Quicksilver Resources (KWK) 10-Q 2010 Q2 Quarterly report

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

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2010

or

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.  Yesþ Noo

     Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yesþ Noo

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

Large accelerated filerþ	Accelerated filero	Non-accelerated filero	Smaller reporting companyo
	(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yeso Noþ

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

Title of Class	Outstanding as of July 30, 2010
Common Stock, $0.01 par value	170,355,422

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

“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

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.

“Crestwood” means Crestwood Midstream Partners, LP and its affiliates

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

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

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

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

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

“Gas Purchase Commitment” means the commitment pursuant to the Eni Transaction to purchase 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

“Lake Arlington Project”means our natural gas leasehold and royalty interests in Tarrant County that we have developed and also includes an additional 25% working interest we purchased on May 11, 2010

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

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“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

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QUICKSILVER RESOURCES INC.
INDEX TO FORM 10-Q
For the Period Ending June 30, 2010

 EX-31.1

 EX-31.2

 EX-32.1

 EX-101 INSTANCE DOCUMENT

 EX-101 SCHEMA DOCUMENT

 EX-101 CALCULATION LINKBASE DOCUMENT

 EX-101 LABELS LINKBASE DOCUMENT

 EX-101 PRESENTATION LINKBASE DOCUMENT

 EX-101 DEFINITION LINKBASE DOCUMENT

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

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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 and8-K.  All such risk factors are difficult to predict, and are subject to material uncertainties that may affect actual results and may be beyond our control.  The forward-looking statements included in this 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.

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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						For the Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
Revenue
Natural gas, NGL and oil	$	211,687		$	199,315		$	413,250		$	382,869
Sales of purchased natural gas		16,821			5,217			33,045			5,217
Other		62			1,509			4,433			3,887
Total revenue		228,570			206,041			450,728			391,973
Operating expense
Oil and gas production expense		38,202			31,703			74,191			63,874
Production and ad valorem taxes		8,889			7,441			17,372			11,807
Costs of purchased natural gas		3,756			8,582			37,063			8,582
Other operating costs		970			1,744			2,224			3,271
Depletion, depreciation and accretion		50,669			50,966			97,426			110,662
General and administrative		17,217			24,389			37,740			41,770
Total expense		119,703			124,825			266,016			239,966
Impairment related to oil and gas properties		-			(70,643	)		-			(967,126	)
Operating income (loss)		108,867			10,573			184,712			(815,119	)
Income from earnings of BBEP - net		23,168			19,016			7,179			19,016
Other income (expense) - net		53,050			(855	)		53,393			(94	)
Interest expense		(46,122	)		(68,081	)		(90,639	)		(108,282	)
Income (loss) before income taxes		138,963			(39,347	)		154,645			(904,479	)
Income tax (expense) benefit		(48,219	)		18,897			(53,301	)		316,720
Net income (loss)		90,744			(20,450	)		101,344			(587,759	)
Net income attributable to noncontrolling interests		(3,941	)		(1,312	)		(6,353	)		(2,982	)
Net income (loss) attributable to Quicksilver	$	86,803		$	(21,762	)	$	94,991		$	(590,741	)
Other comprehensive income (loss) - net of income tax
Reclassification adjustments related to settlements of derivative contracts		(46,089	)		(60,073	)		(72,358	)		(96,987	)
Net change in derivative fair value		14,087			3,701			112,693			112,304
Foreign currency translation adjustment		(9,715	)		14,007			(2,755	)		6,782
Comprehensive income (loss)	$	45,086		$	(64,127	)	$	132,571		$	(568,642	)
Earnings (loss) per common share - basic	$	0.51		$	(0.13	)	$	0.56		$	(3.50	)
Earnings (loss) per common share - diluted	$	0.49		$	(0.13	)	$	0.54		$	(3.50	)
Basic weighted average shares outstanding		170,290			169,009			170,225			168,894
Diluted weighted average shares outstanding		180,872			169,009			180,855			168,894

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

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

	June 30,			December 31,
	2010			2009
ASSETS
Current assets
Cash and cash equivalents	$	3,308		$	1,785
Accounts receivable - net of allowance for doubtful accounts		42,595			65,253
Derivative assets at fair value		138,871			97,957
Other current assets		63,137			54,943
Total current assets		247,911			219,938
Investment in BBEP		92,956			112,763
Property, plant and equipment
Oil and gas properties, full cost method (including unevaluated costs of $375,100 and $458,037, respectively)		2,613,688			2,338,244
Other property and equipment		769,214			747,696
Property, plant and equipment - net		3,382,902			3,085,940
Derivative assets at fair value		67,763			14,427
Deferred income taxes		73,083			133,051
Other assets		42,084			46,763
	$	3,906,699		$	3,612,882
LIABILITIES AND EQUITY
Current liabilities
Accounts payable	$	122,400		$	157,986
Accrued liabilities		156,639			156,604
Derivative liabilities at fair value		-			395
Deferred income taxes		54,888			51,675
Total current liabilities		333,927			366,660
Long-term debt		2,586,923			2,427,523
Asset retirement obligations		61,634			59,268
Other liabilities		30,396			20,691
Deferred income taxes		49,037			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; 175,496,888 and 174,469,836 shares issued, respectively		1,755			1,745
Paid in capital in excess of par value		748,405			730,265
Treasury stock of 5,025,337 and 4,704,448 shares, respectively		(41,167	)		(36,363	)
Accumulated other comprehensive income		158,916			121,336
Retained deficit		(85,994	)		(180,985	)
Quicksilver stockholders’ equity		781,915			635,998
Noncontrolling interests		62,867			60,824
Total equity		844,782			696,822
	$	3,906,699		$	3,612,882

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

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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)		-		-		-			-			(590,741	)		2,982			(587,759	)
Hedge derivative contract settlements reclassified into earnings from accumulated other comprehensive income, net of income tax of $45,138		-		-		-			(96,987	)		-			-			(96,987	)
Net change in derivative fair value, net of income tax of $53,212		-		-		-			112,304			-			-			112,304
Foreign currency translation adjustment		-		-		-			6,782			-			-			6,782
Issuance and vesting of stock compensation		22		10,389		(627	)		-			-			812			10,596
Stock option exercises		-		80		-			-			-			-			80
Distributions paid on KGS common units		-		-		-			-			-			(4,896	)		(4,896	)
Balances at June 30, 2009	$	1,739	$	667,427	$	(36,068	)	$	207,203		$	(214,253	)	$	25,635		$	651,683
Balances at December 31, 2009	$	1,745	$	730,265	$	(36,363	)	$	121,336		$	(180,985	)	$	60,824		$	696,822
Net income		-		-		-			-			94,991			6,353			101,344
Hedge derivative contract settlements reclassified into earnings from accumulated other comprehensive income, net of income tax of $38,226		-		-		-			(72,358	)		-			-			(72,358	)
Net change in derivative fair value, net of income tax of $56,906		-		-		-			112,693			-			-			112,693
Foreign currency translation adjustment		-		-		-			(2,755	)		-			-			(2,755	)
Issuance and vesting of stock compensation		8		10,187		(4,804	)		-			-			190			5,581
Stock option exercises		2		1,207		-			-			-			-			1,209
Issuance of KGS common units		-		6,746		-			-			-			4,308			11,054
Distributions paid on KGS common units		-		-		-			-			-			(8,808	)		(8,808	)
Balances at June 30, 2010	$	1,755	$	748,405	$	(41,167	)	$	158,916		$	(85,994	)	$	62,867		$	844,782

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

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

	For the Six Months Ended
	June 30,
	2010			2009
Operating activities:
Net income (loss)	$	101,344		$	(587,759	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation and accretion		97,426			110,662
Impairment related to oil and gas properties		-			967,126
Deferred income tax expense (benefit)		52,243			(331,321	)
Stock-based compensation		11,529			11,223
Non-cash (gain) loss from hedging and derivative activities		(27,852	)		5,544
Non-cash interest expense		10,178			35,848
Non-cash gain on sale of BBEP units		(35,426	)		-
(Income) loss from BBEP in excess of cash distributions, net of impairment		826			(7,915	)
Other		(469	)		420
Changes in assets and liabilities
Accounts receivable		22,858			89,580
Derivative assets at fair value		18,682			54,896
Other assets		(11,144	)		(4,266	)
Accounts payable		(20,169	)		(25,864	)
Accrued and other liabilities		26,481			(7,833	)
Net cash provided by operating activities		246,507			310,341
Investing activities:
Purchases of property, plant and equipment		(356,402	)		(441,184	)
Proceeds from sales of property and equipment		864			233,488
Net cash used for investing activities		(355,538	)		(207,696	)
Financing activities:
Issuance of debt		540,032			1,020,750
Repayments of debt		(409,613	)		(1,144,031	)
Debt issuance costs paid		(109	)		(22,802	)
Gas Purchase Commitment assumed		-			46,628
Gas Purchase Commitment repayments		(16,592	)		-
Issuance of KGS common units - net of offering costs		11,054			-
Distributions paid on KGS common units		(8,808	)		(4,896	)
Proceeds from exercise of stock options		1,209			80
Taxes paid by KGS for equity-based compensation vesting		(1,144	)		(63	)
Purchase of treasury stock for stock-based compensation vesting		(4,804	)		(627	)
Net cash provided by (used for) financing activities		111,225			(104,961	)
Effect of exchange rate changes in cash		(671	)		125
Net increase (decrease) in cash and cash equivalents		1,523			(2,191	)
Cash and cash equivalents at beginning of period		1,785			2,848
Cash and cash equivalents at end of period	$	3,308		$	657

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

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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 June 30, 2010 and our results of operations for the three and six months ended June 30, 2010 and 2009 and cash flows for the six months ended June 30, 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 materially 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

     The following table shows the level of inputs used in our fair value calculations of our derivative instruments at June 30, 2010 and December 31, 2009:

	Significant Other Observable
	Inputs - Level 2
	June 30,			December 31,
	2010			2009
	(in thousands)
Commodity contracts	$	193,394		$	107,881
Interest rate contracts		13,240			4,108
Gas Purchase Commitment		(6,161	)		(6,625	)
Total	$	200,473		$	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.

Commodity Price Derivatives

     As of June 30, 2010, we had price collars and fixed price swaps that hedge 200 MMcfd, 150 MMcfd and 90 MMcfd of our anticipated natural gas production for 2010, 2011 and 2012, respectively. We also have fixed price swaps that hedge 30 MMcfd of our anticipated natural gas production for 2013 through 2015. A portion of our anticipated 2010 and 2011 NGL production has been hedged with fixed price swaps that cover 10 MBbld and 8 MBbld, respectively.

     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. Additional derivatives entered into further increased the carrying value. Monthly settlements received during 2010 have partially offset these increases.

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Interest Rate Derivatives

     In February 2010, we executed the early settlement of the 2009 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 interest previously accrued and earned, and recognized an adjustment of $14.3 million to the carrying value of the debt. In February 2010, we entered into new interest swaps to hedge the same debt instruments. In May 2010, we executed an early settlement of a portion of the 2010 interest rate swaps. We received cash of $6.8 million in the settlement, including $2.4 million for interest previously accrued and earned, and recognized an additional adjustment of $4.4 million to the carrying value of the debt. These two settlements, totaling $18.7 million, 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)	$	2,263
2011		2,899
2012		3,142
2013		3,404
2014		3,689
2015		2,908
2016		377
	$	18,682

    ⁽¹⁾ Through June 30, 2010, we have recognized $0.9 million of the early settlements as a reduction of interest expense.

