Quicksilver Resources 10Q 2008 Q3 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 September 30, 2008


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

For the transition period from to

Commission file number: 001-14837

Quicksilver Resources Inc.

(Exact name of registrant as specified in its charter)


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


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

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

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

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for at least the past 90 days. Yesþ Noo

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


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

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

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


Title of Class		Outstanding as of October 31, 2008

Common Stock, $0.01 par value		166,870,164

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


	Page
PART I. FINANCIAL INFORMATION

Item 1. Financial Statements (Unaudited)

Condensed Consolidated Statements of Income (Loss) and Comprehensive 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		24

Item 3. Quantitative and Qualitative Disclosures About Market Risk		37

Item 4. Controls and Procedures		40

PART II. OTHER INFORMATION

Item 1. Legal Proceedings		41

Item 1A. Risk Factors		41

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		41

Item 3. Defaults Upon Senior Securities		42

Item 4. Submission of Matters to a Vote of Security Holders		42

Item 5. Other Information		42

Item 6. Exhibits		42

Signatures		43

DEFINITIONS

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

“ABR” means Alternative Bank Rate

“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 of natural gas

“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 Acquisition” means the August 8, 2008 purchase of leasehold, royalty and midstream assets in 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 promulgates accounting standards in the United States

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

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

“Michigan Sales Contract” means the gas supply contract which terminates in March 2009 under which we agreed to 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 we 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

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:

•		changes in general economic conditions;

•		fluctuations in natural gas, NGL and crude oil prices;

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

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

•		effects of hedging natural gas, NGL and crude oil prices;

•		fluctuations in the value of certain of our assets and liabilities;

•		competitive conditions in our industry;

•		actions taken or non-performance by third parties, including suppliers, contractors operators, processors, transporters, customers and counterparties;

•		changes in the availability and cost of capital;

•		delays in obtaining oilfield equipment and increases in drilling and other service costs;

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

•		the effects of existing and future laws and governmental regulations; 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.

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements (Unaudited)

QUICKSILVER RESOURCES INC.

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME

In thousands, except for per share data — Unaudited


	For the Three Months Ended						For the Nine Months Ended
	September 30,						September 30,
	2008			2007			2008			2007
Revenues
Natural gas, NGL and crude oil sales	$	218,214		$	151,046		$	574,717		$	398,297
Other		18,048			8,153			17,063			13,880

Total revenues		236,262			159,199			591,780			412,177


Operating expenses
Oil and gas production expense		33,467			44,246			99,557			104,804
Production and ad valorem taxes		4,448			4,366			9,315			13,068
Other operating costs		975			855			2,934			1,940
Depletion, depreciation and accretion		51,777			32,115			125,756			84,614
General and administrative		25,605			14,328			56,402			34,324

Total expenses		116,272			95,910			293,964			238,750
Income from equity affiliates		—			285			—			682

Operating income		119,990			63,574			297,816			174,109

Equity loss from BreitBurn Energy Partners		89,814			—			93,864			—
Other expense (income) — net		2,113			(385	)		1,055			(1,856	)
Interest expense		34,327			20,690			60,625			53,858

Income (loss) before income taxes and minority interest		(6,264	)		43,269			142,272			122,107
Income tax expense (benefit)		(4,714	)		14,093			47,754			38,158
Minority interest expense, net of income tax		1,125			457			2,621			648

Net income (loss)	$	(2,675	)	$	28,719		$	91,897		$	83,301

Other comprehensive income (loss) — net of income tax
Reclassification adjustments related to settlements of derivative contracts		17,500			(15,146	)		40,396			(29,299	)
Net change in derivative fair value		308,096			14,547			46,847			(4,381	)
Foreign currency translation adjustment		(11,044	)		13,698			(17,858	)		28,678

Comprehensive income	$	311,877		$	41,818		$	161,282		$	78,299


Earnings (loss) per common share — basic	$	(0.02	)	$	0.18		$	0.57		$	0.54

Earnings (loss) per common share — diluted	$	(0.02	)	$	0.17		$	0.54		$	0.50

Basic weighted average shares outstanding		164,087			155,750			159,914			155,114

Diluted weighted average shares outstanding		164,087			168,370			171,759			168,028

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

QUICKSILVER RESOURCES INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

In thousands, except for share data — Unaudited


	September 30,			December 31,
	2008			2007
ASSETS
Current assets
Cash and cash equivalents	$	13,465		$	28,226
Accounts receivable — net of allowance for doubtful accounts		106,776			90,244
Derivative assets at fair value		74,966			10,797
Current deferred income tax asset		—			18,946
Other current assets		59,854			42,188

Total current assets		255,061			190,401

Investment in BreitBurn Energy Partners		294,872			420,171

Property, plant and equipment
Oil and gas properties, full cost method (including unevaluated costs of $745,684 and $215,228, respectively)		3,633,013			1,764,400
Other property and equipment		597,279			377,946

Property, plant and equipment — net		4,230,292			2,142,346
Derivative assets at fair value		55,044			354
Other assets		49,071			22,574

	$	4,884,340		$	2,775,846

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current portion of long-term debt	$	6,956		$	34
Accounts payable		226,792			192,855
Income taxes payable		187			46,601
Accrued liabilities		58,034			54,981
Derivative liabilities at fair value		26,741			64,104
Current deferred tax liability		14,454			—

Total current liabilities		333,164			358,575

Long-term debt		2,474,687			813,817
Asset retirement obligations		28,300			23,864
Derivative liabilities at fair value		46			16,327
Other liabilities		12,929			10,609
Deferred income taxes		426,327			374,645
Deferred gain on sale of partnership interests		79,316			79,316
Minority interests in consolidated subsidiaries		28,782			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; 171,706,359 and 160,633,270 shares issued, respectively		1,717			1,606
Paid in capital in excess of par value		546,791			272,515
Treasury stock of 2,686,622 and 2,616,726 shares, respectively		(15,539	)		(12,304	)
Accumulated other comprehensive income		109,451			40,066
Retained earnings		858,369			766,472

Total stockholders’ equity		1,500,789			1,068,355

	$	4,884,340		$	2,775,846

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

QUICKSILVER RESOURCES INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

In thousands — Unaudited


	For the Nine Months Ended
	September 30,
	2008			2007
Operating activities:
Net income	$	91,897		$	83,301
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation and accretion		125,756			84,614
Deferred income taxes		45,036			37,912
Stock-based compensation		11,810			9,415
Amortization of deferred charges		1,669			1,659
Amortization of deferred loan costs		2,531			1,458
Minority interest expense		2,621			648
Non-cash loss (gain) from hedging and derivative activities		(2,065	)		(2,959	)
Non-cash loss (income) from equity affiliates		93,864			(682	)
Other		276			616
Changes in assets and liabilities
Accounts receivable		(16,532	)		6,754
Other assets		(4,819	)		1,545
Accounts payable		(9,619	)		511
Income taxes payable		(46,414	)		157
Accrued and other liabilities		(21,891	)		36,750

Net cash provided by operating activities		274,120			261,699


Investing activities:
Purchases of property, plant and equipment		(985,124	)		(720,208	)
Alliance Acquisition		(990,649	)		—
Return of investment from BBEP and equity affiliates		31,435			162
Proceeds from sales of properties and equipment		818			166

Net cash used for investing activities		(1,943,520	)		(719,880	)


Financing activities:
Issuance of senior notes		468,611			—
Issuance of term loans		686,000			—
Repayment of notes and loans		(1,784	)		—
Credit facility borrowings — net		537,304			357,673
Debt issuance costs		(24,545	)		(4,513	)
Minority interest contributions		—			109,809
Minority interest distributions		(6,343	)		(7,694	)
Proceeds from exercise of stock options		1,240			15,570
Purchase of treasury stock		(3,235	)		(1,525	)

Net cash provided by financing activities		1,657,248			469,320

Effect of exchange rate changes in cash		(2,609	)		3,170

Net (decrease) increase in cash		(14,761	)		14,309
Cash and cash equivalents at beginning of period		28,226			5,281


Cash and cash equivalents at end of period	$	13,465		$	19,590

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

QUICKSILVER RESOURCES INC.

NOTES TO CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS

UNAUDITED

1. ACCOUNTING POLICIES AND DISCLOSURES

The accompanying condensed consolidated interim financial statements 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 September 30, 2008 and its results of operations for the three- and nine-month periods ended September 30, 2008 and 2007 and cash flows for the nine-month periods ended September 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 (loss) per common share is computed by dividing the net income (loss) 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. Dilution is not computed for periods in which the Company reports a net loss.

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 nine-month periods ended September 30, 2008 and 2007. For the quarter ended September 30, 2008, all dilutive securities were excluded from the diluted net loss per share calculation as they were antidilutive. Additionally, outstanding options to purchase 4,802 shares were antidilutive and excluded from the diluted net income per share calculation for the three- and nine-month periods ended September 30, 2007.


	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2008			2007		2008		2007
	(In thousands, except per					(In thousands, except per
	share data)					share data)
Net income (loss)	$	(2,675	)	$	28,719	$	91,897	$	83,301

Impact of assumed conversions — interest on 1.875% convertible debentures, net of income taxes		—			475		1,425		1,425

Income (loss) available to stockholders assuming conversion of convertible debentures	$	(2,675	)	$	29,194	$	93,322	$	84,726


Weighted average common shares — basic		164,087			155,750		159,914		155,114
Effect of dilutive securities:
Employee stock options		—			1,314		677		1,526
Employee stock and stock unit awards		—			1,490		1,352		1,572
Contingently convertible debentures		—			9,816		9,816		9,816

Weighted average common shares — diluted		164,087			168,370		171,759		168,028


Earnings (loss) per common share — basic	$	(0.02	)	$	0.18	$	0.57	$	0.54

Earnings (loss) per common share — diluted	$	(0.02	)	$	0.17	$	0.54	$	0.50

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. FSP FAS 157-3 was issued by the FASB on October 10, 2008 to clarify application of SFAS No. 157 when determining the fair value of a financial asset when the market for that financial asset is not active. 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

“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. 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 effect, 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 the effect FSP APB 14-1 will have on our consolidated financial statements.

