Quicksilver Resources 10Q 2007 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, 2007


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

For the transition period from to

Commission file number: 001-14837

Quicksilver Resources Inc.

(Exact name of registrant as specified in its charter)


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

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

(817) 665-5000

(Registrant’s telephone number, including area code)

None

(Former name, former address and former fiscal year, if changed since last report)

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, 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, 2007

Common Stock, $0.01 par value		78,425,511

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


		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, 2007 and December 31, 2006		4

Condensed Consolidated Statements of Income and Comprehensive Income for the Three and Six Months Ended June 30, 2007 and 2006		5

Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2007 and 2006		6

Notes to Condensed Consolidated Interim Financial Statements		7

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		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 2. Unregistered Sales of Equity Securities and Use of Proceeds		31

Item 4. Submission of Matters to a Vote of Security Holders		32

Item 6. Exhibits		33

Signatures		34
Description of Non-Employee Director Compensation
Awareness Letter of Deloitte & Touche LLP
Certification Pursuant to Section 302
Certification Pursuant to Section 302
Certification Pursuant to Section 906

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, 2007, and the related condensed consolidated statements of income and comprehensive income for the three-month and six-month periods ended June 30, 2007 and 2006 and of cash flows for the six-month periods ended June 30, 2007 and 2006. These interim financial statements are the responsibility of the Company’s management.

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

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

We have previously audited, in accordance with standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of Quicksilver Resources Inc. and subsidiaries as of December 31, 2006, and the related consolidated statements of income and comprehensive income (loss), stockholders’ equity and cash flows for the year then ended (not presented herein); and in our report dated February 28, 2007, (which report expresses an unqualified opinion and includes an explanatory paragraph relating to the adoption of Statement of Financial Accounting Standards No. 123 (Revised 2004),Share-Based Payment). In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2006, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

/s/ DELOITTE & TOUCHE LLP

Fort Worth, Texas
August 9, 2007

QUICKSILVER RESOURCES INC.

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


	June 30,			December 31,
	2007			2006
ASSETS
Current assets
Cash and cash equivalents	$	3,258		$	5,281
Accounts receivable, net of allowance for doubtful accounts		67,076			76,521
Current derivative assets		25,968			64,086
Other current assets		32,091			25,076

Total current assets		128,393			170,964

Investments in and advances to equity affiliates		7,333			7,434

Property, plant and equipment — net (“full cost”)		2,099,055			1,679,280

Non-current derivative assets		—			3,753

Other assets		22,834			21,481

	$	2,257,615		$	1,882,912

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current portion of long-term debt	$	220		$	400
Accounts payable		137,888			109,914
Accrued liabilities		40,887			67,697
Derivative obligations		882			—
Current deferred income taxes		7,923			21,378

Total current liabilities		187,800			199,389

Long-term debt		1,217,472			919,117

Derivative obligations		6,018			—

Asset retirement obligations		28,666			25,058

Deferred income taxes		180,311			156,251

Minority interest		7,892			7,431

Stockholders’ equity
Preferred stock, $0.01 par value, 10,000,000 shares authorized, no shares issued and outstanding		—			—
Common stock, $0.01 par value, 200,000,000 shares authorized and 81,207,935 and 80,181,593 shares issued, respectively		812			802
Paid in capital in excess of par value		256,528			238,063
Treasury stock of 2,600,536 and 2,579,671 shares, respectively		(11,558	)		(10,737	)
Accumulated other comprehensive income		41,998			60,099
Retained earnings		341,676			287,439

Total stockholders’ equity		629,456			575,666

	$	2,257,615		$	1,882,912

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,
	2007			2006			2007			2006
Revenues
Oil, gas and related product sales	$	133,959		$	88,536		$	247,251		$	187,225
Other revenue		2,439			929			5,727			1,890

Total revenues		136,398			89,465			252,978			189,115

Expenses
Oil and gas production costs		31,989			24,220			60,558			45,630
Production and ad valorem taxes		4,212			1,986			8,702			6,159
Other operating costs		301			546			1,085			949
Depletion, depreciation and accretion		27,905			17,954			52,499			35,627
Provision for bad debts		—			—			(264	)		—
General and administrative		10,298			5,437			20,260			11,691

Total expenses		74,705			50,143			142,840			100,056

Income (loss) from equity affiliates		282			(80	)		397			108


Operating income		61,975			39,242			110,535			89,167

Other income-net		(870	)		(498	)		(1,471	)		(848	)
Interest expense		18,216			10,566			33,168			19,768


Income before income taxes and minority interest		44,629			29,174			78,838			70,247
Income tax expense		12,770			5,555			24,065			19,093
Minority interest		128			11			191			11


Net income	$	31,731		$	23,608		$	54,582		$	51,143


Other comprehensive income, net of income taxes
Reclassification adjustments — hedge settlements		(4,643	)		(2,324	)		(14,153	)		(830	)
Unrealized gain (loss) on derivative instruments		16,751			16,094			(18,928	)		39,566
Foreign currency translation adjustments		13,356			4,907			14,980			4,911

Comprehensive income	$	57,195		$	42,285		$	36,481		$	94,790


Basic net income per common share	$	0.41		$	0.31		$	0.71		$	0.67
Diluted net income per common share	$	0.38		$	0.29		$	0.66		$	0.63

Weighted average common shares outstanding
Basic		77,594			76,723			77,396			76,383
Diluted		84,127			83,089			84,029			82,949

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,
	2007			2006
Operating activities:
Net income	$	54,582		$	51,143
Charges and credits to net income not affecting cash
Depletion,depreciation and accretion		52,499			35,627
Deferred income taxes		23,907			19,063
Non-cash compensation		6,288			2,819
Amortization of deferred loan costs		929			1,255
Non-cash (gain) loss from hedging activities		(981	)		77
Income from equity affiliates		(397	)		(108	)
Minority interest		191			11
Other non-cash items		1,555			129
Changes in assets and liabilities
Accounts receivable		9,709			27,369
Current and other assets		(8,057	)		(13,674	)
Accounts payable		8,992			(1,423	)
Accrued and other liabilities		(2,250	)		9,502

Net cash provided by operating activities		146,967			131,790


Investing activities:
Purchases of property, plant and equipment		(435,086	)		(279,713	)
Return of investment in equity affiliates		167			365
Proceeds from sales of properties		162			4,854

Net cash used for investing activities		(434,757	)		(274,494	)


Financing activities:
Issuance of debt		312,157			408,742
Repayments of debt		(37,261	)		(271,719	)
Debt issuance costs		(2,546	)		(9,192	)
Proceeds from exercise of stock options		12,187			18,366
Minority interest contributions		167			4,506
Purchase of treasury stock		(821	)		(479	)

Net cash provided by financing activities		283,883			150,224


Effect of exchange rates on cash		1,884			(120	)


Net (decrease) increase in cash and cash equivalents		(2,023	)		7,400

Cash and cash equivalents at beginning of period		5,281			14,318


Cash and cash equivalents at end of period	$	3,258		$	21,718

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 the Company’s management, the accompanying condensed consolidated interim financial statements contain all adjustments necessary to present fairly the financial position of the Company as of June 30, 2007 and its income and comprehensive income for the three-month and six-month periods ended June 30, 2007 and 2006 and cash flows for the six-month periods ended June 30, 2007 and 2006. All such adjustments are of a normal recurring nature. The results for interim periods are not necessarily indicative of annual results.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during each reporting period. Management believes its estimates and assumptions are reasonable; however, such estimates and assumptions are subject to a number of risks and uncertainties, which may cause actual results to differ materially from the Company’s estimates.

Certain disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted. Accordingly, these financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Company’s Form 10-K for the year ended December 31, 2006.

Net Income per Common Share

Basic net income per common share is computed by dividing the net income attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period. Diluted net income 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, 2007 and 2006. Outstanding options to purchase 2,401 shares were excluded from the diluted net income per share calculation for the periods ended June 30, 2007 and 2006 as those options were out of the money and, therefore, considered to be antidilutive.


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2007		2006		2007		2006
	(in thousands, except per share amounts)
Net income	$	31,731	$	23,608	$	54,582	$	51,143
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	$	32,206	$	24,083	$	55,532	$	52,093


Weighted average common shares-basic		77,594		76,723		77,396		76,383

Effect of dilutive securities:
Employee stock options		816		1,110		905		1,327
Employee stock awards		809		348		820		331
Contingently convertible debentures		4,908		4,908		4,908		4,908

Weighted average common shares-diluted		84,127		83,089		84,029		82,949


Basic net income per common share	$	0.41	$	0.31	$	0.71	$	0.67

Diluted net income per common share	$	0.38	$	0.29	$	0.66	$	0.63

Recently Issued Accounting Standards

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

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

The Company’s subsidiary, Quicksilver Resources Canada Inc. (“QRCI”), because of its Canadian tax pool balances, remains subject to examination by the Canada Revenue Agency (“Revenue Canada”) for the years 1999 through 2006. During the second quarter of 2007, Revenue Canada completed its review of the Scientific Research and Experimental Development (“SRED”) credits claimed by QRCI for the years 2002 and 2003 and accepted QRCI’s claim for the SRED credits. As a result, QRCI recognized credits of approximately $1.1 million in the second quarter of 2007.

