Quicksilver Resources (KWK) 10-Q 2006 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, 2006

or

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

For the transition period from _________ to _________

Commission file number: 001-14837

Quicksilver Resources Inc.

(Exact name of registrant as specified in its charter)

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

777 West Rosedale, Suite 300, Fort Worth, Texas	76104
(Address of principal executive offices)	(Zip Code)

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

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

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

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

Large accelerated filer  þ     Accelerated filer  o     Non-accelerated filer  o

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

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

	Outstanding as of October 31,
Title of Class	2006
Common Stock, $0.01 par value	77,537,805

QUICKSILVER RESOURCES INC.
INDEX TO FORM 10-Q
For the Period Ending September 30, 2006

	Page
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements (Unaudited)
Report of Independent Registered Public Accounting Firm		3
Condensed Consolidated Balance Sheets at September 30, 2006 and December 31, 2005		4
Condensed Consolidated Statements of Income and Comprehensive Income for the Three and Nine Months Ended September 30, 2006 and 2005		5
Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2006 and 2005		6
Notes to Condensed Consolidated Interim Financial Statements		7
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		19
Item 3. Quantitative and Qualitative Disclosures About Market Risk		31
Item 4. Controls and Procedures		34
PART II. OTHER INFORMATION
Item 1. Legal Proceedings		35
Item 6. Exhibits		35
Signatures		36
Third Supplemental Indenture
Awareness Letter
Certification Pursuant to Section 302
Certification Pursuant to Section 302
Certification Pursuant to Section 906

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, 2006, and the related condensed consolidated statements of income and comprehensive income (loss) for the three-month and nine-month periods ended September 30, 2006 and 2005, and of cash flows for the nine-month periods ended September 30, 2006 and 2005. 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, 2005, and the related consolidated statements of income and comprehensive income (loss), stockholders’ equity and cash flows for the year then ended (not presented herein); and in our report dated March 1, 2006, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2005, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

As discussed in Note 2 to the condensed consolidated financial statements, effective January 1, 2006, the Company adopted Statement of Financial Accounting Standards No. 123 (Revised 2004),Share-Based Payment.

/s/ DELOITTE & TOUCHE LLP

Fort Worth, Texas
November 6, 2006

3

QUICKSILVER RESOURCES INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

In thousands, except for share data — Unaudited

	September 30,			December 31,
	2006			2005
ASSETS
Current assets
Cash and cash equivalents	$	3,363		$	14,318
Accounts receivable, net of allowance for doubtful accounts		68,373			76,121
Current derivative assets		49,472			603
Current deferred income taxes		—			14,614
Other current assets		20,861			7,928
Total current assets		142,069			113,584
Investments in and advances to equity affiliates		8,657			8,353
Property, plant and equipment – net (“full cost”)		1,500,705			1,112,002
Non-current derivative assets		12,894			—
Other assets		20,782			9,155
	$	1,685,107		$	1,243,094
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current portion of long-term debt	$	376		$	70,493
Accounts payable		78,661			48,409
Accrued liabilities		58,106			52,656
Derivative obligations		159			40,632
Current deferred income taxes		17,058			—
Total current liabilities		154,360			212,190
Long-term liabilities
Long-term debt		797,287			506,039
Non-current derivative obligations		—			4,631
Asset retirement obligations		21,811			20,891
Deferred income taxes		151,990			115,728
Minority interest		4,617			—
Total other-long term liabilities		975,705			647,289
Stockholders’ equity
Preferred stock, $0.01 par value, 10,000,000 shares authorized, 0 and 1 share issued and outstanding		—			—
Common stock, $0.01 par value, 200,000,000 and 100,000,000 shares authorized, respectively, and 80,113,675 and 78,650,110 shares issued, respectively		801			787
Paid in capital in excess of par value		235,084			211,843
Treasury stock of 2,579,441 and 2,571,069 shares, respectively		(10,833	)		(10,353	)
Accumulated other comprehensive income (loss)		62,266			(12,382	)
Retained earnings		267,724			193,720
Total stockholders’ equity		555,042			383,615
	$	1,685,107		$	1,243,094

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,
	2006			2005			2006			2005
Revenues
Oil, gas and related product sales	$	98,150		$	82,204		$	285,375		$	204,887
Other revenue		1,063			1,569			2,953			2,675
Total revenues		99,213			83,773			288,328			207,562
Expenses
Oil and gas production costs		24,602			19,396			70,232			53,342
Production and ad valorem taxes		4,502			3,876			10,661			9,866
Other operating costs		300			249			1,249			1,364
Depletion, depreciation and accretion		19,933			13,873			55,560			39,262
General and administrative		6,245			5,381			17,936			13,200
Total expenses		55,582			42,775			155,638			117,034
Income from equity affiliates		210			230			318			669
Operating income		43,841			41,228			133,008			91,197
Other income-net		(167	)		(253	)		(1,015	)		(457	)
Interest expense		11,040			5,589			30,808			15,022
Income from continuing operations before income taxes and minority interest		32,968			35,892			103,215			76,632
Income tax expense		10,046			11,199			29,139			24,000
Minority interest		61			—			72			—
Income from continuing operations		22,861			24,693			74,004			52,632
Gain from discontinued operations, net of income tax		—			62			—			62
Net income	$	22,861		$	24,755		$	74,004		$	52,694
Other comprehensive income, net of income taxes
Reclassification adjustments – hedge settlements		(3,409	)		4,379			(4,239	)		13,017
Unrealized gain (loss) on derivative instruments		33,717			(63,433	)		73,282			(69,363	)
Foreign currency translation adjustments		694			4,013			5,605			2,805
Comprehensive income (loss)	$	53,863		$	(30,286	)	$	148,652		$	(847	)
Basic net income per common share
Continuing operations	$	0.30		$	0.33		$	0.97		$	0.70
Discontinued operations		—			—			—			—
	$	0.30		$	0.33		$	0.97		$	0.70
Diluted net income per common share
Continuing operations	$	0.28		$	0.31		$	0.91		$	0.66
Discontinued operations		—			—			—			—
	$	0.28		$	0.31		$	0.91		$	0.66
Weighted average common shares outstanding
Basic		77,007			75,781			76,593			75,674
Diluted		83,306			82,668			83,056			82,403

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,
	2006			2005
Operating activities:
Net income	$	74,004		$	52,694
Charges and credits to net income not affecting cash Depletion, depreciation and accretion		55,560			39,262
Deferred income taxes		29,095			23,620
Non-cash compensation		4,775			932
Amortization of deferred loan costs		1,615			1,061
Income from equity affiliates		(318	)		(669	)
Minority interest		72			—
Non-cash gain from hedging activities		(114	)		(305	)
Other non-cash items		232			71
Changes in assets and liabilities
Accounts receivable		7,748			(32,834	)
Current and other assets		(17,921	)		(2,498	)
Accounts payable		14,844			6,084
Accrued and other liabilities		18,114			(1,528	)
Net cash provided by operating activities		187,706			85,890
Investing activities:
Purchases of property, plant and equipment		(429,485	)		(226,376	)
Return of investment in equity affiliates		558			512
Proceeds from sales of properties		5,670			9,301
Net cash used for investing activities		(423,257	)		(216,563	)
Financing activities:
Issuance of debt		483,148			143,094
Repayments of debt		(271,808	)		(245	)
Debt issuance costs		(9,213	)		(223	)
Proceeds from exercise of stock options		18,480			1,721
Minority interest contributions		4,506			—
Purchase of treasury stock		(480	)		—
Payment for fractional shares		—			(18	)
Net cash provided by financing activities		224,633			144,329
Effect of exchange rates on cash		(37	)		139
Net (decrease) increase in cash and cash equivalents		(10,955	)		13,795
Cash and cash equivalents at beginning of period		14,318			15,947
Cash and cash equivalents at end of period	$	3,363		$	29,742

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 Company 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, 2006 and its income, comprehensive income and cash flows for the three- and nine-month periods ended September 30, 2006 and 2005. 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, 2005.

     Certain share data presented as of dates prior to September 30, 2005 has been adjusted to reflect the effect of stock splits effected in the form of stock dividends that were paid in June 2004 and 2005.

Net Income per Common Share

     Basic net income or loss per common share is computed by dividing the net income or loss attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period. Diluted net income or loss 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 net income per common share calculations for the three- and nine-month periods ended September 30, 2006 and 2005. Outstanding options to purchase 2,401 shares were excluded from the diluted net income per share calculation for the periods ended September 30, 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,
		2006		2005		2006		2005
		(in thousands, expect per share amounts)
Income from continuing operations		$	22,861	$	24,693	$	74,004	$	52,632
Impact of assumed conversions — interest on 1.875% contingently convertible debentures, net of income taxes			475		475		1,425		1,425
Income from continuing operations available to stockholders assuming conversion of contingently convertible debentures		$	23,336	$	25,168	$	75,429	$	54,057
Weighted average common shares-basic			77,007		75,781		76,593		75,674
Effect of dilutive securities:
Employee stock options			901		1,829		1,178		1,718
Employee stock awards			490		150		377		103
Contingently convertible debentures			4,908		4,908		4,908		4,908
	��
Weighted average common shares-diluted			83,306		82,668		83,056		82,403
Basic net income per common share		$	0.30	$	0.33	$	0.97	$	0.70
Diluted net income per common share		$	0.28	$	0.31	$	0.91	$	0.66

7

Recently Issued Accounting Standards

     The Financial Accounting Standards Board (“FASB”) issued FASB Interpretation No. 48,Accounting for Uncertainty in Income Taxes, an interpretation of SFAS No. 109(“FIN 48”). FIN 48 is effective for fiscal years beginning after December 15, 2006. The Company is currently reviewing FIN 48 and evaluating its potential impact.

     SFAS No. 157,Fair Value Measurements(“SFAS 157”) was issued by the FASB in September 2006. SFAS 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles and expands disclosures related to the use of fair value measurements. The Statement applies under other accounting pronouncements that require or permit fair value measurement. SFAS 157 is effective for financials statements issued for fiscal years beginning after November 15, 2007. The Company is currently evaluating the timing of adoption and the impact that adoption might have on its financial position or results of operations.

     In September 2006, the Securities and Exchange Commission issued Staff Accounting Bulletin No. 108 (“SAB 108”). Due to diversity in practice among registrants, SAB 108 expresses the SEC staff’s views regarding the process by which misstatements in financial statements are evaluated to determine whether financial statement restatement is necessary. SAB 108 is effective for fiscal years ending after November 15, 2006. The SEC encouraged early application of SAB 108. The Company does not believe SAB 108 will have a material impact on its financial position or results from operations.