2. ALLIANCE ACQUISITION

On August 8, 2008, Quicksilver completed the Alliance Acquisition, whereby the Company acquired leasehold, royalty and midstream assets associated with the Barnett Shale formation in northern Tarrant and southern Denton counties of Texas. The purchase price funded, in part, using $316 million of borrowings under its existing senior secured credit facility and proceeds of $674.5 million from the issuance of a $700 million five-year second-lien term loan facility is presented below:


(In thousands)

Purchase Price:
Cash paid	$	1,000,000
Cash received from post-closing settlement		(10,851	)
Cash paid for acquisition-related expenses		1,500

Total cash		990,649
Issuance of 10,400,468 common shares		262,092

	$	1,252,741

Quicksilver’s preliminary purchase price allocation is presented below:


(In thousands)

Allocation of Purchase Price:
Oil and gas properties — proved	$	787,918
Oil and gas properties — unproved		436,066
Midstream assets		30,024
Liabilities assumed		(496	)
Asset retirement obligations		(771	)

	$	1,252,741

The preliminary purchase price allocation is based on preliminary estimates of oil and gas reserves and other valuations and estimates by management and is subject to final closing adjustments and determination of the valuation of tangible assets related to wells, pipelines and facilities. The Company expects to finalize the purchase price allocation during the quarter ending September 30, 2009.

Pro Forma Information

The following table reflects the Company’s unaudited consolidated pro forma statements of income as though the Alliance Acquisition, associated borrowings and issuance of Company common stock had occurred at the beginning of each year presented. The revenue and expenses for the acquisition are included in the 2008 consolidated results of the Company effective August 8, 2008. The pro forma information is not necessarily indicative of the results of operations that would have been achieved if the acquisition had been effective at the beginning of each year presented.


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2008		2007		2008		2007
	(In thousands, except per share data)
Revenues	$	249,956	$	178,267	$	667,762	$	461,617


Net income	$	968	$	15,513	$	88,727	$	43,487


Earnings per share — basic	$	0.01	$	0.09	$	0.53	$	0.26

Earnings per share — diluted	$	0.01	$	0.09	$	0.50	$	0.25

3. 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 September 30, 2008.


	Fair Value Measurements as of September 30, 2008
										Balance Sheet
	Level 1		Level 2		Level 3		Other⁽¹⁾			Total
	(in thousands)
Derivative assets	$	—	$	133,588	$	—	$	(3,578	)	$	130,010


Derivative liabilities	$	—	$	30,365	$	—	$	(3,578	)	$	26,787


⁽¹⁾		Represents amounts netted under master netting arrangements.

The Company’s derivative instruments at September 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 cease delivering a portion of its 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 largely eliminate future earnings exposure for the Company’s remaining obligation under the Michigan Sales Contract. During 2008, the Company has paid $34.2 million, net of derivative settlements, to meet its obligations under 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 principally resulted from the decrease in market prices for natural gas, NGL and oil relative to the prices in our derivative instruments and, to a lesser degree, from settlements made during the nine months ended September 30, 2008. During the nine months ended September 30, 2008, the changes in derivative valuation reflected volatility in natural gas, oil and NGL prices including the recent high market prices in the futures market relative to our derivative positions at June 30, 2008 and the significant decreases in the futures market during the third quarter of 2008 that more than offset the increases of the first six months of 2008 and significantly impacted the value of our derivative positions. 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 remaining contract period 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 Company recorded other revenue of $3.7 million and $3.0 million as the result of derivative hedge ineffectiveness for the nine months ended September 30, 2008 and 2007, respectively.

The estimated fair values of all financial derivatives and contractual fixed-price sale commitments of the Company as of September 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.


	September 30,		December 31,
	2008		2007
	(in thousands)
Derivative assets:
Natural gas basis swaps	$	1,089	$	—
Natural gas fixed-price swaps		7,790		4,666
Natural gas price collars		124,709		10,491

	$	133,588	$	15,157


Derivative liabilities:
Natural gas basis swaps	$	537	$	1,224
Natural gas price collars		102		1,625
Natural gas fixed-price swaps⁽¹⁾		1,493		—
Crude oil price collars		2,954		6,517
NGL fixed-price swaps		793		11,294
Fixed-price natural gas sales contracts⁽²⁾		24,486		63,777

	$	30,365	$	84,437


⁽¹⁾		Includes $1.5 million and $ — million for two fixed-priced swaps related to the Michigan Sales Contract at September 30, 2008 and December 31, 2007, respectively.

⁽²⁾		Includes $24.5 million and $63.5 million for the Michigan Sales Contract at September 30, 2008 and December 31, 2007, respectively.

Cash flow hedge derivative assets and liabilities of $74.2 million have been classified as current at September 30, 2008 based on their maturity. The effective portion of the derivative assets and liabilities held in accumulated other comprehensive income expected to be reclassified to earnings over the next twelve months is $49.9 million of after-tax net gain. The non-current portion of effective cash flow hedges will be reclassified to earnings from accumulated other comprehensive income over the fifteen-month period ending December 31, 2010.

4. INVESTMENT IN BREITBURN ENERGY PARTNERS L.P.

The Company received 21.3 million common units of BBEP, a publicly-traded limited partnership primarily engaged in natural gas, NGL and crude oil production in the United States, 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% of the BBEP common units outstanding as of June 17, 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. Quicksilver’s increased ownership of units resulting from the repurchase of outstanding units by BBEP is reflected in Quicksilver’s results for the quarter ended September 30, 2008.

Summarized unaudited financial information for BBEP is as follows:



	As of
	June 30, 2008
	(In thousands)
Current assets	$	115,294
Property, plant and equipment		1,880,340

Other assets		14,825
Current liabilities		275,976
Long-term debt		694,000
Other non-current liabilities		357,073

Partners’ equity		699,421




	For the Eight Months
	Ended
	June 30, 2008
	(In thousands)
Revenues	$	(118,175	)
Operating expenses		181,747

Operating income		(299,922	)
Interest and other		16,274
Income tax benefit		(2,006	)
Minority interests		155

Net loss	$	(314,345	)

Net loss available to common unitholders	$	(312,794	)

For the nine months ended September 30, 2008, the Company has recognized a $93.9 million loss from its share of BBEP’s loss for the eight months ended June 30, 2008 (reflecting the Company’s ownership period), inclusive of an $89.8 million loss for BBEP’s quarter ended June 30, 2008. The Company’s share of BBEP’s loss includes adjustments to depletion and depreciation expense and intangible asset amortization. During 2008, the Company has received $31.4 million in distributions from BBEP, including $11.1 million during the third quarter. The Company expects to receive an additional $11.1 million in distributions in November 2008.

At September 30, 2008, the Company’s carrying value for its BBEP common units was $294.9 million inclusive of a $286.7 million gain deferred from the transaction. The market value of the Company’s BBEP units was $317.2 million, or $14.86 per common unit, at September 30, 2008. On October 31, 2008, BBEP units had reduced to a fair value of $11.24 per unit. Should the carrying value of the Company’s BBEP units exceed market value at December 31, 2008, the Company would be required to recognize a charge for impairment charge if the Company deems the decrease in value to be “other than temporary”.

5. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment consisted of the following:


	September 30,			December 31,
	2008			2007
	(In thousands)
Oil and gas properties
Subject to depletion	$	3,247,501		$	1,811,295
Unevaluated costs		745,684			215,228
Accumulated depletion		(360,172	)		(262,123	)

Net oil and gas properties		3,633,013			1,764,400
Other plant and equipment
Pipelines and processing facilities		525,980			347,187
General properties		46,649			32,966
Construction in progress		76,639			32,682
Accumulated depreciation		(51,989	)		(34,889	)

Net other property and equipment		597,279			377,946

Property, plant and equipment, net of accumulated depletion and depreciation	$	4,230,292		$	2,142,346

6. LONG-TERM DEBT

Long-term debt consisted of the following:


	September 30,			December 31,
	2008			2007
	(In thousands)
Senior secured credit facility	$	725,716		$	310,710
Second-lien term loan facility, net of unamortized discount		684,599			—
Senior notes due 2015, net of unamortized discount		468,837			—
Senior subordinated notes due 2016		350,000			350,000
Convertible debentures, net of unamortized discount		148,191			148,107
KGS credit agreement		104,300			5,000
Other loans		—			34

Total debt		2,481,643			813,851
Less current maturities		(6,956	)		(34	)

Long-term debt	$	2,474,687		$	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. Interest of 8.25% is 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, restricted subsidiaries distributions, affiliate transactions, mergers and consolidations. Net proceeds of $457 million after discount and issuance costs and were used to pay down balances outstanding under the senior secured credit facility.

On August 8, 2008, the Company entered into a $700 million five-year senior secured second-lien term loan facility (“Term Loan Facility”) pursuant to the Alliance Acquisition. Net proceeds were $674.5 million after discount and issuance costs. The Term Loan Facility’s interest rates are based on LIBOR or ABR options with minimum floors plus a spread. As of September 30, 2008, the interest rate under the Term Loan Facility was 7.75%. Additionally, on the last day of each quarter, the Company must repay 0.25% of the aggregate principal amount of the loan then outstanding. The credit agreement prohibits the declaration or payment of cash dividends by the Company and contains certain financial covenants, among other things, that require a minimum current ratio, a minimum interest coverage ratio, and minimum adjusted proved reserves to total and secured debt coverage ratios. In connection with the Term Loan Facility, on August 8, 2008, Quicksilver entered into collateral agreements pursuant to which Quicksilver’s obligations under the Term Loan Facility, its Senior Notes due 2015 and its domestic subsidiaries’ guaranty obligations with respect to the Term Loan Facility and the Senior Notes due 2015 have been secured equally and ratably by a second lien on substantially all of the assets of Quicksilver and such domestic subsidiaries.

During September of 2008, the Company’s borrowing base under its senior secured credit facility was increased by $200 million to $1.2 billion as the result of a redetermination. In connection with the Term Loan Facility, the senior secured credit facility added minimum total and secured debt to assets coverage ratios to the required financial covenants. As of September 30, 2008, interest was payable at a consolidated interest rate of 4.5%.

At September 30, 2008, KGS’ borrowing capacity was limited by $150 million in commitments. In October of 2008, the lenders commitments under KGS’ credit agreement increased $85 million to $235 million from $150 million. After the increase in commitments under its credit agreement, KGS’ borrowing capacity was limited by certain financial covenants to $168.8 million. The increase of commitments under the credit agreement was the result of an exercise of an accordion option in the facility. Furthermore, the lenders approved reinstatement of the accordion option at $115 million to allow for future expansion of the facility to $350 million with appropriate lender consent. As of September 30, 2008 interest was payable at an interest rate of 4.6%.

As of September 30, 2008, the Company was in compliance with all covenants under its credit facilities and other notes and loans.

