e10vq

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)


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

For the quarterly period ended September 30, 2011


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)

801 Cherry Street, Suite 3700, Unit 19, Fort Worth, Texas		76102
(Address of principal executive offices)		(Zip Code)

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

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 the past 90 days. Yes þ No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No o

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 the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):


Large accelerated filer þ	Accelerated filer o	Non-accelerated filer o	Smaller reporting company o
		(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). Yes o No þ

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


Title of Class		Outstanding as of October 31, 2011
Common Stock, $0.01 par value		171,348,678

DEFINITIONS

As used in this Quarterly Report unless the context otherwise requires:

“ABR” means alternate base rate

“AMT” means alternative minimum tax in the U.S.

“AOCI” means accumulated other comprehensive income

“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

“Canada” means our oil and natural gas operations located in Canada

“C$” means Canadian dollars

“DD&A” means Depletion, Depreciation and Accretion

“GPT” means gathering, processing and transportation expense

“MBbl” or “MBbls” means thousand barrels

“MBbld” means thousand barrels per day

“MMBbls” means million barrels

“MMBtu” means million British Thermal Units, a measure of heating value, and is approximately equal to one Mcf of natural gas

“MMBtud” means MMBtu per day

“Mcf” means thousand cubic feet

“Mcfe” means Mcf of natural gas equivalents, calculated as one Bbl of oil or NGLs equaling six Mcf of natural gas

“MMcf” means million cubic feet

“MMcfd” means million cubic feet per day

“MMcfe” means MMcf of natural gas equivalents

“MMcfed” means MMcfe per day

“NGL” or “NGLs” means natural gas liquids

“NYMEX” means New York Mercantile Exchange

“NYSE” means New York Stock Exchange

“OCI” means other comprehensive income

“Oil” includes crude oil and condensate

“RSU” means restricted stock unit

“Tcf” means trillion cubic feet

COMMONLY USED TERMS

Other commonly used terms and abbreviations include:

“Alliance Leasehold” means the natural gas leasehold and royalty interests acquired in the Alliance area of the Barnett Shale

“Barnett Shale Asset” means our operations and our assets in the Barnett Shale located in the Fort Worth Basin of North Texas

“BBEP” means BreitBurn Energy Partners L.P.

“BBEP Unit” means BBEP limited partner unit

“Canadian Credit Facility” means our new Canadian senior secured revolving credit facility, which along with the U.S. Credit Facility replaced the previous Senior Secured Credit Facility on September 6, 2011

“Crestwood” means Crestwood Holdings LLC

“Crestwood Transaction” means the sale to Crestwood of all our interests in KGS, consisting of 100% of the general partner units, including incentive distribution rights, all of our common and subordinated units and the subordinated note due from KGS

“Eni” means either or both Eni Petroleum US LLC and Eni US Operating Co. Inc., which are subsidiaries of Eni SpA

“Eni Production” means production attributable to Eni pursuant to the Eni Transaction

“Eni Transaction” means the 2009 conveyance of a 27.5% interest in our Alliance Leasehold

“FASB” means the Financial Accounting Standards Board, which promulgates accounting standards in the U.S.

“FASC” means the FASB Accounting Standards Codification, which is the single source of authoritative U.S. GAAP not promulgated by the SEC

“GAAP” means accounting principles generally accepted in the U.S.

“Gas Purchase Commitment” means the commitment pursuant to the Eni Transaction to purchase the Eni Production at a fixed price and which expired on December 31, 2010

“Greater Green River Asset” means our operations and our assets in the Greater Green River Basin located in Colorado and southern Wyoming

“HCDS” means Hill County Dry System, a gas gathering system in Hill County, Texas within the Barnett Shale

“Horn River Asset” means our operations and our assets in the Horn River Basin of Northeast British Columbia

“Horseshoe Canyon Asset” means our operations and our assets in Horseshoe Canyon, the coalbed methane fields of southern and central Alberta

“KGS” means Quicksilver Gas Services LP, a publicly-traded partnership, which we formerly owned that traded under the ticker symbol “KGS” and subsequent to the Crestwood Transaction was renamed Crestwood Midstream Partners LP and trades under the ticker symbol “CMLP”

“KGS Secondary Offering” means the public offering of 4,000,000 KGS common units in 2009 and the underwriters’ purchase of an additional 549,200 KGS common units in 2010

“Mercury” means Mercury Exploration Company, which is owned by members of the Darden family

“NGTL” means NOVA Gas Transmission Ltd., a subsidiary of TransCanada Pipelines Limited

“NGTL Project” means the series of contracts with NGTL for the construction of a pipeline and meter station, which will serve our Horn River Asset

“SEC” means the U.S. Securities and Exchange Commission

“Senior Secured Credit Facility” means our previous U.S. senior secured revolving credit facility and our Canadian senior secured revolving credit facility, which were terminated September 6, 2011 and replaced by the new U.S. Credit Facility and Canadian Credit Facility

“Southern Alberta Asset” means our operations and our assets in the Southern Alberta Basin of northern Wyoming and Montana, including our Cutbank field operations and assets

“U.S. Credit Facility” means our new U.S. senior secured revolving credit facility, which along with the Canadian Credit Facility replaced the previous Senior Secured Credit Facility on September 6, 2011

Forward-Looking Information

Certain statements contained in this Quarterly 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 oil prices;
	•		failure or delays in achieving expected production from exploration and development projects;
	•		uncertainties inherent in estimates of natural gas, NGL and oil reserves and predicting natural gas, NGL and oil reservoir performance;
	•		effects of hedging natural gas, NGL and oil prices;
	•		fluctuations in the value of certain of our assets and liabilities;
	•		competitive conditions in our industry;
	•		actions taken or non-performance by third parties, including suppliers, contractors, operators, processors, transporters, customers and counterparties;
	•		changes in the availability and cost of capital;
	•		delays in obtaining oilfield equipment and increases in drilling and other service costs;
	•		delays in construction of transportation pipelines and gathering and treating facilities;
	•		operating hazards, natural disasters, weather-related delays, casualty losses and other matters beyond our control;
	•		failure or inability to convert drilling licenses to leases and the exploration of our leases;
	•		failure or delays in completing our proposed master limited partnership financings for certain of our Barnett Shale assets;
	•		the effects of existing and future laws and governmental regulations, including environmental and climate change requirements;
	•		the effects of existing or future litigation; and
	•		certain factors discussed elsewhere in this Quarterly Report.

This list of factors is not exhaustive, and new factors may emerge or changes to these factors may occur that would impact our business. Additional information regarding these and other factors may be contained in our filings with the SEC, especially on Forms 10-K, 10-Q and 8-K. All such risk factors are difficult to predict and are subject to material uncertainties that may affect actual results and may be beyond our control. The forward-looking statements included in this Quarterly Report are made only as of the date of this Quarterly Report, and we undertake no obligation to update any of these forward-looking statements to reflect subsequent events or circumstances except to the extent required by applicable law.

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

PART I. FINANCIAL INFORMATION


ITEM 1.		Condensed Consolidated Interim Financial Statements (Unaudited)

QUICKSILVER RESOURCES INC.
CONDENSED CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

In thousands, except for per share data – Unaudited


	For the Three Months Ended						For the Nine Months Ended
	September 30,						September 30,
	2011			2010			2011			2010
Revenue:
Production	$	208,064		$	218,249		$	606,070		$	631,499
Sales of purchased natural gas		20,130			16,982			60,116			50,027
Other		31,699			2,469			54,340			6,902

Total revenue		259,893			237,700			720,526			688,428


Operating expense:
Lease operating		27,673			20,949			73,366			62,438
Gathering, processing and transportation		51,113			18,422			142,201			51,080
Production and ad valorem taxes		7,757			9,201			23,844			26,617
Costs of purchased natural gas		19,954			14,638			59,254			51,701
Other operating		145			1,320			328			3,544
Depletion, depreciation and accretion		57,686			52,542			164,861			149,968
Impairment		-			31,531			49,063			31,531
General and administrative		27,584			24,005			61,745			61,745

Total expense		191,912			172,608			574,662			438,624

Operating income		67,981			65,092			145,864			249,804
Income (loss) from earnings of BBEP		14,370			17,024			(32,721	)		24,203
Other income - net		11,142			14,253			135,441			67,646
Interest expense		(48,393	)		(51,532	)		(142,123	)		(142,171	)

Income before income taxes		45,100			44,837			106,461			199,482
Income tax expense		(16,414	)		(18,268	)		(39,946	)		(71,569	)

Net income		28,686			26,569			66,515			127,913
Net income attributable to noncontrolling interests		-			(4,766	)		-			(11,119	)

Net income attributable to Quicksilver	$	28,686		$	21,803		$	66,515		$	116,794
Other comprehensive income (loss) net of tax:
Reclassification adjustments related to settlements of derivative contracts - net of income tax		(11,869	)		(45,356	)		(38,886	)		(117,714	)
Net change in derivative fair value - net of income tax		51,221			59,217			44,508			171,910
Foreign currency translation adjustment		(35,550	)		6,993			(25,118	)		4,238

Other comprehensive income (loss)		3,802			20,854			(19,496	)		58,434

Comprehensive income	$	32,488		$	42,657		$	47,019		$	175,228


Earnings per common share - basic	$	0.17		$	0.13		$	0.39		$	0.69

Earnings per common share - diluted	$	0.17		$	0.13		$	0.39		$	0.68

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

QUICKSILVER RESOURCES INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
In thousands, except for share data – Unaudited


	September 30,			December 31,
	2011			2010
ASSETS
Current assets
Cash	$	6,602		$	54,937
Accounts receivable - net of allowance for doubtful accounts		61,270			63,380
Derivative assets at fair value		101,006			89,205
Other current assets		48,786			30,650

Total current assets		217,664			238,172
Investments in equity affiliates		21,725			83,341
Property, plant and equipment
Oil and gas properties, full cost method (including unevaluated costs of $460,158 and $304,269, respectively)		3,068,952			2,834,645
Other property and equipment		307,853			233,200

Property, plant and equipment - net		3,376,805			3,067,845
Assets of midstream operations held for sale		—			27,178
Derivative assets at fair value		106,844			57,557
Other assets		40,436			38,241

	$	3,763,474		$	3,512,334

LIABILITIES AND EQUITY
Current liabilities
Current portion of long-term debt	$	149,331		$	143,478
Accounts payable		113,248			167,857
Accrued liabilities		123,937			122,904
Derivative liabilities at fair value		1,677			-
Current deferred tax liability		27,445			28,861

Total current liabilities		415,638			463,100

Long-term debt		1,930,529			1,746,716
Liabilities of midstream operations held for sale		—			1,431
Asset retirement obligations		58,223			56,235
Other liabilities		28,461			28,461
Deferred income taxes		212,829			156,983
Commitments and contingencies (Note 8)
Stockholders’ equity
Preferred stock, par value $0.01, 10,000,000 shares authorized, none outstanding		-			-
Common stock, $0.01 par value, 400,000,000 shares authorized, and 176,894,542 and 175,524,816 shares issued, respectively		1,769			1,755
Paid in capital in excess of par value		731,063			714,869
Treasury stock of 5,376,615 and 5,050,450 shares, respectively		(46,328	)		(41,487	)
Accumulated other comprehensive income		110,691			130,187
Retained earnings		320,599			254,084

Total stockholders’ equity		1,117,794			1,059,408

	$	3,763,474		$	3,512,334

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

QUICKSILVER RESOURCES INC.
CONDENSED CONSOLIDATED STATEMENTS OF EQUITY
In thousands – Unaudited


	Quicksilver Resources Inc. Stockholders’ Equity
								Accumulated
			Additional					Other
	Common		Paid-in		Treasury			Comprehensive			Retained			Noncontrolling
	Stock		Capital		Stock			Income			Earnings			Interest			Total
Balances at December 31, 2009	$	1,745	$	730,265	$	(36,363	)	$	121,336		$	(180,985	)	$	60,824		$	696,822
Net income		-		-		-			-			116,794			11,119			127,913
Hedge derivative contract settlements reclassified into earnings from AOCI, net of income tax of $61,975		-		-		-			(117,714	)		-			-			(117,714	)
Net change in derivative fair value, net of income tax of $87,312		-		-		-			171,910			-			-			171,910
Currency translation adjustment		-		-		-			4,238			-			-			4,238
Issuance & vesting of stock compensation		8		15,333		(4,851	)		-			-			858			11,348
Stock option exercises		2		1,600		(214	)		-			-			-			1,388
Issuance of KGS common units		-		6,746		-			-			-			4,308			11,054
Distributions paid on KGS common units		-		-		-			-			-			(13,550	)		(13,550	)

Balances at September 30, 2010	$	1,755	$	753,944	$	(41,428	)	$	179,770		$	(64,191	)	$	63,559		$	893,409


Balances at December 31, 2010	$	1,755	$	714,869	$	(41,487	)	$	130,187		$	254,084		$	-		$	1,059,408
Net income		-		-		-			-			66,515			-			66,515
Hedge derivative contract settlements reclassified into earnings from AOCI, net of income tax of $18,217		-		-		-			(38,886	)		-			-			(38,886	)
Net change in derivative fair value, net of income tax of $21,456		-		-		-			44,508			-			-			44,508
Currency translation adjustment		-		-		-			(25,118	)		-			-			(25,118	)
Issuance & vesting of stock compensation		13		15,462		(4,841	)		-			-			-			10,634
Stock option exercises		1		732		-			-			-			-			733

Balances at September 30, 2011	$	1,769	$	731,063	$	(46,328	)	$	110,691		$	320,599		$	-		$	1,117,794

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

QUICKSILVER RESOURCES INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
In thousands – Unaudited


	For the Nine Months Ended
	September 30,
	2011			2010
Operating activities:
Net income	$	66,515		$	127,913
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation and accretion		164,861			149,968
Impairment expense		49,063			31,531
Deferred income tax expense		50,960			71,569
Non-cash gain from hedging and derivative activities		(50,550	)		(45,801	)
Stock-based compensation		15,475			17,343
Non-cash interest expense		13,109			13,372
Gain on disposition of BBEP Units		(133,248	)		(49,850	)
(Income) loss from BBEP in excess of cash distributions		49,065			(9,416	)
Other		(897	)		(337	)
Changes in assets and liabilities
Accounts receivable		2,101			25,101
Derivative assets at fair value		-			30,816
Prepaid expenses and other assets		(20,791	)		4,974
Accounts payable		(29,430	)		(18,793	)
Accrued and other liabilities		(1,567	)		(1,000	)

Net cash provided by operating activities		174,666			347,390

Investing activities:
Capital expenditures		(550,954	)		(494,338	)
Proceeds from sale of BBEP Units		145,799			22,498
Proceeds from sale of properties and equipment		3,719			1,030

Net cash used by investing activities		(401,436	)		(470,810	)

Financing activities:
Issuance of debt		648,819			661,232
Repayments of debt		(455,886	)		(491,043	)
Debt issuance costs paid		(10,276	)		(109	)
Gas Purchase Commitment repayments		-			(25,900	)
Issuance of KGS common units - net of offering costs		-			11,054
Distributions paid on KGS common units		-			(13,550	)
Proceeds from exercise of stock options		733			1,388
Taxes paid on vesting of KGS equity compensation		-			(1,144	)
Purchase of treasury stock		(4,841	)		(4,851	)

Net cash provided by financing activities		178,549			137,077

Effect of exchange rate changes in cash		(114	)		(306	)

Net increase (decrease) in cash		(48,335	)		13,351
Cash at beginning of period		54,937			1,785

Cash at end of period	$	6,602		$	15,136

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

QUICKSILVER RESOURCES INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Unaudited

1. ACCOUNTING POLICIES AND DISCLOSURES

The accompanying condensed consolidated interim financial statements have not been audited. In our management’s opinion, the accompanying condensed consolidated interim financial statements contain all adjustments necessary to fairly present our financial position as of September 30, 2011 and our results of operations and cash flows for the three and nine months ended September 30, 2011 and 2010. 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 GAAP requires our management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expense during each reporting period. Our management believes these 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 management’s estimates.