The prior Michigan Single Business Tax was not considered to meet the definition of an income tax under SFAS No. 109 and, therefore, no uncertain tax positions have been recognized for this tax. In July 2007, the Michigan Single Business Tax was replaced with a business income tax and a modified gross receipts tax effective for tax years beginning after January 1, 2008. These new taxes will meet the definition of an income tax under SFAS No. 109. The Company has not recognized any uncertain tax positions with these new taxes.

In May 2006, the Texas business tax was amended by replacing the taxable capital and earned surplus components of the old franchise tax with a new “taxable margin” component effective for taxable years ending December 31, 2007. The Company has not recognized any unrecognized tax benefits for this new Texas “taxable margin” tax.

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

On April 30, 2007, the FASB issued FASB Staff Position (“FSP”) No. FIN 39-1,Amendment of FASB Interpretation No. 39. The FSP amends paragraph 3 of FIN No. 39 to replace the terms “conditional contracts” and “exchange contracts” with the term “derivative instruments” as defined in FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities. It also amends paragraph 10 of Interpretation 39 to permit a reporting entity to offset fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement that have been offset in accordance with that paragraph. The guidance in this FSP is effective for fiscal years beginning after November 15, 2007 and an entity shall recognize the effects of applying this FSP as a change in accounting principle through retrospective application for all financial statements presented unless it is impracticable to do so. The Company is evaluating the FSP’s guidance, but does not believe its adoption will have a material impact on the Company’s financial position, results of operations or cash flows.

2. HEDGING

The estimated fair values of all hedge derivatives and the associated fixed price firm sale commitments as of June 30, 2007 and December 31, 2006 are provided below. The carrying values of these financial instruments and firm commitments are equal to the estimated fair values as of the dates presented. The assets and liabilities recorded in the balance sheet are netted where derivatives with both gain and loss positions are held with a single counterparty under a master netting arrangement. A non-cash gain of $1.0 million was recorded other revenue for the 2007 period as a result of ineffectiveness from the Company’s Canadian cash flow hedges caused by variances in the price differentials for Canadian prices and NYMEX prices.


	June 30,		December 31,
	2007		2006
	(in thousands)
Derivative assets:
Fixed price sale commitments	$	11	$	53
Natural gas basis swaps		—		159
Crude oil financial collars		242		689
Natural gas financial swaps		—		1,009
Natural gas financial collars		27,971		65,982

	$	28,224	$	67,892


Derivative liabilities:
Floating price natural gas financial swaps	$	10	$	53
Natural gas basis swaps		343		—
NGL financial swaps		712		—
Crude oil financial collars		719		—
Natural gas financial swaps		3,779		—
Natural gas financial collars		3,593		—

	$	9,156	$	53

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

At June 30, 2007, net cash flow hedge gains of $24.0 million have been classified as current based on the maturity of the derivative instruments. The Company estimates $16.1 million of after-tax gains will be reclassified from other comprehensive income over the next twelve months.

3. LONG-TERM DEBT

Long-term debt consists of:


	June 30,			December 31,
	2007			2006
	(in thousands)
Senior secured credit facility	$	719,422		$	421,123
Senior subordinated notes		350,000			350,000
Contingently convertible debentures, net of unamortized discount		148,050			147,994
Other loans		220			400

		1,217,692			919,517
Less current maturities		(220	)		(400	)

	$	1,217,472		$	919,117

On February 9, 2007, the Company amended its senior secured credit facility to extend its maturity to February 9, 2012 and to provide for revolving loans, swingline loans and letters of credit from time to time in an aggregate amount not to exceed the borrowing base, which is calculated based on several factors and is initially equal to $850 million. The borrowing base is subject to annual redeterminations and certain other redeterminations. The lenders have agreed to initial revolving credit commitments in

an aggregate amount equal to $1.2 billion, and the Company has an option to increase the facility to $1.45 billion with the consent of the lenders. The lenders’ commitments under the facility are allocated between U.S. and Canadian funds, with the U.S. funds available for borrowing by the Company and Canadian and U.S. funds being available for borrowing by the Company’s Canadian subsidiary, QRCI. The facility offers the option to extend the maturity up to two additional years with requisite lender consent. U.S. borrowings under the facility are guaranteed by most of Quicksilver’s domestic subsidiaries and are secured by, among other things, Quicksilver’s and its domestic subsidiaries’ oil and gas properties. Canadian borrowings under the facility are guaranteed by Quicksilver and most of Quicksilver’s domestic subsidiaries and are secured by, among other things, QRCI’s, Quicksilver’s and certain of Quicksilver’s domestic subsidiaries’ oil and gas properties. The loan agreements for the credit facility prohibit the declaration or payment of dividends by the Company and contain certain financial covenants, which, among other things, require the maintenance of a minimum current ratio and a minimum earnings (before interest, taxes, depreciation, depletion and amortization, non-cash income and expense, and exploration costs) to interest expense ratio. At June 30, 2007, the Company was in compliance with such covenants.

The terms and conditions of the Senior Subordinated Notes require the Company to comply with certain covenants, which primarily limit certain activities, including, among other things, levels of indebtedness, restricted payments, payments of dividends, capital stock repurchases, investments, liens, restrictions on restricted subsidiaries to make distributions, affiliate transactions and mergers and consolidations. At June 30, 2007, the Company was in compliance with such covenants.

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

4. 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, 2007 and 2006, 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, 2007 and December 31, 2006, retirement obligations classified as current were $0.2 million. The following table provides a reconciliation of the changes in the estimated asset retirement obligation for the six-month periods ended June 30, 2007 and 2006.


	Six Months Ended June 30,
	2007			2006
	(in thousands)
Beginning asset retirement obligation	$	25,206		$	20,965
Additional liability incurred		1,845			1,186
Accretion expense		764			649
Change in estimates		—			29
(Gain) loss on settlement of liability		(3	)		96
Asset retirement costs incurred		3			(122	)
Currency translation adjustment		1,000			326

Ending asset retirement obligation	$	28,815		$	23,129

5. COMMITMENTS AND CONTINGENCIES

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


2007	$	19,235
2008		29,106
2009		29,091
2010		2,753

	$	80,185

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


2008	$	4,392
2009		9,506
2010		10,494
2011		10,494
Thereafter		70,154

	$	105,040

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 alleged 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 had yet to be determined. The pleadings of the plaintiffs sought damages in an unspecified amount and injunctive relief against future underpayments. On April 20, 2007, based upon the stipulation of the parties, the Circuit Court dismissed the case, including all claims and counterclaims, without prejudice.

On November 7, 2001, Quicksilver Resources Inc. filed a lawsuit against CMS Marketing Services and Trading Company (“CMS”) in the 236^th Judicial District Court of Tarrant County, Texas. The suit alleged that CMS committed fraud when it entered into a 10-year contract with the Company on March 1, 1999 for the purchase and sale of 10,000 MMBtud of natural gas at a minimum price of $2.47 per MMBtu and breached the contract afterward by failing to comply with a provision of the contract requiring that, if the gas could be scheduled or delivered to derive additional value, the parties would share equally in the additional revenue. The Company sought unspecified damages and rescission of the contract. On May 15, 2007, the Court upheld a jury finding against CMS on the fraudulent inducement claim, rescinded the contract and rendered the contract void beginning May 15, 2007. CMS is appealing the judgment. The Company has also appealed the Court’s judgment because it believes the contract is voidab initiorather than from the date of judgment entry.

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

6. 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. The Company adopted SFAS 123(R) on January 1, 2006. 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) has been attributed to periods beginning January 1, 2006 using the attribution method that was used under SFAS 123. At January 1, 2007, the Company had total compensation cost of $0.5 million related to unvested stock options with a weighted average remaining vesting period of 1.2 years. The Company recorded expense of $0.2 million and $0.3 million for stock options in the first six months of 2007 and 2006, respectively. At June 30, 2007, the Company had $0.3 million of expense remaining in unrecognized compensation cost for the unvested portion of stock options awarded prior to 2006.

