Quicksilver Resources 10Q 2011 Q1 Quarterly report

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

FORM 10-Q

(Mark One)


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

For the quarterly period ended March 31, 2011


o		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. Yesþ Noo

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). Yesþ Noo

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 filerþ	Accelerated filero	Non-accelerated filero	Smaller reporting companyo
		(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). Yeso Noþ

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 April 22, 2011
Common Stock, $0.01 par value		171,111,829

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
“LIBOR” means London Interbank Offered Rate
“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 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 theFASB 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

“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

INDEX TO QUARTERLY REPORT ON FORM 10-Q
For the Quarter Ended March 31, 2011


PART I. FINANCIAL INFORMATION		6

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

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		25

Item 3. Quantitative and Qualitative Disclosures About Market Risk		37

Item 4. Controls and Procedures		38

PART II. OTHER INFORMATION		39

Item 1. Legal Proceedings		39

Item 1A. Risk Factors		39

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		39

Item 3. Defaults Upon Senior Securities		40

Item 4. [Removed and Reserved]		40

Item 5. Other Information		40

Item 6. Exhibits		40

Signature		41
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

Except as otherwise specified and unless the context otherwise requires, references to the “Company,” “Quicksilver,” “we,” “us,” and “our” refer to Quicksilver Resources Inc. and its subsidiaries.

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;

	•		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 Forms10-K,10-Q and8-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
FOR THE THREE MONTHS ENDED MARCH 31, 2011 AND 2010
In thousands, except for per share data – Unaudited


	For the Three Months Ended
	March 31,
	2011			2010
Revenue:
Natural gas, NGL and oil	$	190,301		$	201,563
Sales of purchased natural gas		20,426			16,224
Other		1,460			4,371

Total revenue		212,187			222,158


Operating expense:
Lease operating		21,557			19,964
Gathering, processing and transportation		44,014			16,002
Production and ad valorem taxes		7,581			8,506
Costs of purchased natural gas		19,743			33,307
Other operating		160			1,254
Depletion, depreciation and accretion		52,471			46,757
Impairment		49,063			-
General and administrative		18,391			20,523

Total expense		212,980			146,313

Operating income (loss)		(793	)		75,845
Loss from earnings of BBEP		(20,884	)		(15,989	)
Other income - net		1,121			343
Interest expense		(46,178	)		(44,517	)

Income (loss) before income taxes		(66,734	)		15,682
Income tax expense		(4,024	)		(5,082	)

Net income (loss)		(70,758	)		10,600
Net income attributable to noncontrolling interests		-			(2,412	)

Net income (loss) attributable to Quicksilver	$	(70,758	)	$	8,188

Other comprehensive income (loss)
Reclassification adjustments related to settlements
of derivative contracts - net of income tax		(16,219	)		(26,269	)
Net change in derivative fair value - net of income tax		(17,195	)		98,606
Foreign currency translation adjustment		12,004			6,960

Comprehensive income (loss)	$	(92,168	)	$	87,485


Earnings (loss) per common share - basic	$	(0.42	)	$	0.05

Earnings (loss) per common share - diluted	$	(0.42	)	$	0.05

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


	March 31,			December 31,
	2011			2010
ASSETS
Current assets
Cash and cash equivalents	$	2		$	54,937
Accounts receivable - net of allowance for doubtful accounts		76,694			63,380
Derivative assets at fair value		61,132			89,205
Other current assets		28,285			30,650

Total current assets		166,113			238,172
Investments in equity affiliates		55,674			83,341
Property, plant and equipment - net
Oil and gas properties, full cost method (including unevaluated costs of $356,566 and $304,269, respectively)		2,912,947			2,834,645
Other property and equipment		271,045			233,200

Property, plant and equipment - net		3,183,992			3,067,845
Assets of midstream operations held for sale		26,421			27,178
Derivative assets at fair value		38,008			57,557
Other assets		39,744			38,241

	$	3,509,952		$	3,512,334

LIABILITIES AND EQUITY
Current liabilities
Current portion of long-term debt	$	145,396		$	143,478
Accounts payable		141,532			167,857
Accrued liabilities		106,038			122,904
Derivative liabilities at fair value		1,965			-
Current deferred tax liability		19,050			28,861

Total current liabilities		413,981			463,100
Long-term debt		1,880,768			1,746,716
Liabilities of midstream operations held for sale		1,448			1,431
Asset retirement obligations		61,329			56,235
Derivative liabilities at fair value		972			-
Other liabilities		28,461			28,461
Deferred income taxes		154,704			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 176,665,190 and 175,524,816 shares issued, respectively		1,767			1,755
Paid in capital in excess of par value		720,703			714,869
Treasury stock of 5,373,195 and 5,050,450 shares, respectively		(46,284	)		(41,487	)
Accumulated other comprehensive income		108,777			130,187
Retained earnings		183,326			254,084

Total stockholders’ equity		968,289			1,059,408

	$	3,509,952		$	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		-		-		-			-			8,188			2,412			10,600
Hedge derivative contract settlements reclassified into earnings from accumulated other comprehensive income, net of income tax of $14,006		-		-		-			(26,269	)		-			-			(26,269	)
Net change in derivative fair value, net of income tax of $49,567		-		-		-			98,606			-			-			98,606
Currency translation adjustment		-		-		-			6,960			-			-			6,960
Issuance & vesting of stock compensation		8		5,006		(4,766	)		-			-			(478	)		(230	)
Stock option exercises		1		759		-			-			-			-			760
Issuance of KGS common units		-		6,743		-			-			-			4,307			11,050
Distributions paid on KGS common units		-		-		-			-			-			(4,404	)		(4,404	)

Balances at March 31, 2010	$	1,754	$	742,773	$	(41,129	)	$	200,633		$	(172,797	)	$	62,661		$	793,895


Balances at December 31, 2010	$	1,755	$	714,869	$	(41,487	)	$	130,187		$	254,084		$	-		$	1,059,408
Net loss		-		-		-			-			(70,758	)		-			(70,758	)
Hedge derivative contract settlements reclassified into earnings from accumulated other comprehensive income, net of income tax of $7,781		-		-		-			(16,219	)		-			-			(16,219	)
Net change in derivative fair value, net of income tax of $9,311		-		-		-			(17,195	)		-			-			(17,195	)
Currency translation adjustment		-		-		-			12,004			-			-			12,004
Issuance & vesting of stock compensation		11		5,467		(4,797	)		-			-			-			681
Stock option exercises		1		367		-			-			-			-			368

Balances at March 31, 2011	$	1,767	$	720,703	$	(46,284	)	$	108,777		$	183,326		$	-		$	968,289

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 Three Months Ended
	March 31,
	2011			2010
Operating activities:
Net income (loss)	$	(70,758	)	$	10,600
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation and accretion		52,471			46,757
Impairment expense		49,063			-
Deferred income tax expense		4,024			5,082
Non-cash loss from hedging and derivative activities		54			1,421
Stock-based compensation		5,478			5,680
Non-cash interest expense		3,880			5,075
Gain on disposition of BBEP units		(1,289	)		-
Loss from BBEP in excess of cash distributions		27,253			15,989
Other		89			(323	)
Changes in assets and liabilities
Accounts receivable		(13,256	)		4,905
Derivative assets at fair value		-			14,260
Prepaid expenses and other assets		(3,451	)		5,519
Accounts payable		(24,711	)		(15,553	)
Accrued and other liabilities		(17,134	)		(33,640	)

