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, 2012
or
¨	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  ¨

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   ¨

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 ¨	Non-accelerated filer ¨	Smaller reporting company ¨
		(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  ¨  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, 2012
Common Stock, $0.01 par value	172,948,474 shares

DEFINITIONS

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

“ABR” means alternate base rate

“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

“Bcfe” means Bcf of natural gas equivalent

“Canada” means our oil and natural gas operations located principally in British Columbia and Alberta, Canada

“C$” means Canadian dollars

“DD&A” means Depletion, Depreciation and Accretion

“GPT” means gathering, processing and transportation expense

“LIBOR” means London Interbank Offered Rate

“MBbl” or “MBbls” means thousand barrels

“MBbld” means MBbl per day

“Mcf” means thousand cubic feet

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

“MMcf” means million cubic feet

“MMcfd” means million cubic feet per day

“MMcfe” means MMcf of natural gas equivalent

“MMcfed” means MMcfe per day

“NGL” or “NGLs” means natural gas liquids

“OCI” means other comprehensive income

“Oil” includes crude oil and condensate

“RSU” means restricted stock unit

COMMONLY USED TERMS

Other commonly used terms and abbreviations include:

“2007 Senior Secured Credit Facility” means collectively our U.S. senior secured revolving credit facility and our Canadian senior secured revolving credit facility, each dated as of February 9, 2007, which were terminated September 6, 2011 and replaced at that time by the Initial U.S. Credit Facility and the Initial Canadian Credit Facility

“Amended and Restated Canadian Credit Facility” means our new Canadian senior secured revolving credit facility which was amended and restated, effective December 22, 2011

“Amended and Restated U.S. Credit Facility” means our new U.S. senior secured revolving credit facility which was amended and restated, effective December 22, 2011

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

“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

“CMLP” means Crestwood Midstream Partners LP

“Combined Credit Agreements” means collectively our Amended and Restated U.S. Credit Facility and our Amended and Restated Canadian Credit Facility

“Crestwood” means Crestwood Holdings LLC

“Crestwood Transaction” means the sale to Crestwood of all our interests in KGS, including general partner interests and incentive distribution rights

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

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

“Fortune Creek” means Fortune Creek Gathering and Processing Partnership, a midstream partnership formed December 2011 with KKR for the construction and operation of assets to provide natural gas midstream services within the Horn River, Liard and Cordova basins of British Columbia, Canada

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

“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

“Initial Canadian Credit Facility” means our initial Canadian senior secured revolving credit facility, dated as of

2

September 6, 2011, which was amended and restated by the Amended and Restated Canadian Credit Facility on December 22, 2011

“Initial U.S. Credit Facility” means our initial U.S. senior secured revolving credit facility, dated as of September 6, 2011, which was amended and restated by the Amended and Restated U.S. Credit Facility on December 22, 2011

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

“KKR” means Kohlberg Kravis Roberts & Co. L.P. with whom we formed Fortune Creek

“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 and others’ operations in the Horn River basin

“Sand Wash Asset” means our operations and our assets in the Sand Wash basin located in Colorado and southern Wyoming

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

“VIE” means variable interest entity

“West Texas Asset” means our operations and our assets in the Midland and Delaware basins in West Texas prospective in the Bone Springs and Wolfcamp formations, principally concentrated in three areas: Jeff Davis and Reeves Counties, Upton and Crockett Counties, and Pecos County

3

INDEX TO QUARTERLY REPORT ON FORM 10-Q

For the Quarter Ended September 30, 2012

PART I. FINANCIAL INFORMATION	6
Item 1. Condensed Consolidated Interim Financial Statements (Unaudited)	6
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	29
Item 3. Quantitative and Qualitative Disclosures About Market Risk	48
Item 4. Controls and Procedures	50
PART II. OTHER INFORMATION	51
Item 1. Legal Proceedings	51
Item 1A. Risk Factors	51
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	51
Item 3. Defaults Upon Senior Securities	51
Item 4. Mine Safety Disclosures	51
Item 5. Other Information	51
Item 6. Exhibits	53
Signature	54

Except as otherwise specified and unless the context otherwise requires, references to the “Company,” “Quicksilver,” “we,” “us,” and “our” refer to Quicksilver Resources Inc. and its subsidiaries.

4

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, processing and treating facilities;

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

• the effects of existing and future laws and governmental regulations, including environmental and climate change requirements;

• failure or delay in completing strategic transactions;

• the effects of existing or future litigation;

• failure or delays in completing Quicksilver’s proposed initial public offering of common units representing limited partner interests in a master limited partnership holding portions of our Barnett Shale Asset; and

• additional factors described 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.

5

PART I    FINANCIAL INFORMATION

ITEM 1. Condensed Consolidated Interim Financial Statements (Unaudited)

QUICKSILVER RESOURCES INC.

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)

In thousands, except for per share data – Unaudited

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2012			2011			2012			2011
Revenue
Production	$	157,699		$	208,064		$	480,021		$	606,070
Sales of purchased natural gas	21,313			20,130			42,842			60,116
Other	(1,310		)	31,699			(31,130		)	54,340
Total revenue	177,702			259,893			491,733			720,526
Operating expense
Lease operating	22,115			27,673			72,405			73,366
Gathering, processing and transportation	41,338			51,113			127,040			142,201
Production and ad valorem taxes	6,881			7,757			20,833			23,844
Costs of purchased natural gas	21,254			19,954			42,528			59,254
Depletion, depreciation and accretion	43,209			57,686			149,590			164,861
Impairment	546,835			—			1,601,502			49,063
General and administrative	17,335			27,584			54,836			61,745
Other operating	670			145			820			328
Total expense	699,637			191,912			2,069,554			574,662
Crestwood earn-out	—			—			41,097			—
Operating income (loss)	(521,935		)	67,981			(1,536,724		)	145,864
Income (loss) from earnings of BBEP	—			14,370			—			(32,721		)
Other income - net	(395		)	11,142			(237		)	135,441
Fortune Creek accretion	(4,978		)	—			(14,549		)	—
Interest expense	(42,102		)	(48,393		)	(122,348		)	(142,123		)
Income (loss) before income taxes	(569,410		)	45,100			(1,673,858		)	106,461
Income tax (expense) benefit	(82,352		)	(16,414		)	289,631			(39,946		)
Net income (loss)	$	(651,762	)	$	28,686		$	(1,384,227	)	$	66,515
Reclassification adjustments related to settlements of derivative contracts - net of income tax	(35,182		)	(11,869		)	(104,849		)	(38,886		)
Net change in derivative fair value - net of income tax	(51,057		)	51,221			60,951			44,508
Foreign currency translation adjustment	4,901			(35,550		)	4,231			(25,118		)
Other comprehensive income (loss)	(81,338		)	3,802			(39,667		)	(19,496		)
Comprehensive income (loss)	$	(733,100	)	$	32,488		$	(1,423,894	)	$	47,019
Earnings (loss) per common share - basic	$	(3.83	)	$	0.17		$	(8.14	)	$	0.39
Earnings (loss) per common share - diluted	$	(3.83	)	$	0.17		$	(8.14	)	$	0.39

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

6

QUICKSILVER RESOURCES INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

In thousands, except for share data – Unaudited

	September 30, 2012			December 31, 2011
ASSETS
Current assets
Cash	$	7,436		$	13,146
Accounts receivable - net of allowance for doubtful accounts	67,951			95,282
Derivative assets at fair value	126,075			162,845
Other current assets	41,575			29,154
Total current assets	243,037			300,427
Property, plant and equipment - net
Oil and gas properties, full cost method (including unevaluated costs of $439,767 and $433,341, respectively)	1,846,028			3,226,476
Other property and equipment	248,021			234,043
Property, plant and equipment - net	2,094,049			3,460,519
Derivative assets at fair value	109,313			183,982
Other assets	43,845			50,534
	$	2,490,244		$	3,995,462
LIABILITIES AND EQUITY
Current liabilities
Current portion of long-term debt	$	—		$	18
Accounts payable	48,143			142,672
Accrued liabilities	123,661			142,193
Derivative liabilities at fair value	—			4,028
Current deferred tax liability	3,243			45,262
Total current liabilities	175,047			334,173
Long-term debt	2,165,384			1,903,431
Partnership liability	135,446			122,913
Asset retirement obligations	97,771			85,568
Derivative liabilities at fair value	42,538			—
Other liabilities	19,242			28,461
Deferred income taxes	1,518			258,997
Commitments and contingencies (Note 9)
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 178,770,278 and 176,980,483 shares issued, respectively	1,788			1,770
Paid in capital in excess of par value	755,080			737,015
Treasury stock of 5,816,293 and 5,379,702 shares, respectively	(49,161		)	(46,351		)
Accumulated other comprehensive income	175,191			214,858
Retained earnings (deficit)	(1,029,600		)	354,627
Total stockholders' equity	(146,702		)	1,261,919
	$	2,490,244		$	3,995,462

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

7

QUICKSILVER RESOURCES INC.

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY

In thousands – Unaudited

	Quicksilver Resources Inc. Stockholders’ Equity
	Common Stock		Additional Paid-in Capital		Treasury Stock			Accumulated Other Comprehensive Income			Retained Earnings (Deficit)			Total
Balances at December 31, 2010	$	1,755	$	714,869	$	(41,487	)	$	130,187		$	264,581		$	1,069,905
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
Foreign currency translation adjustment	—		—		—			(25,118		)	—			(25,118		)
Issuance and vesting of stock compensation	13		15,462		(4,841		)	—			—			10,634
Stock option exercises	1		732		—			—			—			733
Balances at September 30, 2011, restated (a)	$	1,769	$	731,063	$	(46,328	)	$	110,691		$	331,096		$	1,128,291
Balances at December 31, 2011	$	1,770	$	737,015	$	(46,351	)	$	214,858		$	354,627		$	1,261,919
Net loss	—		—		—			—			(1,384,227		)	(1,384,227		)
Hedge derivative contract settlements reclassified into earnings from AOCI, net of income tax of $53,756	—		—		—			(104,849		)	—			(104,849		)
Net change in derivative fair value, net of income tax of $29,704	—		—		—			60,951			—			60,951
Foreign currency translation adjustment	—		—		—			4,231			—			4,231
Issuance and vesting of stock compensation	17		18,055		(2,810		)	—			—			15,262
Stock option exercises	1		10		—			—			—			11
Balances at September 30, 2012	$	1,788	$	755,080	$	(49,161	)	$	175,191		$	(1,029,600	)	$	(146,702	)

(a) Note 1 contains additional information.

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

8

QUICKSILVER RESOURCES INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

In thousands – Unaudited

	For the Nine Months Ended September 30,
	2012			2011
Operating activities:
Net income (loss)	$	(1,384,227	)	$	66,515
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation and accretion	149,590			164,861
Impairment expense	1,601,502			49,063
Crestwood earn-out	(41,097		)	—
Deferred income tax expense (benefit)	(285,204		)	50,960
Non-cash (gain) loss from hedging and derivative activities	82,252			(50,550		)
Stock-based compensation	16,983			15,475
Non-cash interest expense	8,060			13,109
Fortune Creek accretion	14,549			—
Gain on disposition of BBEP Units	—			(133,248		)
Loss from BBEP in excess of cash distributions	—			49,065
Other	495			(897		)
Changes in assets and liabilities
Accounts receivable	27,259			2,101
Prepaid expenses and other assets	(4,503		)	(20,791		)
Accounts payable	(24,329		)	(29,430		)
Accrued and other liabilities	(19,954		)	(1,567		)
Net cash provided by operating activities	141,376			174,666
Investing activities:
Purchases of property, plant and equipment	(437,172		)	(550,954		)
Proceeds from Crestwood earn-out	41,097			—
Proceeds from sale of BBEP Units	—			145,799
Proceeds from sale of properties and equipment	3,843			3,719
Net cash used by investing activities	(392,232		)	(401,436		)
Financing activities:
Issuance of debt	367,646			648,819
Repayments of debt	(111,115		)	(455,886		)
Debt issuance costs paid	(3,048		)	(10,276		)
Distribution of Fortune Creek Partnership funds	(6,520		)	—
Proceeds from exercise of stock options	11			733
Excess tax deductions on stock compensation	1,089			—
Purchase of treasury stock	(2,810		)	(4,841		)
Net cash provided by financing activities	245,253			178,549
Effect of exchange rate changes in cash	(107		)	(114		)
Net increase (decrease) in cash	(5,710		)	(48,335		)
Cash at beginning of period	13,146			54,937
Cash at end of period	$	7,436		$	6,602

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

9

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 management’s opinion, the accompanying condensed consolidated interim financial statements contain all adjustments necessary to fairly present our financial position as of September 30, 2012 and our results of operations and cash flows for the periods presented. 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 us 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. We believe our 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 2011 Annual Report on Form 10-K.

Immaterial Restatement

The consolidated financial statements as of and for the year ended December 31, 2010 were restated as disclosed within Item 8, Note 2 in the 2011 Annual Report on Form 10-K to increase the previously recognized gain related to the sale of our interests in KGS by $20.7 million and to provide additional deferred taxes on the increased gain. The previously reported gain excluded certain liabilities for intercompany transactions related to services performed by KGS for our U.S. exploration and production segment, which should have been included in the gain calculation. Additional depletion expense was recognized due to the inclusion of additional future development costs in the 2010 depletion calculation. The results of this restatement, which had no impact on our total cash flow from operations, investing and financing activities as reported, impacted the retained earnings and the total stockholder’s equity as of September 30, 2011. Previously, retained earnings and total stockholder’s equity were reported as $320.6 million and $1,118 million, respectively, in the Form 10-Q for the quarter ended September 30, 2011. These balances have been restated to $331.1 million and $1,128 million, respectively, within the Condensed Consolidated Statement of Equity as of September 30, 2011.

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.

In June 2011, the FASB issued an amendment to accounting guidance to update the presentation of comprehensive income in consolidated financial statements. Under the amended guidance, the presentation of total comprehensive income, the components of net income, and the components of other comprehensive income may be made either in a single continuous statement of comprehensive income or in two separate but consecutive statements. This guidance became effective for us beginning with the quarter ended March 31, 2012, and required retrospective application to earlier periods presented. Our condensed consolidated statements of income (loss) and comprehensive income (loss) for the three and nine months ended September 30, 2012 and 2011 contain the required disclosures. The implementation of this accounting pronouncement also resulted in increased disclosure which is contained in Note 13.

In May 2011, the FASB issued an amendment to the accounting guidance for fair value measurement and disclosure. Among other things, the guidance expands the disclosure requirements around fair value measurements categorized in Level 3 of the fair value hierarchy and requires disclosure of the level in the fair value hierarchy of items that are not measured at fair value in the statement of financial position but whose fair value must be disclosed. It also clarifies and expands upon existing requirements for measurement of the fair value of financial assets and liabilities as well as instruments classified in stockholders’ equity. This guidance became effective for us beginning with the quarter ended March 31, 2012. The adoption of this accounting pronouncement did not have an effect on the fair value measurement, but rather expanded upon existing disclosures.