At January 1, 2007 and 2006, the Company had total compensation cost of $14.7 million and $3.3 million, respectively, related to unvested restricted stock and stock unit awards. Additionally, grants of restricted stock and stock units through June 30, 2007 had total compensation cost of $15.5 million at the time of grant. During the first six months of 2007 and 2006, the Company recognized $6.1 million and $2.4 million respectively, of expense for vesting of restricted stock and stock units. Total unvested compensation cost was $24.1 million at June 30, 2007 with a weighted average remaining vesting period of 1.2 years.

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 six-month periods ended June 30, 2007 and 2006.

Employee Stock Plans

2006 Equity Plan

On March 17, 2006, the Board of Directors of the Company approved the Company’s 2006 Equity Plan, subject to stockholder approval, and recommended that the 2006 Equity Plan be submitted to the Company’s stockholders at the annual meeting of stockholders in 2006. On May 23, 2006, the Company’s stockholders approved the 2006 Equity Plan. Upon approval of the 2006 Equity Plan, 7.0 million shares of common stock were reserved for issuance pursuant to grants of stock options, appreciation rights, restricted shares, restricted stock units, performance shares, performance units and senior executive plan bonuses. Executive officers, other employees, consultants and non-employee directors of the Company or a subsidiary of the Company are eligible to participate in the 2006 Equity Plan. Under the terms of the 2006 Equity Plan, options may be granted at an exercise price that is not less than 100% of the fair market value on the date of grant and may not be exercised more than ten years from the date of grant. Upon approval of the 2006 Equity Plan, the Company ceased to grant additional awards under the 1999 Stock Option and Retention Stock Plan and the 2004 Non-Employee Director Equity Plan.

Stock Options

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


				Wtd Avg
				Exercise
	Shares			Price
Outstanding at beginning of year		1,689,190		$	16.84
Granted		—			—
Exercised		(638,194	)		16.91
Forfeited		(8,190	)		11.01

Outstanding at period end		1,042,806		$	16.85


Exercisable at June 30, 2007		767,279		$	17.95

Vested or expected to vest at June 30, 2007		1,302,605		$	16.79

Stock options vested and exercisable at June 30, 2007 had an aggregate intrinsic value of $21.4 million and a weighted average remaining term of 2.0 years.

Cash received from the exercise of stock options totaled $12.2 million and $18.4 million for the first six months of 2007 and 2006, respectively. The intrinsic value of the options exercised in the first six months of 2007 was $15.4 million.

Restricted Stock

During the first six months of 2007, the Company awarded 410,162 shares of restricted stock and stock units to employees at a weighted average market price of $36.71 per share. The shares and units awarded vest ratably over a three-year period. Each of the four non-employee directors of the Company received a grant of 1,740 restricted shares at a market value of $34.48 per share. These restricted shares will become fully vested one year from the date of grant provided the non-employee director remains a member of the Board of Directors of the Company. An additional 893 shares at a market value of $43.69 per share were granted to each of the four non-employee directors on May 23, 2007. These restricted shares will vest ratably over a three-year period from the date of grant provided the non-employee director remains a member of the Board of Directors of the Company.

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


				Wtd Avg
				Grant Date Fair
	Shares			Value
Outstanding at beginning of year		511,873		$	38.35
Granted		420,694			36.73
Vested		(94,583	)		39.82
Forfeited		(32,546	)		36.39

Outstanding at period end		805,438		$	37.41

The total fair value of shares and units vested during the six months ended June 30, 2007 was $3.7 million.

7. 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, 2007
					Non-					Quicksilver
	Quicksilver		Guarantor		Guarantor					Resources Inc.
	Resources Inc.		Subsidiaries		Subsidiaries		Eliminations			Consolidated
	(in thousands)
ASSETS
Current assets	$	158,611	$	268,141	$	87,591	$	(385,950	)	$	128,393
Investments in subsidiaries (equity method)		600,553		178,314		2		(771,536	)		7,333
Property and equipment, net		1,343,598		87,662		667,795		—			2,099,055
Other assets		21,481		38,279		1,353		(38,279	)		22,834

Total assets	$	2,124,243	$	572,396	$	756,741	$	(1,195,765	)	$	2,257,615


LIABILITIES
Current liabilities	$	394,332	$	135,751	$	43,667	$	(385,950	)	$	187,800
Non-current liabilities		1,100,455		24,427		345,864		(38,279	)		1,432,467
Minority interest		—		7,892		—		—			7,892
Stockholders’ equity		629,456		404,326		367,210		(771,536	)		629,456

Total liabilities and stockholders’ equity	$	2,124,243	$	572,396	$	756,741	$	(1,195,765	)	$	2,257,615


	December 31, 2006
					Non-						Quicksilver
	Quicksilver		Guarantor		Guarantor						Resources Inc.
	Resources Inc.		Subsidiaries		Subsidiaries		Eliminations				Consolidated
	(in thousands)
ASSETS
Current assets	$	165,061	$	250,928	$	78,531	$	(323,556	)		$	170,964
Investments in subsidiaries (equity method)		510,548		131,750		—		(634,864	)	��		7,434
Property and equipment, net		1,043,037		87,025		549,218		—				1,679,280
Other assets		22,397		—		2,837		—				25,234

Total assets	$	1,741,043	$	469,703	$	630,586	$	(958,420	)		$	1,882,912

LIABILITIES
Current liabilities	$	368,073	$	91,414	$	63,458	$	(323,556	)		$	199,389
Non-current liabilities		797,304		24,577		278,545		—				1,100,426
Minority interest		—		—		7,431		—				7,431
Stockholders’ equity		575,666		353,712		281,152		(634,864	)			575,666

Total liabilities and stockholders’ equity	$	1,741,043	$	469,703	$	630,586	$	(958,420	)		$	1,882,912

Condensed Consolidating Statements of Income


	For the Three Months Ended June 30, 2007
						Non-					Quicksilver
	Quicksilver		Guarantor			Guarantor					Resources Inc.
	Resources Inc.		Subsidiaries			Subsidiaries		Eliminations			Consolidated
	(in thousands)
Revenues	$	88,770	$	9,878		$	44,158	$	(6,408	)	$	136,398
Operating expenses		54,687		5,056			21,370		(6,408	)		74,705
Income from equity affiliates		16		266			—		—			282

Income from operations		34,099		5,088			22,788		—			61,975
Equity in net earnings of subsidiaries		19,615		2,972			—		(22,587	)		—
Interest expense and other		13,705		(80	)		3,849		—			17,474
Income tax provision		8,278		1,809			2,683		—			12,770

Net income	$	31,731	$	6,331		$	16,256	$	(22,587	)	$	31,731


	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 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 Six Months Ended June 30, 2007
						Non-					Quicksilver
	Quicksilver		Guarantor			Guarantor					Resources Inc.
	Resources Inc.		Subsidiaries			Subsidiaries		Eliminations			Consolidated
	(in thousands)
Revenues	$	159,638	$	18,634		$	85,592	$	(10,886	)	$	252,978
Operating expenses		101,148		9,499			43,079		(10,886	)		142,840
Income from equity affiliates		22		375			—		—			397

Income from operations		58,512		9,510			42,513		—			110,535
Equity in net earnings of subsidiaries		34,351		4,253			—		(38,604	)		—
Interest expense and other		24,826		(90	)		7,152		—			31,888
Income tax provision		13,455		3,360			7,250		—			24,065

Net income	$	54,582	$	10,493		$	28,111	$	(38,604	)	$	54,582


	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

Condensed Consolidating Statements of Cash Flows


	For the Six Months Ended June 30, 2007
							Non-						Quicksilver
	Quicksilver			Guarantor			Guarantor						Resources Inc.
	Resources Inc.			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(in thousands)
Cash flow provided by operations	$	70,544		$	1,581		$	74,842		$	—		$	146,967
Cash flow used for investing activities		(363,182	)		(47,649	)		(114,882	)		90,956			(434,757	)
Cash flow provided by financing activities		292,304			46,068			36,467			(90,956	)		283,883
Effect of exchange rates on cash		390			—			1,494			—			1,884

Net increase (decrease) in cash & equivalents		56			—			(2,079	)		—			(2,023	)
Cash & equivalents at beginning of period		83			—			5,198			—			5,281

Cash & equivalents at end of period	$	139		$	—		$	3,119		$	—		$	3,258


	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 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

8. SUPPLEMENTAL CASH FLOW INFORMATION

Cash paid for interest and income taxes is as follows:


	Six Months Ended June 30,
	2007		2006
	(in thousands)
Interest	$	32,383	$	12,982
Income taxes	$	695	$	3

Other non-cash transactions are as follows:


	Six Months Ended June 30,
	2007			2006
	(in thousands)
Noncash investing activities – changes in working capital associated with property and equipment	$	(5,582	)	$	(26,950	)

9. RELATED PARTY TRANSACTIONS

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

Quicksilver and its associated entities paid $1.1 million and $0.6 million for rent in the first six months of 2007 and 2006, respectively, for rent on buildings owned by Pennsylvania Avenue LP (“PALP”), a Mercury affiliate, and WFMG, L.P., a PALP affiliate. Rental rates are determined based on comparable rates charged by third parties. Payments received during 2007 from Mercury for sublease rentals, employee insurance coverage and administrative services totaled $0.1 million.

