)		(1,137	)		(119,266	)		-		(396,156	)
Proceeds from sale of BBEP units		134,423			-			-			-		134,423
Proceeds from sale of properties and equipment		1,925			-			1,198			-		3,123

Net cash flow used by investing activities		(139,405	)		(1,137	)		(118,068	)		-		(258,610	)
Issuance of debt		153,500			-			102,945			-		256,445
Repayments of debt		(160,880	)		-			(9,292	)		-		(170,172	)
Proceeds from exercise of stock options		622			-			-			-		622
Purchase of treasury stock		(4,801	)		-			-			-		(4,801	)

Net cash flow provided (used) by financing activities		(11,559	)		-			93,653			-		82,094
Effect of exchange rates on cash		-			-			(1,771	)		-		(1,771	)

Net decrease in cash and equivalents		(54,935	)		-			-			-		(54,935	)
Cash and equivalents at beginning of period		54,937			-			-			-		54,937

Cash and equivalents at end of period	$	2		$	-		$	-		$	-	$	2


	For the Six Months Ended June 30, 2010
				Restricted			Restricted			Restricted		Quicksilver			Unrestricted						Quicksilver
	Quicksilver			Guarantor			Non-Guarantor			Subsidiary		and Restricted			Non-Guarantor			Consolidating			Resources Inc.
	Resources Inc.			Subsidiaries			Subsidiaries			Eliminations		Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(In thousands)
Net cash flow provided by operating activities	$	187,555		$	100		$	43,850		$	-	$	231,505		$	26,749		$	(11,747	)	$	246,507
Capital expenditures		(271,897	)		(100	)		(46,987	)		-		(318,984	)		(34,845	)		(2,573	)		(356,402	)
Distribution to parent		80,276			-			-			-		80,276			(80,276	)		-			-
Proceeds from sale of properties and equipment		864			-			-			-		864			-			-			864

Net cash flow used by investing activities		(190,757	)		(100	)		(46,987	)		-		(237,844	)		(115,121	)		(2,573	)		(355,538	)
Issuance of debt		376,000			-			39,532			-		415,532			124,500			-			540,032
Repayments of debt		(352,500	)		-			(34,013	)		-		(386,513	)		(23,100	)		-			(409,613	)
Debt issuance costs		(109	)		-			-			-		(109	)		-			-			(109	)
Gas Purchase Commitment - net		(16,592	)		-			-			-		(16,592	)		-			-			(16,592	)
Issuance of KGS common units		-			-			-			-		-			11,054			-			11,054
Distributions to parent		-			-						-		-			(14,320	)		14,320			-
Distributions to noncontrolling interests		-			-			-			-		-			(8,808	)		-			(8,808	)
Proceeds from exercise of stock options		1,209			-			-			-		1,209			-			-			1,209
Treasury transactions - equity		(4,804	)		-			-			-		(4,804	)		(1,144	)		-			(5,948	)

Net cash flow provided by financing activities		3,204			-			5,519			-		8,723			88,182			14,320			111,225
Effect of exchange rates on cash		-			-			(671	)		-		(671	)		-			-			(671	)

Net increase (decrease) in cash and equivalents		2			-			1,711					1,713			(190	)		-			1,523
Cash and equivalents at beginning of period		5			-			1,034			-		1,039			746			-			1,785

Cash and equivalents at end of period	$	7		$	-		$	2,745				$	2,752		$	556		$	-		$	3,308

12. SEGMENT INFORMATION

We operate in two geographic segments, the U.S. and Canada, where we are engaged in the exploration and production segment of the oil and gas industry. Prior to the Crestwood Transaction, our processing and gathering segment provided natural gas gathering and processing services predominantly through KGS. Revenue earned by KGS prior to the Crestwood Transaction for the gathering and processing of our gas was eliminated on a consolidated basis as is the GPT expense recognized by our producing properties. We evaluate performance based on operating income and property and equipment costs incurred.


	Exploration & Production					Gathering &									Quicksilver
	U.S.		Canada			Processing			Corporate			Elimination			Consolidated
	(In thousands)
For the Three Months Ended June 30:
2011
Revenue	$	202,788	$	45,383		$	1,222		$	-		$	(947	)		248,446
DD&A		41,580		12,087			466			571			-			54,704
Operating income (loss)		75,615		18,962			440			(16,341	)		-			78,676
Property and equipment costs incurred		136,454		23,640			1,339			-			-			161,433

2010
Revenue	$	195,395	$	28,701		$	28,181		$	-		$	(23,707	)	$	228,570
DD&A		31,708		11,152			7,356			453			-			50,669
Operating income (loss)		106,642		5,834			14,061			(17,670	)		-			108,867
Property and equipment costs incurred		246,917		4,550			9,317			1,347			-			262,131

For the Six Months Ended June 30:
2011
Revenue	$	382,359	$	77,724		$	2,489		$	-		$	(1,939	)	$	460,633
DD&A		80,335		23,511			2,179			1,150			-			107,175
Impairment expense		-		49,063			-			-			-			49,063
Operating income (loss)		135,862		(22,352	)		(316	)		(35,311	)		-			77,883
Property and equipment costs incurred		259,146		98,868			1,730			506			-			360,250

2010
Revenue	$	377,894	$	64,549		$	53,985		$	-		$	(45,700	)	$	450,728
DD&A		59,656		22,437			14,413			920			-			97,426
Operating income (loss)		178,921		19,267			25,183			(38,659	)		-			184,712
Property and equipment costs incurred		324,284		35,134			36,951			1,967			-			398,336

Property, plant and equipment - net
June 30, 2011	$	2,582,715	$	627,036		$	67,637		$	14,565		$	-		$	3,291,953
December 31, 2010		2,403,039		581,775			68,389			14,642			-			3,067,845

Investment in equity affiliates
June 30, 2011	$	12,620	$	-		$	-		$	-		$	-		$	12,620
December 31, 2010		83,341		-			-			-			-			83,341

13. SUPPLEMENTAL CASH FLOW INFORMATION

Cash paid (received) for interest and income taxes was as follows:


	For the Six Months Ended
	June 30,
	2011		2010
	(In thousands)
Interest, net of capitalized interest	$	86,198	$	55,713
Income taxes		5,904		(6,917	)

Other significant non-cash transactions were as follows:


	For the Six Months Ended
	June 30,
	2011		2010
	(In thousands)
Working capital related to capital expenditures	$	64,285	$	102,878
Conveyance of 3,619,901 BBEP common units for producing properties		-		54,407

14. TRANSACTIONS WITH RELATED PARTIES

As of June 30, 2011, members of the Darden family and entities controlled by them beneficially own approximately 32% of our outstanding common stock. Thomas Darden, Glenn Darden and Anne Darden Self are officers and directors of Quicksilver.

We paid $0.1 million and $0.5 million in the first six months of 2011 and 2010, respectively for rent on buildings owned by entities controlled by members of the Darden family. Rental rates were determined based on comparable rates charged by third parties.

During the first six months of 2011 and 2010, we paid $0.3 million and $0.2 million, respectively, for use of an airplane owned by an entity controlled by members of the Darden family. Usage rates were determined based upon comparable rates charged by third parties.

Payments received from Mercury for sublease rentals, employee insurance coverage and administrative services were $0.2 million for the first six months of 2010. In late 2010, Mercury changed carriers for its employees’ health insurance plan, thereby reducing our charges to, and payments from, Mercury. Those 2011 payments received from Mercury were negligible.

ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following Management’s Discussion and Analysis (“MD&A”) is intended to help readers of our financial statements understand our business, results of operations, financial condition, liquidity and capital resources. MD&A is provided as a supplement to, and should be read in conjunction with, the other sections of this Quarterly Report. Prior to the Crestwood Transaction, we conducted our operations in two segments: (1) our more dominant exploration and production segment, and (2) our significantly smaller gathering and processing segment. Except as otherwise specifically noted, or as the context requires otherwise, and except to the extent that differences between these segments or our geographic segments are material to an understanding of our business taken as a whole, we present this MD&A on a consolidated basis.

