Quicksilver Resources 10Q 2006 Q2 Quarterly report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)


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

For the quarterly period ended June 30, 2006


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

For the transition period from to

Commission file number: 001-14837

Quicksilver Resources Inc.

(Exact name of registrant as specified in its charter)


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

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

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

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

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

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

Large accelerated filerþ Accelerated filero Non-accelerated filero

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

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


Title of Class				Outstanding as of July 31, 2006

Common Stock, $0.01 par value				77,539,205

QUICKSILVER RESOURCES INC.
INDEX TO FORM 10-Q
For the Period Ending June 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 June 30, 2006 and December 31, 2005		4

Condensed Consolidated Statements of Income and Comprehensive Income for the Three and Six Months Ended June 30, 2006 and 2005		5

Condensed Consolidated Statements of Cash Flows for the Three and Six Months Ended June 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		18

Item 3. Quantitative and Qualitative Disclosures About Market Risk		28

Item 4. Controls and Procedures		30

PART II. OTHER INFORMATION

Item 1. Legal Proceedings		31

Item 4. Submission of Matters to a Vote of Security Holders		31

Item 6. Exhibits		32

Signatures		33
Amended and Restated Certificate of Incorporation
Awareness Letter of Deloitte & Touche LLP
Certification Pursuant to Section 302
Certification Pursuant to Section 302
Certification Pursuant to 18 U.S.C. Section 1350

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 June 30, 2006, and the related condensed consolidated statements of income and comprehensive income and cash flows for the three- and six-month periods ended June 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, 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
August 4, 2006

QUICKSILVER RESOURCES INC.

CONDENSED CONSOLIDATED BALANCE SHEETS
In thousands, except for share data – Unaudited


	June 30,			December 31,
	2006			2005
ASSETS
Current assets
Cash and cash equivalents	$	21,718		$	14,318
Accounts receivable, net of allowance for doubtful accounts		48,752			76,121
Current deferred income taxes		—			14,614
Other current assets		28,103			8,531

Total current assets		98,573			113,584

Investments in and advances to equity affiliates		8,521			8,353

Property, plant and equipment – net (“full cost”)		1,340,792			1,112,002

Other assets		27,182			9,155

	$	1,475,068		$	1,243,094


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current portion of long-term debt	$	376		$	70,493
Accounts payable		35,875			48,409
Accrued derivative obligations		455			40,632
Accrued liabilities		46,507			52,656

Total current liabilities		83,213			212,190

Long-term debt		721,694			506,039

Derivative obligations		665			4,631

Asset retirement obligations		23,056			20,891

Deferred income taxes		142,806			115,728

Minority interest		4,523			—

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 79,926,559 and 78,650,110 shares issued, respectively		799			787
Paid in capital in excess of par value		233,016			211,843
Treasury stock of 2,579,414 and 2,571,611 shares, respectively		(10,832	)		(10,353	)
Accumulated other comprehensive income (loss)		31,265			(12,382	)
Retained earnings		244,863			193,720

Total stockholders’ equity		499,111			383,615

	$	1,475,068		$	1,243,094

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

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 Six Months Ended
	June 30,						June 30,
	2006			2005			2006			2005
Revenues
Oil, gas and related product sales	$	88,536		$	67,843		$	187,225		$	122,683
Other revenue		929			697			1,890			1,106

Total revenues		89,465			68,540			189,115			123,789

Expenses
Oil and gas production costs		24,220			17,041			45,630			34,016
Production and ad valorem taxes		1,986			3,311			6,159			5,990
Other operating costs		546			654			949			1,045
Depletion, depreciation and accretion		17,954			13,017			35,627			25,389
Provision for bad debts		—			88			—			88
General and administrative		5,437			4,618			11,691			7,731

Total expenses		50,143			38,729			100,056			74,259

Income (loss) from equity affiliates		(80	)		215			108			439


Operating income		39,242			30,026			89,167			49,969

Other income-net		(498	)		(118	)		(848	)		(204	)
Interest expense		10,566			4,776			19,768			9,433


Income before income taxes and minority interest		29,174			25,368			70,247			40,740
Income tax expense		5,555			8,183			19,093			12,801
Minority interest		11			—			11			—


Net income	$	23,608		$	17,185		$	51,143		$	27,939


Other comprehensive income, net of income taxes
Reclassification adjustments – hedge settlements		(2,324	)		2,433			(830	)		8,637
Unrealized gain (loss) on derivative instruments		16,094			4,333			39,566			(5,930	)
Foreign currency translation adjustments		4,907			(528	)		4,911			(1,208	)

Comprehensive income	$	42,285		$	23,423		$	94,790		$	29,438


Basic net income per common share	$	0.31		$	0.23		$	0.67		$	0.37
Diluted net income per common share	$	0.29		$	0.21		$	0.63		$	0.35

Weighted average common shares outstanding
Basic		76,723			75,751			76,383			75,619
Diluted		83,089			82,474			82,949			82,268

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

QUICKSILVER RESOURCES INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

In thousands – Unaudited


	For the Six Months Ended
	June 30,
	2006			2005
Operating activities:
Net income	$	51,143		$	27,939
Charges and credits to net income not affecting cash
Depletion, depreciation and accretion		35,627			25,389
Deferred income taxes		19,063			12,528
Non-cash compensation		2,819			500
Amortization of deferred loan costs		1,255			701
Income from equity affiliates		(108	)		(439	)
Minority interest		11			—
Non-cash (gain) loss from hedging activities		77			(287	)
Other non-cash items		129			58
Changes in assets and liabilities
Accounts receivable		27,369			(2,844	)
Current and other assets		(13,674	)		(3,685	)
Accounts payable		(1,423	)		2,542
Accrued and other liabilities		9,502			(1,459	)

Net cash provided by operating activities		131,790			60,943


Investing activities:
Purchases of property, plant and equipment		(279,713	)		(132,515	)
Return of investment in equity affiliates		365			315
Proceeds from sales of properties		4,854			1,190

Net cash used for investing activities		(274,494	)		(131,010	)


Financing activities:
Issuance of debt		408,742			59,823
Repayments of debt		(271,719	)		(161	)
Proceeds from exercise of stock options		18,366			1,508
Minority interest contributions		4,506			—
Purchase of treasury stock		(479	)	��	—
Payment for fractional shares		—			(18	)
Debt issuance costs		(9,192	)		(107	)

Net cash provided by financing activities		150,224			61,045


Effect of exchange rates on cash		(120	)		283


Net increase (decrease) in cash and cash equivalents		7,400			(8,739	)

Cash and cash equivalents at beginning of period		14,318			15,947


Cash and cash equivalents at end of period	$	21,718		$	7,208

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

QUICKSILVER RESOURCES INC.

NOTES TO CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS

UNAUDITED

1. ACCOUNTING POLICIES AND DISCLOSURES

The accompanying condensed consolidated interim financial statements of Quicksilver Resources Inc. (“Quicksilver” or the “Company”) have not been audited 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 June 30, 2006 and its income, comprehensive income and cash flows for the three- and six-month periods ended June 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 June 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 six-month periods ended June 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 June 30, 2006 as those options were out of the money and, therefore, considered to be antidilutive.