2. STOCK-BASED COMPENSATION

     In December 2004, the FASB issued SFAS No. 123 (revised 2004),Share-Based Payment(“SFAS 123(R)”).This statement requires the cost resulting from all share-based payment transactions be recognized in the financial statements at their fair value on the grant date. SFAS 123(R) was adopted by the Company on January 1, 2006. The Company previously accounted for stock awards under the recognition and measurement principles of APB No. 25,Accounting for Stock Issued to Employees, (“APB 25”) and related Interpretations. Pursuant to APB 25, stock-based employee compensation expense for restricted stock and stock unit grants was reflected in net income, but no compensation expense was recognized for options granted with an exercise price equal to the market value of the underlying common stock on the date of grant.

     The Company adopted SFAS 123(R) using the modified prospective application method described in the statement. Under the modified prospective application method, the Company applied the standard to new awards and to awards modified, repurchased, or cancelled after January 1, 2006. Additionally, compensation cost for the unvested portion of stock option awards outstanding as of January 1, 2006 has been recognized as compensation expense as the requisite service is rendered after January 1, 2006. The compensation cost for unvested stock option awards granted before adoption of SFAS 123(R) shall be attributed to periods beginning January 1, 2006 using the attribution method that was used under SFAS 123. At January 1, 2006, the Company had total compensation cost of $1.1 million related to unvested stock options with a weighted average remaining vesting period of 1.5 years. The Company recorded expense of $0.5 million for stock options in the first nine months of 2006. At September 30, 2006, the Company had $0.6 million of expense remaining in unrecognized compensation cost for the unvested portion of stock options awarded prior to 2006.

     At January 1, 2006, the Company had total compensation cost of $3.3 million related to unvested restricted stock and stock unit awards. Additionally, grants of restricted stock and stock units through September 30, 2006 had total compensation cost of $18.2 million at the time of grant. During the first nine months of 2006, the Company recognized $4.2 million of expense for vesting of restricted stock and stock units. Total unvested compensation cost was $17.0 million at September 30, 2006 with a weighted average remaining vesting period of 2.5 years.

     Prior to the adoption of SFAS 123(R), the Company presented any tax benefits of deductions resulting from the exercise of stock options within operating cash flows in the condensed consolidated statements of cash flow. SFAS 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 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 period ended September 30, 2006.

8

     The following table reflects pro forma net income and the associated earnings per share as if the Company had applied the fair value recognition provisions of SFAS No. 123,Accounting for Stock-based Compensation, to stock-based employee compensation.

	Three Months			Nine Months
	Ended			Ended
	September 30,			September 30,
	2005			2005
	(in thousands, except per share amounts)
Net income	$	24,755		$	52,694
Deduct: Total stock — based compensation expense determined under fair value based method for stock option awards, net of related tax effect		(1,709	)		(5,547	)
Pro forma net income		23,046			47,147
Impact of assumed conversions — interest on 1.875% contingently convertible debentures, net of income taxes		475			1,425
Pro forma net income assuming conversion of contingently convertible debentures	$	23,521		$	48,572
As reported
Basic net income per common share	$	0.33		$	0.70
Diluted net income per common share		0.31			0.66
Pro forma
Basic net income per common share	$	0.31		$	0.64
Diluted net income per common share		0.28			0.59

Employee Stock Plans

1999 and 2004 Plans

     On October 4, 1999, the Board of Directors adopted the Company’s 1999 Stock Option and Retention Stock Plan (the “1999 Plan”), which was approved at the annual stockholders’ meeting held in June 2000. Upon approval of the 1999 Plan, 3.9 million shares of common stock were reserved for issuance pursuant to grants of incentive stock options, non-qualified stock options, stock appreciation rights and retention stock awards. Pursuant to an amendment approved at the annual stockholders’ meeting held in May 2004, an additional 3.6 million shares were reserved for issuance pursuant to the 1999 Plan.

     In February 2004, the Board of Directors adopted the Company’s 2004 Non-Employee Director Equity Plan (the “2004 Plan”), which was approved at the annual stockholders’ meeting held in May 2004. Upon approval of the 2004 Plan, 750,000 shares of common stock were reserved for issuance pursuant to grants of non-qualified options and restricted stock awards to Quicksilver’s non-employee directors.

     Under terms of the 1999 Plan, retention stock awards and options were granted to officers, and employees at an exercise price that was not less than 100% of the fair market value on the date of grant. Under the terms of the 2004 Plan, options were granted to non-employee directors at an exercise price that is not less than 100% of the fair market value on the date of grant. The 1999 Plan and the 2004 Plan each provide that incentive stock options and non-qualified options granted under that plan may not be exercised more than ten years from date of grant.

2006 Equity Plan

     On March 17, 2006, the Board of Directors of the Company approved the Company’s 2006 Equity Plan, subject to stockholder approval, and recommended that the 2006 Equity Plan be submitted to the Company’s stockholders at the annual meeting of stockholders in 2006. On May 23, 2006, the Company’s stockholders approved the 2006 Equity Plan. Upon approval of the 2006 Equity Plan, 7.0 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, 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 ten years from the date of grant. Upon approval of the 2006 Equity Plan, the Company ceased to grant additional awards under the 1999 Plan and the 2004 Plan.

9

Stock Options

     On January 3, 2006, a non-employee director of the Company received options to purchase a total of 2,401 shares of stock at a strike price of $44.39. These options 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.

     The following table summarizes the Company’s stock option activity during the first nine months of 2006.

				Wtd Avg
				Exercise
	Shares			Price
Outstanding at beginning of year		2,840,695		$	17.13
Granted		2,401			44.39
Exercised		(1,036,735	)		17.83
Forfeited		(36,432	)		12.65
Outstanding at period end		1,769,929		$	16.84
Exercisable at September 30, 2006		1,324,099		$	18.29
Weighted average fair value of options granted				$	24.99

     The stock options vested and exercisable at September 30, 2006 had an aggregate intrinsic value of $18.0 million and a weighted average remaining term of 1.6 years.

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

Nine Months Ended September 30,
2006
Grant date	Jan 3, 2006
Risk-free interest rate		4.35	%
Expected life (in years)		10.0
Expected volatility		37.3	%
Dividend yield		—

     Cash received from the exercise of stock options totaled $18.5 million and $1.7 million for the first nine months of 2006 and 2005, respectively. The intrinsic value of the options exercised in the first nine-months of 2006 was $25.2 million.

Restricted Stock

     In January 2006, the Company awarded 254,685 shares of restricted stock and stock units at a weighted average market price of $43.77. Of the stock awarded, 90,000 shares were awarded to executive officers as a retention award that will vest in January 2009. The remaining restricted stock and stock unit awards will vest ratably over a three-year period. On January 3, 2006, each of the non-employee directors of the Company received a grant of 6,760 restricted shares at a market value of $44.39 per share. 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.

     In April 2006, the Company awarded 6,309 shares of restricted stock and stock units at a price of $37.95. An additional 197,258 shares of restricted stock and stock units were awarded in July 2006 at a market price of $32.87. Both awards will vest ratably over a three-year period.

     The following table summarizes the Company’s restricted stock and stock unit activity during the first nine months of 2006.

				Wtd Avg
				Grant Date
	Shares			Fair Value
Outstanding at beginning of year		133,858		$	33.73
Granted		465,012			39.07
Vested		(47,015	)		33.81
Forfeited		(37,882	)		36.67
Outstanding at period end		513,973		$	38.34

     The total fair value of shares vested during the nine months ended September 30, 2006 was $2.1 million.

10

3. PROPERTY

     The Company is required to perform the ceiling test each quarter because it uses the full cost method of accounting for oil and gas properties. Pursuant to SEC Regulation S-X Rule 4-10, the ceiling test is an impairment test performed on a country-by-country basis. The test determines a full cost limitation, or ceiling, on the book value of oil and gas properties, which is generally the after-tax value of the future net cash flows from proved natural gas and crude oil reserves, including the effect of cash flow hedges, discounted at ten percent per annum. Applying the test, the Company compares the full cost ceiling limitation to the net book value of the oil and gas properties reduced by the related net deferred income tax liability and asset retirement obligations. If the net book value reduced by the related net deferred income tax liability and asset retirement obligations exceeds the full cost ceiling limitation, an impairment or noncash write down is required.

     At September 30, 2006, the unamortized cost of the Company’s Canadian oil and gas properties exceeded the full cost ceiling limitation by approximately $56.6 million, net of income taxes. The full cost ceiling limitation included $28.4 million, net of income taxes, for hedge valuations. The natural gas price for September 30, 2006 referenced an AECO price of $3.63 per Mcf adjusted for appropriate price differentials. As permitted by full cost accounting rules, improvements in AECO spot natural gas prices subsequent to September 30, 2006 eliminated the necessity to record a write-down. Because of the volatility of oil and natural gas prices, no assurance can be given that the Company will not experience a write-down in future periods.

4. HEDGING

     The estimated fair values of all hedge derivatives and the associated fixed price firm sale commitments as of September 30, 2006 and December 31, 2005 are provided below. The carrying values of these financial instruments and firm commitments are equal to the estimated fair values for each period presented. The assets and liabilities recorded in the balance sheet are netted where derivatives with both gain and loss positions are held by a single third party.

	September 30,		December 31,
	2006		2005
	(in thousands)
Derivative assets:
Fixed price sale commitments	$	132	$	638
Floating price natural gas basis swaps		235		—
Crude oil financial collars		528
Natural gas financial collars		61,542		—
	$	62,437	$	638
Derivative liabilities:
Natural gas financial collars	$	—	$	44,480
Crude oil financial collars		71		320
Floating price natural gas financial swaps		159		463
Fixed price sale commitments		—		35
	$	230	$	45,298

     The fair values of all natural gas and crude oil financial instruments and, when appropriate, any associated firm sale commitments as of September 30, 2006 and December 31, 2005 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, 2006, deferred cash flow hedge gains of $49.2 million have been classified as current based on the maturity of the derivative instruments. The Company estimates $32.1 million of after-tax gains will be reclassified from other comprehensive income over the next twelve months.

