Quicksilver Resources (KWK) 10-Q 2007 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, 2007

or

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

For the transition period from                    to                    

Commission file number: 001-14837

Quicksilver Resources Inc.

(Exact name of registrant as specified in its charter)

Delaware	75-2756163
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
777 West Rosedale, Fort Worth, Texas	76104
(Address of principal executive offices)	(Zip Code)

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

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

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

     Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.

Large accelerated filerþ  Accelerated filero  Non-accelerated filero

     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, 2007
Common Stock, $0.01 par value	79,050,986

QUICKSILVER RESOURCES INC.
INDEX TO FORM 10-Q
For the Period Ending September 30, 2007

	Page
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements (Unaudited)		3
Report of Independent Registered Public Accounting Firm		3
Condensed Consolidated Balance Sheets at September 30, 2007 and December 31, 2006		4
Condensed Consolidated Statements of Income and Comprehensive Income for the Three and Nine Months Ended September 30, 2007 and 2006		5
Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2007 and 2006		6
Notes to Condensed Consolidated Interim Financial Statements		7
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		22
Item 3. Quantitative and Qualitative Disclosures About Market Risk		36
Item 4. Controls and Procedures		38
PART II. OTHER INFORMATION
Item 1. Legal Proceedings		39
Item 1A. Risk Factors		40
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		41
Item 6. Exhibits		42
Signatures		43
Awareness Letter of Deloitte & Touche LLP
Certification Pursuant to Section 302
Certification Pursuant to Section 302
Certification Pursuant to 18 U.S.C. Section 1350

2

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements (Unaudited)

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of
Quicksilver Resources Inc.
Fort Worth, Texas

We have reviewed the accompanying condensed consolidated balance sheet of Quicksilver Resources Inc. and subsidiaries (the “Company”) as of September 30, 2007, and the related condensed consolidated statements of income and comprehensive income for the three-month and nine-month periods ended September 30, 2007 and 2006 and of cash flows for the nine-month periods ended September 30, 2007 and 2006. These interim financial statements are the responsibility of the Company’s management.

We conducted our reviews in accordance with standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our reviews, we are not aware of any material modifications that should be made to such condensed consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

We have previously audited, in accordance with standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of Quicksilver Resources Inc. and subsidiaries as of December 31, 2006, and the related consolidated statements of income and comprehensive income, stockholders’ equity and cash flows for the year then ended (not presented herein); and in our report dated February 28, 2007, we expressed an unqualified opinion on those consolidated financial statements and included an explanatory paragraph relating to the adoption of Statement of Financial Accounting Standards No. 123(R),Share-Based Payment. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2006, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

/s/ DELOITTE & TOUCHE LLP

Fort Worth, Texas
November 8, 2007

3

QUICKSILVER RESOURCES INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

In thousands, except for share data – Unaudited

	September 30,			December 31,
	2007			2006
ASSETS
Current assets
Cash and cash equivalents	$	19,590		$	5,281
Accounts receivable, net of allowance for doubtful accounts		69,895			76,521
Current derivative assets		26,638			64,086
Other current assets		38,632			25,076
Total current assets		154,755			170,964
Investments in and advances to equity affiliates		7,161			7,434
Property, plant and equipment — Net
Oil and gas properties, full cost method (including unevaluated costs of $239,807 and $191,665, respectively)		2,027,035			1,444,059
Other property and equipment		360,816			235,221
Property, plant and equipment — Net		2,387,851			1,679,280
Non-current derivative assets		—			3,753
Other assets		22,209			21,481
	$	2,571,976		$	1,882,912
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current portion of long-term debt	$	126		$	400
Accounts payable		133,920			109,914
Accrued liabilities		89,325			67,697
Derivative obligations		3,822			—
Current deferred income taxes		6,238			21,378
Total current liabilities		233,431			199,389
Long-term debt		1,318,441			919,117
Derivative obligations		2,733			—
Asset retirement obligations		31,114			25,058
Deferred gain		81,613			—
Deferred income taxes		200,453			156,251
Minority interest		28,795			7,431
Stockholders’ equity
Preferred stock, $0.01 par value, 10,000,000 shares authorized, no shares issued and outstanding		—			—
Common stock, $0.01 par value, 200,000,000 shares authorized and 81,382,738 and 80,181,593 shares issued, respectively		814			802
Paid in capital in excess of par value		261,352			238,063
Treasury stock of 2,615,943 and 2,579,671 shares, respectively		(12,262	)		(10,737	)
Accumulated other comprehensive income		55,097			60,099
Retained earnings		370,395			287,439
Total stockholders’ equity		675,396			575,666
	$	2,571,976		$	1,882,912

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

4

QUICKSILVER RESOURCES INC.

CONDENSED CONSOLIDATED STATEMENTS OF INCOME 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,
	2007			2006			2007			2006
Revenues
Oil, gas and related product sales	$	151,046		$	98,150		$	398,297		$	285,375
Other revenue		8,153			1,063			13,880			2,953
Total revenues		159,199			99,213			412,177			288,328
Expenses
Oil and gas production costs		44,246			24,602			104,804			70,232
Production and ad valorem taxes		4,366			4,502			13,068			10,661
Other operating costs		855			300			1,940			1,249
Depletion, depreciation and accretion		32,115			19,933			84,614			55,560
General and administrative		14,328			6,245			34,324			17,936
Total expenses		95,910			55,582			238,750			155,638
Equity income from affiliates		285			210			682			318
Operating income		63,574			43,841			174,109			133,008
Other income — net		(385	)		(167	)		(1,856	)		(1,015	)
Interest expense		20,690			11,040			53,858			30,808
Income before income taxes and minority interest		43,269			32,968			122,107			103,215
Income tax expense		14,093			10,046			38,158			29,139
Minority interest expense		457			61			648			72
Net income	$	28,719		$	22,861		$	83,301		$	74,004
Other comprehensive income, net of income taxes
Reclassification adjustments – hedge settlements		(15,146	)		(3,409	)		(29,299	)		(4,239	)
Unrealized gain (loss) on derivative instruments		14,547			33,717			(4,381	)		73,282
Foreign currency translation adjustments		13,698			694			28,678			5,605
Comprehensive income	$	41,818		$	53,863		$	78,299		$	148,652
Earnings per common share – basic	$	0.37		$	0.30		$	1.07		$	0.97
Earnings per common share – diluted	$	0.35		$	0.28		$	1.01		$	0.91
Weighted average common shares outstanding
Basic		77,875			77,007			77,557			76,593
Diluted		84,185			83,306			84,014			83,056

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

5

QUICKSILVER RESOURCES INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

In thousands – Unaudited

	For the Nine Months Ended
	September 30,
	2007			2006
Operating activities:
Net income	$	83,301		$	74,004
Adjustments to reconcile net income to net cash provided by operating activities
Depletion, depreciation and accretion		84,614			55,560
Deferred income tax expense		37,912			29,095
Non-cash equity-based compensation		9,415			4,775
Amortization of deferred loan costs		1,458			1,615
Non-cash gain from hedging activities		(2,959	)		(114	)
Equity income from affiliates		(682	)		(318	)
Minority interest expense		648			72
Other non-cash items		2,275			232
Changes in assets and liabilities
Accounts receivable		6,754			7,748
Current and other assets		(12,628	)		(17,921	)
Accounts payable		511			14,844
Accrued and other liabilities		36,907			18,114
Net cash provided by operating activities		247,526			187,706
Investing activities:
Purchases of property, plant and equipment		(706,035	)		(429,485	)
Return of investment in equity affiliates		162			558
Proceeds from sales of properties		166			5,670
Net cash used for investing activities		(705,707	)		(423,257	)
Financing activities:
Issuance of debt		540,030			483,148
Repayments of debt		(182,357	)		(271,808	)
Debt issuance costs		(4,513	)		(9,213	)
Proceeds from exercise of stock options		15,570			18,480
Minority interest contributions		109,809			4,506
Minority interest distributions		(7,694	)		—
Purchase of treasury stock		(1,525	)		(480	)
Net cash provided by financing activities		469,320			224,633
Effect of exchange rates on cash		3,170			(37	)
Net increase (decrease) in cash and cash equivalents		14,309			(10,955	)
Cash and cash equivalents at beginning of period		5,281			14,318
Cash and cash equivalents at end of period	$	19,590		$	3,363

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

6

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 by an independent registered public accounting firm. 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, 2007 and its income and comprehensive income for the three-month and nine-month periods ended September 30, 2007 and 2006 and cash flows for the nine-month periods ended September 30, 2007 and 2006. 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 of America 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, such estimates and assumptions are subject to a number of risks and uncertainties, which may cause actual results to differ materially from the Company’s estimates.

     Certain disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America 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 Form 10-K for the year ended December 31, 2006.

Earnings per Common Share

     Basic earnings per common share is computed by dividing the net income attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period. Diluted earnings per common share is computed using the treasury stock method, which considers the impact to net income and common shares from the potential issuance of common shares underlying stock options, stock warrants and outstanding convertible securities. The following is a reconciliation of the weighted average common shares used in the basic and diluted earnings per common share calculations for the three- and nine- month periods ended September 30, 2007 and 2006. Outstanding options to purchase 2,401 shares were excluded from the diluted net income per share calculation for the periods ended September 30, 2007 and 2006 as those options were out-of-the-money and, therefore, considered to be antidilutive.

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2007		2006		2007		2006
	(in thousands, except per share amounts)
Net income	$	28,719	$	22,861	$	83,301	$	74,004
Impact of assumed conversions — interest on 1.875% contingently convertible debentures, net of income taxes		475		475		1,425		1,425
Net income available to stockholders assuming conversion of contingently convertible debentures	$	29,194	$	23,336	$	84,726	$	75,429
Weighted average common shares - basic		77,875		77,007		77,557		76,593
Effect of dilutive securities:
Employee stock options		657		901		763		1,178
Employee stock awards		745		490		786		377
Contingently convertible debentures		4,908		4,908		4,908		4,908
Weighted average common shares - diluted		84,185		83,306		84,014		83,056
Basic earnings per common share	$	0.37	$	0.30	$	1.07	$	0.97
Diluted earnings per common share	$	0.35	$	0.28	$	1.01	$	0.91

7

Property, Plant and Equipment

     The Company follows the full cost method of accounting for oil and gas properties. Accordingly, all costs associated with the acquisition, exploration and development of oil and gas properties, including costs of undeveloped leasehold, geological and geophysical expenses, dry holes, leasehold equipment and overhead charges directly related to acquisition, exploration and development activities are capitalized. Proceeds received from disposals are credited against accumulated cost except when the sale represents a significant disposal of reserves, in which case a gain or loss is recognized.

     The sum of net capitalized costs and estimated future development and dismantlement costs for each cost center is depleted on the equivalent unit-of-production method, based on proved oil and gas reserves as determined by independent petroleum engineers. Costs associated with unevaluated properties are excluded from amounts subject to depletion. Natural gas and crude oil are converted to equivalent units based upon the relative energy content, which is six thousand cubic feet of natural gas to one barrel of crude oil.

     Net capitalized costs are limited to the lower of unamortized cost net of deferred tax or the cost center ceiling. The cost center ceiling is defined as the sum of (i) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on unescalated year-end prices and costs, adjusted for contract provisions, financial derivatives that hedge the Company’s oil and gas revenue and asset retirement obligations, (ii) the cost of properties not being amortized, and (iii) the lower of cost or market value of unproved properties included in the cost being amortized, less (iv) income tax effects related to differences between the book and tax basis of the natural gas and crude oil properties. Such limitations are imposed separately for the U.S. and Canadian cost centers.

     Based on spot oil and natural gas prices on September 30, 2007 and 2006, the unamortized cost of our Canadian oil and gas properties exceeded the cost center ceiling. As permitted by full cost accounting rules, improvements in spot oil and natural gas prices subsequent to the balance sheet date have eliminated the necessity to record a write-down. Using spot prices in effect on September 30, 2007 and 2006, the write-down would have been approximately $47 million and $57 million, respectively.

     All other property and equipment are stated at original cost and depreciated using the straight-line method based on estimated useful lives from five to forty years.