     As of June 30, 2010, our remaining interest swaps, entered into during February 2010, cover $295 million of our senior notes due 2015 and $155 million of our senior subordinated notes. The interest rate swaps 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 remaining 2010 interest rate swaps qualify for accounting treatment as fair value hedges. The value of the remaining 2010 interest rate swaps, excluding the net interest accrual, amounted to a net asset of $13.2 million as of June 30, 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 remaining 2010 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 open interest rate swaps, were approximately 5.52% and 4.25%, respectively, for the first half of 2010.

     In July 2010, we executed the early settlement of our remaining 2010 interest rate swaps. We received cash of $16.7 million, including $4.6 million for interest previously accrued and earned. We will recognize the remaining $12.1 million as an adjustment to the carrying value of the debt that will be recognized as a reduction of interest expense over the life of the associated underlying debt instruments.

Gas Purchase Commitment

     The Gas Purchase Commitment, which is effective through December 31, 2010, contains an embedded derivative revalued for changes to estimated volumes and prices from June 19, 2009 to June 30, 2010. At June 30, 2010, we have estimated the remaining liability at $33.7 million, including an embedded derivative liability for cumulative changes in estimates since inception of $6.2 million. The derivative reflects a 3.3 Bcf reduction of the total estimated volumes we expect to purchase under the commitment offset by a decrease in market prices over the remaining commitment period compared with our December 31, 2009 estimate. The following summarizes 2010 activity to the Gas Purchase Commitment:

(In thousands)
Liability fair value at December 31, 2009	$	50,744
Decrease due to gas volumes purchased		(16,592	)
Embedded derivative increase (decrease) due to:
Price changes		8,930
Volume changes		(9,394	)
Total increase (decrease) in embedded derivative		(464	)
Liability fair value at June 30, 2010(1)	$	33,688

    ⁽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 June 30, 2010.

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     The estimated fair value of our derivatives at June 30, 2010 and December 31, 2009 were as follows:

	Asset Derivatives				Liability Derivatives
	June 30,		December 31,		June 30,		December 31,
	2010		2009		2010		2009
	(In thousands)				(In thousands)
Derivatives designated as hedges:
Commodity contracts reported in:
Current derivative assets	$	137,473	$	97,883	$	1,107	$	638
Noncurrent derivative assets		57,028		11,031		-		-
Current derivative liabilities		-		243		-		638
Interest rate contracts reported in:
Current derivative assets		2,505		712		-		-
Noncurrent derivative assets		10,735		3,396		-		-
Total derivatives designated as hedges	$	207,741	$	113,265	$	1,107	$	1,276
Derivatives not designated as hedges:
Gas Purchase Commitment reported in accrued liabilities	$	-	$	-	$	6,161	$	6,625
Total derivatives not designated as hedges	$	-	$	-	$	6,161	$	6,625
Total derivatives	$	207,741	$	113,265	$	7,268	$	7,901

     The changes in the carrying value of our derivatives for the three and six months ended June 30, 2010 and 2009 are presented below:

	For the Three Months Ended June 30, 2010
	Gas Purchase			Interest Rate			Commodity
	Commitment			Swaps			Hedges			Total
	(In thousands)
Derivative fair value at March 31, 2010	$	(23,263	)	$	(5,030	)	$	230,718		$	202,425
Net change in amounts receivable/payable		-			209			1,362			1,571
Net settlements reported in revenue		-			-			(57,076	)		(57,076	)
Net settlements reported in interest expense		-			(4,267	)		-			(4,267	)
Cash settlements reported in long-term debt		-			(4,422	)		-			(4,422	)
Change in fair value of Gas Purchase Commitment
reported in costs of purchased gas		17,102			-			-			17,102
Change in fair value of effective interest swaps		-			26,750			-			26,750
Ineffectiveness reported in other revenue		-			-			(2,983	)		(2,983	)
Unrealized gains reported in OCI		-			-			21,373			21,373
Derivative fair value at June 30, 2010	$	(6,161	)	$	13,240		$	193,394		$	200,473

	For the Three Months Ended June 30, 2009
	Gas Purchase			Interest Rate			Commodity
	Commitment			Swaps			Hedges			Total
	(In thousands)
Derivative fair value at March 31, 2009	$	-		$	-		$	342,323		$	342,323
Net change in amounts receivable/payable		-			768			-			768
Net settlements reported in revenue		-			-			(88,261	)		(88,261	)
Change in fair value of Gas Purchase Commitment
reported in costs of purchased gas		(3,818	)		-			-			(3,818	)
Change in fair value of effective interest swaps		-			(1,034	)		-			(1,034	)
Ineffectiveness reported in other revenue		-			-			(598	)		(598	)
Unrealized gains reported in OCI		-			-			4,083			4,083
Derivative fair value at June 30, 2009	$	(3,818	)	$	(266	)	$	257,547		$	253,463

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	For the Six Months Ended June 30, 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		-			(4,788	)		(861	)		(5,649	)
Net settlements reported in revenue		-			-			(81,633	)		(81,633	)
Net settlements reported in interest expense		-			(6,237	)		-			(6,237	)
Cash settlements reported in long-term debt		-			(18,682	)		-			(18,682	)
Change in fair value of Gas Purchase Commitment reported in costs of purchased gas		464			-			-			464
Change in fair value of effective interest swaps		-			38,839			-			38,839
Ineffectiveness reported in other revenue		-			-			(1,588	)		(1,588	)
Cash settlement reported in OCI		-			-			-			-
Unrealized gains reported in OCI		-			-			169,595			169,595
Derivative fair value at June 30, 2010	$	(6,161	)	$	13,240		$	193,394		$	200,473

	For the Six Months Ended June 30, 2009
	Michigan			Gas Purchase			Interest Rate			Commodity
	Contract			Commitment			Swaps			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	)		-			768			-			(2,750	)
Net settlements		16,479			-			-			-			16,479
Net settlements reported in revenue		-			-			-			(142,125	)		(142,125	)
Change in fair value of Gas Purchase Commitment reported in costs of purchased gas		-			(3,818	)		-			-			(3,818	)
Change in fair value of effective interest swaps		-			-			(1,034	)		-			(1,034	)
Ineffectiveness reported in other revenue		(60	)		-			-			(1,666	)		(1,726	)
Cash settlement reported in OCI		-			-			-			(54,896	)		(54,896	)
Unrealized gains reported in OCI		-			-			-			165,516			165,516
Derivative fair value at June 30, 2009	$	-		$	(3,818	)	$	(266	)	$	257,548		$	253,464

     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 $89.4 million net of income taxes. An additional $17.4 million, net of income taxes, remains from the early settlement of the 2010 natural gas collar settled in 2009 and will be reclassified from AOCI into revenue during the remainder of 2010. Hedge derivative ineffectiveness resulted in losses of $1.6 million and $1.7 million recorded in other revenue for the six months ended June 30, 2010 and 2009, respectively.

3. INVESTMENT IN BREITBURN ENERGY PARTNERS L.P.

     We own approximately 17.7 million common units, or 33%, of BBEP, a publicly traded limited partnership, whose price closed at $14.93 per unit at June 30, 2010. Note 4 contains additional information regarding the use of 3.6 million BBEP common units as partial consideration in the acquisition of oil and gas properties in May 2010.

13

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

	For the Three Months Ended				For the Six Months Ended
	March 31,				March 31,
	2010		2009		2010			2009
	(In thousands)
Revenues(1)	$	133,166	$	127,939	$	171,429		$	571,186
Operating expenses		69,277		74,243		142,549			240,039
Operating income (loss)		63,889		53,696		28,880			331,147
Interest and other(2)		5,835		6,871		11,694			32,470
Income tax (benefit) expense		144		468		(1,030	)		1,145
Noncontrolling interests		71		7		90			20
Net income attributable to BBEP	$	57,839	$	46,350	$	18,126		$	297,512

(1)	The three months ended March 31, 2010 and 2009 include commodity derivative unrealized gains of $39.9 million and unrealized losses of $4.1 million, respectively. The six months ended March 31, 2010 and 2009 include commodity derivative unrealized losses of $14.8 million and unrealized gains $342.3 million, respectively.
(2)	The three months ended March 31, 2010 and 2009 include interest rate swap derivative unrealized gains of $0.7 million and $1.0 million, respectively. The six months ended March 31, 2010 and 2009 include interest rate swap derivative unrealized gains of $2.4 million and $11.1 million, respectively.

	As of		As of
	March 31,		December 31,
	2010		2009
	(In thousands)
Current assets	$	155,455	$	142,441
Property, plant and equipment		1,728,086		1,741,089
Other assets		98,523		87,499
Current liabilities		88,691		91,890
Long-term debt		523,000		559,000
Other non-current liabilities		79,604		91,338
Total equity		1,290,769		1,228,801

     For the six months ended June 30, 2010, we recognized income of $7.2 million, or approximately 40%, of BBEP’s income for the six months ended March 31, 2010. For the comparable 2009 period, we recognized income of $121.1 million and impairment expense of $102.1 million.

     Changes in the balance of our investment in BBEP for the six months ended June 30, 2010 were as follows:

(In thousands, except unit data)
Balance at December 31, 2009	$	112,763
Equity income from BBEP		7,179
Distributions from BBEP		(8,005	)
Conveyance of 3,619,901 BBEP units		(18,981	)
Balance at June 30, 2010	$	92,956

     Note 7 contains additional information regarding the April 2010 settlement of our lawsuit against BBEP and other parties.

14

4.  PROPERTY, PLANT AND EQUIPMENT

     Property, plant and equipment consisted of the following:

	June 30,			December 31,
	2010			2009
	(In thousands)
Oil and gas properties
Subject to depletion	$	4,376,233		$	3,947,676
Unevaluated costs		375,100			458,037
Accumulated depletion		(2,137,645	)		(2,067,469	)
Net oil and gas properties		2,613,688			2,338,244
Other plant and equipment
Pipelines and processing facilities		799,045			767,430
General properties		72,035			68,698
Construction in progress		23,533			17,693
Accumulated depreciation		(125,399	)		(106,125	)
Net other property and equipment		769,214			747,696
Property, plant and equipment, net of
accumulated depletion and depreciation	$	3,382,902		$	3,085,940

Ceiling Test Analysis

     Our U.S. and Canadian ceiling tests for the first and second quarters of 2010 resulted in no impairment of our U.S. or Canadian oil and gas properties.  The ceiling limitations were determined using internally prepared proved reserve reports using the unweighted average of the preceding 12-month first-day-of-the-month prices for natural gas, NGL and oil.

     In the first half of 2009, we recorded impairments of our U.S. and Canadian oil and gas properties that totaled $786.9 million and $109.6 million, respectively.  Lower period-end benchmark prices for natural gas, oil and NGL prices at March 31, 2009 and June 30, 2009 were the primary factor contributing to a reduction of the U.S. and Canadian ceiling limitations at March 31, 2009 and the Canadian ceiling limit at June 30, 2009.

     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.

Lake Arlington Acquisition

     On May 11, 2010, we completed the acquisition of an additional 25% working interest in our company-operated Lake Arlington Project.  We acquired the Lake Arlington assets, subject to customary adjustments as provided in the purchase and agreement, for which we conveyed $62.0 million in cash and 3,619,901 BBEP common units we had previously owned with a market value of $54.4 million to the seller on the date of closing.  We recognized a gain of $35.4 million as other income for the difference between our carrying value of $5.24 per BBEP unit and the fair value of $15.03 per BBEP unit.  We expect to finalize adjustments to the purchase price in the third quarter of 2010.