Certain disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted. Accordingly, these financial statements should be read in conjunction with our consolidated financial statements and notes thereto included in our 2010 Annual Report on Form 10-K.

Recently Issued Accounting Standards

Accounting standards-setting organizations frequently issue new or revised accounting rules. We regularly review all new pronouncements to determine their impact, if any, on our financial statements. No pronouncements materially affecting our financial statements have been issued since the filing of our 2010 Annual Report on Form 10-K.

2. CRESTWOOD TRANSACTION AND MIDSTREAM OPERATIONS

In October 2010, we completed the sale of all of our interests in KGS to Crestwood. We received net proceeds of $700 million and recognized a gain of $473.2 million during the fourth quarter of 2010. We have the right to collect up to an additional $72 million in future earn-out payments in 2012 and 2013, although we have recognized no assets related to these opportunities.

The operating results of KGS, as classified in our 2010 statement of income, are summarized below:


	For the Three			For the Nine
	Months Ended			Months Ended
	September 30, 2010			September 30, 2010
	(In thousands)
Revenue from third parties	$	4,371		$	11,928
GPT expense ⁽¹⁾		(20,923	)		(55,261	)
Ad valorem taxes		1,032			3,597
Other operations		1,101			3,099
DD&A		5,710			16,759
General and administrative expense		3,290			5,035

Operating results of midstream operations		14,161			38,699
Interest and other expense		(2,527	)		(6,916	)

Results of midstream operations before income tax		11,634			31,783
Income tax expense		(4,101	)		(11,235	)

Results of midstream operations, net of income tax	$	7,533		$	20,548


⁽¹⁾		Our KGS operations earned revenue from gathering and processing of our natural gas and NGL production. This revenue was consolidated as a reduction of processing, gathering and transportation expense for purposes of presenting our consolidated statements of income.

In the third quarter of 2010, our board of directors also approved a plan for disposal of the HCDS, which is included in our midstream segment. We conducted an impairment analysis of the HCDS and recognized a charge of $28.6 million for impairment in the third quarter of 2010. At December 31, 2010, we presented HCDS assets and liabilities held for sale as follows:


	December 31,
	2010
Assets:
Accounts receivable — net	$	57
Property, plant and equipment — net		27,121

Total	$	27,178


Liabilities:
Other non-current liabilities	$	1,431

Total	$	1,431

We have discontinued our efforts to actively market the HCDS assets to prospective buyers and GAAP generally limits reporting such items as held for sale to one year. As a result, we no longer report the HCDS in our financial statements as an asset held for sale.

Note 3 to the consolidated financial statements in our 2010 Annual Report on Form 10-K contains additional information regarding the Crestwood Transaction.

3. DERIVATIVES AND FAIR VALUE MEASUREMENTS

The following table categorizes our commodity derivative instruments based upon the use of input levels:


	Asset Derivatives				Liability Derivatives
	September 30,		December 31,		September 30,		December 31,
	2011		2010		2011		2010
	(In thousands)				(In thousands)
Level 2 inputs	$	140,740	$	146,762	$	1,677	$	-
Level 3 inputs		67,110		-		-		-

Total	$	207,850	$	146,762	$	1,677	$	-

The fair value of “Level 2” derivative instruments included in these disclosures was estimated using prices quoted in active markets for the periods covered by the derivatives and the value reported by counterparties. The fair value of derivative instruments designated “Level 3” was estimated using prices quoted in markets where there is insufficient market activity for consideration as “Level 2” instruments. Currently, only our 10-year natural gas hedges utilize Level 3 inputs, primarily related to comparatively less market data available for their later term compared with our other shorter term hedges. Estimates were determined by applying the net differential between the prices in each derivative and market prices for future periods to the amounts 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.

The following table identifies the changes in Level 3 fair values for the three and nine months ended September 30, 2011:


	For the Three		For the Nine
	Months Ended		Months Ended
	September 30, 2011		September 30, 2011
	(In thousands)
Balance at beginning of period	$	19,115	$	-
Total gains for the period:
Included in OCI		18,258		18,258
Included in earnings		29,737		48,852

Balance at end of period	$	67,110	$	67,110

Total gains for the period included in earnings attributable to the change in unrealized gains related to assets held at September 30, 2011	$	29,737	$	48,852

Commodity Price Derivatives

As of September 30, 2011, we had price collars and swaps covering our anticipated natural gas and NGL production as follows:


Production	Daily Production
Year	Gas		NGL
	MMcfd		MBbld
2011		190		10.5
2012		165		6.0
2013		105		-
2014—2015		65		-
2016—2021		35		-

On August 31, 2011, we designated our 10-year natural gas swaps as hedges. Unrealized gains of $48.9 million were recognized from the date we entered into them through that date and have been reported in “other revenue.” After the designation date, additional unrealized gains and losses, net of hedge ineffectiveness, have been deferred in OCI until the associated sale of natural gas production occurs.

Interest Rate Derivatives

In 2010, we executed early settlements of our interest rate swaps that were designated as fair value hedges of our senior notes due 2015 and our senior subordinated notes. We received cash of $41.5 million in the settlements, including $10.7 million for interest previously accrued and earned. At the time of the early settlements, we recorded the resulting gain as a fair value adjustment to our debt and began to recognize the deferred gain of $30.8 million as a reduction of interest expense over the lives of our senior notes due 2015 and our senior subordinated notes. The remaining $23.1 million deferral of the 2010 early settlements from all interest rate swaps will continue to be recognized as a reduction of interest expense over the life of the associated underlying debt instruments.

Additional Fair Value Disclosures:


	Asset Derivatives				Liability Derivatives
	September 30,		December 31,		September 30,		December 31,
	2011		2010		2011		2010
	(In thousands)				(In thousands)
Derivatives designated as hedges^{(1) (2)}:
Commodity contracts reported in:
Current derivative assets	$	112,749	$	97,863	$	11,743	$	8,658
Noncurrent derivative assets		106,844		63,419		-		5,862
Current derivative liabilities		-		-		1,677		-

Total derivatives designated as hedges	$	219,593	$	161,282	$	13,420	$	14,520

Total derivatives	$	219,593	$	161,282	$	13,420	$	14,520


⁽¹⁾		The fair value of our hedge derivatives is determined using Level 2 and Level 3 inputs.

⁽²⁾		The 10-year swap derivatives entered into during the second quarter of 2011 were designated as hedges on August 31, 2011.

The changes in the carrying value of our derivatives for the three and nine months ended September 30, 2011 and 2010 are presented below:


	For the Three Months Ended September 30,
	2011			2010
	Commodity			Gas Purchase			Fair Value			Commodity
	Derivatives			Commitment			Derivatives			Derivatives			Total
	(In thousands)
Derivative fair value at beginning of period	$	116,349		$	(6,161	)	$	13,240		$	193,394		$	200,473
Change in net amounts receivable and payable		(576	)		-			(4,392	)		(234	)		(4,626	)
Net settlements reported in revenue		(16,815	)		-			-			(54,716	)		(54,716	)
Cash settlements reported in long-term debt		-			-			(12,134	)		-			(12,134	)
Unrealized change in fair value of Gas Purchase Commitment reported in costs of purchased gas		-			5,496			-			-			5,496
Change in fair value of effective interest swaps		-			-			3,286			-			3,286
Ineffectiveness reported in other revenue		880			-			-			(812	)		(812	)
Unrealized gains reported in other revenue		29,737			-			-			-			-
Unrealized gains reported in OCI		76,598			-			-			89,627			89,627

Derivative fair value at end of period	$	206,173		$	(665	)	$	-		$	227,259		$	226,594


	For the Nine Months Ended September 30,
	2011			2010
	Commodity			Gas Purchase			Fair Value			Commodity
	Derivatives			Commitment			Derivatives			Derivatives			Total
	(In thousands)
Derivative fair value at beginning of period	$	146,762		$	(6,625	)	$	4,108		$	107,881		$	105,364
Change in net amounts receivable and payable		(960	)		-			(9,180	)		(1,096	)		(10,276	)
Net settlements reported in revenue		(56,143	)		-			-			(136,349	)		(136,349	)
Net settlements reported in interest expense		-			-			(10,848	)		-			(10,848	)
Cash settlements reported in long-term debt		-			-			(30,816	)		-			(30,816	)
Unrealized change in fair value of Gas Purchase Commitment reported in costs of purchased gas		-			5,960			-			-			5,960
Change in fair value of effective interest swaps		-			-			46,736			-			46,736
Ineffectiveness reported in other revenue		1,698			-			-			(2,399	)		(2,399	)
Unrealized gains reported in other revenue		48,852			-			-			-			-
Unrealized gains reported in OCI		65,964			-			-			259,222			259,222

Derivative fair value at end of period	$	206,173		$	(665	)	$	-		$	227,259		$	226,594

Gains and losses from the effective portion of derivative assets and liabilities held in AOCI expected to be reclassified into earnings during the twelve months ending September 30, 2012 would result in a gain of $53.7 million net of income taxes. Hedge derivative ineffectiveness resulted in net gains of $1.7 million and losses of $2.4 million for the nine months ended September 30, 2011 and 2010, respectively.

4. INVESTMENT IN BBEP

At September 30, 2011, we owned 8.0 million BBEP Units, or 13.6% of BBEP, whose price closed at $17.40 per unit as of that date. Our ownership interest in BBEP was reduced in February 2011 when BBEP issued approximately 4.9 million BBEP Units. During the nine months ended September 30, 2011, we continued to reduce our ownership through the sale of approximately 7.7 million BBEP Units at a weighted average unit sales price of $18.99. We recognized gains of $133.2 million as other income for the difference between our weighted average carrying value of $1.63 per BBEP Unit and the net sales proceeds.

Changes in the balance of our investment in BBEP for the nine months ended September 30, 2011 were as follows:


(In thousands)

Balance at December 31, 2010	$	83,341
Equity loss in BBEP		(32,721	)
Distributions from BBEP		(16,344	)
BBEP Units sold		(12,551	)

Ending investment balance	$	21,725

We account for our investment in BBEP Units using the equity method, utilizing a one-quarter lag from BBEP’s publicly available information. Summarized estimated financial information for BBEP is as follows:


	For the Three Months Ended				For the Nine Months Ended
	June 30,				June 30,
	2011		2010		2011			2010
	(In thousands)				(In thousands)
Revenue ⁽¹⁾	$	142,368	$	134,216	$	147,829		$	305,645
Operating expense		72,929		73,621		226,349			216,170

Operating income (loss)		69,439		60,595		(78,520	)		89,475
Interest and other ⁽²⁾		11,300		6,437		30,363			18,130
Income tax expense (benefit)		616		561		(825	)		(469	)
Noncontrolling interests		68		28		137			118

Net income (loss) available to BBEP	$	57,455	$	53,569	$	(108,195	)	$	71,696

	⁽¹⁾		For the three months ended June 30, 2011 and 2010, unrealized gains of $48.2 million and $33.2 million on commodity derivatives were recognized, respectively. For the nine months ended June 30, 2011 and 2010, unrealized losses of $146.7 million and unrealized gains of $18.4 million on commodity derivatives were recognized, respectively.

	⁽²⁾		The three months ended June 30, 2011 and 2010 included unrealized losses of $2.1 million and unrealized gains of $1.5 million, respectively, from interest rate swaps. The nine months ended June 30, 2011 and 2010 included unrealized gains of $2.4 million and $3.9 million, respectively, from interest rate swaps.


	As of		As of
	June 30, 2011		December 31, 2010
	(In thousands)
Current assets	$	120,781	$	130,017
Property, plant and equipment		1,712,096		1,722,295
Other assets		46,255		77,855
Current liabilities		103,103		101,317
Long-term debt		427,364		528,116
Other non-current liabilities		116,600		91,477
Total equity		1,232,065		1,209,257

5. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment consisted of the following:


	September 30,			December 31,
	2011			2010
	(In thousands)
Oil and gas properties
Subject to depletion	$	5,049,640		$	4,805,161
Unevaluated costs		460,158			304,269
Accumulated depletion		(2,440,846	)		(2,274,785	)

Net oil and gas properties		3,068,952			2,834,645
Other plant and equipment
Pipelines and processing facilities		355,201			235,676
General properties		73,530			70,267
Accumulated depreciation		(120,878	)		(72,743	)

Net other plant and equipment		307,853			233,200

Property, plant and equipment, net of accumulated depletion and depreciation	$	3,376,805		$	3,067,845

Ceiling Test Analysis

We recorded impairment expense of $49.1 million for our Canadian oil and gas properties at March 31, 2011. We computed the March 31, 2011 ceiling amount using an AECO price of $3.59 Mcf of natural gas, calculated as the unweighted average of the preceding 12-month first-day-of-the-month prices. The AECO natural gas price used to compute the ceiling amount at March 31, 2011 was 12% lower than the AECO price used in computing the ceiling amount at December 31, 2010. Our Canadian ceiling tests prepared at June 30 and September 30, 2011 resulted in no additional impairment of our Canadian oil and gas properties. Our U.S. ceiling tests prepared for each quarter of 2011 resulted in no impairment of our U.S. oil and gas properties.

Notes 2 and 8 to the consolidated financial statements in our 2010 Annual Report on Form 10-K contain additional information regarding our property, plant and equipment and our quarterly ceiling test analysis.

6. LONG-TERM DEBT

Long-term debt consisted of the following:


	September 30,			December 31,
	2011			2010
	(In thousands)
U.S. Credit Facility	$	137,000		$	-
Canadian Credit Facility		117,342			-
Senior Secured Credit Facility		-			21,114
Senior notes due 2015, net of unamortized discount		434,812			470,866
Senior notes due 2016, net of unamortized discount		576,334			583,605
Senior notes due 2019, net of unamortized discount		291,922			293,496
Senior subordinated notes due 2016		350,000			350,000
Convertible debentures, net of unamortized discount		149,331			143,478

Total debt		2,056,741			1,862,559
Unamortized deferred gain —terminated interest rate swaps		23,119			27,635
Current portion of long-term debt		(149,331	)		(143,478	)

Long-term debt	$	1,930,529		$	1,746,716

Credit Facilities

In September 2011, we terminated and replaced our $1.0 billion global Senior Secured Credit Facility with new separate five-year syndicated senior secured revolving credit facilities for our U.S. and Canadian operations. The $1.25 billion U.S. Credit Facility had a borrowing base and commitments of $850 million, including a letter of credit capacity of $75 million, as of September 30, 2011. The C$500 million Canadian Credit Facility had a borrowing base and commitments of C$225 million, including a letter of credit capacity of C$100 million, as of September 30, 2011. Both facilities will be re-determined semi-annually based upon engineering reports and such other information deemed appropriate by the applicable administrative agent, in a manner consistent with its normal oil and gas lending criteria as it exists at the time of such redetermination.

