Quicksilver Resources (KWK) 10-Q 2008 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, 2008

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 incorporation or organization)	(I.R.S. Employer Identification No.)
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 at least the past 90 days. Yes þ No o 

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

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

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

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

Title of Class	Outstanding as of July 25, 2008
Common Stock, $0.01 par value	158,617,077

QUICKSILVER RESOURCES INC.
INDEX TO FORM 10-Q
For the Period Ending June 30, 2008

		Page
PART I.	FINANCIAL INFORMATION
Item 1.	Financial Statements (Unaudited)
	Condensed Consolidated Statements of Income and Comprehensive (Loss) Income		5
	Condensed Consolidated Balance Sheets		6
	Condensed Consolidated Statements of Cash Flows		7
	Notes to Condensed Consolidated Interim Financial Statements		8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		23
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		35
Item 4.	Controls and Procedures		38
PART II.	OTHER INFORMATION
Item 1.	Legal Proceedings		39
Item 1A.	Risk Factors		39
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		39
Item 3.	Defaults Upon Senior Securities		39
Item 4.	Submission of Matters to a Vote of Security Holders		39
Item 5.	Other Information		40
Item 6.	Exhibits		40
Signatures			41
Certification Pursuant to Section 302
Certification Pursuant to Section 302
Certification Pursuant to Section 906

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DEFINITIONS

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

“AECO” means the price of gas delivered onto the NOVA Gas Transmission Ltd. System

“Bbl” or “Bbls” means barrel or barrels

“Bbld” means barrel or barrels per day

“Bcf” means billion cubic feet

“Bcfd” means billion cubic feet per day

“Bcfe” means Bcf of natural gas equivalents, determined by using the ratio of one Bbl of oil or NGLs to six Mcf of gas

“Btu” means British Thermal units, a measure of heating value

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

“CBM” means coalbed methane

“Domestic” means the properties of Quicksilver in the continental United States

“LIBOR” means London Interbank Offered Rate

“MBbls” means thousand barrels

“MMBbls” means million barrels

“MMBtu” means million Btu and is approximately equal to 1 Mcf

“MMBtud” means million Btu per day

“Mcf” means thousand cubic feet

“MMcf” means million cubic feet

“MMcfd” means million cubic feet per day

“MMcfe” means million cubic feet of natural gas equivalents, determined by using the ratio of one Bbl of oil or NGLs to six Mcf of gas

“NGL” or “NGLs” means natural gas liquids

“NYMEX” means New York Mercantile Exchange

“Oil” includes crude oil and condensate

“Tcf” means trillion cubic feet

“Tcfe” means trillion cubic feet of natural gas equivalents, determined by using the ratio of one Bbl of oil or NGLs to six Mcf of gas

COMMONLY USED TERMS

Other commonly used terms and abbreviations include:

“Alliance Transaction” means the anticipated August 8, 2008 purchase of leasehold, royalty and midstream assets associated with the Barnett Shale in northern Tarrant and southern Denton counties of Texas

“BBEP” means BreitBurn Energy Partners L.P.

“BreitBurn Transaction” means the November 1, 2007 conveyance of our Northeast Operations in exchange for aggregate proceeds of $1.47 billion

“FASB” means the Financial Accounting Standards Board who promulgate accounting standards

“IPO” means initial public offering and relates to the KGS initial public offering completed on August 10, 2007

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

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

“Northeast Operations” means the oil and gas properties and facilities in Michigan, Indiana and Kentucky which were conveyed to BreitBurn Operating, L.P. on November 1, 2007

“SEC” means the United States Securities and Exchange Commission

“SFAS” means Statement of Financial Accounting Standards issued by the Financial Accounting Standards Board

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Explanatory Statement

Under the full cost method of accounting, the Company’s U.S.-based exploration and production assets are considered a single asset. The 2007 fourth quarter divestiture of the Northeast Operations, therefore, represents a fractional divestiture of a single asset, which precludes recording the applicable portion of the Northeast Operations’ 2007 results of operations as discontinued operations within the consolidated financial statements.

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:

• the conditions to the completion of the Alliance Transaction, as set for in the purchase and sale agreements providing for the Alliance Transaction;

• the availability and terms of the financing we intend to procure in order to fund a portion of the purchase price for the Alliance Transaction;

• 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;

• competitive conditions in our industry;

• actions taken by third parties, including operators, processors and transporters;

• 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; and

• the effects of existing or future litigation

This list of factors is not exhaustive, and new factors may emerge or changes to these factors may occur that would impact our business. Additional information regarding these and other factors may be contained in our filings with the SEC, especially on Forms 10-K, 10-Q and 8-K. All such risk factors are difficult to predict, and are subject to material uncertainties that may affect actual results and may be beyond our control.

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. Financial Statements (Unaudited)

QUICKSILVER RESOURCES INC.
CONDENSED CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE (LOSS) INCOME
In thousands, except for per share data — Unaudited

	For the Three Months Ended						For the Six Months Ended
	June 30,						June 30,
	2008			2007			2008			2007
Revenues
Natural gas, NGL and crude oil sales	$	198,147		$	133,959		$	356,503		$	247,251
Other		(132	)		2,542			(985	)		5,830
Total revenues		198,015			136,501			355,518			253,081
Operating expenses
Oil and gas production expense		33,560			31,989			66,090			60,558
Production and ad valorem taxes		2,208			4,212			4,867			8,702
Other operating costs		728			301			1,959			1,085
Depletion, depreciation and accretion		38,920			27,905			73,979			52,499
General and administrative		15,382			10,298			30,797			19,996
Total expenses		90,798			74,705			177,692			142,840
Income from equity affiliates		—			282			—			397
Operating income		107,217			62,078			177,826			110,638
Loss from earnings of BreitBurn Energy Partners		(10,269	)		—			(4,050	)		—
Other (expense) income — net		(542	)		767			1,058			1,368
Interest expense		14,466			18,216			26,298			33,168
Income before income taxes and minority interest		81,940			44,629			148,536			78,838
Income tax expense		28,556			12,770			52,468			24,065
Minority interest expense, net of income tax		988			128			1,496			191
Net income	$	52,396		$	31,731		$	94,572		$	54,582
Other comprehensive (loss) income — net of income tax
Reclassification adjustments related to settlements of derivative contracts		24,836			(4,643	)		22,896			(14,153	)
Net change in derivative fair value		(184,952	)		16,751			(261,249	)		(18,928	)
Foreign currency translation adjustment		1,829			13,356			(6,814	)		14,980
Comprehensive (loss) income	$	(105,891	)	$	57,195		$	(150,595	)	$	36,481
Earnings per common share — basic	$	0.33		$	0.20		$	0.60		$	0.35
Earnings per common share — diluted	$	0.31		$	0.19		$	0.56		$	0.33
Basic weighted average shares outstanding		157,889			155,188			157,807			154,791
Diluted weighted average shares outstanding		169,855			168,254			169,764			168,058

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,
	2008			2007
ASSETS
Current assets
Cash and cash equivalents	$	2,329		$	28,226
Accounts receivable — net of allowance for doubtful accounts		116,301			90,244
Derivative assets at fair value		—			10,797
Current deferred income tax asset		97,980			18,946
Other current assets		58,012			42,188
Total current assets		274,622			190,401
Investment in BreitBurn Energy Partners		395,787			420,171
Property, plant and equipment
Oil and gas properties, full cost method (including unevaluated costs of $293,312 and $215,228, respectively)		2,213,819			1,764,400
Other property and equipment		488,827			377,946
Property, plant and equipment — net		2,702,646			2,142,346
Derivative assets at fair value		—			354
Other assets		40,232			22,574
	$	3,413,287		$	2,775,846
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current portion of long-term debt	$	—		$	34
Accounts payable		209,815			192,855
Income taxes payable		104			46,601
Accrued liabilities		42,289			54,981
Derivative liabilities at fair value		297,087			64,104
Total current liabilities		549,295			358,575
Long-term debt		1,288,824			813,817
Asset retirement obligations		26,326			23,864
Derivative liabilities at fair value		121,893			16,327
Other liabilities		10,609			10,609
Deferred income taxes		384,298			374,645
Deferred gain on sale of partnership interests		79,316			79,316
Minority interests in consolidated subsidiaries		29,098			30,338
Stockholders’ equity
Preferred stock, par value $0.01, 10,000,000 shares authorized, none outstanding		—			—
Common stock, $0.01 par value, 400,000,000 and 200,000,000 shares authorized respectively; 161,260,383 and 160,633,270 shares issued, respectively		1,613			1,606
Paid in capital in excess of par value		280,730			272,515
Treasury stock of 2,661,967 and 2,616,726 shares, respectively		(14,658	)		(12,304	)
Accumulated other comprehensive (loss) income		(205,101	)		40,066
Retained earnings		861,044			766,472
Total stockholders’ equity		923,628			1,068,355
	$	3,413,287		$	2,775,846

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,
	2008			2007
Operating activities:
Net income	$	94,572		$	54,582
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation and accretion		73,979			52,499
Deferred income taxes		51,375			23,907
Stock-based compensation		7,641			6,288
Amortization of deferred charges		849			1,071
Amortization of deferred loan costs		1,243			929
Minority interest expense		1,496			191
Non-cash loss (gain) from hedging and derivative activities		11,069			(981	)
Non-cash loss (income) from equity affiliates		4,050			(397	)
Other		272			484
Changes in assets and liabilities
Accounts receivable		(26,057	)		9,709
Other assets		(9,213	)		(476	)
Accounts payable		(8,566	)		8,992
Income taxes payable		(46,497	)		(401	)
Accrued and other liabilities		(19,602	)		(1,849	)
Net cash provided by operating activities		136,611			154,548
Investing activities:
Purchases of property, plant and equipment		(650,458	)		(442,667	)
Return of investment from BreitBurn Energy Partners and equity affiliates		20,334			167
Proceeds from sales of properties and equipment		598			162
Net cash used for investing activities		(629,526	)		(442,338	)
Financing activities:
Issuance of senior notes		468,611			—
Credit facility borrowings — net		14,111			274,896
Debt issuance costs		(10,837	)		(2,546	)
Minority interest contributions		—			167
Minority interest distributions		(4,042	)		—
Proceeds from exercise of stock options		1,082			12,187
Purchase of treasury stock		(2,354	)		(821	)
Net cash provided by financing activities		466,571			283,883
Effect of exchange rate changes in cash		447			1,884
Net decrease in cash		(25,897	)		(2,023	)
Cash and cash equivalents at beginning of period		28,226			5,281
Cash and cash equivalents at end of period	$	2,329		$	3,258

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 of Quicksilver Resources Inc. (“Quicksilver” or the “Company”) have not been audited. In the opinion of the Company’s management, the accompanying condensed consolidated interim financial statements contain all adjustments necessary to present fairly the financial position of the Company as of June 30, 2008 and its results of operations for the three- and six-month periods ended June 30, 2008 and 2007 and cash flows for the six-month periods ended June 30, 2008 and 2007. All such adjustments are of a normal recurring nature. The results for interim periods are not necessarily indicative of annual results.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States 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 revenues and expenses during each reporting period. Management believes its estimates and assumptions are reasonable; however, actual results could differ from the Company’s estimates.

Certain disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States have been condensed or omitted. Accordingly, these financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Company’s 2007 Annual Report on Form 10-K.

Certain reclassifications have been made to prior periods to conform to current period presentation.

Stock Split

On January 7, 2008, Quicksilver’s Board of Directors declared a two-for-one stock split of the outstanding common stock effected in the form of a stock dividend. The stock dividend was paid on January 31, 2008, to holders of record at the close of business on January 18, 2008, but had no effect on shares held in treasury. The capital accounts, all share data and earnings per share data included in these condensed consolidated financial statements for all periods presented reflect retrospective application of the January 2008 stock split.

Earnings per Common Share

Basic earnings per common share is computed by dividing the net income attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period. Diluted earnings per common share is computed using the treasury stock method, which considers the impact to net income and common shares from the potential issuance of common shares underlying stock options, stock warrants and outstanding convertible securities.

