Quicksilver Resources (KWK) 10-Q 2008 Q1 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 March 31, 2008

or

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

For the transition period from                    to                    

Commission file number: 001-14837

Quicksilver Resources Inc.

(Exact name of registrant as specified in its charter)

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

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

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

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

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

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

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

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

Title of Class	Outstanding as of April 30, 2008
Common Stock, $0.01 par value	158,573,546

QUICKSILVER RESOURCES INC.
INDEX TO FORM 10-Q
For the Period Ending March 31, 2008

	Page
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements (Unaudited)
Condensed Consolidated Statements of Income and Comprehensive Loss		5
Condensed Consolidated Balance Sheets		6
Condensed Consolidated Statements of Cash Flows		7
Notes to Condensed Consolidated Interim Financial Statements		8
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		21
Item 3. Quantitative and Qualitative Disclosures About Market Risk		28
Item 4. Controls and Procedures		31
PART II. OTHER INFORMATION
Item 1. Legal Proceedings		32
Item 1A. Risk Factors		32
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		32
Item 3. Defaults Upon Senior Securities		32
Item 4. Submission of Matters to a Vote of Security Holders		32
Item 5. Other Information		32
Item 6. Exhibits		33
Signatures		34
Certification Pursuant to Section 302
Certification Pursuant to Section 302
Certification Pursuant to Section 906

2

DEFINITIONS

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

“AECO” means the price of gas delivered onto the NOVA Gas Transmission Ltd. System

“Bbl” or “Bbls” means barrel or barrels

“Bbld” means barrel or barrels per day

“Bcf” means billion cubic feet

“Bcfd” means billion cubic feet per day

“Bcfe” means Bcf of natural gas equivalents, determined by using the ratio of one Bbl of oil or NGLs to six Mcf of gas

“Btu” means British Thermal units, a measure of heating value

“Canada” means the division of Quicksilver encompassing natural gas and oil properties located in Canada

“CBM” means coalbed methane

“Domestic” means the properties of Quicksilver in the continental United States

“Inside FERC” refers to the publicationInside F.E.R.C.’s Gas Market Report

“LIBOR” means London Interbank Offered Rate

“MBbls” means thousand barrels

“MMBbls” means million barrels

“MMBtu” means million Btu and is approximately equal to 1 Mcf

“MMBtud” means million Btu per day

“Mcf” means thousand cubic feet

“MMcf” means million cubic feet

“MMcfd” means million cubic feet per day

“MMcfe” means million cubic feet of natural gas equivalents, determined by using the ratio of one Bbl of oil or NGLs to six Mcf of gas

“NGL” or “NGLs” means natural gas liquids

“NYMEX” means New York Mercantile Exchange

“Oil” includes crude oil and condensate

“Tcf” means trillion cubic feet

“Tcfe” means trillion cubic feet of natural gas equivalents, determined by using the ratio of one Bbl of oil or NGLs to six Mcf of gas

COMMONLY USED TERMS

Other commonly used terms and abbreviations include:

“BBEP” means BreitBurn Energy Partners L.P.

“BreitBurn Transaction” means the November 1, 2007 conveyance of our Northeast Operations in exchange for aggregate proceeds of $1.47 billion

“FASB” means the Financial Accounting Standards Board who promulgate accounting standards

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

“KGS” means Quicksilver Gas Services LP which is our publicly-traded midstream operations which trades under the ticker symbol “KGS”

“Michigan Sales Contract” means the gas supply contract in place through March 2009 under which we deliver 25 MMcfd at a floor price of $2.49 per Mcf

“Northeast Operations” means the oil and gas properties and facilities in Michigan, Indiana and Kentucky which were conveyed to BreitBurn Operating, L.P. on November 1, 2007

“SEC” means United States Securities and Exchange Commission

“SFAS” means Statement of Financial Accounting Standards issued by the Financial Accounting Standards Board

3

Explanatory Statement

Under the full cost method of accounting, the Company’s U.S.-based exploration and production assets are considered a single asset. The 2007 fourth quarter divestiture of the Northeast Operations, therefore, represents a fractional divestiture of a single asset, which precludes recording the applicable portion of the Northeast Operations’ results of operations as discontinued operations within the consolidated financial statements.

Forward-Looking Information

Certain statements contained in this report and other materials we file with the SEC, or in other written or oral statements made or to be made by us, other than statements of historical fact, are “forward-looking statements” as defined in the Private Securities Litigation Reform Act of 1995. Forward-looking statements give our current expectations or forecasts of future events. Words such as “may,” “assume,” “forecast,” “position,” “predict,” “strategy,” “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe,” “project,” “budget,” “potential,” or “continue,” and similar expressions are used to identify forward-looking statements. They can be affected by assumptions used or by known or unknown risks or uncertainties. Consequently, no forward-looking statements can be guaranteed. Actual results may vary materially. You are cautioned not to place undue reliance on any forward-looking statements. You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include:

• changes in general economic conditions;

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

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

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

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

• competitive conditions in our industry;

• actions taken by third parties, including 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

• certain factors discussed in our Annual Report on Form 10-K for the year ended December 31, 2007.

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

4

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements (Unaudited)

QUICKSILVER RESOURCES INC.

CONDENSED CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE LOSS

In thousands, except for per share data — Unaudited

	For the Three Months Ended
	March 31,
	2008			2007
Revenues
Natural gas, NGL and crude oil sales	$	158,356		$	113,292
Other		(853	)		3,288
Total revenues		157,503			116,580
Operating expenses
Oil and gas production expense		32,530			28,569
Production and ad valorem taxes		2,659			4,490
Other operating costs		1,231			784
Depletion, depreciation and accretion		35,059			24,594
General and administrative		15,415			9,698
Total expenses		86,894			68,135
Income from equity affiliates		—			115
Operating income		70,609			48,560
Income from earnings of BreitBurn Energy Partners		6,219			—
Other income — net		1,600			601
Interest expense		(11,832	)		(14,952	)
Income before income taxes		66,596			34,209
Income tax expense		23,912			11,295
Minority interest expense, net of income tax		508			63
Net income	$	42,176		$	22,851
Other comprehensive loss — net of income tax
Reclassification adjustments related to settlements of derivative contracts		(1,940	)		(9,510	)
Net change in derivative fair value		(76,297	)		(35,679	)
Foreign currency translation adjustment		(8,643	)		1,624
Comprehensive loss	$	(44,704	)	$	(20,714	)
Earnings per common share — basic	$	0.27		$	0.15
Earnings per common share — diluted	$	0.25		$	0.14
Basic weighted average shares outstanding		157,731			154,389
Diluted weighted average shares outstanding		169,730			167,659

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

5

QUICKSILVER RESOURCES INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

In thousands, except for share data — Unaudited

	March 31,			December 31,
	2008			2007
ASSETS
Current assets
Cash and cash equivalents	$	1,976		$	28,226
Accounts receivable — net of allowance for doubtful accounts		115,957			90,244
Derivative assets at fair value		22,125			10,797
Current deferred income tax asset		54,180			18,946
Other current assets		42,769			42,188
Total current assets		237,007			190,401
Investment in BreitBurn Energy Partners		416,731			420,171
Property, plant and equipment — net
Oil and gas properties, full cost method (including unevaluated costs of $281,130 and $215,228, respectively)		2,001,458			1,764,400
Other property and equipment		429,306			377,946
Property, plant and equipment — net		2,430,764			2,142,346
Derivative assets at fair value		—			354
Other assets		25,439			22,574
	$	3,109,941		$	2,775,846
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current portion of long-term debt	$	—		$	34
Accounts payable		182,606			192,855
Income taxes payable		1,457			46,601
Accrued liabilities		40,406			54,981
Derivative liabilities at fair value		186,301			64,104
Total current liabilities		410,770			358,575
Long-term debt		1,115,811			813,817
Asset retirement obligations		24,989			23,864
Derivative liabilities at fair value		20,474			16,327
Other liabilities		10,609			10,609
Deferred income taxes		392,286			374,645
Deferred gain on sale of partnership interests		79,316			79,316
Minority interests in consolidated subsidiaries		29,412			30,338
Stockholders’ equity
Preferred stock, par value $0.01, 10,000,000 shares authorized, none outstanding		—			—
Common stock, $0.01 par value, 200,000,000 shares authorized; 161,244,642 and 160,633,270 shares issued, respectively		1,612			1,606
Paid in capital in excess of par value		277,112			272,515
Treasury stock of 2,652,981 and 2,616,726 shares, respectively		(14,284	)		(12,304	)
Accumulated other comprehensive (loss) income		(46,814	)		40,066
Retained earnings		808,648			766,472
Total stockholders’ equity		1,026,274			1,068,355
	$	3,109,941		$	2,775,846