The U.S. and Canadian Credit Facilities provide for revolving credit loans and letters of credit from time to time. The U.S. Credit Facility also provides for the extension of swingline loans to Quicksilver. Borrowings under the U.S. Credit Facility bear interest at a variable annual rate based on adjusted LIBOR or ABR plus, in each case, an applicable margin, provided that each swingline loan shall be comprised entirely of ABR loans. Borrowings under the Canadian Credit Facility may be made in U.S. dollars or Canadian dollars and will be comprised entirely of Canadian prime loans, Canadian Deposit Offer Rate (“CDOR”) loans, U.S. prime loans or U.S. eurodollar loans, in each case, plus an applicable margin. The applicable margin adjusts as the utilization of the borrowing base changes.

Convertible Debentures

The convertible debentures due November 1, 2024 are contingently convertible into shares of our common stock. The debentures bear interest at an annual rate of 1.875% payable semi-annually on May 1 and November 1. Additionally, holders of the debentures can require us to repurchase all or a portion of their debentures on November 1, 2011, 2014 and 2019 at a price equal to the principal amount thereof plus accrued and unpaid interest. The debentures are convertible into shares of our common stock at a rate of 65.4418 shares for each $1,000 debenture, subject to adjustment. Generally, except upon the occurrence of specified events including certain changes of control, holders of the debentures are not entitled to exercise their conversion rights unless the closing price of our stock is at least $18.34 (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. Upon conversion, we have the option to deliver any combination of our common stock and cash. Should all debentures be converted to our common stock, an additional 9,816,270 shares, subject to adjustment, would become outstanding; however, as of October 1, 2011, the debentures were not convertible based on share prices for the quarter ended September 30, 2011. We have reported these obligations as current obligations in our September 30, 2011 and December 31, 2010 balance sheets.

On November 1, 2011, we repurchased substantially all of the debentures for $150.0 million, after they were presented to us for repurchase by debenture holders. The repurchase transaction was completed utilizing borrowings from the U.S. Credit Facility. During the fourth quarter of 2011, we expect to repurchase or redeem the debentures that were not presented to us for repurchase.

At September 30, 2011 and December 31, 2010, the remaining unamortized discount on the debentures was $0.7 million and $6.5 million, respectively, resulting in a carrying value of $149.3 million and $143.5 million, respectively. The remaining discount will be accreted to face value through October 2011. For the nine months ended September 30, 2011 and 2010, interest expense on our convertible debentures, recognized at an effective interest rate of 6.75%, was $8.0 million and $7.6 million, respectively, including contractual interest of $2.1 million for each period.

Senior Notes

During 2011, we repurchased the following senior notes in open market transactions:


	Repurchase		Face		Premium on
Instrument	Price		Value		Repurchase
			(In thousands)
Senior notes due 2015	$	38,134	$	37,000	$	1,134
Senior notes due 2016		10,646		9,380		1,266
Senior notes due 2019		2,160		2,000		160

	$	50,940	$	48,380	$	2,560

Summary of All Outstanding Debt

The following table summarizes significant aspects of our long-term debt at September 30, 2011:

Priority on Collateral and Structural Seniority⁽¹⁾

Highest priority

Lowest priority

Equal Priority

Equal priority

U.S.

Canadian

2015

2016

2019

Senior

Convertible

Credit Facility

Senior Notes

Subordinated Notes

Debentures⁽²⁾

Principal amount

$850.0 million ⁽³⁾

C$225.0 million ⁽⁴⁾

$438 million

$591 million

$298 million

$350 million

$150 million

Scheduled maturity date

September 6, 2016

August 1, 2015

January 1, 2016

August 15, 2019

April 1, 2016

November 1, 2024

Interest rate on outstanding
borrowings at
September 30, 2011 ^{(5) (6) (7)}

1.75

3.547

8.25

11.75

9.125

7.125

1.875

Base interest rate options

LIBOR, ABR ⁽⁶⁾

CDOR, Canadian
prime, U.S.
prime or LIBOR ⁽⁷⁾

N/A

Financial covenants ⁽⁸⁾

- Minimum current ratio of 1.0

N/A

- Minimum EBITDA to cash interest expense ratio of 2.5

- Maximum net debt to EBITDA ratio of 4.5

Significant restrictive

- Incurrence of debt

N/A

covenants ⁽⁸⁾

- Incurrence of liens

- Payment of dividends

- Equity purchases

- Asset sales

- Affiliate transactions

- Limitations on
derivatives

- Limitations on derivatives

Optional redemption ⁽⁸⁾

Any time

August 1,
2012: 103.875
2013: 101.938

July 1,
2013: 105.875
2014: 102.938

August 15,
2014: 104.563
2015: 103.042

April 1,
2012: 102.375
2013: 101.188

November 8, 2011
and thereafter

2014: par

2015: par

2016: 101.521

2014: par

2017: par

Make-whole redemption ⁽⁸⁾

N/A

Callable prior to

N/A

August 1, 2012 at

July 1, 2013 at

August 15, 2014 at

make-whole
call price of
Treasury + 50 bps

Change of control ⁽⁸⁾

Event of default

Put at 101% of
principal plus
accrued interest

Put at 100% of
principal plus
accrued interest

Equity clawback⁽⁸⁾

N/A

Redeemable until

N/A

July 1, 2012 at

August 15, 2012 at

111.75%, plus
accrued interest
for up to 35%

109.125%, plus
accrued interest
for up to 35%

Subsidiary guarantors⁽⁸⁾

Cowtown Pipeline
Funding, Inc.

N/A

Cowtown Pipeline
Funding, Inc.

N/A

Cowtown Pipeline
Management, Inc.

Cowtown
Pipeline L.P.

Cowtown Gas
Processing L.P.

Estimated fair value ⁽⁹⁾

$137.0.million

$117.3 million

$442.4 million

$649.7 million

$302.5 million

$325.5 million

$149.9 million


⁽¹⁾		Borrowings under the U.S. Credit Facility are guaranteed by certain of Quicksilver’s domestic subsidiaries and are secured by 100% of the equity interests of each of Cowtown Pipeline Management, Inc., Cowtown Pipeline Funding, Inc., Cowtown Gas Processing L.P. and Cowtown Pipeline L.P., and certain oil and gas properties and related assets of Quicksilver. Currently, there are no guarantors under the Canadian Credit Facility, and borrowings under the Canadian Credit Facility are secured by 100% of the equity interests of Quicksilver Resources Canada Inc. and its oil and gas properties and related assets. The other debt presented is based upon structural seniority and priority of payment.

⁽²⁾		Beginning on November 8, 2011, we have the ability to redeem the convertible debentures.

⁽³⁾		The principal amount for the U.S. Credit Facility represents the borrowing base and commitments as of September 30, 2011.


⁽⁴⁾		The principal amount for the Canadian Credit Facility represents the borrowing base and commitments as of September 30, 2011.

⁽⁵⁾		Represents the weighted average borrowing rate payable to lenders and excludes effects of interest rate derivatives.

⁽⁶⁾		Amounts outstanding under the U.S. Credit Facility bear interest, at our election, at (i) adjusted LIBOR (as defined in the credit agreement) plus an applicable margin between 1.50% to 2.50%, (ii) ABR (as defined in the credit agreement), which is the greatest of (a) the prime rate announced by JPMorgan, (b) the federal funds rate plus 0.50% and (c) adjusted LIBOR (as defined in the credit agreement) plus 1.0%, plus, in each case under scenario (ii), an applicable margin between 0.50% to 1.50%. We also pay a per annum fee on all letters of credit issued under the U.S. Credit Facility equal to the applicable margin and a commitment fee on the unused availability of 0.375% to 0.50%, in each case, based on borrowing base usage.

⁽⁷⁾		Amounts outstanding under the Canadian Credit Facility bear interest, at our election, at (i) the CDOR Rate (as defined in the credit agreement) plus an applicable margin between 1.75% and 2.75%, (ii) the Canadian Prime Rate (as defined in the credit agreement) plus an applicable margin between 0.75% and 1.75%, (iii) the U.S. Prime Rate (as defined in the credit agreement) plus an applicable margin between 0.75% and 1.75% and (iv) U.S. eurodollar loans (as defined in the credit agreement) plus an applicable margin between 1.75% to 2.75% We pay a per annum fee on all letters of credit issued under the Canadian Credit Facility equal to the applicable margin and a commitment fee on the unused availability of 0.50% per annum, in each case, based on borrowing base usage.

⁽⁸⁾		The information presented in this table is qualified in all respects by reference to the full text of the covenants, provisions and related definitions contained in the documents governing the various components of our debt.

⁽⁹⁾		The estimated fair value is determined based on market quotations on the balance sheet date for fixed rate obligations. We consider debt with variable interest rates to have a fair value equal to its carrying value.

Note 11 to the consolidated financial statements in our 2010 Annual Report on Form 10-K contains a more complete description of our long-term debt.

7. ASSET RETIREMENT OBLIGATIONS

The following table provides a reconciliation of the changes in the estimated asset retirement obligation for the nine months ended September 30, 2011:


(In thousands)
Beginning asset retirement obligations	$	57,809
Liability of asset held for sale		1,431
Additional liability incurred		4,571
Change in estimates		(2,716	)
Accretion expense		2,003
Asset retirement costs incurred		(2,516	)
Gain on settlement of liability		1,100
Currency translation adjustment		(1,885	)

Ending asset retirement obligations		59,797
Less current portion		(1,574	)

Long-term asset retirement obligation	$	58,223

8. COMMITMENTS AND CONTINGENCIES

Contractual Obligations and Commitments

There have been no significant changes to our contractual obligations and commitments as reported in our 2010 Annual Report on Form 10-K except for a series of contracts with NGTL and additional one-year drilling rig contracts. In September 2011, we resolved all litigation with Eagle Drilling LLC (“Eagle”), which is described below.

In April 2011, we entered into the NGTL Project, which will serve our Horn River Asset. Under these agreements, we agreed to provide financial assurances in the form of letters of credit to NGTL during the construction phase of the project, which is expected to continue through 2014. Assuming the project is fully constructed and based on estimated costs of C$257.4 million, including taxes of C$27.6 million, we expect to provide cumulative letters of credit as follows:


	NGTL Cumulative
	Financial Assurances⁽¹⁾
	(C$ in thousands)		(US$ in thousands)
March 1, 2012	$	68,264	$	65,124
October 1, 2012		109,816		104,764
July 1, 2013		148,400		141,574
October 1, 2013		257,400		245,560


⁽¹⁾		A letter of credit for C$32.6 million is outstanding for the NGTL Project as of September 30, 2011.

Should other companies subscribe to the project, then our financial assurances under the agreements will be reduced. If the project is terminated by NGTL, then we would be responsible for all of the costs incurred or for which NGTL is liable, and we would have the option to purchase NGTL’s rights in the project for a nominal fee. Should the project be terminated by NGTL, we are required to pay NGTL an additional C$26.4 million. No amounts have been recognized on our consolidated balance sheet as of September 30, 2011. Upon completion of the project, all construction-related guarantees will expire.

We have also entered into agreements to deliver production from our Horn River Asset to NGTL over a 10-year period. These agreements will be extended in the event NGTL has either not received 1 Tcf of gas from us and other third parties, or recovered its costs as of the end of the 10-year period. In such event, the extension will be for delivery of minimum volumes of 106 MMcfd until such time that 1 Tcf of gas is delivered.

Also under the agreements, we are required to treat the gas to meet NGTL pipeline specifications. Such treatment will require us to construct treating facilities. We will develop our plans to address the treating requirements prior to the commissioning of the assets being constructed by NGTL.

In July 2011, we entered into two additional drilling rig contracts, each with a term of one year and combined aggregate commitments of $12.0 million.

At September 30, 2011, we had $10.0 million in surety bonds issued to fulfill contractual, legal or regulatory requirements and $34.1 million in letters of credit outstanding against the U.S. Credit Facility. In early October 2011, a letter of credit for $28.9 million was terminated. Letters of credit outstanding against the Canadian Credit Facility were $42.9 million, including $31.1 million issued for the NGTL Project. Surety bonds and letters of credit generally have an annual renewal option.

Contingencies

On September 26, 2011, we entered into a global settlement agreement with Eagle. During the third quarter of 2011, we recognized a charge of $8.5 million and funded our entire obligations under this settlement. Pursuant to this agreement, the Eagle cases filed in Oklahoma and Houston were dismissed.

Note 14 to the consolidated financial statements in our 2010 Annual Report on Form 10-K contains a more complete description of our contractual obligations, commitments and contingencies for which there are no other significant updates during the nine months ended September 30, 2011.

9. QUICKSILVER STOCKHOLDERS’ EQUITY

Common Stock, Preferred Stock and Treasury Stock

We are authorized to issue 400 million shares of common stock with a $0.01 par value per share and 10 million shares of preferred stock with a $0.01 par value per share. At September 30, 2011 and December 31, 2010, we had 176.9 million and 170.5 million shares of common stock outstanding, respectively.

Note 16 to the consolidated financial statements in our 2010 Annual Report on Form 10-K contains additional information about our equity-based compensation plan.

Stock Options

Options to purchase shares of common stock were granted in 2011 with an estimated fair value of $7.6 million. The following summarizes the values from and assumptions for the Black-Scholes option pricing model for stock options issued during the nine months ended September 30, 2011:


Wtd avg grant date fair value			$9.16
Wtd avg grant date			Jan 3, 2011
Wtd avg risk-free interest rate			2.38%
Expected life (in years)			6.0
Wtd avg volatility			66.8%
Expected dividends			-

The following table summarizes our stock option activity for the nine months ended September 30, 2011:


				Wtd Avg Exercise		Wtd Avg Remaining		Aggregate Intrinsic
	Shares			Price		Contractual Life		Value
						(In years)		(In thousands)
Outstanding at January 1, 2011		3,348,642		$	11.10
Granted		834,970			14.88
Exercised		(118,140	)		6.21
Cancelled		(148,764	)		10.78
Expired		(60,021	)		24.28

Outstanding at September 30, 2011		3,856,687		$	11.88		7.7	$	2,655

Exercisable at September 30, 2011		1,910,306		$	11.52		7.1	$	1,762

We estimate that a total of 3.8 million stock options will become vested including those options already exercisable. Compensation expense related to stock options of $5.3 million and $5.2 million was recognized for the nine months ended September 30, 2011 and 2010, respectively. Cash received from the exercise of stock options totaled $0.7 million for the nine months ended September 30, 2011. The total intrinsic value of those options exercised was $1.0 million.

Restricted Stock

The following table summarizes our restricted stock and stock unit activity for the nine months ended September 30, 2011:


	Payable in shares					Payable in cash
				Wtd Avg Grant Date					Wtd Avg Grant Date
	Shares			Fair Value		Shares			Fair Value

Outstanding at January 1, 2011		2,329,089		$	11.27		372,633		$	10.31
Granted		1,389,404			13.89		214,515			14.88
Vested		(1,100,235	)		12.15		(150,505	)		9.76
Cancelled		(137,818	)		12.17		(60,852	)		13.20

Outstanding at September 30, 2011		2,480,440		$	12.30		375,791		$	13.13

As of December 31, 2010, the unrecognized compensation cost related to outstanding unvested restricted stock was $13.9 million, which is expected to be recognized in expense through December 2013. Grants of restricted stock and RSUs during the nine months ended September 30, 2011 had an estimated grant date fair value of $19.3 million. The fair value of RSUs settled in cash was $2.8 million at September 30, 2011. For the nine months ended September 30, 2011 and 2010, compensation expense of $10.2 million and $10.1 million, respectively, was recognized. The total fair value of shares vested during the nine months ended September 30, 2011 was $13.4 million.

