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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, 2010


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

For the transition period from _______ to

Commission file number: 001-14837

Quicksilver Resources Inc.

(Exact name of registrant as specified in its charter)


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

777 West Rosedale, Fort Worth, Texas		76104
(Address of principal executive offices)		(Zip Code)

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

None
(Former name, former address and former fiscal year, if changed since last report)

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

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

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

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

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


Title of Class		Outstanding as of April 26, 2010
Common Stock, $0.01 par value		170,279,079

DEFINITIONS

As used in this quarterly report unless the context otherwise requires:

“Bbl” or “Bbls” means barrel or barrels

“Bbld” means barrel or barrels per day

“Bcf” means billion cubic feet

“Bcfd” means billion cubic feet per day

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

“Canada” means the division of Quicksilver encompassing oil and natural gas properties located in Canada

“DD&A” means Depletion, Depreciation and Accretion

“LIBOR” means London Interbank Offered Rate

“MBbl” or “MBbls” means thousand barrels

“MBbld” means thousand barrels per day

“MMBbls” means million barrels

“MMBtu” means million British Thermal Units, a measure of heating value approximately equal to 1 Mcf of natural gas

“MMBtud” means million Btu per day

“Mcf” means thousand cubic feet

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

“MMcf” means million cubic feet

“MMcfd” means million cubic feet per day

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

“MMcfed” means MMcfe per day

“NGL” or “NGLs” means natural gas liquids

“NYMEX” means New York Mercantile Exchange

“Oil” includes crude oil and condensate

“Tcfe” means trillion cubic feet of natural gas equivalents calculated as one Bbl of oil or NGLs equaling six Mcf of natural gas

COMMONLY USED TERMS

Other commonly used terms and abbreviations include:

“ABR” means adjusted base rate

“AOCI” means accumulated other comprehensive income

“Alliance Leasehold” means the natural gas leasehold and royalty interests acquired on August 8, 2008 in northern Tarrant and southern Denton counties of Texas and developed thereafter

“Alliance Midstream Assets” means the natural gas gathering system and processing facility purchased by KGS from Quicksilver in January 2010

“BBEP” means BreitBurn Energy Partners L.P.

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

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

“Eni Transaction” means the June 19, 2009 conveyance of a 27.5% interest in our Alliance Leasehold

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

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

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

“Gas Purchase Commitment” means the commitment pursuant to the Eni Transaction to purchase Eni Production through December 2010

“KGS” means Quicksilver Gas Services LP, which is our publicly-traded partnership which trades under the ticker symbol of “KGS”

“KGS Credit Facility” means the KGS senior secured revolving credit facility

“KGS Secondary Offering” means the public offering of 4,000,000 KGS common units on December 16, 2009 and the underwriters’ purchase of an additional 549,200 KGS common units in January 2010

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

“Michigan Sales Contract” means the gas supply contract, which expired in March 2009 under which we agreed to deliver 25 MMcfd at a floor price of $2.49 per Mcf

“OCI” means other comprehensive income

“RSU” means restricted stock unit

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

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

Forward-Looking Information

Certain statements contained in this 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 crude oil prices;

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

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

	•		effects of hedging natural gas, NGL and crude 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;

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

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

	•		the effects of existing or future litigation; and

	•		certain factors discussed elsewhere in this quarterly report.

This list of factors is not exhaustive, and new factors may emerge or changes to these factors may occur that would impact our business. Additional information regarding these and other factors may be contained in our filings with the SEC, especially on 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 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,
	2010			2009
Revenue
Natural gas, NGL and crude oil	$	201,563		$	183,554
Sales of purchased natural gas		16,224			-
Other		4,371			2,378

Total revenue		222,158			185,932


Operating expense
Oil and gas production expense		35,989			32,171
Production and ad valorem taxes		8,483			4,366
Costs of purchased natural gas		33,307			-
Other operating costs		1,254			1,527
Depletion, depreciation and accretion		46,757			59,696
General and administrative		20,523			17,381

Total expense		146,313			115,141
Impairment related to oil and gas properties		-			(896,483	)

Operating income (loss)		75,845			(825,692	)
Loss from earnings of BBEP - net		(15,989	)		-
Other income - net		343			761
Interest expense		(44,517	)		(40,201	)

Income (loss) before income taxes		15,682			(865,132	)
Income tax (expense) benefit		(5,082	)		297,823

Net income (loss)		10,600			(567,309	)
Net income attributable to noncontrolling interests		(2,412	)		(1,670	)

Net income (loss) attributable to Quicksilver	$	8,188		$	(568,979	)

Other comprehensive income (loss) - net of income tax
Reclassification adjustments related to
settlements of derivative contracts		(26,269	)		(36,914	)
Net change in derivative fair value		98,606			108,603
Foreign currency translation adjustment		6,960			(7,224	)

Comprehensive income (loss)	$	87,485		$	(504,514	)


Earnings (loss) per common share - basic	$	0.05		$	(3.37	)
Earnings (loss) per common share - diluted	$	0.05		$	(3.37	)
Basic weighted average shares outstanding		170,175			168,841
Diluted weighted average shares outstanding		171,040			168,841

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

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


	March 31,			December 31,
	2010			2009
ASSETS
Current assets
Cash and cash equivalents	$	601		$	1,785
Accounts receivable - net of allowance for doubtful accounts		60,348			65,253
Derivative assets at fair value		172,850			97,957
Other current assets		50,542			54,943

Total current assets		284,341			219,938
Investment in BBEP		96,774			112,763
Property, plant and equipment
Oil and gas properties, full cost method (including unevaluated costs of $392,272 and $458,037, respectively)		2,428,099			2,338,244
Other property and equipment		765,789			747,696

Property, plant and equipment - net		3,193,888			3,085,940
Derivative assets at fair value		54,304			14,427
Deferred income taxes		118,203			133,051
Other assets		44,489			46,763

	$	3,791,999		$	3,612,882

LIABILITIES AND EQUITY
Current liabilities
Accounts payable	$	150,532		$	157,986
Accrued liabilities		132,247			156,604
Derivative liabilities at fair value		812			395
Deferred income taxes		71,756			51,675

Total current liabilities		355,347			366,660
Long-term debt		2,510,494			2,427,523
Asset retirement obligations		61,822			59,268
Other liabilities		20,692			20,691
Derivative liabilities at fair value		654			-
Deferred income taxes		49,095			41,918
Commitments and contingencies (Note 7)		-			-
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; 175,439,552 and 174,469,836 shares issued, respectively		1,754			1,745
Paid in capital in excess of par value		742,773			730,265
Treasury stock of 5,022,244 and 4,704,448 shares, respectively		(41,129	)		(36,363	)
Accumulated other comprehensive income		200,633			121,336
Retained deficit		(172,797	)		(180,985	)

Quicksilver stockholders’ equity		731,234			635,998
Noncontrolling interests		62,661			60,824

Total equity		793,895			696,822

	$	3,791,999		$	3,612,882

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
								Accumulated
			Additional					Other			Retained
	Common		Paid-in		Treasury			Comprehensive			Earnings			Noncontrolling
	Stock		Capital		Stock			Income			(Deficit)			Interests			Total
Balances at December 31, 2008	$	1,717	$	656,958	$	(35,441	)	$	185,104		$	376,488		$	26,737		$	1,211,563
Net income (loss)		-		-		-			-			(568,979	)		1,670			(567,309	)
Hedge derivative contract settlements reclassified into earnings from accumulated other comprehensive income, net of income tax of $16,950		-		-		-			(36,914	)		-			-			(36,914	)
Net change in derivative fair value, net of income tax of $52,805		-		-		-			108,603			-			-			108,603
Foreign currency translation adjustment		-		-		-			(7,224	)		-			-			(7,224	)
Issuance and vesting of stock compensation		22		5,287		(623	)		-			-			418			5,104
Stock option exercises		-		11		-			-			-			-			11
Distributions paid on KGS common units		-		-		-			-			-			(2,448	)		(2,448	)

Balances at March 31, 2009	$	1,739	$	662,256	$	(36,064	)	$	249,569		$	(192,491	)	$	26,377		$	711,386


Balances at December 31, 2009	$	1,745	$	730,265	$	(36,363	)	$	121,336		$	(180,985	)	$	60,824		$	696,822
Net income		-		-		-			-			8,188			2,412			10,600
Hedge derivative contract settlements reclassified into earnings from accumulated other comprehensive income, net of income tax of $14,006		-		-		-			(26,269	)		-			-			(26,269	)
Net change in derivative fair value, net of income tax of $49,567		-		-		-			98,606			-			-			98,606
Foreign currency translation adjustment		-		-		-			6,960			-			-			6,960
Issuance and vesting of stock compensation		8		5,006		(4,766	)		-			-			(478	)		(230	)
Stock option exercises		1		759		-			-			-			-			760
Issuance of KGS common units		-		6,743		-			-			-			4,307			11,050
Distributions paid on KGS common units		-		-		-			-			-			(4,404	)		(4,404	)

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

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,
	2010			2009
Operating activities:
Net income (loss)	$	10,600		$	(567,309	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation and accretion		46,757			59,696
Impairment related to oil and gas properties		-			896,483
Deferred income tax expense (benefit)		5,082			(304,639	)
Non-cash interest expense		5,075			4,139
Stock-based compensation		5,680			5,790
Non-cash loss from hedging and derivative activities		1,421			1,128
Loss from BBEP in excess of cash distributions, net of impairment		15,989			11,101
Other		(323	)		91
Changes in assets and liabilities
Accounts receivable		4,905			33,536
Derivative assets at fair value		14,260			54,896
Other assets		5,519			1,566
Accounts payable		(15,553	)		(21,436	)
Accrued and other liabilities		(33,640	)		(25,692	)

Net cash provided by operating activities		65,772			149,350


Investing activities:
Purchases of property, plant and equipment		(129,331	)		(255,984	)
Proceeds from sales of property and equipment		718			416

Net cash used for investing activities		(128,613	)		(255,568	)


Financing activities:
Issuance of debt		295,446			208,374
Repayments of debt		(227,639	)		(101,188	)
Debt issuance costs paid		(109	)		(39	)
Gas Purchase Commitment repayments		(7,317	)		-
Issuance of KGS common units - net of offering costs		11,050			-
Distributions paid on KGS common units		(4,404	)		(2,448	)
Proceeds from exercise of stock options		760			11
Taxes paid by KGS for equity-based compensation vesting		(1,144	)		(63	)
Purchase of treasury stock for stock-based compensation vesting		(4,766	)		(623	)

Net cash provided by (used for) financing activities		61,877			104,024


Effect of exchange rate changes in cash		(220	)		(224	)


Net decrease in cash		(1,184	)		(2,418	)

Cash and cash equivalents at beginning of period		1,785			2,848


Cash and cash equivalents at end of period	$	601		$	430

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

QUICKSILVER RESOURCES INC.
NOTES TO CONDENSED CONSOLIDATED INTERIM 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, 2010 and our results of operations and cash flows for the three months ended March 31, 2010 and 2009. All such adjustments are of a normal recurring nature. The results for interim periods are not necessarily indicative of annual results.