Our MD&A includes the following sections:

	•		2011 Highlights – a summary of significant activities and events affecting Quicksilver

	•		2011 Capital Program – a summary of our planned capital expenditures during 2011

	•		Results of Operations – an analysis of our consolidated results of operations for the three- and six-month periods presented in our financial statements

	•		Liquidity, Capital Resources and Financial Position – an analysis of our cash flows, sources and uses of cash, contractual obligations and commercial commitments

2011 HIGHLIGHTS

Strategic Alternatives for Quicksilver

On March 24, 2011, an investor group, consisting of members of the Darden family and an entity controlled by them, announced its decision not to pursue a previously announced plan to take the Company private. As a result, our Board of Directors disbanded its transaction committee and the Board of Directors as a whole are working together to evaluate and pursue strategic and growth opportunities for Quicksilver.

Horn River Basin Update

We had four wells tied into sales lines and producing as of December 31, 2010. Through June 2011, we have spent $48.8 million for construction of infrastructure to gather, compress and deliver gas to third-party processing facilities, completion activities for a fifth well, and drilling activities on three other wells, bringing our total count of wells drilled to eight. We have also entered into a series of contracts with NGTL for the extension of their mainline pipeline that will connect to midstream facilities we have committed to construct, which we believe will enhance our take away capacity from Horn River.

Sale of BBEP Units

During the six months ended June 30, 2011, we sold approximately 7.1 million BBEP Units. We received $134.4 million for those units and recognized total gains of $123.8 million in our income statement as other income. Note 4 to the condensed consolidated financials contains additional information about BBEP Units sold subsequent to June 30, 2011.

Increase in Production

Daily production increased 19% during the second quarter of 2011 from the 2010 second quarter. The production increase is discussed further in “Results of Operations” below.

2011 CAPITAL PROGRAM

We incurred capital costs of $360.3 million for the first six months of 2011 and we expect our 2011 capital program of approximately $696 million to be allocated as follows:


			Greater
			Green				Southern
	Barnett		River		West		Alberta				Total		Horn		Horseshoe				Total		Total
	Shale		Basin		Texas		Basin		Other		U.S.		River		Canyon		Other		Canada		Company
	(In millions, except wells)
Drilling and completion	$	240.0	$	53.5	$	3.0	$	0.4	$	-	$	296.9	$	90.2	$	3.0	$	-	$	93.2	$	390.1
Leasehold acquisition		23.0		92.4		29.0		0.1		-		144.5		1.0		3.0		-		4.0		148.5
Midstream infrastructure		29.4		5.0		-		-		-		34.4		63.1		-		-		63.1		97.5
Corporate and other assets		-		-		-		-		41.7		41.7		1.1		0.1		17.5		18.7		60.4

Total forecasted capital	$	292.4	$	150.9	$	32.0	$	0.5	$	41.7	$	517.5	$	155.4	$	6.1	$	17.5	$	179.0	$	696.5

For all of 2011, we continue to expect our average production to be greater than our reported six-month 2011 production rate as we continue to develop our acreage in the Barnett Shale and conduct further exploration on our Horn River Asset, the Greater Green River Basin Asset and the Southern Alberta Asset.

RESULTS OF OPERATIONS

Three Months Ended June 30, 2011 and 2010

The following discussion compares the results of operations for the three months ended June 30, 2011 and 2010, or the 2011 quarter and 2010 quarter, respectively. “Other U.S.” refers to the combined amounts for our Greater Green River Asset and Southern Alberta Basin Asset.

Revenue

Production Revenue:


	Natural Gas				NGL						Oil				Total
	2011		2010		2011			2010			2011		2010		2011		2010
								(In millions)
Barnett Shale	$	98.7	$	74.5	$	59.6		$	37.3		$	4.1	$	3.1	$	162.4	$	114.9
Other U.S.		0.2		0.5		0.3			0.3			3.1		2.4		3.6		3.2
Hedging		21.5		67.9		(12.6	)		(4.0	)		-		-		8.9		63.9

U.S.		120.4		142.9		47.3			33.6			7.2		5.5		174.9		182.0
Horseshoe Canyon		20.2		21.2		-			-			-		-		20.2		21.2
Horn River		5.8		1.9		-			-			-		-		5.8		1.9
Hedging		6.8		6.5		-			-			-		-		6.8		6.5

Canada		32.8		29.6		-			-			-		-		32.8		29.6

Consolidated	$	153.2	$	172.5	$	47.3		$	33.6		$	7.2	$	5.5	$	207.7	$	211.6

Average Daily Production Volume:


	Natural Gas				NGL				Oil				Equivalent Total
	2011		2010		2011		2010		2011		2010		2011		2010
	(MMcfd)				(Bbld)				(Bbld)				(MMcfed)
Barnett Shale		256.9		205.5		13,165		11,762		448		461		338.6		278.8
Other U.S.		0.7		1.4		22		52		375		403		3.1		4.2

U.S.		257.6		206.9		13,187		11,814		823		864		341.7		283.0
Horseshoe Canyon		58.2		60.8		4		5		-		-		58.3		60.8
Horn River		17.3		6.1		-		-		-		-		17.2		6.1

Canada		75.5		66.9		4		5		-		-		75.5		66.9

Consolidated		333.1		273.8		13,191		11,819		823		864		417.2		349.9

Average Realized Price:


	Natural Gas				NGL						Oil				Equivalent Total
	2011		2010		2011			2010			2011		2010		2011		2010
	(per Mcf)				(per Bbl)						(per Bbl)				(per Mcfe)
Barnett Shale	$	4.22	$	3.99	$	49.79		$	34.90		$	99.76	$	72.96	$	5.27	$	4.53
Other U.S.		3.99		3.73		78.25			60.09			92.12		67.11		12.54		8.55
Hedging		0.92		3.61		(10.47	)		(3.76	)		-		-		0.29		2.48
U.S.		5.14		7.59		39.36			31.25			96.28		70.24		5.62		7.07
Horseshoe Canyon	$	3.82	$	3.84	$	77.84		$	62.58		$	-	$	-	$	3.82	$	3.84
Horn River		3.65		3.49		-			-			-		-		3.65		3.49
Hedging		0.99		1.06		-			-			-		-		0.99		1.06
Canada	$	4.78	$	4.87	$	77.84		$	62.58		$	-	$	-	$	4.78	$	4.87
Consolidated	$	5.06	$	6.93	$	39.38		$	31.27		$	96.28	$	70.24	$	5.47	$	6.65

The following table summarizes the changes in our production revenue:


	Natural
	Gas			NGL			Oil			Total
	(In thousands)
Revenue for the 2010 quarter	$	172,535		$	33,627		$	5,525		$	211,687
Volume variances		21,269			4,375			(262	)		25,382
Hedge revenue variances		(46,059	)		(8,529	)		-			(54,588	)
Price variances		5,478			17,796			1,951			25,225

Revenue for the 2011 quarter	$	153,223		$	47,269		$	7,214		$	207,706

Natural gas revenue for the 2011 quarter decreased from the 2010 quarter despite a 19% increase in production. Realized natural gas prices, before hedge settlements, were higher in the U.S. for the 2011 quarter as compared to the 2010 quarter. A 25% increase in natural gas volume from our Barnett Shale Asset was primarily the result of wells tied into sales lines since the 2010 quarter. Canadian natural gas production increased because of a 184% production increase from our Horn River Asset offset by a 4% decrease in production from our Horseshoe Canyon Asset due to decreased capital spending.

The increase in NGL revenue for the 2011 quarter resulted from a 43% increase in realized prices, before hedge losses, received for our Barnett Shale production, which increased 12% compared to the 2010 quarter.

Utilization of derivatives to hedge our sales of natural gas and NGL may result in realized prices varying from market prices that we receive from the sale of our production. Our revenue from natural gas and NGL production for the 2011 quarter and 2010 quarter were higher by $15.7 million and $70.4 million, respectively, because of our hedging activities.