	Three Months Ended				Six Months Ended June
	June 30,				30,
	2006		2005		2006		2005
	(in thousands, expect per share amounts)
Net income	$	23,608	$	17,185	$	51,143	$	27,939
Impact of assumed conversions – interest on 1.875% contingently convertible debentures, net of income taxes		475		475		950		950

Net income available to stockholders assuming conversion of contingently convertible debentures	$	24,083	$	17,660	$	52,093	$	28,889


Weighted average common shares-basic		76,723		75,751		76,383		75,619

Effect of dilutive securities:
Employee stock options		1,110		1,678		1,327		1,657
Employee stock awards		348		137		331		84
Contingently convertible debentures		4,908		4,908		4,908		4,908

Weighted average common shares-diluted		83,089		82,474		82,949		82,268


Basic net income per common share	$	0.31	$	0.23	$	0.67	$	0.37

Diluted net income per common share	$	0.29	$	0.21	$	0.63	$	0.35

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.

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, 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.

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 $1.1 million related to unvested stock options with a weighted average remaining vesting period of 1.5 years. The Company recorded expense of $0.3 million, net of income taxes, for stock options in the first six months of 2006. At June 30, 2006, the Company had $0.8 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 $3.2 million related to unvested restricted stock and stock unit awards. Additionally, grants of restricted stock and stock units through June 30, 2006 had total compensation cost of $11.7 million at the time of grant. During the first six months of 2006, the Company recognized $2.4 million of expense for vesting of restricted stock and stock units. Total unvested compensation cost was $12.4 million at June 30, 2006 with a weighted average remaining vesting period of 1.6 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 quarterly period ended June 30, 2006.

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			Six Months
	Ended			Ended
	June 30, 2005			June 30, 2005
	(in thousands, except per share amounts)
Net income	$	17,185		$	27,939
Impact of assumed conversions – interest on 1.875% contingently convertible debentures, net of income taxes		475			950
Deduct: Total stock – based compensation expense determined under fair value based method for stock option awards, net of related tax effect		(1,907	)		(3,838	)

Pro forma net income available to stockholders assuming conversion of contingently convertible debentures	$	15,753		$	25,051


As reported
Basic net income per common share	$	0.23		$	0.37
Diluted net income per common share		0.21			0.35

Pro forma
Basic net income per common share	$	0.20		$	0.32
Diluted net income per common share		0.19			0.31

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 shareholders 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. There were 750,000 shares reserved under the 2004 Plan, which provides for the grant of non-qualified options and restricted stock awards to Quicksilver’s non-employee directors.

Under terms of the 1999 Plan and 2004 Plan, retention stock awards and options were granted to officers, employees and non-employee directors 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. Incentive stock options and non-qualified options 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, seven million shares of common stock were reserved for issuance pursuant to grants of stock options, appreciation rights, restricted shares, restricted stock units, performances shares and performances 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.

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 six months of 2006.


				Wtd Avg
				Exercise
	Shares			Price
Outstanding at beginning of year		2,840,695		$	17.13
Granted		2,401			44.39
Exercised		(1,019,271	)		18.02
Forfeited		(16,632	)		11.01

Outstanding at period end		1,807,193		$	16.71


Exercisable at June 30, 2006		1,340,962		$	18.13


Weighted average fair value of options granted				$	24.99

The stock options vested and exercisable at June 30, 2006 had an aggregate intrinsic value of $25.0 million and a weighted average remaining term of 2.6 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.


Six Months Ended June 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 $18.4 million and $1.5 million for the first six months of 2006 and 2005, respectively. The intrinsic value of the options exercised in the first half of 2006 was $24.7 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, 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 193,258 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 half of 2006.


				Wtd Avg
				Grant Date
	Shares			Fair Value
Outstanding at beginning of year		133,858		$	33.73
Granted		267,754			43.64
Vested		(46,462	)		33.79
Forfeited		(10,276	)		37.25

Outstanding at period end		344,874		$	41.31

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

3. HEDGING

The estimated fair values of all hedge derivatives and the associated fixed price firm sale and purchase commitments as of June 30, 2006 and December 31, 2005 are provided below. The associated 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.


	June 30,		December 31,
	2006		2005
	(in thousands)
Derivative assets:
Fixed price sale commitments	$	207	$	638
Floating price natural gas basis swaps		5		—
Natural gas financial collars		20,044		—

	$	20,256	$	638


Derivative liabilities:
Natural gas financial collars	$	3,034	$	44,480
Crude oil financial collars		1,344		320
Floating price natural gas financial swaps		211		463
Floating price natural gas basis swaps		57		—
Fixed price sale commitments		—		35

	$	4,646	$	45,298

The fair values of all natural gas and crude oil financial instruments and firm sale and purchase commitments as of June 30, 2006 and December 31, 2005 were estimated based on market prices of 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 sales commitments does not necessarily represent the value a third party would pay or be paid to assume the Company’s contract positions.

At June 30, 2006, deferred cash flow hedge gains of $10.4 million and deferred cash flow hedge losses of $0.2 million have been classified as current based on the maturity of the derivative instruments. The Company estimates $5.9 million of after-tax gains will be reclassified from other comprehensive income over the next twelve months.

4. LONG-TERM DEBT

Long-term debt consists of:


	June 30,			December 31,
	2006			2005
	(in thousands)
Senior secured credit facility	$	223,557		$	357,788
Senior subordinated notes		350,000			—
Contingently convertible debentures, net of unamortized discount		147,937			147,881
Second lien mortgage notes payable		—			70,000
Other loans		576			746
Deferred gain – fair value interest hedge		—			117

		722,070			576,532
Less current maturities		(376	)		(70,493	)

	$	721,694		$	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 June 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 its $192.5 million of borrowings under the U.S. portion of its credit facility in March and April. As of June 30, 2006, the Company’s borrowing base under its senior secured credit facility was $600 million, of which approximately $375.4 million was available for borrowing. The loan agreements for the senior 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 all such covenants at June 30, 2006.

5. 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.

During the six-month periods ended June 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 June 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 six-month periods ended June 30, 2006 and 2005.


	Six Months Ended June 30,
	2006			2005
	(in thousands)
Beginning asset retirement obligation	$	20,965		$	18,471
Additional liability incurred		1,186			474
Accretion expense		649			552
Change in estimates		29			—
Asset retirement costs incurred		(122	)		(77	)
Loss on settlement of liability		96			14
Currency translation adjustment		326			(80	)

Ending asset retirement obligation	$	23,129		$	19,354

6. INCOME TAXES

In May 2006, the Texas Governor signed into law a Texas margin tax which restructures the state business tax 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 $0.9 million deferred tax provision for the Texas margin tax in the second quarter of 2006.

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 for the three- and six-months ended June 30, 2006 as a result of the Canadian rate reductions.

7. 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, which will operate the Processing Partners. A minority owner 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, which will operate Pipeline Partners. Two minority owners contributed a total of $3.1 million to Pipeline Partners for limited partnership interests totaling 7%.

8. 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 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.

As of June 30, 2006, the Company had entered into contracts for the use of eight drilling rigs in its drilling and exploration programs for periods ranging from one to three years at estimated day rates ranging from $15,500 to $21,500 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. Under these contracts, the Company estimates $135.8 million will be paid as follows: $24.7 million in 2006; $46.9 million in 2007; $41.1 million in 2008; and $23.1 million in 2009.

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.