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

6

QUICKSILVER RESOURCES INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

In thousands — Unaudited

	For the Three Months Ended
	March 31,
	2008			2007
Operating activities:
Net income	$	42,176		$	22,851
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation and accretion		35,059			24,594
Deferred income taxes		23,016			11,265
Stock-based compensation		4,009			2,899
Amortization of deferred charges		458			563
Amortization of deferred loan costs		589			456
Minority interest expense		508			63
Non-cash loss from hedging and derivative activities		5,735			29
Non-cash income from equity affiliates		—			(115	)
Other		197			(264	)
Changes in assets and liabilities
Accounts receivable		(5,226	)		605
Prepaid expenses and other assets		(1,109	)		(3,777	)
Accounts payable		5,027			6,507
Income taxes payable		(45,144	)		(394	)
Accrued and other liabilities		(22,011	)		7,724
Net cash provided by operating activities		43,284			73,006
Investing activities:
Purchases of property, plant and equipment		(331,936	)		(209,926	)
Advances to BreitBurn Energy Partners		(50,150	)		—
Return of investment from BreitBurn Energy Partners and equity affiliates		3,440			202
Net cash used for investing activities		(378,646	)		(209,724	)
Financing activities:
Issuance of debt		330,741			143,446
Repayments of debt		(18,061	)		(6,868	)
Debt issuance costs		—			(2,303	)
Minority interest contributions		—			167
Minority interest distributions		(1,972	)		—
Proceeds from exercise of stock options		858			2,976
Purchase of treasury stock		(1,980	)		(494	)
Net cash provided by financing activities		309,586			136,924
Effect of exchange rate changes in cash		(474	)		231
Net (decrease) increase in cash		(26,250	)		437
Cash and cash equivalents at beginning of period		28,226			5,281
Cash and cash equivalents at end of period	$	1,976		$	5,718

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

7

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 March 31, 2008 and its income and comprehensive loss and cash flows for the quarters ended March 31, 2008 and 2007. All such adjustments are of a normal recurring nature. The results for interim periods are not necessarily indicative of annual results.

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

Certain disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States have been condensed or omitted. Accordingly, these financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2007.

Certain reclassifications have been made to prior periods to conform to current period presentation.

Stock Split

On January 7, 2008, Quicksilver’s Board of Directors declared a two-for-one stock split of the outstanding common stock effected in the form of a stock dividend. The stock dividend was paid on January 31, 2008, to holders of record at the close of business on January 18, 2008, but had no effect on shares held in treasury. The capital accounts, all share data and earnings per share data included in these condensed consolidated financial statements for all periods presented reflect retrospective application of the January 2008 stock split.

Earnings per Common Share

Basic earnings per common share is computed by dividing the net income attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period. Diluted earnings per common share is computed using the treasury stock method, which considers the impact to net income and common shares from the potential issuance of common shares underlying stock options, stock warrants and outstanding convertible securities.

The following is a reconciliation of the weighted average common shares used in the basic and diluted earnings per common share calculations for the three-month periods ended March 31, 2008 and 2007. Outstanding options to purchase 4,802 shares were excluded from the diluted net income per share calculation for the quarter ended March 31, 2007 as those options were out-of-the-money and, therefore, considered to be antidilutive. No such antidilutive options were outstanding at March 31, 2008.

8

	Three Months Ended
	March 31,
	2008		2007
	(In thousands, except per
	share data)
Net income	$	42,176	$	22,851
Impact of assumed conversions — interest on 1.875% convertible debentures, net of income taxes		475		475
Income available to stockholders assuming conversion of convertible debentures	$	42,651	$	23,326
Weighted average common shares — basic		157,731		154,389
Effect of dilutive securities:
Employee stock options		730		1,767
Employee stock and stock unit awards		1,453		1,687
Contingently convertible debentures		9,816		9,816
Weighted average common shares — diluted		169,730		167,659
Earnings per common share — basic	$	0.27	$	0.15
Earnings per common share — diluted	$	0.25	$	0.14

Recently Issued Accounting Standards

• Pronouncements Implemented

SFAS No. 157,Fair Value Measurements,was issued by the FASB in September 2006. SFAS No. 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles (“GAAP”) and expands disclosures about fair value measurements. The Statement applies under other accounting pronouncements that require or permit fair value measurement. No new requirements are included in SFAS No. 157, but application of the Statement has changed current practice. On February 12, 2008, the FASB issued FASB Staff Position 157-2 (“FSP 157-2”) which delayed the effective date of SFAS No. 157 for non-financial assets and liabilities. The delay is intended to allow the FASB and its constituents additional time to consider the effect of various implementation issues that have arisen, or that may arise, from the application of SFAS No. 157. The Company adopted SFAS No. 157 on January 1, 2008 for new fair value measurements of financial instruments and recurring fair value measurements of non-financial assets and liabilities. All financial instruments are measured using inputs from three levels of fair value hierarchy. The three levels are as follows:

Level 1 inputs are unadjusted quoted prices in active markets for identical assets or liabilities that we have the ability to access at the measurement date.

Level 2 inputs include quoted prices for similar assets and liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability (i.e., interest rates, yield curves, etc.), and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).

Level 3 inputs are unobservable inputs that reflect the Company’s assumptions about the assumptions that market participants would use in pricing an asset or liability.

See Note 2, Derivatives and Fair Value Measurements, for further disclosures concerning the Company’s fair value measurements of its financial assets and liabilities.

In February 2007, the FASB issued SFAS No. 159,The Fair Value Option for Financial Assets and Financial Liabilities — Including an amendment of FASB Statement No. 115. SFAS No. 159 permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. While SFAS No. 159 became effective on January 1, 2008, the Company did not elect the fair value measurement option for any of its financial assets or liabilities.

9

On April 30, 2007, the FASB issued FASB Staff Position (“FSP”) No. 39-1,Amendment of FASB Interpretation No. 39. The FSP amends paragraph 3 of FIN No. 39 to replace the terms “conditional contracts” and “exchange contracts” with the term “derivative instruments” as defined in SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities. It also amends paragraph 10 of Interpretation 39 to permit a reporting entity to offset fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement that have been offset in accordance with that paragraph. The Company adopted FSP No. 39-1 on January 1, 2008 without significant impact.

• Pronouncements Not Yet Implemented

SFAS No. 141 (revised 2007),Business Combinations, “SFAS No. 141(R)” was issued in December 2007. SFAS No. 141(R) replaces SFAS No. 141,Business Combinations, while retaining its fundamental requirements that the acquisition method of accounting be used for all business combinations and for an acquirer to be identified for each business combination. SFAS No. 141(R) defines the acquirer as the entity that obtains control in the business combination and it establishes the criteria to determine the acquisition date. SFAS No. 141(R) applies to all transactions and events in which one entity obtains control over one or more other businesses. The Statement also requires an acquirer to recognize the assets acquired and liabilities assumed measured at their fair values as of the acquisition date. In addition, acquisition costs are required to be recognized separately from the acquisition. The Statement will apply to any acquisition completed by the Company on or after January 1, 2009, but may not be applied to any acquisition completed prior to January 1, 2009.

SFAS No. 160,Noncontrolling Interests in Consolidated Financial Statements — an amendment of ARB No. 51was issued in December 2007. The Statement amends ARB 51 to establish accounting and reporting standards for the noncontrolling interest in a subsidiary (previously referred to as “minority interest”) and for the deconsolidation of a subsidiary. SFAS No. 160 clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as a component of equity in the consolidated financial statements. The Statement also changes the way the consolidated income statement is presented by requiring consolidated net income to be reported at amounts that include the amounts attributable to both the parent and noncontrolling interest. Additionally, SFAS No. 160 establishes a single method for accounting for changes in a parent’s ownership interest in a subsidiary that do not result in deconsolidation. The Statement is effective for the Company beginning January 1, 2009. Management is determining the extent, if any, this adoption will have on the Company’s financial statements in addition to reclassifying the Company’s noncontrolling interests into equity.

The FASB issued SFAS No. 161,Disclosures about Derivative Instruments and Hedging Activities, in March 2008. Under SFAS No. 161, the Company will be required to disclose the fair value of all derivative and hedging instruments and their gains or losses in tabular format and information about credit risk-related features in derivative agreements, counterparty credit risk, and its strategies and objectives for using derivative instruments. SFAS No. 161 is to be applied prospectively by the Company for interim periods and years beginning after November 15, 2008. The Company expects that application of SFAS No. 161 will affect the Company’s disclosures about its derivative and hedging instruments, but will not impact the Company’s accounting for them.

2. DERIVATIVES AND FAIR VALUE MEASUREMENTS

The Company has measured the fair value of its financial derivatives and its Michigan Sales Contract in accordance with SFAS No. 157. All financial instruments are measured using inputs from the three levels of fair value hierarchy. The three levels are as follows:

In accordance with the fair value hierarchy described in Note 1 above, the following table shows the fair value of the Company’s financial assets and liabilities that are required to be measured at fair value as of March 31, 2008.