Sales of Purchased Natural Gas and Costs of Purchased Natural Gas


	Three Months Ended
	June 30,
	2011		2010
	(In thousands)
Sales of purchased natural gas
Purchases from Eni	$	15,482	$	13,946
Purchases from others		4,078		2,875

Total		19,560		16,821
Costs of purchased natural gas sold
Purchases from Eni		15,493		17,883
Purchases from others		4,064		2,975
Unrealized valuation gain on Gas Purchase Commitment		-		(17,102	)

Total		19,557		3,756

Net sales and purchases of natural gas	$	3	$	13,065

As the Gas Purchase Commitment with Eni expired on December 31, 2010, no unrealized valuation gain or loss was recognized for the 2011 quarter.

Other Revenue


	Three Months Ended
	June 30,
	2011		2010
	(In thousands)
Midstream revenue from third parties
KGS	$	-	$	2,117
Canada		786		567
Other Texas		275		361

Total midstream revenue		1,061		3,045
Unrealized gains on commodity derivatives		19,115		-
Gains (losses) from hedge ineffectiveness		872		(2,983	)
Other		132		-

Total	$	21,180	$	62

In the 2011 quarter, we recognized $19.1 million of unrealized gains on commodity derivatives that we entered into during 2011 that have not been designated as hedges for accounting purposes. Midstream revenue was lower from the 2010 quarter primarily as a result of the sale of our interests in KGS in October 2010.

Operating Expense

Lease Operating


	Three Months Ended June 30,
	2011				2010
	(In thousands, except per unit amounts)
			Per				Per
			Mcfe				Mcfe
Barnett Shale
Cash expense	$	14,003	$	0.45	$	11,982	$	0.47
Equity compensation		211		0.01		218		0.01

	$	14,214	$	0.46	$	12,200	$	0.48

Other U.S.
Cash expense	$	1,370	$	4.81	$	1,239	$	3.29
Equity compensation		44		0.16		44		0.11

	$	1,414	$	4.97	$	1,283	$	3.40

Total U.S.
Cash expense	$	15,373	$	0.49	$	13,221	$	0.51
Equity compensation		255		0.01		262		0.01

	$	15,628	$	0.50	$	13,483	$	0.52

Horseshoe Canyon
Cash expense	$	8,246	$	1.56	$	7,375	$	1.33
Equity compensation		105		0.02		274		0.05

	$	8,351	$	1.58	$	7,649	$	1.38

Horn River
Cash expense	$	505	$	0.32	$	391	$	0.70
Equity compensation		-		-		-		-

	$	505	$	0.32	$	391	$	0.70

Total Canada
Cash expense	$	8,751	$	1.27	$	7,766	$	1.28
Equity compensation		105		0.02		274		0.04

	$	8,856	$	1.29	$	8,040	$	1.32

Total Company
Cash expense	$	24,124	$	0.63	$	20,987	$	0.66
Equity compensation		360		0.01		536		0.02

	$	24,484	$	0.64	$	21,523	$	0.68

Lease operating expense for the 2011 quarter in the U.S. increased 16% when compared to the 2010 quarter. This increase was primarily associated with the increase in production from new wells. A 21% increase in production volume in our Barnett Shale Asset for the 2011 quarter as compared to 2010 quarter increased lease operating expense slightly, but also contributed to the decrease in per Mcfe expense as our fixed costs have been spread across higher production for the 2011 quarter as compared to the 2010 quarter.

Lease operating expense for the 2011 quarter in Canada increased 10% when compared to the 2010 quarter. The increase in Horseshoe Canyon lease operating expense was due to higher additional well repair and maintenance costs for the 2011 quarter and changes in the Canadian dollar relative to the U.S. dollar.

Gathering, Processing and Transportation


	Three Months Ended June 30,
	2011				2010
	(In thousands, except per unit amounts)
			Per				Per
			Mcfe				Mcfe
Barnett Shale	$	42,004	$	1.35	$	14,221	$	0.56
Other U.S.		-		-		6		0.01

Total U.S.		42,004		1.35		14,227		0.55
Horseshoe Canyon		1,215		0.23		1,034		0.19
Horn River		3,507		2.24		1,397		2.50

Total Canada		4,722		0.69		2,431		0.40

Total	$	46,726	$	1.23	$	16,658	$	0.52

GPT expense increased for the 2011 quarter compared to the 2010 quarter primarily due to the loss of fees earned by KGS for gathering and processing production from our Barnett Shale Asset following the closing of the Crestwood Transaction and the increase in Barnett Shale production. KGS’ revenue earned from gathering and processing production from our Barnett Shale Asset was $18.3 million, or $0.71 per Mcfe, for the 2010 quarter. Canadian GPT expense increased for the 2011 quarter as compared to the 2010 quarter both in total dollars and on a per Mcfe basis primarily as a result of higher gathering fees in addition to increased production from our Horn River Asset for the 2011 quarter.

Production and Ad Valorem Taxes


	Three Months Ended June 30,
	2011				2010
	(In thousands, except per unit amounts)
			Per				Per
			Mcfe				Mcfe
Production taxes
U.S.	$	2,891	$	0.09	$	2,696	$	0.10
Canada		61		0.01		209		0.03

Total production taxes		2,952		0.07		2,905		0.09
Ad valorem taxes
U.S.	$	4,859		0.16	$	4,969		0.19
Canada		695		0.10		1,036		0.17

Total ad valorem taxes		5,554		0.15		6,005		0.19

Total	$	8,506	$	0.22	$	8,910	$	0.28

Depletion, Depreciation and Accretion


	Three Months Ended June 30,
	2011				2010
	(In thousands, except per unit amounts)
			Per				Per
			Mcfe				Mcfe
Depletion
U.S.	$	39,879	$	1.28	$	30,233	$	1.17
Canada		9,901		1.44		9,542		1.57

Total depletion		49,780		1.31		39,775		1.25
Depreciation of other fixed assets
U.S.	$	2,434	$	0.08	$	8,959	$	0.35
Canada		1,810		0.26		1,160		0.19

Total depreciation		4,244		0.11		10,119		0.32
Accretion		680		0.02		775		0.02

Total	$	54,704	$	1.44	$	50,669	$	1.59

U.S. depletion for the 2011 quarter reflected a 9% increase in the U.S. depletion rate and a 21% increase in U.S. production when compared to the 2010 quarter. Canadian depletion increased $0.4 million as a result of a13% increase in Canadian production volumes partially offset by an 8% decrease in the Canadian depletion rate when compared to the 2010 quarter.

U.S. depreciation for the 2010 quarter included KGS’ depreciation of $5.6 million.

General and Administrative


	Three Months Ended June 30,
	2011				2010
	(In thousands, except per unit amounts)
			Per				Per
			Mcfe				Mcfe
Cash expense	$	11,222	$	0.30	$	12,143	$	0.38
Equity compensation		4,548		0.12		5,074		0.16

Total	$	15,770	$	0.42	$	17,217	$	0.54

General and administrative expense for the 2011 quarter was lower than the 2010 quarter because the 2010 quarter included $0.6 million of KGS general and administrative expense recognized in the 2010 quarter, prior to the Crestwood Transaction.

Loss from Earnings of BBEP

We record our portion of BBEP’s earnings during the quarter in which its financial statements become publicly available. As a result, our 2011 quarter and 2010 quarter results of operations include BBEP’s earnings for the three months ended March 31, 2011 and 2010, respectively.

We recognized a loss of $26.2 million and income of $23.2 million for equity earnings from our investment in BBEP for the 2011 quarter and 2010 quarter, respectively. BBEP continues to experience significant volatility in its net earnings primarily due to changes in the unrealized value of its derivative instruments for which it does not employ hedge accounting.

Other Income

We recognized a gain of $122.5 million in the 2011 quarter from the sale of 7.0 million BBEP Units in June 2011. In the 2010 quarter we conveyed BBEP Units as consideration in the acquisition of additional working interests in the Lake Arlington properties and settled our litigation with BBEP and another third party for which we recognized $35.4 million and $18.0 million, respectively.