During the first six months of each of 2007 and 2006, the Company paid Regal Jets, LLC (formerly known as 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.

10. SEGMENT INFORMATION

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


	United
	States		Canada		Corporate			Consolidated
	(in thousands)
For the Three Months Ended
June 30, 2007
Revenues	$	99,290	$	37,108	$	—		$	136,398
Depletion, depreciation and accretion		18,529		9,131		245			27,905
Operating income		52,391		20,127		(10,543	)		61,975
Property and equipment costs incurred		232,457		14,104		365			246,926

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

For the Six Months Ended

June 30, 2007
Revenues	$	179,719	$	73,259	$	—		$	252,978
Depletion, depreciation and accretion		34,145		17,883		471			52,499
Operating income		92,161		39,105		(20,731	)		110,535
Property and equipment costs incurred		394,871		33,663		970			429,504

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

Fixed Assets – net
June 30, 2007	$	1,546,495	$	548,974	$	3,586		$	2,099,055

December 31, 2006	$	1,258,807	$	417,199	$	3,274		$	1,679,280

11. QUICKSILVER GAS SERVICES LP

On August 6, 2007, the Company’s wholly-owned subsidiary, Quicksilver Gas Services LP (“QGSLP”), priced its underwritten initial public offering. QGSLP sold 5,000,000 common units representing approximately 21.3% of the limited partner interests in QGSLP, with gross proceeds of approximately $105 million. The Company retained common units and subordinated units representing an approximate 73.2% limited partner interest, and the entire 2% general partner interest in the publicly-traded partnership. Should QGSLP sell an additional 750,000 common units to its underwriters to cover over-allotments, the Company’s common and subordinated units will represent an approximate 70.9% limited partner interest.

QGSLP engages in the business of gathering and processing natural gas produced from the Barnett Shale formation in the Fort Worth Basin in north Texas.

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 expectations or forecasts of future events. Words such as “may,” “assume,” “forecast,” “position,” “predict,” “strategy,” “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe,” “project,” “budget,” “potential,” or “continue,” and similar expressions are used to identify forward-looking statements. They can be affected by assumptions used or by known or unknown risks or uncertainties. Consequently, no forward-looking statements can be guaranteed. Actual results may vary materially. You are cautioned not to place undue reliance on any forward-looking statements. You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include:

	•		changes in general economic conditions;

	•		fluctuations in natural gas and crude oil prices;

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

	•		effects of hedging natural gas and crude oil prices;

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

	•		competitive conditions in our industry;

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

	•		changes in the availability and cost of capital;

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

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

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

	•		the effects of existing or future litigation; and

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

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

RESULTS OF OPERATIONS

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


	Three Months Ended
	June 30,
	2007		2006
	(in thousands)
Total operating revenues	$	136,398	$	89,465
Total operating expenses		74,705		50,143
Operating income		61,975		39,242
Net income		31,731		23,608

We recorded net income of $31.7 million ($0.38 per diluted share) for the three months ended June 30, 2007, compared to net income of $23.6 million ($0.29 per diluted share) for the second quarter of 2006.

Operating Revenues

Revenues for the second quarter of 2007 were $136.4 million; a $46.9 million increase from the $89.5 million reported for the three months ended June 30, 2006. Production revenue increased $45.4 million as a result of a 27% increase in sales volumes and a 19% 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, 2007 and 2006 are as follows:


	Three Months Ended
	June 30,
	2007		2006
Natural gas, oil and NGL sales (in thousands)
United States	$	97,967	$	62,608
Canada		35,992		25,928

Total	$	133,959	$	88,536


Product sale revenues (in thousands)
Natural gas sales	$	102,308	$	72,735
Oil and condensate sales		9,374		9,533
NGL sales		22,277		6,268

Total	$	133,959	$	88,536


Average daily sales volume
Natural gas – Mcfd
United States		107,740		94,585
Canada		53,745		49,624

Total		161,485		144,209
Oil and condensate – Bbld
United States		1,737		1,688
Canada		—		1

Total		1,737		1,689
NGL – Bbld
United States		6,031		1,623
Canada		11		25

Total		6,042		1,648


	Three Months Ended
	June 30,
	2007		2006
Total sales – Mcfed
United States		154,349		114,451
Canada		53,812		49,780

Total		208,161		164,231

Unit prices — including impact of hedges
Natural gas — per Mcf
United States	$	6.77	$	5.45
Canada		7.35		5.71
Consolidated		6.96		5.54

Oil and condensate — per Bbl
United States	$	59.30	$	62.03
Canada		—		51.43
Consolidated		59.30		62.03

NGL — per Bbl
United States	$	40.48	$	41.55
Canada		58.71		57.36
Consolidated		40.52		41.80

Natural gas sales of $102.3 million for the second quarter of 2007 were 41% higher than the $72.7 million of natural gas sales for the second quarter of 2006. Natural gas sales increased $18.6 million as a result of a $1.42 per Mcf increase in realized natural gas prices for the second quarter of 2007 as compared to the 2006 period. A 12% increase in sales volumes for the second quarter of 2007 as compared to the second quarter of 2006 further increased natural gas sales $10.9 million. Production from our coal bed methane (“CBM”) projects in Canada increased for the second quarter of 2007 by approximately 1.0 Bcf as compared to the second quarter of 2006 as a result of new wells placed into production subsequent to the second quarter of 2006. Natural production declines partially offset the Canadian production increases. New wells in the Fort Worth Basin placed into production subsequent to the first quarter of 2006, increased sales volumes by approximately 1.3 Bcf for the second quarter of 2007 compared to the second quarter of 2006. The remainder of the change in U.S. natural gas production includes production from new wells placed into production subsequent to the second quarter of 2006 in all other U.S. operating areas, primarily Michigan, and decreased production associated with natural production declines.

Our second quarter 2007 NGL sales increased $16.0 million to $22.3 million as compared to the second quarter of 2006. NGL sales increased $16.2 million as a result of higher production volumes for the second quarter of 2007. Second quarter 2007 NGL production in the Fort Worth Basin increased approximately 400 MBbl. The increase was due to new wells placed into production subsequent to the second quarter of 2006 and improved NGL recovery from our newest processing facility in the Fort Worth Basin that began operations in March 2007. NGL pricing for the second quarter of 2007 was lower by $1.28 per Bbl and reduced sales by $0.2 million.

Other Revenues

Other revenue for the second quarter of 2007 was $2.4 million consisting primarily of revenue from processing and gathering natural gas which was $1.4 million for the second quarter of 2007 as compared to $0.6 million for the second quarter of 2006. The increase of $0.8 million was primarily the result of revenue earned from the processing of third-party natural gas through our gas processing facility in the Fort Worth Basin which began operating in April 2006 and an increase in the capacity of our gathering system in the Fort Worth Basin. A $1.0 million increase in other revenue was the result of ineffectiveness of our cash flow hedges that hedge future Canadian sales caused by variances in the price differentials for Canadian prices and NYMEX prices. A decrease in marketing revenue partially offset these higher revenues for the second quarter of 2007.

Operating Expenses

Second quarter 2007 operating expenses were $74.7 million; an increase of $24.6 million over the $50.1 million of operating expenses recorded in the second quarter of 2006.

Oil and Gas Operations Expense


	Three Months Ended
	June 30,
	2007		2006
	(in thousands, except per unit
	amounts)
Oil and gas operations expense
United States	$	25,027	$	18,429
Canada		6,962		5,791

Total	$	31,989	$	24,220

Oil and gas operations expense – per Mcfe
United States	$	1.78	$	1.77
Canada		1.42		1.28
Consolidated		1.69		1.62

Oil and gas operations expense was $32.0 million for the second quarter of 2007. The $7.8 million increase over the prior year quarter included increases of $6.6 million and $1.2 million for U.S. and Canadian production costs, respectively.