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5. LONG-TERM DEBT

     Long-term debt consists of:

	September 30,			December 31,
	2006			2005
	(in thousands)
Senior secured credit facility	$	299,210		$	357,788
Senior subordinated notes		350,000			—
Contingently convertible debentures, net of unamortized discount		147,966			147,881
Second lien mortgage notes payable		—			70,000
Other loans		487			746
Deferred gain — fair value interest hedge		—			117
		797,663			576,532
Less current maturities		(376	)		(70,493	)
	$	797,287		$	506,039

     On March 16, 2006, the Company issued $350 million in principal amount of Senior Subordinated Notes due 2016 (“Senior Subordinated Notes”). The Senior Subordinated Notes are unsecured, senior subordinated obligations of the Company and bear interest at an annual rate of 7.125% payable semiannually on April 1 and October 1 of each year. 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 dividends, capital stock repurchases, investments, liens, distributions from restricted subsidiaries, affiliate transactions and mergers and consolidations. At September 30, 2006, the Company was in compliance with such covenants.

     In March 2006, the Company used $70 million of the proceeds from the issuance of the Senior Subordinated Notes to retire the second lien mortgage notes. As a result of the repayment, the Company recognized additional interest expense of $1.0 million consisting of a prepayment premium of $0.8 million and a charge of $0.3 million for associated unamortized deferred financing costs, partially offset by recognition of an associated deferred hedging gain of $0.1 million.

     The Company also used proceeds from the Senior Subordinated Notes to pay down $192.5 million of borrowings under the U.S. portion of its senior secured credit facility in March and April. As of September 30, 2006, the Company’s borrowing base under its senior secured credit facility was $600 million, of which approximately $300 million was available for borrowing. The loan agreements for the senior secured 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, amortization, non-cash income and expense and exploration costs) to interest ratio. The Company was in compliance with such covenants at September 30, 2006.

6. ASSET RETIREMENT OBLIGATIONS

     The Company records the fair value of the liability for asset retirement obligations in the period in which it is incurred. Upon initial recognition of the asset retirement liability, an asset retirement cost is capitalized by increasing the carrying amount of the long-lived asset by the same amount as the liability. In periods subsequent to initial measurement, the asset retirement cost is allocated to expense using a systematic method over the asset’s useful life. Changes in the liability for the asset retirement obligation are recognized for (a) the passage of time and (b) revisions to either the timing or the amount of the original estimate of undiscounted cash flows.

12

During the nine-month periods ended September 30, 2006 and 2005, accretion expense was recognized and included in depletion, depreciation and accretion expense reported in the condensed consolidated statement of income for the period. At September 30, 2006 and December 31, 2005, retirement obligations classified as current were $0.1 million. The following table provides a reconciliation of the changes in the estimated asset retirement obligation for the nine-month periods ended September 30, 2006 and 2005.

	Nine Months Ended
	September 30,
	2006			2005
	(in thousands)
Beginning asset retirement obligation	$	20,965		$	18,471
Additional liability incurred		2,068			1,066
Accretion expense		959			847
Change in estimates		29			—
Loss on settlement of liability		115			27
Sale of properties		(2,439	)		(41	)
Asset retirement costs incurred		(200	)		(89	)
Currency translation adjustment		387			162
Ending asset retirement obligation	$	21,884		$	20,443

7. INCOME TAXES

     In May 2006, the Texas business tax was amended by replacing the taxable capital and earned surplus components of the current franchise tax with a new “taxable margin” component. As the tax base for computing Texas margin tax is derived from an income-based measure, the Company has determined the margin tax is an income tax and, therefore, the provisions of SFAS No. 109,Accounting for Income Taxes(“SFAS 109”), regarding the recognition of deferred taxes apply to the new margin tax. In accordance with SFAS 109, the effect on deferred tax assets and liabilities of a change in tax law should be included in tax expense attributable to continuing operations in the period that includes the enactment date. Therefore, the Company has recalculated its deferred tax assets and liabilities for Texas based upon the new margin tax and recorded a deferred tax provision of $0.9 million and $0.7 million for the Texas margin tax in the second and third quarters of 2006, respectively.

     During the third quarter of 2006, the Company was notified that IRS audits of Terra Energy Ltd. (“Terra”), a wholly-owned subsidiary of Quicksilver, were closed for all years prior to its acquisition by the Company in 2000. As a result, the Company reversed a $0.9 million deferred tax liability for items associated with differences in book basis and tax basis for Terra prior to its acquisition.

     Tax rate reductions were enacted during the second quarter by the Canadian federal government as well as several provinces. As required by SFAS 109, the Company’s Canadian deferred income tax balances were revalued to reflect the changes in these tax rates. The Company recorded a $3.8 million income tax benefit in the second quarter of 2006 as a result of the Canadian rate reductions.

8. MINORITY INTEREST

     In April 2006, Quicksilver contributed its Cowtown gas processing facility to Cowtown Gas Processing Partners LP (“Processing Partners”) for a 95% interest in Processing Partners (1% interest as the general partner and 94% as a limited partner) through its wholly-owned subsidiary Cowtown Gas Processing LP. A minority owner initially contributed $1.4 million to Processing Partners for a 5% limited partnership interest in Processing Partners. Additionally, Quicksilver contributed its Cowtown pipeline assets to Cowtown Pipeline Partners LP (“Pipeline Partners”) for a 93% interest in Pipeline Partners (1% as the general partner and 92% as a limited partner) through its wholly-owned subsidiary Cowtown Pipeline LP. Two minority owners initially contributed a total of $3.1 million to Pipeline Partners for limited partnership interests totaling 7%. Processing Partners and Pipeline Partners have each entered into an agreement with Quicksilver for the Company to operate both partnerships. The Company receives $15,000 and $5,000 per month for management of Processing Partners and Pipeline Partners, respectively.

9. COMMITMENTS AND CONTINGENCIES

     In August 2001, a group of royalty owners, Athel E. Williams et al., brought suit against the Company and three of its subsidiaries in the Circuit Court of Otsego County, Michigan. The suit alleges that Terra Energy Ltd., one of Quicksilver’s subsidiaries, underpaid royalties or overriding royalties to the 13 named plaintiffs and to a class of plaintiffs who have yet to be determined. The pleadings of the plaintiffs seek damages in an unspecified amount and injunctive relief against future

13

underpayments. On January 21, 2005, the Circuit Court issued an order certifying certain claims to proceed on behalf of a class. On July 25, 2006, the Michigan Court of Appeals reversed the certification of all claims on appeal and remanded the case to the trial court for further proceedings. Based on information currently available to the Company, the Company’s management believes that the final resolution of this matter will not have a material effect on its financial position, results of operations, or cash flows.

     The Company has contracts for the use of drilling rigs in its drilling and exploration programs for periods ranging from one to three years at estimated day rates ranging from $18,500 to $22,000 per day. 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, 2006, commitments under these contracts were as follows:

(in thousands)
2006	$	9,771
2007		70,622
2008		45,456
2009		33,236
	$	159,085

     On October 13, 2006, the Company filed a suit in the District Court in Tarrant County, Texas against Eagle Drilling, LLC and Eagle Domestic Drilling Operations, LLC (“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. The Company seeks a declaratory judgment finding that (i) the drilling contracts are void, (ii) the Company is entitled to recover damages incurred due to Eagle’s failure to perform, and (iii) that Eagle is not entitled to early termination compensation provided for in the contracts. On October 23, 2006, Eagle Domestic Drilling Operations, LLC sued the Company in District Court of Cleveland County, Oklahoma for breach of contract as to each of the three drilling contracts alleging damages in the amount of $29 million plus punitive damages and interest. Based upon information currently available, management 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.

     The Company has entered into a firm transportation contract with one pipeline during the third quarter of 2006. Under the contract, we are obligated to transport minimum daily gas volumes, as calculated on a monthly basis, or pay for any deficiencies at a specified reservation fee rate. Our production committed to the pipeline is expected to meet, or exceed, the daily volumes provided in the contract. As of September 30, 2006, commitments under these contracts were as follows:

(in thousands)
2007	$	732
2008		4,392
2009		4,380
2010		4,380
Thereafter		26,304
	$	40,188

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

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,

14

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, 2006
					Non-					Quicksilver
	Quicksilver		Guarantor		Guarantor					Resources Inc.
	Resources Inc.		Subsidiaries		Subsidiaries		Eliminations			Consolidated
	(in thousands)
ASSETS
Current assets	$	147,396	$	243,217	$	58,917	$	(307,461	)	$	142,069
Investments in subsidiaries (equity method)		479,596		109,107		—		(580,046	)		8,657
Property and equipment, net		889,402		87,342		523,961		—			1,500,705
Other assets		30,224		—		3,452		—			33,676
Total assets	$	1,546,618	$	439,666	$	586,330	$	(887,507	)	$	1,685,107
LIABILITIES
Current liabilities	$	319,485	$	83,892	$	58,444	$	(307,461	)	$	154,360
Non-current liabilities		672,091		24,616		278,998		—			975,705
Stockholders’ equity		555,042		331,158		248,888		(580,046	)		555,042
Total liabilities and stockholders’ equity	$	1,546,618	$	439,666	$	586,330	$	(887,507	)	$	1,685,107

	December 31, 2005
					Non-					Quicksilver
	Quicksilver		Guarantor		Guarantor					Resources Inc.
	Resources Inc.		Subsidiaries		Subsidiaries		Eliminations			Consolidated
	(in thousands)
ASSETS
Current assets	$	101,587	$	201,458	$	62,105	$	(251,566	)	$	113,584
Investments in subsidiaries (equity method)		290,951		8,932		—		(291,530	)		8,353
Property and equipment, net		638,355		141,193		332,454		—			1,112,002
Other assets		8,000		—		1,155		—			9,155
Total assets	$	1,038,893	$	351,583	$	395,714	$	(543,096	)	$	1,243,094
LIABILITIES
Current liabilities	$	247,065	$	124,780	$	91,911	$	(251,566	)	$	212,190
Non-current liabilities		408,213		24,542		214,534		—			647,289
Stockholders’ equity		383,615		202,261		89,269		(291,530	)		383,615
Total liabilities and stockholders’ equity	$	1,038,893	$	351,583	$	395,714	$	(543,096	)	$	1,243,094

15

Condensed Consolidating Statement of Income

	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 in net earnings of subsidiaries		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 Three Months Ended September 30, 2005
					Non-					Quicksilver
	Quicksilver		Guarantor		Guarantor					Resources Inc.
	Resources Inc.		Subsidiaries		Subsidiaries		Eliminations			Consolidated
	(in thousands)
Revenues	$	47,945	$	12,616	$	24,072	$	(860	)	$	83,773
Operating expenses		29,041		5,563		9,031		(860	)		42,775
Income from equity affiliates		20		210		—		—			230
Income from operations		18,924		7,263		15,041		—			41,228
Equity in net earnings of subsidiaries		14,745		—		—		(14,745	)		—
Interest expense and other		3,502		4		1,830		—			5,336
Income tax provision		5,474		2,541		3,184		—			11,199
Income from continuing operations		24,693		4,718		10,027		(14,745	)		24,693
Gain from discontinued operations		62		—		—		—			62
Net income	$	24,755	$	4,718	$	10,027	$	(14,745	)	$	24,755

