Form 10-Q

10-Q 1 d343124d10q.htm FORM 10-Q Form 10-Q

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, 2012

or

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

For the transition period from to

Commission file number: 001-14837

Quicksilver Resources Inc.

(Exact name of registrant as specified in its charter)


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

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

(817) 665-5000

(Registrant’s telephone number, including area code)

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):


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

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

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


Title of Class		Outstanding as of April 30, 2012
Common Stock, $0.01 par value		173,210,889 shares

DEFINITIONS

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

“ABR” means alternate base rate

“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

“Bcfe” means Bcf of natural gas equivalents

“Canada” means our oil and natural gas operations located principally in British Columbia and Alberta, Canada

“C$” means Canadian dollars

“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 MBbl 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

“OCI” means other comprehensive income

“Oil” includes crude oil and condensate

“RSU” means restricted stock unit

COMMONLY USED TERMS

Other commonly used terms and abbreviations include:

“2007 Senior Secured Credit Facility” means collectively our U.S. senior secured revolving credit facility and our Canadian senior secured revolving credit facility, each dated as of February 9, 2007, which were terminated September 6, 2011 and replaced at that time by the Initial U.S. Credit Facility and the Initial Canadian Credit Facility

“Amended and Restated Canadian Credit Facility” means our new Canadian senior secured revolving credit facility which was amended and restated, effective December 22, 2011

“Amended and Restated U.S. Credit Facility” means our new U.S. senior secured revolving credit facility which was amended and restated, effective December 22, 2011

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

“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

“CMLP” means Crestwood Midstream Partners LP

“Combined Credit Agreements” means collectively our Amended and Restated U.S. Credit Facility and our Amended and Restated Canadian Credit Facility

“Crestwood” means Crestwood Holdings LLC

“Crestwood Transaction” means the sale to Crestwood of all our interests in KGS, including general partner interests and incentive distribution rights

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

“Fortune Creek” means Fortune Creek Gathering and Processing Partnership, a midstream partnership formed in December 2011 with KKR dedicated to the construction and operation of natural gas midstream services within Horn River

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

“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

“Initial Canadian Credit Facility” means our initial Canadian senior secured revolving credit facility, dated as of September 6, 2011, which was amended and restated by the Amended and Restated Canadian Credit Facility on December 22, 2011

“Initial U.S. Credit Facility” means our initial U.S. senior secured revolving credit facility, dated as of September 6, 2011, which was amended and restated by the Amended and Restated U.S. Credit Facility on December 22, 2011

“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”

“KKR” means the Kohlberg Kravis Roberts & Co. L.P. with whom we formed Fortune Creek

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

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

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

“Sand Wash Asset” means our operations and our assets in the Sand Wash basin located in Colorado and southern Wyoming

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

“VIE” means variable interest entity

“West Texas Asset” means our operations and our assets in the Midland and Delaware basins in West Texas prospective in the Bone Springs and Wolfcamp formations, principally concentrated in four areas: Jeff Davis and Reeves Counties, Upton and Crockett Counties, Pecos County and Presidio County

INDEX TO QUARTERLY REPORT ON FORM 10-Q

For the Quarter Ended March 31, 2012


PART I. FINANCIAL INFORMATION

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

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk			37

Item 4. Controls and Procedures			39

PART II. OTHER INFORMATION

Item 1. Legal Proceedings			40

Item 1A. Risk Factors			40

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			40

Item 3. Defaults Upon Senior Securities			41

Item 4. Mine Safety Disclosures			41

Item 5. Other Information			41

Item 6. Exhibits			42

Signature			43

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, processing 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;

•

failure or delays in completing Quicksilver’s proposed initial public offering of common units representing limited partner interests in a master limited partnership holding portions of our Barnett Shale Asset; and

•

additional factors described elsewhere in this Quarterly Report.

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

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

PART I FINANCIAL INFORMATION

ITEM 1.

Condensed Consolidated Interim Financial Statements (Unaudited)

QUICKSILVER RESOURCES INC.

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)

In thousands, except for per share data – Unaudited


	For the Three Months Ended March 31,
	2012		2011
Revenue
Production	$	171,820	$	190,301
Sales of purchased natural gas		12,086		20,426
Other		(38,437)		1,460

Total revenue		145,469		212,187


Operating expense
Lease operating		28,691		21,557
Gathering, processing and transportation		43,077		44,014
Production and ad valorem taxes		6,763		7,581
Costs of purchased natural gas		11,937		19,743
Other operating		18		160
Depletion, depreciation and accretion		54,439		52,471
Impairment		62,746		49,063
General and administrative		19,095		18,391

Total expense		226,766		212,980
Crestwood earn-out		41,097		-

Operating loss		(40,200)		(793)
Loss from earnings of BBEP		-		(20,884)
Other income - net		93		1,121
Fortune Creek accretion		(4,741)		-
Interest expense		(40,170)		(46,178)

Loss before income taxes		(85,018)		(66,734)
Income tax expense (benefit)		(25,094)		4,024

Net loss	$	(59,924)	$	(70,758)

Other comprehensive income (loss)
Reclassification adjustments related to settlements of derivative contracts - net of income tax		(32,534)		(16,219)
Net change in derivative fair value - net of income tax		91,789		(17,195)
Foreign currency translation adjustment		7,928		12,004

Comprehensive income (loss)	$	7,259	$	(92,168)

Loss per common share - basic	$	(0.35)	$	(0.42)
Loss per common share - diluted	$	(0.35)	$	(0.42)

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, 2012		December 31, 2011
ASSETS
Current assets
Cash and cash equivalents	$	13,032	$	13,146
Accounts receivable - net of allowance for doubtful accounts		62,686		95,282
Derivative assets at fair value		227,591		162,845
Other current assets		29,790		29,154

Total current assets		333,099		300,427
Property, plant and equipment - net
Oil and gas properties, full cost method (including unevaluated costs of $477,434 and $433,341, respectively)		3,258,975		3,226,476
Other property and equipment		240,703		234,043

Property, plant and equipment - net		3,499,678		3,460,519
Derivative assets at fair value		170,274		183,982
Other assets		51,680		50,534

	$	4,054,731	$	3,995,462

LIABILITIES AND EQUITY
Current liabilities
Current portion of long-term debt	$	-	$	18
Accounts payable		88,750		142,672
Accrued liabilities		106,885		142,193
Derivative liabilities at fair value		-		4,028
Current deferred tax liability		63,636		45,262

Total current liabilities		259,271		334,173

Long-term debt		2,012,936		1,903,431
Partnership liability		130,071		122,913
Asset retirement obligations		93,945		85,568
Derivative liabilities at fair value		24,398		-
Other liabilities		28,461		28,461
Deferred income taxes		233,172		258,997
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 179,011,812 and 176,980,483 shares issued, respectively		1,790		1,770
Paid in capital in excess of par value		742,635		737,015
Treasury stock of 5,730,587 and 5,379,702 shares, respectively		(48,692)		(46,351)
Accumulated other comprehensive income		282,041		214,858
Retained earnings		294,703		354,627

Total stockholders’ equity		1,272,477		1,261,919

	$	4,054,731	$	3,995,462

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
	Common Stock		Additional Paid-in Capital		Treasury Stock		Accumulated Other Comprehensive Income		Retained Earnings		Total
Balances at December 31, 2010	$	1,755	$	714,869	$	(41,487)	$	130,187	$	264,581	$	1,069,905
Net loss		-		-		-		-		(70,758)		(70,758)
Hedge derivative contract settlements reclassified into earnings from AOCI, 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, restated ⁽¹⁾	$	1,767	$	720,703	$	(46,284)	$	108,777	$	193,823	$	978,786


Balances at December 31, 2011	$	1,770	$	737,015	$	(46,351)	$	214,858	$	354,627	$	1,261,919
Net loss		-		-		-		-		(59,924)		(59,924)
Hedge derivative contract settlements reclassified into earnings from AOCI, net of income tax of $16,350		-		-		-		(32,534)		-		(32,534)
Net change in derivative fair value, net of income tax of $31,632		-		-		-		91,789		-		91,789
Currency translation adjustment		-		-		-		7,928		-		7,928
Issuance & vesting of stock compensation		19		5,610		(2,341)		-		-		3,288
Stock option exercises		1		10		-		-		-		11

Balances at March 31, 2012	$	1,790	$	742,635	$	(48,692)	$	282,041	$	294,703	$	1,272,477

⁽¹⁾	Note 1 contains additional information.

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,
	2012		2011
Operating activities:
Net loss	$	(59,924)	$	(70,758)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion, depreciation and accretion		54,439		52,471
Impairment expense		62,746		49,063
Crestwood earn-out		(41,097)		-
Deferred income tax expense (benefit)		(25,443)		4,024
Non-cash loss from hedging and derivative activities		45,649		54
Stock-based compensation		5,630		5,478
Non-cash interest expense		1,742		3,880
Fortune Creek accretion		4,741		-
Gain on disposition of BBEP units		-		(1,289)
Loss from BBEP in excess of cash distributions		-		27,253
Other		(29)		89
Changes in assets and liabilities
Accounts receivable		32,612		(13,256)
Prepaid expenses and other assets		(1,874)		(3,451)
Accounts payable		(16,319)		(24,711)
Accrued and other liabilities		(35,503)		(17,134)

Net cash provided by operating activities		27,370		11,713

Investing activities:
Purchases of property, plant and equipment		(174,922)		(196,547)
Proceeds from Crestwood earn-out		41,097		-
Proceeds from sale of BBEP units		-		1,703
Proceeds from sale of properties and equipment		460		507

Net cash used by investing activities		(133,365)		(194,337)

Financing activities:
Issuance of debt		161,658		147,983
Repayments of debt		(53,115)		(15,145)
Debt issuance costs paid		(191)		-
Proceeds from exercise of stock options		10		368
Purchase of treasury stock		(2,341)		(4,797)

Net cash provided by financing activities		106,021		128,409

Effect of exchange rate changes in cash		(140)		(720)

Net decrease in cash		(114)		(54,935)
Cash and cash equivalents at beginning of period		13,146		54,937

Cash and cash equivalents at end of period	$	13,032	$	2

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, 2012 and our results of operations and cash flows for the three months ended March 31, 2011 and 2012. 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 2011 Annual Report on Form 10-K.