Recently Issued Accounting Standards

• Pronouncements Implemented

In June 2006, the Financial Accounting Standards Board (“FASB”) issued Interpretation No. 48 (“FIN 48”),Accounting for Uncertainty in Income Taxes — An Interpretation of FASB Statement No. 109. FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 109,Accounting for Income Taxes.This Interpretation prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. This Interpretation also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. In connection with the Company’s adoption of FIN 48, as of January 1, 2007, the Company recorded an adjustment to retained earnings of approximately $0.3 million for unrecognized tax benefits, all of which would affect our effective tax rate if recognized. This reduction in retained earnings was offset against the Company’s net operating loss carryforwards in the deferred federal income tax liability account. As of January 1, 2007, the Company’s unrecognized tax benefits totaled $1.4 million. The Company’s unrecognized tax benefits at September 30, 2007 were $0.3 million.

8

• Pronouncements Not Yet 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 will change current practice. The Company will adopt SFAS No. 157 on January 1, 2008, but does not expect adoption of SFAS No. 157 to have a material impact on the Company’s financial position, results of operations or cash flows.

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 that have been offset in accordance with that paragraph. The Company will adopt FSP No. 39-1 on January 1, 2008 employing retrospective representation for all periods, but does not expect adoption to have a material impact on the Company’s financial position, results of operations or cash flows.

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. It provides entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. SFAS No. 159 is effective for the Company beginning after January 1, 2008. We are still evaluating the impact of SFAS No. 159 on our consolidated financial condition and results of operations.

2. QUICKSILVER GAS SERVICES LP

     On August 10, 2007, the Company’s majority-owned subsidiary, Quicksilver Gas Services LP (“KGS” or the “Partnership”), completed its underwritten initial public offering (“IPO”). KGS, a limited partnership engaged in the business of gathering and processing natural gas produced from the Barnett Shale formation in the Fort Worth Basin in North Texas, sold 5,000,000 common units for $95.0 million, net of underwriters’ discount and other offering costs. On September 7, 2007, the underwriters of the KGS IPO exercised their option to purchase an additional 750,000 common units for approximately $14.6 million, net of underwriters’ discount.

     Upon completion of these IPO-related transactions, KGS’ ownership is summarized in the following table:

	Ownership
	Quicksilver			Non-Quicksilver			Total
General partner interests		1.9	%		—			1.9	%
Limited partner interests:
Common interests		23.5	%		27.1	%		50.6	%
Subordinated interests		47.5	%		—			47.5	%
Total limited partner interests		71.0	%		27.1	%		98.1	%
Total interests		72.9	%		27.1	%		100.0	%

     The subordinated units will convert into an equal number of common units upon termination of the subordination period. Generally, the subordination period will end when either:

1. KGS has earned and paid at least $0.30 per quarter on each outstanding common unit, subordinated unit and general partner unit for any three consecutive four-quarter periods ending on or after June 30, 2010; or

9

2. KGS has earned and paid at least $0.45 per quarter on each outstanding common unit, subordinated unit and general partner unit for any consecutive four quarters.

     Upon completion of the IPO, KGS paid Quicksilver approximately $112.1 million in cash and issued Quicksilver a subordinated note with a principal amount of $50 million as a return of investment capital contributed and reimbursement for capital expenditures advanced. Quicksilver has deferred a gain of approximately $82 million related to the IPO that will be recognized in the consolidated income statement when the subordination period terminates.

     The Company includes the results of operations and financial position of KGS in the consolidated financial statements of Quicksilver, and recognizes the unowned portion of KGS’ results of operations as a component of minority interest expense.

3. DIVESTITURE OF NORTHEAST REGION OPERATIONS

     On September 11, 2007, Quicksilver signed a definitive agreement (the “BreitBurn” Transaction) to contribute all of its oil and gas properties and facilities in Michigan, Indiana and Kentucky (collectively the “Northeast Operations”) to BreitBurn Operating L.P. (“BreitBurn”). The BreitBurn Transaction closed on November 1, 2007 for total consideration of $750 million of cash and 21.348 million shares of BreitBurn limited partnership units equaling total consideration of $1.47 billion. On November 1, 2007, the Company used $270 million of proceeds from the BreitBurn Transaction to reduce the U.S. borrowings then outstanding under its senior secured credit facility. During November 2007, the Company may repay as much as an additional $307 million of U.S. borrowings outstanding under the senior credit facility which would reduce to zero all U.S. borrowing outstanding under the senior credit facility. Under the terms of the transaction, the Company is prohibited from selling any of the acquired units within one year of closing and is prohibited from selling more than 50% of the acquired units within 18 months of closing.

     Concurrent with closing the BreitBurn Transaction, the Company agreed to provide certain one-time benefits to 138 terminated employees, including settling unvested stock-based compensation in cash and providing cash severance and retention benefits payable in multiple installments over two years. The Company anticipates the total expense associated with the termination-related employees benefits to be approximately $9.7 million which will be recognized approximately 60% in 2007, 20% in 2008 and 20% in 2009. The $5.4 million recognized in oil and gas production costs in the third quarter of 2007 comprised stock modification expenses of $4.3 million and severance payments of $1.1 million associated with services rendered through that time by affected employees. The amounts to be recognized during the fourth quarter of 2007 and beyond are attributable to the services to be rendered by the affected employees over these periods and are payable only in the event of continued service to BreitBurn.

     The Company has a supply contract expiring in March 2009 to deliver 25,000 Mcfd of natural gas at a floor price of $2.49 per Mcf to a customer in Michigan. This contract has been exempt from the mark-to-market provisions for such contracts pursuant to the “normal sales” exclusion of SFAS No. 133. Although the Company had previously delivered production from its Northeast Operations in fulfillment of the contract, the Company will continue to deliver natural gas from other producing areas. Accordingly, the Company continues to apply the “normal sales” exemption for the supply contract. Had the Company terminated the contract, the Company believes that the cost of termination would have been approximately $70 million at September 30, 2007.

     A portion of the Company’s hedging program that was designated as applicable to the Northeast Operations for the period subsequent to the closing of the BreitBurn Transaction no longer qualifies for hedge accounting treatment. Accordingly, concurrent with the signing of the BreitBurn agreement, the Company reclassified the amounts included in accumulated other comprehensive income for the affected Northeast Operations hedges and recognized the changes in fair value for such contracts through September 30, 2007. This aggregate recognition totaled approximately $2.0 million which is included as an increase to other revenue in the consolidated statement of income. In October 2007, the Company re-designated the Northeast Operations gas collars and swaps as hedges of other U.S. production, and will apply hedge accounting treatment for prospective changes in value.

     The Company will account for its investment in the BreitBurn units using the equity method. As such, the Company is considered to have a “continuing interest” in BreitBurn and a portion of the otherwise calculated book gain was deferred. At closing, the Company received BreitBurn units with an aggregate value of $724 million, but recorded them net of a deferred gain of $280 million for a net carrying value of $445 million. Should the Company sell a portion of its BreitBurn units, a pro rata portion of the deferred gain attributable to the sold units would be recognized.

     In completing the transaction, the Company utilized certain investment banking services. Approximately $2 million of expense related to such services is included in general and administrative expense during the quarter ended September 30, 2007, with an additional approximately $6.7 million recognized in the fourth quarter of 2007 as a reduction of proceeds generated by the BreitBurn Transaction.

10

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

4. HEDGING

     The estimated fair values of all hedge derivatives and the associated fixed price firm sale commitments as of September 30, 2007 and December 31, 2006 are provided below. The carrying values of these financial instruments and firm commitments are equal to the estimated fair values as of the dates presented. The assets and liabilities recorded in the balance sheet are netted where derivatives with both gain and loss positions are held with a single counterparty under a master netting arrangement. A non-cash gain of $3.0 million was included in other revenue for 2007, including $1.0 million, as a result of ineffectiveness from the Company’s cash flow hedges caused by variances in the price differentials for estimated future realized prices and NYMEX prices. As discussed in Note 3, other revenue also includes $2.0 million for the derivatives attributable to the Northeast Operations. The contracts previously designated to the Northeast Operations are included in the Company’s consolidated derivative amounts presented below:

	September 30,		December 31,
	2007		2006
	(in thousands)
Derivative assets:
Fixed price sale commitments	$	—	$	53
Natural gas basis swaps		487		159
Crude oil financial collars		6		689
Natural gas financial swaps		2,582		1,009
Natural gas financial collars		22,894		65,982
	$	25,969	$	67,892
Derivative liabilities:
Floating price natural gas financial swaps	$	—	$	53
NGL financial swaps		3,424		—
Crude oil financial collars		1,933		—
Natural gas financial collars		529		—
	$	5,886	$	53

     The fair value of all natural gas and crude oil financial instruments and, when appropriate, any associated firm sale commitments as of September 30, 2007 and December 31, 2006 were estimated based on market prices for natural gas and crude oil for the periods covered by the hedge derivatives. The net differential between the contractual prices in each hedge derivative and commitment and market prices for future periods, as adjusted for estimated basis, has been applied 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. As a result, the estimated fair value of the Company’s hedge derivatives and associated firm sales commitments does not necessarily represent the value a third party would pay or be paid to assume the Company’s contract positions.

     At September 30, 2007, net cash flow hedge gains of $18.9 million have been classified as current based on the maturity of the derivative instruments. The Company estimates $12.7 million of after-tax gains will be reclassified from other comprehensive income over the next twelve months.

     The Company has a supply contract expiring in March 2009 to deliver 25 MMcfd of natural gas at a floor price of $2.49 per Mcf to a customer in Michigan. This contract has been exempt from the mark-to-market provisions for such contracts pursuant to the “normal sales” exclusion of SFAS No. 133. Although the Company had previously delivered production from its Northeast Operations in fulfillment of the contract, the Company will continue to deliver natural gas from other producing areas. Accordingly, the Company continues to apply the “normal sales” exemption for the supply contract. Had the Company terminated the contract, the Company believes that the cost of termination would have been approximately $70 million at September 30, 2007.

11

5. PROPERTY, PLANT AND EQUIPMENT

     Property, plant and equipment consists of:

	September 30,			December 31,
	2007			2006
	(in thousands)
Oil and gas properties:
Subject to depletion	$	2,177,4841		$	1560,459
Unevaluated costs		239,807			191,665
Accumulated depletion		(390,256	)		(308,065	)
Net oil and gas properties		2,027,035			1,444,059
Other property and equipment
Pipelines and processing facilities		366,510			225,771
General properties		30,778			17,183
Construction in progress		17,767			31,613
Accumulated depreciation		(54,239	)		(39,346	)
Net other property and equipment		360,816			235,221
Property, plant and equipment – Net	$	2,387,851		$	1,679,280

6. LONG-TERM DEBT

     Long-term debt consists of:

	September 30,			December 31,
	2007			2006
	(in thousands)
Senior secured credit facility	$	820,363		$	421,123
Senior subordinated notes		350,000			350,000
Contingently convertible debentures, net of unamortized discount		148,078			147,994
KGS credit facility		—			—
Other loans		126			400
		1,318,567			919,517
Less current maturities		(126	)		(400	)
	$	1,318,441		$	919,117

     On February 9, 2007, the Company amended its senior secured credit facility to extend its maturity to February 9, 2012 and to provide for revolving loans, swingline loans and letters of credit from time to time in an aggregate amount not to exceed the borrowing base, which is calculated based on several factors and was initially equal to $850 million, but was subsequently increased to $1.1 billion effective September 11, 2007. The borrowing base is subject to annual redeterminations and certain other redeterminations. The lenders have agreed to $1.2 billion of revolving credit commitments and the Company has an option to increase the facility to $1.45 billion with consent of the lenders. The lenders’ commitments under the facility are allocated between U.S. and Canadian funds, with the U.S. funds available for borrowing by the Company and Canadian and U.S. funds being available for borrowing by the Company’s wholly-owned Canadian subsidiary, Quicksilver Resources Canada Inc. (“QRCI”). The facility allows the Company to extend the maturity up to two additional years with requisite lender consent. U.S. borrowings under the facility are guaranteed by most of Quicksilver’s domestic subsidiaries and are secured by, among other things, Quicksilver’s and its domestic subsidiaries’ oil and gas properties. Canadian borrowings under the facility are guaranteed by Quicksilver and most of Quicksilver’s domestic subsidiaries and are secured by, among other things, QRCI’s, Quicksilver’s and certain of Quicksilver’s domestic subsidiaries’ oil and gas properties. The loan agreements for the credit facility prohibit the declaration or payment of dividends by the Company and contain certain financial covenants, which, among other things, require the maintenance of a minimum current ratio and a minimum earnings (before interest, taxes, depreciation, depletion and amortization, non-cash income and expense, and exploration costs) to interest expense ratio. At September 30, 2007, the Company was in compliance with all covenants.