	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 in net earnings of subsidiaries		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

	For the Nine Months Ended September 30, 2005
						Non-					Quicksilver
	Quicksilver		Guarantor			Guarantor					Resources Inc.
	Resources Inc.		Subsidiaries			Subsidiaries		Eliminations			Consolidated
	(in thousands)
Revenues	$	112,727	$	32,926		$	64,041	$	(2,132	)	$	207,562
Operating expenses		80,649		13,638			24,879		(2,132	)		117,034
Income from equity affiliates		44		625			—		—			669
Income from operations		32,122		19,913			39,162		—			91,197
Equity in net earnings of subsidiaries		38,304		—			—		(38,304	)		—
Interest expense and other		9,891		(40	)		4,714		—			14,565
Income tax provision		7,903		6,984			9,113		—			24,000
Income from continuing operations		52,632		12,969			25,335		(38,304	)		52,632
Gain from discontinued operations		62		—			—		—			62
Net income	$	52,694	$	12,969		$	25,335	$	(38,304	)	$	52,694

16

Condensed Consolidating Statements of Cash Flows

	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 increase (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

	For the Nine Months Ended September 30, 2005
							Non-					Quicksilver
	Quicksilver			Guarantor			Guarantor					Resources Inc.
	Resources Inc.			Subsidiaries			Subsidiaries			Eliminations		Consolidated
	(in thousands)
Cash flow provided by operations	$	38,977		$	21,659		$	25,254		$	—	$	85,890
Cash flow used for investing activities		(113,693	)		(24,553	)		(78,317	)		—		(216,563	)
Cash flow provided by financing activities		95,235			—			49,094			—		144,329
Effect of exchange rates on cash		—			—			139			—		139
Net decrease in cash & equivalents		20,519			(2,894	)		(3,830	)		—		13,795
Cash & equivalents at beginning of period		10,428			1,080			4,439			—		15,947
Cash & equivalents at end of period	$	30,947		$	(1,814	)	$	609		$	—	$	29,742

11. SUPPLEMENTAL CASH FLOW INFORMATION

     Cash paid for interest and income taxes is as follows:

	Nine Months Ended
	September 30,
	2006		2005
	(in thousands)
Interest	$	16,874	$	12,162
Income taxes	$	3	$	875

     Other non-cash transactions are as follows:

	Nine Months Ended
	September 30,
	2006		2005
	(in thousands)
Noncash investing activities — changes in working capital associated with property and equipment	$	2,487	$	5,289

12. RELATED PARTY TRANSACTIONS

     As of September 30, 2006, 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 $1.0 million and $0.7 million for rent in the first nine months of 2006 and 2005, respectively, for rent on buildings owned by Pennsylvania Avenue LP (“PALP”), a Mercury affiliate. Rental rates were determined based on comparable rates charged by third parties. In February 2006, the Company entered into an amendment to its lease with PALP to increase the amount of office space covered thereby. In conjunction with this lease amendment, in February 2006, the Company also entered into a sublease with Mercury for a portion of the property that the Company leases from PALP. The rental rate under the sublease was determined using comparable rates charged by third parties. Payments received during 2006 from Mercury for sublease rentals, employee insurance coverage and administrative services have been $0.1 million. In August 2006, the Company agreed to purchase furniture from PALP for $75,000. The sales price was determined using comparable rates charged by third parties.

17

     During 2006, the Company paid Regal Aviation LLC, an unrelated airplane management company, $0.2 million 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.

13. GEOGRAPHIC INFORMATION

     The Company operates in two geographic segments, the United States and Canada. Both areas are engaged in the exploration and production segment of the oil and gas industry. The Company evaluates performance based on operating income and property and equipment costs incurred.

	United
	States		Canada		Corporate			Consolidated
			(in thousands)
For the Three Months Ended
September 30, 2006
Revenues	$	73,012	$	26,201	$	—		$	99,213
Depletion, depreciation and accretion		12,636		7,042		255			19,933
Operating income		38,079		12,262		(6,500	)		43,841
Property and equipment costs incurred		144,145		35,065		—			179,210
September 30, 2005
Revenues	$	59,658	$	24,115	$	—		$	83,773
Depletion, depreciation and accretion		8,944		4,772		157			13,873
Operating income		31,737		15,029		(5,538	)		41,228
Property and equipment costs incurred		66,164		30,910		461			97,535
For the Nine Months Ended
September 30, 2006
Revenues	$	203,618	$	84,710	$	—		$	288,328
Depletion, depreciation and accretion		34,261		20,725		574			55,560
Operating income		106,223		45,295		(18,510	)		133,008
Property and equipment costs incurred		344,632		86,133		1,207			431,972
September 30, 2005
Revenues	$	143,283	$	64,279	$	—		$	207,562
Depletion, depreciation and accretion		25,466		13,344		452			39,262
Operating income		65,444		39,317		(13,564	)		91,197
Property and equipment costs incurred		150,232		80,676		757			231,665
Fixed Assets — net
September 30, 2006	$	1,088,803	$	409,263	$	2,639		$	1,500,705
December 31, 2005	$	777,330	$	332,580	$	2,092		$	1,112,002

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

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 views, assumptions and expectations with respect to future events, outcomes, results or performance. Words such as “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 events, outcomes, results or performance 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 you should not consider the following list to be a complete statement of all potential risks and uncertainties. Factors that could cause actual events, outcomes, results or performance to differ materially from the results contemplated by such forward-looking statements, or which could otherwise materially affect our financial condition, results of operations or cash flows, 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 oil field 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, 2005.

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

19

RESULTS OF OPERATIONS

Summary Financial Data
Three Months Ended September 30, 2006 Compared with the Three Months Ended September 30, 2005

	Three Months Ended
	September 30,
	2006		2005
	(in thousands)
Total operating revenues	$	99,213	$	83,773
Total operating expenses		55,582		42,775
Operating income		43,841		41,228
Income from continuing operations		22,861		24,693
Net income		22,861		24,755

     We recorded net income of $22.9 million ($0.28 per diluted share) for the three months ended September 30, 2006, compared to net income of $24.8 million ($0.31 per diluted share) for the third quarter of 2005.

Operating Revenues

     Revenues for the third quarter of 2006 were $99.2 million; a $15.4 million increase from the $83.8 million reported for the three months ended September 30, 2005. Production revenue increased $15.9 million as a result of a 24% increase in sales volumes partially offset by a 4% decrease in realized sales prices.

Gas, Oil and Related Product Sales

     Sales volumes, revenues and average realized sales prices for the three months ended September 30, 2006 and 2005 are as follows:

	Three Months Ended
	September 30,
	2006		2005
Natural gas, oil and NGL sales (in thousands)
United States	$	71,955	$	58,101
Canada		26,195		24,103
Total	$	98,150	$	82,204
Product sale revenues (in thousands)
Natural gas sales	$	78,994	$	71,974
Oil and condensate sales		9,551		7,943
NGL sales		9,605		2,287
Total	$	98,150	$	82,204
Average daily sales volume
Natural gas — Mcfd
United States		100,783		87,114
Canada		49,156		40,732
Total		149,939		127,846
Oil and condensate — Bbld
United States		1,603		1,507
Canada		—		—
Total		1,603		1,507
NGL — Bbld
United States		2,483		684
Canada		8		7
Total		2,491		691

20

	Three Months Ended
	September 30,
	2006		2005
Total sales — Mcfed
United States		125,298		100,255
Canada		49,208		40,778
Total		174,506		141,033
Unit prices — including impact of hedges
Natural gas — per Mcf
United States	$	5.70	$	5.98
Canada		5.78		6.42
Consolidated		5.73		6.12
Oil and condensate — per Bbl
United States	$	64.74	$	57.31
Canada		—		—
Consolidated		64.74		57.31
NGL — per Bbl
United States	$	41.80	$	35.75
Canada		78.66		55.44
Consolidated		41.91		35.96

     Natural gas sales of $79.0 million for the third quarter of 2006 were 10% higher than the $72.0 million of natural gas sales for the third quarter of 2005. Natural gas revenue increased $11.6 million because of a 17% increase in sales volumes for the third quarter of 2006 as compared to the third quarter of 2005. Production from our coal bed methane (“CBM”) projects in Canada increased for the third quarter of 2006 by approximately 1.0 Bcf as compared to the third quarter of 2005 as a result of new wells placed into production subsequent to the third quarter of 2005. Natural production declines partially offset the Canadian production increases. New productive wells in the Fort Worth Basin, placed into production subsequent to the third quarter of 2005, increased sales volumes by approximately 2.7 Bcf for the third quarter of 2006 compared to the third quarter of 2005. Additionally, new productive Michigan wells placed into production subsequent to the third quarter of 2005 added an additional 0.2 Bcf of production in the third quarter of 2006. U.S. production increases were partially offset by natural production declines. Partially offsetting increased volumes was a $0.39 per Mcf decrease in average realized sales prices that decreased natural gas revenue $4.6 million.

     Oil and condensate sales were $9.6 million for the three months ended September 30, 2006 compared to $7.9 million for the third quarter of 2005. The average realized oil and condensate sales price for the third quarter of 2006 was $64.74 per Bbl compared to $57.31 per Bbl for the third quarter of 2005. Higher realized sales prices increased revenue by $1.0 million for the third quarter of 2006 compared to the prior year quarter. New productive wells in the Fort Worth Basin added 20 MBbl of oil and condensate in the third quarter of 2006 compared to the third quarter of 2005, which were partially offset by natural production declines in other producing areas. The net increase in oil production improved revenue by an additional $0.6 million compared to the prior year quarter.

     Our third quarter 2006 NGL sales increased $7.3 million to $9.6 million when compared to the third quarter of 2005. NGL production increased for the third quarter of 2006 by approximately 166 MBbl compared to the third quarter of 2005. Third quarter 2006 NGL production in the Fort Worth Basin increased approximately 191 MBbl as a result of new productive wells and the processing of gas in our facilities in the Fort Worth Basin. The Fort Worth Basin increase was partially offset by natural production declines elsewhere in the U.S.

21

Operating Expenses

     Third quarter 2006 operating expenses were $55.6 million; an increase of $12.8 million over the $42.8 million of operating expenses incurred in the third quarter of 2005.