For a more complete description of the Company’s indebtedness existing at December 31, 2007, see Note 13,Long-Term Debt,to the consolidated financial statements in the Company’s 2007 Annual Report on Form 10-K.

7. ASSET RETIREMENT OBLIGATIONS

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


(In thousands)

Beginning asset retirement obligations	$	24,510
Incremental liability incurred		4,314
Accretion expense		1,096
Change in estimates		361
Asset retirement costs incurred		(292	)
Currency translation adjustment		(1,043	)

Ending asset retirement obligations		28,946
Less current portion		(646	)

Long-term asset retirement obligations	$	28,300

8. INCOME TAXES

The following table provides a reconciliation of the changes in the Company’s unrecognized tax benefits for the nine-month period ended September 30, 2008:


(In thousands)

Unrecognized tax benefits at January 1, 2008	$	9,997
Gross increases in unrecognized tax benefits as a result of tax positions taken during a prior period		834
Gross decreases in unrecognized tax benefits as a result of tax positions taken during a prior period		(1,301	)
Reductions resulting from the lapse of applicable statutes of limitation		(275	)

Unrecognized tax benefits at September 30, 2008	$	9,255

The changes to the amounts of unrecognized tax benefits resulted in a 40 basis point increase in the Company’s effective income tax rate for the third quarter of 2008. As the Company expects a net loss for 2008 income tax purposes, there has been no interest expense recognized on the unrecognized tax benefits amounts for 2008. Furthermore, interest expense of $0.6 million recognized in 2007 has been reversed during the nine months ended September 30, 2008. The Company does not anticipate the total amounts of unrecognized tax benefits will significantly increase or decrease within the next 12 months.

The Internal Revenue Service completed its audit of the Company’s 2004 U.S. 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 nine months ended September 30, 2008, the Company paid $47.9 million for U.S. federal 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 such taxes.

9. COMMITMENTS AND CONTINGENCIES

For a complete description of commitments and contingencies at December 31, 2007, see Note 16,Commitments and Contingencies, to the consolidated financial statements in the Company’s 2007 Annual Report on Form 10-K.

Contingencies

In September 2008, the Company entered into a settlement agreement with Eagle Domestic Drilling Operations, LLC and its parent, Blast Energy Services, Inc. (“Eagle/Blast”) that was approved in October by the U.S. District Court for the Southern District of Texas. Under the settlement agreement, the Company agreed to pay Eagle/Blast $10 million over a three-year period, including $5 million on the settlement date. The Company recorded a $9.6 million charge to general and administrative expense during the quarter ended September 30, 2008 for the net present value of these payments. The portion of the suit in the Houston Federal District Court between the Company and Eagle Drilling, LLC and the related litigation against us and P. Jeffrey Cook by Eagle Drilling, LLC and Rod and Richard Thornton in the District Court of Cleveland County, Oklahoma, were not directly affected by this settlement.

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.

Commitments

The Company had commitments outstanding of approximately $87 million to purchase components for our drilling program as of September 30, 2008. In addition, the Company had approximately $36 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 nine months ended September 30, 2008, $71.9 million was paid to the third parties. KGS estimates additional payments of $33.1 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.

10. 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.

Quicksilver Stock Options

At January 1, 2008, the Company had total unrecognized compensation cost of $0.1 million related to unvested stock options. In the nine months ended September 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 $1.2 million and $0.3 million for stock options in the first nine months of 2008 and 2007, respectively. At September 30, 2008, the Company had $3.6 million remaining unrecognized compensation cost for the unvested portion of stock options.

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


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

The following table summarizes the Company’s stock option activity during the nine months ended September 30, 2008:


				Wtd Avg		Wtd Avg		Aggregate
				Exercise		Remaining		Intrinsic
	Shares			Price		Contractual Life		Value
						(In years)		(In thousands)
Outstanding at December 31, 2007		1,021,912		$	7.48
Granted		373,382			30.95
Exercised		(249,444	)		4.98
Cancelled		(42,226	)		28.20

Outstanding at September 30, 2008		1,103,624		$	14.20		4.0	$	9,822

Exercisable at September 30, 2008		572,988		$	7.29		1.8	$	7,084


Vested or expected to vest at September, 30, 2008		1,088,091		$	14.32

Cash received from the exercise of stock options totaled $1.3 million and $15.6 million for the nine months ended September 30, 2008 and 2007, respectively. The intrinsic value of the options exercised in the first nine months of 2008 was $6.7 million.

Quicksilver Restricted Stock and Restricted Stock Units

At January 1, 2008, the Company had total unrecognized compensation cost of $15.2 million related to unvested restricted stock and stock unit awards. Grants of restricted stock and stock units during the nine months ended September 30, 2008 had an estimated grant date fair value of $18.6 million which will be recognized as expense over the vesting period. During the first nine months of 2008 and 2007, the Company recognized expense of $9.8 million and $9.0 million, respectively, for vesting of restricted stock and stock units. Total unrecognized compensation cost was $22.1 million at September 30, 2008 which will be recognized over a weighted average remaining 11-month vesting period.

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


				Wtd Avg
				Grant Date
	Shares			Fair Value
Outstanding at December 31, 2007		1,340,122		$	18.76
Granted		588,712			31.59
Vested		(480,602	)		31.19
Cancelled		(144,347	)		22.72

Outstanding at September 30, 2008		1,303,885		$	24.22

The total fair value of shares and units vested during the nine months ended September 30, 2008 was $14.9 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
Granted		6,605			24.12		137,148			25.25
Vested		(27,330	)		21.36		(6,089	)		21.36
Cancelled		(3,000	)		21.36		(974	)		25.25

Outstanding at September 30, 2008		61,236		$	21.66		139,918		$	25.15

At January 1, 2008, KGS had total unrecognized compensation cost of $1.9 million related to unvested phantom units awards. KGS recognized compensation expense of approximately $1.1 million during the nine months ended September 30, 2008 including $0.4 million for remeasuring awards to be settled in cash to their revised fair value. Grants of phantom units during the nine months ended September 30, 2008 had an estimated grant date fair value of $3.6 million. During the nine months ended September 30, 2008, the fair value of unvested grants of phantom units payable in cash has decreased approximately $0.5 million. KGS has unearned compensation expense of $3.0 million at September 30, 2008 that will be recognized in expense over the next 2.1 years. Phantom units that vested during the nine months ended September 30, 2008 had a fair value of $0.7 million on their vesting date.

11. 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.

Condensed Consolidating Balance Sheets


	September 30, 2008
										Quicksilver
	Quicksilver		Guarantor		Non-Guarantor					Resources Inc.
	Resources Inc.		Subsidiaries		Subsidiaries		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets	$	312,186	$	—	$	336,875	$	(394,000	)	$	255,061
Property and equipment		3,177,418		10,977		1,041,897		—			4,230,292
Investment in subsidiaries (equity method)		741,170		166,853		—		(613,151	)		294,872
Other assets		152,040		151,864		5,080		(204,869	)		104,115

Total assets	$	4,382,814	$	329,694	$	1,383,852	$	(1,212,020	)	$	4,884,340


LIABILITIES AND STOCKHOLDERS EQUITY
Current liabilities	$	413,613	$	152,390	$	161,161	$	(394,000	)	$	333,164
Long-term liabilities		2,468,412		—		678,746		(204,869	)		2,942,289
Deferred gain		—		—		79,316		—			79,316
Minority interest		—		—		28,782		—			28,782
Stockholders’ equity		1,500,789		177,304		435,847		(613,151	)		1,500,789

Total liabilities and stockholders’ equity	$	4,382,814	$	329,694	$	1,383,852	$	(1,212,020	)	$	4,884,340


	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

Condensed Consolidating Statements of Income


	For the Three Months Ended September 30, 2008
												Quicksilver
	Quicksilver			Guarantor			Non-Guarantor					Resources Inc.
	Resources Inc.			Subsidiaries			Subsidiaries		Eliminations			Consolidated
	(In thousands)
Revenues	$	171,634		$	—		$	81,037	$	(16,409	)	$	236,262
Operating expenses		100,636			376			31,669		(16,409	)		116,272
Income from equity affiliates		—			—			—					—

Operating income		70,998			(376	)		49,368		—			119,990
Equity in net earnings of subsidiaries		(31,846	)		(5,263	)		—		37,109			—
Loss from earnings of BBEP		89,814			—			—		—			89,814
Interest expense and other		30,287			(1,736	)		9,014		—			37,565
Income tax (benefit) provision		(14,582	)		476			9,392		—			(4,714	)

Net (loss) income	$	(2,675	)	$	6,147		$	30,962	$	(37,109	)	$	(2,675	)


	For the Three Months Ended September 30, 2007
												Quicksilver
	Quicksilver			Guarantor			Non-Guarantor					Resources Inc.
	Resources Inc.			Subsidiaries			Subsidiaries		Eliminations			Consolidated
	(In thousands)
Revenues	$	104,237		$	—		$	63,307	$	(8,345	)	$	159,199
Operating expenses		73,375			(784	)		31,664		(8,345	)		95,910
Income from equity affiliates		(4	)		—			289					285

Operating income		30,858			784			31,932		—			63,574
Equity in net earnings of subsidiaries		(18,852	)		(552	)		—		19,404			—
Interest expense and other		15,109			(999	)		6,652		—			20,762
Income tax provision		5,882			624			7,587		—			14,093

Net income	$	28,719		$	1,711		$	17,693	$	(19,404	)	$	28,719


	For the Nine Months Ended September 30, 2008
												Quicksilver
	Quicksilver			Guarantor			Non-Guarantor					Resources Inc.
	Resources Inc.			Subsidiaries			Subsidiaries		Eliminations			Consolidated
	(In thousands)
Revenues	$	437,512		$	—		$	197,813	$	(43,545	)	$	591,780
Operating expenses		240,274			1,389			95,846		(43,545	)		293,964
Income from equity affiliates		—			—			—		—			—

Operating income		197,238			(1,389	)		101,967		—			297,816
Equity in net earnings of subsidiaries		(63,759	)		(12,258	)		—		76,017			—
Loss from earnings of BBEP		93,864			—			—		—			93,864
Interest expense and other		45,705			(4,663	)		23,259		—			64,301
Income tax provision		29,531			1,146			17,077		—			47,754

Net income	$	91,897		$	14,386		$	61,631	$	(76,017	)	$	91,897


	For the Nine Months Ended September 30, 2008
												Quicksilver
	Quicksilver			Guarantor			Non-Guarantor					Resources Inc.
	Resources Inc.			Subsidiaries			Subsidiaries		Eliminations			Consolidated
	(In thousands)
Revenues	$	264,053		$	—		$	167,355	$	(19,231	)	$	412,177
Operating expenses		174,523			355			83,103		(19,231	)		238,750
Income from equity affiliates		18			—			664		—			682