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5.  LONG-TERM DEBT

     Long-term debt consisted of the following:

	June 30,		December 31,
	2010		2009
	(In thousands)
Senior Secured Credit Facility	$	493,234	$	467,569
Senior notes due 2015, net of unamortized discount		470,415		469,964
Senior notes due 2016, net of unamortized discount		582,448		581,359
Senior notes due 2019, net of unamortized discount		293,254		293,004
Senior subordinated notes due 2016		350,000		350,000
Convertible debentures, net of unamortized discount		139,736		136,119
KGS credit agreement		226,800		125,400
Total debt		2,555,887		2,423,415
Unamortized deferred gain - terminated interest rate swaps		17,796		-
Fair value - interest rate swaps		13,240		4,108
Long-term debt	$	2,586,923	$	2,427,523

Senior Secured Credit Facility

     The $1.0 billion borrowing base on our Senior Secured Credit Facility was re-affirmed in May 2010.

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.  In the event of conversion, we have the option to deliver either Quicksilver common stock, cash, or any combination thereof.  Should all debentures be converted to Quicksilver common stock, an additional 9,816,270 shares would become outstanding; however, as of July 1, 2010, the debentures were not convertible based on share prices for the quarter ended June 30, 2010.

     At June 30, 2010 and December 31, 2009, the remaining unamortized discount on the debentures was $10.3 million and $13.9 million, respectively, resulting in a carrying value of $139.7 million and $136.1 million, respectively.  The remaining discount will be accreted to face value through October 2011.  For the six months ended June 30, 2010 and 2009, interest expense on our convertible debentures, recognized at an effective interest rate of 6.75%, was $5.0 million and $4.8 million, respectively, including contractual interest of $1.4 million for each period.

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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(2)

Equal priority

Senior Secured

2015

2016

2019

Senior

Convertible

KGS Credit

Credit Facility

Senior Notes

Senior Notes

Senior Notes

Subordinated Notes

Debentures

Agreement

Scheduled maturity date

February 9, 2012

August 1, 2015

January 1, 2016

August 15, 2019

April 1, 2016

November 1, 2024

August 10, 2012

Interest rate at June 30, 2010(3)

3.44%

8.25%

11.75%

9.125%

7.125%

1.875%

3.49%

Base interest rate options(4)

LIBOR, ABR or specified(5)

N/A

N/A

N/A

N/A

N/A

LIBOR, ABR or specified(6)

Financial covenants(7)

- Minimum current ratio of 1.0

N/A

N/A

N/A

N/A

N/A

- Maximum debt to EBITDA ratio of 4.5

- Minimum EBITDA to interest expense ratio of 2.5

- Minimum EBITDA to interest expense ratio of 2.5

Significant restrictive

- Incurrence of debt

- Incurrence of debt

- Incurrence of debt

- Incurrence of debt

- Incurrence of debt

N/A

- Incurrence of debt

covenants(7)

- Incurrence of liens

- Incurrence of liens

- Incurrence of liens

- Incurrence of liens

- Incurrence of liens

- Incurrence of liens

- Payment of dividends

- Payment of dividends

- Payment of dividends

- Payment of dividends

- Payment of dividends

- Equity purchases

- Equity purchases

- Equity purchases

- Equity purchases

- Equity purchases

- Equity purchases

- Asset sales

- Asset sales

- Asset sales

- Asset sales

- Asset sales

- Asset sales

- Limitations on

- Affiliate transactions

- Affiliate transactions

- Affiliate transactions

- Affiliate transactions

- Affiliate transactions

derivatives

- Limitations on derivatives

Estimated fair value(8)

$493.2 million

$469.1 million

$666.0 million

$304.5 million

$321.1 million

$152.6 million

$226.8 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)	The KGS Credit Facility is secured by a first perfected lien on substantially all KGS’ assets.
(3)	Represents the weighted average borrowing rate payable to lenders and excludes effects of interest rate derivatives.
(4)	Interest rate options include a base rate plus a spread.
(5)	Interest rate spreads on our Senior Secured Credit Facility include a floor to ABR of one-month LIBOR plus 1%, an ABR margin range of 1.125% to 2.125% and a Eurodollar and specified rate margin range of 2.00% to 3.00%.
(6)	Interest rate spreads on the KGS Credit Facility include a floor to ABR of one-month LIBOR plus 1%, an ABR margin range of 2.00% to 3.00% and a Eurodollar and specified rate margin range of 3.00% to 4.00%.
(7)	The covenant information presented in this table is qualified in all respects by reference to the full text of the covenants, terms and related definitions contained in the documents governing the various components of our debt.
(8)	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.

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6.   ASSET RETIREMENT OBLIGATIONS

     The following table provides information about our estimated asset retirement obligation activity for the six months ended June 30, 2010.

(In thousands)
Beginning asset retirement obligations	$	59,377
Incremental liability incurred		1,422
Accretion expense		1,513
Asset retirement costs incurred		(352	)
Gain on settlement of liability		271
Currency translation adjustment		(488	)
Ending asset retirement obligations		61,743
Less current portion		(109	)
Long-term asset retirement obligations	$	61,634

7.  COMMITMENTS AND CONTINGENCIES

     As of June 30, 2010, our estimate of total Eni Production volumes purchased under the Gas Purchase Commitment has been reduced 3.3 Bcf from our December 31, 2009 estimates and we determined our remaining liability to be $33.7 million, including an embedded derivative liability of $6.2 million.  Valuation of the liability was based on the most recent estimate of remaining 2010 Eni Production volumes and natural gas prices at June 30, 2010.

     In April 2010, we finalized a global settlement agreement with BBEP and all other parties to our lawsuit whereby we received $18.0 million in cash, which was recognized as other income in the second quarter of 2010.  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 the ability to name two directors to the board of directors of BBEP’s general partner.  If we were to own less than 10% of the outstanding BBEP common units, one of the directors appointed by us would resign. BBEP also agreed to the reinstitution of quarterly distributions and other governance accommodations.

     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.

     In June 2010, we structured a portion of the credit support for our surety bonds to include a $15.0 million cash deposit reported in other current assets. We have the option to replace the cash deposit with a letter of credit in the future.  As of July 2010, our letters of credit were reduced to $25.2 million, which includes $13.9 million issued in support of surety bonds.

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

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8.  NONCONTROLLING INTERESTS AND KGS

     In January 2010, the underwriters purchased an additional 549,200 newly issued common units for $11.0 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” at that time.  In December 2009, KGS offered 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, as of June 30, 2010, 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.

     In July 2010, we agreed to sell all of our interests in KGS to Crestwood.  The Crestwood Transaction will include the sale of a 100% ownership interest in Quicksilver Gas Services Holdings LLC, which owns (a) 5,696,752 common units of KGS, (b) 11,513,635 subordinated units of KGS representing limited partner interests in KGS and (c) 100% of the outstanding membership interests in Quicksilver Gas Services GP LLC including 469,949 general partner units in KGS and 100% of the outstanding incentive distribution rights in KGS.  Crestwood will also receive a $57 million subordinated promissory note issued to us by KGS with a carrying value of $57 million at June 30, 2010.  We expect to receive $701 million in cash at closing and up to $72 million in future earn-out payments in 2012 and 2013.  The Crestwood Transaction is expected to close in the fourth quarter 2010, subject to customary closing conditions.

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 $3.5 million for all unvested stock options in the first six 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		-

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     The following table summarizes stock option activity during the six months ended June 30, 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		(206,876	)		5.85
Cancelled		(77,113	)		8.70
Outstanding at June 30, 2010		3,632,339		$	10.87		8.6	$	11,414
Exercisable at June 30, 2010		1,096,610		$	11.49		8.0	$	3,967
Vested at June 30, 2010 or expected to vest in the future		3,548,324		$	10.91

     Cash received from the exercise of stock options was $1.2 million for the six months ended June 30, 2010 and the total fair value of those options exercised was $1.9 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		892,069			15.58		167,618			15.82
Vested		(1,084,214	)		12.18		(109,602	)		6.22
Cancelled		(68,737	)		11.37		(47,995	)		10.22
Outstanding at June 30, 2010		2,461,993		$	11.39		338,716		$	10.40

     At January 1, 2010, we had total unvested compensation cost of $15.1 million. During the first six months of 2010, we recognized compensation expense for all unvested restricted stock and RSUs of $6.7 million. Grants of restricted stock and stock-settled RSUs during the six months ended June 30, 2010 had an estimated grant date fair value of $13.9 million, which will be recognized as expense over the vesting period. Unrecognized compensation cost remaining at June 30, 2010 for restricted stock and stock-settled RSUs was $21.5 million, which will be recognized through March 2013. The fair value of unvested RSUs settled in cash was $3.7 million at June 30, 2010. The total fair value of restricted shares and RSUs vested during the six months ended June 30, 2010 was $13.1 million.

     Expense for all Quicksilver unvested stock-based compensation granted to our employees who become KGS employees will be recognized upon closing of the Crestwood Transaction. Grant date fair value for unvested stock options and restricted stock was $0.6 million and $0.4 million, respectively.

20

KGS Phantom Units

     The following table summarizes information regarding KGS phantom unit activity:

	Payable in units					Payable in cash
				Wtd Avg Grant Date					Wtd Avg Grant Date
	Units			Fair Value		Units			Fair Value
Outstanding at December 31, 2009		485,672		$	12.75		33,240		$	20.90
Granted		211,600			21.15		-			-
Vested		(179,886	)		13.74		(1,956	)		18.94
Cancelled		(763	)		17.52		-			-
Outstanding at June 30, 2010		516,623		$	15.83		31,284		$	20.82

     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 $1.8 million during the six months ended June 30, 2010.  Grants of phantom units during the six months ended June 30, 2010 had an estimated grant date fair value of $4.5 million.

     KGS has unearned compensation expense of $4.4 million at June 30, 2010 that will be recognized in expense over the vesting period.  Phantom units that vested during the six months ended June 30, 2010 had a fair value of $2.5 million on their vesting date.  We will recognize $4.4 million of expense for all unvested KGS phantom units upon closing of the Crestwood Transaction in accordance with the terms of KGS’ amended 2007 Equity plan.

10.  EARNINGS PER SHARE

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

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2010		2009			2010		2009
	(In thousands, except per share					(In thousands, except per share
	data)					data)
Net income (loss) attributable to Quicksilver	$	86,803	$	(21,762	)	$	94,991	$	(590,741	)
Impact of assumed conversions - interest on 1.875%
convertible debentures, net of income taxes(1)		1,787		-			3,552		-
Income (loss) available to stockholders assuming
conversion of convertible debentures	$	88,590	$	(21,762	)	$	98,543	$	(590,741	)
Weighted average common shares - basic		170,290		169,009			170,225		168,894
Effect of dilutive securities(1):
Employee stock options		766		-			814		-
Employee stock unit awards		-		-			-		-
Contingently convertible debentures		9,816		-			9,816		-
Weighted average common shares - diluted		180,872		169,009			180,855		168,894
Earnings (loss) per common share - basic	$	0.51	$	(0.13	)	$	0.56	$	(3.50	)
Earnings (loss) per common share - diluted	$	0.49	$	(0.13	)	$	0.54	$	(3.50	)

    ⁽¹⁾ For the three and six months ended June 30, 2009, the effects of 9.8 million shares for our convertible debt and stock options and unvested restricted stock units representing 0.9 million shares were antidilutive and excluded from the diluted share calculations.  For the three and six months ended June 30, 2010, the effects of stock options and unvested restricted stock units representing 1.3 million shares were antidilutive and excluded from the diluted share calculations.

21

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.

     The Crestwood Transaction will result in the sale of all unrestricted non-guarantor subsidiaries.