Oil and Gas Operations Expense

	Three Months Ended
	September 30,
	2006		2005
	(in thousands, except per
	unit amounts)
Oil and gas operations expense
United States	$	18,036	$	15,559
Canada		6,566		3,837
Total	$	24,602	$	19,396
Oil and gas operations expense — per Mcfe
United States	$	1.56	$	1.69
Canada		1.45		1.02
Consolidated		1.53		1.50

     Oil and gas operations expense was $24.6 million for the third quarter of 2006. The $5.2 million increase over the prior year quarter included increases of $2.7 million and $2.5 million for Canadian and U.S. production costs, respectively.

     Canadian operating costs were $6.6 million for the third quarter of 2006. Compared to the third quarter of 2005, Canadian operating expenses increased approximately $2.7 million for the 2006 third quarter and included nearly $0.3 million of additional expense due to changes in currency exchange rates. Canadian production overhead increased $1.6 million for the third quarter of 2006 as compared to the 2005 quarter. Compensation expense increased approximately $1.8 million, including $0.5 million of expense in the 2006 quarter for non-compete payments made to senior management no longer employed by us and $0.3 million for vesting of restricted stock unit awards granted earlier in 2006. The remaining $1.0 million increase in compensation expense for the third quarter of 2006 as compared to the 2005 period, was primarily the result of 17 additional employees working during the third quarter of 2006. In addition, lease and gas facility operating expenses increased $0.6 million and $0.4 million, respectively for the third quarter of 2006 compared to the prior year quarter. Additional gas facility operating expense for the third quarter of 2006 was primarily the result of operating our gas facilities constructed in the past year.

     Oil and gas operations expense for the U.S. was $18.0 million for the third quarter of 2006. Third quarter 2006 U.S. operations expense increased $2.5 million from expense of $15.6 million for the third quarter of 2005. The growth of our operations in the Fort Worth Basin increased operating expense approximately $3.4 million for the third quarter 2006 compared to the 2005 quarter. The addition of 35 employees in Texas since the end of the 2005 third quarter contributed $1.5 million of the increase in production overhead expense for the third quarter of 2006 compared to the prior year quarter. The $1.5 million increase in production overhead expense consisted of $1.2 million for compensation expense and $0.3 million in higher field office expenses. Texas lease operating expenses for the third quarter of 2006 increased $1.2 million as compared to the 2005 quarter primarily because of the increasing rate of new wells placed into production. Operation of our pipeline and gas processing facilities increased expense $1.1 million for the third quarter of 2006 and was partially offset by a $0.9 million decrease in third-party processing fees compared to the third quarter of 2005. The remaining increase of $0.5 million was attributable to higher costs in several expense categories. Partially offsetting the increase was a $1.4 million decrease in Michigan operating expense for the 2006 third quarter when compared to the third quarter of 2005. Approximately $0.3 million of the decrease was the result of lower environmental monitoring and remediation costs associated with Michigan gathering lines and facilities and a further $0.7 million decrease in expense was associated with a reduction in Michigan compressor overhaul activities. The remaining $0.4 million decrease in Michigan operating expense for the third quarter of 2006 as compared to the prior year quarter was attributable to lower costs in several expense categories.

Production and Ad Valorem Taxes

     Production and ad valorem tax expense for the third quarter of 2006 was $4.5 million compared to $3.9 million for the third quarter of 2005. Ad valorem taxes increased $0.4 million primarily as the result of additional assets constructed and acquired in conjunction with our drilling program in the Fort Worth Basin. The $0.2 million increase in production taxes was the result of higher sales volumes in the 2006 quarter partially offset by a reduction in average sale prices from the 2005 quarter.

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Depletion, Depreciation and Accretion

	Three Months Ended
	September 30,
	2006		2005
	(in thousands, except per
	unit amounts)
Depletion	$	16,340	$	11,374
Depreciation of other fixed assets		3,283		2,205
Accretion		310		294
Total depletion, depreciation and accretion	$	19,933	$	13,873
Average depletion cost per Mcfe	$	1.02	$	0.88

     Depletion for the third quarter of 2006 was $16.3 million and $4.9 million higher than depletion for the third quarter of 2005. Higher depletion was resulted from a 16% increase in the depletion rate and a 24% increase in sales volumes. Our depletion rate increased as compared to the third quarter of 2005 as a result of our significant actual and estimated future capital expenditures and proved reserves added for our Canadian CBM and Forth Worth Basin properties. The $1.1 million increase in depreciation for the third quarter of 2006 was primarily associated with new gas processing facilities in Canada and gas processing and transportation assets located in the Fort Worth Basin.

General and Administrative Expense

     General and administrative expense for the three months ended September 30, 2006 was $6.2 million compared to $5.4 million for the quarter ended September 30, 2005. The most significant increase in general and administrative expense for the third quarter of 2006 was a $1.2 million increase in employee compensation and benefits, including approximately $1.1 million of expense for vesting of restricted stock and stock option awards. The increase in stock compensation expense was the result of the restricted stock awards granted in 2006. Legal expenses decreased for the third quarter of 2006 as compared to the 2005 quarter by approximately $0.3 million to partially offset the increase in compensation and benefits expense.

Interest Expense

     Interest expense for the third quarter of 2006 was $11.0 million, net of capitalized interest of $0.5 million, which was an increase of $5.5 million compared to the third quarter of 2005. Interest expense for the third quarter of 2006 increased $3.9 million as a result of the approximate $250 million increase in debt outstanding for the end of third quarter of 2006 as compared to the 2005 quarter-end. In March 2006, the Company issued $350 million in principal amount of our senior subordinated notes. A portion of the proceeds from the issuance were used to pay down debt previously outstanding. Higher interest rates, including Canadian prime interest rates paid on the Canadian portion of our senior credit facility, during the third quarter of 2006 contributed $1.6 million to increased interest expense.

Income Tax Expense

     Our provision for income taxes for the third quarter of 2006 decreased $1.2 million from the prior year period to $10.0 million. Our U.S. federal income tax provision of $7.4 million was established using the statutory U.S. federal rate of 35%. Although there was a decrease in U.S. operating income for the third quarter of 2006 of approximately $1.8 million and a deferred federal income tax liability of $0.9 million was reversed as a result of the completion of IRS audits of a wholly-owned subsidiary for years prior to its acquisition by us, the U.S. total income tax provision increased approximately $0.1 million because we recorded an additional deferred state income tax provision of $0.7 million as a result of the newly enacted Texas Margin Tax. The Canadian deferred federal tax provision for the third quarter of 2006 decreased approximately $1.2 million compared to the prior year period which was the result of a reduction in Canadian operating income and a decrease in the combined federal and provincial tax rate to 29% that occurred as a result of legislation enacted in the second quarter of 2006.

23

Summary Financial Data
Nine Months Ended September 30, 2006 Compared with the Nine Months Ended September 30, 2005

	Nine Months Ended
	September 30,
	2006		2005
	(in thousands)
Total operating revenues	$	288,328	$	207,562
Total operating expenses		155,638		117,034
Operating income		133,008		91,197
Income from continuing operations		74,004		52,632
Net income		74,004		52,694

     We recorded net income of $74.0 million ($0.91 per diluted share) for the nine months ended September 30, 2006, compared to net income of $52.7 million ($0.66 per diluted share) for the first nine months of 2005.

Operating Revenues

     Revenues for the first nine months of 2006 were $288.3 million; an $80.8 million increase from the $207.6 million reported for the nine months ended September 30, 2005. Production revenue increased $80.5 million as a result of a 19% increase in sales volumes and a 17% increase in realized sales prices when the 2006 nine-month period is compared to the 2005 period.

Gas, Oil and Related Product Sales

     Sales volumes, revenues and average realized sales prices for the nine months ended September 30, 2006 and 2005 are as follows:

	Nine Months Ended
	September 30,
	2006		2005
Natural gas, oil and NGL sales (in thousands)
United States	$	201,248	$	141,036
Canada		84,127		63,851
Total	$	285,375	$	204,887
Product sale revenues (in thousands)
Natural gas sales	$	238,651	$	179,755
Oil and condensate sales		27,477		20,284
NGL sales		19,247		4,848
Total	$	285,375	$	204,887
Average daily sales volume
Natural gas — Mcfd
United States		95,501		86,229
Canada		48,930		39,366
Total		144,431		125,595
Oil and condensate — Bbld
United States		1,627		1,501
Canada		1		—
Total		1,628		1,501
NGL — Bbld
United States		1,684		509
Canada		14		7
Total		1,698		516
Total sales — Mcfed
United States		115,370		98,284
Canada		49,017		39,415
Total		164,387		137,699

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	Nine Months Ended
	September 30
	2006		2005
Unit prices — including impact of hedges
Natural gas — per Mcf
United States	$	5.94	$	4.93
Canada		6.28		5.93
Consolidated		6.05		5.24
Oil and condensate — per Bbl
United States	$	61.84	$	49.50
Canada		58.54		—
Consolidated		61.84		49.50
NGL — per Bbl
United States	$	41.41	$	34.27
Canada		53.71		44.36
Consolidated		41.51		34.41

     Natural gas sales of $238.7 million for the first nine months of 2006 were 33% higher than natural gas revenue of $179.8 million for the comparable 2005 period. A $0.81 per Mcf increase in average realized sales prices increased natural gas revenue $27.8 million for the 2006 nine-month period compared to the prior year period. Natural gas revenue also increased for the 2006 nine-month period by $31.1 million because of a 15% increase in sales volumes as compared to the first nine months of 2005. Production from our CBM projects in Canada increased for the nine-month 2006 period by approximately 3.9 Bcf from the 2005 period as a result of new wells placed into production. Natural production declines partially offset the Canadian production increases. New productive wells in the Fort Worth Basin in north Texas and Michigan increased sales volumes by approximately 5.7 Bcf and 0.6 Bcf, respectively, for the first nine months of 2006 compared to the prior year period. U.S. production increases were also partially offset by natural production declines.

     Oil and condensate sales were $27.5 million for the nine months ended September 30, 2006 compared to revenue of $20.3 million for the nine-month 2005 period. Higher realized sales prices increased revenue by $5.1 million for the 2006 nine-month period compared to the 2005 period. The average realized oil and condensate sales price for the 2006 nine-month period increased $12.34 per Bbl to $61.84 when compared to average realized prices for the first nine months of 2005. Higher production, primarily from new productive wells in the Fort Worth Basin, increased revenue for the nine-month 2006 period by $2.1 million when compared to the prior year period.