Immaterial Restatement

The consolidated financial statements as of and for the year ended December 31, 2010 were restated as disclosed within Item 8, Note 2 in the 2011 Annual Report on Form 10-K to increase the previously recognized gain related to the sale of our interests in KGS by $20.7 million and to provide additional deferred taxes on the increased gain. The previously reported gain excluded certain liabilities for intercompany transactions related to services performed by KGS for our U.S. exploration and production segment, which should have been included in the gain calculation. Additional depletion expense was recognized due to the inclusion of additional future development costs in the 2010 depletion calculation. The results of this restatement, which had no impact on our total cash flow from operations, investing and financing activities as reported, impacted the retained earnings and the total stockholder’s equity as of March 31, 2011. Previously, retained earnings and total stockholder’s equity were reported as $183.3 million and $968.3 million, respectively, in the Form 10-Q for the quarter ended March 31, 2011. These balances have been restated to $193.8 million and $978.8 million, respectively, within the Condensed Consolidated Statement of Equity as of March 31, 2011.

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.

In June 2011, the FASB issued an amendment to accounting guidance to update the presentation of comprehensive income in consolidated financial statements. Under the amended guidance, the presentation of total comprehensive income, the components of net income, and the components of other comprehensive income may be made either in a single continuous statement of comprehensive income or in two separate but consecutive statements. This guidance became effective for us beginning with the quarter ended March 31, 2012, and requires retrospective application to earlier periods presented. Our condensed consolidated statements of income and comprehensive income for the three months ended March 31, 2012 and 2011 contain the required disclosure. The implementation of this accounting pronouncement resulted in increased disclosure in Note 12.

value hierarchy of items that are not measured at fair value in the statement of financial position but whose fair value must be disclosed. It also clarifies and expands upon existing requirements for measurement of the fair value of financial assets and liabilities as well as instruments classified in shareholders’ equity. This guidance became effective for us beginning with the quarter ended March 31, 2012. The adoption of this accounting pronouncement did not have an effect on the fair value measurement, but rather expanded upon existing disclosures.

In December 2011, the FASB issued an amendment to the accounting guidance for disclosure of arrangements that permit offsetting assets and liabilities. The amendment expands the disclosure requirements to require both gross information and net information about both instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to a master netting arrangement. The amendment is effective for fiscal years, and interim periods within those years, beginning on or after January 1, 2013, and shall be applied retrospectively. We do not expect the adoption of this accounting pronouncement to have a material impact on our financial statements when implemented.

No other pronouncements materially affecting our financial statements have been issued since the filing of our 2011 Annual Report on Form 10-K.

2. CRESTWOOD EARN-OUT

In October 2010, we completed the sale of all of our interests in KGS to Crestwood. As part of the sale, we have the right to collect future earn-out payments through 2013. In February 2012, we collected $41 million of these earn-out payments which is presented as Crestwood earn-out in the condensed consolidated statement of income for the quarter ended March 31, 2012. We have the right to collect up to an additional $31 million in future earn-out payments in 2013, although we have recognized no assets related to these opportunities.

Note 3 to the consolidated financial statements in our 2011 Annual Report on Form 10-K contains additional information regarding the Crestwood Transaction.

3. DERIVATIVES AND FAIR VALUE MEASUREMENTS

The following table categorizes our commodity derivative instruments based upon the use of input levels:


	Asset Derivatives				Liability Derivatives
	March 31, 2012		December 31, 2011		March 31, 2012		December 31, 2011
	(in thousands)				(in thousands)
Level 2 inputs	$	348,880	$	195,838	$	-	$	4,028
Level 3 inputs		48,985		150,989		24,398		-

Total	$	397,865	$	346,827	$	24,398	$	4,028

The fair value of “Level 2” derivative instruments included in these disclosures was estimated using prices quoted in active market for the periods covered by the derivatives and the value reported by counterparties. The fair value of derivative instruments designated “Level 3” was estimated using prices quoted in markets where there is insufficient market activity for consideration as “Level 2” instruments. Currently, only our natural gas hedges with an original tenure of 10 years utilize “Level 3” inputs, primarily due to comparatively less market data available for the later portion of their term compared with our other shorter term hedges. The fair value of both the “Level 2” and the “Level 3” assets and liabilities are determined using discounted cash flow model based on the terms of the derivative instrument, market prices for the periods covered by the derivatives, and the risk-free interest rates. The “Level 3” unobservable inputs are the market prices for the latter half of the 10-year term as there is not an active market for that period of time. These unobservable inputs included within the fair value calculation range from $3.66 to $5.94 and are calculated using prices quoted in active markets for the period of time available and applying the differential from this period of time to the markets prices for the later years in the term. Changes in the “Level 3” inputs are correlated to the changes in the quoted market prices for the period of time available. 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 the risk free rate.

The following table identifies the changes in “Level 3” net asset derivative fair values for the periods indicated:


	2012		2011
	(In thousands)
Balance at beginning of period	$	150,989	$	-
Total gains (losses) for the period:
Unrealized loss on commodity hedges		(21,670)		-
Realized loss on hedge restructure		(14,555)		-
Loss from hedge ineffectiveness		(610)		-
Transfers		(109,685)		-
Settlements		(6,574)		-
Included in OCI		26,962		-

Balance at end of period	$	24,587	$	-

Total losses for the period included in other revenue attributable to the change in unrealized losses related to assets held at the reporting date	$	(21,966)	$	-

Commodity Price Derivatives

As of March 31, 2012, we had price collars and swaps hedging our anticipated natural gas and NGL production as follows:


Production Year	Daily Production
Production Year	Gas	NGL
	MMcfd	MBbld
2012	230	7
2013	150	-
2014—2015	110	-
2016—2021	45	-

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.

During both the 2012 quarter and the 2011 quarter, we recognized $1.2 million of those deferred gains as a reduction of interest expense. The remaining $20.7 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)
Remainder of 2012	$	3,868
2013		5,539
2014		6,012
2015		4,669
2016		569

	$	20,657

Fair Value Disclosures

The estimated fair value of our derivative instruments at March 31, 2012 and December 31, 2011 were as follows:


	Asset Derivatives				Liability Derivatives
	March 31, 2012		December 31, 2011		March 31, 2012		December 31, 2011
	(In thousands)				(In thousands)
Derivatives designated as hedges:
Commodity contracts reported in:
Current derivative assets	$	227,591	$	165,484	$	-	$	2,639
Noncurrent derivative assets		172,715		183,982		2,441		-
Current derivative liabilities		-		-		-		4,028
Noncurrent derivative liabilities		-		-		24,398		-

Total derivatives designated as hedges	$	400,306	$	349,466	$	26,839	$	6,667

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

Total derivatives	$	400,306	$	349,466	$	26,839	$	6,667

The increase in carrying value of our commodity price derivatives since December 31, 2011 principally resulted from the overall decrease in market prices for natural gas relative to the prices in our open derivative instruments as well as additional derivative instruments entered into during the three months ended March 31, 2012.

The changes in the carrying value of our derivatives for the three months ended March 31, 2012 and 2011 are presented below:


	For the Three Months Ended March 31,
	2012		2011
	Cash Flow Derivatives		Cash Flow Derivatives
	(In thousands)
Derivative fair value at beginning of period	$	342,799	$	146,762
Change in amounts receivable/payable-net		(4,443)		(218)
Net settlements reported in revenue		(48,884)		(23,782)
Ineffectiveness reported in other revenue		(3,201)		(53)
Realized losses reported in other revenue		(14,555)		-
Unrealized losses reported in other revenue		(21,670)		-
Unrealized gains (losses) reported in OCI		123,421		(26,506)

Derivative fair value at end of period	$	373,467	$	96,203

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 $142.6 million net of income taxes. Hedge derivative ineffectiveness resulted in net losses of $3.2 million and $0.1 million for the three months ended March 31, 2012 and 2011, respectively. In January and February 2012, we terminated a number of our ten-year derivative instruments in exchange for derivative instruments with shorter durations at above market terms. The decrease in the fair value between the terminated ten-year instrument and the new shorter-term instrument was recognized in the current period as a realized loss. Unrealized losses recognized in 2012 is the difference between the estimated fair value at the inception date and transaction cost for ten-year derivative instruments entered into during the period.

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. During the fourth quarter of 2011, we sold all of our remaining BBEP Units.

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 accounted 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
	(In thousands)
Revenue ⁽¹⁾	$	18,165
Operating expense		79,483

Operating loss		(61,318)
Interest and other ⁽²⁾		9,989
Income tax benefit		(439)
Noncontrolling interests		35

Net loss available to BBEP	$	(70,903)

⁽¹⁾

For the three months ended December 31, 2010, unrealized losses of $82.3 million on commodity derivatives were recognized.