	June 30, 2010
			Restricted		Restricted		Restricted			Quicksilver		Unrestricted					Quicksilver
	Quicksilver		Guarantor		Non-Guarantor		Subsidiary			and Restricted		Non-Guarantor		Consolidating			Resources Inc.
	Resources Inc.		Subsidiaries		Subsidiaries		Eliminations			Subsidiaries		Subsidiaries		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets	$	239,863	$	85,189	$	47,595	$	(109,425	)	$	263,222	$	4,935	$	(20,246	)	$	247,911
Property and equipment		2,246,197		128,527		499,328		-			2,874,052		508,850		-			3,382,902
Investment in subsidiaries (equity method)		551,333		152,319		-		(458,377	)		245,275		-		(152,319	)		92,956
Other assets		219,129		-		9,104		-			228,233		8,624		(53,927	)		182,930
Total assets	$	3,256,522	$	366,035	$	556,027	$	(567,802	)	$	3,610,782	$	522,409	$	(226,492	)	$	3,906,699
LIABILITIES AND EQUITY
Current liabilities	$	323,078	$	108,751	$	15,593	$	(109,425	)	$	337,997	$	16,176	$	(20,246	)	$	333,927
Long-term liabilities		2,151,529		21,715		317,626		-			2,490,870		291,047		(53,927	)		2,727,990
Quicksilver stockholders’ equity		781,915		235,569		222,808		(458,377	)		781,915		152,319		(152,319	)		781,915
Noncontrolling interests		-		-		-		-			-		62,867		-			62,867
Total liabilities and equity	$	3,256,522	$	366,035	$	556,027	$	(567,802	)	$	3,610,782	$	522,409	$	(226,492	)	$	3,906,699

	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
	(In thousands)
ASSETS
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 June 30, 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	$	195,394		$	1,566		$	28,700		$	(629	)	$	225,031		$	27,194		$	(23,655	)	$	228,570
Operating expense		103,657			2,470			23,797			(629	)		129,295			14,063			(23,655	)		119,703
Equity in net earnings of subsidiaries		5,544			6,172			-			(5,544	)		6,172			-			(6,172	)		-
Operating income		97,281			5,268			4,903			(5,544	)		101,908			13,131			(6,172	)		108,867
Income from earnings of BBEP		23,168			-			-			-			23,168			-			-			23,168
Interest expense and other		11,658			-			(1,785	)		-			9,873			(2,945	)		-			6,928
Income tax (expense) benefit		(45,304	)		(1,843	)		(999	)		-			(48,146	)		(73	)		-			(48,219	)
Net income	$	86,803		$	3,425		$	2,119		$	(5,544	)	$	86,803		$	10,113		$	(6,172	)	$	90,744
Net income attributable to noncontrolling interests		-			-			-			-			-			(3,941	)		-			(3,941	)
Net income attributable Quicksilver	$	86,803		$	3,425		$	2,119		$	(5,544	)	$	86,803		$	6,172		$	(6,172	)	$	86,803

22

	For the Three Months Ended June 30, 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	$	157,389		$	185		$	47,324		$	(110	)	$	204,788		$	23,340		$	(22,087	)	$	206,041
Operating expense		112,301			1,154			90,946			(110	)		204,291			13,015			(21,838	)		195,468
Equity in net earnings of subsidiaries		(31,157	)		5,704			-			31,157			5,704			-			(5,704	)		-
Operating income (loss)		13,931			4,735			(43,622	)		31,157			6,201			10,325			(5,953	)		10,573
Income from earnings of BBEP		19,016			-			-			-			19,016			-			-			19,016
Interest expense and other		(64,606	)		1,191			(2,709	)		-			(66,124	)		(2,242	)		(570	)		(68,936	)
Income tax (expense) benefit		9,897			(2,074	)		11,322			-			19,145			(248	)		-			18,897
Discontinued operations		-			-			-			-			-			(819	)		819			-
Net income (loss)	$	(21,762	)	$	3,852		$	(35,009	)	$	31,157		$	(21,762	)	$	7,016		$	(5,704	)	$	(20,450	)
Net income attributable to noncontrolling interests		-			-			-			-			-			(1,312	)		-			(1,312	)
Net income (loss) attributable to Quicksilver	$	(21,762	)	$	3,852		$	(35,009	)	$	31,157		$	(21,762	)	$	5,704		$	(5,704	)	$	(21,762	)

	For the Six Months Ended June 30, 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)
Revenues	$	377,894		$	3,211		$	64,549		$	(1,325	)	$	444,329		$	51,933		$	(45,534	)	$	450,728
Operating expenses		231,498			4,353			47,142			(1,325	)		281,668			29,882			(45,534	)		266,016
Equity in net earnings of subsidiaries		16,146			9,949			-			(16,146	)		9,949			-			(9,949	)		-
Operating income (loss)		162,542			8,807			17,407			(16,146	)		172,610			22,051			(9,949	)		184,712
Income from earnings of BBEP		7,179			-			-			-			7,179			-			-			7,179
Interest expense and other		(28,401	)		-			(3,222	)		-			(31,623	)		(5,623	)		-			(37,246	)
Income tax (expense) benefit		(46,329	)		(3,082	)		(3,764	)		-			(53,175	)		(126	)		-			(53,301	)
Net income (loss)	$	94,991		$	5,725		$	10,421		$	(16,146	)	$	94,991		$	16,302		$	(9,949	)	$	101,344
Net income attributable to noncontrolling interests		-			-			-			-			-			(6,353	)		-			(6,353	)
Net income (loss) attributable to Quicksilver	$	94,991		$	5,725		$	10,421		$	(16,146	)	$	94,991		$	9,949		$	(9,949	)	$	94,991

	For the Six Months Ended June 30, 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)
Revenues	$	294,996		$	217		$	93,138		$	(34	)	$	388,317		$	47,304		$	(43,648	)	$	391,973
Operating expenses		1,004,499			1,438			219,839			(34	)		1,225,742			24,752			(43,402	)		1,207,092
Equity in net earnings of subsidiaries		(88,798	)		13,428			-			88,798			13,428			-			(13,428	)		-
Operating income		(798,301	)		12,207			(126,701	)		88,798			(823,997	)		22,552			(13,674	)		(815,119	)
Income from earnings of BBEP		19,016			-			-			-			19,016			-			-			19,016
Interest expense and other		(101,157	)		2,575			(4,109	)		-			(102,691	)		(4,477	)		(1,208	)		(108,376	)
Income tax (expense) benefit		289,701			(5,174	)		32,404			-			316,931			(211	)		-			316,720
Discontinued operations		-			-			-			-			-			(1,454	)		1,454			-
Net income	$	(590,741	)	$	9,608		$	(98,406	)	$	88,798		$	(590,741	)	$	16,410		$	(13,428	)	$	(587,759	)
Net income attributable to
noncontrolling interests		-			-			-			-			-			(2,982	)		-			(2,982	)
Net income attributable to Quicksilver	$	(590,741	)	$	9,608		$	(98,406	)	$	88,798		$	(590,741	)	$	13,428		$	(13,428	)	$	(590,741	)

23

	For the Six Months Ended June 30, 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	$	187,555		$	100		$	43,850		$	-	$	231,505		$	26,749		$	(11,747	)	$	246,507
Purchases of property, plant and equipment		(271,897	)		(100	)		(46,987	)		-		(318,984	)		(34,845	)		(2,573	)		(356,402	)
Distribution to parent		80,276			-			-			-		80,276			(80,276	)		-			-
Proceeds from sales of property and equipment		864			-			-			-		864			-			-			864
Net cash flow used for investing activities		(190,757	)		(100	)		(46,987	)		-		(237,844	)		(115,121	)		(2,573	)		(355,538	)
Issuance of debt		376,000			-			39,532			-		415,532			124,500			-			540,032
Repayments of debt		(352,500	)		-			(34,013	)		-		(386,513	)		(23,100	)		-			(409,613	)
Debt issuance costs		(109	)		-			-			-		(109	)		-			-			(109	)
Gas Purchase Commitment - net		(16,592	)		-			-			-		(16,592	)		-			-			(16,592	)
Issuance of KGS common units		-			-			-			-		-			11,054			-			11,054
Distributions to parent		-			-			-			-		-			(14,320	)		14,320			-
Distributions to noncontrolling interests		-			-			-			-		-			(8,808	)		-			(8,808	)
Proceeds from exercise of stock options		1,209			-			-			-		1,209			-			-			1,209
Treasury transactions - equity		(4,804	)		-			-			-		(4,804	)		(1,144	)		-			(5,948	)
Net cash flow provided by financing activities		3,204			-			5,519			-		8,723			88,182			14,320			111,225
Effect of exchange rates on cash		-			-			(671	)		-		(671	)		-			-			(671	)
Net decrease in cash and equivalents		2			-			1,711			-		1,713			(190	)		-			1,523
Cash and equivalents at beginning of period		5			-			1,034			-		1,039			746			-			1,785
Cash and equivalents at end of period	$	7		$	-		$	2,745		$	-	$	2,752		$	556		$	-		$	3,308

	For the Six Months Ended June 30, 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	$	184,519		$	20,495		$	85,310		$	-	$	290,324		$	33,249		$	(13,232	)	$	310,341
Purchases of property, plant and equipment		(316,015	)		(20,495	)		(68,894	)		-		(405,404	)		(35,780	)		-			(441,184	)
Proceeds from sales of property and equipment		232,720			-			768			-		233,488			-			-			233,488
Net cash flow used for investing activities		(83,295	)		(20,495	)		(68,126	)		-		(171,916	)		(35,780	)		-			(207,696	)
Issuance of debt		946,302			-			42,948			-		989,250			31,500			-			1,020,750
Repayments of debt		(1,073,605	)		-			(59,926	)		-		(1,133,531	)		(10,500	)		-			(1,144,031	)
Debt issuance costs		(21,677	)		-			(1,125	)		-		(22,802	)		-			-			(22,802	)
Gas Purchase Commitment assumed		46,628			-			-			-		46,628			-			-			46,628
Distributions to parent		-			-			-			-		-			(13,232	)		13,232			-
Distributions to noncontrolling interests		-			-			-			-		-			(4,896	)		-			(4,896	)
Proceeds from exercise of stock options		80			-			-			-		80			-			-			80
Treasury transactions - equity		(627	)		-			-			-		(627	)		(63	)		-			(690	)
Net cash flow provided by (used for) financing activities		(102,899	)		-			(18,103	)		-		(121,002	)		2,809			13,232			(104,961	)
Effect of exchange rates on cash		-			-			125			-		125			-			-			125
Net decrease in cash and equivalents		(1,675	)		-			(794	)		-		(2,469	)		278			-			(2,191	)
Cash and equivalents at beginning of period		1,679			-			866			-		2,545			303			-			2,848
Cash and equivalents at end of period	$	4		$	-		$	72		$	-	$	76		$	581		$	-		$	657

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 fees paid for these services by Quicksilver on producing properties.  We evaluate performance based on operating income and property and equipment costs incurred.

     Based upon our board of directors’ approval of the Crestwood Transaction, our historical financial statements to be contained in our September 30, 2010 Report on Form 10-Q will reflect KGS’ financial information as discontinued operations, which similarly will cause the cessation of reporting KGS’ financial information within the midstream caption within our segment disclosures.