Operating income		89,548			(355	)		84,916		—			174,109
Equity in net earnings of subsidiaries		(53,025	)		(4,627	)		—		57,652			—
Interest expense and other		39,935			(1,020	)		13,735		—			52,650
Income tax provision		19,337			233			18,588		—			38,158

Net income	$	83,301		$	5,059		$	52,593	$	(57,652	)	$	83,301

Condensed Consolidating Statements of Cash Flows


	For the Nine Months Ended September 30, 2008
													Quicksilver
	Quicksilver			Guarantor			Non-Guarantor						Resources Inc.
	Resources Inc.			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(In thousands)
Cash flow provided by operations	$	53,455		$	9,688		$	210,977		$	—		$	274,120
Cash flow used for investing activities		(1,627,306	)		72,342			(289,446	)		(99,110	)		(1,943,520	)
Cash flow provided by financing activities		1,560,117			(82,030	)		80,051			99,110			1,657,248
Effect of exchange rates on cash		(155	)		—			(2,454	)		—			(2,609	)

Net increase (decrease) in cash and equivalents		(13,889	)		—			(872	)		—			(14,761	)
Cash and equivalents at beginning of period		27,010			—			1,216			—			28,226

Cash and equivalents at end of period	$	13,121		$	—		$	344		$	—		$	13,465


	For the Nine Months Ended September 30, 2007
													Quicksilver
	Quicksilver			Guarantor			Non-Guarantor						Resources Inc.
	Resources Inc.			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(In thousands)
Cash flow provided by operations	$	116,890		$	(496	)	$	145,305		$	—		$	261,699
Cash flow used for investing activities		(562,188	)		29,092			(191,881	)		5,097			(719,880	)
Cash flow provided by financing activities		446,035			(28,596	)		56,978			(5,097	)		469,320
Effect of exchange rates on cash		588			—			2,582			—			3,170

Net increase (decrease) in cash and equivalents		1,325			—			12,984			—			14,309
Cash and equivalents at beginning of period		83			—			5,198			—			5,281

Cash and equivalents at end of period	$	1,408		$	—		$	18,182		$	—		$	19,590

12. SUPPLEMENTAL CASH FLOW INFORMATION

Cash paid for interest and income taxes is as follows:


	Nine Months Ended
	September 30,
	2008		2007
	(In thousands)
Interest	$	58,762	$	56,608
Income taxes		49,775		696

Other non-cash transactions are as follows:


	Nine Months Ended
	September 30,
	2008		2007
	(In thousands)
Working capital related to acquisition of property, plant and equipment — net	$	191,959	$	126,569
Issuance of Quicksilver Resources Inc. common stock as consideration in the Alliance Acquisition		262,092		—

13. RELATED-PARTY TRANSACTIONS

As of September 30, 2008, members of the Darden family, Mercury Exploration Company (“Mercury”) and Quicksilver Energy L.P. (“QELP”), entities that are owned by members of the Darden family, beneficially owned approximately 31% 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 $1.6 million in the first nine 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 nine months of 2008 and 2007 totaled $0.1 million.

The Company paid $0.7 million and $0.2 million during the first nine 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 Company signed a settlement agreement with Mercury in which Mercury agreed to make a 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”).

During the second quarter of 2008, KGS obtained 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.

14. 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 September 30, 2008
Revenues	$	171,422	$	61,484	$	19,304	$	—		$	(15,948	)	$	236,262
Depletion, depreciation and accretion		36,178		11,337		3,990		272			—			51,777
Operating income		94,649		40,927		8,818		(24,404	)		—			119,990
Property and equipment costs incurred		1,484,080		21,208		97,525		215			—			1,603,028

2007
Revenues	$	112,180	$	45,068	$	10,282	$	—		$	(8,331	)	$	159,199
Depletion, depreciation and accretion		19,528		10,128		2,209		250			—			32,115
Operating income		46,618		25,695		3,485		(12,224	)		—			63,574
Property and equipment costs incurred		216,238		32,422		35,174		906			—			284,740

For the Nine Months Ended September 30, 2008
Revenues	$	436,926	$	145,825	$	52,694	$	—		$	(43,665	)	$	591,780
Depletion, depreciation and accretion		79,731		34,353		10,874		798			—			125,756
Operating income		247,310		81,862		21,131		(52,487	)		—			297,816
Property and equipment costs incurred		1,938,667		108,482		204,330		769			—			2,252,248

2007
Revenues	$	289,865	$	118,327	$	22,771	$	—		$	(18,786	)	$	412,177
Depletion, depreciation and accretion		50,519		28,011		5,362		722			—			84,614
Operating income		135,307		64,800		6,694		(32,692	)		—			174,109
Property and equipment costs incurred		536,833		62,965		112,570		1,877			—			714,245

Property, Plant and Equipment-net
September 30, 2008	$	3,143,511	$	603,498	$	478,984	$	4,299					$	4,230,292
December 31, 2007		1,290,728		571,496		275,807		4,315			—			2,142,346

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

RESULTS OF OPERATIONS

Summary Financial Data
Three Months Ended September 30, 2008 Compared with the Three Months Ended September 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, NGL and oil for the three months ended September 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	$	117.4		$	29.6	$	61.6		$	30.8		$	9.1		$	1.7		$	188.1		$	62.1
Northeast Operations		—			30.2		—			1.6			—			6.5			—			38.3
Other U.S.		0.2			0.1		0.4			(0.8	)		4.7			2.6			5.3			1.9
Hedging		(15.1	)		6.3		(4.9	)		(0.1	)		(3.4	)		(0.1	)		(23.4	)		6.1

Total U.S.		102.5			66.2		57.1			31.5			10.4			10.7			170.0			108.4
Canada		51.6			27.4		—			0.1			—			—			51.6			27.5
Hedging		(3.4	)		15.1		—			—			—			—			(3.4	)		15.1

Total Canada		48.2			42.5		—			0.1			—			—			48.2			42.6


Total Company	$	150.7		$	108.7	$	57.1		$	31.6		$	10.4		$	10.7		$	218.2		$	151.0

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		137.1		53.2		11,485		7,766		865		262		211.2		101.4
Northeast Operations		—		67.8		—		408		—		983		—		76.2
Other U.S.		0.2		0.3		49		33		469		428		3.3		3.1

Total U.S.		137.3		121.3		11,534		8,207		1,334		1,673		214.5		180.7
Canada		62.5		56.9		—		20		—		—		62.5		57.0


Total Company		199.8		178.2		11,534		8,227		1,334		1,673		277.0		237.7

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	$	9.31		$	6.05	$	58.30		$	43.06		$	114.11		$	70.89	$	9.68		$	6.66
Northeast Operations		—			4.85		—			43.83			—			72.23		—			5.48
Other U.S.		3.77			3.78		88.26			57.04			107.59			65.51		16.69			10.05
Hedging — U.S.		(1.19	)		0.61		(4.61	)		(1.36	)		(27.01	)		—		(1.18	)		0.34

Total U.S.		8.11			5.93		53.82			41.79			84.80			69.67		8.61			6.53

Canada		8.97			5.23		—			52.17			—			—		8.97			5.23
Hedging — Canada		(0.58	)		2.88		—			—			—			—		(0.58	)		2.88

Total Canada		8.39			8.11		—			52.17			—			—		8.39			8.12

Total Company	$	8.20		$	6.63	$	53.82		$	41.82		$	84.80		$	69.67	$	8.56		$	6.91

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


	Natural
	Gas		NGL		Oil			Total
	(In thousands)
Revenue for the quarter ended September 30, 2007	$	108,670	$	31,655	$	10,721		$	151,046
Volume changes		13,150		12,719		(2,171	)		23,698
Price changes		28,878		12,734		1,858			43,470

Revenue for the quarter ended September 30, 2008	$	150,698	$	57,108	$	10,408		$	218,214

Natural gas sales increased as a result of a $1.57 per Mcf increase in realized natural gas prices for the third quarter of 2008 as compared to the 2007 period. Natural gas volumes for Texas and Canada increased 7.7 Bcf and 0.5 Bcf, respectively, from new wells placed into service since September 30, 2007. Approximately 2.6 Bcf of the increase in Texas production is from wells purchased in the Alliance Acquisition in August 2008. These production increases were partially offset by the absence of 6.2 Bcf of natural gas production from the Northeast Operations’ properties which were divested in November 2007.

The increase in NGL sales was due to production increases of 342 MBbl from the Fort Worth Basin due to new wells placed into production subsequent to the third quarter of 2007 and improved NGL recovery. Partially offsetting the increase in Fort Worth Basin production was the absence of production from the divested Northeast Operations’ properties. Realized price per barrel for the 2008 third quarter increased $12.00 per barrel compared to the 2007 period.

Oil sales for the third quarter of 2008 were comparable to the 2007 third quarter. A 31 MBbl net decrease in oil production was nearly offset by a $15.13 per barrel increase in realized oil prices for the 2008 third quarter. The net decline in oil production was due to the absence of production from the Northeast Operations’ properties partially offset by a 59 MBbl increase in Fort Worth Basin and other U.S. oil production.

During the quarter ended September 30, 2008, we estimate that Texas production was reduced by approximately 0.8 Bcfe (or 8.2 Mcfed) due to the impact of hurricanes at our production’s destination points in the affected areas.

Other Revenue

Other revenue in the quarter ended September 30, 2008 increased $9.9 million from the comparable 2007 quarter. The increase was primarily due to additional revenue of $12.8 million that resulted from partial ineffectiveness of the derivatives hedging our Canadian production for the third quarter of 2008 whereas a comparable $2.0 million effect occurred during the 2007 third 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 September 30, 2008. Additional KGS processing and transportation revenue from third parties of $1.6 million partially offset the absence of $2.6 million for Canadian research and development credits in the third quarter of 2007.