     The terms and conditions of the Senior Subordinated Notes require the Company to comply with certain covenants, which primarily limit certain activities, including, among other things, levels of indebtedness, restricted payments, payments of

12

dividends, capital stock repurchases, investments, liens, restrictions on restricted subsidiaries to make distributions, affiliate transactions and mergers and consolidations. At September 30, 2007, the Company was in compliance with such covenants.

     In October 2007, the agents and lenders under the Company’s senior secured credit facility consented to the BreitBurn Transaction. As a condition to such consent, among other things, the parties agreed to a reduction in the borrowing base from $1.1 billion to $750 million effective upon consummation of the BreitBurn Transaction. Reduction of the borrowing base necessitated a prepayment of outstanding borrowings under the credit facility as described below. The Company also agreed to pledge the equity interests in BreitBurn it received as part of the BreitBurn Transaction to secure its and QRCI’s obligations under the credit facility. The covenants in the credit facility otherwise have not changed as a result of the lenders’ consent to the BreitBurn Transaction.

     On September 11, 2007, Quicksilver signed a definitive agreement to contribute all of its Northeast Operations to BreitBurn. The BreitBurn Transaction closed on November 1, 2007 for total consideration of $750 million of cash and 21.348 million shares of BreitBurn limited partnership units equaling total consideration of $1.47 billion. On November 1, 2007, the Company used $270 million of proceeds from the BreitBurn Transaction to reduce the U.S. borrowings then outstanding under its senior secured credit facility. During November 2007, the Company may repay as much as an additional $307 million of U.S. borrowings outstanding under the senior credit facility which would reduce to zero all U.S. borrowing outstanding under the senior credit facility.

     The convertible subordinated debentures due November 1, 2024 are contingently convertible into shares of Quicksilver’s common stock (subject to adjustment). Additionally, holders of the debentures can require the Company to repurchase all or a portion of their debentures on November 1, 2011, 2014 or 2019 at a price equal to the principal amount thereof plus accrued and unpaid interest. The debentures are convertible into Quicksilver common stock at a rate of 32.7209 shares for each $1,000 debenture, subject to adjustment. Generally, except upon the occurrence of specified events, holders of the debentures are not entitled to exercise their conversion rights unless the closing price of Quicksilver’s stock price is at least $36.67 (120% of the conversion price per share) for at least 20 trading days during the period of 30 consecutive trading days ending on the last trading day of the preceding fiscal quarter. As of September 30, 2007, the debentures were convertible into 4,908,128 shares of Quicksilver’s common stock. Upon conversion, the Company has the option to deliver in lieu of Quicksilver common stock, cash or a combination of cash and Quicksilver common stock.

     Concurrent with its IPO, KGS entered into a five-year $150 million senior secured revolving credit facility (“KGS Credit Agreement”), with options exercisable by KGS to extend the facility for up to two additional years and increase the facility up to $250 million, in each case with consent of the lenders. The KGS Credit Agreement provides for revolving credit loans, swingline loans and letters of credit. Borrowings under the facility are guaranteed by the Partnership’s subsidiaries and are secured by substantially all of the assets of the Partnership and each of its subsidiaries. KGS’ interest rate options under the facility include the London InterBank Offered Rate (“LIBOR”) and U.S. prime for revolving loans and a specified rate for swingline loans. Each interest rate option includes a margin which increases in specified increments in tandem with an increase in the Partnership’s leverage ratio, in accordance with the KGS Credit Agreement. KGS must maintain certain financial ratios that can limit its borrowing capacity. The KGS Credit Agreement contains certain restrictive covenants which, among other things, require the maintenance (measured quarterly) of a maximum leverage ratio of debt to Consolidated EBITDA (as defined in the Credit Agreement) and a minimum ratio of Consolidated EBITDA to interest expense.

     At September 30, 2007, KGS’ borrowing capacity was $66.8 million, as limited by the facility’s leverage ratio test; however, there were no outstanding borrowings under the KGS Credit Agreement. The KGS Credit Agreement prohibits the declaration or payment of distributions by the Partnership if an event of default then exists or would result from payment of a distribution. KGS was in compliance with all covenants at September 30, 2007.

7. ASSET RETIREMENT OBLIGATIONS

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

13

     At September 30, 2007 and December 31, 2006, retirement obligations classified as current were approximately $0.2 million. The following table provides a reconciliation of the changes in the estimated asset retirement obligation for the nine-month periods ended September 30, 2007 and 2006.

	Nine Months Ended
	September 30,
	2007			2006
	(in thousands)
Beginning asset retirement obligation	$	25,206		$	20,965
Additional liability incurred		2,993			2,068
Accretion expense		1,187			959
Change in estimates		—			29
Loss on settlement of liability		4			115
Asset retirement costs incurred		(6	)		(200	)
Sale of properties		—			(2,439	)
Currency translation adjustment		1,878			387
Ending asset retirement obligation	$	31,262		$	21,884

8. COMMITMENTS AND CONTINGENCIES

     The Company has contracts for the use of drilling rigs in its drilling and exploration programs for initial periods ranging from one to three years at estimated day rates ranging from $18,500 to $22,000 per day, with five rigs under such contracts at September 30, 2007. Each of the contracts requires payment of the specified day rate for the entire lease term of each contract regardless of the Company’s utilization of the drilling rigs. As of September 30, 2007, commitments under these contracts, in thousands, were as follows:

Remainder of 2007	$	8,832
2008		29,106
2009		29,091
2010		2,753
	$	69,782

     The Company has entered into firm transportation contracts with third-party pipelines under which the Company is obligated to transport minimum daily gas volumes, as calculated on a monthly basis, or pay for any deficiencies at a specified reservation fee rate. The Company’s production committed to the pipelines is expected to meet, or exceed, the minimum daily volumes provided in the contracts. As of September 30, 2007, commitments under these contracts, in thousands, were as follows:

Remainder of 2007	$	—
2008		4,020
2009		9,506
2010		10,494
2011		10,494
Thereafter		70,154
	$	104,668

     The Company is subject to various possible contingencies, which arise primarily from interpretation of federal and state laws and regulations affecting the natural gas and crude oil 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,

14

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.

     As previously reported in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2006, on October 13, 2006, the Company filed suit in the 342nd Judicial District Court in Tarrant County, Texas against Eagle Drilling, LLC and Eagle Domestic Drilling Operations, LLC (together “Eagle”) regarding three contracts for drilling rigs in which the Company alleges that the first rig furnished by Eagle exhibited operating deficiencies and safety defects and that the other rigs failed to conform to specifications set forth in the drilling contracts. Subsequently, on January 19, 2007, Eagle Domestic Drilling Operations, LLC and its parent, Blast Energy Services, Inc. filed for Chapter 11 bankruptcy in the United States Bankruptcy Court for the Southern District of Texas, Houston Division. The Company’s suit against Eagle in Tarrant County was ultimately transferred to the Bankruptcy Court in Houston and has been consolidated with the Eagle/Blast bankruptcy. On September 17, 2007, Eagle Drilling, LLC, and Rod and Richard Thornton, sued the Company and P. Jeffrey Cook, the Company’s Executive Vice President-Operations, in the District Court of Cleveland County, Oklahoma for alleged damages resulting from the Company’s decision to repudiate the rig contracts mentioned above. Based upon information currently available, the Company believes that the final resolution of this matter will not have a material effect on the Company’s financial condition, results of operations, or cash flows.

     In October 2007, KGS entered into a $25.7 million agreement with Exterran Energy Solutions (“Exterran”) to engineer, design, construct, install, and test a 125 MMcf/d cryogenic gas processing and liquid hydrocarbon recovery facility in the Fort Worth Basin. KGS also entered into a $21.9 million agreement with EFX Compression Enerflex (“Enerflex”) to provide natural gas compression equipment for the facility. Progress payments will be due to Exterran and Enerflex upon completion of established milestones related to the construction of the natural gas processing facilities. The gas processing facility is estimated to be placed into operation during the first quarter of 2009.

9. STOCK-BASED COMPENSATION

     At January 1, 2007, the Company had total compensation cost of $0.5 million related to unvested stock options with a weighted average remaining vesting period of 1.2 years. The Company recorded expense of $0.3 million and $0.5 million for stock options in the first nine months of 2007 and 2006, respectively. At September 30, 2007, the Company had $0.2 million of expense remaining in unrecognized compensation cost for the unvested portion of stock options awarded prior to 2006.

     At January 1, 2007 and 2006, the Company had total unvested compensation cost of $14.7 million and $3.3 million, respectively, related to unvested restricted stock and stock unit awards. Additionally, grants of restricted stock and stock units through September 30, 2007 and 2006 had total compensation cost of $15.7 million and $18.2 million, respectively, at the time of grant which will be recognized as expense over the vesting period. During the first nine months of 2007 and 2006, the Company recognized $9.0 million and $4.2 million respectively, of expense for vesting of restricted stock and stock units. Total unvested compensation cost was $21.4 million at September 30, 2007 with a weighted average remaining vesting period of 1.2 years.

     SFAS No. 123(R) requires tax benefits resulting from tax deductions in excess of the compensation cost recognized for those options (“excess tax benefits”) to be classified and reported as both an operating cash outflow and a financing cash inflow upon adoption of SFAS No. 123(R). As a result of the Company’s net operating losses, the excess tax benefits that would otherwise be available to reduce income taxes payable have the effect of increasing the Company’s net operating loss carry forwards. Accordingly, because the Company is not able to realize these excess tax benefits, such benefits have not been recognized in the condensed consolidated statement of cash flows for the nine-month periods ended September 30, 2007 and 2006.

2006 Equity Plan

     Upon approval of the 2006 Equity Plan, seven million shares of common stock were reserved for issuance pursuant to grants of stock options, appreciation rights, restricted shares, restricted stock units, performance shares, performance units and senior executive plan bonuses. Executive officers, other employees, consultants and non-employee directors of the Company or a subsidiary of the Company are eligible to participate in the 2006 Equity Plan. Under the terms of the 2006 Equity Plan, stock options may be granted at an exercise price that is not less than 100% of the fair market value on the date of grant and may not be exercised more than 10 years from the date of grant.

Quicksilver Stock Options

     The following table summarizes the Company’s stock option activity during the first nine months of 2007:

15

				Weighted
				Average
	Shares			Exercise Price
Outstanding at beginning of year		1,689,190		$	16.84
Granted		—			—
Exercised		(825,046	)		18.87
Forfeited		(13,590	)		10.80
Outstanding at period end		850,554		$	14.97
Exercisable at September 30, 2007		580,427		$	16.30
Vested or expected to vest at September 30, 2007		827,073		$	15.08

     Stock options vested and exercisable at September 30, 2007 had an aggregate intrinsic value of $17.8 million and a weighted average remaining term of 1.9 years.

     Cash received from the exercise of stock options totaled $15.6 million and $18.5 million for the first nine months of 2007 and 2006, respectively. The intrinsic value of the options exercised in the first nine months of 2007 was $20.6 million.

Quicksilver Restricted Stock and Restricted Stock Units

     During the first nine months of 2007, the Company awarded 415,162 shares of restricted stock and stock units to employees at a weighted average market price of $36.75 per share. The shares and units awarded vest ratably over a three-year period. Each of the four non-employee directors of the Company received a grant of 1,740 restricted shares at a market value of $34.48 per share on January 3, 2007. These restricted shares will become fully vested one year from the date of grant provided the non-employee director remains a member of the Board of Directors of the Company. An additional 893 shares at a market value of $43.69 per share were granted to each of the four non-employee directors on May 23, 2007. These restricted shares will vest ratably over a three-year period from the date of grant provided the non-employee director remains a member of the Board of Directors of the Company.

     The following table summarizes the Company’s restricted stock and stock unit activity during the first nine months of 2007:

				Weighted
				Average
				Grant Date
	Shares			Fair Value
Outstanding at beginning of year		511,873		$	38.35
Granted		425,694			36.77
Vested		(153,590	)		37.14
Forfeited		(49,595	)		36.18
Outstanding at period end		734,382		$	37.84

     The total fair value of shares and units vested during the nine months ended September 30, 2007 was $6.4 million.