Interest Expense


	Three Months Ended
	June 30,
	2011			2010
	(In thousands)
Interest costs on debt outstanding	$	43,917		$	42,390
Add:
Fees paid on letters of credit outstanding		1,010			2
Premium paid - senior notes repurchased		571			-
Non-cash interest ⁽¹⁾		3,992			5,103
Interest capitalized		(1,938	)		(1,373	)

Interest expense	$	47,552		$	46,122

⁽¹⁾ Amortization of deferred financing costs, original issue discount net of interest swap settlement amortization.

Interest costs on debt outstanding for the 2011 quarter were higher when compared to the 2010 quarter primarily because the 2010 quarter included $3.0 million received from interest rate swaps, which was offset by $2.3 million attributable to KGS. The 2011 quarter increase was impacted by fees for issuance of letters of credit.

Also included in interest expense for the 2011 quarter were losses recognized from the premium paid for repurchase of our 2015 and 2016 senior notes described below:


	Repurchase		Face		Loss on
Instrument	Price		Value		Repurchase
	(In thousands)
Senior notes due 2015	$	5,250	$	5,000	$	250
Senior notes due 2016		2,701		2,380		321

	$	7,951	$	7,380	$	571

In July 2011, we repurchased 2015 and 2019 senior notes with a face value of $16 million and $2 million, respectively, for $19.0 million.

Income Taxes


	Three Months Ended
	June 30,
	2011			2010
Income tax expense (in thousands)	$	19,508		$	48,219
Effective tax rate		15.2	%		34.7	%

Our income tax provision for the 2011 quarter reflects changes in the projected effective tax rate for 2011 from -6.0% to 38.4% including the effects of our recognition of an assessment of $0.6 million in Canada related to a predecessor’s activities in 1997 . The effective tax rate for the 2011 quarter reflects a projection of a full year of Canadian taxable loss taxed at a projected effective rate of 20.5% partially offset by projection of a full year of U.S. taxable income taxed at a projected effective rate of 37.1%. U.S. and consolidated earnings relate to gains associated with our sales of BBEP units and the unrealized derivative gains included in other revenue.

RESULTS OF OPERATIONS

Six Months Ended June 30, 2011 and 2010

The following discussion compares the results of operations for the six months ended June 30, 2011 and 2010, or the 2011 period and 2010 period, respectively. “Other U.S.” refers to the combined amounts for our Greater Green River Asset and Southern Alberta Basin Asset.

Revenue

Production Revenue:


	Natural Gas				NGL						Oil				Total
	2011		2010		2011			2010			2011		2010		2011		2010
	(In millions)
Barnett Shale	$	188.1	$	156.1	$	106.0		$	78.4		$	6.8	$	6.2	$	300.9	$	240.7
Other U.S.		0.7		1.5		0.3			0.4			6.0		4.8		7.0		6.7
Hedging		45.4		116.2		(19.8	)		(13.6	)		-		-		25.6		102.6

U.S.		234.2		273.8		86.5			65.2			12.8		11.0		333.5		350.0
Horseshoe Canyon		41.1		50.1		0.1			0.1			-		-		41.2		50.2
Horn River		9.2		5.0		-			-			-		-		9.2		5.0
Hedging		14.1		8.0		-			-			-		-		14.1		8.0

Canada		64.4		63.1		0.1			0.1			-		-		64.5		63.2

Consolidated	$	298.6	$	336.9	$	86.6		$	65.3		$	12.8	$	11.0	$	398.0	$	413.2

Average Daily Production Volume:


	Natural Gas				NGL				Oil				Equivalent Total
	2011		2010		2011		2010		2011		2010		2011		2010
	(MMcfd)				(Bbld)				(Bbld)				(MMcfed)
Barnett Shale		252.2		189.5		12,352		11,514		392		467		328.6		261.4
Other U.S.		0.7		1.8		24		35		378		393		3.2		4.4

U.S.		252.9		191.3		12,376		11,549		770		860		331.8		265.8
Horseshoe Canyon		58.8		61.6		5		8		-		-		58.8		61.6
Horn River		14.2		6.8		-		-		-		-		14.2		6.8

Canada		73.0		68.4		5		8		-		-		73.0		68.4

Consolidated		325.9		259.7		12,381		11,557		770		860		404.8		334.2

Average Realized Price:


	Natural Gas				NGL						Oil				Equivalent Total
	2011		2010		2011			2010			2011		2010		2011		2010
	(per Mcf)				(per Bbl)						(per Bbl)				(per Mcfe)
Barnett Shale	$	4.12	$	4.55	$	47.42		$	37.63		$	95.92	$	73.30	$	5.06	$	5.09
Other U.S.		4.22		4.52		77.89			66.51			87.95		67.78		12.02		8.41
Hedging		0.99		3.36		(8.83	)		(6.51	)		-		-		0.43		2.13
U.S.	$	5.11	$	7.91	$	38.65		$	31.20		$	92.02	$	70.79	$	5.55	$	7.28
Horseshoe Canyon	$	3.86	$	4.49	$	75.33		$	68.69		$	-	$	-	$	3.87	$	4.50
Horn River		3.60		4.09		-			-			-		-		3.60		4.09
Hedging		1.07		0.64		-			-			-		-		1.07		0.64
Canada	$	4.88	$	5.10	$	75.33		$	68.69		$	-	$	-	$	4.88	$	5.10
Consolidated	$	5.06	$	7.17	$	38.66		$	31.23		$	92.02	$	70.79	$	5.43	$	6.83

The following table summarizes the changes in our production revenue:


	Natural
	Gas			NGL			Oil			Total
	(In thousands)
Revenue for the 2010 period	$	336,915		$	65,318		$	11,017		$	413,250
Volume variances		54,204			5,629			(1,157	)		58,676
Hedge revenue variances		(64,705	)		(6,158	)		-			(70,863	)
Price variances		(27,865	)		21,851			2,957			(3,057	)

Revenue for the 2011 period	$	298,549		$	86,640		$	12,817		$	398,006

Natural gas revenue for the 2011 period decreased from the 2010 period despite a 25% increase in production. Realized prices, including hedge settlements, were lower for the 2011 period as compared to the 2010 period, which more than offset production increases. The 33% increase in natural gas volume from our Barnett Shale Asset was primarily the result of wells tied into sales lines since the 2010 period. The Canadian natural gas production increase was the result of a 109% production increase from additional producing wells in our Horn River Asset offset by a 5% decrease in production from our Horseshoe Canyon Asset due to decreased capital spending.

The increase in NGL revenue for the 2011 period resulted from a 26% increase in realized prices, before hedge losses, and an increase in production from our Barnett Shale Asset compared to the 2010 period.

Utilization of derivatives to hedge our sales of natural gas and NGL may result in realized prices varying from market prices that we receive from the sale of our production. Our production revenue for the 2011 period and 2010 period was higher by $39.7 million and $110.6 million, respectively, because of our hedging activities.

Sales of Purchased Natural Gas and Costs of Purchased Natural Gas


	Six Months Ended June 30,
	2011		2010
	(In thousands)
Sales of purchased natural gas
Purchases from Eni	$	29,399	$	26,565
Purchases from others		10,587		6,480

Total		39,986		33,045
Costs of purchased natural gas sold
Purchases from Eni		29,287		30,401
Purchases from others		10,013		7,126
Unrealized valuation gain on Gas Purchase Commitment		-		(464	)

Total		39,300		37,063

Net sales and purchases of natural gas	$	686	$	(4,018	)

As the Gas Purchase Commitment with Eni expired on December 31, 2010, no unrealized valuation gain or loss was recognized for the 2011 period.