     Our sales of NGLs for the first nine months of 2006 increased $14.4 million to $19.2 million when compared to the nine-month 2005 period. NGL production in the 2006 nine-month period increased by approximately 323 MBbl compared to the first nine months of 2005. NGL production in the Fort Worth Basin for the 2006 period increased approximately 334 MBbl as a result of new productive wells and the processing of gas in our facilities in the Fort Worth Basin.

Operating Expenses

     Operating expenses for the first nine months of 2006 were $155.6 million; an increase of $38.6 million over the $117.0 million of operating expenses incurred in the 2005 nine-month period.

Oil and Gas Operations Expense

	Nine Months Ended
	September 30,
	2006		2005
	(in thousands, except per unit amounts)
Oil and gas operations expense
United States	$	52,664	$	42,540
Canada		17,568		10,802
Total	$	70,232	$	53,342
Oil and gas operations expense — per Mcfe
United States	$	1.67	$	1.59
Canada		1.31		1.00
Consolidated		1.56		1.42

25

     Oil and gas operations expense was $70.2 million for the first nine months of 2006. The $16.9 million increase over the prior year period included a Canadian production expense increase of $6.8 million and a $10.1 million increase in U.S. production expense.

     Canadian operating costs were $17.6 million for the 2006 nine-month period. The $6.8 million increase from the 2005 period was the result of a $4.4 million increase in production overhead and a $2.4 million increase in all other operating expenses inclusive of a $0.9 million increase that resulted from changes in U.S.-Canadian currency exchange rates. The increase in production overhead included an increase in compensation expense for the 2006 nine-month period of over $4.0 million, including $0.8 million for vesting of restricted stock unit and stock option awards and $0.5 million for recognition of expense for non-compete payments made to Canadian executives no longer employed by us. The $0.8 million increase in stock compensation expense was associated with the 2006 award of restricted stock units. The remaining $2.7 million increase in 2006 compensation expense compared to the prior year period is primarily the result of an increase of 18 employees working during the 2006 nine-month as compared to the prior year period. Increased office rent and support expenses further increased production overhead expense for the 2006 period by $0.4 million. The remaining $2.4 million increase in Canadian operating expenses for the 2006 period compared to the 2005 period was primarily associated with the operation of gas facilities constructed in 2005 that contributed approximately $1.4 million of the expense increase, net of a $0.4 million decrease in processing fees paid to third parties and an increase of over $0.6 million for well workover expenses.

     Oil and gas operations expense for U.S. operations during the nine-month 2006 period increased $10.1 million from the prior year period to $52.7 million. The growth of our operations in the Fort Worth Basin since September 30, 2005 was the primary factor that increased operating expense. The commencement of operations of our Texas gas facility, in April 2006 and additional pipeline for 2006 compared to 2005, added operating expense of approximately $3.4 million for the 2006 period net of the $1.0 million reduction in third-party processing fees paid in the 2005 period. A $3.0 million increase in Texas lease operating expense for the 2006 nine-month period compared to the 2005 period was primarily related to salt water disposal, equipment rentals and clean-up of a salt water spill that occurred during the second quarter of 2006. Overhead costs in Texas increased $3.6 million for the 2006 nine-month period compared to the prior year period and were also the result of increased operating activity for 2006. As of September 30, 2006, there were 35 additional Texas employees that resulted in a $2.7 million increase in compensation expense for the 2006 nine-month period compared to the prior year period. The additional employees and operating activity increased field office expense for the 2006 period $0.7 million as compared to the 2005 period. Expense for restricted stock and stock option awards to U.S. operations employees added approximately $0.5 million to the increase in U.S. operations expense for the 2006 period as a result of the 2006 grants of restricted stock.

Production and Ad Valorem Taxes

     Production and ad valorem tax expense for the first nine months of 2006 was $10.7 million compared to $9.9 million for the 2005 nine-month period. Ad valorem taxes for the 2006 period increased $1.1 million as compared to the nine-month period of 2005 as a result of additional assets constructed and wells added in conjunction with our drilling program in the Fort Worth Basin.

Depletion, Depreciation and Accretion

	Nine Months Ended
	September 30,
	2006		2005
	(in thousands, except per unit
	amounts)
Depletion	$	46,011	$	32,972
Depreciation of other fixed assets		8,590		5,443
Accretion		959		847
Total depletion, depreciation and accretion	$	55,560	$	39,262
Average depletion cost per Mcfe	$	1.03	$	0.88

     Depletion for the 2006 nine-month period was $46.0 million, a $13.0 million increase from the comparable 2005 period. The increase was the result of a 17% increase in the depletion rate and a 19% increase in sales volumes. Our depletion rate for 2006 increased over the 2005 period as a result of our significant actual and estimated future capital expenditures and proved reserves added for our Canadian CBM and Forth Worth Basin properties. The $3.1 million increase in depreciation for the 2006 nine-month period compared to the prior year period is associated with new gas processing facilities in Canada and gas processing and transportation assets located in the Fort Worth Basin.

General and Administrative Expense

     General and administrative expense for the nine months ended September 30, 2006 was $17.9 million compared to $13.1 million for the first nine months of 2005. The most significant increase in general and administrative expense for the 2006 nine-

26

month period compared to the prior year period was a $4.9 million increase in employee compensation and benefits, including approximately $2.6 million of expense for vesting of restricted stock and stock option awards. Restricted stock awards granted in 2006 and 27 additional employees working in the corporate office during the 2006 nine-month period were the primary factors increasing compensation expense. Office rent and insurance expense for the 2006 period increased approximately $0.3 million as a result of additional office space compared to the prior year period. Travel expenses for the 2006 nine-month period also increased approximately $0.3 million due, in part, to the additional employees. Partially offsetting these increases was a $0.7 million decrease in professional fees for legal, accounting and engineering services for the first nine months of 2006 as compared to the prior year period.

Interest Expense

     Interest expense for the first nine months of 2006 was $30.8 million, net of capitalized interest of $1.3 million, an increase of $15.8 million compared to the 2005 nine-month period. Interest expense for the first nine months of 2006 included a charge of $1.0 million as a result of the prepayment of $70.0 million in principal amount of our second lien mortgage notes payable with a portion of the proceeds from the issuance of $350 million in principal amount of our senior subordinated notes. The $1.0 million charge consisted of a prepayment premium of $0.8 million and the write-off of $0.3 million of remaining deferred financing costs, partially offset by recognition of the remainder of an associated deferred hedging gain of $0.1 million. Recurring interest expense increased $10.8 million as a result of higher debt levels throughout the 2006 period. Higher interest rates, including the Canadian prime rates paid on the Canadian debt outstanding under the senior credit facility, during the 2006 nine-month period contributed $4.0 million to increased interest expense.

Income Tax Expense

     Our provision for income taxes for the 2006 nine-month period increased $5.1 million from the prior year period as a result of higher pretax income for the 2006 nine-month period compared to the prior year period partially offset by reduction of Canadian deferred federal tax liabilities required upon tax rate reductions enacted in the second quarter of 2006. Our U.S. deferred federal income tax provision of $22.7 million was established using the statutory U.S. federal rate of 35%. The increase of $7.7 million in expense for the 2006 period was the result of higher U.S. operating income partially offset by a reversal of a deferred federal income tax liability of $0.9 million as a result of the completion of IRS audits of a wholly-owned subsidiary for years prior to its acquisition by us. We also recognized a deferred state income tax provision of $1.6 million as a result of the Texas Margin Tax that was enacted in May 2006. The Canadian deferred federal tax provision was approximately $4.8 million for the 2006 nine-month period and included a reduction of $3.8 million for the effect of federal and provincial tax rate reductions that were enacted in the second quarter of 2006.

LIQUIDITY, CAPITAL RESOURCES AND FINANCIAL POSITION

     Net cash from operations was $187.7 million for the nine months ended September 30, 2006, an increase of $101.8 million when compared to the same period in 2005. The increase was due in part to additional net income for the 2006 nine-month period as compared to the comparable 2005 period. Net income of $74.0 million was $21.3 million higher than net income for the first nine months of 2005 primarily as a result of a 19% increase in sales volumes and a 17% increase in realized sales prices. Non-cash expenses including depletion, depreciation and amortization, deferred taxes, stock-based compensation and deferred financing costs increased by $26.9 million and working capital changes were $53.6 million higher when comparing the 2006 nine-month period to the 2005 period.

     Our principal sources of cash are sales of natural gas, crude oil and NGLs. During the nine months ended September 30, 2006, sales under our long-term contracts with price floors averaging $2.48 per Mcf covered 21% of our natural gas production. Additionally, price collars covered approximately 51% of our production for the nine months ended September 30, 2006. At September 30, 2006, we have price collars hedging our natural gas, crude oil, condensate and NGL production of approximately 80.0 MMcfd and 2.0 MBbld, respectively, for the fourth quarter of 2006. The natural gas collars have weighted average price floors and ceilings of $7.65 per Mcf and $11.42 per Mcf, respectively, and the crude oil collars have price floors and ceilings of $50.00 per Bbld and $85.85 per Bbld, respectively. Through October 31, 2006, we have hedged approximately 108 MMcfd of our estimated 2007 natural gas sales using price collars. Approximately 40 MMcfd of our first quarter 2008 natural gas sales are also hedged with natural gas collars.

     During the first nine months of 2006, we paid $429.5 million for property and equipment, an increase of $203.1 million when compared to the nine-month 2005 period. Property and equipment costs incurred (payments for property and equipment plus noncash changes in working capital associated with property and equipment) for the 2006 period totaled $432.0 million, which consisted of $353.3 million expended for exploration and development activities, $62.5 million expended for construction of our gas processing facility in Hood County, Texas and lateral extensions of our north Texas pipeline and $8.6 million expended for Canadian gas processing facilities. Of the $276.4 million incurred for U.S. exploration and development, $251.9 million was spent in Texas, including $28.8 million for non-producing leasehold costs.

27

	Nine Months
	Ended
	September 30, 2006
	(in thousands)
Exploration and development
United States	$	276,384
Canada		76,956
Total exploration and development		353,340
Gas processing and transportation
United States		67,285
Canada		8,624
Total gas processing and transportation		75,909
Corporate and office		2,723
Total plant and equipment costs incurred	$	431,972

     Net cash provided by financing activities for the nine months ended September 30, 2006 was $224.6 million. On March 16, 2006, we issued $350 million in principal amount of Senior Subordinated Notes due in 2016. The Senior Subordinated Notes are unsecured, senior subordinated obligations and bear interest at an annual rate of 7.125% payable semiannually on April 1 and October 1 of each year. The terms and conditions of the Senior Subordinated Notes require us to comply with certain covenants, which primarily limit certain activities, including, among other things, levels of indebtedness, restricted payments, payments of dividends, capital stock repurchases, investments, liens, distributions from restricted subsidiaries, affiliate transactions, transfers or sales of assets and mergers and consolidations. At September 30, 2006, we were in compliance with such covenants.