Preparing financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities, the 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. We believe our estimates and assumptions are reasonable, but actual results could differ from our 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 2009 Annual Report on Form 10-K.

Recently Issued Accounting Standards

Accounting standards-setting organizations frequently issue new or revised accounting rules. We regularly review all new pronouncements to determine their impact, if any, on our financial statements. No pronouncements affecting our financial statements have been issued since the filing of our 2009 Annual Report on Form 10-K.

2.	DERIVATIVES AND FAIR VALUE MEASUREMENTS

Commodity Price Derivatives

As of March 31, 2010, we had price collars or fixed price swaps hedging 200 MMcfd, 120 MMcfd and 60 MMcfd of our anticipated natural gas production for 2010, 2011 and 2012, respectively. We had fixed price swaps hedging 10 MBbld and 8 MBbld of our anticipated 2010 and 2011 NGL production, respectively.

Interest Rate Derivatives

In February 2010, we executed the early settlement of our interest rate swaps that hedged our senior notes due 2015 and our senior subordinated notes. We received cash of $18.0 million in the settlement, including $3.7 million for previously accrued and earned, and recognized an adjustment of $14.3 million to the carrying value of the debt. The $14.3 million settlement will be recognized as a reduction of interest expense over the life of the associated underlying debt instruments currently scheduled as follows:


(In thousands)

2010	$	1,856
2011		2,195
2012		2,380
2013		2,580
2014		2,797
2015		2,181
2016		271

	$	14,260

Also in February 2010, we entered into new interest rate swaps on our senior notes due 2015 and our senior subordinated notes that convert the interest paid on those issues from a fixed to a floating rate indexed to six-month LIBOR. The maturity dates and all other significant terms are the same as those of the underlying debt. As a result, the new interest rate swaps

qualified for hedge accounting treatment as fair value hedges. The value of the contracts, excluding the net interest accrual, amounted to a net liability of $5.0 million as of March 31, 2010. The offsetting fair value adjustment to the debt hedged decreased the carrying value of the debt. There was no ineffectiveness recorded in connection with the new interest rate swaps. The average effective interest rates on the senior notes due 2015 and the senior subordinated notes, including all interest earned from both the early settled and new interest rate swaps, were approximately 3.82% and 5.23%, respectively for the first quarter of 2010.

Other Derivatives

The 2010 activity associated with the liability for the Gas Purchase Commitment is shown below. The Gas Purchase Commitment, which is effective through December 31, 2010, contains an embedded derivative revalued for changes to estimated volumes and prices on March 31, 2010. We recognized an increase in the fair value of the embedded derivative liability for the three months ended March 31, 2010 and recorded a valuation loss as a component of costs of purchased natural gas. At March 31, 2010, we have estimated the remaining liability at $60.1 million, including an embedded derivative liability of $23.3 million, which reflects a 2.0 Bcf reduction of the total estimated volumes purchased under the commitment compared with our December 31, 2009 estimate. The following summarizes activity to the Gas Purchase Commitment:


(In thousands)

Liability fair value at December 31, 2009	$	50,744
Decrease due to gas volumes purchased		(7,317	)
Embedded derivative increase (decrease) due to:
Price changes		21,704
Volume changes		(5,066	)

Total increase (decrease) in embedded derivative		16,638

Liability fair value at March 31, 2010 ⁽¹⁾	$	60,065


⁽¹⁾		The liability for the Gas Purchase Commitment was valued using estimated Eni production volumes through December 2010 and published future market prices and risk-adjusted interest rates as of March 31, 2010.

The estimated fair value of our derivatives at March 31, 2010 and December 31, 2009 were as follows:


	Asset Derivatives				Liability Derivatives
	March 31,		December 31,		March 31,		December 31,
	2010		2009		2010		2009
	(In thousands)				(In thousands)
Derivatives designated as hedges:
Commodity contracts reported in:
Current derivative assets	$	174,108	$	97,883	$	584	$	638
Noncurrent derivative assets		57,386		11,031		-		-
Current derivative liabilities		-		243		584		638
Noncurrent derivative liabilities		392		-		-		-
Interest rate contracts reported in:
Current derivative assets		-		712		674		-
Noncurrent derivative assets		-		3,396		3,082		-
Current derivative liabilities				-		228		-
Noncurrent derivative liabilities		-		-		1,046		-

Total derivatives designated as hedges	$	231,886	$	113,265	$	6,198	$	1,276

Derivatives not designated as hedges:
Gas Purchase Commitment reported in accrued liabilities	$	-	$	-	$	23,263	$	6,625

Total derivatives not designated as hedges	$	-	$	-	$	23,263	$	6,625

Total derivatives	$	231,886	$	113,265	$	29,461	$	7,901

The following table shows the level of inputs used in our fair value calculations of our derivative instruments at March 31, 2010 and December 31, 2009:


	Significant Other Observable
	Inputs - Level 2
	March 31,			December 31,
	2010			2009
	(in thousands)
Gas Purchase Commitment	$	(23,263	)	$	(6,625	)
Commodity contracts		230,718			107,881
Interest rate contracts		(5,030	)		4,108

Total	$	202,425		$	105,364

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.

The increase in carrying value of our commodity price derivatives since December 31, 2009 principally resulted from the overall decline in market prices for natural gas and NGLs relative to the prices of our open derivative instruments. These decreases were partially offset by monthly settlements received thus far during 2010.

The changes in the carrying value of our derivatives for the three months ended March 31, 2010 and 2009 are presented below:


	For the Three Months Ended March 31, 2010
	Gas Purchase			Interest Rate			Commodity
	Commitment			Swaps			Hedges			Total
	(In thousands)
Derivative fair value at December 31, 2009	$	(6,625	)	$	4,108		$	107,881		$	105,364
Net change in amounts receivable/payable		-			(4,997	)		(2,223	)		(7,220	)
Net settlements reported in revenue		-			-			(24,557	)		(24,557	)
Net settlements reported in interest expense		-			(2,296	)		-			(2,296	)
Cash settlements reported in long-term debt					(13,934	)					(13,934	)
Change in fair value of Gas Purchase Commitment reported in costs of purchased gas		(16,638	)		-			-			(16,638	)
Change in fair value of effective interest swaps		-			12,089			-			12,089
Ineffectiveness reported in other revenue		-			-			1,395			1,395
Unrealized gains reported in OCI		-			-			148,222			148,222

Derivative fair value at March 31, 2010	$	(23,263	)	$	(5,030	)	$	230,718		$	202,425


	For the Three Months Ended March 31, 2009
	Michigan			Commodity
	Contract			Hedges			Total
	(In thousands)
Derivative fair value at December 31, 2008	$	(12,901	)	$	290,719		$	277,818
Net change in amounts receivable/payable		(3,518	)		-			(3,518	)
Net settlements		16,479			-			16,479
Net settlements reported in revenue		-			(53,864	)		(53,864	)
Ineffectiveness reported in other revenue		(60	)		(1,068	)		(1,128	)
Cash settlement reported in OCI		-			(54,896	)		(54,896	)
Unrealized gains reported in OCI		-			161,432			161,432

Derivative fair value at March 31, 2009	$	-		$	342,323		$	342,323

Gains and losses from the effective portion of derivative assets and liabilities held in AOCI expected to be reclassified into earnings over the next twelve months would result in a gain of $113.4 million net of income taxes. An additional $26.9 million, net of income taxes, will be reclassified from AOCI due to the realized gain on the 2010 natural gas collar settled in 2009. Hedge derivative ineffectiveness resulted in a gain of $1.4 million and a loss of $1.1 million recorded in other revenue for the three months ended March 31, 2010 and 2009, respectively.

3.	INVESTMENT IN BREITBURN ENERGY PARTNERS L.P.

We own approximately 21.3 million common units of BBEP, a publicly-traded limited partnership, whose price closed at $14.92 per unit at March 31, 2010. We account for our investment in BBEP units using the equity method, utilizing a one-quarter lag from BBEP’s publicly available information. Summarized estimated financial information for BBEP is as follows:


	For the Three Months Ended
	December 31,
	2009			2008
	(In thousands)
Revenues ⁽¹⁾	$	38,263		$	443,247
Operating expenses ⁽²⁾		73,272			165,796

Operating income (loss)		(35,009	)		277,451
Interest and other ⁽³⁾		5,859			25,599
Income tax (benefit) expense		(1,174	)		677
Noncontrolling interests		19			13

Net income (loss) available to BBEP	$	(39,713	)	$	251,162


⁽¹⁾		Includes unrealized losses of $54.7 million and unrealized gains $346.3 million for the three months ended December 31, 2009 and 2008, respectively.