9. CONDENSED CONSOLIDATING FINANCIAL INFORMATION

The following subsidiaries of Quicksilver are guarantors of Quicksilver’s Senior Subordinated Notes issued March 16, 2006: Mercury Michigan, Inc., Terra Energy Ltd., GTG Pipeline Corporation, Cowtown Pipeline Funding, Inc., Cowtown Pipeline Management, Inc., Terra Pipeline Company, Beaver Creek Pipeline, LLC, Cowtown Pipeline LP, and Cowtown Gas Processing, LP (collectively, the “Guarantor Subsidiaries”). Each of the Guarantor Subsidiaries is 100% owned by Quicksilver. The guarantees are full and unconditional and joint and several. The condensed consolidating financial statements below present the financial position, results of operations and cash flows of Quicksilver, the Guarantor Subsidiaries and non-guarantor subsidiaries of Quicksilver.

Condensed Consolidating Balance Sheets


	June 30, 2006
					Non-					Quicksilver
	Quicksilver		Guarantor		Guarantor					Resources Inc.
	Resources Inc.		Subsidiaries		Subsidiaries		Eliminations			Consolidated
	(in thousands)
ASSETS
Current assets	$	115,415	$	230,106	$	45,330	$	(292,278	)	$	98,573
Investments in subsidiaries (equity method)		446,758		99,985		—		(537,222	)		8,521
Property and equipment, net		778,947		86,489		475,356		—			1,340,792
Other assets		26,186		—		996		—			27,182

Total assets	$	1,367,306	$	415,580	$	521,682	$	(829,500	)	$	1,475,068


LIABILITIES
Current liabilities	$	263,399	$	77,000	$	35,092	$	(292,278	)	$	83,213
Long-term liabilities		604,796		24,554		263,394		—			892,744
Stockholders’ equity		499,111		314,026		223,196		(537,222	)		499,111

Total liabilities and stockholders’ equity	$	1,367,306	$	415,580	$	521,682	$	(829,500	)	$	1,475,068


	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
Long-term 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

Condensed Consolidating Statement of Income


	For the Three Months Ended June 30, 2006
						Non-						Quicksilver
	Quicksilver		Guarantor			Guarantor						Resources Inc.
	Resources Inc.		Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(in thousands)
Revenues	$	53,875	$	10,727		$	28,582		$	(3,719	)	$	89,465
Operating expenses		34,341		3,850			15,671			(3,719	)		50,143
Income (loss) from equity affiliates		2		(82	)		—			—			(80	)

Income from operations		19,536		6,795			12,911			—			39,242
Equity in net earnings of subsidiaries		15,978		148			—			(16,126	)		—
Interest expense and other		6,787		11			3,281			—			10,079
Income tax provision		5,119		2,374			(1,938	)		—			5,555

Net income	$	23,608	$	4,558		$	11,568		$	(16,126	)	$	23,608


	For the Three Months Ended June 30, 2005
						Non-					Quicksilver
	Quicksilver		Guarantor			Guarantor					Resources Inc.
	Resources Inc.		Subsidiaries			Subsidiaries		Eliminations			Consolidated
	(in thousands)
Revenues	$	38,370	$	10,821		$	20,052	$	(703	)	$	68,540
Operating expenses		26,531		4,641			8,260		(703	)		38,729
Income from equity affiliates		24		191			—		—			215

Income from operations		11,863		6,371			11,792		—			30,026
Equity in net earnings of subsidiaries		11,677		—			—		(11,677	)		—
Interest expense and other		3,354		(40	)		1,344		—			4,658
Income tax provision		3,001		2,244			2,938		—			8,183

Net income	$	17,185	$	4,167		$	7,510	$	(11,677	)	$	17,185


	For the Six Months Ended June 30, 2006
					Non-					Quicksilver
	Quicksilver		Guarantor		Guarantor					Resources Inc.
	Resources Inc.		Subsidiaries		Subsidiaries		Eliminations			Consolidated
	(in thousands)
Revenues	$	108,843	$	24,105	$	60,949	$	(4,782	)	$	189,115
Operating expenses		67,956		8,224		28,658		(4,782	)		100,056
Income from equity affiliates		2		106		—		—			108

Income from operations		40,889		15,987		32,291		—			89,167
Equity in net earnings of subsidiaries		33,656		148		—		(33,804	)		—
Interest expense and other		12,940		9		5,982		—			18,931
Income tax provision		10,462		5,592		3,039		—			19,093

Net income	$	51,143	$	10,534	$	23,270	$	(33,804	)	$	51,143


	For the Six Months Ended June 30, 2005
						Non-					Quicksilver
	Quicksilver		Guarantor			Guarantor					Resources Inc.
	Resources Inc.		Subsidiaries			Subsidiaries		Eliminations			Consolidated
	(in thousands)
Revenues	$	64,782	$	20,310		$	39,969	$	(1,272	)	$	123,789
Operating expenses		51,608		8,075			15,848		(1,272	)		74,259
Income from equity affiliates		24		415			—		—			439

Income from operations		13,198		12,650			24,121		—			49,969
Equity in net earnings of subsidiaries		23,559		—			—		(23,559	)		—
Interest expense and other		6,389		(44	)		2,884		—			9,229
Income tax provision		2,429		4,443			5,929		—			12,801

Net income	$	27,939	$	8,251		$	15,308	$	(23,559	)	$	27,939

Condensed Consolidating Statements of Cash Flows


	For the Six Months Ended June 30, 2006
							Non-					Quicksilver
	Quicksilver			Guarantor			Guarantor					Resources Inc.
	Resources Inc.			Subsidiaries			Subsidiaries			Eliminations		Consolidated
	(in thousands)
Cash flow provided by operations	$	32,019		$	39,917		$	59,854		$	—	$	131,790
Cash flow used for investing activities		(148,436	)		(37,392	)		(88,666	)		—		(274,494	)
Cash flow provided by financing activities		123,526			—			26,698			—		150,224
Effect of exchange rates on cash		—			—			(120	)		—		(120	)

Net increase (decrease) in cash & equivalents		7,109			2,525			(2,234	)		—		7,400
Cash & equivalents at beginning of period		8,990			(4,410	)		9,738			—		14,318

Cash & equivalents at end of period	$	16,099		$	(1,885	)	$	7,504		$	—	$	21,718


	For the Six Months Ended June 30, 2005
							Non-					Quicksilver
	Quicksilver			Guarantor			Guarantor					Resources Inc.
	Resources Inc.			Subsidiaries			Subsidiaries			Eliminations		Consolidated
	(in thousands)
Cash flow provided by operations	$	29,767		$	7,088		$	24,088		$	—	$	60,943
Cash flow used for investing activities		(65,360	)		(10,050	)		(55,600	)		—		(131,010	)
Cash flow provided by financing activities		34,222			—			26,823			—		61,045
Effect of exchange rates on cash		—			—			283			—		283

Net decrease in cash & equivalents		(1,371	)		(2,962	)		(4,406	)		—		(8,739	)
Cash & equivalents at beginning of period		10,428			1,080			4,439			—		15,947

Cash & equivalents at end of period	$	9,057		$	(1,882	)	$	33		$	—	$	7,208

10. SUPPLEMENTAL CASH FLOW INFORMATION

Cash paid for interest and income taxes is as follows:


	Six Months Ended June 30,
	2006		2005
	(in thousands)
Interest	$	12,982	$	9,174
Income taxes	$	3	$	857

Other non-cash transactions are as follows:


	Six Months Ended June 30,
	2006			2005
	(in thousands)
Noncash investing activities – changes in working capital associated with property and equipment	$	(26,950	)	$	(1,615	)

11. RELATED PARTY TRANSACTIONS

As of June 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 $0.6 million and $0.4 million for rent in the first six 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 it leases from PALP. The rental rate under the sublease was determined using comparable rates charged by third parties. During 2006, the Company has 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.