Operating Expenses

Oil and Gas Production Expense


	Three Months Ended September 30,
	2008				2007
	(In thousands, except per unit amounts)
			Per				Per
			Mcfe				Mcfe
Texas
Cash expense	$	22,043	$	1.13	$	15,225	$	1.64
Equity compensation		301		0.02		118		0.01

	$	22,344	$	1.15	$	15,343	$	1.65

Northeast Operations
Cash expense	$	—	$	—	$	19,186	$	2.74
Equity compensation		—		—		307		0.04

	$	—	$	—	$	19,493	$	2.78

Other U.S.
Cash expense	$	1,639	$	5.01	$	773	$	2.70
Equity compensation		42		0.14		39		0.14

	$	1,681	$	5.15	$	812	$	2.84

Total U.S.
Cash expense	$	23,682	$	1.20	$	35,184	$	2.12
Equity compensation		343		0.02		464		0.03

	$	24,025	$	1.22	$	35,648	$	2.15

Canada
Cash expense	$	8,837	$	1.54	$	8,082	$	1.54
Equity compensation		605		0.10		516		0.10

	$	9,442	$	1.64	$	8,598	$	1.64

Total Company
Cash expense	$	32,519	$	1.27	$	43,266	$	1.98
Equity compensation		948		0.04		980		0.04

	$	33,467	$	1.31	$	44,246	$	2.02

Production expense decreased primarily because of the absence of $19.5 million of expense for the divested Northeast Operations. The decrease was partially offset by increases in production expense for both the Fort Worth Basin and Canada of $7.0 million and $0.8 million, respectively, for the third quarter of 2008 resulting from higher production levels in both areas.

As discussed above, our production from the Fort Worth Basin increased approximately 108%, although expense increased only 46% for the third quarter of 2008 compared to the 2007 third quarter. Fort Worth Basin production expense per Mcfe for the third quarter of 2008 decreased 30% from the third quarter of 2007 to $1.15 per Mcfe. Third quarter Fort Worth Basin production expense of $1.15 per mcfe also reflected a 21% decrease from $1.46 per Mcfe for the second quarter of 2008. These decreases resulted from improved leverage of the fixed component of our Fort Worth Basin infrastructure cost across higher production levels. Cost containment initiatives including improved purchasing programs and additional reliance on automation contributed further to the reduction of production expense on an mcfe-basis.

Canadian production expense per Mcfe was $1.64 per Mcfe for the third quarter of both 2008 and 2007.

Production and Ad Valorem Taxes


	Three Months Ended September 30,
	2008						2007
	(In thousands, except per unit amounts)
				Per					Per
				Mcfe					Mcfe
Production and ad valorem taxes
U.S.	$	4,670		$	0.24		$	3,720	$	0.22
Canada		(222	)		(0.04	)		646	$	0.12

Total production and ad valorem taxes	$	4,448		$	0.17		$	4,366	$	0.20

Third quarter 2008 production and ad valorem taxes increased due to development of our Fort Worth Basin properties, higher property valuations for our existing properties and expansion of KGS’ associated midstream infrastructure. Texas ad valorem tax increases were partially offset by the absence of production and ad valorem taxes for the divested Northeast Operations. We have experienced low severance tax expense for our Texas production as a result of exemptions and rate reductions for development of “high cost wells”. We expect production tax rates in Texas to increase in future quarters as fewer of our wells to be drilled in 2009 and beyond will qualify for production tax exemptions and rate reductions. We expect the drilling and completion costs for our Fort Worth Basin wells to continue to decrease while the cost threshold for exemptions and rate reductions will increase.

Depletion, Depreciation and Accretion


	Three Months Ended September 30,
	2008				2007
	(In thousands, except per unit amounts)
			Per				Per
			Mcfe				Mcfe
Depletion
U.S.	$	34,348	$	1.74	$	17,705	$	1.07
Canada		10,120		1.76		8,827		1.68

Total depletion		44,468		1.74		26,532		1.21
Depreciation of other fixed assets:
U.S.	$	5,928	$	0.30	$	4,039	$	0.24
Canada		1,006		0.17		1,121		0.21

Total depreciation		6,934		0.27		5,160		0.24
Accretion		375		0.02		423		0.02

Total depletion, depreciation and accretion	$	51,777	$	2.03	$	32,115	$	1.47

Higher depletion for the third quarter of 2008 resulted from a 44% increase in the depletion rate and a 17% increase in sales volumes. Our higher depletion rate for the third quarter of 2008 was impacted by the addition of the proved oil and gas properties obtained in the Alliance Acquisition and increases in estimated future capital expenditures as well as the costs of proved reserves added from our Canadian and existing Fort Worth Basin properties. The $1.8 million increase in depreciation for the third quarter of 2008 as compared to the 2007 third 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 $0.5 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. We expect depreciation rates will increase when KGS places its $105 million processing facility into service in the first quarter of 2009.

General and Administrative Expense


	Three Months Ended September 30,
	2008				2007
	(In thousands, except per unit amounts)
			Per				Per
			Mcfe				Mcfe
General and administrative expense
Cash expense	$	12,674	$	0.49	$	12,133	$	0.56
Litigation resolution		9,633		0.38		—		—
Equity compensation		3,298		0.13		2,195		0.10

Total general and administrative expense	$	25,605	$	1.00	$	14,328	$	0.66

General and administrative expense for the third quarter of 2008 increased from the comparable 2007 period due, in part, to a $9.6 million charge for settlement of litigation in September 2008 as discussed in Note 9 to the financial statements included in this report. Recurring general and administrative expense increased $4.2 million for employee compensation and benefits including $1.1 million of non-cash expense for vesting of stock-based compensation and $1.3 million in performance-based compensation to be paid in the fourth quarter of 2008 or first quarter of 2009. Expenses for legal, accounting and other professional services decreased general and administrative expense by approximately $0.5 million for the 2008 third quarter as compared to the 2007 third quarter. During the third quarter of 2007, we recognized $2 million in investment banking fees associated with the BreitBurn Transaction. We have instituted measures to limit future general and administrative expense growth and expect continued leveling of recurring general and administrative expense in future quarters.

Interest Expense


	Three Months Ended June 30,
	September 30,
	2008			2007
	(in thousands)
Interest costs	$	37,101		$	20,831
Less: Interest capitalized		(2,774	)		(141	)

Interest expense	$	34,327		$	20,690

Interest expense for the third quarter of 2008 increased $13.6 million compared to the third quarter of 2007. Interest costs for the third quarter of 2008 were higher than the 2007 third quarter primarily because of the issuance of our 2015 Senior Notes and Term Loan Facility partially offset by a decrease in our average consolidated interest rate. The increase in capitalized interest results from our exploration efforts in West Texas and in the Horn River Basin in Canada and construction of the new KGS processing facility. Based on the higher levels of debt outstanding as compared to previous periods, we expect interest expense to increase during future quarters.

Income Tax Expense


	Three Months Ended June 30,
	September 30,
	2008			2007
Income tax (in thousands)	$	(4,714	)	$	14,093
Effective tax rate		75.3	%		32.6	%

Our provision for income taxes for the third quarter of 2008 decreased from the prior-year period due to an $17.3 million decrease in federal income tax expense associated with lower pretax earnings. Another $2.6 million decrease resulted from reductions in Canadian tax rates and U.S. statutory depletion deductions taken on the 2007 U.S. federal tax return filed in September 2008 which was offset by a $1.1 million increase in Texas margin taxes. The effective tax rate for the 2008 third quarter was most significantly affected by a taxable net loss in the U.S. taxed at approximately 35% and a net taxable profit in Canada taxed at approximately 25%. Should we report earnings in both the U.S. and Canada during 2008 as currently forecasted, we expect our effective income tax rate to be in a range from 33.5% to 35%.

Summary Financial Data
Nine Months Ended September 30, 2008 Compared with the Nine Months Ended September 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, NGL and oil for the nine months ended September 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	$	272.8		$	77.6	$	171.5		$	60.6		$	25.8		$	4.5		$	470.1		$	142.7
Northeast Operations		—			93.5		—			3.9			—			16.4			—			113.8
Other U.S.		0.4			0.2		1.0			(0.4	)		13.2			7.0			14.6			6.8
Hedging		(28.5	)		22.8		(13.4	)		(0.2	)		(8.6	)		(0.2	)		(50.5	)		22.4

Total U.S.		244.7			194.1		159.1			63.9			30.4			27.7			434.2			285.7
Canada		151.1			92.8		—			0.2			—			—			151.1			93.0
Hedging		(10.6	)		19.6		—			—			—			—			(10.6	)		19.6

Total Canada		140.5			112.4		—			0.2			—			—			140.5			112.6


Total Company	$	385.2		$	306.5	$	159.1		$	64.1		$	30.4		$	27.7		$	574.7		$	398.3

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		104.6		42.4		10,976		5,447		864		262		175.6		76.7
Northeast Operations		—		67.5		—		391		—		972		—		75.6
Other U.S.		0.3		0.3		42		31		462		458		3.4		3.2

Total U.S.		104.9		110.2		11,018		5,869		1,326		1,692		179.0		155.5
Canada		62.5		55.6		—		11		—		—		62.5		55.7


Total Company		167.4		165.8		11,018		5,880		1,326		1,692		241.5		211.2

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	$	9.52		$	6.70	$	57.03		$	40.74	$	109.30		$	62.37	$	9.77		$	6.81
Northeast Operations		—			5.08		—			36.37		—			61.83		—			5.51
Other U.S.		4.45			5.03		86.32			47.68		103.65			55.75		16.11			8.82
Hedging — U.S.		(0.99	)		0.79		(4.46	)		—		(23.62	)		—		(1.03	)		0.56

Total U.S.		8.51			6.45		52.69			39.84		83.70			60.06		8.85			6.73

Canada		8.83			6.12		—			61.08		—			—		8.83			6.12
Hedging — Canada		(0.62	)		1.29		—			—		—			—		(0.62	)		1.29

Total Canada		8.21			7.41		—			61.08		—			—		8.21			7.41


Total Company	$	8.40		$	6.77	$	52.69		$	39.88	$	83.70		$	60.06	$	8.69		$	6.91

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


	Natural
	Gas		NGL		Oil			Total
	(In thousands)
Revenue for the nine months ended September 30, 2007	$	306,539	$	64,023	$	27,735		$	398,297
Volume changes		4,109		56,383		(5,915	)		54,577
Price changes		74,596		38,655		8,592			121,843

Revenue for the nine months ended September 30, 2008	$	385,244	$	159,061	$	30,412		$	574,717

Natural gas sales increased as a result of a $1.63 per Mcf increase in realized natural gas prices for the first nine months of 2008 as compared to the 2007 nine-month period. When compared to the 2007 period, natural gas sales volumes for the 2008 nine-month period increased primarily as a result of a 17.1 Bcf increase in natural gas production from the Fort Worth Basin and an additional 1.9 Bcf of Canadian natural gas production. The absence of 18.4 Bcf of natural gas production from the divested Northeast Operations’ properties partially offset the production increases. Production from the Fort Worth Basin and Canada increased primarily from wells placed into production subsequent to September 30, 2007. Natural gas production increases from the Fort Worth Basin also include 2.6 Bcf of natural gas production from the properties purchased in the August 2008 Alliance Acquisition.