⁽²⁾		An impairment of BBEP’s oil and gas properties of $86.4 million was included for the three months ended December 31, 2008.

⁽³⁾		The three months ended December 31, 2009 and 2008 included $0.7 million and $15.1 million, respectively, for unrealized losses on interest rate swaps.


	As of December 31,
	2009		2008
	(In thousands)
Current assets	$	142,441	$	140,566
Property, plant and equipment		1,741,089		1,840,341
Other assets		87,499		235,927
Current liabilities		91,890		79,990
Long-term debt		559,000		736,000
Other non-current liabilities		91,338		47,413
Total equity		1,228,801		1,353,431

For the three months ended March 31, 2010, we recognized a loss of $16.0 million for our share of BBEP’s loss for the three months ended December 31, 2009. For the comparable 2009 period, we recognized income of $102.1 million for the three months ended December 31, 2008 and impairment expense of $102.1 million at March 31, 2009.

Changes in the balance of our investment in BBEP for the first quarter of 2010 were as follows:


(In thousands)

Balance at December 31, 2009	$	112,763
Equity loss in BBEP		(15,989	)
Distributions from BBEP		-

Balance at March 31, 2010	$	96,774

Note 7 contains additional information regarding the April 2010 settlement of our lawsuit against BBEP and other parties. In April 2010, BBEP announced a $0.375 per unit distribution for all outstanding units, which it anticipates paying in May 2010.

4.	PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment consisted of the following:


	March 31,				December 31,
	2010				2009
		(In thousands)
Oil and gas properties
Subject to depletion	$		4,153,280		$	3,947,676
Unevaluated costs			392,272			458,037
Accumulated depletion			(2,117,453	)		(2,067,469	)

Net oil and gas properties			2,428,099			2,338,244
Other plant and equipment
Pipelines and processing facilities			792,699			779,493
General properties			70,487			68,698
Construction in progress			19,000			5,630
Accumulated depreciation			(116,397	)		(106,125	)

Net other property and equipment			765,789			747,696

Property, plant and equipment, net of accumulated depletion and depreciation	$		3,193,888		$	3,085,940

Ceiling Test Analysis

The 2010 first quarter U.S. ceiling limitation was determined using a NYMEX price of $3.98 per Mcf of natural gas, $33.19 per barrel of NGL and $69.64 per barrel of oil. We computed the 2010 first quarter Canadian ceiling amount using an AECO price of $3.90 per Mcf of natural gas. All prices used in determining ceiling limitations were the unweighted average of the preceding 12-month first-day-of-the-month prices. The ceiling tests prepared as of March 31, 2010 for our U.S. and Canadian oil and gas properties resulted in no impairment.

In the first quarter of 2009, we recorded impairment of our U.S. and Canadian oil and gas properties of $786.9 million and $109.6 million, respectively. The decrease in last day of the period benchmark natural gas, oil and NGL prices from December 31, 2008 to March 31, 2009 was the primary factor in the reduction of the U.S. and Canadian ceiling limits at March 31, 2009 when compared to December 31, 2008.

For additional information regarding our property, plant and equipment and our 2009 full cost ceiling impairments, see Note 10 to our consolidated financial statements in our 2009 Annual Report on Form 10-K.

5. LONG-TERM DEBT

Long-term debt consisted of the following:


	March 31,				December 31,
	2010				2009
		(In thousands)
Senior Secured Credit Facility		$	442,647			$	467,569
Senior notes due 2015, net of unamortized discount			470,190				469,964
Senior notes due 2016, net of unamortized discount			581,903				581,359
Senior notes due 2019, net of unamortized discount			293,137				293,004
Senior subordinated notes due 2016			350,000				350,000
Convertible debentures, net of unamortized discount			137,913				136,119
KGS credit agreement			225,800				125,400

Total debt			2,501,590				2,423,415
Unamortized deferred gain - terminated interest rate swaps			13,934				-
Fair value - interest rate swaps			(5,030	)			4,108

Long-term debt		$	2,510,494			$	2,427,523

Senior Secured Credit Facility

At March 31, 2010, we had $443 million outstanding under our Senior Secured Credit Facility, which has a $1.0 billion borrowing base.

Convertible Debentures

The convertible debentures are contingently convertible into shares of Quicksilver common stock at a rate of 65.4418 shares for each $1,000 debenture, subject to adjustment. Upon conversion, we have the option to deliver any combination of Quicksilver common stock and cash. Should all debentures be converted to Quicksilver common stock, an additional 9,816,270 shares would become outstanding; however, as of April 1, 2010, the debentures were not convertible based on share prices for the quarter ended March 31, 2010.

At March 31, 2010 and December 31, 2009, the remaining unamortized discount on the debentures was $12.1 million and $13.9 million, respectively, resulting in a carrying value of $137.9 million and $136.1 million, respectively. The remaining discount will be accreted to face value through October 2011. For the three months ended March 31, 2010 and 2009, interest expense on our convertible debentures, recognized at an effective interest rate of 6.75%, was $2.5 million and $2.4 million, respectively, including contractual interest of $0.7 million for each period.

KGS Credit Facility

At March 31, 2010, KGS had $226 million outstanding under its $320 million credit facility.

Summary of All Outstanding Debt

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

Priority on Collateral and Structural Seniority ⁽¹⁾

Recourse only to

Highest priority

Lowest priority

KGS assets

Equal priority

Senior Secured

2015

2016

2019

Senior

Convertible

KGS Credit

Credit Facility

Senior Notes

Subordinated Notes

Debentures

Agreement

Scheduled maturity date

February 9, 2012

August 1, 2015

January 1, 2016

September 1, 2019

April 1, 2016

November 1, 2024

August 10, 2012

Interest rate at
March 31, 2010 ⁽²⁾

3.12%

8.25%

11.75%

9.125%

7.125%

1.875%

3.25%

Base interest rate options ⁽³⁾

LIBOR, ABR or
specified ⁽⁴⁾

N/A

LIBOR, ABR or
specified ⁽⁵⁾

Financial covenants ⁽⁶⁾

- Minimum current
ratio of 1.0

- Minimum EBITDA to
interest expense ratio
of 2.5

N/A

- Maximum debt to
EBITDA ratio of 4.5

- Minimum EBITDA
to interest expense
ratio of 2.5

Significant restrictive
covenants ⁽⁶⁾

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

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

N/A

- Incurrence of debt
- Incurrence of liens
- Equity purchases
- Asset sales
- Limitations on
derivatives

Estimated fair value ⁽⁷⁾

$442.6 million

$486.9 million

$690.0 million

$318.0 million

$332.5 million

$166.5 million

$225.8 million


⁽¹⁾		The Senior Secured Credit Facility is secured by a first perfected lien on substantially all our assets, excluding KGS’ assets. The other debt presented is based upon structural seniority and priority of payment.

⁽²⁾		Represents the weighted average borrowing rate payable to lenders and excludes effects of interest rate derivatives.

⁽³⁾		Interest rate options include a base rate plus a spread.

⁽⁴⁾		Interest rate spreads on our Senior Secured Credit Facility include a floor to ABR of one-month LIBOR plus a 1% increase in the ABR margin to a range of 1.375% to 2.375% and Eurodollar and specified rate margins to a range of 2.25% to 3.25%.

⁽⁵⁾		Interest rate spreads on the KGS Credit Facility include a floor to ABR of one-month LIBOR plus a 1% increase in the ABR margin to a range of 2.00% to 3.00% and Eurodollar and specified rate margins to a range of 3.00% to 4.00%.

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

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

For a more complete description of our long-term debt, see Note 13 to the consolidated financial statements in our 2009 Annual Report on Form 10-K.

6. ASSET RETIREMENT OBLIGATIONS

The following table provides information about our estimated asset retirement obligations for the three months ended March 31, 2010.


(In thousands)

Beginning asset retirement obligations	$	59,377
Incremental liability incurred		589
Accretion expense		737
Currency translation adjustment		1,228

Ending asset retirement obligations		61,931
Less current portion		(109	)

Long-term asset retirement obligations	$	61,822

7. COMMITMENTS AND CONTINGENCIES

As of March 31, 2010, our estimate of total Eni Production volumes purchased under the Gas Purchase Commitment has been reduced 2.0 Bcf from our December 31, 2009 estimates and we estimated a remaining liability of $60.1 million, including an embedded derivative liability of $23.3 million. Valuation of the liability was based on the most recent estimate of 2010 Eni Production volumes and natural gas prices at March 31, 2010.

In April 2010, we finalized a global settlement agreement with BBEP and all other parties to our lawsuit whereby we subsequently received $18.0 million in cash. Pursuant to the agreement, we also retained full voting rights for our units held in BBEP subject to the provisions of a limited standstill agreement and we were granted the right to name two directors to the board of directors of BBEP’s general partner. BBEP also agreed to the reinstitution of quarterly distributions and other governance accommodations. The $18.0 million settlement was recognized as non-operating income in the second quarter of 2010.

In April 2010, Quicksilver entered into a lease of office space for a term of 12 years that is scheduled to commence August 2010. Aggregate rentals over the life of the lease will total $29.8 million.

On September 17, 2007, Eagle Drilling LLC and Rod and Richard Thornton, sued Quicksilver and our Executive Vice President – Operations in state district court Cleveland County, Oklahoma for approximately $29 million in damages and an unspecified amount of punitive damages in connection with Quicksilver’s repudiation of three rig contracts. In October 2009, a jury awarded $22 million to the plaintiffs. We continue to actively seek an appeal in the matter.