In December 2011, the FASB issued an amendment to the accounting guidance for disclosure of arrangements that permit offsetting assets and liabilities. The amendment expands the disclosure requirements to require both gross information and net information about both instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to a master netting arrangement. The amendment will be effective for us, beginning on January 1, 2013, and must be applied retrospectively. We do not expect the adoption of this accounting pronouncement to have a material impact on our financial statements when implemented.

10

No other pronouncements materially affecting our financial statements have been issued since the filing of our 2011 Annual Report on Form 10-K.

2. CRESTWOOD EARN-OUT

In October 2010, we completed the sale of all of our interests in KGS to Crestwood. As part of the sale, we have the right to collect future earn-out payments through 2013. In February 2012, we collected $41 million of these earn-out payments which is presented as “Crestwood earn-out” in the condensed consolidated statement of income. We have the right to collect up to an additional $31 million in future earn-out payments in 2013, but do not anticipate receiving any additional payment and have recognized no assets related to these opportunities.

Note 3 to the consolidated financial statements in our 2011 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, 2012		December 31, 2011		September 30, 2012		December 31, 2011
	(in thousands)				(in thousands)
Level 2 inputs	$	209,477	$	195,838	$	3,001	$	4,028
Level 3 inputs	25,911		150,989		39,537		—
Total	$	235,388	$	346,827	$	42,538	$	4,028

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 natural gas derivatives with an original tenure of 10 years utilize “Level 3” inputs, primarily due to comparatively less market data available for the later portion of their term compared with our other shorter term derivatives. The fair value of both the “Level 2” and the “Level 3” assets and liabilities are determined using a discounted cash flow model using the terms of the derivative instrument, market prices for the periods covered by thederivatives, and the credit adjusted risk-free interest rates. The “Level 3” unobservable inputs are the market prices for the latter half of the 10-year term as there is not an active market for that period of time. These unobservable inputs included within the fair value calculation range from $3.32 to $6.25 and are based upon prices quoted in active markets for the period of time available and applying the differential from this period of time to the market prices for the later years in the term. Changes in the “Level 3” inputs are correlated to the changes in the quoted market prices for the period of time available. Estimates were determined by applying the 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 the credit adjusted risk-free rate.

11

The following table identifies the changes in “Level 3” net asset derivative fair values for the periods indicated:

	For the Three Months Ended September 30,
	2012			2011
	(In thousands)
Balance at beginning of period	$	45,345		$	19,115
Total gains (losses) for the period:
Unrealized gain on commodity hedges	—			29,737
Loss from hedge ineffectiveness	(1,554		)	—
Settlements in Production Revenue	(1,315		)	—
Settlements in Other Revenue	(6,380		)	—
Changes included in Other Revenue	152			—
Unrealized gains (losses) reported in OCI	(49,874		)	18,258
Balance at end of period	$	(13,626	)	$	67,110
The amount of total gains or losses for the period included in other revenue attributable to the change in unrealized gains or losses related to assets still held at the reporting date	$	(1,402	)	$	29,737

	For the Nine Months Ended September 30,
	2012			2011
	(In thousands)
Balance at beginning of period	$	150,989		$	—
Total gains (losses) for the period:
Unrealized gain (loss) on commodity hedges	(21,670		)	48,852
Realized loss on hedge restructure	(14,555		)	—
Gain from hedge ineffectiveness	2,155			—
Transfers out of Level 3	(109,685		)	—
Settlements in Production Revenue	(11,990		)	—
Settlements in Other Revenue	(17,111		)	—
Changes included in Other Revenue	2,797			—
Unrealized gains reported in OCI	5,444			18,258
Balance at end of period	$	(13,626	)	$	67,110
The amount of total gains or losses for the period included in other revenue attributable to the change in unrealized gains or losses related to assets still held at the reporting date	$	(16,718	)	$	48,852

Transfers from Level 3 to Level 2 represent our ten-year derivative instruments that were exchanged in January and February 2012 for derivative instruments with shorter durations and are valued on the date of the transfer.

12

Commodity Price Derivatives

As of September 30, 2012, we had price collars and swaps hedging our anticipated natural gas and NGL production as follows:

Production Year	Daily Production Volume
	Gas	NGL
	MMcfd	MBbld
2012	230	7
2013	180	—
2014	140	—
2015	120	—
2016-2021	45	—

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. Upon 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.

During the nine months endedSeptember 30, 2012 and 2011, we recognized $3.8 million and $3.6 million, respectively of those deferred gains as a reduction of interest expense. The remaining $18.1 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 currently scheduled as follows:

(In thousands)
Remainder of 2012	$	1,315
2013	5,539
2014	6,012
2015	4,669
2016	569
	$	18,104

Fair Value Disclosures

The estimated fair value of our derivative instruments at September 30, 2012 and December 31, 2011 were as follows:

	Asset Derivatives				Liability Derivatives
	September 30, 2012		December 31, 2011		September 30, 2012		December 31, 2011
	(In thousands)				(In thousands)
Derivatives designated as hedges:
Commodity contracts reported in:
Current derivative assets	$	126,075	$	165,484	$	—	$	2,639
Noncurrent derivative assets	116,895		183,982		7,582		—
Current derivative liabilities	—		—		—		4,028
Noncurrent derivative liabilities	909		—		43,447		—
Total derivatives designated as hedges	$	243,879	$	349,466	$	51,029	$	6,667
Derivatives not designated as hedges:	$	—	$	—	$	—	$	—
Total derivatives	$	243,879	$	349,466	$	51,029	$	6,667

13

The change in carrying value of our commodity price derivatives since December 31, 2011 principally resulted from the overall increase in market prices for natural gas relative to the prices in our open derivative instruments as well as additional derivative instruments entered into during the nine months endedSeptember 30, 2012, offset by settlements during the period.

The changes in the carrying value of our derivatives for the three and nine months endedSeptember 30, 2012 and 2011 are presented below:

	For the Three Months Ended September 30,
	2012			2011
	Cash Flow Hedges			Cash Flow Hedges
	(In thousands)
Derivative fair value at beginning of period	$	342,187		$	116,349
Change in net amounts receivable and payable	907			(576		)
Settlements in production revenue	(54,133		)	(16,815		)
Settlements in other revenue	(10,910		)	—
Settlements deferred in OCI	(6,922		)	—
Ineffectiveness reported in other revenue	(2,832		)	880
Unrealized gains reported in other revenue	—			29,737
Other changes reported in other revenue	176			—
Unrealized gains (losses) reported in OCI	(75,623		)	76,598
Derivative fair value at end of period	$	192,850		$	206,173
	For the Nine Months Ended September 30,
	2012			2011
	Cash Flow Hedges			Cash Flow Hedges
	(In thousands)
Derivative fair value at beginning of period	$	342,799		$	146,762
Change in net amounts receivable and payable	(6,904		)	(960		)
Settlements in production revenue	(151,701		)	(56,143		)
Settlements in other revenue	(28,787		)	—
Settlements deferred in OCI	(16,746		)	—
Ineffectiveness reported in other revenue	2,067			1,698
Realized losses reported in other revenue	(14,555		)	—
Unrealized gains (losses) reported in other revenue	(21,670		)	48,852
Other changes reported in other revenue	(2,308		)	—
Unrealized gain reported in OCI	90,655			65,964
Derivative fair value at end of period	$	192,850		$	206,173

Gains and losses from the effective portion of derivative assets and liabilities held in AOCI expected to be reclassified into earnings during the following twelve months would result in a gain of $54.2 million net of income taxes. Hedge derivative ineffectiveness resulted in gains of $2.1 million and $1.7 million for the nine months endedSeptember 30, 2012 and 2011, respectively. In January and February 2012, we terminated a number of our ten-year derivative instruments in exchange for derivative instruments with shorter durations at above market terms. The decrease in the fair value between the terminated ten-year instrument and the new shorter-term instrument was recognized in the current period as a realized loss. Unrealized losses recognized in 2012 is the difference between the estimated fair value at the inception date and transaction cost for ten-year derivative instruments entered into during the period.

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. During the nine months endedSeptember 30, 2011, gains of $133.2 million were recognized in Other Income from

14

the sale of 7.7 million BBEP Units. During the fourth quarter of 2011, we sold all of our remaining BBEP Units.

Changes in the balance of our investment in BBEP 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		)
Balance at September 30, 2011	$	21,725

We accounted 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 June 30,		For the Nine Months Ended June 30,
	2011		2011
	(In thousands)		(In thousands)
Revenue (1)	$	142,368	$	147,829
Operating expense	72,929		226,349
Operating income (loss)	69,439		(78,520		)
Interest and other (2)	11,300		30,363
Income tax expense (benefit)	616		(825		)
Noncontrolling interests	68		137
Net income (loss) available to BBEP unitholders	$	57,455	$	(108,195	)

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

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

5. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment consisted of the following:

	September 30, 2012			December 31, 2011
	(In thousands)
Oil and gas properties
Subject to depletion	$	5,681,541		$	5,309,330
Unevaluated costs	439,767			433,341
Accumulated depletion	(4,275,280		)	(2,516,195		)
Net oil and gas properties	1,846,028			3,226,476
Other plant and equipment
Pipelines and processing facilities	368,926			340,242
General properties	75,908			71,297
Accumulated depreciation	(196,813		)	(177,496		)
Net other property and equipment	248,021			234,043
Property, plant and equipment, net of accumulated depletion and depreciation	$	2,094,049		$	3,460,519

Ceiling Test Analysis and Impairment

We recorded impairment expense of $436.5 million and $105.4 million at September 30, 2012, $898.7 million and $93.2

15

million at June 30, 2012 and $62.3 million and $0.4 million at March 31, 2012 for our U.S. and Canadian oil and gas properties, respectively. For our U.S. oil and gas properties, we computed the September 30, 2012, June 30, 2012 and March 31, 2012 ceiling amounts using Henry Hub prices of $2.83, $3.15 and $3.73 per MMBtu of natural gas, respectively, calculated as the unweighted average of the preceding 12 month first-day-of-the-month prices. The Henry Hub natural gas prices used to compute the ceiling amounts at September 30, 2012, June 30, 2012 and March 31, 2012 were 31.3%, 23.5% and 9.5% lower than the comparable price used at December 31, 2011. For our Canadian oil and gas properties, we computed the September 30, 2012, June 30, 2012 and March 31, 2012 ceiling amounts using AECO prices of $2.48, $2.72 and $3.64 per MMBtu of natural gas, respectively, calculated as the unweighted average of the preceding 12-month first-day-of-the-month prices. The AECO natural gas prices used to compute the ceiling amount at September 30, 2012, June 30, 2012 and March 31, 2012 were 32.1%, 25.5% and 1.0% lower than the comparable price used at December 31, 2011. For our U.S. oil and gas properties, we computed the September 30, 2012 and June 30, 2012 ceiling amounts using a benchmark price of $35.49 and $35.61 per Bbl of NGL, respectively, calculated based on the unweighted average of the preceding 12-month West Texas Intermediate Crude first-day-of-the-month prices as a benchmark. NGL benchmark prices used to compute the ceiling amounts at September 30, 2012 and June 30, 2012 were 24.8% and 24.5% lower, respectively, than the comparable price used at December 31, 2011. These charges resulted in the recognition of a U.S. net deferred tax asset at September 30, 2012 and June 30, 2012. Additional information about taxes is included in Note 8.

As of September 30, 2012, our U.S. and Canadian ceiling tests included $357.4 million and $140.1 million, respectively, in value for our derivatives treated as hedges. Absent this recognition, after tax we would have recognized $357.4 million of additional impairment expense for our U.S. oil and gas properties and $140.1 million for our Canadian oil and gas properties. Because of the volatility of commodity prices and the prevailing prices subsequent to September 30, 2012, it is reasonably possible we may experience additional impairment in future periods.

We recorded impairment expense of $4.9 million at September 30, 2012 for our U.S. pipelines and processing facilities as our development plans in Colorado have evolved and indicate reduced utilization.

Notes 2 and 8 to the consolidated financial statements in our 2011 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, 2012		December 31, 2011
Combined Credit Agreements	$	490,091	$	227,482
Senior notes due 2015, net of unamortized discount	435,644		435,020
Senior notes due 2016, net of unamortized discount	579,069		576,977
Senior notes due 2019, net of unamortized discount	292,476		292,055
Senior subordinated notes due 2016	350,000		350,000
Convertible debentures, net of unamortized discount	—		18
Total debt	2,147,280		1,881,552
Unamortized deferred gain-terminated interest rate swaps	18,104		21,897
Current portion of long-term debt	—		(18		)
Long-term debt	$	2,165,384	$	1,903,431

Credit Facilities

The Combined Credit Agreements’ global borrowing base was $850 million and the global letter of credit capacity was $240 million as of September 30, 2012. At September 30, 2012, we had $298.5 million available under the Combined Credit Agreements.

In light of then prevailing prices for natural gas and NGLs, we amended our Combined Credit Agreements in August 2012 primarily to relax the financial covenants contained therein through the second quarter of 2014. The next semi-annual redetermination of our global borrowing base was scheduled to be completed in October 2012. However, in conjunction with the amendments to our Combined Credit Agreements, our borrowing base was also redetermined and the next redetermination is scheduled for April 2013. As a result of the amendment and the redetermination process, the following changes were made to the Combined Credit Agreements:

16

• Reduction of the global borrowing base to $850 million from $1.075 billion

• Increase of the applicable margin by 0.50% for each type of loan and issued letters of credit, and setting of the commitment fee on unutilized availability to 0.50%

• Reduction of the minimum required interest coverage ratio from 2.5 to 1.5 for the quarter ending September 30, 2012 through the quarter ending March 31, 2014, then increasing to 2.0 for the quarter ending June 30, 2014, and reverting to 2.5 thereafter

• Addition of a maximum senior secured debt leverage ratio of 2.5 beginning in the quarter ending September 30, 2012

• Until June 30, 2013, and so long as the total leverage ratio for the prior twelve month period is greater than or equal to 4.0:

• Restrict the ability to issue certain additional types of debt;

• Limit the aggregate amount of restricted payments to $15 million;

• Restrict the ability to repay existing debt securities if global borrowing base utilization equals or exceeds 25%; and

• Require a dollar for dollar repayment of the Combined Credit Agreements together with any repayment of existing debt securities if the global borrowing base utilization is less than 25% until the Combined Credit Agreements are paid in full, at which time existing debt securities may be repaid in any amounts; and

• Restrict the ability to terminate certain oil and gas hedging arrangements prior to December 31, 2014.