12. 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
For the Three Months Ended	States		Canada		Corporate			Consolidated
	(in thousands)
June 30, 2006
Revenues	$	63,393	$	26,072	$	—		$	89,465
Depletion, depreciation and accretion		11,273		6,484		197			17,954
Operating income		31,570		13,306		(5,634	)		39,242
Property and equipment costs incurred		104,926		13,587		644			119,157

June 30, 2005
Revenues	$	48,351	$	20,189	$	—		$	68,540
Depletion, depreciation and accretion		8,604		4,267		146			13,017
Operating income		22,874		11,916		(4,764	)		30,026
Property and equipment costs incurred		53,447		23,286		289			77,022


	United
For the Six Months Ended	States		Canada		Corporate			Consolidated
June 30, 2006
Revenues	$	130,606	$	58,509	$	—		$	189,115
Depletion, depreciation and accretion		21,625		13,683		319			35,627
Operating income		68,144		33,033		(12,010	)		89,167
Property and equipment costs incurred		200,487		51,068		1,207			252,762


	United
For the Six Months Ended	States		Canada		Corporate			Consolidated
June 30, 2005
Revenues	$	83,625	$	40,164	$	—		$	123,789
Depletion, depreciation and accretion		16,522		8,572		295			25,389
Operating income		33,707		24,288		(8,026	)		49,969
Property and equipment costs incurred		84,068		49,766		296			134,130

Fixed Assets – net
June 30, 2006	$	956,988	$	380,798	$	3,006		$	1,340,792

December 31, 2005	$	777,330	$	332,580	$	2,092		$	1,112,002

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,” “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.

RESULTS OF OPERATIONS

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


	Three Months Ended June 30,
	2006		2005
	(in thousands)
Total operating revenues	$	89,465	$	68,540
Total operating expenses		50,143		38,729
Operating income		39,242		30,026
Net income		23,608		17,185

We recorded net income of $23.6 million ($0.29 per diluted share) for the three months ended June 30, 2006, compared to net income of $17.2 million ($0.21 per diluted share) for the second quarter of 2005.

Operating Revenues

Revenues for the second quarter of 2006 were $89.5 million; a $21.0 million increase from the $68.5 million reported for the three months ended June 30, 2005. Production revenue increased $20.7 million as a result of a 19% increase in sales volumes and a 10% increase in realized sales prices.

Gas, Oil and Related Product Sales

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


	Three Months Ended June 30,
	2006		2005
Natural gas, oil and NGL sales (in thousands)		��
United States	$	62,608	$	47,777
Canada		25,928		20,066

Total	$	88,536	$	67,843


Product sale revenues (in thousands)
Natural gas sales	$	72,735	$	59,913
Oil and condensate sales		9,533		6,425
NGL sales		6,268		1,505

Total	$	88,536	$	67,843


Average daily sales volume
Natural gas – Mcfd
United States		94,585		87,596
Canada		49,624		37,985

Total		144,209		125,581
Oil and condensate – Bbld
United States		1,688		1,569
Canada		1		—

Total		1,689		1,569
NGL – Bbld
United States		1,623		486
Canada		25		11

Total		1,648		497


	Three Months Ended June 30,
	2006		2005
Total sales – Mcfed
United States		114,451		99,914
Canada		49,780		38,061

Total		164,231		137,975

Unit prices — including impact of hedges
Natural gas — per Mcf
United States	$	5.45	$	5.00
Canada		5.71		5.80
Consolidated		5.54		5.24

Oil and condensate — per Bbl
United States	$	62.03	$	45.01
Canada		51.43		—
Consolidated		62.03		45.01

NGL — per Bbl
United States	$	41.55	$	33.14
Canada		57.36		39.03
Consolidated		41.80		33.27

Natural gas sales of $72.7 million for the second quarter of 2006 were 21% higher than the $60.0 million for the second quarter of 2005. A $0.30 per Mcf increase in average realized sales prices increased natural gas revenue $3.4 million. Natural gas revenue also increased $9.3 million because of a 15% increase in sales volumes as compared to the second quarter of 2005. Production from our coal bed methane (“CBM”) projects in Canada increased for the second quarter of 2006 by approximately 1.5 MMcf as compared to the second quarter of 2005 as a result of new wells placed into production during the past twelve months. Natural production declines partially offset the Canadian production increases. New productive wells in the Fort Worth Basin in north Texas increased sales volumes by approximately 1.4 MMcf for the second quarter of 2006 compared to the second quarter of 2005. New productive wells in Michigan added an additional 0.2 MMcf of production. U.S. production increases were partially offset by natural production declines.

Oil and condensate sales were $9.5 million for the three months ended June 30, 2006 compared to $6.4 million for the second quarter of 2005. The average realized oil and condensate sales price for the second quarter of 2006 was $62.03 per Bbl compared to $45.01 per Bbl for the second quarter of 2005. Higher realized sales prices increased revenue by $2.4 million. New productive wells in the Fort Worth Basin added 18,000 Bbl to 2006 second quarter oil sales and were partially offset by natural production declines in other producing areas. The net increase in oil production improved revenue and condensate by an additional $0.7 million compared to the prior year quarter.

Our second quarter 2006 NGL sales increased $4.8 million to $6.3 million when compared to the second quarter of 2005. NGL production increased by almost 105,000 Bbl compared to the second quarter of 2005. NGL production in the Fort Worth Basin increased approximately 101,000 Bbl as a result of new productive wells and the processing of gas in our facilities in the Fort Worth Basin.

Operating Expenses

Second quarter 2006 operating expenses were $50.1 million; an increase of $11.4 million over the $38.7 million of operating expenses incurred in the first quarter of 2005.

Oil and Gas Operations Expense


	Three Months Ended
	June 30,
	2006		2005
	(in thousands, except per unit
	amounts)
Oil and gas operations expense
United States	$	18,429	$	13,550
Canada		5,791		3,491

Total	$	24,220	$	17,041

Oil and gas operations expense – per Mcfe
United States	$	1.78	$	1.46
Canada		1.28		1.01
Consolidated		1.62		1.36

Oil and gas operations expense was $24.2 million for the second quarter of 2006. The $7.2 million increase over the prior year quarter included a $2.2 million increase in Canadian production costs. Canadian operating costs were $5.8 million for the second quarter of 2006. Compared to the second quarter of 2005, Canadian production overhead increased $1.3 million. Compensation expense increased over $1.0 million, including $0.3 million for vesting of restricted stock unit and stock option awards, primarily as a result of the addition of 21 employees since June 30, 2005 and the award of restricted stock units in early 2006. Lease operating expenses and workover expenses increased $0.5 million and $0.2 million, respectively, while operation of gas facilities constructed in 2005 contributed to the remainder of the Canadian operating cost increase.