24

	Exploration & Production								Corporate						Quicksilver
	United States			Canada			Midstream		and Other			Elimination			Consolidated
	(In thousands)
For the Three Months Ended June 30, 2010
Revenues	$	195,395		$	28,701		$	28,181	$	-		$	(23,707	)	$	228,570
Depletion, depreciation and accretion		31,708			11,152			7,356		453			-			50,669
Operating income		106,642			5,834			14,061		(17,670	)		-			108,867
Property and equipment costs incurred		246,917			4,550			9,317		1,347			-			262,131
For the Three Months Ended June 30, 2009
Revenues	$	152,051		$	47,209		$	24,386	$	5,217		$	(22,822	)	$	206,041
Depletion, depreciation and accretion		34,490			9,671			6,323		482			-			50,966
Operating income		70,725			(42,765	)		11,084		(28,471	)		-			10,573
Property and equipment costs incurred		90,422			13,738			30,383		1,130			-			135,673
For the Six Months Ended June 30, 2010
Revenue	$	377,894		$	64,549		$	53,985	$	-		$	(45,700	)	$	450,728
Depletion, depreciation and accretion		59,656			22,437			14,413		920			-			97,426
Operating income		178,921			19,267			25,183		(38,659	)		-			184,712
Property and equipment costs incurred		324,284			35,134			36,951		1,967			-			398,336
For the Six Months Ended June 30, 2009
Revenue	$	289,779		$	93,138		$	49,394	$	5,217		$	(45,555	)	$	391,973
Depletion, depreciation and accretion		78,381			19,964			11,509		808			-			110,662
Operating income		(669,154	)		(124,841	)		24,819		(45,943	)		-			(815,119	)
Property and equipment costs incurred		228,053			56,516			48,280		1,656			-			334,505
Property, Plant and Equipment-net
June 30, 2010	$	2,244,634		$	499,328		$	637,376	$	1,564		$	-		$	3,382,902
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:

	Six Months Ended June 30,
	2010			2009
	(In thousands)
Interest	$	58,519		$	85,772
Income taxes		(6,917	)		(41,265	)

     Other non-cash transactions include:

	Six Months Ended June 30,
	2010		2009
	(In thousands)
Working capital related to acquisition of property, plant and equipment	$	102,878	$	111,868
Conveyance of 3,619,901 BBEP common units for producing properties		54,407		-

25

14.  RELATED-PARTY TRANSACTIONS

     As of June 30, 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 $0.5 million in the first six months of both 2010 and 2009 for rent on buildings owned or property services performed by entities affiliated with Mercury.  Rental rates have been determined based on comparable rates charged by third parties.

     We paid $0.2 million during the first six 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.

     Payments received from Mercury for sublease rentals, employee insurance coverage and administrative services during the first six months of 2010 and 2009 each totaled $0.2 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.

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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 Form10-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 June 30, 2010, we own 61% of KGS, which we control and consolidate, and we own 33% 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

Lake Arlington Acquisition

     In May 2010, we completed the acquisition of an approximate 25% working interest in our company-operated Lake Arlington Project.  We acquired the additional working interests in the Lake Arlington Project, subject to customary adjustments as provided in the purchase agreement, for which we conveyed $62.0 million in cash and 3,619,901 of the BBEP common units we owned to the seller on the date of closing.  The acquired interests include proved natural gas reserves of approximately 125 Bcf of which 82% are proved developed.  We expect to finalize adjustments to the purchase price in the third quarter of 2010.  As a result of our conveyance of the 3.6 million BBEP common units for the acquired properties, we recognized a $35.4 million gain as other income in the second quarter of 2010.

BBEP Update

     In April 2010, we finalized a global settlement agreement with BBEP and all other parties to our lawsuit whereby we 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 other income in the second quarter of 2010.  Additionally, we received a quarterly distribution of $8.0 million for the first quarter of 2010.  Completion of the Lake Arlington acquisition in May 2010 reduced our ownership of BBEP to 33%.

Crestwood Transaction

     In July 2010, we entered into a purchase agreement to sell all of our interests in KGS to Crestwood.  The Crestwood Transaction will include the sale of a 100% ownership interest in Quicksilver Gas Services Holdings LLC, which owns (a) 5,696,752 common units of KGS, (b) 11,513,635 subordinated units of KGS representing limited partner interests in KGS and (c) 100% of the outstanding membership interests in Quicksilver Gas Services GP LLC including 469,949 general partner units in KGS and 100% of the outstanding incentive distribution rights in KGS.  Crestwood will also purchase a $57 million subordinated promissory note issued to us by KGS.  We expect to receive $701 million in cash at closing and up to $72 million in future earn-out payments in 2012 and 2013.  The Crestwood Transaction is expected to close in the fourth quarter 2010, subject to customary closing conditions.

     Under the agreements governing the Crestwood Transaction, we have agreed for two years not to solicit employees of KGS and not to compete with KGS with respect to gathering, treating and processing of natural gas and the transportation of natural gas liquids in Denton, Hood, Somervell, Johnson, Tarrant, Parker, Bosque and Erath counties in Texas.  We will be entitled to appoint a director to KGS’ general partner’s board of directors until the later of the second anniversary of the closing and such time as we generate less than 50% of KGS’ consolidated revenue in any fiscal year.

27

     In connection with the closing of the Crestwood Transaction, we will provide transitional services to KGS for up to six months on customary terms.  We and KGS will also enter into an agreement for the joint development of areas governed by certain of our existing commercial agreements and amend certain of our existing commercial agreements.  The most significant amendments include extending the terms of all gathering agreements with KGS to 2020 and establishing a fixed gathering rate of $0.55 per MMcf in the Alliance gathering system.

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 and we continue to focus on ways to optimize our 2010 capital program.  Our 2010 capital program will also be influenced by the closing of the Crestwood Transaction, which will cause us to reduce our midstream program and to possibly redirect additional capital toward our exploration and production activities.  We currently expect that our 2010 capital program will total approximately $470 million, excluding acquisitions.  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 $393 million for exploration and development activities.  Our 2010 capital program has $75 million for midstream facilities of which $22 million will be spent in the Horn River Basin in Canada and $53 million will be spent in the U.S. directly by KGS prior to the closing of the Crestwood Transaction. On a regional basis, approximately $390 million is forecasted to be spent in Texas to drill approximately 80 net wells on operated properties, to complete and tie-in approximately 105 net wells and on midstream infrastructure.  Canadian spending for 2010 is forecasted to be approximately $73 million chiefly to explore the Horn River Basin and develop midstream infrastructure and, to a lesser extent, maintain current production levels in our CBM projects in Alberta.  The remaining capital program is spread among our other operating areas.

     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 June 30, 2010 and 2009

     The following discussion compares the results of operations for the three months ended June 30, 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	$	74.5	$	52.1	$	37.3		$	32.7	$	3.1	$	3.9	$	114.9	$	88.7
Other U.S.		0.5		0.1		0.3			-		2.4		2.0		3.2		2.1
Hedging		67.9		61.2		(4.0	)		-		-		-		63.9		61.2
Total U.S.		142.9		113.4		33.6			32.7		5.5		5.9		182.0		152.0
Alberta		21.2		20.3		-			-		-		-		21.2		20.3
British Columbia		1.9		-		-			-		-		-		1.9		-
Hedging		6.5		27.0		-			-		-		-		6.5		27.0
Total Canada		29.6		47.3		-			-		-		-		29.6		47.3
Total Company	$	172.5	$	160.7	$	33.6		$	32.7	$	5.5	$	5.9	$	211.6	$	199.3

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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		205.5		169.0		11,762		14,818		461		805		278.8		262.7
Other U.S.		1.4		0.2		52		15		403		428		4.2		3.0
Total U.S.		206.9		169.2		11,814		14,833		864		1,233		283.0		265.7
Alberta		60.8		65.6		5		4		-		5		60.8		65.6
British Columbia		6.1		-		-		-		-		-		6.1		-
Total Canada		66.9		65.6		5		4		-		5		66.9		65.6
Total Company		273.8		234.8		11,819		14,837		864		1,238		349.9		331.3

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	$	3.99	$	3.39	$	34.90		$	24.20	$	72.96	$	53.45	$	4.53	$	3.71
Other U.S.		3.73		3.00		60.09			34.49		67.11		50.75		8.55		7.82
Hedging - U.S.		3.61		3.97		(3.76	)		-		-		-		2.48		2.53
Total U.S.		7.59		7.36		31.25			24.21		70.24		52.51		7.07		6.29
Alberta		3.84		3.40		62.58			52.00		-		45.01		3.84		3.40
British Columbia		3.49		-		-			-		-		-		3.49		-
Hedging - Canada		1.06		4.53		-			-		-		-		1.06		4.53
Total Canada		4.87		7.93		62.58			52.00		-		45.01		4.87		7.93
Total Company	$	6.93	$	7.52	$	31.27		$	24.22	$	70.24	$	52.48	$	6.65	$	6.61

     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 June 30, 2009	$	160,701		$	32,701		$	5,913		$	199,315
Volume variance		12,024			(6,653	)		(1,785	)		3,586
Hedge settlement variance		(13,912	)		(4,040	)		-			(17,952	)
Price variance		13,722			11,619			1,397			26,738
Revenue for the quarter ended June 30, 2010	$	172,535		$	33,627		$	5,525		$	211,687

     Higher natural gas production and market prices in the 2010 quarter as compared to the 2009 quarter were partially offset by decreased revenue from hedge settlements for the 2010 quarter as compared to the 2009 quarter.  Canadian natural gas production increased primarily from new Horn River wells placed into service during the last half of 2009.  U.S. natural gas production was also higher because of new wells purchased or placed into service since the 2009 quarter despite lower production of 11.8 MMcfd due to the sale of 27.5% of our Alliance properties sold in 2009 and natural production declines from existing Fort Worth Basin wells.  The impact of an unaffiliated pipeline explosion in the Fort Worth Basin had no significant impact on our natural gas volumes for the 2010 quarter.

     The increase in NGL revenue was due to higher market prices partially offset by payments made to settle hedges during the 2010 quarter and a 21% 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.

     Utilization of derivatives to hedge our sales of natural gas, NGL and crude oil resulted in realized prices that varied from market prices received from the sale our production.  Our production revenue from natural gas, NGL and oil production was $70.4 million and $88.2 million higher because of our hedging activities for the 2010 quarter and the 2009 quarter, respectively.

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Sales of Purchased Natural Gas and Costs of Purchased Natural Gas

	Three Months Ended
	June 30,
	2010			2009
Sales of purchased natural gas:	(In thousands)
Purchases from Eni	$	13,946		$	474
Purchases from others		2,875			4,743
Total		16,821			5,217
Costs of purchased natural gas sold:
Purchases from Eni		17,883			903
Purchases from others		2,975			3,861
Unrealized valuation (gain) loss on
Gas Purchase Commitment		(17,102	)		3,818
Total		3,756			8,582
Net sales and purchases of natural gas	$	13,065		$	(3,365	)

     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.  Natural gas purchases and sales made under the Gas Purchase Commitment began in June 2009 while the 2010 quarter includes three months of activity.  The Gas Purchase Commitment is more fully described in Note 2 to our condensed consolidated financial statements.

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Oil and Gas Production Expense

	Three Months Ended June 30,
	2010				2009
	(In thousands, except per unit amounts)
			Per				Per
Texas			Mcfe				Mcfe
Cash expense	$	26,226	$	1.03	$	20,747	$	0.87
Equity compensation		218		0.01		212		0.01
	$	26,444	$	1.04	$	20,959	$	0.88
Other U.S.
Cash expense	$	1,244	$	3.30	$	1,449	$	5.39
Equity compensation		44		0.12		46		0.17
	$	1,288	$	3.42	$	1,495	$	5.56
Total U.S.
Cash expense	$	27,470	$	1.07	$	22,196	$	0.92
Equity compensation		262		0.01		258		0.01
	$	27,732	$	1.08	$	22,454	$	0.93
Alberta
Cash expense	$	8,408	$	1.52	$	8,729	$	1.46
Equity compensation		274		0.05		520		0.09
	$	8,682	$	1.57	$	9,249	$	1.55
British Columbia
Cash expense	$	1,788	$	3.20	$	-	$	-
Equity compensation		-		-		-		-
	$	1,788	$	3.20	$	-	$	-
Total Canada
Cash expense	$	10,196	$	1.67	$	8,729	$	1.46
Equity compensation		274		0.05		520		0.09
	$	10,470	$	1.72	$	9,249	$	1.55
Total Company
Cash expense	$	37,666	$	1.18	$	30,925	$	1.02
Equity compensation		536		0.02		778		0.03
	$	38,202	$	1.20	$	31,703	$	1.05

     The increase in U.S. production expense was primarily associated with the increase in production from new wells and the cost of operating additional compression in the Alliance area.