10. EARNINGS PER SHARE

The following is a reconciliation of the numerator and denominator used for the computation of basic and diluted net income per common share:


	For the Three Months Ended						For the Nine Months Ended
	September 30,						September 30,
	2011			2010			2011			2010
	(In thousands, except per share data)
Net income attributable to Quicksilver	$	28,686		$	21,803		$	66,515		$	116,794
Basic income allocable to participating securities ⁽¹⁾		(359	)		(286	)		(801	)		(1,512	)

Basic net income attributable to Quicksilver	$	28,327		$	21,517		$	65,714		$	115,282
Impact of assumed conversions – interest on 1.875% convertible debentures, net of income taxes		-			-			-			5,361

Income available to stockholders assuming conversion of convertible debentures	$	28,327		$	21,517		$	65,714		$	120,643


Weighted average common shares – basic		169,031			168,053			168,963			167,962
Effect of dilutive securities ⁽²⁾:
Share-based compensation awards		705			730			805			788
Contingently convertible debentures		-			-			-			9,816

Weighted average common shares – diluted		169,736			168,783			169,768			178,566


Earnings per common share - basic	$	0.17		$	0.13		$	0.39		$	0.69

Earnings per common share - diluted	$	0.17		$	0.13		$	0.39		$	0.68


⁽¹⁾		Restricted share awards that contain nonforfeitable rights to dividends are participating securities and, therefore, are included in computing earnings using the two-class method. Participating securities, however, do not participate in undistributed net losses.

⁽²⁾		For the three and nine months ended September 30, 2011, the effects of 9.8 million shares associated with our contingently convertible debt were antidilutive, and stock options and unvested restricted stock units representing 2.0 million and 1.9 million shares, respectively, were antidilutive and, therefore, excluded from the diluted share calculations. For the three months ended September 30, 2010, the effects of 9.8 million shares associated with our contingently convertible debt were antidilutive and, therefore, excluded from the diluted share calculations. For the three and nine months ended September 30, 2010, unvested restricted stock units representing 1.2 million shares were antidilutive and, therefore, excluded from the diluted share calculations.

11. CONDENSED CONSOLIDATING FINANCIAL INFORMATION

Note 18 to the consolidated financial statements in our 2010 Annual Report on Form 10-K contains a more complete description of our guarantor, non-guarantor, restricted and unrestricted subsidiaries. After completing the Crestwood Transaction during the fourth quarter of 2010, we no longer have any unrestricted subsidiaries except for four newly created subsidiaries that held no assets or liabilities as of September 30, 2011. During 2011, we have made immaterial corrections to our previously issued Condensed Consolidating Financial Information as of December 31, 2010. These adjustments had no impact on our previously reported consolidated balance sheet, statements of operations, cash flows or equity, and they have no impact on compliance with any of our debt covenants. The adjustments effect a presentation on a gross basis of Quicksilver’s intercompany receivables and payables to reflect the classification afforded by its wholly-owned, restricted guarantor subsidiaries as of December 31, 2010. An adjustment was also made within property and equipment and equity to reflect intercompany receivables between Quicksilver and its wholly-owned restricted non-guarantor subsidiary.

The following tables present financial information about Quicksilver and our restricted subsidiaries for the three-and nine-month periods covered by the consolidated financial statements.

Condensed Consolidating Balance Sheets


	September 30, 2011
			Restricted		Restricted					Quicksilver
	Quicksilver		Guarantor		Non-Guarantor		Consolidating			Resources Inc.
	Resources Inc.		Subsidiaries		Subsidiaries		Eliminations			Consolidated
					(In thousands)
ASSETS
Current assets	$	280,905	$	87,401	$	46,836	$	(197,478	)	$	217,664
Property and equipment		2,677,287		97,863		601,655		-			3,376,805
Investment in subsidiaries (equity method)		273,362		-		-		(251,637	)		21,725
Other assets		358,876		-		32,024		(243,620	)		147,280

Total assets	$	3,590,430	$	185,264	$	680,515	$	(692,735	)	$	3,763,474


LIABILITIES AND EQUITY
Current liabilities	$	465,245	$	110,573	$	37,298	$	(197,478	)	$	415,638
Long-term liabilities		2,007,391		21,871		444,400		(243,620	)		2,230,042
Stockholders’ equity		1,117,794		52,820		198,817		(251,637	)		1,117,794

Total liabilities and equity	$	3,590,430	$	185,264	$	680,515	$	(692,735	)	$	3,763,474


	December 31, 2010
			Restricted		Restricted					Quicksilver
	Quicksilver		Guarantor		Non-Guarantor		Consolidating			Resources Inc.
	Resources Inc.		Subsidiaries		Subsidiaries		Eliminations			Consolidated
					(In thousands)
ASSETS
Current assets	$	295,697	$	86,582	$	49,424	$	(193,531	)	$	238,172
Property and equipment		2,416,138		68,390		583,317		—			3,067,845
Assets of midstream operations		—		27,178		—		—			27,178
Investment in subsidiaries (equity method)		369,608		—		—		(286,267	)		83,341
Other assets		339,227		—		191		(243,620	)		95,798

Total assets	$	3,420,670	$	182,150	$	632,932	$	(723,418	)	$	3,512,334


LIABILITIES AND EQUITY
Current liabilities	$	496,852	$	106,627	$	53,152	$	(193,531	)	$	463,100
Long-term liabilities		1,864,410		20,346		347,259		(243,620	)		1,988,395
Liabilities of midstream operations		—		1,431		—		—			1,431
Stockholders’ equity		1,059,408		53,746		232,521		(286,267	)		1,059,408

Total liabilities and equity	$	3,420,670	$	182,150	$	632,932	$	(723,418	)	$	3,512,334

Condensed Consolidating Statements of Income


	For the Three Months Ended September 30, 2011
				Restricted			Restricted						Quicksilver
	Quicksilver			Guarantor			Non-Guarantor			Consolidating			Resources Inc.
	Resources Inc.			Subsidiaries			Subsidiaries			Eliminations			Consolidated
							(In thousands)
Revenue	$	209,036		$	1,095		$	50,609		$	(847	)	$	259,893
Operating expenses		162,603			1,706			28,450			(847	)		191,912
Equity in net earnings of subsidiaries		14,728			-			-			(14,728	)		-

Operating income (loss)		61,161			(611	)		22,159			(14,728	)		67,981
Income from earnings of BBEP		14,370			-			-			-			14,370
Interest expense and other		(37,003	)		-			(248	)		-			(37,251	)
Income tax (expense) benefit		(9,842	)		213			(6,785	)		-			(16,414	)

Net income (loss)	$	28,686		$	(398	)	$	15,126		$	(14,728	)	$	28,686


	For the Three Months Ended September 30, 2010
				Restricted			Restricted			Restricted			Quicksilver			Unrestricted						Quicksilver
	Quicksilver			Guarantor			Non-Guarantor			Subsidiary			and Restricted			Non-Guarantor			Consolidating			Resources Inc.
	Resources Inc.			Subsidiaries			Subsidiaries			Eliminations			Subsidiaries			Subsidiaries			Eliminations			Consolidated
										(In thousands)
Revenue	$	204,389		$	1,802		$	28,609		$	(894	)	$	233,906		$	30,366		$	(26,572	)	$	237,700
Operating expenses		132,704			30,776			21,689			(894	)		184,275			14,905			(26,572	)		172,608
Equity in net earnings of subsidiaries		(10,600	)		7,465			-			10,600			7,465			-			(7,465	)		-

Operating income (loss)		61,085			(21,509	)		6,920			10,600			57,096			15,461			(7,465	)		65,092
Income from earnings of BBEP		17,024			-			-			-			17,024			-			-			17,024
Interest expense and other		(32,266	)		-			(1,828	)		-			(34,094	)		(3,185	)		-			(37,279	)
Income tax expense		(24,040	)		7,528			(1,711	)		-			(18,223	)		(45	)		-			(18,268	)

Net income (loss)	$	21,803		$	(13,981	)	$	3,381		$	10,600		$	21,803		$	12,231		$	(7,465	)	$	26,569
Net income attributable to noncontrolling interests		-			-			-			-			-			(4,766	)		-			(4,766	)

Net income (loss) attributable to Quicksilver	$	21,803		$	(13,981	)	$	3,381		$	10,600		$	21,803		$	7,465		$	(7,465	)	$	21,803


	For the Nine Months Ended September 30, 2011
				Restricted			Restricted						Quicksilver
	Quicksilver			Guarantor			Non-Guarantor			Consolidating			Resources Inc.
	Resources Inc.			Subsidiaries			Subsidiaries			Eliminations			Consolidated
							(In thousands)
Revenue	$	591,394		$	3,584		$	128,333		$	(2,785	)	$	720,526
Operating expenses		442,166			4,512			130,769			(2,785	)		574,662
Equity in net earnings of subsidiaries		(6,575	)		-			-			6,575			-

Operating income (loss)		142,653			(928	)		(2,436	)		6,575			145,864
Loss from earnings of BBEP		(32,721	)		-			-			-			(32,721	)
Interest expense and other		(3,182	)		-			(3,500	)		-			(6,682	)
Income tax (expense) benefit		(40,235	)		324			(35	)		-			(39,946	)

Net income (loss)	$	66,515		$	(604	)	$	(5,971	)	$	6,575		$	66,515


	For the Nine Months Ended September 30, 2010
				Restricted			Restricted			Restricted			Quicksilver			Unrestricted						Quicksilver
	Quicksilver			Guarantor			Non-Guarantor			Subsidiary			and Restricted			Non-Guarantor			Consolidating			Resources Inc.
	Resources Inc.			Subsidiaries			Subsidiaries			Eliminations			Subsidiaries			Subsidiaries			Eliminations			Consolidated
										(In thousands)
Revenue	$	582,283		$	5,013		$	93,158		$	(2,219	)	$	678,235		$	82,299		$	(72,106	)	$	688,428
Operating expenses		364,202			35,129			68,831			(2,219	)		465,943			44,787			(72,106	)		438,624
Equity in net earnings of subsidiaries		5,546			17,414			-			(5,546	)		17,414			-			(17,414	)		-

Operating income (loss)		223,627			(12,702	)		24,327			(5,546	)		229,706			37,512			(17,414	)		249,804
Income from earnings of BBEP		24,203			-			-			-			24,203			-			-			24,203
Interest expense and other		(60,667	)		-			(5,050	)		-			(65,717	)		(8,808	)		-			(74,525	)
Income tax (expense) benefit		(70,369	)		4,446			(5,475	)		-			(71,398	)		(171	)		-			(71,569	)

Net income (loss)	$	116,794		$	(8,256	)	$	13,802		$	(5,546	)	$	116,794		$	28,533		$	(17,414	)	$	127,913
Net income attributable to noncontrolling interests		-			-			-			-			-			(11,119	)		-			(11,119	)

Net income (loss) attributable to Quicksilver	$	116,794		$	(8,256	)	$	13,802		$	(5,546	)	$	116,794		$	17,414		$	(17,414	)	$	116,794

Condensed Consolidating Statements of Cash Flows


	For the Nine Months Ended September 30, 2011
				Restricted			Restricted			Quicksilver
	Quicksilver			Guarantor			Non-Guarantor			Resources Inc.
	Resources Inc.			Subsidiaries			Subsidiaries			Consolidated
				(In thousands)
Net cash flow provided by operations	$	126,921		$	2,224		$	45,521		$	174,666
Capital expenditures		(402,286	)		(2,224	)		(146,444	)		(550,954	)
Proceeds from sale of BBEP units		145,799			-			-			145,799
Proceeds from sale of properties and equipment		2,515			-			1,204			3,719

Net cash flow used by investing activities		(253,972	)		(2,224	)		(145,240	)		(401,436	)
Issuance of debt		402,500			-			246,319			648,819
Repayments of debt		(313,880	)		-			(142,006	)		(455,886	)
Debt issuance costs		(7,467	)		-			(2,809	)		(10,276	)
Proceeds from exercise of stock options		733			-			-			733
Purchase of treasury stock		(4,841	)		-			-			(4,841	)

Net cash flow provided by financing activities		77,045			-			101,504			178,549
Effect of exchange rates on cash		-			-			(114	)		(114	)

Net increase (decrease) in cash and equivalents		(50,006	)		-			1,671			(48,335	)
Cash and equivalents at beginning of period		54,937			-			-			54,937

Cash and equivalents at end of period	$	4,931		$	-		$	1,671		$	6,602


	For the Nine Months Ended September 30, 2010
				Restricted			Restricted			Quicksilver			Unrestricted						Quicksilver
	Quicksilver			Guarantor			Non-Guarantor			and Restricted			Non-Guarantor			Consolidating			Resources Inc.
	Resources Inc.			Subsidiaries			Subsidiaries			Subsidiaries			Subsidiaries			Eliminations			Consolidated
										(In thousands)
Net cash flow provided by operating activities	$	257,090		$	593		$	59,704		$	317,387		$	44,873		$	(14,870	)	$	347,390
Capital expenditures		(380,507	)		(593	)		(53,362	)		(434,462	)		(52,470	)		(7,406	)		(494,338	)
Distribution to parent		80,276			-			-			80,276			(80,276	)		-			-
Proceeds from sale of BBEP units		22,498									22,498			-			-			22,498
Proceeds from sale of properties and equipment		1,030			-			-			1,030			-			-			1,030

Net cash flow used by investing activities		(276,703	)		(593	)		(53,362	)		(330,658	)		(132,746	)		(7,406	)		(470,810	)
Issuance of debt		478,500			-			39,532			518,032			143,200			-			661,232
Repayments of debt		(414,500	)		-			(46,443	)		(460,943	)		(30,100	)		-			(491,043	)
Debt issuance costs		(109	)		-			-			(109	)		-			-			(109	)
Gas Purchase Commitment — net		(25,900	)		-			-			(25,900	)		-			-			(25,900	)
Issuance of KGS common units		-			-			-			-			11,054			-			11,054
Distributions to parent		-			-						-			(22,276	)		22,276			-
Distributions to noncontrolling interests		-			-			-			-			(13,550	)		-			(13,550	)
Proceeds from exercise of stock options		1,388			-			-			1,388			-			-			1,388
Treasury transactions — equity		(4,851	)		-			-			(4,851	)		(1,144	)		-			(5,995	)

Net cash flow provided (used) by financing activities		34,528			-			(6,911	)		27,617			87,184			22,276			137,077
Effect of exchange rates on cash		-			-			(306	)		(306	)		-			-			(306	)

Net increase (decrease) in cash and equivalents		14,915			-			(875	)		14,040			(689	)		-			13,351
Cash and equivalents at beginning of period		5			-			1,034			1,039			746			-			1,785

Cash and equivalents at end of period	$	14,920		$	-		$	159		$	15,079		$	57		$	-		$	15,136

12. SEGMENT INFORMATION

We operate in two geographic segments, the U.S. and Canada, where we are engaged in the exploration and production segment of the oil and gas industry. Prior to the Crestwood Transaction, our processing and gathering segment provided natural gas gathering and processing services predominantly through KGS. Revenue earned by KGS prior to the Crestwood Transaction for the gathering and processing of our gas was eliminated on a consolidated basis as is the GPT expense recognized by our producing properties. We evaluate performance based on operating income and property and equipment costs incurred.