Summary of All Outstanding Debt

As of September 30, 2012, the following subsidiaries are guarantors under our debt obligations: Cowtown Pipeline Management, Inc., Cowtown Pipeline Funding, Inc., Cowtown Gas Processing L.P., Cowtown Pipeline L.P., Silver Stream Pipeline Company LLC, and Barnett Shale Operating LLC and, with respect to only our senior notes and senior subordinated notes, QPP Parent LLC and QPP Holdings LLC. The following table summarizes other significant aspects of our long-term debt outstanding at September 30, 2012:

17

	Priority on Collateral and Structural Seniority (1)
	Highest priority				Lowest priority
	Equal priority	Equal Priority
	Combined Credit Agreements	2015 Senior Notes	2016 Senior Notes	2019 Senior Notes	Senior Subordinated Notes
Principal amount (2)	$850 million	$438 million	$591 million	$298 million	$350 million
Scheduled maturity date	September 6, 2016	August 1, 2015	January 1, 2016	August 15, 2019	April 1, 2016
Interest rate on outstanding borrowings at September 30, 2012 (3)	3.20%	8.25%	11.75%	9.125%	7.125%
Base interest rate options (4) (5)	LIBOR, ABR, CDOR	N/A	N/A	N/A	N/A
Financial covenants (6)	- Minimum current ratio of 1.0 - Minimum EBITDA to cash interest expense ratio of 1.5 - Maximum senior secured debt leverage ratio of 2.5	N/A	N/A	N/A	N/A
Significant restrictive covenants (6)	- Incurrence of debt - Incurrence of liens -Payment of dividends - Equity purchases - Asset sales - Affiliate transactions - Limitations on derivatives	- Incurrence of debt - Incurrence of liens -Payment of dividends - Equity purchases - Asset sales - Affiliate transactions	- Incurrence of debt - Incurrence of liens -Payment of dividends - Equity purchases - Asset sales - Affiliate transactions	- Incurrence of debt - Incurrence of liens -Payment of dividends - Equity purchases - Asset sales - Affiliate transactions	- Incurrence of debt - Incurrence of liens -Payment of dividends - Equity purchases - Asset sales - Affiliate transactions
Optional redemption (6)	Any time	August 1, 2012: 103.875 2013: 101.938 2014: par	July 1, 2013: 105.875 2014: 102.938 2015: par	August 15, 2014: 104.563 2015: 103.042 2016: 101.521 2017: par	April 1, 2012: 102.375 2013: 101.188 2014: par
Make-whole redemption (6)	N/A	N/A	Callable prior to July 1, 2013 at make‑whole call price of Treasury +50 bps	Callable prior to August 15, 2014 at make‑whole call price of Treasury +50 bps	N/A
Change of control (6)	Event of default	Put at 101% of principal plus accrued interest	Put at 101% of principal plus accrued interest	Put at 101% of principal plus accrued interest	Put at 101% of principal plus accrued interest
Estimated fair value (7)	$490.1 million	$417.2 million	$594.3 million	$283.5 million	$300.6 million

⁽¹⁾  Borrowings under the Amended and Restated 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., Cowtown Pipeline L.P., Barnett Shale Operating LLC, Silver Stream Pipeline Company LLC, Quicksilver Production Partners Operating Ltd., QPP Parent LLC and QPP Holdings LLC (collectively, the “Domestic Pledged Equity”), 65% of the equity interests of Quicksilver Resources Canada Inc. (“QRCI”) and certain oil and gas properties and related assets of Quicksilver. Borrowings under the Amended and Restated Canadian Credit Facility are guaranteed by Quicksilver and certain of its domestic subsidiaries and are secured by the Domestic Pledged Equity, 100% of the equity interests of QRCI and any of its Canadian subsidiaries, and certain oil and gas properties and related assets of Quicksilver and QRCI. The other debt presented is based upon structural seniority and priority of payment.

⁽²⁾  The principal amount for the Combined Credit Agreements represents the global borrowing base as of September 30, 2012.

⁽³⁾  Represents the weighted average borrowing rate payable to lenders.

⁽⁴⁾  Amounts outstanding under the Amended and Restated U.S. Credit Facility bear interest, at our election, at (i) adjusted LIBOR (as defined in the Amended and Restated U.S. Credit Facility) plus an applicable margin between 2.00% to 3.00%, (ii) ABR (as defined in the Amended and Restated U.S. Credit Facility), which is the greatest of (a) the prime rate announced by JPMorgan, (b) the federal funds rate plus 0.50% and (c) adjusted LIBOR for an interest period of one month plus 1.00%, plus, in each case under scenario (ii), an applicable margin between 1.00% to 2.00%. We also pay a per annum fee on the LC Exposure (as defined in the Amended and Restated U.S. Credit Facility) of all letters of credit issued under the Amended and Restated U.S. Credit Facility equal to the applicable margin, with respect to adjusted LIBOR loans, and a commitment fee on the unused availability under the Amended and Restated U.S. Credit Facility of 0.50%.

18

⁽⁵⁾  Amounts outstanding under the Amended and Restated Canadian Credit Facility bear interest, at our election, at (i) the CDOR Rate (as defined in the Amended and Restated Canadian Credit Facility) plus an applicable margin between 2.00% and 3.00%, (ii) the Canadian Prime Rate (as defined in the Amended and Restated Canadian Credit Facility) plus an applicable margin between 1.00% and 2.00%, (iii) the U.S. Prime Rate (as defined in the Amended and Restated Canadian Credit Facility) plus an applicable margin between 1.00% and 2.00% and (iv) adjusted LIBOR (as defined in the Amended and Restated Canadian Credit Facility) plus an applicable margin between 2.00% to 3.00%. We pay a per annum fee on the LC Exposure (as defined in the Amended and Restated Canadian Credit Facility) of all letters of credit issued under the Amended and Restated Canadian Credit Facility equal to the applicable margin, with respect to adjusted LIBOR loans, and a commitment fee on the unused availability under the Amended and Restated Canadian Credit Facility of 0.50%.

⁽⁶⁾  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.

⁽⁷⁾  The estimated fair value is determined using market quotations based on recent trade activity for fixed rate obligations (“Level 2” inputs). We consider debt with variable interest rates to have a fair value equal to its carrying value (“Level 1” input).

7. ASSET RETIREMENT OBLIGATIONS

The following table provides a reconciliation of the changes in the estimated asset retirement obligation for the nine months endedSeptember 30, 2012.

(In thousands)
Beginning asset retirement obligations	$	85,822
Additional liability incurred	2,263
Change in estimates	4,665
Accretion expense	3,033
Asset retirement costs incurred	(1,422		)
Settlement of liability in excess of obligation recorded	1,998
Currency translation adjustment	1,666
Ending asset retirement obligations	98,025
Less current portion	(254		)
Long-term asset retirement obligation	$	97,771

8. INCOME TAXES

Deferred income taxes are established for all temporary differences between the book and the tax basis of assets and liabilities. In addition, deferred tax balances must be adjusted to reflect tax rates that we expect will be in effect during years in which we expect the temporary differences will reverse. Net operating loss carry‑forwards and other deferred tax assets are reviewed for recoverability, and if necessary, are recorded net of a valuation allowance. In the quarter ended September 30, 2012, we recognized a U.S. valuation allowance of $283.6 million as we determined that it is no longer more likely than not that we will realize the deferred tax benefits primarily related to our cumulative net operating losses.

Tax benefits of $9.2 million were recognized during the quarter ended September 30, 2012 as the statute of limitations related to uncertain tax positions expired.

9. COMMITMENTS AND CONTINGENCIES

Contractual Obligations, Commitments and Contingencies

On July 26, 2011, we received a subpoena duces tecum from the SEC requesting certain documents. The SEC has informed us that their investigation arises out of press releases in 2011 questioning the projected decline curves and economics of shale gas wells. On June 15, 2012, we received an additional request from the SEC for certain information regarding our assessment for impairment of unevaluated properties and plans for development of unevaluated properties.

On September 7, 2012, we entered into a Project Expenditure Authorization (PEA) Amending Agreement with NGTL to delay the targeted in-service date of the NGTL project pipeline and meter station facilities from May 1, 2014 to August 1, 2015. This amendment revised NGTL's spend profile, and correspondingly changed the timing of our financial assurances. Due to

19

this delay, our letters of credit provided decreased from C$68.3 million to C$29.7 million . No additional letters of credit are scheduled to be provided until April 1, 2014.

There have been no other significant changes to our contractual obligations and commitments as reported in our 2011 Annual Report on Form 10-K. Note 14 to the consolidated financial statements in our 2011 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 quarter ended September 30, 2012.

10. FORTUNE CREEK

In December 2011, we entered into an agreement with KKR to form Fortune Creek to construct and operate midstream assets for natural gas produced by us and others primarily in British Columbia. The partnership established an area of mutual interest for the midstream business covering approximately 30 million potential acres which includes transportation and processing infrastructure and agreements.

In forming Fortune Creek, our Canadian subsidiary contributed an existing 20-mile, 20-inch gathering line and its related compression facilities, committed to minimum expenditures of $300 million for drilling and completion activities in our Horn River Asset between 2012 and 2014, and committed gas production from our Horn River Asset for ten years beginning 2012, as more fully described below. KKR contributed $125 million cash in exchange for a 50% interest in Fortune Creek. Our Canadian subsidiary has responsibility for the day-to-day operations of Fortune Creek.

Our Canadian subsidiary entered into a firm gathering agreement with Fortune Creek which is guaranteed by us. At our election, KKR has the responsibility to fund up to C$130 million of the capital required for construction of a new gas treatment facility in exchange for preferential cash flow distributions. If our subsidiary does not meet its obligations under the gathering agreement, KKR has the right to liquidate the partnership and consequently we have recorded the funds contributed by KKR as a liability in our consolidated financial statements. We recognize accretion expense to reflect the rate of return earned by KKR via its investment. Beginning in May 2012, Fortune Creek made cash distributions to KKR, which is reported as cash used by financing activities.

Based on an analysis of the partners’ equity at risk, we have determined the partnership to be a VIE. Further, based on our ability to direct the activities surrounding the production of natural gas and our direct management of the operations of the Fortune Creek facilities, we have determined we are the primary beneficiary and, therefore, we consolidate Fortune Creek.

Note 13 contains financial information for Fortune Creek in our condensed consolidating financial statements.

11. 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, 2012 and December 31, 2011, we had 173.0 million and 171.6 million shares of common stock outstanding, respectively.

Note 17 to the consolidated financial statements in our 2011 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 2012 with an estimated fair value of $8.5 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:

	2012	2011
Weighted avg grant date fair value	$4.21	$9.16
Weighted avg risk-free interest rate	1.14%	2.38%
Expected life (in years)	6.0	6.0
Wtd avg volatility	68.2%	66.8%
Expected dividends	—	—

20

The following table summarizes our stock option activity for the nine months endedSeptember 30, 2012:

	Shares		Wtd Avg Exercise Price		Wtd Avg Remaining Contractual Life	Aggregate Intrinsic Value
					(In years)	(In thousands)
Outstanding at January 1, 2012	3,760,696		$	12.01
Granted	2,020,685		6.90
Exercised	(1,572	)	6.21
Forfeited	(471,790	)	8.82
Expired	(312,242	)	12.31
Outstanding at September 30, 2012	4,995,777		$	10.23	7.2	$	3
Exercisable at September 30, 2012	2,927,909		$	10.88	6.1	$	—

As of September 30, 2012, we estimate that a total of 5.0 million stock options will become vested including those options already exercisable. As of December 31, 2011, the unrecognized compensation cost related to outstanding unvested stock options was $7.5 million, which is expected to be recognized in expense through January 2014. Compensation expense related to stock options of $5.9 million and $5.3 million was recognized for each of the nine months endedSeptember 30, 2012 and 2011, respectively. Cash received from the exercise of stock options totaled less than $0.1 million for the nine months endedSeptember 30, 2012. The total intrinsic value of those options exercised was less than $0.1 million.

Restricted Stock

The following table summarizes our restricted stock and stock unit activity for the nine months endedSeptember 30, 2012:

	Payable in shares				Payable in cash
	Shares		Wtd Avg Grant Date Fair Value		Shares		Wtd Avg Grant Date Fair Value
Outstanding at January 1, 2012	2,460,300		$	12.29	369,846		$	13.12
Granted	2,998,554		6.41		653,195		6.19
Vested	(1,487,637	)	10.33		(199,068	)	11.31
Forfeited	(828,011	)	8.97		(135,624	)	9.68
Outstanding at September 30, 2012	3,143,206		$	8.49	688,349		$	7.74

As of December 31, 2011, the unrecognized compensation cost related to outstanding unvested restricted stock was $17.3 million, which is expected to be recognized in expense through March 2014. Grants of restricted stock and RSUs during the nine months endedSeptember 30, 2012 had an estimated grant date fair value of $23.3 million. The fair value of outstanding RSUs to be settled in cash is $2.8 million at September 30, 2012. For the nine months endedSeptember 30, 2012 and 2011, compensation expense of $11.9 million and $10.2 million, respectively, was recognized. The total fair value of shares vested during the nine months endedSeptember 30, 2012 was $10.9 million.

21

12.EARNINGS PER SHARE

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

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2012			2011			2012			2011
	(In thousands, except per share data)
Net income (loss) attributable to Quicksilver	$	(651,762	)	$	28,686		$	(1,384,227	)	$	66,515
Basic income allocable to participating securities (1)	—			(359		)	—			(801		)
Basic net income (loss) attributable to Quicksilver	$	(651,762	)	$	28,327		$	(1,384,227	)	$	65,714
Weighted average common shares – basic	170,179			169,031			170,054			168,963
Effect of dilutive securities (2):
Share-based compensation awards	—			705			—			805
Weighted average common shares – diluted	170,179			169,736			170,054			169,768
Earnings (loss) per common share – basic	$	(3.83	)	$	0.17		$	(8.14	)	$	0.39
Earnings (loss) per common share – diluted	$	(3.83	)	$	0.17		$	(8.14	)	$	0.39

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

⁽²⁾  For the three months ended September 30, 2012, we had the following antidilutive shares excluded from the dilution calculations: 5.0 million shares associated with our stock options and 0.3 million shares associated with our unvested restricted stock units. For the three months ended September 30, 2011, we had the following antidilutive shares excluded from the dilutive calculation: 9.8 million shares associated with our contingently convertible debt, 2.0 million shares associated with our stock options and 1.9 million shares associated with our unvested restricted stock units. For the nine months endedSeptember 30, 2012, we had the following antidilutive shares excluded from the dilution calculation: 5.0 million shares associated with our stock options and 0.3 million shares associated with our unvested restricted stock units. For the nine months endedSeptember 30, 2011, we had the following antidilutive shares excluded from the dilution calculation: 9.8 million shares associated with our contingently convertible debt, 2.0 million shares associated with our stock options and 1.9 million shares associated with our unvested restricted stock units.