Oil and gas operations expense for the U.S. was $18.4 million for the second quarter of 2006. Second quarter 2006 U.S. operations expense increased $4.9 million from expense of $13.5 million for the second quarter of 2005. The growth of our operations in the Fort Worth Basin increased operating expense approximately $3.5 million. Operation of our pipeline and gas processing facilities increased expense $2.0 million for the second quarter of 2006 and was partially offset by a $0.9 million decrease in third party processing fees compared to the second quarter of 2005. A spill of salt water during the second quarter of 2006 resulted in additional expense for Texas operations of approximately $1.0 million. The addition of 26 employees in Texas contributed $1.2 million of the $1.5 million increase in production overhead expense. Operating expense for Michigan increased $1.9 million for the 2006 second quarter when compared to the second quarter of 2005. Approximately $1.0 million of the increase was the result of environmental clean-up and remediation associated with Michigan gathering lines and facilities and $0.5 million was due to higher lease operating expenses. The remaining $0.4 million increase in expense for the second quarter of 2006 was associated with the operation of compression and processing facilities in Michigan.

Production and Ad Valorem Taxes

Production and ad valorem tax expense for the second quarter of 2006 was $2.0 million compared to $3.3 million for the second quarter of 2005. Production taxes decreased $1.3 million for the second quarter of 2006 as a result of Michigan production tax refunds of approximately $1.7 million for the period from January 2004 through June 2006. Partially offsetting the decrease was a $0.3 million increase in ad valorem taxes for the 2006 period that was primarily the result of additional assets constructed and acquired in conjunction with our drilling program in the Fort Worth Basin.

Depletion, Depreciation and Accretion


	Three Months Ended June 30,
	2006		2005
	(in thousands, except per unit amounts)
Depletion	$	14,874	$	10,860
Depreciation of other fixed assets		2,745		1,875
Accretion		335		282
Total depletion, depreciation and accretion	$	17,954	$	13,017

Average depletion cost per Mcfe	$	1.00	$	0.86

Depletion for the second quarter of 2006 was $14.9 million and $4.0 million higher than depletion for the second quarter of 2005. Higher depletion was primarily as a result of a 15% increase in the depletion rate and a 19% increase in sales volumes. Our depletion rate increased over the second 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 $0.9 million increase in depreciation for the second quarter of 2006 is 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 June 30, 2006 was $5.4 million compared to $4.6 million for the quarter ended June 30, 2005. The most significant increase in general and administrative expense for the second quarter of 2006 was the $1.8 million increase in employee compensation and benefits, including approximately $0.7 million of expense for vesting of restricted stock and stock option awards. The increase was primarily the result of the restricted stock awards made in early 2006 and an additional 36 employees employed in the corporate office as of June 30, 2006 compared to June 30, 2005. Expenses including legal, accounting and engineering fees decreased for the second quarter of 2006 as compared to the 2005 quarter and partially offset the increases in compensation and benefits expense.

Interest Expense

Interest expense for the second quarter of 2006 was $10.6 million, net of capitalized interest of $0.4 million, an increase of $5.8 million compared to the second quarter of 2005. Interest expense for the second quarter of 2006 increased primarily as a result of the $265 million increase in debt outstanding at the end of second quarter of 2006 as compared to the balance at June 30, 2005. 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 rates paid on the Canadian portion of our senior credit facility, during the second quarter of 2006 also contributed to increased interest expense.

Income Tax Expense

Our provision for income taxes decreased $2.6 million from the prior year period to $5.6 million. Our U.S. federal income tax provision of $6.7 million was established using the statutory U.S. federal rate of 35%. The increase of $1.4 million was the result of higher U.S. operating income. A deferred state income tax provision of $0.9 million was recorded as a result of the newly enacted Texas Margin Tax. The Canadian deferred federal tax provision was a tax benefit of approximately $1.9 million that 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.

Summary Financial Data
Six Months Ended June 30, 2006 Compared with the Six Months Ended June 30, 2005


	Six Months Ended June 30,
	2006		2005
	(in thousands)
Total operating revenues	$	189,115	$	123,789
Total operating expenses		100,056		74,259
Operating income		89,167		49,969
Net income		51,143		27,939

We recorded net income of $51.1 million ($0.63 per diluted share) for the six months ended June 30, 2006, compared to net income of $27.9 million ($0.35 per diluted share) for the first half of 2005.

Operating Revenues

Revenues for the first half of 2006 were $189.1 million; a $65.3 million increase from the $123.8 million reported for the six months ended June 30, 2005. Production revenue increased $64.5 million as a result of a 17% increase in sales volumes and a 30% increase in realized sales prices.

Gas, Oil and Related Product Sales

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


	Six Months Ended June 30,
	2006		2005
Natural gas, oil and NGL sales (in thousands)
United States	$	129,293	$	82,935
Canada		57,932		39,748

Total	$	187,225	$	122,683


Product sale revenues (in thousands)
Natural gas sales	$	159,657	$	107,781
Oil and condensate sales		17,926		12,341
NGL sales		9,642		2,561

Total	$	187,225	$	122,683


Average daily sales volume
Natural gas – Mcfd
United States		92,817		85,778
Canada		48,814		38,673

Total		141,631		124,451
Oil and condensate – Bbld
United States		1,639		1,498
Canada		1		—

Total		1,640		1,498
NGL – Bbld
United States		1,279		420
Canada		17		7

Total		1,296		427
Total sales – Mcfed
United States		110,323		97,282
Canada		48,921		38,722

Total		159,244		136,004

Unit prices — including impact of hedges
Natural gas — per Mcf
United States	$	6.06	$	4.38
Canada		6.54		5.67
Consolidated		6.23		4.78

Oil and condensate — per Bbl
United States	$	60.40	$	45.51
Canada		53.21		—
Consolidated		60.39		45.51

NGL — per Bbl
United States	$	41.02	$	33.05
Canada		47.98		38.29
Consolidated		41.12		33.13

Natural gas sales of $160.0 million for the first six months of 2006 were 48% higher than natural gas revenue of $107.8 million for the first half of 2005. A $1.45 per Mcf increase in average realized sales prices increased natural gas revenue $32.5 million. Natural gas revenue also increased $19.3 million because of a 14% increase in sales volumes as compared to the first six months of 2005. Production from our CBM projects in Canada increased for the first half of 2006 by approximately 2.7 MMcf 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 2.7 MMcf and 0.3 MMcf, respectively, for the first half of 2006 compared to the first six months of 2005. U.S. production increases were also partially offset by natural production declines.

Oil and condensate sales were $17.9 million for the six months ended June 30, 2006 compared to $12.3 million for the first half of 2005. Higher realized sales prices increased revenue by $4.0 million. The average realized oil and condensate sales price for the first half of 2006 increased $14.88 per Bbl to $60.39 when compared to prices for the first half of 2005. Higher production, primarily from new productive wells in the Fort Worth Basin, increased revenue by $1.5 million compared to the prior year period.

Our sales of NGLs for the first six months of 2006 increased $7.1 million to $9.6 million when compared to the first half of 2005. NGL production increased by approximately 157,000 Bbl compared to the first half of 2005. NGL production in the Fort Worth Basin increased approximately 143,000 Bbl 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 six months of 2006 were $100.1 million; an increase of $25.8 million over the $74.3 million of operating expenses incurred in the first half of 2005.