The following is a reconciliation of the weighted average common shares used in the basic and diluted earnings per common share calculations for the three- and six-month periods ended June 30, 2008 and 2007. Outstanding options to purchase 4,802 shares were excluded from the diluted net income per share calculation for the three- and six-month periods ended June 30, 2007 as those options were out-of-the-money and, therefore, considered to be antidilutive. No such antidilutive options were outstanding at June 30, 2008.

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	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2008		2007		2008		2007
	(In thousands, except per				(In thousands, except per
	share data)				share data)
Net income	$	52,396	$	31,731	$	94,572	$	54,582
Impact of assumed conversions — interest on 1.875% convertible debentures, net of income taxes		475		475		950		950
Income available to stockholders assuming conversion of convertible debentures	$	52,871	$	32,206	$	95,522	$	55,532
Weighted average common shares — basic		157,889		155,188		157,807		154,791
Effect of dilutive securities:
Employee stock options		761		1,632		742		1,810
Employee stock and stock unit awards		1,389		1,618		1,399		1,641
Contingently convertible debentures		9,816		9,816		9,816		9,816
Weighted average common shares — diluted		169,855		168,254		169,764		168,058
Earnings per common share — basic	$	0.33	$	0.20	$	0.60	$	0.35
Earnings per common share — diluted	$	0.31	$	0.19	$	0.56	$	0.33

Recently Issued Accounting Standards

•

Pronouncements Implemented

SFAS No. 157,Fair Value Measurements,was issued by the FASB in September 2006. SFAS No. 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles (“GAAP”) and expands disclosures about fair value measurements. The Statement applies under other accounting pronouncements that require or permit fair value measurement. No new requirements are included in SFAS No. 157, but application of the Statement has changed current practice. On February 12, 2008, the FASB issued FASB Staff Position 157-2 (“FSP 157-2”) which delayed the effective date of SFAS No. 157 for non-financial assets and liabilities. The delay allows companies additional time to consider the effect of various implementation issues that have arisen, or that may arise, from the application of SFAS No. 157. The Company adopted SFAS No. 157 on January 1, 2008 for new fair value measurements of financial instruments, including its derivative instruments, and recurring fair value measurements of non-financial assets and liabilities. All financial instruments are measured using inputs from three levels of fair value hierarchy. The three levels are as follows:

Level 1 inputs are unadjusted quoted prices in active markets for identical assets or liabilities that we have the ability to access at the measurement date.

Level 2 inputs include quoted prices for similar assets and liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability (i.e., interest rates, yield curves, etc.), and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).

Level 3 inputs are unobservable inputs that reflect the Company’s assumptions about the assumptions that market participants would use in pricing an asset or liability.

In February 2007, the FASB issued SFAS No. 159,The Fair Value Option for Financial Assets and Financial Liabilities — Including an amendment of FASB Statement No. 115. SFAS No. 159 permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. While SFAS No. 159 became effective on January 1, 2008, the Company did not elect the fair value measurement option for any of its financial assets or liabilities.

On April 30, 2007, the FASB issued FASB Staff Position (“FSP”) No. 39-1,Amendment of FASB Interpretation No. 39. The FSP amends paragraph 3 of FIN No. 39 to replace the terms “conditional contracts” and “exchange contracts” with the term

9

“derivative instruments” as defined in SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities. It also amends paragraph 10 of Interpretation 39 to permit a reporting entity to offset fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement that have been offset in accordance with that paragraph. The Company adopted FSP No. 39-1 on January 1, 2008 without significant impact.

•	Pronouncements Not Yet Implemented
	SFAS No. 141 (revised 2007),Business Combinations, “SFAS No. 141(R)” was issued in December 2007. SFAS No. 141(R) replaces SFAS No. 141,Business Combinations, while retaining its fundamental requirements that the acquisition method of accounting be used for all business combinations and for an acquirer to be identified for each business combination. SFAS No. 141(R) defines the acquirer as the entity that obtains control in the business combination and it establishes the criteria to determine the acquisition date. The Statement also requires an acquirer to recognize the assets acquired and liabilities assumed measured at their fair values as of the acquisition date. In addition, acquisition costs are required to be recognized separately from the acquisition. The Statement will apply to any acquisition completed by the Company on or after January 1, 2009, but may not be applied to any acquisition completed prior to January 1, 2009.
	SFAS No. 160,Noncontrolling Interests in Consolidated Financial Statements — an amendment of ARB No. 51was issued in December 2007. The Statement amends ARB 51 to establish accounting and reporting standards for the noncontrolling interest in a subsidiary (previously referred to as “minority interest”) and for the deconsolidation of a subsidiary. SFAS No. 160 clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as a component of equity in the consolidated financial statements. The Statement also changes the way the consolidated income statement is presented by requiring consolidated net income to be reported at amounts that include the amounts attributable to both the parent and noncontrolling interest. Additionally, SFAS No. 160 establishes a single method for accounting for changes in a parent’s ownership interest in a subsidiary that do not result in deconsolidation. The Statement is effective for the Company beginning January 1, 2009. Management is determining the extent, if any, this adoption will have on the Company’s financial statements in addition to reclassifying the Company’s noncontrolling interests into equity.
	The FASB issued SFAS No. 161,Disclosures about Derivative Instruments and Hedging Activities, in March 2008. Under SFAS No. 161, the Company will be required to disclose the fair value of all derivative and hedging instruments and their gains or losses in tabular format and information about credit risk-related features in derivative agreements, counterparty credit risk, and its strategies and objectives for using derivative instruments. SFAS No. 161 is to be applied prospectively by the Company beginning January 1, 2009. The Company expects that application of SFAS No. 161 will affect the Company’s disclosures about its derivative and hedging instruments, but will not impact the Company’s accounting for them.
	In May 2008, the FASB issued SFAS No. 162,The Hierarchy of Generally Accepted Accounting Principles, which identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of financial statements of nongovernmental entities that are presented in conformity with generally accepted accounting principles (GAAP) in the United States of America (the GAAP hierarchy). This Statement is effective 60 days following the SEC’s approval of the Public Company Accounting Oversight Board amendments to AU Section 411,The Meaning of Present Fairly in Conformity with Generally Accepted Accounting Principles.We do not expect the adoption of SFAS 162 to have an impact on our financial statements or related disclosures.
	In May 2008, the FASB issued Staff Position (“FSP”) APB 14-1, “Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement)” (“FSP APB 14-1”), which clarifies that convertible debt instruments that may be settled in cash upon conversion (including partial cash settlement) are not addressed by paragraph 12 of APB Opinion No. 14, “Accounting for Convertible Debt and Debt Issued with Stock Purchase Warrants.” In addition, FSP APB 14-1 indicates that issuers of such instruments generally should separately account for the liability and equity components in a manner that will reflect the entity’s nonconvertible debt borrowing rate when interest cost is recognized in subsequent periods. FSP APB 14-1 is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. Early adoption is prohibited. We must adopt FSP APB 14-1 beginning in the first quarter of fiscal 2009 and will be required to retroactively present prior period information. We are currently evaluating FSP APB 14-1 the effect FSP APB 14-1 will have on our consolidated financial statements.

2. DERIVATIVES AND FAIR VALUE MEASUREMENTS

In accordance with the fair value hierarchy described in SFAS No. 157 above, the following table shows the fair value of the Company’s financial assets and liabilities that are required to be measured at fair value as of June 30, 2008.

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	FairValue Measurements as of June 30, 2008
										Balance at
	Level 1		Level 2		Level 3		Other			June 30, 2008
Derivative assets	$	—	$	40,743	$	—	$	(40,743	)	$	—
Derivative liabilities	$	—	$	459,723	$	—	$	(40,743	)	$	418,980

The fair value of all derivative instruments included above was estimated using commodity prices quoted in active markets for the periods covered by the derivatives and the value confirmed by a counterparty. Estimates were determined by applying the net differential between the prices in each derivative and market prices for future periods, as adjusted for estimated basis differential, to the volumes stipulated in each contract to arrive at an estimated future value. This estimated future value was discounted on each contract at rates commensurate with federal treasury instruments with similar contractual lives.

The Company hedges a portion of its production revenue using various financial derivatives. All derivatives are evaluated using the hedge criteria established under U.S. accounting standards. If hedge criteria are met, the change in a derivative’s fair value (for a cash flow hedge) is deferred in stockholders’ equity as a component of accumulated other comprehensive loss to the extent the hedge is effective. These deferred gains and losses are recognized into income in the period in which the hedged transaction is recognized in revenues to the extent the hedge is effective. The changes in value of ineffective portions of hedges are recognized currently in earnings.

The Company’s derivative instruments at June 30, 2008 and December 31, 2007 include the Michigan Sales Contract that requires delivery of 25 MMcfd of natural gas at a floor of $2.49 Mcf through March 2009. In December 2007, the Company made a decision to no longer deliver a portion of our natural gas production to supply the contract and recognized a $63.5 million loss at that time. In January 2008, the Company entered into two fixed-price natural gas swaps covering all volumes for the remaining contract period, which served to effectively offset the net earnings exposure for the Company’s remaining obligation under the Michigan Sales Contract. During 2008, the Company has paid $17.8 million of net cash in settlement of obligations for the Michigan Sales Contract.

The change in carrying value of the Company’s derivatives and the contractual fixed-price sale commitments in the Company’s balance sheet since December 31, 2007 resulted from the increase in market prices for natural gas, NGL and oil. The change in fair value of the effective portion of all cash flow hedges was reflected in accumulated other comprehensive income, net of deferred tax effects. All derivative assets and liabilities represent the estimated fair value of contract settlements scheduled to occur over each contract period remaining based on commodity market prices as of the balance sheet date. These amounts are not realized until the monthly period in which the related underlying production is sold.

The estimated fair values of all financial derivatives and contractual fixed-price sale commitments of the Company as of June 30, 2008 and December 31, 2007 are provided below. The carrying values of these derivatives are equal to the estimated fair values for each period presented. The assets and liabilities recorded in the balance sheet are netted where derivatives with both gain and loss positions are held by a single counterparty.

11

	June 30,		December 31,
	2008		2007
	(In thousands)
Derivative assets:
Natural gas basis swaps	$	2,326	$	—
Natural gas fixed-price swaps(1)		38,417		4,666
Natural gas price collars		—		10,491
	$	40,743	$	15,157
Derivative liabilities:
Natural gas basis swaps	$	—	$	1,224
Crude oil price collars		10,560		6,517
NGL fixed-price swaps		14,810		11,294
Natural gas fixed-price swaps		116,809		—
Natural gas price collars		232,987		1,625
Fixed-price natural gas sales contracts(2)		84,557		63,777
	$	459,723	$	84,437

(1)	Includes $38.4 million and $ — million for two fixed-priced swaps related to the Michigan Sales Contract at June 30, 2008 and December 31, 2007, respectively.
(2)	Includes $84.3 million and $63.5 million for the Michigan Sales Contract at June 30, 2008 and December 31, 2007, respectively.

Cash flow hedge derivative liabilities of $250.9 million have been classified as current at June 30, 2008 based on the maturity of the derivative instruments. The effective portion of the derivative liability held in accumulated other comprehensive income that is expected to be reclassified to earnings over the next twelve months is $162.6 million of after-tax net loss.

3. INVESTMENT IN BREITBURN ENERGY PARTNERS L.P.

The Company received common units of BBEP, a publicly traded limited partnership, as partial consideration for the divestiture of properties and assets to BreitBurn Operating, L.P. which closed on November 1, 2007. At March 31, 2008, the Company held approximately 32% of the BBEP common units outstanding. On June 17, 2008, BBEP announced that it had repurchased and retired 14.4 million units, which represented approximately 22% of the units previously outstanding. The resulting reduction in the number of BBEP common units outstanding increased the Company’s ownership to approximately 41% at June 30, 2008.

The Company accounts for its investment in BBEP units using the equity method, utilizing a one quarter lag from BBEP’s publicly-available information. BBEP is primarily engaged in natural gas, NGL and crude oil production in the United States. Quicksilver’s increased ownership of units resulting from the repurchase of outstanding units by BBEP will be reflected in Quicksilver’s results for the quarter ended September 30, 2008.