Our NGL sales for the nine months ended September 30, 2008 increased as a result of both higher production volumes and realized sales prices. NGL volume from Texas wells more than doubled to 3.0 MMBbl for the nine months ended September 2008. The 2008 NGL volume increase when compared to the 2007 period was due to new wells placed into production subsequent to September 30, 2007 and improved NGL recovery from our newest processing facility in the Fort Worth Basin that began operating in March 2007. Partially offsetting the increase in Fort Worth Basin production was the absence of production from the divested Northeast Operations’ properties. Realized prices for 2008 increased 32% and also impacted NGL sales.

Oil sales for the period ended September 30, 2008 increased due to higher realized prices partially offset by a net decrease in production. The absence of production from the Northeast Operations’ properties was only partially offset by a 165 MBbl increase in Fort Worth Basin oil production.

Other Revenue

Other revenue in the nine months ended September 30, 2008 increased $3.2 million from the comparable 2007 period. Additional KGS processing and transportation revenue from third parties of $5.1 million, a $0.7 million higher valuation of ineffectiveness for our production revenue hedges and marketing revenue increases of $1.3 million for the 2008 nine-month period were the primary sources of additional other revenue for the 2008 nine-month period. The absence of $4.7 million for Canadian research income recognized in 2007 partially offset 2008 increases to other revenue for the nine-month period.

Operating Expenses

Oil and Gas Production Expense


	Nine Months Ended September 30,
	2008				2007
	(In thousands, except per unit amounts)
			Per				Per
			Mcfe				Mcfe
Texas
Cash expense	$	66,243	$	1.38	$	33,918	$	1.62
Equity compensation		925		0.02		353		0.02

	$	67,168	$	1.40	$	34,271	$	1.64

Northeast Operations
Cash expense	$	—	$	—	$	43,912	$	2.12
Equity compensation		—		—		980		0.05

	$	—	$	—	$	44,892	$	2.17

Other U.S.
Cash expense	$	4,273	$	4.31	$	2,412	$	2.73
Equity compensation		133		0.15		136		0.15

	$	4,406	$	4.46	$	2,548	$	2.88

Total U.S.
Cash expense	$	70,516	$	1.44	$	80,242	$	1.89
Equity compensation		1,058		0.02		1,469		0.03

	$	71,574	$	1.46	$	81,711	$	1.92

Canada
Cash expense	$	26,440	$	1.54	$	21,580	$	1.42
Equity compensation		1,543		0.09		1,513		0.10

	$	27,983	$	1.63	$	23,093	$	1.52

Total Company
Cash expense	$	96,956	$	1.46	$	101,822	$	1.77
Equity compensation		2,601		0.04		2,982		0.05

	$	99,557	$	1.50	$	104,804	$	1.82

Oil and gas production expense decreased $5.2 million for the first nine months of 2008 from the comparable 2007 period due primarily to the absence of production expense of $44.9 million for the divested Northeast Operations. Growth of our operations in the Fort Worth Basin and Canada increased production expense $32.9 million and $4.9 million, respectively, as production volumes increased 130% and 13%, respectively, for the nine months ended September 30, 2008 as compared to the 2007 nine-month period, as discussed previously.

Although oil and gas production expense for our Fort Worth Basin operations were $32.9 million higher for the 2008 nine-month period, production expense per Mcfe decreased 15% to $1.40 per Mcfe when compared to the nine months ended September 30, 2007. The improvement in production expense on an Mcfe-basis was primarily the result of improved leverage of the fixed portion of our Fort Worth Basin infrastructure across higher production levels, cost containment initiatives, new completion techniques used in our capital program during 2008 and higher utilization of automation for the 2008 nine-month period as compared to the 2007 nine-month period.

Canadian oil and gas production expense increased in the first nine months of 2008 due, in part, to a 13% increase in production volumes and inflationary increases. Canadian production expense for the 2008 nine-month period also reflected an additional $1.1 million of production expense when compared to the 2007 period because of the currency effects of a stronger Canadian dollar in relation to the U.S. dollar for the 2008 nine-month period.

Production and Ad Valorem Taxes


	Nine Months Ended September 30,
	2008				2007
	(In thousands, except per unit amounts)
			Per				Per
			Mcfe				Mcfe
Production and ad valorem taxes
U.S.	$	7,688	$	0.16	$	10,645	$	0.25
Canada		1,627		0.10		2,423		0.16

Total production and ad valorem taxes	$	9,315	$	0.14	$	13,068	$	0.23

Production and ad valorem taxes for the 2008 period decreased due to the absence of production from the divested Northeast Operations partially offset by increases due to development of our Fort Worth Basin properties, higher valuations for existing properties and expansion of KGS’ associated midstream infrastructure. We have experienced low severance tax expense for our Texas production as a result of exemptions and rate reductions for development of “high cost wells”.

Depletion, Depreciation and Accretion


	Nine Months Ended September 30,
	2008				2007
	(In thousands, except per unit amounts)
			Per				Per
			Mcfe				Mcfe
Depletion
U.S.	$	75,649	$	1.54	$	45,244	$	1.07
Canada		30,967		1.81		24,506		1.61

Total depletion		106,616		1.61		69,750		1.21
Depreciation of other fixed assets:
U.S.	$	15,293	$	0.31	$	10,668	$	0.25
Canada		2,751		0.16		3,007		0.20

Total depreciation		18,044		0.27		13,675		0.24
Accretion		1,096		0.02		1,189		0.02

Total depletion, depreciation and accretion	$	125,756	$	1.90	$	84,614	$	1.47

Depletion for the first nine months of 2008 increased from the comparable 2007 period. Higher depletion resulted from a 33% increase in the depletion rate and a 15% increase in sales volumes. Our higher depletion rate for the first nine months of 2008 resulted from the significant addition of costs for proved reserves added from our Canadian and Fort Worth Basin properties and the proved oil and gas properties obtained in the Alliance Acquisition. The $4.4 million increase in depreciation for the 2008 period as compared to the 2007 nine-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 $1.4 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 September 30, 2007.

General and Administrative Expense


	Nine Months Ended September 30,
	2008				2007
	(In thousands, except per unit amounts)
			Per				Per
			Mcfe				Mcfe
General and administrative expense
Cash expense	$	37,175	$	0.56	$	27,844	$	0.49
Litigation resolution		9,633		0.14		—		—
Equity compensation		9,594		0.15		6,480		0.11

Total general and administrative expense	$	56,402	$	0.85	$	34,324	$	0.60

General and administrative expense increased $22.1 million for the 2008 period from the comparable 2007 period. A charge of $9.6 million was recognized in the third quarter of 2008 as a result of the settlement of litigation in September 2008 as discussed in Note 9 to the financial statements included in this report. The most significant increase in recurring general and administrative expense for the first nine months of 2008 was a $12.0 million increase in employee compensation and benefits, including $3.1 million of non-cash expense for vesting of stock-based compensation and $4.3 million in performance-based compensation to be paid in the fourth quarter of 2008 and first quarter of 2009. The remaining $4.6 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 expense also increased $1.3 million. During the third quarter of 2007, we recognized $2 million in professional fees associated with the BreitBurn Transaction which closed in November 2007. After consideration of the Breitburn investment banking fees recognized in the 2007 nine-month period, fees for legal, accounting and other professional services increased general and administrative expense by approximately $1.8 million for the 2008 period as compared to the 2007 period. The legal, accounting and professional fee increase for the 2008 nine-month period was the result of additional regulatory filing requirements, business improvement initiatives and KGS’ ongoing expense as a publicly-traded partnership.

Interest Expense


	Nine Months Ended
	September 30,
	2008			2007
	(in thousands)
Interest costs	$	67,026		$	54,877
Less: Interest capitalized		(6,401	)		(1,019	)

Interest expense	$	60,625		$	53,858

Interest expense for the first nine months of 2008 increased $6.8 million compared to the first nine months of 2007. Interest costs for the first nine months of 2008 were higher than the comparable 2007 period primarily because of higher average debt outstanding due to the issuance of our 2015 Senior Notes and our Second-lien Term Loan Facility partially offset by a decrease in our average consolidated interest rate.

Income Tax Expense


	Nine Months Ended
	September 30,
	2008			2007
Income tax (in thousands)	$	47,754		$	38,158
Effective tax rate		33.6	%		31.2	%

The provision for income taxes for the first nine months of 2008 increased from the prior-year period due largely to an increase in pretax income for the 2008 period. Income tax also increased by $2.5 million for Texas margin taxes. 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 in Canada that were recognized in the 2007 period.

LIQUIDITY, CAPITAL RESOURCES AND FINANCIAL POSITION

Overview

Our financial condition and results of operations, including our liquidity and profitability, are significantly affected by the sales prices that we realize for our natural gas, NGL and oil production and the volumes of natural gas, NGL and oil that we produce.

The natural gas, NGL and oil that we produce are commodity products for which established trading markets exist. Accordingly, product pricing is determined by the relationship between supply and demand for these products in the relevant markets. Product supply is affected primarily by fluctuations in production volumes, and product demand is affected by the state of the economy in general, the availability and price of alternative fuels, and a variety of other factors. Prices for our products historically have been volatile, and we have no meaningful influence over the timing and extent of price changes for our products. Although we have mitigated our near term exposure to such price declines through the use of derivative financial instruments covering substantial portions of our expected near-term production, we cannot confidently predict whether or when market prices for natural gas, NGL and oil will increase or decrease.

The volumes that we produce may be significantly affected by the rates at which we acquire leaseholds and other mineral interests and explore, exploit and develop our leaseholds and other mineral interests through drilling and production activities. These activities require substantial capital expenditures, and our ability to fund these activities through cash flow from our operations, borrowings and other sources may be significantly affected by both financial markets and realized prices for our products. In this regard, the turmoil in the credit and financial markets appears to have deepened significantly in recent weeks, resulting in us and other industry participants announcing reductions in planned levels of capital expenditures and drilling activities for the remainder of 2008 and 2009. Although we presently expect to generate annual production growth of more than 25% in 2009, we could experience a decline in the rate at which we are increasing our production if the weakness in natural gas, NGL and oil pricing or the turmoil in the credit and financial markets were to persist or worsen over a prolonged period of time.