Oil and Gas Operations Expense


	Six Months Ended June 30,
	2006		2005
	(in thousands, except per unit amounts)
Oil and gas operations expense
United States	$	34,628	$	27,051
Canada		11,002		6,965

Total	$	45,630	$	34,016

Oil and gas operations expense – per Mcfe
United States	$	1.74	$	1.52
Canada		1.24		0.99
Consolidated		1.59		1.38

Oil and gas operations expense was $45.6 million for the first half of 2006. The $11.6 million increase over the prior year quarter included a $4.0 million increase in Canadian production costs. Canadian operating costs were $11.0 million for the first half of 2006. Compared to the first six months of 2005, production overhead increased $2.7 million. Compensation expense increased over $2.1 million, including $0.4 million for vesting of restricted stock unit and stock option awards, primarily as a result of expense recognized for 2006 award of restricted stock units and an increase of 21 employees. Increased office rent and support expenses further increased production overhead expense by $0.6 million. Operation of gas facilities constructed in 2005 contributed approximately $1.0 million of the expense increase, net of a $0.2 million decrease in processing fees paid to third parties and an increase of over $0.5 million for well workover expenses made up the remainder of the Canadian operating cost increase.

Oil and gas operations expense for U.S. operations increased $7.6 million from the prior year’s period to $34.7 million for the first six months of 2006. The growth of our operations in the Fort Worth Basin increased operating expense approximately $7.2 million. The commencement of operation of our Texas gas facility and pipeline added 2006 operating expense of approximately $3.0 million. A $2.1 million increase in Texas lease operating expense was primarily related to salt water disposal, equipment rentals and clean-up of a salt water spill that occurred during the second quarter. Overhead costs in Texas were the result of increased operating activity and the addition of 36 Texas employees that resulted in $2.0 million of additional expense. Expense for restricted stock and stock option awards to U.S. operations employees contributed approximately $0.3 million of the increase in U.S. operations expense for the 2006 period primarily as a result of the 2006 awards of restricted stock.

Production and Ad Valorem Taxes

Production and ad valorem tax expense for the first six months of 2006 was $6.2 million compared to $6.0 million for the first half of 2005. During the second quarter, we identified approximately $1.7 million in production tax refunds applicable to the period from January 2004 through June 2006 due to the Company from the state of Michigan. Offsetting this decrease were production taxes increases of $1.1 million for the first half of 2006 as a result of higher sales volumes and sales prices during the period. A $0.7 million increase in ad valorem taxes for the 2006 period was primarily the result of additional assets constructed and acquired in conjunction with our drilling program in the Fort Worth Basin.

Depletion, Depreciation and Accretion


	Six Months Ended June
	30,
	2006		2005
	(in thousands, except per unit
	amounts)
Depletion	$	29,671	$	21,598
Depreciation of other fixed assets		5,307		3,238
Accretion		649		553

Total depletion, depreciation and accretion	$	35,627	$	25,389

Average depletion cost per Mcfe	$	1.03	$	0.88

Depletion for the first half of 2006 was $29.7 million, an $8.1 million increase from the comparable 2005 period primarily as a result of a 17% increase in the depletion rate and a 17% increase in sales volumes. Our depletion rate increased over the first half 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 $2.1 million increase in depreciation for the first half of 2006 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 six months ended June 30, 2006 was $11.7 million compared to $7.7 million for the first six months of 2005. The most significant increase in general and administrative expense for the first half of 2006 was the $3.7 million increase in employee compensation and benefits, including approximately $1.5 million of expense for vesting of restricted stock and stock option awards. Restricted stock awards granted in 2006 and the addition of approximately 36 employees in the corporate office since June 30, 2005 were the primary factors increasing compensation expense. Office rent and insurance expenses increased approximately $0.3 million as a result of additional office space and employees.

Interest Expense

Interest expense for the first six months of 2006 was $19.8 million, net of capitalized interest of $0.8 million, an increase of $10.3 million compared to the first half of 2005. Interest expense for the first half 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 primarily as a result of higher debt levels during the first half of 2006. Higher interest rates, including the Canadian prime rates paid on the Canadian debt outstanding under the senior credit facility, during the first half of 2006 also contributed to increased interest expense.

Income Tax Expense

Our provision for income taxes increased $6.3 million from the prior year period as a result of higher pretax income for the first half of 2006 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 $15.2 million was established using the statutory U.S. federal rate of 35%. The increase of $8.4 million was the result of higher U.S. operating income. A deferred state income tax provision of $0.9 million was recorded as a result of the newly enacted Texas Margin Tax. The Canadian deferred federal tax provision was approximately $3.0 million 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 $131.7 million for the six months ended June 30, 2006, an increase of $70.8 million compared to the same period in 2005. The increase was due in part to additional net income for the first half of 2006 as compared to the 2005 period. Net income of $51.1 million was $23.2 million higher than net income for the first half of 2005 primarily as a result of a 17% increase in sales volumes and a 30% increase in realized sales prices. Non-cash expenses including depletion, depreciation and amortization, deferred taxes, stock-based compensation and deferred financing costs increased for 2006 by $20.0 million.

Our principal sources of cash include sales of natural gas, crude oil and NGLs. During the six months ended June 30, 2006, sales under our long-term contracts with price floors covered 21% of our natural gas production. Additionally, price collars covered 50% of our production for the six months ended June 30, 2006. At July 31, 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 remainder of 2006. The natural gas collars have weighted average price floors and ceilings of $7.37 per Mcf and $10.43 per Mcf, respectively, and the crude oil collars have average price floors and ceilings of $50.00 per Bbld and $85.85 per Bbld, respectively. We have hedged approximately 87.4 MMcfd of our estimated 2007 natural gas sales using price collars with average price floors and ceilings of $7.93 per Mcf and $12.18 per Mcf, respectively. Approximately 40.0 MMcfd of our first quarter 2008 natural gas sales are hedged with average price floors and ceilings of $8.50 and $13.68, respectively.

In the first half of 2006, we paid $279.7 million for property and equipment, an increase of $147.2 million when compared to the first half of 2005. 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 $252.8 million, which consisted of $201.4 million expended for exploration and development activities, $41.3 million expended for construction of the our gas processing facility in Hood County, Texas lateral extensions of our North Texas pipeline and $7.9 million expended for Canadian gas processing facilities. Of the $158.5 million incurred for U.S. exploration and development, $141.6 million was spent in Texas, including $14.8 million for non-producing leasehold costs.


	Six Months
	Ended
	June 30, 2006
	(in thousands)
Exploration and development
United States	$	158,496
Canada		42,952

Total exploration and development		201,448
Gas processing and transportation
United States		41,268
Canada		7,870

Total gas processing and transportation		49,138
Corporate and office		2,176

Total plant and equipment costs incurred	$	252,762

Net cash provided by financing activities for the six months ended June 30, 2006 was $150.2 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 June 30, 2006, we were in compliance with such covenants.

In March 2006, we used $70 million of the proceeds of the Senior Subordinated Notes to retire our second lien mortgage notes. 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.

As of June 30, 2006, our borrowing base under our senior secured credit facility was $600 million, of which approximately $375.4 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 June 30, 2006.

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


	June 30,		December 31,
	2006		2005
	(in thousands)
Senior secured credit facility	$	223,557	$	357,788
Senior subordinated notes		350,000		—
Convertible subordinated debentures		147,937		147,881
Second lien mortgage notes payable		—		70,000
Other loans		576		746
Deferred gain – fair interest hedge		—		117

Total debt		722,070		576,532
Stockholders’ equity		499,111		383,615

	$	1,221,181	$	960,147

Financial Position

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

	•		A $10.1 million and $6.1 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 June 30, 2006. The increase in our current derivative assets and decrease in our current derivative liabilities resulted in a $14.6 million decrease in our current deferred tax asset at June 30, 2006.