	Exploration & Production				Gathering &									Quicksilver
	U.S.		Canada		Processing			Corporate			Elimination			Consolidated
					(In thousands)
For the Three Months Ended September 30:
2011
Revenue	$	225,567	$	34,078	$	1,095		$	-		$	(847	)	$	259,893
DD&A		43,441		12,300		1,356			589			-			57,686
Operating income (loss)		72,783		23,982		(611	)		(28,173	)		-			67,981
Property and equipment costs incurred		128,531		35,926		587			5			-			165,049

2010
Revenue	$	204,389	$	28,609	$	31,590		$	-		$	(26,888	)	$	237,700
DD&A		33,963		10,676		7,387			516			-			52,542
Impairment expense		2,920		-		28,611			-						31,531
Operating income (loss)		93,266		7,850		(11,503	)		(24,521	)		-			65,092
Property and equipment costs incurred		100,678		20,140		12,209			1,056			-			134,083


	Exploration & Production				Gathering &									Quicksilver
	U.S.		Canada		Processing			Corporate			Elimination			Consolidated
					(In thousands)
For the Nine Months Ended September 30:
2011
Revenue	$	619,310	$	100,418	$	3,584		$	-		$	(2,786	)	$	720,526
DD&A		123,776		35,811		3,535			1,739			-			164,861
Impairment expense		-		49,063		-			-			-			49,063
Operating income (loss)		208,644		1,630		(927	)		(63,483	)		-			145,864
Property and equipment costs incurred		381,977		134,794		8,017			511			-			525,299

2010
Revenue	$	582,283	$	93,158	$	85,576		$	-		$	(72,589	)	$	688,428
DD&A		93,620		33,114		21,799			1,435			-			149,968
Impairment expense		2,920		-		28,611			-			-			31,531
Operating income (loss)		272,186		27,118		13,680			(63,180	)		-			249,804
Property and equipment costs incurred		424,962		55,274		49,160			3,023			-			532,419

Property, plant and equipment - net
September 30, 2011	$	2,664,338	$	600,192	$	97,863		$	14,412		$	-		$	3,376,805
December 31, 2010		2,403,038		581,775		68,390			14,642			-			3,067,845

Investment in equity affiliates
September 30, 2011	$	21,725	$	-	$	-		$	-		$	-		$	21,725
December 31, 2010		83,341		-		-			-			-			83,341

13. TRANSACTIONS WITH RELATED PARTIES

As of September 30, 2011, members of the Darden family and entities controlled by them beneficially owned approximately 32% of our outstanding common stock. Thomas Darden, Glenn Darden and Anne Darden Self are officers and directors of Quicksilver.

We paid $0.1 million and $0.7 million in the first nine months of 2011 and 2010, respectively, for rent on buildings, including a manufacturing facility, owned by entities controlled by members of the Darden family. Rental rates were determined based on comparable rates charged by third parties. In October 2011, we agreed to purchase the manufacturing facility from an entity controlled by members of the Darden family for $1.1 million. We previously leased this facility from the seller for the manufacture of oil and gas equipment.


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

The following Management’s Discussion and Analysis (“MD&A”) is intended to help readers of our financial statements understand our business, results of operations, financial condition, liquidity and capital resources. MD&A is provided as a supplement to, and should be read in conjunction with, the other sections of this Quarterly Report. Prior to the Crestwood Transaction, we conducted our operations in two segments: (1) our more dominant exploration and production segment, and (2) our significantly smaller gathering and processing segment. Except as otherwise specifically noted, or as the context requires otherwise, and except to the extent that differences between these segments or our geographic segments are material to an understanding of our business taken as a whole, we present this MD&A on a consolidated basis.

Our MD&A includes the following sections:

	•		2011 Highlights — a summary of significant activities and events affecting Quicksilver
	•		2011 Capital Program — a summary of our planned capital expenditures during 2011
	•		Results of Operations — an analysis of our consolidated results of operations for the three- and nine-month periods presented in our financial statements
	•		Liquidity, Capital Resources and Financial Position — an analysis of our cash flows, sources and uses of cash, contractual obligations and commercial commitments

2011 HIGHLIGHTS

Proposed Master Limited Partnership

In October 2011, we announced our intention to file a registration statement on Form S-1 with the Securities and Exchange Commission in connection with issuing common units in a proposed master limited partnership (the “MLP”). The MLP plans to use proceeds of the initial public offering and borrowings under a planned new bank credit facility to buy certain of our Barnett Shale assets. We project that the assets in the initial sale to the MLP will comprise 18% of our current Barnett Shale production and 15% of our year-end 2010 proved Barnett Shale reserves. We will retain a significant ownership position in the MLP and will own 100% of the general partner.

New Credit Facilities

In our Canadian Credit Facility, we provided for the ability to execute a public offering of our Canadian operations as well as a joint venture transaction for our Canadian midstream operations. We are not currently pursuing a public offering of our Canadian operations. As previously disclosed, we regularly evaluate opportunities related to our operations, including our Canadian midstream operations.

Convertible Debentures

Emerging Basins

We had four producing natural gas wells as of December 31, 2010 in our Horn River Asset. Through September 2011, we spent $49.3 million for construction of infrastructure to gather, compress and deliver gas to third-party processing facilities. During 2011, we have also drilled five additional wells including one well drilled to explore the prospect of the Exshaw formation. During the fourth quarter of 2011, we expect to drill four more wells.

We do not expect any of the other wells drilled during 2011 to be completed until 2012. We have also entered into a series of contracts with NGTL for the construction of midstream facilities that we believe will enhance our take away capacity from Horn River.

Through September 30, 2011, we drilled six vertical wells in our Greater Green River Asset. Four of these wells were awaiting completion and two were in flowback. We expect to drill one horizontal well in the fourth quarter of 2011 and to complete five wells, with a goal of having production from all seven wells drilled by December 31, 2011.

Sale of BBEP Units

During the nine months ended September 30, 2011, we sold approximately 7.7 million BBEP Units. We received $145.8 million for those units and recognized total gains of $133.2 million in our income statement as other income.

Strategic Alternatives for Quicksilver

On March 24, 2011, an investor group, consisting of members of the Darden family and an entity controlled by them, announced its decision not to pursue a previously announced plan to take the Company private. As a result, our board of directors disbanded its transaction committee.

2011 CAPITAL PROGRAM

We incurred capital costs of $525.3 million for the first nine months of 2011 and continue to expect our 2011 capital program of approximately $690 million to be allocated as disclosed in our Quarterly Report on Form 10-Q for June 30, 2011.

RESULTS OF OPERATIONS

Three Months Ended September 30, 2011 and 2010

The following discussion compares the results of operations for the three months ended September 30, 2011 and 2010, or the 2011 quarter and 2010 quarter, respectively. “Other U.S.” refers to the combined amounts for our Greater Green River Asset and Southern Alberta Asset.

Revenue

Production Revenue:


	Natural Gas				NGL						Oil				Total
	2011		2010		2011			2010			2011		2010		2011		2010
								(In millions)
Barnett Shale	$	104.9	$	85.0	$	55.2		$	37.3		$	2.4	$	2.7	$	162.5	$	125.0
Other U.S.		0.4		0.4		0.2			0.1			2.9		2.6		3.5		3.1
Hedging		23.2		63.5		(12.9	)		(1.7	)		-		-		10.3		61.8

U.S.		128.5		148.9		42.5			35.7			5.3		5.3		176.3		189.9
Horseshoe Canyon		20.0		19.5		-			-			-		-		20.0		19.5
Horn River		4.7		1.5		-			-			-		-		4.7		1.5
Hedging		7.1		7.3		-			-			-		-		7.1		7.3

Canada		31.8		28.3		-			-			-		-		31.8		28.3

Consolidated	$	160.3	$	177.2	$	42.5		$	35.7		$	5.3	$	5.3	$	208.1	$	218.2

Average Daily Production Volume:


	Natural Gas				NGL					Oil				Equivalent Total
	2011		2010		2011		2010			2011		2010		2011		2010
	(MMcfd)				(Bbld)					(Bbld)				(MMcfed)
Barnett Shale		277.6		217.3		11,911		12,567			304		409		350.9		295.1
Other U.S.		1.2		1.1		26		(10	)		392		425		3.7		3.7

U.S.		278.8		218.4		11,937		12,557			696		834		354.6		298.8
Horseshoe Canyon		57.5		58.9		8		5			-		-		57.6		58.9
Horn River		15.3		4.7		-		-			-		-		15.2		4.7

Canada		72.8		63.6		8		5			-		-		72.8		63.6

Consolidated		351.6		282.0		11,945		12,562			696		834		427.4		362.4

Average Realized Price:


	Natural Gas				NGL						Oil				Equivalent Total
	2011		2010		2011			2010			2011		2010		2011		2010
	(per Mcf)				(per Bbl)						(per Bbl)				(per Mcfe)
Barnett Shale	$	4.11	$	4.25	$	50.38		$	32.37		$	85.71	$	72.21	$	5.04	$	4.61
Other U.S.		2.80		3.64		69.68			86.14			80.14		66.37		9.88		8.65
Hedging		0.90		3.16		(11.75	)		(1.43	)		-		-		0.32		2.25
U.S.		5.01		7.41		38.67			30.90			82.58		69.32		5.40		6.91
Horseshoe Canyon	$	3.77	$	3.61	$	46.52		$	61.62		$	-	$	-	$	3.77	$	3.61
Horn River		3.41		3.42		-			-			-		-		3.41		3.42
Hedging		1.06		1.25		-			-			-		-		1.06		1.25
Canada	$	4.75	$	4.84	$	46.52		$	61.62		$	-	$	-	$	4.75	$	4.85
Consolidated	$	4.96	$	6.83	$	38.68		$	30.91		$	82.58	$	69.32	$	5.29	$	6.55

The following table summarizes the changes in our production revenue:


	Natural
	Gas			NGL			Oil			Total
				(In thousands)
Revenue for the 2010 quarter	$	177,201		$	35,727		$	5,321		$	218,249
Volume variances		26,253			(1,836	)		(885	)		23,532
Hedge revenue variances		(40,474	)		(11,248	)		-			(51,722	)
Price variances		(2,708	)		19,864			849			18,005

Revenue for the 2011 quarter	$	160,272		$	42,507		$	5,285		$	208,064

Natural gas revenue for the 2011 quarter decreased from the 2010 quarter despite a 25% increase in production. Realized prices, before hedge settlements, were slightly lower in the U.S. for the 2011 quarter as compared to the 2010 quarter. A 28% increase in natural gas volume from our Barnett Shale Asset was primarily the result of wells tied into sales lines since the 2010 quarter. Canadian natural gas production increased because of an 11 MMcfd production increase from our Horn River Asset attributable to additional producing wells.

The increase in NGL revenue for the 2011 quarter resulted from a 56% increase in realized prices, before hedge losses, which was partially offset by a 5% decrease in our Barnett Shale production.

Our revenue from natural gas and NGL production for the 2011 quarter and 2010 quarter was higher by $17.4 million and $69.1 million, respectively, because of our hedging activities. During the 2011 quarter we hedged natural gas production of 190 MMcfd at a weighted average NYMEX floor of $5.95 per Mcf and NGL production of 10.5

MBbld at a weighted average floor of $38.84 per Bbl. During the 2010 quarter, we hedged natural gas production of 200 MMcfd at a weighted average NYMEX floor of $7.40 per Mcf and NGL production of 10 MBbld at a weighted average floor of $33.47 per Bbl.

Sales of Purchased Natural Gas and Costs of Purchased Natural Gas


	Three Months Ended
	September 30,
	2011		2010
	(In thousands)
Sales of purchased natural gas
Purchases from Eni	$	17,681	$	14,840
Purchases from others		2,449		2,142

Total		20,130		16,982
Costs of purchased natural gas sold
Purchases from Eni		17,737		18,711
Purchases from others		2,217		1,424
Unrealized valuation gain on Gas Purchase Commitment		-		(5,497	)

Total		19,954		14,638

Net sales and purchases of natural gas	$	176	$	2,344

The Gas Purchase Commitment with Eni expired on December 31, 2010, therefore, we recognized no unrealized valuation gain or loss during the 2011 quarter.

Other Revenue


	Three Months Ended
	September 30,
	2011		2010
	(In thousands)
Midstream revenue from third parties
KGS	$	-	$	2,411
Canada		788		537
Other Texas		248		333

Total midstream revenue		1,036		3,281
Unrealized gains on commodity derivatives		29,737		-
Gains (losses) from hedge ineffectiveness		880		(812	)
Other		46		-

Total	$	31,699	$	2,469

In the 2011 quarter, we recognized $29.7 million of unrealized gains on commodity derivatives that we entered into during 2011 that were not designated as hedges at inception. All of these derivatives were subsequently designated as hedges on August 31, 2011. Midstream revenue was lower from the 2010 quarter primarily as a result of the sale of our interests in KGS in October 2010.

Operating Expense

Lease Operating


	Three Months Ended September 30,
	2011				2010
	(In thousands, except per unit amounts)
			Per				Per
			Mcfe				Mcfe
Barnett Shale
Cash expense	$	16,391	$	0.51	$	12,035	$	0.44
Equity compensation		212		-		201		0.01

	$	16,603	$	0.51	$	12,236	$	0.45

Other U.S.
Cash expense	$	2,191	$	6.44	$	1,219	$	3.62
Equity compensation		82		0.24		45		0.13

	$	2,273	$	6.68	$	1,264	$	3.75

Total U.S.
Cash expense	$	18,582	$	0.57	$	13,254	$	0.48
Equity compensation		294		0.01		246		0.01

	$	18,876	$	0.58	$	13,500	$	0.49

Horseshoe Canyon
Cash expense	$	7,656	$	1.45	$	6,731	$	1.24
Equity compensation		99		0.06		276		0.05

	$	7,755	$	1.51	$	7,007	$	1.29

Horn River
Cash expense	$	1,042	$	0.74	$	442	$	1.02
Equity compensation		-		-		-		-

	$	1,042	$	0.74	$	442	$	1.02

Total Canada
Cash expense	$	8,698	$	1.30	$	7,173	$	1.23
Equity compensation		99		0.01		276		0.04

	$	8,797	$	1.31	$	7,449	$	1.27

Total Company
Cash expense	$	27,280	$	0.69	$	20,427	$	0.61
Equity compensation		393		0.01		522		0.02

	$	27,673	$	0.70	$	20,949	$	0.63

Lease operating expense for the 2011 quarter in the U.S. increased 40% when compared to the 2010 quarter. This higher expense was partially associated with the 19% increase in production from our Barnett Shale Asset. Additionally, we had increases for well work-over efforts on older Barnett Shale wells, salt water disposal and gas lift in the 2011 quarter compared to the 2010 quarter.

Lease operating expense for the 2011 quarter in Canada was 18% higher when compared to the 2010 quarter as Horseshoe Canyon lease operating expense increased because of additional well repair and maintenance costs for the 2011 quarter. Lease operating expense in the 2011 quarter for Horn River was $0.6 million higher than for the 2010 quarter because of additional producing wells and higher production volumes.

Gathering, Processing and Transportation


	Three Months Ended September 30,
	2011				2010
	(In thousands, except per unit amounts)
			Per				Per
			Mcfe				Mcfe
Barnett Shale	$	46,335	$	1.44	$	16,148	$	0.59
Other U.S.		6		0.02		7		0.02

Total U.S.		46,341		1.42		16,155		0.59
Horseshoe Canyon		833		0.16		870		0.16
Horn River		3,939		2.81		1,397		3.23

Total Canada		4,772		0.71		2,267		0.39

Total	$	51,113	$	1.30	$	18,422	$	0.55

GPT expense increased for the 2011 quarter compared to the 2010 quarter primarily due to the loss of fees earned by KGS for gathering and processing production from our Barnett Shale Asset following the closing of the Crestwood Transaction and the increase in Barnett Shale production. KGS’ revenue earned from gathering and processing production from our Barnett Shale Asset was $20.9 million, or $0.76 per Mcfe, for the 2010 quarter. Canadian GPT expense increased for the 2011 quarter as compared to the 2010 quarter both in total dollars and on a per Mcfe basis primarily as a result of higher gathering fees in addition to increased production from our Horn River Asset for the 2011 quarter.