⁽²⁾

The three months ended December 31, 2010 unrealized gains of $3.1 million from interest rate swaps.

5. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment consisted of the following:


	March 31, 2012		December 31, 2011
	(In thousands)
Oil and gas properties
Subject to depletion	$	5,420,217	$	5,309,330
Unevaluated costs		477,434		433,341
Accumulated depletion		(2,638,676)		(2,516,195)

Net oil and gas properties		3,258,975		3,226,476
Other plant and equipment
Pipelines and processing facilities		348,451		340,242
General properties		74,820		71,297
Accumulated depreciation		(182,568)		(177,496)

Net other property and equipment		240,703		234,043

Property, plant and equipment, net of accumulated depletion and depreciation	$	3,499,678	$	3,460,519

Ceiling Test Analysis

We recorded impairment expense of $62.3 million and $0.4 million for our U.S. and Canadian oil and gas properties, respectively, at March 31, 2012. For our U.S. oil and gas properties, we computed the March 31, 2012 ceiling amount using a Henry Hub price of $3.73 MMBtu of natural gas, calculated as the unweighted average of the preceding 12-month first-day-of-the-month prices. The Henry Hub natural gas price used to compute the ceiling amount at March 31, 2012 was 9.5% lower than the comparable price used at December 31, 2011. For our Canadian oil and gas properties, we computed the March 31, 2012 ceiling amount using an AECO price of $3.64 MMBtu 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, 2012 was 1% lower than the comparable price used at December 31, 2011.

As of March 31, 2012, our U.S. and Canadian ceiling tests included $252 million and $103 million, respectively, in value for our derivatives treated as hedges. Absent this recognition, after tax we would have recognized $164 million of additional impairment expense for our U.S. oil and gas properties and $78 million for our Canadian oil and gas properties. Because of the volatility of oil and natural gas prices and prevailing prices subsequent to March 31, 2012, it is reasonably possible we may experience additional impairment in future periods.

Notes 2 and 8 to the consolidated financial statements in our 2011 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, 2012		December 31, 2011
	(In thousands)
Combined Credit Agreements	$	337,200	$	227,482
Senior notes due 2015, net of unamortized discount		435,228		435,020
Senior notes due 2016, net of unamortized discount		577,660		576,977
Senior notes due 2019, net of unamortized discount		292,192		292,055
Senior subordinated notes due 2016		350,000		350,000
Convertible debentures, net of unamortized discount		-		18

Total debt		1,992,280		1,881,552
Unamortized deferred gain—terminated interest rate swaps		20,656		21,897
Current portion of long-term debt		-		(18)

Long-term debt	$	2,012,936	$	1,903,431

Credit Facilities

The Combined Credit Agreements’ global borrowing base remained at $1.075 billion and the global letter of credit capacity was $175 million. At March 31, 2012, we had $679 million available under the facility.

Summary of All Outstanding Debt

As of March 31, 2012, the following subsidiaries are guarantors under our indentures for our senior notes and senior subordinated notes: Cowtown Pipeline Management, Inc., Cowtown Pipeline Funding, Inc., Cowtown Gas Processing L.P., Cowtown Pipeline L.P.,

Silver Stream Pipeline Company LLC and Barnett Shale Operating LLC. The following table summarizes other significant aspects of our long-term debt outstanding at March 31, 2012:


	*Priority on Collateral and Structural Seniority ⁽¹⁾*
	Highest priority				Lowest priority
	Equal priority	Equal Priority
	Combined Credit Agreements	2015 Senior Notes	2016 Senior Notes	2019 Senior Notes	Senior Subordinated Notes
Principal amount	$1.075 billion ⁽²⁾	$438 million	$591 million	$298 million	$350 million
Scheduled maturity date	September 6, 2016	August 1, 2015	January 1, 2016	August 15, 2019	April 1, 2016
Interest rate on outstanding borrowings at March 31, 2012⁽³⁾	2.25%	8.25%	11.75%	9.125%	7.125%
Base interest rate options	LIBOR, ABR, CDOR^{(4) (5)}	N/A	N/A	N/A	N/A
Financial covenants ⁽⁶⁾	- Minimum current ratio of 1.0 - Minimum EBITDA to cash interest expense ratio of 2.5	N/A	N/A	N/A	N/A
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	- Incurrence of debt - Incurrence of liens - Payment of dividends - Equity purchases - Asset sales - Affiliate transactions	- Incurrence of debt - Incurrence of liens - Payment of dividends - Equity purchases - Asset sales - Affiliate transactions	- Incurrence of debt - Incurrence of liens - Payment of dividends - Equity purchases - Asset sales - Affiliate transactions
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, 2012: 102.375 2013: 101.188 2014: par
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	N/A
Change of control ⁽⁶⁾	Event of default	Put at 101% of principal plus accrued interest	Put at 101% of principal plus accrued interest	Put at 101% of principal plus accrued interest	Put at 101% of principal plus accrued interest
Equity clawback⁽⁶⁾	N/A	N/A	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
Estimated fair value ⁽⁷⁾	$337.2 million	$433.1 million	$623.1 million	$289.4 million	$322.0 million

⁽¹⁾

Borrowings under the Amended and Restated U.S. Credit Facility are guaranteed by certain of Quicksilver’s domestic subsidiaries and are secured by 100% of the equity interests of each of Cowtown Pipeline Management, Inc., Cowtown Pipeline Funding, Inc., Cowtown Gas Processing L.P., Cowtown Pipeline L.P., Barnett Shale Operating LLC, Silver Stream Pipeline Company LLC and Quicksilver Resources Partners Operating Ltd., and 65% of the equity interest of QRCI and certain oil and gas properties and related assets of Quicksilver. Borrowings under the Amended and Restated Canadian Credit Facility are guaranteed by Quicksilver and certain of its domestic subsidiaries and are secured by 65% of the equity interests of Quicksilver Resources Canada Inc. and its oil and gas properties and related assets, and certain oil and gas properties and related assets of Quicksilver. The other debt presented is based upon structural seniority and priority of payment.

⁽²⁾

The principal amount for the Combined Credit Agreements represents the global borrowing base as of March 31, 2012.

⁽³⁾

Represents the weighted average borrowing rate payable to lenders.

⁽⁴⁾

Amounts outstanding under the Amended and Restated U.S. Credit Facility bear interest, at our election, at (i) adjusted LIBOR (as defined in the credit agreement) plus an applicable margin between 1.50% to 2.50%, (ii) ABR (as defined in the credit agreement), which is the greatest of (a) the prime rate announced by JPMorgan, (b) the federal funds rate plus 0.50% and (c) adjusted LIBOR (as defined in the credit agreement) plus 1.0%, plus, in each case under scenario (ii), an applicable margin between 0.50% to 1.50%. We also pay a per annum fee on all letters of credit issued under the Amended and Restated U.S. Credit Facility equal to the applicable margin and a commitment fee on the unused availability under

the Amended and Restated U.S. Credit Facility of 0.375% to 0.50%, in each case, based on global borrowing base usage.

⁽⁵⁾

Amounts outstanding under the Amended and Restated Canadian Credit Facility bear interest, at our election, at (i) the CDOR Rate (as defined in the credit agreement) plus an applicable margin between 1.50% and 2.50%, (ii) the Canadian Prime Rate (as defined in the credit agreement) plus an applicable margin between 0.50% and 1.50%, (iii) the U.S. Prime Rate (as defined in the credit agreement) plus an applicable margin between 0.50% and 1.50% and (iv) eurodollar loans (as defined in the credit agreement) plus an applicable margin between 1.50% to 2.50%. We pay a per annum fee on all letters of credit issued under the Amended and Restated Canadian Credit Facility equal to the applicable margin and a commitment fee on the unused availability under the Amended and Restated Canadian Credit Facility of 0.375% to 0.50%, in each case, based on global borrowing base usage.

⁽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 using market quotations based on recent trade activity for fixed rate obligations (“Level 2” inputs). We consider debt with variable interest rates to have a fair value equal to its carrying value (“Level 1” input).

Note 11 to the consolidated financial statements in our 2011 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, 2012.


(In thousands)
Beginning asset retirement obligations	$	85,822
Additional liability incurred		1,338
Change in estimates		4,665
Accretion expense		944
Asset retirement costs incurred		(195)
Settlement of liability		701
Currency translation adjustment		924

Ending asset retirement obligations		94,199
Less current portion		(254)

Long-term asset retirement obligation	$	93,945

8. COMMITMENTS AND CONTINGENCIES

Contractual Obligations, Commitments and Contingencies

On July 26, 2011, we received a subpoena duces tecum from the SEC requesting certain documents. The SEC has informed us that their investigation arises out of press releases in 2011 questioning the projected decline curves and economics of shale gas wells.

There have been no significant changes to our contractual obligations and commitments as reported in our 2011 Annual Report on Form 10-K which contains a more complete description of our contractual obligations, commitments and contingencies.

9. FORTUNE CREEK

The partnership established an area of mutual interest for the midstream business covering approximately 30 million potential acres which includes transportation and processing infrastructure and agreements.

In connection with the partnership formation, we contributed an existing 20-mile, 20-inch gathering line, its related compression facilities, we committed to minimum annual capital expenditures of $100 million for drilling and completion activities in our Horn River Asset for 2012, 2013 and 2014, and we dedicated for ten years beginning 2012 gas production from our Horn River Asset, as more fully described below. KKR contributed $125 million cash in exchange for a 50% interest in the partnership. Our Canadian subsidiary has responsibility for the day-to-day operations of Fortune Creek.