Oil and gas operations expense for the U.S. was $25.0 million for the second quarter of 2007. Second quarter 2007 U.S. production expense increased $6.6 million compared to production expense of $18.4 million for the second quarter of 2006. The growth of our operations in the Fort Worth Basin increased operating expense approximately $6.2 million for the second quarter 2007 compared to the 2006 period. A $2.0 million increase in Texas production overhead expense consisted of $0.9 million for compensation expense and $1.1 million in higher field office expenses, which resulted from the addition of operations personnel and an increase in operating activities as compared to the second quarter of 2006. Texas lease operating expenses for the second quarter of 2007 increased $2.9 million as compared to the 2006 quarter primarily because of the increasing rate of new wells placed into production. Compensation expense for all other U.S. field personnel in 2007 increased approximately $0.4 million, which included $0.1 million for vesting of restricted stock awards.

Canadian operating costs were $7.0 million for the second quarter of 2007. Compared to the second quarter of 2006, oil and gas production expense increased approximately $1.2 million for the second quarter of 2007. Compensation expense increased $1.1 million for the second quarter of 2007 as compared to the 2006 quarter. The increase consisted of $0.3 million of expense for non-compete payments made to senior management no longer employed by us, additional stock compensation expense and additional company contributions to employee retirement savings plans and $0.8 million for additional salary and benefits primarily related to a 9% increase in personnel over the past year as compared to the second quarter of 2006.

Production and Ad Valorem Taxes

Production and ad valorem tax expense for the second quarter of 2007 was $4.2 million compared to $2.0 million for the second quarter of 2006. Second quarter 2007 production taxes increased $1.7 million as a result of higher sales volumes and prices in the 2007 second quarter as compared to the second quarter of 2006. Ad valorem taxes increased $0.5 million primarily as 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,
	2007		2006
	(in thousands, except per unit
	amounts)
Depletion	$	22,858	$	14,874
Depreciation of other fixed assets		4,644		2,745
Accretion		403		335

Total depletion, depreciation and accretion	$	27,905	$	17,954

Average depletion cost per Mcfe	$	1.21	$	1.00

Depletion for the second quarter of 2007 was $22.9 million, which was $8.0 million higher than depletion for the second quarter of 2006. Higher depletion resulted from a 21% increase in the depletion rate and a 19% increase in sales volumes. Our higher depletion rate for the second quarter of 2007 resulted from significant actual and estimated future capital expenditures and proved reserves added for our Canadian CBM and Forth Worth Basin properties. The $1.9 million increase in depreciation for the second quarter of 2007 as compared to the 2006 quarter was primarily associated with new gas processing facilities in Canada and Fort Worth Basin field compression and gas processing facilities and gathering system assets.

General and Administrative Expense

General and administrative expense for the three months ended June 30, 2007 was $10.3 million compared to $5.4 million for the quarter ended June 30, 2006. The most significant increase in general and administrative expense for the second quarter of 2007 was a $3.2 million increase in employee compensation and benefits, including approximately $1.3 million of non-cash expense for vesting of restricted stock and stock option awards. Office expenses, including rent, and information technology expenses increased approximately $0.5 million for the 2007 second quarter as compared to the prior year quarter. These increases were, in large part, the result of a 48% increase in personnel working in the corporate office at June 30, 2007 as compared to June 30, 2006 and vesting of restricted stock granted in the first quarter of 2007. The remaining $1.2 million increase in general and administrative expense included $0.6 million for legal, accounting and other professional fees and $0.6 million spread over several categories.

Interest Expense

Interest expense for the second quarter of 2007 was $18.2 million, net of capitalized interest of $0.2 million, which was an increase of $7.6 million compared to the second quarter of 2006. Since June of 2006, we have increased the amount outstanding under our senior credit facilities by approximately $500 million. Our higher debt outstanding increased interest expense approximately $6.3 million. Higher interest rates incurred during the second quarter of 2007 as compared to the prior year period contributed $1.3 million to increased interest expense.

Income Tax Expense

Our provision for income taxes for the second quarter of 2007 increased $7.2 million from the prior year period to $12.8 million. An increase of $15.5 million in income before taxes for the second quarter of 2007 as compared to the prior year quarter was the reason for increased federal income tax expense. Our U.S. income tax provision of $10.0 million was established using the statutory U.S. federal rate of 35%. Our Canadian income tax provision of approximately $2.6 million was accrued at a combined Canadian and provincial statutory rate of 28.5%. Partially offsetting these increases were income tax credits of approximately $1.1 million for Scientific Research and Experimental Development (“SRED”) granted by the Canada Revenue Agency (“Revenue Canada”) for 2002 expenditures and the absence of a $0.9 million deferred state income tax expense recorded in May of 2006 as a result of the newly enacted Texas Margin Tax. The $3.8 million credit recorded in June 2006 for a reduction in the Canadian federal and provincial income tax rates enacted during the second quarter of 2006 was not repeated in the 2007 period.

Summary Financial Data
Six Months Ended June 30, 2007 Compared with the Six Months Ended June 30, 2006


	Six Months Ended
	June 30,
	2007		2006
	(in thousands)
Total operating revenues	$	252,978	$	189,115
Total operating expenses		142,840		100,056
Operating income		110,535		89,167
Net income		54,582		51,143

We recorded net income of $54.6 million ($0.66 per diluted share) for the six months ended June 30, 2007, compared to net income of $51.1 million ($0.63 per diluted share) for the first half of 2006.

Operating Revenues

Revenues for the first half of 2007 were $253.0 million; a $63.9 million increase from the $189.1 million reported for the six months ended June 30, 2006. Production revenue increased $60.0 million as a result of a 24% increase in sales volumes and a 6% 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, 2007 and 2006 are as follows:


	Six Months Ended
	June 30,
	2007		2006
Natural gas, oil and NGL sales (in thousands)
United States	$	177,230	$	129,293
Canada		70,021		57,932

Total	$	247,251	$	187,225


Product sale revenues (in thousands)
Natural gas sales	$	197,870	$	159,657
Oil and condensate sales		17,013		17,926
NGL sales		32,368		9,642

Total	$	247,251	$	187,225


Average daily sales volume
Natural gas – Mcfd
United States		104,521		92,817
Canada		54,927		48,814

Total		159,448		141,631
Oil and condensate – Bbld
United States		1,701		1,639
Canada		—		1

Total		1,701		1,640
NGL – Bbld
United States		4,681		1,279
Canada		6		17

Total		4,687		1,296

Total sales – Mcfed
United States		142,810		110,323
Canada		54,965		48,921

Total		197,775		159,244

Unit prices — including impact of hedges
Natural gas — per Mcf
United States	$	6.76	$	6.06
Canada		7.03		6.54
Consolidated		6.86		6.23

Oil and condensate — per Bbl
United States	$	55.25	$	60.40
Canada		—		53.21
Consolidated		55.25		60.39

NGL — per Bbl
United States	$	38.11	$	41.02
Canada		76.31		47.98
Consolidated		38.16		41.12

Natural gas sales of $197.9 million for the first six months of 2007 were 24% higher than the $159.7 million of natural gas sales for the first half of 2006. Natural gas sales increased $16.1 million as a result of a $0.63 per Mcf increase in realized natural gas prices for the first half of 2007 as compared to the 2006 period. Natural gas sales increased an additional $22.1 million as sales volumes increased 13% for the 2007 period as compared to the 2006 six-month period. Production from our CBM projects in Canada for the first half of 2007 increased by approximately 2.1 Bcf as compared to the first six months of 2006 as a result of new wells placed into production subsequent to June of 2006. Natural production declines partially offset the Canadian production increases. New wells in the Fort Worth Basin placed into production subsequent to June 2006, increased sales volumes by approximately 3.3 Bcf for the first half of 2007 compared to the 2006 period. Additional Michigan volumes of 0.2 Bcf were recognized upon the successful resolution of a dispute concerning royalty interests. The remainder of the change in U.S. natural gas production includes production from new wells placed into production subsequent to June 2006 in all other U.S. operating areas, primarily Michigan, and decreased production associated with natural production declines.

Oil and condensate sales were $17.0 million for the six months ended June 30, 2007 compared to $17.9 million for the first half of 2006. The average realized oil and condensate sales price for the 2007 period was $55.25 per Bbl compared to $60.39 per Bbl for the first half of 2006. Lower realized sales prices decreased sales by $1.5 million for the first six months of 2007 compared to the prior year period. New wells in the Fort Worth Basin placed into production subsequent to June 2006, added approximately 26 MBbl of oil and condensate in the first half of 2007 compared to the 2006 period, which was partially offset by natural production declines in other producing areas. The net increase in oil production improved sales by an additional $0.6 million compared to the prior year quarter.