	Fair Value Measurements as of March 31, 2008
	Balance at
	March 31, 2008		Level 1		Level 2		Level 3
			(In thousands)
Derivative assets	$	22,911	$	—	$	22,911	$	—
Derivative liabilities	$	207,561	$	—	$	207,561	$	—

The fair value of all derivative instruments included above was estimated using commodity prices quoted in active markets for the periods covered by the derivatives and the value confirmed by a counterparty. Estimates were determined by applying the net differential between the prices in each derivative and market prices for future periods, as adjusted for estimated basis differential, to the volumes stipulated in each contract to arrive at an estimated future value. This estimated future value was discounted on each contract at rates commensurate with federal treasury instruments with similar contractual lives.

10

The Company hedges a portion of its production revenue using various financial derivatives. All derivatives are evaluated using the hedge criteria established under U.S. accounting standards. If hedge criteria are met, the change in a derivative’s fair value (for a cash flow hedge) is deferred in stockholders’ equity as a component of accumulated other comprehensive loss. These deferred gains and losses are recognized into income in the period in which the hedged transaction is recognized in revenues to the extent the hedge is effective. The changes in value of ineffective portions of hedges are recognized currently in earnings.

The Company’s derivative instruments at March 31, 2008 and December 31, 2007 include the Michigan Sales Contract that requires delivery of 25 MMcfd of natural gas at a floor of $2.49 Mcf through March 2009. In December 2007, the Company made a decision to no longer deliver a portion of our natural gas production to supply the contract and recognized a $63.5 million loss at that time. In January 2008, the Company entered into two fixed-price natural gas swaps covering all volumes for the remaining contract period, which served to effectively offset the net earnings exposure for the Company’s remaining obligation under the Michigan Sales Contract.

The change in carrying value of the Company’s derivatives and the contractual fixed-price sale commitments in the Company’s balance sheet since December 31, 2007 resulted from the increase in market prices for natural gas, NGL and oil. The change in fair value of all cash flow hedges was reflected in accumulated other comprehensive income, net of deferred tax effects. All derivative assets and liabilities represent the estimated fair value of contract settlements scheduled to occur over each contract period remaining based on commodity market prices as of the balance sheet date. These amounts are not settleable until the monthly period in which the related underlying production is sold.

The estimated fair values of all financial derivatives and contractual fixed-price sale commitments of the Company as of March 31, 2008 and December 31, 2007 are provided below. The carrying values of these derivatives are equal to the estimated fair values for each period presented. The assets and liabilities recorded in the balance sheet are netted where derivatives with both gain and loss positions are held by a single third party.

	March 31,		December 31,
	2008		2007
	(In thousands)
Derivative assets:
Natural gas basis swaps	$	786	$	—
Natural gas fixed-price swaps(1)		22,125		4,666
Natural gas price collars		—		10,491
	$	22,911	$	15,157
Derivative liabilities:
Natural gas basis swaps	$	—	$	1,224
Crude oil price collars		7,562		6,517
NGL fixed-price swaps		7,920		11,294
Natural gas fixed-price swaps		53,735		—
Natural gas price collars		59,925		1,625
Fixed-price natural gas sales contracts(2)		78,419		63,777
	$	207,561	$	84,437

(1)	Includes $22.1 million and $- million for two fixed-priced swaps related to the Michigan Sales Contract at March 31, 2008 and December 31, 2007, respectively.
(2)	Includes $78.1 million and $63.5 million for the Michigan Sales Contract at March 31, 2008 and December 31, 2007, respectively.

Cash flow hedge derivative liabilities of $107.9 million have been classified as current at March 31, 2008 based on the maturity of the derivative instruments, which would result in $70.6 million of after-tax losses being reclassified from accumulated other comprehensive loss over the next twelve months. Additionally over the next twelve months, the Company estimates it will recognize $36.4 million of after-tax losses from settlement of the Michigan Sales Contract and the associated fixed-price swaps.

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3. INVESTMENT IN BREITBURN ENERGY PARTNERS L.P.

The Company received common units of BBEP, a publicly traded limited partnership, as a partial consideration for the divestiture of properties and assets to BreitBurn Operating, L.P. which closed on November 1, 2007. At March 31, 2008, the Company held approximately 32% of the BBEP common units outstanding.

The Company accounts for its investment in BBEP units using the equity method, utilizing a one quarter lag from BBEP’s publicly-available information. BBEP is primarily engaged in natural gas, NGL and crude oil production in the United States.

Summarized unaudited financial information for BBEP is as follows:

				Estimated
	As of			Two Months Ended
	December 31, 2007			December 31, 2007
	(In thousands)			(In thousands)
Current assets	$	97,763	Revenues	$	61,165
Property, plant and equipment		1,864,487	Operating expenses		44,365
Other assets		24,306	Operating income		16,800
Current liabilities		90,684	Interest and other		4,403
Long-term debt		370,400	Income tax benefit		(669	)
Other non-current liabilities		100,664	Minority interests		31
Partners’ equity		1,424,808	Net income	$	13,035
			Net income available to common unitholders	$	12,567

For the quarter ended March 31, 2008, the Company recognized $6.2 million to record its share of earnings in BBEP for the two months November 1 though December 31, 2007. The Company’s share of BBEP’s estimated earnings for the two months ended December 31, 2007 includes reductions of depletion and depreciation expense and intangible asset amortization which originated from retention bonuses to the Company’s former employees in the Northeast Operations that will be paid by the Company.

At March 31, 2008, the Company’s carrying value for its BBEP common units was $416.7 million inclusive of a $292.3 million gain deferred from the transaction. The market value of the Company’s BBEP units was $428.7 million, or $20.08 per common unit, at March 31, 2008.

12

4. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment consisted of the following:

	March 31,			December 31,
	2008			2007
	(In thousands)
Oil and gas properties
Subject to depletion	$	2,008,159		$	1,811,295
Unevaluated costs		281,130			215,228
Accumulated depletion		(287,831	)		(262,123	)
Net oil and gas properties		2,001,458			1,764,400
Other plant and equipment
Pipelines and processing facilities		386,129			347,187
General properties		35,103			32,966
Construction in progress		47,689			32,682
Accumulated depreciation		(39,615	)		(34,889	)
Net other property and equipment		429,306			377,946
Property, plant and equipment, net of accumulated depletion and depreciation	$	2,430,764		$	2,142,346

5. LONG-TERM DEBT

Long-term debt consisted of the following:

	March 31,		December 31,
	2008		2007
	(In thousands)
Senior secured credit facility	$	586,176	$	310,710
Senior subordinated notes		350,000		350,000
Convertible debentures, net of unamortized discount		148,135		148,107
KGS credit agreement		31,500		5,000
Other loans		—		34
Total debt		1,115,811		813,851
Less current maturities		—		(34	)
Long-term debt	$	1,115,811	$	813,817

For a more complete description of the Company’s indebtedness, see Note 13,Long-Term Debt,to the consolidated financial statements in the Company’s 2007 Annual Report on Form 10-K. As of May 9, 2008, the Company’s borrowing base under its senior secured credit facility was increased to $1 billion from $750 million and will be subject to an interim redetermination on or about November 1, 2008.

6. ASSET RETIREMENT OBLIGATIONS

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

The following table provides a reconciliation of the changes in the Company’s estimated asset retirement obligation for the three-month periods ended March 31, 2008 and 2007.

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	For the Three Months Ended
	March 31,
	2008			2007
	(In thousands)
Beginning asset retirement obligations	$	24,509		$	25,206
Additional liability incurred		1,060			1,454
Accretion expense		352			361
Change in estimates		361			—
Asset retirement costs incurred		(143	)		—
Currency translation adjustment		(504	)		115
Ending asset retirement obligations		25,635			27,136
Less current portion		(646	)		(149	)
Long-term asset retirement obligation	$	24,989		$	26,987

7. INCOME TAXES

During the quarter ended March 31, 2008, there were no changes to the Company’s unrecognized U.S. tax benefits, which totaled $10.0 million at December 31, 2007. If required, interest or penalties will be recognized as a component of interest expense. The Company does not anticipate total unrecognized tax benefits to significantly change due to the settlement of audits or the expiration of statute of limitations.

The Internal Revenue Service completed its audit of the Company’s 2004 Federal income tax return in April 2008. The Company remains subject to examination by the Internal Revenue Service for the years 2001 through 2007. The Company’s subsidiary, QRCI, because of its Canadian tax pool balances, remains subject to examination by the Canada Revenue Agency (“Revenue Canada”) for the years 1999 through 2007.

During the first quarter of 2008, the Company paid $47 million for income taxes for the 2007 tax year, which primarily resulted from the tax-basis gain from the BreitBurn Transaction.