Our Canadian subsidiary entered into a firm gathering agreement with Fortune Creek which is guaranteed by us. At our election, KKR has the responsibility to fund all of the capital contributions associated with the development of the new gas treatment facility in exchange for preferential cash flow distributions. If our subsidiary does not meet its obligations under the gathering agreement, KKR has the right to liquidate the partnership and consequently we have recorded the funds contributed by KKR as a liability in our consolidated financial statements. We recognize accretion expense to reflect the rate of return earned by KKR via its investment.

Based on an analysis of the entities equity at risk, we have determined the partnership to be a VIE. Further, based on our ability to direct the activities surrounding the production of natural gas and our direct management of the operations of the facilities, we have determined we are the primary beneficiary and therefore, we consolidate Fortune Creek.

Note 12 contains financial information for Fortune Creek in our condensed consolidating financial statements.

10. 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, 2012 and December 31, 2011, we had 173.3 million and 171.6 million shares of common stock outstanding, respectively.

Note 17 to the consolidated financial statements in our 2011 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 2012 with an estimated fair value of $8.4 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, 2012:


		2012
Wtd avg grant date fair value		$4.25
Wtd avg grant date		Jan 3, 2012
Wtd avg risk-free interest rate		1.15%
Expected life (in years)		6.0
Wtd avg volatility		68.2%
Expected dividends		-

The following table summarizes our stock option activity for the three months ended March 31, 2012:


	Shares		Wtd Avg Exercise Price		Wtd Avg Remaining Contractual Life		Aggregate Intrinsic Value
					(In years)		(In thousands)
Outstanding at January 1, 2012		3,760,696	$	12.01
Granted		1,980,705		6.96
Exercised		(1,572)		6.21
Cancelled		(206,692)		8.00

Outstanding at March 31, 2012		5,533,137	$	10.36		7.9	$	-

Exercisable at March 31, 2012		2,978,210	$	11.18		6.7	$	-

As of March 31, 2012 we estimate that a total of 5.5 million stock options will become vested including those options already exercisable. Compensation expense related to stock options of $1.9 million was recognized for each of the three months ended March 31, 2012 and 2011. Cash received from the exercise of stock options totaled less than $0.1 million for the three months ended March 31, 2012. The total intrinsic value of those options exercised was less than $0.1 million.

Restricted Stock

The following table summarizes our restricted stock and stock unit activity for the three months ended March 31, 2012:


	Payable in shares				Payable in cash
	Shares		Wtd Avg Grant Date Fair Value		Shares		Wtd Avg Grant Date Fair Value
Outstanding at January 1, 2012		2,460,300	$	12.29		369,846	$	13.12
Granted		2,461,675		6.93		486,583		6.80
Vested		(1,241,128)		10.72		(186,026)		11.22
Cancelled		(431,918)		8.82		(101,827)		9.63

Outstanding at March 31, 2012		3,248,929	$	9.29		568,576	$	8.95

As of December 31, 2011, the unrecognized compensation cost related to outstanding unvested restricted stock was $17.3 million, which is expected to be recognized in expense through March 2014. Grants of restricted stock and RSUs during the three months ended March 31, 2012 had an estimated grant date fair value of $20.4 million. The fair value of RSUs settled in cash was $2.9 million at March 31, 2012. For the three months ended March 31, 2012 and 2011, compensation expense of $4.0 million and $3.6 million, respectively, was recognized. The total fair value of shares vested during the three months ended March 31, 2012 was $9.5 million.

11. 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,
	2012		2011
	(In thousands, except per share data)
Net loss attributable to Quicksilver	$	(59,924)	$	(70,758)
Basic income allocable to participating securities ⁽¹⁾		-		-

Loss available to stockholders	$	(59,924)	$	(70,758)

Weighted average common shares – basic		169,939		168,872
Effect of dilutive securities ⁽²⁾		-		-

Weighted average common shares – diluted		169,939		168,872

Loss per common share – basic	$	(0.35)	$	(0.42)
Loss per common share – diluted	$	(0.35)	$	(0.42)

⁽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, 2012, we had the following antidilutive shares excluded from the dilution calculation: 5.5 million shares associated with our stock options and 0.3 million shares associated with our unvested restricted stock units. For the three months ended March 31, 2011, we had the following antidilutive shares excluded from the dilution calculation: 9.8 million shares associated with our contingently convertible debt, 2.8 million shares associated with our stock options and 1.3 million shares associated with our unvested restricted stock units.

12. CONDENSED CONSOLIDATING FINANCIAL INFORMATION

Note 19 to the consolidated financial statements in our 2011 Annual Report on Form 10-K contains a more complete description of our guarantor, non-guarantor, restricted and 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. Under the indentures for our senior notes and senior subordinated notes, Fortune Creek is not considered to be a subsidiary and therefore it is presented separately from the other subsidiaries for these purposes.

Condensed Consolidating Balance Sheets


	March 31, 2012
	Quicksilver Resources Inc.		Restricted Guarantor Subsidiaries		Restricted Non-Guarantor Subsidiaries		Restricted Subsidiary Eliminations		Quicksilver and Restricted Subsidiaries		Unrestricted Non-Guarantor Subsidiaries		Fortune Creek		Consolidating Eliminations		Quicksilver Resources Inc. Consolidated



	(In thousands)
ASSETS
Current assets	$	359,221	$	88,564	$	77,076	$	(203,441)	$	321,420	$	1,438	$	13,973	$	(3,732)	$	333,099
Property and equipment		2,718,125		37,973		656,761		-		3,412,859		-		86,819		-		3,499,678
Investment in subsidiaries (equity method)		254,829		-		(33,648)		(254,829)		(33,648)		(33,648)		-		67,296		-
Other assets		403,744		-		61,830		(243,620)		221,954		-		-		-		221,954

Total assets	$	3,735,919	$	126,537	$	762,019	$	(701,890)	$	3,922,585	$	(32,210)	$	100,792	$	63,564	$	4,054,731


LIABILITIES AND EQUITY
Current liabilities	$	285,644	$	110,518	$	64,557	$	(203,441)	$	257,278	$	1,438	$	4,287	$	(3,732)	$	259,271
Long-term liabilities		2,177,798		21,936		436,716		(243,620)		2,392,830		-		82		130,071		2,522,983
Stockholders' equity		1,272,477		(5,917)		260,746		(254,829)		1,272,477		(33,648)		96,423		(62,775)		1,272,477

Total liabilities and equity	$	3,735,919	$	126,537	$	762,019	$	(701,890)	$	3,922,585	$	(32,210)	$	100,792	$	63,564	$	4,054,731


	December 31, 2011
	Quicksilver Resources Inc.		Restricted Guarantor Subsidiaries		Restricted Non-Guarantor Subsidiaries		Restricted Subsidiary Eliminations		Quicksilver and Restricted Subsidiaries		Unrestricted Non-Guarantor Subsidiaries		Fortune Creek		Consolidating Eliminations		Quicksilver Resources Inc. Consolidated



	(In thousands)
ASSETS
Current assets	$	336,893	$	87,767	$	63,711	$	(200,727)	$	287,644	$	-	$	27,533	$	(14,750)	$	300,427
Property and equipment		2,743,379		37,936		598,443		-		3,379,758		-		80,761		-		3,460,519
Investment in subsidiaries (equity method)		241,680		-		(29,449)		(241,680)		(29,449)		(29,449)		-		58,898		-
Other assets		401,279		-		76,857		(243,620)		234,516		-		-		-		234,516

Total assets	$	3,723,231	$	125,703	$	709,562	$	(686,027)	$	3,872,469	$	(29,449)	$	108,294	$	44,148	$	3,995,462


LIABILITIES AND EQUITY
Current liabilities	$	348,512	$	109,938	$	76,450	$	(200,727)	$	334,173	$	-	$	14,750	$	(14,750)	$	334,173
Long-term liabilities		2,112,800		21,903		385,294		(243,620)		2,276,377		-		80		122,913		2,399,370
Stockholders' equity		1,261,919		(6,138)		247,818		(241,680)		1,261,919		(29,449)		93,464		(64,015)		1,261,919

Total liabilities and equity	$	3,723,231	$	125,703	$	709,562	$	(686,027)	$	3,872,469	$	(29,449)	$	108,294	$	44,148	$	3,995,462

Condensed Consolidating Statements of Income


	For the Three Months Ended March 31, 2012
	Quicksilver Resources Inc.		Restricted Guarantor Subsidiaries		Restricted Non-Guarantor Subsidiaries		Restricted Subsidiary Eliminations		Quicksilver and Restricted Subsidiaries		Unrestricted Non-Guarantor Subsidiaries		Fortune Creek		Consolidated Eliminations		Quicksilver Resources Inc. Consolidated


	(In thousands)
Revenue	$	131,462	$	1,130	$	13,780	$	(903)	$	145,469	$	-	$	2,397	$	(2,397)	$	145,469
Operating expenses		199,915		909		27,975		(903)		227,896		-		1,267		(2,397)		226,766
Crestwood earn-out		41,097		-		-		-		41,097		-		-		-		41,097
Equity in net earnings of subsidiaries		(15,333)		-		(3,611)		15,333		(3,611)		1,130		-		2,481		-