There have been no other significant changes to our commitments and contingencies as reported in our 2009 Annual Report. For a more complete description of our commitments and contingencies see Note 16 to the consolidated financial statements in our 2009 Annual Report on Form 10-K.

8. NONCONTROLLING INTERESTS AND KGS

In January 2010, the underwriters purchased an additional 549,200 newly issued common units for $11.1 million in connection with the KGS Secondary Offering. After the underwriters’ purchase of additional units, our ownership of KGS was reduced to 61.0%. As a result of the transaction, we recognized an increase of $6.7 million to “Additional Paid-in Capital” in January 2010. In December 2009, KGS offered these additional units to the public as part of its funding strategy for its acquisition of the Alliance Midstream Assets from us. The acquisition was completed in January 2010 for an initial purchase price of $95.2 million, which was subsequently reduced to $84.4 million due to a purchase price adjustment based on timing of construction costs of the system. KGS’ ownership, after completion of the KGS Secondary Offering, is summarized in the following table.


	KGS Ownership
	Quicksilver		Public		Total
General partner interests		1.6%		-		1.6%
Limited partner interests:
Common interests		19.7%		39.0%		58.7%
Subordinated interests		39.7%		-		39.7%

Total interests		61.0%		39.0%		100.0%

The subordinated units will convert into an equal number of common units upon termination of the subordination period, which would end in the fourth quarter of 2010, if KGS continues to earn and pay at least $0.30 per quarter on each outstanding common and subordinated unit through that time.

9. STOCK-BASED COMPENSATION

Note 19 to the consolidated financial statements in our 2009 Annual Report on Form 10-K contains additional information about our equity-based compensation plans.

Quicksilver Stock Options

Options to purchase shares of common stock were granted in 2010 with an estimated fair value of $8.9 million over the vesting period. We recognized expense of $1.7 million for all unvested stock options in the first three months of 2010.

We estimated the fair value of stock options granted in 2010 on the dates of grant using the Black-Scholes option-pricing model with the following assumptions:


	Stock
	Options
	Issued
Weighted average grant date fair value		$15.88
Weighted average grant date	Jan 4, 2010
Weighted average risk-free interest rate		3.00	%
Expected life (in years)		6.0
Weighted average volatility		66.76	%
Expected dividends		—

The following table summarizes stock option activity during the three months ended March 31, 2010:


				Wtd Avg		Wtd Avg
				Exercise		Remaining		Aggregate
	Shares			Price		Contractual Life		Intrinsic Value
						(In years)		(In thousands)
Outstanding at December 31, 2009		3,014,441		$	8.97
Granted		901,887			15.88
Exercised		(134,587	)		5.65
Cancelled		(45,984	)		7.69

Outstanding at March 31, 2010		3,735,757		$	10.78		8.8		$ 19,527

Exercisable at March 31, 2010		1,158,760		$	11.15		8.2		$ 7,141

Vested at March 31, 2010 or expected to vest in the future		3,647,793		$	10.81

Cash received from the exercise of stock options was $0.8 million for the three months ended March 31, 2010 and the total fair value of those options exercised was $1.4 million.

Quicksilver Restricted Stock and Restricted Stock Units

The following table summarizes information regarding our restricted stock and RSU activity:


	Payable in stock					Payable in cash

				Wtd Avg					Wtd Avg
				Grant Date					Grant Date
	Shares			Fair Value		Stock Units			Fair Value

Outstanding at December 31, 2009		2,722,875		$	10.33		328,695		$	6.22
Granted		887,869			15.59		166,118			15.87
Vested		(1,071,366	)		12.14		(109,602	)		6.22
Cancelled		(52,740	)		10.36		(4,439	)		9.71

Outstanding at March 31, 2010		2,486,638		$	11.43		380,772		$	10.39

At January 1, 2010, we had total unvested compensation cost of $15.1 million. During the first three months of 2010, we recognized compensation expense for all unvested restricted stock and RSUs of $3.8 million. Grants of restricted stock and stock-settled RSUs during the three months ended March 31, 2010 had an estimated grant date fair value of $13.8 million, which will be recognized as expense over the vesting period. Unrecognized compensation cost remaining at March 31, 2010 for restricted stock and stock-settled RSUs was $25.1 million, which will be recognized through February 2013. The fair value of unvested RSUs settled in cash was $1.7 million at March 31, 2010. The total fair value of restricted shares and RSUs vested during the three months ended March 31, 2010 was $16.6 million.

KGS Phantom Units

The following table summarizes information regarding KGS phantom unit activity:


	Payable in units					Payable in cash
				Wtd Avg				Wtd Avg
				Grant Date				Grant Date
	Units			Fair Value		Units		Fair Value

Outstanding at December 31, 2009		485,672		$	12.73		33,240	$	20.90
Granted		211,600			21.15		-		-
Vested		(179,886	)		13.74		-		-
Cancelled		(431	)		14.72		-		-

Outstanding at March 31, 2010		516,955		$	15.84		33,240	$	20.90

At January 1, 2010, KGS had total unrecognized compensation cost of $2.9 million related to unvested phantom unit awards. KGS recognized compensation expense of approximately $0.9 million during the three months ended March 31, 2010. Grants of phantom units during the three months ended March 31, 2010 had an estimated grant date fair value of $4.5 million. KGS has unearned compensation expense of $5.3 million at March 31, 2010 that will be recognized in expense over the vesting period. Phantom units that vested during the three months ended March 31, 2010 had a fair value of $2.5 million on their vesting date.

10. EARNINGS PER SHARE

The following is a reconciliation of the numerator and denominator used to compute basic and diluted net income per common share.


	Three Months Ended
	March 31,
	2010		2009
	(In thousands, except per share data)
Net income (loss) attributable to Quicksilver	$	8,188	$	(568,979	)

Impact of assumed conversions – interest on 1.875% convertible debentures, net of income taxes ⁽¹⁾		-		-

Income (loss) available to stockholders assuming conversion of convertible debentures	$	8,188	$	(568,979	)


Weighted average common shares – basic		170,175		168,841
Effect of dilutive securities⁽¹⁾:
Employee stock options		843		-
Employee stock unit awards		22		-
Contingently convertible debentures		-		-

Weighted average common shares – diluted		171,040		168,841


Earnings (loss) per common share – basic	$	0.05	$	(3.37	)
Earnings (loss) per common share – diluted	$	0.05	$	(3.37	)


		⁽¹⁾	For the three months ended March 31, 2010 and 2009, the effects of 9.8 million shares for our convertible debt were antidilutive and excluded from the diluted share calculations. Stock options and unvested restricted stock units representing 0.9 million shares at March 31, 2009 were also antidilutive and excluded from the diluted share calculations.

11. CONDENSED CONSOLIDATING FINANCIAL INFORMATION

Note 20 to the consolidated financial statements in our 2009 Annual Report on Form 10-K contains a more complete description of our guarantor, non-guarantor, restricted and unrestricted subsidiaries.

The following condensed consolidating financial information includes information about the Company and our restricted subsidiaries. The 2009 condensed consolidating financial information includes changes in the financial information of our unrestricted non-guarantor subsidiaries (primarily KGS) to present the 2009 financial information including the effects of the purchase of the Alliance Midstream Assets by KGS.


	March 31, 2010
					Restricted		Restricted			Quicksilver		Unrestricted					Quicksilver
	Quicksilver		Guarantor		Non-Guarantor		Subsidiary			and Restricted		Non-Guarantor		Consolidating			Resources Inc.
	Resources Inc.		Subsidiaries		Subsidiaries		Eliminations			Subsidiaries		Subsidiaries		Eliminations			Consolidated

	(In thousands)
ASSETS
Current assets	$	268,914	$	84,403	$	57,649	$	(111,506	)	$	299,460	$	13,266	$	(28,385	)	$	284,341
Property and equipment		2,033,730		130,235		529,053		-			2,693,018		500,870		-			3,193,888
Investment in subsidiaries (equity method)		569,073		153,305		-		(472,299	)		250,079		-		(153,305	)		96,774
Other assets		250,326		-		11,389		-			261,715		8,845		(53,564	)		216,996

Total assets	$	3,122,043	$	367,943	$	598,091	$	(583,805	)	$	3,504,272	$	522,981	$	(235,254	)	$	3,791,999


LIABILITIES AND EQUITY
Current liabilities	$	322,644	$	118,607	$	36,327	$	(111,506	)	$	366,072	$	17,660	$	(28,385	)	$	355,347
Long-term liabilities		2,068,165		11,878		326,923		-			2,406,966		289,355		(53,564	)		2,642,757
Quicksilver stockholders’ equity		731,234		237,458		234,841		(472,299	)		731,234		153,305		(153,305	)		731,234
Noncontrolling interests		-		-		-		-			-		62,661		-			62,661

Total liabilities and equity	$	3,122,043	$	367,943	$	598,091	$	(583,805	)	$	3,504,272	$	522,981	$	(235,254	)	$	3,791,999


	December 31, 2009
			Restricted		Restricted		Restricted			Quicksilver		Unrestricted					Quicksilver
	Quicksilver		Guarantor		Non-Guarantor		Subsidiary			and Restricted		Non-Guarantor		Consolidating			Resources Inc.
	Resources Inc.		Subsidiaries		Subsidiaries		Eliminations			Subsidiaries		Subsidiaries		Eliminations			Consolidated
ASSETS	(In thousands)
Current assets	$	313,485	$	394	$	42,622	$	(121,580	)	$	234,921	$	2,268	$	(17,251	)	$	219,938
Property and equipment		1,980,053		131,862		491,528		-			2,603,443		482,497		-			3,085,940
Investment in subsidiaries (equity method)		549,200		230,221		-		(436,437	)		342,984		-		(230,221	)		112,763
Other assets		235,304		-		3,112		-			238,416		9,067		(53,242	)		194,241