	•		A $228.8 million increase in our net property, plant and equipment assets includes approximately $252.8 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 has decreased $70.0 million. Our second lien mortgage notes were retired with a portion of the proceeds from the issuance of the senior subordinated notes in March 2006.

	•		A $40.2 million and $4.0 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 June 30, 2006.

	•		Our long-term debt has increased $215.7 million as a result of the issuance of our $350.0 million senior subordinated notes and the $30.9 million increase in the Canadian portion of our senior credit facility to finance Canadian capital expenditures. Partially offsetting these additional borrowings was the repayment of $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.

Contractual Obligations and Commercial Commitments

Information regarding our contractual obligations as of June 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.

Our outstanding long-term debt as of June 30, 2006, was $722.1 million, which includes $350 million in principal amount of Senior Subordinated Notes due in 2016. We pay interest semi-annually at a rate of 7.125% per annum. In March 2006, we used $70 million of the proceeds from issuance of the Senior Subordinated Notes to retire our second lien mortgage notes. In March and April 2006, we used an additional $192.5 million of the proceeds to repay the remaining borrowings outstanding under the U.S. portion of our senior secured credit facility outstanding.

At June 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 $3.6 million remaining in purchase obligations including liabilities of $3.1 million recorded for goods received and services performed at June 30, 2006. Our total remaining purchase obligations for construction and completion of the second gas processing plant at June 30, 2006 were $12.5 million.

We lease drilling rigs from third parties for use in our development and exploration programs. At June 30, 2006 we had the following contracts for use of eight drilling rigs:


Number of Drilling
Rigs	Rate	Term
1	$15,500 per day		One year beginning October 2005
1	$18,500 per day		Two years beginning May 2006
1	$21,500 per day		Three years beginning August 2006
1	$18,500 per day	��	Two years beginning September 2006
1	$21,500 per day		Three years beginning September 2006
1	$18,500 per day		Two years beginning October 2006
1	$21,500 per day		Three years beginning October 2006
1	$21,500 per day		Three years beginning November 2006

Each of the contracts requires payment of the specified day rate for the entire lease term regardless of our utilization of the drilling rigs. We estimate $135.8 million will be paid under the contracts as follows: $24.7 million in 2006; $46.9 million in 2007; $41.1 million in 2008; and, $23.1 million in 2009.

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 $0.3 million in the first half of 2006 for stock option grants.

At January 1, 2006, we had total compensation cost of $3.2 million related to unvested restricted stock and stock unit awards. Additionally, the January 2006 grants of restricted stock and stock units had total compensation cost of $11.7 million at the time of grant. We recorded expense of $2.4 million in the first half of 2006 for restricted stock and stock unit grants.

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.

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 4.4 MMcfd of the natural gas sold under these contracts during the first six months of 2006 were third-party volumes controlled by us.

As of June 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 $7.37 per Mcf and a weighted average ceiling price of $10.43 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 87.4 MMcfd and first quarter 2008 natural gas production of approximately 40.0 MMcfd. Crude oil, condensate and NGL production of 2,000 Bbld has also been hedged for the first half of 2007 with crude oil collars.

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

Weighted Avg

Remaining Contract

Price per

Product

Type

Period

Volume

Mcf or Bbl

Fair Value

(in thousands)

Gas

Collar

Jul 2006-Oct 2006

5,000 Mcfd

5.50– 8.10

)

Gas

Collar

Jul 2006-Oct 2006

5,000 Mcfd

5.50– 8.25

Gas

Collar

Jul 2006-Oct 2006

5,000 Mcfd

6.50– 8.25

320

Gas

Collar

Jul 2006-Oct 2006

10,000 Mcfd

6.50– 8.25

639

Gas

Collar

Jul 2006-Oct 2006

5,000 Mcfd

7.00– 8.35

556

Gas

Collar

Jul 2006-Oct 2006

5,000 Mcfd

7.00– 8.35

556

Gas

Collar

Jul 2006-Oct 2006

5,000 Mcfd

7.00– 8.35

556

Gas

Collar

Jul 2006-Apr 2007

10,000 Mcfd

7.50-11.00

259

Gas

Collar

Jul 2006-Apr 2007

10,000 Mcfd

7.50-11.15

314

Gas

Collar

Jul 2006-Oct 2006

5,000 Mcfd

8.00-10.10

1,074

Gas

Collar

Jul 2006-Oct 2006

5,000 Mcfd

8.00-10.10

1,074

Gas

Collar

Jul 2006-Oct 2006

5,000 Mcfd

8.00-10.20

1,134

Gas

Collar

Jul 2006-Oct 2006

5,000 Mcfd

8.00-10.20

1,134

Gas

Collar

Nov 2006-Mar 2007

10,000 Mcfd

7.50– 9.65

(1,712

)

Gas

Collar

Nov 2006-Mar 2007

10,000 Mcfd

8.00-14.72

114

Gas

Collar

Nov 2006-Mar 2007

10,000 Mcfd

8.00-15.00

310

Gas

Collar

Nov 2006-Mar 2007

10,000 Mcfd

8.50-11.35

(353

)

Gas

Collar

Nov 2006-Mar 2007

10,000 Mcfd

8.50-11.50

(300

)

Gas

Collar

Jan 2007-Dec 2007

10,000 Mcfd

9.00–12.10

2,213

Gas

Collar

Jan 2007-Dec 2007

20,000 Mcfd

9.00–12.10

4,427

Gas

Collar

Apr 2007-Oct 2007

10,000 Mcfd

7.50-11.50

478

Gas

Collar

Apr 2007-Oct 2007

10,000 Mcfd

7.50-11.75

549

Gas

Collar

Apr 2007-Oct 2007

5,000 Mcfd

7.50-11.78

279

Gas

Collar

Apr 2007-Oct 2007

5,000 Mcfd

7.50-11.80

281

Gas

Collar

Apr 2007-Mar 2008

10,000 Mcfd

9.00-12.00

1,868

Gas

Collar

Apr 2007-Mar 2008

10,000 Mcfd

9.00-12.05

1,898

Gas

Collar

Nov 2007-Mar 2008

10,000 Mcfd

8.00-15.00

(389

)

Gas

Collar

Nov 2007-Mar 2008

10,000 Mcfd

8.00-15.65

(276

)

Oil

Collar

Jul 2006-Jun 2007

1,000 Bbld

50.00-85.85

(672

)

Oil

Collar

Jul 2006-Jun 2007

1,000 Bbld

50.00-85.85

(672

)

Total

15,666

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 8.3 MMcfd of our natural gas production was sold under these contracts. The remaining contractual volumes were third-party volumes controlled by us.