KGS Restricted Phantom Units

     Awards of phantom units have been granted under KGS’ 2007 Equity Plan, which permits the issuance of up to 750,000 units. At time of issuance, the Board of Directors of KGS determines whether the issued units will be settled in cash or settled in KGS units. For awards payable in cash, KGS amortizes the expense associated with the award over the vesting period. However, the fair value is reassessed at every balance sheet date, whereby the vested portion of awards are adjusted to reflect revised fair value via compensation expense. Phantom unit awards payable in units are valued at the closing market price of KGS common units on the date of grant. The unearned compensation is amortized to compensation expense over the vesting period of the phantom award. The following table summarizes information regarding the phantom unit activity:

16

	Payable in cash				Payable in units
			Weighted				Weighted
			Average				Average
			Grant Date				Grant Date
	Shares		Fair Value		Shares		Fair Value
Number of unvested units
Outstanding — January 1, 2007		—	$	—		—	$	—
Vested		—		—		—		—
Issued		84,961		21.36		9,833		21.36
Cancelled		—		—		—		—
Unvested Phantom Units — September 30, 2007		84,961	$	21.36		9,833	$	21.36

We recognized compensation expense of approximately $0.1 million during the nine months ended September 30, 2007. We had unearned compensation related to KGS restricted phantom units of approximately $2.2 million at September 30, 2007, which will be recognized over the next 2.9 years.

10. CONDENSED CONSOLIDATING FINANCIAL INFORMATION

     The following subsidiaries of Quicksilver are guarantors of Quicksilver’s Senior Subordinated Notes issued March 16, 2006: Mercury Michigan, Inc., Terra Energy Ltd., GTG Pipeline Corporation, Cowtown Pipeline Funding, Inc., Cowtown Pipeline Management, Inc., Terra Pipeline Company, Beaver Creek Pipeline, LLC, 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.

Condensed Consolidating Balance Sheets

	September 30, 2007
					Non-					Quicksilver
	Quicksilver		Guarantor		Guarantor					Resources Inc.
	Resources Inc.		Subsidiaries		Subsidiaries		Eliminations			Consolidated
	(in thousands)
ASSETS
Current assets	$	4,589	$	275,229	$	229,188	$	(354,251	)	$	154,755
Investments in and advances to equity affiliates		622,217		165,585		—		(780,641	)		7,161
Property, plant and equipment — net		1,544,145		86,797		756,909		—			2,387,851
Other assets		70,727		64,328		2,238		(115,084	)		22,209
Total assets	$	2,241,678	$	591,939	$	988,335	$	(1,249,976	)	$	2,571,976
LIABILITIES
Current liabilities	$	366,089	$	162,143	$	59,450	$	(354,251	)	$	233,431
Non-current liabilities		1,200,193		24,545		524,700		(115,084	)		1,634,354
Minority interest		—		—		28,795		—			28,795
Stockholders’ equity		675,396		405,251		375,390		(780,641	)		675,396
Total liabilities and stockholders’ equity	$	2,241,678	$	591,939	$	988,335	$	(1,249,976	)	$	2,571,976

	December 31, 2006
					Non-					Quicksilver
	Quicksilver		Guarantor		Guarantor					Resources Inc.
	Resources Inc.		Subsidiaries		Subsidiaries		Eliminations			Consolidated
	(in thousands)
ASSETS
Current assets	$	165,061	$	250,928	$	78,531	$	(323,556	)	$	170,964
Investments in and advances to equity affiliates		510,548		131,750		—		(634,864	)		7,434
Property, plant and equipment — net		1,043,037		87,025		549,218		—			1,679,280
Other assets		22,397		—		2,837		—			25,234
Total assets	$	1,741,043	$	469,703	$	630,586	$	(958,420	)	$	1,882,912
LIABILITIES
Current liabilities	$	368,073	$	91,414	$	63,458	$	(323,556	)	$	199,389
Non-current liabilities		797,304		24,577		278,545		—			1,100,426
Minority interest		—		—		7,431		—			7,431
Stockholders’ equity		575,666		353,712		281,152		(634,864	)		575,666
Total liabilities and stockholders’ equity	$	1,741,043	$	469,703	$	630,586	$	(958,420	)	$	1,882,912

17

Condensed Consolidating Statements of Income

	For the Three Months Ended September 30, 2007
							Non-					Quicksilver
	Quicksilver			Guarantor			Guarantor					Resources Inc.
	Resources Inc.			Subsidiaries			Subsidiaries		Eliminations			Consolidated
	(in thousands)
Revenues	$	104,415		$	8,390		$	54,739	$	(8,345	)	$	159,199
Operating expenses		73,375			3,741			27,139		(8345	)		95,910
Income from equity affiliates		(4	)		289			—		—			285
Income from operations		31,036			4,938			27,600		—			63,574
Equity income from affiliates		18,674			374			—		(19,048	)		—
Interest expense and other		15,109			(1,000	)		6,653		—			20,762
Income tax provision		5,882			2,078			6,133		—			14,093
Net income	$	28,719		$	4,234		$	14,814	$	(19,048	)	$	28,719

	For the Three Months Ended September 30, 2006
					Non-					Quicksilver
	Quicksilver		Guarantor		Guarantor					Resources Inc.
	Resources Inc.		Subsidiaries		Subsidiaries		Eliminations			Consolidated
	(in thousands)
Revenues	$	64,106	$	9,078	$	30,048	$	(4,019	)	$	99,213
Operating expenses		38,810		3,819		16,972		(4,019	)		55,582
Income from equity affiliates		7		203		—		—			210
Income from operations		25,303		5,462		13,076		—			43,841
Equity income from affiliates		10,843		808		—		(11,651	)		—
Interest expense and other		7,446		63		3,425		—			10,934
Income tax provision		5,839		1,890		2,317		—			10,046
Net income	$	22,861	$	4,317	$	7,334	$	(11,651	)	$	22,861

	For the Nine Months Ended September 30, 2007
						Non-					Quicksilver
	Quicksilver		Guarantor			Guarantor					Resources Inc.
	Resources Inc.		Subsidiaries			Subsidiaries		Eliminations			Consolidated
	(in thousands)
Revenues	$	264,053	$	27,024		$	140,331	$	(19,231	)	$	412,177
Operating expenses		174,523		13,240			70,218		(19,231	)		238,750
Income from equity affiliates		18		664			—		—			682
Income from operations		89,548		14,448			70,113		—			174,109
Equity income from affiliates		53,025		4,627			—		(57,652	)		—
Interest expense and other		39,935		(1,090	)		13,805		—			52,650
Income tax provision		19,337		5,438			13,383		—			38,158
Net income	$	83,301	$	14,727		$	42,925	$	(57,652	)	$	83,301

	For the Nine Months Ended September 30, 2006
					Non-					Quicksilver
	Quicksilver		Guarantor		Guarantor					Resources Inc.
	Resources Inc.		Subsidiaries		Subsidiaries		Eliminations			Consolidated
	(in thousands)
Revenues	$	172,949	$	33,183	$	90,997	$	(8,801	)	$	288,328
Operating expenses		106,766		12,043		45,630		(8,801	)		155,638
Income from equity affiliates		9		309		—		—			318
Income from operations		66,192		21,449		45,367		—			133,008
Equity income from affiliates		44,499		956		—		(45,455	)		—
Interest expense and other		20,386		72		9,407		—			29,865
Income tax provision		16,301		7,482		5,356		—			29,139
Net income	$	74,004	$	14,851	$	30,604	$	(45,455	)	$	74,004

18

Condensed Consolidating Statements of Cash Flows

	For the Nine Months Ended September 30, 2007
							Non-						Quicksilver
	Quicksilver			Guarantor			Guarantor						Resources Inc.
	Resources Inc.			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(in thousands)
Cash flow provided by operations	$	108,596		$	3,384		$	135,546		$	—		$	247,526
Cash flow used for investing activities		(554,885	)		25,212			(181,131	)		5,097			(705,707	)
Cash flow provided by financing activities		447,026			(28,596	)		55,987			(5,097	)		469,320
Effect of exchange rates on cash		588			—			2,582			—			3,170
Net increase (decrease) in cash & equivalents		1,325			—			12,984			—			14,309
Cash & equivalents at beginning of period		83			—			5,198			—			5,281
Cash & equivalents at end of period	$	1,408		$	—		$	18,182		$	—		$	19,590

	For the Nine Months Ended September 30, 2006
							Non-						Quicksilver
	Quicksilver			Guarantor			Guarantor						Resources Inc.
	Resources Inc.			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(in thousands)
Cash flow provided by operations	$	96,708		$	32,822		$	58,176		$	—		$	187,706
Cash flow used for investing activities		(288,096	)		(54,780	)		(133,117	)		52,736			(423,257	)
Cash flow provided by financing activities		183,529			26,368			67,472			(52,736	)		224,633
Effect of exchange rates on cash		—			—			( 37	)		—			(37	)
Net decrease in cash & equivalents		(7,859	)		4,410			(7,506	)		—			(10,955	)
Cash & equivalents at beginning of period		8,990			(4,410	)		9,738			—			14,318
Cash & equivalents at end of period	$	1,131		$	—		$	2,232		$	—		$	3,363

11. SUPPLEMENTAL CASH FLOW INFORMATION

     Cash paid for interest and income taxes is as follows:

	Nine Months Ended
	September 30,
	2007		2006
	(in thousands)
Interest	$	56,608	$	16,874
Income taxes	$	696	$	3

     Other non-cash transactions are as follows:

	Nine Months Ended
	September 30,
	2007		2006
	(in thousands)
Noncash investing activities — changes in working capital associated with property and equipment	$	8,210	$	2,487

12. RELATED PARTY TRANSACTIONS

     As of September 30, 2007, members of the Darden family, Mercury Exploration Company (“Mercury”) and Quicksilver Energy L.P., entities that are owned by members of the Darden family, beneficially owned approximately 34% of the Company’s outstanding common stock. Thomas Darden, Glenn Darden and Anne Darden Self are officers and directors of the Company.

     Quicksilver and its associated entities paid $1.6 million and $1.0 million in the first nine months of 2007 and 2006, respectively, for rent on buildings owned by Pennsylvania Avenue LP (“PALP”), a Mercury affiliate, and WFMG, L.P., a PALP affiliate. Rental rates are determined based on comparable rates charged by third parties. Payments received during 2007 and 2006 from Mercury for sublease rentals, employee insurance coverage and administrative services totaled $0.2 million and $0.1 million, respectively.

     During the first nine months of 2007 and 2006, the Company paid Regal Jets, LLC (formerly known as Regal Aviation LLC), an unrelated airplane management company, $0.2 million and $0.2 million, 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.

19

13. SEGMENT INFORMATION

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

	Exploration & Production
	United				Processing &								Quicksilver
	States		Canada		Transportation		Corporate			Elimination			Consolidated
	(in thousands)
For the Three Months Ended
September 30, 2007
Revenues	$	112,180	$	45,068	$	10,357	$	—		$	(8,406	)	$	159,199
Depletion, depreciation and accretion		19,528		10,128		2,209		250			—			32,115
Operating income		47,634		25,695		2,469		(12,224	)		—			63,574
Property and equipment costs incurred		216,238		32,422		35,174		906			—			284,740
September 30, 2006
Revenues	$	72,766	$	26,199	$	3,938	$	—		$	(3,690	)	$	99,213
Depletion, depreciation and accretion		11,599		7,042		1,037		255			—			19,933
Operating income		36,661		12,261		1,419		(6,500	)		—			43,841
Property and equipment costs incurred		122,870		35,065		21,275		—			—			179,210

	Exploration & Production
	United				Processing &								Quicksilver
	States		Canada		Transportation		Corporate			Elimination			Consolidated
	(in thousands)
For the Nine Months Ended
September 30, 2007
Revenues	$	289,865	$	118,327	$	22,840	$	—		$	(18,855	)	$	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
September 30, 2006
Revenues	$	203,036	$	84,709	$	10,009	$	—		$	(9,426	)	$	288,328
Depletion, depreciation and accretion		32,120		20,725		2,141		574			—			55,560
Operating income		103,217		45,295		3,006		(18,510	)		—			133,008
Property and equipment costs incurred		282,089		86,133		62,543		1,207			—			431,972
Fixed Assets – net
September 30, 2007	$	1,625,048	$	528,674	$	299,704	$	4,425		$	—		$	2,387,851
December 31, 2006	$	1,126,350	$	417,199	$	132,457	$	3,274		$	—		$	1,679,280

20

14. INCOME TAXES

     There have been no changes to the Company’s unrecognized U.S. tax benefits during the nine months ended September 30, 2007. Because of the Company’s present tax-basis net operating loss position, no accrual of interest or penalties has been recognized. If required, interest or penalties would be recognized as a component of interest expense. The Company remains subject to examination by the Internal Revenue Service for the years 2001 through 2006. Currently, the Internal Revenue Service is auditing the Company’s 2004 Federal income tax return. This examination is expected to be completed in 2008.