Total assets	$	3,078,042	$	362,477	$	537,262	$	(558,017	)	$	3,419,764	$	493,832	$	(300,714	)	$	3,612,882

LIABILITIES AND EQUITY
Current liabilities	$	349,415	$	116,298	$	25,321	$	(121,580	)	$	369,454	$	14,457	$	(17,251	)	$	366,660
Long-term liabilities		2,092,629		11,843		309,840		-			2,414,312		188,330		(53,242	)		2,549,400
Quicksilver stockholders’ equity		635,998		234,336		202,101		(436,437	)		635,998		230,221		(230,221	)		635,998
Noncontrolling interests		-		-		-		-			-		60,824		-			60,824

Total liabilities and equity	$	3,078,042	$	362,477	$	537,262	$	(558,017	)	$	3,419,764	$	493,832	$	(300,714	)	$	3,612,882



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

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

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

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



	For the Three Months Ended March 31, 2009
				Restricted			Restricted			Restricted		Quicksilver			Unrestricted						Quicksilver
	Quicksilver			Guarantor			Non-Guarantor			Subsidiary		and Restricted			Non-Guarantor						Resources Inc.
	Resources Inc.			Subsidiaries			Subsidiaries			Eliminations		Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenue	$	137,607		$	32		$	45,814		$	76	$	183,529		$	23,964		$	(21,561	)	$	185,932
Operating expense		892,198			284			128,893			76		1,021,451			11,736			(21,563	)		1,011,624
Equity in net earnings of subsidiaries		(57,641	)		7,725			-			57,641		7,725			-			(7,725	)		-

Operating income (loss)		(812,232	)		7,473			(83,079	)		57,641		(830,197	)		12,228			(7,723	)		(825,692	)
Income from earnings of BBEP		-			-			-			-		-			-			-			-
Interest expense and other		(36,551	)		1,383			(1,400	)		-		(36,568	)		(2,235	)		(637	)		(39,440	)
Income tax (expense) benefit		279,804			(3,100	)		21,082			-		297,786			37			-			297,823
Discontinued operations		-			-			-			-		-			(635	)		635			-

Net income (loss)	$	(568,979	)	$	5,756		$	(63,397	)	$	57,641	$	(568,979	)	$	9,395		$	(7,725	)	$	(567,309	)
Net income attributable to noncontrolling interests		-			-			-			-		-			(1,670	)		-			(1,670	)

Net income (loss) attributable to Quicksilver	$	(568,979	)	$	5,756		$	(63,397	)	$	57,641	$	(568,979	)	$	7,725		$	(7,725	)	$	(568,979	)



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

Net cash flow used for investing activities		(4,577	)		(130	)		(22,980	)		-		(27,687	)		(97,439	)		(3,487	)		(128,613	)
Issuance of debt		159,000			-			24,446			-		183,446			112,000			-			295,446
Repayments of debt		(193,000	)		-			(23,039	)		-		(216,039	)		(11,600	)		-			(227,639	)
Debt issuance costs		(109	)		-			-			-		(109	)		-			-			(109	)
Gas Purchase Commitment - net		(7,317	)		-			-			-		(7,317	)		-			-			(7,317	)
Issuance of KGS common units		-			-			-			-		-			11,050						11,050
Distributions to parent		-			-			-			-		-			(7,160	)		7,160			-
Distributions to noncontrolling interests		-			-			-			-		-			(4,404	)		-			(4,404	)
Proceeds from exercise of stock options		760			-			-			-		760			-			-			760
Treasury transactions - equity		(4,766	)		-			-			-		(4,766	)		(1,144	)		-			(5,910	)

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

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

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


	For the Three Months Ended March 31, 2009
				Restricted			Restricted			Restricted		Quicksilver			Unrestricted						Quicksilver
	Quicksilver			Guarantor			Non-Guarantor			Subsidiary		and Restricted			Non-Guarantor						Resources Inc.
	Resources Inc.			Subsidiaries			Subsidiaries			Eliminations		Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(In thousands)
Net cash flow provided by operations	$	117,347		$	67		$	28,425		$	-	$	145,839		$	10,229		$	(6,718	)	$	149,350
Purchases of property, plant and equipment		(204,006	)		(67	)		(28,959	)		-		(233,032	)		(22,952	)		-			(255,984	)
Proceeds from sales of property and equipment		416			-			-			-		416			-			-			416

Net cash flow used for investing activities		(203,590	)		(67	)		(28,959	)		-		(232,616	)		(22,952	)		-			(255,568	)
Issuance of debt		169,000			-			17,374			-		186,374			22,000			-			208,374
Repayments of debt		(83,645	)		-			(17,543	)		-		(101,188	)		-			-			(101,188	)
Debt issuance costs		(39	)		-			-			-		(39	)		-			-			(39	)
Distributions to parent		-			-			-			-		-			(6,718	)		6,718			-
Distributions to noncontrolling interests		-			-			-			-		-			(2,448	)		-			(2,448	)
Proceeds from exercise of stock options		11			-			-			-		11			-			-			11
Treasury transactions - equity		(623	)		-			-			-		(623	)		(63	)		-			(686	)

Net cash flow provided by (used for) financing activities		84,704			-			(169	)		-		84,535			12,771			6,718			104,024
Effect of exchange rates on cash		(61	)		-			(163	)		-		(224	)		-			-			(224	)

Net decrease in cash and equivalents		(1,600	)		-			(866	)		-		(2,466	)		48			-			(2,418	)
Cash and equivalents at beginning of period		1,679			-			866			-		2,545			303			-			2,848

Cash and equivalents at end of period	$	79		$	-		$	-		$	-	$	79		$	351		$	-		$	430

12. SEGMENT INFORMATION

We operate in two geographic segments, the United States and Canada, where we are engaged in the exploration and production segment of the oil and gas industry. Additionally, we operate in the midstream segment, where we provide natural gas processing and gathering services in the United States, predominantly through KGS. Revenue earned by KGS for the processing and gathering of Quicksilver gas are eliminated on a consolidated basis as are the costs of these services recognized by Quicksilver on producing properties. We evaluate performance based on operating income and property and equipment costs incurred.


	Exploration & Production				Processing &		Corporate						Quicksilver
	United States		Canada		Gathering		and Other			Elimination			Consolidated
	(in thousands)
For the Three Months Ended March 31, 2010
Revenue	$	182,500	$	35,849	$	25,803	$	-		$	(21,994	)	$	222,158
Depletion, depreciation and accretion		27,949		11,285		7,057		466			-			46,757
Operating income		72,279		13,433		11,123		(20,990	)		-			75,845
Property and equipment costs incurred		77,367		30,585		27,634		620			-			136,206


	Exploration & Production						Processing &		Corporate						Quicksilver
	United States			Canada			Gathering		and Other			Elimination			Consolidated
	(in thousands)
For the Three Months Ended March 31, 2009
Revenue	$	137,729		$	45,929		$	25,075	$	-		$	(22,801	)	$	185,932
Depletion, depreciation and accretion		44,250			10,293			4,827		326			-			59,696
Operating income		(739,359	)		(82,076	)		13,450		(17,707	)		-			(825,692	)
Property and equipment costs incurred		137,632			42,778			17,897		526			-			198,833

Property, Plant and Equipment-net
March 31, 2010	$	2,021,821		$	529,053		$	631,105	$	11,909		$	-		$	3,193,888
December 31, 2009		1,968,430			491,528			614,359		11,623			-			3,085,940

13. SUPPLEMENTAL CASH FLOW INFORMATION

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


	Three Months Ended
	March 31,
	2010			2009
	(In thousands)
Interest	$	50,025		$	46,325
Income taxes		(7,006	)		-

Other non-cash transactions include:


	Three Months Ended
	March 31,
	2010		2009
	(In thousands)
Working capital related to acquisition of property, plant and equipment	$	126,393	$	163,378

14. RELATED-PARTY TRANSACTIONS

As of March 31, 2010, members of the Darden family and entities controlled by them beneficially owned approximately 30% of our outstanding common stock. Thomas F. Darden, Glenn Darden and Anne Darden Self are officers and directors of Quicksilver.

Quicksilver and its associated entities paid $0.2 million in the first three months of both 2010 and 2009 for rent on buildings owned by entities affiliated with Mercury. Rental rates have been determined based on comparable rates charged by third parties.

We paid $0.1 million during the first three months of both 2010 and 2009 for use of an airplane owned by an entity controlled by members of the Darden family. Usage rates are determined based on comparable rates charged by third parties.

We paid $0.4 million in the first three months of 2009 for delay rentals under leases for over 5,000 acres held by a related party entity. The lease terms were determined based on comparable prices and terms granted to third parties with respect to similar leases in the area. No additional payments have been made in 2010.

Payments received from Mercury for sublease rentals, employee insurance coverage and administrative services during the first three months of 2010 and 2009 each totaled $0.1 million.

In connection with our lease of office space beginning in August 2010, an entity affiliated with Mercury expects to receive a $1.3 million commission from the lessor.

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

The following discussion and analysis of our consolidated financial condition and results of operations should be read in conjunction with our condensed consolidated financial statements, and notes thereto, and the other financial data included elsewhere in this quarterly report. The following discussion should also be read in conjunction with our audited consolidated financial statements, and notes thereto, and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in our 2009 Annual Report on Form 10-K.