Net cash provided by operating activities		11,713			65,772


Investing activities:
Purchases of property, plant and equipment		(196,547	)		(129,331	)
Proceeds from sale of BBEP units		1,703			-
Proceeds from sale of properties and equipment		507			718

Net cash used by investing activities		(194,337	)		(128,613	)


Financing activities:
Issuance of debt		147,983			295,446
Repayments of debt		(15,145	)		(227,639	)
Debt issuance costs paid		-			(109	)
Gas Purchase Commitment repayments		-			(7,317	)
Issuance of KGS common units - net offering costs		-			11,050
Distributions paid on KGS common units		-			(4,404	)
Proceeds from exercise of stock options		368			760
Taxes paid on vesting of KGS equity compensation		-			(1,144	)
Purchase of treasury stock		(4,797	)		(4,766	)

Net cash provided by financing activities		128,409			61,877

Effect of exchange rate changes in cash		(720	)		(220	)

Net decrease in cash		(54,935	)		(1,184	)
Cash and cash equivalents at beginning of period		54,937			1,785

Cash and cash equivalents at end of period	$	2		$	601

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 March 31, 2011 and our results of operations and cash flows for the three months ended March 31, 2010 and 2011. 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. Our board of directors 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 Months Ended March 31, 2010
	(In thousands)
Revenue	$	3,744
GPT expense⁽¹⁾		(16,522	)
Ad valorem taxes		1,533
Other operations		1,274
DD&A		6,126
General and administrative expense		1,128

Operating results of midstream operations		10,205
Interest and other expense		(2,082	)

Results of midstream operations before income tax		8,123
Income tax expense		(2,878	)

Results of midstream operations, net of income tax	$	5,245


⁽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.

Details of balance sheet items for these midstream operations are summarized below:


	March 31,		December 31,
	2011		2010
Assets:	(In thousands)

Accounts receivable, net	$	39	$	57
Property, plant and equipment, net		26,382		27,121

Total	$	26,421	$	27,178


Liabilities:

Other non-current liabilities	$	1,448	$	1,431

Total	$	1,448	$	1,431

Note 3 to the consolidated financial statements in our 2010 Annual Report on Form 10-K contains additional information regarding the Crestwood Transaction.

3. DERIVATIVES AND FAIR VALUE MEASUREMENTS

The following table identifies our derivative instruments where estimated fair value is based upon the use of “Level 2” inputs at March 31, 2011 and December 31, 2010:


	March 31,		December 31,
	2011		2010
	(In thousands)
Commodity contracts	$	96,203	$	146,762

Total	$	96,203	$	146,762

The fair value of all derivative instruments included in these disclosures was estimated using prices quoted in active markets for the periods covered by the derivatives and the value reported by counterparties. 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.

Commodity Price Derivatives

As of March 31, 2011, we had price collars and swaps hedging our anticipated natural gas and NGL production as follows:


Production	Daily Production
Year	Gas		NGL
	MMcfd		MBbld
2011		190		10.5
2012		130		2.0
2013		70		-
2014-2015		30		-

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. Upon 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 $26.4 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	$	3,711
2012		5,315
2013		5,769
2014		6,261
2015		4,824
2016		569

	$	26,449

Fair Value Disclosures

The estimated fair value of our derivative instruments at March 31, 2011 and December 31, 2010 were as follows:


	Asset Derivatives				Liability Derivatives
	March 31,		December 31,		March 31,		December 31,
	2011		2010		2011		2010
	(In thousands)				(In thousands)
Derivatives designated as hedges:
Commodity contracts reported in:
Current derivative assets	$	82,720	$	97,863	$	21,588	$	8,658
Noncurrent derivative assets		41,149		63,419		3,141		5,862
Current derivative liabilities		-		-		1,965		-
Noncurrent derivative liabilities		2,192		-		3,164		-

Total derivatives designated as hedges	$	126,061	$	161,282	$	29,858	$	14,520


Derivatives not designated as hedges:	$	-	$	-	$	-	$	-

Total derivatives	$	126,061	$	161,282	$	29,858	$	14,520

The decrease in carrying value of our commodity price derivatives since December 31, 2010 principally resulted from the overall increase in market prices for natural gas relative to the prices in our open derivative instruments and, to a lesser degree, monthly settlements received during 2011.

The changes in the carrying value of our derivatives for the three months ended March 31, 2011 and 2010 are presented below:


	For the Three Months Ended March 31,
	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 amounts receivable/payable-net		(218	)		-			(4,997	)		(2,223	)		(7,220	)
Net settlements reported in revenue		(23,782	)		-			-			(24,557	)		(24,557	)
Net settlements reported in interest expense		-			-			(2,296	)		-			(2,296	)
Cash settlements reported in long-term debt		-			-			(13,934	)		-			(13,934	)
Unrealized change in fair value of Gas Purchase Commitment reported in costs of purchased gas		-			(16,638	)		-			-			(16,638	)
Change in fair value of effective interest swaps		-			-			12,089			-			12,089
Ineffectiveness reported in other revenue		(53	)		-			-			1,395			1,395
Unrealized gains (losses) reported in OCI		(26,506	)		-			-			148,222			148,222

Derivative fair value at end of period	$	96,203		$	(23,263	)	$	(5,030	)	$	230,718		$	202,425

Gains and losses from the effective portion of derivative assets and liabilities held in AOCI expected to be reclassified into earnings during the following twelve months would result in a gain of $41.0 million net of income taxes. Hedge derivative ineffectiveness resulted in net losses of $0.1 million and net gains of $1.4 million for the three months ended March 31, 2011 and 2010, respectively.

4. INVESTMENT IN BBEP

At March 31, 2011, we owned 15.6 million BBEP Units, or 26%, of BBEP, whose price closed at $21.73 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. We further reduced our ownership during the three months ended March 31, 2011 through the sale of approximately 0.1 million BBEP Units at a weighted average unit sales price of $21.83. We recognized a gain of $1.3 million as other income for the difference between our carrying value at the time of the sale of $5.31 per BBEP Unit and the net sales proceeds.

Changes in the balance of our investment in BBEP for the three months ended March 31, 2011 were as follows:


(In thousands)
Balance at December 31, 2010	$	83,341
Equity loss in BBEP		(20,884	)
Distributions from BBEP		(6,369	)
Disposal of BBEP Units		(414	)

Ending investment balance	$	55,674

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
	December 31,
	2010			2009
	(In thousands)
Revenue⁽¹⁾	$	18,165		$	38,263
Operating expense		79,483			73,272

Operating loss		(61,318	)		(35,009	)
Interest and other⁽²⁾		9,989			5,859
Income tax benefit		(439	)		(1,174	)
Noncontrolling interests		35			19

Net loss available to BBEP	$	(70,903	)	$	(39,713	)


	⁽¹⁾	For the three months ended December 31, 2010 and 2009, unrealized losses of $82.3 million and $54.7 million on commodity derivatives were recognized, respectively.

	⁽²⁾	The three months ended December 31, 2010 and 2009 included unrealized gains of $3.1 million and unrealized losses of $0.7 million, respectively, from interest rate swaps.