12

Summarized unaudited financial information for BBEP is as follows:

				For the Quarter
	As of			Ended
	March 31, 2008			March 31, 2008
	(In thousands)			(In thousands)
Current assets	$	97,364	Revenues	$	33,337
Property, plant and equipment		1,863,274	Operating expenses		67,792
Other assets		23,397	Operating income		(34,455	)
Current liabilities		171,408	Interest and other		6,877
Long-term debt		331,000	Income tax benefit		(246	)
Other non-current liabilities		127,489	Minority interests		54
Partners’ equity		1,354,138	Net loss	$	(41,140	)
			Net loss available to common unitholders	$	(40,867	)

For the quarter ended June 30, 2008, the Company recognized a $10.3 million loss and $4.1 million loss that reflects its share of BBEP’s loss for the quarter and six months ended June 30, 2008, respectively. The Company’s share of BBEP’s loss for the quarter ended March 31, 2008 includes reductions of depletion and depreciation expense and intangible asset amortization. During 2008, the Company has received $20.3 million in distributions from BBEP, including $10.7 million during the second quarter. The Company expects to receive an additional $11.1 million in distributions in August 2008.

At June 30, 2008, the Company’s carrying value for its BBEP common units was $395.8 million inclusive of a $289.5 million gain deferred from the transaction. The market value of the Company’s BBEP units was $461.8 million, or $21.63 per common unit, at June 30, 2008. On July 31, 2008, BBEP units had reduced to a fair value of $17.23 per unit, which may result in the Company’s recognition of an impairment charge during the third quarter of 2008, in the event that the decrease in value is deemed to be other than temporary.

4. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment consisted of the following:

	June 30,			December 31,
	2008			2007
Oil and gas properties	(In thousands)
Subject to depletion	$	2,241,522		$	1,811,295
Unevaluated costs		293,312			215,228
Accumulated depletion		(321,015	)		(262,123	)
Net oil and gas properties		2,213,819			1,764,400
Other plant and equipment
Pipelines and processing facilities		421,887			347,187
General properties		40,270			32,966
Construction in progress		72,264			32,682
Accumulated depreciation		(45,594	)		(34,889	)
Net other property and equipment		488,827			377,946
Property, plant and equipment, net of accumulated depletion and depreciation	$	2,702,646		$	2,142,346

13

5. LONG-TERM DEBT

Long-term debt consisted of the following:

	June 30,		December 31,
	2008		2007
	(In thousands)
Senior secured credit facility	$	266,750	$	310,710
Senior notes due 2015, net of unamortized discount		468,611		—
Senior subordinated notes due 2016		350,000		350,000
Convertible debentures, net of unamortized discount		148,163		148,107
KGS credit agreement		55,300		5,000
Other loans		—		34
Total debt		1,288,824		813,851
Less current maturities		—		(34	)
Long-term debt	$	1,288,824	$	813,817

Effective June 27, 2008, the Company issued $475 million of senior notes due 2015 (“Senior Notes due 2015”), which are unsecured, senior obligations of the Company and bear interest at an annual rate of 8.25% payable semiannually on February 1 and August 1 of each year. The terms and conditions of the Senior Notes due 2015 require the Company to comply with certain covenants, which limit, among other things, levels of indebtedness, restricted payments, payments of dividends, capital stock repurchases, investments, liens, restrictions on restricted subsidiaries to make distributions, affiliate transactions and mergers and consolidations. Net proceeds from the issuance were $457 million after discount and underwriting and professional service fees.

As of May 9, 2008, the Company’s borrowing base under its senior secured credit facility was increased to $1 billion from $750 million and is subject to a special redetermination on or about September 15, 2008. Proceeds from the issuance of the Senior Notes due 2015 were used to pay down balances outstanding under the senior secured credit facility.

For a more complete description of the Company’s indebtedness, see Note 13,Long-Term Debt,to the consolidated financial statements in the Company’s 2007 Annual Report on Form 10-K.

6. ASSET RETIREMENT OBLIGATIONS

The Company recognizes the fair value of the liability for legal obligations associated with the retirement of tangible long-lived assets in the period in which it is legally or contractually incurred. When the liability is recognized, an asset retirement cost is capitalized. The liability is accreted to its settlement date fair value over the useful life of the asset, with the associated expense recognized in depletion or depreciation over the useful life of the asset.

The following table provides a reconciliation of the changes in the Company’s estimated asset retirement obligation for the six-month period ended June 30, 2008.

(In thousands)
Beginning asset retirement obligations	$	24,510
Incremental liability incurred		2,001
Accretion expense		722
Change in estimates		361
Asset retirement costs incurred		(209	)
Currency translation adjustment		(413	)
Ending asset retirement obligations		26,972
Less current portion		(646	)
Long-term asset retirement obligation	$	26,326

14

7. INCOME TAXES

During the quarter ended June 30, 2008, there were no changes to the Company’s unrecognized U.S. tax benefits, which totaled $10.0 million at December 31, 2007. If required, interest or penalties will be recognized as a component of interest expense. The Company does not anticipate total unrecognized tax benefits to significantly change due to the settlement of audits or the expiration of statute of limitations.

The Internal Revenue Service completed its audit of the Company’s 2004 Federal income tax return in April 2008. The Company remains subject to examination by the Internal Revenue Service for the years 2001 through 2007. The Company’s subsidiary, QRCI, because of its Canadian tax pool balances, remains subject to examination by the Canada Revenue Agency (“Revenue Canada”) for the years 1999 through 2007.

During the first quarter of 2008, the Company paid $47 million for income taxes for the 2007 tax year, which primarily resulted from the tax-basis gain from the BreitBurn Transaction.

The Company remains subject to a Texas franchise tax featuring a “taxable margin” component. The Company has not recognized any unrecognized tax benefits for the Texas “taxable margin” tax.

8. COMMITMENTS AND CONTINGENCIES

As previously reported in the Company’s 2007 Annual Report on Form 10-K, on October 13, 2006, the Company filed suit in the 342nd Judicial District Court in Tarrant County, Texas against Eagle Drilling, LLC and Eagle Domestic Drilling Operations, LLC (together “Eagle”) regarding three contracts for drilling rigs in which the Company alleges that the first rig furnished by Eagle exhibited operating deficiencies and safety defects and that the other rigs failed to conform to specifications set forth in the drilling contracts. Subsequently, on January 19, 2007, Eagle Domestic Drilling Operations, LLC (“EDDO”) and its parent, Blast Energy Services, Inc. filed for Chapter 11 bankruptcy in the United States Bankruptcy Court for the Southern District of Texas, Houston Division. The Company’s suit against Eagle in Tarrant County was ultimately transferred to the Bankruptcy Court in Houston and was consolidated with the EDDO/Blast bankruptcy. In that case, EDDO has asserted a counterclaim against the Company alleging the Company breached the aforementioned rig contracts and seeking an unspecified amount of actual damages or, alternatively, liquidated damages under the contracts. Based on an order entered on May 13, 2008, the case is now pending before the United States District Court for the Southern District of Texas, Houston Division. It is currently set for trial on September 15, 2008. Separately, on September 17, 2007, Eagle Drilling, LLC, and Rod and Richard Thornton, sued the Company and P. Jeff Cook, the Company’s Executive Vice President-Operations, in the District Court of Cleveland County, Oklahoma for approximately $29 million in damages and an unspecified amount of punitive damages resulting from the Company’s alleged repudiation of the rig contracts mentioned above. Based upon information currently available, the Company believes that the final resolution of these matters will not have a material effect on the Company’s financial condition, results of operations, or cash flows.

The Company had commitments outstanding of approximately $43 million to purchase components for our drilling program as of June 30, 2008. In addition, the Company has approximately $27 million of surety bonds outstanding to fulfill contractual, legal or regulatory requirements. All surety bonds have an annual renewal option.

KGS has entered into agreements with third parties providing for the construction of a natural gas processing plant and natural gas compression equipment for the plant. Progress payments are due to the third parties upon completion of established construction, manufacturing and delivery milestones. During the six months ended June 30, 2008, $38.8 million was paid to the third parties. KGS estimates additional payments of $61.2 million will be made upon completion of specified construction, manufacturing and delivery milestones, with a targeted in-service date during the first quarter of 2009.

The Company is subject to various possible contingencies, which arise primarily from interpretation of federal and state laws and regulations affecting the oil and natural gas industry and contracts to which the Company is a party or is bound. Such contingencies include differing interpretations as to the prices at which natural gas and crude oil sales may be made, the prices at which royalty owners may be paid for production from their leases, environmental issues and other matters. Although management believes it has complied with the various laws and regulations, administrative rulings and interpretations thereof, adjustments could be required as new interpretations and regulations are issued. In addition, production rates, marketing and environmental matters are subject to regulation by various federal and state agencies.

9. STOCK-BASED COMPENSATION

For a more complete description of the Company’s equity plans, see Note 19,Stockholders’ Equity, to the consolidated financial statements in our 2007 Annual Report on Form 10-K.

15

Quicksilver Stock Options

At January 1, 2008, the Company had total compensation cost of $0.1 million related to unvested stock options. In the six months ended June 30, 2008, the Company granted 373,382 options to purchase shares of common stock at an exercise price of $30.95. These option grants had an estimated fair value of $5.1 million on the date of grant. The Company recorded expense of $0.8 million and $0.2 million for stock options in the first six months of 2008 and 2007, respectively. At June 30, 2008, the Company had $4.1 million of expense remaining in unrecognized compensation cost for the unvested portion of stock options.

The fair value of stock options issued in the first quarter of 2008 was estimated on the grant date using the Black-Scholes option pricing model with the following weighted average assumptions:

	Stock
	Options
	Issued
Weighted average grant date fair value	$	13.67
Weighted average grant date	Jan 2, 2008
Weighted average risk-free interest rate		3.41	%
Expected life (in years)		6.0
Weighted average volatility		40.2	%
Expected dividends		—

The following table summarizes the Company’s stock option activity during the first six months of 2008:

				Wtd Avg		Wtd Avg
				Exercise		Remaining		Aggregate
	Shares			Price		Contractual Life		Intrinsic Value
						(In years)		(In thousands)
Outstanding at December 31, 2007		1,021,912		$	7.48
Granted		373,382			30.95
Exercised		(227,664	)		4.60
Cancelled		(42,226	)		28.20
Outstanding at June 30, 2008		1,125,404		$	14.06		4.2	$	27,661
Exercisable at June 30, 2008		594,778		$	7.29		2.0	$	18,648
Vested or expected to vest at June, 30, 2008		1,109,871		$	14.14

Cash received from the exercise of stock options totaled $1.1 million and $12.2 million for the first six-months of 2008 and 2007, respectively. The intrinsic value of the options exercised in the first six months of 2008 was $6.3 million.

Quicksilver Restricted Stock and Restricted Stock Units

At January 1, 2008, the Company had total unvested compensation cost of $15.2 million related to unvested restricted stock and stock unit awards. Grants of restricted stock and stock units during the six months ended June 30, 2008 had an estimated fair value of $17.3 million at the time of grant which will be recognized as expense over the vesting period. During the first six months of 2008 and 2007, the Company recognized $6.3 million and $6.1 million, respectively, of expense for vesting of restricted stock and stock units. Total unvested compensation cost was $24.4 million at June 30, 2008 which will be recognized over a weighted average remaining vesting period of 1 year.

The following table summarizes the Company’s restricted stock and stock unit activity during the first six months of 2008:

				Wtd Avg
				Grant Date
	Shares			Fair Value
Outstanding at December 31, 2007		1,340,122		$	18.76
Granted		551,712			31.40
Vested		(380,858	)		18.87
Cancelled		(131,075	)		22.58
Outstanding at June 30, 2008		1,379,901		$	23.39

16

The total fair value of shares and units vested during the six months ended June 30, 2008 was $11.5 million.