     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 2006. During the second quarter of 2007, Revenue Canada completed its review of the Scientific Research and Experimental Development (“SRED”) credits claimed by QRCI for the years 2002 and 2003 and accepted QRCI’s claim for the SRED credits. As a result, QRCI recognized credits of approximately $1.1 million in the nine months ended September 30, 2007.

     In May 2006, the Texas legislature amended the Texas tax code by replacing the taxable capital and earned surplus components of the existing franchise tax with a new “taxable margin” component which will be effective for the Company on January 1, 2008. The Company has not recognized any unrecognized tax benefits for this new Texas “taxable margin” tax.

     The Company does not anticipate total unrecognized tax benefits to significantly change due to the settlement of audits or the expiration of statute of limitations prior to September 30, 2008.

21

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

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 divestiture of the Northeast Operations, therefore, represents a fractional divestiture of a single asset which precludes recording the applicable portion of the Northeast Operations’ financial position and 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 and crude oil prices;

• failure or delays in achieving expected production from natural gas and crude oil exploration and development projects;

• effects of hedging natural gas and crude oil prices;

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

• competitive conditions in our industry;

• actions taken by third-party operators, processors and transporters;

• changes in the availability and cost of capital;

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

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

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

• the effects of existing or future litigation; and

• factors discussed in our Form 10-K for the year ended December 31, 2006.

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

22

RESULTS OF OPERATIONS

Summary Financial Data
Three Months Ended September 30, 2007 Compared with the Three Months Ended September 30, 2006

Revenues

Oil, Gas and Related Product Sales

     Oil, gas and related product sales, average daily production volumes and average realized sales prices with respect to natural gas, oil and related products for the three months ended September 30, 2007 and 2006 are as follows:

     Oil, gas and related product sales:

	Three Months Ended
	September 30,
	2007		2006
	(in thouands)
Northeast Operations	$	38,413	$	39,772
Texas		62,071		26,668
Other U.S.		2,874		3,027
Corporate and hedging		5,099		2,488
Total U.S.		108,457		71,955
Canada		42,589		26,195
Total	$	151,046	$	98,150

     Average Daily Production Volumes:

	Natural Gas				Oil and								Equivalent Total
	(MMcfd)				Condensate (bbld)				NGL (bbld)				(MMcfed)
	2007		2006		2007		2006		2007		2006		2007		2006
Northeast Operations		67.8		72.8		983		915		408		504		76.2		81.4
Texas		53.2		27.6		262		203		7,766		1,946		101.4		40.5
Other U.S.		0.3		0.4		428		484		34		33		3.1		3.4
Total U.S.		121.3		100.8		1,673		1,602		8,208		2,483		180.7		125.3
Canada		56.9		49.1		—		1		20		8		57.0		49.2
Total		178.2		149.9		1,673		1,603		8,228		2,491		237.7		174.5
Average Realized Prices:
	Natural Gas				Oil and								Equivalent Total
	($/Mcf)				Condensate ($/bbl)				NGL ($/bbl)				($/Mcfe)
	2007		2006		2007		2006		2007		2006		2007		2006
Northeast Operations	$	4.85	$	4.85	$	72.23	$	66.41	$	43.83	$	36.62	$	5.48	$	5.31
Texas		6.05		6.96		70.89		68.53		43.06		42.99		6.66		7.16
Other U.S.		3.78		6.49		65.51		59.98		57.04		51.01		10.05		9.57
Total U.S.		5.93		5.70		69.67		64.74		41.79		41.80		6.53		6.24
Canada		8.11		5.78		—		66.19		52.17		78.66		8.12		5.79
Total	$	6.63	$	5.73	$	69.67	$	64.74	$	41.82	$	41.91	$	6.91	$	6.11

23

The following table summarizes the changes in the production revenues during the quarter ended September 30, 2007 compared with the comparable 2006 period:

(Amounts in thousands)	Natural Gas		Oil		NGL’s			Total
Revenue for the quarter ended September 30, 2006	$	78,994	$	9,551	$	9,605		$	98,150
Volume changes		17,260		444		22,072			39,776
Price changes		12,416		726		(22	)		13,120
Revenue for the quarter ended September 30, 2007	$	108,670	$	10,721	$	31,655		$	151,046

     Natural gas sales of $108.7 million for the third quarter of 2007 were $29.7 million or 38% higher than the third quarter of 2006. Natural gas sales increased as a result of both a $0.90 per Mcf or 16% increase in realized natural gas prices for the third quarter of 2007 as compared to the 2006 period and a 2,605 MMcf or 19% increase in sales volumes. The increased volumes are principally attributable to higher production in the Fort Worth Basin associated with extensive capital expenditures in the region. Also, production from our coal bed methane projects in Canada increased for the third quarter of 2007 by approximately 952 MMcf as compared to the third quarter of 2006 as a result of new wells placed into production subsequent to the third quarter of 2006. The remainder of the change in natural gas production reflects decreased production associated with natural production declines.

     Oil and condensate sales were $10.7 million for the quarter ended September 30, 2007 which was an increase of 12% or $1.2 million from the comparable 2006 period. The majority of the increase is attributable to favorable prevailing prices with a 4% increase in oil production also increasing revenues.

     Our third quarter 2007 NGL sales of $31.7 million increased more than 200% as compared to the third quarter of 2006. NGL sales increased almost entirely due to higher production volumes for the third quarter of 2007, most notably in the Fort Worth Basin. The increase was due to new wells placed into production subsequent to the third quarter of 2006 and improved NGL recovery from our newest processing facility in the Fort Worth Basin that began operations in March 2007.

Other Revenue

     Other revenue in the quarter ended Sept. 30, 2007 increased $7.1 million or more than 600% from the comparable 2006 period. This increase is attributable to a $2.0 million increase in revenue stemming from the valuation of derivative instruments associated with production from our Northeast Operations. Scientific Research and Experimental Development (“SRED”) credits in Canada increased $2.5 million and revenues on third party gathering and processing services increased $1.5 million.

Operating Expenses

Oil and Gas Production Cost

	Three Months Ended September 30,
	2007				2006
	(in thousands, except per unit amounts)
			Cost				Cost
	Amount		Per mcf		Amount		Per mcf
Northeast Operations	$	19,493	$	2.78	$	10,380	$	1.39
Texas		15,343		1.65		6,621		1.78
Other U.S.		812		2.84		1,035		3.27
Total U.S.		35,648		2.15		18,036		1.56
Canada		8,598		1.64		6,566		1.45
Total	$	44,246	$	2.02	$	24,602	$	1.53

24

\

     Oil and gas production cost was $44.2 million for the third quarter of 2007. The $19.6 million increase from the prior year quarter included increases of $17.6 million and $2.0 million for U.S. and Canadian production costs, respectively. In general, these increases are attributable to the aggregate 36% increase in production, inclusive of the 16% increase in Canadian production.

     Oil and gas production cost for the U.S. was $35.6 million for the third quarter of 2007, an increase of 98% compared with the 2006 quarter. The growth of our operations in the Fort Worth Basin increased operating expense approximately $8.1 million for the third quarter of 2007 compared to the 2006 period, comprised, among other things, of increased direct salary and benefits, increased saltwater disposal costs and higher production overhead costs. Additionally the quarter ended September 30, 2007 includes $5.4 million of costs within the Northeast Operations for severance-related costs.

     Texas lease operating expenses for the third quarter of 2007 increased over 130% as compared to the 2006 quarter primarily because of the increasing rate of new wells placed into production although the cost per mcfe has decreased 7% due to the economies of our present operating scale.

     The Northeast Operations production cost increased $9.1 million, which reflects approximately $5.4 million of severance-related benefits and an additional $0.3 million of higher compensation associated with inflations and workforce expansion. The remaining increase is attributable to higher gathering costs and other general increases in the region.

     Canadian oil and gas production cost was $8.6 million for the third quarter of 2007, an increase of 31% compared to the third quarter of 2006. Currency effects increased expense $0.5 million. Canadian expense was further impacted by increased utility costs, higher delay rental costs and by higher production overhead attributable to higher salary costs for the third quarter of 2007 as compared to the 2006 quarter.

Production and Ad Valorem Taxes

     Production and ad valorem tax expense for the third quarter of 2007 was $4.4 million, a decrease of 3% compared to the third quarter of 2006. Third quarter 2007 production taxes decreased $0.8 million as the Northeast Operations’ production decreased and was offset by production increases for Texas, where many of our properties are exempt from or carry a lower rate of production tax based on their drilling cost. Ad valorem taxes increased $0.7 million primarily as the result of additional assets constructed and placed into service in conjunction with our drilling program in the Fort Worth Basin and our more extensive gathering network.

Other Operating Cost

     Other operating cost which principally relates to the cost of processing and gathering third party natural gas in Texas was $0.9 million for the third quarter of 2007. The $0.6 million increase from the prior year quarter relates to the increased cost associated with the expansion of the operating capabilities of our KGS subsidiary with respect to gathering and processing services in the Fort Worth Basin.

25

Depletion, Depreciation and Accretion

	Three Months Ended September 30,
	2007				2006
	(in thousands, except per unit amounts)
			Cost				Cost
	Amount		Per mcf		Amount		Per mcf
Depletion
U.S.	$	17,705	$	1.07	$	10,216	$	0.88
Canada		8,827		1.68		6,124		1.36
Total Depletion		26,532		1.21		16,340		1.02
Depreciation of other fixed assets:
U.S.		4,039		0.24		2,476		0.21
Canada		1,121		0.21		807		0.18
Total Depreciation		5,160		0.24		3,283		0.20
Accretion		423		0.02		310		0.02
Total depletion, depreciation and accretion	$	32,115	$	1.47	$	19,933	$	1.24

     Depletion for the third quarter of 2007 was $26.5 million, which was $10.2 million or 62% higher than depletion for the third quarter of 2006. Higher depletion resulted from a 19% increase in the depletion rate and a 36% increase in sales volumes. Our higher depletion rate for the third quarter of 2007 resulted from significant actual and estimated future capital expenditures and proved reserves added for our Canadian and Fort Worth Basin properties. The $1.9 million increase in depreciation for the third quarter of 2007 as compared to the 2006 third quarter was primarily associated with new gas processing facilities in Canada and Fort Worth Basin field compression and gas processing facilities and gathering system assets.

General and Administrative Expense

     General and administrative expense for the three months ended September 30, 2007 was $14.3 million, an increase of $8.1 or 129% compared to the quarter ended September 30, 2006. This correlates to $0.66 per Mcfe in 2007 compared with $0.39 per Mcfe in 2006. The most significant increase in general and administrative expense for the third quarter of 2007 was a $4.3 million increase in employee compensation and benefits, including approximately $0.9 million of non-cash expense for vesting stock-based compensation. Office expenses, including rent, and information technology expenses increased approximately $0.8 million for the 2007 third quarter as compared to the prior year quarter. These increases were, in large part, the result of increases in personnel working in the corporate office at September 30, 2007 as compared to September 30, 2006 and vesting of restricted stock granted in the first quarter of 2007. The remaining increase in general and administrative expense included $2.8 million for legal, accounting and other professional fees, which include professional fees of $2 million related the BreitBurn Transaction. The Company expects additional expenses of approximately $6.7 million for professional fees on the BreitBurn Transaction to be recognized in the fourth quarter of 2007 at least a portion of which will be recognized as a reduction to proceeds.

Interest Expense

     Interest expense for the third quarter of 2007 was $20.7 million, net of capitalized interest of $0.1 million, which was an increase of $9.7 million or 87% compared to the third quarter of 2006. Since September of 2006, we have increased the amount outstanding under our senior credit facilities by more than $500 million. Our higher outstanding debt increased interest expense by an estimated $8.3 million, while higher prevailing interest rates during the third quarter of 2007 as compared to the prior year period contributed the remaining increase.