	As of December 31,
	2010		2009
	(In thousands)
Current assets	$	145,233	$	142,441
Property, plant and equipment		1,728,256		1,741,089
Other assets		98,113		87,499
Current liabilities		85,035		91,890
Long-term debt		516,000		559,000
Other non-current liabilities		64,715		91,338
Partners’ equity		1,305,852		1,228,801

5. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment consisted of the following:


	March 31,			December 31,
	2011			2010
	(In thousands)
Oil and gas properties
Subject to depletion	$	4,939,775		$	4,805,161
Unevaluated costs		356,566			304,269
Accumulated depletion		(2,383,394	)		(2,274,785	)

Net oil and gas properties		2,912,947			2,834,645

Other plant and equipment
Pipelines and processing facilities		277,500			235,676
General properties		70,907			70,267
Accumulated depreciation		(77,362	)		(72,743	)

Net other property and equipment		271,045			233,200


Property, plant and equipment, net of accumulated depletion and depreciation	$	3,183,992		$	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. The ceiling test prepared for our U.S. oil and gas properties resulted in no impairment at March 31, 2011.

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:


	March 31,			December 31,
	2011			2010
	(In thousands)
Senior Secured Credit Facility	$	155,386		$	21,114
Senior notes due 2015, net of unamortized discount		471,092			470,866
Senior notes due 2016, net of unamortized discount		584,219			583,605
Senior notes due 2019, net of unamortized discount		293,622			293,496
Senior subordinated notes due 2016		350,000			350,000
Convertible debentures, net of unamortized discount		145,396			143,478

Total debt		1,999,715			1,862,559
Unamortized deferred gain - terminated interest rate swaps		26,449			27,635
Current portion of long-term debt		(145,396	)		(143,478	)

Long-term debt	$	1,880,768		$	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 March 31, 2011, there was $795 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 April 1, 2011, the debentures were not convertible based on share prices for the quarter ended March 31, 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 March 31, 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 March 31, 2011 and December 31, 2010, the remaining unamortized discount on the debentures was $4.6 million and $6.5 million, respectively, resulting in a carrying value of $145.4 million and $143.5 million, respectively. The remaining discount will be accreted to face value through October 2011. For the three months ended March 31, 2011 and 2010, interest expense on our convertible debentures, recognized at an effective interest rate of 6.75%, was $2.6 million and $2.5 million, respectively, including contractual interest of $0.7 million for each period.

Summary of All Outstanding Debt

The following table summarizes significant aspects of our long-term debt:

Priority on Collateral and Structural Seniority⁽¹⁾

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⁾

$475 million

$600 million

$300 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
March 31, 2011⁽⁴⁾

3.22

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
covenants⁽⁶⁾

- Incurrence of debt
- Incurrence of liens
- Payment of dividends
- Equity purchases
- Asset sales
- Affiliate transactions
- Limitations on derivatives

- Incurrence of debt
- Incurrence of liens
- Payment of dividends
- Equity purchases
- Asset sales
- Affiliate transactions

N/A

Optional redemption⁽⁶⁾

Any time

August 1,
2012: 103.875
2013: 101.938
2014: par

July 1,
2013: 105.875
2014: 102.938
2015: par

August 15,
2014: 104.563
2015: 103.042
2016: 101.521
2017: par

April 1,
2011: 103.563
2012: 102.375
2013: 101.188
2014: par

November 8, 2011
and thereafter

Make-whole redemption⁽⁶⁾

N/A

Callable prior to
August 1, 2012 at
make-whole call price of
Treasury + 50 bps

Callable prior to
July 1, 2013 at
make-whole call price of
Treasury + 50 bps

Callable prior to
August 15, 2014 at
make-whole call price of
Treasury + 50 bps

Callable prior to
April 1, 2011 at
make-whole call price of
Treasury + 50 bps

N/A

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.
Cowtown Pipeline
Management, Inc.
Cowtown Pipeline L.P.
Cowtown Gas
Processing L.P.
Quicksilver Resources
Canada Inc.

Cowtown Pipeline
Funding, Inc.
Cowtown Pipeline
Management, Inc.
Cowtown Pipeline L.P.
Cowtown Gas
Processing L.P.

N/A

Estimated fair value⁽⁷⁾

$155.4 million

$496.4 million

$702.0 million

$323.6 million

$347.4 million

$160.2 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 March 31, 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) LIBOR 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 (iii) 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 three months ended March 31, 2011.


(In thousands)

Beginning asset retirement obligations	$	57,809
Additional liability incurred		3,610
Accretion expense		613
Asset retirement costs incurred		(268	)
Gain on settlement of liability		135
Currency translation adjustment		1,004

Ending asset retirement obligations		62,903
Less current portion		(1,574	)

Long-term asset retirement obligation	$	61,329

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 NOVA Gas Transmission Ltd. (“NGTL”), a subsidiary of TransCanada Pipelines Limited, for the construction of a pipeline and meter station (the “project”) that 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, which is expected to continue through 2014. Assuming the project is fully constructed and based on estimated costs of C$295 million, including taxes of C$30 million, we expect to provide cumulative letters of credit as follows:


	NGTL
	Cumulative
	Financial
	Assurances
	(C$ in thousands)
April 16, 2011	$	14,750
June 1, 2011	$	32,450
March 1, 2012	$	67,850
October 1, 2012	$	109,150
July 1, 2013	$	147,500
October 1, 2013	$	295,000

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. If the project is terminated by NGTL after June 2011, then we would also be required to pay NGTL an additional C$26.4 million. No amounts have been recognized on our consolidated balance sheet as of March 31, 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.

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.

Contingencies

On March 10, 2011, the Court granted our motions for summary judgment on Eagle’s remaining tort claims, but directed further briefing on choice of law issues after which the Court will consider a motion for reconsideration of the summary judgment motions. The Court denied Eagle’s summary judgment motion on our contract claims on March 31, 2011.

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 quarter ended March 31, 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 March 31, 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 three months ended March 31, 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 three months ended March 31, 2011:


				Wtd Avg		Wtd Avg
				Exercise		Remaining	Aggregate
	Shares			Price		Contractual Life	Intrinsic Value
						(In years)	(In thousands)
Outstanding at January 1, 2011		3,348,642		$	11.10
Granted		834,970			14.88
Exercised		(59,127	)		6.21
Cancelled		(65,089	)		10.11

Outstanding at March 31, 2011		4,059,396		$	11.96	8.1	$	16,776

Exercisable at March 31, 2011		2,027,475		$	11.75	7.4	$	11,180

We estimate that a total of 4.0 million stock options will become vested including those options already exercisable. Compensation expense related to stock options of $1.9 million and $1.7 million was recognized for the three months ended March 31, 2011 and 2010, respectively. Cash received from the exercise of stock options totaled $0.4 million for the three months ended March 31, 2011. The total intrinsic value of those options exercised was $0.5 million.