     Canadian production expense for the 2010 quarter increased from the 2009 quarter due to $1.8 million for costs to operate our Horn River wells that were placed into production in the third and fourth quarters of 2009.  Alberta production expense decreased only $0.6 million despite a $1.5 million reduction of production expense on a Canadian dollar-basis because of changes in U.S.-Canadian exchange rates for the 2010 quarter when compared to the 2009 quarter.  The Canadian dollar-basis expense decrease was primarily due to lower lease operating expense and processing fees.

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Production and Ad Valorem Taxes

	Three Months Ended June 30,
	2010				2009
	(In thousands, except per unit amounts)
			Per					Per
Production taxes			Mcfe					Mcfe
U.S.	$	2,696	$	0.10	$	1,463		$	0.06
Canada		209		0.03		(83	)		(0.01	)
Total production taxes		2,905		0.09		1,380			0.05
Ad valorem taxes
U.S.	$	4,948	$	0.19	$	5,566		$	0.23
Canada		1,036		0.17		495			0.08
Total ad valorem taxes		5,984		0.19		6,061			0.20
Production and ad valorem tax expense	$	8,889	$	0.28	$	7,441		$	0.25

     Fort Worth Basin production tax increases were due to a 22% 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 June 30,
	2010				2009
	(In thousands, except per unit amounts)
			Per				Per
Depletion			Mcfe				Mcfe
U.S.	$	30,411	$	1.17	$	32,809	$	1.36
Canada		9,542		1.57		8,406		1.41
Total depletion		39,953		1.25		41,215		1.37
Depreciation of other fixed assets
U.S.	$	8,781	$	0.34	$	8,208	$	0.34
Canada		1,160		0.19		994		0.17
Total depreciation		9,941		0.31		9,202		0.31
Accretion		775		0.03		549		0.01
DD&A Expense	$	50,669	$	1.59	$	50,966	$	1.69

     Depletion expense for the 2010 quarter decreased slightly from the 2009 quarter due to a decrease in our depletion rates.  Higher production partially offset the depletion rate decrease, as did the increase in Canadian depletion that resulted from changes in U.S.-Canadian dollar exchange 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 including $70.6 million in the 2009 quarter, which significantly reduced the depletion rates.

General and Administrative Expense

	Three Months Ended June 30,
	2010				2009
	(In thousands, except per unit amounts)
			Per				Per
General and administrative expense			Mcfe				Mcfe
Litigation settlement	$	-	$	-	$	5,000	$	0.17
Cash expense		12,143		0.38		14,849		0.49
Equity compensation		5,074		0.16		4,540		0.15
Total general and administrative expense	$	17,217	$	0.54	$	24,389	$	0.81

     We recognized expense of $5.0 million for litigation settlement in the 2009 quarter, but had none in the 2010 quarter.  In addition, legal and professional fees decreased $2.4 million for the 2010 quarter, primarily as a result of resolution and conclusion of our litigation with BBEP in April 2010.

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BBEP-Related Income

     During the 2010 quarter, we recognized income of $23.2 million for equity earnings from our investment in BBEP based upon its reported earnings for the quarter ended March 31, 2010 as compared to income of $19.0 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.

Other Income (Expense) – Net

     In the 2010 quarter, we finalized settlement of our litigation against BBEP and received $18.0 million from BBEP and another third party.  We also recognized a gain of $35.4 million from the conveyance of 3.6 million BBEP common units as partial consideration in the acquisition of additional working interests in our Lake Arlington Project in May 2010.  See Notes 4 and 7 to the condensed consolidated financial statements found in this quarterly report.

Interest Expense

	Three Months Ended
	June 30,
	2010			2009
	(in thousands)
Interest costs on debt outstanding	$	42,392		$	37,924
Add: Non-cash interest(1)		5,103			4,587
Loss on early debt extinguishment		-			27,122
Less: Interest capitalized		(1,373	)		(1,552	)
Interest expense	$	46,122		$	68,081

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

     Interest costs for the 2010 quarter were lower than the 2009 quarter primarily because of the absence of $27.1 million of interest expense related to debt retirement.  Settlements of our interest rate swaps further reduced interest expense by $4.4 million in the 2010 quarter when compared to the 2009 quarter.

Income Tax Expense

	Three Months Ended
	June 30,
	2010		2009
Income tax (benefit) expense (in thousands)	$	48,219	$	(18,897)
Effective tax rate		34.7%		48.0%

     Our provision for income taxes for the 2010 quarter increased from the 2009 quarter due to higher income before taxes.  The 48% effective tax rate for the 2009 quarter was the result of reductions to deferred Texas Margin tax because of recognition of book impairment charges.

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RESULTS OF OPERATIONS – Six Months Ended June 30, 2010 and 2009

     The following discussion compares the results of operations for the six months ended June 30, 2010 and 2009, or the 2010 period and 2009 period, 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	$	156.1	$	124.8	$	78.4		$	58.0	$	6.2	$	7.2	$	240.7	$	190.0
Other U.S.		1.5		0.2		0.4			-		4.8		3.3		6.7		3.5
Hedging		116.2		96.1		(13.6	)		-		-		-		102.6		96.1
Total U.S.		273.8		221.1		65.2			58.0		11.0		10.5		350.0		289.6
Alberta		50.1		47.1		0.1			0.1		-		-		50.2		47.2
British Columbia		5.0		-		-			-		-		-		5.0		-
Hedging		8.0		46.1		-			-		-		-		8.0		46.1
Total Canada		63.1		93.2		0.1			0.1		-		-		63.2		93.3
Total Company	$	336.9	$	314.3	$	65.3		$	58.1	$	11.0	$	10.5	$	413.2	$	382.9

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		189.5		173.1		11,514		14,072		467		911		261.4		263.0
Other U.S.		1.8		0.2		35		23		393		451		4.4		3.1
Total U.S.		191.3		173.3		11,549		14,095		860		1,362		265.8		266.1
Alberta		61.6		65.3		8		5		-		4		61.6		65.3
British Columbia		6.8		-		-		-		-		-		6.8		-
Total Canada		68.4		65.3		8		5		-		4		68.4		65.3
Total Company		259.7		238.6		11,557		14,100		860		1,366		334.2		331.4

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	$	4.55	$	3.98	$	37.63		$	22.78	$	73.30	$	43.88	$	5.09	$	3.99
Other U.S.		4.52		3.42		66.51			14.11		67.78		40.18		8.41		6.13
Hedging - U.S.		3.36		3.06		(6.51	)		-		-		-		2.13		1.99
Total U.S.		7.91		7.04		31.20			22.75		70.79		42.64		7.28		6.01
Alberta		4.49		3.99		68.69			58.49		-		47.25		4.50		3.99
British Columbia		4.09		-		-			-		-		-		4.09		-
Hedging - Canada		0.64		3.90		-			-		-		-		0.64		3.90
Total Canada		5.10		7.89		68.69			58.49		-		47.25		5.10		7.89
Total Company	$	7.17	$	7.28	$	31.23		$	22.77	$	70.79	$	42.65	$	6.83	$	6.38

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

	Natural
	Gas			NGL			Oil			Total
	(In thousands)
Revenue for the six months ended June 30, 2009	$	314,225		$	58,097		$	10,547		$	382,869
Volume variance		15,242			(10,479	)		(3,910	)		853
Hedge settlement variance		(17,928	)		(13,613	)		-			(31,541	)
Price variance		25,376			31,313			4,380			61,069
Revenue for the six months ended June 30, 2009	$	336,915		$	65,318		$	11,017		$	413,250

     Increases in 2010 period natural gas market prices compared to the 2009 period were partially offset by a decrease in revenue from hedge settlements for the 2010 period as compared to the 2009 period.  Canadian natural gas production increased primarily from new Horn River wells placed into service during the last half 2009.  An increase in U.S. natural gas volumes was the result of wells purchased or placed into service after June 2009 partially offset by the 14.1 MMcfd decrease in production from 27.5% of our Alliance properties sold in June 2009.

     The increase in NGL revenue was due to increased market prices partially offset by payments made to settle hedges during the 2010 period and an 18% decrease in Fort Worth Basin production for the 2010 period compared to the 2009 period.  NGL production decreased primarily because we have focused our capital spending in areas of the Barnett Shale where dry natural gas is prevalent.

     Utilization of derivatives to hedge our sales of natural gas, NGL and crude oil resulted in realized prices that varied from market prices received from the sale our production.  Our production revenue from natural gas, NGL and oil production was $110.6 million and $142.2 million higher because of our hedging activities for the 2010 period and the 2009 period, respectively.

     We expect our average production for the third and fourth quarters of 2010 to range between 365 MMcfed to 370 MMcfed and 395 MMcfed to 405 MMcfed, respectively. We currently anticipate our average production for all of 2010 will range between 355 MMcfed to 360 MMcfed.

Sales of Purchased Natural Gas and Costs of Purchased Natural Gas

	Six Months Ended June 30,
	2010			2009
	(In thousands)
Sales of purchased natural gas:
Purchases from Eni	$	26,565		$	474
Purchases from others		6,480			4,743
Total		33,045			5,217
Costs of purchased natural gas sold:
Purchases from Eni		30,401			903
Purchases from others		7,126			3,861
Unrealized valuation (gain) loss on
Gas Purchase Commitment		(464	)		3,818
Total		37,063			8,582
Net sales and purchases of natural gas	$	(4,018	)	$	(3,365	)

     Our marketing activities related to the purchase and sale of natural gas have increased in Texas.  Our purchases and sales of natural gas made under the Gas Purchase Commitment began in June 2009 while the 2010 period includes six months of activity.  The Gas Purchase Commitment is more fully described in Note 2 to our condensed consolidated financial statements.

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Oil and Gas Production Expense

	Six Months Ended June 30,
	2010				2009
	(In thousands, except per unit amounts)
			Per				Per
Texas			Mcfe				Mcfe
Cash expense	$	49,614	$	1.05	$	43,062	$	0.91
Equity compensation		429		0.01		515		0.01
	$	50,043	$	1.06	$	43,577	$	0.92
Other U.S.
Cash expense	$	3,208	$	3.98	$	3,280	$	5.79
Equity compensation		86		0.11		97		0.17
	$	3,294	$	4.09	$	3,377	$	5.96
Total U.S.
Cash expense	$	52,822	$	1.10	$	46,342	$	0.96
Equity compensation		515		0.01		612		0.01
	$	53,337	$	1.11	$	46,954	$	0.97
Alberta
Cash expense	$	16,684	$	1.50	$	15,804	$	1.34
Equity compensation		601		0.05		1,116		0.09
	$	17,285	$	1.55	$	16,920	$	1.43
British Columbia
Cash expense	$	3,569	$	2.92	$	-	$	-
Equity compensation		-		-		-		-
	$	3,569	$	2.92	$	-	$	-
Total Canada
Cash expense	$	20,253	$	1.63	$	15,804	$	1.34
Equity compensation		601		0.05		1,116		0.09
	$	20,854	$	1.68	$	16,920	$	1.43
Total Company
Cash expense	$	73,075	$	1.21	$	62,146	$	1.03
Equity compensation		1,116		0.02		1,728		0.03
	$	74,191	$	1.23	$	63,874	$	1.06

     The increase in U.S. production expense was primarily associated additional production from new wells and the cost of operating additional compression in the Alliance area.