EXECUTIVE OVERVIEW

We are an independent energy company engaged primarily in exploration, development and production of unconventional natural gas onshore in North America. We own producing oil and natural gas properties in the United States, principally in Texas, and in Alberta, Canada, where we had total estimated aggregate proved reserves of approximately 2.4 Tcfe at December 31, 2009. We also have properties in the Horn River Basin of Northeast British Columbia and the Green River Basin of Colorado where we are exploring for additional reserves, but have recognized only immaterial proved reserves based upon drilling activity to date. Additionally as of March 31, 2010, we own 61% of KGS, a publicly-traded midstream master limited partnership controlled and consolidated by us, and we own 40% of the limited partner units of BBEP, a publicly-traded oil and natural gas exploration and production master limited partnership, which we account for using the equity method.

2010 HIGHLIGHTS

BBEP Update

In April 2010, we finalized a global settlement agreement with BBEP and all other parties to our lawsuit whereby we subsequently received $18.0 million in cash. Pursuant to the agreement, we retained full voting rights for our units held in BBEP subject to the provisions of a limited standstill agreement and the ability to name two directors to the board of directors of BBEP’s general partner. BBEP also agreed to the reinstitution of the BBEP quarterly distributions and other governance accommodations. The $18.0 million settlement was recognized as non-operating income in the second quarter of 2010.

2010 CAPITAL OUTLOOK

Commodity prices, drilling and well completion costs and access to capital and services are the most significant drivers of our business. As of the date of this report, natural gas prices have remained depressed. We continue to focus on ways to optimize our 2010 program. We currently expect that our 2010 capital program will total approximately $510 million. Our focus remains on the continued development of our properties in the Barnett Shale and exploration in the Horn River and Greater Green River Basins. For 2010, we expect to spend approximately $440 million for exploration and development activities, $68 million for midstream facilities (including approximately $60 million to be funded directly by KGS) and approximately $2 million for other property and equipment. On a regional basis, approximately $440 million is forecasted to be spent in Texas to drill approximately 75 net wells on operated properties, to complete and tie-in approximately 112 net wells and to further develop our midstream infrastructure. Canadian spending for 2010 is forecasted to be approximately $60 million chiefly to explore the Horn River Basin and, to a lesser extent, to maintain current production levels. The remaining capital program is spread among our other operating areas. We expect the final 2010 capital program to be less than the cash inflows.

Our remaining 2010 capital program described above is dynamic and there are a number of factors that could affect our decision to invest capital. Commodity prices, well costs, hedging programs and program performance are a few factors that individually or in combination could change the scale or relative allocation of our remaining capital program for 2010.

RESULTS OF OPERATIONS – Three Months Ended March 31, 2010 and 2009

The following discussion compares the results of operations for the three months ended March 31, 2010 and 2009, or the 2010 quarter and 2009 quarter, respectively.

Natural Gas, NGL and Crude Oil Revenue

Production Revenue:


	Natural Gas				NGL					Oil and Condensate				Total
	2010		2009		2010			2009		2010		2009		2010		2009
	(In millions)
Texas	$	81.5	$	72.7	$	41.1		$	25.4	$	3.2	$	3.3	$	125.8	$	101.4
Other U.S.		1.2		0.1		0.1			-		2.3		1.3		3.6		1.4
Hedging		48.3		34.8		(9.6	)		-		-		-		38.7		34.8

Total U.S.		131.0		107.6		31.6			25.4		5.5		4.6		168.1		137.6
Canada		31.8		26.9		0.1			-		-		-		31.9		26.9
Hedging		1.6		19.0		-			-		-		-		1.6		19.0

Total Canada		33.4		45.9		0.1			-		-		-		33.5		45.9

Total Company	$	164.4	$	153.5	$	31.7		$	25.4	$	5.5	$	4.6	$	201.6	$	183.5

Average Daily Production Volumes:


	Natural Gas				NGL				Oil and Condensate				Equivalent Total
	2010		2009		2010		2009		2010		2009		2010		2009
	(MMcfd)				(Bbld)				(Bbld)				(MMcfed)
Texas		173.3		177.3		11,263		13,348		474		1,019		243.7		263.5
Other U.S.		2.3		0.3		17		-		381		475		4.8		3.1

Total U.S.		175.6		177.6		11,280		13,348		855		1,494		248.5		266.6
Canada		69.9		64.9		11		-		-		-		69.9		64.9

Total Company		245.5		242.5		11,291		13,348		855		1,494		318.4		331.5

Average Realized Prices:


	Natural Gas				NGL					Oil and Condensate				Equivalent Total
	2010		2009		2010			2009		2010		2009		2010		2009
	(per Mcf)				(per Bbl)					(per Bbl)				(per Mcfe)
Texas	$	5.23	$	4.56	$	40.51		$	21.13	$	73.63	$	36.24	$	5.73	$	4.28
Other U.S.		4.99		3.91		85.70			-		68.49		30.54		8.29		4.67
Hedging - U.S.		3.06		2.18		(9.43	)		-		-		-		1.73		1.45
Total U.S.		8.28		6.73		31.19			21.13		71.36		34.42		7.52		5.74
Canada		5.08		4.60		73.92			-		-		-		5.08		4.60
Hedging - Canada		0.24		3.26		-			-		-		-		0.24		3.26
Total Canada		5.32		7.86		73.92			-		-		-		5.32		7.86
Total Company	$	7.44	$	7.04	$	31.19		$	21.13	$	71.36	$	34.42	$	7.03	$	6.15

The following table summarizes the changes in our production revenue during the 2010 quarter compared with the 2009 quarter:


	Natural
	Gas			NGL			Oil			Total
	(In thousands)
Revenue for the quarter ended March 31, 2009	$	153,524		$	25,396		$	4,634		$	183,554
Volume variance		1,271			(3,922	)		(1,984	)		(4,635	)
Hedge settlement variance		(4,016	)		(9,573	)		-			(13,589	)
Price variance		13,600			19,790			2,843			36,233

Revenue for the quarter ended March 31, 2010	$	164,379		$	31,691		$	5,493		$	201,563

Increases in 2010 quarter natural gas market prices compared to the 2009 quarter were partially offset by a decrease in revenue from hedge settlements for 2010 as compared to the 2009 quarter. Canadian natural gas production increased primarily from new Horn River wells placed into service during the last half 2009. A slight decrease in U.S. natural gas volumes partially offset Canadian production increases. The 27.5% of our Alliance properties sold in June 2009 represented approximately 16.6 MMcfd of production in the 2009 quarter that was nearly offset by production from new wells placed into service in the Alliance area since the 2009 quarter. Additionally, two wells were placed into service in the Greater Green River Basin during the fourth quarter of 2009.

The increase in NGL revenue was due to increased market prices partially offset by payments made to settle hedges during the 2010 quarter production and a 16% decrease in Fort Worth Basin production for the 2010 quarter compared to the 2009 quarter. NGL production decreased primarily because we have focused our capital spending in areas of the Barnett Shale where dry natural gas is prevalent.

Oil and condensate revenue for the 2010 quarter increased due to higher prices partially offset by a decrease in production for the 2010 quarter when compared to the 2009 quarter.

Utilization of derivatives to hedge our sales of natural gas, NGL and crude oil may result in realized prices varying from market prices that we receive from the sale our production. Our production revenue from natural gas, NGL and oil production was $40.3 million and $53.8 million higher because of our hedging activities for the 2010 quarter and the 2009 quarter, respectively.

We expect our average production for the remainder of 2010 to range between 375 MMcfed to 385 MMcfed, which would result in average production of 360 MMcfed to 370 MMcfed for all of 2010.

Sales of Purchased Natural Gas and Costs of Purchased Natural Gas


	Three Months Ended
	March 31,
	2010			2009
	(In thousands)

Sales of purchased natural gas:
Purchases from Eni	$	12,578		$	-
Purchases from others		3,646			-

Total		16,224			-
Costs of purchased natural gas sold:
Purchases from Eni		12,518			-
Purchases from others		4,151			-
Unrealized valuation loss on Gas Purchase Commitment		16,638			-

Total		33,307			-

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

Our marketing activities related to the purchase and sale of natural gas have increased in Texas because of our natural gas sales and purchases made under the Gas Purchase Commitment. The Gas Purchase Commitment is more fully described in Note 2 to our condensed consolidated financial statements.

Other Revenue

Other revenue of $4.4 million for the 2010 quarter increased from the 2009 quarter primarily because of a $1.4 million gain from hedge ineffectiveness recognized in the 2010 quarter compared to a $1.1 million loss in the 2009 quarter.

Oil and Gas Production Expense


	Three Months Ended March 31,
	2010			2009
	(In thousands, except per unit amounts)
			Per			Per
Texas			Mcfe			Mcfe
Cash expense	$	23,389	$ 1.06	$	22,315	$ 0.94
Equity compensation		211	0.01		303	0.01

	$	23,600	$ 1.07	$	22,618	$ 0.95

Other U.S.
Cash expense	$	1,964	$ 4.58	$	1,832	$ 6.16
Equity compensation		41	0.10		50	0.17

	$	2,005	$ 4.68	$	1,882	$ 6.33

Total U.S.
Cash expense	$	25,353	$ 1.13	$	24,147	$ 1.01
Equity compensation		252	0.01		353	0.01

	$	25,605	$ 1.14	$	24,500	$ 1.02

Canada
Cash expense	$	10,057	$ 1.60	$	7,075	$ 1.21
Equity compensation		327	0.05		596	0.10

	$	10,384	$ 1.65	$	7,671	$ 1.31

Total Company
Cash expense	$	35,410	$ 1.24	$	31,222	$ 1.05
Equity compensation		579	0.02		949	0.03

	$	35,989	$ 1.26	$	32,171	$ 1.08

U.S. production expense increased $1.1 million despite an 8% decrease in Fort Worth Basin production during the 2010 quarter when compared to the 2009 quarter. The increase was primarily associated with the cost of operating additional compression and midstream assets in the Alliance area since the 2009 quarter.