Operating Expense

Lease Operating


	Six Months Ended June 30,
	2011				2010
	(In thousands, except per unit amounts)
			Per				Per
			Mcfe				Mcfe
Barnett Shale
Cash expense	$	25,109	$	0.42	$	22,091	$	0.47
Equity compensation		480		0.01		429		0.01

	$	25,589	$	0.43	$	22,520	$	0.48
Other U.S.
Cash expense	$	2,617	$	4.54	$	3,196	$	3.97
Equity compensation		99		0.17		86		0.11

	$	2,716	$	4.71	$	3,282	$	4.08
Total U.S.
Cash expense	$	27,726	$	0.46	$	25,287	$	0.53
Equity compensation		579		0.01		515		0.01

	$	28,305	$	0.47	$	25,802	$	0.54
Horseshoe Canyon
Cash expense	$	15,985	$	1.50	$	14,265	$	1.28
Equity compensation		269		0.03		601		0.05

	$	16,254	$	1.53	$	14,866	$	1.33
Horn River
Cash expense	$	1,134	$	0.44	$	820	$	0.67
Equity compensation		-		-		-		-

	$	1,134	$	0.44	$	820	$	0.67
Total Canada
Cash expense	$	17,119	$	1.30	$	15,085	$	1.22
Equity compensation		269		0.02		601		0.05

	$	17,388	$	1.32	$	15,686	$	1.27
Total Company
Cash expense	$	44,845	$	0.61	$	40,372	$	0.67
Equity compensation		848		0.01		1,116		0.02

	$	45,693	$	0.62	$	41,488	$	0.69

Lease operating expense for the 2011 period in the U.S. increased 10% when compared to the 2010 period. This increase was primarily associated with the increase in production from new wells. An increase in production volume from our Barnett Shale Asset for the 2011 period as compared to 2010 period increased lease operating expense slightly, but also contributed to the 10% decrease in per Mcfe expense as our fixed costs have been spread across higher production for the 2011 period compared to the 2010 period.

Lease operating expense for the 2011 period in Canada increased 11% when compared to the 2010 period. The $1.4 million increase in Horseshoe Canyon lease operating expense was due to additional well repair and maintenance during the 2011 period. The increase in Horn River lease operating expense of $0.3 million for the 2011 period was primarily the result of higher road repair and maintenance costs in the 2011 period and increased production from the 2010 period.

Gathering, Processing and Transportation


	Six Months Ended June 30,
	2011				2010
	(In thousands, except per unit amounts)
			Per				Per
				Mcfe				Mcfe
Barnett Shale	$	82,389	$	1.39	$	27,479	$	0.58

Other U.S.		7		0.01		12		0.01

Total U.S.		82,396		1.37		27,491		0.57

Horseshoe Canyon		2,235		0.21		2,419		0.22

Horn River		6,457		2.52		2,749		2.25

Total Canada		8,692		0.66		5,168		0.42


Total	$	91,088	$	1.24	$	32,659	$	0.54

GPT expense increased for the 2011 period compared to the 2010 period primarily due to the loss of fees earned by KGS for gathering and processing production from our Barnett Shale Asset following the closing of the Crestwood Transaction and the increase in Barnett Shale production. KGS’ revenue earned from gathering and processing production from our Barnett Shale Asset was $34.3 million, or $0.71 per Mcfe, for the 2010 period. Canadian GPT expense increased for the 2011 period as compared to the 2010 period both in total dollars and on a per Mcfe basis primarily as a result of higher gathering fees and increased production from our Horn River Asset for the 2011 period.

Production and Ad Valorem Taxes


	Six Months Ended June 30,
	2011				2010
	(In thousands, except per unit amounts)
			Per				Per
Production taxes			Mcfe				Mcfe
U.S.	$	4,575	$	0.08	$	4,918	$	0.10
Canada		75		0.01		348		0.03

Total production taxes		4,650		0.06		5,266		0.09

Ad valorem taxes
U.S.		10,090		0.17		10,507		0.22
Canada		1,347		0.10		1,643		0.13

Total ad valorem taxes		11,437		0.16		12,150		0.20


Total	$	16,087	$	0.22	$	17,416	$	0.29

Production taxes for the 2011 period reflect the refund of 2008 severance taxes for our Alliance Leasehold in the amount of $0.8 million, which was recorded as a reduction to U.S. production taxes. This decrease was partially offset by an increase in production volume from our Barnett Shale Asset when compared to the 2010 period. The 2011 period includes increased U.S. ad valorem taxes on producing wells added during 2010, particularly in areas with higher ad valorem tax rates, and increases to ad valorem tax rates assessed by taxing entities in Texas. The 2010 period included $2.6 million of ad valorem taxes attributable to KGS.

Depletion, Depreciation and Accretion


	Six Months Ended June 30,
	2011				2010
	(In thousands, except per unit amounts)
			Per				Per
Depletion			Mcfe				Mcfe
U.S.	$	77,024	$	1.28	$	56,490	$	1.17
Canada		19,756		1.49		19,316		1.56


Total depletion		96,780		1.32		75,806		1.25
Depreciation of other fixed assets
U.S.	$	6,057		0.10	$	17,864		0.37
Canada		3,029		0.23		2,243		0.18


Total depreciation		9,086		0.12		20,107		0.33

Accretion		1,309		0.02		1,513		0.03


Total	$	107,175	$	1.46	$	97,426	$	1.61

U.S. depletion for the 2011 period reflected an increase in the U.S. depletion rate and an increase in U.S. production when compared to the 2010 period. Canadian depletion increased slightly for the 2011 period when compared to the 2010 period as a result of an increase in production volumes partially offset by a decrease of 4% in the Canadian depletion rate.

U.S. depreciation for the 2010 period included KGS’ $11.0 million in depreciation.

Impairment Expense

As required under GAAP, we perform quarterly ceiling tests to assess impairment of our oil and gas properties. We also assess our fixed assets reported outside the full-cost pool when circumstances indicate impairment may have occurred. The calculation of impairment expense is more fully described in Note 5 to the condensed consolidated financial statements in Item 1 of this Quarterly Report.

In the first quarter of 2011, we recognized a $49.1 million non-cash charge for impairment of our Canadian oil and gas properties. The AECO natural gas price used to prepare the March 31, 2011 estimate of the ceiling limit for our Canadian full-cost pool decreased approximately 12% from the AECO price used at December 31, 2010 when we also recognized an impairment charge for our Canadian oil and gas properties. Our Canadian ceiling test prepared at June 30, 2011 resulted in no additional impairment of our Canadian oil and gas properties. Our U.S. ceiling tests prepared at March 31, 2011 and June 30, 2011 resulted in no impairment of our U.S. oil and gas properties.

General and Administrative


	Six Months Ended June 30,
	2011				2010
	(In thousands, except per unit amounts)
			Per				Per
			Mcfe				Mcfe
Cash expense	$	24,624	$	0.34	$	27,802	$	0.46
Equity compensation		9,537		0.13		9,938		0.16


Total	$	34,161	$	0.47	$	37,740	$	0.62

General and administrative costs for the 2011 period are lower than the 2010 period primarily because the 2010 period included KGS general and administrative expense of $1.7 million.

Loss from Earnings of BBEP

We record our portion of BBEP’s earnings during the quarter in which its financial statements become publicly available. As a result, our 2011 period and 2010 period results of operations include BBEP’s earnings for the six months ended March 31, 2011 and 2010, respectively.

We recognized losses of $47.1 million and income of $7.2 million for equity earnings from our investment in BBEP for the 2011 period and 2010 period, respectively. BBEP continues to experience significant volatility in its net earnings primarily due to changes in the value of its derivative instruments for which it does not employ hedge accounting.

Other Income

Gains of $123.8 million were recognized in the 2011 period from the sale of 7.1 million BBEP Units. In the 2010 period, we conveyed BBEP Units as consideration in the acquisition of additional working interests in the Lake Arlington properties and settled our litigation with BBEP and another third party for which we recognized $35.4 million and $18.0 million, respectively.

Interest Expense


	Six Months Ended June 30,
	2011			2010
	(In thousands)
Interest costs on debt outstanding	$	87,114		$	83,159
Add:
Fees paid on letters of credit outstanding		1,259			108
Premium paid - senior notes repurchased		571			-
Non-cash interest ⁽¹⁾		7,872			10,178
Interest capitalized		(3,086	)		(2,806	)


Interest expense	$	93,730		$	90,639

⁽¹⁾ Amortization of deferred financing costs, original issue discount net of interest swap settlement amortization.