13. CONDENSED CONSOLIDATING FINANCIAL INFORMATION

Note 19 to the consolidated financial statements in our 2011 Annual Report on Form 10-K contains a more complete description of our guarantor, non-guarantor, restricted and unrestricted subsidiaries.

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. Under the indentures for our senior notes and senior subordinated notes, Fortune Creek is not considered to be a subsidiary and therefore it is presented separately from the other subsidiaries for these purposes.

22

Condensed Consolidating Balance Sheets

	September 30, 2012
	Quicksilver Resources Inc.			Restricted Guarantor Subsidiaries			Restricted Non- Guarantor Subsidiaries			Restricted Subsidiary Eliminations			Quicksilver and Restricted Subsidiaries			Unrestricted Non- Guarantor Subsidiaries			Fortune Creek		Consolidating Eliminations			Quicksilver Resources Inc. Consolidated
	(In thousands)
ASSETS
Current assets	$	285,659		$	90,863		$	77,895		$	(205,745	)	$	248,672		$	11,546		$	5,863	$	(23,044	)	$	243,037
Property and equipment	1,399,421			37,637			565,296			—			2,002,354			—			91,695		—			2,094,049
Investment in subsidiaries (equity method)	61,433			—			(37,523		)	(61,433		)	(37,523		)	(37,546		)	—		75,069			—
Other assets	362,158			—			34,620			(243,620		)	153,158			—			—		—			153,158
Total assets	$	2,108,671		$	128,500		$	640,288		$	(510,798	)	$	2,366,661		$	(26,000	)	$	97,558	$	52,025		$	2,490,244
LIABILITIES AND EQUITY
Current liabilities	$	218,945		$	111,787		$	58,300		$	(205,745	)	$	183,287		$	11,524		$	3,280	$	(23,044	)	$	175,047
Long-term liabilities	2,036,429			22,003			515,264			(243,620		)	2,330,076			—			84		131,739			2,461,899
Stockholders' equity	(146,703		)	(5,290		)	66,724			(61,433		)	(146,702		)	(37,524		)	94,194		(56,670		)	(146,702		)
Total liabilities and equity	$	2,108,671		$	128,500		$	640,288		$	(510,798	)	$	2,366,661		$	(26,000	)	$	97,558	$	52,025		$	2,490,244

	December 31, 2011
	Quicksilver Resources Inc.		Restricted Guarantor Subsidiaries			Restricted Non- Guarantor Subsidiaries			Restricted Subsidiary Eliminations			Quicksilver and Restricted Subsidiaries			Unrestricted Non- Guarantor Subsidiaries			Fortune Creek		Consolidating Eliminations			Quicksilver Resources Inc. Consolidated
	(In thousands)
ASSETS
Current assets	$	336,893	$	87,767		$	63,711		$	(200,727	)	$	287,644		$	—		$	27,533	$	(14,750	)	$	300,427
Property and equipment	2,743,379		37,936			598,443			—			3,379,758			—			80,761		—			3,460,519
Investment in subsidiaries (equity method)	241,680		—			(29,449		)	(241,680		)	(29,449		)	(29,449		)	—		58,898			—
Other assets	401,279		—			76,857			(243,620		)	234,516			—			—		—			234,516
Total assets	$	3,723,231	$	125,703		$	709,562		$	(686,027	)	$	3,872,469		$	(29,449	)	$	108,294	$	44,148		$	3,995,462
LIABILITIES AND EQUITY
Current liabilities	$	348,512	$	109,938		$	76,450		$	(200,727	)	$	334,173		$	—		$	14,750	$	(14,750	)	$	334,173
Long-term liabilities	2,112,800		21,903			385,294			(243,620		)	2,276,377			—			80		122,913			2,399,370
Stockholders' equity	1,261,919		(6,138		)	247,818			(241,680		)	1,261,919			(29,449		)	93,464		(64,015		)	1,261,919
Total liabilities and equity	$	3,723,231	$	125,703		$	709,562		$	(686,027	)	$	3,872,469		$	(29,449	)	$	108,294	$	44,148		$	3,995,462

23

Condensed Consolidating Statements of Income

	For the Three Months Ended September 30, 2012
	Quicksilver Resources Inc.			Restricted Guarantor Subsidiaries			Restricted Non- Guarantor Subsidiaries			Restricted Subsidiary Eliminations			Quicksilver and Restricted Subsidiaries			Unrestricted Non- Guarantor Subsidiaries		Fortune Creek		Consolidated Eliminations			Quicksilver Resources Inc. Consolidated
	(In thousands)
Revenue	$	151,546		$	1,182		$	25,670		$	(696	)	$	177,702		$	—	$	4,422	$	(4,422	)	$	177,702
Operating expenses	560,615			739			140,391			(696		)	701,049			—		3,010		(4,422		)	699,637
Equity in net earnings of subsidiaries	(91,904		)	—			(2,268		)	91,904			(2,268		)	1,443		—		825			—
Operating income (loss)	(500,973		)	443			(116,989		)	91,904			(525,615		)	1,443		1,412		825			(521,935		)
Fortune Creek accretion	—			—			—			—			—			—		—		(4,978		)	(4,978		)
Interest expense and other	(37,965		)	—			(4,586		)	—			(42,551		)	23		31		—			(42,497		)
Income tax (expense) benefit	(112,824		)	(155		)	29,383			—			(83,596		)	—		—		1,244			(82,352		)
Net income (loss)	$	(651,762	)	$	288		$	(92,192	)	$	91,904		$	(651,762	)	$	1,466	$	1,443	$	(2,909	)	$	(651,762	)
Other comprehensive income (loss)	(68,457		)	—			(12,881		)	12,881			(68,457		)	—		—		—			(68,457		)
Equity in OCI of subsidiaries	(12,881		)	—			—			—			(12,881		)	—		—		—			(12,881		)
Comprehensive income (loss)	$	(733,100	)	$	288		$	(105,073	)	$	104,785		$	(733,100	)	$	1,466	$	1,443	$	(2,909	)	$	(733,100	)

	For the Three Months Ended September 30, 2011
	Quicksilver Resources Inc.			Restricted Guarantor Subsidiaries			Restricted Non-Guarantor Subsidiaries			Consolidating Eliminations			Quicksilver Resources Inc. 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	$	28,686		$	(398	)	$	15,126		$	(14,728	)	$	28,686
Other comprehensive income (loss)	33,077			—			(29,275		)	29,275			33,077
Equity in OCI of subsidiaries	(29,275		)	—			—			—			(29,275		)
Comprehensive income (loss)	$	32,488		$	(398	)	$	(14,149	)	$	14,547		$	32,488

24

	For the Nine Months Ended September 30, 2012
	Quicksilver Resources Inc.			Restricted Guarantor Subsidiaries			Restricted Non- Guarantor Subsidiaries			Restricted Subsidiary Eliminations			Quicksilver and Restricted Subsidiaries			Unrestricted Non- Guarantor Subsidiaries		Fortune Creek		Consolidated Eliminations			Quicksilver Resources Inc. Consolidated
	(In thousands)
Revenue	$	432,341		$	3,390		$	58,296		$	(2,294	)	$	491,733		$	—	$	10,021	$	(10,021	)	$	491,733
Operating expenses	1,784,270			2,541			288,965			(2,294		)	2,073,482			—		6,093		(10,021		)	2,069,554
Crestwood earn-out	41,097			—			—			—			41,097			—		—		—			41,097
Equity in net earnings of subsidiaries	(185,797		)	—			(6,930		)	185,797			(6,930		)	3,959		—		2,971			—
Operating income (loss)	(1,496,629		)	849			(237,599		)	185,797			(1,547,582		)	3,959		3,928		2,971			(1,536,724		)
Fortune Creek accretion	—			—			—			—			—			—		—		(14,549		)	(14,549		)
Interest expense and other	(114,579		)	—			(8,060		)	—			(122,639		)	23		31		—			(122,585		)
Income tax (expense) benefit	226,981			(297		)	59,310			—			285,994			—		—		3,637			289,631
Net income (loss)	$	(1,384,227	)	$	552		$	(186,349	)	$	185,797		$	(1,384,227	)	$	3,982	$	3,959	$	(7,941	)	$	(1,384,227	)
Other comprehensive income (loss)	(44,868		)	—			5,201			(5,201		)	(44,868		)	—		—		—			(44,868		)
Equity in OCI of subsidiaries	5,201			—			—			—			5,201			—		—		—			5,201
Comprehensive income (loss)	$	(1,423,894	)	$	552		$	(181,148	)	$	180,596		$	(1,423,894	)	$	3,982	$	3,959	$	(7,941	)	$	(1,423,894	)

	For the Nine Months Ended September 30, 2011
	Quicksilver Resources Inc.			Restricted Guarantor Subsidiaries			Restricted Non- Guarantor Subsidiaries			Consolidating Eliminations			Quicksilver Resources Inc. 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	$	66,515		$	(604	)	$	(5,971	)	$	6,575		$	66,515
Other comprehensive income (loss)	8,102			—			(27,598		)	27,598			8,102
Equity in OCI of subsidiaries	(27,598		)	—			—			—			(27,598		)
Comprehensive income (loss)	$	47,019		$	(604	)	$	(33,569	)	$	34,173		$	47,019

25

Condensed Consolidating Statements of Cash Flows

	For the Nine Months Ended September 30, 2012
	Quicksilver Resources Inc.			Restricted Guarantor Subsidiaries			Restricted Non-Guarantor Subsidiaries			Quicksilver and Restricted Subsidiaries			Unrestricted Non-Guarantor Subsidiaries		Fortune Creek			Quicksilver Resources Inc. Consolidated
	(In thousands)
Net cash flow provided (used) by operating activities	$	74,952		$	655		$	48,301		$	123,908		$	—	$	17,468		$	141,376
Purchases of property, plant and equipment	(199,136		)	(655		)	(227,509		)	(427,300		)	—		(9,872		)	(437,172		)
Proceeds from Crestood earn-out	41,097			—			—			41,097			—		—			41,097
Proceeds from sale of properties and equipment	3,489			—			354			3,843			—		—			3,843
Net cash flow used by investing activities	(154,550		)	(655		)	(227,155		)	(382,360		)	—		(9,872		)	(392,232		)
Issuance of debt	177,500			—			190,146			367,646			—		—			367,646
Repayments of debt	(98,018		)	—			(13,097		)	(111,115		)	—		—			(111,115		)
Debt issuance costs	(1,998		)	—			(1,050		)	(3,048		)	—		—			(3,048		)
Distribution of Fortune Creek Partnership funds	—			—			—			—			—		(6,520		)	(6,520		)
Proceeds from exercise of stock options	11			—			—			11			—		—			11
Excess tax deductions on stock compensation	1,089			—			—			1,089			—		—			1,089
Purchase of treasury stock	(2,810		)	—			—			(2,810		)	—		—			(2,810		)
Net cash flow provided (used) by financing activities	75,774			—			175,999			251,773			—		(6,520		)	245,253
Effect of exchange rates on cash	—			—			2,855			2,855			—		(2,962		)	(107		)
Net increase (decrease) in cash and equivalents	(3,824		)	—			—			(3,824		)	—		(1,886		)	(5,710		)
Cash and equivalents at beginning of period	363			—			—			363			—		12,783			13,146
Cash and equivalents at end of period	$	(3,461	)	$	—		$	—		$	(3,461	)	$	—	$	10,897		$	7,436

	For the Nine Months Ended September 30, 2011
	Quicksilver Resources Inc.			Restricted Guarantor Subsidiaries			Restricted Non-Guarantor Subsidiaries			Consolidating Eliminations		Quicksilver Resources Inc. 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 (used) 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

14. 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. Additionally, we operate a significantly smaller midstream segment in the U.S. and Canada, where we provide natural gas gathering and processing services, primarily to our U.S. and Canadian exploration and production segments. Following the formation of our partnership with KKR, beginning in January 2012, we have additional midstream operations in Canada through Fortune Creek. Based on the immateriality of our midstream segment, we have combined U.S. and Canadian information. We evaluate performance based on operating income and property and equipment costs incurred.

26

	Exploration & Production															Quicksilver
	U.S.			Canada			Midstream			Corporate			Elimination			Consolidated
For the Three Months Ended September 30:	(In thousands)
2012
Revenue	$	151,777		$	24,962		$	6,081		$	—		$	(5,118	)	177,702
DD&A	27,605			13,740			1,274			590			—			43,209
Impairment expense	436,481			105,409			4,945			—			—			546,835
Operating income (loss)	(393,280		)	(113,585		)	2,854			(17,924		)	—			(521,935		)
Property and equipment costs incurred	43,722			21,382			1,824			837			—			67,765
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
For the Nine Months Ended September 30:
2012
Revenue	$	419,581		$	69,105		$	15,363		$	—		$	(12,316	)	491,733
DD&A	108,845			35,182			3,790			1,773			—			149,590
Impairment expense	1,397,538			199,019			4,945			—			—			1,601,502
Operating income (loss)	(1,258,519		)	(227,371		)	5,776			(56,610		)	—			(1,536,724		)
Property and equipment costs incurred	160,699			178,783			13,263			6,284			—			359,029
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
Property, plant and equipment-net
September 30, 2012	$	1,408,964		$	563,736		$	112,675		$	8,674		$	—		$	2,094,049
December 31, 2011	2,752,101			596,935			102,237			9,246			—			3,460,519

15. SUPPLEMENTAL CASH FLOW INFORMATION

Cash paid (received) for interest and income taxes was as follows:

	For the Nine Months Ended September 30,
	2012			2011
	(In thousands)
Interest, net of capitalized interest	$	141,811		$	154,649
Income taxes	(1,528		)	5,904

Other significant non-cash transactions were as follows:

	For the Nine Months Ended September 30,
	2012		2011
	(In thousands)
Working capital related to capital expenditures	$	37,386	$	75,409

27

16. TRANSACTIONS WITH RELATED PARTIES

As of September 30, 2012, members of the Darden family and entities controlled by them beneficially owned approximately 30% of our outstanding common stock. Thomas Darden, Glenn Darden and Anne Darden Self are officers and directors of Quicksilver.

During the first nine months of 2012 and 2011, we paid $0.4 million and $0.6 million, respectively, for use of an airplane owned by an entity controlled by members of the Darden family. Usage rates were determined based upon comparable rates charged by third parties.

Payments received from Mercury, a company owned by members of the Darden family, for sublease rentals, employee insurance coverage and administrative services were negligible for the first nine months of 2012 and 2011.

We paid $0.1 million in the first nine months of 2011 for rent on buildings owned by entities controlled by members of the Darden family. Rental rates were determined based on comparable rates charged by third parties. No similar payments were made in the first nine months of 2012.