Operating income		(42,689)		221		(17,806)		15,333		(44,941)		1,130		1,130		7,222		(40,200)
Fortune Creek Accretion		-		-		-		-		-		-		-		(4,741)		(4,741)
Interest expense and other		(38,643)		-		(1,434)		-		(40,077)		-		-		-		(40,077)
Income tax (expense) benefit		21,408		(77)		3,763		-		25,094		-		-		-		25,094

Net income	$	(59,924)	$	144	$	(15,477)	$	15,333	$	(59,924)	$	1,130	$	1,130	$	(2,260)	$	(59,924)
Other comprehensive income		38,807		-		28,376		(28,376)		38,807		-		-		-		38,807
Equity in OCI of subsidiaries		28,376		-		-		-		28,376		-		-		-		28,376

Comprehensive income (loss)	$	7,259	$	144	$	12,899	$	(13,043)	$	7,259	$	1,130	$	1,130	$	(2,260)	$	7,259


	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 income	$	(70,758)	$	(491)	$	(33,317)	$	33,808	$	(70,758)
Other comprehensive income		(28,245)		-		6,835		(6,835)		28,245
Equity in OCI of subsidiaries		6,835		-		-		-		6,835

Comprehensive income (loss)	$	(92,168)	$	(491)	$	(26,482)	$	26,973	$	(92,168)

Condensed Consolidating Statements of Cash Flows


	For the Three Months Ended March 31, 2012
	Quicksilver Resources Inc.		Restricted Guarantor Subsidiaries		Restricted Non-Guarantor Subsidiaries		Quicksilver and Restricted Subsidiaries		Fortune Creek		Quicksilver Resources Inc. Consolidated
	(In thousands)
Net cash flow provided (used) by operating activities	$	(3,195)	$	438	$	27,099	$	24,342	$	3,028	$	27,370
Purchases of property, plant and equipment		(95,994)		(438)		(77,304)		(173,736)		(1,186)		(174,922)
Proceeds from Crestwood earn-out		41,097		-		-		41,097		-		41,097
Proceeds from sale of properties and equipment		269		-		191		460		-		460

Net cash flow used by investing activities		(54,628)		(438)		(77,113)		(132,179)		(1,186)		(133,365)
Issuance of debt		100,000		-		61,658		161,658		-		161,658
Repayments of debt		(40,018)		-		(13,097)		(53,115)		-		(53,115)
Debt issuance costs		(191)		-		-		(191)		-		(191)
Proceeds from exercise of stock options		10		-		-		10		-		10
Purchase of treasury stock		(2,341)		-		-		(2,341)		-		(2,341)

Net cash flow provided (used) by financing activities		57,460		-		48,561		106,021		-		106,021
Effect of exchange rates on cash		-		-		1,453		1,453		(1,593)		(140)

Net increase (decrease) in cash and equivalents		(363)		-		-		(363)		249		(114)
Cash and equivalents at beginning of period		363		-		-		363		12,783		13,146

Cash and equivalents at end of period	$	-	$	-	$	-	$	-	$	13,032	$	13,032


	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 operating activities	$	(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

13. 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. Additionally, we operate a significantly smaller midstream segment in the U.S. and Canada, where we provide natural gas gathering and processing services. Following our announced partnership with KKR, beginning in January 2012, we have additional midstream operations in Canada through Fortune Creek. Based on the immateriality of our midstream segment, we have combined U.S. and Canadian information. We evaluate performance based on operating income and property and equipment costs incurred.


	Exploration & Production										Quicksilver Consolidated
	U.S.		Canada		Midstream		Corporate		Elimination		Quicksilver Consolidated
For the Three Months Ended March 31:		(In thousands)
2012
Revenue	$	131,462	$	13,780	$	3,527	$	-		$ (3,300)	$	145,469
DD&A		41,823		10,815		1,201		600		-		54,439
Impairment expense		62,342		404		-		-		-		62,746
Operating income (loss)		(8,742)		(13,115)		1,352		(19,695)		-		(40,200)
Property and equipment costs incurred		72,431		53,623		5,980		3,533		-		135,567
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

Property, plant and equipment - net
March 31, 2012		2,726,751		655,223		108,333		9,371		-		3,499,678
December 31, 2011		2,752,101		596,935		102,237		9,246		-		3,460,519

14. SUPPLEMENTAL CASH FLOW INFORMATION

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


	For the Three Months Ended
	March 31,
	2012			2011
	(In thousands)
Interest	$	66,020		$	70,490
Income taxes		(2,839	)		(57	)

Other significant non-cash transactions were as follows:


	For the Three Months Ended March 31,
	2012		2011
	(In thousands)
Working capital related to capital expenditures	$	69,983	$	98,973

15. TRANSACTIONS WITH RELATED PARTIES

As of March 31, 2012, members of the Darden family and entities controlled by them beneficially own approximately 30% of our outstanding common stock. Thomas Darden, Glenn Darden and Anne Darden Self are officers and directors of Quicksilver.

During the first three months of 2012 and 2011, we paid $0.1 million and $0.2 million, respectively, for use of an airplane owned by an entity controlled by members of the Darden family. Usage rates were determined based upon comparable rates charged by third parties.

Payments received from Mercury for sublease rentals, employee insurance coverage and administrative services were negligible for the first three months of 2012 and 2011.

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 as well as our 2011 Annual Report on Form 10-K. We conduct our operations in two segments: (1) our more dominant exploration and production segment, and (2) our significantly smaller midstream 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:

•

2012 Highlights — a summary of significant activities and events affecting Quicksilver

•

2012 Capital Program — a summary of our planned capital expenditures during 2012

•

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

2012 HIGHLIGHTS

Master Limited Partnership

On February 10, 2012, we filed a Form S-1 with the SEC to begin the registration and sale of limited partnership interests in a master limited partnership holding certain of our mature properties in our Barnett Shale Asset. We expect to amend the registration statement in late May to include financial statements for 2011 and to address comments received from the SEC. We expect this registration statement to become effective in the second or third quarter of 2012.

Emerging Basins

We deployed a rig in March 2012 to commence drilling operations on our West Texas Asset. Our plan for 2012 is to drill and complete up to five wells. We hold a position of approximately 155,000 net acres in the Delaware and Midland basins, at least 2/3 of which we believe is prospective for oil, including from the Wolfcamp and Bone Springs formations. In the first quarter of 2012, we retained an investment bank to help evaluate the opportunities for a joint venture partner to acquire an interest in and participate in the development of our West Texas acreage.

We set surface pipe on one well during the first quarter in our Sand Wash Asset, however wildlife stipulations prevent us from finishing the drilling process until September 2012. We expect to begin drilling operations on additional wells in May 2012. We plan to drill a mix of four to seven vertical and horizontal wells in 2012. We hold approximately 260,000 net acres in the Sand Wash Basin, at least 200,000 of which are prospective of oil. At December 31, 2011, we had recognized no proved oil reserves in our Sand Wash Asset.

Crestwood Earn-Out

In October 2010, we completed the sale of all of our interests in KGS to Crestwood. As part of the sale, we have the right to collect future earn-out payments through 2013. In February 2012, we collected $41 million of these earn-out payments, which is presented as Crestwood earn-out in the condensed consolidated statement of income for the quarter ended March 31, 2012. We have the right to collect up to an additional $31 million in future earn-out payments in 2013, although we have recognized no assets related to these opportunities.

2012 CAPITAL PROGRAM

We had capital expenditures of $174.9 million for the first three months of 2012. We expect our capital spending for the remainder of 2012 to be in line with the 2012 capital program as presented in the 2011 Annual Report on Form 10-K.

Average production for the second quarter of 2012 is expected to be flat with first quarter 2012.

RESULTS OF OPERATIONS

The following discussion compares the results of operations for the three months ended March 31, 2012 and 2011, or the 2012 quarter and 2011 quarter, respectively. “Other U.S.” refers to the combined amounts for our Sand Wash Asset and Bakken Asset.

Revenue

Natural Gas, NGL and Oil

Production Revenue:


	Natural Gas				NGL				Oil				Total
	2012		2011		2012		2011		2012		2011		2012		2011
	(In millions)
Barnett Shale	$	55.2	$	89.4	$	44.6	$	46.4	$	3.3	$	2.7	$	103.1	$	138.5
Other U.S.		0.2		0.3		0.1		0.2		4.0		2.9		4.3		3.4
Hedging		39.6		23.9		0.3		(7.2)		-		-		39.9		16.7

Total U.S.		95.0		113.6		45.0		39.4		7.3		5.6		147.3		158.6
Horseshoe Canyon		13.4		20.9		0.1		-		-		-		13.5		20.9
Horn River		2.1		3.5		-		-		-		-		2.1		3.5
Hedging		8.9		7.3		-		-		-		-		8.9		7.3

Total Canada		24.4		31.7		0.1		-		-		-		24.5		31.7

Total	$	119.4	$	145.3	$	45.1	$	39.4	$	7.3	$	5.6	$	171.8	$	190.3

Average Daily Production Volume:


	Natural Gas				NGL				Oil				Equivalent Total
	2012		2011		2012		2011		2012		2011		2012		2011
	(MMcfd)				(Bbld)				(Bbld)				(MMcfed)
Barnett Shale		232.8		247.4		11,508		11,531		359		335		304.0		318.6
Other U.S.		0.8		0.8		10		23		486		381		3.8		3.2

Total U.S.		233.6		248.2		11,518		11,554		845		716		307.8		321.8
Horseshoe Canyon		57.9		59.4		13		6		-		-		57.9		59.4
Horn River		11.3		11.1		-		-		-		-		11.3		11.1