Income Tax Expense

     Our provision for income taxes for the third quarter of 2007 increased $4.0 million from the prior year period to $14.1 million. An increase of $9.9 million in pretax income for the third quarter of 2007 as compared to the prior year quarter was the reason for increased federal income tax expense. Our consolidated effective income tax rate of 32.9% in 2007 represents a 2.4% increase from the comparable 2006 period.

26

Divestiture-Related Items

     As mentioned elsewhere, the Company recognized certain items related to the BreitBurn Transaction during the quarter ended September 30, 2007. These items are summarized below:

(Amounts in thousands)
Description	Financial Statement Caption	Amount
Hedging de-designation for Northeast Operations	Increase to Other Revenue	$	2,000
Severance benefits to terminated Northeast Operations employees	Increase to Oil and gas production costs		(5,400	)
Professional fees associated with the BreitBurn Transaction	Increase to General and administrative expense		(2,000	)
Total net divestiture-related items	Reduction to pretax income	$	(5,400	)

The following table highlights the impact that these items had on our reported expenses for the periods indicated:

	Three Months Ended September 30, 2007
	(in thousands, except per unit amounts)
					Excluding
	Amount		Cost		Divestiture		Cost
	As Reported		Per mcf		Expenses		Per mcf
Oil and gas operations expense:
Northeast Operations	$	19,493	$	2.78	$	14,093	$	2.01
Total U.S.		35,648		2.15		30,248		1.82
Total Company		44,246		2.02		38,846		1.78
General and administrative expense	$	14,328	$	0.66	$	12,328	$	0.56

27

Nine Months Ended September 30, 2007 Compared with the Nine Months Ended September 30, 2006

Revenues

Oil and Gas Related Product Sales

     Oil, gas and related product sales, average daily production volumes and average realized sales prices with respect to natural gas, oil and related products for the nine months ended September 30, 2007 and 2006 are as follows:

Oil, gas and related product sales:

	Nine Months Ended September 30,
	2007		2006
	(in thousands)
Northeast Operations	$	113,830	$	127,166
Texas		142,610		65,168
Other U.S.		7,791		8,573
Corporate and hedging		21,457		341
Total U.S.		285,688		201,248
Canada		112,609		84,127
Total	$	398,297	$	285,375

Average Daily Production Volumes:

	Natural Gas				Oil and								Equivalent Total
	(MMcfd)				Condensate (bbld)				NGL (bbld)				(MMcfed)
	2007		2006		2007		2006		2007		2006		2007		2006
Northeast Operations		67.5		72.3		972		941		391		424		75.6		80.5
Texas		42.4		22.9		262		215		5,447		1,229		76.7		31.5
Other U.S.		0.3		0.3		458		472		31		31		3.2		3.4
Total U.S.		110.2		95.5		1,692		1,628		5,869		1,684		155.5		115.4
Canada		55.6		48.9		—		—		11		14		55.7		49.0
Total		165.8		144.4		1,692		1,628		5,880		1,698		211.2		164.4
Average Realized Prices:
	Natural Gas				Oil and								Equivalent Total
	($/Mcf)				Condensate ($/bbl)				NGL ($/bbl)				($/Mcfe)
	2007		2006		2007		2006		2007		2006		2007		2006
Northeast Operations	$	5.08	$	5.38	$	61.83	$	64.41	$	36.37	$	37.98	$	5.51	$	5.78
Texas		6.70		7.55		62.37		65.93		40.74		42.43		6.81		7.58
Other U.S.		5.03		7.27		55.75		58.33		47.68		47.73		8.82		9.38
Total U.S.		6.45		5.94		60.06		61.84		39.84		41.41		6.73		6.39
Canada		7.41		6.28		—		—		61.08		53.71		7.41		6.29
Total	$	6.77	$	6.05	$	60.06	$	61.84	$	39.88	$	41.51	$	6.91	$	6.36

The following table summarizes the changes in the production revenues during the nine months ended September 30, 2007 compared with the comparable 2006 period:

(Amounts in thousands)	Natural Gas		Oil			NGL’s			Total
Revenue for the nine months ended September 30, 2006	$	238,651	$	27,477		$	19,247		$	285,375
Volume changes		39,483		1,049			45,530			86,062
Price changes		28,405		(791	)		(754	)		26,860
Revenue for the nine months ended September 30, 2007	$	306,539	$	27,735		$	64,023		$	398,297

28

     Natural gas sales of $306.5 million for the first nine months of 2007 were $67.9 million or 28% higher than the first nine months of 2006. Natural gas sales increased due to higher realized natural gas prices for the first nine months of 2007 as compared to the 2006 period and due to more produced volumes, particularly in the Fort Worth Basin and, to a lesser extent, in Canada. Natural production declines, partially offset the production increases.

     Oil and condensate sales were $27.7 million for the nine months ended September 30, 2007, roughly flat compared to the first nine months of 2006. The average realized oil and condensate sales price for the 2007 period dipped slightly compared with the first nine months of 2006, whereas new wells in the Fort Worth Basin placed into production subsequent to September 2006 contributed to slightly higher oil revenue.

     Our NGL sales for the first nine months of 2007 increased $44.8 million or more than 230% to $64.0 million compared to the first nine months of 2006. Although realized prices dipped slightly, NGL production from the Fort Worth Basin in the 2007 period increased dramatically as a result of new wells placed into production subsequent to September 2006, start-up of our first natural gas processing facility in April 2006 and improved NGL recoveries that resulted from the March 2007 start-up of our newest processing facility. The Fort Worth Basin increases were partially offset by natural production declines.

Other Revenue

     Other revenue in the nine months ended September 30, 2007 increased $10.9 million or more than 300% from the comparable 2006 period. This increase is attributable to $4.2 million of higher SRED credits in Canada, to $3.4 million of higher natural gas gathering and processing revenues associated with our KGS assets in the Fort Worth Basin. Also, other revenue benefited by $1.0 million due to higher ineffectiveness on derivative instruments and a $2.0 million non-cash gain on derivative instruments associated with production from our Northeast Operations.

Operating Expenses

Oil and Gas Production Cost

	Nine Months Ended September 30,
	2007				2006
	(in thousands, except per unit amounts)
			Cost				Cost
	Amount		Per mcf		Amount		Per mcf
Northeast Operations	$	44,892	$	2.17	$	34,166	$	1.55
Texas		34,271		1.64		15,942		1.85
Other U.S.		2,548		2.88		2,556		2.80
Total U.S.		81,711		1.92		52,664		1.67
Canada		23,093		1.52		17,568		1.31
Total	$	104,804	$	1.82	$	70,232	$	1.56

     Oil and gas production cost for the U.S. was $81.7 million for the first nine months of 2007, which was an increase of $29.0 million compared to the 2006 period. The growth of our operations in the Fort Worth Basin is the primary driver in this increase by virtue of higher processing costs, gathering costs and saltwater disposal costs attributable to the higher production levels. Operating costs in Texas also are influenced by increased salary, benefits and vehicle costs associated with an increased headcount necessary for the increased production.

     Expense for our Northeast Operations increased $10.7 million for the first nine months of 2007 compared to the prior year period, including an increase in overhead expense of $7.5 million. The overhead expense increases were primarily the result of severance-related costs of $5.4 million recognized during the quarter ended September 30, 2007, additional compensation and benefit expense. Principal reasons for direct cost increases in the 2007 period are increased repairs, higher gathering expenses and higher workover costs.

     Canadian oil and gas production cost was $23.1 million for the first nine months of 2007, an increase of $5.5 million or 31% compared to the first nine months of 2006. Canadian compensation expense increased more than $3.3 million for the first nine

29

months of 2007 as compared to the 2006 nine months. In addition, increases in workover costs, delay rentals, utilities and gas facility and processing expenses increased for the first nine months of 2007 compared to the prior year period. These increases reflect additional wells placed into production and the construction of additional gas processing facilities during the past year.

Production and Ad Valorem Taxes

     Production and ad valorem tax expense for the nine months ended September 30, 2007 was $13.1 million, an increase of $2.4 million or 23% compared to the same period in 2006. Production taxes increased $0.7 million as the Northeast Operations’ realized prices were slightly higher in the current year. Ad valorem taxes increased $1.7 million primarily as the result of additional assets constructed and placed into service in conjunction with our drilling program in the Fort Worth Basin and our more extensive gathering network.

Other Operating Expense

     Other operating expense which principally relates to the cost of processing and gathering third party natural gas in Texas was $1.9 million for the nine months ended September 30, 2007. The $0.7 million increase from the prior year period relates to the increased cost associated with the expansion of the operating capabilities of our KGS subsidiary with respect to gathering and processing services in the Fort Worth Basin.

Depletion, Depreciation and Accretion

	Nine Months Ended September 30,
	2007				2006
	(in thousands, except per unit amounts)
			Cost				Cost
	Amount		Per mcf		Amount		Per mcf
Depletion
U.S.	$	45,245	$	1.07	$	27,912	$	0.89
Canada		24,506		1.61		18,099		1.35
Total Depletion		69,751		1.21		46,011		1.03
Depreciation of other fixed assets:
U.S.		10,668		0.25		6,323		0.20
Canada		3,007		0.20		2,267		0.17
Total Depreciation		13,675		0.24		8,590		0.19
Accretion		1,188		0.02		959		0.02
Total depletion, depreciation and accretion	$	84,614	$	1.47	$	55,560	$	1.24

     Depletion for the first nine months of 2007 was $69.8 million, which was $23.7 million or 52% higher than depletion for the 2006 period. Higher depletion resulted from a 18% increase in the depletion rate and a 28% increase in sales volumes. Our higher depletion rate for the first nine months of 2007 resulted from increases to both actual and estimated future capital expenditures and proved reserves added for our Canadian and Forth Worth Basin properties. The $5.1 million increase in depreciation for the first nine months of 2007 as compared to the 2006 period was primarily associated with new gas processing facilities in Canada and Fort Worth Basin gas compression and processing facilities and gathering system assets.

General and Administrative Expense

     General and administrative expense for the nine months ended September 30, 2007 was $34.3 million an increase of $16.4 million or 91% compared to the nine months ended September 30, 2006. This correlates to $0.60 per Mcfe in 2007 compared with $0.40 per Mcfe in 2006. The most significant increase in general and administrative expense for the first nine months of 2007 was a $10.6 million increase in employee compensation and benefits, including approximately $3.4 million of non-cash expense for vesting of stock based compensation. Office expenses, including rent, and information technology expenses increased approximately $1.2 million for the 2007 period as compared to the prior year nine-month period. These increases were, in large part, the result of increases in personnel working in the corporate office at September 30, 2007 as compared to September 30, 2006. Additionally, expense for legal, accounting and other professional services increased $3.9 million for the first nine months of 2007, including legal fees of $0.6 million incurred as a result of the favorable resolution of a dispute concerning royalty interests on certain Michigan wells.

30

     During the quarter ended September 30, 2007, the Company recognized professional fees of $2 million related the BreitBurn Transaction. The Company expects additional expenses of $6.7 million for professional fees on the BreitBurn Transaction to be recognized in the fourth quarter of 2007 as a reduction to the proceeds generated by the divestiture of the Northeast Operations.

Interest Expense

     Interest expense for the first nine months of 2007 was $53.9 million, net of capitalized interest of $1.0 million, which was an increase of $23.1 million compared to the first nine months of 2006. Our average debt outstanding for the first nine months of 2007 was approximately $350 million higher than the 2006 nine-month period. Our higher debt outstanding increased interest expense approximately $17.6 million. Higher interest rates incurred during the first nine months of 2007 as compared to the comparable 2006 period contributed the remaining $5.4 million in increased interest expense. Partially offsetting these increases was the absence of a $1.0 million prepayment charge associated with the retirement of debt in March of 2006.

Income Tax Expense

     Our provision for income taxes for the nine months ended September 30, 2007 increased $9.0 million from the prior year period to $38.2 million. The increase in our income tax provision was the result of a $18.3 million increase in pre tax income for the first nine months of 2007 as compared to the first nine months of 2006. Our U.S. income tax provision of $24.7 million in 2007 was established using the statutory U.S. federal rate of 35% and was flat with the rate in 2006. Our Canadian income tax provision of approximately $13.2 million was accrued at a combined Canadian and provincial statutory rate of 28.5%, but also included income tax credits of approximately $1.1 million for SRED. In 2006, the Company recorded a $3.8 million credit in June 2006 for a reduction in the Canadian federal and provincial income tax rates enacted during the second quarter of 2006.