A director of Quicksilver also serves on the board of a vendor to our primary Canadian subsidiary. From June 2011, the period when the director began serving on the board of the vendor, to September 2011, we paid $0.4 million for services performed by the vendor. For the first nine months of 2012 we paid $4.5 million to the vendor for materials used in our exploration and production segment. Charges for products and services were at comparable market rates.

28

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 as well as our 2011 Annual Report on Form 10-K. We conduct our operations in two segments: (1) our more dominant exploration and production segment, and (2) our significantly smaller midstream 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:

• 2012 Highlights – a summary of significant activities and events affecting Quicksilver

• 2012 Capital Program – a summary of our planned capital expenditures during 2012

• 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

2012 HIGHLIGHTS

Joint Venture Update

In September 2012 we entered into an Acquisition and Exploration Agreement with SWEPI LP ("SWEPI"), a subsidiary of Royal Dutch Shell plc, to jointly develop Quicksilver's and SWEPI's oil and gas interests in the Sand Wash Basin and to establish an Area of Mutual Interest covering in excess of 850,000 acres in the basin upon closing. We will own a 50% interest in approximately 330,000 acres. We expect to complete this transaction before year-end.

We continue to pursue strategic alternatives for our West Texas, Horn River and Barnett Shale Assets as well as a secondary transaction in our Sand Wash Asset.

Horn River Development

We completed our first multi‑well pad in our Horn River Asset during June and July 2012. The initial production results from these new wells ranged between 23 MMcfd and 34 MMcfd which exceeded initial production expectations. We are currently producing 30 MMcfd from our Horn River Asset which includes production from only one of the eight wells completed this summer. We currently have nine wells shut‑in in our Horn River Asset with an estimated production capability of 150 MMcfd. Our midstream commitments have been impacted by delays in the commissioning of a third-party gas treating facility, which we originally expected would receive our gas beginning in May 2012, and may now be delayed into 2013. We are securing alternative treating and transportation arrangements on an interim and interruptible basis that will allow Horn River Basin production to be increased up to an additional 50 MMcfd beginning in December 2012.

Emerging Basins

We deployed a rig in April 2012 to commence drilling operations in our Sand Wash Asset to target oil production. In the third quarter, we drilled one well, completed one well and re‑completed a well we previously drilled. Our plan for the fourth quarter of 2012 is to drill one well and complete two wells. In conjunction with the closing of the SWEPI agreement, we plan to participate in the drilling and completion of up to three additional wells for the fourth quarter 2012.

We deployed a rig in March 2012 to commence drilling operations in our West Texas Asset to target oil production. In the third quarter of 2012, we re‑completed a well and re‑entered an existing well to drill a horizontal lateral. Our plan for the fourth quarter of 2012 is to complete one well. We hold a position of approximately 155,000 net acres in the Delaware and Midland basins for which approximately 65% is prospective for oil.

Master Limited Partnership

In February 2012, we filed a Form S‑1 with the SEC to begin the registration and sale of limited partnership interests in a master limited partnership holding certain of our mature properties in our Barnett Shale Asset. We amended the registration statement in May to include financial statements for 2011 and to address comments received from the SEC and in June to include financial statements for the first quarter of 2012 and to address further comments received from the SEC. In July 2012, we were informed that the SEC had no further comments. We continue to monitor market conditions to assess the timing of an offering.

29

Significant Contract Revisions

In August 2012, we amended our Combined Credit Agreements primarily to loosen the financial covenants through the second quarter of 2014. Specific changes to the Combined Credit Agreements are outlined in Note 6 to the condensed consolidated financial statements.

In September 2012, we entered into a Project Expenditure Authorization Amending Agreement with NGTL to delay the targeted in‑service date of the NGTL project pipeline and meter station facilities from May 1, 2014 to August 1, 2015. This deferral resulted in a reduction in our letters of credit provided. Additionally, because of this delay in the NGTL project pipeline and meter station, we have delayed Fortune Creek's construction of a new gas treatment facility.

Hedging and Derivatives

We continue to execute our derivative program. The table below summarizes our natural gas derivative positions and activity:

	As of June 30, 2012		Entered into subsequently		As of November 7, 2012
	Volume Mmcfd	Weighted Avg Price Per Mcf	Volume Mmcfd	Weighted Avg Price Per Mcf	Volume Mmcfd	Weighted Avg Price Per Mcf
2012	230	$5.75 - $6.00	(5)	$6.20	225	$5.74 - $6.00
2013	150	$5.40	50	$4.22	200	$5.10
2014	110	$5.54	60	$4.23	170	$5.08
2015	110	$5.54	40	$4.39	150	$5.23
2016 - 2021	45	$4.67	(5)	$6.20	40	$4.48

2012 CAPITAL PROGRAM

We incurred costs related to our capital program of $359.0 million for the first nine months of 2012. We reduced our original capital program in response to the continued depression in natural gas prices and the sharp decline in NGL prices. We anticipate fourth quarter spending to approximate $30 million, for a total 2012 capital program of approximately $389 million.

RESULTS OF OPERATIONS

Three Months Ended September 30, 2012 and 2011

The following discussion compares the results of operations for the three months ended September 30, 2012 and 2011, or the 2012 quarter and 2011 quarter, respectively. “Other U.S.” refers to the combined amounts for our Sand Wash Asset and Bakken Asset.

Revenue

Production Revenue:

	Natural Gas				NGL					Oil				Total
	2012		2011		2012		2011			2012		2011		2012		2011
	(In millions)
Barnett Shale	$	48.6	$	104.9	$	29.9	$	55.2		$	2.6	$	2.4	$	81.1	$	162.5
Other U.S.	0.2		0.4		0.1		0.2			3.3		2.9		3.6		3.5
Hedging	37.9		23.2		8.5		(12.9		)	—		—		46.4		10.3
U.S.	86.7		128.5		38.5		42.5			5.9		5.3		131.1		176.3
Horseshoe Canyon	11.0		20.0		—		—			—		—		11.0		20.0
Horn River	8.7		4.7		—		—			—		—		8.7		4.7
Hedging	6.9		7.1		—		—			—		—		6.9		7.1
Canada	26.6		31.8		—		—			—		—		26.6		31.8
Consolidated	$	113.3	$	160.3	$	38.5	$	42.5		$	5.9	$	5.3	$	157.7	$	208.1

30

Average Daily Production Volume:

	Natural Gas		NGL		Oil		Equivalent Total
	2012	2011	2012	2011	2012	2011	2012	2011
	(MMcfd)		(Bbld)		(Bbld)		(MMcfed)
Barnett Shale	193.2	277.6	11,052	11,911	322	304	261.5	350.9
Other U.S.	0.6	1.2	18	26	439	392	3.4	3.7
Total U.S.	193.8	278.8	11,070	11,937	761	696	264.9	354.6
Horseshoe Canyon	53.9	57.5	3	8	—	—	53.9	57.6
Horn River	43.6	15.3	—	—	—	—	43.6	15.2
Total Canada	97.5	72.8	3	8	—	—	97.5	72.8
Total	291.3	351.6	11,073	11,945	761	696	362.4	427.4

Average Realized Price:

	Natural Gas				NGL					Oil				Equivalent Total
	2012		2011		2012		2011			2012		2011		2012		2011
	(per Mcf)				(per Bbl)					(per Bbl)				(per Mcfe)
Barnett Shale	$	2.74	$	4.11	$	29.43	$	50.38		$	87.29	$	85.71	$	3.38	$	5.04
Other U.S.	2.73		2.80		36.33		69.68			81.39		80.14		11.30		9.88
Hedging	2.12		0.90		8.31		(11.75		)	—		—		1.90		0.32
Total U.S.	4.87		5.01		37.75		38.67			83.88		82.58		5.38		5.40
Horseshoe Canyon	$	2.22	$	3.77	$	45.92	$	46.52		$	—	$	—	$	2.22	$	3.77
Horn River	2.17		3.41		—		—			—		—		2.17		3.41
Hedging	0.77		1.06		—		—			—		—		0.77		1.06
Total Canada	$	2.96	$	4.75	$	45.92	$	46.52		$	—	$	—	$	2.97	$	4.75
Total	$	4.23	$	4.96	$	37.75	$	38.68		$	83.88	$	82.58	$	4.73	$	5.29

The following table summarizes the changes in our natural gas, NGL and oil revenue:

	Natural Gas			NGL			Oil		Total
	(In thousands)
Revenue for the 2011 quarter	$	160,272		$	42,507		$	5,285	$	208,064
Volume variances	(22,280		)	(4,052		)	494		(25,838		)
Hedge revenue variances	14,473			21,371			—		35,844
Price variances	(39,094		)	(21,370		)	93		(60,371		)
Revenue for the 2012 quarter	$	113,371		$	38,456		$	5,872	$	157,699

Natural gas and NGL revenue for the 2012 quarter decreased from the 2011 quarter due to lower volumes produced and realized prices. The decrease in natural gas volume from our Barnett Shale Asset was primarily due to production decline resulting from the aging of existing wells, and our capital spending reductions. Natural gas production volumes were also impacted by a temporary disruption as a result of a fire at a third-party processing facility in the Barnett Shale and temporary shut-ins in support of new development activity.

Utilization of derivatives to hedge our sales of natural gas and NGL may result in realized prices varying from market prices that we receive from the sale of our production. Our production revenue for the 2012 quarter and 2011 quarter was higher by $53.3 million and $17.4 million, respectively, because of our hedging activities.

We monitor the economic impact of continuing to produce from certain of our wells in the current price environment and, as a result, we may temporarily shut-in wells. Wells shut-in during the 2012 quarter had an immaterial impact on our production volumes. We believe these and any possible future shut-ins would result in increases to operating income and

31

operating cash flows, and continue to have only an immaterial impact on our production volumes.

Sales of Purchased Natural Gas and Costs of Purchased Natural Gas

	Three Months Ended September 30,
	2012		2011
	(In thousands)
Sales of purchased natural gas
Purchases from Eni	$	20,383	$	17,681
Purchases from others	930		2,449
Total	21,313		20,130
Costs of purchased natural gas sold
Purchases from Eni	20,383		17,737
Purchases from others	871		2,217
Total	21,254		19,954
Net sales and purchases of natural gas	$	59	$	176

Other Revenue

	Three Months Ended September 30,
	2012			2011
	(In thousands)
Midstream revenue:
Canada	$	477		$	788
Texas	486			248
Total midstream revenue	963			1,036
Gain (loss) from hedge ineffectiveness	(2,832		)	880
Unrealized gain on commodity derivatives	—			29,737
Other	559			46
Total	$	(1,310	)	$	31,699

In the 2011 quarter, we recognized $29.7 million of unrealized gain for derivatives that we entered into during 2011 that were not designated as hedges for accounting purposes. Loss from hedge ineffectiveness was $2.8 million for the 2012 quarter as compared to a gain of $0.9 million for the 2011 quarter as our derivate instruments are based on NYMEX pricing and our production is sold at market prices other than NYMEX. At September 30, 2012, we did not have any basis swaps to offset the price differential.

32

Operating Expense

Lease Operating

	Three Months Ended September 30,
	2012				2011
	(In thousands, except per unit amounts)
			Per Mcfe				Per Mcfe
Barnett Shale
Cash expense	$	11,464	$	0.48	$	16,391	$	0.51
Equity compensation	201		0.01		212		—
	$	11,665	$	0.49	$	16,603	$	0.51
Other U.S.
Cash expense	$	2,149	$	6.94	$	2,191	$	6.44
Equity compensation	39		0.13		82		0.24
	$	2,188	$	7.07	$	2,273	$	6.68
Total U.S.
Cash expense	$	13,613	$	0.56	$	18,582	$	0.57
Equity compensation	240		0.01		294		0.01
	$	13,853	$	0.57	$	18,876	$	0.58
Horseshoe Canyon
Cash expense	$	7,378	$	1.49	$	7,656	$	1.45
Equity compensation	85		0.02		99		0.06
	$	7,463	$	1.51	$	7,755	$	1.51
Horn River
Cash expense	$	799	$	0.20	$	1,042	$	0.74
Equity compensation	—		—		—		—
	$	799	$	0.20	$	1,042	$	0.74
Total Canada
Cash expense	$	8,177	$	0.91	$	8,698	$	1.30
Equity compensation	85		0.01		99		0.01
	$	8,262	$	0.92	$	8,797	$	1.31
Total Company
Cash expense	$	21,790	$	0.65	$	27,280	$	0.69
Equity compensation	325		0.01		393		0.01
	$	22,115	$	0.66	$	27,673	$	0.70

The Barnett Shale Asset experienced lower gas lift costs, compression expense and saltwater disposal costs compared to the 2011 quarter as certain higher cost wells remained shut-in during the 2012 quarter. Other U.S. lease operating costs were impacted on a unit basis by increased activity in our Sand Wash Asset.

Lease operating expense for the 2012 quarter in Canada decreased compared to the 2011 quarter primarily due to lower well and compressor repair and maintenance costs incurred during the 2012 quarter.

33

Gathering, Processing and Transportation

	Three Months Ended September 30,
	2012				2011
	(In thousands, except per unit amounts)
			Per Mcfe				Per Mcfe
Barnett Shale	$	33,894	$	1.41	$	46,335	$	1.44
Other U.S.	3		0.01		6		0.02
Total U.S.	33,897		1.39		46,341		1.42
Horseshoe Canyon	822		0.17		833		0.16
Horn River	6,619		1.65		3,939		2.81
Total Canada	7,441		0.83		4,772		0.71
Total	$	41,338	$	1.24	$	51,113	$	1.30

US GPT per Mcfe in the 2012 quarter was lower primarily due to lower variable fuel charges as prices have decreased and on a gross basis was lower due to the decreased production discussed earlier. Canadian GPT increased in total for the 2012 quarter as compared to the 2011 quarter as a result of increased volumes at our Horn River Asset, and decreased on a per Mcfe basis in the Horn River primarily as a result of fixed costs under our firm agreements with third parties being spread over increased volumes in the 2012 quarter. Canadian GPT includes unused firm capacity of $1.4 million and $1.6 million for the 2012 period and the 2011 period, respectively.

Production and Ad Valorem Taxes

	Three Months Ended September 30,
	2012				2011
	(In thousands, except per unit amounts)
			Per Mcfe				Per Mcfe
Production taxes
Barnett Shale	$	961	$	0.04	$	2,747	$	0.09
Other U.S.	231		0.01		274		0.01
Total U.S.	1,192		0.05		3,021		0.09
Horseshoe Canyon	50		0.01		81		0.02
Horn River	—		—		—		—
Total Canada	50		0.01		81		0.01
Total production taxes	1,242		0.04		3,102		0.08
Ad valorem taxes
U.S.	$	4,747	0.19		$	3,979	0.12
Canada	892		0.10		676		0.10
Total ad valorem taxes	5,639		0.17		4,655		0.12
Total	$	6,881	$	0.21	$	7,757	$	0.20

Barnett Shale production taxes per Mcfe in the 2012 quarter was lower primarily due to lower realized prices on natural gas.