Canadian production expense for the 2010 quarter increased from the 2009 quarter due to a $1.6 million increase from changes in U.S.-Canadian exchange rates for the 2010 quarter when compared to the 2009 quarter and the costs to operate our Horn River wells that were placed into production in the third and fourth quarters of 2009.

Production and Ad Valorem Taxes


	Three Months Ended March 31,
	2010				2009
	(In thousands, except per unit amounts)
			Per				Per
Production and ad valorem taxes			Mcfe				Mcfe
U.S.	$	7,737	$	0.35	$	3,942	$	0.16
Canada		746		0.12		424		0.07

Total production and ad valorem taxes	$	8,483	$	0.30	$	4,366	$	0.15

Ad valorem and production taxes in the Fort Worth Basin increased for the 2010 quarter approximately $2.7 million and $1.0 million, respectively when compared to the 2009 quarter. Ad valorem tax increases were primarily because of the addition of wells and midstream facilities placed into service over the past twelve months and the expiration of finite-lived tax abatements. Fort Worth Basin production tax increases were due to a 34% increase in realized prices before hedge settlements and a reduction in the number of new wells that qualified for exemptions or rate reductions.

Depletion, Depreciation and Accretion


	Three Months Ended March 31,
	2010				2009
	(In thousands, except per unit amounts)
			Per				Per
Depletion			Mcfe				Mcfe
U.S.	$	26,434	$	1.17	$	41,872	$	1.74
Canada		9,774		1.55		9,102		1.56

Total depletion		36,208		1.26		50,974		1.71
Depreciation of other fixed assets
U.S.	$	8,729	$	0.39	$	7,310	$	0.30
Canada		1,083		0.17		823		0.14

Total depreciation		9,812		0.34		8,133		0.27
Accretion		737		0.03		589		0.02

Total DD&A	$	46,757	$	1.63	$	59,696	$	2.00

Depletion expense for the 2010 quarter decreased from the 2009 quarter due to a decrease in depletion rates. Both our U.S. and Canadian depletion rates have been impacted by impairment charges. During 2009, total U.S and Canadian impairment charges of $786.9 million and $192.7 million were recognized during 2009 including $896.5 million in the 2009 quarter, which significantly reduced the depletion rates. Changes in the U.S.-Canadian dollar exchange rate and higher production volumes partially offset decreases in the Canadian depletion rate.

The increase in U.S. depreciation for the 2010 quarter as compared to the 2009 quarter was primarily associated with additions to U.S. field compression assets placed into service since March 31, 2009.

General and Administrative Expense


	Three Months Ended March 31,
	2010				2009
	(In thousands, except per unit amounts)
			Per				Per
General and administrative expense			Mcfe				Mcfe
Cash expense	$	15,658		$ 0.55	$	12,665		$ 0.42
Equity compensation		4,865		0.17		4,716		0.16

Total general and administrative expense	$	20,523		$ 0.72	$	17,381		$ 0.58

Higher compensation expense of $2.9 million, including a $0.1 million increase in stock-based compensation expense, accounted for most of the $3.1 million increase in general and administrative expense for the 2010 quarter when compared to the 2009 quarter. The remaining $0.3 million increase is attributable to a $0.7 million expense increase spread across several categories that was partially offset by a $0.5 million decrease in legal fees for the 2010 quarter.

BBEP-Related Income

During the 2010 quarter, we recognized a loss of $16.0 million for equity earnings from our investment in BBEP based upon its reported earnings for the quarter ended December 31, 2009 as compared to income of $102.1 million recognized in the 2009 quarter. BBEP continues to experience significant volatility in its net earnings due to changes in value of its derivative instruments for which it does not employ hedge accounting.

For the 2009 quarter, we performed an impairment analysis that utilized the March 31, 2009 closing price of $6.53 per BBEP unit, which resulted in an aggregate fair value of $139.4 million for the portion of BBEP units that we owned. The estimated fair value of our investment in BBEP was $102.1 million less than the $241.5 million carrying value of our investment in BBEP. The $102.1 million difference was recognized as an impairment charge during the 2009 quarter. A similar analysis was performed as of March 31, 2010, which resulted in no further impairment. Note 5 to the condensed consolidated financial statements contains additional information regarding our investment in BBEP.

Interest Expense


	Three Months Ended
	March 31,
	2010			2009
	(in thousands)
Interest costs	$	40,875		$	37,373
Add: Non-cash interest ⁽¹⁾		5,075			4,139
Less: Interest capitalized		(1,433	)		(1,311	)

Interest expense	$	44,517		$	40,201


⁽¹⁾		Amortization of deferred financing costs and original issue discounts

Interest costs for the 2010 quarter were higher than the 2009 quarter primarily because of an increase in our weighted average interest rates. The impact of higher interest rates was partially offset by proceeds from our interest rate swaps, which reduced interest costs by $6.5 million in the 2010 quarter.

Income Tax Expense


	Three Months Ended
	March 31,
	2010		2009
Income tax (benefit) expense (in thousands)	$	5,082	$	(297,823)
Effective tax rate		32.4%		34.4%

Our provision for income taxes for the 2010 quarter increased from the 2009 quarter due to higher income before taxes. The effective tax rate for the 2010 quarter was 32.4%, which we expect to be our effective income tax rate for all of 2010.

Quicksilver Resources Inc. and its Restricted Subsidiaries

Note 11 to our condensed consolidated financial statements contains information about the Company and its restricted and unrestricted subsidiaries.

The combined results of operations for the Company and its restricted subsidiaries are substantially similar to our consolidated results of operations, which are discussed above under Results of Operations. The combined financial position of the Company and its restricted subsidiaries and our consolidated financial position are materially the same except for the property, plant and equipment purchased by the unrestricted subsidiaries since the KGS initial public offering, the borrowings under the KGS Credit Facility and the equity of the unrestricted subsidiaries. The other balance sheet items are discussed below in “Financial Position.” The combined operating cash flows, financing cash flows and investing cash flows for the

Company and its restricted subsidiaries are substantially similar to our consolidated operating cash flows, financing cash flows and investing cash flows, which are discussed below in Liquidity, Capital Resources and Financial Condition.

LIQUIDITY, CAPITAL RESOURCES AND FINANCIAL CONDITION

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 significantly affected by instability in the credit and financial markets.


	Three Months Ended
	March 31,
	2010			2009
	(In thousands)
Net cash provided by operating activities	$	65,772		$	149,350
Net cash used for investing activities		(128,613	)		(255,568	)
Net cash provided by financing activities		61,877			104,024
Effect of exchange rate changes in cash		(220	)		(224	)

Operating Cash Flows

Net cash provided by operations for the 2010 quarter decreased $83.5 million from the comparable 2009 quarter primarily because of the absence of the 2009 receipt of $54.9 million from the early settlement of a 2010 commodity hedge and distributions of $11.1 million from BBEP. Additionally, the 2010 quarter included increased operating expenses and interest expense as compared to the 2009 quarter.

For the 2010 quarter, price collars and swaps covered natural gas production of 200 MMcfd and 10 MBbld of our NGL production. Our commodity derivative settlements resulted in increased production revenue of $40.3 million for the 2010 quarter. These price collars and swaps remain in place to hedge our anticipated natural gas production for the remainder of 2010. We have also hedged 120 MMcfd and 60 MMcfd of our anticipated natural gas production for 2011 and 2012 and 8 MBbld of our anticipated 2010 NGL production using natural gas price collars and NGL price swaps, respectively.

Investing Cash Flows

Our expenditures for property and equipment (payments for property and equipment plus non-cash changes in working capital associated with property and equipment) consisted of the following:


	Three Months Ended March 31,
	2010		2009
	(In thousands)
Exploration and development:
Texas	$	71,012	$	122,800
Other U.S.		4,780		14,563

Total U.S.		75,792		137,363
Canada		30,584		43,765

Total exploration and development		106,376		181,128
Midstream - Texas		27,634		16,906
Corporate and field office		2,196		799

Total plant and equipment costs incurred	$	136,206	$	198,833

Our capital expenditures for the 2010 quarter have decreased from the 2009 quarter principally due to our expenditures for the development of our Barnett Shale properties and Canadian CBM properties decreasing $51.8 million and $26.6 million, respectively. Our 2010 expenditures for exploration in the Horn River and Greater Green River Basins increased $3.6 million from the 2009 quarter. The increase in 2010 midstream capital expenditures reflects our focus, through KGS, on expansion of the infrastructure in the Alliance area in response to our 2009 development of the Alliance properties. We currently expect to spend approximately $510 million for capital expenditures for 2010.

Financing Cash Flows

During the 2010 quarter, we have made net payments of $32.6 million on the Senior Secured Credit Facility while KGS has increased borrowings $100.4 million under the KGS Credit Facility. As a result of the net cash activity under the Senior Secured Credit Facility and KGS Credit Facility and the effect of changes in U.S.-Canadian exchange rates on the balance outstanding under the Canadian portion of the Senior Secured Credit Facility, we have increased our outstanding balances under those facilities by $75.4 million. Lower spending on our capital program in the 2010 quarter resulted in lower borrowings compared to the 2009 and, consequently, lower financing cash inflows. We expect the lenders under our Senior Secured Credit Facility to reaffirm our $1.0 billion borrowing base during the second quarter of 2010.

At March 31, 2010, we had $443 outstanding under our $1 billion Senior Secured Credit Facility and KGS had $226 million outstanding under its credit facility.