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 June 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

Jul 2006

194 Mcfd

7.44

Gas

Sale

Jul 2006

600 Mcfd

7.06

Gas

Sale

Jul 2006-Aug 2006

164 Mcfd

9.10

Gas

Sale

Jul 2006-Dec 2006

426 Mcfd

8.47

140

207

Financial derivatives

Gas

Floating Basis

Jul 2006-May 2007

3,284 Mcfd

(57

)

Gas

Floating Basis

Dec 2006-Jan 2007

968 Mcfd

Gas

Floating Price

Jul 2006

645 Mcfd

(23

)

Gas

Floating Price

Jul 2006

323 Mcfd

)

Gas

Floating Price

Jul 2006-Oct 2006

325 Mcfd

(63

)

Gas

Floating Price

Jul 2006-Oct 2006

325 Mcfd

(108

)

Gas

Floating Price

Nov 2006-Dec 2006

328 Mcfd

(12

)

(263

)

Total-net

(56

)

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 $1.2 million higher and $13.3 million lower as a result of the hedging programs for the first six months of 2006 and 2005, respectively. Marketing revenue was $0.3 million lower as a result of hedging activities for both of the six month periods ending June 30, 2006 and 2005.

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 six months ended June 30, 2006 and 2005.

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 second 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 disclosures.

Changes in Internal Control Over Financial Reporting

There has been no change in our internal control over financial reporting during the quarter ended June 30, 2006 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II – OTHER INFORMATION

ITEM 1. Legal Proceedings

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.

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

The following items of business were presented to the stockholders at the annual meeting held on May 23, 2006.

Election of Directors

At the meeting, three directors were elected to serve terms expiring at the Company’s Annual Meeting of Stockholders to be held in 2009. The vote with respect to the election of these directors was as follows:


			Total Vote
	Total Vote for		Withheld for
Name	Each Director		Each Director
Glenn Darden		71,571,549		522,540

James A. Hughes		71,709,833		384,256

W. Yandell Rogers, III		71,699,146		394,943

Thomas F. Darden, Steven Morris, Anne Darden Self and Mark Warner continue to serve as directors of the Company.

Ratification of Appointment of Independent Registered Public Accounting Firm

At the meeting, the stockholders ratified the appointment by the Company’s Audit Committee of Deloitte & Touche as our independent registered public accounting firm for fiscal year ending December 31, 2006. The vote on such proposal was as follows:


For			71,739,185
Against			269,573
Abstentions			85,331

Approval of Quicksilver’s Amended and Restated Certificate of Incorporation

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


For			71,012,774
Against			988,807
Abstentions			92,508

Approval of Quicksilver’s 2006 Equity Plan

At the meeting, stockholders approved the Quicksilver Resources Inc. 2006 Equity Plan as follows:


For			51,330,378
Against			14,678,613
Abstentions			105,849

ITEM 6. Exhibits:


Exhibit No.			Description
*3.1			Amended and Restated Certificate of Incorporation of Quicksilver Resources Inc. filed with the Secretary of State of the State of Delaware on May 23, 2006.

3.2			Amended and Restated Certificate of Designation of Series A Junior Participating Preferred Stock of Quicksilver Resources Inc. (filed as Exhibit 4.3 to the Company’s Form 8-A/A (Amendment No. 1) filed December 21, 2005 and included herein by reference).

10.1			Quicksilver Resources Inc. 2006 Executive Bonus Program (filed as Exhibit 10.1 to the Company’s Form 8-K filed April 5, 2006 and included herein by reference).

10.2			Quicksilver Resources Inc. 2006 Equity Plan (filed as Appendix C to Quicksilver Resources Inc. Proxy Statement filed April 7, 2006 and included herein by reference).

10.3			Form of Restricted Share Agreement pursuant to the 2006 Equity Plan (filed as Exhibit 10.2 to the Company’s Form 8-K filed May 25, 2006 and included herein by reference).

10.4			Form of Restricted Stock Unit Agreement pursuant to the 2006 Equity Plan (filed as Exhibit 10.3 to the Company’s Form 8-K filed May 25, 2006 and included herein by reference).

10.5			Form of Quicksilver Resources Canada Inc. Restricted Stock Unit Agreement pursuant to the 2006 Equity Plan (filed as Exhibit 10.4 to the Company’s Form 8-K filed May 25, 2006 and included herein by reference).

10.6			Form of Incentive Stock Option Agreement pursuant to the 2006 Equity Plan (filed as Exhibit 10.5 to the Company’s Form 8-K filed May 25, 2006 and included herein by reference).

10.7			Form of Non-Qualified Stock Option Agreement pursuant to the 2006 Equity Plan (filed as Exhibit 10.6 to the Company’s Form 8-K filed May 25, 2006 and included herein by reference).

10.8			Form of Non-Employee Director Restricted Share Agreement pursuant to the 2006 Equity Plan (filed as Exhibit 10.7 to the Company’s Form 8-K filed May 25, 2006 and included herein by reference).

10.9			Form of Non-Employee Director Non-Qualified Stock Option Agreement pursuant to the 2006 Equity Plan (filed as Exhibit 10.8 to the Company’s Form 8-K filed May 25, 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

SIGNATURES

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

Dated: August 4, 2006


		Quicksilver Resources Inc.

		By:		/s/ Glenn Darden Glenn Darden
				President and Chief Executive Officer

		By:		/s/ Philip W. Cook Philip W. Cook
				Senior Vice President – Chief Financial Officer

EXHIBIT INDEX


Exhibit No.			Description
*3.1			Amended and Restated Certificate of Incorporation of Quicksilver Resources Inc. filed with the Secretary of State of the State of Delaware on May 23, 2006.

3.2			Amended and Restated Certificate of Designation of Series A Junior Participating Preferred Stock of Quicksilver Resources Inc. (filed as Exhibit 4.3 to the Company’s Form 8-A/A (Amendment No. 1) filed December 21, 2005 and included herein by reference).

10.1			Quicksilver Resources Inc. 2006 Executive Bonus Program (filed as Exhibit 10.1 to the Company’s Form 8-K filed April 5, 2006 and included herein by reference).

10.2			Quicksilver Resources Inc. 2006 Equity Plan (filed as Appendix C to Quicksilver Resources Inc. Proxy Statement filed April 7, 2006 and included herein by reference).

10.3			Form of Restricted Share Agreement pursuant to the 2006 Equity Plan (filed as Exhibit 10.2 to the Company’s Form 8-K filed May 25, 2006 and included herein by reference).

10.4			Form of Restricted Stock Unit Agreement pursuant to the 2006 Equity Plan (filed as Exhibit 10.3 to the Company’s Form 8-K filed May 25, 2006 and included herein by reference).

10.5			Form of Quicksilver Resources Canada Inc. Restricted Stock Unit Agreement pursuant to the 2006 Equity Plan (filed as Exhibit 10.4 to the Company’s Form 8-K filed May 25, 2006 and included herein by reference).

10.6			Form of Incentive Stock Option Agreement pursuant to the 2006 Equity Plan (filed as Exhibit 10.5 to the Company’s Form 8-K filed May 25, 2006 and included herein by reference).

10.7			Form of Non-Qualified Stock Option Agreement pursuant to the 2006 Equity Plan (filed as Exhibit 10.6 to the Company’s Form 8-K filed May 25, 2006 and included herein by reference).

10.8			Form of Non-Employee Director Restricted Share Agreement pursuant to the 2006 Equity Plan (filed as Exhibit 10.7 to the Company’s Form 8-K filed May 25, 2006 and included herein by reference).

10.9			Form of Non-Employee Director Non-Qualified Stock Option Agreement pursuant to the 2006 Equity Plan (filed as Exhibit 10.8 to the Company’s Form 8-K filed May 25, 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

Positive
Negative
Uncertain
Constraining
Legalese
Litigious
Readability	8th grade Avg

Quicksilver Resources (KWK) Inactive 10-Q2006 Q2 Quarterly report

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