In May 2006, the Texas legislature amended the Texas tax code by replacing the taxable capital and earned surplus components of the existing franchise tax with a new “taxable margin” component which became effective for the Company on January 1, 2007. The Company has not recognized any unrecognized tax benefits for the Texas “taxable margin” tax.

8. COMMITMENTS AND CONTINGENCIES

As previously reported in the Company’s 2007 Annual Report on Form 10-K, on October 13, 2006, the Company filed suit in the 342nd Judicial District Court in Tarrant County, Texas against Eagle Drilling, LLC and Eagle Domestic Drilling Operations, LLC (together “Eagle”) regarding three contracts for drilling rigs in which the Company alleges that the first rig furnished by Eagle exhibited operating deficiencies and safety defects and that the other rigs failed to conform to specifications set forth in the drilling contracts. Subsequently, on January 19, 2007, Eagle Domestic Drilling Operations, LLC and its parent, Blast Energy Services, Inc. filed for Chapter 11 bankruptcy in the United States Bankruptcy Court for the Southern District of Texas, Houston Division. The Company’s suit against Eagle in Tarrant County was ultimately transferred to the Bankruptcy Court in Houston and was consolidated with the Eagle/Blast bankruptcy. On September 17, 2007, Eagle Drilling, LLC, and Rod and Richard Thornton, sued the Company and P. Jeff Cook, the Company’s Executive Vice President-Operations, in the District Court of Cleveland County, Oklahoma for approximately $29 million in damages and an unspecified amount of punitive damages resulting from the Company’s decision to repudiate the rig contracts mentioned above. Based upon information currently available, the Company believes that the final resolution of this matter will not have a material effect on the Company’s financial condition, results of operations, or cash flows.

KGS has entered into agreements with third parties providing for the construction of natural gas processing facilities and natural gas compression equipment for the facilities. Progress payments are due to the third parties upon completion of established construction, manufacturing and delivery milestones. During the three months ended March 31, 2008, $19.0 million was paid to the third parties. KGS estimates additional payments of $81.0 million will be made upon completion of specified construction, manufacturing and delivery milestones.

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

14

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

9. STOCK-BASED COMPENSATION

For a more complete description of the Company’s equity plans, see Note 19,Stockholders’ Equity, to the consolidated financial statements in our 2007 Annual Report on Form 10-K.

Quicksilver Stock Options

At January 1, 2008, the Company had total compensation cost of $0.1 million related to unvested stock options with a weighted average remaining vesting period of 2.2 years. In the first quarter of 2008, the Company granted 373,382 options to purchase shares of common stock at an exercise price of $30.95. These option grants had an estimated fair value of $5.1 million on the date of grant. The Company recorded expense of $0.5 million and $0.1 million for stock options in the first three months of 2008 and 2007, respectively. At March 31, 2008, the Company had $4.3 million of expense remaining in unrecognized compensation cost for the unvested portion of stock options.

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

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

The following table summarizes the Company’s stock option activity during the first three months of 2008:

			Wtd Avg		Wtd Avg
			Exercise		Remaining		Aggregate
	Shares		Price		Contractual Life		Intrinsic Value
					(In years)		(In thousands)
Outstanding at December 31, 2007		1,021,912	$	6.38
Granted		373,382		30.95
Exercised		186,988		4.60
Cancelled		28,220		26.78
Outstanding at March 31, 2008		1,180,086	$	13.97		4.4	$	26,626
Exercisable at March 31, 2008		630,378	$	7.19		2.2	$	18,497
Vested or expected to vest at March 31, 2008		1,164,147	$	14.08

Cash received from the exercise of stock options totaled $0.9 million and $3.0 million for the first quarter of 2008 and 2007, respectively. The intrinsic value of the options exercised in the first three months of 2008 was $4.9 million.

Quicksilver Restricted Stock and Restricted Stock Units

At January 1, 2008, the Company had total unvested compensation cost of $15.2 million related to unvested restricted stock and stock unit awards. The 2008 first quarter grants of restricted stock and stock units had an estimated fair value of $16.9 million at the time of grant which will be recognized as expense over the vesting period. During the first three months of 2008 and 2007, the Company recognized $3.2 million and $2.8 million, respectively, of expense for vesting of restricted stock and stock units. Total unvested compensation cost was $27.6 million at March 31, 2008 which will be recognized over a weighted average remaining vesting period of 1.2 years.

15

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

			Wtd Avg
			Grant Date
	Shares		Fair Value
Outstanding at December 31, 2007		1,340,122	$	18.76
Granted		538,305		31.39
Vested		347,230		30.17
Cancelled		81,965		22.12
Outstanding at March 31, 2008		1,449,232	$	23.24

The total fair value of shares and units vested during the three months ended March 31, 2008 was $3.5 million.

KGS Restricted Phantom Units

The following table summarizes information regarding KGS phantom unit activity:

	Payable in cash					Payable in units
				Wtd Avg					Wtd Avg
				Grant Date					Grant Date
	Units			Fair Value		Units			Fair Value
Outstanding at December 31, 2007		84,961		$	21.36		9,833		$	21.36
Vested		—			—		(6,089	)		21.36
Issued		2,751			23.63		137,148			25.25
Cancelled		(3,000	)		21.36		—			—
Outstanding at March 31, 2008		84,712		$	21.43		140,892		$	25.15

KGS recognized compensation expense of approximately $0.4 million during the three months ended March 31, 2008, including $0.2 million for remeasuring awards to be settled in cash to their revised fair value. Unearned compensation related to KGS restricted phantom units of approximately $4.2 million at March 31, 2008 will be recognized in expense over the next 2.9 years. Phantom units that vested during the three months ended March 31, 2008 had a fair value of $0.2 million on their vesting date.

10. CONDENSED CONSOLIDATING FINANCIAL INFORMATION

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

As part of the divestiture of properties and assets to BreitBurn Operating, L.P., Quicksilver sold its interests in Mercury Michigan, Inc., Terra Energy Ltd., GTG Pipeline Corporation, Terra Pipeline Company and Beaver Creek Pipeline, LLC, each of which had been a guarantor of Quicksilver’s Senior Subordinated Notes. The results of operations and cash flows of these subsidiaries for the 2007 period are included as non-guarantor subsidiaries in the condensed consolidating financial statements to conform to the current presentation.

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Condensed Consolidating Balance Sheets

	March 31, 2008
										Quicksilver
	Quicksilver		Guarantor		Non-Guarantor					Resources Inc.
	Resources Inc.		Subsidiaries		Subsidiaries		Eliminations			Consolidated
					(In thousands)
ASSETS
Current assets	$	311,609	$	—	$	270,544	$	(345,146	)	$	237,007
Property and equipment		1,481,585		10,953		938,226		—			2,430,764
Investment in subsidiaries (equity method)		790,711		168,747		—		(542,727	)		416,731
Other assets		75,301		110,743		2,329		(162,934	)		25,439
Total assets	$	2,659,206	$	290,443	$	1,211,099	$	(1,050,807	)	$	3,109,941
LIABILITIES AND STOCKHOLDERS EQUITY
Current liabilities	$	503,880	$	113,585	$	138,451	$	(345,146	)	$	410,770
Long-term liabilities		1,129,052		—		598,051		(162,934	)		1,564,169
Deferred gain		—		—		79,316		—			79,316
Minority interest		—		—		29,412		—			29,412
Stockholders’ equity		1,026,274		176,858		365,869		(542,727	)		1,026,274
Total liabilities and stockholders’ equity	$	2,659,206	$	290,443	$	1,211,099	$	(1,050,807	)	$	3,109,941

	December 31, 2007
										Quicksilver
	Quicksilver		Guarantor		Non-Guarantor					Resources Inc.
	Resources Inc.		Subsidiaries		Subsidiaries		Eliminations			Consolidated
					(In thousands)
ASSETS
Current assets	$	213,288	$	596	$	243,086	$	(266,569	)	$	190,401
Property and equipment		1,294,573		1,858		845,915		—			2,142,346
Investment in subsidiaries (equity method)		819,119		160,825		—		(559,773	)		420,171
Other assets		72,426		82,251		2,171		(133,920	)		22,928
Total assets	$	2,399,406	$	245,530	$	1,091,172	$	(960,262	)	$	2,775,846
LIABILITIES AND STOCKHOLDERS EQUITY
Current liabilities	$	470,690	$	77,529	$	76,925	$	(266,569	)	$	358,575
Long-term liabilities		860,361		—		512,821		(133,920	)		1,239,262
Deferred gain		—		—		79,316					79,316
Minority interest		—		—		30,338					30,338
Stockholders’ equity		1,068,355		168,001		391,772		(559,773	)		1,068,355
Total liabilities and stockholders’ equity	$	2,399,406	$	245,530	$	1,091,172	$	(960,262	)	$	2,775,846