Total Canada		69.2		70.5		13		6		-		-		69.2		70.5

Total		302.8		318.7		11,531		11,560		845		716		377.0		392.3

Average Realized Price:


	Natural Gas				NGL				Oil				Equivalent Total
	2012		2011		2012		2011		2012		2011		2012		2011
	(per Mcf)				(per Bbl)				(per Bbl)				(per Mcfe)
Barnett Shale	$	2.60	$	4.02	$	42.62	$	44.68	$	98.59	$	90.72	$	3.72	$	4.83
Other U.S.		2.38		4.43		53.50		77.55		91.65		83.80		12.35		11.51
Hedging		1.86		1.07		0.31		(6.93)		-		-		1.43		0.58
Total U.S.	$	4.47	$	5.09	$	42.95	$	37.82	$	94.61	$	87.05	$	5.26	$	5.48
Horseshoe Canyon	$	2.55	$	3.90	$	68.43	$	73.64	$	-	$	-	$	2.56	$	3.91
Horn River		2.07		3.53		-		-		-		-		2.07		3.53
Hedging		1.42		1.15		-		-		-		-		1.42		1.15
Total Canada	$	3.89	$	4.99	$	68.07	$	73.64	$	-	$	-	$	3.90	$	4.99
Total	$	4.34	$	5.07	$	42.98	$	37.84	$	94.61	$	87.05	$	5.01	$	5.39

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


	Natural Gas
	Natural Gas		NGL		Oil		Total
	(In thousands)
Revenue for the 2011 quarter	$	145,325	$	39,372	$	5,604	$	190,301
Volume variances		(4,511)		397		1,094		(3,020)
Hedge revenue variances		17,358		7,526		-		24,884
Price variances		(38,731)		(2,195)		581		(40,345)

Revenue for the 2012 quarter	$	119,441	$	45,100	$	7,279	$	171,820

Natural gas revenue for the 2012 quarter decreased from the 2011 quarter despite the increase in hedge revenue. Realized prices, without hedge gains, were 35% lower for the 2012 quarter as compared to the 2011 quarter. The 5% decrease in natural gas volume from our Barnett Shale Asset was primarily due to production decline resulting from the aging of existing wells and our capital spending pattern.

NGL revenue for the 2012 quarter was higher than the 2011 quarter as a result of hedge losses recognized in the 2011 quarter of $7.2 million.

Utilization of derivatives to hedge our sales of natural gas and NGL may result in realized prices varying from market prices that we receive from the sale of our production. Our production revenue for the 2012 quarter and 2011 quarter was higher by $48.8 million and $24.0 million, respectively, because of our hedging activities.

We are engaged in the process of reviewing the economic impact of continuing to produce from certain of our wells in the current price environment. As a result, we may shut-in wells. However, we believe these shut-ins would result in increases to operating income and operating cash flows, and have only an immaterial impact on our production volumes.

Sales of Purchased Natural Gas and Costs of Purchased Natural Gas


	Three Months Ended March 31,
	2012		2011
	(In thousands)
Sales of purchased natural gas:
Purchases from Eni	$	11,145	$	13,917
Purchases from others		941		6,509

Total		12,086		20,426
Costs of purchased natural gas sold:
Purchases from Eni		11,183		13,794
Purchases from others		754		5,949

Total		11,937		19,743

Net sales and purchases of natural gas	$	149	$	683

Other Revenue


	Three Months Ended March 31,
	2012		2011
	(In thousands)
Midstream revenue:
Canada	$	731	$	844
Other Texas		227		275

Total midstream revenue		958		1,119
Loss from hedge ineffectiveness		(3,201)		(53)
Realized loss from hedge restructure		(14,555)		-
Unrealized loss on commodity derivatives		(21,670)		-
Other		31		394

Total	$	(38,437)	$	1,460

Other revenue for the three months ended March 31, 2012 decreased from the 2011 quarter due to the recognition of realized losses in 2012 from our restructuring of our hedge platform. In January and February 2012, we terminated a number of our ten-year derivative instruments in exchange for derivative instruments with shorter durations at above market terms. The decrease in the fair value between the terminated ten-year instrument and the new shorter-term instrument was recognized in the current period as a realized loss. Losses from hedge ineffectiveness were $3.2 million for the 2012 quarter as compared to less than $0.1 million for the 2011 quarter as our derivative instruments are based on NYMEX pricing and our production is sold at market prices other than NYMEX. At March 31, 2012, we do not have any basis swaps to offset the price differential. Unrealized losses recognized in 2012 is the difference between the estimated fair value at the inception date and transaction cost for ten-year derivative instruments entered into during the period.

Operating Expense

Lease Operating


	Three Months Ended March 31,
	2012				2011
	(In thousands, except per unit amounts)
			Per				Per
			Mcfe				Mcfe
Barnett Shale
Cash expense	$	17,233	$	0.62	$	11,106	$	0.39
Equity compensation		415		0.02		269		0.01

	$	17,648	$	0.64	$	11,375	$	0.40
Other U.S.
Cash expense	$	2,159	$	6.14	$	1,246	$	4.27
Equity compensation		48		0.14		55		0.19

	$	2,207	$	6.28	$	1,301	$	4.46
Total U.S.
Cash expense	$	19,392	$	0.69	$	12,352	$	0.43
Equity compensation		463		0.02		324		0.01

	$	19,855	$	0.71	$	12,676	$	0.44
Horseshoe Canyon
Cash expense	$	7,756	$	1.47	$	7,739	$	1.45
Equity compensation		126		0.01		164		0.03

	$	7,882	$	1.48	$	7,903	$	1.48
Horn River
Cash expense	$	954	$	0.93	$	978	$	0.98
Equity compensation		-		-		-		-

	$	954	$	0.93	$	978	$	0.98
Total Canada
Cash expense	$	8,710	$	1.38	$	8,717	$	1.37
Equity compensation		126		0.02		164		0.03

	$	8,836	$	1.40	$	8,881	$	1.40
Total Company
Cash expense	$	28,102	$	0.82	$	21,069	$	0.60
Equity compensation		589		0.02		488		0.01

	$	28,691	$	0.84	$	21,557	$	0.61

The Barnett Shale Asset experienced higher gas lift costs, workover expense and saltwater disposal costs compared to prior year due to the aging of existing wells and costs to maintain production. Other U.S. lease operating costs were impacted on a gross and unit basis by increased production and costs for our Sand Wash Asset.

Lease operating expense for the 2012 quarter in Canada was flat compared to the 2011 quarter.

Gathering, Processing and Transportation


	Three Months Ended March 31,
	2012				2011
	(In thousands, except per unit amounts)
			Per Mcfe				Per Mcfe
Barnett Shale	$	38,638	$	1.40	$	40,377	$	1.41
Other U.S.		3		0.01		16		0.05

Total U.S.		38,641		1.38		40,393		1.39
Horseshoe Canyon		1,069		0.20		1,019		0.19
Horn River		3,367		3.30		2,602		2.61

Total Canada		4,436		0.70		3,621		0.57

Total	$	43,077	$	1.26	$	44,014	$	1.25

Canadian GPT increased for the 2012 quarter as compared to 2011 quarter both in total dollars and on a per Mcfe basis primarily as a result of fixed costs under our firm agreements with third parties. GPT per Mcfe was flat in the U.S.

Production and Ad Valorem Taxes


	Three Months Ended March 31,
	2012				2011
	(In thousands, except per unit amounts)
			Per Mcfe				Per Mcfe
Production taxes
U.S.	$	1,551	$	0.06	$	1,684	$	0.06
Canada		3		0.02		14		-

Total production taxes		1,554		0.05		1,698		0.04
Ad valorem taxes
U.S.	$	4,711		0.17	$	5,231		0.18
Canada		498		0.08		652		0.10

Total ad valorem taxes		5,209		0.15		5,883		0.17

Total	$	6,763	$	0.20	$	7,581	$	0.21

Depletion, Depreciation and Accretion


	Three Months Ended March 31,
	2012				2011
	(In thousands, except per unit amounts)
			Per Mcfe				Per Mcfe
Depletion
U.S.	$	39,990	$	1.43	$	37,145	$	1.28
Canada		8,955		1.42		9,855		1.55

Total depletion		48,945		1.43		47,000		1.33
Depreciation of other fixed assets:
U.S.	$	2,380	$	0.08	$	3,622	$	0.13
Canada		2,170		0.34		1,219		0.19

Total depreciation		4,550		0.13		4,841		0.14
Accretion		944		0.03		630		0.02

Total	$	54,439	$	1.59	$	52,471	$	1.49

U.S. depletion for the 2012 quarter reflected a 12% increase in the U.S. depletion rate partially offset by a 4% decrease in U.S. production when compared to the 2011 quarter. Canadian depletion decreased in 2012 due to a reduction in the carrying value of the Canadian oil and gas properties in the 2011 quarter. Following the impairment recognized in the 2012 quarter, we expect U.S. and Canadian depletion rates will be relatively unchanged.

U.S. depreciation for the 2012 quarter was lower than the 2011 quarter primarily because of reduced carrying value of our midstream assets following their impairment in late 2011. Canada depreciation was higher due to the increased capital spending on the Fortune Creek non-oil and gas properties in the second half of 2011.

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 2012 quarter, we recognized $62.3 million and $0.4 million in non-cash charges for impairment of our U.S. and Canadian oil and gas properties, respectively, as of March 31, 2012.