Restricted Stock

The following table summarizes our restricted stock and stock unit activity for the three months ended March 31, 2011:


	Payable in shares					Payable in cash
				Wtd Avg Grant					Wtd Avg Grant
				Date Fair					Date Fair
	Shares			Value		Shares			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		(1,089,297	)		12.06		(137,463	)		9.49
Cancelled		(63,477	)		11.62		(5,966	)		13.49

Outstanding at March 31, 2011		2,321,039		$	12.66		443,719		$	13.12

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 three months ended March 31, 2011 had an estimated grant date fair value of $17.0 million. The fair value of RSUs settled in cash was $6.3 million at March 31, 2011. For the three months ended March 31, 2011 and 2010, compensation expense of $3.6 million and $3.8 million, respectively, was recognized. The total fair value of shares vested during the three months ended March 31, 2011 was $15.6 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
	March 31,
	2011			2010
	(In thousands, except
	per share data)
Net income (loss) attributable to Quicksilver	$	(70,758	)	$	8,188
Basic income allocable to participating securities⁽¹⁾		-			(107	)

Basic net income (loss) attributable to Quicksilver	$	(70,758	)	$	8,081
Impact of assumed conversions – interest on 1.875% convertible debentures, net of income taxes		-			-

Income (loss) available to stockholders assuming conversion of convertible debentures	$	(70,758	)	$	8,081


Weighted average common shares – basic		168,872			167,856
Effect of dilutive securities⁽²⁾:
Share-based compensation awards		-			864
Contingently convertible debentures		-			-

Weighted average common shares – diluted		168,872			168,720


Earnings (loss) per common share – basic	$	(0.42	)	$	0.05

Earnings (loss) per common share – diluted	$	(0.42	)	$	0.05


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

⁽²⁾		For the three months ended March 31, 2011 and 2010, the effects of 9.8 million shares associated with our contingently convertible debt and stock options and unvested restricted stock units representing 2.8 million shares and 1.3 million, respectively, 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.

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

Condensed Consolidating Balance Sheets


	March 31, 2011
			Restricted		Restricted		Restricted			Quicksilver
	Quicksilver		Guarantor		Non-Guarantor		Subsidiary			Resources Inc.
	Resources Inc.		Subsidiaries		Subsidiaries		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets	$	147,331	$	86,914	$	43,696	$	(111,828	)	$	166,113
Property and equipment		2,503,149		67,837		613,006		-			3,183,992
Assets of midstream operations		-		26,421		-		-			26,421
Investment in subsidiaries (equity method)		312,940		-		-		(257,266	)		55,674
Other assets		316,241		3,675		1,457		(243,621	)		77,752

Total assets	$	3,279,661	$	184,847	$	658,159	$	(612,715	)	$	3,509,952


LIABILITIES AND EQUITY
Current liabilities	$	359,655	$	110,049	$	56,105	$	(111,828	)	$	413,981
Long-term liabilities		1,951,717		20,360		397,778		(243,621	)		2,126,234
Liabilities of midstream operations		-		1,448		-		-			1,448
Stockholders’ equity		968,289		52,990		204,276		(257,266	)		968,289

Total liabilities and equity	$	3,279,661	$	184,847	$	658,159	$	(612,715	)	$	3,509,952


	December 31, 2010
			Restricted		Restricted		Restricted			Quicksilver
	Quicksilver		Guarantor		Non-Guarantor		Subsidiary			Resources Inc.
	Resources Inc.		Subsidiaries		Subsidiaries		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets	$	210,652	$	86,582	$	49,424	$	(108,486	)	$	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	$	3,335,404	$	182,150	$	631,390	$	(636,610	)	$	3,512,334


LIABILITIES AND EQUITY
Current liabilities	$	411,586	$	106,627	$	53,373	$	(108,486	)	$	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	$	3,335,404	$	182,150	$	631,390	$	(636,610	)	$	3,512,334

Condensed Consolidating Statements of Income


	For the Three Months Ended March 31, 2011
							Restricted			Restricted			Quicksilver
	Quicksilver			Guarantor			Non-Guarantor			Subsidiary			Resources Inc.
	Resources Inc.			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenue	$	179,571		$	1,510		$	32,341		$	(1,235	)	$	212,187
Operating expenses		137,169			2,266			74,780			(1,235	)		212,980
Equity in net earnings of subsidiaries		(33,808	)		-			-			33,808			-

Operating income (loss)		8,594			(756	)		(42,439	)		33,808			(793	)
Loss from earnings of BBEP		(20,884	)		-			-			-			(20,884	)
Interest expense and other		(43,270	)		-			(1,787	)		-			(45,057	)
Income tax (expense) benefit		(15,198	)		265			10,909			-			(4,024	)

Net loss	$	(70,758	)	$	(491	)	$	(33,317	)	$	33,808		$	(70,758	)


	For the Three Months Ended March 31, 2010
				Restricted			Restricted			Restricted			Quicksilver			Unrestricted						Quicksilver
	Quicksilver			Guarantor			Non-Guarantor			Subsidiary			and Restricted			Non-Guarantor			Consolidated			Resources Inc.
	Resources Inc.			Subsidiaries			Subsidiaries			Eliminations			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenue	$	182,500		$	1,645		$	35,849		$	(696	)	$	219,298		$	24,739		$	(21,879	)	$	222,158
Operating expenses		127,841			1,883			23,345			(696	)		152,373			15,819			(21,879	)		146,313
Equity in net earnings of subsidiaries		10,602			3,777			-			(10,602	)		3,777			-			(3,777	)		-

Operating income		65,261			3,539			12,504			(10,602	)		70,702			8,920			(3,777	)		75,845
Loss from earnings of BBEP		(15,989	)		-			-			-			(15,989	)		-			-			(15,989	)
Interest expense and other		(40,059	)		-			(1,437	)		-			(41,496	)		(2,678	)		-			(44,174	)
Income tax expense		(1,025	)		(1,239	)		(2,765	)		-			(5,029	)		(53	)		-			(5,082	)

Net income	$	8,188		$	2,300		$	8,302		$	(10,602	)	$	8,188		$	6,189		$	(3,777	)	$	10,600
Net income attributable to noncontrolling interests		-			-			-			-			-			(2,412	)		-			(2,412	)

Net income attributable to Quicksilver	$	8,188		$	2,300		$	8,302		$	(10,602	)	$	8,188		$	3,777		$	(3,777	)	$	8,188

Condensed Consolidating Statements of Cash Flows


	For the Three Months Ended March 31, 2011
				Restricted			Restricted			Restricted		Quicksilver
	Quicksilver			Guarantor			Non-Guarantor			Subsidiary		Resources Inc.
	Resources Inc.			Subsidiaries			Subsidiaries			Eliminations		Consolidated
	(In thousands)
Net cash flow provided (used) by operations	$	(805	)	$	417		$	12,101		$	-	$	11,713
Purchases of property, plant and equipment		(128,911	)		(417	)		(67,219	)		-		(196,547	)
Proceeds from sale of BBEP units		1,703			-			-			-		1,703
Proceeds from sale of properties and equipment		507			-			-			-		507

Net cash flow used by investing activities		(126,701	)		(417	)		(67,219	)		-		(194,337	)
Issuance of debt		87,000			-			60,983			-		147,983
Repayments of debt		(10,000	)		-			(5,145	)		-		(15,145	)
Proceeds from exercise of stock options		368									-		368
Purchase of treasury stock		(4,797	)								-		(4,797	)