	Nine Months Ended
	September 30,
	2008			2007
	(In thousands)
Net cash provided by operating activities	$	274,120		$	261,699
Net cash used for investing activities		(1,943,520	)		(719,880	)
Net cash provided by financing activities		1,657,248			469,320
Effect of exchange rate changes in cash		(2,609	)		3,170

Net cash provided by operations increased compared to the same period in 2007 primarily due to additional net income of $8.6 million for the nine months ended September 30, 2008 which included a non-cash loss of $93.9 million from BBEP and higher depletion, depreciation and accretion of $41.1 million. Operating cash flow was adversely impacted by payments of $48 million for U.S. federal income taxes as compared to no such payments in the 2007 period. Operating cash flow was also adversely impacted by changes in working capital.

For the nine months ended September 30, 2008, price collars and swaps covered approximately 67% of our total production and resulted in lower realized revenues from our production of $61.1 million. As of October 31, 2008, we had price collars or fixed price swaps hedging our anticipated natural gas, NGL and oil production of approximately 200 MMcfd, 3,000 Bbld and 1,000 Bbld, respectively, for the fourth quarter 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.

We received cash distributions on our BBEP units of $31.4 million during the nine months ended September 30, 2008 compared to approximately $61.7 million of cash from operations generated by the Northeast Operations over the 2007 nine-month period. Cash distributions received in 2008 from BBEP have been reported as investing cash flows. We anticipate that BBEP will report income for the 11 months ended September 30, 2008. In that event, cash distributions received by us from BBEP will be reported as operating cash flows up to our portion of reported BBEP income.

During the first nine months of 2008, we paid $985.1 million for property and equipment (exclusive of the Alliance Acquisition), an increase of approximately $265 million from the comparable 2007 period. Excluding Alliance Acquisition property and equipment, property and equipment purchased (payments for property and equipment plus noncash changes in working capital associated with property and equipment) for the 2008 period totaled $1.0 billion, which consisted primarily of $788.6 million expended for exploration and development activities and $194.2 million expended for our Fort Worth Basin gas processing and gathering operations. Of the $788.6 million incurred for exploration and development, $24.6 million and $56.8 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.


	Nine Months Ended
	September 30, 2008
	(In thousands)
Alliance Acquisition	$	1,253,280
Exploration and development:
Texas		659,090
Other U.S.		24,631

Total U.S.		683,721
Canada		104,837

Total exploration and development		788,558
Midstream:
Texas		194,245
Canada		3,515

Total midstream		197,760
Corporate and field office		12,650

Total plant and equipment costs incurred	$	2,252,248

Net cash provided by financing activities for the nine months ended September 30, 2008 totaled $1.66 billion. On June 27, 2008, we issued $475 million in Senior Notes due in 2015 which generated net proceeds of $457 million after discount and issuance costs. 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.

On August 8, 2008, pursuant to the Alliance Acquisition, we entered into a $700 million five-year secured second-lien term loan facility (“Term Loan Facility”) which generated net proceeds of $674.5 million after discount and issuance costs. The Term Loan Facility’s interest rates are based on LIBOR or ABR options with minimum floors plus a spread. As of September 30, 2008, the interest rate under the Term Loan Facility was 7.75%. Additionally, on the last day of each quarter, we must repay 0.25% of the aggregate principal amount of the loan outstanding on the quarterly repayment date. The credit agreement prohibits the declaration or payment of cash dividends by us and contains certain financial covenants, among other things, that require the maintenance of (a) a minimum current ratio, (b) a minimum interest coverage ratio, (c) a minimum adjusted proved reserves to total debt ratio, and (d) a minimum adjusted proved reserves to total secured debt ratio. In connection with the Term Loan Facility, we entered into collateral agreements pursuant to which Quicksilver’s obligations under the Term Loan Facility, its Senior Notes due 2015 and its domestic subsidiaries’ guaranty obligations with respect to the Term Loan Facility and the Senior Notes due 2015 have been secured equally and ratably by a second lien on substantially all of assets of Quicksilver and such domestic subsidiaries.

During September of 2008, the borrowing base under our senior secured credit facility was set at $1.2 billion. At September 30, 2008, approximately $472.6 million was available for borrowing under our senior secured credit facility. The loan agreements for the senior credit facility prohibit the declaration or payment of cash dividends by us and contain certain financial covenants, which, among other things, require the maintenance of a minimum current ratio, a minimum interest coverage ratio, and a minimum adjusted proved reserves to total debt ratio and a minimum adjusted proved reserves to total secured debt ratio. We were in compliance with those covenants as well as all other covenants under our credit facility and other notes and loans outstanding at September 30, 2008.

KGS’ $150 million senior secured credit facility had $104.3 million of borrowings outstanding and $45.7 million available for borrowing at September 30, 2008, and KGS was in compliance with all of its covenants. On October 10, 2008, the lenders commitments under KGS’ credit agreement increased $85 million to $235 million. At that date, the borrowing capacity was limited by certain financial covenants to $168.8 million. The increase in KGS’ credit agreement commitments was the result of an exercise of an accordion option in the facility. Furthermore, the lenders approved reinstatement of the accordion at $115 million to allow for future expansion of the facility to $350 million with appropriate lender consent.

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


	September 30,		December 31,
	2008		2007
	(In thousands)
Long-term and short-term debt:
Senior secured credit facility	$	725,716	$	310,710
Second-lien term note facility		684,599		—
Senior notes due 2015		468,837		—
Senior subordinated notes due 2016		350,000		350,000
Convertible subordinated debentures		148,191		148,107
KGS credit agreement		104,300		5,000
Other loans		—		34

Total debt		2,481,643		813,851
Stockholders’ equity		1,500,789		1,068,355


Total capitalization	$	3,982,432	$	1,882,206

After funding estimated remaining 2008 capital expenditures of approximately $150 million, we expect the borrowings outstanding under our senior secured credit facility and the KGS credit facility to increase by approximately $80 million to $110 million during the fourth quarter of 2008.

Financial Position

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

•		An increase of more than $2.09 billion in our net property, plant and equipment assets, which includes approximately $1.25 billion for exploration and producing properties and midstream assets purchased in the Alliance Acquisition and $1.0 billion in capital costs incurred principally for development, exploitation and exploration of our existing oil and gas properties as well as additional natural gas processing and gathering system assets.

•		We incurred additional long-term debt of $1.69 billion, primarily as a result of our Alliance Acquisition and our capital expenditure program partially offset by cash flow from operations. During 2008, we entered into a $700 million Term Loan Facility, issued $475 million of Senior Notes due 2015 and increased borrowing under our senior secured credit facility and the KGS credit facility.

•		Our current and non-current derivative assets have increased $118.9 million while our current and non-current derivative liabilities have decreased $53.6 million. The fair value of our fixed-price natural gas purchase swaps and the estimated fair value of the remaining commitment under the Michigan Sales Contract decreased our total derivative assets and liabilities by $1.5 million and $39.3 million, respectively. The remaining changes to our derivative assets and liabilities are the result of changes in the estimated fair value of our cash-flow hedges. The fair value changes to the cash-flow hedge derivatives are the result of lower pricing of natural gas, crude oil and NGLs compared to pricing under our derivative contracts at September 30, 2008. Additionally, our net current deferred tax asset position of $18.9 million at December 31, 2007 has reversed and we have recorded a current deferred income tax liability position of $14.5 million as a result of the increase in estimated fair value of our natural gas, crude oil and NGL cash-flow hedge derivatives and net cash payments of $34.2 million in settlement of the Michigan Sales contract.

Contractual Obligations and Commercial Commitments

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

	•		We have commitments of approximately $87 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 $36 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 interim 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 nine months ended September 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;

	•		Income from earnings of BBEP; 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 price movements.

Commodity Price Risk

We enter into financial derivative contracts to mitigate our exposure to commodity price risk associated with anticipated future natural gas, NGL and crude oil production. As of September 30, 2008, approximately 140 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 fourth quarter of 2008. Additionally, we have used fixed-price swaps and collars 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. We believe we will have more predictability of our natural gas, oil and NGL revenues as a result of these financial derivative contracts.

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 $61.1 million lower and $42.0 million higher as a result of our hedging programs for the first nine months of 2008 and 2007, respectively. Other revenue was $3.7 million and $3.0 million higher as a result of derivative and hedging ineffectiveness for the nine-month periods ending September 30, 2008 and 2007, respectively.

The following table summarizes our open derivative positions as of September 30, 2008 that hedge our future production.

Weighted Avg

Price Per Mcf

Product

Type

Contract Period

Volume

or Bbl

Fair Value

(In thousands)

Gas

Swap

Oct 2008-Dec 2008

25,000 Mcfd

8.13

1,293

Gas

Swap

Oct 2008-Dec 2008

7,500 Mcfd

8.13

388

Gas

Swap

Oct 2008-Dec 2008

5,000 Mcfd

8.14

263

Gas

Swap

Oct 2008-Dec 2008

2,500 Mcfd

8.15

134

Gas

Swap

Oct 2008-Dec 2008

10,000 Mcfd

8.21

591

Gas

Swap

Oct 2008-Dec 2008

10,000 Mcfd

8.22

600

Gas

Swap

Jan 2009-Dec 2009

10,000 Mcfd

8.45

1,121

Gas

Swap

Jan 2009-Dec 2009

10,000 Mcfd

8.45

1,121

Gas

Swap

Jan 2009-Dec 2009

20,000 Mcfd

8.46

2,279

Gas

Collar

Oct 2008-Dec 2008

20,000 Mcfd

7.50- 9.15

541

Gas

Collar

Oct 2008-Dec 2008

10,000 Mcfd

9.00-11.70

1,429

Gas

Collar

Oct 2008-Dec 2008

20,000 Mcfd

8.25- 9.75

1,562

Gas

Collar

Oct 2008-Dec 2008

10,000 Mcfd

9.00-12.60

1,390

Gas

Collar

Oct 2008-Dec 2008

30,000 Mcfd

12.00-16.50

12,002

Gas

Collar

Oct 2008-Dec 2008

10,000 Mcfd

12.00-16.90

4,056

Gas

Collar

Oct 2008-Mar 2009

20,000 Mcfd

7.50- 9.35

903

Gas

Collar

Oct 2008-Mar 2009

20,000 Mcfd

8.00-10.20

2,346

Gas

Collar

Jan 2009-Dec 2009

20,000 Mcfd

7.50- 9.34

(102

)