In performing our quarterly ceiling tests, we utilize first of month prices for the preceding 12 months. Due to the decrease in natural gas prices in the second quarter 2012 compared to the second quarter 2011, there is a significant likelihood of impairment of oil and gas properties. As of March 31, 2012, our U.S. and Canadian ceiling tests included $252 million and $103 million, respectively, in value for our derivatives treated as hedges. Absent this recognition, after tax we would have recognized $164 million of additional impairment expense for our U.S. oil and gas properties and $78 million for our Canadian oil and gas properties. If any of our derivatives we treat as hedges become ineligible for hedge treatment, it could significantly impact the amount of impairment that we recognize.

General and Administrative


	Three Months Ended March 31,
	2012				2011
	(In thousands, except per unit amounts)
			Per Mcfe				Per Mcfe
Cash expense	$	14,054	$	0.41	$	13,401	$	0.38
Equity compensation		5,041		0.15		4,990		0.14

Total	$	19,095	$	0.56	$	18,391	$	0.52

General and administrative expense for the 2012 quarter was greater than the 2011 quarter due to a separation payment of $0.8 million recorded as additional compensation expense in 2012.

Crestwood Earn-Out

In February 2012, we collected $41 million of earn-out payments from Crestwood, which is presented as Crestwood earn-out in the condensed consolidated statement of income for the quarter ended March 31, 2012.

Loss from Earnings of BBEP

We recorded our portion of BBEP’s earnings during the quarter in which its financial statements became publicly available. As a result, our 2011 quarter results of operations included BBEP’s earnings for the three months ended December 31, 2010. We sold the last of our BBEP Units in the fourth quarter of 2011.

We recognized losses of $20.9 million for equity earnings from our investment in BBEP for the 2011 quarter.

Other Income

Gains of $1.3 million were recognized in the 2011 quarter from the sale of BBEP Units.

Fortune Creek Accretion

In December 2011, we entered into an agreement to form a midstream partnership, Fortune Creek, dedicated to the construction and operation of midstream assets to support natural gas producers primarily in British Columbia. In connection with the partnership formation, KKR contributed $125 million cash in exchange for a 50% interest in the partnership and first priority on all cash flows generated. KKR contribution is shown as Partnership liability in the condensed consolidated balance sheet, and we recognize accretion expense to reflect the rate of return earned by KKR via its investment.

Interest Expense


	Three Months Ended March 31,
	2012		2011
		(In thousands)
Interest costs on debt outstanding	$	42,043	$	43,197
Fees paid on letters of credit outstanding		29		249
Add: Non-cash interest ⁽¹⁾		1,742		3,880
Less: Interest capitalized		(3,644)		(1,148)

Interest expense	$	40,170	$	46,178

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

Interest costs on debt outstanding for the 2012 quarter were lower when compared to the 2011 quarter primarily because of the lower amortization of deferred financing costs due to costs expensed in late 2011 related to the termination of the 2007 Senior Secured Credit Facility and the Initial U.S Credit Facility.

Income Taxes

The U.S. effective tax rate for the three months ended March 31, 2012 and 2011 are as follows:


	Three Months Ended
	2012			2011
	(In thousands)
Income tax (benefit) expense	$	(20,146	)	$	14,933
Effective tax rate		30.6	%		-66.3	%

The Canadian effective tax rate for the three months ended March 31, 2012 and 2011 are as follows:


	Three Months Ended
	2012			2011
	(In thousands)
Income tax (benefit) expense	$	(4,948	)	$	(10,909	)
Effective tax rate		25.7	%		24.7	%

The consolidated effective tax rate for the three months ended March 31, 2012 and 2011 are as follows:


	Three Months Ended March 31,
	2012			2011
	(In thousands)
Income tax (benefit) expense	$	(25,094	)	$	4,024
Effective tax rate		29.5	%		-6.0	%

The effective tax rate for the 2012 quarter reflects a projection of a full year of U.S. and Canadian taxable losses. We expect that the consolidated effective tax rate of 29.5% for the 2012 quarter will be our effective tax rate for all of 2012 based upon our projection of pretax income and estimated permanent differences for 2012.

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 balances related to Fortune Creek which were included in the consolidated financial position as of March 31, 2012. 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 2012 through 2021, 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, 2012.


Production	Daily Production Volume
Year	Gas	NGL
	MMcfd	MBbld
2012	230	7
2013	150	-
2014—2015	110	-
2016—2021	45	-

The following summarizes our cash flow activity for the 2012 quarter and 2011 quarter:


	Three Months Ended March 31,
	2012			2011
	(In thousands)
Net cash provided by operating activities	$	27,370		$	11,713
Net cash used by investing activities		(133,365	)		(194,337	)
Net cash provided by financing activities		106,021			128,409

Operating Cash Flows

Net cash provided by operations for the 2012 quarter increased from the 2011 quarter due to positive changes in working capital partially offset by lower realized prices (including hedging effects) and the receipt of BBEP distributions of $6.4 million in the 2011 quarter.

Investing Cash Flows

Costs incurred for property, plant and equipment for the 2012 quarter and 2011 quarter were as follows:


	United States		Canada		Consolidated
	(In thousands)
For the Three Months Ended March 31, 2012
Exploration and production	$	72,431	$	53,623	$	126,054
Midstream		447		5,533		5,980
Administrative		1,115		2,418		3,533

Total	$	73,993	$	61,574	$	135,567

For the Three Months Ended March 31, 2011
Exploration and production	$	116,246	$	40,315	$	156,561
Midstream		5,236		33,566		38,802
Administrative		1,174		123		1,297

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

Costs incurred reflect the true nature of the activity of the 2012 capital program, while capital expenditures per the condensed consolidated statement of cash flows also reflect the related changes in working capital. Our 2012 capital costs incurred have decreased for both U.S. and Canada as a result of our overall decrease in capital spend in 2012 compared to 2011. Our capital costs incurred for midstream operations during the 2011 quarter reflect the infrastructure to gather, compress and deliver our Horn River gas production to third-party processing facilities.

The 2012 capital expenditures were partially offset by the receipt of the $41.1 million earn-out payment received from Crestwood in February 2012.

Financing Cash Flows

Net financing cash flows in the 2012 quarter include net borrowings of $108.5 million under our Combined Credit Agreements. Net financing cash flows in the 2011 quarter included net borrowings of $132.8 million under our 2007 Senior Secured Credit facility.

Liquidity and Borrowing Capacity

At March 31, 2012, the Combined Credit Agreements global borrowing base remained at $1.075 billion and the global letter of credit capacity was $175 million. At March 31, 2012, there was $679 million available under the Combined Credit Agreements. We do not expect any change to the global borrowing base as a result of the semi-annual re-determination, which is expected to be completed in the latter half of May 2012.

Our ability to remain in compliance with the financial covenants in our Combined Credit Agreements 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.

If the rating agencies were to reduce our debt or credit ratings, our borrowing costs may increase, our potential pool of investors and funding resources may be reduced, and we may be required to post additional collateral under selected contracts. These events may have an adverse effect on our results of operations, financial condition and cash flows. In addition, any such reduction in our debt or credit ratings may adversely affect the trading price of our outstanding securities.

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 2012 capital program will be funded by cash flow from operations and utilization of our Combined Credit Agreements. We are also pursuing joint venture partners in our West Texas Asset and Horn River Asset.

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, utilization of our Combined Credit Agreements, the issuance of debt or other securities or a combination of those sources.

Financial Position

The following impacted our balance sheet as of March 31, 2012, as compared to our balance sheet as of December 31, 2011:

•

Our accounts receivable balance decreased $32.6 million from December 31, 2011 to March 31, 2012 primarily due to the collection of $14.8 million for a non-income tax matter in Canada and a decrease of $14.5 million in production receivables due to lower realized prices before hedges at March 31, 2012 compared to December 31, 2011.

•

Our net property, plant and equipment balance increased $39.2 million from December 31, 2011 to March 31, 2012. We incurred capital costs of $136 million during 2012 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 $13.4 million. Offsetting the increases was $116.2 million of DD&A and impairment expense.

•

The valuation of our current and non-current derivative assets and liabilities was $30.7 million higher on a net basis for March 31, 2012 as compared to December 31, 2011. The increase was the result of lower market natural gas prices and fair value attributable to derivative instruments entered into during 2012.

•

The $53.9 million decrease in accounts payable was primarily due to a reduction in accrued capital expenditures of $37.6 million from the December 31, 2011 amount and a decrease in trade payables of $17.5 million from December 31, 2011.

•

Long-term debt increased $108.5 million for net borrowings under the Combined Credit Agreements.

Contractual Obligations and Commercial Commitments

There have been no significant changes to our contractual obligations and commitments as reported in our 2011 Annual Report on Form 10-K.

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 2011 Annual Report on Form 10-K. These critical estimates, for which no significant changes occurred during the three months ended March 31, 2012, include estimates and assumptions for:


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

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

OFF-BALANCE SHEET ARRANGEMENTS

Our contracts with NGTL provide financial assurances to it during the construction phase of the NGTL Project, which is expected to continue through 2014. Assuming the project is fully constructed at estimated costs of C$257.4 million, we expect to provide letters of credit through 2014. Item 8, Note 14 in our 2011 Annual Report on Form 10-K contains additional information about our contracts with NGTL.

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.