34

Depletion, Depreciation and Accretion

	Three Months Ended September 30,
	2012				2011
	(In thousands, except per unit amounts)
			Per Mcfe				Per Mcfe
Depletion
U.S.	$	25,704	$	1.05	$	41,834	$	1.28
Canada	11,759		1.31		9,569		1.43
Total depletion	37,463		1.12		51,403		1.31
Depreciation of other fixed assets
U.S.	$	2,146	$	0.09	$	3,236	$	0.10
Canada	2,536		0.28		2,352		0.35
Total depreciation	4,682		0.14		5,588		0.14
Accretion	1,064		0.03		695		0.02
Total	$	43,209	$	1.30	$	57,686	$	1.47

U.S. depletion for the 2012 quarter reflected a decrease in production and a decrease in the depletion rate due to impairments recognized earlier in 2012 when compared to the 2011 quarter. Canadian depletion increased in the 2012 quarter due to an increase in production when compared to the 2011 quarter partially offset by a decrease in depletion rate as a result of impairment recognized earlier in 2012. Following the impairment recognized in the 2012 quarter, we expect U.S. and Canadian depletion rates will be between $0.94 and $1.00 per Mcfe for the fourth quarter of 2012.

U.S. depreciation for the 2012 quarter was lower than the 2011 quarter primarily because of reduced carrying value of our midstream assets following their impairment in late 2011. Canadian depreciation was higher due to increased capital spending on the Fortune Creek non-oil and gas properties throughout the second half of 2011.

Impairment Expense

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 2012 quarter, we recognized $436.5 million and $105.4 million in non-cash charges for impairment of our U.S. and Canadian oil and gas properties, respectively.

In performing our quarterly ceiling tests, we utilize first-day-of-the-month prices for the preceding 12 months. Due to the decrease in forecasted natural gas and NGL prices during the fourth quarter 2012 compared to the fourth quarter 2011, there is a reasonable possibility we may experience further impairment of oil and gas properties. As of September 30, 2012, our U.S. and Canadian ceiling tests included $357.4 million and $140.1 million, respectively, in value for our derivatives treated as hedges. Absent this recognition, after tax we would have recognized $357.4 million of additional impairment expense for our U.S. oil and gas properties and $140.1 million for our Canadian oil and gas properties. If any of our derivatives we treat as hedges become ineligible for hedge treatment, it could significantly impact the amount of impairment that we recognize.

Additionally, we recognized impairment expense of $4.9 million for certain midstream assets in Colorado as our development plans have evolved and indicate reduced utilization.

35

General and Administrative

	Three Months Ended September 30,
	2012				2011
	(In thousands, except per unit amounts)
			Per Mcfe				Per Mcfe
Cash expense	$	8,856	$	0.27	$	11,086	$	0.28
Audit and accounting fees	845		0.03		247		0.01
Strategic transaction costs	998		0.03		3,056		0.08
Litigation settlement	—		—		8,500		0.22
Equity compensation	6,636		0.20		4,695		0.11
Total	$	17,335	$	0.53	$	27,584	$	0.70

General and administrative expense for the 2012 quarter was lower than the 2011 quarter primarily due to the settlement of the Eagle litigation in 2011, partially offset by an increase in equity compensation due to accelerated stock compensation expense in connection with a previously announced executive retirement.

Loss from Earnings of BBEP

We recorded our portion of BBEP’s earnings during the quarter in which its financial statements became publicly available. As a result, our 2011 quarter results of operations included BBEP’s earnings for the three months ended June 30, 2011. We sold the last of our BBEP Units in the fourth quarter of 2011.

We recognized gains of $14.4 million for equity earnings from our investment in BBEP for the 2011 quarter.

Other Income

Gains of $9.5 million were recognized in the 2011 quarter from the sale of 0.6 million BBEP Units in July 2011.

Fortune Creek Accretion

In December 2011, we entered into an agreement with KKR to form Fortune Creek to construct and operate midstream assets for natural gas produced by us and others primarily in British Columbia. In connection with the partnership formation, KKR contributed $125 million cash in exchange for a 50% interest in Fortune Creek. KKR’s contribution is shown as Partnership liability in the condensed consolidated balance sheet, and we recognize accretion expense to reflect the rate of return earned by KKR via its investment.

Interest Expense

	Three Months Ended September 30,
	2012			2011
	(In thousands)
Interest costs on debt outstanding	$	44,081		$	43,039
Add:
Fees paid on letters of credit outstanding	—			115
Premium paid on senior notes repurchased	—			1,989
Non-cash interest (1)	4,592			5,237
Total interest costs incurred	48,673			50,380
Less:
Interest capitalized	(6,571		)	(1,987		)
Interest expense	$	42,102		$	48,393

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

36

Interest costs on debt outstanding for the 2012 quarter were higher when compared to the 2011 quarter primarily because of increased interest rates and debt outstanding partially offset by an increase in capitalized interest on capital expenditures related to our exploratory plays.

Income Taxes

The effective tax rates for the three months ended September 30, 2012 and 2011 are as follows:

	Three Months Ended September 30,
	2012			2011
	(in thousands)
Income tax (benefit) expense-U.S.	$	112,979		$	9,630
Effective tax rate-U.S.	(25.3		)%	41.8		%
Income tax (benefit) expense-Canada	$	(30,627	)	$	6,784
Effective tax rate-Canada	24.9		%	30.8		%
Income tax (benefit) expense-total	$	82,352		$	16,414
Effective tax rate-total	(14.5		)%	36.4		%

Income tax expense for the three months ended September 30, 2012 included a U.S. valuation allowance of $283.6 million as we determined reduced likelihood of realizing deferred tax benefits primarily related to our cumulative net operating losses. Additionally, tax benefits of $9.2 million were recognized during the three months ended September 30, 2012 as the statute of limitations related to the tax benefits expired. The effective tax rate for the 2012 quarter reflects a projection of a full year of U.S. and Canadian taxable losses. Our income tax provision for the 2011 quarter reflected changes in the projected effective tax rate for 2011 as of September 30, 2011 to adjust for the sale of BBEP units in July 2011 as well as the unrealized derivative gains in other revenue. The effective rate for the 2011 quarter reflected a projection of full year Canadian taxable loss partially offset by the projection of a full year of U.S. taxable income.

RESULTS OF OPERATIONS

Nine Months EndedSeptember 30, 2012 and 2011

The following discussion compares the results of operations for the nine months ended September 30, 2012 and 2011, or the 2012 period and 2011 period, respectively. “Other U.S.” refers to the combined amounts for our Sand Wash Asset and Bakken Asset.

Revenue

Production Revenue:

	Natural Gas				NGL					Oil				Total
	2012		2011		2012		2011			2012		2011		2012		2011
	(In millions)
Barnett Shale	$	145.5	$	293.1	$	108.8	$	161.2		$	8.8	$	9.2	$	263.1	$	463.5
Other U.S.	0.5		0.9		0.3		0.5			10.6		8.9		11.4		10.3
Hedging	122.8		68.6		15.1		(32.7		)	—		—		137.9		35.9
Total U.S.	268.8		362.6		124.2		129.0			19.4		18.1		412.4		509.7
Horseshoe Canyon	33.4		61.1		0.1		0.1			—		—		33.5		61.2
Horn River	13.4		14.0		—		—			—		—		13.4		14.0
Hedging	20.7		21.2		—		—			—		—		20.7		21.2
Total Canada	67.5		96.3		0.1		0.1			—		—		67.6		96.4
Total	$	336.3	$	458.9	$	124.3	$	129.1		$	19.4	$	18.1	$	480.0	$	606.1

37

Average Daily Production Volume:

	Natural Gas		NGL		Oil		Equivalent Total
	2012	2011	2012	2011	2012	2011	2012	2011
	(MMcfd)		(Bbld)		(Bbld)		(MMcfed)
Barnett Shale	214.2	260.7	11,293	12,204	349	362	284.1	336.1
Other U.S.	0.7	1.0	23	24	455	383	3.6	3.3
Total U.S.	214.9	261.7	11,316	12,228	804	745	287.7	339.4
Horseshoe Canyon	55.0	58.4	5	6	—	—	55.0	58.5
Horn River	23.3	14.5	—	—	—	—	23.3	14.5
Total Canada	78.3	72.9	5	6	—	—	78.3	73.0
Total	293.2	334.6	11,321	12,234	804	745	366.0	412.4

Average Realized Price:

	Natural Gas				NGL					Oil				Equivalent Total
	2012		2011		2012		2011			2012		2011		2012		2011
	(per Mcf)				(per Bbl)					(per Bbl)				(per Mcfe)
Barnett Shale	$	2.48	$	4.12	$	35.15	$	48.39		$	92.01	$	93.04	$	3.38	$	5.05
Other U.S.	2.38		3.60		49.74		74.95			85.35		85.25		11.66		11.22
Hedging	2.09		0.96		4.86		(9.79		)	—		—		1.75		0.39
Total U.S.	$	4.57	$	5.08	$	40.05	$	38.66		$	88.24	$	89.05	$	5.23	$	5.50
Horseshoe Canyon	$	2.21	$	3.83	$	66.18	$	62.41		$	—	$	—	$	2.22	$	3.83
Horn River	2.10		3.54		—		—			—		—		2.10		3.54
Hedging	0.96		1.06		—		—			—		—		0.96		1.06
Total Canada	$	3.14	$	4.84	$	66.18	$	62.41		$	—	$	—	$	3.15	$	4.84
Total	$	4.19	$	5.02	$	40.06	$	38.67		$	88.24	$	89.05	$	4.79	$	5.38

The following table summarized the changes in our production revenue:

	Natural Gas			NGL			Oil			Total
	(In thousands)
Revenue for the 2011 period	$	458,821		$	129,147		$	18,102		$	606,070
Volume variances	(44,415		)	(11,515		)	1,523			(54,407		)
Hedge revenue variances	53,751			47,751			—			101,502
Price variances	(131,852		)	(41,118		)	(174		)	(173,144		)
Revenue for the 2012 period	$	336,305		$	124,265		$	19,451		$	480,021

Natural gas and NGL revenue for the 2012 period decreased from the 2011 period primarily due to lower realized prices without hedge gains. The decrease in natural gas volume from our Barnett Shale Asset was primarily due to production decline resulting from the aging of existing wells and our capital spending pattern. Natural gas production volumes were also impacted by temporary shut-ins in support of new development activity.

Utilization of derivatives to hedge our sales of natural gas and NGL may result in realized prices varying from market prices that we receive from the sale of our production. Our production revenue for the 2012 period and 2011 period was higher by $158.6 million and $57.1 million, respectively, because of our hedging activities.

38

Sales of Purchased Natural Gas and Costs of Purchased Natural Gas

	Nine Months Ended September 30,
	2012		2011
	(In thousands)
Sales of purchased natural gas
Purchases from Eni	$	40,254	$	47,080
Purchases from others	2,588		13,036
Total	42,842		60,116
Costs of purchased natural gas sold
Purchases from Eni	40,288		47,024
Purchases from others	2,240		12,230
Total	42,528		59,254
Net sales and purchases of natural gas	$	314	$	862

Other Revenue

	Nine Months Ended September 30,
	2012			2011
	(In thousands)
Midstream revenue from third parties
Canada	$	1,952		$	2,418
Texas	1,096			799
Total midstream revenue	3,048			3,217
Gain from hedge ineffectiveness	2,067			1,698
Loss from hedge restructure	(14,555		)	—
Gain (Loss) on commodity derivatives	(21,670		)	48,852
Other	(20		)	573
Total	$	(31,130	)	$	54,340

In the 2011 period, we recognized $48.9 million of unrealized gain for derivatives that we entered into during 2011 that were not designated as hedges for accounting purposes. Losses on commodity derivatives recognized in 2012 are equal to the difference between the estimated fair value at the inception date and transaction cost for ten-year derivative instruments entered into during the period. In January and February 2012, we terminated a number of our ten-year derivative instruments in exchange for derivative instruments with shorter durations at above market terms. The decrease in the fair value between the terminated ten­year instrument and the new shorter term instrument was recognized in the current period as a realized loss from hedge restructure. Gains from hedge ineffectiveness were $2.1 million for the 2012 period as compared to $1.7 million for the 2011 period as our derivative instruments are based on NYMEX pricing and our production is sold at market prices other than NYMEX. At September 30, 2012, we did not have any basis swaps to offset the price differential.

39

Operating Expense

Lease Operating

	Nine Months Ended September 30,
	2012				2011
	(In thousands, except per unit amounts)
			Per Mcfe				Per Mcfe
Barnett Shale
Cash expense	$	41,633	$	0.53	$	41,500	$	0.45
Equity compensation	842		0.01		692		0.01
	$	42,475	$	0.54	$	42,192	$	0.46
Other U.S.
Cash expense	$	6,448	$	6.59	$	4,807	$	5.24
Equity compensation	126		0.13		181		0.20
	$	6,574	$	6.72	$	4,988	$	5.44
Total U.S.
Cash expense	$	48,081	$	0.61	$	46,307	$	0.50
Equity compensation	968		0.01		873		0.01
	$	49,049	$	0.62	$	47,180	$	0.51
Horseshoe Canyon
Cash expense	$	21,011	$	1.39	$	23,642	$	1.48
Equity compensation	293		0.02		368		0.03
	$	21,304	$	1.41	$	24,010	$	1.51
Horn River
Cash expense	$	2,052	$	0.32	$	2,176	$	0.55
Equity compensation	—		—		—		—
	$	2,052	$	0.32	$	2,176	$	0.55
Total Canada
Cash expense	$	23,063	$	1.07	$	25,818	$	1.30
Equity compensation	293		0.01		368		0.01
	$	23,356	$	1.08	$	26,186	$	1.31
Total Company
Cash expense	$	71,144	$	0.71	$	72,125	$	0.64
Equity compensation	1,261		0.01		1,241		0.01
	$	72,405	$	0.72	$	73,366	$	0.65

The Barnett Shale Asset experienced higher gas lift costs, workover expense and saltwater disposal costs compared to the 2011 period due to the aging of existing wells and costs to maintain production. Other U.S. lease operating costs were impacted on a gross and unit basis by increased production and costs for our Sand Wash Asset.

Lease operating expense for the 2012 period in Canada decreased compared to the 2011 period due to lower well and compressor repair and maintenance costs and lower labor costs incurred during the 2012 period.