Net cash flow provided by financing activities		72,571			-			55,838			-		128,409
Effect of exchange rates on cash		-			-			(720	)		-		(720	)

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 Three Months Ended March 31, 2010
				Restricted			Restricted			Quicksilver			Unrestricted						Quicksilver
	Quicksilver			Guarantor			Non-Guarantor			and Restricted			Non-Guarantor						Resources Inc.
	Resources Inc.			Subsidiaries			Subsidiaries			Subsidiaries			Subsidiaries			Eliminations			Consolidated
										(In thousands)
Net cash flow provided (used) by operating activities	$	50,013		$	130		$	20,759		$	70,902		$	(1,457	)	$	(3,673	)	$	65,772
Purchases of property, plant and equipment		(85,571	)		(130	)		(22,980	)		(108,681	)		(17,163	)		(3,487	)		(129,331	)
Distribution to parent		80,276			-			-			80,276			(80,276	)					-
Proceeds from sale of properties and equipment		718			-			-			718			-			-			718

Net cash flow used by investing activities		(4,577	)		(130	)		(22,980	)		(27,687	)		(97,439	)		(3,487	)		(128,613	)
Issuance of debt		159,000			-			24,446			183,446			112,000			-			295,446
Repayments of debt		(193,000	)		-			(23,039	)		(216,039	)		(11,600	)		-			(227,639	)
Debt issuance costs		(109	)		-			-			(109	)		-			-			(109	)
Gas Purchase Commitment - net		(7,317	)		-			-			(7,317	)		-			-			(7,317	)
Issuance of KGS common units		-			-			-			-			11,050			-			11,050
Distributions to parent		-			-						-			(7,160	)		7,160			-
Distributions to noncontrolling interests		-			-			-			-			(4,404	)		-			(4,404	)
Proceeds from exercise of stock options		760			-			-			760			-			-			760
Taxes paid on vested KGS equity compensation		-			-			-			-			(1,144	)		-			(1,144	)
Purchase of treasury stock		(4,766	)		-			-			(4,766	)		-			-			(4,766	)

Net cash flow provided (used) by financing activities		(45,432	)		-			1,407			(44,025	)		98,742			7,160			61,877
Effect of exchange rates on cash		-			-			(220	)		(220	)		-			-			(220	)

Net increase (decrease) in cash and equivalents		4			-			(1,034	)		(1,030	)		(154	)		-			(1,184	)
Cash and equivalents at beginning of period		5			-			1,034			1,039			746			-			1,785

Cash and equivalents at end of period	$	9		$	-		$	-		$	9		$	592		$	-		$	601

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 March 31:
2011
Revenue	$	179,571	$	32,341		$	1,510		$	-		$	(1,235	)	$	212,187
DD&A		38,756		11,424			1,713			578			-			52,471
Impairment expense		-		49,063			-			-			-			49,063
Operating income (loss)		60,245		(41,314	)		(755	)		(18,969	)		-			(793	)
Property and equipment costs incurred		116,591		74,004			5,236			829			-			196,660

2010
Revenue	$	182,500	$	35,849		$	25,803		$	-		$	(21,994	)	$	222,158
DD&A		27,949		11,285			7,057			466			-			46,757
Operating income (loss)		72,279		13,433			11,123			(20,990	)		-			75,845
Property and equipment costs incurred		77,367		30,585			27,634			620			-			136,206

Property, plant and equipment – net
March 31, 2011		2,488,172		613,006			67,837			14,977			-			3,183,992
December 31, 2010		2,403,039		581,775			68,389			14,642			-			3,067,845

Investment in equity affiliates
March 31, 2011		55,674		-			-			-			-			55,674
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 Three Months Ended
	March 31,
	2011			2010
	(In thousands)
Interest	$	70,490		$	50,025
Income taxes		(57	)		(7,006	)

Other significant non-cash transactions were as follows:


	For the Three Months Ended
	March 31,
	2011		2010
	(In thousands)
Working capital related to capital expenditures	$	98,973	$	126,393

14. TRANSACTIONS WITH RELATED PARTIES

As of March 31, 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 $0.2 million in the first three months of 2010 for rent on buildings owned by entities controlled by members of the Darden family. For the first three months of 2011, rentals paid to these entities were negligible. Rental rates were determined based on comparable rates charged by third parties.

During the first three months of 2011 and 2010, we paid $0.2 million and $0.1 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 $0.1 million for the first three 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-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 for a take private transaction of the Company. As a result, our Board of Directors disbanded its transaction committee, and going forward, the Board of Directors as a whole will again work together to evaluate and pursue strategic and growth opportunities for Quicksilver.

Horn River Basin Exploration

We had four wells tied into sales lines and producing as of December 31, 2010. In 2011, we have spent $71.2 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.

Increase in Production

Daily production increased 23% during the first quarter of 2011 from the 2010 first quarter. The production increase is discussed further inResults of Operationsbelow.

2011 CAPITAL PROGRAM

We had capital expenditures of $197 million for the first three months of 2011. The most significant change from our previously disclosed capital program is a $24 million increase in our planned acreage acquisition in the Greater Green River Basin.

For all of 2011, we continue to expect our average production to be greater than our first quarter 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 and the Southern Alberta Asset.

FINANCIAL RISK MANAGEMENT

We have established internal control policies and procedures for managing risk within our organization. The possibility of decreasing prices received for our natural gas, NGL and oil 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. Item 3 of this Quarterly Report contains details of our commodity price and interest rate risk management.

RESULTS OF OPERATIONS

The following discussion compares the results of operations for the three months ended March 31, 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

Natural Gas, NGL and Oil

Production Revenue:


	Natural Gas				NGL						Oil				Total
	2011		2010		2011			2010			2011		2010		2011		2010
								(In millions)
Barnett Shale	$	89.4	$	81.5	$	46.4		$	41.1		$	2.7	$	3.2	$	138.5	$	125.8
Other U.S.		0.3		1.2		0.2			0.1			2.9		2.3		3.4		3.6
Hedging		23.9		48.3		(7.2	)		(9.6	)		—		—		16.7		38.7

Total U.S.		113.6		131.0		39.4			31.6			5.6		5.5		158.6		168.1
Horseshoe Canyon		20.9		28.9		—			0.1			—		—		20.9		29.0
Horn River		3.5		3.0		—			—			—		—		3.5		3.0
Hedging		7.3		1.5		—			—			—		—		7.3		1.5

Total Canada		31.7		33.4		—			0.1			—		—		31.7		33.5

Total	$	145.3	$	164.4	$	39.4		$	31.7		$	5.6	$	5.5	$	190.3	$	201.6

Average Daily Production Volume:


	Natural Gas				NGL				Oil				Equivalent Total
	2011		2010		2011		2010		2011		2010		2011		2010
	(MMcfd)				(Bbld)				(Bbld)				(MMcfed)
Barnett Shale		247.4		173.3		11,531		11,263		335		474		318.6		243.7
Other U.S.		0.8		2.3		23		17		381		381		3.2		4.8

Total U.S.		248.2		175.6		11,554		11,280		716		855		321.8		248.5
Horseshoe Canyon		59.4		62.5		6		11		—		—		59.4		62.5
Horn River		11.1		7.4		—		—		—		—		11.1		7.4