Financial Position

The following summarizes the significant changes to our balance sheet as of March 31, 2010, as compared to our December 31, 2009 balance sheet:

•

Our current and non-current derivative assets and liabilities increased $113.7 million on a net basis. The valuation of our remaining open derivative positions increased as a result of natural gas price decreases relative to our commodity derivative pricing during the 2010 quarter. Our net open derivative position partially offset these increases $40.3 million because of monthly settlements during the 2010 quarter. Our current deferred income tax liability increased $20.1 million because of higher valuations for our open derivative positions.

•

Our net property, plant and equipment balance increased $107.9 million over the three-month period ended March 31, 2010. During the 2010 quarter, we have incurred $136.2 million for property, plant and equipment that has been partially offset by DD&A of $46.0 million. The remaining increase was due to the effects of changes in U.S.-Canadian exchange rates from December 31, 2009 to March 31, 2010.

Contractual Obligations and Commercial Commitments

As of March 31, 2010, our estimates of Eni Production covered by the Gas Purchase Commitment have been reduced 2.0 Bcf from December 31, 2009 estimates. At March 31, 2010, we estimated a remaining liability of $60.1 million, including an embedded derivative liability of $23.3 million. Valuation of the liability was based on the most recent estimate of 2010 Eni Production volumes and natural gas prices at March 31, 2010.

In April 2010, Quicksilver entered into a lease of office space with a term of 12 years that is scheduled to commence August 2010. Aggregate rentals over the life of the lease will total $29.8 million.

There have been no other significant changes to our contractual obligations and commercial commitments as disclosed in Item 7 in our 2009 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 2009 Annual Report on Form 10-K. These critical estimates, for which no significant changes occurred during the three months ended March 31, 2010, 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 of the estimates or assumptions. The estimates and assumptions could change materially as conditions within and beyond our control change. Accordingly, actual results could differ materially from those estimates.

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements within the meaning of Item 303(a)(4) of SEC Regulation S-K.

Recently Issued Accounting Standards

No pronouncements affecting our financial statements have been issued since the filing of our 2009 Annual Report on Form 10-K.


ITEM 3.		Quantitative and Qualitative Disclosures About Market Risk

We have established policies and procedures for managing risk within our organization, including internal controls. The level of risk assumed by us is based on our objectives and capacity to manage risk.

Our primary risk exposure is from fluctuations in natural gas, oil and NGL commodity prices. We have mitigated the risk of adverse price movements with swaps and collars; however, we have also limited future gains from favorable price movements.

Commodity Price Risk

We enter into financial derivative contracts to mitigate our exposure to commodity price risk associated with anticipated future natural gas, NGL and crude oil production. Our financial derivative contracts result in more predictability of our natural gas, NGL and crude oil revenue. As of March 31, 2010, natural gas price collars of 200 MMcfd and 10 MBbld of NGL price swaps are in place to hedge a portion of our anticipated production for the remainder of 2010. Anticipated 2011 natural gas and NGL production has been hedged with 120 MMcfd of natural gas price collars and 8 MBbld of NGL price swaps. We also have 60 MMcfd of natural gas price collars in place to hedge a portion of our 2012 anticipated natural gas production.

Utilization of our hedging program may result in natural gas, NGL and crude oil realized prices varying from market prices that we receive from the sale of natural gas, NGL and crude oil. Our revenue from natural gas, NGL and crude oil production was $40.3 million higher because of our hedging program for the 2010 quarter. Other revenue was $1.4 million higher as a result of derivative and hedging ineffectiveness for the 2010 quarter.

The following table summarizes our commodity derivative positions as of March 31, 2010:

Weighted Avg

Remaining Contract

Price Per Mcf or

Product

Type

Period

Volume

Bbl

Fair Value

(In thousands)

Gas

Collar

Apr 2010-Dec 2010

20 MMcfd

8.00-11.00

20,599

Gas

Collar

Apr 2010-Dec 2010

20 MMcfd

8.00-11.00

20,599

Gas

Collar

Apr 2010-Dec 2010

20 MMcfd

8.00-12.20

20,606

Gas

Collar

Apr 2010-Dec 2010

20 MMcfd

8.00-12.20

20,606

Gas

Collar

Apr 2010-Dec 2010

10 MMcfd

8.50-12.05

11,663

Gas

Collar

Apr 2010-Dec 2010

20 MMcfd

8.50-12.05

23,326

Gas

Collar

Apr 2010-Dec 2010

10 MMcfd

8.50-12.08

11,670

Gas

Collar

Apr 2010-Dec 2011

10 MMcfd

6.00- 7.00

8,134

Gas

Collar

Apr 2010-Dec 2011

10 MMcfd

6.00- 7.00

8,134

Gas

Collar

Apr 2010-Dec 2011

20 MMcfd

6.00- 7.00

16,269

Gas

Collar

Apr 2010-Dec 2012

20 MMcfd

6.50- 7.15

28,004

Gas

Collar

Apr 2010-Dec 2012

20 MMcfd

6.50- 7.18

28,018

Gas

Collar

Jan 2011-Dec 2011

10 MMcfd

6.25- 7.50

4,107

Gas

Collar

Jan 2011-Dec 2011

10 MMcfd

6.25- 7.50

4,107

Gas

Collar

Jan 2011-Dec 2011

20 MMcfd

6.25- 7.50

8,215

Gas

Collar

Jan 2012-Dec 2012

20 MMcfd

6.50- 8.01

7,285

Gas

Basis

Apr 2010-Dec 2010

20 MMcfd

⁽¹

⁾

(765

)

Gas

Basis

Apr 2010-Dec 2010

20 MMcfd

⁽¹

⁾

(765

)

Gas

Basis

Apr 2010-Dec 2010

10 MMcfd

⁽²

⁾

(19

)

Gas

Basis

Apr 2010-Dec 2010

10 MMcfd

⁽²

⁾

(31

)

Gas

Basis

Apr 2010-Dec 2010

20 MMcfd

⁽²

⁾

(309

)

Gas

Basis

Jan 2011-Dec 2011

10 MMcfd

⁽¹

⁾

286

Gas

Basis

Jan 2011-Dec 2011

10 MMcfd

⁽¹

⁾

286

Gas

Basis

Jan 2011-Dec 2011

20 MMcfd

⁽¹

⁾

572

NGL

Swap

Apr 2010-Dec 2010

2 MBbld

32.65

(3,273

)

NGL

Swap

Apr 2010-Dec 2010

3 MBbld

32.98

(4,576

)

NGL

Swap

Apr 2010-Dec 2010

1 MBbld

33.63

(1,367

)

NGL

Swap

Apr 2010-Dec 2010

1 MBbld

34.15

(1,225

)

NGL

Swap

Apr 2010-Dec 2010

3 MBbld

34.22

(3,554

)

NGL

Swap

Jan 2011-Dec 2011

3 MBbld

36.06

(909

)

NGL

Swap

Jan 2011-Dec 2011

2 MBbld

36.31

(438

)

NGL

Swap

Jan 2011-Dec 2011

3 MBbld

41.95

5,463

Total

230,718


⁽¹⁾		AECO Basis swaps hedge the AECO basis adjustment for 40 MMcfd at a deduction of $0.45 per Mcf from NYMEX for the remainder of 2010 and 40 MMcfd at a deduction of $0.39 Mcf from NYMEX for 2011.

⁽²⁾		Basis swaps for 40 MMcfd hedge the Houston Ship Channel basis adjustment at a weighted average deduction of $0.067 Mcf from NYMEX for the remainder of 2010.

We have entered into no new commodity derivatives positions since March 31, 2010.

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, 2010, our disclosure controls and procedures were effective to provide reasonable assurance that material information required to be disclosed by us (including our consolidated subsidiaries) in reports that we file or submit under the Securities Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

PART II. OTHER INFORMATION

ITEM 1. Legal Proceedings

On April 5, 2010, we entered into a global settlement agreement with BBEP and all parties to the BBEP litigation on the same terms as the February 3, 2010 settlement agreement disclosed in our 2009 Annual Report on Form 10-K. Pursuant to that agreement, the District Court entered its Final Judgment and Order of Dismissal on April 6, 2010.

There have been no other material changes in legal proceedings from those described in Part I, Item 3 included in our 2009 Annual Report on Form 10-K.

ITEM 1A. Risk Factors

There have been no material changes in risk factors from those described in Item 1A of our 2009 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, 2010.



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

January 2010		269,007	$	15.01		-		-
February 2010		46,939	$	14.96		-		-
March 2010		1,850	$	14.11		-		-


Total		317,796	$	15.00		-		-


⁽¹⁾		Represents shares of common stock surrendered by employees to satisfy our income tax withholding obligations arising upon the vesting of restricted stock issued under our Amended and Restated 1999 Stock Option and Retention Stock Plan or Amended and Restated 2006 Equity Plan.

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

ITEM 3. Defaults Upon Senior Securities

None.

ITEM 4. [Removed and Reserved]

ITEM 5. Other Information

None.

ITEM 6. Exhibits:


Exhibit No.		Description
* 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.


*		Filed herewith


PART I. FINANCIAL INFORMATION

Item 1. Condensed Consolidated Interim Financial Statements (Unaudited)

Condensed Consolidated Statements of Income (Loss) and Comprehensive Income (Loss)

Condensed Consolidated Balance Sheets

Condensed Consolidated Statements of Equity

Condensed Consolidated Statements of Cash Flows

Notes to Condensed Consolidated Interim Financial Statements

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Item 4. Controls and Procedures

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

Item 1A. Risk Factors

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

Item 3. Defaults Upon Senior Securities

Item 4. [Removed and Reserved]

Item 5. Other Information

Item 6. Exhibits

Signature
EX-31.1
EX-31.2
EX-32.1

Large accelerated filer þ

Accelerated filer o

Non-accelerated filer o

Smaller reporting company o

(Do not check if a smaller reporting company)


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