17

Condensed Consolidating Statements of Income

	For the Three Months Ended March 31, 2008
													Quicksilver
	Quicksilver			Guarantor			Non-Guarantor						Resources Inc.
	Resources Inc.			Subsidiaries			Subsidiaries			Eliminations			Consolidated
							(In thousands)
Revenues	$	116,887		$	—		$	53,261		$	(12,645	)	$	157,503
Operating expenses		66,957			499			32,083			(12,645	)		86,894
Income from equity affiliates		—			—			—						—
Operating income		49,930			(499	)		21,178			—			70,609
Equity in net earnings of subsidiaries		11,895			2,376			—			(14,271	)		—
Income from earnings of BreitBurn Energy Partners		6,219			—			—						6,219
Interest expense and other		(5,446	)		1,433			(6,727	)					(10,740	)
Income tax provision		(20,422	)		(327	)		(3,163	)					(23,912	)
Net income	$	42,176		$	2,983		$	11,288		$	(14,271	)	$	42,176

	For the Three Months Ended March 31, 2007
													Quicksilver
	Quicksilver			Guarantor			Non-Guarantor						Resources Inc.
	Resources Inc.			Subsidiaries			Subsidiaries			Eliminations			Consolidated
							(In thousands)
Revenues	$	70,868		$	—		$	50,190		$	(4,478	)	$	116,580
Operating expenses		46,461			459			25,693			(4,478	)		68,135
Income from equity affiliates		6						109						115
Operating income		24,413			(459	)		24,606			—			48,560
Equity in net earnings of subsidiaries		14,736			1,281			—			(16,017	)		—
Interest expense and other		(11,120	)		(63	)		(3,231	)					(14,414	)
Income tax provision		(5,178	)		183			(6,300	)					(11,295	)
Net income	$	22,851		$	942		$	15,075		$	(16,017	)	$	22,851

Condensed Consolidating Statements of Cash Flows

	For the Three Months Ended March 31, 2008
													Quicksilver
	Quicksilver			Guarantor			Non-Guarantor						Resources Inc.
	Resources Inc.			Subsidiaries			Subsidiaries			Eliminations			Consolidated
							(In thousands)
Cash flow provided by operations	$	(45,590	)	$	9,093		$	79,781					$	43,284
Cash flow used for investing activities		(231,747	)		23,270			(132,502	)		(37,667	)		(378,646	)
Cash flow provided by financing activities		252,122			(32,363	)		52,160			37,667			309,586
Effect of exchange rates on cash		(58	)		—			(416	)					(474	)
Net increase (decrease) in cash and equivalents		(25,273	)		—			(977	)		—			(26,250	)
Cash and equivalents at beginning of period		27,010			—			1,216			—			28,226
Cash and equivalents at end of period	$	1,737		$	—		$	239		$	—		$	1,976

18

	For the Three Months Ended March 31, 2007
													Quicksilver
	Quicksilver			Guarantor			Non-Guarantor						Resources Inc.
	Resources Inc.			Subsidiaries			Subsidiaries			Eliminations			Consolidated
							(In thousands)
Cash flow provided by operations	$	42,754		$	(231	)	$	30,483					$	73,006
Cash flow used for investing activities		(166,157	)		(24,282	)		(67,639	)		48,354			(209,724	)
Cash flow provided by financing activities		123,755			24,513			37,010			(48,354	)		136,924
Effect of exchange rates on cash		—			—			231						231
Net increase (decrease) in cash and equivalents		352			—			85						437
Cash and equivalents at beginning of period		83			—			5,198						5,281
Cash and equivalents at end of period	$	435		$	—		$	5,283		$	—		$	5,718

11. SUPPLEMENTAL CASH FLOW INFORMATION

Cash paid for interest and income taxes is as follows:

	Three Months Ended
	March 31,
	2008		2007
	(In thousands)
Interest	$	18,295	$	6,443
Income taxes		47,196		734

Other non-cash transactions are as follows:

	Three Months Ended
	March 31,
	2008		2007
	(In thousands)
Noncash changes in working capital related to acquisition of property, plant and equipment — net	$	14,536	$	(27,597	)

12. RELATED-PARTY TRANSACTIONS

As of March 31, 2008, 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 F. Darden, Glenn Darden and Anne Darden Self are officers and directors of the Company.

Quicksilver and its associated entities paid $0.6 million and $0.5 million in the first three months of 2008 and 2007, respectively, for rent on buildings owned by Pennsylvania Avenue LP (“PALP”), a Mercury affiliate, and WFMG, L.P., a PALP affiliate. Rental rates have been determined based on comparable rates charged by third parties.

Payments received from Mercury for sublease rentals, employee insurance coverage and administrative services during the first three months of 2008 and 2007 totaled $0.1 million.

The Company paid $0.2 million during both the first three months of 2008 and 2007 for use of an airplane owned by Sevens Aviation, LLC, a company owned indirectly by members of the Darden family. Usage rates are determined based on comparable rates charged by third parties.

13. SEGMENT INFORMATION

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

19

	Exploration & Production				Processing &								Quicksilver
	United States		Canada		Gathering		Corporate			Elimination			Consolidated
					(In thousands)
For the Three Months Ended March 31,
2008
Revenues	$	116,731	$	38,512	$	15,185	$	—		$	(12,925	)	$	157,503
Depletion, depreciation and accretion		20,089		11,431		3,275		264						35,059
Operating income		62,951		16,716		4,805		(13,863	)					70,609
Property and equipment costs incurred		212,006		76,443		54,430		361						343,240
2007
Revenues	$	79,220	$	36,151	$	5,372	$	—		$	(4,163	)	$	116,580
Depletion, depreciation and accretion		14,308		8,752		1,308		226						24,594
Operating income		38,230		18,978		1,276		(9,924	)					48,560
Property and equipment costs incurred		135,415		19,559		26,999		605						182,578
Property, Plant and Equipment
March 31, 2008	$	1,477,659	$	615,916	$	332,772	$	4,417					$	2,430,764
December 31, 2007		1,290,728		571,496		275,807		4,315						2,142,346

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

RESULTS OF OPERATIONS

Summary Financial Data
Three Months Ended March 31, 2008 Compared with the Three Months Ended March 31, 2007

Revenues

Oil, Gas and Related Product Sales

Production revenues, average daily volumes and average realized sales prices with respect to natural gas, oil and related products for the three months ended March 31, 2008 and 2007 are as follows:

Production Revenues:

	Natural Gas					NGL					Oil and Condensate					Equivalent Total
	2008			2007		2008			2007		2008			2007		2008			2007
									(In millions)
Texas	$	58.6		$	20.2	$	48.4		$	9.0	$	6.5		$	1.3	$	113.5		$	30.5
Northeast Operations		—			29.4		—			0.9		—			4.3		—			34.6
Other U.S.		0.3			0.3		0.3			0.2		3.8			2.0		4.4			2.5
Hedging		2.5			11.7		(3.6	)		—		(1.5	)		—		(2.6	)		11.7
Total U.S.		61.4			61.6		45.1			10.1		8.8			7.6		115.3			79.3
Canada		43.5			31.6		—			—		—			—		43.5			31.6
Hedging		(0.4	)		2.4		—			—		—			—		(0.4	)		2.4
Total Canada		43.1			34.0		—			—		—			—		43.1			34.0
Total Company	$	104.5		$	95.6	$	45.1		$	10.1	$	8.8		$	7.6	$	158.4		$	113.3

Average Daily Production Volumes:

	Natural Gas				NGL				Oil and Condensate				Equivalent Total
	2008		2007		2008		2007		2008		2007		2008		2007
	(MMcfd)				(Bbld)				(Bbld)				(MMcfed)
Texas		80.4		32.2		9,989		2,900		777		260		145.0		51.2
Northeast Operations		—		68.7		—		388		—		933		—		76.7
Other U.S.		0.5		0.4		41		28		474		472		3.6		3.3
Total U.S.		80.9		101.3		10,030		3,316		1,251		1,665		148.6		131.2
Canada		62.5		56.1		—		—		—		—		62.5		56.1
Total Company		143.4		157.4		10,030		3,316		1,251		1,665		211.1		187.3

21

Average Realized Prices:

	Natural Gas					NGL					Oil and Condensate					Equivalent Total
	2008			2007		2008			2007		2008			2007		2008			2007
	(per Mcf)					(per Bbl)					(per Bbl)					(per Mcfe)
Texas	$	8.01		$	6.97	$	53.28		$	34.60	$	91.58		$	54.62	$	8.60		$	6.63
Northeast Operations		—			4.75		—			26.93		—			51.58		—			5.03
Other U.S.		4.36			7.12		84.30			39.01		88.65			47.83		13.80			7.83
Hedging — U.S.		0.35			1.31		(4.05	)		—		(13.01	)		—		(0.19	)		1.01
Total U.S.	$	8.34		$	6.75	$	49.36		$	33.81	$	77.46		$	50.99	$	8.53		$	6.72
Canada	$	7.64		$	6.25	$	—		$	—	$	—		$	—	$	7.64		$	6.25
Hedging — Canada		(0.07	)		0.48		—			—		—			—		(0.07	)		0.48
Canada	$	7.57		$	6.73	$	—		$	—	$	—		$	—	$	7.57		$	6.73
Total Company	$	8.00		$	6.75	$	49.36		$	33.81	$	77.46		$	50.99	$	8.24		$	6.72