Interest costs on debt outstanding for the 2011 period were higher when compared to the 2010 period primarily because of an $8.3 million decrease in interest rate swap gains and settlements recognized, a $1.2 million increase in fees paid for issuance of letters of credit and a $0.6 million loss from the early repayment of $7.4 million of senior notes at par value. Offsetting this increase was $4.4 million of interest expense recognized in the 2010 period that was attributable to KGS and lower outstanding debt balances during the 2011 period.

Additional information about the loss on debt extinguishment can be found in the discussion of interest expense for the 2011 quarter.

Income Taxes


	Six Months Ended
	June 30,
	2011			2010

Income tax expense (in thousands)	$	23,532		$	53,301

Effective tax rate		38.4	%		34.5	%

Our income tax provision for the 2011 period has decreased from the income tax provision recognized for the 2010 period. The effective tax rate for the 2011 period reflects a projection of a full year of Canadian taxable loss partially offset by projection of a full year of U.S. taxable income. The increase in the 2011 effective income tax rate resulted from the lower applicable tax rate applied to our Canadian taxable loss and U.S. taxable income taxed at a higher U.S. effective tax rate. The increase in the tax rate from the quarter ended March 31, 2011 to the quarter ended June 30, 2011 is most significantly related to U.S. tax effect of the gains associated with the sale of BBEP Units and

unrealized derivative gains included in other revenue. We expect that the effective tax rate of 38.4% for the 2011 period will be our effective tax rate for all of 2011, based upon our projection of pretax income and estimated permanent differences for 2011.

Quicksilver Resources Inc. and its Restricted Subsidiaries

Information about Quicksilver and our restricted and unrestricted subsidiaries is included in Note 11 to our condensed consolidated financial statements included in Item 1 of this Quarterly Report.

The combined results of operations for Quicksilver and our restricted subsidiaries are substantially similar to our consolidated results of operations, which are discussed above under “Results of Operations.” The combined financial position of Quicksilver and our restricted subsidiaries and our consolidated financial position are the same. The combined operating cash flows, financing cash flows and investing cash flows for Quicksilver and our restricted subsidiaries are substantially similar to our consolidated operating cash flows, financing cash flows and investing cash flows, which are discussed below in “Cash Flow Activity.”

LIQUIDITY, CAPITAL RESOURCES AND FINANCIAL POSITION

Cash Flow Activity

Our financial condition and results of operations, including our liquidity and profitability, are significantly affected by the prices that we realize for our natural gas, NGL and oil production and the volumes of natural gas, NGL and oil that we produce.

The natural gas, NGLs and oil that we produce are commodity products for which established trading markets exist. Accordingly, product pricing is generally influenced by the relationship between supply and demand for these products. Product supply is affected primarily by fluctuations in production volumes, and product demand is affected by the state of the economy in general, the availability and price of alternative fuels and a variety of other factors. Prices for our products historically have been volatile, and we have no meaningful influence over the timing and extent of price changes for our products. Although we have mitigated our near term exposure to such price declines through derivative financial instruments covering substantial portions of our expected near-term production, we cannot confidently predict whether or when market prices for natural gas, NGL and oil will increase or decrease.

The volumes that we produce may be significantly affected by the rates at which we acquire leaseholds and other mineral interests and explore, exploit and develop our leasehold and other mineral interests through drilling and production activities. These activities require substantial capital expenditures, and our ability to fund these activities through cash flow from our operations, borrowings and other sources may be affected by instability in the capital markets.

For the remainder of 2011 through 2021, price collars and swaps cover a portion of our natural gas and NGL revenue. The following summarizes future production hedged with commodity derivatives as of June 30, 2011:


Production	Daily Production Volume
Year	Gas		NGL
	MMcfd		MBbld
2011		190		10.5

2012		165		4.0

2013		105		-

2014-2015		65		-

2016-2021		35		-

The following summarizes our cash flow activity for the 2011 period and 2010 period:


	Six Months Ended
	June 30,
	2011			2010
	(In thousands)
Net cash provided by operating activities	$	123,352		$	246,507

Net cash used by investing activities		(258,610	)		(355,538	)

Net cash provided by financing activities		82,094			111,225

Operating Cash Flows

Net cash provided by operations for the 2011 period decreased from the 2010 period, primarily due to lower realized prices (including hedging effects) and higher net payments to KGS for GPT costs partially offset by an additional $5.0 million in additional BBEP distributions in the 2011 period. In addition, the 2010 period included nonrecurring cash receipts for income tax refunds, litigation settlement and interest rate swap settlements and terminations totaling $41.8 million.

Investing Cash Flows

During the 2011 period, we sold 7.1 million BBEP Units for an average price of $18.99 or total proceeds of $134.4 million that was used to repay borrowings outstanding under our Senior Secured Credit Facility.

Our costs incurred for property, plant and equipment for the 2011 period and 2010 period were as follows:


	United States		Canada		Consolidated
	(In thousands)
For the Six Months Ended June 30, 2011

Exploration and development	$	246,515	$	49,870	$	296,385

Gathering and processing		9,671		48,754		58,425

Administrative		5,196		244		5,440


Total	$	261,382	$	98,868	$	360,250


For the Six Months Ended June 30, 2010

Exploration and development	$	322,565	$	25,585	$	348,150

Gathering and processing ⁽¹⁾		36,857		9,245		46,102

Administrative		3,780		304		4,084


Total	$	363,202	$	35,134	$	398,336

⁽¹⁾ Represents KGS’ capital expenditures in the U.S.

Our 2011 period capital costs incurred have decreased $101.8 million and increased $63.7 million for the U.S. and Canada, respectively. Our capital expenditures for gathering and processing during the 2011 period include construction of infrastructure to gather, compress and deliver our Horn River gas production to third-party processing facilities. Our Canadian exploration and development costs for the 2011 period reflect a higher level of drilling and completion activities. Completion activities have been in process for our fifth well and drilling activities are ongoing for three additional wells.

Financing Cash Flows

Net financing cash flows in the 2011 period include $7.4 million of purchases and retirement of our senior notes, net borrowings of $93.7 million under our Senior Secured Credit Facility and activity for our stock compensation plan. Financing cash flows in the 2010 period included net borrowings of $29.0 million under our Senior Secured Credit facility and $101.4 million under the KGS Credit Facility. The 2010 period also included proceeds of $11.1 million from the KGS Secondary Offering partially offset by repayments of $16.6 million under the Gas Purchase Commitment.

Liquidity and Borrowing Capacity

At June 30, 2011, the borrowing base and commitments under the Senior Secured Credit Facility, which matures February 9, 2013, were $1.0 billion and the aggregate letter of credit capacity was $175 million. The Senior Secured Credit Facility provides us an option to increase availability by up to $250 million, with a maximum of $1.45 billion with lender consents and additional commitments. We can also extend the maturity date up to two additional years with lenders’ approval. At June 30, 2011, there was $803 million available under the facility. Our ability to remain in compliance with the financial covenants in our credit facilities may be affected by events beyond our control, including market prices for our products. Any future inability to comply with these covenants, unless waived by the requisite lenders, could adversely affect our liquidity by rendering us unable to borrow further under our credit facilities and by accelerating the maturity of our indebtedness. Additional information about our senior note repurchases can be found in Note 6 to the condensed consolidated financial statements.

Additional information about our debt and related covenants are more fully described in Note 6 to the condensed consolidated financial statements in Item 1 of this Quarterly Report.

We believe that our capital resources are adequate to meet the requirements of our existing business. We continue to anticipate that our 2011 capital expenditure program will be substantially funded by cash flow from operations, utilization of our Senior Secured Credit Facility and asset transactions.