KGS Restricted Phantom Units

The following table summarizes information regarding KGS phantom unit activity:

	Payable in cash					Payable in units
				Wtd Avg					Wtd Avg
				Grant Date					Grant Date
	Units			Fair Value		Units			Fair Value
Outstanding at December 31, 2007		84,961		$	21.36		9,833		$	21.36
Vested		—			—		(6,089	)		21.36
Issued		6,200			24.27		137,148			25.25
Cancelled		(3,000	)		21.36		—			—
Outstanding at June 30, 2008		88,161		$	21.56		140,892		$	25.15

At January 1, 2008, KGS had total unvested compensation cost of $1.9 million related to unvested phantom units awards. KGS recognized compensation expense of approximately $0.8 million during the six months ended June 30, 2008, including $0.3 million for remeasuring awards to be settled in cash to their revised fair value. Grants of phantom units during the six months ended June 30, 2008 had an estimated fair value of $2.7 million. KGS has unearned compensation expense of $3.8 million at June 30, 2008 that will be recognized in expense over the next 2.4 years. Phantom units that vested during the six months ended June 30, 2008 had a fair value of $0.2 million on their vesting date.

10. CONDENSED CONSOLIDATING FINANCIAL INFORMATION

The following subsidiaries of Quicksilver are guarantors of Quicksilver’s Senior Notes due 2015 and Senior Subordinated Notes due 2016: Cowtown Pipeline Funding, Inc., Cowtown Pipeline Management, Inc., Cowtown Pipeline LP, and Cowtown Gas Processing, LP (collectively, the “Guarantor Subsidiaries”). Each of the Guarantor Subsidiaries is 100% owned by Quicksilver. The guarantees are full and unconditional and joint and several. The condensed consolidating financial statements below present the financial position, results of operations and cash flows of Quicksilver, the Guarantor Subsidiaries and non-guarantor subsidiaries of Quicksilver.

As part of the divestiture of properties and assets to BreitBurn Operating, L.P., Quicksilver sold its interests in Mercury Michigan, Inc., Terra Energy Ltd., GTG Pipeline Corporation, Terra Pipeline Company and Beaver Creek Pipeline, LLC, each of which had been a guarantor of Quicksilver’s Senior Subordinated Notes due 2016. The results of operations and cash flows of these subsidiaries for the 2007 period are included as non-guarantor subsidiaries in the condensed consolidating financial statements to conform to the current presentation.

17

Condensed Consolidating Balance Sheets

	June 30, 2008
										Quicksilver
	Quicksilver		Guarantor		Non-Guarantor					Resources Inc.
	Resources Inc.		Subsidiaries		Subsidiaries		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets	$	416,922	$	—	$	301,450	$	(443,750	)	$	274,622
Property and equipment		1,699,550		10,981		992,115		—			2,702,646
Investment in subsidiaries (equity method)		744,722		167,796		—		(516,731	)		395,787
Other assets		90,642		131,911		2,198		(184,519	)		40,232
Total assets	$	2,951,836	$	310,688	$	1,295,763	$	(1,145,000	)	$	3,413,287
LIABILITIES AND STOCKHOLDERS EQUITY
Current liabilities	$	608,806	$	133,800	$	250,439	$	(443,750	)	$	549,295
Long-term liabilities		1,419,402		—		597,067		(184,519	)		1,831,950
Deferred gain		—		—		79,316		—			79,316
Minority interest		—		—		29,098		—			29,098
Stockholders’ equity		923,628		176,888		339,843		(516,731	)		923,628
Total liabilities and stockholders’ equity	$	2,951,836	$	310,688	$	1,295,763	$	(1,145,000	)	$	3,413,287

	December 31, 2007
										Quicksilver
	Quicksilver		Guarantor		Non-Guarantor					Resources Inc.
	Resources Inc.		Subsidiaries		Subsidiaries		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets	$	213,288	$	596	$	243,086	$	(266,569	)	$	190,401
Property and equipment		1,294,573		1,858		845,915		—			2,142,346
Investment in subsidiaries (equity method)		819,119		160,825		—		(559,773	)		420,171
Other assets		72,426		82,251		2,171		(133,920	)		22,928
Total assets	$	2,399,406	$	245,530	$	1,091,172	$	(960,262	)	$	2,775,846
LIABILITIES AND STOCKHOLDERS EQUITY
Current liabilities	$	470,690	$	77,529	$	76,925	$	(266,569	)	$	358,575
Long-term liabilities		860,361		—		512,821		(133,920	)		1,239,262
Deferred gain		—		—		79,316		—			79,316
Minority interest		—		—		30,338		—			30,338
Stockholders’ equity		1,068,355		168,001		391,772		(559,773	)		1,068,355
Total liabilities and stockholders’ equity	$	2,399,406	$	245,530	$	1,091,172	$	(960,262	)	$	2,775,846

18

Condensed Consolidating Statements of Income

	For the Three Months Ended June 30, 2008
													Quicksilver
	Quicksilver			Guarantor			Non-Guarantor						Resources Inc.
	Resources Inc.			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues	$	148,991		$	—		$	63,515		$	(14,491	)	$	198,015
Operating expenses		72,681			514			32,094			(14,491	)		90,798
Income from equity affiliates		—			—			—						—
Operating income		76,310			(514	)		31,421			—			107,217
Equity in net earnings of subsidiaries		20,018			4,619			—			(24,637	)		—
Income from earnings of BBEP		(10,269	)		—			—			—			(10,269	)
Interest expense and other		(9,972	)		1,494			(7,518	)		—			(15,996	)
Income tax provision		(23,691	)		(343	)		(4,522	)		—			(28,556	)
Net income	$	52,396		$	5,256		$	19,381		$	(24,637	)	$	52,396

	For the Three Months Ended June 30, 2007
													Quicksilver
	Quicksilver			Guarantor			Non-Guarantor						Resources Inc.
	Resources Inc.			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues	$	88,948		$	—		$	53,961		$	(6,408	)	$	136,501
Operating expenses		54,687			680			25,746			(6,408	)		74,705
Income from equity affiliates		16			—			266						282	��
Operating income		34,277			(680	)		28,481			—			62,078
Equity in net earnings of subsidiaries		19,437			2,794			—			(22,231	)		—
Interest expense and other		(13,706	)		84			(3,955	)		—			(17,577	)
Income tax provision		(8,277	)		208			(4,701	)		—			(12,770	)
Net income	$	31,731		$	2,406		$	19,825		$	(22,231	)	$	31,731

	For the Six Months Ended June 30, 2008
													Quicksilver
	Quicksilver			Guarantor			Non-Guarantor						Resources Inc.
	Resources Inc.			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues	$	265,878		$	—		$	116,776		$	(27,136	)	$	355,518
Operating expenses		139,638			1,013			64,177			(27,136	)		177,692
Income from equity affiliates		—			—			—			—			—
Operating income		126,240			(1,013	)		52,599			—			177,826
Equity in net earnings of subsidiaries		31,913			6,995			—			(38,908	)		—
Income from earnings of BBEP		(4,050	)		—			—			—			(4,050	)
Interest expense and other		(15,418	)		2,927			(14,245	)		—			(26,736	)
Income tax provision		(44,113	)		(670	)		(7,685	)		—			(52,468	)
Net income	$	94,572		$	8,239		$	30,669		$	(38,908	)	$	94,572

19

	For the Six Months Ended June 30, 2007
													Quicksilver
	Quicksilver			Guarantor			Non-Guarantor						Resources Inc.
	Resources Inc.			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues	$	159,816		$	—		$	104,151		$	(10,886	)	$	253,081
Operating expenses		101,148			1,139			51,439			(10,886	)		142,840
Income from equity affiliates		22			—			375			—			397
Operating income		58,690			(1,139	)		53,087			—			110,638
Equity in net earnings of subsidiaries		34,173			4,075			—			(38,248	)		—
Interest expense and other		(24,826	)		21			(7,186	)		—			(31,991	)
Income tax provision		(13,455	)		391			(11,001	)		—			(24,065	)
Net income	$	54,582		$	3,348		$	34,900		$	(38,248	)	$	54,582

Condensed Consolidating Statements of Cash Flows

	For the Six Months Ended June 30, 2008
													Quicksilver
	Quicksilver			Guarantor			Non-Guarantor						Resources Inc.
	Resources Inc.			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(In thousands)
Cash flow provided by operations	$	(79,043	)	$	9,443		$	206,211		$	—		$	136,611
Cash flow used for investing activities		(404,699	)		48,163			(204,511	)		(68,479	)		(629,526	)
Cash flow provided by financing activities		457,023			(57,606	)		(1,325	)		68,479			466,571
Effect of exchange rates on cash		(70	)		—			517			—			447
Net increase (decrease) in cash and equivalents		(26,789	)		—			892			—			(25,897	)
Cash and equivalents at beginning of period		27,010			—			1,216			—			28,226
Cash and equivalents at end of period	$	221		$	—		$	2,108		$	—		$	2,329

	For the Six Months Ended June 30, 2007
													Quicksilver
	Quicksilver			Guarantor			Non-Guarantor						Resources Inc.
	Resources Inc.			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(In thousands)
Cash flow provided by operations	$	77,788		$	(735	)	$	77,495		$	—		$	154,548
Cash flow used for investing activities		(370,426	)		(45,333	)		(117,535	)		90,956			(442,338	)
Cash flow provided by financing activities		292,304			46,068			36,467			(90,956	)		283,883
Effect of exchange rates on cash		390			—			1,494			—			1,884
Net increase (decrease) in cash and equivalents		56			—			(2,079	)		—			(2,023	)
Cash and equivalents at beginning of period		83			—			5,198			—			5,281
Cash and equivalents at end of period	$	139		$	—		$	3,119		$	—		$	3,258

11. SUPPLEMENTAL CASH FLOW INFORMATION

Cash paid for interest and income taxes is as follows:

	Six Months Ended
	June 30,
	2008		2007
	(In thousands)
Interest	$	28,084	$	32,383
Income taxes		48,546		695

20

Other non-cash transactions are as follows:

	Six Months Ended
	June 30,
	2008		2007
	(In thousands)
Noncash changes in working capital related to acquisition of property, plant and equipment — net	$	14,109	$	(5,582	)

12. RELATED-PARTY TRANSACTIONS

As of June 30, 2008, members of the Darden family, Mercury Exploration Company (“Mercury”) and Quicksilver Energy L.P., entities that are owned by members of the Darden family, beneficially owned approximately 33% of the Company’s outstanding common stock. Thomas F. Darden, Glenn Darden and Anne Darden Self are officers and directors of the Company.

Quicksilver and its associated entities paid $1.1 million in the first six months of both 2008 and 2007 for rent on buildings owned by Pennsylvania Avenue LP (“PALP”), a Mercury affiliate, and WFMG, L.P., a PALP affiliate. Rental rates have been 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 2008 and 2007 totaled $0.1 million.

The Company paid $0.3 million and $0.2 million during the first six months of 2008 and 2007, respectively, for use of an airplane owned by Sevens Aviation, LLC, a company owned indirectly by members of the Darden family. Usage rates are determined based on comparable rates charged by third parties.

On May 20, 2008, the Audit Committee of Quicksilver approved a settlement agreement with Mercury in which Mercury agreed to make payment to the Company of approximately $0.4 million in connection with issues related to the ownership and operation of certain oil and gas properties acquired by the Company from Mercury in 2001, including audit claims received by the Company with respect to certain of the acquired properties and the administration of certain employee benefits by the Company ( the “Mercury Settlement”). The Committee members reviewed the terms of, and relevant facts and circumstances surrounding the Mercury Settlement, as well as the terms of the Company’s Related Party Transaction Policy in approving the settlement.

KGS has agreed to obtain additional easement rights for a total cost of $0.2 million from an affiliate of an entity that beneficially owns more than 5% of KGS’ outstanding units.

13. SEGMENT INFORMATION

The Company operates in two geographic segments, the United States and Canada, where the Company is engaged in the exploration and production segment of the oil and gas industry. Additionally, the Company operates in the midstream segment, where it provides natural gas processing and gathering services in the United States, predominantly through KGS. The Company evaluates performance based on operating income and property and equipment costs incurred.