The following table summarizes the changes in the production revenues during the quarter ended March 31, 2008 compared with the comparable 2007 period:

	Natural
	Gas			NGL		Oil			Total
				(In thousands)
Revenue for the quarter ended March 31, 2007	$	95,562		$	10,091	$	7,639		$	113,292
Volume changes		(8,883	)		30,321		(2,790	)		18,648
Price changes		17,808			4,641		3,967			26,416
Revenue for the quarter ended March 31, 2008	$	104,487		$	45,053	$	8,816		$	158,356

Natural gas sales of $104.5 million for the first quarter of 2008 were $8.9 million or 9% higher than the first quarter of 2007. Natural gas sales increased as a result of a $1.25 per Mcf or 19% increase in realized natural gas prices for the first quarter of 2008 as compared to the 2007 period. Natural gas sales volumes decreased 1.1 Bcf or 8%. The decreased volumes are principally attributable to the absence of 6.2 Bcf of natural gas sales from the Northeast Operations which were divested in November 2007. Partially offsetting that decrease was additional production in the Fort Worth Basin of 4.4 Bcf and 0.6 Bcf in our CBM projects in Canada. Both increases were the result of new wells placed into production subsequent to the first quarter of 2007 partially offset by decreases due to natural production declines.

Our first quarter 2008 NGL sales of $45.1 million increased $35.0 million or over 340% as compared to the first quarter of 2007. The NGL sales increase was almost entirely due to higher production volumes for the first quarter of 2008, principally in the Fort Worth Basin. The production volume increase was due to new wells placed into production subsequent to the first quarter of 2007 and improved NGL recovery from our newest processing facility in the Fort Worth Basin that began operations in March 2007. More favorable realized pricing during the 2008 quarter also impacted NGL sales. Partially offsetting the Fort Worth Basin and pricing increases was the absence of production from the Northeast Operations.

Oil sales were $8.8 million for the quarter ended March 31, 2008 which was an increase of 15% or $1.2 million from the comparable 2007 period. The increase is attributable to higher realized prices partially offset by a net decrease in production. The absence of production from the Northeast Operations was only partially offset by a 47.2 MBbl increase in Fort Worth Basin oil production.

Other Revenue

Other revenue in the quarter ended March 31, 2008 decreased $4.1 million from the comparable 2007 period. The derivatives hedging our Canadian production were partially ineffective which resulted in a charge of $5.1 million for the change in fair value of the ineffective portion during the quarter ended March 31, 2008. Additional third-party processing and transportation revenue of $1.1 million for KGS partially offset that loss.

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Operating Expenses

Oil and Gas Production Cost

	Three Months Ended March 31,
	2008				2007
	(In thousands, except per unit amounts)
			Per				Per
			Mcfe				Mcfe
Texas
Cash expense	$	21,836	$	1.66	$	7,212	$	1.56
Equity compensation		314		0.02		117		0.03
	$	22,150	$	1.68	$	7,329	$	1.59
Northeast Operations
Cash expense	$	—	$	—	$	12,624	$	1.83
Equity compensation		—		—		302		0.04
	$	—	$	—	$	12,926	$	1.87
Other U.S.
Cash expense	$	888	$	2.41	$	744	$	2.94
Equity compensation		48		0.15		37		0.12
	$	936	$	2.56	$	781	$	3.06
Total U.S.
Cash expense	$	22,724	$	1.68	$	20,580	$	1.74
Equity compensation		362		0.03		456		0.04
	$	23,086	$	1.71	$	21,036	$	1.78
Canada
Cash expense	$	8,763	$	1.54	$	7,047	$	1.39
Equity compensation		681		0.12		486		0.10
	$	9,444	$	1.66	$	7,533	$	1.49
Total Company
Cash expense	$	31,487	$	1.64	$	27,627	$	1.64
Equity compensation		1,043		0.05		942		0.06
	$	32,530	$	1.69	$	28,569	$	1.70

Oil and gas production cost was $32.5 million for the first quarter of 2008, an increase of $4.0 million or 14% from the comparable 2007 period. The $4.0 million increase from the prior year quarter was the result of increases of over $2.0 million and $1.9 million for U.S. and Canadian production costs, respectively. In general, these increases are attributable to the aggregate 14% increase in production, inclusive of the 13% increase in Canadian production and absence of production as a result of the divestiture of the Northeast Operations.

Oil and gas production cost for the United States was $23.1 million for the first quarter of 2008, an increase of 10% compared with the comparable 2007 period. The growth of our operations in the Fort Worth Basin increased operating expense approximately $14.8 million for the first quarter of 2008 compared to the 2007 period. The increases were comprised primarily of increased direct salary and benefits, repair and maintenance costs, compression costs, processing costs and higher production overhead costs. Partially offsetting this increase was a $12.9 million decrease in production expense that resulted from the divestiture of the Northeast Operations in November 2007.

Texas lease operating expenses per Mcfe for the first quarter of 2008 increased 6% as compared to the 2007 quarter primarily because of prevailing Fort Worth Basin cost increases instituted by certain vendors and increased repair and maintenance costs and compression costs as well as the current scale of operations associated with KGS’ gas facilities operations.

Canadian oil and gas production cost was $9.4 million for the first quarter of 2008, an increase of 25% compared to the first quarter of 2007. Currency effects increased expense approximately $1.2 million as the Canadian dollar strengthened in relation to the U.S. dollar between the two periods.. Canadian expense was also impacted by increased gas processing and transportation costs, utility costs and higher production overhead attributable to higher salary and rent costs for the first quarter of 2008 as compared to the 2007 first quarter period.

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Production and Ad Valorem Taxes

	Three Months Ended March 31,
	2008				2007
	(In thousands, except per unit amounts)
			Per				Per
			Mcfe				Mcfe
Production and ad valorem taxes
U.S.	$	1,738	$	0.13	$	3,602	$	0.31
Canada		921		0.16		888		0.16
Total production and ad valorem taxes	$	2,659	$	0.14	$	4,490	$	0.27

Production and ad valorem tax expense for the first quarter of 2008 was $2.7 million, a decrease of 41% compared to the first quarter of 2007. First quarter 2008 production taxes decreased $1.4 million due to the absence of production for the Northeast Operations partially offset by production increases for Texas, where many of our properties are exempt from or carry a lower rate of production tax based on their drilling cost. Ad valorem taxes decreased $0.5 million also as the result of the absence of the Northeast Operations partially offset by additional property values that have resulted from our drilling program in the Fort Worth Basin and additions to our extensive gathering network.

Other Operating Costs

Other operating costs, which principally relate to the cost of processing and gathering third-party natural gas in Texas, were $1.2 million for the first quarter of 2008. The $0.4 million increase from the prior year quarter relates to the increased cost associated with the expansion of the operating capabilities of our KGS subsidiary with respect to gathering and processing services in the Fort Worth Basin.

Depletion, Depreciation and Accretion

	Three Months Ended March 31,
	2008				2007
	(In thousands, except per unit amounts)
			Per				Per
			Mcfe				Mcfe
Depletion
U.S.	$	19,062	$	1.41	$	12,638	$	1.07
Canada		10,505		1.85		7,722		1.53
Total depletion		29,567		1.54		20,360		1.21
Depreciation of other fixed assets:
U.S.	$	4,422	$	0.33	$	2,994	$	0.25
Canada		718		0.13		879		0.17
Total depreciation		5,140		0.27		3,873		0.23
Accretion		352		0.02		361		0.02
Total depletion, depreciation and accretion	$	35,059	$	1.82	$	24,594	$	1.46

Depletion for the first quarter of 2008 was $29.6 million, which was $9.2 million or 45% higher than depletion for the first quarter of 2007. Higher depletion resulted from a 27% increase in the depletion rate and a 14% increase in sales volumes. Our higher depletion rate for the first quarter of 2008 resulted from significant increases in estimated future capital expenditures and the costs of proved reserves added from our Canadian and Fort Worth Basin properties. The $1.3 million increase in depreciation for the first quarter of 2008 as compared to the 2007 first quarter was primarily associated with additions of Fort Worth Basin field compression, gas processing facilities and gathering system assets.