Our NGL sales for the first half of 2007 increased $22.7 million to $32.4 million as compared to the first half of 2006. NGL sales increased $23.4 million as a result of higher production volumes for the 2007 period. NGL production from the Fort Worth Basin in the 2007 period increased approximately 733 MBbl as a result of new wells placed into production subsequent to June 2006, start-up of our first natural gas processing facility in April 2006 and improved NGL recoveries that resulted from the March 2007 start-up of our newest processing facility. The Fort Worth Basin increases were partially offset by natural production declines elsewhere in the U.S. NGL prices decreased $2.96 per Bbl for the 2007 six-month period as compared to 2006 and reduced sales by approximately $0.7 million.

Other Revenues

Other revenue, consisting primarily of revenue from the processing, gathering and marketing of natural gas, was $5.7 million for the six months ended June 30, 2007 compared to $1.9 million for the first half of 2006. A $1.9 million increase in gas processing and transportation revenue was primarily the result of revenue earned from the processing of third-party natural gas through our gas processing facility in the Fort Worth Basin which began operating in April 2006. An increase in the capacity of our gathering system in the Fort Worth Basin also contributed to the revenue increase. An additional increase in other revenue for the first half of 2007 resulted from a $1.6 million rebate of Alberta crown royalties in Canada. The rebate was made under a program that promotes new technologies in the energy sector. A remaining $1.0 million increase in other revenue for the 2007 period was the result of ineffectiveness of our Canadian cash flow hedges caused by variances in the price differentials for Canadian prices and NYMEX prices. A decrease in marketing revenue for the 2007 period partially offset these increases.

Operating Expenses

Operating expenses for the six months ended June 30, 2007 were $142.8 million; an increase of $42.8 million over the $100.0 million of operating expenses incurred in the first half of 2006.

Oil and Gas Operations Expense


	Six Months Ended
	June 30,
	2007		2006
	(in thousands, except per unit
	amounts)
Oil and gas operations expense
United States	$	46,063	$	34,628
Canada		14,495		11,002

Total	$	60,558	$	45,630

Oil and gas operations expense – per Mcfe
United States	$	1.78	$	1.73
Canada		1.46		1.24
Consolidated		1.69		1.59

Oil and gas operations expense was $60.6 million for the first half of 2007. The $14.9 million increase over the prior year period included increases of $11.4 million and $3.5 million for U.S. and Canadian production costs, respectively.

Oil and gas operations expense for the U.S. was $46.1 million for the first half of 2007. U.S. production expense for the 2007 period increased $11.4 million compared to production expense of $34.6 million for the first half of 2006. The growth of our operations in the Fort Worth Basin increased operating expense approximately $9.0 million for the first half of 2007 compared to the 2006 period. A $2.6 million increase in Texas production overhead expense consisted of $1.0 million for compensation expense and $1.6 million in higher field office expenses, which resulted from the addition of operations personnel and an increase in operating activities as compared to the first six months of 2006. Texas lease operating expenses for the first half of 2007 increased $5.6 million as compared to the 2006 period primarily because of the increasing rate of new wells placed into production. Operation of our Texas natural gas processing facilities and gathering system operations increased expense $1.0 million for the first half of 2007. Our first natural gas processing facility began operation in April 2006 while our gathering system grew to connect additional wells completed over the past year. Expense for our Michigan operations increased $1.1 million for the first six months of 2007 compared to the prior year period. Michigan overhead expense increased $0.9 million for the first half of 2007 as compared the 2006 period and included additional non-cash compensation expense of $0.3 million for the vesting of stock awards granted in January 2007. The remaining overhead expense increases were primarily the result of additional compensation and benefit expense of $0.6 million as well as increases in maintenance and repairs.

Canadian operating costs were $14.5 million for the first six months of 2007. Compared to the first half of 2006, oil and gas production expense increased approximately $3.5 million for the first half of 2007. Compensation expense increased $2.6 million for the first six months of 2007 as compared to the 2006 six months. The increase consisted of $0.6 million of expense for non-compete payments made to senior management no longer employed by us, additional non-cash compensation expense of $0.5 million for vesting of restricted stock unit awards granted in January 2007, $0.3 million for additional company contributions to employee retirement plans and $1.2 million for additional salary and benefits primarily related to a 9% increase in personnel at June 30, 2007 as compared to June 30, 2006. In addition, lease operating and gas facility and processing expenses increased $0.6 million each for the first six months of 2007 compared to the prior year period. These increases reflect additional wells placed into production and the construction of additional gas processing facilities during the past year.

Production and Ad Valorem Taxes

Production and ad valorem tax expense for the first six months of 2007 was $8.7 million compared to $6.2 million for the first half of 2006. U.S and Canadian production taxes increased $1.0 million and $0.4 million, respectively as a result of higher volumes and higher realized prices. Ad valorem taxes increased $1.1 million primarily as the result of additional assets constructed and acquired in conjunction with our drilling programs in the Fort Worth Basin and Alberta, Canada.

Depletion, Depreciation and Accretion


	Six Months Ended
	June 30,
	2007		2006
	(in thousands, except per unit
	amounts)
Depletion	$	43,219	$	29,671
Depreciation of other fixed assets		8,516		5,307
Accretion		764		649

Total depletion, depreciation and accretion	$	52,499	$	35,627

Average depletion cost per Mcfe	$	1.21	$	1.03

Depletion for the first six months of 2007 was $43.2 million and $13.5 million higher than depletion for the 2006 period. Higher depletion resulted from a 17% increase in the depletion rate and a 32% increase in sales volumes. Our higher depletion rate for the first half of 2007 resulted from significant actual and estimated future capital expenditures and proved reserves added for our Canadian CBM and Forth Worth Basin properties. The $3.2 million increase in depreciation for the first half of 2007 as compared to the 2006 period was primarily associated with new gas processing facilities in Canada and Fort Worth Basin gas compression and processing facilities and gathering system assets.

General and Administrative Expense

General and administrative expense for the six months ended June 30, 2007 was $20.3 million compared to $11.7 million for the six months ended June 30, 2006. The most significant increase in general and administrative expense for the half of 2007 was a $6.3 million increase in employee compensation and benefits, including approximately $2.4 million of non-cash expense for

vesting of restricted stock and stock option awards. Office expenses, including rent, and information technology expenses increased approximately $0.9 million for the 2007 period as compared to the prior year six-month period. These increases were, in large part, the result of a 48% increase in personnel working in the corporate office at June 30, 2007 as compared to June 30, 2006 and vesting of restricted stock granted in early in 2007. Additionally, expense for legal, accounting and other professional services increased $1.2 million for the first six months of 2007 including legal fees of $0.6 million incurred as a result of the favorable resolution of a dispute concerning royalty interests on certain Michigan wells.

Interest Expense

Interest expense for the first half of 2007 was $33.2 million, net of capitalized interest of $0.9 million, which was an increase of $13.4 million compared to the first half of 2006. Our average debt outstanding for the first six months of 2007 was approximately $380 million higher than the 2006 six-month period. Our higher debt outstanding increased interest expense approximately $11.7 million. Higher interest rates incurred during the first half of 2007 as compared to the prior year period contributed $1.7 million to increased interest expense. Partially offsetting these increases was the absence of a $1.0 million prepayment charge associated with the retirement of debt in March of 2006.

Income Tax Expense

Our provision for income taxes for the six months ended June 30, 2007 increased $5.0 million from the prior year period to $24.1 million. The $5.0 million increase in our income tax provision was the result of an $8.6 million increase in income before taxes for the first half of 2007 as compared to the first half of 2006. Our U.S. income tax provision of $16.8 million was established using the statutory U.S. federal rate of 35%. Our Canadian income tax provision of approximately $7.2 million was accrued at a combined Canadian and provincial statutory rate of 28.5%. Partially offsetting these increases were income tax credits of approximately $1.1 million for Scientific Research and Experimental Development (“SRED”) granted by the Canada Revenue Agency (“Revenue Canada”) for 2002 expenditures and the absence of a $0.9 million deferred state income tax expense recorded in May of 2006 as a result of the newly enacted Texas Margin Tax. The $3.8 million credit recorded in June 2006 for a reduction in the Canadian federal and provincial income tax rates enacted during the second quarter of 2006 was not repeated in the 2007 period.

LIQUIDITY, CAPITAL RESOURCES AND FINANCIAL POSITION

Net cash from operations was $147.0 million for the six months ended June 30, 2007, an increase of $15.2 million compared to the same period in 2006. Net income of $54.6 million for the first half of 2007 was $3.4 million higher than net income for the first six months of 2006 and non-cash expenses including depletion, depreciation and amortization, deferred taxes, stock-based compensation and deferred financing costs were $25.2 million higher for the six months ended June 30, 2007. These additional sources of operating cash were partially offset by a decrease in working capital of $13.4 million for the 2007 six-month period as compared to the first half of 2006.