	Exploration & Production				Processing &								Quicksilver
	United States		Canada		Gathering		Corporate			Elimination			Consolidated
	(In thousands)
For the Three Months Ended June 30,
2008
Revenues	$	148,775	$	45,828	$	18,204	$	—		$	(14,792	)	$	198,015
Depletion, depreciation and accretion		23,010		11,584		3,609		717			—			38,920
Operating income		90,166		24,219		7,508		(14,676	)		—			107,217
Property and equipment costs incurred		242,581		10,831		52,375		193			—			305,980
2007
Revenues	$	98,464	$	37,211	$	7,085	$	—		$	(6,259	)	$	136,501
Depletion, depreciation and accretion		16,682		9,132		1,845		246			—			27,905
Operating income		49,442		20,229		2,950		(10,543	)		—			62,078
Property and equipment costs incurred		189,258		14,104		43,200		365			—			246,927

21

	Exploration & Production				Processing &								Quicksilver
	United States		Canada		Gathering		Corporate			Elimination			Consolidated
	(In thousands)
For the Six Months Ended June 30,
2008
Revenues	$	265,506	$	84,340	$	33,389	$	—		$	(27,717	)	$	355,518
Depletion, depreciation and accretion		43,099		23,015		6,884		981			—			73,979
Operating income		153,117		40,935		12,313		(28,539	)		—			177,826
Property and equipment costs incurred		454,587		87,274		106,805		554			—			649,220
2007
Revenues	$	177,684	$	73,362	$	12,457	$	—		$	(10,422	)	$	253,081
Depletion, depreciation and accretion		30,991		17,884		3,153		471			—			52,499
Operating income		87,673		39,208		4,225		(20,468	)		—			110,638
Property and equipment costs incurred		324,673		33,663		70,198		970			—			429,504
Property, Plant and Equipment
June 30, 2008	$	1,695,721	$	618,971	$	383,613	$	4,341		$	—		$	2,702,646
December 31, 2007		1,290,728		571,496		275,807		4,315			—			2,142,346

14. ACQUISITIONS

On July 7, 2008, the Company announced it had entered into agreements providing for the Alliance Transaction, for consideration of $1 billion in cash and $307 million in Company common stock, subject to normal closing adjustments and conditions. Quicksilver expects to fund the cash portion of the transaction through a combination of borrowings under a proposed $700 million five-year second-lien term loan facility, operating cash flow, and borrowings under its existing senior secured credit facility. The Company’s common stock to be issued in the transaction will be valued based on the volume weighted-average price for the 15 consecutive trading days immediately prior to the third trading day prior to closing the transaction, which is scheduled to occur on August 8, 2008. The Company expects to reflect the acquisition as an increase to its property, plant and equipment balances, subsequent to closing the transaction.

22

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

RESULTS OF OPERATIONS

Summary Financial Data
Three Months Ended June 30, 2008 Compared with the Three Months Ended June 30, 2007

Revenues

Oil, Gas and Related Product Sales

Production revenues, average daily production volumes and average realized sales prices with respect to natural gas, oil and related products for the three months ended June 30, 2008 and 2007 are as follows:

Production Revenues:

	Natural Gas					NGL						Oil and Condensate					Total
	2008			2007		2008			2007			2008			2007		2008			2007
	(In millions)
Texas	$	96.7		$	27.7	$	61.5		$	20.8		$	10.3		$	1.5	$	168.5		$	50.0
Northeast Operations		—			33.9		—			1.3			—			5.5		—			40.7
Other U.S.		0.2			0.1		0.2			0.2			4.7			2.4		5.1			2.7
Hedging		(16.2	)		4.7		(4.8	)		(0.1	)		(3.8	)		—		(24.8	)		4.6
Total U.S.		80.7			66.4		56.9			22.2			11.2			9.4		148.8			98.0
Canada		56.1			33.9		—			0.1			—			—		56.1			34.0
Hedging		(6.8	)		2.0		—			—			—			—		(6.8	)		2.0
Total Canada		49.3			35.9		—			0.1			—			—		49.3			36.0
Total Company	$	130.0		$	102.3	$	56.9		$	22.3		$	11.2		$	9.4	$	198.1		$	134.0

Average Daily Production Volumes:

	Natural Gas				NGL				Oil and Condensate				Equivalent Total
	2008		2007		2008		2007		2008		2007		2008		2007
	(MMcfd)				(Bbld)				(Bbld)				(MMcfed)
Texas		95.8		41.6		11,449		5,623		950		264		170.2		76.9
Northeast Operations		—		65.9		—		375		—		998		—		74.1
Other U.S.		0.2		0.2		35		33		443		475		3.1		3.4
Total U.S.		96.0		107.7		11,484		6,031		1,393		1,737		173.3		154.4
Canada		62.5		53.8		—		11		—		—		62.5		53.8
Total Company		158.5		161.5		11,484		6,042		1,393		1,737		235.8		208.2

Average Realized Prices:

	Natural Gas					NGL					Oil and Condensate					Equivalent Total
	2008			2007		2008			2007		2008			2007		2008			2007
	(per Mcf)					(per Bbl)					(per Bbl)					(per Mcfe)
Texas	$	11.10		$	7.33	$	59.02		$	40.63	$	119.36		$	61.38	$	10.88		$	7.14
Northeast Operations		—			5.66		—			37.83		—			60.96		—			6.04
Other U.S.		5.29			4.48		85.95			44.96		115.48			54.64		18.09			8.61
Hedging — U.S.		(1.84	)		0.50		(4.65	)		—		(29.88	)		—		(1.57	)		0.35
Total U.S.		9.24			6.77		54.45			40.48		88.25			59.30		9.44			6.97
Canada		9.87			6.93		—			58.71		—			—		9.87			6.93
Hedging — Canada		(1.21	)		0.42		—			—		—			—		(1.21	)		0.42
Total Canada		8.66			7.35		—			58.71		—			—		8.66			7.35
Total Company	$	9.02		$	6.96	$	54.45		$	40.52	$	88.25		$	59.30	$	9.23		$	7.07

23

The following table summarizes the changes in the production revenues during the quarter ended June 30, 2008 compared with the comparable 2007 period:

	Natural
	Gas			NGL		Oil			Total
	(In thousands)
Revenue for the quarter ended June 30, 2007	$	102,308		$	22,277	$	9,374		$	133,959
Volume changes		(1,866	)		20,064		(1,857	)		16,341
Price changes		29,619			14,558		3,670			47,847
Revenue for the quarter ended June 30, 2008	$	130,061		$	56,899	$	11,187		$	198,147

Natural gas sales increased as a result of a $2.06 per Mcf increase in realized natural gas prices for the second quarter of 2008 as compared to the 2007 period. A small decrease in natural gas sales volumes was attributable to the absence of 6.0 Bcf of natural gas production from the Northeast Operations which were divested in November 2007. Offsetting this decrease was an additional 4.9 Bcf of natural gas sales volumes that were principally attributable to sizeable increases in production in the Barnett Shale in Texas, where a substantial portion of our capital expenditures were deployed. Production in our CBM projects in Canada also increased 0.8 Bcf as a result of the completion of more wells.

The increase in NGL sales was due to production increases of 495 MBbl and realized prices that were $13.93 per barrel higher in the second quarter of 2008 compared to the comparable prior year quarter. Production volumes in the Fort Worth Basin increased due to new wells placed into production subsequent to the second quarter of 2007 and improved NGL recovery. Partially offsetting the Fort Worth Basin and pricing increases was the absence of production from the Northeast Operations.

The increase in oil sales is attributable to higher realized prices partially offset by a net decrease in production. The absence of production from the Northeast Operations was only partially offset by a 62 MBbl increase in Fort Worth Basin oil production.

Other Revenue

Other revenue in the quarter ended June 30, 2008 decreased $2.7 million from the comparable 2007 quarter. The decrease was primarily due to partial ineffectiveness of the derivatives hedging our Canadian production which resulted in a charge of $4.4 million for 2008 second quarter as compared to additional revenue of $1.0 million for the 2007 second quarter. The change in the fair value of the ineffective portion of our Canadian hedges was due to changes in basis differentials during the quarter ended June 30, 2008. Additional KGS third-party processing and transportation revenue of $2.4 million partially offset the partial ineffectiveness charge.

24

Operating Expenses

Oil and Gas Production Costs

	Three Months Ended June 30,
	2008				2007
	(In thousands, except per unit amounts)
			Per				Per
			Mcfe				Mcfe
Texas
Cash expense	$	22,364	$	1.44	$	11,480	$	1.64
Equity compensation		310		0.02		118		0.02
	$	22,674	$	1.46	$	11,598	$	1.66
Northeast Operations
Cash expense	$	—	$	—	$	12,100	$	1.79
Equity compensation		—		—		373		0.06
	$	—	$	—	$	12,473	$	1.85
Other U.S.
Cash expense	$	1,747	$	5.74	$	897	$	3.10
Equity compensation		42		0.15		59		0.19
	$	1,789	$	5.89	$	956	$	3.29
Total U.S.
Cash expense	$	24,111	$	1.53	$	24,478	$	1.74
Equity compensation		352		0.02		549		0.04
	$	24,463	$	1.55	$	25,027	$	1.78
Canada
Cash expense	$	8,840	$	1.55	$	6,450	$	1.32
Equity compensation		257		0.05		512		0.10
	$	9,097	$	1.60	$	6,962	$	1.42
Total Company
Cash expense	$	32,951	$	1.53	$	30,928	$	1.63
Equity compensation		609		0.03		1,061		0.06
	$	33,560	$	1.56	$	31,989	$	1.69

Production costs increased as a result of a $2.1 million increase in Canadian production costs partially offset by a small decrease in U.S. production costs for the second quarter of 2008.

The small decrease in oil and gas production costs for our U.S. properties was due to the absence of $12.5 million in production expense that resulted from the divestiture of the Northeast Operations in November 2007. That decrease was almost offset by higher production costs in the Fort Worth Basin resulting from the growth of our operations in the Fort Worth Basin where production increased over 120% as a result of additional wells placed into production over the past twelve months. Texas lease operating expenses per Mcfe for the second quarter of 2008 decreased as compared to the 2007 second quarter primarily due to cost containment initiatives and improving leverage of our fixed cost structure over a higher volume base.

Canadian oil and gas production costs increased, in part, because of a 16% increase in production volumes. Canadian expense was also higher in the second quarter of 2008 because of additional gas processing and transportation costs and production overhead expense compared to the second quarter of 2007. Gas processing and transportation costs for the second quarter of 2008 increased approximately $1.2 million. Canadian production overhead increased approximately $0.9 million due primarily to additional compensation and rent costs, and an additional $0.3 million increase that resulted from the currency effects of the stronger Canadian dollar in relation to the U.S. dollar between the two periods.

25

Production and Ad Valorem Taxes

	Three Months Ended June 30,
	2008				2007
	(In thousands, except per unit amounts)
			Per				Per
			Mcfe				Mcfe
Production and ad valorem taxes
U.S.	$	1,280	$	0.08	$	3,324	$	0.24
Canada		928		0.16		888		0.18
Total production and ad valorem taxes	$	2,208	$	0.10	$	4,212	$	0.22

Second quarter 2008 production and ad valorem taxes decreased due to the absence of production for the Northeast Operations partially offset by production increases for Texas, where many of our properties are exempt from or carry a lower rate of production tax because of the cost of drilling and completing wells.

Other Operating Costs

Other operating costs, which principally relate to the costs of processing and gathering third-party natural gas in Texas, were $0.7 million for the second quarter of 2008, an increase of $0.4 million from the comparable 2007 amount. The increase was due to higher KGS gathering and processing volumes from third parties for the second quarter of 2008 as compared to the 2007 second quarter.