In May 2011, the FASB issued an amendment to the accounting guidance for fair value measurement and disclosure. Among other things, the guidance expands the disclosure requirements around fair value measurements categorized in Level 3 of the fair value hierarchy and requires disclosure of the level in the fair value hierarchy of items that are not measured at fair value in the statement of financial position but whose fair value must be disclosed. It also clarifies and expands upon existing requirements for measurement of the fair value of financial assets and liabilities as well as instruments classified in shareholders’ equity. This guidance became effective for us beginning with the quarter ended March 31, 2012. The adoption of this accounting pronouncement did not have an effect on the fair value measurement, but rather expanded upon existing disclosures.

No other pronouncements materially affecting our financial statements have been issued since the filing of our 2011 Annual Report on Form 10-K.

ITEM 3. Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

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.

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 $48.8 million and $24.0 million for the 2012 quarter and 2011 quarter, respectively. Other revenue was $39.4 million and $0.1 million lower, respectively, for the 2012 quarter and 2011 quarter due to hedge ineffectiveness, unrealized losses at inception of new long-dated derivatives and realized losses on hedge restructuring.

The following table details our open derivative positions at March 31, 2012:


Product	Type	Production Hedged	Remaining Contract Period	Volume	Weighted Avg Price Per Mcf or Bbl
Gas	Collar	U.S.	Apr 2012-Dec 2012	20 MMcfd	6.50- 7.15
Gas	Collar	U.S.	Apr 2012-Dec 2012	20 MMcfd	6.50- 7.18
Gas	Collar	U.S.	Apr 2012-Dec 2012	20 MMcfd	6.50- 8.01
Gas	Swap	Canada	Apr 2012-Dec 2012	5 MMcfd	6.20
Gas	Swap	Canada	Apr 2012-Dec 2012	5 MMcfd	6.20
Gas	Swap	Canada	Apr 2012-Dec 2012	10 MMcfd	6.22
Gas	Swap	Canada	Apr 2012-Dec 2013	10 MMcfd	5.00
Gas	Swap	Canada	Apr 2012-Dec 2015	10 MMcfd	6.42
Gas	Swap	Canada	Apr 2012-Dec 2015	10 MMcfd	6.45
Gas	Swap	Canada	Apr 2012-Dec 2021	10 MMcfd	4.63
Gas	Swap	U.S.	Apr 2012-Dec 2013	10 MMcfd	5.00
Gas	Swap	U.S.	Apr 2012-Dec 2013	10 MMcfd	5.00
Gas	Swap	U.S.	Apr 2012-Dec 2013	10 MMcfd	5.00
Gas	Swap	U.S.	Apr 2012-Dec 2015	20 MMcfd	6.00
Gas	Swap	U.S.	Apr 2012-Dec 2015	10 MMcfd	6.00
Gas	Swap	U.S.	Apr 2012-Dec 2015	5 MMcfd	6.23
Gas	Swap	U.S.	Apr 2012-Dec 2015	5 MMcfd	6.20
Gas	Swap	U.S.	Apr 2012-Dec 2015	5 MMcfd	5.68
Gas	Swap	U.S.	Apr 2012-Dec 2021	5 MMcfd	6.20
Gas	Swap	U.S.	Apr 2012-Dec 2021	10 MMcfd	4.54
Gas	Swap	U.S.	Apr 2012-Dec 2021	5 MMcfd	4.38
Gas	Swap	U.S.	Apr 2012-Dec 2021	5 MMcfd	4.35
Gas	Swap	U.S.	Apr 2012-Dec 2021	10 MMcfd	4.37
NGL	Swap	U.S.	Apr 2012-Dec 2012	1 MBbld	42.81
NGL	Swap	U.S.	Apr 2012-Dec 2012	1 MBbld	43.07
NGL	Swap	U.S.	Apr 2012-Dec 2012	2 MBbld	43.94
NGL	Swap	U.S.	Apr 2012-Dec 2012	1 MBbld	47.99
NGL	Swap	U.S.	Apr 2012-Dec 2012	1 MBbld	46.55
NGL	Swap	U.S.	Apr 2012-Dec 2012	1 MBbld	46.75

These open derivative positions had a net fair value of $373.5 million as of March 31, 2012.

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.

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 both the 2012 quarter and the 2011 quarter, we recognized $1.2 million of those deferred gains as a reduction of interest expense.

Should we be required to borrow under our Combined Credit Agreements and based on interest rates as of March 31, 2012, each $50 million in borrowings would result in additional annual interest payments of $1.1 million. If the current borrowing availability under our Combined Credit Agreements were to be fully utilized by year-end 2012 at interest rates as of March 31, 2012, we estimate that annual interest payments would increase by $15.3 million. If interest rates change by 1% on our March 31, 2012 variable debt balances of $337.2 million, our annual pre-tax income would decrease or increase by $3.4 million.

In the future, we may enter into interest rate derivative contracts on a portion of our outstanding debt to mitigate the risk of fluctuation of rates or manage the floating versus fixed rate risk.

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 2012 quarter and the 2011 quarter resulted in a gain of $0.1 million and a loss of $0.1 million, respectively, and were included in other income. Furthermore, the Amended and Restated Canadian 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, 2012, our disclosure controls and procedures were not 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. In light of the material weakness regarding hedge accounting described below, we recorded an unrealized loss on hedge derivatives and have concluded that the financial statements in this Quarterly Report on form 10-Q present fairly, in all material respects, our consolidated financial condition, results of operation and cash flows in conformity with generally accepted accounting principles.

Changes in Internal Control Over Financial Reporting

As disclosed in our 2011 Annual Report on Form 10-K, a material weakness was identified related to the design and operating effectiveness of the computation of impairment of our non-oil and gas assets. In response to

the identification of the material weakness, management has enhanced its process for documenting identification of impairment indicators, and the presentation and review of undiscounted recovery tests and discounted cash flow analyses for the quarter ended March 31, 2012. Additionally management enhanced the process for preparation and review of the inputs to the asset retirement obligation and the depletion calculation for the quarter ended March 31, 2012 in response to identified significant deficiencies as of December 31, 2011 related to these calculations. Management believes that these enhancements and improvements will, as performed in the current period and when repeated in future periods, remediate the material weakness and significant deficiencies described above.

For the quarter ended March 31, 2012, a material weakness was identified related to the operating effectiveness of the controls surrounding the computation of derivative value. The weakness principally relates to the inception valuation methodology used on our ten-year derivatives entered into during the quarter ended March 31, 2012. Although the valuation produced an accounting result that conformed to GAAP, it was not consistent with the valuation methodology we use for our other derivatives. To a lesser extent, the weakness relates to the preparation and review of the inputs to the valuation model. In response to this material weakness, management has enhanced its process to value derivatives with particular emphasis on long-dated derivatives. Management believes that these enhancements and improvements will, when repeated in future periods, remediate the material weakness.

There has been no other change in our internal control over financial reporting during the quarter ended March 31, 2012, 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 2011 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 2011 Annual Report on Form 10-K.

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, 2012.


Period	Total Number of Shares Purchased ⁽¹⁾		Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plan ⁽²⁾		Maximum Number of Shares that May Yet Be Purchased Under the Plan ⁽²⁾
January 2012		293,630	$	6.81		-		-
February 2012		45,575	$	6.07		-		-
March 2012		11,680	$	5.44		-		-

Total		350,885	$	6.67		-		-

⁽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 stock plan.

⁽²⁾

We do not have a publicly announced plan for repurchasing our common stock.

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. Mine Safety Disclosures

None.

ITEM 5. Other Information

None.

ITEM 6. Exhibits

Exhibit No.

Exhibit Description

Incorporated by Reference

Filed (†) or
Furnished (‡)
Herewith (as
indicated)

Form

SEC File
No.

Exhibit

Filing
Date

4.1

Thirteenth Supplemental Indenture, dated as
of February 28, 2012, among Quicksilver
Resources Inc., the subsidiary guarantors
named therein and The Bank of New York
Mellon Trust Company, N.A., as trustee

†

4.2

Fourteenth Supplemental Indenture, dated
as of February 28, 2012, among Quicksilver
Resources Inc., the subsidiary guarantors
named therein and The Bank of New York
Mellon Trust Company, N.A., as trustee

†

4.3

Fifteenth Supplemental Indenture, dated as
of February 28, 2012, among Quicksilver
Resources Inc., the subsidiary guarantors
named therein and The Bank of New York
Mellon Trust Company, N.A., as trustee

†

4.4

Sixteenth Supplemental Indenture, dated as
of February 28, 2012, among Quicksilver
Resources Inc., the subsidiary guarantors
named therein and The Bank of New York
Mellon Trust Company, N.A., as trustee

†

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

‡

SIGNATURES

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 10, 2012
	Quicksilver Resources Inc.

	By:	/s/ John C. Regan
	John C. Regan
	Senior Vice President - Chief Financial Officer
	(Duly Authorized Officer, Principal Financial and Accounting Officer)

EXHIBIT INDEX

Exhibit No.

Exhibit Description

Incorporated by Reference

Filed (†) or
Furnished (‡)
Herewith (as
indicated)

Form

SEC File
No.

Exhibit

Filing
Date

4.1

Thirteenth Supplemental Indenture, dated as of February 28, 2012, among Quicksilver Resources Inc., the subsidiary guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee

†

4.2

Fourteenth Supplemental Indenture, dated as of February 28, 2012, among Quicksilver Resources Inc., the subsidiary guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee

†

4.3

Fifteenth Supplemental Indenture, dated as of February 28, 2012, among Quicksilver Resources Inc., the subsidiary guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee

†

4.4

Sixteenth Supplemental Indenture, dated as of February 28, 2012, among Quicksilver Resources Inc., the subsidiary guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee

†

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

‡