Divestiture-Related Items

     As mentioned elsewhere, the Company recognized certain items related to the BreitBurn Transaction during the nine months ended September 30, 2007. These items are summarized below:

(Amounts in thousands)
Description	Financial Statement Caption	Amount
Hedging de-designation for Northeast Operations	Increase to Other Revenue	$	2,000
Severance benefits to terminated Northeast Operations employees	Increase to Oil and gas production costs		(5,400	)
Professional fees associated with the BreitBurn Transaction	Increase to General and administrative expense		(2,000	)
Total net divestiture-related items	Reduction to pretax income	$	(5,400	)

The following table highlights the impact that these items had on our reported expenses for the periods indicated:

	Nine Months Ended September 30, 2007
	(in thousands, except per unit amounts)
					Excluding
	Amount		Cost		Divestiture		Cost
	As Reported		Per mcf		Expenses		Per mcf
Oil and gas operations expense:
Northeast Operations	$	44,892	$	2.17	$	39,492	$	1.91
Total U.S.		81,711		1.92		76,311		1.80
Total Company		104,804		1.82		99,404		1.72
General and administrative expense	$	34,324	$	0.60	$	32,324	$	0.56

31

LIQUIDITY, CAPITAL RESOURCES AND FINANCIAL POSITION

     Net cash from operations was $247.5 million for the nine months ended September 30, 2007, an increase of $59.8 million compared to the same period in 2006. Net income of $83.3 million for the first nine months of 2007 was $9.3 million higher than net income for the first nine months of 2006 and non-cash expenses including depletion, depreciation and amortization, deferred taxes, stock-based compensation and deferred financing costs were $41.7 million higher for the nine months ended September 30, 2007. Cash from operations was further increased by additional working capital of $8.8 million for the 2007 nine-month period as compared to the first nine months of 2006.

     On November 1, 2007, we contributed our Northeast Operations to BreitBurn Operating L.P. for total consideration of $1.47 billion, payable as $750 million in cash and 21.348 million common units of BreitBurn Energy Partners L.P.

     During the first nine months of 2007, EBITDA of the Northeast Operations was $ 47.3 million, excluding severance-related costs. It is anticipated that in future periods this EBITDA will be partially offset by distributions on the BreitBurn Energy common units received in the BreitBurn Transaction, currently anticipated to be approximately $12.5 million per calendar quarter.

     Our principal sources of cash are sales of natural gas, crude oil and NGLs. During the nine months ended September 30, 2007, sales under our long-term contracts with price floors averaging $2.48 per Mcf covered 25% of our U.S. natural gas production. Additionally, price collars covered approximately 65% of our total production for the nine months ended September 30, 2007. We currently have price collars or fixed price swaps hedging our anticipated natural gas, crude oil and condensate and NGL production of approximately 123 MMcfd, 1,000 Bbld and 3,000 Bbld, respectively, for the fourth quarter of 2007. We have hedged approximately 40 MMcfd and 65 MMcfd of our anticipated 2008 natural gas sales using price collars and fixed-price swaps, respectively. Anticipated 2008 crude oil of approximately 1,000 Bbld has also been hedged with crude oil price collars while 3,000 Bbld of anticipated 2008 NGL production has been hedged with fixed-price swaps. Anticipated first quarter 2009 natural gas production of approximately 90 MMcfd has been hedged with natural gas price collars. Approximately 50 MMcfd of anticipated 2009 natural gas production has been hedged with natural gas price collars for each of the three remaining quarters of 2009.

     During the first nine months of 2007, we paid $706 million for property and equipment, an increase of more than $275 million compared to the first nine months of 2006. Property and equipment acquired (payments for property and equipment plus noncash changes in working capital associated with property and equipment) for the 2007 period totaled $714 million, which consisted of $577 million expended for exploration and development activities (including almost $18 million for the Northeast Operations), $111 million expended for our Fort Worth basin gas processing and gathering operations and $8.0 million expended for Canadian gas processing facilities. Of the $522 million incurred for U.S. exploration and development, $504 million was spent in Texas, including $29 million for non-producing leasehold costs. During 2006, we received approximately $4.5 million from the sale of producing property in Canada.

	Nine Months Ended
	September 30, 2007
	(in thousands)
Exploration and development:
Northeast Operations	$	17,558
Texas		503,842
Other U.S.		919
Total U.S.		522,319
Canada		54,304
Total exploration and development:		576,623
Gas processing and transportation:
Northeast Operations		876
Texas		120,055
Other U.S.		—
Total U.S.		120,931
Canada		8,027
Total gas processing and transportation:		128,958
Corporate and field office		8,664
Total plant and equipment costs incurred	$	714,245

     On August 10, 2007, the Company’s majority-owned subsidiary, KGS, completed its initial public offering (“IPO”). KGS, a limited partnership engaged in the business of gathering and processing natural gas produced from the Barnett Shale formation in the Fort Worth Basin in North Texas, sold 5,000,000 common units for $95.0 million, net of underwriters’ discount and other offering costs. On September 7,

32

2007, the underwriters of the KGS IPO exercised their option to purchase an additional 750,000 common units for $14.6 million, net of underwriters’ discount. The following table summarizes ownership of KGS upon completion of these IPO transactions:

	Interests
	Limited Partner			General Partner			Total
Quicksilver ownership
Common		23.5	%		1.9	%		25.4	%
Subordinate		47.5	%		—			47.5	%
Non-Quicksilver ownership		27.1	%		—			27.1	%
Total		98.1	%		1.9	%		100.0	%

     The subordinated units will convert into an equal number of common units upon termination of the subordination period. Generally, the subordination period will end when KGS has earned and paid at least $0.30 per quarter on each outstanding common unit, subordinated unit and general partner unit for any three consecutive four-quarter periods ending on or after June 30, 2010. Should KGS earn and pay at least $0.45 per quarter on each outstanding common unit, subordinated unit and general partner unit for any consecutive four quarters the subordination period will terminate automatically.

     Upon completion of the IPO, KGS paid Quicksilver approximately $112.1 million in cash and issued to Quicksilver a subordinated note with a principal amount of $50 million as a return of investment capital contributed and reimbursement for capital expenditures advanced. Quicksilver has deferred a gain of approximately $82 million related to the IPO that will be recognized in the consolidated statement of income when the subordination period has terminated.

     Net cash provided by financing activities for the nine months ended September 30, 2007 totaled $469.3 million. In September 2007, the borrowing base under our senior secured credit facility was increased from $850 million to $1.1 billion. At September 30, 2007, approximately $279.2 million was available for borrowing. The loan agreements for the senior credit facility prohibit the declaration or payment of dividends by us and contain certain financial covenants, which, among other things, require the maintenance of a minimum current ratio and a minimum earnings (before interest, taxes, depreciation, depletion, amortization, non-cash income and expense and exploration costs) to interest ratio. We were in compliance with covenants at September 30, 2007.

     In connection with the KGS IPO, KGS entered into a five-year $150 million senior secured revolving credit facility (“KGS Credit Agreement”), with options exercisable by KGS to extend the facility for up to two additional years and increase the facility up to $250 million, in each case with the consent of the lenders. KGS must maintain certain financial ratios that can limit its borrowing capacity. The KGS Credit Agreement contains certain restrictive covenants which, among other things, require the maintenance of a maximum leverage ratio of debt to Consolidated EBITDA (as defined in the Credit Agreement) and a minimum ratio of Consolidated EBITDA to interest expense. At September 30, 2007, KGS’ borrowing capacity was $66.8 million, as limited by the facility’s leverage ratio test; however, there were no outstanding borrowings under the KGS Credit Agreement. The KGS Credit Agreement prohibits the declaration or payment of distributions by the Partnership if an event of default then exists or would result from the payment of a distribution. KGS was in compliance with all covenants as of September 30, 2007.

     On September 11, 2007, Quicksilver signed a definitive agreement to contribute all of its oil and gas properties and facilities in Michigan, Indiana and Kentucky (collectively the “Northeast Operations”) to BreitBurn Operating L.P. (the “BreitBurn Transaction”). The BreitBurn Transaction closed on November 1, 2007 for total consideration of $750 million of cash and 21.348 million shares of BreitBurn limited partnership units equaling total consideration of $1.47 billion. On November 1, 2007, the Company used $270 million of proceeds from the BreitBurn Transaction to reduce the U.S. borrowings then outstanding under its senior secured credit facility. During November 2007, the Company may repay as much as an additional $307 million of U.S. borrowings outstanding under the senior credit facility which would reduce to zero all U.S. borrowing outstanding under the senior credit facility.

33

     As of September 30, 2007 and December 31, 2006, our total capitalization was as follows:

	September 30,		December 31,
	2007		2006
	(in thousands)
Senior secured credit facility	$	820,363	$	421,123
Senior subordinated notes		350,000		350,000
Convertible subordinated debentures		148,078		147,994
KGS secured credit facility		—		—
Other loans		126		400
Total debt		1,318,567		919,517
Stockholders’ equity		675,396		575,666
	$	1,993,963	$	1,495,183

Financial Position

     The following impacted our balance sheet as of September 30, 2007, as compared to our balance sheet as of December 31, 2006:

• Over $700 million increase in our net property, plant and equipment assets includes approximately $714.2 million in capital costs incurred principally for development, exploitation and exploration of our oil and gas properties as well as additional natural gas processing and gathering system assets in Texas.

• We incurred additional long-term debt of $400 million, primarily as a result of our capital expenditure program and partially offset by cash flow from operations. These borrowings have been drawn from our senior secured credit facility. A portion of these borrowings was repaid using after-tax proceeds from the BreitBurn Transaction during November 2007.

• Our current and deferred derivative assets have decreased $41.2 million and we have recorded current and non-current derivative liabilities of $3.8 million and $2.7 million, respectively. These fluctuations reflect the relatively less favorable pricing of our financial derivatives as compared to the forward pricing of natural gas, crude oil and NGLs at September 30, 2007 as market prices have generally trended upward. Additionally, our current deferred tax liability decreased $15.1 million as a result of the lower estimated fair value of our natural gas, crude oil and NGL financial derivatives.

• Minority interest in our Texas gas processing and gathering subsidiaries increased $21.4 million as a result of the initial public offering of KGS limited partnership units to the public. The KGS IPO resulted in a gain of $81.6 million that will be deferred until the subordination period covering a portion of our continued interests is terminated. We also received $112.1 million in cash as a result of the KGS IPO.

• Accumulated other comprehensive income decreased $5.0 million as a result of the decrease in the estimated fair value of our financial derivatives, net of income taxes. Partially offsetting that decrease was a $28.7 million increase in our currency translation adjustment that resulted from the strengthening of the Canadian dollar in relation to the U.S. dollar compared with the first nine months of 2007.

Recently Issued Accounting Standards

• Pronouncements Implemented

     In June 2006, the Financial Accounting Standards Board (“FASB”) issued Interpretation No. 48 (“FIN 48”),Accounting for Uncertainty in Income Taxes — An Interpretation of FASB Statement No. 109. FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 109,Accounting for Income Taxes.This Interpretation prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. This Interpretation also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. In connection with our adoption of FIN 48, as of January 1, 2007, we recorded an adjustment to retained earnings of approximately $0.3 million for unrecognized tax benefits, all of which would affect our effective tax rate if recognized. This reduction in retained earnings was offset against our net operating loss carryforwards in the deferred federal income tax liability account. As of January 1, 2007, our unrecognized tax benefits totaled $1.4 million. Our unrecognized tax benefits at September 30, 2007 were $0.3 million.

34

• Pronouncements Not Yet 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 will change current practice. We will adopt SFAS No. 157 on January 1, 2008, but do not expect adoption of SFAS No. 157 to have a material impact on our financial position, results of operations or cash flows.

     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 that have been offset in accordance with that paragraph. We will adopt FSP No. 39-1 on January 1, 2008 employing retrospective representation for all periods, but do not expect adoption to have a material impact on our financial position, results of operations or cash flows.

     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. It provides entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. SFAS No. 159 is effective for the Company beginning after January 1, 2008. We are still evaluating the impact of SFAS No. 159 on our consolidated financial condition and results of operations.