Depletion, Depreciation and Accretion

	Three Months Ended June 30,
	2008				2007
	(In thousands, except per unit amounts)
			Per				Per
			Mcfe				Mcfe
Depletion
U.S.	$	22,239	$	1.41	$	14,901	$	1.06
Canada		10,341		1.82		7,957		1.62
Total depletion		32,580		1.52		22,858		1.21
Depreciation of other fixed assets
U.S.	$	4,943	$	0.31	$	3,638	$	0.26
Canada		1,027		0.18		1,006		0.21
Total depreciation		5,970		0.27		4,644		0.25
Accretion		370		0.02		403		0.02
Total depletion, depreciation and accretion	$	38,920	$	1.81	$	27,905	$	1.47

Higher depletion for the second quarter of 2008 resulted from a 27% increase in the depletion rate and a 13% increase in sales volumes. Our higher depletion rate for the second quarter of 2008 resulted from significant increases in estimated future capital expenditures and the costs of proved reserves added from our Canadian and Fort Worth Basin properties. The $1.3 million increase in depreciation for the second quarter of 2008 as compared to the 2007 second quarter was primarily associated with additions of Fort Worth Basin field compression, gas processing facilities and gathering system assets partially offset by the absence of $1.1 million of depreciation expense for divested Northeast Operations depreciable assets. On a unit cost basis, depreciation increased due to the impact of straight-line recognition of plant, pipeline and other surface equipment over higher total production.

26

General and Administrative Expense

	Three Months Ended June 30,
	2008				2007
	(In thousands, except per unit amounts)
			Per				Per
			Mcfe				Mcfe
General and administrative expense
Cash expense	$	12,204	$	0.57	$	7,971	$	0.42
Equity compensation		3,178		0.15		2,327		0.12
Total general and administrative expense	$	15,382	$	0.72	$	10,298	$	0.54

General and administrative expense for the second quarter of 2008 increased over the 2007 period due, in part, to a $3.9 million increase in employee compensation and benefits that included $0.9 million of non-cash expense for vesting of stock-based compensation and $1.2 million in performance-based compensation to be paid in the fourth quarter of 2008 or first quarter of 2009. The remaining increase in employee compensation is related to additional headcount which was necessary to bring our infrastructure to a level needed to accommodate the current and anticipated future growth in our production. Expenses for legal, accounting and other professional services increased general and administrative expense by approximately $0.6 million for the 2008 second quarter as compared to the 2007 second quarter. Higher costs for the second quarter of 2008 were the result of business improvement initiatives, additional regulatory filing requirements, additional investor relations activity and KGS’ ongoing costs associated with activities and requirements for a publicly-traded partnership.

Interest Expense

Interest expense for the second quarter of 2008 was $14.5 million, net of capitalized interest of $1.9 million, which was a decrease of $3.7 million compared to the second quarter of 2007. Interest expense for the second quarter of 2008 was lower than the 2007 second quarter primarily because of an additional $1.7 million of capitalized interest and a decrease in the average interest rate on our debt balances outstanding.

Income Tax Expense

	Three Months Ended
	June 30,
	2008			2007
Income tax (in thousands)	$	28,556		$	12,770
Effective tax rate		34.8	%		28.6	%

Our provision for income taxes for the second quarter of 2008 increased from the prior year period due to a $13.0 million increase in federal income tax expense associated with higher pretax earnings. The remaining $2.8 million increase was due to Texas margin deferred income taxes and tax credits for research and development in Canada that we recognized in 2007.

27

Summary Financial Data
Six Months Ended June 30, 2008 Compared with the Six Months Ended June 30, 2007

Revenues

Oil, Gas and Related Product Sales

Production revenues, average daily production volumes and average realized sales prices with respect to natural gas, oil and related products for the six months ended June 30, 2008 and 2007 are as follows:

Production Revenues:

	Natural Gas					NGL					Oil and Condensate						Total
	2008			2007		2008			2007		2008			2007			2008			2007
									(In millions)
Texas	$	155.4		$	48.0	$	109.9		$	29.8	$	16.8		$	2.8		$	282.1		$	80.6
Northeast Operations		—			63.3		—			2.2		—			9.9			—			75.4
Other U.S.		0.3			0.3		0.6			0.3		8.5			4.4			9.4			5.0
Hedging		(13.5	)		16.4		(8.5	)		—		(5.3	)		(0.1	)		(27.3	)		16.3
Total U.S.		142.2			128.0		102.0			32.3		20.0			17.0			264.2			177.3
Canada		99.6			65.4		—			0.1		—			—			99.6			65.5
Hedging		(7.3	)		4.5		—			—		—			—			(7.3	)		4.5
Total Canada		92.3			69.9		—			0.1		—			—			92.3			70.0
Total Company	$	234.5		$	197.9	$	102.0		$	32.4	$	20.0		$	17.0		$	356.5		$	247.3

Average Daily Production Volumes:

	Natural Gas				NGL				Oil and Condensate				Equivalent Total
	2008		2007		2008		2007		2008		2007		2008		2007
	(MMcfd)				(Bbld)				(Bbld)				(MMcfed)
Texas		88.1		36.9		10,719		4,269		864		262		157.6		64.1
Northeast Operations		—		67.3		—		382		—		966		—		75.4
Other U.S.		0.4		0.3		38		30		458		473		3.4		3.3
Total U.S.		88.5		104.5		10,757		4,681		1,322		1,701		161.0		142.8
Canada		62.5		54.9		—		6		—		—		62.5		55.0
Total Company		151.0		159.4		10,757		4,687		1,322		1,701		223.5		197.8

Average Realized Prices:

	Natural Gas					NGL					Oil and Condensate					Equivalent Total
	2008			2007		2008			2007		2008			2007		2008			2007
	(per Mcf)					(per Bbl)					(per Bbl)					(per Mcfe)
Texas	$	9.69		$	7.17	$	56.35		$	38.60	$	106.87		$	58.04	$	9.83		$	6.94
Northeast Operations		—			5.20		—			32.32		—			56.46		—			5.53
Other U.S.		4.66			5.78		85.06			42.30		101.61			51.26		15.82			8.23
Hedging — U.S.		(0.83	)		0.89		(4.37	)		—		(21.90	)		—		(0.93	)		0.65
Total U.S.		8.83			6.76		52.07			38.11		83.15			55.25		9.02			6.86
Canada		8.75			6.58		—			76.31		—			—		8.75			6.58
Hedging — Canada		(0.64	)		0.45		—			—		—			—		(0.64	)		0.45
Total Canada		8.11			7.03		—			76.31		—			—		8.11			7.03
Total Company	$	8.53		$	6.86	$	52.07		$	38.16	$	83.15		$	55.25	$	8.77		$	6.91

The following table summarizes the changes in the production revenues during the six-month period ended June 30, 2008 compared with the comparable 2007 period:

28

	Natural
	Gas			NGL		Oil			Total
				(In thousands)
Revenue for the six months ended June 30, 2007	$	197,870		$	32,368	$	17,013		$	247,251
Volume changes		(9,447	)		42,337		(3,720	)		29,170
Price changes		46,124			27,248		6,710			80,082
Revenue for the six months ended June 30, 2008	$	234,547		$	101,953	$	20,003		$	356,503

Natural gas sales increased as a result of a $1.67 per Mcf increase in realized natural gas prices for the first half of 2008 as compared to the 2007 six-month period. When compared to the 2007 period, natural gas sales volumes decreased primarily as a result of the absence of 12.2 Bcf of natural gas production from the Northeast Operations which were divested in November 2007. Wells placed into production subsequent to June 30, 2007 resulted in additional production from the Fort Worth Basin of 9.3 Bcf and 1.4 Bcf from our CBM projects in Canada.

Our NGL sales for the six months ended June 30, 2008 increased as a result of both higher production volumes and realized sales prices. The production volume increase was due to new wells placed into production subsequent to June 30, 2007 and improved NGL recovery from our newest processing facility in the Fort Worth Basin that began operations in March 2007. More favorable realized pricing during the 2008 period also impacted NGL sales. Partially offsetting the Fort Worth Basin and pricing increases was the absence of production from the Northeast Operations.

Oil sales for the period ended June 30, 2008 increased due to higher realized prices partially offset by a net decrease in production. The absence of production from the Northeast Operations was only partially offset by a 109 MBbl increase in Fort Worth Basin oil production.

Other Revenue

Other revenue in the six months ended June 30, 2008 decreased $6.8 million from the comparable 2007 period. The derivatives hedging our production were partially ineffective, due primarily to changes in basis differentials, and resulted in a charge of $9.9 million for the six months ended June 30, 2008 as compared to additional revenue of $1.0 million for the 2007 six-month period. Additional KGS third-party processing and transportation revenue of $3.5 million partially offset the partial ineffectiveness charge.

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Operating Expenses

Oil and Gas Production Costs

	Six Months Ended June 30,
	2008				2007
	(In thousands, except per unit amounts)
			Per				Per
			Mcfe				Mcfe
Texas
Cash expense	$	44,200	$	1.54	$	18,693	$	1.61
Equity compensation		624		0.02		235		0.02
	$	44,824	$	1.56	$	18,928	$	1.63
Northeast Operations
Cash expense	$	—	$	—	$	24,725	$	1.81
Equity compensation		—		—		674		0.05
	$	—	$	—	$	25,399	$	1.86
Other U.S.
Cash expense	$	2,636	$	3.96	$	1,640	$	3.02
Equity compensation		90		0.15		96		0.16
	$	2,726	$	4.11	$	1,736	$	3.18
Total U.S.
Cash expense	$	46,836	$	1.60	$	45,058	$	1.74
Equity compensation		714		0.02		1,005		0.04
	$	47,550	$	1.62	$	46,063	$	1.78
Canada
Cash expense	$	17,602	$	1.55	$	13,498	$	1.36
Equity compensation		938		0.08		997		0.10
	$	18,540	$	1.63	$	14,495	$	1.46
Total Company
Cash expense	$	64,438	$	1.58	$	58,556	$	1.63
Equity compensation		1,652		0.04		2,002		0.06
	$	66,090	$	1.62	$	60,558	$	1.69

Oil and gas production costs increased for the first six months of 2008 from the comparable 2007 period due to increases in both the U.S. and Canada. In general, these increases are attributable to the aggregate 14% increase in production, which was achieved despite the absence of production attributable to the divested Northeast Operations.

Oil and gas production costs for the United States increased as a result of the growth of our Fort Worth Basin operations. The $25.9 million increase in Texas oil and gas production expense was primarily the result of a 147% increase in production volumes for the 2008 six-month period as compared to the 2007 six-month period. Texas oil and gas production expense per Mcfe for the first six months of 2008 decreased 4% when compared to the 2007 six-month unit cost primarily due to cost containment initiatives and improving cost leverage across our increased production. Partially offsetting the increase in U.S. oil and gas production costs was a $25.4 million decrease in production expense that resulted from the divestiture of the Northeast Operations in November 2007.

Canadian oil and gas production costs increased in the first six months of 2008 due, in part, to a 14% increase in production volumes. Canadian gas processing costs for the 2008 six-month period increased approximately $2.5 million from the comparable prior year period. Additionally, production overhead expense for the first half of 2008 increased $2.3 million as compared to the first half of 2007. The increase in production overhead was attributable to higher compensation and rent costs of approximately $1.1 million with the remaining $1.2 million increase resulting primarily from currency effects that reflected the strengthening of the Canadian dollar in relation to the U.S. dollar between the two periods.

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Production and Ad Valorem Taxes

	Six Months Ended June 30,
	2008				2007
	(In thousands, except per unit amounts)
			Per				Per
			Mcfe				Mcfe
Production and ad valorem taxes
U.S.	$	3,018	$	0.10	$	6,925	$	0.27
Canada		1,849		0.16		1,777		0.18
Total production and ad valorem taxes	$	4,867	$	0.12	$	8,702	$	0.24

Production and ad valorem taxes for the 2008 period decreased due to the absence of production for the Northeast Operations partially offset by production and infrastructure increases for Texas, where many of our properties are exempt from or carry a lower rate of production tax because of the cost of drilling and completing wells.

Other Operating Costs

Other operating costs, which relate to the cost of processing and gathering third-party natural gas in Texas, were $1.9 million for the first six months of 2008. The $0.9 million increase from the 2007 six-month period was the result of higher KGS gathering and processing volumes from third parties for the 2008 six-month period.