Production and Ad Valorem Taxes


	Three Months Ended September 30,
	2011				2010
	(In thousands, except per unit amounts)
			Per				Per
			Mcfe				Mcfe
Production taxes
U.S.	$	3,021	$	0.09	$	2,265	$	0.08
Canada		81		0.01		131		0.02

Total production taxes		3,102		0.08		2,396		0.08
Ad valorem taxes
U.S.	$	3,979		0.12	$	6,569		0.24
Canada		676		0.10		236		0.04

Total ad valorem taxes		4,655		0.12		6,805		0.20

Total	$	7,757	$	0.20	$	9,201	$	0.28

The 2010 quarter included $1.0 million for KGS ad valorem taxes. The increase in U.S. production taxes during the 2011 quarter was due to the increase in U.S. production.

Depletion, Depreciation and Accretion


	Three Months Ended September 30,
	2011				2010
	(In thousands, except per unit amounts)
			Per				Per
			Mcfe				Mcfe
Depletion
U.S.	$	41,834	$	1.28	$	32,456	$	1.17
Canada		9,569		1.43		9,079		1.55

Total depletion		51,403		1.31		41,535		1.24
Depreciation of other fixed assets
U.S.	$	3,236	$	0.10	$	9,066	$	0.33
Canada		2,352		0.35		1,141		0.20

Total depreciation		5,588		0.14		10,207		0.31
Accretion		695		0.02		800		0.03

Total	$	57,686	$	1.47	$	52,542	$	1.58

U.S. depletion for the 2011 quarter reflected a 9% increase in the U.S. depletion rate and a 19% increase in U.S. production when compared to the 2010 quarter. The increase in the U.S. depletion rate was the result of a 33% increase in net book value for our U.S. properties and future development costs while the 2010 year-end proved U.S. reserves increased only 22% compared to the 2009 year-end. Canadian depletion increased $0.5 million as a result of a 14% increase in Canadian production volumes partially offset by an 8% decrease in the Canadian depletion rate when compared to the 2010 quarter. The decrease in the Canadian depletion rates relates to the decrease in the net book value of our Canadian properties as a result of ceiling test impairment charges in December 2010 and March 2011 and a decrease in estimated future development costs.

U.S. depreciation for the 2010 quarter included KGS depreciation of $5.7 million.

General and Administrative


	Three Months Ended September 30,
	2011				2010
	(In thousands, except per unit amounts)
			Per				Per
			Mcfe				Mcfe
Cash expense	$	11,333	$	0.29	$	14,006	$	0.42
Strategic transaction costs		3,056		0.08		2,560		0.08
Litigation settlement		8,500		0.22		2,400		0.07
Equity compensation		4,695		0.11		5,039		0.15

Total	$	27,584	$	0.70	$	24,005	$	0.72

General and administrative expense for the 2011 quarter included $8.5 million for settlement of the Eagle litigation and $3.1 million for legal, accounting and other professional fees incurred in connection with possible strategic transactions. The 2010 quarter included costs related to settlement of a separate legal matter for $2.4 million, Crestwood Transaction legal and professional fees of $2.6 million and KGS general and administrative expense of $3.3 million arising prior to the Crestwood Transaction.

Earnings of BBEP

We record our portion of BBEP’s earnings during the quarter in which its financial statements become publicly available. As a result, our 2011 quarter and 2010 quarter results of operations include BBEP’s earnings for the three months ended June 30, 2011 and 2010, respectively.

We recognized income of $14.4 million and $17.0 million for equity earnings from our investment in BBEP for the 2011 quarter and 2010 quarter, respectively. BBEP continues to experience significant volatility in its net earnings primarily due to changes in the unrealized value of its derivative instruments for which it does not employ hedge accounting.

Other Income

We recognized a gain of $9.5 million in the 2011 quarter from the sale of 0.6 million BBEP Units in July 2011. In the 2010 quarter we recognized a gain of $14.4 million from the sale of 1.4 million BBEP Units.

Interest Expense


	Three Months Ended
	September 30,
	2011			2010
	(In thousands)
Interest costs on debt outstanding	$	43,039		$	48,850
Add:
Fees paid on letters of credit outstanding		115			-
Premium paid — senior notes repurchased		1,989			-
Non-cash interest ⁽¹⁾		5,237			4,080
Interest capitalized		(1,987	)		(1,398	)

Interest expense	$	48,393		$	51,532

⁽¹⁾Amortization of deferred financing costs, original issue discount net of interest swap settlement amortization.

Interest costs on debt outstanding for the 2011 quarter were reduced when compared to the 2010 quarter primarily because the 2010 quarter included $2.5 million of interest attributable to KGS. The 2011 quarter included $2.0 million in premiums paid to repurchase senior notes that was offset by interest accrued on lower average debt balances in the 2011 quarter. The increase in non-cash interest is primarily attributable to the write-off deferred financing, original issue discount net of deferred interest swap settlement gains attributable to the senior notes repurchased and $1.0 million of deferred financing costs associated with the terminated Senior Secured Credit Facility.

We used proceeds from borrowings under our U.S. Credit Facility to fund the repurchases which are summarized below:


	Repurchase		Face		Premium on
Instrument	Price		Value		Repurchase
	(In thousands)
Senior notes due 2015	$	32,884	$	32,000	$	884
Senior notes due 2016		7,945		7,000		945
Senior notes due 2019		2,160		2,000		160

	$	42,989	$	41,000	$	1,989

Upon completion of the convertible debenture repurchase in November 2011, noncash interest for accretion of original issue discount on the convertible debentures, of which $2.0 million was recognized in the 2011 quarter, will be eliminated.

Income Taxes


	Three Months Ended
	September 30,
	2011			2010
Income tax expense (in thousands)	$	16,414		$	18,268
Effective tax rate		36.4	%		40.7	%

Our income tax provision for the 2011 quarter reflects changes in the projected effective tax rate for all of 2011 from 38.4% through June 30, 2011 to our now projected 37.5%. The effective tax rate for the 2011 quarter reflects a projection of a full year of Canadian taxable loss taxed at a projected effective rate of (11.8)% partially offset by projection of a full year of U.S. taxable income taxed at a projected effective rate of 36.0%. U.S. and consolidated

earnings have been impacted by gains associated with our sales of BBEP units and the unrealized derivative gains included in other revenue.

RESULTS OF OPERATIONS

Nine Months Ended September 30, 2011 and 2010

The following discussion compares the results of operations for the nine months ended September 30, 2011 and 2010, or the 2011 period and 2010 period, respectively. “Other U.S.” refers to the combined amounts for our Greater Green River Asset and Southern Alberta Asset.

Revenue

Production Revenue:


	Natural Gas				NGL						Oil				Total
	2011		2010		2011			2010			2011		2010		2011		2010
	(In millions)
Barnett Shale	$	293.1	$	241.1	$	161.2		$	115.8		$	9.2	$	8.9	$	463.5	$	365.8
Other U.S.		0.9		1.9		0.5			0.4			8.9		7.5		10.3		9.8
Hedging		68.6		179.7		(32.7	)		(15.3	)		-		-		35.9		164.4

U.S.		362.6		422.7		129.0			100.9			18.1		16.4		509.7		540.0
Horseshoe Canyon		61.1		69.6		0.1			0.1			-		-		61.2		69.7
Horn River		14.0		6.5		-			-			-		-		14.0		6.5
Hedging		21.2		15.3		-			-			-		-		21.2		15.3

Canada		96.3		91.4		0.1			0.1			-		-		96.4		91.5

Consolidated	$	458.9	$	514.1	$	129.1		$	101.0		$	18.1	$	16.4	$	606.1	$	631.5

Average Daily Production Volume:


	Natural Gas				NGL				Oil				Equivalent Total
	2011		2010		2011		2010		2011		2010		2011		2010
	(MMcfd)				(Bbld)				(Bbld)				(MMcfed)
Barnett Shale		260.7		198.8		12,204		11,869		362		448		336.1		272.7
Other U.S.		1.0		1.6		24		19		383		403		3.3		4.2

U.S.		261.7		200.4		12,228		11,888		745		851		339.4		276.9
Horseshoe Canyon		58.4		60.7		6		7		-		-		58.5		60.7
Horn River		14.5		6.1		-		-		-		-		14.5		6.1

Canada		72.9		66.8		6		7		-		-		73.0		66.8

Consolidated		334.6		267.2		12,234		11,895		745		851		412.4		343.7

Average Realized Price:


	Natural Gas				NGL						Oil				Equivalent Total
	2011		2010		2011			2010			2011		2010		2011		2010
	(per Mcf)				(per Bbl)						(per Bbl)				(per Mcfe)
Barnett Shale	$	4.12	$	4.44	$	48.39		$	35.75		$	93.04	$	72.96	$	5.05	$	4.91
Other U.S.		3.60		4.31		74.95			63.30			85.25		67.28		11.22		8.48
Hedging		0.96		3.28		(9.79	)		(4.71	)		-		-		0.39		2.17
U.S.	$	5.08	$	7.72	$	38.66		$	31.09		$	89.05	$	70.31	$	5.50	$	7.14
Horseshoe Canyon	$	3.83	$	4.20	$	62.41		$	66.78		$	-	$	-	$	3.83	$	4.21
Horn River		3.54		3.91		-			-			-		-		3.54		3.91
Hedging		1.06		0.84		-			-			-		-		1.06		0.84
Canada	$	4.84	$	5.01	$	62.41		$	66.78		$	-	$	-	$	4.84	$	5.02
Consolidated	$	5.02	$	7.05	$	38.67		$	31.12		$	89.05	$	70.31	$	5.38	$	6.73

The following table summarizes the changes in our production revenue:


	Natural
	Gas			NGL			Oil			Total
				(In thousands)
Revenue for the 2010 period	$	514,115		$	101,045		$	16,339		$	631,499
Volume variances		80,399			3,310			(2,046	)		81,663
Hedge revenue variances		(105,178	)		(17,407	)		-			(122,585	)
Price variances		(30,515	)		42,199			3,809			15,493

Revenue for the 2011 period	$	458,821		$	129,147		$	18,102		$	606,070

Natural gas revenue for the 2011 period decreased from the 2010 period despite a 25% increase in production. Realized prices, before hedge settlements, were lower for the 2011 period as compared to the 2010 period, which more than offset production increases. The 31% increase in natural gas volume from our Barnett Shale Asset was primarily the result of wells tied into sales lines since the 2010 period. The Canadian natural gas production increase was the result of increases from additional producing wells in our Horn River Asset offset by a small decrease in production from our Horseshoe Canyon Asset.

The increase in NGL revenue for the 2011 period resulted from a 35% increase in realized prices, before hedge losses, and an increase in production from our Barnett Shale Asset compared to the 2010 period.

Our production revenue for the 2011 period and 2010 period was higher by $57.1 million and $179.7 million, respectively, because of our hedging activities. During the 2011 period, we hedged natural gas production of 190 MMcfd at a weighted average NYMEX floor of $5.95 per Mcf and NGL production of 10.5 MBbld at a weighted average floor of $38.84 per Bbl. During the 2010 period, we hedged natural gas production of 200 MMcfd at a weighted average NYMEX floor of $7.40 per Mcf and NGL production of 10 MBbld at a weighted average floor of $33.47 per Bbl.

Sales of Purchased Natural Gas and Costs of Purchased Natural Gas


	Nine Months Ended
	September 30,
	2011		2010
	(In thousands)
Sales of purchased natural gas
Purchases from Eni	$	47,080	$	41,405
Purchases from others		13,036		8,622

Total		60,116		50,027
Costs of purchased natural gas sold
Purchases from Eni		47,024		49,112
Purchases from others		12,230		8,549
Unrealized valuation gain on Gas Purchase Commitment		-		(5,960	)

Total		59,254		51,701

Net sales and purchases of natural gas	$	862	$	(1,674	)

As the Gas Purchase Commitment with Eni expired on December 31, 2010, no unrealized valuation gain or loss was recognized for the 2011 period.

Other Revenue


	Nine Months Ended
	September 30,
	2011		2010
	(In thousands)
Midstream revenue from third parties
KGS	$	-	$	6,512
Canada		2,418		1,745
Other Texas		799		1,044

Total midstream revenue		3,217		9,301
Unrealized gains on commodity derivatives		48,852		-
Gains (losses) from hedge ineffectiveness		1,698		(2,399	)
Other		573		-

Total	$	54,340	$	6,902

We recognized $48.9 million in the 2011 period for unrealized gains on commodity derivatives that were not designated as hedges at inception, but were subsequently designated as hedges on August 31, 2011. Midstream revenue for the 2011 period was lower primarily as a result of the sale of our interests in KGS in October 2010.

Operating Expense

Lease Operating


	Nine Months Ended September 30,
	2011				2010
	(In thousands, except per unit amounts)
			Per				Per
			Mcfe				Mcfe
Barnett Shale
Cash expense	$	41,500	$	0.45	$	34,126	$	0.46
Equity compensation		692		0.01		630		0.01

	$	42,192	$	0.46	$	34,756	$	0.47
Other U.S.
Cash expense	$	4,807	$	5.24	$	4,415	$	3.87
Equity compensation		181		0.20		131		0.11

	$	4,988	$	5.44	$	4,546	$	3.98
Total U.S.
Cash expense	$	46,307	$	0.50	$	38,541	$	0.51
Equity compensation		873		0.01		761		0.01

	$	47,180	$	0.51	$	39,302	$	0.52
Horseshoe Canyon
Cash expense	$	23,642	$	1.48	$	20,628	$	1.25
Equity compensation		368		0.03		877		0.05

	$	24,010	$	1.51	$	21,505	$	1.30
Horn River
Cash expense	$	2,176	$	0.55	$	1,631	$	0.99
Equity compensation		-		-		-		-

	$	2,176	$	0.55	$	1,631	$	0.99
Total Canada
Cash expense	$	25,818	$	1.30	$	22,259	$	1.22
Equity compensation		368		0.01		877		0.05

	$	26,186	$	1.31	$	23,136	$	1.27
Total Company
Cash expense	$	72,125	$	0.64	$	60,800	$	0.65
Equity compensation		1,241		0.01		1,638		0.02

	$	73,366	$	0.65	$	62,438	$	0.67

Lease operating expense for the 2011 period in the U.S. increased 20% when compared to the 2010 period. The increase in lease operating expense for the 2011 period resulted primarily from higher production volumes from our Barnett Shale Asset including costs attributable to new producing wells.

Lease operating expense for the 2011 period in Canada increased 13% when compared to the 2010 period. Horn River lease operating expense of $2.2 million for the 2011 period was 33% higher than the 2010 period, but decreased 44% on a per Mcfe basis. These changes resulted from additional producing wells and the 138% increase in Horn River production. The $2.5 million increase in Horseshoe Canyon lease operating expense was due to additional well repair and maintenance during the 2011 period.

Gathering, Processing and Transportation


	Nine Months Ended September 30,
	2011				2010
	(In thousands, except per unit amounts)
			Per				Per
			Mcfe				Mcfe
Barnett Shale	$	128,724	$	1.40	$	43,627	$	0.59
Other U.S.		13		0.01		18		0.02

Total U.S.		128,737		1.39		43,645		0.58
Horseshoe Canyon		3,068		0.19		3,658		0.22
Horn River		10,396		2.62		3,777		2.28

Total Canada		13,464		0.68		7,435		0.41

Total	$	142,201	$	1.26	$	51,080	$	0.54

GPT expense increased for the 2011 period compared to the 2010 period primarily due to the loss of fees earned by KGS for gathering and processing production from our Barnett Shale Asset following the closing of the Crestwood Transaction and the increase in Barnett Shale production. KGS’ revenue earned from gathering and processing production from our Barnett Shale Asset was $55.3 million, or 0.73 per Mcfe, for the 2010 period. Canadian GPT expense increased for the 2011 period as compared to the 2010 period both in total dollars and on a per Mcfe basis primarily as a result of higher gathering fees and increased production from our Horn River Asset for the 2011 period.