Depending upon conditions in the capital markets and other factors, we will from time to time consider the issuance of debt or other securities, other possible capital markets transactions or the sale of assets, the proceeds of which could be used to refinance current indebtedness or for other corporate purposes. We will also consider from time to time additional acquisitions of, and investments in, assets or businesses that complement our existing asset portfolio. Acquisition transactions, if any, are expected to be financed through cash on hand and from operations, bank borrowings, the issuance of debt or other securities, the sale of assets or a combination of those sources.

Financial Position

The following impacted our balance sheet as of June 30, 2011, as compared to our balance sheet as of December 31, 2010:

	•		Our net property, plant and equipment balance increased $224.1 million from December 31, 2010 to June 30, 2011. We have incurred capital expenditures of $360.3 million during 2011 and also recognized assets for retirement obligations established for new wells and facilities. Changes to U.S. -Canadian exchange rates further increased our property, plant and equipment balances $19.3 million. Offsetting the increases was $154.9 million of DD&A and impairment expense.

	•		The valuation of our current and non-current derivative assets and liabilities was $30.4 million lower on a net basis for June 30, 2011 as compared to December 31, 2010. The decrease was the result of 2011 settlements received of $39.7 million partially offset by unrealized valuation gains of $8.5 million for our remaining commodity derivatives.

	•		Our investment in BBEP Units decreased $70.7 million during the 2011 period. In addition to recognizing $47.1 million in losses from the earnings of BBEP, we received $13.0 million in dividends from BBEP and retired $10.7 million of our investment balance in connection with the sale of 7.1 million BBEP Units.

	•		The $62.2 million decrease in accounts payable was primarily due to Texas ad valorem taxes of $17.4 million included in accounts payable as of December 31, 2010 and a $36.6 million reduction in accrued capital expenditures from December 31, 2010.

	•		Long-term debt increased $93.7 million for net borrowings under the Senior Secured Credit Facility. The increase was partially offset by the repurchase of $7.4 million of our senior notes due 2015 and 2016 and recognition of a portion of the gains deferred from our 2010-settled interest rate swap derivatives.

Contractual Obligations and Commercial Commitments

There have been no significant changes to our contractual obligations and commitments as reported in our 2010 Annual Report except for contracts we entered into with NOVA Gas Transmission Ltd. (“NGTL”) in April 2011 and the two drilling rig contracts we entered into in July 2011 with a term of one year and aggregate commitments of $13.0 million. Note 8 to the condensed consolidated financial statements found in this Quarterly Report contains additional information about our NGTL contracts and drilling rig contracts.

Critical Accounting Estimates

Management’s discussion and analysis of financial condition and results of operations are based on our condensed consolidated interim financial statements and related footnotes contained within this report. The process of preparing financial statements in conformity with GAAP requires the use of estimates and assumptions to determine certain of the assets, liabilities, revenue and expense. Our more critical accounting estimates used in the preparation of the consolidated financial statements were discussed in our 2010 Annual Report on Form 10-K. These critical estimates, for which no significant changes occurred during the six months ended June 30, 2011, include estimates and assumptions for:


•	oil and gas reserves	•	stock-based compensation
•	full cost ceiling calculations	•	income taxes
•	derivative instruments

These estimates and assumptions are based upon what we believe is the best information available at the time we make the estimate or assumption. The estimates and assumptions could change materially as conditions within and beyond our control change. Accordingly, actual results could differ materially from those estimates and assumptions.

OFF-BALANCE SHEET ARRANGEMENTS

Our contracts with NGTL provide financial assurances to it during the construction phase of the NGTL Project, which is expected to continue through 2014. Assuming the project is fully constructed at estimated costs of C$296.8 million, we expect to provide letters of credit through 2014. Note 8 to the condensed consolidated financial statements found in this Quarterly Report contains additional information about our contracts with NGTL.

RECENTLY ISSUED ACCOUNTING STANDARDS

No pronouncements materially affecting our financial statements have been issued since the filing of our 2010 Annual Report on Form 10-K.

ITEM 3. Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

We have internal control policies and procedures for managing commodity price and interest rate risk within our organization. The possibility of decreasing prices received for our production is among the several risks that we face. We seek to manage this risk by entering into derivative contracts which we strive to treat as financial hedges. We have mitigated the downside risk of adverse price movements through the use of derivatives but, in doing so, we have also limited our ability to benefit from favorable price movements. This commodity price strategy enhances our ability to execute our development, exploitation and exploration programs, meet debt service requirements and pursue acquisition opportunities even in periods of price volatility or depression.

We enter into financial derivative contracts to mitigate our exposure to commodity price risk associated with anticipated future production and to increase the predictability of our revenue. Utilization of our financial hedging program will most often result in realized prices from the sale of our natural gas, and NGLs that vary from market prices. As a result of settlements of derivative contracts, our revenue from natural gas, and NGL production was greater by $39.7 million and $110.6 million for the 2011 period and 2010 period, respectively. Other revenue was $0.8 million higher and $1.6 million lower, respectively, for the 2011 period and 2010 period due to hedge ineffectiveness.

The following table details our open derivative positions at June 30, 2011:

Weighted Avg

Production

Remaining Contract

Price Per Mcf

Fair Value

Product

Type

Hedged

Period

Volume

or Bbl

Total

(In thousands)

Gas

Collar

Canada

Apr 2011-Dec 2011

10 MMcfd

6.00- 7.00

2,851

Gas

Collar

Canada

Apr 2011-Dec 2011

10 MMcfd

6.00- 7.00

2,851

Gas

Collar

Canada

Apr 2011-Dec 2011

20 MMcfd

6.00- 7.00

5,703

Gas

Collar

U.S.

Apr 2011-Dec 2011

10 MMcfd

6.25- 7.50

3,295

Gas

Collar

U.S.

Apr 2011-Dec 2011

10 MMcfd

6.25- 7.50

3,295

Gas

Collar

U.S.

Apr 2011-Dec 2011

20 MMcfd

6.25- 7.50

6,590

Gas

Collar

U.S.

Apr 2011-Dec 2012

20 MMcfd

6.50- 7.15

20,005

Gas

Collar

U.S.

Apr 2011-Dec 2012

20 MMcfd

6.50- 7.18

20,088

Gas

Collar

U.S.

Jan 2012-Dec 2012

20 MMcfd

6.50- 8.01

12,700

Gas

Basis

Canada

Apr 2011-Dec 2011

10 MMcfd

)

127

Gas

Basis

Canada

Apr 2011-Dec 2011

10 MMcfd

)

127

Gas

Basis

Canada

Apr 2011-Dec 2011

20 MMcfd

)

253

Gas

Swap

Canada

Apr 2011-Dec 2013

10 MMcfd

5.00

998

Gas

Swap

Canada

Jan 2012-Dec 2021

5 MMcfd

6.20

2,577

Gas

Swap

Canada

Jan 2012-Dec 2021

5 MMcfd

6.23

3,038

Gas

Swap

Canada

Jan 2012-Dec 2021

10 MMcfd

6.22

5,769

Gas

Swap

U.S.

Apr 2011-Dec 2013

10 MMcfd

5.00

998

Gas

Swap

U.S.

Apr 2011-Dec 2013

10 MMcfd

5.00

998

Gas

Swap

U.S.

Apr 2011-Dec 2013

10 MMcfd

5.00

998

Gas

Swap

U.S.

Apr 2011-Dec 2015

10 MMcfd

6.00

13,049

Gas

Swap

U.S.

Apr 2011-Dec 2015

20 MMcfd

6.00

26,098

Gas

Swap

U.S.

Jan 2012-Dec 2021

5 MMcfd

6.20

2,577

Gas

Swap

U.S.

Jan 2012-Dec 2021

5 MMcfd

6.20

2,577

Gas

Swap

U.S.

Jan 2012-Dec 2021

5 MMcfd

6.20

2,577

NGL

Swap

U.S.

Apr 2011-Dec 2011

3 MBbld

36.06

(7,650

)

NGL

Swap

U.S.

Apr 2011-Dec 2011

2 MBbld

36.31

(5,010

)

NGL

Swap

U.S.

Apr 2011-Dec 2011

1 MBbld

40.50

(1,735

)

NGL

Swap

U.S.