     Canadian production expense for the 2010 period increased from the 2009 period due to expense of $3.6 million to operate our Horn River wells in British Columbia that were placed into production in the last half of 2009.  Alberta production expense increased $0.4 million despite a $1.7 million reduction of production expense incurred on a Canadian dollar-basis caused by changes in U.S.-Canadian exchange rates for the 2010 period when compared to the 2009 period.  The Canadian dollar-basis expense decrease was primarily due to lower lease operating expense and processing fees.

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Production and Ad Valorem Taxes

	Six Months Ended June 30,
	2010				2009
	(In thousands, except per unit amounts)
			Per					Per
Production taxes			Mcfe					Mcfe
U.S.	$	4,919	$	0.10	$	2,582		$	0.05
Canada		348		0.03		(96	)		(0.01	)
Total production taxes		5,267		0.09		2,486			0.04
Ad valorem taxes
U.S.	$	10,462		0.22	$	8,389			0.17
Canada		1,643		0.13		932			0.08
Total ad valorem taxes		12,105		0.20		9,321			0.16
Production and ad valorem tax expense	$	17,372	$	0.29	$	11,807		$	0.20

     Ad valorem tax increases were primarily because of the addition of wells and midstream facilities placed into service in the Fort Worth Basin over the past twelve months and the expiration of finite-lived tax abatements.  Fort Worth Basin production tax increases were due to a 28% 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

	Six Months Ended June 30,
	2010				2009
	(In thousands, except per unit amounts)
			Per				Per
Depletion			Mcfe				Mcfe
U.S.	$	56,845	$	1.17	$	74,681	$	1.55
Canada		19,316		1.56		17,509		1.48
Total depletion		76,161		1.25		92,190		1.54
Depreciation of other fixed assets
U.S.	$	17,508	$	0.36	$	15,516	$	0.32
Canada		2,243		0.18		1,818		0.15
Total depreciation		19,751		0.33		17,334		0.29
Accretion		1,514		0.03		1,138		0.01
Total DD&A	$	97,426	$	1.61	$	110,662	$	1.84

     Depletion expense for the 2010 period decreased from the 2009 period due to a decrease in our depletion rates.  Increased production partially offset the effects of lower depletion rates, as did a $2.7 million increase that resulted from changes in U.S.-Canadian dollar exchange 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, which significantly reduced the depletion rates.

     The increase in U.S. depreciation for the 2010 period as compared to the 2009 period was primarily associated with additions to U.S. field compression and midstream assets placed into service since June 30, 2009.

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General and Administrative Expense

	Six Months Ended June 30,
	2010				2009
	(In thousands, except per unit amounts)
			Per				Per
General and administrative expense			Mcfe				Mcfe
Litigation settlement	$	-	$	-	$	5,000	$	0.08
Cash expense		27,802		0.46		27,514		0.47
Equity compensation		9,938		0.16		9,256		0.15
Total general and administrative expense	$	37,740	$	0.62	$	41,770	$	0.70

     We recognized $5.0 million for litigation settlement in the 2009 period, but had none in the 2010 period.  Additionally, legal and professional fees decreased $2.8 million, primarily a result of the resolution and conclusion of our litigation with BBEP in April 2010.  Those decreases were partially offset by higher compensation expense of $3.8 million, including a $0.7 million increase in stock-based compensation expense.

BBEP-Related Income

     During the 2010 period, we recognized income of $7.2 million for equity earnings from our investment in BBEP based upon its reported earnings for the period ended March 31, 2010 as compared to income of $121.1 million recognized in the 2009 period.  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 period, 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 period.  A similar analysis was performed as of June 30, 2010, which resulted in no further impairment.  Note 5 to the condensed consolidated financial statements contains additional information regarding our investment in BBEP.

Other Income (Expense) – Net

     In the 2010 quarter, we finalized settlement of our litigation against BBEP and received $18.0 million from BBEP and another third party.  We also recognized a gain of $35.4 million from the conveyance of 3.6 million BBEP common units as consideration in the acquisition of additional working interests in our Lake Arlington Project in May 2010.  See Notes 4 and 7 to the condensed consolidated financial statements found in this quarterly report.

Interest Expense

	Six Months Ended June 30,
	2010			2009
	(in thousands)
Interest costs on debt outstanding	$	83,267		$	75,297
Add: Non-cash interest(1)		10,178			8,726
Loss on early debt extinguishment		-			27,122
Less: Interest capitalized		(2,806	)		(2,863	)
Interest expense	$	90,639		$	108,282

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

     Interest costs for the 2010 period were lower than the 2009 period primarily because of the absence of $27.1 million of expense related to the June 2009 early retirement of a portion of our debt.  Settlements of our interest rate swaps further reduced interest expense by $10.8 million in the 2010 period.

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Income Tax Expense

	Six Months Ended June 30,
	2010		2009
Income tax (benefit) expense (in thousands)	$	53,301	$	(316,720	)
Effective tax rate		34.5%		35.0%

     Our provision for income taxes for the 2010 period increased from the 2009 period due to higher income before taxes.  The effective tax rate for the 2010 period was 34.5%, which we expect to be our effective income tax rate for all of 2010.

Outlook for the Remainder of 2010

     Upon closing of the Crestwood Transaction, our consolidated expense will change from our 2010 historical trends because of the absence of KGS intercompany revenue earned from gathering and processing production and KGS’ operating expense.  Beginning with our September 30, 2010 Quarterly Report on Form 10-Q, all prior historical financial results will reflect KGS as discontinued operations.  The following summarizes, on a Mcfe-basis, historical and pro forma operating expense and other costs for the six months ended June 30, 2010 and their projected equivalents for the remaining six months of 2010.

	Six Months Ended
	June 30, 2010
	As						Remainder
	Reported			Pro Forma(1)			2010(2)
	(Per Mcfe)
Oil and gas production expense	$	1.23		$	1.79		$	1.65 to $1.70
Production and ad valorem taxes		0.29			0.24		$	0.22 to $0.25
DD&A		1.61			1.43		$	1.40 to $1.45
General and administrative		0.62			0.59		$	0.45 to $0.50
Interest expense		1.50			1.34		$	1.24 to $1.28
		5.25			5.39		$	4.96 to $5.18
Income tax benefit on the above		(1.84	)		(1.89	)	($1.74 to $1.81)
Net income attributable to noncontrolling interests		0.11			-			-
Net loss from the above attributable to Quicksilver	$	3.52		$	3.50		$	3.22 to $3.37

(1)	Assumes that the historical “as reported” expenses reflect KGS’ financial results as discontinued operations and that the interest expense from the Senior Secured Credit Facility is eliminated from the beginning of 2010.
(2)	Remainder of 2010 reflects the elimination of the interest on our Senior Secured Credit Facility beginning on October 1, 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 differ from our consolidated results of operations to the extent our U.S. oil and gas properties are charged by KGS for gathering and processing of natural gas.  KGS revenue is eliminated to the extent KGS’ revenue is charged to our U.S. oil and gas properties, which are identified in the combined results of operations and discussed above underResults 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 inLiquidity, Capital Resources and Financial Condition.  Upon completion of the Crestwood Transaction, we expect our consolidated results of operations, consolidated financial position and cash flows will be similar to our combined results of operations, consolidated financial position and cash flows for the Company and its restricted subsidiaries.

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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.

	Six Months Ended June 30,
	2010			2009
	(In thousands)
Net cash provided by operating activities	$	246,507		$	310,341
Net cash used for investing activities		(355,538	)		(207,696	)
Net cash provided by (used for) financing activities		111,225			(104,961	)
Effect of exchange rate changes in cash		(671	)		125

Operating Cash Flows

     Net cash provided by operations for the 2010 period decreased $63.8 million from the comparable 2009 period. Significant decreases include a $116.5 million decrease in cash receipts for settlements of commodity derivatives and a $34.3 million decrease in cash receipts from income tax refunds. Partially offsetting these decreases was the $18.0 million cash receipt for resolution of our BBEP litigation, improvements due to a $27.3 million decrease in interest payments, net of interest swap settlements, and additional revenue of $30.3 million from higher production volumes and prices for the 2010 period compared to the 2009 period.

     For the remainder of 2010 through 2015, price collars and swaps hedge a portion of our anticipated natural gas and NGL production.  The following summarizes future production hedged with commodity derivatives:

	Daily Production
Year	Gas		NGL
	MMcfd		Bbld
2010		200		10
2011		150		8
2012		90		-
2013		30		-
2014		30		-
2015		30		-

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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:

	Six Months Ended June 30,
	2010		2009
	(In thousands)
Exploration and development:
Texas	$	316,160	$	209,208
Other U.S.		6,405		18,723
Total U.S.		322,565		227,931
British Columbia		25,585		33,972
Alberta		9,245		22,216
Total Canada		34,830		56,188
Total exploration and development		357,395		284,119
Midstream - Texas		36,857		48,280
Corporate and field office		4,084		2,106
Total plant and equipment costs incurred	$	398,336	$	334,505

     Our capital expenditures for the 2010 period, excluding the $125.2 million acquisition of additional working interests in our Lake Arlington Project, have decreased from the 2009 period principally due to a reduction of our expenditures for development of our Barnett Shale and Canadian CBM properties of $18.4 million and $13.0 million, respectively.  Expenditures for exploration in the Horn River and Greater Green River Basins decreased by $8.4 million and $12.3 million, respectively.  Midstream capital expenditures, primarily through KGS, have been reduced $11.4 million for the 2010 period as compared to the 2009 period.  We currently expect to spend approximately $450 million for capital expenditures, exclusive of acquisitions, for 2010.

Financing Cash Flows

     During the 2010 period, we have increased borrowings under our Senior Secured Credit Facility $29.0 million while KGS has increased borrowings $101 million under the KGS Credit Facility.  Increased borrowings under our Senior Secured Credit Facility were primarily the result of the timing of capital expenditures, including $70.8 million for additional working interests in our Lake Arlington project.  Changes in U.S.-Canadian exchange rates reduced the outstanding balance under the Canadian portion of the Senior Secured Credit Facility by $3.4 million.  Borrowings under the KGS Credit Facility increased primarily as a result of the $84.4 million purchase of the Alliance Midstream Assets from us.  As a result of our borrowings under the Senior Secured Credit Facility and KGS Credit Facility, we had $493 million and $227 million, respectively, outstanding at June 30, 2010.  The lenders under our Senior Secured Credit Facility re-affirmed our $1.0 billion borrowing base in May 2010.

Crestwood Transaction and Proceeds

     We expect that the $701 million of proceeds from the Crestwood Transaction will be utilized to completely repay outstanding borrowings under the Senior Secured Credit Facility, to fund our fourth quarter income tax liability of approximately $130 million and to pay for transaction-related costs.

Financial Position

     The following summarizes the significant changes to our balance sheet as of June 30, 2010, as compared to our December 31, 2009 balance sheet:

• Our current and non-current derivative assets and liabilities increased $94.6 million on a net basis.  The valuation of our remaining open derivative positions increased $168.0 million as a result of natural gas price decreases relative to our commodity derivative pricing during the 2010 period and the addition of derivatives during 2010 that hedge anticipated 2011 through 2015 natural gas production

41

and 2011 anticipated NGL production.  Additonally, valuation of our interest rate swaps increased $9.1 million. Monthly settlements of $82.6 million received during the 2010 period partially offset these increases.