40

Gathering, Processing and Transportation

	Nine Months Ended September 30,
	2012				2011
	(In thousands, except per unit amounts)
			Per Mcfe				Per Mcfe
Barnett Shale	$	108,997	$	1.40	$	128,724	$	1.40
Other U.S.	11		0.01		13		0.01
Total U.S.	109,008		1.38		128,737		1.39
Horseshoe Canyon	2,850		0.19		3,068		0.19
Horn River	15,182		2.37		10,396		2.62
Total Canada	18,032		0.84		13,464		0.68
Total	$	127,040	$	1.27	$	142,201	$	1.26

Canadian GPT increased for the 2012 period as compared to the 2011 period both in total dollars and on a per Mcfe basis primarily as a result of fixed costs under our firm agreements with third parties. Canadian GPT includes unused firm capacity of $5.2 million and $2.8 million for the 2012 period and the 2011 period, respectively. GPT per Mcfe was flat in the U.S.

Production and Ad Valorem Taxes

	Nine Months Ended September 30,
	2012				2011
	(In thousands, except per unit amounts)
			Per Mcfe				Per Mcfe
Production taxes
Barnett Shale	$	3,608	$	0.05	$	6,779	$	0.07
Other U.S.	639		0.65		817		0.89
Total U.S.	4,247		0.05		7,596		0.08
Horseshoe Canyon	102		0.01		156		0.01
Horn River	—		—		—		—
Total Canada	102		0.01		156		0.01
Total production taxes	4,349		0.04		7,752		0.07
Ad valorem taxes
U.S.	14,191		0.18		14,069		0.15
Canada	2,293		0.11		2,023		0.10
Total ad valorem taxes	16,484		0.16		16,092		0.14
Total	$	20,833	$	0.20	$	23,844	$	0.21

41

Depletion, Depreciation and Accretion

	Nine Months Ended September 30,
	2012				2011
	(In thousands, except per unit amounts)
			Per Mcfe				Per Mcfe
Depletion
U.S.	$	103,230	$	1.31	$	118,858	$	1.28
Canada	29,389		1.37		29,325		1.47
Total depletion	132,619		1.32		148,183		1.32
Depreciation of other fixed assets
U.S.	$	6,825	0.09		$	9,293	0.10
Canada	7,113		0.33		5,381		0.27
Total depreciation	13,938		0.14		14,674		0.13
Accretion	3,033		0.03		2,004		0.01
Total	$	149,590	$	1.49	$	164,861	$	1.46

U.S. depletion for the 2012 period reflected an increase in the depletion rate partially offset by a decrease in production when compared to the 2011 period. On a per Mcfe basis, Canadian depletion decreased in 2012 because production increased and the depletion rate decreased when compared to the 2011 period.

U.S. depreciation for the 2012 period was lower than the 2011 period primarily because of the reduced carrying value of our midstream assets following their impairment in late 2011. Canadian depreciation was higher due to increased capital spending on the Fortune Creek non-oil and gas properties in the second half of 2011.

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 2012 period, we recognized $1,397.5 million and $199.0 million in non-cash charges for impairment of our U.S. and Canadian oil and gas properties, respectively, as of September 30, 2012. Additionally, we recognized impairment expense of $4.9 million for certain midstream assets in Colorado as our development plans have evolved and indicate reduced utilization.

In the 2011 period, we recognized $49.1 million in non-cash charges for impairment of our Canadian oil and gas properties.

General and Administrative

	Nine Months Ended September 30,
	2012				2011
	(In thousands, except per unit amounts)
			Per Mcfe				Per Mcfe
Cash expense	$	32,728	$	0.33	$	33,609	$	0.30
Audit and accounting fees	5,389		0.05		869		0.01
Strategic transaction costs	998		0.01		4,534		0.04
Litigation settlement	—		—		8,500		0.08
Equity compensation	15,721		0.16		14,233		0.12
Total	$	54,836	$	0.55	$	61,745	$	0.55

General and administrative expense for the 2012 period was lower than the 2011 period primarily due to the Eagle

42

litigation settlement of $8.5 million and $4.5 million of strategic transaction costs in 2011 partially offset by an increase in audit and accounting fees during 2012.

Crestwood Earn-Out

In February 2012, we collected $41 million of earn-out payments from Crestwood, which is presented as Crestwood earn-out in the condensed consolidated statement of income for the nine months ended September 30, 2012.

Loss from Earnings of BBEP

We recorded our portion of BBEP’s earnings during the quarter in which its financial statements became publicly available. As a result, our 2011 period results of operations included BBEP’s earnings for the nine months ended June 30, 2011. We sold the last of our BBEP Units in the fourth quarter of 2011.

We recognized losses of $32.7 million for equity earnings from our investment in BBEP for the 2011 period.

Other Income

Gains of $133.2 million were recognized in the 2011 period from the sale of 7.7 million BBEP Units.

Fortune Creek Accretion

In December 2011, we entered into an agreement with KKR to form Fortune Creek to construct and operate midstream assets for natural gas produced by us and others primarily in British Columbia. In connection with the partnership formation, KKR contributed $125 million cash in exchange for a 50% interest in Fortune Creek. KKR’s contribution is shown as Partnership liability in the condensed consolidated balance sheet, and we recognize accretion expense to reflect the rate of return earned by KKR via its investment.

Interest Expense

	Nine Months Ended September 30,
	2012			2011
	(In thousands)
Interest costs on debt outstanding	$	128,592		$	130,153
Add:
Fees paid on letters of credit outstanding	74			1,374
Premium paid - senior notes repurchased	—			2,560
Non-cash interest (1)	8,060			13,109
Total interest costs incurred	136,726			147,196
Less:
Interest capitalized	(14,378		)	(5,073		)
Interest expense	$	122,348		$	142,123

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

Interest costs on debt outstanding for the 2012 period were lower when compared to the 2011 period primarily because of the lower amortization of deferred financing costs due to costs expensed in late 2011 related to the termination of the 2007 Senior Secured Credit Facility and the Initial U.S Credit Facility and the increase in capitalized interest on capital expenditures related to our exploratory plays.

43

Income Taxes

The effective tax rates for the nine months ended September 30, 2012 and 2011 are as follows:

	For the Nine Months Ended September 30,
	2012			2011
	(in thousands)
Income tax (benefit) expense - U.S.	$	(226,684	)	$	39,262
Effective tax rate - U.S.	15.9		%	35.0		%
Income tax (benefit) expense - Canada	$	(62,947	)	$	684
Effective tax rate - Canada	25.2		%	(11.8		)%
Income tax (benefit) expense - total	$	(289,631	)	$	39,946
Effective tax rate - total	17.3		%	37.5		%

Income tax benefit for the nine months ended September 30, 2012 included a U.S. valuation allowance of $283.6 million as we determined reduced likelihood of realizing deferred tax benefits primarily related to our cumulative net operating losses. Additionally, tax benefits of $9.2 million were recognized during the nine months ended September 30, 2012 as the statute of limitations related to the tax benefits expired. The effective tax rate for the 2012 period reflects a projection of a full year of U.S. and Canadian taxable losses. We expect that the consolidated effective tax rate of 17.3% for the 2012 period will be our effective tax rate for all of 2012 based upon our projection of pretax income and estimated permanent differences for 2012. The effective rate for the 2011 period reflected a projection of full year Canadian taxable loss partially offset by the projection of a full year of U.S. taxable income.

Quicksilver Resources Inc. and its Restricted Subsidiaries

Information about Quicksilver and our restricted and unrestricted subsidiaries is included in Note 13 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,” except for Fortune Creek accretion expense. The combined financial position of Quicksilver and our restricted subsidiaries and our consolidated financial position are materially the same except for balances related to Fortune Creek which were included in the consolidated financial position as of September 30, 2012. 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 “Cash Flow Activity,” except for cash flows associated with the operations and development of Fortune Creek.

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, NGLs 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 commodity prices 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 2012 through 2021, price collars and swaps hedge a portion of our natural gas and NGL revenue. The following summarizes future production hedged with commodity derivatives as of September 30, 2012.

44

Production	Daily Production
Year	Gas	NGL
	MMcfd	MBbld
2012	230	7
2013	180	—
2014	140	—
2015	120	—
2016-2021	45	—

The following summarizes our cash flow activity for the 2012 period and 2011 period:

	Nine Months Ended September 30,
	2012			2011
	(In thousands)
Net cash provided by operating activities	$	141,376		$	174,666
Net cash used by investing activities	(392,232		)	(401,436		)
Net cash provided by financing activities	245,253			178,549

Operating Cash Flows

Net cash provided by operations for the 2012 period decreased from the 2011 period due to lower realized prices (including hedging effects) and lower production volumes partially offset by positive changes in working capital.

Net cash provided by operations for the 2012 period also includes hedge cash settlements of $16.7 million which is deferred in other comprehensive income related to our long‑dated hedges restructured in the first quarter of 2012. The revenue impact will be realized over the original term of the hedges which extends until 2021. Additionally, $28.8 million in cash was received related to previously recorded gains in other revenue related to hedge settlements.

Investing Cash Flows

Costs incurred for property, plant and equipment for the 2012 period and 2011 period were as follows:

	United States		Canada		Consolidated
	(In thousands)
For the Nine Months Ended September 30, 2012
Exploration and development	$	160,699	$	178,783	$	339,482
Midstream	824		12,439		13,263
Administrative	2,989		3,295		6,284
Total	$	164,512	$	194,517	$	359,029
For the Nine Months Ended September 30, 2011
Exploration and development	$	377,310	$	84,778	$	462,088
Midstream	8,017		49,331		57,348
Administrative	5,178		685		5,863
Total	$	390,505	$	134,794	$	525,299

Costs incurred reflect the true nature of the activity of the 2012 capital program, while capital expenditures shown in the condensed consolidated statement of cash flows also reflect the related changes in working capital. Our 2012 capital costs incurred have decreased for the U.S. as a result of our overall decrease in capital spend in 2012 compared to 2011. The increase in the costs incurred for exploration and development activities in Canada in 2012 when compared to 2011 relates to a significant drilling and completion program in the Horn River Basin. Our capital costs incurred for midstream operations during the 2011 period reflect the construction of infrastructure to gather, compress and deliver our Horn River gas production to third-party processing facilities. Changes in working capital are driven by the reduction in accounts payable from prior year

45

activities.

We received a $41.1 million earn-out payment from Crestwood in February 2012. During the 2011 period, we sold 7.7 million BBEP Units for total proceeds of $145.8 million. Both of these receipts were recorded as investing activities.

Financing Cash Flows

Net financing cash flows in the 2012 period include net borrowings of $256.5 million under our Combined Credit Agreements. Net financing cash flows in the 2011 period included $48.4 million of purchases and retirements of our senior notes and net borrowings of $241.3 million under our 2007 Senior Secured Credit facility.

Liquidity and Borrowing Capacity

At September 30, 2012, the Combined Credit Agreements’ global borrowing base was $850 million and the global letter of credit capacity was $240 million. At September 30, 2012, there was $298.5 million available under the Combined Credit Agreements. In light of then prevailing prices for natural gas and NGLs, we amended our Combined Credit Agreements in August 2012 primarily to relax the financial covenants contained therein through the second quarter of 2014. The next semi-annual redetermination of our global borrowing base was scheduled to be completed in October 2012. However, in conjunction with the amendments to our Combined Credit Agreements, our borrowing base was also redetermined and the next scheduled redetermination is scheduled for April 2013. Our ability to remain in compliance with the amended financial covenants in our Combined Credit Agreements may be affected by events beyond our control, including market prices for our products, the success of our drilling efforts and production volumes. 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. As a result of the amendment and the redetermination process, the following changes were made to the Combined Credit Agreements:

• Reduction of the global borrowing base to $850 million from $1.075 billion

• Increase of the applicable margin by 0.50% for each type of loan and issued letters of credit, and setting of the commitment fee on unutilized availability to 0.50%

• Reduction of the minimum required interest coverage ratio from 2.5 to 1.5 for the quarter ending September 30, 2012 through the quarter ending March 31, 2014, then increasing to 2.0 for the quarter ending June 30, 2014, and reverting to 2.5 thereafter

• Addition of a maximum senior secured debt leverage ratio of 2.5 beginning in the quarter ending September 30, 2012

• Until June 30, 2013, and so long as the total leverage ratio for the prior twelve month period is greater than or equal to 4.0:

• Restrict the ability to issue certain additional types of debt;

• Limit the aggregate amount of restricted payments to $15 million;

• Restrict the ability to repay existing debt securities if global borrowing base utilization equals or exceeds 25%; and

• Require a dollar for dollar repayment of the Combined Credit Agreements together with any repayment of existing debt securities if the global borrowing base utilization is less than 25% until the Combined Credit Agreements are paid in full, at which time existing debt securities may be repaid in any amounts; and

• Restrict the ability to terminate certain oil and gas hedging arrangements prior to December 31, 2014.

Our debt ratings were reduced by Moody’s and by Standard & Poors during the year. If the rating agencies were to further reduce our debt or credit ratings, our borrowing costs may increase, our potential pool of investors and funding resources may be reduced, and we may be required to post collateral under selected contracts and with counterparties. These events may have an adverse effect on our results of operations, financial condition and cash flows. In addition, any such reduction in our debt or credit ratings may adversely affect the trading price of our outstanding securities.

Additional information about our debt and related covenants is included in Note 6 to the condensed consolidated financial statements in Item 1 of this Quarterly Report. The information presented above is qualified in all respects by reference to the full text of the documents governing the various components of our debt.

We anticipate that our remaining 2012 capital program of approximately $30 million will be funded by cash flow from operations and asset sale proceeds. We have significant commitments to deliver gas for gathering and transport, in particular from our Horn River Asset, and must pay fees related to those services whether or not we deliver gas. These commitments limit our flexibility to further reduce our capital program. In addition, if our drilling efforts are not successful or production volumes are lower than we anticipate, we may expand our capital program in order to satisfy our delivery commitments or be required to

46

pay fees with respect to gas delivery shortfalls. Any significant increase in our capital program could require us to raise additional capital, which we cannot provide assurance that we could do on acceptable terms or at all.

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 repay 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, utilization of our Combined Credit Agreements, the issuance of debt or other securities or a combination of those sources.

Financial Position

The following impacted our balance sheet as of September 30, 2012, as compared to our balance sheet as of December 31, 2011:

• Our accounts receivable balance decreased $27.3 million from December 31, 2011 to September 30, 2012 primarily due to the collection of $14.8 million for a non-income tax matter in Canada and a decrease of $19.6 million in production receivables due to lower realized prices before hedges at September 30, 2012 compared to December 31, 2011, partially offset by an increase of $6.1 million in an income tax receivable from the U.S. federal government from year-end.