Our principal sources of cash are sales of natural gas, crude oil and NGLs. During the six months ended June 30, 2007, sales under our long-term contracts with price floors averaging $2.48 per Mcf covered 28% of our U.S. natural gas production. Additionally, price collars covered approximately 66% of our total production for the six months ended June 30, 2007. We currently have price collars or fixed price swaps hedging our anticipated natural gas and crude oil, condensate and NGL production of approximately 127 MMcfd and 2,000 Bbld, respectively, for the remainder of 2007. We have hedged approximately 65 MMcfd and 40 MMcfd of our anticipated 2008 natural gas sales using price collars and fixed price swaps, respectively. Expected crude oil production of 1,000 Bbld for 2008 has been hedged using price collars. Approximately 40 MMcfd of our expected first quarter 2009 natural gas sales is also hedged with natural gas collars.

During the first half of 2007, we paid $435.1 million for property and equipment, an increase of $155.4 million compared to the first six months of 2006. Property and equipment costs incurred (payments for property and equipment plus noncash changes in working capital associated with property and equipment) for the 2007 period totaled $429.5 million, which consisted of $344.3 million expended for exploration and development activities, $66.0 million expended for our Fort Worth basin gas processing and gathering operations and $9.6 million expended for Canadian gas processing facilities. Of the $320.6 million incurred for U.S. exploration and development, $312.0 million was spent in Texas, including $26.3 million for non-producing leasehold costs. During 2006, we received approximately $4.5 million from the sale of producing property in Canada. We have not sold any of our producing properties during 2007.


	Six Months Ended
	June 30, 2007
	(in thousands)
Exploration and development
United States	$	320,595
Canada		23,746

Total exploration and development		344,341
Gas processing and transportation
United States		71,449
Canada		9,579

Total gas processing and transportation		81,028
Corporate and office		4,135

Total plant and equipment costs incurred	$	429,504

Net cash provided by financing activities for the six months ended June 30, 2007 totaled $283.9 million. As of June 30, 2007, the borrowing base under our senior secured credit facility was $850 million, of which approximately $130 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 such covenants at June 30, 2007.

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


	June 30,		December 31,
	2007		2006
	(in thousands)
Senior secured credit facility	$	719,422	$	421,123
Senior subordinated notes		350,000		350,000
Convertible subordinated debentures		148,050		147,994
Other loans		220		400

Total debt		1,217,692		919,517
Stockholders’ equity		629,456		575,666

	$	1,847,148	$	1,495,183

Financial Position

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

	•		A $419.8 million increase in our net property, plant and equipment assets includes approximately $429.5 million in capital costs incurred for development, exploitation and exploration of our oil and gas properties as well as additional natural gas processing and gathering system assets in Texas.

	•		We incurred additional long-term debt of $274.9 million primarily as a result of our capital expenditures of $435.1 million exceeding our cash flow from operations by $288.1 million. These borrowings have been drawn from our senior secured credit facility.

	•		Our current and deferred derivative assets have decreased $41.9 million and we have recorded current and non-current derivative liabilities of $0.9 million and $6.0 million, respectively. These fluctuations reflect the relatively less favorable pricing of our financial derivatives as compared to the forward pricing of natural gas, crude oil and NGLs at June 30, 2007. Additionally, our current deferred tax liability decreased $13.5 million as a result of the lower estimated fair value of our natural gas, crude oil and NGL financial derivatives.

	•		Accumulated other comprehensive income decreased $33.1 million as a result of the decrease in the estimated fair value of our financial derivatives, net of income taxes. Partially offsetting that decrease was a $14.8 million increase in our currency translation adjustment that resulted from the strengthening of the Canadian dollar in relation to the U.S. dollar over the first six months of 2007.

Recently Issued Accounting Standards

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

There have been no changes to our unrecognized tax benefits for the United States for the six months ended June 30, 2007. Because of our current net operating loss position, no accrual of interest or penalties has been recognized. If required, interest or penalties would be recognized as interest expense. We remain subject to examination by the Internal Revenue Service for the years 2001 through 2006. Currently, the Internal Revenue Service is auditing our 2004 Federal income tax return. This examination is expected to be completed in 2008.

Our subsidiary, Quicksilver Resources Canada Inc. (“QRCI”), because of its Canadian tax pool balances, remains subject to examination by the Revenue Canada Agency (“Revenue Canada”) for the years 1999 through 2006. Revenue Canada is currently reviewing the Scientific Research and Experimental Development (“SRED”) credits claimed, but not recognized, by QRCI for the years 2004 through 2006. Revenue Canada granted $1.1 million of SRED credits in the second quarter of 2007.

In May 2006, the Texas business tax was amended by replacing the taxable capital and earned surplus components of the old franchise tax with a new “taxable margin” component effective for taxable years ending December 31, 2007. We have not recognized any unrecognized tax benefits for this new Texas “taxable margin” tax.

We do not anticipate that total unrecognized tax benefits will significantly change due to the settlement of audits and the expiration of statute of limitations prior to June 30, 2008.

On April 30, 2007, the FASB issued FASB Staff Position (“FSP”) No. FIN 39-1,Amendment of FASB Interpretation No. 39. The FSP amends paragraph 3 of FIN No. 39 to replace the terms “conditional contracts” and “exchange contracts” with the term “derivative instruments” as defined in FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities. It also amends paragraph 10 of Interpretation 39 to permit a reporting entity to offset fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement that have been offset in accordance with that paragraph. The guidance in this FSP is effective for fiscal years beginning after November 15, 2007 and an entity shall recognize the effects of applying this FSP as a change in accounting principle through retrospective application for all financial statements presented unless it is impracticable to do so. We are evaluating the FSP’s guidance, but does not believe its adoption will have a material impact on our financial position, results of operations or cash flows.

ITEM 3. Quantitative and Qualitative Disclosures About Market Risk

We have established policies and procedures for managing risk within our organization, including internal controls. The level of risk assumed by us is based on our objectives and capacity to manage risk.

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

Commodity Price Risk

We enter into financial contracts to hedge our exposure to commodity price risk associated with anticipated future natural gas production. These contracts have included no-cost collars and fixed price swaps. During the first half of 2007, we sold approximately 25.0 MMcfd of natural gas for a floor price of $2.49 per Mcf under a long-term contract that extends through March 2009. Approximately 2.4 MMcfd of the natural gas sold under this contract during the first six months of 2007 were third-party volumes controlled by us.

We also sold approximately 10.0 MMcfd for a floor price of $2.47 per Mcf under a long-term contract that extended through March 2009. On May 15, 2007, a ruling by the 236^th Judicial District Court of Texas rescinded the contract and rendered it void

from that date and we began selling the 10.0 MMcfd at market prices on May 22, 2007. Through that date, approximately 0.9 MMcfd of the natural gas sold under the contract were third-party volumes controlled by us.

As of June 30, 2007, natural gas price collars have been put in place to hedge approximately 127 MMcfd of our anticipated natural gas production for the remainder of 2007. We have also hedged 2,000 Bbld of anticipated crude oil, condensate and NGL production with crude oil price collars and NGL fixed price swaps for the remainder of 2007. Price collars and swaps have also been put in place to hedge approximately 65 MMcfd and 40 MMcfd, respectively, of our anticipated 2008 natural gas production. Anticipated 2008 crude oil and condensate production of approximately 1,000 Bbld has also been hedged with crude oil price collars. Anticipated first quarter 2009 natural gas production of approximately 40 MMcfd has been hedged with natural gas price collars.

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

Remaining

Price Per

Product

Type

Contract Period

Volume

Mcf or Bbl

Fair Value

(in thousands)

Gas

Collar

Jul 2007-Oct 2007

10,000 Mcfd

$7.50-11.50

1,052

Gas

Collar

Jul 2007-Oct 2007

10,000 Mcfd

7.50-11.75

1,057

Gas

Collar

Jul 2007-Oct 2007

5,000 Mcfd

7.50-11.78

529

Gas

Collar

Jul 2007-Oct 2007

5,000 Mcfd

7.50-11.80

532

Gas

Collar

Jul 2007-Dec 2007

20,000 Mcfd

7.00- 9.15

676

Gas

Collar

Jul 2007-Dec 2007

10,000 Mcfd

8.00-11.20

1,905

Gas

Collar

Jul 2007-Dec 2007

10,000 Mcfd

9.00-12.10

3,453

Gas

Collar

Jul 2007-Dec 2007

20,000 Mcfd

9.00-12.10

6,906

Gas

Collar

Jul 2007-Mar 2008

15,000 Mcfd

7.50- 8.70

200

Gas

Collar

Jul 2007-Mar 2008

5,000 Mcfd

7.50- 8.90

131

Gas

Collar

Jul 2007-Mar 2008

10,000 Mcfd

9.00-12.00

4,173

Gas

Collar

Jul 2007-Mar 2008

10,000 Mcfd

9.00-12.05

4,185

Gas

Collar

Nov 2007-Mar 2008

10,000 Mcfd

8.00-15.00

1,002

Gas

Collar

Nov 2007-Mar 2008

10,000 Mcfd

8.00-15.65

1,010

Gas

Collar

Jan 2008-Dec 2008

20,000 Mcfd

7.50- 9.15

(1,614

)