     We used $70 million of the proceeds of the Senior Subordinated Notes to retire our second lien mortgage notes in March 2006. As a result of the repayment, we recognized additional interest expense of $1.0 million consisting of a prepayment premium of $0.8 million and a charge of $0.3 million for associated unamortized deferred financing costs, partially offset by recognition of an associated deferred hedging gain of $0.1 million. We also used approximately $192.5 million of the proceeds to repay the borrowings outstanding under the U.S. portion of our senior secured credit facility. For 2006, we have increased our borrowings under the U.S. and Canadian senior secured credit facilities approximately $133.1 million.

     As of September 30, 2006, our borrowing base under our senior secured credit facility was $600 million, of which approximately $300 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 all such covenants at September 30, 2006.

     As of September 30, 2006 and December 31, 2005, our total capitalization was as follows:

	September
	30,		December 31,
	2006		2005
	(in thousands)
Senior secured credit facility	$	299,210	$	357,788
Senior subordinated notes		350,000		—
Convertible subordinated debentures		147,966		147,881
Second lien mortgage notes payable		—		70,000
Other loans		487		746
Deferred gain — fair interest hedge		—		117
Total debt		797,663		576,532
Stockholders’ equity		555,042		383,615
	$	1,352,705	$	960,147

Financial Position

     The following impacted our balance sheet as of September 30, 2006, as compared to our balance sheet as of December 31, 2005:

• A $48.9 million and $12.9 million increase in our current and deferred derivative assets, respectively, reflecting the relative decrease in natural gas prices as compared to the price collars that hedge a portion of our future natural gas and crude oil production at September 30, 2006. The increase in our current derivative assets and

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	decrease in our current derivative liabilities resulted in a $14.6 million decrease in our current deferred tax asset and a $17.1 million increase in our current deferred tax liability at September 30, 2006.
•	A $388.7 million increase in our net property, plant and equipment assets includes approximately $432.0 million in capital costs incurred for development, exploitation and exploration of our oil and gas properties as well as additional pipeline and gas processing assets in Texas.
•	Our current portion of long-term debt decreased $70.0 million as a result of the retirement of our second lien mortgage notes which were repaid with a portion of the proceeds from the issuance of the senior subordinated notes in March 2006.
•	A $40.5 million and $4.6 million decrease in our current and deferred derivative obligations, respectively, reflecting the relative decrease in natural gas prices as compared to the price floors and caps of our natural gas and crude oil collars at September 30, 2006.
•	Our long-term debt increased $291.2 million primarily as a result of our capital expenditures of $429.5 million exceeding our operating cash flow by $241.8 million. During 2006, we issued our $350.0 million senior subordinated notes, and increased borrowings outstanding under the Canadian portion of our senior credit facility by $46.4 million. We experienced a $105.0 million net decrease in the U.S. portion of our senior credit facility. In the first four months of 2006 we repaid the $165.0 million of debt outstanding on the U.S. portion of our senior credit facility at December 31, 2005, as well as an additional $27.5 million repayment of 2006 borrowings, with a portion of the proceeds from the issuance of our senior subordinated notes. During the third quarter we borrowed $60.0 million under the U.S. portion of the senior debt facility.

Contractual Obligations and Commercial Commitments

     Information regarding our contractual obligations as of September 30, 2006 is set forth below. This information should be read in conjunction with the information provided in the contractual obligations and commercial commitments table included in our Annual Report on Form 10-K for the period ended December 31, 2005.

			Payments Due by Year
													After
	Total		2006		2007		2008		2009		2010		2010
							(in thousands)
Long-Term Debt	$	799,697	$	91	$	396	$	—	$	299,210	$	—	$	500,000
Scheduled Interest Obligations		269,780		13,876		27,751		27,751		27,751		27,751		144,900
Drilling Contracts		159,085		9,771		70,622		45,456		33,236		—		—
Transportation Contract		40,188		—		732		4,392		4,380		4,380		26,304
Asset Retirement Obligations		21,884		50		173		—		—		115		21,546
Purchase Obligations		15,142		9,219		5,923		—		—		—		—
Operating Leases		7,992		813		3,138		2,198		1,841		2		—
Total Obligations	$	1,313,768	$	33,820	$	108,735	$	79,797	$	366,418	$	32,248	$	692,750

• Long-Term Debt.Our outstanding long-term debt as of September 30, 2006, was $797.7 million, which includes $350 million in principal amount of Senior Subordinated Notes due in 2016. The Notes were issued in March 2006 and accrue interest at a rate of 7.125% per annum, which is paid semiannually. We used $70 million and $192 million of the proceeds from issuance of the Senior Subordinated Notes to retire our second lien mortgage notes and reduce borrowings outstanding under our credit facility, respectively. Based upon our borrowings outstanding and interest rates in affect at September 30, 2006, we estimate our annual interest payments to be $18.3 million based upon our debt outstanding and current interest rates. If the borrowing base under our secured senior credit facility were to be fully utilized at interest rates in effect at September 30, 2006, interest payments would increase by approximately $19.1 million annually.

• Scheduled Interest Obligations.As of September 30, 2006, we had annual scheduled interest payments in place of $24.9 million and $2.8 million on our $350 million Senior Subordinated Notes due April 1, 2016 and our $150 million contingently convertible debentures due November 1, 2024, respectively.

• Drilling Contracts.We lease drilling rigs from third parties for use in our development and exploration programs. Each of the contracts requires payment of the specified day rate for the entire lease term regardless of our utilization of the drilling rigs.

• Transportation Contract.We entered into a firm transportation contract with a pipeline during the third quarter of 2006. Under the contract, we are obligated to transport minimum daily gas volumes, as calculated on a monthly basis, or pay for any deficiencies at a specified reservation fee rate. Our production committed to the pipeline is expected to meet, or exceed, the daily volumes provided in the contract.

• Purchase Obligations.At September 30, 2006, we were contractually obligated to purchase goods and services in connection with construction of two gas processing plants in Texas. For the first gas processing plant, we have

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$1.6 million remaining in purchase obligations, including liabilities of $1.1 million recorded for goods received and services performed at September 30, 2006. Our total remaining purchase obligations for construction and completion of the second gas processing plant at September 30, 2006 were $13.5 million including liabilities of $8.1 million for goods received and services performed at September 30, 2006.

     Critical Accounting Policies

     We are required to perform the ceiling test each quarter because we use the full cost method of accounting for oil and gas properties. Pursuant to SEC Regulation S-X Rule 4-10, the ceiling test is an impairment test performed on a country-by-country basis. The test determines a limitation, or ceiling, on the book value of oil and gas properties, which is generally the after-tax value of the future net cash flows from proved natural gas and crude oil reserves, including the effect of cash flow hedges, discounted at ten percent per annum. Applying the test, we compare the full cost ceiling limitation to the net book value of the oil and gas properties reduced by the related net deferred income tax liability and asset retirement obligations. If the net book value reduced by the related net deferred income tax liability and asset retirement obligations exceeds the ceiling, an impairment or noncash write down is required. Companies that use the full cost method of accounting for oil and gas properties are required to perform the ceiling test each quarter.

     At September 30, 2006, the unamortized cost of our Canadian oil and gas properties exceeded the full cost ceiling limitation by approximately $56.6 million, net of income taxes. The full cost ceiling limitation included $28.4 million, net of income taxes, for hedge valuations. The natural gas price for September 30, 2006 referenced an AECO price of $3.63 per Mcf adjusted for appropriate price differentials. As permitted by full cost accounting rules, improvements in AECO spot natural gas prices subsequent to September 30, 2006 eliminated the necessity to record a write-down. Because of the volatility of oil and natural gas prices, no assurance can be given that the Company will not experience a write-down in future periods.

Recently Issued Accounting Standards

     In December 2004, the Financial Accounting Standards Boards (“FASB”) issued SFAS No. 123 (revised 2004),Share-Based Payment(“SFAS 123(R)”).This statement requires the cost resulting from all share-based payment transactions be recognized in the financial statements at their fair value on the grant date. We adopted SFAS 123(R) on January 1, 2006. We previously accounted for stock awards under the recognition and measurement principles of APB No. 25,Accounting for Stock Issued to Employees, and related Interpretations. Stock-based employee compensation expense for restricted stock and stock unit grants was reflected in net income, but no compensation expense was recognized for options granted with an exercise price equal to the market value of the underlying common stock on the date of grant.

     We adopted SFAS 123(R) using the modified prospective application method described in the statement. Under the modified prospective application method, we have applied the standard to new awards and to awards modified, repurchased, or cancelled after January 1, 2006. Additionally, compensation cost for the unvested portion of stock awards outstanding as of January 1, 2006 has been recognized as compensation expense as the requisite service is rendered after January 1, 2006. The compensation cost for unvested stock awards granted before adoption of SFAS 123(R) shall be attributed to periods beginning January 1, 2006 using the attribution method that was used under SFAS 123. At January 1, 2006, we had total compensation cost of $1.1 million related to unvested stock options with a weighted average remaining vesting period of 1.5 years. We recorded expense of $0.5 million in the first nine months of 2006 for stock option grants.

     At January 1, 2006, we had total compensation cost of $3.3 million related to unvested restricted stock and stock unit awards. During 2006, grants of restricted stock and stock units had total compensation cost of $18.2 million at the time of grant. We recorded expense of $4.2 million in the first nine months of 2006 for restricted stock and stock unit grants. Total unvested compensation cost for all restricted stock and stock unit grants was $17.0 million at September 30, 2006.

     The FASB recently issued FASB Interpretation No. 48,Accounting for Uncertainty in Income Taxes, an interpretation of SFAS No. 109(“FIN 48”). FIN 48 is effective for fiscal years beginning after December 15, 2006. We are currently reviewing FIN 48 and evaluating its potential impact.

     FAS No. 157,Fair Value Measurements,(“SFAS 157”) was issued by the FASB in September 2006. SFAS 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles (“GAAP”) and expands disclosures related to the use of fair value measurements. The Statement applies under other accounting pronouncements that require or permit fair value measurement. SFAS 157 is effective for financials statements issued for fiscal years beginning after November 15, 2007. We are currently evaluating the timing of adoption and the impact that adoption might have on our financial position or results of operations.