• Our net property, plant and equipment balance decreased $1.37 billion from December 31, 2011 to September 30, 2012. We incurred capital cost of $359 million during 2012 and also recognized assets for retirement obligations established for new wells and facilities. Changes to U.S.-Canadian exchange rates further increased our property, plant and equipment balances $23.7 million. Offsetting the increases was $1.75 billion of DD&A and impairment expense.

• The valuation of our current and non-current net deferred income tax liability was $299.5 million lower from December 31, 2011 to September 30, 2012 due to a deferred income tax benefit recognized on book impairment charges recorded in 2012. Our U.S. deferred tax asset has a full valuation allowance of $283.6 million as we determined reduced likelihood of realizing deferred tax benefits primarily related to our cumulative net operating losses.

• The $94.5 million decrease in accounts payable was due to a reduction in accrued capital expenditures of $38.2 million from the December 31, 2011 amount and a decrease in trade payables of $56.3 million from December 31, 2011 as activity has decreased from year‑end.

• Long-term debt increased $262.0 million for net borrowings under the Combined Credit Agreements.

Contractual Obligations and Commercial Commitments

There have been no significant changes to our contractual obligations and commitments as reported in our 2011 Annual Report on Form 10-K.

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 2011 Annual Report on Form 10-K. These critical estimates, for which no significant changes occurred during the nine months ended September 30, 2012, 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 as

47

of October 2012 is expected to continue through 2015. Assuming the project is fully constructed at estimated costs of C$296.8 million, we expect to provide letters of credit through 2015. Item 8, Note 14 in our 2011 Annual Report on Form 10-K contains additional information about our contracts with NGTL.

On September 7, 2012, we entered into a PEA Amending Agreement with NGTL to delay the targeted in-service date of the NGTL project pipeline and meter station facilities from May 1, 2014 to August 1, 2015. This amendment revised NGTL's spend profile, and correspondingly changed the timing of our financial assurances. Due to this delay, our letters of credit provided decreased from C$68.3 million to C$29.7 million. No additional letters of credit are scheduled to be provided until April 1, 2014.

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.

In June 2011, the FASB issued an amendment to accounting guidance to update the presentation of comprehensive income in consolidated financial statements. Under the amended guidance, the presentation of total comprehensive income, the components of net income, and the components of other comprehensive income may be made either in a single continuous statement of comprehensive income or in two separate but consecutive statements. This guidance became effective for us beginning with the quarter ended March 31, 2012, and required retrospective application to earlier periods presented. Our condensed consolidated statements of income (loss) and comprehensive income (loss) for the three and nine months ended September 30, 2012 and 2011 contain the required disclosures. The implementation of this accounting pronouncement also resulted in increased disclosure which is contained in Note 13.

In May 2011, the FASB issued an amendment to the accounting guidance for fair value measurement and disclosure. Among other things, the guidance expands the disclosure requirements around fair value measurements categorized in Level 3 of the fair value hierarchy and requires disclosure of the level in the fair value hierarchy of items that are not measured at fair value in the statement of financial position but whose fair value must be disclosed. It also clarifies and expands upon existing requirements for measurement of the fair value of financial assets and liabilities as well as instruments classified in stockholders’ equity. This guidance became effective for us beginning with the quarter ended March 31, 2012. The adoption of this accounting pronouncement did not have an effect on the fair value measurement, but rather expanded upon existing disclosures.

In December 2011, the FASB issued an amendment to the accounting guidance for disclosure of arrangements that permit offsetting assets and liabilities. The amendment expands the disclosure requirements to require both gross information and net information about both instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to a master netting arrangement. The amendment will be effective for us, beginning on January 1, 2013, and must be applied retrospectively. We do not expect the adoption of this accounting pronouncement to have a material impact on our financial statements when implemented.

No other pronouncements materially affecting our financial statements have been issued since the filing of our 2011 Annual Report on Form 10-K.

ITEM 3. Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

We have established internal control policies and procedures for managing risk within our organization. The possibility of decreasing prices received for our natural gas, NGL and oil 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 prices. As a result of settlements of derivative contracts, our revenue from natural gas and NGL production was greater by $158.6 million and $57.1 million for the 2012 period and 2011 period, respectively. Other revenue was $34.2 million lower for the 2012 period due to hedge ineffectiveness, unrealized losses at inception of new long-dated derivative instruments and realized losses on hedge restructuring. Other revenue was $50.6 million higher for the 2011 period due to hedge ineffectiveness and unrealized gains on derivatives that we entered into during 2011 that were not designated as hedges until August 2011 for accounting purposes.

48

The following table details our open derivative positions at September 30, 2012:

Product	Type	Production Hedged	Remaining Contract Period	Volume	Weighted Avg Price Per Mcf or Bbl
Gas	Collar	U.S.	Oct 2012 -Dec 2012	20 MMcfd	6.50 - 7.15
Gas	Collar	U.S.	Oct 2012 -Dec 2012	20 MMcfd	6.50 - 7.18
Gas	Collar	U.S.	Oct 2012 -Dec 2012	20 MMcfd	6.50 - 8.01
Gas	Swap	Canada	Oct 2012 -Dec 2012	5 MMcfd	6.20
Gas	Swap	Canada	Oct 2012 -Dec 2012	5 MMcfd	6.20
Gas	Swap	Canada	Oct 2012 -Dec 2012	10 MMcfd	6.22
Gas	Swap	Canada	Oct 2012 - Dec 2013	10 MMcfd	5.00
Gas	Swap	Canada	Oct 2012 - Dec 2015	10 MMcfd	6.42
Gas	Swap	Canada	Oct 2012 - Dec 2015	10 MMcfd	6.45
Gas	Swap	Canada	Oct 2012 -Dec 2021	10 MMcfd	4.63
Gas	Swap	Canada	Jan 2013 - Dec 2015	10 MMcfd	4.04
Gas	Swap	U.S.	Oct 2012 - Dec 2013	10 MMcfd	5.00
Gas	Swap	U.S.	Oct 2012 - Dec 2013	10 MMcfd	5.00
Gas	Swap	U.S.	Oct 2012 - Dec 2013	10 MMcfd	5.00
Gas	Swap	U.S.	Oct 2012 - Dec 2015	20 MMcfd	6.00
Gas	Swap	U.S.	Oct 2012 - Dec 2015	10 MMcfd	6.00
Gas	Swap	U.S.	Oct 2012 - Dec 2015	5 MMcfd	6.23
Gas	Swap	U.S.	Oct 2012 - Dec 2015	5 MMcfd	6.20
Gas	Swap	U.S.	Oct 2012 - Dec 2015	5 MMcfd	5.68
Gas	Swap	U.S.	Oct 2012 - Dec 2021	5 MMcfd	6.20
Gas	Swap	U.S.	Oct 2012 - Dec 2021	10 MMcfd	4.54
Gas	Swap	U.S.	Oct 2012 - Dec 2021	5 MMcfd	4.38
Gas	Swap	U.S.	Oct 2012 - Dec 2021	5 MMcfd	4.35
Gas	Swap	U.S.	Oct 2012 - Dec 2021	10 MMcfd	4.37
Gas	Swap	U.S	Jan 2013 - Dec 2014	10 MMcfd	3.91
Gas	Swap	U.S	Jan 2013 - Dec 2014	10 MMcfd	3.89
NGL	Swap	U.S.	Oct 2012-Dec 2012	1 MBbld	42.81
NGL	Swap	U.S.	Oct 2012-Dec 2012	1 MBbld	43.07
NGL	Swap	U.S.	Oct 2012-Dec 2012	2 MBbld	43.94
NGL	Swap	U.S.	Oct 2012-Dec 2012	1 MBbld	47.99
NGL	Swap	U.S.	Oct 2012-Dec 2012	1 MBbld	46.55
NGL	Swap	U.S.	Oct 2012-Dec 2012	1 MBbld	46.75

These open derivative positions had a net fair value of $192.9 million as of September 30, 2012.

In October 2012, we streamlined our hedge platform. In connection with terminations of a portion of our existing natural gas hedge positions, we executed a new series of hedges that resulted in a revised natural gas hedging platform as follows:

Production Year	Volume Mmcfd	Weighted Avg Price Per Mcf
2012	225	$5.74 - $6.00
2013	200	$5.10
2014	170	$5.08
2015	150	$5.23
2016 - 2021	40	$4.48

49

These hedges did not result in the transfer or the receipt of any net cash proceeds. We expect our entire hedge portfolio to continue to qualify for hedge accounting.

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 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 credit adjusted rates commensurate with federal treasury instruments with similar contractual lives.

Interest Rate Risk

Changes in interest rates affect the interest rate we pay on borrowings under the Combined Credit Agreements. Our senior notes and senior subordinated notes have fixed interest rates and thus do not expose us to risk from fluctuations in market interest rates. Changes in interest rates do affect the fair value of our fixed rate debt.

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 2012 period and the 2011 period, we recognized $3.8 million and $3.6 million, respectively, of those deferred gains as a reduction of interest expense.

Should we be required to borrow under our Combined Credit Agreements and based on interest rates as of September 30, 2012, each $50 million in borrowings would result in additional annual interest payments of $1.6 million. If the current borrowing availability under our Combined Credit Agreements were to be fully utilized by year-end 2012 at interest rates as of September 30, 2012, we estimate that annual interest payments would increase by $9.6 million. If interest rates change by 1% on our September 30, 2012 variable debt balances of $490.1 million, our annual pre-tax loss would decrease or increase by $4.9 million.

In the future, we may enter into interest rate derivative contracts on a portion of our outstanding debt to mitigate the risk of fluctuation of rates or manage the floating versus fixed rate risk.

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 2012 period and the 2011 period resulted in a loss of less than $0.1 million and $2.7 million, respectively, and were included in other income. Furthermore, the Amended and Restated Canadian Credit Facility permits Canadian borrowings to be made in either U.S. or Canadian-denominated amounts. However, the aggregate borrowing capacity of the entire facility is calculated using the U.S. dollar equivalent. 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, 2012, 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

As disclosed in our 2011 Annual Report on Form 10-K, a material weakness was identified related to the design and operating effectiveness of the computation of impairment of our non-oil and gas assets. In response to the identification of the material weakness, management has enhanced its process for documenting identification of impairment indicators, and the preparation and review of undiscounted recovery tests and discounted cash flow analyses for the quarters ended March 31, June 30 and September 30, 2012. Additionally management enhanced the process for preparation and review of the inputs to the asset retirement obligation and the depletion calculation for the quarters ended March 31, June 30 and September 30, 2012

50

in response to identified significant deficiencies as of December 31, 2011 related to these calculations. Management believes that these enhancements and improvements, as performed in the current period and when repeated in future periods, remediate the material weakness and significant deficiencies described above.

For the quarter ended March 31, 2012, a material weakness was identified related to the operating effectiveness of the controls surrounding the computation of derivative value. The weakness principally relates to the inception valuation methodology used on our ten-year derivatives entered into during the quarter ended March 31, 2012. Although the valuation produced an accounting result that conformed to GAAP, it was not consistent with the valuation methodology we use for our other derivatives. To a lesser extent, the weakness relates to the preparation and review of the inputs to the valuation model. In response to this material weakness, for the quarters ended June 30, 2012 and September 30, 2012, management has enhanced its process to value derivatives with particular emphasis on long-dated derivatives. Management believes that these enhancements and improvements, as performed in the current period and when repeated in future periods, remediate the material weakness.

There has been no other change in our internal control over financial reporting during the quarter ended September 30, 2012, 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

There have been no other material changes in the legal proceedings described in Part I, Item 3 included in our 2011 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 2011 Annual Report on Form 10-K.

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, 2012.

Period	Total Number of Shares Purchased (1)	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plan (2)	Maximum Number of Shares that May Yet Be Purchased Under the Plan (2)
July 2012	80,753	$	5.51	—	—
August 2012	—	$	—	—	—
September 2012	466	$	3.32	—	—
Total	81,219	$	5.50	—	—

⁽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 stock plan.

⁽²⁾  We do not have a publicly announced plan for repurchasing our common stock.

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. Mine Safety Disclosures

None.

ITEM 5. Other Information

51

None.

52

ITEM 6. Exhibits

		Incorporated by Reference				Filed (†) or Furnished (‡) Herewith (as indicated)
Exhibit No.	Exhibit Description	Form	SEC File No.	Exhibit	Filing Date
10.1	Letter to Jeff Cook dated July 20, 2012					†
10.2	Omnibus Amendment No. 2 to Combined Credit Agreements, dated as of August 6, 2012, among Quicksilver Resources Inc., Quicksilver Resources Canada Inc. and the agents and lenders identified therein	10-Q	001-14837	10.4	8/9/2012
10.3	PEA Amending Agreement, dated as of August 28, 2012, between Quicksilver Resources Canada Inc. and Nova Gas Transmission Ltd.	8-K	001-14837	10.1	9/10/2012
10.4	Amendment to Commitment Letter Agreement, dated as of August 28, 2012, between Quicksilver Resources Canada Inc. and Nova Gas Transmission Ltd.	8-K	001-14837	10.2	9/10/2012
10.5*	Acquisition and Exploration Agreement, dated September 20, 2012, between Quicksilver Resources Inc. and SWEPI LP	8-K	001-14837	10.1	9/24/2012
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					‡

* Portions of exhibit deleted pursuant to request for confidential treatment. These portions have been furnished separately to the Securities and Exchange Commission.

53

SIGNATURES

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

Dated:	November 8, 2012	Quicksilver Resources Inc.
		By:	/s/ John C. Regan
			John C. Regan
			Senior Vice President-Chief Financial Officer (Duly Authorized Officer, Principal Financial and Accounting Officer)

54

EXHIBIT INDEX

		Incorporated by Reference				Filed (†) or Furnished (‡) Herewith (as indicated)
Exhibit No.	Exhibit Description	Form	SEC File No.	Exhibit	Filing Date
10.1	Letter to Jeff Cook dated July 20, 2012					†
10.2	Omnibus Amendment No. 2 to Combined Credit Agreements, dated as of August 6, 2012, among Quicksilver Resources Inc., Quicksilver Resources Canada Inc. and the agents and lenders identified therein	10-Q	001-14837	10.4	8/9/2012
10.3	PEA Amending Agreement, dated as of August 28, 2012, between Quicksilver Resources Canada Inc. and Nova Gas Transmission Ltd.	8-K	001-14837	10.1	9/10/2012
10.4	Amendment to Commitment Letter Agreement, dated as of August 28, 2012, between Quicksilver Resources Canada Inc. and Nova Gas Transmission Ltd.	8-K	001-14837	10.2	9/10/2012
10.5*	Acquisition and Exploration Agreement, dated September 20, 2012, between Quicksilver Resources Inc. and SWEPI LP	8-K	001-14837	10.1	9/24/2012
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					‡

* Portions of exhibit deleted pursuant to request for confidential treatment. These portions have been furnished separately to the Securities and Exchange Commission.

55