Production and Ad Valorem Taxes


	Nine Months Ended September 30,
	2011				2010
	(In thousands, except per unit amounts)
			Per				Per
Production taxes			Mcfe				Mcfe
U.S.	$	7,596	$	0.08	$	7,184	$	0.10
Canada		156		0.01		478		0.03

Total production taxes		7,752		0.07		7,662		0.08
Ad valorem taxes
U.S.		14,069		0.15		17,076		0.23
Canada		2,023		0.10		1,879		0.10

Total ad valorem taxes		16,092		0.14		18,955		0.20

Total	$	23,844	$	0.21	$	26,617	$	0.28

Production taxes for the 2011 period reflect the refund of 2008 severance taxes for our Alliance Leasehold in the amount of $0.8 million, which was recorded as a reduction to U.S. production taxes. Higher production volumes for the 2011 period from our Barnett Shale Asset increased production tax expense. The 2010 period included $3.6 million of ad valorem taxes attributable to KGS.

Depletion, Depreciation and Accretion


	Nine Months Ended September 30,
	2011				2010
	(In thousands, except per unit amounts)
			Per				Per
			Mcfe				Mcfe

Depletion
U.S.	$	118,858	$	1.28	$	89,301	$	1.17
Canada		29,325		1.47		28,395		1.56

Total depletion		148,183		1.32		117,696		1.25
Depreciation of other fixed assets
U.S.	$	9,293		0.10	$	26,574		0.35
Canada		5,381		0.27		3,384		0.19

Total depreciation		14,674		0.13		29,958		0.32
Accretion		2,004		0.01		2,314		0.03

Total	$	164,861	$	1.46	$	149,968	$	1.60

U.S. depletion for the 2011 period reflected an increase in the U.S. depletion rate and an increase in U.S. production when compared to the 2010 period. Canadian depletion increased slightly for the 2011 period when compared to the 2010 period as a result of an increase in production volumes partially offset by a 6% decrease in the Canadian depletion rate.

U.S. depreciation for the 2010 period included KGS depreciation of $16.8 million.

Impairment Expense

As required under GAAP, we perform quarterly ceiling tests to assess impairment of our oil and gas properties. We also assess our fixed assets reported outside the full-cost pool when circumstances indicate impairment may have occurred. The calculation of impairment expense is more fully described in Note 5 to the condensed consolidated financial statements in Item 1 of this Quarterly Report.

In the first quarter of 2011, we recognized a $49.1 million non-cash charge for impairment of our Canadian oil and gas properties. The AECO natural gas price used to prepare the March 31, 2011 estimate of the ceiling limit for our Canadian full-cost pool decreased approximately 12% from the AECO price used at December 31, 2010 when we also recognized an impairment charge for our Canadian oil and gas properties. Our Canadian ceiling test prepared at June 30, 2011 and September 30, 2011 resulted in no additional impairment of our Canadian oil and gas properties. Our U.S. ceiling tests, prepared quarterly, resulted in no impairment of our U.S. oil and gas properties in the 2011 period or the 2010 period.

General and Administrative


	Nine Months Ended September 30,
	2011				2010
	(In thousands, except per unit amounts)
			Per				Per
			Mcfe				Mcfe

Cash expense	$	34,478	$	0.31	$	41,808	$	0.44
Strategic transaction costs		4,534		0.04		2,560		0.03
Litigation settlement		8,500		0.08		2,400		0.03
Equity compensation		14,233		0.12		14,977		0.16

Total	$	61,745	$	0.55	$	61,745	$	0.66

General and administrative costs for the 2011 period included $8.5 million for settlement of the Eagle litigation and $4.5 million for legal, accounting and professional fees incurred in connection with the evaluation of possible strategic transactions. The 2010 period included costs for the settlement of a separate legal matter for $2.4 million,

Crestwood Transaction professional and legal fees of $2.6 million and $5.0 million of KGS general and administrative expense arising prior to the Crestwood Transaction.

Earnings of BBEP

We record our portion of BBEP’s earnings during the quarter in which its financial statements become publicly available. As a result, our 2011 period and 2010 period results of operations include BBEP’s earnings for the nine months ended June 30, 2011 and 2010, respectively.

We recognized a $32.7 million loss and income of $24.2 million for equity earnings from our investment in BBEP for the 2011 period and 2010 period, respectively. BBEP continues to experience significant volatility in its net earnings primarily due to changes in the value of its derivative instruments for which it does not employ hedge accounting.

Other Income

We recognized gains of $133.2 million in the 2011 period from the sale of 7.7 million BBEP Units. In the 2010 period, we recognized $35.4 million and $14.4 million, respectively, from the conveyance of 3.6 million BBEP Units as consideration in the acquisition of additional working interests in the Lake Arlington properties and the sale of 1.4 million BBEP Units. In the 2010 period, we also finalized a settlement of our litigation with BBEP and received $18.0 million from BBEP and another third party.

Interest Expense


	Nine Months Ended
	September 30,
	2011			2010
	(In thousands)
Interest costs on debt outstanding	$	130,153		$	132,895
Add:
Fees paid on letters of credit outstanding		1,374			108
Premium paid — senior notes repurchased		2,560			-
Non-cash interest ⁽¹⁾		13,109			13,372
Interest capitalized		(5,073	)		(4,204	)

Interest expense	$	142,123		$	142,171

⁽¹⁾ Amortization of deferred financing costs, original issue discount net of interest swap settlement amortization.

Interest costs on debt outstanding for the 2011 period were flat when compared to the 2010 period. The 2010 period included recognition of an additional $9.3 million in interest rate swap gains and settlements recognized partially offset by interest expense attributable to KGS of $6.9 million. The $1.3 million increase in fees paid for issuance of letters of credit and $2.6 million loss for the premium paid to repurchase $48.4 million of senior notes at par value were partially offset by decreased interest recognized on lower outstanding debt balances during the 2011 period. The 2011 period also included non-cash interest attributable to the repurchased senior notes and $1.0 million of deferred financing fees attributable to the terminated Senior Secured Credit Facility.

We used proceeds from the U.S. Credit Facility to fund the repurchases which are summarized below:


	Repurchase		Face		Premium on
Instrument	Price		Value		Repurchase
	(In thousands)
Senior notes due 2015	$	38,134	$	37,000	$	1,134
Senior notes due 2016		10,646		9,380		1,266
Senior notes due 2019		2,160		2,000		160

	$	50,940	$	48,380	$	2,560

Income Taxes


	Nine Months Ended
	September 30,
	2011			2010
Income tax expense (in thousands)	$	39,946		$	71,569
Effective tax rate		37.5	%		35.9	%

Our income tax provision for the 2011 period decreased from the income tax provision recognized for the 2010 period, primarily as a result of the decrease in pretax earnings. The effective tax rate for the 2011 period reflects a projection of a full year of Canadian taxable loss partially offset by projection of a full year of U.S. taxable income. The increase in the projected 2011 effective income tax rate resulted from the lower applicable tax rate applied to our Canadian taxable loss and U.S. taxable income taxed at a higher U.S. effective tax rate. The increase in the tax rate from the quarter ended June 30, 2011 to the quarter ended September 30, 2011 is most significantly related to U.S. tax effect of the gains associated with the sale of BBEP Units and unrealized derivative gains included in other revenue. We project an effective tax rate for all of 2011 to be 37.5%, based upon our projection of pretax income and estimated permanent differences for 2011.

Quicksilver Resources Inc. and its Restricted Subsidiaries

Information about Quicksilver and our restricted and unrestricted subsidiaries is included in Note 11 to our condensed consolidated financial statements included in Item 1 of this Quarterly Report.

The combined results of operations for Quicksilver and our restricted subsidiaries are substantially similar to our consolidated results of operations, which are discussed above under “Results of Operations.” The combined financial position of Quicksilver and our restricted subsidiaries and our consolidated financial position are the same. The combined operating cash flows, financing cash flows and investing cash flows for Quicksilver and our restricted subsidiaries are substantially similar to our consolidated operating cash flows, financing cash flows and investing cash flows, which are discussed below in “Liquidity, Capital Resources and Financial Position.”

LIQUIDITY, CAPITAL RESOURCES AND FINANCIAL POSITION

Cash Flow Activity

Our financial condition and results of operations, including our liquidity and profitability, are significantly affected by the prices that we realize for our natural gas, NGL and oil production and the volumes of natural gas, NGL and oil that we produce.

The natural gas, NGLs and oil that we produce are commodity products for which established trading markets exist. Accordingly, product pricing is generally influenced by the relationship between supply and demand for these products. Product supply is affected primarily by fluctuations in production volumes, and product demand is affected by the state of the economy in general, the availability and price of alternative fuels and a variety of other factors. Prices for our products historically have been volatile, and we have no meaningful influence over the timing and extent of price changes for our products. Although we have mitigated our near-term exposure to such price declines through derivative financial instruments covering substantial portions of our expected near-term production, we cannot confidently predict whether or when market prices for natural gas, NGL and oil will increase or decrease.

The volumes that we produce may be significantly affected by the rates at which we acquire leaseholds and other mineral interests and explore, exploit and develop our leasehold and other mineral interests through drilling and production activities. These activities require substantial capital expenditures, and our ability to fund these activities through cash flow from our operations, borrowings and other sources may be affected by instability in the capital markets.

For the remainder of 2011 through 2021, price collars and swaps cover a portion of our natural gas and NGL revenue. The following summarizes future production hedged with commodity derivatives as of September 30, 2011:


Production	Daily Production
Year	Gas	NGL
	MMcfd	MBbld
2011	190	10.5
2012	165	6.0
2013	105	-
2014-2015	65	-
2016-2021	35	-

The following summarizes our cash flow activity for the 2011 period and 2010 period:


	Nine Months Ended
	September 30,
	2011			2010
	(In thousands)
Net cash provided by operating activities	$	174,666		$	347,390
Net cash used by investing activities		(401,436	)		(470,810	)
Net cash provided by financing activities		178,549			137,077

Operating Cash Flows

Net cash provided by operations for the 2011 period decreased from the 2010 period, primarily due to higher net payments to KGS for GPT costs of $67.5 million partially offset by a $16.8 million increase in production revenue, including hedge settlements, and $1.6 million in additional BBEP distributions in the 2011 period. In addition, the 2010 period included nonrecurring cash transactions for income tax refunds, settlement of litigation and interest rate swap settlements totaling $87.8 million.

Investing Cash Flows

During the 2011 period, we sold 7.7 million BBEP Units for an average price of $18.99 or total proceeds of $145.8 million that was used to repurchase $48.4 million of our senior notes and repay borrowings outstanding under our Senior Secured Credit Facility.

Our costs incurred for property, plant and equipment for the 2011 period and 2010 period were as follows:


	United States			Canada		Consolidated
			(In thousands)
For the Nine Months Ended September 30, 2011
Exploration and development	$	377,310		$	84,778	$	462,088
Gathering and processing		8,017			49,331		57,348
Administrative		5,178			685		5,863

Total	$	390,505		$	134,794	$	525,299


For the Nine Months Ended September 30, 2010
Exploration and development	$	422,415		$	45,587	$	468,002
Gathering and processing ⁽¹⁾		49,160			9,245		58,405
Administrative		5,569			443		6,012

Total	$	477,144		$	55,275	$	532,419

⁽¹⁾ Includes KGS’ capital expenditures in the amount of $48.5 million arising prior to its sale in 2010.

Our 2011 period consolidated capital costs incurred were comparable to the 2010 period, but our Canadian capital costs incurred increased $79.7 million and our U.S. costs incurred decreased $86.8 million. Our capital expenditures for gathering and processing during the 2011 period include construction of infrastructure to gather, compress and deliver our Horn River gas production to third-party processing facilities. Our Canadian exploration and development costs for the 2011 period reflect a higher level of drilling and completion activities.

Financing Cash Flows

Net financing cash flows in the 2011 period included $48.4 million of purchases and retirement of our senior notes, net borrowings of $241.3 million under the U.S. Credit Facility and Canadian Credit Facility and activity for our stock compensation plan. Financing cash flows in the 2010 period included net borrowings of $57.1 million under our Senior Secured Credit Facility and $113.1 million under the KGS’ credit facility. The 2010 period also included repayments of $25.9 million under the Gas Purchase Commitment partially offset by proceeds of $11.1 million received from the KGS Secondary Offering.

Liquidity and Borrowing Capacity

In September 2011 we terminated and replaced our $1.0 billion global Senior Secured Credit Facility with new five-year separate syndicated senior secured revolving credit facilities for our U.S. and Canadian operations. “2011 Highlights” contains additional information about the changes to our debt.

Our ability to remain in compliance with the financial covenants in our credit facilities may be affected by events beyond our control, including market prices for our products. Any future inability to comply with these covenants, unless waived by the requisite lenders, could adversely affect our liquidity by rendering us unable to borrow further under our credit facilities and by accelerating the maturity of our indebtedness.

Additional information about our senior note repurchases and our repurchase of our convertible debentures can be found in Note 6 to the condensed consolidated financial statements. Additional information about our debt and related covenants are more fully described in Note 6 to the condensed consolidated financial statements in Item 1 of this Quarterly Report.

We believe that our capital resources are adequate to meet the requirements of our existing business. We continue to anticipate that our 2011 capital expenditure program will be substantially funded by cash flow from operations, utilization of our U.S. Credit Facility and Canadian Credit Facility and asset sales.

Depending upon conditions in the capital markets and other factors, we will from time to time consider the issuance of debt or other securities, other possible capital markets transactions or the sale of assets, the proceeds of which could be used to refinance current indebtedness or for other corporate purposes. We will also consider from time to time additional acquisitions of, and investments in, assets or businesses that complement our existing asset portfolio. Acquisition transactions, if any, are expected to be financed through cash on hand and from operations, bank borrowings, the issuance of debt or other securities, the sale of assets or a combination of those sources.

Financial Position

The following impacted our balance sheet as of September 30, 2011, as compared to our balance sheet as of December 31, 2010:

	•		Our net property, plant and equipment balance increased $282.3 million from December 31, 2010 to September 30, 2011. We incurred capital expenditures of $525.3 million during the 2011 period and also recognized assets for retirement obligations established for new wells and facilities. DD&A and impairment expense and changes to U.S.-Canadian exchange rates reduced our property, plant and equipment balances $211.9 million and $32.3 million, respectively.

	•		The valuation of our current and non-current derivative assets and liabilities was $59.4 million higher on a net basis at September 30, 2011 as compared to December 31, 2010. The increase was primarily the result of recognized unrealized gains of $48.9 million associated with our 10-year natural gas price swaps prior to their designation as hedges and deferred unrealized gains of $66.0 million recognized in OCI partially offset by settlements received of $57.1 million.

	•		Our investment in BBEP Units decreased $61.6 million during the 2011 period. In addition to recognizing $32.7 million in net losses from the earnings of BBEP, we received $16.3 million in dividends from BBEP and retired $12.6 million of our investment balance in connection with the sale of 7.7 million BBEP Units.