Depletion, Depreciation and Accretion

	Six Months Ended June 30,
	2008				2007
	(In thousands, except per unit amounts)
			Per				Per
			Mcfe				Mcfe
Depletion
U.S.	$	41,301	$	1.41	$	27,539	$	1.07
Canada		20,847		1.83		15,680		1.58
Total depletion		62,148		1.53		43,219		1.21
Depreciation of other fixed assets
U.S.	$	9,365	$	0.32	$	6,631	$	0.26
Canada		1,745		0.15		1,885		0.19
Total depreciation		11,110		0.27		8,516		0.24
Accretion		721		0.02		764		0.02
Total depletion, depreciation and accretion	$	73,979	$	1.82	$	52,499	$	1.47

Depletion for the first six months of 2008 increased from the comparable 2007 period. Higher depletion resulted from a 27% increase in the depletion rate and a 14% increase in sales volumes. Our higher depletion rate for the first half of 2008 resulted from significant increases in estimated future capital expenditures and the costs of proved reserves added from our Canadian and Fort Worth Basin properties. The $2.6 million increase in depreciation for the 2008 period as compared to the 2007 six-month period was primarily associated with additions of Fort Worth Basin field compression, gas processing facilities and gathering system assets partially offset by the absence of $2.1 million of depreciation expense for Northeast Operations depreciable assets. Depreciation for 2008 on a unit cost basis increased due to the additional surface equipment, compression equipment and gathering networks placed into service since June 30, 2007.

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General and Administrative Expense

			Six Months Ended June 30,
	2008				2007
	(In thousands, except per unit amounts)
			Per				Per
General and administrative expense			Mcfe				Mcfe
Cash expense	$	24,501	$	0.60	$	15,711	$	0.44
Equity compensation		6,296		0.16		4,285		0.12
Total general and administrative expense	$	30,797	$	0.76	$	19,996	$	0.56

General and administrative expense increased $0.20 per Mcfe for the 2008 period from the comparable 2007 period. The most significant increase in general and administrative expense for the first half of 2008 was a $7.4 million increase in employee compensation and benefits, including $2.0 million of non-cash expense for vesting of stock-based compensation and $3.0 million in performance-based compensation to be paid in the fourth quarter of 2008 and first quarter of 2009. The remaining $2.4 million increase in employee compensation is related to additional headcount which was necessary to bring our infrastructure to a level needed to accommodate the current and anticipated growth in our production. Office rent and overhead costs also increased $0.7 million. Fees for legal, accounting and other professional services increased general and administrative expense by approximately $1.7 million for the 2008 period as compared to the 2007 period. Higher costs for the 2008 six-month period were the result of increasing investor relations activities, additional regulatory filing requirements, business improvement initiatives and KGS’ ongoing costs associated with activities and requirements for a publicly-traded partnership.

Interest Expense

Interest expense for the first six months of 2008 was $26.3 million, net of capitalized interest of $3.6 million, which was a decrease of $6.9 million compared to the first six months of 2007. Interest expense for the first half of 2008 was lower than the comparable 2007 period in part because of an additional $2.7 million of capitalized interest and a decrease in the average interest rate on our debt balances outstanding.

Income Tax Expense

	Six Months Ended
	June 30,
	2008			2007
Income tax (in thousands)	$	52,468		$	24,065
Effective tax rate		35.3	%		30.5	%

The provision for income taxes for the first six months of 2008 increased from the prior year period due largely to an increase in pretax income for the 2008 period. The increase in the effective tax rate for the 2008 period resulted from higher non-deductible expenses related to officers’ compensation and the absence of tax credits for research and development in Canada that were recognized in the first half of 2007. Income tax also increased by $2.2 million for Texas margin deferred income taxes.

LIQUIDITY, CAPITAL RESOURCES AND FINANCIAL POSITION

	For the Six Months Ended
	June 30,
	2008			2007
	(In thousands)
Net cash provided by operating activities	$	136,611		$	154,548
Net cash used for investing activities		(629,526	)		(442,338	)
Net cash provided by financing activities		466,571			283,883
Effect of exchange rate changes in cash		447			1,884

Net cash provided by operations decreased compared to the same period in 2007 primarily due to a $47 million payment for 2007 U.S. federal income tax as compared to no such payments in the 2007 period. Net income of $94.6 million for the first six months

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of 2008 was $40.0 million higher than net income for the first six months of 2007. Operating cash flow was also adversely impacted by increases in working capital.

Our principal sources of cash are revenues generated by our production. Price collars and swaps covered approximately 68% of our total production for the six months ended June 30, 2008. As of July 31, 2008, we had price collars or fixed price swaps hedging our anticipated natural gas, oil and NGL production of approximately 178 MMcfd, 1,000 Bbld and 3,000 Bbld, respectively, for the remainder of 2008. We have hedged approximately 190 MMcfd and 160 MMcfd of our anticipated 2009 and 2010 natural gas sales, respectively, using price collars and fixed-price swaps.

During the first six months of 2007, the Northeast Operations generated cash of approximately $45.5 million. Distributions on our BBEP units were $20.3 million during the comparable 2008 period and have been reported as investing cash flows.

During the first six months of 2008, we paid $650.4 million for property and equipment, an increase of approximately $208 million from the comparable 2007 period. Property and equipment acquired (payments for property and equipment plus noncash changes in working capital associated with property and equipment) for the 2008 period totaled $649.2 million, which consisted primarily of $531.0 million expended for exploration and development activities and $106.8 million expended for our Fort Worth basin gas processing and gathering operations. Of the $531.0 million incurred for exploration and development, $19.7 million and $53.8 million was spent for acquisition of non-producing leasehold in the United States and Canada, respectively, inclusive of our acquisitions of acreage in the Horn River Basin in northeast British Columbia.

	Six Months Ended
	June 30, 2008
	(In thousands)
Exploration and development:
Texas	$	435,157
Other U.S.		10,761
Total U.S.		445,918
Canada		85,032
Total exploration and development		530,950
Midstream:
Texas		108,300
Canada		1,857
Total midstream		110,157
Corporate and field office		8,113
Total plant and equipment costs incurred	$	649,220

Net cash provided by financing activities for the six months ended June 30, 2008 totaled $466.6 million. On June 27, 2008, we issued $475 million in Senior Notes due in 2015 which generated net proceeds of $457 million after discount and underwriting and professional fees. The Senior Notes due 2015 bear interest at an annual rate of 8.25% payable semiannually on February 1 and August 1 of each year. All net proceeds from the transaction were used to reduce existing borrowings outstanding under our senior credit facility. The loan agreements for the senior credit facility prohibit the declaration or payment of dividends by us and contain certain financial covenants, which, among other things, require the maintenance of a minimum current ratio and a minimum earnings (before interest, taxes, depreciation, depletion, amortization, non-cash income and expense and exploration costs) to interest ratio. As of May 9, 2008, the borrowing base under our senior secured credit facility was increased to $1 billion from $750 million and is subject to a special redetermination on or about September 15, 2008. At June 30, 2008, approximately $730 million was available for borrowing under our senior secured credit facility, and we were in compliance with all of our covenants.

KGS’ $150 million senior secured credit facility had $55.3 million of borrowings outstanding at June 30, 2008, and KGS was in compliance with all of its covenants. Approximately $84.3 million was available for borrowing under the KGS senior secured credit facility at June 30, 2008.

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As of June 30, 2008 and December 31, 2007, we had the following total capitalization:

	June 30,		Decenber 31,
	2008		2007
	(In thousands)
Long-term and short-term debt:
Senior secured credit facility	$	266,750	$	310,710
Senior notes due 2015		468,611		—
Senior subordinated notes due 2016		350,000		350,000
Convertible subordinated debentures		148,163		148,107
KGS credit agreement		55,300		5,000
Other loans		—		34
Total debt		1,288,824		813,851
Stockholders’ equity		923,628		1,068,355
Total capitalization	$	2,212,452	$	1,882,206

After funding estimated remaining 2008 capital expenditures of approximately $450 million, a part of the cash portion of the purchase price payable in the Alliance Transaction (see below), net operating costs and interest expense, we expect the borrowings outstanding under our senior secured credit facility and the KGS credit facility to increase by approximately $450 million to $500 million during the second half of 2008.

Financial Position

The following impacted our balance sheet as of June 30, 2008, as compared to our balance sheet as of December 31, 2007:

• An increase of over $560.3 million in our net property, plant and equipment assets, which includes approximately $649.2 million in capital costs incurred principally for development, exploitation and exploration of our oil and gas properties as well as additional natural gas processing and gathering system assets.

• We incurred additional long-term debt of $475 million, primarily as a result of our capital expenditure program and partially offset by cash flow from operations. Borrowings were drawn from our senior secured credit facility and the KGS credit facility. A portion of the borrowings under our senior secured credit facility were repaid with the proceeds from the issuance of our Senior Notes due 2015.

• Our current and non-current derivative liabilities have increased $233.0 million and $105.6 million, respectively. Our current derivative liabilities include $45.6 million for the estimated fair value of the Michigan Sales Contract, net of the swap valuation of $38.7 million for the fixed-price swaps entered into in January 2008 to offset our net earnings exposure for the remaining contract period under the Michigan Sales Contract. All other changes in derivative assets and liabilities reflect changes in the estimated fair value of our cash-flow hedges. The changes are the result of higher pricing of natural gas, crude oil and NGLs compared to our derivative contracts at June 30, 2008 as market prices have generally trended upward. Additionally, our current deferred tax asset increased $79.0 million as a result of the increase in estimated fair value of our natural gas, crude oil and NGL financial derivatives.

Alliance Transaction

On July 7, 2008, we announced that we had entered into agreements to acquire leasehold, royalty and midstream assets, associated with the Barnett Shale in northern Tarrant and southern Denton counties of Texas, for consideration of $1 billion in cash and $307 million in Quicksilver Resources common stock, subject to customary closing adjustments. We expect to fund the cash portion of the transaction through a combination of cash on hand, borrowings under both a proposed $700 million five-year second-lien term loan facility and our existing credit facility. We expect that the proposed second-lien term loan will be issued at 98% of face value and have an initial interest rate of LIBOR plus 4.5% per annum, with an increase of 0.25% every 3 months after the second anniversary date of the note. The common stock issued in the transaction will be valued based on the volume weighted-average price for the 15 consecutive trading days immediately prior to the third trading day prior to closing the transaction which is scheduled to occur on August 8, 2008. We expect that the number of shares to be issued pursuant to the transaction will be approximately 10.7 million.

Upon completion, the Alliance Transaction will result in our acquisition of interests entitling us to an average net revenue interest of approximately 90% in production from approximately 13,000 acres in northern Tarrant and southern Denton counties. Based upon information provided to us by the sellers and our own internal estimates, we believe that the acquisition will add natural gas

34

production of 40 MMcfd, 350 Bcf of proved natural gas reserves and a significant amount of additional resource potential to our existing base assets. The transaction will also increase the absolute value of operating expenses and severance taxes, although the impact of such costs on a unit basis is still to be determined. Furthermore, the transaction will likely cause our consolidated depletion, depreciation and amortization rate to increase from $1.82 per Mcfe for the first half of 2008 to a rate of $2.15 per Mcfe to $2.20 per Mcfe for the second half of 2008.

Contractual Obligations and Commercial Commitments

Significant changes to our contractual obligations and commercial commitments not otherwise disclosed as of June 30, 2008 include the following:

• We have commitments of approximately $43 million outstanding to purchase components for our drilling program; and,

• We have issued additional surety bonds to fulfill contractual, legal or regulatory requirements bringing the total of surety bonds outstanding to approximately $27 million.

Accounting Developments

The information regarding recent accounting pronouncements is included in Note 1 to our condensed consolidated interim financial statements included in Item 1 of this quarterly report.

Critical Accounting Estimates

Management’s discussion and analysis of financial condition and results of operations are based on our condensed consolidated financial statements and related footnotes contained within this quarterly report. Our more critical accounting estimates used in the preparation of the consolidated financial statements were discussed in our 2007 Annual Report on Form 10-K. These critical estimates, for which no significant changes have occurred in the six months ended June 30, 2008, include estimates and assumptions for:

• Oil and gas properties, including underlying reserves and cost capitalization limitations;

• Derivative instruments;

• Asset retirement obligations;

• Stock-based compensation;

• Income taxes;

• Equity earnings from BreitBurn Energy Partners; and,

• Revenue.