Gas

Collar

Jan 2009-Dec 2009

20,000 Mcfd

7.75-10.20

2,083

Gas

Collar

Jan 2009-Dec 2009

10,000 Mcfd

7.75-10.26

1,092

Gas

Collar

Jan 2009-Dec 2009

20,000 Mcfd

8.25- 9.60

3,288

Gas

Collar

Jan 2009-Dec 2009

10,000 Mcfd

8.25-10.45

2,267

Gas

Collar

Jan 2009-Dec 2009

10,000 Mcfd

8.25-10.45

2,267

Gas

Collar

Jan 2009-Dec 2009

10,000 Mcfd

8.25-10.45

2,267

Gas

Collar

Jan 2009-Dec 2009

10,000 Mcfd

11.50-14.48

12,381

Gas

Collar

Apr 2009-Dec 2009

10,000 Mcfd

8.50-13.15

2,766

Gas

Collar

Apr 2009-Dec 2009

30,000 Mcfd

11.00-13.50

23,601

Gas

Collar

Jan 2010-Dec 2010

20,000 Mcfd

8.00-11.00

2,307

Gas

Collar

Jan 2010-Dec 2010

20,000 Mcfd

8.00-11.00

2,275

Gas

Collar

Jan 2010-Dec 2010

20,000 Mcfd

8.00-12.20

3,372

Gas

Collar

Jan 2010-Dec 2010

20,000 Mcfd

8.00-12.20

3,473

Gas

Collar

Jan 2010-Dec 2010

20,000 Mcfd

8.50-12.05

5,173

Gas

Collar

Jan 2010-Dec 2010

10,000 Mcfd

8.50-12.05

2,586

Gas

Collar

Jan 2010-Dec 2010

10,000 Mcfd

8.50-12.08

2,654

Gas

Collar

Jan 2010-Dec 2010

40,000 Mcfd

10.00-13.50

26,628

Gas

Basis

Oct 2008-Dec 2008

10,000 Mcfd

218

Gas

Basis

Oct 2008-Dec 2008

10,000 Mcfd

218

Gas

Basis

Oct 2008-Dec 2008

20,000 Mcfd

436

Gas

Basis

Oct 2008-Dec 2008

10,000 Mcfd

217

Gas

Basis

Jan 2009-Dec 2009

20,000 Mcfd

(358

)

Gas

Basis

Jan 2009-Dec 2009

10,000 Mcfd

(179

)

NGL

Swap

Oct 2008-Dec 2008

1,000 Bbld

39.58

(653

)

NGL

Swap

Oct 2008-Dec 2008

2,000 Bbld

45.94

(140

)

Oil

Collar

Oct 2008-Dec 2008

500 Bbld

65.00-73.90

(1,448

)

Oil

Collar

Oct 2008-Dec 2008

500 Bbld

65.00-77.45

(1,506

)

Total

129,202

At September 30, 2008, we had six months remaining to complete our obligation to deliver 25 MMcfd of natural gas under the Michigan Sales Contract. In December 2007, we determined we would cease delivery of a portion of our natural gas production to supply the 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 largely eliminate the net earnings exposure of our remaining obligation under the Michigan Sales Contract. During 2008, we have made $34.2 million of net cash payments for settlement of obligations for the Michigan Sales Contract. The following table summarizes these open positions as of September 30, 2008.

Weighted Avg

Price Per

Product

Type

Contract Period

Volume

Mcf or Bbl

Fair Value

(In thousands)

Gas

Sale

Oct 2008-Mar 2009

25,000 Mcfd

2.49

(24,486

)

Gas

Swap

Oct 2008-Mar 2009

10,000 Mcfd

8.20

(597

)

Gas

Swap

Oct 2008-Mar 2009

15,000 Mcfd

8.20

(896

)

Total

(25,979

)

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 counterparties. 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 following table summarizes the changes to our net derivative positions during the nine months ended September 30, 2008.


	Michigan			Cash Flow
	Contracts			Derivatives			Total
	(in thousands)
Derivative fair value at December 31, 2007	$	(63,777	)	$	(5,503	)	$	(69,280	)

Net cash payment due		4,436			1,461			5,897

Net cash paid in settlement		34,198			59,706			93,904

Change in value reported in other revenue		(836	)		4,507			3,671

Change in value reported in other comprehensive income		—			69,031			69,031

Derivative fair value at September 30, 2008	$	(25,979	)	$	129,202		$	103,223

Credit Risk

During the nine months ended September 30, 2008, we had NGL sales of $154.2 million to two parties. These sales represent 27% of our consolidated production revenue during the nine 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.

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 September 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 September 30, 2008 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. Legal Proceedings

On September 17, 2008, we entered into a settlement agreement with Eagle Domestic Drilling Operations, LLC and Blast Energy Services, Inc. (“Eagle/Blast”) regarding the Houston litigation, that was approved in October by the United States District Court for the Southern District of Texas, Houston. Pursuant to the settlement agreement, we agreed to pay Eagle/Blast $10 million over a three-year period, including $5 million on the settlement date. The portion of the suit in the Houston Federal District Court between us and Eagle Drilling, LLC and the related litigation against us and P. Jeffrey Cook by Eagle Drilling, LLC and Rod and Richard Thornton in the District Court of Cleveland County, Oklahoma, were not dismissed as a result of this settlement.

On October 31, 2008, we filed a lawsuit in the District Court of Tarrant County, Texas, against BreitBurn Energy Partners L.P. (“BBEP”), BreitBurn GP, LLC, (“BreitBurn GP”), BreitBurn Operating L.P., (“BreitBurn Operating”), Provident Energy Trust, (“Provident”) and certain individuals who serve as, or have previously served as, directors and/or officers of BreitBurn GP and/or Provident (collectively, the “Defendants”).

We allege that, among other things, one or more of the Defendants breached the Contribution Agreement pursuant to which we acquired an ownership interest in BBEP, and violated the Texas Securities Act and the Texas Business & Commerce Code, committed common law fraud, fraudulent inducement, negligent misrepresentation and civil conspiracy.

We have requested, among other things, relief for actual and exemplary damages, and for injunctive and declaratory relief.

There have been no other 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 and Part II, Item 1. Legal Proceedings included in our Quarterly Report on Form 10-Q filed with the SEC on August 6, 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 September 30, 2008.


					Total Number of		Maximum Number
	Total Number				Shares Purchased as		of Shares that May
	of Shares		Average Price		Part of Publicly		Yet Be Purchased
Period	Purchased⁽¹⁾		Paid per Share		Announced Plan⁽²⁾		Under the Plan⁽²⁾
July 2008		23,773	$	36.24		—		—
August 2008		—	$	—		—		—
September 2008		882	$	22.50		—		—

Total		24,655	$	35.75		—		—


⁽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

No items were submitted to a vote of stockholders during the third quarter ended September 30, 2008.

ITEM 5. Other Information

None.

ITEM 6. Exhibits:


Exhibit No.			Description
*2.1			Purchase and Sale Agreement, dated as of July 3, 2008, among Nortex Minerals, L.P., Petrus Investment, L.P., Petrus Development, L.P., and Perot Investment Partners, Ltd., as Sellers, and Quicksilver Resources Inc., as Purchaser (filed as Exhibit 10.1 to the Company’s Form 8-K filed July 7, 2008 and included herein by reference).

*2.2			Purchase and Sale Agreement, dated as of July 3, 2008, among Hillwood Oil & Gas, L.P., Burtex Minerals, L.P., Chief Resources, LP, Hillwood Alliance Operating Company, L.P., Chief Resources Alliance Pipeline LLC, Chief Oil & Gas LLC, Berry Barnett, L.P., Collins and Young, L.L.C. and Mark Rollins, as Sellers, and Quicksilver Resources Inc., as Purchaser (filed as Exhibit 10.2 to the Company’s Form 8-K filed July 7, 2008 and included herein by reference).

*4.1			Sixth Supplemental Indentures, dated as of July 10, 2008, among Quicksilver Resources Inc., the subsidiary guarantors named therein and The Bank of New York Mellon Trust, N.A., as trustee (filed as Exhibit 4.1 to the Company’s Form 8-K filed July 10, 2008 and included herein by reference).

10.1			Fifth Amendment to Combined Credit Agreements, dated as of August 4, 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 August 5, 2008 and included herein by reference).

10.2			Credit Agreement, dated as of August 8, 2008, among Quicksilver Resources Inc., the lenders party thereto and Credit Suisse, Cayman Islands Branch, as administrative agent (filed as Exhibit 10.1 to the Company’s Form 8-K filed August 8, 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.


*		Excludes schedules and exhibits we agree to furnish supplementally to the SEC upon request.

**		Filed herewith

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: November 5, 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

EXHIBIT INDEX


Exhibit No.			Description
*2.1			Purchase and Sale Agreement, dated as of July 3, 2008, among Nortex Minerals, L.P., Petrus Investment, L.P., Petrus Development, L.P., and Perot Investment Partners, Ltd., as Sellers, and Quicksilver Resources Inc., as Purchaser (filed as Exhibit 10.1 to the Company’s Form 8-K filed July 7, 2008 and included herein by reference).

*4.1			Sixth Supplemental Indentures, dated as of July 10, 2008, among Quicksilver Resources Inc., the subsidiary guarantors named therein and The Bank of New York Mellon Trust, N.A., as trustee (filed as Exhibit 4.1 to the Company’s Form 8-K filed July 10, 2008 and included herein by reference).

*2.2			Purchase and Sale Agreement, dated as of July 3, 2008, among Hillwood Oil & Gas, L.P., Burtex Minerals, L.P., Chief Resources, LP, Hillwood Alliance Operating Company, L.P., Chief Resources Alliance Pipeline LLC, Chief Oil & Gas LLC, Berry Barnett, L.P., Collins and Young, L.L.C. and Mark Rollins, as Sellers, and Quicksilver Resources Inc., as Purchaser (filed as Exhibit 10.2 to the Company’s Form 8-K filed July 7, 2008 and included herein by reference).

10.1			Fifth Amendment to Combined Credit Agreements, dated as of August 4, 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 August 5, 2008 and included herein by reference).

10.2			Credit Agreement, dated as of August 8, 2008, among Quicksilver Resources Inc., the lenders party thereto and Credit Suisse, Cayman Islands Branch, as administrative agent (filed as Exhibit 10.1 to the Company’s Form 8-K filed August 8, 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.


*		Excludes schedules and exhibits we agree to furnish supplementally to the SEC upon request.

**		Filed herewith

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Quicksilver Resources (KWK) Inactive 10-Q2008 Q3 Quarterly report

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