Apr 2011-Dec 2011

1.5 MBbld

40.42

(2,622

)

NGL

Swap

U.S.

Apr 2011-Dec 2011

3 MBbld

41.95

(4,400

)

NGL

Swap

U.S.

Jan 2012-Dec 2012

1 MBbld

42.81

(822

)

NGL

Swap

U.S.

Jan 2012-Dec 2012

1 MBbld

43.07

(728

)

NGL

Swap

U.S.

Jan 2012-Dec 2012

2 MBbld

43.94

(823

)

Total

116,349

⁽¹⁾ Basis swaps hedge the AECO basis adjustment at a deduction of $0.39 per Mcf from NYMEX for 2011.

The fair value of “Level 2” derivative instruments was estimated using prices quoted in active markets for the periods covered by the derivatives. The fair value of “Level 3” derivative instruments was estimated using price quoted from less active markets for the periods covered by those derivatives. The fair value of each derivative is compared to the counterparty’s value for reasonableness. Estimates were determined by applying the net differential between the prices in each derivative and market prices for future periods to the amounts stipulated in each contract to arrive at an estimated future value. This estimated future value was discounted on each contract at rates commensurate with federal treasury instruments with similar contractual lives.

Interest Rate Risk

In 2010, we executed early settlements of our interest rate swaps that were designated as fair value hedges of our senior notes due 2015 and our senior subordinated notes. We deferred gains of $30.8 million as a fair value adjustment to our debt, which we began to recognize over the life of the associated debt instruments. During the 2011 period and

2010 period, we recognized $2.4 million and $0.9 million of those deferred gains, respectively. Additionally, we recognized $6.2 million received from periodic settlements in the 2010 period as reductions of interest expense.

Foreign Currency Risk

Our Canadian subsidiary uses the Canadian dollar as its functional currency. To the extent that business transactions in Canada are not denominated in Canadian dollars, we are exposed to foreign currency exchange rate risk. Non-functional currency transactions for the 2011 period and the 2010 period resulted in gains of $0.9 million and losses of $0.7 million, respectively, and were included in other income. Furthermore, the Senior Secured Credit Facility permits Canadian borrowings to be made in either U.S. or Canadian-denominated amounts. However, the aggregate borrowing capacity of the entire facility is calculated using the U.S. dollar equivalent. Accordingly, there is a risk that exchange rate movements could impact our available borrowing capacity.

ITEM 4. Controls and Procedures

Conclusions Regarding the Effectiveness of Disclosure Controls and Procedures

We carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures as of the end of the period covered by this report pursuant to Securities Exchange Act Rule 13a-15. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that, as of June 30, 2011, our disclosure controls and procedures were effective to provide reasonable assurance that material information required to be disclosed by us (including our consolidated subsidiaries) in reports that we file or submit under the Securities Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

There has been no change in our internal control over financial reporting during the period ended June 30, 2011 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. Legal Proceedings

Other than the above disclosure which amends and supplements the Form 10-Q filed on May 9, 2011, there have been no material changes in the legal proceedings described in Part I, Item 3 included in our 2010 Annual Report on Form 10-K.

ITEM 1A. Risk Factors

There have been no material changes in the risk factors described in Part I, Item 1A included in our 2010 Annual Report on Form 10-K other than the change described in Part II, Item 1A included in our Quarterly Report on Form 10-Q filed on May 9, 2011.

ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds

Issuer Purchases of Equity Securities

The following table summarizes our repurchases of Quicksilver common stock during the quarter ended June 30, 2011:


					Total Number of		Maximum Number
	Total Number				Shares Purchased as		of Shares that May
	of Shares		Average Price		Part of Publicly		Yet Be Purchased
Period	Purchased ⁽¹⁾		Paid per Share		Announced Plan ⁽²⁾		Under the Plan ⁽²⁾

April 2011		287	$	14.13		-		-
May 2011		-		-		-		-
June 2011		-		-		-		-

Total		287	$	14.13		-		-

	⁽¹⁾		Represents shares of common stock surrendered by employees to satisfy income tax withholding obligations arising upon the vesting of restricted stock issued under our Amended and Restated 2006 Equity Plan.

	⁽²⁾		We do not currently have in place any publicly announced, specific plans or programs to purchase equity securities.

We have not paid cash dividends on our common stock and intend to retain our cash flows from operations for future operations and development of our business. In addition, we have debt agreements that restrict the payment of dividends.

ITEM 3. Defaults Upon Senior Securities

None.

ITEM 4. [Removed and Reserved]

ITEM 5. Other Information

On July 26, 2011, we received a subpoena duces tecum from the SEC requesting certain documents. The SEC has informed us that their investigation arises out of recent press reports questioning the projected decline curves and economics of shale gas wells. We understand from the SEC that a number of other shale gas producers received similar subpoenas.

ITEM 6. Exhibits


Exhibit No.		Description
	10.1	Project and Expenditure Authorization, dated as of April 6, 2011, between Quicksilver Resources Canada Inc. and Nova Gas Transmission Ltd. (filed as Exhibit 10.1 to the Company’s Form 8-K, filed April 14, 2011, and included herein by reference)
	10.2	Commitment Letter Agreement, dated as of April 6, 2011, between Quicksilver Resources Canada Inc. and Nova Gas Transmission Ltd. (filed as Exhibit 10.2 to the Company’s Form 8-K, filed April 14, 2011, and included herein by reference)
*	31.1	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
*	31.2	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
*	32.1	Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
*	101.INS	XBRL Instance Document
*	101.SCH	XBRL Taxonomy Extension Schema Linkbase Document
*	101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
*	101.LAB	XBRL Taxonomy Extension Labels Linkbase Document
*	101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document
*	101.DEF	XBRL Taxonomy Extension Definition Linkbase Document


*		Filed herewith.

EXHIBIT INDEX


Exhibit No.		Description
	10.1	Project and Expenditure Authorization, dated as of April 6, 2011, between Quicksilver Resources Canada Inc. and Nova Gas Transmission Ltd. (filed as Exhibit 10.1 to the Company’s Form 8-K, filed April 14, 2011, and included herein by reference)
	10.2	Commitment Letter Agreement, dated as of April 6, 2011, between Quicksilver Resources Canada Inc. and Nova Gas Transmission Ltd. (filed as Exhibit 10.2 to the Company’s Form 8-K, filed April 14, 2011, and included herein by reference)
*	31.1	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
*	31.2	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
*	32.1	Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
*	101.INS	XBRL Instance Document
*	101.SCH	XBRL Taxonomy Extension Schema Linkbase Document
*	101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
*	101.LAB	XBRL Taxonomy Extension Labels Linkbase Document
*	101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document
*	101.DEF	XBRL Taxonomy Extension Definition Linkbase Document


*		Filed herewith.


PART I. FINANCIAL INFORMATION

Item 1. Condensed Consolidated Interim Financial Statements (Unaudited)			6

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			27

Item 3. Quantitative and Qualitative Disclosures About Market Risk			45

Item 4. Controls and Procedures			47

PART II. OTHER INFORMATION

Item 1. Legal Proceedings			47

Item 1A. Risk Factors			47

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			48

Item 3. Defaults Upon Senior Securities			48

Item 4. [Removed and Reserved]			48

Item 5. Other Information			48

Item 6. Exhibits			48

Signature			49
EX-31.1
EX-31.2
EX-32.1
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT


(In thousands)
Balance at beginning of period	$	-
Total gains or losses for the period:
Included in earnings		19,115

Balance at end of period	$	19,115


The amount of total gains or losses for the period included in earnings attributable to the change in unrealized gains or losses related to assets still held at the reporting date	$	19,115


⁽¹⁾		Our KGS operations earned revenue from gathering and processing of our natural gas and NGL production. This revenue was consolidated as a reduction of processing, gathering and transportation expense for purposes of presenting our consolidated statements of income.


	Quicksilver Resources Inc.
	By:	/s/ Philip Cook
	Philip Cook
	Senior Vice President - Chief Financial Officer (Duly Authorized Officer and Principal Financial Officer)