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General and Administrative Expense

	Three Months Ended March 31,
	2008				2007
	(In thousands, except per unit amounts)
			Per				Per
			Mcfe				Mcfe
General and administrative expense
Cash expense	$	12,296	$	0.64	$	7,740	$	0.46
Equity compensation		3,119		0.16		1,958		0.12
Total general and administrative expense	$	15,415	$	0.80	$	9,698	$	0.58

General and administrative expense for the three months ended March 31, 2008 was $15.4 million, an increase of $5.7 million or 59% compared to the quarter ended March 31, 2007. This correlates to $0.80 per Mcfe for the first quarter of 2008 compared with $0.58 per Mcfe for the comparable 2007 period. The most significant increase in general and administrative expense for the first quarter of 2008 was a $3.5 million increase in employee compensation and benefits, including approximately $1.2 million of non-cash expense for vesting of stock-based compensation and approximately $1.0 million in performance-based compensation to be paid in or after the fourth quarter of 2008. The remaining $1.3 million increase in employee compensation is related to increased headcount which was necessary to bring our infrastructure to a level needed to accommodate the anticipated growth in our production. Fees for legal, accounting and other professional services increased general and administrative expense by approximately $1.8 million for the 2008 first quarter as compared to the 2007 first quarter. Higher fees for the first quarter of 2008 were the result of KGS’ ongoing costs associated with activities and requirements for a publicly-traded partnership and activity associated with our divestiture of the Northeast Operations.

Interest Expense

Interest expense for the first quarter of 2008 was $11.8 million, net of capitalized interest of $1.7 million, which was a decrease of $3.1 million or 21% compared to the first quarter of 2007. Interest expense for the first quarter of 2008 was lower than the 2007 first quarter, in part, because of an additional $1.1 million of capitalized interest and a decrease in the average interest rate on our debt balances outstanding. These items decreased interest expense approximately $2.8 million for the quarter ended March 31, 2008. Interest expense also decreased as a result of our lower average outstanding debt balance for the first quarter of 2008 compared to the 2007 as the cash proceeds received in November 2007 from the BrietBurn Transaction allowed us to maintain a lower average debt balance outstanding.

Income Tax Expense

	Three Months Ended
	March 31,
	2008			2007
Income tax (in thousands)	$	23,912		$	11,295
Effective tax rate		35.9	%		33.0	%

Our provision for income taxes for the first quarter of 2008 increased $12.6 million from the prior year period to $23.9 million. Pretax income for the first quarter of 2008 increased $32.4 million and resulted in an $11.3 million increase in federal income tax expense. The remaining income tax increase of $1.3 million consisted of an increase in Texas margin deferred income taxes and the loss of deductions because of the limitations imposed on a portion of officers’ compensation expense. These increases were partially offset by a decrease in the Canadian statutory tax rate to 25% from 29% in 2007.

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LIQUIDITY, CAPITAL RESOURCES AND FINANCIAL POSITION

	For the Three Months Ended
	March 31,
	2008			2007
	(In thousands)
Net cash provided by operating activities	$	43,284		$	73,006
Net cash used for investing activities		(378,646	)		(209,724	)
Net cash provided by financing activities		309,586			136,924
Effect of exchange rate changes in cash		(474	)		231

Net cash provided by operations was $43.3 million for the three months ended March 31, 2008, a decrease of $29.7 million compared to the same period in 2007. Net income of $42.2 million for the first three months of 2008 was $19.3 million higher than net income for the first three months of 2007 and non-cash expenses, including depletion, depreciation and amortization, deferred taxes, stock-based compensation, derivative activities and deferred financing costs were $29.1 million higher for the three months ended March 31, 2008. Changes to working capital for the first quarter of 2008 included a $47.0 million payment for 2007 U.S. federal income taxes, whereas no comparable amount was paid in 2007 for the 2006 tax year.

Our principal sources of cash are revenues generated by our production. Price collars and swaps covered approximately 72% of our total production for the three months ended March 31, 2008. At March 31, 2008, we had price collars or fixed price swaps hedging our anticipated natural gas, oil and NGL production of approximately 147 MMcfd, 1,000 Bbld and 3,000 Bbld, respectively, for the remainder of 2008. We have hedged approximately 150 MMcfd of our anticipated 2009 natural gas sales using price collars and fixed-price swaps.

During the first three months of 2007, the Northeast Operations generated cash of approximately $19.3 million. A 2008 first quarter distribution of $9.7 million on our BBEP common units, including approximately $6.2 million included in operating cash flows, partially offset the decrease in generated cash due to the divestiture of our Northeast Operations.

During the first quarter of 2008, we paid $331.9 million for property and equipment, an increase of more than $120 million compared to the first quarter of 2007. Property and equipment acquired (payments for property and equipment plus noncash changes in working capital associated with property and equipment) for the 2008 period totaled $343.2 million, which consisted primarily of $286.4 million expended for exploration and development activities, $53.1 million expended for our Fort Worth basin gas processing and gathering operations. Of the $286.4 million incurred for exploration and development, $11.6 million and $54.3 million was spent for non-producing leasehold costs in the United States and Canada, respectively, inclusive of our acquisition of acreage in the Horn River Basin in northeast British Columbia.

	Three Months Ended
	March 31, 2008
	(In thousands)
Exploration and development:
Texas	$	202,100
Other U.S.		4,209
Total U.S.		206,309
Canada		75,946
Total exploration and development		282,255
Midstream:
Texas		58,394
Canada		173
Total midstream		58,567
Corporate and field office		2,418
Total plant and equipment costs incurred	$	343,240

Net cash provided by financing activities for the three months ended March 31, 2008 totaled $309.6 million. At March 31, 2008, approximately $162 million was available for borrowing under our senior secured credit facility. As of May 9, 2008, the borrowing base under our senior secured credit facility was increased to $1 billion from $750 million and will be subject to an interim redetermination on or about November 1, 2008. 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

26

covenants at March 31, 2008. KGS’ $150 million senior secured credit facility had $31.5 million of borrowings outstanding at March 31, 2008. KGS was in compliance with the covenants under its senior secured credit facility. Approximately $74 million was available for borrowing under the KGS senior secured credit facility.

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

	March 31,		December 31,
	2007		2007
	(In thousands)
Long-term and short-term debt:
Senior secured credit facility	$	586,176	$	310,710
Senior subordinated notes		350,000		350,000
Convertible subordinated debentures		148,135		148,107
KGS credit agreement		31,500		5,000
Other loans		—		34
Total debt		1,115,811		813,851
Stockholders’ equity		1,026,274		1,068,355
Total capitalization	$	2,142,085	$	1,882,206

Financial Position

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

• An increase of over $288.0 million in our net property, plant and equipment assets, which includes approximately $343.2 million in capital costs incurred principally for development, exploitation and exploration of our oil and gas properties as well as additional natural gas processing and gathering system assets.

• We incurred additional long-term debt of $312.7 million, primarily as a result of our capital expenditure program and partially offset by cash flow from operations. These borrowings have been drawn from our senior secured credit facility and the KGS credit facility.

• Our current and deferred derivative assets have increased $11.0 million, and our current and deferred derivative liabilities have increased $122.2 million and $4.1 million, respectively. Current derivative assets of $22.1 million represent fixed-price swaps entered into in January 2008 to offset our net earnings exposure for the remaining contract period under the Michigan Sales Contract. Our current derivative liabilities include $78.1 million for the estimated fair value of the Michigan Sales Contract. All other changes in derivative assets and liabilities reflect changes in the estimated fair value of our cash-flow hedge derivatives. The changes are the result of higher pricing of natural gas, crude oil and NGLs compared to our derivative contracts at March 31, 2008 as market prices have generally trended upward. Additionally, our current deferred tax asset increased $35.2 million as a result of the increase in estimated fair value of our natural gas, crude oil and NGL financial derivatives.

Accounting Developments

The information regarding recent accounting pronouncements is included in Note 1 to our condensed consolidated interim financial statements included in Item 1 of this quarterly report.

Critical Accounting Estimates

Management’s discussion and analysis of financial condition and results of operations are based on our condensed consolidated financial statements and related footnotes contained within this quarterly report. Our more critical accounting estimates used in the preparation of the consolidated financial statements were discussed in our 2007 Annual Report on Form 10-K. These critical estimates, for which no significant changes have occurred in the three months ended March 31, 2008, include:

• Oil and Gas Properties;

• Ceiling Test;

• Oil and Gas Reserves;

• Derivative Instruments;

• Asset Retirement Obligations;

• Stock-based Compensation;

• Income Taxes;

27

• Income from Earnings of BreitBurn Energy Partners;

• Revenue.

The process of preparing financial statements in conformity with GAAP requires the use of estimates and assumptions to determine certain of the assets, liabilities, revenues and expenses. These estimates and assumptions are based upon what we believe is the best information available at the time of the estimates or assumptions. The estimates and assumptions could change materially as conditions within and beyond our control change. Accordingly, actual results could differ materially from those estimates.