35

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 and crude oil commodity prices. We have mitigated the risk of adverse price movements through the use of swaps and collars; however, we have also limited future gains from favorable movements.

Commodity Price Risk

     We enter into financial contracts to hedge our exposure to commodity price risk associated with anticipated future natural gas production. These contracts have included no-cost collars and fixed price swaps. During the first nine months of 2007, we sold approximately 30 MMcfd of natural gas for a floor price of $2.49 per Mcf under a long-term contract that extends through March 2009. Approximately 3 MMcfd of the natural gas sold under this contract during the first nine months of 2007 were third-party volumes controlled by us.

     We also sold approximately 10.0 MMcfd for a floor price of $2.47 per Mcf under a long-term contract that extended through March 2009. On May 15, 2007, a ruling by the 236^th Judicial District Court of Texas rescinded the contract and rendered it void from that date and we began selling the 10.0 MMcfd at market prices on May 22, 2007. Through that date, approximately 0.9 MMcfd of the natural gas sold under the contract were third-party volumes controlled by us.

     As of September 30, 2007, natural gas price collars have been put in place to hedge approximately 123 MMcfd of our anticipated natural gas production for the fourth quarter of 2007. We have also hedged 1,000 Bbld of anticipated crude oil and condensate and 3,000 Bbld of NGL production with crude oil price collars and NGL fixed price swaps, respectively for the fourth quarter of 2007. Price collars and swaps have also been put in place to hedge approximately 65 MMcfd and 40 MMcfd, respectively, of our anticipated 2008 natural gas production. Anticipated 2008 crude oil and condensate production of approximately 1,000 Bbld has also been hedged with crude oil price collars while 3,000 Bbld of anticipated 2008 NGL production has been hedged with fixed price swaps. Anticipated first quarter 2009 natural gas production of approximately 90 MMcfd has been hedged with natural gas price collars. Approximately 50 MMcfd of anticipated 2009 natural gas production has been hedged with natural gas price collars for each of the three remaining quarters of 2009.

36

     The following table summarizes our open financial derivative positions as of September 30, 2007 related to our natural gas and crude oil production.

		Remaining		Price Per
Product	Type	Contract Period	Volume	Mcf or Bbl	Fair Value
					(in thousands)
Gas	Collar	Oct 2007	10,000 Mcfd	$7.50-11.50	$	334
Gas	Collar	Oct 2007	10,000 Mcfd	7.50-11.75		334
Gas	Collar	Oct 2007	5,000 Mcfd	7.50-11.78		166
Gas	Collar	Oct 2007	5,000 Mcfd	7.50-11.80		167
Gas	Collar	Oct 2007-Dec 2007	20,000 Mcfd	7.00- 9.15		684
Gas	Collar	Oct 2007-Dec 2007	10,000 Mcfd	8.00-11.20		1,088
Gas	Collar	Oct 2007-Dec 2007	10,000 Mcfd	9.00-12.10		1,912
Gas	Collar	Oct 2007-Dec 2007	20,000 Mcfd	9.00-12.10		3,824
Gas	Collar	Oct 2007-Mar 2008	15,000 Mcfd	7.50- 8.70		822
Gas	Collar	Oct 2007-Mar 2008	5,000 Mcfd	7.50- 8.90		314
Gas	Collar	Oct 2007-Mar 2008	10,000 Mcfd	9.00-12.00		3,099
Gas	Collar	Oct 2007-Mar 2008	10,000 Mcfd	9.00-12.05		3,138
Gas	Collar	Nov 2007-Mar 2008	10,000 Mcfd	8.00-15.00		1,305
Gas	Collar	Nov 2007-Mar 2008	10,000 Mcfd	8.00-15.65		1,315
Gas	Collar	Jan 2008-Dec 2008	20,000 Mcfd	7.00- 9.15		939
Gas	Collar	Apr 2008-Mar 2009	20,000 Mcfd	7.50- 9.35		165
Gas	Collar	Apr 2008-Mar 2009	20,000 Mcfd	8.00-10.20		3,288
Gas	Collar	Jan 2009-Dec 2009	20,000 Mcfd	7.50- 9.34		(529	)
Oil	Collar	Oct 2007-Dec 2007	500 Bbld	70.00-91.10		6
Oil	Collar	Oct 2007-Dec 2007	500 Bbld	60.00-72.80		(471	)
Oil	Collar	Jan 2008-Dec 2008	500 Bbld	65.00-73.90		(912	)
Oil	Collar	Jan 2008-Dec 2008	500 Bbld	65.00-77.45		(550	)
Gas	Swap	Jan 2008-Dec 2008	25,000 Mcfd	$8.13		1,608
Gas	Swap	Jan 2008-Dec 2008	7,500 Mcfd	8.13		470
Gas	Swap	Jan 2008-Dec 2008	5,000 Mcfd	8.14		330
Gas	Swap	Jan 2008-Dec 2008	2,500 Mcfd	8.15		174
NGL	Swap	Oct 2007-Dec 2007	1,000 Bbld	40.32		(1,030	)
NGL	Swap	Oct 2007-Dec 2007	2,000 Bbld	42.46		(1,185	)
NGL	Swap	Jan 2008-Dec 2008	1,000 Bbld	39.58		(1,209	)
Gas	Basis Swap	Oct 2007-Dec 2007	25,000 Mcfd			197
Gas	Basis Swap	Oct 2007-Dec 2007	20,000 Mcfd			62
Gas	Basis Swap	Jan 2008-Dec 2008	10,000 Mcfd			114
Gas	Basis Swap	Jan 2008-Dec 2008	10,000 Mcfd			114
				Total	$	20,083

     Utilization of our hedging program may result in natural gas and crude oil realized prices varying from market prices that we receive from the sale of natural gas and crude oil. Our revenue from natural gas and crude oil production was $42.1 million and $6.4 million higher as a result of our hedging programs for the first nine months of 2007 and 2006, respectively. Other revenue was $3.0 million higher and $0.1 million lower as a result of hedging activities for the nine-month periods ending September 30, 2007 and 2006, respectively.

     We have a supply contract expiring in March 2009 to deliver 25,000 Mcfd of natural gas at a floor price of $2.49 per mcf to a customer in Michigan. This contract has been exempt from the mark-to-market provisions for such contracts pursuant to the “normal sales” exclusion of SFAS No. 133. Although we had previously delivered production from our Northeast Operations in fulfillment of the contract, we will continue to deliver natural gas from other producing areas. Accordingly, we continue to apply the “normal sales” exemption for the supply contract. Had we terminated the contract, we believe that the cost of termination would have been approximately $70 million at September 30, 2007.

37

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 the end of the third quarter of 2007, 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, 2007 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

38

PART II – OTHER INFORMATION

ITEM 1. Legal Proceedings

     As previously reported in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2006, on October 13, 2006, we filed suit in the 342nd Judicial District Court in Tarrant County, Texas against Eagle Drilling, LLC and Eagle Domestic Drilling Operations, LLC (together “Eagle”) regarding three contracts for drilling rigs in which we allege that the first rig furnished by Eagle exhibited operating deficiencies and safety defects and that the other rigs failed to conform to specifications set forth in the drilling contracts. Subsequently, on January 19, 2007, Eagle Domestic Drilling Operations, LLC and its parent, Blast Energy Services, Inc. filed for Chapter 11 bankruptcy in the United States Bankruptcy Court for the Southern District of Texas, Houston Division. Our suit against Eagle in Tarrant County was ultimately transferred to the Bankruptcy Court in Houston and has been consolidated with the Eagle/Blast bankruptcy. On September 17, 2007, Eagle Drilling, LLC, and Rod and Richard Thornton, sued us and P. Jeffrey Cook, our Executive Vice President-Operations, in the District Court of Cleveland County, Oklahoma for alleged damages resulting from our decision to repudiate the rig contracts mentioned above. Based upon information currently available, we believe that the final resolution of this matter will not have a material effect on our financial condition, results of operations, or cash flows.

39

ITEM 1A. Risk Factors

     Other than as set forth below, there have been no material changes from the risk factors previously disclosed in our Annual Report onForm 10-K for the year ended December 31, 2006.

We depend on KGS to gather, process and transport most of our Barnett Shale gas production, and we own a significant equity interest in KGS.

     In connection with the KGS IPO, among other transactions, we transferred to KGS most of our pipeline gathering system located in the southern portion of the Fort Worth Basin (the “Cowtown Pipeline”) and our natural gas processing plant located in Hood County, Texas, (the “Cowtown Plant”), and we entered into a long-term agreement with KGS under which we are obligated to offer to KGS the right to provide gathering and processing services for much of our production in Hood, Somervell, Johnson, Tarrant, Hill, Parker, Bosque and Erath Counties in North Texas and charge specified fees. In addition, KGS has the option to purchase certain pipeline assets from us at historical cost within two years after those assets commence commercial service. KGS is obligated to purchase the Lake Arlington Dry System and the Hill County Dry System from us at fair market value within two years after those assets commence commercial service. Also, we have entered into a services and secondment agreement with KGS’ general partner, for an initial term of 10 years, pursuant to which certain of our employees are seconded to KGS’ general partner to provide operating, routine maintenance and other services with respect to the Cowtown Plant and the Cowtown Pipeline under the direction, supervision and control of KGS’ general partner, and KGS’ general partner will reimburse us for these services.

     As a result of the transactions and arrangements described above, we have diminished control over assets that are important to our business and operations, we are committed to transactions that will not necessarily be economically advantageous at the times at which they are ultimately consummated and increased demands have been placed on certain of our personnel who perform services for both us and KGS. If our use of assets transferred to KGS are interrupted due to factors beyond our control, the commitments that we have to KGS prove to be uneconomic and/or the effectiveness of our management personnel is decreased due to their responsibilities to KGS, we may experience an adverse effect to our business, results of operations and financial condition.

     Furthermore, through our ownership interest in KGS, we share in KGS’ results of operations and may be entitled to distributions from KGS. Accordingly, we are indirectly subject to the risks associated with KGS’ business and operations, including, but not limited to:

• changes in general economic conditions;

• fluctuations in natural gas prices;

• failure or delays in us and third parties achieving expected production from natural gas projects;

• competitive conditions in our industry;

• actions taken by third-party operators, processors and transporters;

• changes in the availability and cost of capital;

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

• construction costs or capital expenditures exceeding estimated budgeted costs or expenditures;

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

• the effects of future litigation; and

• other factors discussed in KGS’ Registration Statement on Form S-1 (No. 333-140599) and as are or may be detailed from time to time in KGS’ public announcements and other filings with the Securities and Exchange Commission.

40

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

Issuer Purchases of Equity Securities

     The following table summarizes the Company’s repurchases of its common stock during the quarter ended September 30, 2007.

					Total Number of		Maximum Number
					Shares Purchased		of Shares that May
					as Part of Publicly		Yet Be Purchased
	Total Number of		Average Price		Announced Plans		Under the Plans or
Period	Shares Purchased (1)		Paid per Share		or Programs (2)		Programs (2)
July 1 to July 31, 2007		15,407	$	45.70		—		—
August 1 to August 31, 2007		—		—		—		—
September 1 to September 30, 2007		—		—		—		—
Total		15,407	$	45.70		—		—

(1)	Represents shares of common stock surrendered by employees to satisfy the Company’s 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 2006 Equity Plan.
(2)	The Company does not currently have in place any publicly announced, specific plans or programs to purchase equity securities.

41

ITEM 6. Exhibits:

Exhibit No.	Description
10.1	Contribution Agreement, dated September 11, 2007, between Quicksilver Resources Inc. and BreitBurn Operating L.P. (filed as Exhibit 10.2 to the Company’s Form 8-K filed November 7, 2007 and included herein by reference.)
*15.1	Awareness Letter of Deloitte & Touche LLP.
*31.1	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*31.2	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*32.1	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

* Filed herewith

42

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 9, 2007

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

43

EXHIBIT INDEX

Exhibit No.	Description
10.1	Contribution Agreement, dated September 11, 2007, between Quicksilver Resources Inc. and BreitBurn Operating L.P. (filed as Exhibit 10.2 to the Company’s Form 8-K filed November 7, 2007 and included herein by reference.)
*15.1	Awareness Letter of Deloitte & Touche LLP.
*31.1	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*31.2	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*32.1	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

* Filed herewith

44