	•		The $54.6 million decrease in accounts payable was primarily due to Texas ad valorem taxes of $17.4 million included in accounts payable as of December 31, 2010, a $25.4 million reduction in payable and accrued capital expenditures and a reduction in operating expenses payable and accrued from December 31, 2010.

	•		Long-term debt increased $241.3 million for net borrowings under our credit facilities. We partially offset these borrowings with the repurchase of $48.4 million of our senior notes due 2015, 2016 and 2019 and recognition of a portion of the gains deferred from our 2010-settled interest rate swap derivatives.

Contractual Obligations and Commercial Commitments

There have been no significant changes to our contractual obligations and commitments as reported in our 2010 Annual Report except for contracts we entered into with NGTL in April 2011, and the two drilling rig contracts we entered into in July 2011, each with a term of one year and aggregate commitments of $12.0 million. Note 8 to the condensed consolidated financial statements found in Item 1 of this Quarterly Report contains additional information about our NGTL contracts and drilling rig contracts.

Critical Accounting Estimates

Management’s discussion and analysis of financial condition and results of operations are based on our condensed consolidated interim financial statements and related footnotes contained within this report. The process of preparing financial statements in conformity with GAAP requires the use of estimates and assumptions to determine certain of the assets, liabilities, revenue and expense. Our more critical accounting estimates used in the preparation of the consolidated financial statements were discussed in our 2010 Annual Report on Form 10-K. These critical estimates, for which no significant changes occurred during the nine months ended September 30, 2011, include estimates and assumptions for:


• oil and gas reserves		• stock-based compensation
• full cost ceiling calculations		• income taxes
• derivative instruments

These estimates and assumptions are based upon what we believe is the best information available at the time we make the estimate or assumption. The estimates and assumptions could change materially as conditions within and beyond our control change. Accordingly, actual results could differ materially from those estimates and assumptions.

OFF-BALANCE SHEET ARRANGEMENTS

Our contracts with NGTL provide financial assurances to it during the construction phase of the NGTL Project, which is expected to continue through 2014. Assuming the project is fully constructed at estimated costs of C$257.4 million, we expect to provide letters of credit through 2014. Note 8 to the condensed consolidated financial statements found in Item 1 of this Quarterly Report contains additional information about our contracts with NGTL.

RECENTLY ISSUED ACCOUNTING STANDARDS

No pronouncements materially affecting our financial statements have been issued since the filing of our 2010 Annual Report on Form 10-K.

ITEM 3. Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

We have internal control policies and procedures for managing commodity price and interest rate risk within our organization. The possibility of decreasing prices received for our production is among the several risks that we face. We seek to manage this risk by entering into derivative contracts which we strive to treat as financial hedges. We have mitigated the downside risk of adverse price movements through the use of derivatives but, in doing so, we have also limited our ability to benefit from favorable price movements. This commodity price strategy enhances our ability to execute our development, exploitation and exploration programs, meet debt service requirements and pursue acquisition opportunities even in periods of price volatility or depression.

We enter into financial derivative contracts to mitigate our exposure to commodity price risk associated with anticipated future production and to increase the predictability of our revenue. Utilization of our financial hedging program will most often result in realized prices from the sale of our natural gas, and NGLs that vary from market

The following table details our open derivative positions at September 30, 2011:

Weighted Avg

Production

Remaining Contract

Price Per Mcf

Fair Value

Product

Type

Hedged

Period

Volume

or Bbl

Total

(In thousands)

Gas

Collar

Canada

Oct 2011-Dec 2011

10 MMcfd

6.00- 7.00

2,028

Gas

Collar

Canada

Oct 2011-Dec 2011

10 MMcfd

6.00- 7.00

2,028

Gas

Collar

Canada

Oct 2011-Dec 2011

20 MMcfd

6.00- 7.00

4,055

Gas

Collar

U.S.

Oct 2011-Dec 2011

10 MMcfd

6.25- 7.50

2,256

Gas

Collar

U.S.

Oct 2011-Dec 2011

10 MMcfd

6.25- 7.50

2,256

Gas

Collar

U.S.

Oct 2011-Dec 2011

20 MMcfd

6.25- 7.50

4,513

Gas

Collar

U.S.

Oct 2011-Dec 2012

20 MMcfd

6.50- 7.15

21,575

Gas

Collar

U.S.

Oct 2011-Dec 2012

20 MMcfd

6.50- 7.18

21,665

Gas

Collar

U.S.

Jan 2012-Dec 2012

20 MMcfd

6.50- 8.01

16,626

Gas

Basis

Canada

Oct 2011-Dec 2011

10 MMcfd

)

(117

)

Gas

Basis

Canada

Oct 2011-Dec 2011

10 MMcfd

)

(117

)

Gas

Basis

Canada

Oct 2011-Dec 2011

20 MMcfd

)

(235

)

Gas

Swap

Canada

Oct 2011-Dec 2013

10 MMcfd

5.00

4,587

Gas

Swap

Canada

Jan 2012-Dec 2021

5 MMcfd

6.20

9,422

Gas

Swap

Canada

Jan 2012-Dec 2021

5 MMcfd

6.20

9,422

Gas

Swap

Canada

Jan 2012-Dec 2021

10 MMcfd

6.22

19,505

Gas

Swap

U.S.

Oct 2011-Dec 2013

10 MMcfd

5.00

4,587

Gas

Swap

U.S.

Oct 2011-Dec 2013

10 MMcfd

5.00

4,587

Gas

Swap

U.S.

Oct 2011-Dec 2013

10 MMcfd

5.00

4,587

Gas

Swap

U.S.

Oct 2011-Dec 2015

10 MMcfd

6.00

17,985

Gas

Swap

U.S.

Oct 2011-Dec 2015

20 MMcfd

6.00

35,970

Gas

Swap

U.S.

Jan 2012-Dec 2021

5 MMcfd

6.20

9,422

Gas

Swap

U.S.

Jan 2012-Dec 2021

5 MMcfd

6.20

9,422

Gas

Swap

U.S.

Jan 2012-Dec 2021

5 MMcfd

6.23

9,918

NGL

Swap

U.S.

Oct 2011-Dec 2011

3 MBbld

36.06

(4,117

)

NGL

Swap

U.S.

Oct 2011-Dec 2011

2 MBbld

36.31

(2,699

)

NGL

Swap

U.S.

Oct 2011-Dec 2011

1 MBbld

40.50

(965

)

NGL

Swap

U.S.

Oct 2011-Dec 2011

1.5 MBbld

40.42

(1,457

)

NGL

Swap

U.S.

Oct 2011-Dec 2011

3 MBbld

41.95

(2,491

)

NGL

Swap

U.S.

Jan 2012-Dec 2012

1 MBbld

42.81

(371

)

NGL

Swap

U.S.

Jan 2012-Dec 2012

1 MBbld

43.07

(277

)

NGL

Swap

U.S.

Jan 2012-Dec 2012

2 MBbld

43.94

NGL

Swap

U.S.

Jan 2012-Dec 2012

1 MBbld

46.55

997

NGL

Swap

U.S.

Jan 2012-Dec 2012

1 MBbld

47.99

1,522

Total

206,173

⁽¹⁾ Basis swaps hedge the AECO basis adjustment at a deduction of $0.39 per Mcf from NYMEX for 2011.

The fair value of all derivative instruments included in these disclosures was estimated using prices quoted in active markets for the periods covered by the derivatives and the value confirmed by counterparties. Estimates were determined by applying the net differential between the prices in each derivative and market prices for future periods to the amounts 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.

Interest Rate Risk

In 2010, we executed early settlements of our interest rate swaps that were designated as fair value hedges of our senior notes due 2015 and our senior subordinated notes. We deferred gains of $30.8 million as a fair value adjustment

to our debt, which we began to recognize over the life of the associated debt instruments. During the 2011 period and 2010 period, we recognized $3.6 million and $2.0 million of those deferred gains, respectively. Additionally, we recognized $10.8 million received from periodic settlements in the 2010 period as reductions of interest expense.

Foreign Currency Risk

Our Canadian subsidiary uses the Canadian dollar as its functional currency. To the extent that business transactions in Canada are not denominated in Canadian dollars, we are exposed to foreign currency exchange rate risk. Non-functional currency transactions for the 2011 period and the 2010 period resulted in gains of $2.7 million and losses of $0.8 million, respectively, and were included in other income. Furthermore, the Canadian Credit Facility permits Canadian borrowings to be made in either U.S. or Canadian-denominated amounts. Accordingly, there is a risk that exchange rate movements could impact our available borrowing capacity.

ITEM 4. Controls and Procedures

Conclusions 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 September 30, 2011, 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 period ended September 30, 2011 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

On September 26, 2011, we entered into a global settlement agreement with Eagle Drilling, LLC (“Eagle”). During the 2011 quarter, we recognized a charge of $8.5 million and funded our entire obligation under this settlement. Pursuant to this agreement, the Eagle cases filed in Oklahoma and Houston were dismissed.

Other than the above disclosure and the change described in Part II, Item 1 included in our Quarterly Report on Form 10-Q filed on August 9, 2011, there have been no material changes in the legal proceedings described in Part I, Item 3 included in our 2010 Annual Report on Form 10-K.

ITEM 1A. Risk Factors

There have been no material changes in the risk factors described in Part I, Item 1A included in our 2010 Annual Report on Form 10-K other than the change described in Part II, Item 1A included in our Quarterly Report on Form 10-Q filed on May 9, 2011 and the risk factor provided below:

We are subject to environmental laws, regulations and permits, including greenhouse gas requirements that may expose us to significant costs, liabilities and obligations.

We are subject to stringent and complex U.S. and Canadian federal, state, provincial and local environmental laws, regulations and permits and international environmental conventions, relating to, among other things, the generation, storage, handling, use, disposal, gathering, movement and remediation of natural gas, NGLs, oil and other hazardous materials; the emission and discharge of such materials to the ground, air and water; wildlife protection; the storage, use and treatment of water; the placement, operation and reclamation of wells; and the health and safety of our employees. Failure to comply with these environmental requirements may result in our being subject to litigation, fines

or other sanctions, including the revocation of permits and suspension of operations. We expect to continue to incur significant capital and other compliance costs related to such requirements.

We could be liable for any environmental contamination at our or our predecessors’ currently or formerly owned or operated properties or third-party waste disposal sites. Certain environmental laws, including CERCLA, more commonly known as Superfund, impose joint and several strict liability for releases of hazardous substances at such properties or sites, without regard to fault or the legality of the original conduct. In addition to potentially significant investigation and remediation costs, such matters can give rise to claims from governmental authorities and other third parties for fines or penalties, natural resource damages, personal injury and property damage. Regulators are also becoming increasingly focused on air emissions from our industry, including volatile organic compound emissions. This increased scrutiny could lead to heightened enforcement of existing regulations as well as the imposition of new measures to control our emissions or curtail our operations.

These laws, regulations and permits, and the enforcement and interpretation thereof, change frequently and generally have become more stringent over time. For example, GHG emission regulation is becoming more stringent. We are currently required to report annual GHG emissions from certain of our operations, and additional GHG emission related requirements have been implemented or are in various stages of development. The EPA has begun regulating GHG emissions from stationary sources pursuant to the federal Clean Air Act, as a result of which we might be required to obtain permits to construct, modify or operate facilities on account of, and implement emission control measures for, our GHG emissions. Also, regulatory authorities are considering, or have developed, energy or emission measures to reduce GHG emissions for oil and gas operations. Any limitation of, or further regulation of, GHG emissions, including through a cap-and-trade system, technology mandate, emissions tax, reporting requirement or other program, could adversely affect our business, financial condition, reputation, operating performance and product demand. In addition, to the extent climate change results in warmer temperatures or more severe weather, our or our customers’ operations may be disrupted, which could curtail our exploration and production activity, increase operating costs and reduce product demand.

In addition, various U.S. federal and state initiatives have been implemented, or are under development to regulate or further investigate the environmental impacts of hydraulic fracturing, a practice that involves the pressurized injection of water, chemicals and other substances into rock formations to stimulate hydrocarbon production. In particular, the EPA has commenced a study to determine the environmental and health impacts of hydraulic fracturing and announced that it will propose standards for the treatment or disposal of fracturing fluids. In addition, certain states in which we operate, including Colorado, Montana, Texas and Wyoming, have adopted, or are considering adopting, regulations that have imposed, or could impose, more stringent permitting, transparency, disposal and well construction requirements on hydraulic fracturing operations. For example, Texas adopted a new law that requires disclosure of information regarding the substances used in the hydraulic fracturing process to the Railroad Commission of Texas and the public. Such disclosure may result in increased scrutiny or third-party claims, or otherwise result in operational delays, liabilities and increased costs.

Our costs, liabilities and obligations relating to environmental matters could have a material adverse effect on our business, reputation, results of operations and financial condition.

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 September 30, 2011:


					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⁾
July 2011		2,088	$	14.38		-		-
August 2011		154		10.27		-		-
September 2011		891		9.19		-		-

Total		3,133	$	12.70		-		-

	⁽¹⁾		Represents shares of common stock surrendered by employees to satisfy income tax withholding obligations arising upon the vesting of restricted stock issued under our Amended and Restated 2006 Equity Plan.

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

We have not paid cash dividends on our common stock and intend to retain our cash flows from operations for future operations and development of our business. In addition, we have debt agreements that restrict the payment of dividends.

ITEM 3. Defaults Upon Senior Securities

None.

ITEM 4. [Removed and Reserved]

ITEM 5. Other Information

None.

ITEM 6. Exhibits


Exhibit No.		Description
*10.1		Credit Agreement, dated as of September 6, 2011, among Quicksilver Resources Inc. and the agents and lenders identified therein
*10.2		Credit Agreement, dated as of September 6, 2011, among Quicksilver Resources Canada Inc. and the agents and lenders identified therein
* 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
* 101.INS		XBRL Instance Document
* 101.SCH		XBRL Taxonomy Extension Schema Linkbase Document
* 101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document
* 101.LAB		XBRL Taxonomy Extension Labels Linkbase Document
* 101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document
* 101.DEF		XBRL Taxonomy Extension Definition Linkbase Document


*		Filed herewith.

EXHIBIT INDEX


Exhibit No.		Description
*10.1		Credit Agreement, dated as of September 6, 2011, among Quicksilver Resources Inc. and the agents and lenders identified therein
*10.2		Credit Agreement, dated as of September 6, 2011, among Quicksilver Resources Canada Inc. and the agents and lenders identified therein
* 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
* 101.INS		XBRL Instance Document
* 101.SCH		XBRL Taxonomy Extension Schema Linkbase Document
* 101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document
* 101.LAB		XBRL Taxonomy Extension Labels Linkbase Document
* 101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document
* 101.DEF		XBRL Taxonomy Extension Definition Linkbase Document


*		Filed herewith.


PART I. FINANCIAL INFORMATION

Item 1. Condensed Consolidated Interim Financial Statements (Unaudited)			6

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			28

Item 3. Quantitative and Qualitative Disclosures About Market Risk			46

Item 4. Controls and Procedures			49

PART II. OTHER INFORMATION

Item 1. Legal Proceedings			49

Item 1A. Risk Factors			49

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			51

Item 3. Defaults Upon Senior Securities			51

Item 4. [Removed and Reserved]			51

Item 5. Other Information			51

Item 6. Exhibits			51

Signature			52
EX-10.1
EX-10.2
EX-31.1
EX-31.2
EX-32.1
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT


	Quicksilver Resources Inc.
	By:	/s/ Philip Cook
	Philip Cook
	Senior Vice President - Chief Financial Officer (Duly Authorized Officer and Principal Financial Officer)