Total Canada		70.5		69.9		6		11		—		—		70.5		69.9


Total		318.7		245.5		11,560		11,291		716		855		392.3		318.4

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	$	4.02	$	5.23	$	44.68		$	40.51		$	90.72	$	73.63	$	4.83	$	5.73
Other U.S.		4.43		4.99		77.55			85.70			83.80		68.49		11.51		8.29
Hedging		1.07		3.06		(6.93	)		(9.43	)		—		—		0.58		1.73
Total U.S.	$	5.09	$	8.28	$	37.82		$	31.19		$	87.05	$	71.36	$	5.48	$	7.52
Horseshoe Canyon	$	3.90	$	5.13	$	73.64		$	73.92		$	—	$	—	$	3.91	$	5.14
Horn River		3.53		4.60		—			—			—		—		3.53		4.60
Hedging		1.15		0.24		—			—			—		—		1.15		0.24
Total Canada	$	4.99	$	5.32	$	73.64		$	73.92		$	—	$	—	$	4.99	$	5.32
Total	$	5.07	$	7.44	$	37.84		$	31.19		$	87.05	$	71.36	$	5.39	$	7.03

The following table summarizes the changes in our natural gas, NGL and oil revenue:


	Natural
	Gas			NGL		Oil			Total
	(In thousands)
Revenue for the 2010 quarter	$	164,379		$	31,691	$	5,493		$	201,563
Volume variances		34,116			985		(900	)		34,201
Hedge revenue variances		(18,646	)		2,371		—			(16,275	)
Price variances		(34,524	)		4,325		1,011			(29,188	)

Revenue for the 2011 quarter	$	145,325		$	39,372	$	5,604		$	190,301

Natural gas revenue for the 2011 quarter decreased from the 2010 quarter despite a 30% increase in production. Realized prices, without hedge gains, were 23% lower for the 2011 quarter as compared to the 2010 quarter and more than offset production increases. The 43% 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 50% production increase from 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 quarter resulted from a 21% increase in realized prices, before hedge losses, and a small increase in production from our Barnett Shale Asset 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 $24.0 million and $40.3 million, respectively, because of our hedging activities.

Sales of Purchased Natural Gas and Costs of Purchased Natural Gas


	Three Months Ended
	March 31,
	2011		2010
	(In thousands)
Sales of purchased natural gas:
Purchases from Eni	$	13,917	$	12,578
Purchases from others		6,509		3,646

Total		20,426		16,224
Costs of purchased natural gas sold:
Purchases from Eni		13,794		12,518
Purchases from others		5,949		4,151
Unrealized valuation (gain) loss on Gas Purchase Commitment		—		16,638

Total		19,743		33,307

Net sales and purchases of natural gas	$	683	$	(17,083	)

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
	March 31,
	2011			2010
	(In thousands)
Midstream revenue:
KGS	$	—		$	1,983
Canada		844			641
Other Texas		275			352

Total midstream revenue		1,119			2,976
Gain (loss) from hedge ineffectiveness		(53	)		1,395
Other		394			—

Total	$	1,460		$	4,371

Midstream revenue was $1.9 million lower from the 2010 quarter primarily as a result of the sale of our interests in KGS in October 2010, and lower volume on our HCDS. Losses from hedge ineffectiveness were $0.1 million for the 2011 quarter as compared to gains for the 2010 quarter.

Operating Expense

Lease Operating


	Three Months Ended March 31,
	2011				2010
	(In thousands, except per unit amounts)
			Per				Per
			Mcfe				Mcfe
Barnett Shale
Cash expense	$	11,106	$	0.39	$	10,109	$	0.46
Equity compensation		269		0.01		211		0.01

	$	11,375	$	0.40	$	10,320	$	0.47
Other U.S.
Cash expense	$	1,246	$	4.27	$	1,957	$	4.57
Equity compensation		55		0.19		41		0.10

	$	1,301	$	4.46	$	1,998	$	4.67
Total U.S.
Cash expense	$	12,352	$	0.43	$	12,066	$	0.54
Equity compensation		324		0.01		252		0.01

	$	12,676	$	0.44	$	12,318	$	0.55
Horseshoe Canyon
Cash expense	$	7,739	$	1.45	$	6,935	$	1.23
Equity compensation		164		0.03		327		0.06

	$	7,903	$	1.48	$	7,262	$	1.29
Horn River
Cash expense	$	978	$	0.98	$	384	$	0.58
Equity compensation		—		—		—		—

	$	978	$	0.98	$	384	$	0.58
Total Canada
Cash expense	$	8,717	$	1.37	$	7,319	$	1.16
Equity compensation		164		0.03		327		0.05

	$	8,881	$	1.40	$	7,646	$	1.21
Total Company
Cash expense	$	21,069	$	0.60	$	19,385	$	0.68
Equity compensation		488		0.01		579		0.02

	$	21,557	$	0.61	$	19,964	$	0.70

Although U.S. lease operating expense for the 2011 quarter was almost unchanged in comparison to the 2010 quarter, lease operating expense per Mcfe was 21% lower than the 2010 quarter. A 31% 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 compared to the 2010 quarter.

Lease operating expense for the 2011 quarter in Canada increased 16% when compared to the 2010 quarter. Lease operating expense for the 2011 quarter on a Canadian dollar basis increased C$0.8 million or 11%, and 10% on a Canadian dollar basis per Mcfe from the 2010 quarter. The C$0.3 million increase in Horseshoe Canyon lease operating expense was due to additional repair and maintenance of compressors during the 2011 quarter. The increase in Horn River lease operating expense of C$0.5 million for the 2011 quarter was primarily the result of increased road fees in the area as well as additional producing wells and production.

Gathering, Processing and Transportation


	Three Months Ended March 31,
	2011				2010
	(In thousands, except per unit amounts)
			Per				Per
			Mcfe				Mcfe
Barnett Shale	$	40,377	$	1.41	$	13,257	$	0.60
Other U.S.		16		0.05		6		0.01

Total U.S.	$	40,393	$	1.39	$	13,263	$	0.59
Horseshoe Canyon		1,019		0.19		1,342		0.24
Horn River		2,602		2.61		1,397		2.11

Total Canada		3,621		0.57		2,739		0.43

Total	$	44,014	$	1.25	$	16,002	$	0.56

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. KGS’ revenue earned from gathering and processing production from our Barnett Shale Asset was $16.0 million, or $0.73 per Mcfe, for the first quarter of 2010. 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 transportation fees associated with increased production from our Horn River Asset for the 2011 quarter.

Production and Ad Valorem Taxes


	Three Months Ended March 31,
	2011				2010
	(In thousands, except per unit amounts)
			Per				Per
			Mcfe				Mcfe
Production taxes
U.S.	$	1,684	$	0.06	$	2,222	$	0.10
Canada		14		—		140		0.02

Total production taxes		1,698		0.04		2,362		0.09
Ad valorem taxes
U.S.	$	5,231		0.18	$	5,538		0.25
Canada		652		0.10		606		0.10

Total ad valorem taxes		5,883		0.17		6,144		0.21

Total	$	7,581	$	0.21	$	8,506	$	0.30

Production taxes for the 2011 quarter reflect a 16% decrease in realized prices before hedge settlements partially offset by a 31% increase in production volume from our Barnett Shale Asset when compared to the 2010 quarter. During the 2011 quarter, we received a 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. The absence of $1.5 million of KGS ad valorem taxes for the 2010 quarter partially offset 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.