• Our net property, plant and equipment balance increased $297.0 million over the six-month period ended June 30, 2010.  During the 2010 period, we have incurred $125.2 million for the acquisition of additional working interests in our Lake Arlington Project and $273.1 million for ongoing exploration and development activities and midstream expansion that have been partially offset by DD&A of $95.9 million and the effects of changes in U.S.-Canadian exchange rates from December 31, 2009 to June 30, 2010.

• Our net deferred tax position asset has decreased $60.0 million as a result of U.S. income before income taxes for the six-month period ended June 30, 2010.

Contractual Obligations and Commercial Commitments

     As of June 30, 2010, our estimates of Eni Production covered by the Gas Purchase Commitment have been reduced 3.3 Bcf from December 31, 2009 estimates.  At June 30, 2010, we estimated a remaining liability of $33.7 million, including an embedded derivative liability of $6.2 million.  Valuation of the liability was based on the most recent estimate of 2010 Eni Production volumes and natural gas prices at June 30, 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.

     In June 2010, we structured a portion of the credit support for our surety bonds to include a $15.0 million cash deposit.  We have the option to replace the cash deposit with a letter of credit in the future.  As of July 2010, our letters of credit were reduced to $25.2 million, which includes $13.9 million issued in support of surety bonds.

     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 six months ended June 30, 2010, include estimates and assumptions for:

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

     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 materially affecting our financial statements have been issued since the filing of our 2009 Annual Report on Form 10-K.

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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

     Item 2 contains additional information regarding our hedging positions as of June 30, 2010.

     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 $110.6 million and $142.2 million higher because of our hedging program for the 2010 period and 2009 period, respectively.  Other revenue was $1.6 million and $1.7 million lower as a result of derivative and hedging ineffectiveness for the 2010 period and 2009 period, respectively.

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     The following table lists our commodity derivative positions as of June 30, 2010:

				Weighted Avg
		Remaining Contract		Price Per Mcf or
Product	Type	Period	Volume	Bbl		Fair Value
						(In thousands)
Gas	Collar	Jul 2010-Dec 2010	20 MMcfd	$	8.00-11.00	$	11,713
Gas	Collar	Jul 2010-Dec 2010	20 MMcfd		8.00-11.00		11,713
Gas	Collar	Jul 2010-Dec 2010	20 MMcfd		8.00-12.20		11,767
Gas	Collar	Jul 2010-Dec 2010	20 MMcfd		8.00-12.20		11,767
Gas	Collar	Jul 2010-Dec 2010	20 MMcfd		8.50-12.05		13,570
Gas	Collar	Jul 2010-Dec 2010	10 MMcfd		8.50-12.05		6,785
Gas	Collar	Jul 2010-Dec 2010	10 MMcfd		8.50-12.08		6,790
Gas	Collar	Jul 2010-Dec 2011	10 MMcfd		6.00-  7.00		5,501
Gas	Collar	Jul 2010-Dec 2011	10 MMcfd		6.00-  7.00		5,501
Gas	Collar	Jul 2010-Dec 2011	20 MMcfd		6.00-  7.00		11,001
Gas	Collar	Jul 2010-Dec 2012	20 MMcfd		6.50-  7.15		22,576
Gas	Collar	Jul 2010-Dec 2012	20 MMcfd		6.50-  7.18		22,671
Gas	Collar	Jan 2011-Dec 2011	10 MMcfd		6.25-  7.50		4,094
Gas	Collar	Jan 2011-Dec 2011	10 MMcfd		6.25-  7.50		4,094
Gas	Collar	Jan 2011-Dec 2011	20 MMcfd		6.25-  7.50		8,187
Gas	Collar	Jan 2012-Dec 2012	20 MMcfd		6.50-  8.01		8,026
Gas	Basis	Jul 2010-Dec 2010	20 MMcfd		(1)		1,328
Gas	Basis	Jul 2010-Dec 2010	20 MMcfd		(1)		1,328
Gas	Basis	Jul 2010-Dec 2010	20 MMcfd		(2)		229
Gas	Basis	Jul 2010-Dec 2010	10 MMcfd		(2)		197
Gas	Basis	Jul 2010-Dec 2010	10 MMcfd		(2)		202
Gas	Basis	Jan 2011-Dec 2011	20 MMcfd		(1)		1,825
Gas	Basis	Jan 2011-Dec 2011	10 MMcfd		(1)		912
Gas	Basis	Jan 2011-Dec 2011	10 MMcfd		(1)		912
Gas	Swap	Jan 2011-Dec 2015	10 MMcfd	$	6.00		2,331
Gas	Swap	Jan 2011-Dec 2015	20 MMcfd		6.00		4,662
NGL	Swap	Jul 2010-Dec 2010	2 MBbld		32.65		(490	)
NGL	Swap	Jul 2010-Dec 2010	3 MBbld		32.98		(552	)
NGL	Swap	Jul 2010-Dec 2010	1 MBbld		33.63		(65	)
NGL	Swap	Jul 2010-Dec 2010	1 MBbld		34.15		31
NGL	Swap	Jul 2010-Dec 2010	3 MBbld		34.22		132
NGL	Swap	Jan 2011-Dec 2011	3 MBbld		36.06		3,025
NGL	Swap	Jan 2011-Dec 2011	2 MBbld		36.31		2,195
NGL	Swap	Jan 2011-Dec 2011	3 MBbld		41.95		9,436
				Total		$	193,394

(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 June 30, 2010.

44

     We also have recorded a liability for the Gas Purchase Commitment, which is more fully described in Note 2 to the condensed consolidated financial statements.

Interest Rate Risk

     In February 2010, we executed the early settlement of our 2009 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 interest previously earned unsettled amounts, and recognized an adjustment of $14.3 million to the carrying value of the debt.  In May 2010, we executed an early settlement of a portion of our 2010 interest rate swaps that hedged our senior notes due 2015 and our senior subordinated notes.  We received cash of $6.8 million in the settlement, including $2.4 million for interest previously accrued and earned, and recognized an additional adjustment of $4.4 million to the carrying value of the debt.  The $18.7 million from these early settlements will be recognized as a reduction of interest expense over the life of the associated underlying debt instruments.  We have subsequently recognized $0.9 million as a reduction of interest expense in 2010.

     Our remaining interest rate swaps were entered into during February 2010 and cover $295 million of our senior notes due 2015 and $155 million of our senior subordinated notes.  The remaining 2010 interest rate swaps 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, these remaining 2010 interest rate swaps qualified for hedge accounting treatment as fair value hedges.  The value of the remaining 2010 interest rate swaps, excluding the net interest accrual, amounted to a net asset of $13.2 million as of June 30, 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 fair value hedges.

     For the 2010 period and 2009 period, interest expense decreased $11.5 million and $0.8 million, respectively, because of our open and settled interest rate swaps.

     In July 2010, we executed the early settlement of our remaining 2010 interest rate swaps.  We received cash of $16.7 million, including $4.6 million for interest previously accrued and earned.  We will recognize the remaining $12.1 million as an adjustment to the carrying value of the debt that will be recognized as a reduction of interest expense over the life of the associated underlying debt instruments.

     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.

ITEM 4.  Controls and Procedures

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

     We carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures as of the end of the period covered by this report pursuant to Securities Exchange Act Rule 13a-15.  Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that, as of June 30, 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.

Changes in Internal Control Over Financial Reporting

     There has been no change in our internal control over financial reporting during the quarter ended June 30, 2010 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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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 disclosed in our 2009 Annual Report on Form 10-K 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 the risk factors from those described in Item 1A of our 2009 Annual Report on Form 10-K with the exception of the addition of risk factors related to the proposed Crestwood Transaction.  Some of the risks which may be relevant to us include:

The Crestwood Transaction purchase agreement limits our ability to pursue alternatives to sell our interest in KGS to Crestwood.

     The Crestwood Transaction purchase agreement contains provisions that make it more difficult for us to sell our interests in KGS to a party other than Crestwood.  These provisions include a general prohibition on us soliciting alternative transactions with respect to a sale of our interests in KGS.  Further, there are only limited circumstances that permit us to respond to, and negotiate with a third party making an unsolicited offer that our board of directors reasonably believes would be expected to lead to a superior proposal for our interests in KGS.  Although we can terminate the Crestwood Transaction purchase agreement to enter into such a proposal so long as it complies with certain notice and other conditions set forth in the Crestwood Transaction purchase agreement, we will be required to pay Crestwood a termination fee of $23.3 million and reimbursement of expenses up to a specified limit.

     While we believe these provisions are reasonable and not preclusive of other offers, the provisions might discourage a third party that has an interest in acquiring all or a significant part of our interests in KGS from considering or proposing that acquisition, even if that party were prepared to pay consideration with a higher value than the currently proposed purchase consideration.

Failure to complete the sale of our interests in KGS could negatively impact our stock price and future business and financial results.

     If the Crestwood Transaction is not completed, our ongoing business may be adversely affected and, without realizing any of the benefits of the Crestwood Transaction, we would be subject to a number of risks, including the following:

• we may experience negative reactions from the financial markets;

• we will be required to pay certain costs relating to the Crestwood Transaction, whether or not the sale is completed; and,

• we will not be able to repay our outstanding borrowing under the Senior Secured Credit Facility or deploy proceeds toward exploration and development activities.

     There can be no assurance that the risks described above will not materialize, and if any of them do, they may adversely affect our stock price, business and financial results.

In order to complete the Crestwood Transaction, we and Crestwood must obtain certain governmental approvals, and if such approvals are not granted, the completion of the Crestwood Transaction may be jeopardized.

     Completion of the Crestwood Transaction is conditioned upon the expiration or termination of the applicable waiting period relating to the transaction under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, or HSR Act.  Although Quicksilver and Crestwood have agreed in the Crestwood Transaction purchase agreement to use their reasonable best efforts to obtain approval under the HSR Act, there can be no assurance that these approvals will be obtained.

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

Issuer Purchases of Equity Securities

     The following table summarizes our repurchases of Quicksilver common stock during the quarter ended June 30, 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)
April 2010		869	$	13.87		-		-
May 2010		218	$	13.87		-		-
June 2010		2,006	$	11.09		-		-
Total		3,093	$	12.07		-		-

(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 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
10.1	Asset Purchase Agreement, dated May 11, 2010, between Marshall R. Young Oil Co., as Seller, and Quicksilver Resources Inc., as Buyer (filed as Exhibit 10.1 to the Company’s Form 8-K filed May 12, 2010 and included herein by reference)
* 31.1	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
* 31.2	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
* 32.1	Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
* 101.INS	XBRL Instance Document
* 101.SCH	XBRL Taxonomy Extension Schema Linkbase Document
* 101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
* 101.LAB	XBRL Taxonomy Extension Labels Linkbase Document
* 101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document
* 101.DEF	XBRL Taxonomy Extension Definition Linkbase Document

* Filed herewith

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SIGNATURES

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

Dated: August 9, 2010

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

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EXHIBIT INDEX

Exhibit No.	Description
10.1	Asset Purchase Agreement, dated May 11, 2010, between Marshall R. Young Oil Co., as Seller, and Quicksilver Resources Inc., as Buyer (filed as Exhibit 10.1 to the Company’s Form 8-K filed May 12, 2010 and included herein by reference)
* 31.1	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
* 31.2	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
* 32.1	Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
* 101.INS	XBRL Instance Document
* 101.SCH	XBRL Taxonomy Extension Schema Linkbase Document
* 101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
* 101.LAB	XBRL Taxonomy Extension Labels Linkbase Document
* 101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document
* 101.DEF	XBRL Taxonomy Extension Definition Linkbase Document

* Filed herewith

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