Gas

Collar

Apr 2008-Mar 2009

20,000 Mcfd

7.50- 9.35

(1,979

)

Gas

Collar

Apr 2008-Mar 2009

20,000 Mcfd

8.00-10.20

1,160

Oil

Collar

Jul 2007-Dec 2007

500 Bbld

70.00-91.10

242

Oil

Collar

Jul 2007-Dec 2007

500 Bbld

60.00-72.80

(196

)

Oil

Collar

Jan 2008-Dec 2008

500 Bbld

65.00-73.90

(373

)

Oil

Collar

Jan 2008-Dec 2008

500 Bbld

65.00-77.45

(150

)

Gas

Swap

Jan 2008-Dec 2008

25,000 Mcfd

$8.13

(2,383

)

Gas

Swap

Jan 2008-Dec 2008

7,500 Mcfd

8.13

(715

)

Gas

Swap

Jan 2008-Dec 2008

5,000 Mcfd

8.14

(459

)

Gas

Swap

Jan 2008-Dec 2008

2,500 Mcfd

8.15

(221

)

NGL

Swap

Jul 2007-Dec 2007

1,000 Bbld

40.32

(712

)

Gas

Basis Swap

Jul 2007-Dec 2007

25,000 Mcfd

(42

)

Gas

Basis Swap

Jul 2007-Dec 2007

20,000 Mcfd

—

Gas

Basis Swap

Jan 2008-Dec 2008

10,000 Mcfd

(151

)

Gas

Basis Swap

Jan 2008-Dec 2008

10,000 Mcfd

(151

)

Total

19,067

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, 2007 related to natural gas marketing.

Weighted Avg

Product

Type

Contract Period

Volume

Price per Mcf

Fair Value

(in thousands)

Fixed price sale contracts

Gas

Sales

Jul-Aug 2007

161 Mcfd

7.98

Financial derivatives

Gas

Floating Price

Jul-Aug 2007

161 Mcfd

(10

)

Total-net

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 $21.4 million higher and $1.2 million lower as a result of the hedging programs for the first six months of 2007 and 2006, respectively. Other revenue was $1.0 million higher and $0.3 million lower as a result of hedging activities for the six-month periods ending June 30, 2007 and 2006, respectively.

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 2007, our disclosure controls and procedures were effective to provide reasonable assurance that material information required to be disclosed by us (including our consolidated subsidiaries) in reports that we file or submit under the Securities Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

There has been no change in our internal control over financial reporting during the quarter ended June 30, 2007 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

In August 2001, a group of royalty owners, Athel E. Williams et al., brought suit against us and three of our subsidiaries in the Circuit Court of Otsego County, Michigan. The suit alleged that Terra Energy Ltd., one of our subsidiaries, underpaid royalties or overriding royalties to the 13 named plaintiffs and to a class of plaintiffs who had yet to be determined. The pleadings of the plaintiffs sought damages in an unspecified amount and injunctive relief against future underpayments. On April 20, 2007, based upon the stipulation of the parties, the Circuit Court dismissed the case, including all claims and counterclaims, without prejudice.

On November 7, 2001, Quicksilver Resources Inc. filed a lawsuit against CMS Marketing Services and Trading Company (“CMS”) in the 236^th Judicial District Court of Tarrant County, Texas. The suit alleged that CMS committed fraud when it entered into a 10-year contract with us on March 1, 1999 for the purchase and sale of 10,000 MMBtud of natural gas at a minimum price of $2.47 per MMBtu and breached the contract afterward by failing to comply with a provision of the contract requiring that, if the gas could be scheduled or delivered to derive additional value, the parties would share equally in the additional revenue. We sought unspecified damages and rescission of the contract. On May 15, 2007, the Court upheld a jury finding against CMS on the fraudulent inducement claim, rescinded the contract and rendered the contract void beginning May 15, 2007. CMS is appealing the judgment. We have also appealed the Court’s judgment because we believe the contract is voidab initiorather than from the date of judgment entry.

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

Issuer Purchases of Equity Securities

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


							Maximum
					Total Number of		Number of
					Shares		Shares that
					Purchased as		May Yet Be
					Part of Publicly		Purchased
	Total Number				Announced		Under the
	of Shares		Average Price		Plans or		Plans or
Period	Purchased (1)		Paid per Share		Programs (2)		Programs (2)
April 1 to April 30, 2007		7,487	$	42.04		—		—
May 1 to May 31, 2007		44	$	41.47		—		—
June 1 to June 30, 2007		236	$	44.81		—		—

Total		7,767	$	42.12		—		—


(1)		Represents shares of common stock surrendered by employees to satisfy the Company’s income tax withholding obligations arising upon the vesting of restricted stock issued under our Amended and Restated 1999 Stock Option and Retention Plan.

(2)		The Company does not currently have in place any publicly announced, specific plans or programs to purchase equity securities.

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, 2007.

Election of Directors

At the meeting, two directors were elected to serve terms expiring at the Company’s Annual Meeting of Stockholders to be held in 2010. 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
Anne Darden Self		71,937,817		1,572,105

Steven M. Morris		73,375,319		134,603

Glenn Darden, Thomas F. Darden, James A. Hughes, W. Yandell Rogers III 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 LLP as our independent registered public accounting firm for fiscal year ending December 31, 2007. The vote on such proposal was as follows:


For			73,175,326
Against			314,015
Abstentions			20,581

ITEM 6. Exhibits:


Exhibit No.		Description

10.1		Quicksilver Resources Inc. 2007 Executive Bonus Plan (filed as Exhibit 10.1 to the Company’s Form 8-K filed April 16, 2007 and included herein by reference).

10.2		Quicksilver Resources Inc. Amended and Restated 2006 Equity Plan (filed as Exhibit 10.1 to the Company’s Form 8-K filed May 25, 2007 and included herein by reference).

10.3		Form of Non-Employee Director Restricted Share Agreement pursuant to the Quicksilver Resources Inc. Amended and Restated 2006 Equity Plan (Three-Year Vesting) (filed as Exhibit 10.2 to the Company’s Form 8-K filed May 25, 2007 and included herein by reference).

10.4		Quicksilver Resources Inc. Amended and Restated 1999 Stock Option and Retention Stock Plan (filed as Exhibit 10.3 to the Company’s Form 8-K filed May 25, 2007 and included herein by reference).

10.5		Quicksilver Resources Inc. Amended and Restated 2004 Non-Employee Director Equity Plan (filed as Exhibit 10.4 to the Company’s Form 8-K filed May 25, 2007 and included herein by reference).

*10.6		Description of Non-Employee Director Compensation for Quicksilver Resources Inc.

*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 9, 2007


	Quicksilver Resources Inc.
	By:	/s/ Glenn Darden
		Glenn Darden
		President and Chief Executive Officer

	By:	/s/ Philip Cook
		Philip Cook
		Senior Vice President - Chief Financial Officer

EXHIBIT INDEX


Exhibit No.		Description

10.1		Quicksilver Resources Inc. 2007 Executive Bonus Plan (filed as Exhibit 10.1 to the Company’s Form 8-K filed April 16, 2007 and included herein by reference).

10.2		Quicksilver Resources Inc. Amended and Restated 2006 Equity Plan (filed as Exhibit 10.1 to the Company’s Form 8-K filed May 25, 2007 and included herein by reference).

10.3		Form of Non-Employee Director Restricted Share Agreement pursuant to the Quicksilver Resources Inc. Amended and Restated 2006 Equity Plan (Three-Year Vesting) (filed as Exhibit 10.2 to the Company’s Form 8-K filed May 25, 2007 and included herein by reference).

10.4		Quicksilver Resources Inc. Amended and Restated 1999 Stock Option and Retention Stock Plan (filed as Exhibit 10.3 to the Company’s Form 8-K filed May 25, 2007 and included herein by reference).

10.5		Quicksilver Resources Inc. Amended and Restated 2004 Non-Employee Director Equity Plan (filed as Exhibit 10.4 to the Company’s Form 8-K filed May 25, 2007 and included herein by reference).

*10.6		Description of Non-Employee Director Compensation for Quicksilver Resources Inc.

*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	H.S. freshman Avg

Quicksilver Resources (KWK) Inactive 10-Q2007 Q2 Quarterly report

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