Depletion, Depreciation and Accretion


	Three Months Ended March 31,
	2011				2010
	(In thousands, except per unit amounts)
			Per					Per
			Mcfe					Mcfe
Depletion
U.S.	$	37,145	$	1.28	$	26,257	$	1.17
Canada		9,855		1.55		9,774		1.55

Total depletion		47,000		1.33		36,031		1.26
Depreciation of other fixed assets
U.S.	$	3,622	$	0.13	$	8,905	$	0.40
Canada		1,219		0.19		1,083		0.17

Total depreciation		4,841		0.14		9,988		0.35
Accretion		630		0.02		738		0.02

Total	$	52,471	$	1.49	$	46,757	$	1.63

U.S. depletion for the 2011 quarter reflected a 9% increase in the U.S. depletion rate and a 29% increase in U.S. production when compared to the 2010 quarter. Changes in the U.S.-Canadian dollar exchange rate accounted for a $0.5 million increase in Canadian depletion that was nearly offset by a 5% decrease in the Canadian dollar depletion rate. Following the impairment recognized in the 2011 quarter, we expect Canadian depletion will be $1.42 per Mcfe.

U.S. depreciation for the 2011 quarter was lower than the 2010 quarter primarily because KGS’ depreciation of $5.4 million was included for the 2010 quarter.

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 2011 quarter, we recognized a $49.1 million non-cash charge for impairment of our Canadian oil and gas properties as of March 31, 2011. The AECO natural gas price used to prepare the 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.

General and Administrative


	Three Months Ended March 31,
	2011				2010
	(In thousands, except per unit amounts)
			Per				Per
			Mcfe				Mcfe
Cash expense	$	13,401	$	0.38	$	15,658	$	0.55
Equity compensation		4,990		0.14		4,865		0.17

Total	$	18,391	$	0.52	$	20,523	$	0.72

General and administrative expense for the 2011 quarter was lower than the 2010 quarter despite expense of $0.7 million recognized in connection with evaluation of a take-private transaction including legal, professional and other costs and expenses. The increase were partially offset by the absence of expense associated with our litigation with BBEP, which was settled in April 2010, and the absence of $1.7 million of expense attributable to KGS for the 2010 quarter.

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 and 2010 quarter results of operations include BBEP’s earnings for the three months ended December 31, 2010 and 2009, respectively.

We recognized losses of $20.9 million and $16.0 million for equity earnings from our investment in BBEP for the 2011 and 2010 quarters, 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 $1.3 million were recognized in the 2011 quarter from the sale of BBEP Units.

Interest Expense


	Three Months Ended
	March 31,
	2011			2010
	(In thousands)
Interest costs on debt outstanding	$	43,446		$	40,875
Add: Non-cash interest⁽¹⁾		3,880			5,075
Less: Interest capitalized		(1,148	)		(1,433	)

Interest expense	$	46,178		$	44,517

⁽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 of the absence of $6.5 million received in the 2010 quarter from interest rate swaps. Offsetting this increase was $2.1 million of interest expense recognized in the 2010 quarter that was attributable to KGS and lower outstanding debt balances during the 2011 quarter.

Income Taxes


	Three Months Ended
	March 31,
	2011			2010
Income tax expense (In thousands)	$	4,024		$	5,082
Effective tax rate		-6.0	%		32.4	%

Our income tax provision for the 2011 quarter remains comparable to the 2010 quarter income tax provision despite the loss recognized before income taxes for the 2011 quarter. The effective tax rate for the 2011 quarter reflects a projection of a full year of Canadian taxable loss partially offset by projection of a full year of U.S. taxable income. As the Canadian taxable loss was taxed at the lower applicable Canadian tax rate and U.S. taxable income was taxed at a higher U.S. effective tax rate, our consolidated income tax provision resulted in income tax expense for the 2011 quarter. We expect that the effective tax rate of (6.0%) for the 2011 quarter 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 materially the same except for the property, plant and equipment purchased by the unrestricted subsidiaries which prior to October 1, 2010

consisted of KGS and its subsidiaries. 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 2015, price collars and swaps hedge a portion of our natural gas and NGL revenue. The following summarizes future production hedged with commodity derivatives as of March 31, 2011.


Production	Daily Production Volume
Year	Gas	NGL
	MMcfd	MBbld
2011	190	10.5
2012	130	2.0
2013	70	—
2014 - 2015	30	—

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


	Three Months Ended
	March 31,
	2011			2010
	(In thousands)
Net cash provided by operating activities	$	11,713		$	65,772
Net cash used by investing activities		(194,337	)		(128,613	)
Net cash provided by financing activities		128,409			61,877

Operating Cash Flows

Net cash provided by operations for the 2011 quarter decreased from the 2010 quarter, primarily due to lower realized prices (including hedging effects) and higher payments to KGS for GPT costs partially offset by receipt of BBEP distributions of $6.4 million in the 2011 quarter. In addition, the 2010 quarter included nonrecurring cash receipts for income tax refunds and interest rate swap settlements and terminations totaling $32.4 million.

Investing Cash Flows

Our expenditures for property, plant and equipment for the 2011 quarter and 2010 quarter were as follows:


	United States		Canada		Consolidated
	(In thousands)
For the Three Months Ended March 31, 2011
Exploration and production	$	116,246	$	40,315	$	156,561
Gathering and processing		5,236		33,566		38,802
Administrative		1,174		123		1,297

Total	$	122,656	$	74,004	$	196,660


	United States		Canada		Consolidated
	(In thousands)
For the Three Months Ended March 31, 2010
Exploration and production	$	75,792	$	30,584	$	106,376
Gathering and processing⁽¹⁾		27,634		—		27,634
Administrative		2,196		—		2,196

Total	$	105,622	$	30,584	$	136,206

⁽¹⁾ Includes KGS’ capital expenditures of $27.4 million.

Our 2011 capital expenditures for our exploration and production activities have increased $40.5 million and $9.7 million for the U.S. and Canada, respectively. Our capital expenditures for gathering and processing during the 2011 quarter reflect the sale of KGS in 2010 and construction of infrastructure to gather, compress and deliver our Horn River gas production to third-party processing facilities.

Financing Cash Flows

Net financing cash flows in the 2011 quarter include borrowings of $132.8 million under our Senior Secured Credit Facility and activity for our stock-compensation plan. Net financing cash flows in the 2010 quarter included net borrowings of $67.8 million under our Senior Secured Credit facility. The 2010 quarter also included proceeds of $11.1 million from the KGS Secondary Offering partially offset by repayments of $7.3 million under the Gas Purchase Commitment and activity for KGS’ stock-compensation plans.

Liquidity and Borrowing Capacity

At March 31, 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 March 31, 2011, there was $795 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 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 sales.

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 March 31, 2011, as compared to our balance sheet as of December 31, 2010:

	•		Our net property, plant and equipment balance increased $116.1 million from December 31, 2010 to March 31, 2011. We have incurred capital expenditures of $196.7 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 $16.1 million. Offsetting the increases was $101.5 million of DD&A and impairment expense.