     In September 2006, the Securities and Exchange Commission issued Staff Accounting Bulletin No. 108 (“SAB 108”). Due to diversity in practice among registrants, SAB 108 expresses SEC staff views regarding the process by which misstatements in financial statements are evaluated for purposes of determining whether financial statement restatement is necessary. SAB 108 is

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effective for fiscal years ending after November 15, 2006, and early application is encouraged. Our management does not believe SAB 108 will have a material impact on our financial position or results from operations.

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. We sell approximately 10.0 MMcfd and 25.0 MMcfd of natural gas for floor prices of $2.47 per Mcf and $2.49 per Mcf, respectively, under long-term contracts that extend through March 2009. Approximately 4.3 MMcfd of the natural gas sold under these contracts during the first nine months of 2006 were third-party volumes controlled by us.

     As of September 30, 2006, we have hedged approximately 80.0 MMcfd of our natural gas production for the remainder of 2006 using collars with a weighted average floor price of $7.65 per Mcf and a weighted average ceiling price of $11.42 per Mcf. We also have 2,000 Bbld of crude oil, condensate and NGL production hedged with crude oil price collars for the remainder of 2006. The current crude oil collars have a floor price of $50.00 per Bbl and a ceiling price of $85.85 per Bbl.

     Price collars have also been put in place to hedge 2007 natural gas production of approximately 108 MMcfd and first quarter 2008 natural gas production of approximately 40.0 MMcfd. Crude oil, condensate and NGL production of approximately 1,250 Bbld has also been hedged for 2007 with crude oil collars.

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     The following table summarizes our open financial derivative positions as of September 30, 2006 related to our natural gas and crude oil production.

		Remaining Contract		Price per
Product	Type	Period	Volume	Mcf or Bbl		Fair Value
						(in thousands)
Gas	Collar	Oct 2006	5,000 Mcfd	$5.50– 8.10	(1)	$	201
Gas	Collar	Oct 2006	5,000 Mcfd	5.50– 8.25	(1)		201
Gas	Collar	Oct 2006	5,000 Mcfd	6.50– 8.25	(1)		356
Gas	Collar	Oct 2006	5,000 Mcfd	7.00– 8.35	(1)		434
Gas	Collar	Oct 2006	5,000 Mcfd	7.00– 8.35	(1)		434
Gas	Collar	Oct 2006	5,000 Mcfd	7.00– 8.35	(1)		434
Gas	Collar	Oct 2006	5,000 Mcfd	8.00-10.10	(1)		589
Gas	Collar	Oct 2006	5,000 Mcfd	8.00-10.10	(1)		589
Gas	Collar	Oct 2006	5,000 Mcfd	8.00-10.20	(1)		589
Gas	Collar	Oct 2006	5,000 Mcfd	8.00-10.20	(1)		589
Gas	Collar	Oct 2006	10,000 Mcfd	6.50– 8.25	(1)		712
Gas	Collar	Oct 2006-Apr 2007	10,000 Mcfd	7.50-11.00			2,612
Gas	Collar	Oct 2006-Apr 2007	10,000 Mcfd	7.50-11.15			2,659
Gas	Collar	Nov 2006-Mar 2007	10,000 Mcfd	7.50– 9.65			1,105
Gas	Collar	Nov 2006-Mar 2007	10,000 Mcfd	8.00-14.72			2,135
Gas	Collar	Nov 2006-Mar 2007	10,000 Mcfd	8.50-11.35			2,410
Gas	Collar	Nov 2006-Mar 2007	10,000 Mcfd	8.50-11.50			2,462
Gas	Collar	Nov 2006-Mar 2007	20,000 Mcfd	8.00-15.00			4,177
Gas	Collar	Jan 2007-Dec 2007	10,000 Mcfd	9.00–12.10			6,247
Gas	Collar	Jan 2007-Dec 2007	20,000 Mcfd	9.00–12.10			12,494
Gas	Collar	Apr 2007-Oct 2007	10,000 Mcfd	7.50-11.50			1,773
Gas	Collar	Apr 2007-Oct 2007	10,000 Mcfd	7.50-11.75			1,721
Gas	Collar	Apr 2007-Oct 2007	5,000 Mcfd	7.50-11.78			936
Gas	Collar	Apr 2007-Oct 2007	5,000 Mcfd	7.50-11.80			938
Gas	Collar	Apr 2007-Mar 2008	10,000 Mcfd	9.00-12.00			5,243
Gas	Collar	Apr 2007-Mar 2008	10,000 Mcfd	9.00-12.05			5,311
Gas	Collar	May 2007-Dec 2007	10,000 Mcfd	8.00-11.20			2,355
Gas	Collar	Nov 2007-Mar 2008	10,000 Mcfd	8.00-15.00			879
Gas	Collar	Nov 2007-Mar 2008	10,000 Mcfd	8.00-15.65			956
Oil	Collar	Oct 2006-Jun 2007	1,000 Bbld	50.00-85.85			(35	)
Oil	Collar	Oct 2006-Jun 2007	1,000 Bbld	50.00-85.85			(35	)
Oil	Collar	Jul 2007-Dec 2007	500 Bbld	70.00-91.10			528
Gas	Basis	Oct 2006-May 2007	3,292 Mcfd				207
Gas	Basis	Dec 2006-Jan 2007	968 Mcfd				28
				Total		$	62,234

⁽¹⁾ These collars were settled in October at the final October NYMEX price of $4.201 per Mcf.

     Commodity price fluctuations affect our remaining natural gas and crude oil volumes as well as our NGL volumes. A portion of our natural gas production is sold under long-term natural gas sales contracts with market pricing. Additional natural gas volumes of 16.5 MMcfd are committed at market price through September 2008. Approximately 8.1 MMcfd of our natural gas production was sold under these contracts. The remaining contractual volumes were third-party volumes controlled by us.

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     We also enter into financial contracts to hedge our exposure to commodity price risk associated with future contractual natural gas sales and purchases. These contracts consist of fixed price sales to third parties. As a result of these firm sale commitments, the associated financial price swaps have qualified as fair value hedges. The following table summarizes our open financial derivative positions and hedged firm commitments as of September 30, 2006 related to natural gas marketing.

				Weighted Avg
Product	Type	Contract Period	Volume	Price per Mcf		Fair Value
						(in thousands)
Fixed price sale contracts
Gas	Sale	Oct 2006	234 Mcfd	$	8.77	$	33
Gas	Sale	Oct 2006	700 Mcfd	$	5.21		22
Gas	Sale	Oct 2006	600 Mcfd	$	5.18		18
Gas	Sale	Oct 2006-Dec 2006	296 Mcfd	$	8.20		59
						$	132
Financial derivatives
Gas	Floating Price	Oct 2006	323 Mcfd			$	(34	)
Gas	Floating Price	Oct 2006	323 Mcfd				(45	)
Gas	Floating Price	Oct 2006	645 Mcfd				(11	)
Gas	Floating Price	Oct 2006	645 Mcfd				(16	)
Gas	Floating Price	Nov 2006	333 Mcfd				(31	)
Gas	Floating Price	Dec 2006	333 Mcfd				(22	)
							(159	)
				Total-net		$	(27	)

     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 $6.4 million higher and $20.2 million lower as a result of the hedging programs for the first nine months of 2006 and 2005, respectively. Other revenue was $0.1 million and $0.3 million lower as a result of hedging activities for the nine month periods ending September 30, 2006 and 2005, respectively.

Interest Rate Risk

     Our interest rate swap covering $75.0 million notional variable-rate debt ended on March 31, 2005. The interest rate swap converted a floating three-month LIBOR rate to a 3.74% fixed-rate.

     A gain of $0.3 million for the termination of an interest rate swap hedging $40.0 million of fixed-rate second lien mortgage notes in January 2004 was deferred and was being recognized over the period remaining to original maturity of our second lien mortgage notes. We repaid and retired the second lien mortgage notes in March 2006. The remaining deferred gain of $0.1 million was recognized upon retirement of these notes.

     As a result of these swaps, interest expense was $0.1 million and $0.2 million lower, respectively, for the nine months ended September 30, 2006 and 2005.

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ITEM 4. Controls and Procedures

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

     We carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures as of the end of the period covered by this report pursuant to Securities Exchange Act Rule 13a-15. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that, as of the end of the third quarter of 2006, 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 to allow timely decisions regarding required disclosures.

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, 2006 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II — OTHER INFORMATION

ITEM 1. Legal Proceedings

     As previously reported in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2005, in August 2001, a group of royalty owners, Athel Williams et al., brought suit against us and three of our subsidiaries in the Circuit Court of Otsego County, Michigan. On January 21, 2005, the Circuit Court issued an order certifying certain claims to proceed on behalf of a class. On July 25, 2006, the Michigan Court of Appeals reversed the certification of all claims on appeal and remanded the case to the trial court for further proceedings. Based on information currently available to us, 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.

     On October 13, 2006, we filed suit in the District Court in Tarrant County, Texas against Eagle Drilling, LLC and Eagle Domestic Drilling Operations, LLC (Eagle”) regarding three contracts for drilling rigs in which we allege that the first rig furnished by Eagle exhibited operating deficiencies and safety defects. We seek a declaratory judgment that (i) the drilling contracts are void, (ii) we are entitled to recover damages incurred due to Eagle’s failure to perform, and (iii) that Eagle is not entitled to early termination compensation provided for in the contracts. On October 23, 2006, Eagle Domestic Drilling Operations, LLC sued us in District Court of Cleveland County, Oklahoma for breach of contract as to each of the three drilling contracts alleging damages in the amount of $29 million plus punitive damages and interest. 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.

ITEM 6. Exhibits:

Exhibit No.	Description
*4.1	Third Supplemental Indenture, dated as of September 26, 2006, among Quicksilver Resources Inc., the subsidiary guarantors named therein and JPMorgan Chase Bank, National Association, as trustee.
10.1	Quicksilver Resources Inc. Amended and Restated Key Employee Change in Control Retention Incentive Plan (filed as Exhibit 10.1 to the Company’s Form 8-K filed August 31, 2006 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

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SIGNATURES

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

Dated: November 6, 2006

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

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EXHIBIT INDEX

Exhibit No.	Description
*4.1	Third Supplemental Indenture, dated as of September 26, 2006, among Quicksilver Resources Inc., the subsidiary guarantors named therein and JPMorgan Chase Bank, National Association, as trustee.
10.1	Quicksilver Resources Inc. Amended and Restated Key Employee Change in Control Retention Incentive Plan (filed as Exhibit 10.1 to the Company’s Form 8-K filed August 31, 2006 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

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