ITEM 3. Quantitative and Qualitative Disclosures About Market Risk

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

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

Commodity Price Risk

We enter into financial derivative contracts to mitigate our exposure to commodity price risk associated with anticipated future natural gas production. As of March 31, 2008, approximately 87 MMcfd and 60 MMcfd of natural gas price collars and swaps, respectively, have been put in place to hedge our remaining 2008 anticipated production. Additionally, we have used fixed-price swaps to hedge 3,000 Bbld of NGL and 1,000 Bbld of oil of our anticipated 2008 production. Anticipated 2009 natural gas production of approximately 110 MMcfd and 40 MMcfd has also been hedged using price collars and swaps, respectively. At March 31, 2008, 66% of our 2008 expected production is hedged with financial derivatives. We believe we will have more predictability of our natural gas, oil and NGL revenues as a result of these financial derivative contracts.

Utilization of our hedging program may result in natural gas, NGL and crude oil realized prices varying from market prices that we receive from the sale of natural gas and crude oil. Our revenue from natural gas, NGL and crude oil production was $3.0 million lower and $14.1 million higher as a result of our hedging programs for the first three months of 2008 and 2007, respectively. Other revenue was $5.5 million lower as a result of hedging ineffectiveness for the three-month period ending March 31, 2008. Hedging activities did not affect other revenue for the three-month period ending March 31, 2007.

The following table summarizes our open derivative positions as of March 31, 2008 related to our future natural gas, NGL and crude oil production.

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				Weighted Avg
				Price Per Mcf
Product	Type	Contract Period	Volume	or Bbl		Fair Value
						(In thousands)
Gas	Swap	Apr 2008-Dec 2008	25,000 Mcfd	$	8.13	$	(14,865	)
Gas	Swap	Apr 2008-Dec 2008	7,500 Mcfd		8.13		(4,459	)
Gas	Swap	Apr 2008-Dec 2008	5,000 Mcfd		8.14		(2,959	)
Gas	Swap	Apr 2008-Dec 2008	2,500 Mcfd		8.15		(1,473	)
Gas	Swap	Apr 2008-Dec 2008	10,000 Mcfd		8.21		(5,718	)
Gas	Swap	Apr 2008-Dec 2008	10,000 Mcfd		8.22		(5,691	)
Gas	Swap	Jan 2009-Dec 2009	10,000 Mcfd		8.45		(9,268	)
Gas	Swap	Jan 2009-Dec 2009	20,000 Mcfd		8.46		(4,651	)
Gas	Swap	Jan 2009-Dec 2009	20,000 Mcfd		8.46		(4,651	)
Gas	Collar	Apr 2008-Dec 2008	20,000 Mcfd		7.50- 9.15		(7,906	)
Gas	Collar	Apr 2008-Dec 2008	10,000 Mcfd		9.00-11.70		(584	)
Gas	Collar	Jul 2008-Dec 2008	20,000 Mcfd		8.25- 9.75		(4,551	)
Gas	Collar	Oct 2008-Dec 2008	10,000 Mcfd		9.00-12.60		(240	)
Gas	Collar	May 2008-Mar 2009	20,000 Mcfd		7.50- 9.35		(11,293	)
Gas	Collar	May 2008-Mar 2009	20,000 Mcfd		8.00-10.20		(7,386	)
Gas	Collar	Jan 2009-Dec 2009	20,000 Mcfd		7.50- 9.34		(8,403	)
Gas	Collar	Jan 2009-Dec 2009	20,000 Mcfd		7.75-10.20		(5,549	)
Gas	Collar	Jan 2009-Dec 2009	10,000 Mcfd		7.75-10.26		(2,731	)
Gas	Collar	Jan 2009-Dec 2009	20,000 Mcfd		8.25- 9.60		(5,717	)
Gas	Collar	Jan 2009-Dec 2009	10,000 Mcfd		8.25-10.45		(1,855	)
Gas	Collar	Jan 2009-Dec 2009	10,000 Mcfd		8.25-10.45		(1,855	)
Gas	Collar	Jan 2009-Dec 2009	10,000 Mcfd		8.25-10.45		(1,855	)
Gas	Basis	Apr-08	10,000 Mcfd				30
Gas	Basis	Apr-08	10,000 Mcfd				30
Gas	Basis	Apr-08	30,000 Mcfd				90
Gas	Basis	Apr-08	30,000 Mcfd				90
Gas	Basis	Apr 2008-Dec 2008	10,000 Mcfd				273
Gas	Basis	Apr 2008-Dec 2008	10,000 Mcfd				273
NGL	Swap	Apr 2008-Dec 2008	1,000 Bbld		39.58		(3,581	)
NGL	Swap	Apr 2008-Dec 2008	2,000 Bbld		45.94		(4,339	)
Oil	Collar	Apr 2008-Dec 2008	500 Bbld		65.00-73.90		(4,030	)
Oil	Collar	Apr 2008-Dec 2008	500 Bbld		65.00-77.45		(3,532	)
				Total		$	(128,356	)

At March 31, 2008, we had one year remaining on our obligation to deliver 25 MMcfd of natural gas under the Michigan Sales Contract. In December 2007, we determined we would no longer deliver a portion of our natural gas production to supply the contractual volumes under the Michigan Sales Contract. At that time, we recognized a loss of $63.5 million for the fair value of the Michigan Sales Contract through the end of its term in March 2009. In January 2008, we entered into two fixed-price natural gas swaps covering all volumes for the remaining contract period, which served to effectively offset the net earnings exposure of our remaining obligation under the Michigan Sales Contract. The following table summarizes these open positions as of March 31, 2008.

29

				Weighted Avg
				Price Per Mcf
Product	Type	Contract Period	Volume	or Bbl		Fair Value
						(In thousands)
Gas	Sale	Apr 2008-Mar 2009	25,000 Mcfd	$	2.49	$	(78,144	)
Gas	Swap	Apr 2008-Mar 2009	10,000 Mcfd		8.20		8,850
Gas	Swap	Apr 2008-Mar 2009	15,000 Mcfd		8.20		13,275
				Total		$	(56,019	)

Credit Risk

During the three months ended March 31, 2008, the Company had NGL sales of $46.5 million to two parties. These sales represent 29% of our consolidated production revenue during the quarter then ended. In accordance with our established credit policy, we review each counterparty for credit worthiness prior to the extension of credit and regularly monitor our exposure to all counterparties by reviewing credit ratings, financial statements and credit service reports. We maintain credit limits for each of our customers and parental guarantees and collateral are used to manage our exposure to counterparties according to our established policy.

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ITEM 4. Controls and Procedures

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

We carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures as of the end of the period covered by this report pursuant to Securities Exchange Act Rule 13a-15. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that, as of March 31, 2008, our disclosure controls and procedures were effective to provide reasonable assurance that material information required to be disclosed by us (including our consolidated subsidiaries) in reports that we file or submit under the Securities Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

There has been no change in our internal control over financial reporting during the quarter ended March 31, 2008 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

31

PART II. OTHER INFORMATION

ITEM 1. Legal Proceedings

There have been no material changes in legal proceedings from those described in Part I, Item 3, “Legal Proceedings” included in our Annual Report on Form 10-K for the year ended December 31, 2007, filed with the SEC on February 28, 2008.

ITEM 1A. Risk Factors

There have been no material changes in risk factors from those described in Part I, Item 1A, “Risk Factors” included in our Annual Report on Form 10-K for the year ended December 31, 2007, filed with the SEC on February 28, 2008.

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

Issuer Purchases of Equity Securities

The following table summarizes our repurchases of Quicksilver common stock during the quarter ended March 31, 2008.

					Total Number of		Maximum Number
	Total Number				Shares Purchased as		of Shares that May
	of Shares		Average Price		Part of Publicly		Yet Be Purchased
Period	Purchased(1)		Paid per Share		Announced Plan(2)		Under the Plan(2)
January 2008		31,956	$	57.73		—		—
February 2008		2,852	$	30.89		—		—
March 2008		1,447	$	32.60		—		—
Total		36,255	$	54.62		—		—

(1)

Represents shares of common stock surrendered by employees to satisfy our income tax withholding obligations arising upon the vesting of restricted stock issued under our Amended and Restated 1999 Stock Option and Retention Stock Plan or 2006 Equity Plan. Shares purchased in January 2008 reflect the share price prior to the two-for-one stock split effected in the form of a stock dividend. The stock dividend was paid on January 31, 2008.

(2)

We do not currently have in place any publicly announced, specific plans or programs to purchase equity securities.

ITEM 3. Defaults Upon Senior Securities

None.

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

None.

ITEM 5. Other Information

None.

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ITEM 6. Exhibits:

EXHIBIT INDEX

Exhibit No.	Description
*31.1	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*31.2	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*32.1	Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

* Filed herewith

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SIGNATURES

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

Dated: May 9, 2008

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

34

EXHIBIT INDEX

Exhibit No.	Description
*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

35