The process of preparing financial statements in conformity with GAAP requires the use of estimates and assumptions to determine certain of the assets, liabilities, revenues and expenses. 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.

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 related to fluctuations in natural gas, oil and NGL commodity prices. We have mitigated the risk of adverse price movements through the use of swaps and collars; however, we have also limited future gains from favorable movements.

Commodity Price Risk

We enter into financial derivative contracts to mitigate our exposure to commodity price risk associated with anticipated future natural gas, NGL and crude oil production. As of July 31, 2008, approximately 118 MMcfd and 60 MMcfd of natural gas price collars and swaps, respectively, have been put in place to hedge a portion of our anticipated production for the remainder of 2008. Additionally, we have used fixed-price swaps and swaps to hedge 3,000 Bbld of NGL and 1,000 Bbld of oil, respectively, of our anticipated production for the remainder of 2008. Anticipated 2009 and 2010 natural gas production of approximately 190 MMcfd and 160 MMcfd, respectively, has been hedged using price collars and swaps, respectively. We believe we will have more predictability of our natural gas, oil and NGL revenues as a result of these financial derivative contracts.

35

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 $34.6 million lower and $21.4 million higher as a result of our hedging programs for the first six months of 2008 and 2007, respectively. Other revenue was $9.9 million lower and $1.0 million higher as a result of hedging ineffectiveness for the six-month periods ending June 30, 2008 and 2007, respectively.

The following table summarizes our open derivative positions as of June 30, 2008 related to our future natural gas, NGL and crude oil production.

				Weighted Avg
				Price Per
Product	Type	Contract Period	Volume	Mcf or Bbl		Fair Value
						(In thousands)
Gas	Swap	Jul 2008-Dec 2008	25,000 Mcfd	$	8.13	$	(24,735	)
Gas	Swap	Jul 2008-Dec 2008	7,500 Mcfd		8.13		(7,420	)
Gas	Swap	Jul 2008-Dec 2008	5,000 Mcfd		8.14		(4,938	)
Gas	Swap	Jul 2008-Dec 2008	2,500 Mcfd		8.15		(2,464	)
Gas	Swap	Jul 2008-Dec 2008	10,000 Mcfd		8.21		(9,748	)
Gas	Swap	Jul 2008-Dec 2008	10,000 Mcfd		8.22		(9,729	)
Gas	Swap	Jan 2009-Dec 2009	10,000 Mcfd		8.45		(14,453	)
Gas	Swap	Jan 2009-Dec 2009	10,000 Mcfd		8.45		(14,453	)
Gas	Swap	Jan 2009-Dec 2009	20,000 Mcfd		8.46		(28,869	)
Gas	Collar	Jul 2008-Dec 2008	20,000 Mcfd		7.50- 9.15		(16,134	)
Gas	Collar	Jul 2008-Dec 2008	10,000 Mcfd		9.00-11.70		(3,963	)
Gas	Collar	Jul 2008-Dec 2008	20,000 Mcfd		8.25- 9.75		(14,381	)
Gas	Collar	Oct 2008-Dec 2008	10,000 Mcfd		9.00-12.60		(1,978	)
Gas	Collar	Jul 2008-Mar 2009	20,000 Mcfd		7.50- 9.35		(23,657	)
Gas	Collar	Jul 2008-Mar 2009	20,000 Mcfd		8.00-10.20		(19,512	)
Gas	Collar	Jan 2009-Dec 2009	20,000 Mcfd		7.50- 9.34		(23,754	)
Gas	Collar	Jan 2009-Dec 2009	20,000 Mcfd		7.75-10.20		(19,563	)
Gas	Collar	Jan 2009-Dec 2009	10,000 Mcfd		7.75-10.26		(9,627	)
Gas	Collar	Jan 2009-Dec 2009	20,000 Mcfd		8.25- 9.60		(21,780	)
Gas	Collar	Jan 2009-Dec 2009	10,000 Mcfd		8.25-10.45		(9,116	)
Gas	Collar	Jan 2009-Dec 2009	10,000 Mcfd		8.25-10.45		(9,116	)
Gas	Collar	Jan 2009-Dec 2009	10,000 Mcfd		8.25-10.45		(9,116	)
Gas	Collar	Apr 2009-Dec 2009	10,000 Mcfd		8.50-13.15		(2,689	)
Gas	Collar	Jan 2010-Dec 2010	20,000 Mcfd		8.00-11.00		(10,198	)
Gas	Collar	Jan 2010-Dec 2010	20,000 Mcfd		8.00-11.00		(10,198	)
Gas	Collar	Jan 2010-Dec 2010	20,000 Mcfd		8.00-12.20		(7,371	)
Gas	Collar	Jan 2010-Dec 2010	20,000 Mcfd		8.00-12.20		(7,371	)
Gas	Collar	Jan 2010-Dec 2010	20,000 Mcfd		8.50-12.05		(6,764	)
Gas	Collar	Jan 2010-Dec 2010	10,000 Mcfd		8.50-12.05		(3,382	)
Gas	Collar	Jan 2010-Dec 2010	10,000 Mcfd		8.50-12.08		(3,317	)
Gas	Basis	Jul 2008-Dec 2008	10,000 Mcfd				1,163
Gas	Basis	Jul 2008-Dec 2008	10,000 Mcfd				1,163
NGL	Swap	Jul 2008-Dec 2008	1,000 Bbld		39.58		(5,648	)
NGL	Swap	Jul 2008-Dec 2008	2,000 Bbld		45.94		(9,162	)
Oil	Collar	Jul 2008-Dec 2008	500 Bbld		65.00-73.90		(5,441	)
Oil	Collar	Jul 2008-Dec 2008	500 Bbld		65.00-77.45		(5,119	)
				Total		$	(372,840	)

At June 30, 2008, we had nine months remaining on our obligation to deliver 25 MMcfd of natural gas under the Michigan Sales Contract. In December 2007, we determined we would no longer deliver a portion of our natural gas production to supply the

36

contractual volumes under the Michigan Sales Contract. At that time, we recognized a loss of $63.5 million for the fair value of the Michigan Sales Contract through the end of its term in March 2009. In January 2008, we entered into two fixed-price natural gas swaps covering all volumes for the remaining contract period, which served to effectively offset the net earnings exposure of our remaining obligation under the Michigan Sales Contract. During 2008, we have made $17.8 million of net cash payments for settlement of obligations for the Michigan Sales Contract. The following table summarizes these open positions as of June 30, 2008.

				Weighted Avg
				Price Per
Product	Type	Contract Period	Volume	Mcf or Bbl		Fair Value
						(In thousands)
Gas	Sale	Jul 2008-Mar 2009	25,000 Mcfd	$	2.49	$	(84,313	)
Gas	Swap	Jul 2008-Mar 2009	10,000 Mcfd		8.20		15,367
Gas	Swap	Jul 2008-Mar 2009	15,000 Mcfd		8.20		23,050
				Total		$	(45,896	)

The fair value of all derivative instruments included above was estimated using commodity prices quoted in active markets for the periods covered by the derivatives and the value confirmed by a counterparty. Estimates were determined by applying the net differential between the prices in each derivative and market prices for future periods, as adjusted for estimated basis differential, to the volumes 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.

Credit Risk

During the six months ended June 30, 2008, we had NGL sales of $96.2 million to two parties. These sales represent 27% of our consolidated production revenue during the six months then ended. In accordance with our established credit policy, we review each counterparty for credit worthiness prior to the extension of credit and regularly monitor our exposure to all counterparties by reviewing credit ratings, financial statements and credit service reports. We maintain credit limits for each of our customers and parental guarantees and collateral are used to manage our exposure to counterparties according to our established policy.

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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, 2008, 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, 2008 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

Based on an order entered on May 13, 2008, our case against Eagle is now pending before the United States District Court for the Southern District of Texas, Houston Division. It is currently set for trial on September 15, 2008.

Other than this change in the Eagle litigation, there have been no material changes in legal proceedings from those described in Part I, Item 3. “Legal Proceedings” included in our 2007 Annual Report on Form 10-K, filed with the SEC on February 28, 2008.

ITEM 1A. Risk Factors

There have been no material changes in risk factors from those described in Part I, Item 1A. “Risk Factors” included in our 2007 Annual Report on Form 10-K, filed with the SEC on February 28, 2008.

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, 2008.

					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 2008		8,584	$	41.63		—		—
May 2008		218	$	38.97		—		—
June 2008		184	$	39.85		—		—
Total		8,986	$	41.53		—		—

(1)	Represents shares of common stock surrendered by employees to satisfy our income tax withholding obligations arising upon the vesting of restricted stock issued under our Amended and Restated 1999 Stock Option and Retention Stock Plan or Amended and Restated 2006 Equity Plan.
(2)	We do not currently have in place any publicly announced, specific plans or programs to purchase equity securities.

ITEM 3. Defaults Upon Senior Securities

None.

ITEM 4. Submission of Matters to a Vote of Security Holders

The following items of business were presented to the stockholders at the annual meeting held on May 21, 2008.

Election of Directors

     At the meeting, three directors were elected to serve terms expiring at the Company’s Annual Meeting of Stockholders to be held in 2011. The vote with respect to the election of these directors was as follows:

			Total Vote
	Total Vote for		Withheld for
Name	Each Director		Each Director
Thomas F. Darden		144,842,890		5,138,337
W. Byron Dunn		137,223,350		12,757,877
Mark J. Warner		148,232,362		1,748,865

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Glenn Darden, James A. Hughes, Steven M. Morris, W. Yandell Rogers III and Anne Darden Self continue to serve as directors of the Company.

Approval of Quicksilver’s Amended and Restated Certificate of Incorporation

     At the meeting, stockholders approved the Quicksilver Resources Inc. Amended and Restated Certificate of Incorporation as follows:

For	115,079,609
Against	25,642,489
Abstentions	19,892

ITEM 5. Other Information

None.

ITEM 6. Exhibits:

Exhibit No.	Description
3.1	Amended and Restated Certificate of Incorporation of Quicksilver Resources Inc. filed with the Secretary of State of the State of Delaware on May 21, 2008 (filed as Exhibit 4.1 to the Company’s Form S-3, File No. 333-151847, filed June 23, 2008 and included herein by reference).
4.1	Fifth Supplemental Indenture, dated as of June 27, 2008, among Quicksilver Resources Inc., the subsidiary guarantors named therein and The Bank of New York Trust Company, N.A., as trustee (filed as Exhibit 4.1 to the Company’s Form 8-K filed June 30, 2008 and included herein by reference).
10.1	Fourth Amendment to Combined Credit Agreements, dated as of June 20, 2008, among Quicksilver Resources Inc., Quicksilver Resources Canada Inc. and the agents and combined lenders identified therein (filed as Exhibit 10.1 to the Company’s Form 8-K filed June 25, 2008 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.

* 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 6, 2008

Quicksilver Resources Inc.
By:	/s/ Glenn Darden
	Glenn Darden
	President and Chief Executive Officer
By:	/s/ Philip Cook
	Philip Cook
	Senior Vice President — Chief Financial Officer

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EXHIBIT INDEX

Exhibit No.	Description
3.1	Amended and Restated Certificate of Incorporation of Quicksilver Resources Inc. filed with the Secretary of State of the State of Delaware on May 21, 2008 (filed as Exhibit 4.1 to the Company’s Form S-3, File No. 333-151847, filed June 23, 2008 and included herein by reference).
4.1	Fifth Supplemental Indenture, dated as of June 27, 2008, among Quicksilver Resources Inc., the subsidiary guarantors named therein and The Bank of New York Trust Company, N.A., as trustee (filed as Exhibit 4.1 to the Company’s Form 8-K filed June 30, 2008 and included herein by reference).
10.1	Fourth Amendment to Combined Credit Agreements, dated as of June 20, 2008, among Quicksilver Resources Inc., Quicksilver Resources Canada Inc. and the agents and combined lenders identified therein (filed as Exhibit 10.1 to the Company’s Form 8-K filed June 25, 2008 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.

* Filed herewith

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