	•		The valuation of our current and non-current derivative assets and liabilities was $50.6 million lower on a net basis for March 31, 2011 as compared to December 31, 2010. The decrease was the result of 2011 settlements received of $24.0 million and unrealized valuation losses of $26.5 million for our remaining commodity derivatives.

	•		The $26.3 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 reduction in capital expenditures decreased accounts payable $5.1 million from the December 31, 2010 amount.

	•		Long-term debt increased $134.1 million for net borrowings under the Senior Secured Credit Facility and amortization of original issuance discounts on our bond issuances partially offset by 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 NGTL in April 2011. Note 8 to the condensed consolidated financial statements found in this Quarterly Report contains additional information about our contracts with NGTL.

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 three months ended March 31, 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 NOVA Gas Transmission Ltd. (“NGTL”) provide financial assurances to NGTL during the construction phase, which is expected to continue through 2014. Assuming the project is fully constructed at estimated costs of C$295 million, we expect to provide letters of credit. 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 onForm 10-K.


ITEM 3.		Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

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 $24.0 million and $40.3 million for the 2011 quarter and 2010 quarter, respectively. Other revenue was $0.1 million lower and $1.4 million greater, respectively, for the 2011 quarter and 2010 quarter due to hedge ineffectiveness.

The following table details our open derivative positions at March 31, 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

4,033

Gas

Collar

Canada

Apr 2011-Dec 2011

10 MMcfd

6.00- 7.00

4,033

Gas

Collar

Canada

Apr 2011-Dec 2011

20 MMcfd

6.00- 7.00

8,065

Gas

Collar

U.S.

Apr 2011-Dec 2011

10 MMcfd

6.25- 7.50

4,715

Gas

Collar

U.S.

Apr 2011-Dec 2011

10 MMcfd

6.25- 7.50

4,715

Gas

Collar

U.S.

Apr 2011-Dec 2011

20 MMcfd

6.25- 7.50

9,429

Gas

Collar

U.S.

Apr 2011-Dec 2012

20 MMcfd

6.50- 7.15

21,741

Gas

Collar

U.S.

Apr 2011-Dec 2012

20 MMcfd

6.50- 7.18

21,832

Gas

Collar

U.S.

Jan 2012-Dec 2012

20 MMcfd

6.50- 8.01

11,395

Gas

Basis

Canada

Apr 2011-Dec 2011

10 MMcfd

⁽¹⁾

432

Gas

Basis

Canada

Apr 2011-Dec 2011

10 MMcfd

⁽¹⁾

432

Gas

Basis

Canada

Apr 2011-Dec 2011

20 MMcfd

⁽¹⁾

863

Gas

Swap

Canada

Apr 2011-Dec 2013

10 MMcfd

5.00

(474)

Gas

Swap

U.S.

Apr 2011-Dec 2013

10 MMcfd

5.00

(474)

Gas

Swap

U.S.

Apr 2011-Dec 2013

10 MMcfd

5.00

(474)

Gas

Swap

U.S.

Apr 2011-Dec 2013

10 MMcfd

5.00

(474)

Gas

Swap

U.S.

Apr 2011-Dec 2015

10 MMcfd

6.00

9,981

Gas

Swap

U.S.

Apr 2011-Dec 2015

20 MMcfd

6.00

19,962

NGL

Swap

U.S.

Apr 2011-Dec 2011

3 MBbld

36.06

(8,894)

NGL

Swap

U.S.

Apr 2011-Dec 2011

2 MBbld

36.31

(5,795)

NGL

Swap

U.S.

Apr 2011-Dec 2011

1 MBbld

40.50

(1,754)

NGL

Swap

U.S.

Apr 2011-Dec 2011

1.5 MBbld

40.42

(2,661)

NGL

Swap

U.S.

Apr 2011-Dec 2011

3 MBbld

41.95

(4,051)

NGL

Swap

U.S.

Jan 2012-Dec 2012

1 MBbld

42.81

(234)

NGL

Swap

U.S.

Jan 2012-Dec 2012

1 MBbld

43.07

(140)

Total

96,203

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

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 quarter, we recognized $1.2 million of those deferred gains as a reduction of interest expense. During the 2010 quarter, we recognized $0.3 million of those deferred gains and $6.2 million received in periodic settlements as reductions of interest expense.

The remaining gain deferred from the 2010 early settlements 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	$	3,711
2012		5,315
2013		5,769
2014		6,261
2015		4,824
2016		569

	$	26,449

The fair value of all derivative instruments included in these disclosures was estimated using prices quoted in active markets for the periods covered by the derivatives and the value confirmed by counterparties. 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.

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 quarter and the 2010 quarter resulted in losses of $0.1 million for each quarter 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 March 31, 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 quarter ended March 31, 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

There have been no other 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 with the exception of the risk factor provided below:

We have substantial financial and other commitments related to our development of a gathering, processing and transportation system for our Horn River Asset.

We have agreed to provide NOVA Gas Transmission Ltd. (“NGTL”) financial assurances in the form of letters of credit to cover its costs to construct a pipeline and meter station (the “project”) that will connect the gas produced from our Horn River Asset, to NGTL’s Alberta System (the “Horn River Mainline”). Our financial exposure is staged in increments as the project is built and ultimately, the costs for the project are estimated to be C$295 million including taxes of approximately C$30 million. Upon completion of the project, the requirement to provide the letters of credit will terminate. We have also committed to deliver for transport up to 1 Tcf of gas to NGTL and to construct a treatment facility to deliver gas that will meet NGTL’s specifications for the Horn River Mainline. Our ability to fund these commitments may be affected by economic and capital markets conditions and other factors that may be beyond our control. In addition, we only have 16.4 MMcf of proved reserves in the Horn River Basin as of December 31, 2010. Accordingly, our ability to deliver up to 1 Tcf of gas depends upon our ability to drill additional successful wells on our Horn River Asset, find third-party sources to supplement or satisfy our obligation, or to pay a demand charge. Failure to satisfy our financial or other commitments could have a material adverse affect on our business, results of operations and financial condition.


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 March 31, 2011.


					Total Number of		Maximum Number of
	Total Number of				Shares Purchased as		Shares that May Yet
	Shares		Average Price		Part of Publicly		Be Purchased Under
Period	Purchased⁽¹⁾		Paid per Share		Announced Plan⁽²⁾		the Plan⁽²⁾
January 2011		263,667	$	14.80		—		—
February 2011		58,992	$	15.15		—		—
March 2011		86	$	13.86		—		—

Total		322,745	$	14.86		—		—

	⁽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

None.


ITEM 6.		Exhibits


Exhibit No.		Description
10.1		Quicksilver Resources Inc. 2011 Executive Bonus Plan (filed as Exhibit 10.1 to the Company’s Form 8-K, filed February 25, 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.

SIGNATURE

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

Dated: May 9, 2011


	Quicksilver Resources Inc.
	By:	/s/ Philip Cook
		Philip Cook
		Senior Vice President - Chief Financial Officer

EXHIBIT INDEX


Exhibit No.		Description
10.1		Quicksilver Resources Inc. 2011 Executive Bonus Plan (filed as Exhibit 10.1 to the Company’s Form 8-K, filed February 25, 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.

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Quicksilver Resources (KWK) Inactive 10-Q2011 Q1 Quarterly report

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